Legislature(2003 - 2004)
09/02/2004 09:00 AM House BUD
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* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
ALASKA STATE LEGISLATURE
JOINT MEETING
LEGISLATIVE BUDGET AND AUDIT COMMITTEE
SENATE RESOURCES STANDING COMMITTEE
September 2, 2004
9:00 a.m.
MEMBERS PRESENT
LEGISLATIVE BUDGET AND AUDIT
Representative Ralph Samuels, Chair
Representative Mike Chenault
Representative Mike Hawker
Representative Beth Kerttula (via teleconference)
Representative Reggie Joule, alternate
Senator Gene Therriault, Vice Chair
Senator Lyman Hoffman
SENATE RESOURCES
Senator Fred Dyson
Senator Ralph Seekins
Senator Kim Elton
Senator Georgianna Lincoln
OTHER LEGISLATORS PRESENT
Representative Bill Stoltze
Representative Ethan Berkowitz
Representative Les Gara
Representative Eric Croft
Representative Paul Seaton (via teleconference)
Representative David Guttenberg (via teleconference)
Senator Donny Olson
Senator Gretchen Guess
MEMBERS ABSENT
LEGISLATIVE BUDGET AND AUDIT
Senator Ben Stevens
Representative Vic Kohring
Senator Con Bunde
Senator Gary Wilken
SENATE RESOURCES
Senator Tom Wagoner, Vice Chair
COMMITTEE CALENDAR
^ALASKA NATURAL GAS PIPELINE ISSUES
PREVIOUS COMMITTEE ACTION
No previous action to record.
WITNESS REGISTER
Lesa Adair
Vice President, Muse Stancil
Harold Heinze
Chief Executive Officer, Alaska Natural Gas Development
Authority
Brian Rogers, Information Insights
Robert Cupina, Deputy Director, Office of Energy Projects
John Katz, Assistant General Counsel for Energy Projects,
Federal Energy Regulatory Commission (FERC)
Margery Fowke, National Energy Board, Canada
Commissioner Dave Harbour and Administrative Law Judge Jan
Wilson, Regulatory Commission of Alaska
Commissioner Daniel Seamount, Alaska Oil and Gas Conservation
Commission
Mark Myers, Director of the Division of Oil and Gas, Department
of Natural Resources
ACTION NARRATIVE
TAPE 04-24, SIDE A [BUD TAPE]
CHAIR RALPH SAMUELS called the joint meeting of the Legislative
Budget and Audit Committee and the Senate Resources Standing
Committee to order at 9:00 a.m. Chair Samuels introduced Lesa
Adair, Vice President of Muse Stancil and Company and said Ms.
Adair consults on issues related to valuations, damage
assessment, market evaluations and transactional due diligence
in the energy sector. Ms. Adair has over 20 years experience in
the industry and is frequently obtained to resolve disputes and
advise clients on mergers, acquisitions, project development and
investment decisions in the transportation process, refining
marketing, and electrical generation sectors.
NATURAL GAS LIQUIDS, IN-STATE NATURAL GAS PROCESSING AND
PETROCHEMICAL FACILITIES
MS. LESA ADAIR, Vice President of Muse Stancil, told members she
would review natural gas liquids, the market in general, and the
options for in-state processing and petrochemical facilities, as
well as the alternatives. She referred members to page 2 of her
handout and said she would talk briefly about the natural gas
liquids (NGL) market and focus on the United States and Canada,
relative to potential NGL production from Alaska. She began:
If we look at 2003 total year numbers, the production
of natural gas liquids in the Lower 48 totaled about
1.7 million barrels. That production was primarily
concentrated in the southcentral United States - no
big surprise there - that's where the bulk of the oil,
and particularly gas production, is in the Lower 48
with about 66 percent of the production coming from
that particular area. In addition, we imported about
165,000 barrels per day of NGL production, primarily
from Canada, coming through pipelines into the upper
Midwest.
In contrast, let's talk a little bit about Canadian
production. Their production was about 670,000 barrels
a day and, of course, their exports just happen to
equal our imports at about 165,000 barrels a day.
Based on numbers we've been provided from the
Department of Natural Resources and looking at the
total potential production and throughput on NGP and
the compositions that are expected of NGLs in the gas,
it looks like the potential production from the Alaska
gas pipeline (AGP) throughput for NGLs would be on the
order of 160,000 barrels a day but about 120,000
barrels a day of that would be ethane. Contrast that
with U.S. supply of about 625,000 barrels a day of 1.7
million barrels being total ethane, the AGP liquids
are going to run about 50 to 60 percent ethane, as
opposed to current Lower 48 consumption and
production, which is about one-third ethane. Canada is
very much the same. They've got a slightly higher
percentage of ethane at about 40 percent. So AGP is
going to be more highly leveraged on ethane.
Let's look at how the market really works in terms of
natural gas liquids today. In the Lower 48 we have
two, really, principle market hubs - Mont Bellevue,
which is located on the Texas gulf coast and Conway,
right in the center of the United States near
Hutchison, Kansas. Both of those locations are
interconnected with large diameter transmission
piping. Further, they are interconnected all the way
back up into Edmonton, Alberta through a series of
pipelines so that the entire Lower 48 and Canadian
natural gas liquid markets are very well integrated.
As a result, what we tend to see, because the largest
consumption of natural gas liquids occurs here in Pad
3, and it's specifically on the U.S. Gulf Coast, is
that the prices are pretty much set by the consumption
that occurs in Mont Bellevue and then the whole rest
of the market adjusts, all the way back up to
Edmonton, off basis differentials for transportation.
From time to time, there can be regional disruptions
in supply, seasonal supply and demand that may throw
those particular relationships out of whack for a
little while but, in general, the price is pretty much
netback from a market clearing price at Mont Bellevue.
The other key thing to keep in mind about these market
centers and again, the biggest ones in the Lower 48
are Mont Bellevue and Conway, Sarnia is also north of
Detroit - is also a large NGL market center, and then
Edmonton, Alberta. These particular areas have large
fractionation units, multiple large fractionation
units. And the other distinctive factor there is that
they have both the demand for the NGLs in those areas
and significant underground storage in the form of
salt cavern storage. Salt cavern storage is the most
efficient way to store natural gas liquids. In Conway,
they really only have the fractionation in the
underground storage. They're really a distribution
point balancing the demand between the northern and
southern parts of the United States and Canada,
whereas in the other markets, they're all derivative,
manufacturing polyethylene, polypropylene and so forth
in those areas.
If we look at product price trends, and truthfully all
we want to talk about here are the trends, the ethane
natural gas liquid tracks the natural gas price very
closely. It is correlated very well to the natural
gas, while propane and butane track the crude oil
price. The important thing to understand with gas
processing, as opposed to refining, for example, where
all of the products that are derived from crude oil
generally follow the crude oil price, there are so
many derivative markets for natural gas liquids that
we don't have the gas price setting the price for all
the products. They move independently. As a result,
the margins move independently and you can have a lot
more volatility in the margins.
Let me just point out a couple of spots here to make
that clear. If we look here in the period of 1995, you
can see that crude oil prices are tracking fairly flat
in this area but you can see natural gas and ethane
moving independently in a downward trend in this
particular area. Propane and butane prices were likely
relatively stable while gas prices were falling. The
other thing to notice is that as these prices move,
you don't necessarily get the same order of magnitude
shifts, even though they may be following the same
trend. For example, in the period towards the end of
the curve out here in the 2001 forward period, crude
changed about $10 a barrel or moved about 40 percent
of its value, where gas moved $3.50 for about 140
percent of its underlying value so large change is not
necessarily the same order of magnitude.
When we look at natural gas processing, we have to
look at what is the value of extracting these natural
gas liquids from the gas itself and that's really what
the next page 5 is focusing on. Here, as opposed to
the prior slide, what we're looking at is the dollars
per MMBTU for both natural gas, the blue line - the
bottom line in most of the chart, and ethane, which is
the red line, the top line. And we're actually able to
compare the value of the ethane if it's sold on the
top line in red as a liquid directly to the value of
the ethane if it's sold as natural gas.
The important thing to recognize here is if you look
at the period of the early 1990s, you can see a fairly
wide difference between those two lines indicating
that if you take ethane out of natural gas, you don't
sell it for the blue price - turn it into a liquid,
sell it for the red price, you make the difference. As
you track across time, move closer to current and,
specifically after late 2000 where you see the great
big lovely peak in prices, you can see those lines
moving much closer together. As those lines move
closer together, the value of ethane as a liquid is
becoming almost equal to the value of ethane as a
natural gas. What that says is there's no incentive
for a processor to change it from gas to liquid.
Rather, he's indifferent. He'd rather just sell it as
natural gas and not have to pay the processing cost.
NGL pricing on page 6 - there's a lot of debate about
what's going to happen to pricing and, frankly, one of
the things that I think is going to create some
disruption in the market may be the timing and the
actual location of the extraction of liquids from AGP.
EIA has rolled, I believe, Alaska natural gas into
their forecasts. At least it appears to be in there
for everything I've looked at and they're forecasting
that on average, on an annual basis, they think NGL
prices are going to remain essentially flat on a real
basis in the long term. They're projecting the
increase of something around 1 percent, slightly more
than natural gas, which leads me to believe that their
view is that we may see a slight improvement in gas
processing margins over time. But specifically for AGP
liquids, what we have to be concerned about is where
those liquids are going to end up and specifically,
how much it costs to get it there because obviously
we're not going to have enough demand in Alaska for
all of the natural gas liquids that can be extracted,
therefore you're going to have to deal with export
pricing and that really is going to be the biggest
determinator really of what those prices are netted
back to the wellhead or to the border, whatever basis
you want to look at.
The other thing that you need to think about too is
that because AGP liquids will be highly leveraged to
ethane, we have to think about where will all of the
ethane go but the best place for all the ethane may
not necessarily be the best place for the propane and
the butane. Because these products all go to different
derivative markets, you may have widely differing
economics, depending on the ultimate destination of
each segment of the NGL production.
Let's talk a little bit about historic processing
margins. We'll look at the Lower 48 and maybe that
will help us get some idea of what you'll be faced
with in looking at AGP liquids. My firm, Muse Stancil
and Company, publishes every month an oil and gas
journal - these NGL extraction margins. And really
what they're meant to represent are hypothetical
plants in the mid-continent and the U.S. Gulf Coast.
And really, this margin is meant to represent
economically how is gas processing doing. In each
individual situation the margins may be higher or
lower but, on average, this tells us how margins are
changing over time. In the mid-continent we tend to
see fairly rich natural gas streams. Those plants do
require usually a little bit more compression. On the
Gulf Coast you have less compression but much leaner
gas, much larger plants. And you can see that if we
look at the trend, over time, from early 1990, that we
are in a significant long, very slow decline in
natural gas processing margins. This particular
calculation is done from the standpoint of the plant
operator, assuming that he buys the gas, he extracts
the liquids, and pays all of his operating costs. So
this gives us the cash margin really, that he would
earn for performing those services. It does not take
into account the overhead, which can vary widely from
company to company or the capital expenditures that
may be going on - the return of or the return on
capital. So this is sort of a before tax type number.
But you can definitely see we're in a downward trend
long term and, for gas processors in particular, the
last three and one-half years have been pretty tough.
On the U.S. Gulf Coast you can see that since 2001,
margins have actually averaged negative cash return.
Now what is the producers' perspective on this same
profitability for gas processing? One of the things
that's pretty typical in gas processing contracts that
we see all over the world, not just in the Lower 48,
is what a processor agrees to produce or to process
gas for a percent of the proceeds. In other words, he
captures the percent of the product and that's what he
takes as his payment for the services. So the producer
is used to paying a percent of his proceeds over to
the processor and so one other thing that we look at
is from a producer's perspective, he usually pays for
all the fuel. He has to bear the shrinkage - that is
how much his gas volume decreases when he extracts
liquids, and also the transportation and fractionation
charges from moving those products away from the
plant. So we look at it from his perspective and we
say okay, if you're going to process your gas, how
much of a liquid do you need to get back to pay for
processing, to pay for fuel, for the shrinkage, and
the transportation fractionation? And if you look back
in the early '90s, you can see that a producer in the
mid-continent or on the Gulf Coast was making money if
he got 60 percent of his proceeds back.
But over time, just as we saw with the gas processing
margin, that amount of liquids he needs to receive to
pay for processing has continued to increase. When the
value of the liquids exceeds the 100 percent bar that
means that the producer has gone from earning some
income for processing to paying for it; in other
words, it's become a cost center. He can't ever get
enough liquid back to pay for the cost of processing.
And so, in the period since late 2000, we have begun
to see a shift in the mentality in the industry that
more and more people view processing, at least in the
short to medium term, as a cost center rather than a
profit center. There are unique opportunities out
there, depending on composition, capital expenditures
and so forth, where some people are making money but,
again, as a barometer in general, processing has
become more of a cost than a profit center.
Now I'd like to shift gears a little bit, moving on to
page 9, to talk about alternative dispositions for the
AGP-NGL throughput. The Department of Revenue has
obtained us to assist in developing their
understanding of the economics of these different
alternatives and so one of the first things we took a
look at is what particular areas, what market centers,
make the most sense. If we look at extraction in
petrochemical manufacturing outside of the State of
Alaska, the first place that you think of is the U.S.
Gulf Coast, where over 80 percent of the capacity for
[indisc.] production in North America is located.
Other centers include in Alberta, primarily in the
Edmonton area, where about 12 percent of the capacity
exists, and then Sarnia and other various locations in
the U.S. Midwest, which tend to be large isolated
manufacturing facilities. The nearest infrastructure
of any plausible size, and this includes derivative
manufacturing of ethane, the fractionation
capabilities and the underground storage we talked
about earlier, is really Alberta. If we look though,
at Alberta's ethane balance, they're currently
manufacturing just a little bit more, not even 10
percent more ethane than they utilize, and so they're
pretty balanced on supply. We do know that their
availability of liquids is going to go down over time
as their gas continues to decline and so, over the
medium to long term, there may be some opportunities
to supplement the ethane that they're using in their
petrochemical manufacturing there in Alberta. Their
total demand currently is about 250,000 barrels a day.
If we look at AGP's potential of 120,000 barrels a day
of ethane, that's roughly half their current capacity,
so that's an awful lot of NGL or ethane in particular
to have to displace into Alberta. However, there could
be additional capacity installed there or additional
take-away pipeline capacity installed to handle the
incremental ethane coming off of AGP.
Extraction in Alaska - first of all we'd have to think
about the fact that when we pull out the ethane, other
things are going to come with the ethane. It's not
likely that we could come up with an economic
solution, which says we build a natural gas liquids
pipeline to take the excess propane, butane and so
forth that comes out with the ethane to a market, as
well as a gas pipeline. So our feasibility look really
centered on the notion that you would extract what you
need for manufacturing in Alaska and that everything
else would go back in the AGP so that you would only
have to build one piece of transportation
infrastructure for the state.
To have a market for that primarily ethane would also
require the development of a petrochemical
manufacturing complex and, most likely, that would be
ethylene going to polyethylene and then the
infrastructure to support that, including the storage
utilities, electrical and so forth. It's possible that
you may require some additional transportation
infrastructure but our design is not at a level yet to
really determine that. Polyethylene is pretty easy to
transport - you can put it in rail cars, hopper cars,
in bags and transport it by rail and marine.
The facility would look something like this on page
10. The facility would handle about 1.4 bcf of
throughput on the extraction plant. That's out of a
roughly 4.3 bcf total throughput on AGP. From that we
would produce about 40,000 barrels per day of ethane
to be fed to the ethylene facility and another 1,000
barrels a day of propane or so for local consumption.
Any incremental propane that couldn't be sold and
butane that's extracted would go back into the
pipeline for transportation to the ultimate pipeline
termination point. You would also be able to produce
commercial quality natural gas for local distribution
off the top of the extraction plant. And any residue
gas that you couldn't sell, which our figures show
would be about a B [BCF] or a little over a B [BCF],
would go back into AGP as well.
The design and construction of this sort of facility
is probably duplicative in that you would ultimately
size all the facilities at the terminus of the main
line pipeline to handle 100 percent of the throughput
because, obviously, if you're going to have one
ethylene plant, one polyethylene plant, they're going
to have to be in shut down and turn around for some
extended periods of time and you wouldn't want to have
to shut down your pipeline to do that so you would
probably just have a slightly bigger extraction plant
at the terminus of the pipeline to allow you the
flexibility to mute that gas in either direction.
Downstream of the extraction plant, on page 11, your
ethane would feed an ethylene cracker. You would
produce ethylene, which would feed a polyethylene
plant and then produce the polyethylene resin, which
would be little pellets that look like little chips of
wax. There are some by-products from the production of
ethylene, however ethylene production is by far the
most efficient process. If you try to use propane to
propylene or naphthenic-type cracking, you get a lot
more by-product, stuff you can't use. If you're in
Edmonton or on the U.S. Gulf Coast, those by-products
can be sold into other related petrochemical
facilities in the area - refineries, other
petrochemical manufacturing. Here we've assumed that
all these by-products have to be burned as fuel
because we are not anticipating that we would have
additional available infrastructure to absorb those
by-products.
In summary, if we look at Fairbanks versus other
potential points for extraction and downstream
processing of NGLs, we believe there will be an
attractively priced feedstock at Fairbanks that,
because you're exporting the gas, the price of gas at
Fairbanks is likely going to be some Canadian border
or Alberta-related price netted back from the tariff,
which should lead you to a fairly inexpensive price
for feedstock in Fairbanks. Fairbanks also does, with
the rail connection, offer a link to waterborne
transportation and there is demand for polyethylene
resin in California. Now that demand is being met
today so you would have to be able to penetrate the
market at the right price to make sure you could get
all the placement of that market.
There are synergistic benefits, including pipeline
quality natural gas availability to Fairbanks and
possibly other areas. You would have to have
electrical generation within the complex and you could
possibly oversize that facility and provide additional
merchant electrical power delivery into the grid.
The disadvantages we see of the Fairbanks location is
that there is some variability in the gas composition
over time, that's just a function of how gas comes out
of the reservoir and that's something we deal with
everywhere. However, here it's going to be very
localized. In the Lower 48, it's kind of spread out
all over the place. What that means is you have to
size your gas processing facility to be able to ensure
that you're always going to be able to extract enough
ethane to keep your ethylene plant going, which means
it's probably a little bit bigger than it would
generally need to be.
There's going to be a little bit of inefficiency in
processing because you're going to process 1.5 bcf of
gas in Fairbanks; 1 bcf of that is going to go back
into the pipeline. When it does, it gets remixed with
other components and has to be reprocessed again at
the terminus of the pipeline so you do have to have
the capacity and pay the operating costs for that to
be processed twice. We talked about the non-optimal
sizing. You're going to want to make your downstream
facilities big enough to take all the gas in the event
that you've got an outage in your ethylene production
or just for routine maintenance of your ethylene
facility.
In looking at capital costs - and I think this is one
that's real important, especially since we've just in
the last several weeks learned that there are at least
three ethylene plants in the Gulf Coast that are going
to be shutting down because they're at a cost
disadvantage. Fairbanks appears to be about a 35
percent higher capital cost than installing similar
facilities on the U.S. Gulf Coast, and perhaps 25
percent higher than an Alberta type installation. That
is before we consider the fact that we're going to
have to add infrastructure that already exists in
Alberta or exists on the U.S. Gulf Coast that we could
incorporate and use so there would be additional costs
above and beyond that. The fixed operating costs are
likely higher, due to wages and also due to the fact
that you're going to have to fly in expertise, parts,
and equipment, which are readily available in those
other centers. We talked about the lack of supporting
infrastructure and the fact that the by-products
really don't have a market here so anything that we
create out of ethylene manufacturing that's not pure
ethylene is going to have to be burned probably as
fuel in the facility.
If we look at the preliminary economics, and this is a
very high level analysis, but it appears to us that
the production of the ethane in Fairbanks is just
economically less attractive than in either Alberta or
on the U.S. Gulf Coast. You've got the advantage of
potentially a lower feedstock price than your ethane.
The lower variable costs, and by that we mean fuel, if
your gas is cheaper, it's cheaper to burn as fuel as
well. But that's more than offset by higher fixed
operating costs, the location differential in a remote
location, and the lower product value due to
downgrading those by-products to fuel.
The significantly higher capital cost is probably also
going to be a disincentive for most of your major
manufacturers to invest. If they're looking at a
location in Alaska where there's stranded gas versus a
location in Asia where there's stranded gas and they
can build a plant for 30 to 40 percent less than
Alaska, they're more than likely going to go to Asia.
We see an awful lot of manufacturing of facilities
being installed in Asia today and, in fact, the U.S.
Gulf Coast facilities are running at less than
capacity because they're having trouble competing with
the more efficient and cheaper product out of the Asia
Pacific.
Looking at recent historical U.S. Gulf Coast margins
for ethylene production, we're assuming - we believe
Fairbanks could probably achieve a similar margin
because its got the feedstock advantage but it's going
to have higher investment costs. But, if it's able to
do that, it will have a significantly less attractive
rate of return simply because you've got a higher
capital investment. Alberta's rate of return is
probably a little bit higher. Their contracts are
structured a little bit differently than the U.S. Gulf
Coast. So, Fairbanks is pretty economically
disadvantaged in terms of trying to compete in the
world market. And that's all I have. I'm happy to take
any questions.
CHAIR SAMUELS asked, regarding the capacity, if Ms. Adair said
the capacity from Fairbanks south would have to be the same as
the capacity from the North Slope to Fairbanks, just in case the
plant was out and had to be modified.
MS. ADAIR said that is correct and, more than likely, to keep
the gas flowing, the downstream facility would be sized as if
Fairbanks wasn't there. That would provide the ability to keep
the gas flowing if Fairbanks had to be shut down. The
incremental cost in terms of the pipe size is not that great.
CHAIR SAMUELS asked what percent would be taken out if the plant
was up and operating as intended as it goes by Fairbanks; and
how much empty space would be headed for Chicago.
MS. ADAIR replied, "About 1/2 B [BCF] is what our numbers show
because we pull off 1.5 and we put back in about 1, so about
500,000."
SENATOR RALPH SEEKINS asked how the NGL content of the gas
envelope that comes off the North Slope compares to other areas
or regions.
MS. ADAIR said the composition is more like a Gulf of Mexico
type gas. It tends to have less propane and butane in it but has
more ethane. From the extraction profitability standpoint, the
propane and butane tend to be the higher value components of the
gas. She noted as compared to the Lower 48 and Canadian
production, Alaska gas is 50 to 60 percent ethane; the Lower 48
and Canadian gas is 30 to 35 percent.
SENATOR SEEKINS said the primary object is to get gas from the
North Slope to someone who will burn it at a power plant or at a
commercial application down the road. He asked, "Let's say we
had a complete gas envelope that didn't have anything taken off
from it and it got to the Canadian border. Is then that - what
do we deliver out the other end? Is there any BTU per BTU
relationship that exists when it comes back into the United
States?"
MS. ADAIR replied the real question has to do with the way the
major transmission line systems and local distribution systems
are designed and, to a certain degree, how water heaters and
stoves are designed to work with natural gas. She explained what
you typically see in the United States are natural gas pipelines
operating at 1,000 btu gas. Some operate as high as 1,050. In
Alberta, the gas processing facilities that are remotely located
do what is called dew point control. They strip out the heaviest
liquids - propanes and butanes; and make it easier to move the
gas in pipelines without a lot of liquids falling out. The
problem with liquids falling out is twofold: a loss of
efficiency and safety considerations. In the Alberta system, the
heavier liquids are extracted in the field and then large
straddle plants sit over their big gas transmission systems and
extract the rest of the ethane. However, in all cases when
looking at local distribution systems, the btus are very low so
the producer does not have a choice. At some point along the
value chain, the gas must be processed. The btu content must be
reduced for distribution purposes and someone must pay for it.
SENATOR SEEKINS said everyone wants to make natural gas usable
in Alaska in Fairbanks and with a line to Anchorage. He asked if
the product that comes down that line to Fairbanks would be
usable downstream in Alaska without any processing.
MS. ADAIR said it would not without some sort of processing,
however, a petrochemical complex taking the product all of the
way to polyethylene resin would not be necessary to make a
commercial quality natural gas for local use.
SENATOR SEEKINS commented, "I've heard people talking about -
well there are, on the other side of the border, there are
people that are saying and they get to the Whitehorse area and
they're saying if we can get that intact envelope here, we can
strip that stuff off, we can get it down to the Alaska coastline
and get it out to the markets if Alaska doesn't. Is that a
possibility? Is there any discussion about that that you're
aware of?"
MS. ADAIR said she is not aware of any such discussions and has
not been asked to study that question. She noted the potential
limitation revolves around having enough heavy-duty vessels to
move that high-pressure product, particularly ethane.
SENATOR SEEKINS said many [legislators] want to have in-state
processing to enhance Alaskans' overall quality of life. He
asked Ms. Adair, with that in mind, if her basic conclusion is
that may not be economically feasible.
MS. ADAIR said the problem is that Alaska will have a hard time
competing in the worldwide market if it has integrated
petrochemical manufacturing in-state.
CHAIR SAMUELS asked what type of processing facility would be
required to pull the heavy liquids out to service Fairbanks and
Anchorage.
MS. ADAIR explained the processing would require the same
technology to produce the natural gas liquids but the processing
plant would be a different size and the cost would be much
smaller. It would not require any of the downstream processing
and the liquids that were not used could be put back into the
pipeline.
SENATOR SEEKINS asked if those liquids would be put back in the
gas pipeline as opposed to the oil pipeline.
MS. ADAIR said that is correct and that it would be a relatively
small amount compared to the overall throughput on the AGP.
CHAIR SAMUELS referred to page 8 and asked if demand for the
liquids drops, the processing cost goes up for everyone, and
whether the demand has dropped so low that the manufacturers
cannot recover their operating costs.
MS. ADAIR said the margin for gas processing is very volatile
and feedstocks, which are natural gas, work off a different
supply and demand curve than the products do. What has happened
is that the demand for natural gas in and of itself is so strong
that, to the extent everything possible is left in the gas, it
is more economically beneficial to do so. She continued, "And
that's really what creates this situation is gas prices are so,
so high. People would like to - producers would like to sell
their propane as natural gas if they could in some places but,
because of the safety considerations, they are not able to do
that. So, demand is still very strong for all of these
products."
SENATOR SEEKINS asked, " It appears to me then what we're saying
when we look at this chart on page 8, that this is kind of a
stand-alone - I'm buying the gas, what the price of the gas is.
It's a separate accounting for that structure but what you're
saying is it's necessary for them to take some of these liquids
out?"
MS. ADAIR said it is.
SENATOR SEEKINS asked if the break-even chart is based on having
to buy the liquids but not considering that they have to be
stripped out.
MS. ADAIR explained that it is based on the producers'
opportunity costs - the gas given by the producers to create the
liquids. She continued, "Some of that he gives up because he has
to shrink out the propane and the butane. Some of it he gives up
because it's burned as fuel. That's gas that he could be selling
for revenue. So it's that whole opportunity cost that he bears
to produce those liquids. That's really what the chart is
driving at; it's that his cost has gone up."
SENATOR SEEKINS said often the expense structure is a necessity,
not necessarily a reduction in opportunity.
MS. ADAIR said the producer may have flexibility to a certain
degree, depending on whether he or someone else is processing
for him, to reduce the amount of processing done. Generally
producers sell to someone else who does the processing but some
producers in the Gulf Coast retain the right to not process
their gas when prices get high.
CHAIR SAMUELS acknowledged that Senators Lincoln, Hoffman,
Dyson, Guess, Elton, Seekins and Olson and Representatives
Berkowitz, Joule, Chenault, Hawker, and Stoltze were present. He
then announced that Mr. Harold Heinze would address the
committee.
IN-STATE OFF-TAKE POINTS AND SPURLINE: COST AND DESIGN
eHe
MR. HAROLD HEINZE, Chief Executive Officer of the Alaska Natural
Gas Development Authority (ANGDA), advised members that his
presentation would mirror Ms. Adair's but would address a much
smaller scale. He noted that at the last hearing, members talked
about some access and opportunity issues, and some people
"raised their eyebrows" over the assertion that these things
would work economically. As a result, ANGDA hired some
contractors to do some feasibility studies based on some worst
case assumptions and came to the conclusion that there are gas
off-take opportunities in Alaska worth understanding. He said he
would focus on providing gas for a number of different options:
electric power plants, propane distribution, and piped gas
distribution systems. He also said he would talk about an
approach that is on a different scale. ANGDA designed an
entirely stand-alone facility to perform those functions and
costed it. He pointed out that it is not an optimized design but
ANGDA has identified many ways to lower its cost and improve the
design. He advised members that they need to immediately start
considering that any gas pipeline that runs any major volume
down through Alaska will have compressor stations on it. If
those compressor stations are 100 miles apart, there would be
seven or eight of them. Every one of those stations must perform
the function of conditioning the gas. They must make the gas
usable as a fuel and, in the process of doing so, will extract
products that are valuable to Alaska's citizens. He reminded
members that may not be on the scale of a huge petrochemical
industry but it is very important for Alaska. He said he would
then talk about a spur line into the Cook Inlet area because
that represents a major off-take opportunity for Alaska. He gave
the following presentation.
Again, to kind of put it in scale for you, if you go
back to the previous presentation, one of the early
charts there showed the U.S. propane production at
500,000 barrels a day. If you kind of look around
Alaska, how much propane is used in Alaska today,
there's no exact number I could find but my best guess
is it's probably a little over 1,000 barrels a day of
propane is used in Alaska right now. And I went
through and I did an estimate just - again, roughly
off some previous demand studies that have been done
related to gas and I estimated that if you supplied
basically the whole interior of Alaska that was not on
the highway system or not on the pipeline, in other
words on the river system or the disbursed road
system, that you'd need something maybe resembling
2,000 barrels a day of propane to do that. So, again,
on the scale of the world, we're pretty small.
But also just to put in perspective for you, what you
didn't hear in the last presentation is how much
propane is going down the line. That number is
anywhere from 50 to 100,000 barrels a day of propane
is going down that line. So what I'm talking about
here is a relatively minor extraction of something
that's going by. It will not change the economics of
anything related to the pipeline but it is important
to the economics of Alaska and Alaskans. [END OF TAPE
04-24, SIDE A]
TAPE 04-24, SIDE B
MR. HEINZE continued.
...on the line. We sized - again, these kind of plants
are very common. This is not brain surgery. This is
off the shelf stuff. You can call people up and order
these parts from a catalog and you can put them on a
skid if they are small enough. As a matter of fact,
the unit we are looking at here is smaller than any
manufacturer really wanted to talk about but we were
able, through a little cajoling, to get them to think
really small. This facility process is only 10 million
cubic feet a day of gas. Again, to kind of put that in
perspective for you, Fairbanks would probably use a
number two or three times that. Ten million a day
would be enough for a large mine development but it
would be an overwhelming number compared to any of our
smaller communities or smaller opportunities that we
would be looking at. In terms of scale, that was about
as small as we could get people to kind of think
about. And we said okay, we'll stop there, because
even if it was too big, you obviously can turn this
kind of facility on, run it for a period of time, and
when the tank is full, you turn it off and then you
turn it back on. You can do that in an operational
sense here. Again, there's nothing very magic in all
of this stuff here.
REPRESENTATIVE BILL STOLTZE asked Mr. Heinze if he has talked to
the Matanuska Electric Association (MEA) because it will be
ending its long-term contract with Chugiak in the not too
distant future and the Matanuska Valley is the fastest growing
part of the state.
MR. HEINZE asked to defer that topic to the spur line
discussion. He then continued with his presentation.
In terms of the propane issue here, this is a plant
that again, you'll see summarized a little later.
Again, the economics on this - basically, what we
found out, this plant would cost a little more than
$10 million. If you work the economics of it,
basically you can extract propane under this situation
for about 50 to 75 cents a gallon. Now, there are
optimizations you could make on this plant. There are
a lot of variations on this theme and, for instance,
if I looked at the Yukon River, which would have a
bigger plant than this, I could keep driving that
number down. So the 50 to 75 cents is the upper number
per gallon. On a broad feasibility sense, I'd like you
to think about the fact that that is a potentially
very attractive number to Alaska. In Alaska we pay
basically the propane price in Alberta plus the
transportation here. If the gas going by here is at
some intermediate value compared to Edmonton, then our
price would be lower. At 50 cents even, you can afford
to be extracting it at some place that's very
convenient for you to wholesale from and so there is
at least worth understanding here. I'm not claiming
this is a done deal but it's worth understanding.
CHAIR SAMUELS asked Mr. Heinze to also address, later in his
presentation, the reduction in capacity and whether there will
be empty capacity heading south.
MR. HEINZE replied, "You will see on the scale of the things
we're talking about other than the gas off-take to come to the
Cook Inlet area, other than the spur line issue, there's no
issue I'm raising here - it gets lost in the round off, let me
put it that way." He then continued.
We also looked at the same plant because if you have
to basically go through the same process to condition
the gas for, say, to make a turbine fuel for either
powering a pump station or compressors for providing
electric power generation, or providing local
distribution of gas, you have to go through these same
basic processors. If you look at the front end of this
plant, it's identical. All I've taken out here is the
idea of reinjecting the gas and now I'm using the gas
beneficially. And again, we looked at this plant. The
economics are very attractive and, frankly, if I took
credit for having both gas available for use and
propane, now the price per unit on both of those goes
down. So, again, I can improve on this.
What we don't know at this point is - and we suspect
only because the information, frankly, is not
available to us, is that at every compressor station,
there would be something that looked like this. Our
engineering expertise says that to run a compressor
station, you've got to do something like this at every
compressor station. But, since we've never seen the
plans or diagrams or process or anything at the
stations, we don't know. But that is our engineering
judgment at this point.
That's interesting because if you already have a large
amount of gas that's going to be used to fuel the
compressor station and burned in the turbines and
pushing that 4.5 billion cubic feet of gas south,
that's in itself going to yield a lot of propane. And
again, how you look at that cost structure and all
those other things is very interesting.
SENATOR SEEKINS asked if the gas must be dehydrated before it is
put in the pipeline.
MR. HEINZE said the water vapors are removed to a certain level
but ANGDA does not know what that dehydration level is because
it has not seen the exact specifications. He pointed out that
[the dehydration requirement] could be removed to optimize the
facility. If the pipeline specification was low enough it might
not be necessary, depending on ANGDA's process design. That
process is there to get to the necessary temperatures further in
the process. The gas is chilled to a very cold temperature and
any water vapor at all at that point creates difficulties. He
noted the dehydration step accounts for several million dollars.
SENATOR SEEKINS surmised that if it is not dehydrated, it would
produce carbonic acid mixed with CO2, which would eat right
through steel.
MR. HEINZE said ANGDA is very comfortable that the water
specification would be such that that would not be a worry. He
said the problem is that as you went through these facilities,
the water temperatures achieved would be much lower. He repeated
that for the feasibility study, ANGDA took the worst-case
scenario it could think of.
SENATOR LINCOLN recalled Mr. Heinze saying a propane plant at
the compressor stations would cost about $10 million and asked
if that cost would increase by having the utility gas in there
as well.
MR. HEINZE replied:
This is actually a lower cost facility because we
don't have to reinject the gas. Because we have a
beneficial use for the gas and don't have to reinject
it, it saves us the cost of a compressor. Every time I
drop a box off of this thing, I think of it as $1 or
$2 million shaved off the plant. It's just some pieces
of the puzzle we don't have to have there to operate
correctly. So this is a much simpler operation in our
mind. And so what it argues very strongly is, again,
as you look at what we would call a very small
facility, for some parts of Alaska it is very large.
But, on the other hand, we can make available through
these kinds of facilities a fair amount.
For instance, this facility yields 100 barrels a day
roughly of propane. So in that sense it is small. But
again, we could scale this facility up and achieve
much greater economies of scale. Let's say you wanted
1,000 barrels a day at the Yukon River. All this
feasibility work says is that might be very attractive
because we could beat That 50 to 75 cents a gallon
propane, by a lot probably, in a facility designed
just for that purpose.
MR. HEINZE continued his presentation.
Again, I've kind of told you everything that's on that
slide already. This was just kind of looking at it -
every place you had a power plant, for instance, at
North Pole. North Pole was putting in a 60-megawatt
plant. It would take a facility about this size to
condition the gas for use in that plant probably or
some variation of it. You could produce propane there.
You could probably produce 100 barrels a day of
propane, is all we're saying, as a by-product of doing
this. So that's important. We have no understanding of
the combination of the pump stations on the
TransAlaska pipeline, which are being electrified
under their new program and how that might co-locate
and co-act with compressor stations located, again,
along a gas line. And from our perspective, there
might be some wonderful synergies involved in co-
locating those major facilities and operations, in
which case - again, you would have a fairly large use
for gas to fuel the turbines that run the generators
that drive the motors that drive the compressors and
trunks, so it's logical.
Again, I'm going to continue to emphasize to you that
even though we are a small piece of the show, there's
4.5 billion cubic feet a day going down that line and
we're talking about here something that's 1/1000th of
that. It is very important that we define the ability
and where and how those things might happen. I took a
crack at it for you here. Again, last time I drew up a
broad list. Here's my more definitive list of where I
would, at least, see those kinds of points. And it
seems to me that you'll notice some of the points I've
tried to list were in Canada. And it's, again, my
general understanding that this type of a pipeline
going through Canada would have to make the revision
for this kind of access that we're talking about. Now
maybe the law is different there. Maybe something else
is different. I don't know. I haven't researched it
but it seems to me that we, in our own best interest,
ought to be looking at something like that.
And then my final point is I think you ought to put
the burden of what I'm trying to talk about here
today, frankly, on any project proponent. These are
issues and opportunities that are part and parcel of
running the system through the public land, as far as
I'm concerned, and they need to be addressed as part
of the design. We found our ability to do this was
very hindered by the fact that there is, for instance,
no publicly available information on the composition
of the gas that's going down this pipeline. I mean you
just heard a presentation on a whole petrochemical
industry and I don't know what the basis of that
presentation was. It's not publicly available. I don't
even know how to design these facilities for sure.
The other thing you've got to worry about is the
tariff issue and, again, I've got to just bring this
back up with you because the key to this is physically
we can take the gas off. I've shown you a facility
that can do it. I've shown you feasibility economics
that say it is possible economically to do it. But,
it's dead in the water under a tariff structure that
discriminates against taking gas off in Alaska. If you
don't have a tariff structure that allows us to gain
the benefit of being closer to the source, all bets
are off. If I have to pay the same price in Fairbanks
that I would in Edmonton, the economics don't work and
it's that simple.
Again, I would suggest to you that you can include
these things in either the grant of right-of-way by
the state, or whatever Stranded Gas Act things you do.
Mr. Chairman, I'd like to just take a few minutes and
talk about the spur line and some of the issues
related to it. Part of the charge that ANGDA was given
in Ballot Measure 3 was to look specifically at a spur
line to the Cook Inlet area. It was not just to look
at an LNG project but also to look at a spur line.
Basically, a part of the report that we will be
publishing in a week - we did do that and we have
basically, again, completed preliminary work on it and
I very briefly summarized it here. We did define an
alignment for the 140 miles that's shown on these two
poster boards behind you. It goes from Glenallen,
basically, at the TransAlaska pipeline right-of-way
and it leads into a place in Palmer that is basically
- I would describe it to you as the place where the
highways and the railroad intersect - the Glen and
Parks Highway and the railroad and the new overpass
and all that. That happens to be the point where you
can get to the Enstar 20 inch system, which is the
basic piping system in this whole area. And so we'd
design that line to go between those two places. It's
a high-pressure line. Its cost estimate was about $300
million.
We also hired a financial company to look at the
financing of that where ANGDA would be acting as a
state-owned utility. The advantage of being a state-
owned utility is that basically you can do 100 percent
debt financing for a project of this size and you can
do it at a very low interest rate - lower than the
interest rates that we talked about yesterday in the
presentation. For that type of a design we estimated
that we could move gas from Glenallen to the Palmer
area for about 15 cents/million btu. That's a very low
number. It's very difficult to move any gas anywhere
in Cook Inlet for that number. Most of the time it's a
bigger number than that just within the Cook Inlet
area.
There are, obviously, in terms of the spur line, a lot
of issues that are well beyond our control. Obviously
there is not gas sitting there right now in Glenallen
for me to go pick up. If you want to go to Delta and
pick it up there, it's about twice the cost. It's
about twice the pipeline and about twice to everything
else. We did not work that problem in detail because
the pipeline would follow the TAPS right-of-way, which
is a well understood pipeline and corridor and there
are just no big issues in laying a 24 inch pipe.
As you'll see on the map here, we did lay out a basic
route that follows the Glen Highway because the state
does have that right-of-way. We do have the ability to
lay pipe in that right-of-way. From a technical point
of view, there are places that we have identified
where it was logical to deviate from that right-of-way
and possibly improve the pipelining circumstances.
Again, as anybody whose driven the road knows, there
are places where the side slopes are pretty steep and
where the river kind of comes up against the cliffs
and those kinds of things. It would be hard to fit in
the right-of-way. It could be done but it would be
hard to and we've identified other areas that we'd
like to go down.
SENATOR SEEKINS noted that Senator Wagoner was very interested
in looking into the routing of a connection into the Palmer area
from the Fairbanks area that would follow the Parks Highway and
asked if ANGDA looked at such a route.
MR. HEINZE said at this point, ANGDA has looked into the record.
The state has information on file sufficient to define a right-
of-way from the Fairbanks to Palmer area. ANGDA also found there
is no information on the Glenallen "on-in" route so ANGDA will
take the step of submitting that right-of-way application.
Regarding the study between the two different routes, at this
point, ANGDA has formed no opinion that has allowed it to
differentiate between the two. ANGDA is aware of advantages and
disadvantages to each; the biggest advantage to coming through
Glenallen is twofold. First, it would reach the greatest
population of the state and, secondly, it is the easiest in
terms of right-of-way issues because it follows the TransAlaska
pipeline right-of-way through an area that is made up solely of
state and private lands. On the other hand, the other route has
a definable right-of-way. ANGDA will study that and look at the
smaller projects for bringing North Slope gas to the area.
SENATOR SEEKINS said it is his understanding that Senator
Wagoner believed the possible route from Fairbanks to Palmer did
not cross any federal land either; it is all state and private
land.
MR. HEINZE said the examples he has seen of that route contained
some special state park land and federal parkland. He admitted
he does not know whether ways can be found around that at this
point.
SENATOR SEEKINS said he saw a relocation to the east side of the
Parks Highway, which is totally outside of federal land but
other people say it would have to go through the national park.
MR. HEINZE said at this point, ANGDA's preliminary assessment is
that the cost to deliver gas either way is very comparable.
ANGDA sees no cost advantage to one route over the other, the
reason being that even though the Glenallen route is longer, it
would be more economically attractive to "ride a longer distance
in a big pipe to Delta" and, second, that route already has a
right-of-way and road system.
SENATOR SEEKINS asked if the right-of-way from Delta south is
already owned and would have to be purchased by the state.
MR. HEINZE said in one of ANGDA's studies about its broader
responsibilities under Ballot Measure 3, it determined one of
the specifics was to look at the permits and other certificates
held by the Yukon Pacific Corporation. ANGDA determined that a
large number of those permits are still good and valuable. ANGDA
looked at that favorably in that it could buy a federal and
state right-of-way held by Yukon Pacific that would go all of
the way to Glenallen.
SENATOR DYSON asked if ANGDA anticipates the optimum use of in-
state gas will exceed the state's royalty share.
MR. HEINZE said right now, 200 bcf is used in Alaska annually.
About half of that amount is used in the LNG export facility on
the Kenai, owned by Conoco and Marathon. They currently feed
that with their own reserves. He does not know their future
intentions. He continued:
I have no idea, I have no way of knowing what they
intend to do in the future on that. For the purposes
of these economics, I have made the assumption that
what I see today is what I have in the future.
Obviously there is a case where they choose to do
zero. There is also a case where they choose to expand
based on a new and plentiful supply. At least one of
the companies I just named is a major owner of gas on
the North Slope. If their gas was used in that plant,
I presume the state would not take it as their
responsibility to supply that gas. Of the remaining
100 billion a year, half of that is roughly Agrium.
And, again, I don't know exactly what role the state
would play in that. The state might be a seller there
or they might buy gas from other people commercially
or whatever. I know they are interested in the fact
that a spur line like this, hooked this close to a big
supply up north, might give them the kind of pricing
advantage they feel they have to have in the
marketplace to continue to operate. Again, our focus
has been much more on them frankly, than trying to
build a new industry, because if we can't make their
economics work, then again my experience says it's
going to be very difficult to do something in terms of
greenfield, so we have a lot of incentive to try to
make that work.
If I could, back to Representative Stoltze's question
about the Matanuska area and all that, it is our
intention in the spur line that we would put major -
we would like others to have major electric generation
facilities at both ends of that spur line. It makes
sense that where we take off in Glenallen to have a
generating plant - that also wholesales propane. It
makes sense to have an electric power plant and other
things as we come into the Enstar system.
REPRESENTATIVE STOLTZE asked if an entity that might have the
capacity to serve 20 percent of the state's population would
provide more justification or impetus and whether that entity
would need to "come to the table" formally.
MR. HEINZE said that early in the spur line discussions, he
invited every utility, agency, and others to a meeting. MEA did
attend that meeting. Since then, people have taken a greater
interest in the dialog but that is the choice of each entity at
this point. A spur line to this area may be a very attractive
proposition for the citizens of Alaska. And while everyone hopes
that a lot of gas is discovered in Cook Inlet, the DOE study put
a multi-billion dollar price tag on it. Therefore, this
alternative must be kept on the table.
SENATOR DYSON said everyone at the table feels responsible to
make sure that Alaskans benefit from North Slope gas
distribution but the bottom line question is whether the state
is able to meet the foreseeable need for home heating and power
with its royalty share.
MR. HEINZE said the portion he firmly believes the state is
responsible for dealing with is in the range of 50 to 60 billion
cubic feet per year. That is a very small amount compared to the
state's share of several trillion cubic feet. However, regarding
all other in-state uses, the arithmetic becomes a bit more
problematic, but that is for commercial and industrial companies
that are capable of taking care of themselves. His preliminary
review says if ANGDA can bring a large supply to this area at a
reasonable price, it makes sense for the industrial users to not
only continue but to expand to help their own economics. He then
alerted members that in one-week newspapers around the state
will produce a 12-page report to the people, required by Ballot
Measure 3. ANGDA has distributed 150,000 copies throughout the
state for inclusion in all major newspapers in Alaska. He hopes
it provides a positive view of what ANGDA can do related to gas
use in Alaska. He noted that ANGDA will be powering up a website
at the same time that will contain all consultant reports and
everything it has done in its first year.
SENATOR SEEKINS asked Mr. Heinze if he is aware of any plans or
consideration of a liquids line that would go from the Interior
to the Cook Inlet area.
MR. HEINZE said he is not aware of any current consideration but
when he mentioned that he looked at the right-of-way information
on file with the state, the information was for a liquid line
from Fairbanks south. That application was submitted a number of
years ago. At that time, the parties were having difficulty
discussing the cost of shipping on the railroad. Someone decided
it was appropriate to look into alternative economics. He
believes that design is legitimate.
SENATOR SEEKINS asked if there has been an ongoing discussion
about that possibility.
MR. HEINZE said not that he is aware of but he is not in that
business.
REPRESENTATIVE GARA recalled the Wood MacKenzie "folks" said, at
the meeting yesterday, that contrary to what others have said,
the state has a large window of opportunity to secure an LNG
contract if it ships LNG to Valdez. He noted that contrasts with
people who have said that time is of the essence regarding that
sale. He asked Mr. Heinze to respond. His second concern is that
Southcentral will always have an increasing demand for gas and
no one knows what will be available in Cook Inlet in 10 years,
so the amount that will need to come off of a spur line is
unknown. He said five or six years from now, when the gas line
is more definite, the Cook Inlet supply will be more definite.
He asked if companies that are deciding whether to build a gas
pipeline will base their decisions on whether natural gas will
be offloaded in Southcentral because of an inadequate amount in
Cook Inlet and whether they will have to analyze that now.
MR. HEINZE said in regard to the second question, ANGDA has made
certain assumptions as to size, cost, volume and other factors
and showed the low number of 15 cents per million btu. If that
same line moved half the volume through it, the cost would be 30
cents per million btu. If half the volume came all the way from
Delta, the cost would be 60 cents per million btu. He explained:
If we are delivering into this area gas priced at the
North Slope that's based upon a transportation
distance to Chicago, and we're this much closer, even
at 60 cents from Delta here, that is a price lower
than the world price. We have some advantage. Again, I
don't know if it's $1.00, I don't know if it's $1.50,
but it's a number. And again, we can see that clearly
in our work.
What's also very clear is that while we don't know how
much will be found in Cook Inlet, we do know it will
be expensive. And again, I'll just go back to the
statistics. DOE estimated [that] to find reserves to
sustain this area would take $5 or $6 billion worth of
exploration investment. Why wouldn't you look at a few
hundred million dollars for a pipeline as a viable
alternative? And again, that's the arithmetic we're
lead to is that you don't, fortunately, have to decide
right now which way you prefer or whatever, and
certainly the spur line does not change the course of
the big pipeline and all those other things. We're
prepared to tack the spur line into wherever we can
find the gas. In the ultimate, you'll see in this
report, one of the projects we suggest looking at into
the future is frankly going all the way to the North
Slope to just supply this area and a bullet line.
However difficult that sounds to you at this point,
that may be a viable alternative from an Alaskan
perspective - that may be attractive. Again,
remembering that the advantage of getting gas to
tidewater anywhere is that not only do we go through
our communities in the Interior, but once we have it
to tidewater, we can deliver it to coastal
communities, which again, in essence reaches 99
percent of our population. If you can go down the
rivers, you go down the highway system, and you can go
on the coastal marine transport, you can reach just
about everybody in Alaska one way or another.
So, that's kind of the feel we have for the spur line
is that I've had producers or people looking at
drilling in Cook Inlet and asked me whether they
should drill. And I said can you get a good price? And
if they answer yes, I say why wouldn't you drill? What
are you worried about me for? On the other hand, I
wouldn't sit around and wait for ten years to see if
we do build a pipeline in and then expect you're going
to get the same prices then that you can once there is
a large supply hooked to the area.
On the flip side, about this report, again, not to
steal its thunder, this is a feasibility at best
report - okay? And what we looked at was in terms of
the specific LNG project we were asked to look at 2
bcf/day to Valdez basically. Did we see things about
it that said stop, don't work on this anymore, quit,
this is a bad idea and the answer was no. If anything,
we found encouragement frankly. And, for instance,
Wood MacKenzie was one of the people, you'll see, was
working this. And they, in particular rate, in a cost
sense, all the LNG projects in the world. And I mean I
will break it to you - it doesn't steal our thunder
that we are not one of the low cost ones. But, on the
other side of it, we're not so far out the top that
it's silly for us to think about an LNG project. For
instance, the example I use - the easiest one to
understand is Shell Oil Company, a major knowledgeable
player in the world, a mega-major, developed a place
called Sakhalin, facing a lot of similar challenges to
what we face here. If you go to the rudimentaries of
that economic decision they made, our decision is
probably actually more positive than theirs, I would
contend. So, if they thought it was okay to go ahead,
that tells me we need to understand our project better
and that's all this report says is understand it
better.
At the same time, it also has become clear from the
consultive reports we've gotten back in trying to
understand these projects, that Alaska clearly has
some issues. We have some competitive disadvantages.
We don't have workers that are brought in from
Bangladesh. We don't pay third world wages here. So
our labor component on a project that may involve 30
or 40 million man hours of labor is a pretty big
factor in this thing and it may affect, somewhat, our
competitiveness. And that's something we need to
understand because again, I would hope that you all
realize that if we were able to design the project in
a way that it better fit the Alaska labor pool, such
that even if we did have a lot of extra money in the
project but it was money that you were comfortable was
being spent in Alaska, that might not be all bad. If
instead of doing something in one year we took five
years to do it and made it happen in that way - that
might be considered good by some people. Again, we
have to do those kinds of factors in it.
We are going to be, because of that, looking at other
variations of the theme than we were given in Ballot
Measure 3. We are going to look at smaller, more
Alaskan sized projects and with some other variations
that we think might help the competitiveness of the
project.
SENATOR LINCOLN said she is anxious to read the ANGDA report and
is pleased to hear about the potential take-off locations he
listed. She believes that Alaskans must look at what this
project can do in terms of delivering some of the by-product of
the gas line to the people, not just solely the bottom line of
extracting the gas for export to the Lower 48. She noted she is
extremely encouraged to see how the take-off points might affect
the smallest villages, not just the most populated areas of
Alaska.
SENATOR HOFFMAN asked Mr. Heinze to expand on how 99 percent of
communities can benefit and whether that will be from the
state's royalty share.
MR. HEINZE said ANGDA took a hard look at the fact that Alaska
has a small population that would not use a huge amount of
energy, compared to the amount that would be shipped to the
Lower 48. He said he was trying to draw attention to the fact
that a pipeline route that goes through the Interior, down the
highway system and intersects with the Yukon River, would reach
a large number of people. But, to take that further to bring gas
to anywhere on the coast, a compressed natural gas facility
could be built so that it could be barged to communities of any
size. ANGDA and a contractor are looking at that possibility,
especially in the smaller communities, of providing a barge
mounted gas supply with a large gas driven electric turbine
generator next to it where the village plugs in. He cautioned
that is not something that would instantly happen throughout
every coastal community in Alaska, but it might within a
generation. Regarding the state's role, he said to the extent
that ANGDA makes a margin, it has not faced up to what it would
do with that margin but it might provide an interest-free
revolving loan fund.
TAPE 04-25, SIDE A
SENATOR SEEKINS said if the line was brought in, it would
eventually become dominant and have to be designed for
expansion. He asked if that wouldn't have a chilling effect on
exploration.
MR. HEINZE replied in reality, if a pipeline were brought in
with a large supply at a certain price, his decision to drill
would be based on that price. He couldn't expect to command a
higher price. Different companies have different economics,
however. It would discourage some, but not others. Because the
state has had a surplus supply for many years, it has enjoyed
very low prices, about $2.50 MBTU wholesale or about half of
what the world price is right now. He estimates that price will
rise with more exploration money. If the spur line were brought
in at a cost of $300 million that would drive the prices back to
what they are today. If one translates that into potential
disposable income of residential families, it would equal $100
million a year of additional disposable income.
SENATOR SEEKINS said the demand for that pipe would increase
quicker than if there was still a competing force trying to find
additional gas sources.
MR. HEINZE said the linkage here will supply a generation or two
with a plentiful supply. If some of the bigger numbers presented
by Mark Myers (Director, Division of Oil and Gas) were realized
on the North Slope, they are talking about many generations of
Alaskans.
SENATOR KIM ELTON said he had a comment about the report that he
wanted Mr. Heinze to respond to.
It would have been helpful to have a presentation or a
document from you on what those findings or the
elements of the report would have been, because we've
gathered yesterday and today a great number of people
with certain levels of expertise and it would have
been great to toss the findings that you have into
that mix to get their reaction. So, I'm frustrated
that you don't want to steal the thunder of a report
that is going to be printed in the newspaper in the
next week. If it's going to be printed next, you know
what the report says.
MR. HEINZE apologized, but said the reality is that he had to
make a choice. He would have loved to have the release at this
meeting, but he didn't have control over both of their
timelines.
I assure you that all of you as legislators will be
given advance copies tomorrow. Every one of you will
receive that. We certainly respect the fact that as a
number of the important leaders of our state, that you
need to know what this looks like before it is widely
available. On the other hand, Ballot Measure 3 was an
initiative of the people; this is a report to the
people and we felt that the proper approach was to
find a way to let everybody know at one time and,
frankly, not let any one segment of the media gain
some advantage or control over what the message was.
We carefully thought through a 12-page report and we
wanted the message to be holistic and go out and let
everybody see it at once.... I will also clarify to
you that the report is not a bottom line. The report
simply says, 'Here's what we found out and here's what
we think needs to be done going forward. I honestly
see the report more as a start than a finish of
anything....
CHAIR SAMUELS said the committee set the parameters on topics
that would be discussed and he had no idea that Mr. Heinze's
report would be coming out next week.
SENATOR ELTON observed:
Having been in the news business, I can tell you that
if you don't have every comma in place two weeks
before publication date of something like this - and
it would have been very, very helpful to have those
findings so that we could toss it into the mix - I'd
be stunned I guess if they don't know where every
comma is in their report at this point in time.
CHAIR SAMUELS announced a brief at-ease before the next
presentation.
NEGOTIATION OF STATE AND MUNICIPAL PROPERTY TAXES UNDER THE
STRANDED GAS ACT
MR. STEVEN THOMPSON, Mayor, City of Fairbanks, said he is chair
of the Municipal Advisory Group (MAG), and that he would give
them an overview of MAG and what it has agreed upon so far in
resolutions regarding taxes and gas pipeline impacts. MAG was
formed to advise and make recommendations to the administration
on the anticipated social, economic and revenue impacts of a gas
pipeline project as well as on the affect of any municipal tax
relief the administration may negotiate in an effort to enhance
the economics of a project.
The group is made up of representatives from
communities that will likely be impacted by
construction of the natural gas pipeline, including
Anchorage, the City of Delta Junction, the City of
Fairbanks, the Fairbanks North Star Borough, the City
of Kenai, the Kenai Peninsula Borough, Skagway, the
Haines Borough, the City of North Pole, the North
Slope Borough, the City of Seward, the City of Valdez
and representing the unorganized regions, the Tanana
Chief's Conference....
Today I'm here to talk to you about what's important
mostly to our communities. Even though we are a very
geographically and culturally diverse group, we have
been able to identify many issues that we share
similar perspectives on and those are reflected in our
first resolution. I believe you have copies of those.
We all agreed that no reduction or deferral in
municipal taxes is acceptable without appropriate
justification from the State of Alaska and the project
sponsors. We are willing to help make the project
happen, but if it means a reduction in revenue
opportunities for us, there needs to be a clear,
verifiable justification for it. We have also agreed
that the State of Alaska should weigh the cost of
benefit of a tax exemption with the difficulty of
administering an exemption from specific taxes.
We've agreed that the State of Alaska should devise a
payment in lieu of taxes structure that provides
certainty for municipalities at least through the end
of the stated contract period - that the State of
Alaska should insure the payment in lieu of taxes
structure recognizes the loss to present and future
forms of local government of opportunity to respond to
changing conditions through changing tax rates, and
that the State of Alaska should provide incentives to
the successful applicant under the Stranded Gas Act to
insure the training and hiring of Alaskans for the
construction, operation, and maintenance of the gas
line.
One critical point we all agreed on is that the State
of Alaska should require that the successful applicant
will include takeoff points at strategic locations
along the pipeline to make gas available to meet the
reasonably foreseeable demand for in-state natural gas
use - that the State of Alaska should insure there
will be a fair tariff to the points of in-state
takeoff of gas.
Finally, we agree that the State of Alaska should
insure that affected municipalities' combined share of
the economic rent of [an] approved project should
correlate with the revenue stream of the project by
negotiating that the present value of the aggregate
amount of payment in lieu of taxes is not less than
the amount that would have been collected under
current Alaska law.
The points of our second resolution are that no
property currently taxed under Titles 29.45 and 43.56
should become exempt under this contract. The contract
should clarify how dual-use facilities will be taxed
in order to protect municipalities' current tax base.
No exemption should apply to existing gas
infrastructure. Due to the relatively small amount and
incredible complexity in administering a sales and use
tax exemption, those taxes should not be on the table
for negotiations.
Finally, at our last meeting last week, we approved a
third resolution that mainly focuses on issues
surrounding the need for natural gas in communities
all around the state and we requested the
administration specifically to include the placement
of municipal takeoff points in the rural and urban
areas of Interior, Southcentral and Southeast Alaska
[and] amend statutes to provide greater assurance that
Alaska communities will have access to gas from any
trans-Alaska gas pipeline - and that the State of
Alaska should retain its right to take the state's
royalty gas in kind to meet those needs. This third
resolution has been approved by the group. However,
there still needs to be ratification by community
councils before it is final.
We have also had some great discussions on what shape
of payment in lieu of taxes [PILT] might work best for
us. Although we all have different tax structures, the
municipal advisory group is working together to
identify what our similarities are and make as many
unified recommendations to the governor as possible.
Again, the point I want to make very clear to you
right now is that our communities need access to the
gas. It is unthinkable that there may even be a
possibility of a gas pipeline through Alaska that
doesn't allow us to use some of that gas right here in
the state. And yet, for some reason, it's apparently a
point of negotiation in this proposed project
application.
The MAG, in our first and third resolutions, made very
clear that we expect any gas pipeline project be
required by law to provide for adequate takeoff points
and spur lines to meet the reasonably foreseeable
demand for in-state use. We recommend in our third
resolution that you change Alaska statutes to do just
that. We also want to make it clear that we want the
State of Alaska to insure a fair tariff to the points
of in-state takeoff of gas and that the state retain
its right to choose to take its royalty gas in kind or
in value - as determined to be in the best interests
of the state and to change that determination when
conditions warrant.
We need to be able to share in the revenue benefits of
a gas pipeline. Having said all that, if you have any
questions before the Information Insights
presentation, I would be very happy to answer them.
SENATOR FRED DYSON agreed with the spirit of what Mayor Thompson
said but had a few questions. He referred to language on the
last page that reads - be able to share in the revenue benefits
of the gas pipeline. He asked if Mayor Thompson thought there
should be a formula for the revenue that the state gets from the
gas pipeline, similar to the revenue sharing program.
MR. THOMPSON said that is the point that MAG was trying to make.
SENATOR DYSON asked if he was implying that there must be a
pipeline to Southeast or that there be a supply system for
Southeast.
MR. THOMPSON answered that it means that there should be points
from which take-off spur lines could advance. Ports and valves
could be put into the line for a future time when a compression
plant is built to service Southeast.
SENATOR DYSON asked if he thought there should be a pipeline to
Southeast or whether a supply could be barged - not necessarily
a pipeline everywhere.
MR. THOMPSON said that is correct.
SENATOR LYMAN HOFFMAN asked why Western Alaska was left out.
MR. THOMPSON said it wasn't left out. One of the take-off points
would be the Yukon and areas in the upstream side.
SENATOR ELTON asked if he had identified what the statutory
changes should be and communicated them to the governor's
office.
MR. THOMPSON replied that MAG got to the point of adopting the
resolutions, but not beyond that point.
SENATOR ELTON asked who the governor's office or a legislator
would get in touch with to discuss the statutory changes MAG
envisions.
MR. THOMPSON said he could get more information on that and that
MAG would be adopting more resolutions.
SENATOR SEEKINS asked if he is suggesting that municipalities be
able to tax construction of a pipeline on a property tax basis.
MR. THOMPSON replied that under the Stranded Gas Act, the state
can exempt properties having to do with the gas line - an office
building, for instance, from property tax through the contract
period. The municipalities would receive payment in lieu of
taxes from the state for that. How municipalities receive that
payment is a problem that needs to be resolved. They need to
figure out how to deal with a dual use facility as far as
property tax goes.
SENATOR SEEKINS asked if the tax bill would be due after
completion of the building or during the process. Discussions
indicate that the impact would occur now and there is no way to
meet the need for additional schools and services, etc.
MR. THOMPSON said MAG is addressing those questions.
We're looking at the economic impact, which would be
during the construction and then the revenue impact of
not having property tax for the length of the
contract.... That will be in our reports. I think
Information Insights will give you some of the
economic impact during construction when he makes his
presentation.... The ramp up period of construction is
going to have an effect on communities along the
construction route clear to Seward. If that's where a
pipe comes in, there'll be an economic impact of
upgrading their ports to be able to receive the pipe.
Kenai could be building compression modules. There
could be a big impact there. Influx of pipeline
workers is going to definitely increase the need for
police and emergency services. The schools part of it
is going to be addressed.
CHAIR SAMUELS agreed with what he said, particularly about
Alaskans using their own resource and being able to choose
between royalty in kind and royalty in value.
I want to just make sure that it has a down side also,
that internally your discussion - if you cannot adjust
the compression from the North Slope to the
distribution center in Fairbanks or Delta or wherever,
and you have empty capacity going south, somebody has
to pay - it either gets spread over the cost of the
remaining gas, in which case at the end point our gas
is now the transportation costs are higher and they
are already very high or we have to charge more on the
front end on the Slope to Delta portion. Internally,
I'm assuming that your discussions have been taking
place that there's not a line in the sand going -
we're not going to pay a tariff one penny more than
what it costs to go from A to B if it puts the whole
project at risk to pay on the capacity in the pipeline
headed south from Fairbanks or Delta.
MR. THOMPSON responded that those conversations continue to take
place within the group. They want to make sure the State of
Alaska benefits from the gas and not just see it all disappear.
CHAIR SAMUELS said the trade-off would be that you get the gas
here, but you lose the cash at the end of the line.
MR. LARRY PERSILY, Department of Revenue, testified:
The state's ad valorem property taxes, which are AS
43.56, apply to oil and gas production exploration
property. Just to run through some of the basics for
people who may not be familiar with it - it's
generally based on the remaining value of the asset.
That would be your value after depreciation. Under
state law, it's limited to 20 mils. The municipalities
assess their tax first; the state gets the balance.
So, if a municipality has an 18 mil rate, they would
get 18 mils; the state would get 2 mils. If the muni
is at 15, they would get 15; the state would get 5.
Property tax statute regulations treat pipelines
different during construction than during operation.
This gets to Senator Seekins' question. First of all,
under construction, the property tax is due from the
commencement date of construction. When that pipe hits
the dock and the front end loaders are there, the
property tax is due - not at the completion of the
project. That has been one of the issues certainly in
the past and certainly of concern to any project
sponsor - that they have to start paying property tax
during the years of construction before there is any
cash flow from the project. During the construction,
it's the full and true value of the actual cost. Then
when it goes into operation, it becomes the economic
value, which is based on the estimated life of the
proven reserves. So, if you believe you've got 30
years of proven reserves, we're going to use a
depreciation schedule for that 30-year life-span of
the project and in trying to appraise it - just to
back up a minute - even though the municipalities
collect oil and gas exploration production property
tax, the state does the assessing, which has also in
the past been an issue of contention between the state
and municipalities. Because, of course, if you're a
municipality and the state is doing the assessing and
you're looking at your revenue drop as the assessments
drop, you may think the state is doing a bad job of
assessing. There is a state assessment review board
that will deal with those cases. Of course, property
owners would think the state is doing a bad job of
assessing, because it might be too high. So, the state
often gets caught in the middle between municipalities
who want the assessments higher and the property
owners who want the assessments lower.
In assessing pipeline property that's in operation, we
look at the life of the proven reserves; you look at
sales comparison, which is difficult because this
isn't a home. You don't have comps out there as you
think of your home assessment. It's not that someone
has sold pipelines in Alaska or sold gas treatment
plants on the North Slope. So, doing comps or sales
comparison is difficult. Costs - you can get into a
debate - what is the replacement cost, which is what
state law talks about, not explicitly what did it just
cost to build that facility, but what would it cost
you today to replace it. And certainly, on older
facilities, the replacement costs could be
significantly less than what it cost you to build it
with new technologies. You can look at the income
approach and from all those hopefully come up with the
right answer.
As you think of the importance of property taxes to
municipalities on this gas line project, certainly
there is the impact funding in the construction years
as the mayor talked about, as Brian Rogers will
discuss. Under property tax law, status quo tax
payments are due the minute you start construction and
during those years, in many of the communities, you're
going to have the most impact - schools, roads,
ambulances, police protection and such. After
construction, funding of ongoing general government -
that's what property taxes are for - and that's going
to be an important issue to municipalities who, when
they look at this, are looking for certainty as they
try working on their budget planning - as they are
deciding whether to issue bonds. Are they going to
have revenue to pay it off? They need to know with
some certainty what kind of revenue stream they are
going to have.
This is perhaps just the way the grid was set up - an
exaggerated look, but it points out the problem. This
is a very conservative scenario. This is based on pure
cost of a gas pipeline - no new reserves that would
extend the life. So, if you find new reserves that
line that declines would hit a new plateau. If you
think you've got 20 more years, it's going to level it
out and then it's going to start declining again. It
assumes no new investments, which would add to the
basis value of that property. But what this points
out, and this is an example if you had a $5 billion
pipeline, during construction, you're property tax
payments increase very quickly and very steeply as all
that money is being spent during the five years. At
that point then, you now have the basis in your line,
you're draining your reserves. Every year the value of
that operating pipeline decreases. So, the property
tax revenue decreases. As I said, this is a
conservative scenario that shows no new investment and
no new reserves. So, it really wouldn't be that steep,
but it points out the problems for municipalities -
you're getting a percentage of an asset that's
declining in value, which, if it's your municipality,
is maybe not where you'd want to be long-term.
SENATOR DYSON said he suspected the gas pipeline, like the oil
pipeline, would have a much longer life than was originally
anticipated. "When that turns out to be true, is there a
mechanism for recapture and how does that work for the local
folks?"
MR. PERSILY replied:
As the Department of Revenue's assessors looked at the
oil pipeline and we looked at extending the life of
the line, adjustments are made and the assessed value
of that pipeline is taken into account. If it's going
to be producing income for a longer period of time, it
should have a higher value as you extend it out. So,
under law we do make adjustments and change the
assessments. It's just like your home - every year a
new assessment notice goes out.
SENATOR DYSON said a 15-year longer life than is expected would
change the slope of the line considerably. He asked:
Is there a mechanism to go back and recapture the
property taxes that should have been paid based on now
a more accurate assumption of the useful life of the
line?
MR. PERSILY replied:
The number doesn't go back up if you can visualize....
You still only had $X billion into the line. The cost
basis didn't change. What you're doing now is not so
much stopping the depreciation, but extending out. So,
instead of going down steep, it might reach a plateau
and go close to level and then start to climb again,
but at a much more gradual pace because you're not
going to retroactively change your collections, but
you're going to extend your collections for many more
years than you had expected collecting more money over
the life of the project. But the total basis into it
that you're depreciating hasn't gone up, so the value
is still, say, a $10 billion line. Instead of
collecting taxes for 30 years, now maybe you're going
to collect tax for 50 or 60 years.
SENATOR SEEKINS inserted, "But at a low rate."
MR. PERSILY replied, "Right, but cumulatively it's going to be
much more than you would expect at the beginning of the
project."
SENATOR DYSON added, "And similarly, if the replacement costs go
up, that would also change the basis?"
MR. PERSILY answered:
Sure, you could argue if the replacement costs go up
that could be a factor the state would take into
account. I can certainly tell you that the owners of
the TransAlaska Pipeline, well not so much the
pipeline, but the Prudhoe Bay facilities, always argue
that the replacement costs go down, because they would
argue you could build those facilities today much
cheaper than you built them then, because of what they
know now as opposed to what they knew 30 years ago.
So, I welcome your input, but I think they might
disagree. Not surprising.
SENATOR SEEKINS asked what the statute says regarding the
administrative codes he's quoting on page 3.
MR. PERSILY read from AS 43.56.060 (d), "'The department shall
assess property for the taxes levied at the full and true value
January 1' - and this deals with pipelines - 'The first
assessment date shall be the construction commencement date.'"
SENATOR SEEKINS said if the legislature wants to change any of
that, it has to be done in statute.
MR. PERSILY replied that is correct. Section (b) of that statute
deals with construction; section (e) talks about once it's in
operation. It says, "the full and true value of taxable property
used in pipeline transportation" and then it goes on to say,
"economic values based on estimated life of the proven
reserves." Technically, economically recoverable talks about,
"straight line basis for depreciation over the economic life of
the project."
MR. PERSILY moved on to slide 7 and said:
The commercial problems presented by the property tax
in the current form - and I guess these would be
commercial problems from the perspective of the
project sponsors - front end loaded. As I explained,
you start paying property taxes the minute the
equipment hits state territory. If you're a project
sponsor, you might say, 'Gee, that's a lot of money to
pay before I start having cash flow," but certainly
from a municipal perspective, that's when you start
seeing the impact when the construction begins. You
could say it's regressive in that it exacerbates the
impact of cost overruns because your property tax is
based on the value of what you're putting in there
during construction or the basis when you go to
operation. If project sponsors are worried about a 20
percent cost overrun on the project, that would mean
not only do they have that problem to deal with, which
leads to a higher tariff, but if you have a cost
overrun, the property tax bill is going to go up.
Fiscal uncertainty is an issue certainly for the
sponsors. They are not going to know what the property
tax rate is going to be - not just the assessment, but
the mil rate itself in the future. For the
municipalities it's a problem too, as you think about
municipal budgeting and wanting some certainty.
The uncertainty in the asset valuation is an issue
just about every year. There's a lot of money at
stake. This isn't whether your home is worth $240,000
or $220,000; this is whether the property might be
worth $3 billion or $3.5 billion - disputes whether to
use cost income market approach, asset life,
capitalization rate. So, these are a lot of the
problems that are faced under the status quo that we
would hope to deal with in the Stranded Gas Act to
help encourage construction of a project and setting
up a fiscal system that would be best for the
municipalities, too.
Under the Stranded Gas Act in terms of property taxes,
first is that obligation that the payments are shared
with the municipalities, that the state sets up in the
Stranded Gas Act and it's approved by the legislature
some system in lieu of the status quo for property
taxes. The state is obligated under statute to share
that with municipalities who would be losing that
property tax ability on their own. It's to be shared
with not just the economically affected communities,
certainly, but the revenue affected communities. There
are two different ones - a revenue-affected community
might be someone who is losing the ability to assess
property tax revenue on that pipeline. Someone who is
economically affected might be someone who is not
going to have any of the pipe in their community, but
would have an economic impact, for example - if
construction equipment is brought in at Haines, barged
to Haines and trucked through the highway system to
construction sites. Ultimately, when the line goes
into operation, Haines will not have pipeline
property, but during those years of construction,
they're going to have an impact if you're talking of
thousands of truckloads of equipment moving across the
dock and moving through their community. So, you've
got two different kinds of communities, both of which
need to be accommodated in the Stranded Gas Act.
You certainly want something that's fair and
reasonable with due regard to the size of the tax base
that would be exempted under the Stranded Gas Act.
You've got to deal with the economic and social
burdens imposed by construction and operation in the
communities. The Stranded Gas Act also calls on the
Department of Revenue to consult with the Municipal
Advisory Group in crafting contract language.
MR. PERSILY said the last slide looks at negotiation issues.
Certainly, one key is to improve the project
economics. We want a project; you want a pipeline
built; that's the whole goal of the Stranded Gas Act.
One way you can deal with it, certainly, is the issue
of the front end loading, the [indisc.] at the
beginning during construction as long as you take into
account certainly the strong needs for municipalities
during those years, but you want to come up with
something that improves project economics, recognizes
the municipal issues, deals not just with the
certainty for the sponsors, certainty for the
municipalities as they budget and the issue of the
declining tax base. The fact that under status quo
every year in theory, that pipeline is going to be
worth less as you get closer to the end of the
economic life, impact aid during construction - that's
when a lot of municipalities are going to see their
highest costs - is during the construction boom. We
don't believe it would be as much as during the oil
pipeline, but it's going to be significant and as we
heard at the last committee meeting from the
Department of Natural Resources and the federal
geologists, there could be a lot more gas there.
This project could have a much longer life than we're
looking at now with just 35 TCF. You want to make sure
that what's in that contract protects the
municipalities so that if this project runs 50 or 60
years, they're still getting substantial revenue
during all that time. And, at the end of the contract,
because under the Stranded Gas Act, it's limited to a
35-year contract, you've got to look at what happens
that next day. If you've got a 35-year contract, and
you've got some payment in lieu of taxes, some
mechanism set up and then the next day when you revert
back, that needs to be dealt with in the contract
rather than just saying you'll worry about it in 35
years.
One other thing to keep in mind is restructuring taxes
is not necessarily lowering taxes. Improving the
project economics doesn't mean giving away money or
taking something away from the municipalities.
Restructuring tax in the Stranded Gas Act, hopefully,
would improve the economics and also enhance the
revenue stream for the municipalities at the same
time.
TAPE 04-25, SIDE B
MR. PERSILY, in response to a question from Senator Seekins,
related that the Stranded Gas Act negotiators are looking at
what is the best way to insure the municipalities' revenue most
accurately reflects the economics of the project and the length
of the project's life rather than the current status quo, which
is tied to a declining number.
REPRESENTATIVE LES GARA asked, "If I'm correct, we've taken
roughly $75 million per year in property taxes now, then
distribute it to the municipalities from North Slope
operations?"
MR. PERSILY responded:
The last time I looked, I believe the total take of
oil and gas production and exploration property tax
was around $250 million, of which I think the
municipalities get a couple hundred million and the
state about $50 million - about 20 percent.
REPRESENTATIVE GARA asked if he could assume the ratio would be
similar for pipeline operations and if he could guess at the
amount property taxes would bring in during the construction
phase.
MR. PERSILY said the state would be involved in receiving
payments if there is a new structure in lieu of property taxes,
because more of the gas line is going to be on state lands than
with the oil line. He guessed that a property tax rate of 20
mils on a $10 billion project would bring $200 million. He
reminded them that property taxes are not linked to the
economics of a project.
SOCIAL AND ECONOMIC IMPACTS OF A HIGHWAY ROUTE GAS PIPELINE
MR. BRIAN ROGERS, principal consultant, Information Insights,
Inc., said his report is really a work in progress. Information
Insights was contracted by the MAG to look at the social and
economic impacts of the gas pipeline, both construction and
operations with a real focus on what it does for local
governments, to look at the revenue impacts to municipalities
under the Stranded Gas Act and to look at subsistence and
cultural impacts to villages and local governments as part of
gas pipeline construction. His focus is on the producer's
application only and, to date, on just the gas pipeline portion,
not the gas treatment plant or the upstream facilities or any
in-state spur lines.
As some background, just thinking about the
TransAlaska Pipeline System (TAPS), the TAPS was a far
larger project in its impact on Alaska - if escalating
those costs over today - larger than the total cost of
the entire line and almost four times the size of the
Alaska segment and that impact is placed on an economy
where the population is doubled and it's a far more
robust economy than we had in the early '70s.
However, TAPS gives us some ideas as to what the
impacts are likely to be. Looking at the pipeline
corridor under TAPS, affecting the North Slope
Borough, the North Star Borough, the Interior villages
and Valdez, the impact on schools was lower than most
expected. The workforce development was late in
starting - very little effect. On public safety - very
significant impacts - high staffing turnovers. As
staff went to work for the pipeline construction,
wages skyrocketed - municipal wages up 40 percent over
a two-year period. Some increases in criminal
activity, basically indexed pretty much to populations
increases. Huge increases in road usage, both from the
population and from the project and those road usages
weren't just on the primary industrial routes. In the
health care - significant issues for the private
sector - very little in the public sector for health
care. Real improvements in health care availability
occurred during that period. Acute housing shortages,
particularly in Fairbanks and Delta, Valdez, right
along the pipeline corridor - utilities were way
overburdened. I expect Senator Seekins remembers the
comment by the municipal utility system in Fairbanks
in 1974 when they said they ran out of telephone
numbers and it would be two years before they could
get any new ones ready. It was just a way overburdened
system.
Over the three years, household income went up almost
60 percent; there were cost of living increases as
well over that period of time and population impacts
significant throughout the corridor. Delta Junction's
population up by over 25 percent, Valdez - 76 percent
increase, the Fairbanks North Star Borough -
relatively low at 15 percent. Most of that focused in
the city. The City of Fairbanks went up by 75 percent
over that period.
But the impacts were felt outside the pipeline
corridor. In Southcentral Alaska, you saw the Kenai
population go up by a third over that period of time -
Anchorage population up by 15 percent. There were
significant transportation challenges during the TAPS
construction that affected areas throughout the state.
This timeline is looking at 1973 - 1977. There was
even more impact post-construction. If you look at
cumulative impacts of oil and gas production, the big
impacts happened once the state started spending money
it was receiving once the line was completed and we
saw the oil price increase of 1979. That '79, '80,
'81 period had even more impacts, particularly on
education, but also on a lot of the other municipal
services and state services.
Looking at the gas pipeline as we've looked at the
socio-economic impacts, we're focusing right now on
what are the issues relative to population growth,
what requirements are there for workforce development,
how does it affect municipal and state infrastructure,
what are the impacts on law enforcement and emergency
services, impacts on education - although we expect
those to be fairly light, health and human services
and some other municipal impacts. Our study is based
on the application data from the producers, which
looks at construction costs, schedule, logistics,
workforce and materials shipment and the
infrastructure requirements that the producers have
laid out. However, there is certain information that
just isn't there in their conceptual model - where
certain construction and support activities take
place, where they would spend by community, which
really causes the impacts on the communities, or a
hard timeline. The starting date in their application
depends on action at the state and federal level.
We've had some challenges with the impacts of
confidentiality. We have had access to confidential
data and we cannot release any of that confidential
data, but some of that drives some key assumptions -
things like where is the freight movement, what's the
construction process, where are the camps and when are
they operating and what are the costs of some of the
components. We've used those to build our economic
model, but those underlying assumptions - so far many
of them are confidential ... we're trying to make the
model more transparent.... We can estimate some of
the regional impacts, but can't talk very much about
exactly where those occur, because it might allow
somebody to sort of reverse engineer what the
confidential data would be.
This project schedule is one that was contained in the
producers' application, however, I've added years to
it - that is if we assume that the governmental
frameworks were in place by the end of 2004, when do
the activities take place....
[He then explained the chart.]
Permitting completed by 2008, procurement for the
project beginning in '09 and preconstruction
activities beginning in 2009 with full construction
starting in 2010 and going through 2013, the actual
delivery of gas at the beginning of 2014. This is
based on their conceptual model without any changes
based on their 2001 study. There may have been changes
in their thinking since then, but that isn't available
as part of their application.
Based on what information we have and looking at
population impacts, we see about a 12,000 increase net
to Alaska population over the three-year construction
period. Some increases in services required by local
governments for that population and that increased
population and the other activities drives some other
impacts in addition to population-induced impacts,
which would be those that are wage inflation issues.
The net effect of the population based services
throughout the Railbelt and the construction corridor
and the areas that serve the construction, we've
estimated at $21 million in direct costs to local
government over the preconstruction and construction
period from those impacts that are population-driven.
The second general area is workforce. If we look at
direct and indirect and induced on an annual basis, an
increase of about 8,500 jobs with some very
significant opportunities for local hire during the
construction.
SENATOR HOFFMAN said a population increase of 12,000 seems low
compared to TAPS impacts.
MR. ROGERS replied that it does intuitively feel low, but TAPS
was far bigger as a project and there is a lot more opportunity
for local hire and contracts, which means less in the way of new
population coming in. If the local hire efforts don't
materialize, the impacts and numbers would go up.
On the workforce, the seasonal factors and the long
lead time that we have - if you look back at that
schedule with preconstruction beginning in '09 -
there's a lot of time to address workforce training
between now and then to assist the industry in keeping
the impacts of new population down and assist Alaskans
in getting the primary benefits out of the
construction process. We won't get all of the benefits
obviously, but there will be some significant ones.
Some local government costs in dealing with workforce
development - primary activities here, though, we
anticipate will be the industry, state and federal
governments - and our focus is on the municipal
impacts.
To give a sense - one of the things that is available
in the public data looks at the overall sequencing of
the craft trades during construction and the
conceptual model assumes peak workforce in the winter
months - actually January through March - is the peak
period line wide. If we look from Prudhoe to Alberta -
we don't have the data that's exactly to Alaska, but
looking at line-wide and taking a proportion and
looking at what the impact would be if you added it to
the current construction workforce.
This chart takes from the Department of Labor the
construction employment in Alaska in 2003 and lays
onto it the additional craft trade workforce that
would be required during a typical year of
construction. What you can see is there's an increase
in the construction workforce in those winter months
when there's a lot of unemployed Alaska construction
workers who potentially could take advantage of many
of those jobs. There's a second peak in the summer,
which is a challenge, because that's right on top of
our existing peak. This does not take into account any
of the support activities. This isn't camp staff,
contractor support, or any of the logistics materials
moving. This is actually just the craft demand, but
just looking at the proportion of it that is in those
winter months and thinking about the structure of
Alaska's existing construction, there are some great
opportunities to use Alaskans for that and that then
minimizes the need to import workers.
SENATOR LINCOLN said her concern is that outside workers are
continuing to be imported for the existing pipeline rather than
hiring Alaskans. Yesterday she heard that a contract can't state
a percent of residents to be hired because it's illegal. She
asked what he proposed to do to leverage the state's position to
use state businesses and workforce.
MR. ROGERS replied that Information Insight's role is to develop
specific policy level mitigating measures for that. There may be
ways to set targets in the negotiations and have certain
provisions take effect if those targets get reached. He was sure
there would be other measures.
SENATOR LINCOLN asked if he had seen the hard numbers from the
TAPS in terms of where we are today.
MR. ROGERS replied that he had looked at existing apprenticeship
programs in Alaska today and how long it takes to complete by
craft.
Most of them, if we start soon, we are in a position
to graduate sufficient journey-level workers to
address many of the crafts. There are some crafts for
which the skill level is beyond a beginning journey
level and we can't get there. There are several skills
that just aren't out there. An example cited by the
producers is the equipment that will be used to lower
the pipe into the trench - that's equipment - they'll
be using more equipment on this line than exists in
the world today and two to three times as many
operators for that size as there are out there today.
So, there's got to be a major training effort. The
question there is how much of that is going to be
Alaska-trained and non-Alaska-trained.... If we train
Alaskans for skills that are good for one project that
won't be replicated, what do they do post-project?
They have to look elsewhere to find work with their
skill level. So, there's a balancing act there. We
don't assume that 100 percent hire is going to be
possible even if we had all the training funds in the
world.
SENATOR ELTON observed that one of the impacts he saw from TAPS
was that people were leaving jobs in other communities around
the state for higher paid pipeline jobs and the communities had
to import people to fill their jobs.
MR. ROGERS replied that economically speaking, the higher paying
jobs would offset the entry-level jobs that would be created by
people moving up.
SENATOR SEEKINS echoed Senator Elton's concern and said that
local hire requirements can have a negative affect on his
business in Fairbanks, because his people are recruited and he
has to go out and find qualified people and train them.
MR. ROGERS answered that some of those things balance out. A
more complete socio-economic study would have to address those
impacts on the private sector. The seasonal chart indicates that
income may flow to families in terms of a member being able to
work year-round as opposed to just eight months.
REPRESENTATIVE GARA asked what kind of population increase he
envisioned if the local hire efforts can't be controlled.
MR. ROGERS replied that he hadn't calculated those impacts, yet.
A poor effort would require more recruitment and hiring from out
of state, which might have a secondary impact. People could hear
there are jobs and move here.
CHAIR SAMUELS remarked that another impact to the private
industry is that wages for local businesses will have to go up.
MR. ROGERS replied that would happen, but he estimated that it
would be far more moderate than during the oil pipeline
construction, although Delta and Tok might have those hyper-
numbers.
Transportation infrastructure is the single largest
cost item. That has to do with the size and weight of
the project loads that will be traveling on Alaska's
transportation infrastructure. The volume of the
direct traffic that's part of the project, as well as
population induced traffic in the villages and off the
main road system, issues of dust mitigation and the
need for railroad improvements.
When you think about Alaska's infrastructure - the
major routes for freight coming into the state - ports
of Anchorage, Whittier, Valdez, Haines, Seward - we
have the railroad, potentially Skagway all impacted
during construction, barges into Prudhoe Bay, the
Alaska Highway at the Canadian border - significant
freight movements across all of these. In addition,
potentially, Kenai, depending on competitive bidding
for modules, Kenai and Anchorage numbers could vary
significantly.
We've looked at the transportation maintenance needs
affecting local governments and villages and estimated
those maintenance needs at $14 million over the period
of construction. That's a very low number because the
biggest challenge comes post construction in any
rebuilding that needs to occur. We're still working on
how to get at those numbers, but this portion really
focuses on what's needed in a construction payment in
lieu of taxes to assist local governments.
In addition, we've got some major state transportation
infrastructure - a series of highways and bridges in
the Port of Haines, totaling $265 million. If all of
that is federal aid available, that's $26 million
state appropriation toward those highways and they
need to be in place by 2009. So, in order to get them
in place by 2009, that's going to affect the state
transportation improvement plan and the municipal
impact of that is it pushes back some projects that
people would like to see sooner rather than later to
the extent that the state chooses to make this
infrastructure available. The industry has said that
these really deal with load factors - some bridges.
There are a couple that are height factors on
overpasses and this is a core level that has been
publicly released. There may be other roads, bridges,
highways, ports in addition to this that would require
some enhancement prior to construction.
MR. ROGERS said for a sense of TAPS impact on road usage, he
picked a small street closest to his office in Fairbanks called
Wendell Street. The preconstruction rate was about 10,000
vehicles per day and peak construction rate was about 18,000 per
day. There would be similar, but smaller, increases throughout
Fairbanks, Delta and certain areas of Anchorage. Part of it is
traffic diversion from the highways that have the industrial
traffic and part of it is just population induced.
Law enforcement emergency services - we're basically
dealing with crime, traffic, subsistence resource
protection. We looked at both increased state trooper
presence and local police and VPSO. In addition,
increased use of emergency services for both paid and
volunteer fire and ambulance departments. Assuming
that a portion of this is troopers, $20 million in
costs to local governments, $4.5 million to the state.
If the troopers aren't there, it will be a higher cost
on local government and VPSO.
MR. ROGERS said the education increase is relatively minor.
During the oil pipeline, for every 47 workers, there was one
additional student. Increases in state funding as well as local
contribution add up to $13 million.
Health and human services are relatively low, about $4 million.
Health needs and emergencies are covered in the camps. About $12
million in wage inflation is estimated to vary by community.
Subsistence issues, including village liaisons, subsistence
research and monitoring preconstruction and during construction,
for a total of $5 million.
MR. ROGERS said this all totals about $125 million for the
preconstruction and construction periods from 2007 to 2014. That
compares to $202 million that would be paid from property taxes.
However the bulk of those taxes are paid in FY 2014 when
construction is completed.
The challenge is that while the numbers are relatively
comparable, if you exclude that amount after
construction is completed, the municipal impacts hit
before the tax impacts would be there and they hit
differentially. The City of Fairbanks has no pipeline
within city limits, but is one of the most impacted
cities. So, a pure tax regime does not address the
social and economic impacts. In addition, in the
unorganized borough, there is not a way of addressing
those needs today. Of those impacts, about $84 million
would be the municipals' share and $41 million the
state's share, which really is focused on the roads,
education and on police.
There are some offsets to these municipals costs. New
construction of property that won't be tax exempt -
warehouses that aren't direct pipeline - that drives
some new revenues to municipalities. It can be used as
an offset. We've got a little more work to do to
complete those offset numbers.
I'll run quickly through the subsistence impacts and
socio-cultural. The issues there really have to do
with how does a project impact the availability of
resources, the access to those resources and
competition for the resources. Federal law would
require certain mitigation measures and some
monitoring and enforcement of those impacts. In the
North Slope, those impacts would have to do with
access, competition and disturbance - some cumulative
impacts. North Slope impacts will be greater than what
we've cited here because this does not include a gas
treatment plant or upstream facilities, also impacts
in the northern Interior and upper Tanana villages in
terms of competition for resources, harvest levels and
some cultural resource issues in the Interior.
The activities that affect those have to do with new
road construction, truck traffic, the activities
around a construction camp, and those things that
happen during development or during some of the
upgrades required to our infrastructure.
In total - impacts on villages - wage, employment,
changes of structure of villages during the period of
construction with a shift in focus from subsistence
activities. If the population that would have been out
hunting this week are instead working for wage income,
there's less resource to share with elders and others.
We see some population shifts as occurred during TAPS
and just as in the urban areas, some changes in the
social fabric with effects of drugs and alcohol as
there is more cash income.
Finally, some management and regulatory issues are out
there. To close, our work is focused on the municipal
impacts. We've just about finished the work on the gas
pipeline portion, working on the gas treatment plant.
Upstream, as other applications come in, their impacts
may be different from those of the producers'
pipeline. We'd possibly also be looking at those....
Our final report [is] due to the MAG at the end of
September.
SENATOR LINCOLN referred to the population chart and asked him
if he had considered the shifting population in-state.
MR. ROGERS replied that his model looks at net impacts in each
region based on the producers' conceptual model and he couldn't
be precise about the effect of additional regional movement.
12:10 - 1:15 - recess
CHAIR SAMUELS called the meeting back to order and the committee
moved to the next presentation by Robert Cupina, Deputy
Director, Office of Energy Projects, Federal Energy Regulatory
Commission (FERC), and John Katz, Assistant General Counsel for
Energy Projects, FERC. Chair Samuels informed members that Mr.
Cupina's office is responsible for processing applications for
the construction and operation of interstate and international
natural gas facilities including LNG and licensees for non
federal hydro-electric projects as well as managing the dam's
safety program. Mr. Katz is senior counsel at FERC where he
specializes in hydroelectric licensing and natural gas pipeline
certification matters.
PANEL DISCUSSION ON THE REGULATION OF GAS PIPELINES, GATHERING
LINES AND PROCESSING FACILITIES
MR. CUPINA said that natural gas is a critical component of the
nation's energy mix and informed members:
The Department of Energy predicts that growth and
demand over the next several decades will require a
significant increase in gas production and delivery
capacity. Supplies from the Lower 48 sources, imported
LNG and Alaskan gas, will all be needed to meet
projected demand. An application to construct and
operate an Alaskan pipeline may be filed with FERC
under either the Alaska Natural Gas Transportation Act
(ANGTA) or the Natural Gas Act (NGA). We have no
application before us right now and we would encourage
sponsors to make a single filing to avoid time-
consuming duplicative processing and potential
litigation. Whatever form a proposal to us takes, we
are positioned to review such a project
comprehensively and expeditiously so that gas can
reach the market in a timely fashion. Alaska gas
pipeline provisions in the national energy bill will
ensure such timely completion by clarifying that NGA
proposals, to compete with ANGS, (A) and (D) be
considered by providing that FERC is the lead agency
and by imposing strict processing timeframes.
So, our comments today and our answers are based on
the commission's current competitive market non-
subsidization approach to major new pipeline projects.
These open-access policies under which shippers are
able to buy gas directly from production areas and
separately obtain transportation capacity on
interstate pipelines should serve the interests of the
state of Alaska as well as of all other shippers. At
the same time, we are mindful that the size, scope,
and importance and uniqueness of an Alaskan pipeline
as well as certain provisions in the National Energy
Bill may call for some variance in that approach to
insure its development.
SENATOR GRETCHEN GUESS said that it has been implied that FERC
doesn't consider rolled-in tariffs, but only considers
incremental tariffs and asked if he could comment on that.
MR. CUPINA replied:
For a new pipeline, we'd just be talking about an
initial rate. So, at that juncture you're not really
talking about rolled-in or incremental. It's usually
when there's an addition to that system or some
expansion that the issue of how to recover the cost
for that expansion arises. The policy has been in
general for an expansion - we would consider rolling
in, in fact we require rolling-in when [END OF TAPE
04-25, SIDE B]
TAPE 04-26, SIDE A
MR. CUPINA continued:
The new rate would be higher than the existing rate
that is incrementally priced. So, there's roll-in when
it benefits the existing shippers by lowering their
rate.
MR. KATZ added:
As you probably know from reading [the proposed
federal energy bill] and its impacts with regard to
expansion and other issues... the draft energy bill
required that if the commissioner was going to require
an expansion of an Alaska gas pipeline, that it was
required by the proposed law to insure that the rates
established would not require existing shippers on the
pipeline to subsidize expansion shippers. So, that is
fairly consistent with the commission's existing
policy.
CHAIR SAMUELS asked if the ability to roll in tariffs could be
contracted away. "If in the Stranded Gas Act between Alaska and
the applicant wanted to have rolled in tariffs, how would FERC
view that?"
MR. CUPINA asked if he was talking about all expansions.
CHAIR SAMUELS replied yes - just in the instance:
Let's say that the price was going to increase the
tariff, not just decrease, could it be contracted away
or how would FERC view the ability to contract away
the ability to have incremental tariffs as opposed to
mandating rolled-in tariffs?
MR. KATZ replied that it depends. The right to not have rates
increased is a right of the existing shippers, not a right of
the pipeline. He realizes that in some scenarios in Alaska the
shippers are the pipeline, so that might be different than a
typical case.
In a typical case, I don't know that the commission
would allow the pipeline to contract the rights of
shippers. In a case where the shippers and the
pipeline have the same identity, it might view it
differently.
CHAIR SAMUELS indicated there were no further questions for FERC
and said that Margery Fowke would testify next.
NATIONAL ENERGY BOARD'S REGULATION OF THE CANADIAN SEGMENT(S) OF
AN ALASKA NATURAL GAS PIPELINE
MS. MARGERY FOWKE, National Energy Board, Canada, said she would
speak on two matters with respect to the board's jurisdiction of
practice - those are incremental and rolled-in tolls and the
board's ability to order expansions of facilities in certain
cases.
I thought I'd spend a few moments to talk about the
board's mandate and jurisdiction and processes for
anybody who might not be familiar with the National
Energy Board (NEB). The board has both regulatory and
advisory responsibilities, which have changed little
since our inception in 1959. We have jurisdiction
regarding the certification of pipelines, tolls and
tariffs, construction of pipeline and ongoing safe
operation of the pipeline and the ability of the board
to require a pipeline company to provide facilities
for other shippers. The board also regulates the
export and import of natural gas and oil, the export
of electricity, the construction of international
power lines, the exploration on federally regulated
lands - that's offshore and north of 60, and the board
provides advice to the federal government of Canada.
It's not that it's an exhaustive list, but it's the
highlights of what we do.
This map shows generally the natural gas and oil
pipelines that are regulated by the board, the ones in
Canada, of course. The board regulates over 27,000
miles of pipelines, inter-provincial and national
pipelines. The board is a quasi-judicial tribunal with
all the powers of a court of record. We have nine
full-time members and the Act provides for temporary
members as well. We currently have eight full-time
members. A quorum of the board to sit on most hearings
is three members and the process at a board hearing
would be similar to what most of you would be familiar
with - witnesses are sworn, they're cross examined by
parties of opposing interests, the board counsel and
the board ask questions and then there's final
arguments at the end of the hearing.
When an application for the construction of a pipeline
is filed, the Act requires that we have a public
hearing and that that hearing be oral. Section 52 of
the Act sets out some of the things that the board
must consider when we look at an application for a
pipeline such as supply, markets, economic
feasibility. With respect to economic matters, one of
the main focuses of the board right now is with
respect to third-party impacts. In addition, one of
the main issues these days is environment. With
respect to a pipeline of interest to you, the Canadian
Environmental Assessment Act would apply. There would
likely be a joint review panel, which would involve
territorial, federal, including the national energy
board and aboriginal representatives. I can't say with
any certainty what the process would be for an
application that could be filed for a pipeline coming
out of Alaska, but I can tell you that the model that
is currently being used for the Mackenzie project is
that there is a joint review panel, which will
consider the environmental matters. The board has one
member that's appointed to that panel and I believe
there are eight members on it.
The board at the same time will conduct a hearing into
all matters within its jurisdiction and will
incorporate the joint review panel with respect to
environment. The member that's on the joint review
panel will report back to the board on it. Once all of
the hearings are complete, if the joint review panel
allows for it and the NEB is of the view that it
should be approved, then a certificate of public
convenience and necessity would be issued. This allows
the pipeline company to construct the pipeline and
operate it.
In terms of our working with FERC, the board has
recently entered into a memorandum of understanding
(MOU) with FERC and I've provided that at tab 3. The
parties recognized that it's in the public interest to
coordinate their efforts, that there may be cases
where coordinated reviews may be considered, that
timing should be coordinated and the parties agree to
notify the other party if there is an application to
it where the matter is being heard by the other
tribunal.
I'd like to move to toll regulation by NEB. When new
facilities, either greenfield or an expansion, are
being applied for, the board usually considers tolling
matters at the same hearing. The requirement in the
Act is that tolls be just and reasonable and that they
be charged equally to all persons for traffic of the
same description over the same route in substantially
the same circumstances. That is in section 62 of the
board's act.
The board can set tolls using a number of different
methodologies. We can use the traditional cost of
service methodology or any other to set tolls
ourselves. Tolls can also be negotiated or they can be
subject to a settlement. The board is very accepting
of settlements. We have settlement guidelines, which
can be found on our web and they require that all
parties have a chance to participate in the
settlement. A settlement can provide for unique and
different arrangements and most new construction of
pipelines in recent history have had tolls that are
either negotiated in part or subject to a settlement.
The only requirement the board has is that we be able
to find that the tolls are just and reasonable. Pretty
much everything else is up for grabs.
The board has broken down the pipeline companies that
it regulates into two different groups. Group 1
companies are the larger companies, such as
TransCanada Pipelines Ltd., Westcoast Energy Inc. and
Enbridge. Group 2 companies are the smaller pipelines
and they are regulated on a complaint basis.
I was asked to address the frequency of toll hearings
and whether the pipeline has the option or the
obligation to refile its tolls in the face of
declining costs. The frequency of toll hearings really
varies. For some group 1 companies, if they can't come
to a settlement with their shippers, it's virtually an
annual event and that's the case with TransCanada
Pipelines - the largest pipeline that we regulate.
They are right now pretty much annually before us.
At any time after a board decision, the pipeline or an
interested person can file a request for a review of
the board decision. One of the grounds for the review
is changed circumstances. So, if there were declining
costs, a review application could be filed with the
board. The board would then have to examine it to
determine whether a review should be held and, if so,
whether the previous decision needs to be changed.
Some pipelines have multi-year settlements and in such
a case, we wouldn't expect the company or the
participants to be back before us during the term of
that settlement. In the settlements, usually changes
that could come up through the term of the settlement
are taken into account by some cost sharing factor or
risk sharing factor. If the parties to the settlement
were to agree that they needed to reassess the
settlement in the middle of the term, it could be done
and it is right now being done in one of the oil
pipelines. I think, as well, my view, if you are in
the middle of a long settlement and it could be shown
that the tools were no longer just and reasonable,
that you would have an argument to come back to the
board and have it look at the settlement again. The
onus would be on the party trying to bring the
settlement back towards the board to show that it
should be changed and that the tolls are not just and
reasonable, but I think it could be done.
If you're talking about a group 2 company, they're
regulated on the complaint basis and if there is a
third party shipper, tolls have to be filed with the
board, but it doesn't examine them to any great extent
unless there is a complaint filed. So, if there were
changes in the costs to the pipeline and a shipper
wanted to file a complaint to request that the board
look at those tolls, the board could do it at that
point in time. So, in short, while there's no
obligation on a company to file new tolls in the face
of declining costs or any other change circumstances,
there are means by which the pipeline or another
interested party could bring the matter back to the
board for consideration of the issue. As well, the
board could of its own motion bring the matter up for
discussion.
I'd like to turn now to the question of rolled-in
versus incremental tolls. Let me start by saying that
there are no rules at the NEB on this issue. There's
nothing in the Act; there's nothing in the regulations
and we have no policy that we have issued with respect
to rolled-in versus incremental tolls. There are some
past decisions where the board has considered the
matter, but I'd like you to note that we are not bound
by past decisions and, in fact, we must consider every
relevant issue in a new hearing. So, we can't rely on
past decisions alone. We have to reexamine issues. I'd
also like to note that the seminal cases in this issue
were in 1987 and 1989; so there's not a lot of
anything recent.
Any expansion of a pipeline out of Alaska would be
fairly far down the road and we all know, there's a
lot of unanswered variables that could be at play. We
also don't know what the regulatory environment would
be. I've seen a lot of changes in my time at the
board; I foresee that there will be changes in the
next 10 to 15 years. I can't tell you what the board
would do with an application at the time of an
expansion in terms of rolled-in versus incremental
tolls, but I can tell is what the board's past
decisions have said and I can tell what some of the
considerations that the board has taken into account
in making those decisions.
There have been a number of decisions, but
unfortunately for our purposes, none of them are
particularly recent. I'm going to focus on GH-2-87 and
GH-5-89, which are TransCanada hearing decisions and
those are the most helpful decisions on the matter.
I've also included references here to the Westcoast
Energy Inc. decisions, but Westcoast is a very
different system. It includes gathering lines and
processing plants; it has historically had a much
different tolling regime with a lot of specific tolls
for specific services. So, the Westcoast decisions
aren't particularly helpful. I've included the
references for some oil pipeline decisions -
Interprovincial Pipe Line Inc. and Trans Mountain Pipe
Line Company Ltd. are both oil companies - and I'll
briefly touch on those. All of the board decisions are
on the website. The last two numbers in the decision
are the year of the decision. So, GH-2-87 was a
hearing that started in 1987. I've included behind tab
4 some excerpts for our decisions from GH-2-87, GH-5-
89 and GH-5-94, the Westcoast decision.
I'd like to discuss the specifics of just a few cases
and what I think are the board considerations that run
through these decisions. In GH-2-87, it was a
TransCanada facilities application. The board decided
that the rolled-in method of cost allocation and toll
design would be appropriate for the proposed
facilities. The board looked at practical and legal
considerations. The board made it clear that existing
customers do not possess acquired rights to enjoy the
use of the older facilities at lower embedded costs.
The payment of tolls in the past did not confer any
benefit beyond the provision of the service at that
time. The board didn't equate those who paid with the
service with those who paid for facilities. The board
also endorsed the concept that TransCanada is an
integrated system. In the board's view, the new
facilities contributed to the capacity and integrity
of the system as a whole. Therefore, the board
determined that the toll should be charged on a
rolled-in basis. However, the board also found that if
the services required by only a limited number of
shippers and the facilities could be separately
identified from the integrated rate base, that the
principals of cost-causation and user pay would apply
to insure that there was no undue cross subsidization
by other toll payers. Therefore, in this hearing, GH-
2-87, the provision of additional delivery pressure at
any delivery point would be recovered through stand-
alone tolls.
In GH-5-89, which was the biggest TransCanada
expansion that we've ever considered, the board
considered the rolled-in versus incremental tolling
methodology. The board reaffirmed its findings in GH-
2-87 that the previous toll-payers have to acquire
rights. They can't be exempted from a toll increase
simply because they paid tolls in the past. The board
found, again, that on completion, the facilities would
be integral to the TransCanada Pipeline system. It
looked at cost causation and found that the aggregate
demand of all shippers gives rise to the need for
additional pipeline capacity. The board looked at
economic efficiency and stated that rolled-in tolls
would send appropriate price signals. The board found
that incremental tolls would create economic
distortions because existing shippers would not be
exposed to the appropriate market signals. The board
was of the view that the magnitude of the expansion
didn't justify changing the methodology nor did the
riskiness of the market. It stated that factors such
as size, cost of impact on tolls might be factors that
the board would take into account when determining
whether or not to authorize the construction of the
facilities, but they didn't justify discrimination
among shippers on the basis of when they commenced or
would commence paying tolls.
The one Westcoast case that I did want to mention is
GH-5-94 and in that case, the board found for rolled-
in tolls placing significant weight on the extent to
which the proposed facilities would be integral to the
Westcoast facilities in that specific area. The board
stated that in its view shippers didn't pay for
specific facilities; they contracted for specific
services.
There are a few oil pipeline decisions on rolled-in
tolls. In all of the Interprovincial Pipe Line
decisions, the board found that the toll should be
stand-alone, not rolled-in. This was based on the fact
that the facilities would only be used by a small
number of shippers. Not all of the shippers are not
all commodity groups. Therefore, the principles of
user pay would be best reflected by stand-alone tolls.
The board found there is no unjust discrimination in
shippers, because all those using the specific
services were being treated the same way. The board
also noted the need to minimize cross-subsidization
and to allow for business decisions to be made on the
basis or appropriate price signals.
The Trans Mountain decisions that I referred to
allowed all or part of the expansion to be rolled-in
where it found the facilities would be for use of all
of the shippers or where it would enhance the overall
efficiency of the entire system.
So, from all of these decisions, I've pulled what
seemed to be in my view, the important considerations
that the board has taken into account. I would stress
to you that this is not a board pronouncement. The
board has not issued anything on it. I would also
point out to you that although the board has stated in
numerous decisions that it supports the principles set
out in the GH-5-89 decision, any time the issue of
tolling methodology comes up, it must be addressed on
a case-by-case basis.
The second matter that I was asked to focus on was the
ability of the board to order the provision of
facilities. Subsection 71(3) of the NEB Act allows the
board to order a company to provide adequate and
suitable facilities for the transmission of, in this
case, gas. There are two tests in this action; the
board has to consider it necessary and desirable to do
so in the public interest and the board has to find
that no undue burden will be placed on the pipeline
company by requiring the company to do so. This
section has been very infrequently considered.
The few decisions that we have had that consider this
section don't provide much guidance for us on how the
board would consider an application now. I've provided
the excerpts from these decisions behind tab 5. In the
first case that I could find, GH-3-86, the board
considered an application by Cyanamid Canada Pipeline
Inc. to construct facilities to require TransCanada
Pipelines to provide interconnection facilities. If
you look at that decision, you'll note that they're
talking about section 59 instead of section 71 - just
a change of numbering the late '80s. The board found
that the application by Cyanamid to construct its own
facilities should be approved and that the approval
would have no significance if the board weren't
prepared to grant the interconnection. Therefore, the
board found the interconnection to be in the public
interest and found there would be no undue burden on
TransCanada. That's just about the extent of the
board's reasoning. It was very short on the section 71
issue and doesn't provide as much guidance on the
matter. It's also the only case I could find where the
board actually ordered the interconnection of
facilities.
In MH-2-88, the board was considering both subsection
71-2 and 71-3; 71-2 is the ability of the board to
require a gas pipeline to receive, transport and
deliver gas. In this case, the board found that the
pipeline company could transport the gas with the
current configuration of its system and therefore, it
found it unnecessary to order a 71-3 to construct
additional facilities.
In GH-4-91, it was again a TransCanada facilities
application and the board heard an application under
71-3 from a prospective shipper to provide services
and facilities. The board was not convinced that the
applicant had demonstrated need for the facilities and
therefore denied the 71-3.
Finally, in GH-3-96, it was again an application under
both 71-2 and 71-3. The pipeline company was opposed
to providing the service, but admitted on the stand
that it could do so without additional facilities. The
board told them that they had to provide the service,
but didn't require them to construct any facilities
under 71-3.
So, the important considerations that I take from
those four cases are that first, there must be a clear
demonstration for the need for the facilities and
second, that the transportation can be provided by the
pipeline company on its existing facilities, the board
will not order new facilities to be constructed. There
has been no discussion in any decision of the tests
that are in 71-3. In my view, if an application came
forward now, the board would have to be looking at
what those tests are and what they mean and there
would probably need to be some discussion of them. I
know in recent hearings where there has been
discussion on the record about 71-3, there has been
quite a bit of debate about what the tests mean. The
board has not found it necessary to discuss in any
reason. So, we don't know what the board's view is,
but we do know that there has been a lot of discussion
on it.
That's all I was intending to present today. I hope it
has been of some assistance to you....
CHAIR SAMUELS said he would eventually have a lot of questions
on how the two regulatory bodies, FERC and NEB, work together
when the pipeline crosses the border, but he wanted to continue
with Dave Harbour.
MR. DAVE HARBOUR, Chair, Regulatory Commission of Alaska (RCA),
introduced Judge Jan Wilson, Administrative Law Judge, RCA, who
specializes in the application of oil and gas pipeline
regulations, particularly under AS 42.06.
With your approval today, what I'd like to do is offer
our panel participation as citizens. The reason for
this is the decisions we make and the statement we
make in public are the product of due process hearings
and a legal record. So, we don't for a moving target
like this express approval on the commission on what
we say. We'll do our best to help today with your
deliberations. Our goal is to provide you with this
brief opening statement and then attempt to personally
help with the questions you may have.
Bonnie Robson advised us today that we'd be talking
about general regulatory issues affecting the Alaska
gas pipeline. I think the statements you've got are
going to be most to the point of the interests of this
committee. However, I think I can provide a few points
that might assist and round out your understanding.
First, the Alaska Pipeline Act establishes our
commission's pipeline jurisdiction throughout the
state except as it might conflict with federal
jurisdiction. The legislature specified in AS 42.06
that the Alaska Commission has jurisdiction, 'of
intrastate transportation of North Slope natural gas
through a North Slope natural gas pipeline.' So, that
is there.
Second, in chapter 15 of USC 15, we find language
dealing with the regulation of interstate pipelines
and a special note that federal regulation and matters
relating to the transportation of natural gas in
interstate and foreign commerce is in the public
interest. So, that will be regulated by the federal
government, but the jurisdiction is limited and does
not include, 'local distribution of natural gas or to
the facilities used for such distribution'. Federal
jurisdiction also doesn't apply to 'persons engaged in
the transportation in interstate commerce or the sale
in interstate commerce for resale of natural gas
received by such person from another person within or
at the boundary of a state if all the gas so received
is ultimately consumed within the state.'
Number three - jurisdictional decision. Where specific
projects are involved, federal and state regulators
are similarly situated. That is to say we can't make
findings and issue decisions except when we have real
applications, fact finding, a complete record, and an
opportunity for all parties to have their due process.
I think all the regulatory agencies that you hear from
today have that type of a concept in common....
The RCA and the FERC have anticipated that an Alaska
gas project could produce jurisdictional questions and
we've created a memorandum of understanding (MOA).
It's very similar in wording to the MOA in the pack
Ms. Fowke handed to you from the NEB - between it and
FERC. That is to say we don't have a specific
application; we don't have specific projects to deal
with, but there is an anticipation by the agencies,
the FERC, the NEB, and the RCA that this is coming and
that we need to work and will work effectively
together to resolve jurisdictional questions.
A number of conversations we've had with Chairman Wood
of the FERC and Commissioner Brownel have verified
this. I think that the members can take comfort in
that.
Finally, I draw your attention to the energy bill. Mr.
Cupina made some reference to it earlier and Mr. Katz
is highly conversant with it, but while several recent
versions are interesting, I'll refer to the S 1005
version, not the whole 215 pages, but section 131
dealing with the Alaska Natural Gas Pipeline Act. I
want to draw your attention to several provisions
relating to jurisdiction that you've discussed at this
meeting that should give Alaska comfort.
Number one, Section 133 requires the FERC to provide
by an open season process support for exploration,
development and competition - secondly, to provide for
capacity beyond the initial capacity and access for
gas other than from Prudhoe Bay and Pt. Thompson.
Second, the act requires the certificate holder to
evaluate in-state needs including tie-in points for
in-state access.
Third, the state can request that the FERC hear its
concerns for access to the pipeline for transportation
of royalty gas for local and state consumption.
Fourth, Section 135 provides for expansion of the
pipeline in appropriate circumstances.
Fifth, Section 138 anticipates local distribution of
North Slope gas, additional pipelines and rate
coordination with us, with Alaska. Maybe the best
contribution I can make to your afternoon is to give
you a memorandum that Bob Loeffler gave me a couple of
days ago anticipating this event. Bob is a lawyer; I'm
not a lawyer. Bob, from his viewpoint representing the
state, has summarized this jurisdictional question in
a two-page memo. I think to some rights the FERC and
RCA are in a good position to efficiently coordinate
processes as a project takes shape and an actual
application is filed. I said an application; I'm kind
of reflecting the sentiment that Mr. Cupina gave you
earlier - the admonition to us all that a single
application will be much more timely dealt with than
multiple competitive applications through a regulatory
process. Thank you, Mr. Chairman. Judge Wilson and I
will be happy to answer any questions that members may
have.
CHAIR SAMUELS asked if NEB ordered an expansion and FERC can't
order an expansion, would that give Canadian explorers access to
the pipe south of Alberta and then because that expansion was
filled up, would that cut off Alaskan explorers.
MS. FOWKE asked if he was assuming it was Canadian gas coming
in.
CHAIR SAMUELS said yes and clarified that he was asking if the
Canadian companies would have an advantage because of their
regulatory environment. "Has that happened before?"
MS. FOWKE replied that it hasn't happened before. The pipelines
that are in existence now originate in Canada and the suppliers
are all Canadian.
Because we have all rolled-in, one producer is not in
a better situation than another producer, because they
all pay the same toll. If your scenario is that if you
had a pipeline coming from Alaska down through Canada
and there was Alaskan supply coming through it and
then there was a pool discovered in Canada that was
then going to come on? Was that your scenario?
CHAIR SAMUELS replied yes.
MS. FOWKE replied:
I guess the producers that are producing in the United
States and Alaska and the Canadians producing in
Canada would pay the same rate for the Canadian
portion of the pipeline. So, the toll that they would
pay in Canada, assuming that the pool that you're
talking about is relatively far north - if it's south,
you might have a different issue - the toll that they
would be paying would be the same or essentially the
same depending on your tolling regime. So, they
wouldn't be discriminated against in terms of the
Canadian toll that's being paid.
CHAIR SAMUELS asked Mr. Cupina to respond.
MR. CUPINA replied:
I don't think there's any discrepancy in that if we
had an incremental expansion and, at the same time in
Canada they had a rolled-in expansion, those two
different rate regimes are applied. I'm not sure why
they would have to be uniform.
MR. KATZ said he heard the question to be what happened to
producers who are not initial shippers on the pipeline if gas
was later developed and was ready to move and the pipeline
declined to move that gas. I think you're correct that in the
absence of the energy bill, the commission would not have the
authority to require the expansion of that pipeline.
SENATOR ELTON added that the other instance is expansion of
capacity in Canada that would preclude expansion of capacity at
the northern part of the Alaskan component of the line. He said
he'd be interested in knowing how the two regulatory bodies
would deal with that issue.
MS. FOWKE asked how an expansion in Canada would preclude
expansion in Alaska.
SENATOR ELTON was assuming that authorized expansion of capacity
in Canada would limit expansion capacity for Alaskan producers.
CHAIR SAMUELS asked if the expansion caps out in Canada.
MS. FOWKE replied no, the engineers just get more and more
excited about what they get to do. The cheapest expansion is
going to be with compression; then you start looping the line,
which might have economic restrictions. There aren't any
physical restrictions.
I don't see how an expansion in Canada would preclude
an expansion for Alaskan shippers. If there was a pool
to be developed in Canada, in the Yukon, that would
then ship on this same pipeline that was bringing
Alaskan gas down and if that somehow captured some of
the cheaper expansion - the compressors - then it
wouldn't prohibit or restrict our ability to provide
for more facilities if there was more gas being
produced in Alaska that needed to be shipped and if it
was in the public interest to provide for expansion.
SENATOR ELTON asked, "Doesn't there have to be a protocol
between FERC and NEB to accommodate U.S. producers for capacity
expansion that would be conducted in Canada?"
MS. FOWKE replied:
It may well be that we work out some kind of a
protocol, but we can't influence the other tribunal's
decision. FERC can't influence what our decision is;
our decision has to be in the Canadian public
interest. The FERC's decisions have to be in the
American public interest.... I can tell you that in
all the history that's gone on, the pipelines have
managed to meet at the borders and the expansions have
been seamless. And there have been major expansions.
The GH-5-89 expansion was a $2.6 billion expansion in
Canada that went down into the States. It was huge at
the time and it was seamless. They approved what they
needed to approve; and we approved what we needed to
be approved. So, it's always happened....
MR. KATZ added, "That's the situation where the MOU between the
commission and the NEB would come usefully into play, because
while I absolutely agree with what was just said with respect to
each tribunal needing to make independent decisions. The MOU
provides the framework where the two entities could work
together developing the records they need and gathering
requisite information and one would hope that having done that,
the logical conclusions would be reached by both entities if
they had the same information before them.
CHAIR SAMUELS said he hated to beat a dead horse, but the fear
is that Canadians would take advantage of the cheap expansion
rolled-in. Alaskan explorers would come on later with the
incremental tariff and the exploration dollars flow to Canada
then as opposed to flowing to Alaska.
MS. FOWKE responded that the tolls are just one of the issues
that the explorers have to look at. However, in the scenario
where the Alaskan gas were to come on and have more expensive
expansion in Canada, because a pool in Canada was taking the
cheaper expansion, there would still be rolled-in tolls in
Canada.
The producers who are producing in Canada that came on
stream with the cheaper expansion would still be
facing an increase in toll, the same increase as the
producers that are producing in Alaska would face.
MR. CUPINA said he thought the timing of when to lock in
capacity would be a market decision that the shippers or
producers would have to take into consideration.
REPRESENTATIVE MIKE HAWKER said there have been references to a
25-year old treaty between the RCA and NEB.
MS. LOWKE replied that would probably be the Northern Pipeline
Treaty, which is what preceded the Canadian Northern Pipeline
Act dealing with the Foothills project. Since there are
outstanding issues on that matter, she wasn't able to discuss
it.
REPRESENTATIVE HAWKER said a statement was made by TransCanada
that they have the right to build any pipeline that would be
built in Canada. It was in response to sponsors in Alaska that
want to be part of building a pipeline in Canada. He asked if
TransCanada has a preemptory right.
MS. LOWKE replied, "That is their view."
REPRESENTATIVE HAWKER said that Alaska has a sponsor group that
is interested in building a pipeline across Canada.
TAPE 04-26, SIBE B
REPRESENTATIVE GUESS asked what currently prohibits the RCA from
having an approach like the NEB on taking it on a case-by-case
basis on whether a roll-in on incremental tariff is in the best
interest.
MR. CUPINA replied that it's the commission's policy choice,
which has been in effect since 1999, and maybe since 1995 as
opposed to any inherent bar. There is a written commission
policy statement that spells that out, nothing at the federal
level. "The statute requires what is called just and reasonable
rates. Throughout the history of the Natural Gas Act, that's
constituted different types of rates and different types of rate
designs.
REPRESENTATIVE GARA observed that nothing jumps out at him as a
problem under existing Canadian law that would prevent a fair
transportation of Alaska gas.
What is the guarantee that we have that at some point
when a large new reservoir of Canadian gas is found
that a rule wouldn't be adopted in Canada that would
say all pipelines that go through Canada have to allow
for a 50 percent transportation of Canadian gas? It
would take a law change in Canada. Should we not even
consider that something like that might ever happen?
MS. LOWKE replied that it's possible.
The North American energy market is so integrated and
the NEB is so aware of that as is our parent
department, the Natural Resources Canada. I guess 10
years ago who thought we were going to be seeing $50
oil! I find that really hard to imagine. We've got
NAFTA, too. So, I'm sure there's some arrangements in
NAFTA that talk about this....
REPRESENTATIVE CHENAULT considered that the same rules could
pass that would only allow us to accept so much from Canada
CHAIR SAMUELS asked if NEB chose to order an expansion and FERC
chose not to order an expansion, even though they had the
ability to, it can only order expansion on the pipeline that is
physically in Canada and FERC could only order it for what is in
the U.S. He asked if that issue would be in the MOU between the
organizations and how many political battles are there between
the two now.
MR. KATZ responded:
I don't think we've ever had any such and as a
reality, no shipper is going to sign up to pay a rate
if they don't know that their gas can get to market.
So, I think it would be exceedingly unlikely that
shippers would sign up for a rate and start paying
reservation charges or whatever else if they weren't
assured that there was a way to get the gas through
Canada....
MR. CUPINA added:
In our experience...there have been a number of cross-
border projects...and they match up because the
commercial realities required that they match up. We
have a good relationship with the NEB and we'll
continue that, but that's not the only grounds on
which these types of communications will occur.
REPRESENTATIVE HAWKER said that a certain Canadian interest
believes it has grounds for a position that says they have an
exclusive right to construct any gas pipeline that might be
constructed and asked if it was across Canada or just in a
certain province.
MS. LOWKE replied that it was in Alberta going down to the
existing Foothills pipeline and through the Yukon.
REPRESENTATIVE HAWKER asked how that issue could be resolved.
MS. LOWKE replied:
Absent the federal government coming out with some
kind of policy that would say something, which they
have not done or an act that would say that they would
have exclusive authority and making it absolutely
clear that they do. I assume the matter would have to
come before the NEB either through the Foothills
proposal that might require some modifications to what
they have or through another proponent applying to the
board and then Foothills could, if they wanted at that
point, challenge the board's jurisdiction to hear the
matter.... If an application is filed with us by any
of the other groups, we will examine it to determine
whether it is complete and absent anything else, we
will set it down for a hearing. We can tell you that
there have been meetings at the NEB with the other
groups. The producers as a group has been in talking
to us. The board has not said to them and we have no
grounds to say to them that we will not consider their
application.
REPRESENTATIVE HAWKER asked if anyone had filed a claim or
protest with the NEB.
MS. LOWKE replied no and she didn't think any filings were
imminent. She could only think of one circumstance in the last
20 years when expansions didn't go through, which was because
market conditions changed - the Millennium Pipeline. The FERC
approved it and NEB was still in the process, but the project
just cratered. A lot of expansions had happened for oil
pipelines and the regulatory agencies managed to come to the
same decisions.
MR. CUPINA added that he wouldn't characterize the Millennium
project as having cratered. Millennium is working with other
agencies that have related statutes to FERC's and it remains to
be seen where those discussions lead. There is talk that
Millennium would amend its project.
MS. LOWKE said her point is that there were no disparate FERC
and NEB decisions with respect to the pipeline.
MR. CUPINA agreed.
PANEL DISCUSSION ON THE REGULATION OF THE PHYSICAL AND ECONOMIC
WASTE
COMMISSIONER DANIEL SEAMOUNT, ALASKA OIL AND GAS CONSERVATION
COMMISSION (AOGCC), said he would begin by giving an overview of
a preliminary study done by the owners and how AOGCC fits into
that. He also would talk about the statute and the orders that
would be appropriate to the North Slope gas project and give
more details about a review of a study the owners did to
determine what kinds of volumes to expect from major gas sales
out of Prudhoe Bay, which resulted in an estimate of what the
impact would be on liquids recovery as a result of bringing the
project on. He would then recommend what future work would be
needed.
If Prudhoe Bay were to be developed for oil only,
recovery would be over 13 billion barrels of
hydrocarbon liquids. That includes oil condensate and
natural gas liquids. Currently, the cumulative
production from Prudhoe Bay has been over 11 billion
barrels, which exceed the original 1977 reserve
estimates by 2 billion barrels. The field has been
managed very well - very efficiently. It has been a
world-class operation up to this point. Gas sales will
add about 3.5 billion barrels of oil equivalent. You
can put gas on now or 30 years from now probably and
you're not going to have any conservation problems
with bringing the gas on. There is a question about
the timing and rate that would affect how much oil
you're going to recover.
Just a short technical explanation of where the
concerns might be - this is a cartoon of a slice
through Prudhoe Bay field. It can be any oil and gas
field in the world. But normally, oil field practices
produce as much of the oil as possible and then
produce the gas later - after you're done with the oil
and that way you'll maximize recovery of both oil and
gas and you'll minimize the waste of the oil. So, what
you want to do is produce all this oil down here; the
gas cap will expand. After the gas cap has expanded as
far as it will reasonably go and you've gotten all
your oil, then you blow down the gas cap.
Normally, you need this to recycle the gas back into
the reservoir to maintain pressure. This allows for
mixing of EOR (enhanced oil recovery) fluids to cause
the oil to flow easier and also maintaining pressure
that pushes the oil out of the ground up to the well
bores and into the pipeline. Generally, early gas
withdrawal causes some challenges regarding loss of
oil. What we're talking about now with the North Slope
gas pipeline project is actually an early withdrawal
of oil.
Where the AOGCC comes in is we have statutory
responsibility to regulate reservoir management
including the timing and off-take rates for
conservation purposes. From this preliminary study
that the owners did, the result was it looks like gas
sales will negatively impact total liquid hydrocarbon
recovery. The reduction could be in the hundreds of
millions of barrels. It's a very preliminary study.
More study needs to be done to see if it's actually
going to be that high or not. The greatest impact
would occur with earlier sales of higher off take
rates. However, the good news is that the timing of
the sales and the gas production rate doesn't appear
to significantly affect the total hydrocarbon
recovery. That's when you consider both oil and gas
and total barrels of oil in place if you look at a
reasonable life of the field. If you don't think the
field is going to last - if the infrastructure is
going to go down, if it's aging and you don't last
past 2050, you probably won't lose that much oil in
reality, less than 100 million barrels. But further
evaluation is required to validate these preliminary
findings.
So, where do we fit in? This is a pretty busy slide.
It compares industry with DNR, with AOGCC's roles.
There's been a lot of confusion about where an AOGCC
fits in especially since all of the bru-ha-ha that's
been going on in the Valley regarding coalbed methane.
The AOGCC's role is only regulatory; it's not
proprietary. DNR's role is proprietary. It manages the
resource and Director Myers might have some comment on
this later. The DNR manages its resources for revenue
and other values and promotes prevention of both
physical and economic waste through unitization. The
AOGCC doesn't worry about value and economics, it
regulates for conservation issues, prevent waste,
protect relative rights and promote greater recovery.
It's worried more about saving the resource than what
the economic implications are. A lot of times both the
economic and physical waste issues are intertwined.
Mostly the AOGCC regulates subsurface activities. DNR,
DEC and other agencies have regulatory authority over
most the surface activities.
AOGCC was established under the Oil and Gas
Conservation Act, AS 31, before statehood in the late
50s. It's an independent quasi-judicial agency where
we report to the people of the state as represented by
you, the legislature. We have authority over all lands
in Alaska, not just state lands - state, federal and
private lands. Our duties are to protect, prevent
physical waste of the resource, insure greater
ultimate recovery, protect relative rights and protect
underground sources of drinking water.
As far as relating to the major gas sales project, our
main concerns are to prevent waste and insure a
greater ultimate recovery. We have been investigating
to determine whether or not waste exists or is eminent
and, as I say, the operators have done a very good job
on Prudhoe Bay. We have had very few concerns over
waste in the last 20 years. We have required plans of
reservoir development and operation and we will
require plans for the future development. Under the
statute, this would include regulating the quantity
and rate of production of oil and gas.
The definition of waste in the statute is the
inefficient, excessive or improper use of or
unnecessary dissipation of reservoir energy or
operating or producing in a way that reduces the
amount of oil or gas recovered under operations
conducted in accordance with good oil field
engineering practices. Like I said before, gas blow
down or gas production is normally delayed to the end
of a productive oil life to maximize the oil recovery.
While Prudhoe Bay is very unique, it's in a very
hostile environment. The oil infrastructure - you've
got to be able to handle the oil. It's not that simple
at Prudhoe Bay. This is something that needs to be
looked at really carefully.
Under applicable rules, Conservation Order 341(d) is
the pool rules that govern Prudhoe Bay. The three
rules under that conservation order that would be
applicable to the gas line project would be rule 9,
which gives a maximum off take rate of 2.7 billion
standard cubic feet per day. This was written in 1977.
It contemplated 2 BCF/day pipeline saleable gas rate.
Right now about 300 MCF/day of that 2 BCF are used for
enhanced oil projects within the field and in the
satellite fields.
Rule 12 basically says that the operator has to
maintain reservoir pressure high enough so that the
EOR gas mixes with the oil to make it flow easier and
also to keep the pressure up so that the oil can flow
out of the well bores.
Rule 17 is a more recent rule and it deals with - it's
a very ingenious idea where you inject water into the
gas cap to displace the gas to keep the pressure up.
This could be a very important mitigation measure when
you start taking the gas off. It may save up to 100
million barrels of oil just by replacing the gas
you're taking out with the water.
Things about Rule 9 - AOGCC approval is required for
sales rates in excess of 2.7 BCF/day. It also may be
advisable that we revisit rule 9 assumptions, since
that rule was written in 1977 at the field's start up.
It's a very old model. It's now obsolete; there was
very little information on the production at that
time. Now we have so much more information and the
technology is so much better. The vitals are so much
more improved that it's time to relook at this. When
we come up with the off take rules, we hope they will
be based on current knowledge and sound reservoir
management. With a project of this magnitude and cost,
it's critical that we be given adequate time to
evaluate prior to approval. We started that evaluation
in August 2002 when we hired an expert consultant on
reservoir simulations, Frank Vlaskovich, who has
experience in working on the North Slope in the
Prudhoe Bay reservoir. He completed a report in June
2003 and we have to emphasize that the results were
based on very preliminary work by the owners and a
very rough projection; so, today we can't come up with
an answer of what the exact effect will be on the
liquids recovery. We looked at sensitivities, the
effect of a sales rate between 2.9 and 4.3 BCF/day,
the effect of sales timings looking at starting dates
between 2010 and 2020 and a number of options to
mitigate the oil loss. One of them I mentioned earlier
was gas cap water injection - increasing that. That
could mitigate the oil loss by up to 100 million
barrels. And then CO2 injection. Prudhoe Bay gas is 12
percent CO2, which is about 3.5 to 4.5 TCF of CO2. CO2
has been very successful in other parts of the world
as an enhanced oil recovery fluid. Further studies
could show that much of the oil could be recovered
just by injecting the CO2. There are also potential
uses of the CO2 because of the recent scare over
global warming and CO2 sequestration. People are
starting to look at places like Oklahoma where 55
billion barrels of oil have been left in the ground
because it was not produced correctly. Now they're
thinking that putting CO2 in those reservoirs will
recover a lot more of the oil. If they had produced
the fields in Oklahoma at the beginning of the last
century the same way that Prudhoe Bay has been
produced, they probably could have recovered 30
billion barrels of that lost 55 billion. So, that just
goes back to the fact that this field has been
operated in a very efficient way.
This next slide is probably redundant. I've beat it to
death enough. As far as the reduction in liquid
hydrocarbons, that's dependent on a number of factors
- field depletion optimization, mitigation measures -
a couple of which I just described and also just by
producing the gas, the field life will be extended.
So, that gives more opportunity to produce more of the
oil. I'm not saying that the end result is we're going
to lose hundreds of millions of barrels. It's we just
need to do more study on it.
CHAIR SAMUELS said he assumed that was specific to certain
fields.
MR. SEAMOUNT replied yes, but he was just at the beginning of
looking at Prudhoe Bay and hasn't looked at Pt. Thompson at all,
except for some initial discussions of possible ways of
developing it.
MR. MARK MYERS, Director, Division of Oil and Gas, Department of
Natural Resources (DNR), said there are two plausible
development centers at Pt. Thompson.
One is a gas cycling project where you take the high-
pressure gas and condensate. You cycle it out of the
well to the surface, take out the liquids and put the
gas back in. You continue to just pull out the
liquids. Then you later blow down as Dan was
describing.
The second scenario would be to immediately start with
gas sales, in which case, you recover less liquids,
but you recover most of the energy back in gas. So,
again, there's economic and physical trade offs. It's
a very different reservoir mechanism that is present
at Prudhoe Bay. Pt. Thompson pressure is almost double
that of the original Prudhoe Bay reservoir pressure.
It's a very high-pressure reservoir. Prudhoe is a more
standard pressure reservoir. Prudhoe has a much larger
oil lake under laid by a water lake with a gas cap and
Pt. Thompson is a condensate with a little lake and
then a little bit of water underneath it. So, they are
different animals and each field has to be looked
individually and optimized. It's not a simple
equation, but for the gas line, it's mainly those two
fields, at least for initial production.
CHAIR SAMUELS asked if he had the geologic information he needs
on the various fields to make the trade off decision.
MR. MYERS replied that he has the information from Prudhoe Bay;
there's lots of production data.
The question is of optimization. With that the amount
of oil loss you'll see is directly proportional to the
amount of mitigation. The more water you put in the
gas cap, the more efficient, but it costs money to
reinject more water, but it maintains the pressure
higher. More in injection in oil lake of water or CO2,
a faster cycling time on the reservoir. All of those
would increase ultimate recovery, but they cost money
and they trade off energy used in compression versus
gas you could sell. So, there's an optimization issue
that goes on and really Prudhoe Bay is at the stage
where the knowledge base isn't going to increase
dramatically. It's merely a matter of optimizing the
time of sales and then optimizing the amount of money
you spend on the various mitigation strategies.
Pt. Thompson has yet to be developed. So, we have some
good well control and we have some seismic; we have no
production history and a lot less certainty about the
reservoir. So, there's more uncertainty around that
and as you start in production you gain more and more
certainty. So, some tough decisions will have to be
made on Pt. Thompson that are economic and they are
also reservoir related. We have some good reservoir
modeling that was done by the partners. We have a fair
amount of good well control, but there is still a lot
of uncertainty on the fringes of the reservoir of the
ultimate size of the prize and the best technology to
use to produce it.
CHAIR SAMUELS asked if the CO2 injection technology has already
been developed and does it cost more to operate.
MR. MEYERS replied that all the technologies talked about today
are existing technologies, but the biggest challenge with CO2 is
corrosion and requires use of stainless steel and changing out
some parts and pumps; there is money involved in doing that.
MR. SEAMOUNT explained another point:
That with proper engineering, total hydrocarbon
recovery - that's barrels of oil equivalent - is
relative insensitive to gas sales and sales rate if
you assume a reasonable end of life of the field. This
is where Prudhoe Bay may be unique in that there may
be a time element where you have to get this gas out
before everything craters or something goes wrong and
2050 is a long time out. It's insensitive out to 2050
when you bring on the gas sales and what rate it is.
Some of our recommendations here is with the AOGCC you
should be part of a process of further evaluation. We
need to participate before a decision is made to spend
all this money starting the project up. We should be
active in setting the producing rate or at least
according to the statutes. We must have adequate lead
time to complete due diligence and this will insure a
good technical review that will help the legislature
and others make informed decisions. The owners have
told us they plan to continue updating the existing
reservoir and facilities models. So far the work
they've done is a very good start. We need to continue
on this work, update our predictive tools and optimize
our operating strategies to maximize oil recovery. Can
oil losses be effectively mitigated? What are the
effects on the other pools and reservoirs that depend
upon Prudhoe Bay gas for their EOR projects for their
future pools and reservoirs? The owners have told us
we will be part of the reservoir evaluation process.
REPRESENTATIVE REGGIE JOULE asked him to explain updating
predictive tools.
MR. SEAMOUNT replied:
These would be the reservoir model, the software, the
programs run to predict what kinds of rates to expect
and what kinds of recoveries to expect. You take raw
information from the wells, from the production, from
pressure data and you run it through a computer
simulator and it will spit out predictions as to what
kinds of recoveries you can expect of oil, what kinds
of gas, natural gas liquids.
REPRESENTATIVE JOULE asked if AOGCC has all this information.
MR. SEAMOUNT replied, "Yes we do. We have access to it."
REPRESENTATIVE JOULE asked if it had been interpreted.
MR. SEAMOUNT replied, "No, it takes a lot of man power, a lot of
computer time to take all this raw information, stick it in the
computer. It gets very expensive."
REPRESENTATIVE JOULE asked if AOGCC has the resources to do it.
MR. SEAMOUNT replied that it doesn't have the resources, but
industry does. That's why he is proposing to work with industry
when they are doing the evaluations. He has been talking with
the owners now and then and they are getting along pretty well.
REPRESENTATIVE JOULE asked how far behind are we?
MR. MYERS replied:
There are varying levels of accuracy in which you do
this. Think of a computer model; think of a grid -
think of a grid the size of a chessboard or you can
have a grid with thousands of little squares. The more
detail, the more computer intense and the more certain
your model is. So, the level of detail, the model we
have right now is pretty good at smaller than the
chess board size, but not the tiny dot size. As you go
through and get closer to the reality of a gas line,
you get more and more detail. What we have now is
pretty darn good. It gives you confidence in the
initial conclusions that there will be a minimal
amount of oil loss, but there will be some. Then it's
the obligation of what mitigation you put in. So, the
results we have now show us ... if we start gas sales
at this date, we expect to have this much oil loss, if
no additional mitigation. If more water goes in the
gas cap, it might be this much; if more cycling
occurs, it'll be this much. But we can't predict what
investments companies are going to be willing to make
at the time. That's why this joint work that Dan is
talking about. So, you have to start running the what-
ifs and the optimization of gas off take. For
instance, if the producers propose 2.5 BCF out of
Prudhoe Bay versus 3.5 BCF, there's a big impact in
oil loss differential unless you pump a lot more water
into the gas cap.... The baseline model work is done
and we're pretty confident that the oil loss if
nothing is done and the gas sales in the 2012
timeframe, the maximum oil loss might be 500 million
barrels, but you recover a lot more energy in gas.
Conversely, there are cases where you can run
scenarios with enough pressure injection where that is
way down to less than 100 million barrels. We already
know that and we already have good production decline
curves for Prudhoe given the current level of
investment. But if that level of investment changes,
if they change the rate of production in Prudhoe, any
number of things could happen. If they do commit to
reinject CO2 as miscible injectant, that changes the
equation. Current development plans don't have any of
those long-term things in there. There is sort of a
segregation in the companies between those working the
oil issue and those working the gas line and the gas
sales. So, right now Prudhoe is managed as an oil
reservoir to maximize oil recovery. They haven't made
the switch over to gas, yet. So, all of these
scenarios are hypothetical.... Both agencies have a
say in what oil loss should be to meet the
requirements of physical and economic waste.
CHAIR SAMUELS asked if they are going to participate before the
decision in reference to page 15.
MR. SEAMOUNT replied:
We have been participating. We haven't got into the
next stage of final evaluation, yet, but we were able
to participate. We were able to at least review the
first simulation that was run.
SENATOR LINCOLN asked how AOGCC is going to achieve the goals he
listed to be part of a review.
MR. SEAMOUNT replied:
We reviewed their first simulation study and they
allowed us in to review it and come back with some
information. That was the first step. The next step is
when they begin building their final new and improved
model. We would like to be a part of that. We haven't
made any agreements on that yet.
CHAIR SAMUELS asked if there was a barrier to their
participation now that he needs help with.
MR. SEAMOUNT replied that he didn't see a barrier as the owners
are working with him now.
SENATOR ELTON said he assumed that the state had a lot of the
information on throughput already, but if it doesn't, how much
more time does the AOGCC need to advise the legislature so it
can make a good decision.
MR. SEAMOUNT answered that part of it depends on industry and
how soon they would do their final evaluation. It would take
AOGCC two years and $2 million to do it on its own.
SENATOR DYSON asked if gas sales and other waste might be useful
in recovery of the heavy oil in West Sak.
MR. MYERS replied:
The gas line, again, until there is final approval by
AOGCC and by DNR on state lands, there will be no
authority to authorize any significant off take of
gas. So, fundamentally, there's a separate process
independent of the pipeline proposals, because that
sale event won't occur until 2010 to 2016, depending
on who you talk to. So, fundamentally, that process of
approval will occur much later that probably a
sanctioning of the pipeline project. There will be a
period of time in which folks will determine what gas
they want to nominate knowing full well they still
need agencies' approvals. It won't be a carte blanche
that once you cut a deal that a pipeline will go and
the pipeline goes to open season and people nominate
gas. They will be taking risk in nominating that gas
if they do not have approval to off take that gas. So,
the processes are separate. The companies must believe
at the point they nominate gas that they can
demonstrate there will not be physical or economic
waste or they're taking a big risk in that process.
Again, DNR's & AOGCC's processes are separate and
distinct, but they are somewhat aligned in the issue
of having to deal with physical waste. The closer you
are to the final development is when you run your
final simulations and you go for agency approval....
TAPE 04-27, SIDE A
MR. MEYERS continued:
We won't have that distinct information or a blessing
and approval at the open season time for this
pipeline, because that final engineering work won't
have been done, because it'll be years and years in
advance and they know they're going to have to run
their models again later, because they'll have that
much more information to find and they would have done
that much more mitigation in the field. In the
meantime, the field will be managed for minimizing oil
loss, which again is AOGCC's responsibility through
their pool rules....
In a sense of the amount of gas and where it gets
used, certainly a miscible injectant into the heavy
oil will help recovery. The question is where is that
miscible injectant going to come from and the timing
of it. Ultimately, if you have a gas pipeline, you
will put that down the pipeline. So, what's happened
is in all these fields like Kuparak and Prudhoe Bay,
miscible injectant has been created and injected into
the main reservoir. At some point, it's less economic
to put that miscible injectant into the main reservoir
and they'll shift it over to the West Sak, in the case
of Kuparak or Milne from the Kuparak formation into
the Schrader Bluff. So, we'll see MI (miscible
injectant) moving around the field that's already
being used. They'll keep recycling and reinjecting at
Kuparak, at some time, when it becomes more
economically efficient to put in the heavy oil zone.
At the same time, CO2 is a wonderful miscible
injectant for heavy oil. So, they could, if it was
optimized, just use a CO2 flood in a lot of the heavy
oil. So, there'll be this optimization between sales
and delivery of gas and where they take and the timing
of that versus the use of miscible injectant. It's a
balancing act. It's coming from multiple sources; it's
already in the fields and they'll probably use that as
their first miscible injectant for the heavy oil
zones.
SENATOR DYSON said he has followed the Canadian efforts with
their heavy oil and there is some talk about in situ combustion.
He asked if that is a scenario that could work with Alaska's
heavy oil.
MR. MYERS replied probably not - for two reasons. One is that
our heavy oil is actually at the light end, 16 - 23 API
(American Petroleum Institute) gravity, which can be produced
better through conventional means in multi-lateral wells.
In situ burning would only be applicable, hypothetically, for
some of the shallower parts of the heavy oil in the Ugnu
Formation that is at 8 - 12 API that probably isn't very
moveable.
The problem is that you've got cold temperatures and
permafrost.... My gut feeling is that there's a whole
lot more studies that need to be done before you even
consider it.... Most of the oil in the next 15 will
probably be this lighter end of the heavy oil, which
is volumetrically where they can get out of a multi-
lateral well 15,000 barrels per day. That far exceeds
the advantage of an in situ burning or a huff and puff
steam type mechanism that they use in Alberta.
SENATOR DYSON mentioned that Representative Berkowitz has
discussed a win-win where the state gets paid for sequestering
CO2 and use that for driving oil recovery and asked if he
thought that might work for us sometime.
MR. SEAMOUNT answered that there are a lot of CO2 emissions on
the North Slope through flue-gas.
If they come up with credits for CO2 sequestration to
industry, that would be the first place to start. Then
if you get really creative, possibly re-injection of
the produced CO2 that'll get you both enhanced oil
recovery and some tax credits. But that may be pushing
it a bit.
MR. MYERS said there would be another opportunity in the gas
hydrate zones where gas is present in crystalline form that's
just below the permafrost. The estimates are that those volumes
exceed that of the conventional gas at Prudhoe Bay. CO2
replacement of hydrates is very efficient.
So, there are all sorts of other potential advance
technologies and uses for CO2 sequestration, which
could aid additional methane production as well as
heavy oil production. CO2 will become extremely
valuable rather than being a nuisance on the North
Slope.
MR. SEAMOUNT said they didn't know what kind of mitigation
measures are going to be required or even be possible. A more
in-depth study is needed.
MR. MYERS said that DNR and the AOGCC have some overlapping
authority. DNR's authority is limited to state lands and AOGCC's
authority goes to federal and private ownership. DNR's authority
is established in AS 38 and it is a broad mandate over economic
and physical waste, conservation of resource and protections of
the state's best interest. The Supreme Court has confirmed that.
A lot of DNR's authority comes through its ability through
unitization, which is putting oil and gas property together,
multiple leases to produce from a single set of facilities.
The Supreme Court said that unitization development
and conservation of all natural resources belong to
the state for the maximum benefit of its people....
We also have regulatory functions.... A lot of them
focus around unitization.... The commissioner may
establish, change, revoke drilling producing and
royalty requirements of leases. So the state has an
active role. It can help regulate the rate of
drilling, the number of exploration wells in a unit.
The commissioner can also modify that through plans of
development over time - and development of the
quantity and the rate of production within the
units....
We're, again, required under unitization to make a
public finding that it's in the public interest and to
meet certain standards. Those standards that we have
to justify in unitization or in plans of development
promote conservation of the resource...promote,
prevent, economic and physical waste.
An example of physical waste is when you flare gas instead of
paying to have it reinjected. A pure economic waste is like at
Prudhoe Bay if the operator chose to put the gas down a pipeline
rather than reinject it and we lost economic value because we
produced less oil. Drilling too many wells in an area is
economic waste of resources.
MR. MYERS explained a slide of optimizing oil and gas geologic
structures.
CHAIR SAMUELS asked if there are any other mechanisms the state
has to insure access to the pipeline other than RIK or RIV.
MR. MYERS replied RIK and RIV are the only mechanisms in which
the state would have total control. With proper negotiations it
is possible to do things like require mandatory seasons for
expansion at various times. The federal legislation gives FERC
the ability to mandate access if it passes.
REPRESENTATIVE GARA had a question on page 9 of Mr. Seamount's
presentation regarding rule 9 on the maximum gas off take that's
allowed. Some people are talking about a 3.5 BCF/day gas
pipeline and the current rule says the maximum allowable rate is
2.7 BCF/day. "Why isn't it absolutely time to revisit that to
provide people with some certainty who are considering investing
in a gas pipeline?"
MR. SEAMOUNT replied that a hearing would probably happen soon.
REPRESENTATIVE GARA asked when he anticipated having a reliable
ruling.
MR. SEAMOUNT said that is difficult to answer until the
testimony at the hearing is complete. He said the answer would
be easier if the AOGCC had a new complete reservoir model that
it could rely upon and it does not have that yet.
REPRESENTATIVE GARA commented, "And there are two flip sides.
One is the rule that says as the leaseholder, you're allowed to
produce this amount of gas and so maybe after the hearing
process, it would be increased from 2.7 bcf/day to the amount
needed for the pipeline. What about the flip side? Would the
rule also say to the lessees that you're required to allow the
release of that amount of gas or else that would be waste if you
don't allow the release of that amount of gas?"
MR. SEAMOUNT said he cannot see how producing more gas would be
required. He asked Representative Gara if he was saying it would
aid in the ultimate recovery.
REPRESENTATIVE GARA asked if it could be seen that not allowing
enough gas out to make a pipeline feasible could be a waste.
MR. SEAMOUNT said it could be an economic waste. Regarding
physical waste, he said he could see that if one could foresee
that the infrastructure is going to go down in a few years so
that if it is not taken out now, it never will be.
REPRESENTATIVE GARA said if Rule 9 was updated to the 3.5 number
as Mr. Seamount anticipates, all Rule 9 would say is that
leaseholders would be allowed to send 3.5 bcf/day but would not
be required to.
MR. SEAMOUNT said that is correct.
MR. MYERS pointed out that the size of the pipeline is
determined by the pipeline builders who will be heavily
influenced by the nomination process. The pipeline will have
limited specifications - it will only have certain optimum
ranges that are economically feasible. However, within that
range, the builders will ask who wants to send gas through that
line. If only 3 bcf is nominated, the builders will design a
pipeline that can provide a reasonable tariff for 3 bcf. The
companies nominating that gas will have to believe they can get
regulatory approval to produce from those fields and prevent
physical and economic waste. If they don't have the gas, they
will be exploring to get the gas from the NPRA or Foothills if
they can't get the gas from Prudhoe Bay. He emphasized that it
is the individual companies, not the fields that will nominate
the gas in and they will have to believe and have agreements to
produce that gas and regulatory approval. Therefore, just
because the pipeline is designed for 4.5 bcf does not mean at
the end of the open season process it will be a 4.5 bcf
pipeline. For example, if 6 bcf gets nominated from credit-
worthy parties, the builders will try to build a 6 bcf pipeline
from day one. He noted it is a commercial process that is used
to design the size of the pipeline but that must be backstopped
by good faith that the regulatory approval will come and that
the economic standards can be met in the future.
REPRESENTATIVE GARA asked if the estimated available 3.5 bcf of
natural gas includes Point Thomson.
MR. MEYER said the public numbers for the North Slope range from
33 and 35 trillion cubic feet of known proven reserves, largely
from Prudhoe Bay and Point Thomson with some associated gas with
other oil fields. He noted the undiscovered resource potential
in the NPRA is significantly larger. He said the Prudhoe Bay and
Point Thomson gas would supply 18 to 20 years at the 4 to 4.5
range and the rest of the gas would come from elsewhere. Or by
the time of the actual development of the pipeline, the
companies will be taking less gas from those two fields and more
from other sources.
CHAIR SAMUELS asked for suggestions of where the legislature
wants to "go from here" and said he would start by bringing up
the local hire issue. He felt that although local hire cannot be
mandated, knowing what jobs would be required in advance would
allow the legislature to take steps to insure that the jobs that
are available could be filled by people who would not otherwise
have jobs and deteriorate the economy. He said he would like to
get more information along those lines so that adequate training
could be provided.
SENATOR LINCOLN said she would like to expand that idea so that
Alaska businesses are utilized.
CHAIR SAMUELS agreed and said he was not satisfied with his
questions or the answers to Exxon about marketing. He again
asked members to think about where they wanted to go from here.
SENATOR ELTON thought that given the issues that have been put
before the committees, from a process perspective, members need
to consider how to keep those issues alive so that they can get
a better sense of where those who testified are going and follow
what they are doing. He suggested using existing committees or
creating a subgroup of legislators and coordinating with the
Executive Branch to avoid a lot of duplication and create
synergy between the two groups.
CHAIR SAMUELS told members that during the previous legislative
session, Senate President Therriault appointed Senators Stevens
and Guess and Speaker Kott appointed Representatives Joule and
Weyhrauch to be the liaisons between the legislature and the
administration during the interim. He joined that group as the
chair of the Legislative Budget and Audit Committee, as did
Senator Therriault. When they met with the administration, they
told the administration that their understanding of the Stranded
Gas Act was to prevent all 60 legislators from "throwing rocks
at each other" for political reasons. The point was the act was
to establish one negotiating point. In addition, they told the
administration what issues came up during their legislative
committee hearings. He pointed out such a meeting has occurred
already [during this interim].
REPRESENTATIVE JOULE commented, regarding the question of state
ownership, he believes that needs to be explored further,
particularly the RIK and RIV issue.
REPRESENTATIVE STOLTZE said he pursued that line of questioning
in the Finance Committee but he didn't feel that he got an
answer. The question there was if the state does have an
ownership, what percentage would it need to have an impact and
whether there is a minimum amount and he would like to follow up
on that.
REPRESENTATIVE HAWKER said he would like to further pursue the
state's participation in the broadest sense. He would like the
committee to expand into whether the state should participate
and to hear more from the capital market people about financing
and cost of capital alternatives, especially since the committee
will only have 30 days to review [any agreement]. He noted,
"Secondly, the other one that really peaks my interest - and
again we've got a regulatory authority person here saying I
won't get into that one because it's such an undetermined issue
and it seems to me to be a pretty significant issue - a route
that would go across Canada if, in fact, we are legally
prescribed going across Canada."
SENATOR LINCOLN said what she finds troubling is that there is a
whole mass of people that are a part of this process. Right now
the administration is negotiating and no one knows where that
negotiation will lead or the timing. She said in addition, the
AOGCC's role, its goals and interactions with the legislature,
the role of the commissioner of DNR, which is very broad, ANGDA,
and the role of the Senate Resources Committee, all play parts
and she is unsure how they fit together in legislative
deliberations and pursuing the best course of action.
CHAIR SAMUELS thought the committee can apply pressure to any
mechanism it wants to, whether that be ANGDA or another, but the
reality is that the legislature will have a minimum of 30 days
to approve a contract and it will be deciding on a product put
before it. He thought members need to be familiar with the
subjects, such as the trade-off for RIK or RIV, or the choices
and trade-offs that were made in the contract. He pointed out
that some of the issues raised by members, such as vocational
education, will be important to know about for the next
legislature so that it can plan for training.
REPRESENTATIVE JOULE said all legislators will want to be ahead
of the curve on the local hire issue and that the legislature
now has some experience under its belt and the luxury of a
little bit of time. He felt the more that opportunity can be
maximized, the better off the state will be.
SENATOR DYSON noted that although all members are enthusiastic
about Alaska hire, there will be great pressure for the
construction to occur under project labor agreements and he
guesses that will happen. He pointed out that project labor
agreements are often touted as the best tool available to
guarantee Alaska hire. He is sympathetic to that but some of the
bargaining units have internal rules that do not allow them to
add new people into the Alaska rolls if someone elsewhere in the
Northwest bargaining unit is unemployed. He suggested adding
incentives or doing something to help qualified Alaskans to get
into those bargaining units ahead of other workers from the
Northwest. He complimented Chair Samuels and Senator Ogan for
organizing these educational hearings. He then asked that the
presenters not use acronyms, as not all members are familiar
with them.
CHAIR SAMUELS said he would consider and work on getting another
meeting together in approximately one month.
SENATOR SEEKINS thanked the co-chairs as well, and then noted
that, to quote from Dr. Martin Luther King, "without a dream,
the people will perish." He said a gas line is a dream of many
Alaskans and that with every dream, there is an intent to kill
it. He said he feels relatively certain that any final gas line
dream will not be what he or any other member prefers. He
believes the challenge for members is to not kill any reasonable
dream just because it is not exactly what each member wants. He
hoped all members could work with the administration and other
participants to bring this dream to fruition and make it
profitable for those in the business and for the residents of
Alaska, Canada and the United States.
REPRESENTATIVE GARA said the process of the Stranded Gas Act
almost requires the legislature to say something to the
administration sooner rather than later. He said if the
committee keeps all of the information it has gathered over the
last two years internal, the administration will not know what
the committee is thinking and will enter into a deal it believes
is best, leaving the legislature the right to only say yes or no
to it. He said he believes the legislature has punted, and to be
fair to the administration, the legislators can probably all
agree on some issues that have been discussed in these meetings
but the administration does not know which. He thought if
committee members can agree on some of the concepts, such as
access to the gas by in-state users, creative ways to deal with
local hire, that it is important to convey those agreements now
so that the committee does not address those after the deal is
done.
CHAIR SAMUELS repeated that a group of legislators has met with
the administration and discussed specific topics and that the
administration was open to discussions. He said he would
organize another meeting with the administration. Chair Samuels
then asked members to contact him or any other subgroup members
about individual concerns, which will also be relayed to the
administration. He said he would work on getting more
information on the issues of ownership and capital markets and
adjourned the meeting at 3:45 p.m.
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