Legislature(2007 - 2008)TERRY MILLER GYM
06/04/2008 10:00 AM Senate SENATE SPECIAL COMMITTEE ON ENERGY
| Audio | Topic |
|---|---|
| Start | |
| SB3001|| HB3001 | |
| Lb&a Consultants Barry Pulliam, Lesa Adair, William Mogel, Dr. john Neri, Dan Dickinson | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| *+ | SB3001 | TELECONFERENCED | |
SB3001-APPROVING AGIA LICENSE
HB3001-APPROVING AGIA LICENSE
10:03:09 AM
CHAIR HUGGINS brought SB 3001 and HB 3001 before the committees
for consideration.
SENATOR GREEN, President of the Senate, noted the new Senate
Special Committee on Energy consists of members of the Senate
Resources Standing Committee and the Senate Finance Committee.
During these joint meetings Senator Huggins would chair.
REPRESENTATIVE HARRIS, Speaker of the House, explained that he,
Representative Samuels, Representative Kerttula, and
Representative Coghill, chair of the House Rules Standing
Committee, were representing the House Special Subcommittee on
AGIA, the Alaska Gasline Inducement Act.
CHAIR HUGGINS announced that Representative Samuels, who chairs
the Legislative Budget & Audit Committee (LB&A or BUD), would be
the facilitator today.
REPRESENTATIVE SAMUELS informed members that three consultants -
Barry Pulliam, Lesa Adair, and Dan Dickinson - would give
presentations today and tomorrow, followed by a roundtable
discussion. He introduced the others: William Mogel, a Federal
Energy Regulatory Commission (FERC) attorney, and Dr. John Neri,
who was tasked with the ins and outs of rate making. He said
letters went out under his signature to TransCanada and the
administration that he didn't personally write; a lot of
technical information and questions came from Dr. Neri.
REPRESENTATIVE SAMUELS noted he has tried to stay at arm's
length from the consultants. Questions have been relayed from
the legislature and other consultants, and the LB&A consultants
were asked to review certain subjects. He encouraged questions
during their presentations.
10:09:36 AM
^LB&A Consultants Barry Pulliam, Lesa Adair, William Mogel,
Dr. John Neri, Dan Dickinson
BARRY PULLIAM, Senior Economist, Econ One Research, gave his
background, saying he has worked on oil and natural gas for 20
years. In some capacity, he has worked for or with the State of
Alaska for most of that time on behalf of the administration and
the legislature, dealing with issues such as taxes, a gas line,
and royalties. He also works with other states; has worked with
the federal government on energy matters; and has worked for
private companies including producers, refiners, and pipelines.
MR. PULLIAM began his PowerPoint presentation titled "Comments
to Legislature on TransCanada Proposal"; a handout duplicated
the slides. He noted he would discuss the proposed tariffs and
the related cost structure, implications, and sensitivities
surrounding the assumptions. This would provide a foundation
when considering the presentations to follow.
MR. PULLIAM paraphrased slide 1, which was labeled "What Does
TransCanada Propose to Do?" and had the following points:
- Construct and operate 1,700-mile, 48-inch pipeline
from North Slope to Alberta, with initial capacity
of 4.5 bcf/day, expandable to 5.9 bcf/day with
addition of compression
- Conditioned on receiving sufficient firm
transportation commitments
- Pipeline would terminate at Boundary Lake on the
British Columbia/Alberta border, where it would
enter the "AECO Hub"
- At AECO, shippers would arrange for extraction of
valuable NGLs (either from third parties or
through construction of own facilities).
"Residue" gas could be sold either in Canada or
shipped to Lower 48.
- Construct and operate necessary Gas Treatment Plant
("GTP"), if not undertaken by another party
- Provide pipeline access for LNG facility if demand
warrants
MR. PULLIAM said while the pipeline ultimately would be
expandable to over 7 billion cubic feet a day (Bcf/day),
initially it would be expandable to about 5.9 Bcf/day just
through compression. The AECO Hub is an interconnection of
pipelines, a center for market activity and price formation that
is one of the most active trading areas in North America.
REPRESENTATIVE SAMUELS added that the AECO Hub isn't a single
spot, but involves the entire province of Alberta.
10:14:34 AM
REPRESENTATIVE GARDNER asked: Is there adequate infrastructure
now to ship gas from AECO to Chicago if that is the market?
MR. PULLIAM replied while it might not exist today, most folks
anticipate sufficient infrastructure to move the gas away from
Alberta by the time gas comes on line, in 10 years or so. There
might need to be some expansion of existing lines, but it's
unlikely that there'd need to be a new line built to take all
this gas to the Lower 48. Ms. Adair would speak to that later.
MR. PULLIAM continued with slide 1, saying as the gas moves down
the pipeline it contains natural gas liquids (NGLs) that will be
extracted, most likely at AECO, where the NGL-extraction
capacity is anticipated to be sufficient to handle gas from
Alaska. He believes those NGLs will have significant value for
producers, shippers, and the State of Alaska. After extraction,
the "residue" gas that's left could be sold in Canada or shipped
to the Lower 48.
10:16:48 AM
REPRESENTATIVE GUTTENBERG asked whether TransCanada assumes the
NGLs would be shipped or whether provisions allow those to be
extracted within Alaska.
MR. PULLIAM replied he believes the assumption is that the
liquids would be shipped with the gas. While he didn't know of
any prohibition on in-state extraction, in large part the
infrastructure and capacity already exist in Alberta for that.
It may be the most efficient to extract NGLs in Alberta to get
the highest value for the state.
REPRESENTATIVE GUTTENBERG asked: Once the NGLs get to AECO,
does a different authority control it or is it under the
shippers' contract?
MR. PULLIAM answered there are issues at AECO as to how NGL-
extraction rights are allocated. As the gas enters the pipeline
in Alaska and all the way down to AECO, the NGLs belong to the
shippers; it is up to them either to negotiate with folks who
have extraction facilities in AECO or to potentially build a
facility there themselves to extract the NGLs.
REPRESENTATIVE GUTTENBERG surmised there'd be no conflict in
taking the NGLs from Alberta into the Lower 48.
MR. PULLIAM gave his understanding that shippers bringing gas
into AECO typically don't move NGLs further; they sell
extraction rights in AECO and then the owners of the plants are
responsible for further shipping. It doesn't mean it couldn't
be done differently, through negotiation, keeping the NGLs and
shipping them. But it may make more sense to have someone else
do the extraction in AECO and then have that entity pay for the
value of those NGLs.
REPRESENTATIVE SAMUELS asked: What percentage of the Prudhoe
Bay gas is NGLs, and if those are taken in Alaska or in AECO,
how much gas would be lost? And would it affect the financing
because the throughput would have dropped?
10:19:50 AM
MR. PULLIAM answered it is a relatively small percentage. The
question is where to get the most value. If NGLs are taken out
of Alaska, they must be moved to markets that consume and pay
for them. If NGLs are extracted in Alaska, the quantity is more
than could be used today in Alaska; they'd have to be moved out
of state in some form, requiring a pipeline and/or marine
transportation. The expense would likely be greater than if the
NGLs traveled in the pipe and then were extracted in Alberta.
MR. PULLIAM, in further response with respect to pulling out
propane at the Yukon River, opined that some NGLs could be
extracted for local uses without causing problems down the line.
The gas would have to be measured as it gets to Canada to
determine its composition. If propane is pulled out in Alaska,
some value will be pulled out; propane has a higher value on
average than the stream, which is mostly methane. Any amount
taken in Alaska for local use wouldn't likely damage the
economics associated with moving the gas to Alberta and doing
extraction there.
REPRESENTATIVE SAMUELS surmised Alaskans would use a relatively
small amount of propane. He asked if a small enough plant could
be built to make it economical to drop some propane at the Yukon
River in order to help get energy to those living in Western
Alaska, knowing there'll be a transportation cost.
MR. PULLIAM deferred to Ms. Adair.
10:23:05 AM
LESA ADAIR, Muse Stancil, indicated her company worked for LB&A
previously on this issue of in-state use. She said it boils
down the value of propane in Alaska relative to other places.
The capital cost of building a plant to extract liquids is more
driven by how much gas must be processed to extract the propane,
rather than the amount of propane that comes out.
MS. ADAIR noted the plant has to be big enough to handle enough
gas to extract the propane. Those economics can work if someone
is importing propane or hauling it a long distance. For
instance, they'd looked at a couple of plants in northwestern
Alberta where bottled gas is highly profitable because the
product is imported today. She gave her feeling that it could
work, but said the economics hadn't been run on that case.
CHAIR HUGGINS highlighted in-state jobs that this industry will
create instead of just exporting raw resources.
REPRESENTATIVE DOOGAN gave his understanding that the business
about NGL offtake is an economic assumption, rather than a term
of the agreement that the legislature is being asked to approve.
MR. PULLIAM affirmed that.
REPRESENTATIVE DOOGAN requested that such instances be clarified
during the presentation.
10:25:31 AM
REPRESENTATIVE NEUMAN referred to the phrase "extraction of
valuable NGLs" on slide 1. He surmised if TransCanada builds a
pipeline, that will be a decision among the producers,
TransCanada, and any industry that might be attracted by Alaska
to come build a plant to process NGLS; nothing in AGIA covers it
or says the NGLs will be shipped outside, and so it leaves open
the possibility for value-added products to be produced in
Alaska within this process.
MR. PULLIAM relayed his understanding that nothing in AGIA
requires NGLs to be extracted at one place or another. Before
the gas can be used in residential or industrial markets, NGLs
will be extracted; they have value. He opined that the owners
of the NGLs would make a commercial decision as to where the
highest value is.
REPRESENTATIVE NEUMAN asked: If the state could attract someone
to build a processing plant to extract butanes, propanes, and so
on - either for use in Alaska or to export - is there any hammer
so the state can have first-access rights to those NGLs?
MR. PULLIAM replied he wasn't aware of any, though it was a
little outside his field.
10:27:39 AM
SENATOR WAGONER asked if building a plant to extract propanes
and ethanes in Southcentral Alaska makes it more economically
feasible. Surmising the tariff would likely be lower than to
Alberta, he suggested if a spur line brings natural gas/methane
into Southcentral anyway, it could ride in the same line with
propanes that aren't used in the Yukon.
MR. PULLIAM replied he hadn't modeled that scenario. He gave
his sense that for the volume discussed, the pipe would be much
smaller that carries ethane or ethane and propane; there'd be
relatively high fixed costs over which to spread that smaller
volume. Also, once extracted in Alaska, it has to be turned
into a finished product, either for Alaskan consumption - some
of which can be done with propane - or else for export, the case
with ethane now. One must add up all associated shipping costs
to see how it stacks up. Given likely economies of scale, it
probably isn't as good from a netback-value standpoint.
MS. ADAIR agreed that was probably right. For downstream users,
particularly for ethane, one issue is that most plants competing
economically today are world-scale, huge facilities. Facilities
in Alberta today will need those ethanes. Mentioning sunk
costs, established markets, and takeaway capacity, she predicted
it would be costly to compete. She opined that an economic
analysis would show it is more cost-effective if those go to
Alberta to existing markets.
MS. ADAIR indicated there'll likely be a need to process gas
used in Alaska. Commercial economics must be analyzed for
recovering ethane or letting it be sold as natural gas, which
happens on the U.S. Gulf Coast, depending on relative prices for
those.
MS. ADAIR also mentioned bottled gas markets locally for
propane; suggested butanes and pentanes can be used for gasoline
blending in Alaska; and said liquids can be spiked back into the
pipeline, for example, if there isn't a market in the Yukon for
some of those heavier liquids. She said it's more efficient to
move everything under one system than to build multiple systems
to transport products.
SENATOR THOMAS asked: Right now, what is the best use of that
gas economically? Would it be used in the tar sands, for
example, or go to the Midwest for heating and power generation?
MR. PULLIAM replied if it comes down the pipeline into Alberta,
it may be used in a combination of ways, locally in Alberta in
the tar sands and also moving into the Lower 48. Physically, it
will increase the Western Canada gas supply, which has been
declining; that supply is used in Canada and the surplus is
exported to the Lower 48. Effectively, Alaska's gas will be
exported to the Lower 48; the economics will be a Lower 48
netback. Physically, a lot of it may be used in Canada.
10:33:32 AM
REPRESENTATIVE SAMUELS asked if on pure economics, maximizing
value to its shareholders, TransCanada doesn't care if NGLs are
taken off in AECO or shipped to Chicago, but if some is taken at
the Yukon River there'll be a little less gas and thus a
slightly higher tariff per unit.
MR. PULLIAM replied he believes it largely is accurate that
TransCanada doesn't have an interest in gas processing or NGL
extraction, which will be performed by somebody else; it isn't a
service that company provides now. Agreeing that if the NGLs
were extracted in Alaska the volumes would decline a little, he
pointed out that they'd have to come from another source, either
through quicker production or gas coming from other fields.
REPRESENTATIVE SAMUELS requested confirmation that the
TransCanada proposal has an in-state tariff which would apply to
propane dropped out at the river and that a little would be
saved on the tariff, since it wouldn't be the Alberta tariff.
MR. PULLIAM affirmed that.
10:35:35 AM
CHAIR HUGGINS asked if anything in AGIA or in TransCanada's
proposal modifies the state's flexibility with respect to its
royalty share.
MR. PULLIAM replied not that he was aware of. Returning to the
slide, he noted TransCanada proposes to construct and operate a
gas treatment plant (GTP) if that isn't undertaken by another
party. He said it seems fairly clear in the proposal that
TransCanada's preference is for someone else to do that.
10:36:30 AM
REPRESENTATIVE GARDNER asked how access pricing and processing
costs are calculated, whether that is regulated, and if there is
any way it could impede new explorers wanting to get into the
GTP. She also asked who owns the gas.
MR. PULLIAM answered first about GTP access. He said
TransCanada's proposal envisions the GTP as a regulated
facility. There'd be a regulated cost-of-service tariff,
although there may be issues, depending on who builds it, as to
how that regulation is applied. Noting this is outside his
field and deals with FERC policies, he surmised it would be a
regulated facility if integrated with the pipe, but he wasn't
sure what access issues would exist if it were built by the
producers and operated separately.
MR. PULLIAM highlighted the importance of considering this,
since the GTP is integral to getting the gas to market. If
exploration is a key activity to encourage, he said, then being
able to get gas into the GTP or to expand the GTP in some way
will be important.
MR. PULLIAM turned to who owns the gas, saying that is a legal
question best answered by one of the state's attorneys; he is an
economist. He offered his lay understanding that the gas has
been leased to the producers, which have ownership rights to it.
The state gets a royalty portion and also has sovereign capacity
and the ability to tax the gas as it is extracted.
REPRESENTATIVE SAMUELS advised members that tomorrow the
question involving the GTP would be addressed during the
roundtable discussion. He said the point of AGIA is to ensure
access. If the GTP is a bottleneck, he surmised FERC will get
involved. He posed a scenario in which an expansion would drive
the tariff up and he owned the GTP at Prudhoe Bay; he asked why
he would expand it, costing him more with respect to the tariff.
10:41:12 AM
SENATOR THERRIAULT told members last week he was surprised to
hear that Asian gas systems burn a higher-Btu-content gas.
Selling into that market and getting the higher price requires
that blend, and Alaska's gas stream is right about at what they
need. If that happens, there'd be no ability to strip out large
quantities of gas liquids either to sell to a separate market or
to use in Alaska. He asked if Mr. Pulliam agreed.
MR. PULLIAM concurred, saying if gas is to be sent to the Far
East in the form of liquefied natural gas (LNG), it will be for
industrial uses. They can handle gas that is relatively rich,
with the NGLs still in it, and contracts are typically written
for a relatively rich stream. Assuming that Alaska's gas is
exported to the Far East in conformity with how it's typically
done there, it would mean relatively few NGLs taken out of the
gas before it's shipped.
MR. PULLIAM pointed out in North America it works differently.
For safety reasons, NGLs need to be stripped out before the gas
is used commercially for industrial or residential purposes.
Also, NGLs have tremendous value in today's market and future
projections. They have to be stripped out if they stay in North
America, which involves a separate sale. If the gas is sent to
the Far East under the kind of terms in place now, a relatively
small amount of NGLs could be taken out prior to that.
10:44:34 AM
REPRESENTATIVE JOULE recalled hearing for a long time how hungry
the country is for Alaska's gas. He asked: If some of this gas
will be used in the tar sands and some in the Canadian market,
how much will really be used in the Lower 48? Also, he said
part of the argument against an all-Alaska gas pipeline to get
to the Asian market is that the congressional delegation will be
upset. He noted this gets into a larger political arena.
MR. PULLIAM responded that the gas would be sent via pipeline to
Alberta, where it would connect with an existing system taking
gas to the U.S. In Alberta, all that gas gets comingled. A
particular molecule cannot be attributed to Alaska or Canada
physically, although it can be through accounting.
MR. PULLIAM said today Western Canada exports gas to the U.S.
If Alaska's gas connects into that, it increases the supply
there and effectively pushes the gas into the U.S. As long as
Canada exports more than 4.5 Bcf/day, the addition of Alaska's
gas effectively moves it into the Lower 48, in his opinion,
since if Alaska's physical gas is used in Canada, it pushes
Canadian gas into the Lower 48.
REPRESENTATIVE LeDOUX asked: How do we know Canada would
continue to export gas to the U.S. if there were a gas shortage
in Canada?
MR. PULLIAM surmised if Canadian production got so low that
there wasn't anything left to export, the gas would be used
there. However, all projections he's seen show Canada exporting
gas for a long time, although those exports are declining as
production in Canada has declined and usage there has risen.
MR. PULLIAM added that the Canadian and U.S. markets for gas are
tied together as one larger market; that's different from
elsewhere in the world today. They are tied by an extensive
system of pipelines that have operated for some time to move gas
from Canada into the U.S. That is expected to continue for the
foreseeable future.
MS. ADAIR noted her presentation would address some of this.
REPRESENTATIVE SAMUELS remarked that setting aside political
concerns - including federal loan guarantees and what Congress
thinks - if Alaska sold its gas to the tar sands and got the
best price there because of not having to pay the tariff to
Chicago, the state wouldn't care economically.
MR. PULLIAM replied he thought that was correct. To the extent
the federal government allows Alaska to do what it wants with
the gas, seeking the highest netback makes sense. As a
practical and economic matter, if the gas connects into a grid
in Canada, it effectively moves gas into the Lower 48,
regardless of whether it's the same physical gas. He gave his
understanding from discussions with the U.S. Department of
Energy (DOE) and others in the federal government that they'd
view it the same way - not as an export to Canada, but as
facilitating the movement of more gas into the U.S.
10:51:38 AM
SENATOR THERRIAULT emphasized that the shorter the distance, the
higher the netback to the state. If Alaska can sell to a closer
market, it's advantageous in the long term. He requested to
hear at some point about the original congressional language or
the treaty between the U.S. and Canada as far as anticipating
where the gas would ultimately be delivered and whether there is
a commitment or requirement that a certain number of molecules
make it across the border.
REPRESENTATIVE SAMUELS replied if they cannot get the answer in
the next two days, they'll task somebody with getting it during
the special session. It is a good point as to whether Congress
requires the gas to get to the U.S.; some rules for the
$18 billion in loan guarantees haven't been written yet.
REPRESENTATIVE SAMUELS emphasized that TransCanada's proposal
has suggestions, not requirements, on how the company would
structure those; it will depend on Congress. Although some
won't be answerable, there can be research on what has been done
so far and whether rules say certain molecules or a certain
amount of extra gas must go somewhere in particular and not end
up in Canada's tar sands.
10:53:12 AM
MR. PULLIAM turned to the last point on slide 1, saying
TransCanada proposes to provide pipeline access for an LNG
facility if demand warrants - if, when an open season is held,
there is sufficient demand for a pipeline into Southcentral
Alaska or Valdez to build an LNG facility.
REPRESENTATIVE SAMUELS suggested saving the following for the
roundtable discussion, since FERC and rate making would be
involved. He posed a scenario with an open season in which
somebody bids 2 Bcf/day for LNG, which wouldn't leave enough gas
to build the across-Canada pipeline. He asked who would
determine in the open season which bid to take.
MR. PULLIAM answered in part, saying if there were an open
season with such demand for in-state use, he believes it would
cause TransCanada to look at whether it would build the rest of
the line or what makes the most sense. Typically, a company
would rank commitments in terms of the present value of those in
an open season and then allocate them based on what gives the
highest value overall.
REPRESENTATIVE SAMUELS asked who would have that say - the
state, the federal government, or the pipeline company.
MR. PULLIAM gave his sense that it's a process the pipeline
company would go through.
10:56:32 AM
MR. PULLIAM paraphrased slide 2, the second on what TransCanada
proposes to do, which said:
Offer tariffs reflecting:
- 20, 25 and 30 year firm transportation commitments
- Recourse and Negotiated Rates (Alaska); Negotiated
Rates (Canada)
- Capital Structure of 70% debt/30% equity (recourse),
75% debt/25% equity (negotiated)
- Equity return floating at 965 basis points above 10-
year T-bonds
- 100% cost recovery (3.5 MMBtu/day and above)
MR. PULLIAM added that TransCanada proposes two types of
tariffs: 1) a recourse rate, a traditional cost-of-service rate
that is required by AGIA, and 2) a negotiated rate, which is
something the parties sit down and come to agreement about.
Both would be addressed later. Consistent with the requirements
of AGIA, TransCanada is offering the capital structure set forth
above; the negotiated rates are for when the pipeline comes into
operation, when there'd be a little higher debt ratio.
MR. PULLIAM noted the equity return is a little different from
other U.S. pipelines. It would float year to year at 965 basis
points above 10-year Treasury bonds ("T-bonds"); this equals
9.65 percent interest. If T-bonds are at 5 percent, the total
would be 14.65 percent.
REPRESENTATIVE SAMUELS recalled during the session Mr. Porter
had looked back at the rate of return (ROR) for 10-year T-bonds,
finding the floating rate of return went from 14 percent to the
mid-20s. He asked Mr. Pulliam if he'd run a calculation
comparing that and whether he could confirm that the ROR could
go that high.
MR. PULLIAM indicated he'd show calculations later. Turning to
the final point on the slide, he said TransCanada's tariffs
would reflect 100 percent cost recovery, meaning those shipping
on the pipeline would be expected to pay ultimately for the full
cost of constructing and financing the pipe, as well as the
associated operating costs. TransCanada is offering to build as
long as commitments are greater than the amount shown.
10:59:45 AM
MR. PULLIAM addressed slide 3, the third slide on what
TransCanada proposes, which had the following points:
- Assess market demand for expansion every two years
through non-binding open seasons
- Offer rolled-in rates for expansions, subject to
ceiling of 115% of initial tariff
- Provide minimum of 5 in-state delivery points, using
distance-sensitive rates
MR. PULLIAM noted these are consistent with AGIA. The second
point means if the cost of expansion would drive up the initial
rates by less than 15 percent once expansion costs are factored
in, then those rates would be included in everyone's tariff,
including the tariff for those that committed in the initial
open season. It may drive rates down as well by putting more
gas in there, but rolled-in treatment would be used at least up
to the 115 percent ceiling. He would show an example later.
REPRESENTATIVE SAMUELS posed a question for Mr. Pulliam and
Dr. Neri when that time comes: Can that number be negotiated
away?
REPRESENTATIVE CRAWFORD inquired about the difference between
binding and nonbinding open seasons.
MR. PULLIAM answered that a nonbinding open season is one in
which the company solicits interest in transportation, rather
than requiring someone to sign up at that point. In a binding
open season, if someone responds to a solicitation and it is
accepted, that is binding and the party would then be expected
to sign a firm transportation (FT) commitment.
MR. PULLIAM, in further response, relayed his understanding that
it would be up to TransCanada to conduct the proceeding. But
explorers or potential shippers would be the ones to respond and
say what type of capacity they'd like and so forth.
REPRESENTATIVE CRAWFORD asked whether TransCanada could respond
by saying no.
MR. PULLIAM said he wasn't sure, but they have to conduct it.
He gave his understanding that if the demand is there and people
are willing to pay the cost of the proposed tariffs, they'd be
required to go forward.
SENATOR WIELECHOWSKI asked how it works. For instance, does the
open season have to be for gas to Alberta or Valdez, or can it
be for gas to anywhere?
11:04:08 AM
JOHN NERI, Ph.D., Benjamin Schlesinger and Associates, Inc.,
gave his understanding that this is once the pipeline has been
constructed. If the pipeline is from Prudhoe Bay to Alberta,
the points would have been defined already and the nonbinding
open season would be the pipeline's way of finding interest from
shippers as to whether it should expand the system. If, over
the years, there are intermediate receipt or delivery points, it
gets a little more complicated and there might be open seasons
for those points.
11:05:10 AM
REPRESENTATIVE FAIRCLOUGH asked: If it can't exceed 115 percent
of the cost in determining access to the line, is there an
inflation-proof factor for construction, or will inflation eat
it up so there is no longer an assessment of the market?
MR. PULLIAM offered his understanding that if they couldn't
expand within the 115 percent cap, they wouldn't be required to
offer rolled-in treatment for an expansion. An expansion could
still take place, but it would bear whatever incremental costs
were associated with it.
REPRESENTATIVE FAIRCLOUGH expressed concern, saying it limits
access to the line if someone has to pay the entire expansion
cost but inflation for construction isn't factored into a
baseline tariff.
REPRESENTATIVE LeDOUX asked if anyone could answer definitively.
MR. PULLIAM suggested someone from the administration probably
could.
11:07:57 AM
SENATOR ELTON highlighted the second point on slide 3, "Offer
rolled-in rates for expansions, subject to ceiling of 115% of
initial tariff." He asked if TransCanada is required to do so.
MR. PULLIAM affirmed that, noting the 115 percent ceiling is
required by AGIA.
SENATOR THERRIAULT gave his understanding that the rolled-in
rates, the 115 percent cap, and the ROR must be sanctioned by
FERC. TransCanada hopes for a 14 percent ROR; the producers or
whoever ships on the line will negotiate that rate down, which
is in the state's best interests because the netback would go
up. He recalled that the FERC language says there can be
rolled-in rates, but not to the point of subsidization, a point
FERC determines.
SENATOR THERRIAULT also recalled that the state required that
TransCanada propose in its application that it is willing to do
rolled-in rates up to 115 percent. But until it goes to FERC,
it isn't known if FERC will set that cap at 105 percent, for
instance. He requested discussion about what the state asked
for, what TransCanada proposed, and FERC's role in this.
MR. PULLIAM opined that it's under the control of the regulators
and that FERC said there'll be a presumption that rolled-in
treatment is appropriate for expansions; this doesn't mean it
has ceded control or oversight, however, since FERC is the
ultimate arbiter of what is required. He suggested FERC's role
in the process might be different in the context of a recourse
rate versus a negotiated rate.
11:11:35 AM
DAN DICKINSON added that the administration, in several places
in the findings, pointed out that the State of Alaska could be
among the parties that appeal, saying it should be 500 basis
points, for instance. The state isn't bound by this plan and
could be appealing those numbers along with the shippers.
MR. PULLIAM turned to the final point on slide 3. He said it's
consistent with AGIA that TransCanada is offering to provide a
minimum of five in-state delivery points and to offer tariffs on
a distance-sensitive basis. An example of how such rates work
would be shown, but it means tariffs for movement in Alaska
would be related to mileage and would be lower than for movement
outside of the state.
SENATOR WIELECHOWSKI asked whether there'd be a "postage stamp"
rate for all of Alaska, so if there are five offtake points
they'd have the same rate, even if one required 100 miles of in-
state line and the other required 700 miles.
MR. PULLIAM affirmed that. He said the rate is calculated based
on the average delivery cost for all those locations.
11:13:10 AM
REPRESENTATIVE KELLY returned to rolled-in rates. Interpreting
Mr. Pulliam's remarks about the 115 percent cap to mean the
incremental shipper has to pick it all up, he asked: Is it not
the case that it's rolled in up to the 115 percent constraint
and then the delta above that the incremental shipper picks up
at 100 percent, instead of the whole deal being off?
MR. PULLIAM said he wasn't sure if the entire increment would be
picked up or it would just be the amount above 115 percent.
REPRESENTATIVE KELLY asked Mr. Pulliam to get back on that. He
also asked about inflation, surmising the 115 percent is
strictly in nominal dollars.
MR. PULLIAM gave his understanding that it would be the rate
that would be expressed in nominal dollars.
MR. DICKINSON added that the first series of expansions, as
noted on the previous slide, will probably lower the rates for
everyone. The rolled-in rates occur later, when looping is
required. It won't be going from a base. Inflation may or may
not eat it up, and there will be more overhead than 15 percent.
11:15:09 AM
REPRESENTATIVE FAIRCLOUGH focused on distance-sensitive rates,
asking what happens with respect to Alaska's offtake in relation
to the rate for going through Canada, because there's less to
monetize going through that line for capital construction costs.
MR. PULLIAM replied that the cost is spread out for all movement
of gas throughout Alaska, whether it's going to the border or to
locations in Alaska. Then the cost is allocated based on the
mileage and the volume to those different locations.
REPRESENTATIVE FAIRCLOUGH offered that the more gas that is
taken off in Alaska for in-state use, the higher the tariff rate
will be because there will be less to monetize going to market
through Canada.
MR. PULLIAM said that's what he anticipates.
11:15:58 AM
REPRESENTATIVE WILSON gave her understanding from meetings in
Anchorage that it would depend on how far the gas has already
come down the pipeline. She interpreted Mr. Pulliam's remarks
to mean that if there is only one offtake point and they pay $3,
and then two years later a new offtake point is added much
farther down the line, it still would be added together so that
the tariff for the first offtake point would go up.
MR. PULLIAM responded if that occurred after the initial offtake
points were set, he wasn't sure if it would lead to two
different rates or would all get rolled into one. He said he
didn't know if it would change the overall in-state rate and
didn't believe the proposal specified how that would work.
11:18:00 AM
REPRESENTATIVE GARDNER said the tariff rate is set for the
original shippers; over time, expansion shippers, using
compression expansion, bring down the rate for everyone. So the
last new shipper using the rolled-in rate starts out at the
lowest potential rate. Then new expansion shippers come in and
looping is required. For the 115 percent ceiling for the last
of the expansion shippers before the looping rates, she asked if
that's 115 percent of the lowest possible rate or if the
expansion shippers would experience a new tariff that has a
ceiling of 115 percent of what the original shippers paid, the
highest rate to date.
MR. PULLIAM replied it's 115 percent of the initial rates, to
his understanding.
REPRESENTATIVE GARDNER surmised the expansion shippers would
experience an increase that could be significantly more than
they'd signed up for.
MR. PULLIAM said it could be; that's his understanding.
11:19:33 AM
REPRESENTATIVE LeDOUX referred to Representative Wilson's
question about in-state delivery points. She asked: If there
isn't anything in the proposal to cover that, should there be?
MR. PULLIAM replied nothing he sees in the proposal addresses
the specific question. He indicated it might be helpful to
include that if a license is issued. Also, there is a
regulatory backstop, since FERC will look at it and ask whether
it's a reasonable treatment if there's any ambiguity. If the
desire is to lock it in up front, though, that could be done.
11:20:56 AM
REPRESENTATIVE SAMUELS posed a question for all the consultants
later: Will the entire 115 percent evolve around how FERC
interprets the word "subsidization"? For instance, if BP is
paying $3.00 as a tariff, with the potential risk that it will
go to $3.45 - billions over the life of the project - is it
subsidization?
REPRESENTATIVE SAMUELS followed up on Senator Therriault's
comments, saying FERC will determine this. As he recalled, the
shippers when they take FT commitments could argue their
economic interests before FERC, but AGIA requires that
TransCanada ask for this and then the state can go with what it
believes is in its best interest for the tariff. He added that
the mandate from Congress which leaned towards rolled-in tariffs
and expanding the basin will play into it somehow, but a roomful
of lawyers at FERC will determine that.
MR. PULLIAM indicated later this would be addressed somewhat.
He turned to slide 4, a proposed timeline assuming a license is
awarded in April 2008. Since it wasn't awarded then, he said
the timing would move back accordingly unless there are places
where TransCanada believes it can make up for that.
MR. PULLIAM said the initial open season is envisioned 18 months
after the license is awarded, September 2009 on this timeline.
If it's successful, FERC filings would be in place for the
certificate of public convenience and necessity, he indicated,
which would ultimately allow TransCanada to begin construction.
MR. PULLIAM noted the anticipated FERC response is in April
2013, with project sanction at the beginning of 2014, which
starts the construction process. This takes the project to
early 2018, although initial gas is shown on this timeline for
November 2017. He pointed out that the administration's
findings include different assumptions for timing and generally
see this schedule as optimistic, predicting instead that first
gas will be about 2020.
11:25:19 AM
REPRESENTATIVE CRAWFORD told members how extremely irritated he
feels that it takes four years to get FERC approval, but two
years to build it. Saying America needs this gas, he suggested
focusing on getting expedited FERC approval.
SENATOR WIELECHOWSKI asked whether FERC would expedite this and
where the holdup is that would cause a three-year delay, to
2020, in getting the gas on line.
MR. PULLIAM gave his assessment that FERC is committed to
expediting it and is charged by Congress with doing so, which
FERC takes seriously; later in the month someone from FERC would
address those issues. One delay relates to the ability to do
work in the summertime. This requires phasing, and the timeline
on the slide is based on getting a license in April 2008 so work
can start in the summer. If the license is issued at the end of
summer, it pushes work back a year. He said the administration
could better explain other delays, since they'd looked at all
the regulatory and construction phases.
11:28:21 AM
MR. PULLIAM showed slide 5, "What Does TransCanada Ask From the
State?" It had the following points, along with a chart under
the third bullet point that showed amounts budgeted, the state
reimbursement, and the reimbursement percentages:
- License
- Follow through on State commitments under AGIA
- State Contribution of $500 million toward
development cost of pipeline
- Not to be included in tariff rate base
REPRESENTATIVE GARA returned to slide 4, surmising a four-year
FERC approval process also would apply to any other proposal,
including one from the producers.
MR. PULLIAM replied he wasn't aware of anything in the FERC
approval process specific to just TransCanada or the producers.
MR. NERI added that FERC approvals for pipelines in the Lower 48
typically take 24 months or less. He wasn't certain why it
might be 48 months for this proposal, although it is a large
project with unique circumstances.
11:29:58 AM
REPRESENTATIVE LeDOUX asked about the state license versus what
is issued from FERC.
MR. DICKINSON explained that FERC issues a certificate, a
critical step in building a pipeline. But the state has now
defined its license, a copy of which can be found on the
website; it is distinct from what FERC does.
REPRESENTATIVE LeDOUX asked whether that means the producers
can't do anything without a state license.
MR. DICKINSON replied the license refers to three documents:
AGIA; the request for applications (RFA) put out as a
consequence of AGIA; and the application. He indicated the
commissioner of the Department of Revenue (DOR) had said nothing
in the license prevents anyone from doing the same things
without it. The license grants certain benefits to whoever
holds it, and it is a one-time deal for one company.
REPRESENTATIVE LeDOUX suggested it equates to the $500 million.
MR. DICKINSON agreed that's the most visible aspect, but said
other things are being granted. He mentioned a coordinator.
AN UNIDENTIFIED SPEAKER mentioned treble damages.
11:32:41 AM
REPRESENTATIVE HAWKER asked whether Canada's regulatory agency
would be involved and might complicate this timeline or whether
that is encompassed in the FERC timeline.
MR. PULLIAM answered that this chart came from TransCanada's
proposal, and he believes it encompasses a generic label of
FERC. While this is ongoing, though, the same process would
have to be going on with Canada's National Energy Board (NEB).
AN UNIDENTIFIED SPEAKER asked whether the regulatory
interrelationship would be discussed later.
MR. PULLIAM agreed it could be talked about.
11:33:43 AM
REPRESENTATIVE WILSON asked: If the state gives a license to
TransCanada, doesn't the treble damages provision mean the state
couldn't give a license to anyone else?
MR. DICKINSON opined that the treble damages provision is
triggered by a payment of money, presumably the $500 million or
favorable treatment with respect to the royalty or tax, although
he couldn't recall the exact language. There is a process to
award one license, which is now before the legislature. If it
fails, there may be another process to bring up another license,
but he didn't believe it was anticipated that a second live
license would be issued.
REPRESENTATIVE WILSON gave her understanding that if the state
assisted anyone else, the treble damages provision would apply.
MR. DICKINSON replied there are caveats. If at some point the
project is found to be uneconomic and both parties mutually
withdraw, there'd be no treble damages. The treble damages
would only occur if, say, one party thought it was uneconomic
but the other didn't; then it might be asked whether the state
was doing something with another party.
MR. DICKINSON suggested looking at the language defining treble
damages, noting there are two clauses: one that triggers it and
one that defines the amount. Those don't use the same words and
therefore might cause legal debate. He opined that assistance,
particularly nonexclusive assistance, wouldn't trigger it.
SENATOR STEVENS asked if the treble damages are for the amount
of money expended or include loss of revenue.
MR. DICKINSON proposed looking carefully at the statute and
getting a legal opinion. He said the words are ambiguous to him
as a layperson. He recalled last week in Anchorage the
Department of Natural Resources (DNR) commissioner, who isn't an
attorney either, defined the treble damages as measured by what
is left over after reimbursement.
MR. DICKINSON highlighted slide 5. He said the commissioner's
interpretation was that the maximum treble damages would be
three times $111 million, or $333 million. However, others
would say it's three times the total spent, closer to $2.4
billion. There is some question as to whether it's three times
on top of what has already been paid or the total payment.
11:37:25 AM
MR. PULLIAM explained the chart under the third bullet point of
slide 5, saying the state's contribution of $500 is something
TransCanada's proposal asked for; AGIA has provisions on that
contribution, including how much can occur prior to the open
season, during the certification period, at least as a
percentage. What is shown on the slide is from an amendment to
TransCanada's proposal as to how those dollars would be spent.
MR. PULLIAM noted about $82 million is budgeted through the open
season, with the state reimbursing 50 percent; to get to the
certification TransCanada anticipates another $528.7 million,
with the state reimbursing $458.8 million. That's about
87 percent, whereas AGIA calls for 90 percent - less because the
$500 million cap is reached during that time. Overall, through
the certification period, the proposed budget is about $611
million, with the state contributing $500 million, about 82
percent.
MR. PULLIAM said about $29 billion is estimated all the way
through construction; the state's $500 million contribution
would be about 2 percent of that. The $500 million cannot be
included in the rate base, which is worth about 5 cents per
MMBtu on the tariff. Examples would be shown later.
CHAIR HUGGINS requested confirmation that AGIA requires
TransCanada to go to certification, but not build the pipeline.
MR. PULLIAM affirmed that.
SENATOR ELTON referred to presentations by the state's reviewers
of the license application, recalling they'd suggested that the
$500 million affects the tariff assessed afterwards and that if
there is a successful project, the amount will actually be an
investment which returns dollars later.
MR. PULLIAM agreed it certainly is an investment. He said the
question is what the return will be. Part of what the state is
doing is buying down the tariff for all shippers, about 5 cents
per MMBtu. The state has a fairly large percentage of the gas
"pie" with its royalty and taxes, particularly at projected
price levels; it will get a big piece back in tariffs. Also, as
with any investment, this is making a bet, taking some risk in
return for a lower tariff and with the hope that it will help
move the process along.
11:42:08 AM
SENATOR THERRIAULT recalled hearing last week that the expected
tariff reduction is 6 cents. He asked about the difference,
saying the 5 cents is at $1.2 billion and so that penny is
meaningful. He also expressed concern that some folks believe
the state will write a check for $500 million the day after the
license is issued, though that's not how the law works.
MR. PULLIAM opined that the difference between the 5 cents he'd
quoted - which is based on TransCanada's estimate - and the
administration's 6 cents is from using different cost levels for
the pipeline and a longer construction period, which results in
a little higher savings but on a higher tariff. As to the
second point, he agreed a check wouldn't be written right away;
these would be matching funds provided after review of the
expenditures, to his understanding.
SENATOR GREEN asked: If the $500 million makes a 5-cent or 6-
cent difference and the state sees it all invested early on, up
to 82 percent of the investment total preconstruction, wouldn't
it make the same difference if that $500 million were extended
out over, say, only up to 50 percent throughout the process
until the state reached its $500 million?
MR. PULLIAM answered that it should have a little larger effect
earlier in the process. In calculating tariffs, a pipeline is
entitled to an allowance for funds used during construction
(AFUDC), which is like interest on money invested. To the
extent that the state defers earlier dollars, it actually would
have a little more impact on the tariff savings.
SENATOR GREEN said she wants assurance that the pipeline will
get built as the state invests its $500 million.
SENATOR BUNDE asked: Could AGIA have required the building of a
pipeline?
MR. PULLIAM replied he wasn't sure. As things normally
progress, a company goes to FERC for certification after getting
commitments to ship gas. If FERC provides the necessary
certificate, it would be in the pipeline's interest to go ahead
if it has those commitments.
11:46:14 AM
REPRESENTATIVE LeDOUX suggested if this gets all the way through
the certification process, FERC could say this is a go, the
commitments could exist, and the $500 million could already be
paid. She asked whether TransCanada could decide not to do it
because it doesn't seem economically viable.
MR. DICKINSON answered that TransCanada may have that legal and
technical ability. Practically, though, if binding shipping
commitments exist and TransCanada has obtained FERC
certification under the terms of AGIA, it seems unlikely to
decide against proceeding unless there are some extraordinary
conditions on the certificate. There is an out if TransCanada
meets the criteria for proving it's uneconomic, though at that
point it would be pretty hard to do so. Also, the state could
challenge it, if it were obviously economically viable, and say
the company needed to proceed.
MR. DICKINSON noted if there is a failed open season and
commitments don't exist, however, TransCanada would be applying
for a certificate and paying 10 cents on every dollar - with the
state putting out 90 cents - without much hope of a return.
TransCanada will want to find customers. If so, it will likely
get a certificate. But having a certificate doesn't find
customers, the gas shippers who use the transportation service.
REPRESENTATIVE LeDOUX gave her understanding, then, that
TransCanada would have to prove it's not economic in order to
decline to build the pipeline. It couldn't simply decide on its
own that the project isn't economic.
MR. DICKINSON replied he would double-check, but believed that
to be the case.
11:50:57 AM
MR. PULLIAM summarized slide 6, the second slide on what
TransCanada asks from the state, which had the following points
from TransCanada's proposal:
- Engagement with ANS producers to reach agreement on
fiscal terms
- Encouragement of robust exploration and development
of North Slope gas resources
- Cooperation of State to reach out to stakeholders
- Cooperation of State in efforts with the Federal
Government to obtain support for project
- Use of loan guarantees for cost overruns
- Exploration of alternative credit concepts, i.e.,
backstop Shipper contract
MR. PULLIAM relayed his understanding that these aren't
requirements, but things TransCanada is asking the state to do
in order to help make the project work.
11:51:18 AM
REPRESENTATIVE CISSNA highlighted the third point, saying
unanticipated problems increase costs and slow a project, which
for mega-projects can be disastrous. Noting she represents
stakeholders, citizens in communities with a local economy, she
surmised TransCanada has experience with socioeconomic impacts.
Saying many such impacts are starting already, she asked what
consideration has been given to how TransCanada and the state
can mitigate any negative aspects or costs.
MR. PULLIAM gave his reading that TransCanada hadn't
specifically addressed that in the proposal, other than working
in cooperation with the state to reach out to stakeholders. He
interpreted this to mean that if people are impacted in some
negative way, TransCanada would reach out to try to resolve it.
MR. PULLIAM agreed that the larger the project, the more there
is to consider, things that can and do go wrong. One should
spend time getting the planning right at the outset - the better
the planning, the better the execution. He said he thought it
would be important during the planning process to listen to the
concerns of individuals in communities as to what those
negatives might be.
MR. DICKINSON recalled in the prior go-round there was a body
created, a municipal advisory commission, which hired
Information Insights and did a report. Noting many items looked
at would be features of this project as well, he suggested that
is a good place to start.
11:55:59 AM
REPRESENTATIVE LeDOUX asked about the first point, "Engagement
with ANS producers to reach agreement on fiscal terms."
MR. PULLIAM gave his interpretation that TransCanada wants an
agreement on the fiscal terms to remove any potential impediment
to a successful open season and getting the pipeline
operational.
REPRESENTATIVE HAWKER asked whether these are conditions or
gratuitous requests that the state doesn't need to follow up on.
MR. PULLIAM answered that as a legal matter he didn't know, but
he didn't believe they were gratuitous. He'd seen
correspondence back and forth and didn't believe they were
characterized as precedent or legally binding. He gave his
understanding that TransCanada believes these are important
issues on which they'd like to see progress.
REPRESENTATIVE LeDOUX asked if this is returning to the issue of
fiscal certainty, an impediment a couple of years ago.
MR. PULLIAM indicated he believes fiscal certainty through
locking in the tax rate is part of it, together with the
percentage the state gets. He surmised TransCanada would want a
reasonable balance between the state and the producers as to how
the state effectively taxes the pipeline, which would impact the
tariff. Potentially more important is how the state taxes the
gas production itself.
11:59:57 AM
MR. DICKINSON explained the state's taxes and royalties. First,
property tax that the project pays goes into the tariff and gets
paid by the shippers, although TransCanada will get the bill.
Second, there is an allowance for income tax, including
corporate income tax; if TransCanada makes profits on the
pipeline it will get the bill, but it goes into the tariff and
is paid by the producers. Third, production tax is based on
production; TransCanada presumably would have no production, so
it would be paid by the producers. Those are the taxes.
MR. DICKINSON said, fourth, royalties are based on what is
produced off of state-owned land, so TransCanada wouldn't pay
those either. So taxes and royalties to the state if this
project is built won't come out of TransCanada's pocket.
They'll all come from the shippers, presumably the producers
that are the customers on the pipeline.
REPRESENTATIVE LeDOUX asked: In order to get this to a
successful open season, will the legislature have to talk about
providing the producers with some fiscal certainty on taxes over
a specific length of time?
MR. PULLIAM replied he didn't know, but TransCanada has said it
would like for the state to come to an agreement with the
producers on fiscal terms; in their view, that would facilitate
a successful open season and project.
REPRESENTATIVE DOOGAN asked: If the legislature approves a
license for TransCanada, does it obligate the state either to
reach an agreement with the producers on fiscal terms or to
discuss fiscal terms with them? Or is this a third category -
things TransCanada would like the state to do - along with the
contract and economic assumptions?
MR. PULLIAM replied that is his understanding. As it's packaged
in the context of a license - referring to AGIA, the RFA, and
TransCanada's proposal - whether that creates something as a
legal matter he couldn't answer. But based on public discussion
from the administration and TransCanada, it seems to be in the
category of things TransCanada would like the state to do that
it believes are helpful in moving the project forward. He
opined that neither side has said, at least publicly, that any
of these are binding.
REPRESENTATIVE DOOGAN requested to hear from any of the LB&A
consultants or the administration's consultants if they disagree
with that interpretation.
12:03:47 PM
MR. PULLIAM addressed slide 7, the third slide on what
TransCanada asks from the state, which had the following points
from TransCanada's proposal:
In the event of an unsuccessful open season:
- Expect State to use its position of sovereign
government to encourage, induct and persuade ANS
producers to commit gas
- Expect State to thoroughly evaluate and seriously
consider financial and commercial feasibility of
dedicating significant State resources to
underwriting an alternative financing mechanism for
the project
REPRESENTATIVE LeDOUX asked: If there's not a successful open
season - meaning there's no agreement to ship the gas - what
project would there be and what difference would it make if the
state finds an alternative financing mechanism for it?
MR. PULLIAM replied if nobody commits gas in the open season in
sufficient quantities, the question is how to make the project
go. Gas is the way to get financing. These types of projects
typically aren't done on speculation, and that isn't anticipated
here. As he reads the proposal, if there isn't a successful
open season TransCanada asks for the state to perhaps look
creatively at ways to finance it, including state guarantees or
funds, for instance, or legal action to get commitments.
REPRESENTATIVE LeDOUX surmised the state assumes if the pipe is
there, the gas will be there and the customers to use the line.
MR. PULLIAM responded that the biggest cost of the pipe is the
upfront capital; about 75 percent of the tariff cost comes from
those construction and financing costs. If that is overcome and
the pipe is there, under almost any conceivable scenario of gas
prices and operating costs, there'd be a tremendous incentive to
sell the gas. If someone came in and laid the pipe at one's
feet, the tariff would likely be cheap.
MR. DICKINSON clarified that there can be more than one binding
open season. The open season is a sort of shorthand; then there
must be agreements and so forth to get the commitments. Simply
having one open season that doesn't result in express
commitments doesn't stop the process; the company can keep going
and might change terms.
MR. PULLIAM concurred.
12:08:37 PM
SENATOR ELTON asked: If the legislature approves the license,
will this be a playground for lawyers with respect to treble
damages, for instance, because this information and these
requests have been transmitted? He suggested the need for legal
advice on whether the state has accepted legal obligations from
the applicant.
REPRESENTATIVE SAMUELS surmised the consultants hadn't looked
into that, saying it could be looked at by an attorney.
Returning to the first point on slide 7, he suggested there
could be a reserves tax, a tax deal, delayed taxes, a rebate,
and so on. But if there is no gas, TransCanada wants the
state's help in some way to get gas into the pipeline. It
doesn't specify whether it is a carrot or stick and has no
timeline. He requested confirmation from Mr. Pulliam.
MR. PULLIAM said he thinks that's what TransCanada is asking.
12:10:48 PM
CHAIR HUGGINS told members he'll be pursuing a contract to go
along with a license. He suggested having a contract that takes
the state's "must haves" in AGIA and what TransCanada has asked
for, forming an amalgamation. This would clear up any ambiguity
so the legislature knows what it is agreeing to.
12:12:12 PM
MR. PULLIAM read from slide 8, "How Does the State Subsidy
Help?" It had the following points:
Reduces risk to TransCanada
- State shares in risk that project may not proceed to
completion and is responsible for 82 percent
($500 Million) of the targeted $611 million in
development costs
Reduces tariff, which benefits resource owners: State
and producers. Using TransCanada assumptions as to
costs and tariffs, the $500 million impacts the tariff
as follows:
- Estimated tariff to Alberta without subsidy is
$2.46/MMBtu
- Estimated tariff to Alberta with subsidy is
$2.41/MMBtu
- This is $0.05/MMBtu
- Over a 25-year period, this amounts to a reduction
in tolls of $2.2 billion. Approximately
$1.2 billion is expected to accrue to the State
MR. PULLIAM added that this reduces upfront risk to TransCanada,
since its initial outlay would be relatively low. And by
reducing the tariff, it also benefits the resource owners. The
subsidy is worth about a nickel per MMBtu.
MR. PULLIAM indicated the $1.2 billion to accrue to the state
was an estimate from the LB&A consultants. As for how $500
million gets $2.2 billion back, the $500 million today has the
effect of offsetting capital costs by giving a return that is
akin to interest. In response to Representative Hawker, he said
these are all expressed in nominal dollars.
REPRESENTATIVE HAWKER noted these would be cash dollars that
come in over 25 years, then. If the traditional present-value
calculation is followed, comparing $500 million today versus a
cash-flow stream of $1.2 billion over 25 years, it isn't a one-
to-one comparison as to what is being invested versus what is
being obtained.
MR. PULLIAM agreed, saying it would be much less than the
present value of $1.2 billion.
REPRESENTATIVE GARA asked if the state wouldn't have to spend
the full $500 million if the producers committed their gas to
the point where this could proceed.
MR. PULLIAM gave his understanding that if the legislature
approves the license, it commits the state to spending the
$500 million up to the point of getting a certificate, even if
the producers were to commit their gas immediately.
12:15:43 PM
SENATOR FRENCH asked what estimates the LB&A consultants had
arrived at. Recalling that last week's presentation in
Anchorage showed much higher estimates from Black & Veatch
compared with TransCanada's on slide 8, he said a quick
conversation with one of the administration's consultants
indicated the big difference - about $1.50 - is the difference
between a cost estimate developed today in today's dollars
versus a cost estimate for the 2016 time period for actual
construction.
MR. PULLIAM agreed the administration predicts higher tariffs
than TransCanada does. First, the administration estimates
capital costs overall will be higher in today's dollars because
the GTP will be more expensive to build and the exchange rate
between Canadian and U.S. dollars will be lower than in the
projections required by the RFA.
MR. PULLIAM said, second, it forecasts higher inflation, about
4 percent a year versus 2.5 percent. Third, it estimates
completion in 2020, two years later than TransCanada's 2018,
increasing interest on the moneys invested. Finally, it
predicts higher borrowing costs.
MR. PULLIAM noted those all factor in. He anticipates the
tariff will likely be higher than what is in TransCanada's
proposal. He said he isn't an engineer and so cannot go into
cost estimates like some of the consultants hired by the
administration, but he has looked at their reports and doesn't
see anything that strikes him as unreasonable with respect to
cost estimates or assumptions they used in determining a tariff.
He hadn't heard yet from TransCanada about the differences.
12:19:40 PM
MR. PULLIAM addressed slide 9, "Tariff Fundamentals," which had
the following points:
What is a tariff?
- Document that sets forth rate and terms of service
provided by a pipeline to shippers
- The per-unit cost charged by a pipeline to ship gas
from point of injection to point of extraction
(Point A to Point B)
MR. PULLIAM added that the $2.41 to Alberta is the per-unit
charge, for instance. He characterized the tariff as the entire
package governing the service.
MR. PULLIAM turned to slide 10, a map labeled "TransCanada's
Tariff Estimates" that gave these estimates: GTP $0.59, Alaska
section $$0.92, Yukon-BC section $0.75, and Alberta section
$0.15, for a total without fuel of $2.41; fuel $0.86 and a total
with fuel of $3.27. A footnote, related to the fuel and total
with fuel, said "25-year average based on AEQ2008 price profile
at Henry Hub, with $0.40/MMBtu differential to AECO."
MR. PULLIAM noted much of what he'd been planning to say here
had just been discussed. In response to Senator French, he said
this all assumes 4.5 Bcf/day coming into the GTP.
MR. PULLIAM explained that when someone signs a tariff, there is
an agreement to pay a certain per-unit rate and provide the fuel
consumed in the operations. The pipeline doesn't send the
shipper a bill for the fuel but takes it out of the gas. The
cost is the value, what the gas would yield on a netback basis
on the North Slope. The higher the price, the higher that fuel
component will be; the lower the price, the lower the component.
The slide shows an estimated average cost of $0.86 for fuel.
MR. PULLIAM specified that these are all nominal dollars over
the 25-year period, assuming gas prices in AECO consistent with
the DOE's latest forecast put out earlier this year, less a 40-
cent differential between Henry Hub and AECO. Observing that
TransCanada's estimated total with fuel is $3.27, he suggested
the administration's number would be closer to $5.00.
12:23:10 PM
MR. PULLIAM paraphrased slide 11, "Significance of the Tariff to
Resource Owners," which said:
All else equal, resource owners (State and producers)
prefer lower tariffs; lower tariffs = higher netbacks
In the case of gas, tariffs typically involve long-
term "take or pay" commitments. Here we are talking
about commitments likely ranging between 15 and 30
years
- In this respect, gas pipeline tariffs are different
than oil pipeline tariffs. With oil pipelines (such
as TAPS), there is typically no take or pay aspect
- Risk to shipper rises with length of commitment
- Risk to shipper rises with level of tariff relative
to the expected gas price
- Tariff level is fixed while price of gas at market
is unknown and variable
MR. PULLIAM emphasized that risk to the shippers rises -
although risk to the pipeline falls - with the length of the
commitment. This is because a tariff, at least when it has been
negotiated, locks in a consistent price level per unit for
shipping. What's typically unknown, though, is the market price
for gas. The further out in time one goes, the more unknown
that is. So the risk to the shipper that signs on to the
consistent payment of the tariff increases as the time
commitment increases.
MR. PULLIAM showed slide 12, a graph depicting an example of gas
prices and a tariff, also labeled "Significance of the Tariff to
Resource Owners." He noted the bars at the bottom show the
fixed tariff over time, not including the fuel component.
REPRESENTATIVE GARDNER highlighted risk to the shipper. She
asked: Is it practical for the state to offer what the
producers call fiscal certainty so the rate when the contract is
signed holds true until that contract expires or is
renegotiated?
MR. PULLIAM replied he could see some logic in tying those
together, but it boils down to 1) whether it ultimately makes a
significant difference economically to go out over a certain
amount of time and 2) whether legally the state could do so.
The committees took a break from 12:26:29 PM to 1:30:22 PM.
REPRESENTATIVE SAMUELS returned attention to slide 12.
MR. PULLIAM noted they'd been discussing the commitment to ship
and how that leads to a fixed payment over time. What the
shipper hopes to get is the sale of the gas, which generally
isn't at a guaranteed price but varies with market conditions.
The longer it goes over time, the less certainty there is about
that difference, and it introduces an element of risk.
MR. PULLIAM showed slides 13 and 14, similar graphs depicting
the difference if the gas price is lower or if the tariff is
higher than anticipated. In either case, the difference between
the fixed payments and the price received for the gas is less.
It varies over time, and the longer the time, the more economic
risk it introduces.
MR. PULLIAM discussed slide 15, also titled "Significance of the
Tariff to Resource Owners." It had a different graph and said:
Based on current projections by the EIA over 25 years
beginning in 2018 and potential tariffs set out in the
TransCanada application, the tariffs would be
approximately 25% of the value of gas at AECO
MR. PULLIAM explained that this graph depicts a levelized tariff
that TransCanada has put in place, along with fuel costs that
rise over time as a function of gas prices. It also shows
projected gas prices from the Energy Information Administration
(EIA), which is the arm of the DOE that forecasts prices for
Henry Hub, the main trading center in the U.S. What the
consultants did was to bring it back to an AECO basis and add in
the value of NGL extraction to that line.
MR. PULLIAM alluded to the key on the graph, which had the
estimated AECO sales price at $12.91, 100 percent; the tariff at
$2.41, 18.7 percent; fuel at $0.86, 6.6 percent; total costs at
$3.27, 25.3 percent; and a netback at $9.64, 74.7 percent. He
noted EIA's forecast prices are higher and continue to rise over
time. The tariff, with fuel, equates to about 25 percent of the
value of the gas at AECO, with the netback at about 75 percent.
MR. PULLIAM highlighted uncertainty in forecasting oil or gas
prices. He said one reason for considering a gas pipeline is
that expectations for gas prices have gone up significantly in
this decade. These particular forecasts represent the views of
EIA as of early 2008 and generally equate with other forecasts,
though somewhat conservative; Wood Mackenzie and some other
private firms predict higher gas prices. He emphasized that
these forecasts have been evolving over time, with changing
expectations even in the last half a year for both oil and gas.
1:35:36 PM
MR. PULLIAM turned to slide 16, which had a graph similar to
slide 15 and said:
Increasing capital costs by 50% would lead to tariffs
being approximately 32% of the value of gas at AECO
The key showed these figures: estimated AECO sales price at
$12.91, 100 percent; tariff at $3.35, 25.9 percent; fuel at
$0.78, 6.0 percent; total costs at $4.13, 32.0 percent; and
netback at $8.78, 68.0 percent.
MR. PULLIAM clarified that this depicts what would happen if
TransCanada's assumed costs were to increase by 50 percent.
This is more in line with what the administration predicts,
though not quite as high. The total cost including fuel would
be close to one-third of the netback value.
MR. PULLIAM showed slide 17, a three-column summary with these
categories: "25% Below EIA AEO 2008 Forecast," which gave a
netback of 68.7%; "EIA AEO 2008 Forecast," which gave a netback
of 74.7%; and "25% Above EIA AE 2008 Forecast," which gave a
netback of 78.2%.
MR. PULLIAM said the average netback value is shown in the
middle category. For all, the tariff doesn't change but the
fuel element does; lower prices mean lower fuel costs. Under
any of these scenarios there is a good, positive netback,
consistent with the view that gas prices should be fairly robust
going forward.
SENATOR FRENCH asked whether other presentations would address
where the netback falls in relation to other projects globally.
MR. PULLIAM replied it isn't in his presentation, though he
anticipates seeing some from the administration. As for
netbacks, the value at the inlet of the GTP, he said these
certainly appear to be substantial and healthy on a per-unit
basis. The debate will be how to divide that value.
1:38:54 PM
MR. PULLIAM summarized slide 18, "Tariff Fundamentals," which
had the following points:
Tariffs are regulated
- U.S. is regulated by the Federal Energy Regulatory
Commission (FERC)
- Canada is regulated by the National Energy Board
(NEB)
- Charged with insuring that rates are "just and
reasonable"
- Opportunity for shippers to challenge tariffs
through rate proceedings
MR. PULLIAM added that the charge to FERC and NEB to set just
and reasonable rates means the rates would be consistent with a
competitive market operating rates that are cost-based. An
important part of the process is the opportunity to shippers and
other interested parties such as the state to challenge the
rates through rate proceedings. Both recourse rates and
negotiated rates are being offered by TransCanada.
1:40:06 PM
MR. PULLIAM addressed slide 19, "Recourse Rates," which had the
following points:
- Traditionally, tariffs have been based on "cost of
service." Tariff rates under a traditional cost-
based approach are known as "Recourse" rates
- These tariffs provide for recovery of operating
costs, capital costs and a "reasonable" return on
invested capital
- Initial tariffs would be established by FERC in
filings by the pipeline during certification. These
rates could be challenged in FERC and/or NEB by
shippers in rate proceedings
MR. PULLIAM said this is the traditional approach at both FERC
and NEB. Capital costs are for the pipeline itself. The rates
can be challenged by shippers or other stakeholders through rate
proceedings.
MR. PULLIAM showed slide 20, "Recourse Rates and Cost of
Service," which said:
Key elements of cost of service include:
- Return on Investment
- Return of Investment (Depreciation)
- Operating Expenses
- Non-Income Taxes (e.g., Property Taxes)
- Income Taxes
MR. PULLIAM elaborated. He said return on investment includes
return on equity, the cost of the debt. The investment itself
is recovered in a tariff through depreciation; if $20 billion is
spent on the pipeline, that will be depreciated over time. The
others are pass-through costs. For instance, income tax paid by
the pipeline flows through in the rates, so the shippers
ultimately pay it.
MR. PULLIAM said the more profit there is - the higher the
return on equity - the more there'll be in income tax, which
raises the rates. The lower the return on equity is, the lower
the income tax and thus the tariff will be.
1:43:03 PM
MR. PULLIAM discussed slide 21, also labeled "Recourse Rates and
Cost of Service," which showed cost-of-service elements in
TransCanada's estimates as follows: return on investment
$33.2 billion, 32 percent; return of investment (depreciation)
$33.2 billion, 32 percent; operating and maintenance
$9.5 billion, 9 percent; non-income taxes $15.8 billion,
15 percent; income taxes $12.3 billion, 12 percent; and a total
of $104.0 billion, 100 percent.
MR. PULLIAM said the return on investment and return of
investment are about two-thirds of the cost of service that goes
into the tariff. In large part, those drive the tariff rate.
The pipeline has some control over those through what it asks
for as a return and what it invests. The cost of the project
itself dictates what the capital has to be, and then regulatory
agencies have a big say in what the return will be.
MR. PULLIAM added that the pipeline also has some control over
operating and maintenance costs through how it manages those,
but they are a relatively small percentage. It has little
control over taxes, which are set by governments, although it
may have some lobbying influence. Pass-through items are about
one-third of the cost of service.
1:45:09 PM
MR. PULLIAM addressed slide 22, "Cost of Service--Return on
Investment," which read:
Return on Investment is calculated as:
Rate Base x Rate of Return
Rate Base is:
Gross Plant (Initial Capital Investment + AFUDC)
- Accumulated Depreciation
= Net Plant
- Accumulated Deferred Income Taxes
+ Working Capital
= Rate Base
MR. PULLIAM gave details. He said the rate of return is
whatever is allowed. Gross capital is what is put into the
plant initially, along with the AFUDC, which allows interest to
be earned on money invested today; it goes into the tariff
calculation, and the longer the time between when funds are
expended and the project comes on line, the larger this is.
Accumulated deferred income taxes are sometimes known as ADIT.
The rate base is what someone ultimately gets a return on.
MR. PULLIAM showed slide 23, "Cost of Service--Rate of Return,"
which had the following points:
Rate of Return is:
- "Reasonable Return" on Investment (Rate Base)
- Function of three components:
- Capitalization Ratio (Debt, Equity)
- Cost of Debt
- Allowed Return on Equity
MR. PULLIAM reiterated that both regulatory bodies are charged
with setting a reasonable return. The AGIA requirement for the
capitalization ratio is that the pipeline seek to have at least
70 percent debt. That's important. Generally, debt is cheaper
than equity and is tax-deductible; a higher debt-to-equity
ratio, within reason, usually leads to a lower cost of service.
MR. PULLIAM said within that, the cost of financing as far as
floating debt is important and typically is flowed through in
the regulatory process. The allowed return on equity is open to
more debate and is where FERC and NEB will have more of a hand
in what is allowed.
1:47:54 PM
MR. PULLIAM showed slide 24, also labeled "Cost of Service--Rate
of Return," which had the following points:
- These elements are set by FERC to allow "Reasonable
Return"
- Typically allow for pass-through of debt costs, plus
- Return on Equity consistent with business risk
associated with the pipeline venture
- FERC has approved Equity Returns in the range of
12-14%
- Higher end of the range for "greenfield"
projects
- NEB returns have traditionally been lower
- Rate of return is one of the biggest issues for
regulators
- Initial rates allowed by regulators can be revisited
in an initial rate hearing 3-4 years after pipeline
operation begin
- Initial return is likely to be reduced if business
risk is judged to be lower
MR. PULLIAM indicated these generally apply to both FERC and
NEB. Elsewhere in the U.S., FERC has approved rates of 12-14
percent; equity returns on larger new projects have been at the
higher end. The NEB returns have traditionally been lower,
though negotiated rates in Canada have been somewhat above what
NEB allows and closer to the upper end of the FERC range.
MR. PULLIAM said rate of return is one of the biggest issues for
regulators, something they look at closely. Initial rates
allowed in the certification process will typically be revisited
by the regulatory body once the pipeline has been operating. If
it determines the risk is less than originally thought, it is
likely to lower the allowed return.
MR. PULLIAM explained that factors which tend to reduce the risk
and lead regulators to lower the return include: that the
pipeline has been operating for some period, that it has been
fully subscribed, and that it appears things are working as
anticipated and the pipe will be full for some time. The
aforementioned are all in the context of the cost-of-service
approach, the recourse rates.
1:50:13 PM
MR. PULLIAM paraphrased slide 25, "Negotiated Rates," which had
the following points:
- Negotiated rates are also regulated by FERC
- However, as the name implies, these are rates that
are "negotiated" between shipper and the pipeline
company
- All elements are up for negotiation. This includes:
- Rate of Return
- Length of commitment
- Flexibility
- Treatment of cost overruns
- Future expansion issues
- Changes in operating costs
MR. PULLIAM said TransCanada is offering to provide negotiated
rates, which must be approved by FERC and NEB but aren't
prescribed. Such rates may be for 5, 10, 15, or 20 years, for
instance, and there is flexibility for scheduling and so on.
REPRESENTATIVE SAMUELS referred to future expansion and asked:
Could TransCanada negotiate a rate with the producers that would
throw out the 115 percent?
MR. PULLIAM gave his understanding that they'd be required to
keep that, but couldn't go above that level. He then said they
might be able to negotiate something better.
REPRESENTATIVE SAMUELS posed a scenario of TransCanada having
negotiated with BP to ship gas for $3, with a 20-year FT
commitment; an expansion raises the tariff, and AGIA requires
that TransCanada go to FERC and request that it be rolled in so
the $3 tariff takes a hit. He asked: If it's a negotiated
rate, not a recourse rate, what do AGIA and the TransCanada
proposal require? Do they still have to go to FERC and ask for
a higher tariff, above what was negotiated with the customer?
MR. PULLIAM relayed his understanding that the aforementioned
provision is to be included in the negotiated rates.
REPRESENTATIVE SAMUELS asked: Does the state have a say in the
negotiated rate?
MR. PULLIAM answered that the state has some say before the rate
is approved. Assuming the pipeline company and shippers have
come to agreements and set negotiated rates, the state would
have some say until the time when FERC certifies the project.
While the state could try to go back later and challenge those
rates, the regulatory bodies generally view the negotiation and
bargaining process as providing an outcome they want to see; so
the ability to challenge afterwards would likely be much less.
REPRESENTATIVE SAMUELS returned to the 115 percent and asked:
If Anadarko comes in and wants to put gas in the pipeline but it
will drive the tariff up, it is your view that TransCanada would
have to go to FERC and argue to roll in the tariff and bump up
the rate negotiated with its original customers?
MR. PULLIAM acknowledged there might be legal aspects, but
opined that TransCanada would be required to include rolled-in
treatment in the negotiated tariff. He also suggested perhaps
TransCanada could agree to forgo that and offer better
negotiated terms to a shipper.
1:54:51 PM
MR. PULLIAM summarized slide 26, also labeled "Negotiated
Rates," which had the following points:
- Negotiated rates can result in lower tariffs than
recourse rates through the process of commercial
negotiation
- Negotiation takes the place of regulation. However,
as the negotiation takes place with the backdrop of
regulatory oversight (and recourse rate option/
backstop), the process can help reduce tariffs
charged
- Typically involve long-term shipping commitments
- Negotiated rates must be approved by FERC and NEB
- Regulatory bodies have viewed negotiation process
favorably and are reluctant to modify them after the
fact
MR. PULLIAM added that for shippers, the worst that will happen
through negotiation is the recourse rate, whereas negotiation
can result in more favorable terms. He paraphrased slide 27,
also labeled "Negotiated Rates," which said:
A point for the State to consider:
- The negotiation process can provide favorable
results for the State by helping to keep tariffs
down
- State likely would not have opportunity to challenge
these rates after the fact. The opportunity to
challenge would be in the certification process
- State's interest should be protected. However, this
is the time to apply scrutiny
MR. PULLIAM emphasized that the time to challenge negotiated
rates is during the certification process. Waiting to see how
they play out won't work.
1:57:01 PM
MR. PULLIAM showed slide 28, "Some Examples of Recourse and
Negotiated Rates," which had these comparisons: for Alliance
Pipeline the recourse rate was $0.53 and the negotiated rate
$0.54; for Rex West, the recourse rate was $0.91 and the
negotiated rate $0.77-$0.79; for Gulf Stream, the recourse rate
was $0.66 and the negotiated rate $0.57-$0.59; and for Maritimes
and Northeast Phase IV the recourse rate was $0.78 and the
negotiated rate $0.53.
MR. PULLIAM noted generally recourse rates have been higher, in
part because of the negotiation. Also, in the negotiated
setting - which also can happen in the recourse setting - the
tariff is typically levelized. He showed slide 29, "The
'Levelized' Tariff," which had the following points:
- A traditional cost-based tariff starts high and
falls as a pipeline recoups its capital costs (i.e.,
return on investment and return of investment)
- This happens because the rate base falls over time
as the pipeline is depreciated
- A levelized tariff is one in which the tariff is
constant over time. The level of the tariff is set
such that it results in the same Net Present Value
(NPV) and the cost of service for the non-levelized
tariff
MR. PULLIAM explained that net present value (NPV) is figured
for what a traditional cost-of-service tariff would be, and that
is translated into a constant-rate tariff that gives the
pipeline the same present value in terms of tariffs over time.
By contrast, traditional cost-based tariffs, seen in many
recourse rates, start high and fall over time as the pipeline is
depreciated and that is recovered through the tariff; the
company doesn't get to earn a return on the amount depreciated.
MR. PULLIAM pointed out that everything members will see, both
from these consultants and the administration, assumes there
will be levelized tariffs. He showed slide 30, a bar graph
labeled "Illustration of a Levelized Tariff," and then
paraphrased slide 31, "Tariffs Proposed by TransCanada," which
had the following points:
Offer 25, 30 and 35-year firm transportation services
(FT)
Offer Recourse Rate tariff for GTP and Alaska Pipeline
Section; Negotiated Rate tariff for all sections
- No Recourse Rate offered for Canada, as this is not
normal business practice in Canada (i.e., negotiated
rates are the norm)
MR. PULLIAM specified that new pipelines in Canada typically
have negotiated rates, although those have to be approved by the
regulators.
2:00:21 PM
REPRESENTATIVE SAMUELS again referred to the 115 percent and
said the point of the 15 percent extra is to ensure that
explorers get in. For the roundtable discussions, he asked:
Could rates be rolled in within Alaska, but negotiated to be
lower in Canada? Could gamesmanship occur between TransCanada
and the producers as to what is requested from the regulatory
agencies? Is it possible to use the NEB and FERC processes
independently and negotiate rates that are invisible to the
regulatory agencies?
MR. PULLIAM addressed slide 32, "Key Elements of Recourse Rate
Tariff," which had the following points:
- Provides for full recovery of capital costs on
"straight line" basis over 25-year period, assuming
initial transportation agreements are for this
period
- 100% load factor rates for authorized overrun
services
- Rate base will exclude Alaska portion of
$500 million State contribution
- Capitalization of 70% debt / 30% equity
- Expansions capitalized at 60% debt / 40% equity
MR. PULLIAM, on the second point, said shippers will bear the
cost of overruns that are authorized. He also noted the debt-
to-equity ratio for capitalization is in keeping with AGIA;
expansions would be financed at a lower debt amount.
2:03:01 PM
MR. PULLIAM paraphrased slide 33, "Debt Costs," which stated:
Debt costs will be weighted average cost incurred by
pipeline
- Contemplate U.S. loan guarantees
- Loan guarantees were originally $18 billion, up to
80% of project
- They were indexed to inflation. In 2008 dollars,
this is approximately $20 billion
- Assuming 75% debt, this would support project of
$26.8 billion in $2008 if all the loan guarantee was
used
- TransCanada has assumed a number for loan guarantee
debt of 4.7%. Based on expectations of inflation in
the 2.5% range, this may be somewhat low
- Borrowing without the U.S. loan guarantee is
estimated at 150 basis points higher (i.e., 6.2%)
MR. PULLIAM recalled discussion as to whether the loan
guarantees would work for overruns. He said the federal
government has provided for loan guarantees, with the
stipulation that it could be the lower of $18 billion or
80 percent of the project cost.
MR. PULLIAM emphasized that the amount is indexed to inflation.
Since the law was passed in 2004, it would be about $20 billion
today. Assuming 75 percent debt financing, this would support a
project of about $26.8 billion today. TransCanada's estimate in
2008 dollars is about $25.8 billion - close to the maximum
available with the loan guarantees.
MR. PULLIAM also said TransCanada's analysis assumes the loan
guarantees will carry about a 4.7 percent debt rate. However,
his review suggests this may be a little low; it would be
addressed in the next slide, consistent with what the
administration anticipates. Without the loan guarantee,
TransCanada estimates debt costs at 150 points or 1.5 percent
higher than the loan-guaranteed amount.
2:05:35 PM
REPRESENTATIVE SAMUELS asked: Do you consider both the 4.7 and
6.2 percent low, and they would float together?
MR. PULLIAM answered he thinks both are a little low. The 150
basis points is probably a little more reasonable, the
difference between the two. But he believes the overall
structure is a bit low.
REPRESENTATIVE SAMUELS asked: How much does the 150 basis
points cost us in the tariff? If there were no loan guarantees,
how much would the tariff go up?
MR. PULLIAM answered that for every percentage point difference
in debt, there is about an 11-cent change in the tariff,
assuming the capital costs shown.
2:06:36 PM
MR. PULLIAM turned to slide 34, also labeled "Debt Costs," a bar
graph of inflation-adjusted historical 10-year T-bond and
corporate bond rates for the last 20 years. He said because
interest rates have changed with inflation, this shows the
spread between different interest rates and current inflation.
MR. PULLIAM observed that the spread for 10-year T-bonds, for
instance, has come down over time and recently went negative.
Over the last 5 years the average spread was low, 1.31 percent;
over the last 10 years, it was 2.1 percent; and over 20 years,
it was 3 percent above inflation. He surmised the recent
experience is lower than what folks will require in terms of
spreads over inflation. Something between the 10-year and 20-
year rate is probably more reasonable, from above 2 percent to
2.5 percent over inflation.
MR. PULLIAM said over the last 10 years the difference between
AAA bonds and 10-year T-bonds has been about 1.4 percent,
whereas for lower-rated bonds it's a "low 2 percent" spread
between T-bonds and BAA bonds. He also said he believes the
historical numbers support the spread between the guaranteed and
nonguaranteed, that 150 basis points which TransCanada has
proposed, but the guaranteed rate itself is probably too low.
2:09:05 PM
MR. PULLIAM showed slide 35, "Potential Borrowing Costs for
Guaranteed Loan." It depicted rates using historical premiums
over inflation. Projected inflation was 2.50 percent for all
categories. The risk-free premium was 3.00 percent for the 20-
year average, 2.10 percent for the 10-year average, and 1.13
percent for the 5-year average. The margin was 0.50 percent for
all. And the total was 6.00 percent for the 20-year average,
5.10 percent for the 10-year, and 4.13 percent for the 5-year.
MR. PULLIAM explained that the margin was calculated at
0.50 percent, 50 basis points, to get the financing over the T-
bond rate. That puts the 10-year average over 5 percent, and
for the 20-year average it's closer to 6 percent. He suggested
a reasonable place would be somewhere in between. Below
5 percent, on a long-term basis, seems too low.
MR. PULLIAM turned to slide 36, "Equity Costs." A bar graph
notated "965 Basis Points Above Historical 10-Year T-Bond
Rates," it had a key showing the 20-year average at
15.73 percent, the 10-year average at 14.51 percent, and the 5-
year average at 14.05 percent. He explained that TransCanada
has talked about an equity return that floats at 965 basis
points above the 10-year T-bond rate.
MR. PULLIAM said from a commercial standpoint, he doesn't see
anything unreasonable in the floating rate, though it hasn't
been used and approved before by FERC. Typically, FERC has had
a fixed rate. Historically, that rate has been above 18 percent
but has been falling over time; in the last five years it has
averaged about 14 percent. As noted before, the last five years
is a period of historically low real interest rates, the spread
over inflation.
2:11:31 PM
SENATOR WIELECHOWSKI recalled that slide 34 shows that in 1988,
for instance, the 10-year T-bond rate was about 4.5 percent. He
asked: If 965 basis points are added, shouldn't it be more
around 14-15 percent? He also asked whether this is the rate of
return, what they'll be able to get back on their tariff, which
he recalled Mr. Pulliam said is normally 12-14 percent.
MR. PULLIAM replied this is the proposed rate of return on the
equity portion. In further response, he explained that
TransCanada has proposed 965 basis points over the T-bond rates.
If it were applied back historically, it would look like this.
MR. PULLIAM surmised the question was whether one would take the
approximately 4.5 percent shown on slide 34 and then add it to
the 965. He pointed out that this is the spread over inflation
that's in slide 34; thus an additional amount for inflation
would be included in that total amount. So this line on the
current graph includes an inflation component, he indicated.
SENATOR WIELECHOWSKI asked: If bond yields increase
dramatically when the gas is flowing, will that decrease the
money Alaska gets through its taxes, since it would increase the
tariff and be more of a write-off for the companies?
MR. PULLIAM replied if the rates rise and there is a floating
rate over the T-bonds, that increases the tariff and reduces
netbacks.
SENATOR WIELECHOWSKI expressed interest in long-term forecasts
for T-bonds.
REPRESENTATIVE SAMUELS asked what the normal rate of return
allowed in Canada is.
MR. PULLIAM opined it's closer to the 12 percent range, but
sometimes negotiated rates in Canada can be higher than NEB
would allow in its formulas. Ultimately, that rate will come
from negotiation in Canada and may be closer to the U.S. number.
DR. NERI added, with respect to interest rate forecasts, that
he'd checked before coming here. The Congressional Budget
Office makes 10-year forecasts; those currently project a 10-
year bond rate of 5.2 percent in 2018. Adding the 9.65 percent
risk premium gets it to 14.85 percent.
2:16:16 PM
MR. PULLIAM turned attention to slide 37, "Potential Equity
Return Under Proposal," noting it dovetailed with that. Like
slide 35, it depicted rates using historical premiums over
inflation; projected inflation was 2.50 percent for all; and the
risk-free premium was 3.00 percent for the 20-year average,
2.10 percent for the 10-year average, and 1.13 percent for the
5-year average. Equity premium was 9.65 percent for all.
Totals were 15.15 percent for the 20-year average, 14.25 percent
for the 10-year, and 13.28 percent for the 5-year.
MR. PULLIAM said ultimately these rates will respond to
inflation. If inflation is low, rates will be low; if inflation
is high, rates will rise. If 2.5 percent inflation is assumed
going forward, looking somewhere between the 10-year and 20-year
historical premiums on the 10-year T-bond, which is in the 2-3
percent range, and then adding that 965 basis points, it gives a
rate of return between 14.25 and 15.15 percent. So the
14.85 percent number that Dr. Neri talked about, flowing from
the federal government's forecast, is in that range.
MR. PULLIAM emphasized that the premium has been low for the
last five years. The 10-year Treasury bond has been only
1 percent or so above inflation. If it did stay in that low
range, potentially the equity return would be below 14 percent.
But he'd expect it to be higher in the future.
2:17:38 PM
MR. PULLIAM paraphrased slide 38, a continuation of "Key
Elements of Recourse Rate Tariff," which said:
- Depreciation will be on straight-line basis over
25 years (i.e., 4% per year)
- Operating costs, income and other taxes are passed
on to shippers
- Fuel gas will be recovered from shippers based on
actual pipeline losses
- 4.40% GTP
- 2.15% Alaska & Yukon-BC Sections
- 0.90% Alberta Section
- Shippers retain title to natural gas liquids
entrained in the gas and are free to dispose (i.e.,
sell or process them as they see fit)
MR. PULLIAM emphasized that, particularly in the negotiated
setting, these items are all open for negotiation. And even if
there's a formula that TransCanada would like to take to FERC,
it doesn't mean FERC would approve it. Noting that the costs
passed on to shippers, including fuel, had been discussed
earlier, he also said shippers are free to dispose of or process
the NGLs once those are in AECO.
2:19:27 PM
MR. PULLIAM addressed slide 39, "Negotiated Rate Tariffs," which
had the following points:
- Most new pipeline construction works off negotiated
tariffs
- TransCanada proposes to offer 25, 30 and 35-year
negotiated tariffs
- TransCanada proposes that its negotiated rates would
incorporate:
- Levelized tariff
- 70% debt / 30% equity capital structure through
date of operation, falling to a 75% debt / 25%
equity capitalization for period of operation
- Expansions would be 60% debt / 40% equity
structure
- Equity and Debt rates proposed are the same as
for recourse rates (i.e., 965 basis points over
cost of 10-year T-Bond and actual debt costs)
- Return on Equity reduction offered for
negotiated rates
- In addition, TransCanada proposes to use U.S. loan
guarantees to finance cost overruns if available
MR. PULLIAM added that negotiated rates will likely be a big
part. TransCanada is offering these terms, at least initially;
it doesn't mean shippers must accept them. He clarified that
the debt-to-equity ratio shifts after construction is complete.
He indicated the reduction in the rates for return on equity is
offered in case of cost overruns, at least for the first five
years of the tariff; the U.S. loan guarantees would be used to
finance cost overruns as well, if available.
2:21:09 PM
MR. PULLIAM summarized slide 40, a continuation of "Negotiated
Rate Tariffs," which said:
- Shipper must agree to accept treatment of rolled-in
rates under Alaska Gasline Inducement Act (AGIA)
- Shipper must agree not to seek or support changes to
the economic parameters that underpin the negotiated
rate design at FERC and NEB
- Notwithstanding the terms offered by TransCanada,
the actual terms to be negotiated between shippers
and TransCanada, with the exception of those
mandated under AGIA, such as treatment of rolled-in
rates, are open for negotiation
- There is no requirement to accept the economic
parameters proposed by TransCanada. Shipper can
bargain for lower rates, increased flexibility, and
alternative vehicles for protection against cost
overruns than those offered
- See earlier differences in Recourse and Negotiated
Rates
- TransCanada proposes to offer equity ownership in
the pipeline "Anchor" shippers who subscribe in the
initial Open Season
MR. PULLIAM, with respect to the second point, said the shippers
must agree not to go back on the rates they've negotiated. On
the last point, he said TransCanada has nothing more broad in
its proposal with regard to how much it is willing to offer.
2:22:15 PM
REPRESENTATIVE SAMUELS said if a shipper has 20 percent of the
gas and bids 20 percent of the FT in the line, TransCanada says
it is open to offering to sell 20 percent of the pipe; at the
end of the day, there conceivably could be a consortium of
Conoco, Exxon, BP, and TransCanada owning the pipe. He asked:
Does TransCanada's proposal talk about how that particular
entity would be run or whether there'd be three votes, with the
shippers controlling the pipeline company?
MR. PULLIAM answered that he doesn't see anything in the
proposal as to how it would be run, including who would have
voting control and so forth, although he surmised it would have
to be consistent with the tenets in AGIA.
REPRESENTATIVE SAMUELS gave his understanding that there is a
presumption of rolled-in tariffs from Congress and FERC, and
then AGIA says it is 115 percent that the pipeline entity - no
matter who it is - has to follow because TransCanada agreed to
it originally. As it is purchased, there'd have to be an
agreement saying that the new owner would also agree. He asked:
Is that a statutory change, or do they just approach the future
governor years from now and say they've changed their minds
about the 115 percent and the three big producers now own three-
fourths of the pipeline?
MR. PULLIAM replied he doesn't know how that would play out, but
he suspects the original owner would have to stick with those
terms. Although he indicated he believes selling off pieces of
the ownership that could have different terms wouldn't be
allowed, he noted that a legal question.
2:24:34 PM
REPRESENTATIVE WILSON returned to the last point on slide 39:
"In addition, TransCanada proposes to use U.S. loan guarantees
to finance cost overruns if available." She surmised that's
probably not an option right now for cost overruns.
MR. PULLIAM replied it's a two-part question. The loan
guarantees are available generally for the project, but whether
that includes cost overruns is still undecided within the
federal government; it's something TransCanada would like.
Second, with respect to "if available," he also means if there
is a desire to have those funds available for cost overruns,
then building the pipeline based on anticipated costs will
require using nonguaranteed funds in place of those.
REPRESENTATIVE WILSON asked whether Congress would have to
decide that.
MR. PULLIAM opined that perhaps the U.S. Department of Treasury
could handle it without congressional intervention, though he
wasn't sure.
2:26:20 PM
MR. PULLIAM showed the first of six slides labeled "Incentive
Adjustments to Return on Equity." Slide 41 was a graph that
specified it assumes 75% debt / 25% equity. He noted the line
across the top tracks the 14 percent return on equity discussed
in the proposal. If one assumes that 965 basis points above the
T-bonds gives 14 percent over time, the return looks like this
without any of the incentives TransCanada has offered. Below it
depicts different capital cost projections in 2008 dollars.
MR. PULLIAM explained that TransCanada proposes to reduce
its rate of return for the first five years of operation. For
every percentage increase above the cost that TransCanada
estimates at the time of certification, the company would
decrease its return by 5 basis points. If, for example, the
baseline for costs is $25.8 billion at the point of
certification and then overruns are 10 percent, the return would
be reduced by 0.5 percent or 50 basis points.
2:28:04 PM
REPRESENTATIVE SAMUELS asked: Would TransCanada make 14 percent
up to the $25 billion in this example, and then on the next
dollar spent get a smaller rate of return but still make money,
so that the more it costs, the more the company makes?
MR. PULLIAM responded that there'd be examples with specific
dollar amounts, but to his understanding the return on the
overall amount would be reduced at least for the first five
years. It wouldn't just be the increment over the
$25.8 billion; the overall equity return would be reduced by
half a point. If it went 40 percent over budget, the return
would drop to 12 percent overall. This applies the first five
years of construction; then the return goes back to 14 percent.
MR. PULLIAM discussed slide 42, a similar graph. He noted it
shows what happens over the 25-year period. As overruns go up,
the result is a blended rate that comes down and approaches
something a little over 13.5 percent with a cost overrun as high
as 40 percent. This is the effective rate that results from
including the incentive portion for the first five years and
then going back to the standard rate beyond that. He suggested
thinking of a weighted average that falls in between the two.
MR. PULLIAM spoke about slides 43-46, pointing out that profits
increase as capital goes up with non-incentive rates at a fixed
rate of return, since equity is 25 percent of total capital. If
there are just incentive rates and a reduction to 12 percent,
profits still go up as capital increases, but less quickly; at
40 percent the rate levels off.
MR. PULLIAM said with the blending of the two over time, there
is increased profit as capital goes up, although at a lower rate
than the non-incentive rate. Slides 44-46 had this note:
"TransCanada proposes to reduce its allowed return on equity by
up to 200 basis points (2%) over first 5 years in the event of
cost overruns."
2:32:31 PM
MR. PULLIAM addressed slide 47, "Potential to Use Government
guaranteed loans to cover potential overruns," which said:
- TransCanada proposes to use Government guaranteed
loans to cover potential overruns
- $18 billion made available in $2004
- Would be approximately $20 billion in $2008
- Assuming 75% debt financing overall, a project of
$26.8 billion ($2008) would absorb the full
guarantee amount
- TransCanada's proposal amounts to $25.8 billion
($2008)
- Accordingly, reservation of Government guaranteed
loans for any significant cost overruns would
require use of more expensive non-guaranteed debt
MR. PULLIAM noted the guarantees amount to $20 billion in 2008
dollars, which at 75 percent debt supports a project of $26.8
billion. Since TransCanada's proposal is for $25.8 billion,
reserving a portion for cost overruns requires using non-
guaranteed debt for the initial capitalization of the pipeline.
2:33:30 PM
REPRESENTATIVE LeDOUX asked: Can this deal happen without using
the government-guaranteed loans to cover potential overruns?
MR. PULLIAM answered that the government loans are helpful to
the project, although from what he's seen - based on current gas
price projections and tariff costs with/without those guarantees
- they aren't the linchpin. They serve to reduce the tariff and
make it more economic.
REPRESENTATIVE LeDOUX asked whether Mr. Pulliam was saying it's
not actually part of the deal.
MR. PULLIAM replied part of the proposal is to use those loan
guarantees. However, it is a little unclear in the proposal
whether those will be reserved for cost overruns or used in the
initial pipeline construction.
REPRESENTATIVE LeDOUX asked: Are those loan guarantees in law
now? If TransCanada applies for them, will it get them?
MR. PULLIAM answered yes, as long as TransCanada meets the
conditions set forth in the legislation.
2:35:50 PM
MR. PULLIAM, in response to Chair Huggins, explained that the
non-guaranteed debt will have a higher interest rate. Most of
the pipeline is debt-financed. At higher interest rates, the
financing costs will be higher on the biggest portion of the
pipeline. Ultimately, the regulators will allow those higher
interest rates to be passed through in the form of a tariff.
REPRESENTATIVE SAMUELS gave his understanding that if the
guarantees are used on the front end, capital costs can be
reduced but there's nothing left for overruns. But if it's
saved for overruns, capital is higher but it isn't known what
the overruns will be and thus it might be wasted.
MR. PULLIAM surmised that any amount which hadn't been used for
cost overruns could be applied later on.
2:36:40 PM
REPRESENTATIVE DOOGAN asked: If the government guarantee goes
to loans for initial financing and then there are cost overruns,
how would those typically be financed?
MR. PULLIAM replied they could be financed either by increased
borrowing or by putting equity capital in. If someone proposes
a certain capital structure for debt and equity and has targeted
75 percent, presumably it will continue to be funded at that
same rate as costs go up. Someone could instead seek to fund it
over time, however, using different percentages.
REPRESENTATIVE DOOGAN said in this example it's more expensive
money across the board, because it isn't government-guaranteed;
those funds would have already been used.
MR. PULLIAM concurred, saying he'd assume the company would try
to use as much of the government-guaranteed money as possible;
there's only a certain amount.
2:38:51 PM
REPRESENTATIVE HAWKER gave his understanding that although these
guaranteed loans are available, the process to obtain them is
fairly lengthy, complex, and uncertain.
MR. PULLIAM responded that he isn't familiar with the entire
process, believes it is lengthy and requires a lot of
certification, and doesn't know whether there is uncertainty
with respect to how they're used.
SENATOR WILKIN asked about two incentives he'd heard about in
Anchorage last week to minimize cost overruns: 1) the return on
equity shown here that seems to cost some $3 billion for a
40 percent overrun and 2) one related to federal corporate
income tax and a deduction or surcharge.
MR. PULLIAM indicated he hadn't been in Anchorage and didn't
know. In response to Senator Therriault, he said the loan
guarantee amount will continue to grow until used. If project
costs grow with the rate of inflation, the relationships all
stay the same. The administration's projected costs are at a
higher growth rate than general inflation, however, more like
4 percent, whereas the loan guarantees are indexed to the
general rate of inflation.
2:41:28 PM
SENATOR THERRIAULT asked whether Mr. Pulliam's calculations
accounted for that.
MR. PULLIAM replied he'd shown these in 2008 dollars to try to
maintain an apples-to-apples basis as much as possible.
SENATOR WIELECHOWSKI asked if pipeline companies typically have
tremendous cost overruns or if some factor keeps those down.
MR. PULLIAM answered that, first, the shippers are highly
sensitive to costs, and in the regulatory process they'll try to
ensure that the costs which are ultimately approved are
reasonable and prudent; the regulators are charged with that.
Second, in negotiating rates, shippers can anticipate and
negotiate terms about how overruns will be treated. They may
embrace something like TransCanada has talked about, require
something more stringent, or have different terms.
DR. NERI concurred.
CHAIR HUGGINS highlighted the importance of understanding the
process for the federal loan guarantees, including what triggers
them, what the procedure is, and how long it takes.
2:44:00 PM
REPRESENTATIVE SAMUELS agreed. Following up on Senator
Wielechowski's question, he posed a topic for the roundtable
discussion: Is the negotiated rate the incentive, in large
part, in a normal pipeline to keep cost overruns down? He
surmised there'd only be a certain parameter that the
negotiation allowed one to go up to, and then it would be on the
pipeline company.
MR. PULLIAM suggested an analogy where someone has negotiated
with a contractor to build a house.
REPRESENTATIVE SAMUELS surmised that person would absorb some of
the risk. The only difference would be that this is a
$30 billion or $40 billion project, and the risk from cost
overruns accelerates quickly because of the size of the project.
MR. PULLIAM concurred. He turned to slide 48, also labeled
"Potential to Use Government Guaranteed Loan for Cost Overruns,"
a chart with the following columns: total capital in 2008
dollars; overrun; amount of debt at 75 percent debt/equity
ratio; amount of loan guarantee in 2008 dollars; non-guaranteed
debt; and average debt rate by percentage.
MR. PULLIAM said this shows what is available from the federal
government and how it would look at different capital-cost
levels. He indicated if cost projections were as TransCanada
proposed, $25.8 billion in 2008 dollars with no overrun, it
would be as shown: debt at $19.4 billion, the loan guarantee at
$20.1 billion, zero non-guaranteed debt, and an average debt
rate of 4.7 percent.
MR. PULLIAM added that if costs go up, the guaranteed amount
doesn't go up, but the required debt does in order to keep the
debt-to-equity ratio. If it costs more, it can be termed an
overrun or just "higher capital." At 50 percent more, about
$39 billion total, $29 billion in debt would be required; one-
third or $9 billion would be non-guaranteed funds. Using
TransCanada's spreads, this would raise the average debt cost by
about 0.5 percent.
2:47:16 PM
REPRESENTATIVE JOHNSON highlighted slide 6, "What Does
TransCanada Ask From the State?" He drew attention to the
following point: "Cooperation of State in efforts with the
Federal Government to obtain support for project - Use of loan
guarantees for cost overruns." He asked: Does the state have
any cost-overrun responsibility under the proposal? And if we
say yes to this, would the state have to provide a guarantee for
those, above and beyond what the federal government does?
MR. PULLIAM gave his understanding that this refers to use of
the federal guarantees, not a state guarantee.
2:48:09 PM
MR. PULLIAM showed slide 49, "Sensitivities," which said:
As discussed above, capital costs are the biggest
driver of costs. The critical elements are:
- Overall Capital
- Capitalization (i.e., Debt/Equity)
- Debt Cost
- Return on Equity
MR. PULLIAM specified that capital costs will be the biggest
costs in the tariff. Overall capitalization - what the debt
costs and the return on equity - is important in the tariff as
well. Slides 50-52 would show sensitivities, how the tariff
would change under different assumptions relative to what
TransCanada has put into its baseline tariff assumption.
MR. PULLIAM showed slide 50, "Tariffs ($/MMBtu)," a chart with
the following note: "Base tariff is per TransCanada assumptions
re: costs, capital state and financing (i.e., $25.8bn, 75% debt
/ 25% equity, 4.7-6.2% debt cost, 14% return on equity)." He
indicated the vertical line in the middle represents $2.41, the
number from TransCanada's proposal. The graph depicts what
happens to the tariff if various factors are increased or
decreased by a certain percentage.
MR. PULLIAM pointed out that debt is the biggest part of the
capital. The tariff is sensitive to debt costs; if debt is
reduced by 1 percent, the tariff drops about 12 cents, for
instance. Return on equity is a little less sensitive because
there is less equity in the proposal, 25 percent. There'd be a
movement of 5 or 6 cents either way on the equity piece; that is
relative to a 14 percent return.
MR. PULLIAM showed slide 51, "Estimated State Revenues
(Billion $)," a chart with the following note: "Base ($226.9bn)
is per TransCanada assumptions re: costs, capital state and
financing (i.e., $25.8bn, 75% debt / 25% equity, 4.7-6.2% debt
cost, 14% return on equity)."
MR. PULLIAM said this shows the projected impact on state
revenues, generally following the same pattern. Capital costs
are the more sensitive. These are nominal dollars expressed
over 25 years. The debt ratio is a little lower and debt costs
are somewhere between the two.
SENATOR THERRIAULT remarked that this shows why it was important
that the state's desired debt-to-equity ratio be a "must have."
This shows the impact on the return. He said FERC will allow a
debt-to-equity ratio within what it calls a "zone of
reasonableness." He recalled that for the Rockies Express
Pipeline this was 55/45.
SENATOR THERRIAULT said if the State of Alaska allowed that kind
of spread and there was a lot more equity, there'd be a
tremendous impact to the state. He asked why Mr. Pulliam had
chosen just a +5/-5 percent range here.
MR. PULLIAM replied this is for illustration, how it would move
over a relatively small range of 5 percent. It certainly could
be expanded to show much larger ranges. With movement of 25
percent, the bar on the chart would be commensurate.
SENATOR THERRIAULT surmised proposals outside of AGIA that want
higher equity could have a sizable impact on the state's
earnings.
MR. PULLIAM agreed. He said these are more like changes on the
margin. But they could be run with wider sensitivities.
2:52:44 PM
MR. PULLIAM showed the final chart on sensitivities, slide 52,
"Estimated Shipper Revenues (Billion $)," which had the
following note: "Base ($122.5bn) is per TransCanada assumptions
re: costs, capital state and financing (i.e., $25.8bn, 75% debt
/ 25% equity, 4.7-6.2% debt cost, 14% return on equity)."
MR. PULLIAM said these again are nominal dollars. The pattern
is similar to what was seen earlier, although the sensitivity
range is a little narrower for shippers because the forecast
under the current system shows more total dollars flowing to the
State of Alaska than to the shippers.
REPRESENTATIVE DOOGAN referred to the timeline on slide 4 and
asked when the tariff rates will be set.
MR. PULLIAM answered that he believes the initial tariffs will
be set at the point of certification to build the pipeline.
REPRESENTATIVE DOOGAN asked whether that applies whether there
are recourse rates or negotiated rates for the tariffs.
2:54:45 PM
MR. PULLIAM suggested Dr. Neri might comment, but said it's
subject to what those terms provide. For instance, capital may
end up being higher or lower than what is set forth. If it's
higher, for instance, then the actual per-unit tariff could be
higher than what is there at the certification point. But the
methodology at least, what goes into those rates, would be set
at that point of certification.
REPRESENTATIVE DOOGAN asked: Will there be another tariff-
setting procedure at the end of construction?
DR. NERI answered that generally when FERC grants a certificate
to construct a pipeline, especially for recourse rates, one
certificate condition is that the pipeline at some point -
usually three years later - come in and justify the rates,
document costs, and maybe even file a rate case. So there's
usually a three-year review by FERC of the cost and the rates.
REPRESENTATIVE DOOGAN asked: If a pipeline company is trying to
get commitments at an open season, does it have to be able to
predict at least the initial rates?
DR. NERI replied that during the open season, in the open season
documents, the pipeline will indicate what it thinks the rate
will be. Potential shippers will submit bids. After the open
season, if the pipeline decides to file its certificate, it will
have more information and will, in the certificate application,
file for rates to be charged to the shippers. If those rates
are approved by FERC, they'll go into effect.
REPRESENTATIVE DOOGAN asked whether there could be three sets of
rates, then: the rates at the open season, the rates at
certification, and then the rates upon completion.
DR. NERI replied no. The rates at certification would go into
effect. But, as part of the certificate condition, FERC
generally requires pipelines to come in three years later to
justify the rates that were approved in the certificate.
REPRESENTATIVE DOOGAN asked: If there were significant cost
overruns between the time of certification and completion, how
would those be handled in the rate making?
MR. PULLIAM responded if capital costs were higher than
anticipated, he believes in the initial certification process
the company would apply to have a certain return on capital that
would then apply to the higher capital base. It would be those
rates that go into effect. That would be reviewable three years
or so after the pipeline began operation, when the pipeline
would have to justify those rates.
2:59:01 PM
MR. PULLIAM discussed slides 53-55, "Expansion Issues," which
listed the following points:
- Expansion of pipeline capacity would occur either
via addition of compression, or through looping
(i.e., additional pipeline)
- TransCanada estimates that expansion up to
5.9 bcf/day (30% increase) could occur through the
addition of compression
- Expansions between 5.9 bcf/day and 6.5 bcf/day would
occur through either compression or looping
- Looping involves adding parallel pipeline
sections along a portion of the main line
- Beyond 6.5 bcf/day, expansion could occur up to 7.2
bcf/day through looping
- AGIA requires TransCanada to study demand for
expansion every two years and offer non-binding Open
Seasons if demand is warranted
- AGIA also requires TransCanada to offer "rolled-in"
rates as long as they do not result in increase over
original rates by more than 15% (i.e., 115% of
original rates)
- Rolled-in rates mean that the costs of the expansion
"rolled-in" with the original costs and the total is
spread out over total volumes
- This could result in higher or lower rates for
original shippers depending on the cost of the
expansion
- The alternative is incremental rates for expansion.
Under incremental pricing, the shipper[s] for the
expansion capacity bear the entire cost of the
expansion. Again, this could be lower or higher
than the original rates
MR. PULLIAM noted that expansions were addressed earlier as
well. He specified that the 30 percent increase in the second
bullet point is 30 percent over the 4.5 initial throughput.
With rolled-in rates, both the initial shippers and the
expansion shippers pay on the same basis.
MR. PULLIAM, in response to Senator Green, gave his
understanding that the 115 percent applies to the initial rate.
As the pipeline expands to about 5.9 Bcf/day, rates likely would
decrease; compression would be added, and the initial costs
would be spread over a higher volume. There could be a
situation wherein an expansion after that leads to an increase
over those lower rates.
3:01:55 PM
REPRESENTATIVE SAMUELS posed an example with an initial rate of
$3.00. There is compression expansion and the rate drops to
$2.50. Anadarko comes in and bids $2.50 for its gas, and
everyone pays $2.50. Then there's an expansion with looping,
and the rate rises to $3.25. He asked whether Anadarko would be
on the hook for 15 percent above $2.50 or above $3.00.
MR. PULLIAM gave his understanding that it would be relative to
the initial rate, up to 15 percent above $3.00.
REPRESENTATIVE SAMUELS suggested also asking the administration
and TransCanada what their understanding is. He said Anadarko
in this instance could sign up at $2.50 and go to $3.45,
15 percent above a rate that Anadarko hadn't agreed to ever, the
$3.00 rate.
MR. PULLIAM affirmed that as his understanding from what he'd
read and seen presented thus far. Returning to the slides, he
said rolled-in rates can lead to higher or lower rates for
initial shippers, depending on the cost of the expansion. The
alternative is incremental rates in which expansion shippers pay
the entire cost of expansion; this could be higher or lower than
the original rates, depending on how efficient the expansion is.
MR. PULLIAM showed slide 56, "Example of Rolled-In Rate
Treatment," a bar graph showing how rolled-in rates could either
lower or raise rates for initial shippers. He specified that it
wasn't based on the proposal.
MR. PULLIAM noted if there were initial tariffs of $2.00 and an
incremental expansion with relatively low-cost compression, it
would result in $1.50 on the incremental volume to support that
expansion; rolling that in leads to a lower average rate for
everyone. Conversely, if the expansion was relatively costly so
it went up to $2.50, then rolling the higher expansion cost in
would result in a higher tariff for everyone.
3:04:38 PM
REPRESENTATIVE GATTO asked what happens if the amount of gas
available to put in the pipeline keeps dropping. There'd be a
commitment that someone wouldn't have to pay more than
15 percent above the base rate. But the rate would start to
climb for everyone if less gas were in the pipe. He asked:
Under that scenario, how do you prevent the rate from climbing
above the initial rate?
MR. PULLIAM replied that's a different risk issue. That's why
there are transportation commitments to begin with. Shippers
will agree to put a certain amount of gas in; if they don't ship
that amount of gas, they'll pay as if they did.
3:05:43 PM
SENATOR THOMAS observed that the gas treatment plant wasn't
mentioned here and asked: If the GTP is built for 4.5 Bcf/day
and then the line expands to 7.2 Bcf/day, what impact does that
have and how does it affect the tariff? He suggested there
might be a huge capital cost for the GTP in that instance,
depending on who owns it.
MR. PULLIAM said that's a good question. TransCanada's proposal
doesn't include a scenario for expanding the GTP. He said
engineering for the GTP is a out of his area of expertise, but
the gas would have to be conditioned in some way, either from
adding to the central GTP facility or perhaps through
constructing small facilities to address incremental volumes.
As to which would be most efficient, he didn't know.
SENATOR THERRIAULT asked Mr. Pulliam why he'd stopped the
expansion through looping at 7.2 Bcf/day. He surmised if it
were still cost-competitive, someone could lay pipe to get
around bottlenecks or have parallel lines.
MR. PULLIAM answered that it matched with estimates in
TransCanada's proposal, which ran the numbers up to 7.2 Bcf/day.
As to how efficient it is to loop beyond that, he wasn't sure.
3:08:20 PM
SENATOR WIELECHOWSKI recalled for the base pipeline the debt-to-
equity ratio is 70/30 under AGIA, but for expansions TransCanada
wants 60/40. He asked: What economic impact does that have if
it's up to 6.5 or 7.2 Bcf/day and there's a 44 percent increase,
changing that ratio from 70/30 to 60/40? He surmised it would
be significant.
MR. PULLIAM answered it would have the effect of raising capital
costs on a per-unit basis, though he wasn't sure how significant
it would be.
SENATOR WIELECHOWSKI suggested it would be a loss of billions of
dollars to the state.
MR. PULLIAM replied that relative to using a 70/30 ratio,
depending on how big the expansion is, it could be billions.
However, the value of having the expansion would, in itself, be
a big benefit to the state. If it could be done on a 70/30
basis, though, and was a significant expansion, that difference
could be quite valuable to the state.
3:09:52 PM
MR. PULLIAM discussed slide 57, also labeled "Expansion Issues,"
which had a graph and the following points:
- TransCanada estimates that expansions up to 6.5
bcf/day (44% increase in capacity) would reduce
rates on a rolled-in basis
- At 7.2 bcf/day, TransCanada estimates that rolled-in
treatment of expansions could increase rates
(depending on timing of expansions(s)), but by less
than the 15% threshold
MR. PULLIAM said the graph shows what TransCanada anticipates at
different expansion levels. A horizontal line shows 115 percent
of the initial tariff. The figures refer to pipeline tariffs,
not the GTP. He noted TransCanada predicts expansions generally
would reduce the tariff, inclusive of fuel, up to about 6.5
Bcf/day. It would start to increase as looping begins.
MR. PULLIAM added that the administration has done some of this
modeling as well and has verified in general, to his belief, the
manner in which the pipe would be expanded, though the patterns
look a bit different from this, with some increase seen at a
lower level. In the end, the 115 percent level isn't approached
- at least with current projections - at any of these kinds of
expansions. Moving from 4.5 to 7.2 Bcf/day is a fairly large
expansion, more than 50 percent, over the initial capacity.
3:12:06 PM
MR. PULLIAM discussed slide 58, also labeled "Expansion Issues,"
which had the following points:
- If TransCanada estimates are correct, existing
shippers would be expected to be supportive of
rolled-in treatment up to 6.5 bcf/day. Beyond that,
they would rather see incremental pricing
- This could differ depending on the position of
the party seeking the expansion. If it is an
existing shipper, it may still favor rolled-in
treatment above 6.5 bcf/day depending on how
much existing capacity it has relative to the
amount of incremental capacity it is seeking
- For example, if a shipper had 10% of the
original capacity, but was going to have 100% of
the expansion capacity, then it would likely
favor rolled-in treatment even if it raised the
cost for it[s] original capacity
- This is because it can spread the costs of the
incremental (relatively expensive expansion)
across others' volumes
- Neither FERC nor NEB are required to accept rolled-
in treatment of rates as required by AGIA, though
FERC has stated that there will be a presumption of
rolled-in treatment
MR. PULLIAM added, with respect to different positions of
parties, that it would depend on a shipper's mix of gas as well
as how much initial capacity that shipper has relative to the
expansion capacity. The FERC presumption of rolled-in treatment
is rebuttable; the pipeline or shippers could present evidence
that it should be done on an incremental basis instead.
3:13:47 PM
MR. PULLIAM summarized slide 59, "In-State Tariffs," which said:
- TransCanada has proposed offering at least 5 in-
state "off-take" locations, one of which would
accommodate a "spur" line to the Anchorage area
- In-State Study before Open Season
- Tariffs would be offered on distance sensitive
basis, with a single "zonal" rate offered for all
Alaska off-take locations
- Rates to the different locations would be calculated
based on their relative distances to the total
Alaska section, then a weighted average rate would
be applied to all off-take in Alaska
MR. PULLIAM added that the in-state study is consistent with
AGIA. In response to Representative LeDoux, he specified that
TransCanada proposes to do a study of demand for gas within the
state and make that available before the open season. Thus
folks would have a sense of gas requirements in Alaska.
MR. PULLIAM said the final chart, slide 60, also labeled "In-
State Tariffs," is a simplified version with off-take locations
at 200, 300, and 500 miles and examples of off-take volumes; the
overall rate to the border is $1.00 per Mcf and the distance is
800 miles. Total cost is allocated based on the distance to
each location and the weighted volume coming off each.
MR. PULLIAM said while it is relatively cheap to serve location
A and more expensive for location C, those are weighted
together. In this case, the average distance is 52.5 percent of
the distance to Canada, so the rate is 52.5 percent of the total
rate to Canada.
3:16:00 PM
REPRESENTATIVE HAWKER remarked that philosophically he can see
certain simplicities in having a single-zone tariff for all of
Alaska. But he asked why folks taking gas off at the Yukon
River should subsidize shipping gas all the way to the Kenai,
for instance, and why Fairbanks residents should subsidize gas
going to LNG or urea plants further south.
MR. PULLIAM replied he thinks it boils down to administrative
ease and simplicity. Ultimately, there'll be a balancing
between equity and administrative ease, which often is one of
the tensions in the regulatory process. The postage-stamp type
of rate provides that administrative ease.
3:17:18 PM
REPRESENTATIVE LeDOUX asked whether it's correct that this
TransCanada proposal won't work unless the producers agree in
the open season to ship their gas.
MR. PULLIAM answered that a pipeline to commercialize the gas
has certainly got to have gas in it. Right now, that gas is
controlled by producers under the leases they have. There has
to be some way for that gas to get into the system, either by
agreement or coercion or some process.
REPRESENTATIVE LeDOUX asked: Why is or isn't TransCanada's
proposal better than what the producers have proposed under the
name Denali?
REPRESENTATIVE SAMUELS suggested moving forward, rather than
beginning the debate that will occur over the next two months.
Legislators would hear five days of presentations from the
administration and TransCanada on why they believe this is the
best path to monetize North Slope gas. He pointed out that the
process was set up so the LB&A consultants could highlight
questions for legislators to ask and what to look for.
MR. DICKINSON noted there's a general PowerPoint slide
presentation on the Denali website, but there are thousands of
pages on the TransCanada proposal. Any comparison will suffer
as a result.
The committees took an at-ease from 3:21:10 PM to 3:39:10 PM.
3:39:32 PM
MS. ADAIR gave her background, saying she's a chemical engineer
by training and a registered professional engineer in Texas and
Oklahoma; she indicated she also has a master's of business
administration (MBA) from Southern Methodist University (SMU).
She has designed pipelines, gas-processing facilities, and so
on. In her day-to-day job, she looks at issues where the
technical part of the energy industry collides with economics.
She does work on due diligence for financing and lots of work on
damages, contract disputes and negotiations, and so on.
3:40:57 PM
MS. ADAIR began her presentation, "Financial Assessment of the
Impact of the Alaska Gas Pipeline," which was duplicated in a
handout. She showed slide 2, "Key Study Aspects," which said:
- Financial Analysis of the Alaska Gas Pipeline
Project from the perspective of TransCanada and
Producer Project
- Assessment of the future performance of
TransCanada's Canadian gas assets in two cases, With
and Without Alaska Gas Supply
- High-level overview other TransCanada assets
- Evaluation of supply and demand/competition issues
in North America that may impact the TransCanada
pipeline assets
- Evaluation of impact of the Alaska gas on
TransCanada's future earnings
MS. ADAIR noted that, for the most part, Muse Stancil has taken
base-case forecasts of the pipeline, rather than doing an
analysis of TransCanada's proposal or an independent analysis of
the pipeline. The effort has been to put this project in the
context of the environment in which it will function; to address
how the pipeline will affect TransCanada's assets; to discuss
issues that may impact TransCanada's pipeline assets on the
North American front; and to look at the impact of the Alaska
gas pipeline on TransCanada's future earnings as a corporation.
3:42:13 PM
MS. ADAIR showed slides 3-4, "Financial Analysis of the Alaska
Gas Pipeline," which had the following points:
Assess the investment philosophy, asset portfolio, and
financial structure of potential owner companies
- TransCanada
- Producer Project Owner
- ConocoPhillips (COP)
- British Petroleum (BP)
Assess the risk/reward and potential return of the
investment in the pipeline project
- Assuming certain percentage of firm transportation
(FT) committed before investment
- Assuming no FT commitment until year 2 of operations
- Assuming all FT sold prior to initial construction
Evaluate the potential investment in the Alaska
Pipeline Project in the context of each company's
investment philosophy, asset portfolio, and financial
structure
- Assess how investing in the project could impact
each company's financial stability
- Assess the project in light of other likely
alternative project investments available to the
companies
MS. ADAIR explained that for the analysis of the pipeline from
the perspective of the marketplace, Muse Stancil was asked to
talk about how the companies differ that ultimately may be
owner-operators. Muse Stancil was contracted before the Denali
project was announced; ConocoPhillips and BP were added as
specific companies following that, instead of the generic
producer project owner intended originally.
3:43:01 PM
MS. ADAIR said everything she would show is publicly available
information obtained from annual reports, stock analyst reports,
and so on.
MS. ADAIR discussed slides 5-6, "TransCanada." Slide 5 was a
map of Canada and the U.S. depicting gas storage, power plants,
wholly owned pipelines, and affiliated pipelines. She said
TransCanada has a vast footprint in North America, including a
lot of power generation; it is an integrated energy company, at
least on the gas side. Slide 6 had the following points:
Corporate Vision and Investment Philosophy
- Become the leading energy infrastructure company in
North America
- Deliver strong financial performance
- Maximize corporate financial flexibility
- Execute on the current portfolio of large,
attractive projects and initiatives
- Create and cultivate a high-quality portfolio of
future growth opportunities
Asset Portfolio
- Natural Gas Transportation
- 36,500 miles of wholly-owned pipelines connecting
North American gas producing basins to downstream
markets
- 15 billion cubic feet per day (Bcf/d) of natural
gas transported in 2007
- Natural Gas Storage
- 355 billion cubic feet (Bcf) of storage capacity
- Crude Oil Transportation
- Keystone Pipeline Project linking growing
Canadian oil sands supplies with refineries in
the U.S. Midwest
- New build, plus conversion of underutilized
Mainline capacity
- Power Generation
- Assets in Canada and the U.S.
- Diverse portfolio of nuclear, natural gas, coal,
hydro, and wind
- LNG
- Two LNG import terminals in the development phase
- Quebec location on the St. Lawrence River
- New York State in Long Island Sound
- Marketing
3:44:00 PM
MS. ADAIR said she believes this came from TransCanada's latest
annual report. The company's focus is on the midstream sector,
providing services to producers and people who buy gas all over
North America; it also cares about its shareholders. In the
past three years or so TransCanada has grown quite a bit, based
on projects it has identified and executed as well as
acquisitions in the marketplace. The Alaska gas pipeline
project is a great growth opportunity for the company.
MS. ADAIR, with respect to TransCanada's assets, added that the
natural gas storage capacity is primarily in Canada, but also is
affiliated with the ANR Pipeline system that it owns in the
Lower 48. TransCanada is just beginning to enter the crude oil
side; the conversion of underutilized mainline capacity refers
to converting lines in Canada to oil. Diverse power generation
assets are primarily in Alberta and Northeastern U.S. She
mentioned the LNG projects and also said the marketing relates
to TransCanada's unregulated assets.
3:47:06 PM
MS. ADAIR addressed slides 7-8, also labeled "TransCanada,"
noting this information came from stock reports and what they'd
seen in TransCanada's annual report. Slides 7-8 said, with a
few details omitted:
Key Facets of Current Portfolio
- Planned investment of approximately $10 billion in a
number of energy infrastructure projects currently
under construction throughout North America
- Pipeline Segment
- Approximately $5.3 billion of committed capital
projects
- Alberta System's North Central Corridor
- Keystone Oil Pipeline
- Energy Segment
- Plan to invest more than $4.6 billion in a
variety of projects
Future Investments Criteria
- Select only the very best opportunities and
move those initiatives forward
- Build on existing large and attractive
portfolio of projects and investment
opportunities in the Pipeline and Energy
Segments
- Cultivate a portfolio that provides the
opportunity to reinvest substantial
discretionary cash flow into opportunities in
natural gas and crude oil pipelines, power
generation facilities, natural gas storage, and
LNG terminals
- Capitalize on North America's increasing demand
for cleaner and more efficient energy
- Continue to deliver strong and sustainable
financial returns to shareholders
MS. ADAIR added that in Alberta, TransCanada is doing pipeline
expansion and looping in the north central corridor. The
Keystone oil pipeline is a joint venture with ConocoPhillips.
As for the energy segment, this is power generation as well as
LNG and gas storage.
MS. ADAIR explained that for future investments, TransCanada is
looking for opportunities in sectors that grow the businesses
the company already participates in or that are adjacent to
those; TransCanada wants to explore its core competencies in
ways that meet criteria in terms of increasing demand for
cleaner and more efficient energy in North America. And the
company wants to continue to deliver strong and sustainable
financial returns for its shareholders.
3:48:55 PM
MS. ADAIR turned to slide 9, which had a graph of TransCanada's
long-term debt in U.S. dollars and the following points:
Financial Structure
- Current Market Capitalization, $23 billion
- Long-term debt as of March 31, 2008, $13 billion
- Detailed 2007 Financial Performance analysis
located in Appendix
REPRESENTATIVE RAMRAS recalled during the legislative session
TransCanada executed a $2.8 billion power-generation
transaction. He opined that equity markets generally discourage
large companies that deviate from their primary business. He
asked whether Muse Stancil had analyzed that transaction and, if
so, whether the market had rewarded TransCanada for broadening
its energy portfolio. He also asked whether Ms. Adair had any
references here to TransCanada's immediate peer group that
speaks to its capacity to execute this Alaska project.
MS. ADAIR answered no to the last question. As to the first,
she surmised he was talking about the Ravenswood project out of
New York. She said her information wasn't extensive, but she'd
had Muse Stancil's "power guy" look into it.
MS. ADAIR opined that one problem with Ravenswood is it's a
peaking facility, not utilized 100 percent of the time. It also
has reserve or standby payments, to her understanding, to
maintain the equipment and have it ready to go; there is some
concern as to how long those payments may be available.
Furthermore, she believes there's some concern that the
acquisition might dilute earnings, at least short term.
MS. ADAIR said those are things shareholders don't like to hear,
especially when looking at the record for acquisitions, which
have been accretive to earnings. She opined that this
particular acquisition might have been a momentary blip. She
recalled reading and hearing that the company has plans to
repower that facility and turn it around.
REPRESENTATIVE RAMRAS said his question was relative to the size
of the market capitalization of TransCanada and the fact that a
$2.8 billion acquisition for Ravenswood was that dilutive, to
his understanding. He expressed concern about the scale and
TransCanada's ability to execute the Alaska project.
MS. ADAIR answered that with respect to this Alaska pipeline,
the FT component won't be a function of the company's size; it
will relate to the creditworthiness of the parties to the FT
contracts. That is what will carry the day on the debt.
REPRESENTATIVE RAMRAS asked Ms. Adair to expand her answer with
respect to construction risk when it comes to a project between
$21 billion and $36 billion, given what he said is FERC's view
about risks associated with global Arctic gas projects; that the
Trans-Alaska Pipeline System (TAPS) oil pipeline ran 800 percent
over budget; and TransCanada's present market capitalization
relative to the risk of 50, 100, or 200 percent cost overruns.
3:53:15 PM
MS. ADAIR answered with regard to cost overruns that she
believes it's a question the legislature and the market in
general will have to grapple with. That risk more than likely
won't be laid off to an engineer, procure, and construct (EP&C)
contractor, at least not completely; it will have to be managed.
MS. ADAIR suggested looking at the stock-value market cap of
TransCanada at $23 billion and a total enterprise value if the
company's long-term debt is added to the market cap of about
$36 billion. Compared with the types of overruns talked about -
50 percent on $20 billion - it's a lot of money.
MS. ADAIR said, however, that this project is meant to ride on
its own merits and not on a parent guarantee of any particular
company. So management of construction risk is key to financing
the project. The ultimate question is how to manage risks
sufficiently to satisfy the debt and equity that must be raised,
since TransCanada will have to raise equity to do this.
3:54:36 PM
SENATOR WIELECHOWSKI noted the value of the U.S. dollar has
plummeted relative to Canadian dollars. He asked whether that
has affected any of the numbers shown for TransCanada.
MS. ADAIR answered that Muse Stancil tried to do everything in
U.S. dollars in order to have an apples-to-apples comparison.
She didn't believe it would have any impact because corrections
had been done in everything she would show today.
3:55:17 PM
REPRESENTATIVE GARDNER asked what is meant by EP&C contractors.
MS. ADAIR replied those are the companies that build pipelines,
supply equipment, and would put together the project. Usually
when there is a turnkey construction contract for a big project,
there are penalties associated with missing milestones, certain
cost overruns, and so on. The EP&C contractor cannot insure
against every possible delay or lay it off on someone else. An
example is a delay or cost increase related to regulatory
issues. Certain inherent risks to the project rest with those
who own it.
3:56:38 PM
MS. ADAIR noted TransCanada doubled its debt in the last five
years, but also raised equity during this time and almost
doubled its net income, as shown on slides 10-12. Those slides
had graphs depicting net income by segment, capital expenditures
by segment, and capital expenditures and acquisitions.
MS. ADAIR highlighted segments of TransCanada's business. She
explained that "power" relates to power-generation assets and
gas storage, whereas "gas transmission" is specifically pipeline
assets. TransCanada has a pretty good distribution between
those two segments, moving around a little bit, depending on
markets; it isn't highly leveraged in one segment or the other.
MS. ADAIR also highlighted a fairly drastic increase in
expenditures over time. At least in the last couple of years,
she said, spending has focused on the energy sector including
wind projects, hydroelectric power, and so on, with less direct
spending in the pipeline segment.
MS. ADAIR noted there has been significant spending on
acquisitions, through which TransCanada has been successfully
growing. In 2007 that included acquiring ANR Pipeline - a
significant pipeline from the Gulf of Mexico to Midwest markets
- and the outstanding interest in Great Lakes Pipeline. In
response to a question, she opined that Ravenswood wasn't
included here.
3:58:48 PM
MS. ADAIR briefly showed slide 13, "Financial Analysis of
Potential Owner Companies," which said:
Producer Project Owners
- ConocoPhillips
- British Petroleum
MS. ADAIR discussed slides 14-18, "ConocoPhillips Asset
Portfolio," which had a map, graphs, and the following points:
Exploration activities in 23 counties
Production activities in 16 countries
- Total 2007 production 2.3 million barrels per oil
equivalent day
- Including Lukoil and Syncrude
Refineries
- 12 in the U.S.
- 4 in Europe
- 1 in Asia
- 2007 Refining Capacity 2.7 million barrels per
day (MMbp/d)
- 2.04 MMbp/d in U.S.
- 669 thousand barrels per day (Mbp/d)
Internationa[l]
As of December 31, 2007:
- Third-largest integrated energy company in the
U.S.
- Market capitalization
- Oil and natural gas reserves
- Oil and natural gas production
- Fourth-largest refiner in the world
- Sixth-largest worldwide reserves holder, non-
government-controlled company
Refined Products Marketing
- U.S., Europe, and Malaysia
- Phillips 66, Conoco, 76, and JET brands
Joint Venture Operations
- DCP Midstream in the U.S., 50 percent interest
- 63 Natural Gas Processing Plants
- 58,000 miles of natural gas gathering
- Chevron Phillips Chemical Company, 50 percent
Interest
- 36 Production Facilities in 7 countries
- 6 Research and Technology Centers
Corporate Vision and Investment Philosophy
- Exercised a consistent, proven investment
strategy that balances allocations of cash flow
- Grow the asset base
- Return capital to shareholders through
dividends and share repurchases
- Manage debt
- Investment allocations are based upon the dynamic
industry environment including identification of
new investment opportunities
- In the recent past, the company has completed key
acquisitions and new investments while reducing
corporate debt
- 2007 Uses of Cash are summarized in the chart
below
Financial Structure
- Current market capitalization, $144 billion
- Debt as of March 31, 2008, $22 billion
- Long-term debt, $20 billion
MS. ADAIR said while TransCanada is primarily a North American
service provider with a couple of investments in South America,
ConocoPhillips has activities all over the world and is fully
integrated in the oil and gas market sectors. It has chemicals
investments and a fairly significant investment with DCP
Midstream - Duke ConocoPhillips; its 58,000 miles of natural gas
gathering is primarily in North America.
MS. ADAIR drew attention to statistics for year-end 2007, saying
ConocoPhillips is the third-largest integrated energy company in
the U.S., looking at factors like market cap, reserves, and
production rates. It is the fourth-largest refiner in the
world, with 17 refineries, primarily in the U.S. It has a lot
of reserves as well.
4:00:14 PM
MS. ADAIR referred to recent financial reports and said
ConocoPhillips, like any company, wants to grow its asset base.
It has been returning capital to shareholders through dividends
and share repurchases. When a company buys its own stock back
instead of investing in projects, that typically means its board
of directors feels its in-house projects and those being
cultivated are better than current marketplace opportunities.
ConocoPhillips has a pretty significant investment in its own
company and projects.
MS. ADAIR told members probably the hardest thing for any
company right now is to figure out what to do in the current
marketplace. Nobody knows if prices will remain at $110 or $120
or whether this is just a blip. Long-term planning is tough.
Most big companies have reacted by using oil and gas price
forecasts that are significantly lower than the current prices.
MS. ADAIR noted ConocoPhillips has done quite a bit in
acquisitions and new investments, paying down its debt. It is
looking to shore up its balance sheet some.
4:02:08 PM
MS. ADAIR highlighted stock value of $144 billion and
$22 billion in debt for ConocoPhillips, of which $20 billion is
long-term debt. Commensurate with the run-up in oil prices, she
said, ConocoPhillips has taken on additional debt, likely to try
to find more oil.
MS. ADAIR said because ConocoPhillips is such a diverse
business, there are lots of segments, including Lukoil, a
Russian oil company joint venture. ConocoPhillips's exploration
production and income has driven it for the last four years,
though it was down a bit in 2007; that happened with many
companies as costs finally caught up with runaway oil prices.
MS. ADAIR said ConocoPhillips' refining and marketing sector has
done well, also seen across the board until this year because it
was relatively stable and because relatively low oil price
refining margins have been strong as demand for products has
increased worldwide.
MS. ADAIR noted ConocoPhillips' capital budget for 2007 was
about $12 billion, significantly higher than TransCanada's. The
bulk of it has been in exploration and production because lots
of money must be spent to develop reserves and there are
worldwide operations. Some money is being spent on refining and
marketing.
4:04:00 PM
MS. ADAIR turned attention to BP, slide 19, "BP Worldwide,"
which had the following points:
Exploration activities in 29 countries
Over 24,000 service stations worldwide
Interest in 17 crude oil refineries
Corporate Vision and Investment Philosophy
- Continue to support the strong list of projects
under development and coming on stream
- Newly delineated the business into groups to
emphasize the key drivers of the business
- Upstream
- Downstream
- Alternative Energy
- Investments in alternative energy to provide a
focus on technology to support the existing
business as well as the development of the supply
of low-carbon energy for the future
- Focus on evaluation of long-term strategy given
increased oil prices and the trends in the world
economy, including the identification of the
right opportunities in a challenging marketplace
- Cash flows from BP's strong asset base are
allowing the company to increase investment in
future growth and shareholder dividends
- Returning cash to shareholders through dividends
and buybacks
- Increased the quarterly dividend (March 2008)
to 13.525 cents per share, compared with 10.325
cents per share in 2007, a 16 percent increase
- $7.5 billion of shares were repurchased for
cancellation in 2007
MS. ADAIR indicated while ConocoPhillips is a really big
company, BP is huge. Such a company has numerous opportunities
presented daily. She said BP recently reorganized its business
into upstream, downstream, and alternative energy segments
because it believes that investing in the latter could really
impact the rest of its business.
MS. ADAIR likened BP's thinking to investing in the NASA space
program, which results in an enormous amount of technology that
provides benefits in many areas. She said BP seems to be trying
to figure out ways that the technology in alternative energy can
help its upstream and downstream programs and also enhance its
balance sheet.
MS. ADAIR additionally said that BP speaks to the task of
determining what to do in the long term, given the new era of
oil prices, and is looking at growing the company, especially
with respect to shareholder dividends. That BP also has been
buying back its stock is another signal that it has lots of
cash, but not as many good projects as desired.
4:05:57 PM
MS. ADAIR showed slides 20-21, "BP Worldwide Asset Portfolio,"
which had the following categories and additional details not
listed here:
Africa
Asia
Australasia
Europe
- London is where BP's corporate headquarters are
located, and the UK is, therefore, a center for
trading, legal, finance, and other mainstream
business functions. The UK is also home to
three of BP's major global research and
technology groups.
North America
- Exploration and Production - The BP group is
the largest oil and gas producer and one of the
largest gasoline retailers in the United
States, and has significant natural gas
production in Canada
- The largest non-U.S. company on the New York
Stock Exchange
- BP Alternative Energy business operations
center - Houston, and solar manufacturing
facilities in the U.S.
- Canadian activities focus on the production of
natural gas and derivatives
- Exploration and production work is a core
aspect of BP's presence in Trinidad and Tobago
- where BP is a major local producer
South America
MS. ADAIR noted BP has more diversity than ConocoPhillips, with
investment in solar manufacturing in India and Australia,
exploration and production, doing the Baku-Tbilisi-Ceyhan (BTC)
pipeline, and so on; she emphasized the opportunities. In North
America, there is lots of exploration and production. Some work
has been done in South America, as TransCanada has also done;
there BP is doing work related to chemicals and solar projects.
4:06:45 PM
MS. ADAIR discussed slide 22, which had a graph labeled "BP
Debt" and the following points:
Financial Structure
- Current Market Capitalization, $228 billion
- Debt as of December 31, 2007, $31 billion
MS. ADAIR noted the graph shows that the trend over time has
been pretty stable, although it rose some in 2007, probably
reacting to higher oil prices.
MS. ADAIR addressed slides 23-24, graphs labeled "BP Capital
Expenditures and Acquisitions" and "BP Operating Segment
Profit." She noted that, as seen with ConocoPhillips, BP is
mainly an exploration and production company; that's where most
of their base revenues come from. They are spending money in
those sectors to develop reserves for the long term.
MS. ADAIR said BP calculates its net income equivalent a little
differently than is done in the U.S. Exploration and production
dwarfs other business segments. In particular, BP has had some
issues with refining and marketing; surmising many legislators
heard about the Texas City incidents and some refining issues,
she said BP is hopeful to have those put behind it and is
looking for less future spending in those areas.
4:08:08 PM
MS. ADAIR discussed slide 25, "Company Financial Comparison,"
two graphs comparing 2007 capitalization and also the average
annual capital expenditures (2003-2007) for TransCanada,
ConocoPhillips, and BP. She noted that total capitalization for
TransCanada was the least, whereas BP's was highest by far. For
capital expenditures (CAPEX), the average over the last five
years was used. As shown, BP is spending $15 billion to
$16 billion annually in its capital budget. TransCanada's
capital expenditures, while far less than the others, have been
increasing over the entire timeframe.
4:08:50 PM
MS. ADAIR turned to slides 26-27, "Risk/Reward and Potential
Project Return," which had the following points:
Assuming certain percentage of FT committed before
investment
- Revenue Risk is reduced, but not eliminated
- Some Revenue Upside is lost as a result of likely
lower overall negotiated tariff rates for FT
shippers
- Some Revenue Upside is retained as uncommitted
operational capacity may be sold to spot shippers at
base tariff rates
- Some Capacity Risk may be eliminated depending upon
the Project Developer's final technical design
relative to overall system FT commitments
- The Project Developer still faces significant risks
- Construction risk - weather delays, design
delays, construction quality issues, material /
equipment availability delays, etc.
- Capital Cost risk - raw material costs, labor,
interest rate risk
- Operating Cost risk - depending upon how FT is
structured, negotiated rates will leave
operational risk with Project Developer
- Credit risk that is assessed based upon the
creditworthiness of the companies standing
behind the FT commitment
- Regulatory risk
Assuming no FT commitment until year 2 of operations
- Not a valid reference case
- The pipeline project is not likely to be built
without throughput commitments, therefore, the risk
is very, very high for any project sponsor looking
to proceed with development in this case
Assuming all FT sold prior to initial construction
- If all of the FT capacity on the system is sold
prior to initial construction, revenue risk is
mitigated
- Capacity risk is reduced as project can be "right-
sized" to meet committed market demand with
expansion capabilities
- The Project Developer still faces significant risks
- Construction risk - weather delays, design
delays, construction quality issues, material /
equipment availability delays, etc.
- Capital Cost risk - raw material costs, labor,
interest rate risk
- Operating Cost risk - depending upon how FT is
structured, negotiated rates will leave
operational risk with Project Developer
- Credit risk that is assessed based upon the
creditworthiness of the companies standing
behind the FT commitment
- Regulatory risk
MS. ADAIR elaborated. She said this is Muse Stancil's viewpoint
on FT and the Alaska gas pipeline, addressing cases they'd been
asked to consider. For the first assumption, that a percentage
of the FT is committed before investment, there is revenue risk
is for the project owners. The possible loss of some revenue
upside is because the negotiated rate will, for the most part,
be constant throughout. What is retained is for capacity that
hasn't been committed. That can be committed on negotiated
rates later or there may be a recourse rate; hopefully it won't
go unused.
MS. ADAIR said some capacity risk may be eliminated because of
the ability to right-size the pipeline; the engineering design
may be better because of knowing exactly what the FT commitment
will be. That goes into the thinking for expansion as well.
However, significant risks still must be dealt with, as listed
above. Capital costs carry risk because of inflation. For
operating cost risk, the negotiation is really an allocation of
that risk on those costs going forward.
MS. ADAIR explained that credit risk is assessed based on who
signs an FT commitment. The debt holders and, if equity must be
raised, the people who'll invest in equity in this project want
to be sure that whoever executes those FT contracts can pay,
whether they're selling gas or not. Ultimately, that means
looking to the producers with significant balance sheets to
backstop those FT commitments.
MS. ADAIR noted there's ongoing regulatory risk for a pipeline.
The regulatory environment is never locked in. For instance,
recently there have been pipeline inspection rules about more
frequent testing and greater degrees of monitoring, and there
are carbon dioxide and greenhouse gas issues.
4:12:18 PM
MS. ADAIR turned to the next assumption, no FT commitments when
the pipeline is built. Noting she'd sought input from people
with lots of experience in this area, Ms. Adair reported that
they'd all responded that it's not even a valid reference case;
they didn't believe the project would be built without
throughput commitments, and therefore the risk would be very,
very high for any project sponsor that looks to proceed on a
speculation basis.
MS. ADAIR spoke about the final assumption, that all the FT is
sold before initial construction. She said in that case,
revenue risk is pretty much taken care of, assuming a lot of
reopeners haven't been negotiated in the contracts. Capacity
risk is reduced significantly because the subscribed volumes
will be known. Since it will likely be closer to construction,
there'll be better reserve estimates and production forecast
rates; thus a better design can be done to fit the project to
the reserves that the pipeline is meant to service.
MS. ADAIR noted the project developer will still have all those
other risks discussed before. That doesn't mean the project
developer has to carry them all 100 percent, but it is necessary
to deal with those and think about how to mitigate them and lay
those risks off or allocate them to others in order to have the
most financially successful project for the project investors.
4:13:45 PM
MS. ADAIR paraphrased slide 28, "Potential Company Investment,"
which said:
Evaluate the potential investment in the Alaska
Pipeline Project in the context of each company's
investment philosophy, asset portfolio, and financial
structure
- Assess how investing in the project could impact
each company's financial stability
- Assess the project in light of other likely
alternative project investments available to the
companies
TransCanada
COP
BP
4:14:06 PM
MS. ADAIR discussed slide 29, "Potential Company Investment -
TransCanada," which had the following points:
Financial Stability
- In the last five years, net income has doubled
and the company has been able to take on
additional debt, almost doubling long-term debt
in the same period
- The company has also been able to define and
capture new opportunities that have provided a
solid foundation for new equity
- The "midstream" energy services sector has been
in favor with investors
- More than 60 percent of TransCanada's equity is
held by institutional investors
- Favor predictable, stable returns
- Favor low risk investments for the majority of
their portfolios
- Sometimes take on medium to high risk
investments, but do so in "small bites"
- A project the size of the Alaska Gas Pipeline
dwarfs cumulative total TransCanada capital
spending in the last 5 years
- On a stand-alone basis, at today's market
capitalization, taking on this project will be
highly leveraging to TransCanada, both positive
and negative, in contrast to historical
investments
- Would likely require raising additional equity
- Would likely impact equity returns in the
medium-term, dependent upon project timeline
and cash funding needs
Relative to other TransCanada Investments
- Complements existing Canadian gas pipeline and
storage assets, owned by TransCanada and others
- Long lead time does not provide support for near-
to medium-term earnings growth; TransCanada would
have to identify, consummate, and execute other
projects in the interim
- May provide needed infusion of natural gas
liquids into Alberta
- Supports expected supply shortfall in
petrochemical feedstock
- May provide some supply to meet heavy crude
diluent demand
Note: Diluent is pentanes plus NGL used to mix
with heavy crude for shipment
MS. ADAIR added that TransCanada has been able to capture new
opportunities and is growing through acquisition. Investors
like the mid-stream sector because of predictable returns for
the most part, though there might be projects such as Ravenswood
that those sorts of investors aren't happy with. At last check,
60 percent of equity was held by institutional investors, which
tend to invest in things like state employee pension funds.
MS. ADAIR said the Alaska project is huge relative to what
TransCanada has taken on. However, TransCanada has the core
competencies in its gas businesses to manage a project like
this. If TransCanada were a stand-alone owner-operator for the
project today, taking the project on would be highly leveraging
to the company. Also, it will have to raise equity, and there's
a chance that medium-term equity returns for its shareholders
would be affected, depending on the project timeline, cash
funding, and details for getting the project off the ground.
MS. ADAIR noted this project certainly complements TransCanada's
portfolio of Canadian gas pipeline and storage assets. The long
lead time could be a problem for the company, depending upon how
it's structured, because TransCanada has been adding projects
that are accretive to earnings, adding acquisitions, and growing
the company.
MS. ADAIR said because this project will feed into the
TransCanada system, as mentioned this morning, the infusion of
NGLs from the Alaska gas will support a couple of issues facing
Canadian producers today: petrochemical feedstock and diluent
for heavy crude oil. Heavy crude oil can be almost like road
tar. To get it to flow in pipelines, it is diluted, usually
with "C5" plus heavy NGLs. Having a ready supply could benefit
the market in Alberta, depending on quantities available and how
much actually makes it that far in the pipeline.
4:18:01 PM
REPRESENTATIVE RAMRAS gave an analogy in the hotel business. He
asked about the scale of TransCanada's proposed project in
relation to its market capitalization, debt, and so on, compared
with the relative scale for ConocoPhillips and BP. He asked
Ms. Adair to return with a single slide, a one-page recap, to
demonstrate risk.
MS. ADAIR suggested thinking about increasing the size of any
business through finding partners to put in seed money. For
instance, if hotel rooms were sold for 10-15 years before
commencing a building project, the bank would loan money on it.
As long as there are project partners to help put the equity
seed money in, she said, the money could probably be borrowed
from the bank to do the project.
REPRESENTATIVE RAMRAS took issue if the hotel rooms would be
sold for a fixed cost, saying there'd be construction risk if
his construction cost was unknown. Returning to this project,
he surmised this would cause the producers to absorb an
inordinate amount of risk that would dampen the environment in
which a business transaction could be consummated.
4:21:41 PM
MS. ADAIR replied she believes the negotiation of that rate
would come into play for the willing buyer or seller. Someone
would look at what the market would bear and what partners would
be willing to do. Any developer for this project will have to
assess how much equity return is needed, how much risk is
acceptable, and so forth. It's not a slam-dunk.
MS. ADAIR further responded by showing slide 25, "Company
Financial Comparison," two graphs comparing 2007 capitalization
and also the average annual capital expenditures (2003-2007) for
TransCanada, ConocoPhillips, and BP. She noted the first graph
depicts enterprise value, adding the companies' market equity
value to their debt. If this project is presumed to be about
$20 billion, it's below the total market cap of TransCanada, but
certainly much lower than BP or ConocoPhillips.
4:23:11 PM
REPRESENTATIVE GARA offered that this will be the biggest
project in TransCanada's history, since to his belief it's the
biggest in North America. He asked how it compares with
pipelines that BP and ConocoPhillips have built. He also asked
Ms. Adair, based on what she knows, whether she believes
TransCanada can pull this off.
MS. ADAIR responded to the first question by saying most
integrated companies like ConocoPhillips and BP have their
exploration and production assets together. Some but not all
include their gas conditioning plants, processing and gathering,
and so forth in those same segments, although some companies
like Exxon have separate pipeline segments.
MS. ADAIR said the tendency is that when any large company takes
on a megaproject, it almost always does it with partners; it
doesn't want to take on all the risk in its own portfolio for
that one project. So companies pool assets - financial,
intellectual, engineering, and so on - and diversify the risk of
the project among all of them.
MS. ADAIR turned to whether TransCanada can do the project. She
opined, based on public information review, that TransCanada has
the core skills to do it; it operates lots of gas pipelines,
builds projects, and does things all the time.
MS. ADAIR said the sheer size of this project will be big for
anybody. Noting she'd received an e-mail from BP recruiting
engineers to come to Alaska, she highlighted the current
shortage of engineers that affects everyone. She surmised,
however, that by pooling interests and working together - either
collectively as owners or helping each other because it's in
everyone's best interests - they can do the project.
REPRESENTATIVE GARA asked whether this would also be the biggest
pipeline project for the other companies.
MS. ADAIR replied she hadn't searched the world over, but
suggested looking at projects of the same magnitude, especially
in today's dollars. TransCanada's mainline system from Alberta
to the eastern coast of Canada has five pipelines in the ditch
in some places, for instance. There are many systems where one
was built and then others were added, and there are lots of big
projects. But in one lump sum this may be the biggest.
4:27:09 PM
REPRESENTATIVE SAMUELS noted Representative Kerttula had asked
to hear TransCanada's take on some of the conclusions. He
suggested that would be appropriate during the roundtable
discussion, when TransCanada could have its financial analysts
available; the same could be done for ConocoPhillips and BP if
they wished.
REPRESENTATIVE SAMUELS, on behalf of Representative Gara,
proposed tasking Muse Stancil with seeing if there are other
projects of this magnitude that ConocoPhillips and BP or others
have done and how the risk has been mitigated.
REPRESENTATIVE KERTTULA recalled last week legislators heard
from Goldman Sachs, whose representatives provided a similar
answer about TransCanada's ability.
4:28:46 PM
MS. ADAIR discussed slide 30, "Potential Company Investment -
ConocoPhillips," which said:
Financial Stability
- COP routinely takes on large, medium- to high-
risk projects; however, as a large, integrated
multi-national corporation, such higher risk
projects are offset by long-term producing
reserves, midstream assets, and other investments
- Approximately 80 percent of COP equity is held by
institutional and mutual fund investors that own
the stock because of the corporation's ability to
manage such risks
- The capital required for execution of the project
is of the same order of magnitude as COP's
current capital budget
- In any case, the financial risk of the Alaska Gas
Pipeline Project will ride on the shoulders of
those companies that own or control the majority
of the gas reserves in the state
- Companies like [COP] are used to taking on such
risks in return for developing reserves
- Investors in companies like [COP] expect
corporations to take on such risk to develop
the reserves, but also trust the established
track record of these companies in assessing
and managing development risk
Relative to other ConocoPhillips Investments
- The COP investment philosophy is based upon
allocation of capital
- [That] COP has been investing in stock buybacks
in the last couple of years suggests that
management views returning recent cash increases
to investors to be more profitable than investing
in additional new projects
- COP likely views the Alaska Gas Pipeline Project
as leveraging and important to the company's
future reserve position as they have allocated
the initial capital to pursue the first phases of
the Denali project development
MS. ADAIR explained that ConocoPhillips and BP are probably in
the same situation in terms of financial stability and how they
would view this project. For them, it's a way to monetize their
gas reserves, which is important. They're used to taking on
big, high-risk projects. They do lots of investing in
exploration and production, and exploration is a very high-risk
business. They know how to model projects like this to
understand the risks and to manage them.
MS. ADAIR also addressed slide 31, "Potential Company Investment
- BP," which said:
Financial Stability
- Even larger than COP, BP is one of the largest,
integrated multi-national energy corporations and
does take on medium- to high-risk projects in
balance with the corporation's total portfolio
risk
- The capital required for execution of the project
is in line with BP's current capital budget
- In any case, the financial risk of the Alaska Gas
Pipeline Project will ride on the shoulders of
those companies that own or control the majority
of the gas reserves in the state
- Companies like [BP] are used to taking on such
risks in return for developing reserves
- Investors in companies like [BP] expect
corporations to take on such risk to develop
the reserves, but also trust the established
track record of these companies in assessing
and managing development risk
Relative to other BP Investments
- Like COP, BP has also been buying back stock
- BP also invests, as do most large, integrated
companies, based upon an allocation model that
considers the health of each asset sector and the
ranking of available projects on a risk/return
basis
- Stock buyback typically signals board confidence
in the existing asset base and a preference for
returning recent cash increases to investors
rather than increasing capital spending with
additional new investments
4:29:23 PM
MS. ADAIR told members whereas about 80 percent of
ConocoPhillips' shareholders are institutional investors, mutual
funds, and pension-type funds, BP has perhaps 15-20 percent of
those. As shown on a previous slide, capital budgets for both
far exceed this pipeline.
MS. ADAIR said it's important to note, however, that on an
annualized basis the investment in the pipeline doesn't happen
in one day. The $23.2 billion will be spent over a long period
of time. When looked at that way, it brings the total amount
they're managing yearly to a much lower number.
MS. ADAIR added that both ConocoPhillips and BP have been buying
back their stock and paying good dividends. They're looking for
good investments for their shareholders. Both have validated at
least the study phase of this project with the announcement of
their capital commitments to the Denali project.
4:31:10 PM
SENATOR WIELECHOWSKI recalled hearing that the rates of return
on the upstream portion are much higher than the 14 percent for
the pipeline. He asked why these companies would spend billions
of dollars developing something for which they get such a lower
rate of return.
MS. ADAIR answered this isn't about the pipeline to them. The
pipeline is just the equipment they need to get the gas from the
ground to the market. While it isn't true if gas is at $1.75 to
$2.00 per MMBtu, at today's higher market prices, the reserves
in the ground will likely always be worth more to them than the
ownership interest in the pipeline.
SENATOR WIELECHOWSKI asked: Why wouldn't they be happy with
having an independent company come in and build the pipeline so
they can make the huge profits that are predicted for the
upstream portion?
MS. ADAIR cited her experience operating gas plants, oil wells,
and gas wells in the field. She said when the operatorship is
turned over to someone else, especially someone not as focused
on the upstream, goals aren't always aligned. There are issues
of flexibility, cost savings, and intangibles that a producer
wants to control within the whole producing operation.
Producers can be juxtaposed to pipelines in terms of when
they're curtailed, when maintenance is done, and so on. Those
issues are eliminated by being the operator of that equipment.
4:33:32 PM
SENATOR WIELECHOWSKI asked what is meant by the final point on
the ConocoPhillips slide, that the company likely views this
project as leveraging.
MS. ADAIR answered that every exploration and production (E&P)
company is trying to add reserves to its balance sheet. If
there isn't a conduit for those to get to the marketplace, they
aren't on the balance sheet. So companies want to monetize
those and get them on the balance sheet as asset.
4:33:53 PM
SENATOR THERRIAULT asked: In looking at the companies, did you
pull together any information on their reserve replacement
ratios?
MS. ADAIR indicated Muse Stancil could get that information,
which is readily available.
REPRESENTATIVE SAMUELS announced the meeting would reconvene at
9:00 a.m. tomorrow morning. SB 3001 and HB 3001 were held over.
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