Legislature(2007 - 2008)TERRY MILLER GYM
06/07/2008 10:00 AM Senate SENATE SPECIAL COMMITTEE ON ENERGY
| Audio | Topic |
|---|---|
| Start | |
| SB3001|| HB3001 | |
| Tony Palmer, Transcanada; Commissioners Galvin and Irwin | |
| Continuation of Transcanada Presentation with Questions | |
| Presentation by Bob Swenson of Dnr and Dave Houseknecht of Usgs | |
| 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
10:10:16 AM
CHAIR HUGGINS brought SB 3001 and HB 3001 before the committees.
He noted that there would be follow-up questions for TransCanada
and additional information from Mr. Palmer; Commissioners Galvin
and Irwin were available for questions. Also on the agenda was a
presentation from Bob Swenson of the Department of Natural
Resources (DNR) and Dave Houseknecht of the U.S. Geological
Survey (USGS).
^Tony Palmer, TransCanada; Commissioners Galvin and Irwin
10:12:48 AM
TONY PALMER, Vice President, Alaska Business Development,
TransCanada Alaska LLC, indicated he would share information
sent since yesterday's meeting. Referring to discussion of
whether Keystone contracts were made available publicly in
regulatory forums, he reported that in a Canadian National
Energy Board (NEB) hearing, Keystone did provide redacted pro
forma copies of the transportation service agreements for its
base system; those are available online at:
https://www.neb-one.gc.ca/ll-eng/livelink.exe?
func=ll&objid=444693&objaction=browse
MR. PALMER noted that the second issue relates to whether
TransCanada could prevent a party that had built a pipeline to
TransCanada's Alberta system from entering it. He said
provisions in the NEB Act and the provincial regulator require
TransCanada to interconnect. Section 71(3) of that Act governs
construction of new facilities for federally regulated pipelines.
MR. PALMER said even if TransCanada didn't want it, NEB has had
the power for decades to require expansion or interconnection.
Reading from Section 71(3)(c), he said NEB can require the
junction of a pipeline with other facilities for the transmission
of hydrocarbons or other commodities if the board finds it places
no undue burden on the company.
10:15:53 AM
SENATOR THOMAS asked: What is considered a competing pipeline
with respect to size? Is 0.5 billion cubic feet a day (Bcf/day)
the capacity absent any expansion? Does it matter whether it
comes from the Foothills or the North Slope? Would financial
incentives such as tax provisions make a difference? And when it
comes to an independent builder without state participation, how
does that play in?
10:17:16 AM
PATRICK GALVIN, Commissioner, Department of Revenue (DOR),
responded that 0.5 Bcf/day is the initial capacity. Any pipeline
can be expanded. The idea was to make the assurance, recognizing
that any applicant will assess its opportunity to acquire
sufficient firm transportation (FT) commitments. If the state
sponsored another pipeline in some financial way and it took away
some existing gas that could be committed to this Alaska Gasline
Inducement Act (AGIA) line, it would diminish the likelihood of
success for this pipeline. So the administration would focus on
the initial amount to hit that threshold.
COMMISSIONER GALVIN discussed what assistance the state might
provide that would trigger this mechanism. He said the statute
was carefully crafted to focus on financial assistance, including
tax breaks, targeted to that particular project. An overall tax
change wouldn't target a particular project. Also, as he'd
responded yesterday, the state clearly would still provide and
even coordinate all the regulatory processes for these other
projects. But because the state is a sovereign, and to have a
clean decision-making process, none of that activity would
trigger this provision.
COMMISSIONER GALVIN addressed the question of whether the gas
comes from the Foothills or the North Slope. He said those could
be considered competing for the same gas supply. It wouldn't be
gas in Nenana, for instance, because the target of AGIA is from
the North Slope to market. As to whether this would hinder a
private company trying to pursue the line without any state
financial assistance, he said no. While it clearly allows for
competing projects to advance, it doesn't allow the state to
provide financial assistance to those competing projects.
MR. PALMER concurred.
10:21:09 AM
TOM IRWIN, Commissioner, Department of Natural Resources, added
that 0.5 Bcf/day might sound small, but he'd put it in context.
Under AGIA, 0.5 Bcf/day or less doesn't compete. For example,
10.0 Bcf/day goes from Canada to the U.S. The 0.5 to be used
within Alaska is 5 percent of that. If there is a 4.0 to 4.5
Bcf/day line, 0.5 Bcf/day would be all the state's royalty gas,
significant quantities for in-state use.
COMMISSIONER IRWIN referred to Cook Inlet and indicated
0.19 Bcf/day is used for liquefied natural gas (LNG) today. That
would leave 0.31 for in-state use including Agrium. In 1998,
with Agrium running, it was 0.142. Predicting by 2020 it will be
up to 0.18 of the 0.19, he concluded that 0.5 Bcf/day allows for
all the in-state use that can feasibly be foreseen, all Alaska's
royalty gas if it chooses.
COMMISSIONER IRWIN emphasized that gas will be available in
Alaska. He said it doesn't compete and is a separate issue.
This isn't either/or. In fact, if it rose to 1.0-1.5, some would
have to be exported, fitting with the "Y-line" concept. There is
plenty at 0.5 Bcf/day.
REPRESENTATIVE RAMRAS questioned the math, citing calculations of
100 Bcf a year with a build-out in Fairbanks and the presumption
of being able to nominate adequate gas once there is
infrastructure. He mentioned adding Flint Hills and the build-
out of Fairbanks, Anchorage, and Agrium.
REPRESENTATIVE RAMRAS also recalled a trip that he, the Speaker,
and the commissioner took to China to see what markets exist; he
said if trade with China isn't likely in the near future, it
doesn't preclude it with Korea or Japan. He emphasized getting
gas right now to energy-isolated communities including Fairbanks,
expressing concern that it may require a larger pipeline to be
viable, which AGIA precludes.
10:26:13 AM
COMMISSIONER IRWIN clarified that he was talking per day, whereas
Representative Ramras was talking per year. He said if those
numbers are divided by 365 days, then 0.5 Bcf/day satisfies it.
Economical energy is needed today for Alaskan businesses as well
as for Alaska's future, which doesn't compete with what
Representative Ramras was talking about.
COMMISSIONER IRWIN indicated the Chinese opportunities have been
looked at with experts. The economics appear best if there is a
line to Canada that then sets up the gas treatment plant (GTP)
and the pipeline to Delta; the administration concludes that a Y-
line to Valdez would make terrific economic sense. Noting that
the two tie together, he reminded members that he'd testified
when AGIA was proposed as a bill that he wouldn't be satisfied
until Alaska has both. This is a route to both, he said, a clear
path forward.
10:28:02 AM
COMMISSIONER GALVIN reminded members of yesterday's discussion of
false choices, the idea that there must be a choice between
Alaskan gas now versus AGIA. He agreed with Representative
Ramras that if the goal is to meet Alaska's needs now with a
pipeline which pays for itself, ultimately that must connect to a
much larger market, with LNG for export and a larger-capacity
line. The question becomes at what point a balance is reached so
there is a quick LNG project that is economically viable. He
asked, however, whether this is really the goal.
COMMISSIONER GALVIN explained that if the goal is to maximize
value to Alaskans, there are two interests: 1) revenue,
monetizing North Slope gas to the maximum possible, encompassed
in AGIA; and 2) getting gas to Alaskans. He said the
administration's analysis of a large-capacity line, the
TransCanada project, versus an LNG project showed that tens of
billions of value in today's dollars would be lost by switching
from the TransCanada project to an LNG project.
COMMISSIONER GALVIN therefore opined that the State of Alaska
could build a small-capacity line to serve Alaska's needs
entirely with state money and not worry about economies of scale.
That would be a tremendously better economic decision for the
state and would get gas to Alaskans more quickly than hooking it
up to an LNG project.
COMMISSIONER GALVIN pointed out that even small-capacity LNG
projects have timeline considerations, as analyzed in the
finding. The entire supply-route chain must be lined up. This
includes having the gas committed, along with the question of who
will commit gas to an LNG project for an Asian market. It also
includes getting the export license, lining up contracts, and so
on. That won't be quick.
COMMISSIONER GALVIN emphasized the opportunity to choose. He
said if Alaskans believe gas truly is the fuel of the future -
better than going for a hydroelectric project or other
alternatives - then the state can build the line, which will be
cheaper than forgoing TransCanada's Alaska project.
10:31:34 AM
REPRESENTATIVE RAMRAS remarked, "Only if we make it so." He said
1) he doesn't hear a "can do" attitude from the two commissioners
about providing gas for Alaskans; 2) he stands on his math for
annual usage for Anchorage, Fairbanks, and potentially others
along the Railbelt and down to Valdez, as well as Agrium and
Flint Hills; and 3) he hears $500 million going to a Canadian
multinational conglomerate and an interest in getting gas to
Alaskans after a large line is built because that provides value
to the state treasury, not the household incomes of Alaskans.
COMMISSIONER IRWIN responded by indicating he cares equally about
in-state usage. He again highlighted the per-year versus per-day
calculations, reiterating his belief that 0.5 Bcf/day clearly
covers it all, and more. He emphasized that he absolutely
believes, as does the administration, in the energy needs of
today. This AGIA project doesn't compete with in-state use, he
said. It's two different issues.
10:33:53 AM
SENATOR THERRIAULT reported that he'd met with ENSTAR Natural Gas
Company ("ENSTAR") representatives when they were in town; they
have a $6 million budget to start working on the economics of a
bullet line and indicated they're being approached by companies
with products around the world, pitching composite versus steel
pipe, for instance. When asked, they'd indicated they need
nothing from the state government right now, other than perhaps
assistance with permitting and gathering information.
SENATOR THERRIAULT highlighted two ways to ensure that in-state
gas is affordable and that the tariff doesn't price it out of the
market. First, capacity can be ramped up, since any molecule
riding a bigger line gets a cheaper ride and the farther it goes,
the better. Or, second, the debt can be paid down. He asked:
Has the administration considered helping to pay down the debt so
a bigger line isn't needed to deliver an affordable product to
Alaskans?
10:35:43 AM
COMMISSIONER GALVIN responded that economical energy is an issue
this administration has taken head-on. The Alaska Energy
Authority is undertaking long-term planning, and this legislature
will talk soon about short-term energy relief and how that builds
into a mid-term and long-term energy plan.
COMMISSIONER GALVIN addressed whether the administration would
consider paying down the cost of a bullet line to lower the
tariff to provide affordable energy. He said that's been
discussed publicly as an option. However, to simply rush in and
say the answer to the energy future is a bullet line doesn't
recognize alternative energy choices that state dollars could go
towards instead.
COMMISSIONER GALVIN said that public dialogue needs to occur, and
AGIA was set up to allow that discussion. The administration has
a "can do" attitude and wants to find solutions, but it requires
a joint effort, based on facts and true choices for long-term
energy needs.
COMMISSIONER GALVIN reminded members that many bumper-sticker
solutions have impacts. For instance, if a bullet line takes all
the state royalty gas and provides it to Alaskans at a cheaper
price, it will affect tax revenue, royalty revenue, and Alaskans'
permanent fund dividends. That trade-off needs to be recognized.
Is it the most cost-effective way of solving this problem? That
choice needs to be made with the best information available.
COMMISSIONER GALVIN noted that 0.5 Bcf/day is 500 million cubic
feet a day. Within the Southcentral area, which uses natural gas
to generate electricity, the entire market including homes and
commercial operations uses 252 million cubic feet a day. That's
currently served by the Cook Inlet gas supply.
COMMISSIONER GALVIN also noted that export of LNG is about
190 million cubic feet a day. Agrium at its peak almost a decade
ago used about 150 million a day. All that will continue to be
served by Cook Inlet for years; if the desired exploration is
successful, it should be served for decades.
COMMISSIONER GALVIN concluded by saying there are two issues: 1)
an immediate need to get gas to Alaskans, which doesn't conflict
with AGIA, and 2) the long-term need, for which spur lines off
the main line are the solution; those aren't in competition,
either, and won't be implicated by this provision. Noting a big
question is whether approval of the AGIA license somehow
precludes the state from solving this problem of low-cost gas for
Alaskans, he said the answer is no.
10:41:34 AM
REPRESENTATIVE DOOGAN asked: When does the state's commitment to
TransCanada to not financially support a competing pipeline end?
COMMISSIONER GALVIN referred to the statute and replied it ends
upon commencement of commercial operations of the pipeline.
MR. PALMER agreed.
10:42:16 AM
SENATOR STEDMAN pointed out that many parts of Alaska such as
Kodiak or Southeast won't see a gas line, and there are serious
issues in Western Alaska related to fuel costs. He emphasized
the need for solutions statewide, not just for the Railbelt.
COMMISSIONER IRWIN replied he couldn't agree more. Indicating
this significant issue could have different answers in various
parts of the state, he cautioned against focusing so hard on one
area that others are missed.
10:43:29 AM
REPRESENTATIVE NEUMAN mentioned high fuel prices around the state
including the Yukon River. He asked if the soonest natural gas
can get to Alaskans is when the pipeline is built and gas flows.
COMMISSIONER GALVIN replied no. He clarified that he'd said the
state can satisfy the needs of Alaskans separately.
REPRESENTATIVE NEUMAN surmised that would entail a spur line off
of the main line.
COMMISSIONER GALVIN answered no. He said the state could build a
separate line if there's a collective decision that it's the best
choice among the energy options.
REPRESENTATIVE NEUMAN gave his understanding that if it's over
0.5 Bcf/day or 500 million cubic feet, there couldn't be
financial incentives from the state.
COMMISSIONER GALVIN agreed if it's bigger than 500 million.
However, he said it is unlikely to get anywhere close to that
size to meet the needs of folks on the Yukon.
REPRESENTATIVE NEUMAN indicated he'd received information that
peak capacity without Agrium was 480 million cubic feet a day.
Alluding to a presentation by Econ One, he said in the event of
an unsuccessful open season, TransCanada expects the state to use
its sovereign status to encourage, induce, and persuade Alaska
North Slope (ANS) producers to commit gas. He asked how the
state would likely do that, in light of the Denali project.
COMMISSIONER GALVIN requested that he wait until tomorrow, when
an entire day was scheduled to address that.
10:48:10 AM
CHAIR HUGGINS said AGIA reduces flexibility by limiting the
volumes, but volume doesn't matter if it isn't economically
feasible. Noting new projects will create demand, he said this
body passed a resolution on in-state gas, a subject many of his
constituents feel strongly about. He stressed the need to
separate false choices from good ones to retain the flexibility
to feasibly get in-state gas to Alaskans, wherever they live.
COMMISSIONER GALVIN replied he agrees 100 percent with the need
to focus on ensuring all options are kept available to satisfy
in-state needs. While the assurances in the AGIA license do
limit the state's flexibility, this doesn't preclude a solution
to Alaska's in-state energy needs, given the demand expected
within Alaska, current supplies in Cook Inlet, and the timeframe
before getting to the main line.
10:51:18 AM
REPRESENTATIVE JOHNSON asked: Does it trigger the treble damages
if we decide it's best to build a bullet line and it doesn't
reach the expected threshold, but is capable of delivering more
than 0.5 Bcf/day through compression or looping?
COMMISSIONER GALVIN replied no. It would happen if there were an
open season seeking more than the 0.5 Bcf/day. Any line could be
expanded, so that capability wouldn't be the threshold.
10:52:26 AM
REPRESENTATIVE WILSON asked: If prices continue to climb, might
there be a point where the price is as high as or higher than
what is paid now, even if there is a line for Alaska?
COMMISSIONER GALVIN answered yes. Clearly, it could rise beyond
what people pay now, even if the state subsidized every
transportation aspect. That's why, when looking at a long-term
choice, policymakers must consider the options. These include
whether to lock the state into a nonrenewable resource such as
natural gas for the long-term supply or go with a renewable
source or something like hydroelectric power as an alternative.
COMMISSIONER GALVIN cautioned against seeing natural gas as a
panacea because at this moment the price is lower than other
choices. He emphasized that this decision needs to be made
conscientiously. Particularly in Southcentral Alaska, folks are
looking at the next generation of energy supply, and the state
will be locked into that for 30 years or more. This is a
critical juncture, with a great opportunity to decide.
10:54:40 AM
COMMISSIONER IRWIN recalled hearing someone in Nome say he wants
the big line, but wants it treated as a drug dealer would treat
his drugs - as a seller, not a user. That person had asked for
renewable, clean energy for the future of the state.
Commissioner Irwin suggested that parallels this discussion.
REPRESENTATIVE WILSON told members she believes the state should
look at renewable energy because people will need to be wise
about how they spend their money to convert their furnaces and so
on. She suggested communities especially need to look at that.
REPRESENTATIVE ROSES said he agrees with the math. If a line
impacts the volume in the big line, financially it's better to
generate revenue and then subsidize the other line by having the
state pay transportation costs. He expressed concern, though,
that a precedent has been set by discussing a $1.2 billion
subsidy to citizens to offset high energy costs. He suggested
the calculation should anticipate that folks will want that
subsidy until the line exists; thus the savings account for
paying that down may dwindle.
10:56:56 AM
CHAIR HUGGINS asked Mr. Palmer to elaborate on TransCanada's
involvement in a change in AGIA during the course of the debate
on that legislation, from 50 percent reimbursement up to the
current 90 percent.
MR. PALMER replied last year, as AGIA was being established, he'd
testified six times before the Senate and House regarding
TransCanada's position on proceeding beyond an open season. He
recalled being asked whether there was some incentive the state
could provide to potential applicants under AGIA if it required
that parties continue beyond a failed open season; he'd answered
that the state could increase its contribution. That's the
extent of TransCanada's involvement in that process, he said.
MR. PALMER noted the state came back with a proposal which did
that and maintained the requirement that a successful applicant
must continue beyond a failed open season and go through Federal
Energy Regulatory Commission (FERC) certification. It also
increased the state's percentage of contribution post-open
season, but it maintained the $500 million cap.
MR. PALMER, as to whether TransCanada had considered that in
evaluating whether to apply under AGIA, said definitely yes. He
surmised it was a consideration for other parties as well, who
likely also examined whether the $500 million is sufficient.
10:59:53 AM
CHAIR HUGGINS recalled those discussions in committee.
Indicating the amendment was proposed by the administration, he
surmised there were communications in that respect and noted
Commissioner Galvin was to give a follow-up answer.
COMMISSIONER GALVIN replied he hadn't had time to go back through
the legislative record last night, but his recollection was
similar to Mr. Palmer's, that there was ample testimony during
the initial hearings from potential applicants who expressed
concern about the risk/reward trade-off. This was one of many
amendments generated by the administration during the process.
As to whether the matching-contribution distribution was
responsive to TransCanada's request, he said it was.
CHAIR HUGGINS asked whether it was based on negotiations or
discussions with TransCanada.
COMMISSIONER GALVIN specified that it was based on the input from
TransCanada that came through the committee process.
CHAIR HUGGINS asked whether that included raising the
reimbursement to 90 percent.
COMMISSIONER GALVIN replied yes. What he didn't recall, though,
was what the other potential applicants said during their
testimony and if they specifically discussed the post-open season
matching contribution. He indicated the administration was
addressing a number of concerns raised by potential applicants at
the time; this was one. As Mr. Palmer said, TransCanada was on
record as saying it needed a change there.
SENATOR STEDMAN clarified for the public that while the
administration may work up recommended amendments, those need to
have a committee member's sponsorship. Committee members make
the amendments.
11:03:11 AM
^Continuation of TransCanada presentation with questions
MR. PALMER returned to the PowerPoint presentation he'd begun
yesterday, "TransCanada's AGIA Application Presentation to the
Legislature"; a handout duplicated the slides. He began with
slide 26, "Canada - Advantages of the NPA - Timing," which had
the following points relating to the Alaska Pipeline Project
(APP) and Canada's Northern Pipeline Act (NPA):
Certificate of public convenience and necessity has
been issued by statute (section 21 of the NPA)
- Public interest determination has been made
- Process for meeting current environmental
standards and approving design plans will include
input by appropriate stakeholders and First
Nations but will not revisit the go/no go decision
Single window, expeditious regime
- Cabinet is authorized to transfer the powers
of any department or agency of the Gov't of
Canada to the Minister responsible for the NP
Agency
- Minister is entitled to second employees from
any dept or agency (including the NEB) to the
NP Agency
MR. PALMER noted he'd testified a number of times on Canadian
regulatory issues. TransCanada has held the certificate of
public convenience and necessity for this project in Canada for
some 30 years. He emphasized that while environmental issues
will be reviewed, there will be no revisiting of the go/no go
decision.
MR. PALMER told members the single-window, expeditious regime is
very different from what has occurred on the Mackenzie project.
While the Northern Pipeline (NP) Agency has been modestly
staffed, appropriately so, it has authority to second employees,
as it has in the past for the pre-build and every expansion of
Foothills Pipe Lines, obtaining staff from across the government
of Canada, including the NEB, to review the project.
MR. PALMER, in response to a query, explained that to second is
to transfer employees on a temporary basis from their regular
department under the aegis or authority of the NP Agency.
11:04:30 AM
MR. PALMER addressed slide 27, "Canada - Advantages of the NPA -
History of Implementation," which said:
The NPA has a history of implementation that will
provide the precedents required to move forward on the
APP.
The NPA was used as the regulatory vehicle for the
following:
- Construction of the Pre-Build (approximately 25%
of the Canadian portion of the APP)
- Construction of 5 Expansions of the Pre-Build
- Other - acquisition of Duke's Interest in
Foothills (as recently as 2003-2004)
MR. PALMER emphasized that the NPA has been used many times,
including for pre-build facilities put in place in 1981-1982 and
further construction through 1998, as well as acquisition of
Duke's interest in Foothills five years ago.
MR. PALMER discussed slides 28-29, "Canada - Advantages of the
NPA - Flexibility," which had the following points:
NPA is not prescriptive as to volume or design
- Sec. 3 (Treaty): "The initial capacity of the
Pipeline will be sufficient to meet, when
required, the contractual requirements of the
United States shippers and of Canadian shippers."
- Sec. 1 (Treaty) indicates that the line size may
be 48-54 inches in diameter "or any other
combination of pressure and diameter which would
achieve safety, reliability and economic
efficiency ... the decision relating to pipeline
specifications remains the responsibility of the
appropriate regulatory authorities."
- NPA is not prescriptive as to timing
- No sunset date in legislation
NPA is uniquely designed to meet current standards by
requiring:
- Approval by the Designated Officer of plans
submitted by Foothills to implement the approved
project
- Foothills to comply with all undertakings it
provided during the NEB hearing and to provide to
DO, for approval:
- Final detailed design and detailed construction
procedures and specifications
- A schedule for project control, including
schedules for regulatory reviews and approvals
- Results of further studies (environmental,
social and economic matters) as may be ordered
or directed by the DO
- Business and opportunity plans, environmental
plans and procedures, plans for meeting Terms &
Conditions
MR. PALMER noted he'd heard parties ask whether the project has
changed somehow because the capacity is different now. He
emphasized that the treaty language isn't specific to a
particular capacity. On the first point, Section 3 (Treaty), he
said Canadian shippers at the time contemplated moving Mackenzie
Valley gas down this pipeline; this is a separate project. The
language is permissive as to volumes, not restrictive.
MR. PALMER explained that an NEB certificate generally has a two-
year sunset date. There was no such provision on this
certificate because the parties didn't know the construction date
at the time. Also, there is a particular named individual called
the designated officer (DO), usually a member of the NEB who,
under the NPA, is given specific duties and responsibilities;
those would be provided for members' review.
11:08:01 AM
MR. PALMER addressed slide 30, "Canada - Advantages of the NPA -
Land Rights," which had the following points:
Foothill holds a right-of-way (ROW) in the Yukon
- Provides access through Yukon along the route of
the APP
- Acknowledged in the Umbrella Final Agreement by
Yukon First Nations, Canada and Yukon
- Final agreements have been entered into by the
Kluane, Champagne Aishihik and T'an Kwach'an
First Nations, Kwanlin Dun, Carcross/Tagish and
the Teslin [Tlingit] Council
- ROW has since been approved by Cabinet pursuant to
Sec. 37 of the NPA and remains in full force and
effect
MR. PALMER said TransCanada has held the right-of-way (ROW)
through the entire Yukon Territory for this project since 1983.
Ten years after it was granted, an umbrella agreement recognizing
the ROW was reached among all Yukon First Nations, represented by
the Council for Yukon Indians at the time; the Canadian
government; and the Yukon Territory government.
MR. PALMER, noting six of the eight subsequent final land claims
established in the Yukon Territory specifically recognized that
ROW, gave his understanding that the same would happen with the
other two when their land claims are resolved. That ROW remains
in full force and effect.
11:08:59 AM
MR. PALMER discussed slide 31, "Canada - Other Land - BC and
Alberta," which had the following points:
- In BC, Foothills holds Map Reserves under the Land
Act and Mining Reserves under the Mining (Placer)
Act for all lands required for pipeline purposes
- In Alberta, Foothills holds a Consultative Notation
with respect to Provincial Crown Lands
- The effect of the above is to give notice of
intended use of land to all others and provides
Foothills with the opportunity to review and comment
upon any conflicting proposed development
- The normal process for acquiring Crown land rights
will occur as the project progresses; including a
License of Occupation (Land Act) in BC and a
Pipeline Agreement (Public Lands Act) in Alberta
- Negotiations with landowners for privately held
lands
MR. PALMER explained that whereas the Yukon Territory is
relatively virgin territory for gas pipelines, British Columbia
(BC) and Alberta have had pipelines some 50 years. TransCanada
has 15,000 miles of pipe in Alberta and knows how to get these
things done there, he assured members, noting competitors have
thousands of miles of pipe in BC. There is an established
process with an established group of officials as well as
legislation to do this.
11:09:50 AM
CHAIR HUGGINS clarified that the Foothills Mr. Palmer had
referenced is unrelated to Alaska's foothills geography.
SENATOR FRENCH asked why TransCanada has a right-of-way through
the Yukon Territory but not BC, going all the way to Alberta,
since it seems that would have been part of the process over the
last many years. He also asked what resistance might exist to
getting that through BC.
MR. PALMER replied the rationale some 25 years ago was that it
was potentially difficult to get a ROW through the Yukon, so it
was sought earlier than normal. Alberta and BC were expected to
have a straightforward process, which usually is done after the
open season; that is how TransCanada has contemplated it.
MR. PALMER added that it isn't unusual for certain parties to try
to extract value from a pipeline company or other infrastructure
developer, to prosecute either political or legal angles in that
attempt. This happens all the time on infrastructure projects,
and TransCanada faces it daily. However, that process - both
legislative and regulatory - is well handled in Alberta and BC,
and TransCanada deals with 100 First Nations on its existing
system across Canada every day.
11:12:04 AM
REPRESENTATIVE SAMUELS alluded to issues in Canada. Mentioning
the NPA process versus the NEB process, he asked whether
TransCanada would go to court to stand up for its rights.
MR. PALMER answered that he believes both the State of Alaska and
the government of Canada have a letter on record from
TransCanada's chief executive officer to that effect.
REPRESENTATIVE SAMUELS mentioned the money at stake in the
project and asked: Do you see a problem with respect to timing
if the Canadian court system determines this issue, if Enbridge
goes through with an NEB process or TransCanada goes through with
an NPA process?
MR. PALMER replied that Enbridge, along with any other party, had
every opportunity to participate in the AGIA process but hadn't
done so; nor did Enbridge submit a final bid under the Stranded
Gas Development Act (SGDA) process and complete that by agreeing
to reimbursement with the former administration. He added that
if TransCanada is granted this AGIA license and is proceeding, it
is in effect not addressing the exclusivity issue. TransCanada
would be prosecuting the project under NPA, and he wasn't aware
of Enbridge having a competing project.
COMMISSIONER GALVIN reported that the state did hire an analysis
of that issue, comparing the two and also looking at Canadian
permitting issues in general. Indicating that's in the finding
and appendix, he specified that Bennett Jones was the Canadian
counsel hired to do an analysis of all legal issues associated
with the Canadian permitting; their conclusions on timing and
potential impacts to the schedule are incorporated into the
administration's analysis of the project economics. Someone from
Bennett Jones would be available Monday and Tuesday.
11:15:37 AM
CHAIR HUGGINS asked about the First Nations structure, including
whether this entails privately held land and whether the parties
are tribes or corporations such as exist in Alaska.
MR. PALMER explained that TransCanada will be negotiating with
individual First Nations groups, which generally don't have
Native corporations. Eight First Nations in the Yukon Territory
are along the ROW; TransCanada holds the ROW through the entire
Yukon and already has access to the lands, but must negotiate
benefits with those parties.
MR. PALMER said specific benefits laid out in the terms and
conditions to NPA some 30 years ago along the ROW are the law of
Canada. TransCanada will meet those and has done preliminary
negotiations with a number of First Nations about improving on
the law of the land in this regard. It's a very different
circumstance than exists for the Mackenzie Valley project.
REPRESENTATIVE DAHLSTROM asked: If TransCanada couldn't
successfully negotiate with one of the First Nations, would that
group be able to sue and stop the project? And in that case, who
would be liable for the costs incurred?
MR. PALMER responded that TransCanada cannot prevent a party from
going to court on any issue. However, TransCanada has terms and
conditions established in the Act after significant hearings on
this some 30 years ago and is offering to enhance those. If
negotiations are unsuccessful and parties don't want benefits
superior to what was offered 30 years ago, TransCanada would rely
on the rights and obligations under the law. That doesn't
preclude parties from taking a political angle, as described
earlier to Senator French, or going to court.
MR. PALMER said if a party chose to do that, it could delay the
process, although there are some limitations on that. It could
also increase the cost of the project, since delay costs money.
TransCanada would bear some of that risk, as described in its
capital cost risk assessment, and the shippers would bear some.
He surmised in that case, a number of parties would be highly
motivated to resolve this issue, but he reiterated that some who
see a major infrastructure development might seek to extract
value in whatever fashion they could.
11:19:51 AM
REPRESENTATIVE DAHLSTROM asked: Could the State of Alaska
potentially incur some cost also, an unknown amount?
MR. PALMER answered that the state wouldn't have a direct
payment. But since the state is a royalty and tax collector, its
net value could go down if the cost of the pipeline goes up.
While acknowledging that there could be some impact, he offered
assurance that TransCanada has the law on its side, 30 years of
dealing with parties on this project, and 50 years' experience
dealing with 100 First Nations.
CHAIR HUGGINS asked about the Mackenzie project delays.
MR. PALMER replied he isn't an expert on that, although he has
observed it from afar. A number of issues have delayed that
project in the regulatory arena, including the regulatory process
established as a result of land-claims resolutions in the
Northwest Territories; the process under the NEB Act, which
doesn't have an expedited or single-window regime; and
negotiations with First Nations on both benefits and access.
CHAIR HUGGINS asked how long that delay is.
MR. PALMER recalled there was a commercial agreement among the
owners and shippers in 2003 or early 2004, and the hope is for an
NEB decision by 2009. Subsequent to that, additional land and
water use approvals must be obtained. After that, the project
will proceed.
SENATOR FRENCH observed that Mr. Palmer had emphasized access in
distinguishing the Alaska project from the Mackenzie project
delays. He asked about that distinction.
11:23:25 AM
MR. PALMER answered that there are two distinguishing factors:
1) access and 2) that there is law on terms and conditions that
establishes base benefits. As for access, TransCanada holds the
right-of-way through the Yukon Territory. By contrast, the
Mackenzie Valley project will be obtaining a ROW after getting
regulatory approval.
MR. PALMER paraphrased slide 32, "Canada - Environment," noting
he'd spoken about some of these already. Slide 32 said:
Fundamental Decisions
In passing the NPA, Parliament clearly:
- Decided that the APP is in the public interest
- Determined there is a need for the APP
- Recognized a general route for the APP
- Recognized that environmental and social impacts,
while expected, would be acceptable with mitigation
- Created NP Agency to be the exclusive regulatory
agency to determine environmental and socio-economic
issues related to the completion of the APP, i.e.
what was appropriate and what required mitigation
11:24:19 AM
MR. PALMER turned to slide 33, "AGIA 'Must-haves' Promote Basin
Development," which said:
- Rolled-in tolls up to 115% of initial rates in
Alaska
- Open Season every 2 years
- In-State deliveries
- Distance-sensitive tolls
- Minimum 5 delivery points
- Low equity ratio requirement for pipeline sponsors
- State fiscal incentives (if any) targeted to AGIA
pipeline shippers
MR. PALMER added he believes these are important for long-term
basin development. Highlighting recent significant discussion of
rolled-in tolls, he indicated other slides would address this.
With respect to the open season every two years, he mentioned
expansions with engineering increments.
MR. PALMER said in-state deliveries off this pipeline couldn't
occur until 2018. The schedule provided yesterday indicates that
if TransCanada is granted a license in August - assuming all
necessary approvals and customer requirements are in place -
project completion will be in September 2018. If the legislature
approves it more quickly and TransCanada knows that in advance,
it could significantly improve the schedule by providing
additional time in the summer.
11:26:16 AM
REPRESENTATIVE FAIRCLOUGH asked how inflation will affect the
tariff and rolled-in rates, the 115 percent, and access and
equity in the pipeline.
MR. PALMER gave his understanding that no inflation factor is
added in to the 115 percent. If TransCanada's numbers were
perfectly correct, and including fuel the pipeline were completed
for $2.76, that number in nominal dollars would be in effect;
15 percent would be added to the Alaskan section of the pipe, not
the Canadian section, which is governed by NEB rules.
MR. PALMER, saying inflation could "take that issue away," added
that generally pipelines don't have straight-line depreciation.
Often a relatively balanced approach over time is seen with
expansions and depreciation of the pipe. But there certainly are
occasions when inflation causes costs to go up.
REPRESENTATIVE FAIRCLOUGH mentioned the Trans-Alaska Pipeline
System (TAPS) for oil and her understanding that no additional
producers can transport their commodity to market on TAPS. With
respect to the Alaskan portion of this gas line, she asked: What
happens in the three big producers buy up all the capacity during
the open season?
11:28:45 AM
MR. PALMER noted he isn't an expert on TAPS, but replied that for
this gas project, if the three large North Slope producers today
decide to take 4.5 Bcf/day capacity, that's good and the pipeline
will be put into service. If other parties also want capacity in
the initial open season, say, an additional 0.5 or 1.0 Bcf/day to
serve in-state or out-of-state markets, TransCanada will design
the pipeline for 5.0 or 5.5 Bcf/day. That's one circumstance.
MR. PALMER said if, however, only those three big producers bid
in the open season for 4.5 Bcf/day and TransCanada wants to
expand, he has shown some economics both in TransCanada's
application and in responses to the Legislative Budget & Audit
Committee (LB&A or BUD). Other slides show results for a
particular case LB&A requested, and he has shown circumstances
where expansions went through 7.2 Bcf/day early in the game.
MR. PALMER concluded by saying there is significant flexibility,
but he cannot predict inflation. Looking at today's
circumstances, however, he doesn't see that inflation in the
short term, after "in service," will deny access based on that
provision. That provision doesn't deal with just 115 percent in
Alaska in the short run. If costs exceed 115 percent, there is a
significant benefit because 115 percent will be rolled in and
only the number above that will be incremental.
REPRESENTATIVE FAIRCLOUGH expressed concern that if the three big
producers own more than 51 percent of the line, there could be
access issues for other producers to open the basin.
MR. PALMER replied that TransCanada believes if it brought in
other parties under the AGIA license as shareholders, they would
be obliged to take on the same obligations that TransCanada will
have under that license. He indicated he'd heard from a number
of parties over the past few days about their expectations of
TransCanada as a good partner with regard to this issue.
11:31:22 AM
SENATOR GREEN asked: Is it common in contracts to have a
mandatory open season schedule prior to construction of a
pipeline? She requested examples of pipeline projects for which
there has been a mandatory open season directed in advance.
MR. PALMER answered it's common to have open seasons for a
pipeline before proceeding with certification. That's the normal
process. And if it hadn't been mandated, TransCanada or any
other commercial party would pursue it in that fashion. What is
different here, to his belief, is the mandate to go to the market
every two years for an expansion. However, this isn't an issue
for TransCanada, which seeks expansions on an economic basis
continually, as a normal course of business, on all its
pipelines. It has done so for 50 years.
MR. PALMER explained that, as a pipeline company, TransCanada is
highly incentivized to go to the market continually to ensure
it's serving future customers as well as current ones.
Expressing hope that he'd showed how it has assisted
TransCanada's business in the long run, he added that it was an
easy "must have" for TransCanada to agree to.
11:33:46 AM
SENATOR THERRIAULT alluded to the AGIA amendment discussed
earlier that raised the percentage to 90 percent. Reinforcing
Senator Stedman's comments that the legislature is in charge of
the amendment process, Senator Therriault reported that he'd just
called his own staff and found on the Senate side that language
was included in the committee substitute (CS) from the Senate
Finance Committee. Indicating the rolled-in rate and 115 percent
came from FERC for the U.S. portion of the line, he asked whether
NEB generally uses a rolled-in-rate methodology.
MR. PALMER affirmed it's the norm in Canada and has been for
decades. Rolled-in tolls occur whether costs go up or down, he
said, and there isn't a limit such as the 115 percent. That has
worked well to expand Western Canadian systems for 50 years, and
it remains the norm. He expects it to apply to this project.
11:35:10 AM
MR. PALMER followed up on a question from Representative Kelly to
another witness a couple of days ago. He recalled that it
involved potential delivery to Fairbanks of an additional 50
million to 100 million cubic feet of gas a day from the pipeline.
MR. PALMER reported that he'd spoken carefully with TransCanada's
engineering group, who'd indicated if the pipeline is constructed
for 4.5 Bcf/day to Alberta as the initial nominated volume, then
the way TransCanada can operate the pipeline would allow some
spare capacity as far south as Fairbanks, up to 100 million a
day. That's in addition to what would go to Alberta if Fairbanks
grew over time.
MR. PALMER continued with slide 33, noting he'd talked before
about the low equity ratio that has lowered the tolls. If the
state decided to change its fiscal incentives, those would be
targeted to this pipeline.
11:36:33 AM
MR. PALMER read from slide 34, "Long-run Basin Development -
Pipeline Expansions," which posed these questions:
- Value to Producers / Governments?
- Does Alaska have enough gas?
- Drilling impacts?
- Impact of rolled-in tolls?
He said the second question relates to gas beyond Alaska's proven
reserves.
MR. PALMER discussed slide 35, "Value of Potential Expansions
($Billions)." Assuming an annual average netback of $6.89/MMBtu,
it listed: the base project at 25 years (4.5 Bcf/day), with
combined producer/government revenue of $350 billion; expansion
Case I, base volumes for 10 years and 30 percent expansion for
25 years (5.9 Bcf/day), with combined revenue of $600 billion and
expansion value of $250 billion; and expansion Case II, base
volumes for 10 years and 60 percent expansion for 25 years
(7.2 Bcf/day), with combined revenue of $700 billion and
expansion value of $350 billion.
MR. PALMER specified that these are based on economics in
TransCanada's application, not the administration's assessment
shown in Anchorage last week. Noting the company had to make
assumptions in its application about producers' production costs
and what production taxes would be, he said TransCanada doesn't
profess to be expert in either area and thus he'd pooled those to
try to avoid that issue.
MR. PALMER indicated this takes the netback after the gas is sold
in Alberta, using U.S. Energy Information Administration (EIA)
forecasts that TransCanada was provided for 2006; that gas price
was just under $10 per Mcf in nominal terms, on average, over
25 years. Since prices in Alberta are now at $10, that assumes
no increase for the next 34 years. The $350 billion is the value
to be shared among the producers and governments. Of course, the
producers would have to pay production costs, take their profits,
and pay taxes to the governments.
MR. PALMER explained that for expansion Case I, TransCanada's
look at this basin says this is relatively conservative, with no
expansions in the first 10 years of service. For a base volume
of 4.5 Bcf/day for 10 years and then 30 percent expansion for an
additional 25 years, as he recalled, proven reserves would have
to increase from 45 Bcf to some 78 Bcf. This gives $250 billion
in value to the producers and governments.
MR. PALMER said expansion Case II, with 60 percent expansion at
year 10 up to 7.2 Bcf/day, doubles the value of the base project.
These are direct revenues only, not benefits Alaska would see
through all the indirect drilling and development to achieve this
or multiplier effects.
11:40:19 AM
MR. PALMER turned to slide 36, "Basin Development - Western
Canada Example," which had two graphs and the following points:
Pipeline expansion can create "virtuous circle"
- More exploration and drilling
- If successful, leads to more pipeline expansion
Exploration and drilling drives service industry and
employment over long term
MR. PALMER noted this relates to his opening statements. The
left graph shows completed Western Canadian Sedimentary Basin
(WCSB) gas wells since 1955. In 1955, folks knew TransCanada's
pipeline was in the works and were drilling and completing 180
wells a year; there were 200 by the time it went into service in
1958. That has grown massively over time. He emphasized that it
is the expansions and induced drilling that provide the
employment, not operation of the existing pipeline.
MR. PALMER explained that the right-hand graph shows what has
happened with Western Canadian potential and proven reserves as
well as cumulative production. In 1955, it was expected that
there'd be 75 trillion cubic feet (Tcf); now it's above 250 Tcf.
Some 150 Tcf has been produced over the last 50 years. Proven
reserves 10 years after the pipeline went into service had almost
quadrupled, from 15 Tcf in 1955 up to 55 Tcf in 1968. At that
point, they leveled off.
MR. PALMER explained that proven reserves level off because
producers and other parties don't tend to prove up reserves to
store them in case of a strong market. Keeping enough for 8-10
years is the norm in Canada and the Lower 48. So as there has
been an increase in production, proven reserves have been
relatively steady.
11:43:09 AM
REPRESENTATIVE SAMUELS returned to the expansion cases on
slide 35, asking about the amount of gas at Prudhoe Bay.
COMMISSIONER GALVIN indicated he'd been using 24 Tcf and said
there'd be rock experts later.
REPRESENTATIVE SAMUELS surmised that if there were 24 Tcf at
Prudhoe Bay and no more exploration, nobody could win if at least
45 Tcf total would be needed over time.
MR. PALMER clarified that TransCanada's analysis looked at the
economics from the Prudhoe Bay owners' perspective if they
accepted capacity and didn't find additional gas and thus ended
up with spare capacity for that 25 years. The conclusion was
still that it would be a positive investment for them.
MR. PALMER said it can be looked at in terms of whether the
desire is to keep the line filled throughout that and maximize
that. If so, new gas must be found. But as to whether they have
to find the gas to make money, TransCanada has found that isn't
the case.
REPRESENTATIVE SAMUELS asked whether, from TransCanada's
perspective, the line could be built and operated and would pay
with 24 Tcf total.
MR. PALMER answered that this analysis assumes 4.5 Bcf/day into
the pipeline and 5.0 into the gas treatment plant (GTP), which is
how the 45 Tcf is arrived at that he'd described. If there is
less than 4.5 Bcf/day contracted over 25 years, TransCanada
believes it needs 3.5 Bcf/day to make the pipeline through Canada
work, as described previously. TransCanada believes the
economics still work.
MR. PALMER added he hadn't looked at the specific case that the
administration looked at, taking a contract and being responsible
for the tolls over this timeframe with a lower volume. While
he'd sat through some of the administration's presentations and
didn't disagree fundamentally, he hadn't done his own analysis.
COMMISSIONER IRWIN commented that there is another 9 Tcf at Point
Thomson, so there is plenty.
REPRESENTATIVE SAMUELS said his question didn't revolve around
Point Thomson. It was philosophical, the fear being that
expansions won't happen if the ConocoPhillips-BP Denali project
beats this project to FERC, cuts a tax deal, and so on. He
asked: Does it behoove the Prudhoe Bay owners to just monetize
their own gas, or does it enhance their project to go to 45 Tcf
over time? And would TransCanada take the risk to monetize
24 Tcf if there were no other gas besides Prudhoe Bay gas?
11:47:30 AM
MR. PALMER replied that TransCanada hadn't done that analysis,
but believes there is sufficient gas in this basin to go beyond
the volumes shown. Referring to a graph, he said the top line
indicates 45 Tcf over the course of 25 years; the second, 78 Tcf
over 35 years; and the third, 90 Tcf over 35 years.
MR. PALMER, noting he isn't a geologist, cited TransCanada's
experience in other basins, not just in Canada. He opined that
if TransCanada puts an expandable pipeline in place and can
succeed with it, proven reserves will grow in order to serve this
market. It assumes this gas will be economic in the market, that
there'll be a decent gas price and so on. But he hasn't looked
at this basin contemplating only 24 Tcf.
MR. PALMER contrasted that with Mackenzie Valley, where the
pipeline initially will have one-quarter this capacity and proven
reserves are 6 Tcf, significantly less on a ratio basis, with
less potential as well. Returning to Alaska, he said TransCanada
believes, if it is granted a license and is successful, that this
will be a highly prolific basin that can draw expansions to the
project over time. So, no, he hadn't looked at in terms of only
moving 24 Tcf forever.
11:49:20 AM
REPRESENTATIVE SAMUELS thanked Mr. Palmer and announced he would
draft a letter. He said the point of the question was when the
economics would flip so it wasn't desirable from the standpoint
of an original shipper with 24 Tcf of gas. Acknowledging there
are many factors, he opined that intuitively someone would want
to get to 45 Tcf in order to mitigate the risk that tariffs would
go through the ceiling, and thus would want to explore for gas.
MR. PALMER noted he hadn't understood the first question that way
and would try to respond. He surmised that customers who execute
contracts obliging them to pay for 4.5 Bcf/day for 25 years, if
that's what is decided, will seek to mitigate risk by producing
45 [Tcf] over the course of that 25 years; that should give them
the highest possible value. He added he wouldn't speak for those
parties, who clearly are well qualified to speak for themselves.
COMMISSIONER GALVIN suggested that before drafting his letter,
Representative Samuels should look at the report done by Black &
Veatch in the modeling. He said when looking at the reserve
risk, the administration was surprised by the amount of actual
risk in making those commitments. One question was whether the
project will only be economic if new discoveries are made. He
said the answer, surprisingly, was that it still will be economic
even if those future discoveries aren't made and they end up with
an oversized line.
COMMISSIONER GALVIN interpreted Representative Samuels' question
to have changed at the end, initially asking whether a producer-
owned pipeline would have similar motivations to have exploration
taking place on the North Slope.
REPRESENTATIVE SAMUELS explained that he believes the fear is a
bit unfounded until it gets to where the tariff starts to go back
up. After that point, he agrees with the general perspective of
AGIA that the state's interests need to be protected. Until it
gets to the 45, though, the risk allocation among shippers -
including the state as a shipper - will always mean having a
little more gas in there to ensure that the tariffs don't go
through the roof on the remaining gas as it dwindles.
COMMISSIONER GALVIN suggested the question is whether to have a
pipeline that encourages the three big producers to explore or
that encourages an entire market of new entrants to explore and
take on the associated risk. He said he believes, from the
administration's perspective, the answer is clear: The
administration wants one that encourages a whole suite of new
explorers to come up to Alaska.
REPRESENTATIVE SAMUELS conveyed his thanks, saying he looked
forward to the Black & Veatch presentation again.
11:53:27 AM
MR. PALMER prefaced slide 37 by turning to the protections FERC
provides under the legislation put in place for this project
almost four years ago, as well as FERC regulations. He said he
would read specific citations and comment on how that could
affect whether rolled-in tolls would occur on a pipeline that
isn't proceeding under AGIA.
MR. PALMER reminded members that the Alaska Natural Gas Pipeline
Act (ANGPA) was passed in October 2004. The FERC regulations
governing conduct of open seasons for Alaska gas transportation
projects were issued in February 2005; he and other parties gave
presentations in Anchorage when a hearing was held in December
2004 on those, and TransCanada argued vigorously for a rebuttable
presumption of rolled-in tolls, as did other parties including
the State of Alaska.
MR. PALMER explained that those FERC regulations govern voluntary
expansions - he emphasized voluntary - by the pipeline company.
There is a rebuttable presumption of rolled-in tolls for
voluntary expansions proposed by a pipeline company. This
presumption applies except where an expansion is mandated
pursuant to Section 105 of ANGPA, which authorizes FERC to order
an expansion of an Alaska pipe under certain criteria. That is
unusual in the U.S., although NEB has held that power in Canada
for decades. He said it is some protection under ANGPA.
MR. PALMER again paraphrased Section 105. He said if FERC orders
an expansion, it can establish rates on an incremental or rolled-
in basis, but it must ensure that the rates don't require
existing shippers to subsidize expansion shippers. He pointed
out that "subsidize" isn't defined in this context.
MR. PALMER also said obtaining a FERC order to expand the
pipeline would be time-consuming and costly, as opposed to having
a pipeline company voluntarily agree under AGIA to go forward and
apply for an expansion. Shippers would be in a very different
circumstance if they must request that FERC mandate an expansion
when they haven't found gas yet and are considering whether to
explore. Also, they no longer would have the absolute protection
of a rebuttable presumption of rolled-in tolls.
MR. PALMER noted that AGIA requires a pipeline sponsor to file
for rolled-in tolls up to 115 percent of the initial tolls; it
has been well explained that this doesn't guarantee how FERC will
rule. Saying the positions that initial shippers and expansion
shippers will take are known, he surmised the position of the
pipeline company may well be the tipping point as to whether
there will be rolled-in tolls.
MR. PALMER further noted that AGIA requires the pipeline company
to test the market every two years and commit to expand
voluntarily. As discussed, for TransCanada this isn't a burden
because the company does this in its normal course of business.
Of course, TransCanada in its AGIA application made those
commitments, as required by AGIA.
11:58:33 AM
SENATOR WIELECHOWSKI asked: If TransCanada makes 14 percent
regardless of how much is in the line, what is the incentive to
expand the line? Does the company make more money when it goes
from 4.5 to 7.2 Bcf/day?
MR. PALMER answered it isn't volume-specific. However, the
company then has an opportunity to continue to invest its money
at a profitable rate in its base business. In effect, it's
highly attractive to have brownfield expansions on an existing
facility. This also allows diversifying the supply and markets
over time, which TransCanada believes is good for its business
and is inherently aligned with what any government would wish.
SENATOR WIELECHOWSKI surmised that with a producer-owned line,
there would be more incentive to expand because it would put more
of the producer's product in the line.
MR. PALMER, noting he wanted to be very careful in responding as
to what TransCanada's potential shippers may wish to do, replied
that his experience over a long time has been that existing
customers are always keen to expand for their own volumes and not
necessarily for other producers' volumes.
CHAIR HUGGINS reminded members that FERC will be in Anchorage to
respond to questions during this session.
The meeting was recessed from 12:01:08 PM until 1:33:49 PM.
MR. PALMER discussed slide 37, the first of two labeled "Impact
of Rolled-in Tolls?" It had a bar graph with the heading
"Incremental Costs." A note said it was for Alaska and Yukon-BC
sections only, and it listed these assumed volumes:
4.5 Bcf/day years 1 & 2
5.9 Bcf/day years 3 & 4
6.5 Bcf/day years 5 & 6
7.2 Bcf/day years 7 & beyond
MR. PALMER explained that this specific example was requested of
TransCanada by LB&A, which had provided a scenario for an
expansion case commencing at 4.5 Bcf/day for the first two years
and so on, as shown. TransCanada ran that case, and the graph
shows incremental costs if the project were tolled incrementally.
It was run for the pipeline only, not the GTP, which is why the
numbers are lower than seen before.
MR. PALMER noted for the pipeline only, the cost for 4.5 Bcf/day
would be about $1.76. Going up to 5.9 Bcf/day with compression,
incremental costs would actually be lower than that, as described
previously. Once it moves up to 6.5 and 7.2 Bcf/day on an
incremental basis, however, it increases dramatically. At
7.2 Bcf/day, that number is about $4.28 on an incremental basis.
1:36:08 PM
MR. PALMER discussed slide 38, which had one graph on the left
labeled "Rolled-in Tolls (Initial and Expansion Customers)" and
another labeled "FERC Lower 48 'Standard'" that showed separate
bars for initial and expansion customers. The slide also said:
Rolled-in tolls increase chance of expansions above
5.9 Bcf/d
- 35% lower tolls for expansion customers to 6.5 Bcf/d
- 50% lower to 7.2 Bcf/d
MR. PALMER explained that this shows the impact under AGIA and
the "115 percent test" on rolled-in tolls. He noted that the
horizontal line labeled "AGIA Standard (115% of initial)" on the
left-hand graph was just above $2.00.
MR. PALMER pointed out that if incremental costs are rolled in,
this graph shows a decline from 4.5 to 5.9 Bcf/day, a modest
decrease just under 10 cents. Going up to 6.5 Bcf/day, it
coincidentally increases by approximately 10 cents. And moving
up to 7.2 Bcf/day, the toll increases to about $2.00. While
still under the 115 percent test in AGIA, the price on a rolled-
in-toll basis would have increased for the base customers.
MR. PALMER noted that the graph on the right shows what would
happen if FERC's Lower 48 standard were applied to this project.
That standard is to roll in the tolls, averaging them, when tolls
go down. When moving from 4.5 to 5.9 Bcf/day, the tolls decline,
as also seen in the left-hand chart. But whenever the tolls go
up, base customers stay at that lower toll. So if this were a
Lower 48 pipeline, new explorers would pay incremental tolls. At
6.5 Bcf/day, it would be $1.00 higher; at 7.2 Bcf/day, it would
be $2.50 higher.
MR. PALMER surmised that this permanent increase relative to base
customers would be a significant factor for a potential explorer
in deciding whether to explore in this basin and commit gas. He
noted the state wrestled with this policy issue last year in
establishing AGIA and deciding whether to ask the pipeline
sponsor to propose rolled-in tolls up to 115 percent of the
initial toll. He said rolled-in tolls are important, as are the
FERC rules as to which rates shown on the graph the pipeline
sponsor will propose.
1:39:21 PM
CHAIR HUGGINS asked whether FERC's Lower 48 standard applies to
the Alaska gas pipeline.
MR. PALMER said FERC's Lower 48 standard doesn't apply for a
voluntary expansion. However, for a mandatory expansion there is
the provision he'd described, the subsidy question. If that is
interpreted to imply an increase, which some parties have argued,
then it would apply for a mandatory expansion, an expansion that
the pipeline sponsor did not support.
CHAIR HUGGINS asked whether the left-hand graph that describes
rolled-in rates relates to the request, not the FERC decision.
MR. PALMER replied that is what the pipeline sponsor is required
to request of FERC. As described today, the positions of the
existing customers and future customers are known. What the
pipeline requests can often be the tipping point.
1:41:16 PM
MR. PALMER turned to climate change, slides 39-42, noting
Representative Seaton had asked some related questions over the
last several months. Slide 39, "Climate Change Challenge -
Overview," had the following points:
- Global concerns continue to grow.
- Intergovernmental Panel on Climate Change (IPCC)
strengthens argument to limit manmade greenhouse
gases (GHGs).
- Most common mandate GHG is carbon dioxide (CO2).
- Bulk of CO2 emissions generated by combustion of
fossil fuel.
- Meeting the growing demand for energy while lowering
GHGs is challenging as fossil fuels are abundant and
inexpensive compared to low carbon alternatives.
MR. PALMER highlighted the final point as the key message. He
then relayed information from slide 40, "Alaska's Greenhouse Gas
Emissions," which had two pie graphs and the following text:
The United States emits approximately 14% of global
manmade GHG emissions.
Alaska emits less than 1% of US domestic GHG emissions:
52 million of 7076 million tonnes CO2e.
1:41:44 PM
MR. PALMER summarized slide 41, "Alaska and Climate Change,"
which said:
Alaska faces a unique challenge:
- Alaska and other regions at high northern latitudes
will experience greater warming trends resulting
from climate change. ("Warming is expected to be
greatest over land and at most high northern
latitudes...." Section 3.2.2, Page 46, Climate
Change 2007: Synthesis Report, IPCC)
- Supplying natural gas to markets will increase
Alaska's emissions levels, however it will also help
address the challenge of climate change by
potentially displacing higher carbon fuels
- Natural gas is cleanest burning fossil fuel,
emitting approximately 50% less CO2 than coal at the
burner tip and roughly 25% less CO2 than oil when
combusted
MR. PALMER discussed slide 42, "TransCanada's Climate Change
Activities," which had the following information:
Emissions Reduction Programs
- Leak Detection and Repair Program
- Blowdown Management
- High Efficiency Engines
Technology Development
- Supersonic Ejector Patent
- Incineration
- Field test RB211-6761
Sharing Knowledge
- Methane to Markets (Washington, China, Russia)
- USEPA Natural Gas Star - since 1990s
MR. PALMER elaborated, saying TransCanada has had a long-term
leak detection and repair program on its existing pipeline
systems and inspects all pipelines, valves, fittings, and so on.
Blowdown management is when maintenance is done on a piece of
pipe and gas must be dealt with between the valves being
addressed. TransCanada has a new piece of equipment and now
combusts that fuel, rather than venting it into the atmosphere.
MR. PALMER told members this is to try to address climate change
issues and be a cleaner, more environmentally friendly company.
Noting he would discuss the Supersonic Ejector patent shortly, he
said TransCanada has been an active participant in both Canadian
and U.S. conferences and workshops around the world.
1:43:38 PM
MR. PALMER turned to slide 43, "Technology Excellence," which had
two photographs and the following text:
TransCanada is currently operating the world's first
Rolls-Royce RB211-6761.
Unit demonstrates high efficiency (40%), low NOx and
CO2 emissions.
Features include: remote stand-alone operation,
modular design (ease of maintenance, reduced downtime).
MR. PALMER noted he'd described a highly efficient and low-fuel-
consumption pipeline that TransCanada has proposed, 2.15 percent
fuel on this pipeline from Prudhoe Bay to Boundary Lake.
TransCanada proposes to use highly efficient compressors. The
company put this Rolls-Royce RB211-6761, the largest compressor
available, into service on its Alberta pipeline system to test it
five years ago. Proven technology that has operated for five
years, it is the type of compressor likely to be used on this
Alaska pipeline.
MR. PALMER briefly discussed slide 44, "TransCanada Invents New
Gas Technology," which had a photograph and this text:
Supersonic Ejector reinjects very low pressure methane
into high pressure gas stream
Benefits include:
- GHG reduction of 1,700 tCO2e (per unit per year),
- Savings of $28,000 (per unit per year),
- Zero operating cost.
MR. PALMER explained that there are dry seals on the pipelines
and a modest emission of gas at those seals. TransCanada is
patenting a technology that removes those methane emissions from
the environment.
1:44:59 PM
MR. PALMER addressed slide 45, "GHG Emissions from Long Haul
Natural Gas Pipelines," which had the following information:
TransCanada's Alberta System - 2.5 million tonnes CO2e
(typically 900 PSI, 11 bcfd, 300 miles average distance
of haul)
TransCanada's Mainline - 3.8 million tonnes CO2e
(typically 900 PSI, 7 bcfd, 1400 miles average distance
of haul)
Proposed GTP - 4.1 million tonnes CO2e
Proposed pipeline/facilities - 2.0 million tonnes CO2e
(2500 PSIG, 4.5 bcfd, 1715 miles)
MR. PALMER indicated the carbon dioxide equivalent (CO2e) is in
metric tonnes; he wasn't certain of the conversion to U.S. tons.
As for the Alberta system, he said TransCanada has 15,000 miles
of pipe and moves gas on average 300 miles, with 1,100 receipt
and delivery points. The mainline refers to TransCanada's system
from Alberta to eastern North America.
MR. PALMER noted the final point shows the proposed project. The
GTP is where the bulk of the emissions will come from, since
that's where the bulk of the fuel is consumed. It has a high
fuel ratio at that facility. He told members there is no
technology yet developed to efficiently capture greenhouse gas
emissions from compressor-fuel gas combustion. The 2.0 million
tonnes is for the entire pipeline moving south.
MR. PALMER paraphrased slide 46, "Climate Change - Alaska
Pipeline Project," which had the following points:
TransCanada will responsibly manage GHG emissions
associated with the pipeline.
TransCanada's efforts to control emissions from this
project will include the use of Best Management
Practices in pipeline design and operation including:
- Installation of the highest efficiency engines that
are suitable for this application
- Use of high strength steel, which will lower fuel
usage by allowing higher pressure operation
- Implementation of industry leading methane
management programs
MR. PALMER noted he'd described how TransCanada has controlled
emissions. He added that the company is the leader in high-
strength steel, welding technology, and operation of pipelines.
1:46:59 PM
MR. PALMER discussed slide 47, "Summary," which said:
Last year, the Administration and Legislature
established AGIA as Alaska's transparent and
competitive process to advance a gas pipeline project
- AGIA was structured to encourage:
- Construction of base project
- Long-run basin development
- Open access terms for:
- Initial and future shippers
- In-State, Lower 48, and LNG markets
TransCanada has the credentials and capacity to build,
own, operate and expand the project
TransCanada's objectives are aligned with AGIA
- Early in-service
- Long-run basin development
- Open access - equitable treatment for all customers
MR. PALMER thanked the legislators for their attention and
questions. He said TransCanada is highly motivated to advance
the project, succeed with it, and obtain the license.
1:48:20 PM
REPRESENTATIVE SEATON expressed appreciation that Mr. Palmer had
addressed emissions. He asked: If carbon credits are issued for
this project in excess of what is later needed, how will those be
handled? Will those credits or any income from them help to
lower the tolls?
MR. PALMER answered that there is no mechanism in place to deal
with carbon credits at this time, either on the state or federal
level that he's aware of. As those come forward, there will have
to be an examination and response at that time.
1:49:34 PM
REPRESENTATIVE FAIRCLOUGH asked about access and a correlation
involving proven reserves as a way to fill the pipeline. She
explained that Alaska reportedly has a closed-access pipeline
under TAPS. A constituent's e-mail had just cited a Texas
Railroad Commission model that allows access or capacity
allocations based proportionately on proven reserves. That
allows for exploration. If more reserves are brought onto their
books, they reallocate the transportation ability; this increases
profitability and allows new producers to find space even on
larger pipes if they prove up reserves.
COMMISSIONER GALVIN deferred to FERC representatives who would
speak tomorrow, saying he believes it's more a regulation matter.
He opined that the response may relate to the difference between
how an oil pipeline is regulated versus a gas pipeline - common
carriage versus contract carriage.
MR. PALMER noted he isn't an expert in oil transportation
systems, but agreed it sounds like an oil mechanism, where
generally there are common carriers. For a large Alberta oil
pipeline to the U.S., for instance, parties are prorated based on
either nominations or proven reserves.
MR. PALMER compared that with contract carriers, which natural
gas pipelines normally are. If someone contracts for 300 million
a day, he explained, the pipeline must reserve that amount on a
firm basis each and every day and isn't allowed to prorate it.
He added that while he wasn't aware of any common carriage in the
gas pipeline business, he hadn't researched the Texas Railroad
Commission on this issue.
1:54:05 PM
REPRESENTATIVE RAMRAS asked about TransCanada's market
capitalization relative to that of the producers; whether
TransCanada intends to execute this project on its own;
TransCanada's capacity to handle this project; the lack of FT
commitments; the notion that for a 4.5 Bcf/day pipeline over
25 years, the capacity could be off by 20 Tcf; and how
TransCanada will handle cost overruns if it cannot get the
$18 billion in federal loan guarantees.
MR. PALMER answered that TransCanada's market capitalization
today is just above $20 billion; he doesn't dispute the numbers
others have stipulated on the record for ConocoPhillips and BP.
They are large corporations, as is TransCanada. But no company
will build this pipeline on the basis of its market
capitalization only.
MR. PALMER said he doesn't believe any company has committed, now
or in the past, to build this pipeline on speculation, including
those proposing alternatives to the AGIA project; as he recalled,
their public statements to date have been that they'll hold an
open season, and he wasn't aware that they'd committed to build
any pipeline - nor has TransCanada or anyone else. He'd
described in the last two days why that is so. Even with the
financial capacity to commit $30 billion to build on speculation,
without a loan guarantee or money from anyone else, no party is
capable of achieving that.
MR. PALMER explained that gas pipelines are developed in a
certain fashion. TransCanada proposes to do this in a fashion
that's traditional and takes advantage of the U.S. government
loan guarantee; as indicated previously, TransCanada believes
there's an innovative way to use that for cost overruns. If that
isn't available, however, TransCanada still intends to proceed
with the project and use the loan guarantee for base capital as
it's currently structured.
MR. PALMER further replied that while there've been only
preliminary discussions with U.S. officials, TransCanada doesn't
believe a change in legislation is required, since regulations
haven't been promulgated, but he'd had no assurance about that.
If TransCanada is unsuccessful in obtaining U.S. government
approval for using the loan guarantee for overruns, it will
prosecute the project as described, taking a portion of the
capital-costs risk and having the customers take the remainder.
MR. PALMER assured Representative Ramras that TransCanada is
large enough to do this project. The company built a longer
facility when first incorporated, for instance, when its market
capitalization approached zero. It continues to build large
projects. TransCanada has a $5 billion oil pipeline underway and
hopes to soon have a second component that will bring it up to
some $13 billion, approximately half the capital cost of this
Alaska project; TransCanada has a partner, having sought one, and
is pleased to be working with ConocoPhillips on that.
MR. PALMER opined that TransCanada has the capacity to do this
project alone, as described before. In addition, TransCanada
believes strongly from the statements of the current North Slope
leaseholders that if they become shippers - which they haven't
committed to - they are highly interested in becoming an owner of
this pipeline. If that doesn't happen, TransCanada has other
partners available, if it so desires.
MR. PALMER pointed out that if this is a successful project,
TransCanada also has available the public markets to raise equity
if so required. For projects developed in the last two years, it
has done so successfully, as described earlier. Referring to
cash-flow numbers shown over the past couple of days, he said if
TransCanada doesn't succeed with any new projects beyond the
current ones on its books, it has a history of developing new
projects and expanding its cash flows beyond those.
2:01:40 PM
MR. PALMER noted there'd been questions about Ravenswood and the
debt-rating agencies. He said TransCanada was put on a ratings
watch, which is normal on a large transaction; a month later
Standard & Poor's confirmed its rating at A- and Canada's DBRS
did the same, while Moody's has it at a higher notch but might
lower it to A- after review. He opined that the fact that
TransCanada has been able to finance in the public markets for a
difficult circumstance, when the markets are unstable, proves it
has access to the market for equity or debt, if so required.
MR. PALMER added that the U.S. loan guarantee will assist the
project whether it's available for overruns or not. TransCanada
has raised $3 billion in the public markets in the last 15 months
and $2 billion in the debt markets. But while TransCanada has
the capacity to do this project as proposed, it won't advance it
through construction without customers or credit. Mr. Palmer
said he has been clear on that issue for 12-16 months and doesn't
believe any party will advance without contracts. Nobody to date
that he's aware of has promised to do so, either large companies
- TransCanada being one - or small ones.
2:03:25 PM
REPRESENTATIVE RAMRAS voiced appreciation for the response, but
characterized this as a fool's errand. He opined that the
leaseholders have been explicit that there'll be no gas for this
project. And the state's seed money won't change the behavior of
these large corporations. He also suggested that if this were a
boardroom in the private sector, it wouldn't withstand scrutiny
because the empirical data before the legislature isn't
sufficient to presume this will move toward a transaction. He
said he would carry this message across the state.
COMMISSIONER GALVIN took exception to the assertion about gas
commitments. He specified that the producers have never said
they won't commit gas to this project. Rather, they've expressed
concern about aspects of AGIA they believe will cause them to
consider that issue, and they've clearly expressed a desire for
additional changes to the state fiscal system, based on their
desire for profitability of this project.
COMMISSIONER GALVIN indicated the issue of how to get gas
committed to this project will be discussed over the next couple
of days. It is a challenge to get that gas to the TransCanada
project, he said, but not one that has been precluded. In
addition, experts who've looked at this project closely have said
there is a high likelihood the gas will ultimately be committed
once the interests have lined up.
COMMISSIONER GALVIN also took exception to the suggestion that if
this were a boardroom, somehow the decision would be different.
He said he didn't know how many legislators at the forum last
week had talked to the Goldman Sachs folks in particular or
others who advise the boards of these energy companies about
opportunities such as this one.
COMMISSIONER GALVIN surmised that those experts would have
advised - looking at this opportunity from the state's position
as a resource owner - that advancing this TransCanada project
would be appropriate and would be done if this were strictly a
commercial venture.
2:08:26 PM
REPRESENTATIVE RAMRAS objected, characterizing the earlier
meetings as propaganda and saying he didn't want to accept
hearsay. He asked that Goldman Sachs be brought before the
legislature to be questioned on the record.
COMMISSIONER GALVIN replied that Goldman Sachs would be in Juneau
Monday and Tuesday and in Anchorage later. Some of their top
energy folks would be advising the state on questions put before
them about the finance markets and TransCanada's ability to
undertake the responsibilities. Discounting any idea that they'd
take a position just because it was favorable to the
administration's, he said these are companies that have a high
degree of integrity, putting that integrity on the line.
MR. PALMER added that TransCanada does operate in the private
sector. Its board made a commercial decision to participate in
the process established by this legislature. It did so because
of the belief that TransCanada can attract the customers.
TransCanada isn't in the business of pursuing a project where it
might spend over $100 million of shareholders' money with the
expectation of failure. If that were so, the decision would have
been different and TransCanada wouldn't have filed under AGIA.
2:11:10 PM
SENATOR DYSON told members the administration had responded
better than he could, indicating he considered the remarks of
Representative Ramras out of line. Agreeing with Commissioner
Galvin that the companies have never said they wouldn't ship at
the wellhead or the GTP, Senator Dyson said he believes there is
a letter on his own desk this week from Exxon in response to an
inquiry from several legislators.
SENATOR DYSON reported that the last two times he visited with
FERC commissioners, they reminded him that this project is unique
in that Congress has decided it is in the national interest and
that this continent needs Alaska's gas, with the clear
implication that they would follow through.
SENATOR DYSON gave his understanding that the day that this
project is declared valid, the companies get to book the
equivalent of 8.6 billion barrels of oil, more than a thousand
billion dollars that they get to add to their books. He
discounted the notion that shareholders would allow those
companies to refuse to ship under such circumstances.
SENATOR DYSON said almost no projects in North America have been
built by the producers. Almost all are independent pipelines.
The kinds of partnerships that will come together here are
typical. He reported that FERC officials have assured him that
the best of all circumstances for the state is to have competing
proposals show up at their desk; a marriage most likely will come
out of that, even if forced, and the stakeholders will come
together for a successful project.
REPRESENTATIVE DOOGAN asked the chair what proportion of
questioning versus political posturing there would be during
these proceedings.
CHAIR HUGGINS replied that since all the legislators are
politicians, it's probably 100 percent politics, with variations
among those present. They all deserve a chance to ask questions
and state opinions, so long as they display respect and decorum.
He offered to address any further concerns after the meeting.
2:16:19 PM
REPRESENTATIVE NEUMAN mentioned the open season, saying he
believes TransCanada's proposal wants to get to a class 4
engineering report, which is 15-20 percent "project definition
complete," with expenditures of approximately $80 million split
50/50 between the state and TransCanada, $40 million each. This
is so an application can go to FERC to ensure there are FT
commitments in order to produce the gas.
REPRESENTATIVE NEUMAN contrasted that with the Denali project,
for which ConocoPhillips and BP propose to spend over
$600 million to have a class 1 or 2 engineering report, 50-100
percent project definition complete. He said that's critical to
ensure that all producers wanting to ship gas down that pipeline
have the necessary information to apply for capacity within that
pipe and get a FT commitment; in that way, whoever builds this
pipeline can get the money to build it.
REPRESENTATIVE NEUMAN recalled hearing Mr. Palmer say that
TransCanada already has a lot of information, but said he didn't
know what it was worth or how much was spent getting there. He
said he'd rather have ten proposals go to FERC; it seems there'll
be at least two. He mentioned trying to ensure that there is a
pipeline eventually, with FT commitments.
REPRESENTATIVE NEUMAN also surmised that it will delay the
pipeline if TransCanada's proposal goes forward and at the open
season there aren't sufficient FT commitments to get $30 billion
to build it. Expressing concern about the timeline to get low-
cost energy to Alaskans, he recalled hearing that the least
expensive way would be a spur line off a mainline. He suggested
that if TransCanada is willing to spend over $100 million and the
state will put in another $500 million, TransCanada essentially
will be doing the contract work out of that.
MR. PALMER replied that he wasn't in a position to comment on
what others would spend on a different project, having no
knowledge of it except for a 12-page PowerPoint presentation he'd
seen. But TransCanada's professional opinion, based on 50 years
of experience and information available today within the
corporation, is that TransCanada can come up with a very credible
capital-cost estimate to hold an open season for $84 million, as
shown on the estimate provided to legislators.
MR. PALMER also said he wouldn't speak to why others would pay
more to get to an open season. When purchasing something, he
looks at who is credible and has the capability, rather than
simply getting a party that will charge him more for an estimate.
He expressed hope that over the last few months he has conveyed
TransCanada's credibility and capability to the legislature and
the people of Alaska - that TransCanada knows how to do this
business, having been involved in this business and this project
for a very long time.
MR. PALMER, with regard to TransCanada's risk exposure, noted
there'd been testimony from a number of parties over the last
several days that TransCanada will incur the costs first and then
be reimbursed up to $500 million, with different ratios both
before and after the open season. Giving his assurance that
TransCanada hasn't lowballed the number before the open season in
order to get to the 90 percent factor, he said whether it's
committed in advance of or after the open season doesn't matter
because the entire $500 million will be used.
MR. PALMER indicated over several years TransCanada will have
exposure to more than $100 million of its own money and will make
nothing off the state's money. Also, if the estimate to get to
the FERC certificate is wrong and the state is already at its
cap, TransCanada's exposure increases. If it can be done
successfully for less, the state and TransCanada both save money.
He expressed hope that the cost estimates had been adequately
addressed in the binders and testimony provided over time.
2:24:16 PM
REPRESENTATIVE NEUMAN explained that his question centered on the
type of engineering report, the blueprint for the project, and
whether there is sufficient information available to make the
decisions for TransCanada to attract FT commitments worth
$30 billion. Since TransCanada's application says it believes
this can be done with a class 4 report, there seems to be a
discrepancy with trying to get a different proposal, and he
doesn't have anything else to gauge this proposal against.
MR. PALMER replied that he hopes TransCanada has shown itself to
be a respectable, respectful, and professional organization that
deals with these potential customers daily as it moves gas
throughout North America. TransCanada believes it can provide a
credible and standard cost estimate, as it would for other
projects when going to an open season. Whether large or small,
in Alberta or the Lower 48, this is the standard the company
applies. He said he couldn't comment on other parties.
REPRESENTATIVE NEUMAN relayed his belief that TransCanada is a
highly respectable company, which he'd heard from other companies
as well. However, for a successful open season he believes the
more information companies have that may want to sign up for a FT
commitment, the better off the state is. He suggested that's
critical to ensuring there is gas to Alaskans.
MR. PALMER offered that merely spending a lot of money doesn't
necessarily get a better cost estimate. For example, the parties
pursuing the Mackenzie Valley project have spent a great deal; he
noted TransCanada had only a tiny participation in that and
didn't drive that project in any way. He said last year those
capital costs ended up doubling after hundreds of millions of
dollars had been spent.
2:27:10 PM
COMMISSIONER GALVIN told members Representative Neuman's question
was a good one; the administration has heard the same thing about
comparisons between what the Denali project claims it will have
as cost estimates pre-open season and what TransCanada says.
Thus the administration's economic analysis separates the risks
associated with the cost estimate being off, referred to as
"project scope risk." If it were missed because of not having
gotten further at the time of the open season, the issue is how
much risk there'd be in terms of its impact on the tariff and
ultimately on profitability to the producers.
COMMISSIONER GALVIN reported that the impact was found to be
small - the range of possible variation from doing the additional
engineering has a relatively small impact compared with other
risk factors. He opined that's why, from the industry
perspective, the norm is to go the level TransCanada is
proposing; the additional clarity of having the engineering get
down to such a further level doesn't help tremendously.
2:28:49 PM
REPRESENTATIVE GARA expressed concern that Mr. Palmer will hear
"fire" and voice concern to the shareholders that the State of
Alaska might not be a good partner.
MR. PALMER gave his assurance that he takes no offense,
understands this is a difficult decision for this body and for
Alaskans, and believes the comments have been heartfelt.
REPRESENTATIVE GARA concurred with the earlier comments of
Senator Dyson. Noting many folks are interested in a bullet
line, he recalled there'd be a much lower, if not zero, tax for
in-state gas use. He asked: What are the fiscal ramifications
for the State of Alaska if choosing a bullet line for in-state
gas use somehow precludes building a larger-diameter gas line?
REPRESENTATIVE GARA also noted that in-state gas use is to be
addressed in the scheduled out-of-Juneau hearings. He said he'd
never heard of a proposal that would provide low-cost gas without
some massive state subsidy; this includes the tentative proposal
from ENSTAR Natural Gas Company and others, as well as any spur
line from this project or an in-state bullet line. He asked: Is
it correct that there won't be low-cost gas without a subsidy
from the state? What are the expectations for in-state gas
prices under any of these scenarios? And what are the tax
ramifications for primarily an in-state-use gas line?
2:31:05 PM
COMMISSIONER GALVIN responded first to the tax questions.
Referring to the 2007 legislation known as Alaska's Clear and
Equitable Share (ACES), he said it included a global change to
the state production tax - it takes the tax rate currently used
within the Cook Inlet market for gas produced there and applies
that to any North Slope gas consumed within Alaska. Thus gas
consumed within Alaska has a lower tax rate, which means lower
revenue, but that's not the driver of the issue.
COMMISSIONER GALVIN turned to providing affordable gas to
Alaskans. Mentioning high expectations, he clarified that the
state potentially would provide low-cost transportation of the
gas if the state were to build a bullet line and subsidize the
cost. He highlighted Senator Therriault's point that in order to
make transportation economic, one either can increase the
throughput by adding LNG or other things or else can just
subsidize the cost that ultimately may be recovered in the
tariffs. So the transportation costs could be brought down.
COMMISSIONER GALVIN said ultimately it will be a matter of what
the actual price is for the gas. Within Cook Inlet, that's
controversial in terms of whether it's the cost of production or
is somehow tied to a Henry Hub price or if there is a need to
jack up the actual commodity price of gas to spur exploration. A
similar question would be faced when getting to possibly bringing
North Slope gas down to Fairbanks or bringing gas up from Cook
Inlet to Fairbanks to satisfy demand.
COMMISSIONER GALVIN added that the price for the gas will be
determined down the line, probably by a regulatory agency like
the Regulatory Commission of Alaska (RCA) or by the market
itself. At this point, there is a risk of setting an
exceedingly high expectation that the state could unilaterally
create low-cost gas, absent a tremendous amount of state
resources being brought to bear.
COMMISSIONER GALVIN also mentioned the idea of the state's
providing royalty gas as the source of low-cost gas, providing it
at a dramatically reduced, below-market price within Alaska. He
said that has been discussed on the oil side for a number of
years, but it creates constitutional issues associated with the
expectations of what the state will get for its resources. While
it is open for discussion, it has those ramifications.
COMMISSIONER GALVIN recalled that Senator Stedman had expressed
concern about giving away the state's one source of revenue at an
incredibly low rate to Alaskans, since not all Alaskans would be
in a position to consume that low-cost energy. Noting the state
gets its value through the sale of it, Commissioner Galvin
cautioned that there is no panacea, including a bullet line. In
some ways, the fact that the state is enjoying tremendous
revenues right now opens up opportunities to explore different
possibilities. But this needs to be approached with eyes wide
open and based on facts that can be gathered.
2:35:55 PM
SENATOR STEDMAN noted that recent presentations and analyses have
been based on $10 gas, with much larger numbers than the previous
administration's proposal, the gross dollar value if this gas
gets to market. With respect to risk exposure, he wondered why
the state would have a 90/10 split if this project is nearly
risk-free, roughly 80-90 percent at the end, depending on how it
is counted, and whether the legislature would be here if that
were reversed, with 10-20 percent state money. He asked about
TransCanada's monetary comfort level in pursuing this project
versus relying on other people's funds.
MR. PALMER answered that TransCanada looked carefully at the
proposal under AGIA, viewing it as an overall business deal
including the rights such as the $500 million and the
responsibilities. Last year when testifying, he was asked
whether TransCanada would commit to apply at 90 percent; he'd
demurred because last spring TransCanada hadn't decided whether
to file at any percentage.
MR. PALMER recalled that there were variations on how the state
would share risk, including monetary amounts and percentages.
TransCanada was asked many times whether it was prepared to
commit to apply. While some parties said they would bid and then
didn't necessarily end up at the finish line, TransCanada never
stated it would bid at 90, 80, or 50 percent. But once AGIA
passed and the request for applications (RFA) was issued,
TransCanada closely examined the overall opportunity and risks.
As to whether the $500 million was an important factor, he
affirmed that it was.
2:40:00 PM
SENATOR STEDMAN asked: Is there any relationship between the
probability of success and the ratio for state money versus
TransCanada shareholder money?
MR. PALMER reiterated his remarks about examining the situation,
adding that part of it was looking at TransCanada's financial
exposure if it never successfully completed the project.
TransCanada figures to use the state's $500 million before
hitting the final cost estimate to get to FERC; the $500 million
cap and not the 80-90 percent is the limiting factor.
MR. PALMER added that if the state had offered 50 percent as its
entire exposure before and after, then TransCanada's exposure
would have been about $300 million. However, he wasn't in a
position to say whether that would have changed TransCanada's
decision to submit a bid.
SENATOR STEDMAN clarified that he was struggling with the
probability of success versus the split of 50/50, 75/25, and so
forth.
MR. PALMER said perhaps he hadn't understood the question. If
TransCanada had bid and taken on $300 million in risk rather than
$100 million, for example, at that point he didn't think it would
have changed the probability of the project's success. If
there'd been exposure to a much higher financial commitment in
order to bid, however, TransCanada might not have come to the
table. Nobody might have. That might have changed the state's
probability of success in attracting an AGIA licensee.
SENATOR STEDMAN suggested that correlates with the last days of
the AGIA legislative process, when amendments were made including
one changing the reimbursement from 80 to 90 percent.
2:44:17 PM
REPRESENTATIVE GATTO told members what's important to him is
keeping the eye on the prize, the future of the state for the
next generations. He said he doesn't believe TransCanada is a
charity, but came here for the money; people are watching and
wanting to ensure that it succeeds. He surmised that TransCanada
had done an immense amount of investigation before making the
commitment to submit the application that agreed with all the
requirements. He expressed confidence that TransCanada can do
this project and that everyone will be better off for it.
2:47:24 PM
REPRESENTATIVE SAMUELS noted he hadn't been a big fan of the AGIA
process. While respecting TransCanada, he said there wasn't the
competition promised. He'd rather see the administration
negotiating TransCanada down as far as possible to get a better
deal, lowering the rate of return from 14 percent, for instance.
2:51:49 PM
COMMISSIONER IRWIN explained that when this process was set out,
looking at the state's history at that time, the administration
made a conscious decision to have a fair, open, competitive
process. The administration could have asked for bidders without
asking for best and final offers. But that may have resulted in
negotiations behind closed doors with various companies. That is
a route often chosen by businesses.
COMMISSIONER IRWIN said the administration instead chose another
route that businesses also use: clearly defining what the state
wants and then using the "best and final offer by date certain"
concept. He reminded members that in meetings with large groups,
he'd frequently said only one good bidder is needed. While some
were pushed out for unknown reasons, those companies made their
own decisions. In this case, this high-quality company played,
participated, and honored the state's rules for a best and final
offer by a date certain.
COMMISSIONER IRWIN said the administration gave a promise. The
administration got AGIA passed, was tasked with proceeding, and
put out an RFA. To go back now and ask for more out of
TransCanada wouldn't be honoring the state's word. The
administration chose the "best and final offer" route, and he
doesn't regret it. There could always be a little more on the
table somewhere, but the state got a high-quality company.
COMMISSIONER IRWIN added that when he looks at what TransCanada
offered such as debt equity, he believes that was from
competition. It might not have been obtained through
negotiation. He concluded by saying he can't speak for
Mr. Palmer and his company, but can clearly say how much he
thinks of them. They also have negotiations to do to bring this
gas pipeline to a hugely successful completion for everyone.
2:55:30 PM
COMMISSIONER GALVIN followed up, saying the bottom line is that
TransCanada will be negotiating with the producers on shipping
rates. The producers can negotiate to bring those down, probably
with a better negotiating position than the state would have in
trying to do the same.
COMMISSIONER GALVIN also cautioned against thinking AGIA didn't
create competition. He said it clearly did in the minds of the
applicants, the only place it could affect the outcome. As
Mr. Palmer has testified, TransCanada didn't know who would apply
and therefore put in an application based upon the expectation
that others would compete, the best offer it could give. This is
what's before the legislature today.
2:57:52 PM
SENATOR STEDMAN asked: What will the state do if this proposal
ends up before FERC and FERC decides 600 basis points above the
10-year Treasury bond rate is appropriate, for example, rather
than 900-some basis points?
COMMISSIONER GALVIN answered that he wouldn't speculate now,
since it will be based on a future decision and a variety of
considerations. As noted yesterday, the state isn't obligated to
defend every aspect of the TransCanada proposal, including rate-
of-equity expectations and the point Senator Stedman just made.
However, there'll be an assessment of the level at which the
state wants to advocate for something that affects the value to
TransCanada, given that the state brought TransCanada into this
process with the expectation of being partners going forward.
COMMISSIONER GALVIN added that the administration wants to make
sure the state's partner gets the value it would like and
reasonably expects out of this project, just as anybody would
want a partner to succeed. So that will be part of the
administration's analysis. But the state isn't bound to having
to defend it, which he indicated is the most important piece that
the administration wanted to retain.
2:59:26 PM
REPRESENTATIVE KELLY asked Mr. Palmer how many real players
TransCanada had thought would bid on this project.
MR. PALMER replied that TransCanada had market intelligence in
the late fall about certain parties that TransCanada expected
weren't going to bid, but didn't know the accuracy of that.
However, TransCanada had believed one major competitor would be
making a strong bid and was surprised that didn't happen; that
competitor had stipulated it would bid, and TransCanada had
received no contrary market intelligence.
REPRESENTATIVE KELLY asked: If the state had come to TransCanada
as the only party that the state was interested in talking to,
would TransCanada's best and final offer have been higher or
lower than it is now?
MR. PALMER answered that TransCanada feels it stretched to get to
this point, looking at the risk; the opportunity; the value to
the company; the requirements under AGIA, both moral and legal;
and the rights that would be obtained. Rather than being pushed
by the board to be more aggressive, he had pushed the board to
get to this level.
REPRESENTATIVE KELLY called himself an "options guy" and voiced
appreciation for the fact that the legislature is pushing hard
for questions. He surmised as a player TransCanada will take the
state's "must haves" all the way to FERC, and the others with a
project in the works will have to deal with the fact that
somebody will arrive at FERC with the Alaska story and a way to
meet it, which is healthy for everyone involved. He opined that
the state is right where it ought to be, with a good return
predicted and so forth.
CHAIR HUGGINS asked Mr. Palmer whether he and others from
TransCanada would be available over the next 50 days or so.
MR. PALMER affirmed that.
The committees took an at-ease from 3:03:26 PM to 3:18:37 PM.
^Presentation by Bob Swenson of DNR and Dave Houseknecht of USGS
CHAIR HUGGINS invited Bob Swenson and Dave Houseknecht to give
their presentation.
BOB SWENSON, Director, Division of Geological & Geophysical
Surveys, Department of Natural Resources, explained that they
would discuss the advancement in the understanding of the North
Slope region, how that is used to do resource assessments, and
what undiscovered resource assessments USGS has performed. He
would provide an overview of the geology, and Mr. Houseknecht
would explain resource assessments done in 2004 and 2006.
MR. SWENSON began a PowerPoint presentation titled "Natural Gas
Exploration Potential in the Alaskan Arctic"; a handout
duplicated the slides. He noted the opening slide shows the test
well in Prudhoe Bay State No. 1, the first test of gas on the
North Slope from the Prudhoe Bay gas cap in the late 1960s.
Since then, knowledge about the North Slope has increased
dramatically.
MR. SWENSON showed the next slide, a map labeled "Arctic Alaska -
Key Geologic Features." Pointing out that the area of discussion
extends from the Canadian-U.S. boundary to the Russian-U.S.
boundary, he highlighted the Chukchi Sea platform; the Beaufort
Sea arctic slope; and the onshore sequence including the National
Petroleum Reserve-Alaska (NPRA), state lands, and the Arctic
National Wildlife Refuge (ANWR).
MR. SWENSON said the geologic portions become important in any
resource assessment. This relates to the tectonic regime in
these areas. Seen is the underlying geology that makes up the
depositional sequences, where sediment is being deposited. To
the north is the Barrow Arch, a rift shoulder sequence, meaning
when North America rifted away from Northern Canada it created a
breakup of this part of the crust.
MR. SWENSON highlighted its importance, saying it is similar to
North Sea regions where the coast of the Atlantic rifted away
from Europe. To the south is another major tectonic province,
the Brooks Range, a major source for sediment deposited in the
Colville and Hanna troughs.
3:22:03 PM
MR. SWENSON turned to the next slide, "Stratigraphy - Known &
Potential Source Rocks," which had a depiction labeled "Central
North Slope Stratigraphy" going from the Cenozoic down to the
Pre-Mississippian, as well as these notations on the right-hand
side, from top to bottom: Paleogene Canning, Seabee, GRZ (HRZ),
Lower Kingak, Shublik, Lisburne (Kuna), and Kekiktuk.
MR. SWENSON explained that since the late 1960s an incredible
amount of work has been done on the North Slope by state
geologists and by industry and federal representatives. From
that work, a comprehensive story has been put together of what
the rocks look like and their depositional setting. If a well
were drilled all the way down into the basement rock, the depth
would vary tremendously, depending on the location. This slide
shows the package of rocks that would be seen, with the age of
the rocks.
MR. SWENSON told members there are a number of important points
on this slide. Though he wouldn't go into detail, those include
the reservoir rocks shown in yellow and the source rock facies,
the highly organic facies that if put through the correct
temperature and pressure regimes by burial will generate
hydrocarbons.
MR. SWENSON noted that on the right-hand side is a sequence of
these highly organic facies on the North Slope. This shows that
the North Slope is a supercharged basin, with a number of these
different facies that have gone through various tectonic and
geologic histories to generate hydrocarbons.
MR. SWENSON explained that the next slides show the lateral
continuity of these different source facies, from the earlier
Triassic and Permian facies to the Beaufortian and Brookian
sequences. One important aspect is the ability to correlate
between samples of hydrocarbons and the original source facies
using modern geochemical techniques, making models of where
different facies may or may not have generated.
3:24:19 PM
MR. SWENSON discussed a slide labeled "Arctic Alaska Source Rock
Systems," noting these regional maps depict where the source
facies are located; important colors are light greens and
yellows. The lower part of the sequence shows this highly
organic facies was deposited over pretty much the entire area in
the Triassic and the Jurassic sequence; this includes into the
Chukchi Sea region, offshore state waters, and the Beaufort Sea.
MR. SWENSON said for the Cretaceous and Paleogene sequences,
these deposits occurred over much of the area. In the southern
part of this region, the Terrigenous - meaning it came from land
sources - and Mixed Kerogen areas are highly gas-prone.
MR. SWENSON noted that the next slide, "Overview of Regional
Geology," depicts a cross-section showing what this depositional
sequence has gone through over time. This is from the Brooks
Range heading north to the Beaufort Sea. The rift sequence
mentioned earlier, similar to what is found in the North Sea, can
be seen. To the south is a classic foreland basin, similar to
the Canadian thrust belt. He emphasized that the North Slope
deposits including Prudhoe Bay, Kuparuk, and Alpine are here on
the Barrow Arch; this area has oil and associated gas.
3:26:12 PM
MR. SWENSON explained that in the deeper parts of the basin,
those same source rocks have generated both oil and gas in the
shallow section. In the deeper section, those source rocks have
gone through a crack to gas, meaning it's primarily a gas
province, both to the south because of the deep burial and to the
north. Also important is that because of the thrusting - the
deformation as the Brooks Range was built - there was uplift and
release of that gas along with a flushing of any earlier oil
charge that may or may not have been there.
MR. SWENSON discussed the next slide, "Reservoir quality
studies," which had what appeared to be a photograph labeled
"Skimo Anticline - Overturned Forelimb"; another labeled
"Porosity"; and a graph labeled "Porosity (%) vs. Permeability
(mD), North Slope Foothills."
MR. SWENSON advised members that the reservoir rock has porosity
and permeability, as shown on the thin section on the upper part
of the slide; blue areas are the spaces between the rock that
give the porosity, while the interconnectivity, how well fluid
flows in that, is the permeability. Thus the graph relates to
how much oil or gas can be fit into those pore spaces and also
how well those are connected and hence how fast the fluid will
flow. That's an important aspect for any resource development.
3:27:26 PM
MR. SWENSON turned to results from the exploration phases,
showing a slide labeled "Foothills Drilling and Gas Occurrences."
He explained that this map shows discovered gas accumulations in
the Foothills region, where he would be focusing; wells with
numerous strong or fair gas shows; and wells with few or minor
gas shows. The large circles represent that most of the wells
drilled in the Foothills regions - few for the size of this area
- had very, very strong gas shows.
MR. SWENSON noted that the next two slides, "Foothills Cross
Section - Oil and Gas Shows" and "Foothills Structural Plays,
Seismic Interpretation," depict each of these wells in context
with the geology and also the seismic line from the Kavik field
area, which gives an idea of what the subsurface looks like.
MR. SWENSON said for the first, each well is represented by a
vertical line; in between is an interpretation of the basin field
geometry of that whole Colville trough, revealing the
complexities that also bring up opportunity because what is going
on isn't known for every portion of the basin. Important to note
is that the red and green tick marks on the vertical lines
represent gas shows, in red, and oil shows. For each well, there
were numerous shows of both oil and gas.
3:29:19 PM
MR. SWENSON turned to the seismic line for the Kavik area seen on
the earlier map. Highlighting the gas shows throughout that
sequence, he noted there's a tremendous amount of deformation
seen in the Foothills region; this sets up numerous different
types of plays that could be explored for with respect to gas.
MR. SWENSON addressed a slide labeled "Conventional Exploration
Play Types" that relates to oil and gas trapping mechanisms. He
told members that to understand the geology in any of these
basins, especially a supercharged basin like the North Slope,
it's important to have a fair understanding of the reservoir rock
distributions, the geometries of all the different traps, and the
generation and migration of hydrocarbons to fill those traps.
All this geology is fit into the resource evaluation to come up
with estimates for undiscovered resources. He turned the
presentation over to Mr. Houseknecht.
3:30:13 PM
CHAIR HUGGINS mentioned legislation passed in a special session
that allowed access to data from different organizations
including the producers and other companies. He asked what the
status is and whether that has aided this work.
MR. SWENSON replied a lot of additional information has been
gained. The charter agreement for all the data made publicly
available is in-house. Also, DNR's Division of Oil & Gas has a
complete set of onshore data. The data that can be used is
publicly available or else agreements have been made for it.
MR. SWENSON said this data has dramatically increased the ability
with respect to subsurface interpretation, both with detailed
well information and seismic data. Noting he'd just showed one
seismic line, he said there is a whole suite of seismic lines
across the North Slope, and USGS has an even more comprehensive
data set.
3:31:27 PM
DAVE HOUSEKNECHT, Geologist, U.S. Geological Survey, U.S.
Department of the Interior, began by saying he would address the
role of the USGS and its sister agency, the Minerals Management
Service (MMS), with respect to how the information they generate
relates to these deliberations. One mandate of USGS is to do
systematic evaluations of energy and mineral resources nationwide
and worldwide.
MR. HOUSEKNECHT explained that they collaborate with state
organizations such as DNR divisions and take opportunities to
interact with industry where possible; it's important to share
ideas and exchange data where appropriate. They then go behind
closed doors and make estimates of how much oil and gas remains
to be discovered; it's essential that this process be independent
of any influence because that's the basis of their credibility in
Washington, D.C.
MR. HOUSEKNECHT said the information he would share today is from
work over the last decade. He opined that it's significant that
all this work was published before the AGIA proceedings began.
He noted summaries of the information can be made available to
the legislature or by e-mailing him; his e-mail address was shown
as dhouse@usgs.gov.
3:33:21 PM
MR. HOUSEKNECHT highlighted a paper he and colleague Ken Bird
published in 2006, a broad summary of what they know about those
reserves and undiscovered oil and gas resources in northern
Alaska. In addition, he said, short factsheets provide an
executive summary for specific areas where they've worked. This
represents the work of both USGS and MMS, and it predates the
AGIA proceedings.
MR. HOUSEKNECHT discussed a slide labeled "Known Gas
Accumulations in Arctic Alaska," which listed known unit and gas
reserves (Bcf) as follows: Prudhoe Bay 24,526; Pt. Thomson
8,000; Pt. McIntyre 1,526; Kuparuk River 1,150; Duck Island 843;
North Star 450; Colville River 400; Barrow-Walakpa 34; Milne
Point 14; and a total of 35,417. It also listed other known
accumulations, possible gas reserves onshore and offshore (Bcf).
Onshore it showed: Gubik 600, Kavik 115, Square Lake 58, Meade
20, Umiat 5, East Umiat 4, and "?" for East Kurupa, Kemik, and
Wolf Creek. For the offshore Outer Continental Shelf (OCS) it
showed Burger at 14,000 and "?" for Sandpiper.
3:35:01 PM
MR. HOUSEKNECHT explained that two fundamental types of gas
resources are shown: known accumulations of associated gas,
meaning gas associated with oil, with Prudhoe Bay as the best
example; and non-associated gas, meaning gas that occurs in an
accumulation in the absence of oil or significant liquids. Most
of the associated gas resources are clustered in the north near
the Barrow Arch, whereas most of the non-associated gas resources
are clustered in the Foothills, where there has been relatively
little exploration; he would return to this point.
MR. HOUSEKNECHT highlighted proved reserves in arctic Alaska,
mentioning a summary published by DNR's Division of Oil & Gas.
He said other accumulations have been discovered, but not much is
known about the size. As shown here, the biggest is the Burger
prospect, a discovery drilled about 1990 in the Chukchi Sea that
was the focus of a big lease sale recently by MMS.
MR. HOUSEKNECHT emphasized that until now there've been about 500
exploration wells drilled in northern Alaska. One was drilled
intentionally looking for natural gas this past season. Thus
what is known about gas reserves and gas resources in northern
Alaska is the result of looking for oil. In fact, most
accumulations discovered in the Foothills represent exploration
failures that have one well in them and in many cases tested a
lot of gas; because it was gas and there was no commercial market
for it, the company never delineated that accumulation and so it
isn't really known how big it is.
MR. HOUSEKNECHT showed a slide labeled "Alpine Play in NPRA -
More Gas than Oil?" He said as resource assessments are
performed in northern Alaska to estimate oil and gas that remains
to be discovered, this area of North America is difficult to deal
with as a geologist because there is so little exploration
information. A good example is northeastern NPRA, where in 2004
USGS completed such an assessment and six months later
ConocoPhillips leased some of the results of that exploration
drilling.
MR. HOUSEKNECHT explained that at the time of the assessment, all
that was known of the Alpine play was the Alpine field, which has
a gas-to-oil ratio of 840, quite low. Shortly after the
estimates were released saying there was a lot of oil and
condensate with some gas in NPRA, the results from new
discoveries were released. Within about 20 miles, moving
westward from Alpine, there is a gas accumulation in the
westernmost discovery, with a lot of condensate.
MR. HOUSEKNECHT said this suggests the oil numbers may be a bit
high and gas estimates a bit conservative. Highlighting the need
for continuing study of these frontier areas, he said every well
drilled represents a significant amount of new information that
the agencies then have to work with.
3:39:50 PM
MR. HOUSEKNECHT showed a slide labeled "Assessment Methodology -
Geologic Basis." He emphasized that although the mean estimate
typically is reported in the literature and media, these
estimates of undiscovered oil and gas resources capture a range
of probabilities.
MR. HOUSEKNECHT explained the process. When they go behind
closed doors, they start by measuring and filling out on a
probabilistic scale how thick the reservoir is; how big the
closures are, seen in the seismic data; and what they think the
porosity and water saturation of the reservoir are. They do a
simulation, and the result is a distribution of oil and gas
accumulation sizes that capture the range of uncertainty.
MR. HOUSEKNECHT said they then apply risk, which relates to
whether those source rocks have generated oil and gas, whether
that has made it into the reservoir, as well as the presence of
good reservoir rocks and traps; this provides a distribution of
in-place resources. After that, they apply a recovery factor to
get an estimate of "technically recoverable resources"; this is
the volume of oil and gas they believe is recoverable using
current technology, regardless of price.
MR. HOUSEKNECHT showed a slide that had a map of Alaska and parts
of Canada, labeled "Undiscovered Conventional Gas Potential." He
said one can see why so much emphasis is placed on the arctic
part of Alaska, where the largest of the bubbles represented
119 Tcf of gas. He noted the bubbles represent mean estimates
made by USGS onshore, MMS offshore, and the Geological Survey of
Canada in the Mackenzie delta. The large bubbles represent that
those agencies believe there are large gas resources in arctic
North America.
MR. HOUSEKNECHT discussed a slide labeled "Potential for
Undiscovered Petroleum in Arctic Alaska," which listed mean
estimates of undiscovered conventional gas in Tcf. For onshore
and state offshore areas, USGS estimates were: NPRA, 61.35 for
non-associated gas, 11.68 for associated gas, and 73.03 total
gas; Central North Slope, 33.32 non-associated, 4.20 associated,
and 37.52 total; ANWR, 1002 Area, 3.84 non-associated, 4.76
associated, and 8.60 total; and a subtotal of 98.51 non-
associated, 20.64 associated, and 119.15 total. For federal
offshore areas, MMS estimates had total gas only: Chukchi Shelf,
76.77; Beaufort Shelf, 27.65; Hope Basin, 3.77; and a subtotal of
108.19. The total for all was 227.34 Tcf.
3:42:51 PM
MR. HOUSEKNECHT told members this summarizes both the means and
the uncertainty associated with the estimates. The numbers in
the yellow boxes are from USGS for the onshore North Slope and
state waters. The ANWR numbers had been estimated in 1998; the
NPRA numbers in 2002; and the central North Slope, mostly state
land, in 2005. The blue boxes have MMS numbers for the Beaufort
and Chukchi areas.
MR. HOUSEKNECHT emphasized that this shows the range of
uncertainty. When he briefs Alaska's congressional delegation
about the amount of gas, he gives the low and high numbers. The
lower number represents a 95 percent probability. For instance,
he'll say there's a 95 percent chance that there is 24 Tcf of
technically recoverable natural gas in the central North Slope
area and a 5 percent chance of 45 Tcf. However, the mean of that
distribution, 33.3 Tcf, is typically used in congressional
hearings, by the media, and so on.
3:44:11 PM
MR. HOUSEKNECHT added that one awkward thing about probabilistic
distributions is that statistically it's not legal to add up what
are called the fractals and to provide a summation of that range
of uncertainty. He indicated USGS is in the process of doing
that statistically; it will be released soon. Until then,
however, the means of those distributions can be added, which he
said is a legal and rigorous statistical methodology. Those are
shown on the slide, with a subtotal for onshore and state
offshore areas of 119.15 Tcf.
MR. HOUSEKNECHT explained that MMS does its assessments a little
differently, which is why there aren't independent estimates of
non-associated and associated gas. The subtotal for the offshore
arctic is 108.19 Tcf. He said this is the U.S. Department of the
Interior's perspective on undiscovered gas resources in arctic
Alaska and the adjacent OCS. Even though economic analysis isn't
the main goal, they attempt to include an economic filter.
3:46:30 PM
MR. HOUSEKNECHT showed a slide labeled "Estimates of Gas
Accumulation Sizes" that plots numbers of gas accumulations
against the gas accumulation size class in Bcf. He said the
economics of undiscovered oil and gas are driven by how big the
accumulations are. This graph shows mean estimates and the
95 percent and 5 percent probability estimates, to give some idea
of the uncertainty. The largest accumulations of non-associated
gas in state lands are probably in the range of 1.5 to 3.0 Tcf;
at the mean, there may be 5 or 6 in the 768 Bcf to 1.5 Tcf range,
and there may be more than 15 in the 400-750 Bcf range.
3:48:10 PM
MR. HOUSEKNECHT addressed a slide labeled "Economic Analysis
Simulates Exploration and Development," indicating he'd used this
with respect to ANWR in Washington, D.C.; although he hadn't
prepared a gas example, it works the same. Explaining the
process for an economic analysis, he said the first thing they do
for state lands, for instance, is to divide the area into
subareas based on where they think accumulations are and whether
those will be mostly oil, mostly gas, or some mixture.
MR. HOUSEKNECHT said next they ask the assessment geologists to
determine what size of accumulations can be expected in each
area. Then the economist will "build" pipelines based on the
assumption that the largest accumulations closest to existing
infrastructure are discovered first. That supports construction
of a regional transportation system and development of that
accumulation, if large enough.
MR. HOUSEKNECHT concluded with the slide, saying that in turn
supports the development of satellites. An example for gas is
the larger Alpine field and newer discoveries in NPRA. As
infrastructure extends into an area, that can be used as a
jumping-off point to develop similar areas in the same fashion.
3:49:38 PM
MR. HOUSEKNECHT showed a slide labeled "Central North Slope
Economically Recoverable Gas," relating to undiscovered non-
associated natural gas resources. He noted it plots market price
and gas volume in Tcf. The vertical lines represent the estimate
of the 95 percent probability value, the mean value, and the
5 percent value.
MR. HOUSEKNECHT explained that when the economist does the
analysis, the result is a set of curves like this. The curve for
the mean suggests at about $3 per thousand cubic feet (Mcf), no
gas in this example is economically viable. Noting that this
price includes transportation to a Chicago market, he said as the
price increases, an increasing volume of gas is economically
recoverable. At $10 per Mcf, this shows 27-28 Tcf would be
economically available.
MR. HOUSEKNECHT emphasized that this simple modeling suggests
about 83 percent of the mean estimate of technically recoverable
resources close to existing infrastructure is actually
economically recoverable at $10 per Mcf. While these numbers
change as one goes farther from the infrastructure, it gives some
idea in context. Noting all the economic parameters have been
published, he offered to provide links to the online
publications.
3:51:40 PM
MR. HOUSEKNECHT turned to the next slide, "Arctic Alaska
Exploration Maturity. He said this shows a low-angle
perspective, with the most prospective area for oil and gas being
north of the Brooks Range, extending at least to the shelf edge
of the Beaufort and across all the Chukchi Sea to the Russian
maritime boundary. In this area, marked by red dots, there have
been fewer than 500 exploration wells drilled since the 1940s,
when the U.S. Navy started exploring in NPRA.
MR. HOUSEKNECHT put this into perspective using Wyoming as an
example; he noted Wyoming was shown at the same scale. He said
in arctic Alaska about 150,000 square miles are believed to be
prospective, including onshore, state waters, and OCS. In
Wyoming, where more than 19,000 exploration wells have been
drilled, about one-quarter isn't prospective because it is core
uplifts, and 75,000 square miles are prospective. As shown, the
entire state of Wyoming would fit between Prudhoe Bay and Burger,
two of the largest gas accumulations known in arctic Alaska to
date.
MR. HOUSEKNECHT said Wyoming has produced over 21 Tcf so far and
has proved reserves of at least 24 Tcf; its exploration-well
density is about 250 wells per square mile. By comparison, the
exploration-well density in arctic Alaska is about 3 per 1,000
square miles, mostly concentrated along the coast and straddling
Prudhoe Bay. Thus arctic Alaska is said to be an underexplored
frontier gas province about which there is lots to learn.
3:54:06 PM
MR. HOUSEKNECHT showed a slide labeled "Wyoming Gas Reserves &
Production History," a graph that plots Wyoming known gas
resources from 1977-2006, with cumulative production and proved
reserves. Noting a similar curve was shown earlier for the
Western Canadian sedimentary basin, he said this is public domain
data from the EIA.
MR. HOUSEKNECHT reported that in 1977 there'd been about 7.5 Tcf
produced, with about the same in reserves. Today, almost 30 Tcf
has been produced, with about 24 Tcf in reserves. In 1981, the
USGS said about 25 Tcf remained to be discovered; in 1995, after
a lot was discovered, USGS said it was 16-17 Tcf; and about two
years ago, USGS said it's about 95 Tcf. He would explain why.
3:55:20 PM
MR. HOUSEKNECHT discussed a slide labeled "'Unconventional' Gas
Resources (continuous resources)," that had USGS maps for coalbed
gas; overpressured, basin-centered gas; and gas hydrates. He
explained that before 1990-1995, Lower 48 natural gas exploration
focused on conventional resources, those occurring in straight
accumulations with water contact under the gas. However, folks
realized a lot of gas is in unconventional formations, including
shale gas, coalbed gas, and so on.
MR. HOUSEKNECHT said the industry responded by developing
technology. In concert with that, rising costs made it
economically viable to develop those unconventional resources.
Thus they've been added to the resource base, resulting in a
significant ramping up since the mid-1990s. However, Alaska is
at the low end of the curve. For arctic Alaska, it is known that
there are unconventional resources, but the first steps are just
being taken to estimate how much may be recoverable.
MR. HOUSEKNECHT indicated USGS is working with an interagency
team to try to estimate how much gas hydrate may be recoverable
in arctic Alaska. With respect to overpressured, basin-centered
gas, he noted there is good evidence that this lies behind the
foothills of the Brooks Range, where a number of wells tested
high-pressure gas, though the volume isn't known. While USGS is
just now starting to build the database to estimate
unconventional resources, it remains to be seen whether those
will be added to the reserves base.
3:58:11 PM
MR. HOUSEKNECHT paraphrased the final slide, "Summary," which had
the following points that he noted Mr. Swenson had demonstrated:
Arctic Alaska Natural Gas Resources
Arctic Alaska supercharged hydrocarbon basin grossly
under explored with respect to gas
More than 35 TFC proved reserves
Federal mean estimates of undiscovered, conventional
gas resources: 119 TCF onshore & state waters plus 108
TCF federal offshore
Huge upside potential in "unconventional" gas resources
not included in estimates
- gas hydrates
- overpressured basin-centered gas
- coalbed gas
MR. HOUSEKNECHT added that the hydrocarbon basin includes both
oil and natural gas that's grossly underexplored. The "federal
offshore" is the OCS; those are mean estimates of technically
recoverable resources. He concluded the presentation by saying
the unconventional gas resources not yet included in the
estimates remain the focus of a lot of USGS research and the
research of other federal and state agencies.
3:59:12 PM
SENATOR WIELECHOWSKI highlighted concern that there might be an
attempt to put OCS gas into the pipeline and that the state would
get no royalty or tax from it. He asked: At what point will it
be technically possible for gas from the Chukchi and Beaufort
Seas to be put into the pipeline?
MR. HOUSEKNECHT replied that is a major question, one MMS has
attempted to address. He gave his perspective that some offshore
activity would be seen now that the Chukchi lease sale has
brought in such big dollars; however, there is no clear
indication as to whether the bidders there are looking for
liquids or gases at this point.
MR. HOUSEKNECHT opined that development of natural gas resources
will occur onshore first and then migrate outward, away from
existing infrastructure, and that OCS gas is further on the
horizon than onshore and state-waters gas. He declined to
speculate on the timeframe, saying it largely depends on whether
there is a viable commercial market and whether that market and
areas to do exploration are available.
4:01:21 PM
MR. SWENSON referred to the slide shown by Mr. Houseknecht
labeled "Economic Analysis Simulates Exploration and
Development," saying it is key to this question. For any given
potential accumulation, there'll be the "risk of success," the
economics of actually getting the resource to the market and the
ability to access that.
MR. SWENSON explained that if relatively low-risk plays are close
to infrastructure so the upfront capital expenditures early on
are low, those will likely be the first to be developed, even if
they're not the largest. If there is drilling offshore in the
Beaufort or Chukchi Sea, it's hard to understand exactly how that
production would happen, especially in the Chukchi Sea, even if
were something like an LNG facility on a platform offshore that
would never actually make it to shore. He said that's something
he can't predict. But if something is economic and somebody is
doing the exploration, those will be the first plays pursued.
4:02:55 PM
SENATOR WIELECHOWSKI referred to the graph that plots market
price and gas volume. He asked whether the presenters had done
any cost analysis of the Chukchi or Beaufort areas.
MR. HOUSEKNECHT replied no, although MMS has done some work; he
offered to provide links to publications MMS had released on
that. He indicated the economic analysis he'd shown for the
state lands was USGS's first attempt ever to put an economic
filter on these undiscovered gas resources in arctic Alaska.
When they did the ANWR and NPRA assessments, they felt there
weren't enough constraints on timing of a gas line or the costs
for getting discoveries in those areas to market.
MR. HOUSEKNECHT explained that when they finished the central
North Slope assessment, however, the gas line issue was clearly
ramping up in Alaska and the Lower 48, and FERC was already
holding informational hearings; he'd testified at one. So
despite the uncertainty about access to market and other costs,
they'd felt compelled to attempt the estimate described. He
added that those graphs use 2003 dollars and costs, but after
listening to Mr. Palmer this morning, he believes the costs
probably aren't too far off.
4:05:07 PM
REPRESENTATIVE GARA noted there has been discussion about
possibly having two pipelines, a large-diameter line and a bullet
line, and so the question of how much gas the North Slope has is
increasingly important. He gave his understanding that ENSTAR
will be looking in the Foothills region over the next two summers
to assess the viability of a bullet line.
REPRESENTATIVE GARA asked Mr. Houseknecht what he believes might
be in the Foothills area in comparison with what is known at
Prudhoe Bay. Saying he has heard generally from DNR folks that
it might be more difficult to retrieve gas if it's there, he also
asked why that is.
MR. HOUSEKNECHT referred to the slide labeled "Known Gas
Accumulations in Arctic Alaska" and replied that for the onshore
area, the associated gas is generally in the northern part, the
coastal plain and state waters where it occurs in association
with liquid oil and condensate. The non-associated gas is
primarily in the Foothills. As USGS sees it, an area in the
intermediate part of the Slope will have a mixture of both.
Probably the best example is the gas trend that includes the
Gubik gas field and the Umiat oil field.
MR. HOUSEKNECHT added that, as seen from Prudhoe Bay, Point
Thomson, and so on, the associated gas accumulations on the
Barrow Arch perhaps have the potential to be larger because the
reservoirs are of better quality. The structures have more
integrity in terms of not being broken up. As one moves to the
Foothills to the south, there is a greater likelihood that
accumulations are smaller, but there are likely to be more of
them. He surmised that if this geology were in the Lower 48, it
would have been thoroughly explored and producing gas for many
decades.
4:08:21 PM
MR. SWENSON discussed why it would be harder to produce gas from
Foothills-type accumulations. He noted that an earlier slide
showed the depth of burial of the rocks for a gas province,
saying it was much deeper and hotter. That also affects the
reservoir quality, which in the Foothills is a challenge because
of the size of the pore spaces and how well those fit together.
The permeability and ability to produce that into a well bore can
be challenging. An example is the Kavik field. He surmised that
this is likely where the comment had come from.
4:09:05 PM
SENATOR STEDMAN requested comment on the Yukon-Kuskokwim delta
potential and whether that has been reviewed. He also asked
whether any exploratory work has been done in Southeast Alaska,
where some areas look similar to Cook Inlet on a surface map.
MR. SWENSON addressed the Yukon-Kuskokwim delta. He agreed with
Mr. Houseknecht's suggestion that if Alaska's numerous
sedimentary basins were in the Lower 48, there would have been
significantly more exploration. He said there are wells in most
of the basins, with more information from some than others.
MR. SWENSON explained that the primary difference between here
and the other basins is that most of the others are Tertiary in
age and don't have the same supercharged nature. Often, the gas
in interior basins is related specifically to coals; an example
is Cook Inlet, where 90 percent of the gas produced has been
biogenic, having migrated from the coal. He emphasized that it's
not coalbed methane, but is biogenic.
MR. SWENSON said for other basins like the Yukon-Kuskokwim or any
of the Bering Sea basins, a number of wells were drilled in the
1980s when the industry got together. There are snippets of
information, but many don't have the same source rock potential.
As economies change, though, there could be additional
exploration. When there is infrastructure in the interior parts
like the Nenana or Susitna basin along the Railbelt, there'll be
exploration. He added that with the Division of Oil & Gas
exploration license program, a fair amount of exploration has
been ongoing in those other basins.
4:11:24 PM
REPRESENTATIVE SAMUELS told members he'd recently spoken with
folks who said methane hydrate research is further along than
some might think. He requested comment on the monetization or
recovery of gas hydrates.
MR. HOUSEKNECHT indicated USGS is participating in a
collaborative research effort and had an integral part in both
the Mallik well drilled on the Mackenzie delta a few years ago
and the Mount Elbert well drilled on the North Slope a year ago.
His group is in the process of making its first estimate of how
much gas may be technically recoverable, and he expects that to
be released within three months or so. The next step will be to
determine how much is economically viable, which is still an area
of active research.
MR. HOUSEKNECHT said there is no question that hydrates have a
very large potential to add to a reserves base, as do basin-
centered gases. The coalbed gases probably would come in third
among those three unconventional types, but one estimate has
already been made from coalbed gases in northern Alaska, with a
mean estimate of as much as 18 Tcf; this data is available in a
published factsheet. He said more is being learned by the day,
week, and month. Probably within relatively few years there'll
be a much better estimate of what's economically recoverable.
4:13:52 PM
SENATOR DYSON told members he's uncomfortable about talk of a
bullet line while so much of the Cook Inlet basin is unexplored
for gas. He asked what the broad understanding is of what
recoverable reserves may be there.
MR. HOUSEKNECHT answered that the last published USGS estimate
was in 1995 and thus is badly out of date. To his recollection,
it was 2 Tcf for undiscovered resources, which he believes is
conservative. They're working on a new estimate that may be
completed in about 18 months. Based on information they
currently see, he opined that the number will rise significantly;
he declined to quantify that.
MR. SWENSON added that the National Energy Technology Laboratory
did a study on that and used 17 Tcf as the resource for all of
Cook Inlet and the Shelikof Strait areas. He noted the ability
to do that is based on the knowledge and data available; in some
areas of Cook Inlet, it's relatively limited, but that's
increasing in a number of cases.
SENATOR DYSON remarked that some folks who work for the Division
of Oil & Gas and some companies that have been out there think
17 Tcf may be in the ballpark. He commended the efforts.
4:16:04 PM
REPRESENTATIVE KELLY observed that the presenters and TransCanada
had given easy-to-understand comparisons with Wyoming and parts
of Canada. He asked what similar comparisons would look like for
oil, both on land and in state waters.
MR. HOUSEKNECHT answered that the paper he'd referred to that is
available on the Web is a summary for arctic Alaska of both oil
and gas resources that are undiscovered. Indicating he was
reading from it, he said the estimated total for liquids onshore
and beneath state waters for arctic Alaska, including crude oil
and natural gas liquids (NGLs), is 27 billion barrels at the
mean. That is almost equally divided between NPRA and the ANWR
coastal plain, with a relatively smaller number for the central
North Slope because it has been much more intensely explored
already, having been open for business several decades.
MR. HOUSEKNECHT further reported that MMS estimates about
24 billion barrels recoverable offshore - about 15 billion in the
Chukchi area and 8 billion in the Beaufort area. If the USGS
estimates he'd just cited for onshore and state waters are added
to the MMS estimates for the OCS, the sum that remains to be
discovered is a little more than 50 billion barrels.
MR. HOUSEKNECHT proposed looking at an example from the North
Slope, where the Alpine discovery was the largest onshore
discovery in North America in the last 25 years. This
serendipitous discovery occurred when the company that drilled
the well had a different primary objective. He said the lesson
learned in both oil and gas basins is that the more exploration
one does, the more one tends to find.
4:19:21 PM
SENATOR THOMAS asked whether the information on the 500
exploratory wells drilled since the 1940s is available through
USGS or requires some process to obtain.
MR. HOUSEKNECHT replied that most of the information is in the
public domain and is mostly available through the Alaska Oil and
Gas Conservation Commission (AOGCC); for some, especially for
NPRA, USGS maintains an active archive. Some proprietary wells
have had that status as long as 30 years, and even USGS doesn't
have access to those. Among the 500 or so exploration wells, he
estimated information is available for probably 95-97 percent.
SENATOR THOMAS asked what determines whether a well is
proprietary.
MR. HOUSEKNECHT deferred to Kevin Banks of the Division of Oil &
Gas, but noted that the answer depends on whether the wells are
drilled on state leases, Native lands, or federal leases. All
three have different regulations controlling the release of
results. Also, companies can petition those lease owners to hold
the wells proprietary. So there isn't a universal rule for
northern Alaska.
4:21:21 PM
REPRESENTATIVE CHENAULT thanked the presenters for the
information, but said he'd be more interested in hearing from
AOGCC about gas takeoff at Prudhoe Bay, since he'd heard Point
Thomson isn't needed now to build a gas pipeline. He asked that
AOGCC members be made available as well.
CHAIR HUGGINS concurred, indicating he would work on that. He
thanked the presenters. Both SB 3001 and HB 3001 were held over.
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