Legislature(2007 - 2008)ANCHORAGE
06/18/2008 09:00 AM Senate SENATE SPECIAL COMMITTEE ON ENERGY
| Audio | Topic |
|---|---|
| Start | |
| SB3001|| HB3001 | |
| Net Present Value - Black & Veatch | |
| Roundtable Discussion Including Producers | |
| Public Testimony | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| + | SB3001 | TELECONFERENCED | |
ALASKA STATE LEGISLATURE
JOINT MEETING
SENATE SPECIAL COMMITTEE ON ENERGY
HOUSE RULES STANDING COMMITTEE
Anchorage, Alaska
June 18, 2008
9:05 a.m.
MEMBERS PRESENT
SENATE SPECIAL COMMITTEE ON ENERGY
Senator Charlie Huggins, Chair
Senator Bert Stedman, Vice Chair
Senator Lyman Hoffman
Senator Lesil McGuire
Senator Gary Stevens
Senator Joe Thomas
Senator Bill Wielechowski
Senator Fred Dyson
Senator Thomas Wagoner
HOUSE RULES
Representative John Coghill
Representation Anna Fairclough
Representative Craig Johnson
Representative Ralph Samuels
Representative Beth Kerttula
MEMBERS ABSENT
SENATE SPECIAL COMMITTEE ON ENERGY
Senator Kim Elton
Senator Lyda Green
Senator Donald Olson
HOUSE RULES
Representative John Harris
Representative David Guttenberg
OTHER LEGISLATORS PRESENT
Senator Con Bunde
Senator Bettye Davis
Senator Johnny Ellis
Senator Hollis French
Representative Bob Buch
Representative Harry Crawford
Representative Nancy Dahlstrom
Representative Mike Doogan
Representative Les Gara
Representative Berta Gardner
Representative Carl Gatto
Representative Mike Hawker
Representative Lindsey Holmes
Representative Reggie Joule
Representative Wes Keller
Representative Kevin Meyer
Representative Mark Neuman
Representative Kurt Olson
Representative Jay Ramras
Representative Bill Stoltze
Representative Bob Lynn
Representative Max Gruenberg
COMMITTEE CALENDAR
SENATE BILL NO. 3001
"An Act approving issuance of a license by the commissioner of
revenue and the commissioner of natural resources to TransCanada
Alaska Company, LLC and Foothills Pipe Lines Ltd., jointly as
licensee, under the Alaska Gasline Inducement Act; and providing
for an effective date."
HEARD AND HELD
HOUSE BILL NO. 3001
"An Act approving issuance of a license by the commissioner of
revenue and the commissioner of natural resources to TransCanada
Alaska Company, LLC and Foothills Pipe Lines Ltd., jointly as
licensee, under the Alaska Gasline Inducement Act; and providing
for an effective date."
HEARD AND HELD
PREVIOUS COMMITTEE ACTION
BILL: SB3001
SHORT TITLE: APPROVING AGIA LICENSE
SPONSOR(s): RULES BY REQUEST OF THE GOVERNOR
06/03/08 (S) READ THE FIRST TIME - REFERRALS
06/03/08 (S) ENR
06/03/08 (S) REPORT ON FINDINGS AND DETERMINATION
06/04/08 (S) ENR AT 10:00 AM TERRY MILLER GYM
06/04/08 (S) Heard & Held
06/04/08 (S) MINUTE(ENR)
06/05/08 (S) ENR AT 9:00 AM TERRY MILLER GYM
06/05/08 (S) Heard & Held
06/05/08 (S) MINUTE(ENR)
06/06/08 (S) ENR AT 10:00 AM TERRY MILLER GYM
06/06/08 (S) Heard & Held
06/06/08 (S) MINUTE(ENR)
06/07/08 (S) ENR AT 10:00 AM TERRY MILLER GYM
06/07/08 (S) Heard & Held
06/07/08 (S) MINUTE(ENR)
06/08/08 (S) ENR AT 1:00 PM TERRY MILLER GYM
06/08/08 (S) Heard & Held
06/08/08 (S) MINUTE(ENR)
06/09/08 (S) ENR AT 10:00 AM TERRY MILLER GYM
06/09/08 (S) Heard & Held
06/09/08 (S) MINUTE(ENR)
06/10/08 (S) ENR AT 10:00 AM TERRY MILLER GYM
06/10/08 (S) Heard & Held
06/10/08 (S) MINUTE(ENR)
06/12/08 (S) ENR AT 10:00 AM FBX Carlson Center
06/12/08 (S) Heard & Held
06/12/08 (S) MINUTE(ENR)
06/13/08 (S) ENR AT 10:00 AM FBX Carlson Center
06/13/08 (S) Heard & Held
06/13/08 (S) MINUTE(ENR)
06/14/08 (S) ENR AT 10:00 AM FBX Carlson Center
06/14/08 (S) Heard & Held
06/14/08 (S) MINUTE(ENR)
06/16/08 (S) ENR AT 9:00 AM ANCHORAGE
06/16/08 (S) Heard & Held
06/16/08 (S) MINUTE(ENR)
06/17/08 (S) ENR AT 9:00 AM ANCHORAGE
06/17/08 (S) Heard & Held
06/17/08 (S) MINUTE(ENR)
06/18/08 (S) ENR AT 9:00 AM ANCHORAGE
BILL: HB3001
SHORT TITLE: APPROVING AGIA LICENSE
SPONSOR(s): RULES BY REQUEST OF THE GOVERNOR
06/03/08 (H) READ THE FIRST TIME - REFERRALS
06/03/08 (H) RLS
06/03/08 (H) WRITTEN FINDINGS & DETERMINATION
06/04/08 (H) RLS AT 9:00 AM CAPITOL 120
06/04/08 (H) Heard & Held; Subcommittee Assigned
06/04/08 (H) MINUTE(RLS)
06/04/08 (H) RLS AT 10:00 AM TERRY MILLER GYM
06/04/08 (H) Heard & Held
06/04/08 (H) MINUTE(RLS)
06/05/08 (H) RLS AT 9:00 AM TERRY MILLER GYM
06/05/08 (H) Heard & Held
06/05/08 (H) MINUTE(RLS)
06/06/08 (H) RLS AT 10:00 AM TERRY MILLER GYM
06/06/08 (H) Heard & Held
06/06/08 (H) MINUTE(RLS)
06/07/08 (H) RLS AT 10:00 AM TERRY MILLER GYM
06/07/08 (H) Heard & Held
06/07/08 (H) MINUTE(RLS)
06/08/08 (H) RLS AT 1:00 PM TERRY MILLER GYM
06/08/08 (H) Heard & Held
06/08/08 (H) MINUTE(RLS)
06/09/08 (H) RLS AT 10:00 AM TERRY MILLER GYM
06/09/08 (H) Heard & Held
06/09/08 (H) MINUTE(RLS)
06/10/08 (H) RLS AT 10:00 AM TERRY MILLER GYM
06/10/08 (H) Heard & Held
06/10/08 (H) MINUTE(RLS)
06/12/08 (H) RLS AT 10:00 AM FBX CARLSON CENTER
06/12/08 (H) Heard & Held
06/12/08 (H) MINUTE(RLS)
06/13/08 (H) RLS AT 10:00 AM FBX CARLSON CENTER
06/13/08 (H) Heard & Held
06/13/08 (H) MINUTE(RLS)
06/14/08 (H) RLS AT 10:00 AM FBX CARLSON CENTER
06/14/08 (H) Heard & Held
06/14/08 (H) MINUTE(RLS)
06/16/08 (H) RLS AT 9:00 AM ANCHORAGE
06/16/08 (H) Heard & Held
06/16/08 (H) MINUTE(RLS)
06/17/08 (H) RLS AT 9:00 AM ANCHORAGE
06/17/08 (H) Heard & Held
06/17/08 (H) MINUTE(RLS)
06/18/08 (H) RLS AT 9:00 AM ANCHORAGE
WITNESS REGISTER
GOVERNOR WALTER J. HICKEL [former governor]
POSITION STATEMENT: Opposed exclusive license to TransCanada
under SB 3001 and HB 3001; emphasized gas to Alaskans.
PATRICK GALVIN, Commissioner
Department of Revenue
Juneau, AK
POSITION STATEMENT: Participated during the net present value
(NPV) portion of the hearing on SB 3001 and HB 3001.
SCOTT SMITH, Vice President
Black & Veatch Corp.
POSITION STATEMENT: Gave PowerPoint presentation on NPV and
answered questions during hearing on SB 3001 and HB 3001.
DEEPA PODUVAL
Black & Veatch Corp.
POSITION STATEMENT: Assisted with PowerPoint presentation and
answered questions during hearing on SB 3001 and HB 3001.
MIKE ELENBAAS
Black & Veatch Corp.
POSITION STATEMENT: Assisted with PowerPoint presentation and
answered questions during hearing on SB 3001 and HB 3001.
NANETTE THOMPSON, Unit/Tech Support
Division of Oil & Gas
Department of Natural Resources
Anchorage, AK
POSITION STATEMENT: Participated in roundtable discussion
during hearing on SB 3001 and HB 3001.
JULIE HOULE, Section Chief
Resource Evaluation
Division of Oil & Gas
Department of Natural Resources
Anchorage, AK
POSITION STATEMENT: Participated in roundtable discussion
during hearing on SB 3001 and HB 3001.
CATHY FOERSTER, Commissioner
Alaska Oil and Gas Conservation Commission (AOGCC)
Department of Administration
Anchorage, AK
POSITION STATEMENT: Participated in roundtable discussion
during hearing on SB 3001 and HB 3001.
CRAIG HAYMES, Alaska Production Manager
ExxonMobil
POSITION STATEMENT: Participated in roundtable discussion
during hearing on SB 3001 and HB 3001.
ANIL CHOPRA, Ph.D., President
PetroTel Inc.
Dallas, TX
POSITION STATEMENT: Participated in roundtable discussion
during hearing on SB 3001 and HB 3001.
JOHN ZAGER, General Manager
Chevron - Alaska Area
POSITION STATEMENT: Participated in roundtable discussion
during hearing on SB 3001 and HB 3001.
CHARLES McKEE
Anchorage, AK
POSITION STATEMENT: Testified during public hearing on SB 3001
and HB 3001.
PAUL LAIRD, General Manager
Alaska Support Industry Alliance
POSITION STATEMENT: Voiced opposition to AGIA license under
SB 3001 and HB 3001 as well as support for Denali project.
JERRY McCUTCHEON
Anchorage, AK
POSITION STATEMENT: Spoke against AGIA and Denali project
during public hearing on SB 3001 and HB 3001.
MATTHEW FAGNANI
Anchorage, AK
POSITION STATEMENT: Opposed approving a license under SB 3001
and HB 3001.
MAYNARD TAPP
Anchorage, AK
POSITION STATEMENT: Opposed the AGIA proposal under SB 3001 and
HB 3001 and requested support for the producers and Denali.
MIKE ROGERS
Anchorage, AK
POSITION STATEMENT: Spoke against AGIA and Denali project
during hearing on SB 3001 and HB 3001, saying if a license is
approved, it should be amended.
BARBARA BACHMEIER
Anchorage, AK
POSITION STATEMENT: Highlighted jobs and opposed AGIA,
TransCanada, and Denali during hearing on SB 3001 and HB 3001.
JOHN WOOD
Willow, AK
POSITION STATEMENT: Testified on SB 3001 and HB 3001, saying he
doesn't favor the AGIA process except as a negotiation tool.
KATE TROLL, Executive Director
Alaska Conservation Alliance
Anchorage, AK
POSITION STATEMENT: Supported AGIA proposal under SB 3001 and
HB 3001, but expressed some concerns.
CAMILLE CONTE
Anchorage, AK
POSITION STATEMENT: Suggested saying no to TransCanada and yes
to a line to Valdez during hearing on SB 3001 and HB 3001.
BRIAN DAVIES
Anchorage, AK
POSITION STATEMENT: Opposed granting license under SB 3001 and
HB 3001 because it might prevent parties from coming together.
RON AKSAMIT
Anchorage, AK
POSITION STATEMENT: Supported approving license under SB 3001
and HB 3001 to keep TransCanada in the game.
TOM LAKOSH
Anchorage, AK
POSITION STATEMENT: Voiced support for SB 3001 and HB 3001 and
for developing Point Thomson.
SHANNYN MOORE
Anchorage, AK
POSITION STATEMENT: Testified on SB 3001 and HB 3001, saying
AGIA should be amended.
RON ALLEVA
Anchorage, AK
POSITION STATEMENT: Testified during hearing on SB 3001 and
HB 3001, saying he is against AGIA and in favor of Denali.
CHRISTOPHER CONSTANT
Anchorage, AK
POSITION STATEMENT: During hearing on SB 3001 and HB 3001,
encouraged amending AGIA to assure jobs for Alaskans.
ACTION NARRATIVE
CHAIR CHARLIE HUGGINS called the joint meeting of the Senate
Special Committee on Energy and the House Rules Standing
Committee to order at 9:05:49 AM.
SB3001-APPROVING AGIA LICENSE
HB3001-APPROVING AGIA LICENSE
9:05:49 AM
CHAIR HUGGINS brought SB 3001 and HB 3001 before the committees.
He welcomed former Governor Walter J. Hickel and referenced that
there would be discussion of net present value (NPV) by the
administration and Black & Veatch. A roundtable discussion to
answer questions about Point Thomson was scheduled later, and
public testimony was to begin at 6 p.m.
9:07:04 AM
GOVERNOR WALTER J. HICKEL testified as follows:
Let me begin with my bottom line. The State of Alaska
represents all of our people, the owners of the
resources on the state lands at the North Slope, and
... should build the Alaska natural gas pipeline.
We should hire a pipeline company, perhaps
TransCanada, and build it and own it. That's the only
way we can keep control of this resource that is worth
untold billions. Anytime you yield control of public
assets to a private company, you have to be content to
sit and wait, because they are in control. And if you
yield control to foreign governments and their
regulatory agencies, just move to the back of the bus.
Before I expand on this, I want to salute you,
Mr. Chairman, and your colleagues for holding these
hearings. The issue is how to achieve maximum benefit
from North Slope natural gas resources. That's your
assignment under the constitution.
As citizens of our owner state, all Alaskans also have
this obligation to follow this issue and make their
views known. Billions upon billions of dollars are at
stake. We need to get Alaska gas to Alaskans, and to
make that gas affordable we need to access the world's
markets. That means an all-Alaska gasline to Valdez
and LNG exports to the world. Our neighbor nations on
the Pacific Rim are ready to pay twice as much as
Alberta or Chicago. This week. Japan is paying over
$20.00 per Mcf. They are paying $11.69 in Alberta.
The last time I saw you, Mr. Chairman, was in Beijing,
where we met with leaders in China oil and gas. That
was an important trip. We must understand the world,
and we need vision. Vision is the key to a pioneering
country. And to me the vision is clear and is based
on reality.
For 50 years of statehood, Alaska's political ties
have been with America - and thank God for that - but
our economic ties are with Asia. We offered our
timber, coal, LNG to the South 48, but we couldn't get
them past Seattle. So we made friends and contacts in
Japan and Korea, and we built our young economy based
on those relationships. In 1969, we pioneered the
first LNG shipments to Japan from anywhere, shipments
that continue from Kenai today.
I just say, wake up, America. It's a world economy.
Check the labels on your T-shirt and names on your TV
and automobiles. Chances are, they weren't made in
America. Our national economy - that means our
standard of living - depends on our productivity and
our ability to compete. We won't survive by just
playing the stock market. There is no wealth without
production.
I commend Governor Sarah Palin for introducing a wide-
open, transparent process on the gasline issue. For
years, the North Slope [producers] claimed ... that
Alaska natural gas was not economic. They said there
was no market. But AGIA produced five eager
applicants, and the producers changed their tune.
They cobbled together yet another public relations
campaign about a gasline project that I promise you
will never happen.
We've seen this before, over and over. And they still
badmouth LNG. You know, ladies and gentlemen, if LNG
is so bad, why are they heavily involved?
ConocoPhillips has invested $60 billion in the largest
LNG [liquefaction] plant in the world in Qatar; BP has
an LNG project in Tangguh, Indonesia; and Exxon has a
new project in Papua New Guinea. And that's only part
of the story.
Ladies and gentlemen, they don't oppose LNG. They
oppose Alaska's LNG because our LNG competes with
their LNG. And the truth is, LNG is changing the
world. You can't build a pipeline to Australia,
Japan, India, or China.
9:12:27 AM
GOVERNOR HICKEL continued:
It's no secret that I'm opposed to giving the
exclusive license to TransCanada. The public thinks
that they plan to ship North Slope gas to America.
But their goal, and they don't deny it, is to use most
of our gas to heat the Alberta tar sands to create
synthetic oil. And they face obstacles and delays
beyond our control. And the key word is "control."
They admit that the Mackenzie River pipeline, mired in
problems, will go ahead of an Alaska gasline - just
more delay. The Canadian Supreme Court has ruled, and
rightfully so, that the Canadian government must
consult and accommodate even those First Nations that
have not resolved their land claims when it comes to
issues such as a pipeline that impact their
traditional territory - more delay. TransCanada
cannot build a 4.5 billion-cubic-feet-per-day pipeline
without gas from the producers - more delay.
And producers' gas carries the bombshell of demands
for "fiscal certainty," and you know what that means.
What's more, without even so much as a mention,
TransCanada plans to export millions of barrels of
valuable North Slope gas liquids to Alberta. Those
gas liquids should stay in Alaska. Billions of
dollars of state revenue and hundreds of value-added
jobs for Alaskans for decades rest on this great
issue.
There is no reason to hold up the Alaska LNG line
while we wait for TransCanada to sort out their
problems in Canada. Last week, Commissioner Pat
Galvin and others from the Palin gasline team informed
me that TransCanada is prepared to hold a simultaneous
open season. This means that those who control North
Slope gas will be invited to reserve space at the same
time in either a Canadian pipeline or an all-Alaska
pipeline to Valdez.
If the market wants to ship LNG first, TransCanada
will build the all-Alaska line first. They didn't
mention, by the way, [to] which route the state will
dedicate its gas. But I was somewhat encouraged by
what ... the commissioner said, only to learn this
week that TransCanada has refused to clarify any such
commitment to hold a simultaneous open season.
9:15:33 AM
GOVERNOR HICKEL continued:
This illustrates and underlines my message today. If
TransCanada is granted a license by the state, the
state will lose control. Alaska appears to be caught
between the producers on one side and a bad deal on
the other. So what do we do? Fortunately, there's
another option.
Ever since the people of Alaska voted six years ago in
favor of an all-Alaska gasline, they have been
waiting. And now, with a crisis in Alaska fuel and
energy costs, they are getting frustrated. How much
longer can we ask them to wait?
In Fairbanks last week, you heard loud and clear that
we need Alaska's gas for Alaska's people now. And the
crisis in rural Alaska is worse. But it's no good to
have the Alaska gas if it comes very sky-high. The
way to lower the price is through volume. We must
move our gas in a pipeline big enough to serve large
markets. The best way to do that is build an all-
Alaska gasline to Valdez. And the state should build
it and really should own it.
Without the Canadian government or FERC making us jump
through a thousand hoops, we could build that gasline
in five or six years to Alaskans. And the ... entire
project can [be] completed soon thereafter. If you
hold a hearing on how the state can build and own our
own gasline, please ask me to come back. It's not
rocket science.
So I urge you to deny that TransCanada plan. If you
don't, we will lose control of our gas and Alaska will
be locked into the market at the end of that pipeline
in Alberta.
As we meet here, there is a rush going on for ... new
gas plays in Pennsylvania, West Virginia, Texas, and
the Rockies. Alaska gas in the South 48 will face
severe competition in a few years. That means that
our gas, instead of serving America as Governor Palin
sincerely hopes it will, will stay in Alberta and be
used to heat the tar sands.
So ... let's take the faster, better, and more
beneficial alternative. Let's build the Alaska
gasline ourselves. With LNG, we will serve the world.
We will move our [gas] to the highest and best
markets, and we will keep the jobs ... here at home.
That's "maximum benefit" for our people. And that's
your responsibility and your opportunity, and the
mission of this generation. God bless you and thank
you a lot.
9:18:45 AM
SENATOR DYSON expressed appreciation for the perspective. He
reported that when he and Senator Therriault met with Bud
Albright of the U.S. Department of Energy (DOE) a few months
ago, they raised the question of getting a liquefied natural gas
(LNG) export license; Mr. Albright and his staff seemed to think
that while it might make economic sense, it would be difficult
politically with the national mood and this Congress. Recalling
a similar situation regarding oil when he worked for BP in the
early 1970s, Senator Dyson asked Governor Hickel what his sense
is of Alaska's ability to get such a license now.
GOVERNOR HICKEL replied he believes it is absolutely necessary
and totally available. He emphasized that Alaska should lead in
this regard, rather than getting led in the wrong direction.
SENATOR DYSON said he wasn't quite as confident about the
outcome nationally. He asked Governor Hickel what he thought
about a strategy such as building a facility and letting the
market determine where the gas goes.
GOVERNOR HICKEL answered that the market is there. Meeting with
top people in China a month ago, he was told they have two
thousand billion dollars and are willing to help build a
pipeline; they don't want to own it, but want a guarantee that
they can buy some of the LNG. He stressed that the market isn't
the Lower 48, where there is lots of competition, but is China,
India, Japan, Hawaii, and so on. It won't happen without LNG,
he said, which is changing the world.
SENATOR DYSON asked: Is the lack of a great market for Alaska's
natural gas on the West Coast because of the existing supply and
because regasification permitting in that area is difficult?
GOVERNOR HICKEL affirmed that, adding that the best way to get
it from the arctic to a world market is by sea from Valdez.
SENATOR DYSON told Governor Hickel that if he can influence the
federal government to allow exploration in the eastern portion
of the Cook Inlet basin on federal land, he'd appreciate it.
CHAIR HUGGINS thanked Governor Hickel and asked that he continue
to provide counsel.
The committees took an at-ease from 9:26:42 AM to 9:47:37 AM.
^Net Present Value - Black & Veatch
PATRICK GALVIN, Commissioner, Department of Revenue (DOR), began
by saying today's presentations provide perspective on how the
evaluation criteria fit into the decision legislators must make.
The economic analysis comes out of the Alaska Gasline Inducement
Act (AGIA) statute. For any AGIA license application, the state
is obligated to review the project's NPV to the state. While
the primary purpose is to identify what maximizes the economics
to the state, it also allows comparisons among projects.
COMMISSIONER GALVIN said more important now is how the
economic/NPV analysis factors into the likelihood of success.
Much of what has been presented in Juneau and Anchorage looked
at risk sensitivities to projected factors such as gas price,
cost, and available gas. Today, the sensitivity analysis would
be shown in the context of the likelihood of success even under
worst-case scenarios. Black & Veatch had been asked to focus on
low-gas scenarios, for instance.
COMMISSIONER GALVIN emphasized that all of the runs were done
assuming no expansion in the 25 years. Whereas yesterday there
was discussion of when Point Thomson gas might be available,
today's analysis assumes if it isn't available at the beginning,
it won't come in at all, an extremely conservative assumption.
This analysis doesn't try to identify the optimal pipeline. He
turned the presentation over to Black & Veatch.
9:52:42 AM
CHAIR HUGGINS asked why AGIA says "sufficiently maximize" rather
than "maximize" and whether that can be done.
COMMISSIONER GALVIN replied that he didn't recall much
discussion of that qualifier. In other contexts, he has seen
that the idea of maximizing benefits can be taken to an
impossible extreme; thus a qualifier often allows a reasonable
case. He indicated the administration took its obligation under
AGIA in this respect to be the obligation to identify and look
at alternatives and then decide whether going forward with the
license would be better than those alternatives.
CHAIR HUGGINS, in reply to Representative Gardner, deferred
response to Governor Hickel's testimony until later.
9:56:05 AM
SCOTT SMITH, Vice President, Black & Veatch Corp., gave his
background, noting that Black & Veatch focuses on the energy
sector worldwide. As part of the consulting organization that
focuses primarily on the energy sector in North America, he
leads the market analysis portion, dealing with markets;
pricing; and valuation of assets, midstream assets in
particular. With Black & Veatch and its predecessor consulting
firms about 10 years, he worked for upstream exploration and
production (E&P) and marketing companies in the prior 15 years.
MR. SMITH began a PowerPoint presentation titled "Overview of
the Methodology Utilized to Determine the Net Present Value to
Stakeholders"; a hard copy was provided. He addressed slide 2,
which said:
What are the key factors to determine NPV?
1. An estimate of cash flows, net, by year:
- Includes capital expenditures, operating expenses
and revenue
2. An assumption about the discount rate.
He added that variations in capital spending, pricing, tax
revenue splits, and so forth create different cash flow splits
for parties over the years. He turned to slide 3, which had the
following points and a footnote citing Section 4.1 of the "NPV
Report" for discussion of discount rates in the NPV analysis:
A discount rate is needed to calculate NPV for each
project stakeholder
Discount rate is a price. It is the price associated
with waiting to get a benefit, versus getting a
benefit today.
Many factors can influence the price of waiting
(discount rate). These include: alternative
investment returns, [one's] cost of capital, general
inflation conditions, concern for the well being of
future generations
Discount rates vary by stakeholder:
- State - 5% (Sensitivities of 0%, 2%, 6%, 8% were
also used)
- TransCanada - 8.8%
- Producers - 10% and 15%
MR. SMITH suggested thinking of the discount rate as the amount
someone is willing to take today instead of waiting to receive
dollars over time in an annuity-type structure, acknowledging a
dollar is worth more today. Because the producers, the state,
and TransCanada are all different, the assumptions used
different rates for each, for the reasons shown.
MR. SMITH explained that AGIA requires several discount rate
assumptions to be used to test the sensitivity of the NPV
benefits to the state. While a rational argument could be made
that 5 percent may be too low - since alternate investments such
as the permanent fund might yield 8 percent - 5 percent was
settled on for this analysis, partly because it is consistent
with earlier analyses.
MR. SMITH indicated the nearly 9 percent used for TransCanada is
a blended rate based on TransCanada's cost of equity, the return
on equity expected for the pipeline coupled with debt costs for
the project. And while 15 percent is more typically used by the
producers for evaluating projects, a lower rate of 10 percent
was also run to understand the sensitivity for this particular
project. There isn't much capital investment required to get
Prudhoe Bay into production, he noted, although shipping
commitments must be signed, assuming it is a third-party pipe.
10:03:30 AM
MR. SMITH added that by being consistent, this allows
comparisons of a 4.5 billion cubic feet a day (Bcf/d) pipeline
versus 4.0 Bcf/d for the state. If looking at different pipe
assumptions, it allows understanding how the NPV would vary.
However, it makes it harder to compare the state and producer
NPVs because of the different discount rates. Thus when
comparing among all entities, cash flows provide a better
comparison than NPVs.
The committees took a brief at-ease at 10:06:03 AM.
MR. SMITH addressed slides 4-6, illustrating the decreased value
of cash flows over time due to inflation. Highlighting slide 5,
"Net Present Value (NPV) calculates how much a stream of future
cash flows are worth today," he said at a discount rate of
5 percent, $100 today will be worth half that much in 20 years
from an NPV standpoint. As shown on slide 6, $245 billion of
undiscounted cash flow for a 4.0 Bcf/d project for the state is
equivalent to a $61 billion NPV.
10:08:55 AM
MR. SMITH turned to the second presentation, "Net Present Value
(NPV) Analysis"; a hard copy was provided. Noting that AGIA
requires an analysis of the NPV benefits to the state and
arguably the different stakeholders, as well as the likelihood
of success, he explained that Black & Veatch was asked to run
calculations under different scenarios.
MR. SMITH explained the process. He said first they interfaced
with Goldman Sachs for inputs into the model, worked with the
technical team to understand cost estimates, and then aggregated
the information into the economic analysis. They used prices
and costs to figure cash flows and then converted that into NPV.
Then they did scenario or risk analysis, for instance, what
happens to cash flows and NPV benefits to the state and other
stakeholders if production or prices don't match the estimates.
MR. SMITH discussed slide 2 of the second presentation, which
had the following points:
Project Economics are Robust
NPV for Key Stakeholders Indicates Positive NPV for
4.0 Bcf/d project that does not rely on Pt Thomson
NPV Results are Sensitive to Many Factors with
Commodity Prices being the Most Significant
- Producer NPV Remains Positive with Low Market Price
Assumptions
4.0 Bcf/d project has acceptable netback risks, lower
reserve risk than 4.5 Bcf/d project with Pt Thomson
gas
NPV positive across wide range of project cost
outcomes, cost escalation scenarios
Tariffs for Smaller Pipeline Configurations (4.0 &
3.5 Bcf/d) Increase by 13% to 21% Relative to the
4.5 Bcf/d Proposal Base Case
MR. SMITH elaborated. He said overall, given the base
assumptions and variations, Black & Veatch sees a robust
project. Last week in Juneau there was discussion of a
liquefied natural gas (LNG) scenario, different pipeline sizes,
and supply cases of 4.0 Bcf/d and 3.5 Bcf/d, to understand
whether the project is economic to the state, the producers, and
TransCanada.
MR. SMITH pointed out that it was found to be economic for all
scenarios looked at, with significant cash flows and NPVs. For
instance, the 4.0 Bcf/d case has a significant benefit to the
state, more than $60 billion, and sizable benefits to the
producers.
MR. SMITH added that the biggest risk is the price of gas when
it is finally sold. So scenarios included various price
assumptions, and a risk assessment was done to understand the
implications of escalation, inflation, and so on; this would be
addressed in more detail. The effort was to make it as
transparent as possible to highlight risk and benefits.
10:14:49 AM
CHAIR HUGGINS asked what is meant by "lower reserve risk" with
respect to the 4.0 Bcf/d case discussed on the slide.
MR. SMITH indicated Black & Veatch had looked at scenarios where
the pipeline is full over the entire evaluation period and then
what happens if the contract period is cut from 25 years, as
proposed by TransCanada, to 20 years. That reduces the reserves
required to fill the pipeline over time.
MR. SMITH reported that the amount of yet-to-find (YTF) gas for
the 4.5 Bcf/d case is approximately 25 percent; that includes
Point Thomson. But for a 4.0 Bcf/d project over 20 years,
without Point Thomson, the YTF gas drops to 15 percent. So
there is lower risk because of the lower volume and the shorter
contract term.
10:15:53 AM
REPRESENTATIVE SAMUELS expressed concern because this changes
two variables. He asked why that wasn't done with the 25- or
20-year term with respect to the YTF gas, as well as the
difference in the tariff without changing the length of time.
MR. SMITH replied that information in the back of the packet
details this; he also would provide further information to make
it an apples-to-apples comparison. He agreed that the base
assumption for a 4.5 Bcf/d case and a 25-year contract term
proposed by TransCanada is different from the Black & Veatch
base assumption for the 4.0 Bcf/d at 20 years.
10:17:02 AM
MR. SMITH continued with slide 2, noting Black & Veatch sees
positive NPV benefits and cash flows across different outcomes
and scenarios. Emphasizing tariff differences, he said they'd
started with a tariff around $4.70, given the technical team's
input for the 4.5 Bcf/d case. That tariff increases 13-20
percent as volumes decrease; at 3.5 Bcf/d it's about $1.00 more.
They looked at those sensitivities, cash flow differences, and
related NPV benefits. Ms. Poduval would address cash flows, NPV
projections, and the production scenarios.
10:18:08 AM
SENATOR STEDMAN asked Mr. Smith to spend a little time on price,
including historical data.
MR. SMITH directed attention to a graph for 2008-2044 labeled
"Various Price Forecasts were Considered in Analysis." The
following were depicted: Wood Mackenzie AECO forecast;
estimated Energy Information Administration (EIA) AECO Forecast;
and Black & Veatch base case, "P10," and "P90."
MR. SMITH explained that the Wood Mackenzie base case, used for
the apples-to-apples comparison across different projects, was
selected after discussion with the state. It's an independent
forecast; that independent consultancy does worldwide market
analyses and provides views to players across the world -
including the North Slope producers - on prices for oil, natural
gas, and so on. That forecast is well known and paid for. In
addition, Wood Mackenzie provides a specific forecast to AECO.
MR. SMITH noted the projected price for 2008 is around $6.00,
lower than current prices. This is a fundamental base case for
expected supply and demand. While the project must be looked at
for a 25-year period, that isn't expected to start until 2018-
2020; market prices don't go out past that, so they rely on
forecasts. The chart shows supply and demand starting off
fairly low compared with today and increasing so that by 2045
it's around $30.00.
MR. SMITH said prices over the last 3 or 4 years have been in
the $5.00 to $6.00 range. In the late 1990s and early 2000s,
prices were $2.00 to $3.00, with a gas surplus, whereas today
there is no production shut in and LNG supposedly is a new
marginal source of supply for North America. So there are
higher price expectations than historically, but the forecasts
start at a lower price point than the current market.
10:22:40 AM
SENATOR STEDMAN noted the legislature spent time looking at oil
prices and hadn't received forecasts close to what has happened.
He expressed concerned that if they go back before 2008,
forecasts won't reflect future gas prices, and that an ever
increasing price makes an NPV analysis more positive. He
requested that time be spent looking at price sensitivity if
prices stop rising so much. He also recalled that folks from
the Federal Energy Regulatory Commission (FERC) had indicated
there is a lot of momentum with respect to Lower 48 gas and LNG.
MR. SMITH replied that the end of the presentation gets into an
analysis that removes the forecasting element. Forecasts aren't
spot on. Also on the slide is an EIA forecast; these are
published annually by the U.S. Department of Energy and provided
free to the public. Black & Veatch estimated what EIA would
project for AECO prices; EIA doesn't provide projections for
Canada but provides one for Louisiana, which Black & Veatch
converted after finding that EIA forecasts had underestimated
prices over the last 15 or more years.
MR. SMITH explained, for example, that the EIA forecast doesn't
include assumptions about carbon costs and carbon emissions.
General predictions of industry consultants such as Black &
Veatch and Wood Mackenzie include a general expectation of
repercussions from environmental legislation that potentially
will push the demand for natural gas, thus pushing prices upward
because natural gas generates less carbon as a whole.
MR. SMITH, while agreeing that prices don't always behave in
this linear fashion, said Black & Veatch generally believes
prices will be higher rather than lower. In large part, this is
because of cost of finding reserves has increased substantially
over the last 5 or so years.
10:27:54 AM
SENATOR STEDMAN asked about concern about downward price
pressure because of increasing volumes from the Rockies and
Alaska.
MR. SMITH replied that he agrees there would be some impact on
prices from Alaska's gas. After looking at pricing forecasts by
Wood Mackenzie and EIA, Black & Veatch sees prices dropping
around 20 cents in North America because of that supply; it is
imbedded in these prices.
MR. SMITH turned to new supplies from the Rockies or
Pennsylvania and New York, as mentioned by Governor Hickel.
Mr. Smith said while those are new resource potential for the
Lower 48 or North America as a whole, the question is how much
they'll cost to produce. Through technology and higher prices,
these shale plays and nonconventional resources are now becoming
economic. If prices were $4.00 like 5 years ago, however, the
cost to recover them would be too high. Thus those are more
supportive to the price.
10:29:55 AM
REPRESENTATIVE BUCH gave his understanding that Henry Hub prices
were established primarily because of proximity, since 17
pipelines crossed at that point. Referring to Senator Stedman's
question about price, he asked: If we continue in the same
vein, where will we be with the AECO Hub market? Will it change
how natural gas is priced if Alaska starts bringing in a
substantial volume across Canada to the Lower 48?
MR. SMITH replied that the New York Mercantile Exchange (NYMEX)
uses Henry Hub in Louisiana as a delivery mechanism for
contracts being bought and sold, so it tends to be a well
referenced point for pricing; it's prices in southern Louisiana
and nowhere else. Although EIA doesn't do it explicitly, each
forecast has to factor in increased gas in a particular part of
the pipeline grid and how that price relates to Henry Hub.
MR. SMITH provided an example of what was assumed. Noting the
AECO price is the price delivered into Canada, he said Wood
Mackenzie believes by the late 2025-2030 time period, prices
will be higher in Canada than Louisiana; this relates to
expectations for LNG import into Louisiana and declines in
Western Canadian production.
MR. SMITH said looking at the EIA forecast, however, Black &
Veatch assumed a flat discount for AECO prices because that's
traditionally been seen there and also for consistency with how
TransCanada evaluated its application; thus 75 cents was
deducted when comparing that with Louisiana prices.
MR. SMITH relayed his opinion and that of Black & Veatch, that
they expect prices in Canada to be slightly lower than in
southern Louisiana, more in the traditional range of 50 cents to
a dollar, depending on the time period. Referring to Henry Hub,
he emphasized factoring in the supply-and-demand drivers in
Canada when the gas is delivered, to ensure the price is
appropriate for that point and to value the economics to that.
MR. SMITH added that Black & Veatch does factor in such
elements, recognizing there are different and distinct markets
and trying to understand the pricing pressures in Canada as
these fundamentals change, including gas from Alaska showing up
if a pipeline is built in the 2020 timeframe.
10:34:32 AM
REPRESENTATIVE NEUMAN surmised that the demand wouldn't be as
steep as shown here in the outer years because of the growing
global demand for renewable resources such as solar energy, wind
power, hydroelectric power, and so on. He asked how much of
that is factored into the price forecasts.
MR. SMITH explained that demand has three main components.
First, the core North American demand - residential and
commercial heating of spaces and water - traditionally has been
population-driven and slow growing, about 1 percent a year.
Second, industrial demand has been flat or declining slightly
because of high prices since 2000, when there was lots of
ammonia production for fertilizer by companies like Agrium;
depending on the scenario viewed, that won't significantly drive
demand or growth. Third is power generation, which for natural
gas is three to four times larger in size, although it is small
in aggregate compared with coal-fired or nuclear generation.
MR. SMITH highlighted the different opinions, saying it is
uncertain. The base projection from EIA's current forecast has
substantial renewable-energy growth, relatively flat gas-demand
growth, and nuclear generation at the tail end of the period.
By contrast, Wood Mackenzie has a more robust view of how much
gas-fired electrical generation will be put in place to meet the
growth.
MR. SMITH also said nobody knows what legislation relating to
carbon will influence choices that electric utilities make for
generation, or what will happen with respect to renewable energy
and demand-side management. It is factored in, in some sense,
in the scenarios Black & Veatch includes, as well as the other
sensitivity analyses on pricing that will be detailed later.
REPRESENTATIVE NEUMAN suggested the uncertainty is what Senator
Stedman was getting at. While many forecasts appear to be based
on past demand, he said renewable resources are starting to gain
momentum now, particularly in the industrial area. He predicted
this will change even more.
10:39:49 AM
SENATOR STEDMAN asked about forecasts for oil, since it has a
relationship with gas.
MR. SMITH replied it isn't in the presentation, but Black &
Veatch has a fairly conservative assumption for oil prices,
looking at EIA and Wood Mackenzie. Wood Mackenzie's forecast
for oil is around $75, escalating to about $200 in the 2044
timeframe. It has a profile similar to gas, starting at a
fairly low level, although today's spot prices are substantially
higher than the base forecast.
MR. SMITH said for oil and natural gas prices, there has been
volatility over the years; one could argue either way, that
there is or isn't a relationship. For example, there was a low
oil-to-gas price relationship when hurricanes Rita and Katrina
caused gas prices to shoot up to $15; today, oil prices are 10
times higher than gas prices, and sometimes that has gone up to
12 or 13 times higher. The markets are related, but not in all
regards.
MR. SMITH addressed average prices, noting over the past 10 or
so years those have been around 8:1, meaning if gas were at $10,
it would equate to $80 a barrel for oil. As a general
expectation, the forecasts of Wood Mackenzie, EIA, and Black &
Veatch have shown a higher oil-to-gas relationship initially,
through the evaluation period of 2008-2020, and then declining
to a more traditional type of range and the 8:1 ratio.
10:43:26 AM
REPRESENTATIVE GATTO suggested a fourth component of demand,
transportation. He opined that natural gas for automobiles
would cost the equivalent of $1.80 a gallon if there were that
ability. He asked whether this is a possibility, whether it is
included in the model, and whether Black & Veatch has even
considered it.
MR. SMITH answered that the general expectation, from what he
recalled in assumptions used by Wood Mackenzie or EIA, is that
fuel for transportation would be a relatively minor component of
natural gas demand through time. The bulk of the demand will
come from space heating for residential and commercial
customers, even though it's growing slowly, and from fueling
power-generation facilities for electricity. He turned the
presentation over to Ms. Poduval.
10:44:54 AM
DEEPA PODUVAL, Black & Veatch Corp., explained that today's
focus would be on scenarios that assume Point Thomson gas won't
be available, smaller pipeline configurations than shown
previously for the 4.5 Bcf/d proposed by TransCanada. Black &
Veatch had looked at 4.0 Bcf/d and 3.5 Bcf/d cases.
MS. PODUVAL showed slide 3, "Production Assumptions: 4.0 Bcf/d
Case," a graph showing years 2020-2044 and the following areas:
Prudhoe Bay Unit (PBU)/state existing, state yet-to-find, and
federal onshore, with this note for the latter two: "Yet-to-
find production assumes a 50/50 mix of State/Fed Onshore
reflecting ratio of available reserves."
MS. PODUVAL explained that this assumes Prudhoe Bay produces
about 3.5 Bcf/d of gas initially to flow through the pipeline,
with other state existing fields supplying 0.5 Bcf/d. As
production declines from those, it assumes gas from onshore YTF
fields in the Foothills and National Petroleum Reserve-Alaska
(NPR-A) will become available around 2030, split 50/50 between
those two, which appear to be head-to-head from an exploration
and development perspective now.
10:48:00 AM
REPRESENTATIVE SAMUELS asked: So, after 12 years the flows
would drop significantly, and the thinking is to get financing
on a project in 2020 based on those other two areas?
MS. PODUVAL specified that this assumes after 10 years of
production, starting in 2020-2030, proven reserves at Prudhoe
Bay and the state existing fields will start declining and YTF
gas will become available to fill the pipeline. She noted that
later Mike Elenbaas would address the economics of a really
conservative assumption that has no Point Thomson gas and not
even 1 Mcf of YTF gas.
10:49:13 AM
SENATOR STEDMAN highlighted firm transportation (FT) commitments
to get the pipeline financed. He said Chevron and other
producers had indicated they weren't excited about committing to
YTF gas at the open season. He asked how the financing
mechanism would play into YTF gas when someone would have to bid
that for 10-11 years.
MR. SMITH answered that there are a couple of issues.
TransCanada's proposal assumes a 25-year contract term, with
recovery of the asset over that time; it puts all the risk of
reserves and producing that on the initial shippers. An initial
shipper isn't necessarily precluded from assigning capacity to
another party; FERC regulations allow that to get rid of the
contract risk, although no one has to buy it.
MR. SMITH said furthermore, as shown in the Black & Veatch
report, initial shippers may negotiate with TransCanada for a
contract term different from the depreciable life, say, 20 or 15
years. It isn't uncommon for Lower 48 pipeline projects to have
some reserve risk on the back end. For this analysis, however,
at least for the base case scenarios, Black & Veatch assumed
25 years, or, in this case, a 20-year contract period and 20-
year life.
10:52:16 AM
SENATOR STEDMAN asked about initial financing to build it.
MR. SMITH replied that obviously there have to be initial
contracts for that capacity. The question is whether they'll
take all of the risk on the back end or whether some mechanisms
contractually put some risk back onto the pipeline itself; that
is subject to negotiation, and Black & Veatch has looked at
scenarios to understand what happens to an initial shipper's
expected cash flow and NPV benefit if that shipper is on the
hook and has to pay for transportation in the out years but
doesn't have gas to fill it.
COMMISSIONER GALVIN, in response to Chair Huggins, explained
that the runs are in the Black & Veatch report and the "finding"
chapter; he offered to present those as slides. Regarding
Senator Stedman's concern, he said a number of mechanisms will
be worked out among the parties between now and the point of
financing. The state can't anticipate what that arrangement
will be, but can look at whether there is enough of an economic
opportunity for the parties to find such an arrangement.
COMMISSIONER GALVIN said this will be financed based on
FT commitments. Whether those FT commitments will be made was
analyzed from different perspectives, including whether
sufficient cash flow from the project will justify somebody
taking on that risk. The analysis included the risk and
economics associated with finding the additional gas or the
conservative case of finding none, to see whether this would
still be an economic opportunity. It was found that, yes, it
would still pay for itself.
MR. SMITH noted that a related slide is part of the sensitivity
analysis.
10:56:58 AM
MS. PODUVAL added that the Black & Veatch modeling for the risk
of having no YTF gas assumes that initial shippers would bear
the risk for the transportation capacity through the contract
period. That would be addressed by Mr. Elenbaas.
MS. PODUVAL showed slide 4, "Production Assumptions: 3.5 Bcf/d
Case," a graph like slide 3. She said this assumes 3.0 Bcf/d
from Prudhoe Bay and 0.5 Bcf/d from other state existing fields
at the start of operations in 2020. Similar to the 4.0 Bcf/d
case, as production declines at those fields, YTF gas is assumed
to keep the pipeline full.
MS. PODUVAL pointed out that while both these cases are very
conservative in assuming no expansion of this pipeline, other
producers such as Chevron or Shell that are on the North Slope
exploring could have production during this period that triggers
expansion.
MS. PODUVAL discussed slide 5, "Production Assumptions used in
the NPV Analysis for the 4.0 Bcf/d Conservative Base Case,"
which had the following points:
Prudhoe Bay
- 24.5 Tcf
- Initial production rate - 3.5 Bcf/d
State existing
- 3.7 Tcf:
- Colville River - 0.4 Tcf
- Duck Island - 0.8 Tcf
- Kuparuk - 1.2 Tcf
- Northstar - 0.5 Tcf
- GPMA - 0.9 Tcf
- Initial production rate - 0.5 Bcf/d
Note - this case assumes NO Point Thomson production
MS. PODUVAL said the reserve assumptions were 24.5 trillion
cubic feet (Tcf) of hydrocarbon gas available from Prudhoe Bay
and 3.7 Tcf at the state existing fields, as shown. She
recalled that PetroTel talked about maybe cycling the Point
Thomson reservoir for 10-15 years, extracting the liquid oil as
well as condensate production, at which point it begins to make
economic sense to start producing gas to optimize hydrocarbons
there. But she said that isn't taken into account under this
very conservative assumption of no Point Thomson gas.
COMMISSIONER GALVIN, in response to Chair Huggins, specified
that this is throughput. He offered to go through the technical
report to find what production would satisfy the throughput for
both production consumption as well as the fuel consumption on
the line. As Mr. Smith had indicated, he said the Black &
Veatch economic model aggregates the various reports; the
associated technical report is a separate sub-basis.
11:02:27 AM
REPRESENTATIVE NEUMAN referred to the 4.0 Bcf/d assumptions and
the fact that it takes energy to produce this gas. Suggesting
there'll be gas taken for Alaskans and expressing hope for a
spur line using 2.0 Bcf/d of LNG, he said there are existing LNG
plants to keep running, he'd like more value-added products, and
gas-to-liquids (GTL) production will be required by the federal
government. Thus there'll be competition for the 4.0 Bcf/d in
the mainline to Canada, hopefully for in-state use. He asked
that those be brought into the picture.
COMMISSIONER GALVIN replied that he sees the root of the
question as whether, for this analysis, FT commitments and
investments will result in a pipeline. The administration isn't
saying a 4.0 Bcf/d line is the optimal size and has said a Y-
line with LNG and these other components is the big goal. The
reason for this particular analysis, however, is to see whether
it can get off the ground with just the known resources at
Prudhoe Bay and the surrounding fields, without Point Thomson.
COMMISSIONER GALVIN added that where those molecules end up will
be a function of where the economic benefits are realized. From
this stream there'll be some royalty gas, and the state may
decide to take it off before it ultimately gets to market. But
that market value will have to be obtained. As for LNG and
other opportunities, the hope is to find additional gas to fill
those needs as well. Those are separate questions. This
particular analysis looks at a whether a 4.0 Bcf/d pipeline to
market can be financed even in a worst-case scenario.
MS. PODUVAL specified that Black & Veatch assumed about
5 percent fuel loss at the gas treatment plant (GTP), which was
provided by the technical team. The volumes shown are going
into the pipeline after the GTP. The production volumes will
actually be greater than the 3.5 Bcf/d from Prudhoe Bay and the
0.5 Bcf/d from state existing fields.
11:07:04 AM
CHAIR HUGGINS said the committee would still like the numbers.
He asked whether the administration has discussed with
TransCanada what minimum volumes TransCanada is looking to get
to AECO.
COMMISSIONER GALVIN recalled that Mr. Palmer of TransCanada said
the open season will be open to in-state gas, LNG, and Canadian
destinations and that TransCanada hasn't put a minimum that
would be required to go to AECO. What TransCanada described in
its application is a pipeline that will be appropriately sized
for everything down to 3.5 Bcf/d. That's for getting it to the
ultimate destination.
11:08:14 AM
REPRESENTATIVE GARA asked the reason for this analysis, since
nobody knows what gas will be available for this pipeline and if
it is or isn't available for TransCanada, the same is true for
the producers' project. It seems the uncertainty will be
resolved as the project moves ahead, he suggested.
COMMISSIONER GALVIN replied that is correct for comparing the
Denali and TransCanada projects, which clearly deal with the
same gas-supply issues and whether that affects their viability.
However, this analysis relates to whether to grant this license
and commit the state's matching funds. The administration
wouldn't advocate for granting a license if they didn't believe
there is a good likelihood of success. So it goes to whether
there is sufficient gas at only Prudhoe Bay and the surrounding
fields to possibly finance and get this project off the ground.
They'd found the answer is yes.
COMMISSIONER GALVIN added that while the ultimate prize is all
the YTF gas that will be encouraged through the open-access
provisions and ultimately discovered so the pipeline will
expand, the first objective is to get a pipeline. As to whether
issuing a license will likely result in a pipeline, the
administration believes from this analysis that the answer is
yes, even in the most conservative case.
CHAIR HUGGINS said $19 million has been spent to get this
information, and he'd like to understand what it is; that's the
reason for his question.
11:11:34 AM
MS. PODUVAL addressed slide 6, "Expected Tariffs from the North
Slope to the AECO Market," a graph labeled "AECO Tariff" that
showed tariffs of $4.73 at 4.5 Bcf/d, $5.33 at 4.0 Bcf/d, and
$5.71 at 3.5 Bcf/d. Noting 4.5 Bcf/d is the base case proposed
by TransCanada, she said the tariff increases by about
13 percent for 4.0 Bcf/d and about 20 percent for 3.5 Bcf/d.
MS. PODUVAL explained that the assumptions behind the tariffs
are capital costs estimated by the technical team. They'd
assumed the pipe size is 48 inches all the way from the North
Slope to Alberta. However, they'd changed the assumption of how
much compression would be needed. Capital costs go from about
$31.3 billion down to $29.4 billion when going from 4.5 to 4.0
Bcf/d. However, the volume is reduced over which those costs
are spread, thereby causing the tariffs to increase as shown,
13 to 20 percent over the 4.5 Bcf/d case.
11:13:38 AM
REPRESENTATIVE SAMUELS recalled that a 2005 Econ One
presentation showed a $2.65 tariff to AECO. He asked why costs
have nearly doubled since then and how confident Black & Veatch
is about this cost estimate.
MS. PODUVAL answered that over the last four or five years there
has been an enormous increase in capital costs and the cost of
steel. She mentioned an estimate that from 2005 to 2008, costs
rose about 80 percent on the upstream side. So these estimates
take that escalation into account, as well as 4 percent
escalation year over year, about 65 percent from 2008 to when
the pipeline is constructed. That is the technical team's
assessment of what capital costs will be.
MS. PODUVAL explained that Black & Veatch did a risk assessment,
asking what happens to the project economics if costs are much
higher or lower than base estimates; Mr. Elenbaas would discuss
the analysis results. While nobody can accurately predict the
cost by the time this pipeline is constructed, she said Black &
Veatch tried to use the best information available to see
whether the project still works even if costs aren't as
expected. The analysis seems to show it will work.
REPRESENTATIVE SAMUELS expressed concern from the standpoint of
someone with a 20-year FT commitment whose costs have doubled in
two years and whose future costs are likely to rise so much.
MS. PODUVAL pointed out that as costs rise, so do prices tend to
rise. That's one reason the project remains profitable despite
a twofold increase in tariffs since they were last estimated.
REPRESENTATIVE SAMUELS asked how long a lag time is anticipated
if prices drop. He suggested the worst case would be if steel
were bought at high prices.
MR. SMITH replied that he didn't recall what the lag would be in
some of the analyses Ms. Poduval referred to. Recent history
has shown dramatic increases in prices and capital costs. Also,
he didn't recall whether the GTP was included in the Econ One
analysis number. For instance, if the reference point on the
$4.73 has about $1.25 of tariff associated with the GTP, that
could explain some difference. However, he'd expect the tariff
to be higher regardless because of the increased capital costs.
SENATOR STEDMAN highlighted tables in the Black & Veatch report,
noting one on page 121 gives a breakdown of the tariff with the
GTP in the Alaska section, Yukon, and Alberta, and then a total
tariff of $4.73. He indicated a table on page 31 addresses the
five-year equity reduction if there's a cost overrun, looks at
whether or not the federal loan guarantees are used, and then
looks at a 40 percent cost overrun. He said that marginal
spread on the tariff from $4.73 to $5.90 ends at $1.24.
SENATOR STEDMAN surmised a 40 percent cost overrun might not be
unreasonable and thus that $1.24 tacked on to the tariff would
push the 4.0 Bcf/d tariff to $6.57 and the 3.5 Bcf/d tariff to
$6.95. He recalled that for the old estimates the legislature
was working with, it was $2.65 and a $3.50 stress price. He
asked: If there were a 40 percent overrun and a tariff of about
$6.60, what stress price would collapse this project?
11:20:13 AM
MR. SMITH responded that TransCanada's proposal tries to
mitigate exposure, but doesn't do so completely; scenarios can
be seen where that $4.73 in the base case can get to around
$6.00 for a tariff if there is a 40 percent overrun in certain
instances. Also, given existing price scenarios and those for
NPVs that were run, the economics still are favorable with a
40 percent cost overrun. The price expectations start in the
$7.00 range in 2008 and rise to over $10.00. Thus a $6.00
tariff still gives a netback margin to the stakeholders.
SENATOR STEDMAN said one issue is risk exposure. Page 30 of the
report says this project doesn't insulate shippers from cost
overruns, although page 31 has a table that reflects in
TransCanada's proposal its five-year reduction on equity and use
of the U.S. federal loan guarantees, which Goldman Sachs had
talked about. He said compared with the project proposed by the
previous administration, there doesn't seem to be as much
emphasis in reviewing the sensitivity of the tariff versus the
stress price. He clarified that he was looking for some comfort
that the analysis isn't being driven by the desired solution.
MR. SMITH answered that Black & Veatch had tried to look at
pricing independently with respect to different scenarios and
costs, relying on the cost overruns in a couple of ways. First,
the analysis of projected costs was developed by the technical
team, which projected a range higher than TransCanada had
proposed; these were based on schedule shifts and so on. That
could lead to changes in the tariff.
MR. SMITH said secondarily Black & Veatch looked at tariff
implications for 20-40 percent cost overruns. They'd looked at
what happens if one doesn't believe the price forecasts of Wood
Mackenzie or EIA and instead the project is just stressed
relative to a price of $5.00 today. They'd looked at analysis
around the base price case assumptions relative to tariffs at
those price levels, but hadn't combined them. They'd looked at
stressing the project at $5.00, $6.00, and $7.00, leaving those
effectively flat through time. He offered to get into that now
or wait until that point is reached in the slide presentation.
SENATOR STEDMAN said it could be done in the presentation. He
suggested he was perhaps looking at it too simply, with a tariff
of $7.00, since $7.00 plus gas would be needed.
MR. SMITH concurred. He said there are a lot of moving parts.
Keeping it specific is a clear way to understand the risk for
the stakeholders. This would be detailed in the price
sensitivity analysis.
11:26:17 AM
MS. PODUVAL discussed slide 7, "4.0 Bcf/d Conservative Base Case
Cash Flows," which had an upper graph labeled "Cash-flows to
Stakeholders" and a pie chart labeled "Total Net Cash Flow for
Project by Stakeholder (Non-Discounted, 2008-2044)." The latter
showed the following: U.S. Government $107 billion, 19%;
Canadian Government $10 billion, 2%; State of Alaska
$245 billion, 44%; TransCanada $55 billion, 10%; and Producer
$137 billion, 25%.
MS. PODUVAL noted the pie chart showed TransCanada's cash flows
as it spends capital to build the pipeline and cash flows from
tariff revenues. The top graph showed cash flows through time
for the state, producers, and U.S. government, with a little
sliver for the Canadian government.
MS. PODUVAL emphasized that the state's cash flows from this
project will grow through time. This is driven by increased
prices and progressivity on the ACES production tax - from the
Act known as Alaska's Clear and Equitable Share - that kicks in
at higher prices. Since over time the state's production tax
increases, its share of the total cash flows increases
accordingly.
MS. PODUVAL relayed the percentages for each stakeholder shown
on the pie chart, noting this is through the 25-year analysis
time period and is in nominal dollars, not discounted back to
2008 to be expressed as an NPV yet. This is just total, year-
to-year cash flows, amounting to $245 billion to the state,
44 percent of the total cash flows from this project.
11:28:51 AM
SENATOR STEDMAN returned attention to a previous slide and
mentioned the tax progressivity that also relates to oil. He
asked: When the analysis was done on future gas prices, what
oil price assumptions were used for the chart from 2008-2044?
MS. PODUVAL replied this goes back to the oil price forecasts
from Wood Mackenzie mentioned by Mr. Smith, which are tied into
its gas price assumptions. Those oil price assumptions are
about $81 in 2020 and $227 in 2044.
MR. SMITH added that page 106 of the NPV report shows those,
which Black & Veatch used as a basis in this analysis.
COMMISSIONER GALVIN highlighted the importance with regard to
progressivity that the state must address at some point. The
administration had to build into the model the current tax code,
he noted, which has progressivity based on a fixed $30 trigger
for the margin; that doesn't change with time, inflation, or
expected costs. When it gets to where the projections have both
gas and oil prices rising with inflation, particularly in 2030-
2040, the state portion of the revenue stream increases fairly
dramatically because that progressivity isn't being adjusted for
inflation.
SENATOR STEDMAN inferred that this chart might be a little
optimistic.
COMMISSIONER GALVIN agreed. In response to Chair Huggins, he
clarified that the tax regime is fine in terms of the economics
of this project. Whether it needs to be adjusted for other
reasons is open to further discussion.
11:32:45 AM
REPRESENTATIVE DOOGAN asked whether this assumes TransCanada is
building the GTP.
MS. PODUVAL affirmed that.
REPRESENTATIVE DOOGAN, noting TransCanada's proposal states a
preference that someone else build the GTP, asked: If we assume
instead that the producers build it because of tax credits,
would the state's revenue profile look more like TransCanada's,
with negative cash flow from this project to start with?
COMMISSIONER GALVIN replied that the GTP is outside the tax
credit program right now. The only change would be that the
cash flows for the producers and TransCanada would shift a bit.
11:34:11 AM
MS. PODUVAL elaborated on slide 8, "The State's NPV5 is Lower
with Smaller Project Capacity but Remains Significant," a graph
showing $66.1 billion at 4.5 Bcf/d in 2008 dollars,
$60.7 billion at 4.0 Bcf/d, and $51.6 billion at 3.5 Bcf/d.
MS. PODUVAL said the approximately $61 billion represents the
$245 billion on the previous slide, cash flows through time to
the state over 25 years, discounted back to 2008. Thus it would
be neutral between receiving $61 billion today or $245 billion
over 25 years, from 2020 to 2044; that's the NPV to the state
for the 4.0 Bcf/d project, and the NPV to the state from the
3.5 Bcf/d project is still $52 billion. These are significant
NPVs and returns to the state, even with smaller projects
without Point Thomson gas.
MS. PODUVAL discussed slide 9, "Producer NPV Shows a Similar
Trend When Compared to the State," which had two graphs. The
one labeled "Aggregate Producer NPV10" showed $13.5 billion at
4.5 Bcf/d, $12.3 billion at 4.0 Bcf/d, and $10.5 billion at
3.5 Bcf/d, all in 2008 dollars. The one labeled "Aggregate
Producer NPV15" showed $5.2 billion at 4.5 Bcf/d, $4.7 billion at
4.0 Bcf/d, and $4.0 at 3.5 Bcf/d.
MS. PODUVAL noted for the smaller projects without Point Thomson
gas, when cash flows are discounted back at 10 percent, the
producers' NPV is about $12 billion; at 15 percent, it's still
$4.7 billion. So the smaller pipeline cases reduce the
producers' NPVs but not significantly, as shown above.
11:36:28 AM
REPRESENTATIVE SAMUELS asked whether this assumes YTF gas will
be found by someone other than the current producers.
MS. PODUVAL affirmed that. In further reply, she said this
assumes the YTF gas is found to fill the pipeline and is
actually found by the initial shippers on the pipeline during
the contract period of 25 or 20 years. After that, it
transitions to what they're calling "yet-to-find producers."
Black & Veatch is assuming a 20-year contract period for the
smaller pipeline cases of 4.0 or 3.5 Bcf/d.
11:38:07 AM
SENATOR FRENCH referred to a previous slide and asked: If there
are 20-year contracts, why is the assumption for a 36-year
project life, from 2008 to 2044? He surmised the gas pipeline
would last even longer than the oil pipeline because of fewer
corrosion issues and so on.
MS. PODUVAL answered that Black & Veatch is assuming the
pipeline becomes operational in 2020. So the 25-year analysis
period is from 2020 through 2044. Taken into account are the
capital spent by TransCanada even before 2020 and the state's
matching contribution. Because the discussion is today, they've
discounted all those cash flows back to 2008.
SENATOR FRENCH asked why the 20-year period was expanded to
25 years.
MS. PODUVAL replied they'd kept the 25-year analysis period
standardized as an assumption throughout the analysis,
representing the 25-year depreciation life that TransCanada
proposed in its application.
COMMISSIONER GALVIN added that for an NPV analysis, it makes a
difference in the amount of cash flows that will be calculated.
If the NPV numbers were shifted between a 25-year and 20-year
period, it wouldn't be an apples-to-apples comparison because
the cash flow for one scenario would be 5 years shorter. Thus
25 years was retained for the NPV comparison.
COMMISSIONER GALVIN also pointed out that because of the
shortened contract, in these scenarios the capital costs for
TransCanada are collected over a shorter time, so tariffs are
higher than for a 25-year period. When it gets to that 20th
year, TransCanada's cash flow ends up "falling off the cliff"
because the tariff is recalculated based on the cost at that
time, and the tariff in the 21st year is very small. So the
cash flows for the last 5 years aren't to TransCanada's benefit.
COMMISSIONER GALVIN said for a smaller-capacity line, the issue
is reserve risk. It is expected that commercial players will
look to address that by having a shorter contract. The effort
here is to anticipate where that will go. The tariff would be
higher, but the exposure on the reserve side would be lower. So
that's shown here. But to compare NPVs for a 4.5, 4.0, and 3.5
Bcf/d case, they had to keep the same timeframe for cash flows.
SENATOR FRENCH asked about the reduced tariff in the last years
of the 25-year period.
11:42:10 AM
MIKE ELENBAAS, Black & Veatch Corp., specified it goes down to
about $1.00. While all the capital will have been recovered by
TransCanada through the first 20 years, operating expenses for
the pipeline still will need to be recovered. In that last 5
years, rates get reset just to recover those.
SENATOR FRENCH asked what happens to the state's revenues after
that first 25 years, since there might be another 25 years of
life for the pipeline.
MR. SMITH answered that cash flows don't automatically drop
then, but continue. What isn't shown is the discounted value of
those cash flows in year 25, which adds to the NPV. Everything
is for NPV 2008. For 2044, 35 years down the line, discounted
at 5 percent, those cash flows add just a little to the NPV. If
they ran a 26-year or 30-year NPV, it wouldn't be a great deal
different from the 25-year NPV. Particularly when the producers
are brought in at 10 or 15 percent, it's practically nothing
because of being discounted back 35 years.
11:44:35 AM
MS. PODUVAL turned attention to slide 10, "Project NPV is
Affected by Many Factors," which had the following points:
- Prices
- Project cost
- Project cost escalation
- Interest rates
- Cost of finding and developing "new gas"
- Etc.
Bottom line: Understanding how project economics are
affected by uncertainty in inputs that affect cash
flows.
MS. PODUVAL noted these uncertainties impacting the NPVs to the
state and the producers are the main factors, with prices being
the largest one. The previous slides had shown NPVs to the
state and the producers under baseline assumptions of costs,
prices, and so on.
MS. PODUVAL said the Black & Veatch analysis varied each of
these, recognizing it isn't known what they'll actually be in
2020 when the pipeline is operational. Thus each factor was
risk assessed, looking at what happens to the project economics
if these are much lower or higher than estimated in the base
case. Mr. Elenbaas would address the NPV sensitivity analysis.
11:45:46 AM
MR. ELENBAAS discussed slide 11, a tornado diagram labeled
"Price is a Key Driver to Variations in the NPV5 to the State of
Alaska" that listed these sensitivity factors on the left:
commodity prices, cost escalation, upstream capital costs,
TransCanada capital costs, pipeline interest rate, TransCanada
schedule, and production scenarios. As Mr. Smith had mentioned,
Black & Veatch wanted to explicitly analyze risk under different
assumptions to make more transparent how that risk impacts the
project stakeholders, Mr. Elenbaas told members.
MR. ELENBAAS explained that Black & Veatch had looked at key
factors listed on the previous slide and the range of
uncertainty for those, asking how that impacts the state's NPV.
The line in the center of this diagram shows the base case state
NPV for the 4.5 Bcf/d case. Although they hadn't run the
4.0 Bcf/d case, it would show similar relative outputs. On the
"x" axis, NPV to the state is plotted using a 5 percent discount
rate; that varies from zero up to about $140. Then each bar of
the chart looks at a different factor.
MR. ELENBAAS emphasized that based on their estimates, commodity
prices have the largest impact with respect to uncertainty for
the project, particularly for the state and the producers. The
base case assumptions are on the right, and the Wood Mackenzie
prices are in that center base line number. The far left of
this price-related bar shows a very low uncertainty and a low
probability of 10 percent that the state NPV for this project
could be about $20 billion; on the upside is a 10 percent chance
of its being nearly $120 billion.
MR. ELENBAAS noted the range for cost escalation is much less,
but is obviously another big risk. The bars are in this order
so higher-risk issues rise to the top. The base numbers include
compounding cost escalation of 4 percent, year over year, until
the project goes into service. On the high end, it was
increased significantly, to 6 percent for capital costs, which
increased the tariff by a little over $1.00. So cost is a big
issue, modeled in a couple of ways, looking at both cost-
escalation risk and cost-scope risk.
MR. ELENBAAS told members this is looking at escalation only.
If the project costs $31 billion and year-over-year escalation
is 6 percent for 12 years before this goes into service,
there'll be a very high tariff and less money to the state,
$45 billion - still a significant amount.
MR. ELENBAAS said also looked at were upstream capital costs to
the yet-to-find producers that will help fill the pipe. In the
base case on the center line, Black & Veatch found doubling
those capital costs decreased the state's NPV somewhat, but not
nearly as significantly as prices. Also looked at were the
other issues shown, modeling them explicitly to look at those
risks. The key take-away here is that price is the biggest
uncertainty, with cost also a large uncertainty.
11:53:00 AM
SENATOR STEDMAN asked about upstream capital costs versus the
capital expenditures (CAPEX) shown as 6 percent and the
100 percent increase as they relate to escalation.
MR. ELENBAAS answered that Black & Veatch looked at a baseline
of 4 percent cost escalation for not only the pipeline project,
but also upstream capital costs. This sensitivity looks at
increasing that for all stakeholders including TransCanada and
the producers, primarily the producers of YTF production that is
needed. That's where most of the capital costs are.
SENATOR STEDMAN asked how a 20 or 40 percent cost overrun would
fit in.
MS. PODUVAL responded that a 20 percent cost overrun is included
under TransCanada's capital costs, the fourth factor from the
top on the chart. Upstream capital costs are production costs
at the field. Cost escalation is the year-over-year escalation
applied to both TransCanada's capital costs to build the
pipeline and the producers' costs to develop and produce from
the different fields. On one hand, this looks at the baseline
assumption for the pipeline capital costs as well as upstream
production. On the other hand, it looks at cost escalation
associated with the upstream and the pipeline.
SENATOR STEDMAN asked about sensitivity to cost overruns for the
midstream when the line is built. With a 20 or 40 percent cost
overrun, he said from this chart it appears the state shouldn't
be concerned about that. He asked why the producers would be
concerned about it, since they seem very sensitive to not having
a cost overrun of 40 percent.
MS. PODUVAL replied this shows the NPV to the state, whereas
Mr. Elenbaas has another chart showing the NPVs to the producers
from varying the capital costs.
MR. SMITH added that throughout this analysis, the framework for
the modeling is comparing an oil-only world to an oil-plus-gas
world and thus some of the cost risk isn't as large. Higher
cost escalation decreases the economics of the pipeline project
to the producers, playing into it a little bit.
COMMISSIONER GALVIN surmised that Senator Stedman was addressing
what happens with regard to predicted costs versus the ultimate
costs, and that Ms. Poduval was saying it depends on the cause
of that difference. If it is because original cost estimates
weren't fully fleshed out and additional engineering was needed,
for instance, that is within TransCanada's capital costs; that
has relatively less significant impact on it. If it is because
costs in general escalate faster than anticipated, the costs
would end up at the same point, but that would be the bar on the
graph associated with cost escalation, a fairly significant bar.
The meeting was recessed from 11:58:34 AM to 1:38:45 PM.
^Roundtable Discussion including Producers
CHAIR HUGGINS announced a roundtable discussion to answer
questions. At his invitation, the following introduced
themselves: Cathy Foerster of the Alaska Oil and Gas
Conservation Commission (AOGCC); Nan Thompson, Julie Houle, and
Steve Moothart of the Division of Oil & Gas, Department of
Natural Resources (DNR); Craig Haymes of ExxonMobil; John Zager
of Chevron - Alaska Area; and Dr. Anil Chopra of PetroTel Inc.
(via teleconference).
1:41:38 PM
NANETTE THOMPSON, Unit/Tech Support, Division of Oil & Gas,
Department of Natural Resources, noted she was asked three
questions yesterday and had two answers but needed more time to
research Senator Wielechowski's question.
MS. THOMPSON reminded members that Representative Samuels had
asked DNR's opinion on the 23rd Plan of Development (POD) and
she'd responded that the attorney general had advised to not
comment on what DNR Commissioner Irwin substantively had
decided, but instead defer to pages in the POD. Noting those
are pages 29-63, she offered a copy for Representative Samuels,
saying she'd testify under the same restriction today, which she
has been advised is in the state's best interest.
MS. THOMPSON also noted that Representative Fairclough had asked
about DNR's position on the permits, since ExxonMobil's
presentation discussed the permitting process. In response,
Ms. Thompson said a pre-application meeting will start in about
half an hour at DNR. The pre-application process is available
to anyone who potentially plans to do work on state lands.
MS. THOMPSON explained that this is an opportunity for the
applicant to present information once to all potentially
affected state agencies. ExxonMobil had called to say it had a
project in this area and wanted a pre-application meeting; all
the different state agencies were invited to come listen. It's
show-and-tell. No permits are issued until much later, after
complete applications are filed.
MS. THOMPSON said DNR's position is that permits won't be issued
for lands for which it doesn't have leasehold rights. But until
hearing the presentation at the pre-application meeting and
getting a clear idea of which leases are affected, DNR can't say
whether these operations will be permitted. So this is the
start of a process with the attorneys general to determine if
issuing any permit is appropriate, based on the legal status of
the leases. She noted yesterday she'd said the lease status is
an open legal issue that DNR is actively working on.
1:44:12 PM
JULIE HOULE, Section Chief, Resource Evaluation, Division of Oil
& Gas, Department of Natural Resources, addressed a question
asked by Representative Roses about what gas could be put into a
pipeline besides that from Point Thomson and Prudhoe Bay. She
said approximate other available sources of recoverable
reserves, based on DNR's annual report, are: Colville River,
400 Bcf; Duck Island, 843 Bcf; Kuparuk, 1,150 Bcf; Northstar,
450 Bcf; and the greater Point McIntyre area, 880 Bcf.
CHAIR HUGGINS noted this was covered this morning, though the
figures on the slide were rounded up. He asked Ms. Foerster
whether she concurred with those numbers.
1:34:28 PM
CATHY FOERSTER, Commissioner, Alaska Oil and Gas Conservation
Commission (AOGCC), Department of Administration, replied she
hadn't reviewed the gas reserves numbers for these fields
recently and thus couldn't verify their validity. She pointed
out that these are oil fields, not gas fields, and her related
testimony holds true for the gas in these oil fields.
CHAIR HUGGINS requested that Ms. Foerster review those and then
get back to the committee.
1:46:39 PM
REPRESENTATIVE SAMUELS recalled that yesterday Dr. Chopra talked
about Point Thomson with respect to 50 percent oil recovery and
then Mr. Haymes said there's probably 5 percent on the rim. He
asked whether AOGCC agrees with the assumptions and conclusions
that DNR and the administration's consultants have come up with.
MS. FOERSTER replied that AOGCC hasn't reviewed in detail the
analysis by PetroTel, but did a cursory review of some of the
assumptions and conclusions. Furthermore, AOGCC hasn't reviewed
ExxonMobil's analysis in its entirety. However, AOGCC is in the
process of performing an independent analysis of Point Thomson,
using Gaffney Cline & Associates, which does reservoir
engineering consulting and has geologists, for instance.
MS. FOERSTER noted as part of that analysis, AOGCC has access to
all confidential and non-confidential data from ExxonMobil, BP,
Chevron, and so forth, as well as the opportunity to review the
analysis done by ExxonMobil. This allows AOGCC's analysis to be
validated.
MS. FOERSTER offered her experience that whenever two separate
technically competent groups take the same raw data, they'll
analyze it differently, based on their assumptions and
techniques because of education, experience, technical tools,
and so on, and will adamantly believe theirs is correct.
Because of the little data available and all the assumptions and
forecasts, the only guarantee is that neither will be right.
She said data AOGCC has looked at so far, and the part of the
analysis AOGCC has done independently, is somewhere between the
two and probably closer to ExxonMobil's.
REPRESENTATIVE SAMUELS suggested that at a policy level, if the
unit is dissolved because it is believed the ExxonMobil/Chevron
proposal was analyzed wrong, somebody else such as Shell will
see it the state's way and develop the field that way. He asked
what that accomplishes for development and getting a gas line.
MS. FOERSTER replied that she doubts Shell would come in with
exactly the same analysis as ExxonMobil or Texaco because Shell
would start from scratch and use its own tools and experiences.
REPRESENTATIVE SAMUELS asked when AOGCC would be done with its
analysis.
MS. FOERSTER answered that right now AOGCC is at the mercy of
ExxonMobil, which is setting the schedule.
1:51:42 PM
CRAIG HAYMES, Alaska Production Manager, ExxonMobil, said
ExxonMobil has been underway since last August and plans to try
to finish sharing the data by the end of this year. There is a
significant amount to share, and it's a lengthy process because
of the amount and because it's a complex field. The process is
to ensure it shares all the right information in a logical,
sequential order. While there have been scheduling challenges
and it might be a bit longer, the end of this year is targeted.
MS. THOMPSON said while the question intimated that Commissioner
Irwin's decision to terminate the unit was based on the PetroTel
study, that study wasn't part of the commissioner's decision or
the record of that decision. That litigation was the end
product of the company's appeal of the original decision to
terminate it.
REPRESENTATIVE SAMUELS replied he understood that, but this is
the information under which the administration will proceed,
believing what PetroTel says and using that as the parameters
with respect to Point Thomson. Thus he'd asked when AOGCC would
come out with its own independent view.
1:54:06 PM
ANIL CHOPRA, Ph.D., President, PetroTel Inc., told members he
wanted to address the dominant issue of data that arose
yesterday and today. He drew attention to a PowerPoint
presentation titled "Response to Testimony and Q/A Discussions
Held on June 17, 2008"; a hard copy showed logos for both
PetroTel and DNR's Division of Oil & Gas.
DR. CHOPRA relayed information from a slide labeled "Do we have
enough data in Point Thomson to define a Full Field Plan of
Development for both the oil and gas reserves?" that had the
following points:
- 19 wells have been drilled
- 14 wells penetrated Point Thomson reservoirs
- 3600 ft of high quality core has been taken and
analyzed
- 20 well tests have been completed, defining rates
and pressures
- Eight 3D seismic surveys have been acquired and
interpreted
- Multiple fluid samples have been taken and fluid
property evaluations have been conducted
- Conclusion: The type and amount of reservoir data
is sufficient to develop a Full Field Plan of
Development for oil and gas development at the Point
Thomson Field
DR. CHOPRA added that because yesterday it appeared some folks
felt there was hardly any data, he'd gone back and compiled a
list. He said ExxonMobil's testimony also spoke to what data is
available and has been used.
DR. CHOPRA highlighted the tremendous amount of core, saying at
least 10 wells have been cored and analyzed; 20 well tests have
been completed, defining oil rate, condensate rate, gas rate,
and pressures, so there is a pretty good idea of pressure
throughout this high-pressure reservoir, with pressure around
10,200 pounds per square inch (psi) and excellent continuity in
the reservoir.
DR. CHOPRA noted PetroTel works worldwide, having done more than
200 studies, and has seen many field plans produced with one-
third of this amount of data. Thus PetroTel concluded that the
type and amount of reservoir data available today is sufficient
to develop a full field POD for both oil and gas in the Point
Thomson field. Referring to a report from ExxonMobil, he said
there is so much data already that it will take the next six
months for the data transfer from ExxonMobil.
DR. CHOPRA referred again to yesterday's testimony and said the
range was bracketed for gas in place; if Brookian and Pre-
Mississippian are added, it could go even higher. It is known
that there is gas, a gas condensate, and there is oil in this
gas cap, about 660 million barrels. He emphasized that there is
absolutely no reason to say there isn't enough data to do
something about this field.
1:59:22 PM
DR. CHOPRA addressed a slide labeled "Response to Exxon
Presentation," which had the following points:
- Exxon presented yesterday that they did not see a
reduction in Pt Thomson well productivity due to
condensate dropout.
- Their own published work on the Arun Field in
Indonesia (with a condensate yield of 65 STB/MMSCF)
shows a 50% reduction in well productivity occurring
during blowdown.
- As a result, Exxon initiated lean gas injection in
Arun, as soon as production began, to minimize
liquid drop out and to maximize condensate recovery.
- In a blowdown scenario, 2 to 3 times the number of
wells will be required to maintain the same rate.
Producing oil earlier will require fewer number of
wells in the long term.
- Condensate will be trapped in the reservoir in a
blowdown scenario, thereby reducing liquid recovery.
DR. CHOPRA added with respect to the first point that he was
really surprised by that. If Point Thomson has gas condensate
and the company has taken 20 well tests showing condensate
dropout and high pressure with a yield of 66, it is very similar
to the Arun Field, which had a 50 percent reduction in well
productivity during blowdown and a condensate yield of 65.
DR. CHOPRA addressed a graph labeled "Point Thomson Well
Productivity During Blowdown." He said if there's a blowdown
there, PetroTel's position is that it will require 2 to 3 times
the number of wells to maintain the same rate. If gas is sold
to any pipeline coming in at 1.5 Bcf/d and 15 wells are drilled,
the rates will start dropping quickly and within 10-15 years it
will be at one-third the gas rate and require drilling 45-50
wells because of the liquid dropout around the well bores. He
asked why ExxonMobil sees the condensate drop out.
DR. CHOPRA relayed information from a slide labeled "Take Home
Point: Point Thomson Blowdown" that said:
- It will require very aggressive additional drilling
schedule ($100 Million/well) for up to 50 wells to
maintain a stable gas rate for the pipeline for the
next twenty-five years.
- This is because of the condensate dropout and the
drop in reservoir pressure over time.
DR. CHOPRA indicated PetroTel's proposal for gas cycling
mitigates that by getting the liquids out first so they get out
of the way of the gas production and maximize liquid recovery.
Half a billion barrels of oil can be produced, worth $70 billion
in today's market.
DR. CHOPRA suggested implementing that field development plan
and then going back to start doing the blowdown of gas. He said
that gas will still be available for a future pipeline because
it won't be going anywhere. As stated yesterday, the drilling
could cost $50 million to $100 million per well.
2:02:11 PM
DR. CHOPRA addressed a slide labeled "Exxon Description of Gas
Cycling" that said:
"What do we mean by cycling gas to produced
condensate? The cycling of gas requires two wells: a
production well and an injection well. These wells
will be placed four miles apart in the heart of the
reservoir to provide a true test on the effectiveness
of cycling gas at Point Thomson...."
This was followed by a depiction labeled "Gas Cycling" and a
slide labeled "What is Gas Cycling" that had these points:
- Exxon's gas cycling description is NOT a gas cycling
project by industry definition. Their depiction of
fluid movement is wrong by laws of physics. The dry
gas will go to the top and gravity tongue. It will
break through to high permeability zones to the
producing well resulting in poor sweep. They show
dry gas which is lighter going to the bottom of the
reservoir.
- In PetroTel's design of gas cycling, the injectors
are placed at the apex or at the highest points in
the structure to maximize sweep.
- Exxon's 4 miles distance (per their written
testimony) is too long a distance to observe
pressure support in a reasonable amount of time.
2:02:25 PM
DR. CHOPRA explained that ExxonMobil's gas cycling process for
these two wells - four miles apart in the heart of the
reservoir, a very large distance - was shown in ExxonMobil's
diagram as injecting dry gas down and then going to the
projection well. He said that's not physically correct.
DR. CHOPRA explained that the dry gas is much lighter, since the
condensate has all come out, if it was processed right. Dry gas
always goes to the top and tends to go towards the producer
hugging the top. He suggested the ExxonMobil diagram showed
more of a gas displacement, rather than gas cycling.
DR. CHOPRA noted these two proposed wells are at the highest
point in the structure; thus the gas will follow a circuitous
route. Recalling it was stated that they'd be finding out
whether the gas cycling process works, Dr. Chopra said this
won't be found out for a very long time because of the way it's
injected and where it's injected.
DR. CHOPRA said typically everyone in the industry knows gas
cycling is where dry gas is injected at the highest point in the
structure, the apex, like at Prudhoe Bay. It displaces the
heavier gas towards the producers that produce the liquids and
recycle the dry gas. That's dry cycling. So the plan PetroTel
has come up with, with extensive gas cycling to recover all this
condensate from the fields, is highly desirable.
DR. CHOPRA added that based on the pressures seen, permeability
levels, and so on, PetroTel doesn't see any reason it won't work
as long as there is intelligent design of the position of the
injectors and so forth, looking at the seismic data and
structure. He emphasized that there is plenty of data to do
that; in fact, it's a large database.
2:04:49 PM
DR. CHOPRA addressed the final slide, "Prudhoe Bay Gas
Requirements," which had the following points:
- Prudhoe Bay is undergoing a major APEX water
injection program to maintain pressure.
- The purpose of water injection project was to
facilitate gas sales.
- AOGCC have quantified the effect of different gas
offtakes based on modeling work.
- This work was used to justify the offtake in 2019
for AGIA pipeline requirements from Prudhoe Bay.
- Black and Veatch study shows the AGIA pipeline is
still robust without Point Thomson gas.
DR. CHOPRA added that he was on the advisory board for that
water injection project. A key reason it was put together was
for future gas sales; at the time, 15 years ago, the operators
decided if they were going to sell gas, they'd have to maintain
pressure using water, which is a lot cheaper solvent than gas.
The AOGCC project mentioned was confidential.
DR. CHOPRA referred to yesterday's discussion of offtake in
Prudhoe Bay and whether there will be enough gas. He said the
Black & Veatch modeling showed the AGIA pipeline is robust even
without Point Thomson gas. Thus this scenario had been taken
into account to some extent by the AOGCC study.
CHAIR HUGGINS thanked Dr. Chopra. Referring to 2019 and the
discussion of AOGCC, he asked to hear from Ms. Foerster.
2:07:01 PM
MS. FOERSTER noted DNR was allowed access to the results of the
AOGCC study and thus took that data and did its own analysis;
the 2019 is from an analysis by DNR, not AOGCC. She said AOGCC
signed a confidentiality agreement, as did DNR, that prohibits
quoting any numbers. But as she said yesterday, the later the
gas is taken, the less will be taken, and the more mitigation
the operator has done in the meantime, the more likely it is
that the losses will be lower and thus acceptable. She declined
to comment further because of the confidentiality agreement.
DR. CHOPRA explained that water injection has become a very
important part of Prudhoe Bay's life. It was expected
originally that a ballpark number of 1 million barrels a day of
water would be injected into the Prudhoe Bay gas cap to maintain
pressure. The pressure is good for Prudhoe Bay, and water
injection will have taken the place of gas there.
DR. CHOPRA said by 2019, the incremental value of gas versus
water injection to maintain pressure and recover oil would have
gone down significantly; that was the modeling work done by
AOGCC. PetroTel has made a tool to study the effect of
different offtakes to see the optimal amount of gas to take from
Prudhoe Bay. While that work needs to be quantified further,
there are 10 years when so much water would have been injected
because they've been displacing the gas with water.
MS. FOERSTER remarked that she didn't know how uncomfortable she
should feel and whether she should seek legal advice about data
AOGCC gave to DNR under this confidentiality understanding. She
said she wasn't happy.
CHAIR HUGGINS called on Ms. Thompson as the DNR representative.
MS. THOMPSON deferred to Ms. Houle to talk about the technical
work, which was done by PetroTel.
MS. HOULE responded that Jack Hartz, the DNR reservoir engineer
who worked with PetroTel on its study, was out of state. She
suggested that she get back to the committee and have Mr. Hartz
answer any questions.
CHAIR HUGGINS indicated he would let AOGCC and DNR work out any
differences about proprietary information.
2:10:57 PM
CHAIR HUGGINS asked Ms. Thompson whether anything except the
legal proceeding keeps ExxonMobil and PetroTel from conferring
about the $700,000 worth of reservoir information. He gave his
understanding from yesterday that ExxonMobil disagrees with
PetroTel's conclusion to some degree and wants to confer,
thinking PetroTel might agree with its findings in such a case.
MS. THOMPSON replied she couldn't answer without understanding
the scope of the confidentiality agreement. For instance, she
didn't know whether ExxonMobil was the only party that gave DNR
and AOGCC the data protected by this agreement. Thus she didn't
know whether it was okay for them to confer, since other
parties' interests might be compromised by such a discussion.
CHAIR HUGGINS encouraged facilitating communications about this
key piece of topography when it comes to oil and gas, suggesting
it would benefit Alaskans.
2:12:44 PM
MS. THOMPSON concurred. Responding to comments yesterday by
Chevron and ExxonMobil about how DNR wouldn't speak to them
about the handling of this reservoir, she explained that
discussions with Commissioner Irwin during the pendency of the
remand proceeding were not appropriate. When that was going on,
DNR was under an order from Judge Gleason to consider a specific
legal question; Commissioner Irwin was directed to adjudicate
that question and so acted in the role of a judge. Just as
someone cannot negotiate with a judge when there is ongoing
litigation, it wouldn't have been appropriate for the parties,
individually or as a group, to negotiate with him.
MS. THOMPSON said there has been extensive negotiation over the
history of the unit. When the 22nd POD was reconsidered
repeatedly by the department, for instance, negotiations
extended over a couple of years about what the acceptable POD
would be. The final plan wasn't consistent with that, and the
decision was made to terminate the unit. Thus DNR was put in a
litigation posture by the parties that appealed. So it's not
that DNR is averse to negotiating. When the time is ripe, when
the case is no longer before DNR as an adjudicator, those
discussions may again be appropriate.
2:14:16 PM
CHAIR HUGGINS suggested having Mr. Zager of Chevron address one
of his bullet points about discussions with DNR. First,
however, he invited Mr. Haymes of ExxonMobil to respond to
Dr. Chopra's testimony.
MR. HAYMES read from the last bullet point on Dr. Chopra's first
slide, which said:
- Conclusion: The type and amount of reservoir data
is sufficient to develop a Full Field Plan of
Development for oil and gas development at the Point
Thomson Field.
MR. HAYMES responded that it depends on the POD. For gas sales
development, it is correct that there is enough information to
move into that with relatively low risk; when straws are put
into that high-pressure reservoir, regardless of the
discontinuity, baffles, or quality differences, it will drain
the gas. The gas is extremely mobile, and with that high
pressure, it will eventually migrate to the wells.
MR. HAYMES added, however, that for development of cycling or a
very thin, discontinuous, heavy oil column, there isn't enough
information to bring forward a full field POD. Thus this POD
recognizes there isn't enough information, and it focuses on
learning more for cycling and more about the oil rim,
potentially delineating and producing that.
MR. HAYMES suggested that caveats or key boundaries be put on
the PetroTel report. He said ExxonMobil hadn't seen PetroTel's
detailed technical report and wasn't privy to its information
and assumptions; thus he would go off DNR's summary of it, which
is an appendix to the gas pipeline findings documents.
2:16:34 PM
MR. HAYMES read four portions from that DNR summary of the
PetroTel report, as follows:
A good understanding of the special economics involved
is therefore required for optimum engineering of gas
condensate reservoirs. ...
Technical issues remain to be resolved. Economic
evaluation still needs to be done to validate
conceptual conclusions and refine potential
development scenarios. ...
At this stage of the analysis, scenarios were designed
and run to discover and evaluate key sensitivities to
recovery, rather than to derive optimal production
economics. ...
A large factor in this will be the number of
development wells that can be economically drilled and
operated.
MR. HAYMES reminded members that yesterday he'd said ExxonMobil,
BP, Chevron, and ConocoPhillips operate tens of thousands of
fields and reservoirs around the world and have an ownership in
the majority of high-pressure gas fields worldwide. They've
used state-of-the-art technology and modeling and have leveraged
the expertise of thousands of people; this resource assessment
and development plan is a conglomerate of that expertise.
MR. HAYMES also noted that yesterday he'd said they have a lot
of incentive to produce hydrocarbons. All around the world,
wherever he has worked, it has been in their lifeblood to get as
much oil and gas out of the ground as possible. He indicated
ExxonMobil has done this at Prudhoe Bay and Kuparuk as an active
partner, as well as Duck Island, Granite Point, and many other
reservoirs around the world. He said Point Thomson is no
different in this respect, although it has unique challenges and
there is a unique field POD to move it forward.
MR. HAYMES specified that ExxonMobil would be prepared to share
its information with PetroTel, although it would need to be done
through a confidentiality agreement, as currently done with
AOGCC. The data ExxonMobil provided to DNR is indeed already
under a confidentiality agreement, and the company would need to
look at that agreement to share the data. He said ExxonMobil is
more than willing to sit down and share its work with anybody.
2:19:11 PM
CHAIR HUGGINS encouraged maximum cooperation to bring benefits
to Alaskans in the near term.
DR. CHOPRA informed members he'd found interesting information
on the General Electric (GE) website. He said they implemented
high-pressure reinjection in 1975 at 10,000 pounds per square
inch absolute (psia). In 1995, such reinjection was implemented
in Venezuela at 9,150 psia, and in 2005, such reinjection was at
10,700 psia. He said high-pressure gas reinjection has been
there, as and when required, as a choice to produce more oil.
MR. HAYMES asked for a copy of those documents. He indicated
ExxonMobil had done a worldwide search, but hadn't found
anything operating today over 7,000 psi.
DR. CHOPRA responded that he'd sent the PDF document with his
slides. On the website it says "high-pressure gas reinjection"
and then gives the timeline for 1973, 1975, 1995, 1999, and
2005. For 1975, it says 10,000 psi North Sea, and for 1995 it
says 9,150 psi in Venezuela. He asked that this document be
shared with Mr. Haymes and others.
CHAIR HUGGINS indicated the committee would take care of it. He
asked whether Mr. Zager had anything to add with respect to
conferring with the state.
2:21:48 PM
JOHN ZAGER, General Manager, Chevron - Alaska Area, responded
that it has been a frustrating process, likely on the state's
side as well, and he was glad to hear of the possibility for
dialogue in the relatively near future. He noted his attorneys
tell him that when two parties are highly motivated, they can
figure out a way to have some dialogue.
2:22:34 PM
REPRESENTATIVE DAHLSTROM asked whether Mr. Haymes would like
legislators to sign a confidentiality form, after which
ExxonMobil would be willing to release information to those
legislators individually.
MR. HAYMES answered that the offer on the confidentiality
agreement was with PetroTel and DNR, as was done with AOGCC.
There is a lot of information. If there is something a
legislator is interested in, ExxonMobil could look at that on an
individual-by-individual basis. While not closed to the idea,
ExxonMobil would need to determine the purpose, given that the
data is confidential. With AOGCC and DNR, there's an end point.
REPRESENTATIVE DAHLSTROM said her purpose would be to make the
correct decision here, certainly not for pleasure reading.
2:24:30 PM
SENATOR STEDMAN asked Mr. Haymes and Mr. Zager: If there were a
20-year supply of gas for a 4.0 or 3.5 Bcf/d line, how would the
corporations handle the issue of YTF gas at the time of the
initial open season when trying to get FT commitments to finance
the line and get it built? Does it create a liability? If so,
how much, and how is that dealt with?
MR. HAYMES replied that for YTF gas, Appendix J of the gasline
decision document talks about an estimated need for gas of 70-
80 Tcf for a 4.5 Bcf/d pipeline for 35 years; at 4.5 Bcf/d for
25 years, it would be 50-57 Tcf; and at 3.5 Bcf/d for 25 years,
40-50 Tcf. It depends on how long that commitment is. So much
is needed because a gas field declines. An FT commitment for 25
or 35 years is made at 3.5 or 4.5 Bcf/d for that entire
duration. But as the field declines, another must be found to
fill that, allowing for the decline of that field as well.
MR. HAYMES said if Point Thomson is out of the equation and just
Prudhoe Bay is looked at along with other gas, which there isn't
a lot of, then another Prudhoe Bay equivalent is required. Thus
any shipper will make a FT commitment with an unknown amount of
YTF gas; that's just for the initial shipment, not expansions.
MR. HAYMES noted ExxonMobil would back that, finance it, and
carry it as a liability, reporting it as a liability under
Securities and Exchange Commission (SEC) guidelines. It has to
be factored into the economics. He indicated the economics that
legislators have seen to date, not including those from
ExxonMobil, don't take that into account.
MR. HAYMES added that this provides incentive to explore for
more gas and to encourage others to do so. Indicating
ExxonMobil would be on the hook to pay for over half of the gas
that doesn't exist as known reserves today, he asked: To find a
Prudhoe Bay equivalent in time for the next open season or the
one after, who is drilling for that today? Where is it?
2:29:01 PM
MR. HAYMES continued. He said ExxonMobil's share of the FT
commitments is more than $100 billion. Without commitments,
there is no financing and a pipeline won't be built. Before any
molecule of gas goes into the pipeline, the state and the
producers will need to sit down and work together.
MR. HAYMES emphasized that ExxonMobil is willing to work with
the state, is honoring this AGIA process, and has been at every
public hearing and forum with both a commercial and a public
affairs representative. Furthermore, ExxonMobil has written
three letters saying it will commit its gas to pipelines,
whether at the wellhead or even at Point Thomson, as stated on
February 19, when ExxonMobil said it would commit its share of
Point Thomson gas to any pipeline, whoever holds an open season.
MR. HAYMES pointed out, however, that anywhere in the world one
makes a commitment of gas, it is with commercial conditions that
FERC also reviews to see what makes sense. That's why FERC
issues its own conditions on the certificate. There's a lot of
exposure in an FT commitment because of the need for YTF gas.
While the gas potential in Alaska is huge, it's remote, in an
environmentally challenging area, capital-intensive, and will
take a long time.
2:31:30 PM
MR. HAYMES, in further response, explained that the market seeks
long-term FT commitment. If it's 1.5 Bcf/d for 25 or 30 years,
ExxonMobil doesn't have that much gas. While it has about a
third of the North Slope gas, its FT commitment will be that
plus lots more. So ExxonMobil will carry that and cover the
liability. If the company runs out of gas in year 20, it will
still pay as though it is shipping 1.5 Bcf/d.
MR. HAYMES emphasized that this is probably the world's largest
gas pipeline project in terms of commitments. While ExxonMobil
can underwrite those and the banks will believe the company can
pay those bills, it is a massive risk to put $100-plus billion
of liability on its balance sheet and report it, not knowing
whether there will be gas to cover it.
2:34:13 PM
SENATOR STEDMAN asked about the positive side, that ExxonMobil
would get to book some reserves.
MR. HAYMES replied that three quarters of the undiscovered
resource potential in North American is in Alaska, according to
the federal assessment. Although it may not be economic or
actually there, this potential is estimated to be hundreds of
Tcf. Some, but not a lot, is onshore, but most is in federal
waters, at least six miles offshore and in an extremely harsh
environment. It will cost a lot of money and entail huge
environmental concerns to eventually get that to market, but it
will happen, since technology allows the industry a step change
in what it does every 10 years.
SENATOR STEDMAN asked Mr. Haymes to focus on the value of
booking the reserves.
MR. HAYMES answered that with ExxonMobil's share of the gas, if
it brings on a gas pipeline at 4.5 Bcf/d, it will double its
U.S. gas production and increase its worldwide gas production by
15 percent. So there is a lot of incentive to do it. But today
there are no reserves on its books for gas at Prudhoe Bay, Point
Thompson, or anywhere because it's stranded gas. The only
reserves ExxonMobil puts on its books are those burned as fuel,
which are put on and then taken off because the gas was used.
MR. HAYMES said the amount of reserves the company will add
equates to over 1 billion oil-equivalent barrels, about the
average ExxonMobil has replaced around the world per year for
the last 5 years. So yes, there absolutely is a benefit in that
ExxonMobil can book those reserves, but that's only about half
of the FT commitment it will have to make. It cannot book the
yet-to-find gas. So there is a balance.
2:37:28 PM
MR. ZAGER noted that Chevron is much smaller than ExxonMobil.
He said the YTF gas is a huge issue. How to share that risk,
many billions of dollars, will need to be addressed.
2:38:29 PM
REPRESENTATIVE DOOGAN gave his understanding that who should
develop Point Thomson has to be decided, with a separate
question of how this should occur; PetroTel has done studies,
but ExxonMobil proposes a slightly different way. In addition,
there are questions about how much the gas will be worth and so
on. He asked: If TransCanada is licensed and goes to an open
season, taking 36 months instead of 24, is there any way gas can
be nominated from Point Thomson in that timeframe?
MR. HAYMES replied first with regard to who should develop Point
Thomson, saying there are four of the largest oil and gas
companies in the world with extensive experience with high-
pressure operations. As for how, he said everyone including
PetroTel, DNR, AOGCC, and the owners agree cycling is the next
best step along with delineating the oil rim and, if that's
productive, bringing it on to production. The agreement on that
is very encouraging, he said, and ExxonMobil has a project
underway to do that, hoping it can continue to proceed.
MR. HAYMES noted ExxonMobil already has completed a confidential
data room pools process with AOGCC for Prudhoe Bay and is
underway with Point Thomson as well. Roughly by the end of this
year, AOGCC will have sufficient information to at least have a
ballpark idea of the impacts of gas offtake on liquids recovery
for both. Over time, impacts lessen because more of the liquids
will have been produced. There are substantially more liquids
at Prudhoe Bay, by a factor of 10 to 20, than at Point Thomson.
MR. HAYMES affirmed that ExxonMobil could make FT commitments in
any open season in 1-3 years. As anywhere in the world, those
would be conditional, based on reasonable commercial terms and
reaching a unanimous conclusion among the agencies on the right
offtake rate. He said progressing with the AOGCC pool-rules
process is critical for Point Thomson and Prudhoe Bay so
everyone can sit down and make an informed decision.
MR. HAYMES said AOGCC's mantra is to maximize resource recovery
and not quite, but almost, ignore economics. At some point
balancing between gas and oil must be looked at. While in an
ideal world there'd be both, no reservoir in the world ever gets
all the oil and gas out of the ground - he said it's a fact of
physics - and every retrograde condensate reservoir loses
condensate. If it were otherwise, there'd be lots to go around
for a long, long time. So ExxonMobil will be there, but with
commercial conditions and critical technical work as well.
2:44:07 PM
MS. FOERSTER also responded, saying it is possible AOGCC will
have gained enough confidence after the study to grant pool
rules that include an allowable offtake of gas. However,
questions may remain about the producibility of the oil rim, the
success of cycling, and how long cycling will take, and thus
only by drilling, producing, cycling, and testing will a ruling
be possible. While she didn't know if there could be an open
season without an allowable gas offtake, she said perhaps only
by producing the field would AOGCC get the needed information.
AN UNIDENTIFIED SPEAKER said one point of agreement seems to be
that the sooner the field is in production and wells drilled,
the better the information will be to make decisions during the
open season or subsequently. He suggested if the full legal
process is gone through, nobody will make an open season
nomination for years.
MS. THOMPSON, with respect to whether Point Thomson gas would be
there in 36 months for an open season, said her answer is maybe
but it doesn't matter for this AGIA license. She explained that
she says "maybe" because she is an optimist. It clearly isn't
headed in that direction right now, but over time she has seen
dramatic changes happen quickly, and there are a lot of changes
and shifts in opportunities now. And while it is an important
debate on the future of the reservoir, it doesn't matter for
this license because the studies submitted in the appendices say
the project can be built without Point Thomson gas.
MS. THOMPSON said while the companies that want to enhance their
bargaining leverage in the contentious Point Thomson litigation
might say that gas is essential, she doesn't believe it is true.
It also shouldn't surprise legislators that they are hearing an
aggressive position on development from the companies, because
of the prices. Citing a recent Wall Street Journal article, she
said those issues are much more complex than the question right
now. She reiterated her answer: "Maybe but it doesn't matter."
2:48:58 PM
MR. ZAGER said when he hears it is still economic, he looks at
the $16 billion of NPV that is reduced in value and thinks
that's a lot of money if the pipe is downsized from 4.5 to
3.5 Bcf/d. He surmised there is a way to capture a lot of that
value by making the right decision on Point Thomson. Mentioning
discussion of discounting the risk of developing Point Thomson,
he said maybe when Chevron is putting its own money on the table
it is a little more risk-sensitive, having been in situations
that failed after being confident going in.
MR. ZAGER added that Point Thomson is a place where the waters
have to be tested before committing that it won't be made
available for gas and that oil is being counted on absolutely.
He told members that if the wrong decision is made there, there
will be too small of a pipeline and the knowledge that Point
Thomson could have been in the mix.
2:50:23 PM
DR. CHOPRA responded to Representative Doogan as well. With
respect to a 3.5 Bcf/d pipeline, he mentioned compression to
increase the flow rate and said it's not like it would be a
smaller pipeline. As for Point Thomson gas, he noted PetroTel's
study says the oil needs to be produced first. Saying he'd
heard 25, 35, or 45 years, he added that the state can nominate
that gas; it will be there, and the sooner the liquids are
extracted out of the gas cap, the sooner that will be.
DR. CHOPRA emphasized that PetroTel's study doesn't take Point
Thomson gas out of the equation, but says that during the 45
years of the pipeline, that gas will be there. He said PetroTel
sees that the oil rim can be significantly enhanced. Its lower-
gravity oil is missing gas. If gas is added, it swells and
decreases the viscosity and thus can produce the oil.
DR. CHOPRA said if there is a timeframe of 45-50 years and
Alaska has these great discoveries of gas, the pipeline will
last indefinitely and Point Thomson gas will come sooner or
later. He cautioned, however, that if folks get greedy and
start putting the Point Thomson gas first, half a billion
barrels of liquid will be lost there forever.
REPRESENTATIVE DOOGAN expressed appreciation for the time and
effort the participants had put into this, saying he now
understands why the administration took the Point Thomson gas
out of the calculations for this pipeline.
2:53:31 PM
SENATOR WAGONER highlighted the importance of AOGCC's
information and returned to the question of when AOGCC's study
of the reservoir and modeling will be complete.
MS. FOERSTER answered that AOGCC expects to complete its
analysis within six months of final receipt of all the data from
ExxonMobil, which Mr. Haymes has indicated should be the end of
this year or a little later. In further response, she said the
legislature provided funds in an earlier session to do studies
at Prudhoe Bay and Point Thomson; right now AOGCC predicts those
funds are sufficient, but the longer things drag on, the more
costly they become.
2:55:38 PM
SENATOR WAGONER recalled some confusion during yesterday's
discussion. He gave his understanding that AOGCC will allow a
drawdown of 2.7 Bcf of gas, of which 0.7 Bcf would go into other
areas for fuel and other purposes, leaving 2.0 Bcf. He recalled
when the Stranded Gas Development Act was being considered a few
years ago, there was testimony that Point Thomson could supply
more than 4.5 Bcf of gas. He said he understands the value of
the liquids and oil, but asked why there is trouble now getting
1.5 Bcf within 10 years or so.
MR. HAYMES offered that Prudhoe Bay and Point Thomson together
have the potential to produce 4.5 Bcf/d, but that is subject to
AOGCC's approval of the offtake rate and depends on the
timeline. On a sustainable basis, Point Thomson doesn't have
that capability on its own.
SENATOR WAGONER said he'd been somewhat shocked by the
difference between the estimates of PetroTel and the industry
for recoverable reserves of condensates and oil, given that
everyone is using the same database for the same oil fields.
MS. FOERSTER responded that anytime one develops a new field,
different groups do estimates. First, exploration geologists
give oil-in-place estimates and so on. Next, a reservoir
engineer like Dr. Chopra does the model and gives another
estimate. Then a development engineer comes along, using
further information; offering a fishing analogy that compared
the development engineer to the person who actually puts the
fish on a scale and takes a knife to it, she said that wasn't
the role Dr. Chopra had.
3:01:26 PM
DR. CHOPRA told members he hasn't heard anyone dispute that
Point Thomson is a big field with 10 Tcf of gas; some say it
might produce 4.5 Bcf/d. So PetroTel looked at that 10 Tcf, not
even knowing it was classified as an oil field by the State of
Alaska. He said everyone also agrees this is a gas condensate,
averaging 66 stock tank barrels (STB) of condensate per million
cubic feet of gas. The two can be multiplied together, giving
660 million barrels of condensate.
DR. CHOPRA highlighted maximizing recovery of the condensate,
predicting Prudhoe Bay oil recovery will reach 65-75 percent
when it's done. So when PetroTel started looking at it, he
said, the objective was to provide self-sufficiency and reduce
dependence on foreign oil and, therefore, the question was how
to get the oil out.
DR. CHOPRA added that gas cycling is a simple process. The gas
is produced, and then dry gas is reinjected and the liquids are
taken out. Typically, people may not do that because they think
it might take 100 years. When PetroTel set up its simulations,
however, it found 75 percent of that condensate could be
recovered within 15 years, a very high recovery. Others have
done the work but not looked at recovery through gas cycling and
thus expect to recover only 24-25 percent. That's the
difference between the two numbers, he suggested.
DR. CHOPRA noted PetroTel looked at the upside. To get the
number for the condensate is fairly easy; PetroTel has done it
all over the world, and ExxonMobil and Chevron have done it as
well. It's a matter of cycling the gas. While folks worry
about pressure, he said PetroTel's research shows there has been
high-pressure injection since the 1970s, as mentioned earlier.
If that technology can be brought to the North Slope, getting 75
percent of the condensate should be easy.
DR. CHOPRA also pointed out that folks worry about the oil rim.
But PetroTel looked at the well tests and found these wells flow
if gas is added, with the oil becoming fine like oil at Kuparuk
or Prudhoe Bay. If that can be done, there's another 900
million barrels in the oil rim. That's how PetroTel is looking
at the field versus how others may view it, he said. PetroTel
always tries to objectively maximize the value for its client,
in this case the State of Alaska.
3:05:52 PM
MS. FOERSTER returned to her fishing analogy, saying the
PetroTel analysis, as noted in its study, assesses resource
potential, not economically recoverable oil and gas. She read,
"It should be noted that no physical constraints to the
development well, such as location of surface drill sites and
facilities or drilling departures from surface location, have
been applied during this modeling." Ms. Foerster said when
field development begins, it won't be done with a reservoir
model. It will be done with gravel and drill bits, constrained
by depths, pressures, and so on.
MS. FOERSTER added that other important aspects include geologic
conditions, rock properties, well deliverability, well costs and
spacing, well pattern geometry, and the plant; that's the knife
and scale in the analogy. An optimum number of wells will
economically recover the maximum oil and gas within a reasonable
drilling budget; however, the scope of this study did not
include optimization of development, but was designed to
estimate resource volumes and quantify the range of recoverable
resource using conceptual development scenarios. There is no
knife or scale in this work, she emphasized.
DR. CHOPRA offered clarification, saying many things in the oil
industry terminology have to be stated by SEC guidelines. There
is a strict definition of what can be called reserves, and there
are rules regarding resource potential and objectivity to the
client. He agreed PetroTel wasn't out there on the Point
Thomson site, didn't take a survey there and look at the tundra
and weather conditions, didn't design the plant, and didn't
optimize; those weren't within the scope of the study. But even
without optimizing, PetroTel was able to get that much oil.
DR. CHOPRA suggested imagining what additional potential could
be obtained if optimization of this field occurred. He said
PetroTel looked at it and used common sense about where to place
wells and what to do. That is the result of the study. If this
is a reservoir that could be done, then this is the resource
potential that could be recovered.
3:09:36 PM
SENATOR WAGONER characterized this as a tangle of information
and asked, perhaps of TransCanada or the Denali group later: If
there won't be enough gas for a 48-inch pipeline, why does a
world-renowned, major pipeline company want to build a 48-inch
pipeline and, at the same time, Denali want to do the same?
MS. THOMPSON agreed that this is a great question to ask
TransCanada and the Denali group if the opportunity arises.
SENATOR WAGONER asked how many 25-year FT transportation deals
ExxonMobil has in the Lower 48 and requested documentation so
legislators can see how those work.
MR. HAYMES answered he would follow up if that information is
allowed to be shared.
The committees took an at-ease from 3:11:45 PM to 3:30:36 PM.
REPRESENTATIVE GATTO asked Ms. Foerster whether the order for
Prudhoe Bay, which says 2.7 is the amount of offtake, dates from
the 1970s.
MS. FOERSTER affirmed that.
REPRESENTATIVE GATTO said it strikes him that an offtake order
in 2018 would allow substantially more gas because the liquids
are declining.
MS. FOERSTER replied it isn't that simple. This presupposes
that the current commission agrees the 2.7 allowable offtake was
appropriate for the last 30 years and would have been good for
the reservoir and ultimate recovery if it had been used.
However, that isn't true.
REPRESENTATIVE GATTO said he is only presupposing that the
offtake order was in the 1970s, not some other time.
MS. FOERSTER pointed out that there is no gas pipeline and 2.7
of offtake hasn't happened. She said it's faulty logic to say a
higher number would be good for the reservoir later.
3:34:47 PM
REPRESENTATIVE GATTO asked if ExxonMobil makes FT commitments
worldwide for gas it doesn't have but expects to get.
MR. HAYMES replied it's complex. ExxonMobil tries to match the
gas it has or might have with the market demands, which may be
for 25 years or 1 year, depending on the location; for this kind
of volume, it typically is longer rather than shorter. Various
companies want different volumes for specific lengths of time.
Those are stacked together and a commitment is made to transport
gas to support the financing, trying to match it with reserves
and resources. There's not always a match. If there is more
gas, the effort is to find more buyers in time. If there isn't
enough gas, ExxonMobil carries that risk.
MR. HAYMES said this unique pipeline will be the largest private
infrastructure project in North American history, hundreds of
billions of dollars. ExxonMobil believes it's important to have
an equity share of the pipeline and appreciates that TransCanada
recognizes that as well. ExxonMobil is looking for an equity
share equal to its throughput, which will help to manage
upstream, mid-term, and downstream risks.
MR. HAYMES added that when TransCanada seeks financing for the
pipeline, it will need to take the commitments made by the
companies. Noting he didn't know those amounts and could only
speak for ExxonMobil, he said if there only is Prudhoe Bay gas
and the owners commit their relative shares, for example, that
isn't enough to finance this pipeline.
3:37:29 PM
REPRESENTATIVE GATTO asked whether the commercial terms
Mr. Haymes had mentioned earlier include tax terms that the
state would impose.
MR. HAYMES answered that this refers to all commercial terms
impacting economics or cash flow for a producer like ExxonMobil.
They're looking for predictable terms, just as someone
approaching a bank for a home loan wants to know the interest
rate. This is just on a much larger scale.
REPRESENTATIVE GATTO observed that a bank loan also figures in
property taxes and insurance, which likely increase each year.
Giving his understanding that 10 years is specified under AGIA,
he asked whether that is sufficient time, since he surmised the
first 10-year period is the most important.
MR. HAYMES replied if ExxonMobil had FT commitments for
10 years, that would be sufficient, but they'll likely be much
longer. He said that the gasline findings documents talk about
how changing the tax terms by 50 percent after 10 years has no
substantial impact on NPV for the shippers, and that if changing
the taxes doesn't impact the shippers, then it wouldn't impact
the state. However, ExxonMobil looks at cash flows as well.
Saying nobody intentionally operates a pipeline at a loss, he
recalled that a graph in Appendix G-1 or G-2 of the decision
documents shows a negative cash flow after year 10. He
suggested this needs to be considered.
3:40:45 PM
SENATOR DYSON remarked that historically in Alaska, the resource
has been harvested and taken elsewhere to be refined; it seems
not much of the money stays in Alaska. He also relayed his
understanding that in North America the gas liquids, ethanes,
propanes, and so forth are generally refined near the market,
rather than near the production, for economic reasons. He
asked: Is there any way it could work economically to keep the
refining and value-added jobs in Alaska, given the logistics and
transportation issues?
MR. ZAGER replied he hadn't looked at that particular issue, but
generally there is excellent transportation for these liquids,
the pipeline that has been built. If the products are refined
in Alaska, separate products will need to be transported
individually to keep their value. From a macro-economic
perspective, Alaska is fairly disadvantaged in that market.
MR. HAYMES concurred, saying while not impossible, it would be
extremely challenging because Alaska is so remote from the
consumers, with a small population and huge land mass. Whereas
high-end products would require a transportation system for each
product, now it can all go down the oil pipeline, with economies
of scale for transportation, and then be refined elsewhere. He
added he hadn't looked at it in detail.
3:44:00 PM
REPRESENTATIVE GARA asked about what seems to be an
inconsistently. Noting he doesn't necessarily buy that the
Point Thomson gas is needed for a pipeline, he recalled in 2005
ExxonMobil proposed a 4.5 Bcf/d pipeline under the Stranded Gas
Development Act. He asked why that isn't the case now.
MR. HAYMES agreed under that Act a proposed 4.5 Bcf/d pipeline
was supported by the major shippers and producers. He said it
was recognized then that there were yet-to-be-discovered
resources, although he wasn't there for that extremely complex
contract. He opined that this can work, but requires everybody
sitting down together, including all the producers, the
government, and any other party that can add value, not just
TransCanada. He noted a recent deal to sell gas to Fairbanks
Natural Gas took a year to settle to the satisfaction of both
parties. He said ExxonMobil's position hasn't changed.
REPRESENTATIVE GARA asked whether it's fair to say Mr. Haymes
believes there can be 4.5 Bcf/d today if all parties align.
MR. HAYMES replied that's fair to say, but it will take a lot of
work from everybody to get there. The 4.5 Bcf/d included Point
Thomson gas.
REPRESENTATIVE GARA suggested there may be areas where the
state's interests align more with ExxonMobil than ExxonMobil's
interests align with BP and ConocoPhillips at this point.
Noting only ExxonMobil had responded to a letter sent to all
three producers asking whether they'd be willing to commit gas
to an independently owned pipeline, he said ExxonMobil had
answered yes, with the caveats Representative Gatto discussed.
REPRESENTATIVE GARA gave his understanding that BP and
ConocoPhillips oppose the TransCanada proposal, whereas he isn't
hearing ExxonMobil be as vocal on that, and that whereas
ExxonMobil is seeking an equity share in the TransCanada
project, BP and ConocoPhillips aren't. He asked: Is it correct
that ExxonMobil at this point isn't interested in the BP-
ConocoPhillips deal, but is interested in possibly becoming part
owner of the TransCanada project?
MR. HAYMES answered that ExxonMobil is evaluating both proposals
carefully and believes eventually a gas pipeline will need all
the producers and the state to come together; otherwise,
there'll be no pipeline. At this point, neither proposal has
been ruled out. He added that ExxonMobil recognizes and is
honoring the AGIA process that the state is going through and
wants to work with the state to make it happen.
3:49:15 PM
REPRESENTATIVE GARA highlighted the commitment stated in the
letter to him and other legislators that said ExxonMobil would
sell gas. He asked about caveats.
MR. HAYMES specified that ExxonMobil meant it would commit its
gas on reasonable commercial terms.
REPRESENTATIVE GARA gave his understanding that part of that
means long-term fiscal certainty, as Representative Gatto talked
about. He asked: Apart from fiscal certainty, will you demand
production tax cuts from the state?
MR. HAYMES replied he wasn't sure yet what those reasonable
commercial terms would be. They'd be worked by ExxonMobil's gas
marketing company on the same basis as for every gas deal in the
world. He said he wasn't privy to what that would be at this
point, but clearly it would be an engagement discussion point in
order to work that together.
REPRESENTATIVE GARA referred to the fact that the Denali project
of BP and ConocoPhillips proposes a competing line. He asked
whether perhaps they haven't offered to commit gas to an
independent line, even with caveats, because they'd rather sell
gas into their own line and maybe block the TransCanada deal.
MR. HAYMES suggested that question would be best put to those
companies.
3:51:27 PM
REPRESENTATIVE FAIRCLOUGH noted she isn't a lawyer and thanked
participants for their decorum while legislators try to
understand everyone's positions. She asked how many plans of
development have been approved at Point Thomson.
MS. THOMPSON replied that 20 PODs were approved. The 12th,
22nd, and 23rd were not.
REPRESENTATIVE FAIRCLOUGH asked: When the state started
accepting PODs at Point Thomson in the first five years, were
they just for moving the ball forward, rather than actual plans
for production?
MS. THOMPSON responded that within the first five years there
was discussion about production. While there wasn't a specific
plan to put oil into the Trans-Alaska Pipeline System (TAPS),
the first POD talked about doing so. Recalling a statement
yesterday, she clarified that the regulation specifically
references production as a requirement in a POD; she would
provide the regulation to Mr. Haymes after today's meeting.
REPRESENTATIVE FAIRCLOUGH gave her understanding that although
Commissioner Irwin decided to deny development at Point Thomson,
some previous administrations had consequences in the form of
penalties and had accepted development there.
MS. THOMPSON, replying to further questions from Representative
Fairclough, explained that each lease sale usually has a
different primary term of five, seven, or ten years, depending
on where the lease is located and how long the department feels
is reasonable to get the land into production. While lease
terms have changed over time, this isn't necessarily to hold a
particular unit accountable. She said she believes the decision
about the terms is made before every lease sale; it depends on
the location and what is known about the resource already.
3:56:05 PM
REPRESENTATIVE FAIRCLOUGH highlighted concern about access to
the pipeline and a public perception that access has been denied
to TAPS. She noted she'd received an e-mail from a constituent
about the Texas Railroad Commission, which for common carriage -
as opposed to contract carriage - allows throughput
proportionate to reported reserves. Suggesting such a system
for the gas pipeline would allow explorers to open the basin to
show they have proven reserves in order to acquire space on the
line, she asked what Ms. Foerster knew anything about that.
MR. FOERSTER responded that the only company that isn't an owner
of TAPS that has requested access is Pioneer at Oooguruk;
Pioneer started production in the last week or two, and now its
oil is going into TAPS. She agreed that lack of access to TAPS
is a perception. Noting she'd worked in Texas many years ago
but has been in Alaska more than 16 years, she surmised how the
Texas Railroad Commission conducts its business has changed and
said she didn't recall details; she declined to speculate.
AN UNIDENTIFIED SPEAKER gave his understanding that whereas an
oil pipeline is usually prorated according to the amount of
reserves one has, a gas pipeline takes long-term commitments and
thus the company putting up the financing wants to be assured
that it can actually move its gas.
REPRESENTATIVE FAIRCLOUGH said that's why she'd indicated she
understood the difference between contract and common carriage.
She reiterated that she'd thought it perhaps could be applied to
provide access and assurance that one owner wouldn't have a
majority interest that could push others out.
4:00:19 PM
REPRESENTATIVE FAIRCLOUGH asked about the difference between the
administration's model using a Monte Carlo approach and the Wood
Mackenzie model. She said she'd asked various presenters for an
explanation, but hadn't received an answer.
MS. FOERSTER replied she has no expertise in uncertainty
modeling but has benefited from Monte Carlo simulations, which
are commonly accepted as an appropriate way to model
uncertainty. She didn't know what was used in the Wood
Mackenzie study.
CHAIR HUGGINS asked Commissioner Galvin to bring an answer
tomorrow during the presentation.
4:02:18 PM
REPRESENTATIVE FAIRCLOUGH recalled yesterday it was said that
applications for permits had been submitted to DNR for wells and
an ice road. Noting the administration says having two
competing projects isn't a problem, she asked: Will the regular
process and timeframe occur, and will the permit applications
just received from the producers sitting at the table be
thoroughly vetted and then either approved or denied in an
appropriate time period?
MS. THOMPSON, noting she'd addressed this at the beginning of
the roundtable discussion, observed that the pre-application
meeting should be wrapping up now and opined that no
applications have been submitted yet. She reiterated some of
her earlier explanation.
MS. THOMPSON added that what will happen to the permits depends
on the leases they'll operate on. As she'd explained yesterday,
there are 45 separate leases in the former Point Thomson unit,
and whether they still retain the rights to develop those lands
depends on what they're going to do; when they're going to do
it; and, most significantly, what land they're going to do it
on. That's something her agency found out this afternoon when
looking at the pre-application finding.
MS. THOMPSON emphasized that while DNR's position is to not
interfere with valid leasehold rights, there is a difference of
opinion as to what those rights are. The department is
beginning the process to understand which leases will be
affected and then will work with its legal counsel to figure out
whether they have the right to develop it. That will be
resolved in the coming months.
4:05:02 PM
MS. HOULE suggested Mr. Zager could speak to this also, but said
many times companies have leases and form a unit, doing surface
permitting through DNR's lease-permitting group for a lot of
wells and sites. On the North Slope, for example, companies
will permit maybe a dozen locations because they aren't exactly
sure until they look again at their seismic data and so on.
Many sites that receive permits may never be drilled.
4:06:00 PM
REPRESENTATIVE FAIRCLOUGH asked whether it's accurate that
Commissioner Irwin and the administration are in the process of
exerting the state's rights at Point Thomson from the
administration's perspective, taking away those leases and
shutting down the unit.
MS. THOMPSON answered that the commissioner has issued a
decision that the unit is terminated. Consequently, because
almost all the leases are beyond their primary terms and some
are held just because they're in the unit, the legal process to
terminate the leases will also begin. As she'd explained
yesterday, there are different arguments. Some leases have had
wells drilled; some have not. They're all being looked at
individually to determine the correct resolution.
4:06:52 PM
REPRESENTATIVE FAIRCLOUGH said she takes seriously her oath to
protect the State of Alaska. Expressing concern with the
genuineness of saying there can be competing pipelines if
someone is submitting permits for development and those are
under litigation, she asked: As we try to move a commercial
private project forward, will it be put at bay because of the
legal process, even if rightfully so? Does taking back
possession of Alaska's natural resource in essence makes it
impossible for the private sector to compete?
MS. THOMPSON responded that the competing pipeline is from BP
and ConocoPhillips, not ExxonMobil. Also, the administration
believes this AGIA project can proceed with or without gas from
Point Thomson. The effort isn't to interrelate the two. The
effort to regain the leases in Point Thomson is based on what
has happened in that unit since it was formed in 1977, not any
particular objective that has to do with AGIA.
MS. THOMPSON added that the administration will give them a fair
shake. If the permit applications eventually submitted are for
leases that they have the right to continue operations on, those
will be granted. Referring to Ms. Houle's comments, she said
plenty of lease operations continue even without a unit on the
North Slope. She pointed out that she doesn't yet know what the
application says and must see it in order to provide an answer.
REPRESENTATIVE FAIRCLOUGH replied she appreciates that, but
today they've heard having more data will allow knowing more
precisely what Point Thomson has. If acquiring that information
is postponed, it becomes more costly; if it is received sooner,
it drives the tariff down because there'll be more gas
commitments and a better financing package to take to market.
REPRESENTATIVE FAIRCLOUGH said although she understands the
distinction between the competing pipelines, there is a benefit
to better understanding the reserves and the reservoir, to know
when it can deliver. She questioned just letting the free
market work when more information is needed and yet the ability
to get that information is being pushed outward in time. She
asked Mr. Haymes about the permits.
4:10:39 PM
MR. HAYMES said ExxonMobil submitted permitted applications last
week and he personally signed the checks to go with those permit
application letters. As the operator, ExxonMobil submitted
those permits on behalf of all the leaseholders at Point
Thomson, including BP, ConocoPhillips, Chevron, and 24 others.
REPRESENTATIVE FAIRCLOUGH gave her understanding that the state
believes there is a high probability it can win and take back
the leases. She asked, however, whether there isn't potential
increased risk for the state in denying a permit, should
ExxonMobil win in court.
MS. THOMPSON replied that's a question the legal team working on
Point Thomson is very carefully evaluating.
4:12:20 PM
CHAIR HUGGINS asked whether the permitting is for two pieces:
the wells and the ice road.
MR. HAYMES answered that there are permit requirements across
quite a number of fronts, and those two are correct. There also
are land-use permits, coastal water permits, and a number of
different agencies with permitting requirements to undertake
field activities on the leases at Point Thomson.
CHAIR HUGGINS told Ms. Thompson he'd be interested in basic
infrastructure that he surmised won't rest on whether a well
will be honored. He asked what the state's position will likely
be on an ice road.
MS. THOMPSON replied it depends on its location and who has the
right to build it on the land where it is proposed. She said
she couldn't answer without knowing the location, but could
provide that information if the committee so desires.
CHAIR HUGGINS said his interest is simply wanting to get Point
Thomson into production as soon as possible.
4:13:42 PM
REPRESENTATIVE FAIRCLOUGH requested that the administration have
a conversation with the legislature about denying permits. She
said there must be a way to protect the state legally and let
the state do what it believes is in the best interests; she
mentioned offering a credit, for instance. She emphasized that
denying a permit seems to put the state further behind with
respect to having Point Thomson on line.
4:14:33 PM
REPRESENTATIVE KERTTULA relayed her understanding that projects
such as the ice road can be phased, which has frequently been
done in Alaska following a series of court cases. She asked
whether this has helped to speed up the projects and suggested
the state certainly would look at that.
MS. THOMPSON concurred, also agreeing with Mr. Haymes that there
are a lot of different permits potentially at issue. She said
there can't be a general answer; it may be different for each.
She indicated it is something the administration is looking at
carefully with the legal team working on the Point Thomson
litigation. In further response, she said the administration
hasn't shut the door and said it isn't taking any applications
from ExxonMobil.
4:15:47 PM
REPRESENTATIVE KERTTULA pointed out that it was the previous
administration that finally put its foot down, specifically,
Commissioner Menge. She said she couldn't recall how many PODs
had been put forward during the Murkowski Administration, but it
didn't begin here when the final denial came.
MS. THOMPSON agreed it was then-Commissioner Menge; the unit was
terminated at the end of the Murkowski Administration. The
owners asked for reconsideration, and Commissioner Irwin wasn't
there yet, so it was then-Acting Commissioner Rutherford who
affirmed on reconsideration.
4:16:27 PM
REPRESENTATIVE KERTTULA recalled hearing yesterday that AOGCC
had supported this POD, but offered her own recollection that
AOGCC had actually stayed neutral.
MS. FOERSTER said Representative Kerttula was right. She
explained that AOGCC needs to stay neutral in these sorts of
things. Ms. Foerster noted at the Point Thomson hearings with
DNR, someone quoted her as saying she loved the plan.
Clarifying that on a technical basis she believes it is a
fabulous plan, she remarked, "If three of the biggest and most
successful oil companies on the planet can't come up with a
technically fabulous plan, then God help the industry." She
said the POD also answers the questions AOGCC needs answered.
MS. FOERSTER pointed out, however, that DNR and not AOGCC
approves plans of development. While DNR looks at some of the
same things as AOGCC, it also looks at different things and
looks differently at some of the same things. "Not my job, with
all due respect," she concluded.
4:17:59 PM
REPRESENTATIVE COGHILL followed up on Representative
Fairclough's questions regarding permits. He said he
understands the ticklish issue with Point Thomson, but with
respect to a competing pipeline application, TransCanada and
Denali may both be seeking permits for everything from crossing
rivers to getting access to resources within DNR. He asked
whether the state is able and willing to work with both and
whether there is sufficient staffing capacity.
MS. THOMPSON replied certainly there is a willingness to work
with whatever pipeline applicant there is. Agreeing there is a
whole array of permits, she noted Representative Fairclough had
inquired about the specific permit applications from ExxonMobil
to develop Point Thomson.
MS. THOMPSON said permits for rights-of-way and so forth will
need to be resolved by whichever project goes forward, and the
state stands ready. Pointing out that she isn't the person to
answer about staffing, she suggested Commissioner Irwin would
inform the legislature if additional resources are needed to
process two applications.
4:20:00 PM
REPRESENTATIVE COGHILL asked: Does approving the AGIA license
preclude DNR's ability to assist the Denali project?
MS. THOMPSON replied that specific provisions in AGIA talk about
what can't be done and associated penalties. Noting that
Commissioner Galvin was listening, she suggested he could answer
better tomorrow.
REPRESENTATIVE COGHILL said at least one vote hangs on that
answer.
4:21:23 PM
MR. ZAGER closed by expressing concern that Ms. Thompson had
implied Chevron's motive for its position was because it would
somehow enhance its leverage in the Point Thomson issue. He
said Chevron has been consistent year after year in its view of
Point Thomson and has agreed with every administration until a
couple of weeks ago. The position has changed on the other
side, however. He suggested it benefits the administration's
position on Point Thomson to now say that gas isn't needed for a
gas pipeline.
4:22:22 PM
MR. HAYMES closed by saying ExxonMobil wants to work with DNR to
resolve the Point Thomson dispute, believing its POD does
everything needed to prudently develop the resource and manage
the risks for the state and the leaseholders. He said he was
encouraged to hear Ms. Thompson say that of course the state
wants to develop this resource.
MR. HAYMES added that this gas is critical for a gas pipeline
and the sooner it can be moved forward, the better. ExxonMobil
has a real project underway, with people employed and working
that today, and will be awarding more contracts in the next two
weeks, Alaskan contractors. The permit applications are in, and
those are essential to continue.
4:23:30 PM
MS. THOMPSON offered an example to follow up Representative
Fairclough's question about access denied to TAPS. Ms. Thompson
recalled that the then-president of Conoco, before Conoco owned
an interest in TAPS, said he'd sold his interest in the Milne
Point unit and it broke his heart to do it; he couldn't make
that production economic unless the company also owned an
interest in the pipeline.
4:24:42 PM
CHAIR HUGGINS thanked participants, noting the administration
would continue its presentation on NPV tomorrow.
The meeting was recessed from 4:27:39 PM to 6:02:31 PM.
^Public Testimony
CHAIR HUGGINS called the meeting back to order. He welcomed the
public, noting that because there were relatively few
testifiers, each would be allowed about five minutes.
6:04:07 PM
CHARLES McKEE told members he'd listened to some of the Black &
Veatch discussion of estimated expenditures based on dollars
today and the discounted rate. He spoke about a 2 percent
charge on Federal Reserve notes, talked about the Treasury seal,
and said part of American history was abdicated because of not
wanting the U.S. to break away from that rental policy imposed
in 1913.
MR. McKEE said while oil is traded in dollars, the Euro is
gaining influence in the U.S. and the world. Expressing concern
that the producers have attempted to stifle development outside
of their control, he shared a map, discussed his website, and
asked: If we're going to have an open market, what currency
will we use and how will it be devalued?
6:11:21 PM
PAUL LAIRD, General Manager, Alaska Support Industry Alliance,
noted his trade association of companies provides goods and
services to Alaska's oil, gas and mining industries. He was
testifying on behalf of its 430 member organizations that have
approximately 35,000 Alaskan employees.
MR. LAIRD, assisted by others, sang a song to the tune of "How
Do You Solve a Problem like Maria?" from The Sound of Music. It
began, "How do you solve a problem like AGIA? How do you tell
the truth from all the hype?" The lyrics expressed numerous
concerns - including that Point Thomson gas is off the table,
that the state subsidy is wrong, and that the power lies with
FERC - and asked legislators to vote against the AGIA license
and instead support the Denali project.
6:15:22 PM
JERRY McCUTCHEON began by claiming he'd killed the gas pipeline
in the 1980s. He said he'd tried to tell the legislature in
1976-1977 that a gas pipeline isn't in Alaska's best interests
and that gas offtake could only come at the expense of oil
production. Opining that the oil companies lied about Prudhoe
Bay production, he said Ms. Foerster, when pressed for an amount
and date for gas offtake, told the legislature Prudhoe Bay had
already produced 6 billion barrels of oil more than if a gasline
had been built in the 1980s.
MR. McCUTCHEON said the parameters today are the same as
30 years ago and will continue 30 years more. He voiced concern
about information presented during the Murkowski
Administration's efforts to get a gasline. He also suggested
suing the oil companies to find out how much oil is in Prudhoe
Bay; he estimated another 10 billion barrels.
MR. McCUTCHEON concluded by calling AGIA a disaster and saying
it will only get worse. He cited testimony that the
responsibilities need to be memorialized and that Chair Huggins
had suggested the need for a contract as well as a license.
Noting he doesn't support the Denali project either, he opined
that discussion of a gasline is at least a decade premature.
6:24:18 PM
MATTHEW FAGNANI told members that constructing a natural gas
pipeline is critical to the state's economy. Characterizing the
administration's presentations as propaganda, however, he asked
that legislators listen closely to the industry and vote no to
this license
MR. FAGNANI inquired why the state downgraded the project to a
3.5 Bcf/d line and expressed surprise at hearing that 2.0 Bcf/d
from Prudhoe Bay and yet-to-be-identified fields can be counted
on. He asked why the pipeline isn't built to handle Alaska's
full known gas capacity.
MR. FAGNANI expressed concern that Commissioner Irwin is holding
up production of Point Thomson in the courts. He said Point
Thomson needs to be in production; there will be lower oil
revenues if Prudhoe Bay is tapped prematurely for gas, which
isn't managing the resource for the maximum benefit.
MR. FAGNANI also said a private-sector gasline of this magnitude
should be viable without monetary inducements; a $500 million
state subsidy should be of great concern for budgetary reasons
and because it isn't contingent on actually building a pipeline.
Highlighting jobs and not more taxation of the industry, he
urged members to reject the AGIA proposal and let the
competitive marketplace work.
6:28:12 PM
MAYNARD TAPP told members he is against the AGIA proposal and
believes in supporting the tried-and-true companies of BP,
ConocoPhillips, and ExxonMobil that have invested so much to
help Alaska become an enviable place with a surplus of tax
revenues. Saying he doesn't doubt TransCanada's integrity or
strength, he expressed hope that TransCanada can become partners
with Denali and others to build this project.
MR. TAPP said because of financial risk to the state, he can't
see providing $500 million to do something that is already being
done. He also doesn't believe AGIA offers the correct
incentives to avoid failure. However, he believes AGIA is a
success in that the Denali project has been formed and is
progressing.
MR. TAPP opined that the only economic reason for a gasline is
to grow the oil-based business upon which the state's wealth
depends. Financing will be through proven reserves of gas,
including Point Thomson. He said building a gasline enables oil
and gas development because there'll be two transportation
systems to market: TAPS and the Denali gas pipeline.
MR. TAPP offered his belief that state revenues from gas are
best protected by commercial entities influenced by the risks of
the project; those owners have a stake in controlling the costs
of pipeline construction, and ultimately transportation, to
ensure the most competitive product in the market. With oil
declining 6 percent a year, he said the gasline must not be
delayed and the state must work with the producers to encourage
more oil production.
6:32:01 PM
MIKE ROGERS indicated he believes in August 2010 the people of
Alaska should vote up or down on treble damages on the
$500 million and conditional approval. Mentioning FERC
testimony, he said consensus has emerged as a dominant concern
because two pipelines could receive regulatory approval.
Reasonable people have raised questions that can't be answered
in the 60-day limit provided in AGIA.
MR. ROGERS said it makes no sense at this time to give carte
blanche approval to development, when real doubts exist
regarding both the science of gas fields and the financing of
gas pipelines. With conditional approval, Alaskans could
preserve their rights to continue to negotiate while others with
obscure agendas maneuver for advantage. If the legislature
approves this license, he asked that it be amended to allow
Alaskan citizens to vote and said he would vote no. Adding he
doesn't support the Denali project either, he sang a song
dedicated to the "victims of AGIA."
REPRESENTATIVE GARDNER clarified that the treble damages
provision, should the state grant a license and then materially
support another project, doesn't apply to the $500 million.
MR. ROGERS replied that was good to hear, since he believes the
only project that will eventually get built, unless the Alberta
tar sands become highly profitable, is an all-Alaskan pipeline
to Valdez.
6:39:05 PM
BARBARA BACHMEIER, speaking on her own behalf, noted she is
affiliated with a statewide nonprofit organization providing
services to Alaskan veterans, many disabled. She'd read in the
Anchorage Daily News on April 9 that the BP-ConocoPhillips
project called Denali was offering 150 jobs to Anchorage-based
employees by year's end. She said she was delighted, thinking
about putting veterans to work.
MS. BACHMEIER said, however, Denali's website didn't give
employment information, so she'd called the contact person, who
on April 23 said it would be two weeks; on May 8 he didn't know
when it would be. Yesterday the website still didn't list
employment information, but the June 18 paper said the 150
employees to be assembled by year's end will be from BP,
ConocoPhillips, and outside contractors. Noting she wasn't
happy about that, she said 150 jobs were promised.
MS. BACHMEIER also said TransCanada Alaska has no office space
at this time, no business plan, and no employment plan, although
she'd been told the opportunity for jobs may be known in about
18 months. She suggested Alaskans deserve better in both
instances. When jobs are promised, they should be delivered.
She closed by saying she'd prefer that the state do this on its
own and that she doesn't support AGIA, TransCanada, or Denali.
6:44:01 PM
JOHN WOOD told members he isn't affiliated with oil companies or
the state and believes this is one of the most important issues
the state has ever faced. He opined that AGIA's shortcoming is
that the $500 million would have made more sense if additional
competitive bids had been received; its strength is that it has
shown the oil industry it isn't the only game in town and thus
will bring the companies to the table.
MR. WOOD expressed disappointment that the administration wasn't
represented at this public hearing. He said TransCanada appears
to be the company that could bring a pipeline down the highway
route, since TransCanada appears to know what it is doing and
has the industry contacts to pull it off. From a public
perspective, he doesn't know what project is best for Alaska.
He requested a side-by-side comparison of in-state LNG from
Valdez versus the TransCanada line to Alberta.
MR. WOOD highlighted ensuring that the oil fields aren't
impacted. Saying this is the time to negotiate with the
producers, LNG companies, and TransCanada, he said if it isn't
successful, then the Point Thomson decision should be followed
up. Suggesting a win-win situation can be created with all
players at the table with an incentive to go forward, he said
there is no need for the state to lay out $500 million to do it.
Mr. Wood specified that he isn't in favor of the AGIA process,
but wants it on the table as a negotiation tool.
6:48:39 PM
KATE TROLL, Executive Director, Alaska Conservation Alliance
(ACA), noted her umbrella organization is composed of 40 state-
based conservation groups with about 38,000 Alaskan members.
Since how energy is used is highly important to the conservation
community, last year ACA developed a position paper supporting a
gas pipeline. They see Alaska's natural gas as a bridge to a
future with clean, renewable energy for Alaska and the U.S.
MS. TROLL said while wanting more information before deciding on
a stand-alone LNG proposal, ACA was pleased to see TransCanada
is willing to consider an LNG option. Based on available
information, ACA supports a pipeline that meets its criteria and
principles, finding TransCanada's proposal more closely aligns
with those, compared with the Denali proposal. She said ACA
supports the AGIA project, tempered with concerns it hopes to
work with the Palin administration to address.
MS. TROLL detailed the concerns: incentivizing the flow of gas
to the Lower 48 to offset coal-fired generation and away from
the Alberta tar sands, where producing energy generates three
times more greenhouse gas emissions than producing oil and is
highly inefficient; ensuring in-state use and a more thorough
analysis of greenhouse gas emissions; maximizing benefits to
Alaskans, which ACA believes an open-access pipeline that spurs
competition will do, providing billions more in revenues than a
pipeline controlled by the producers; considering an oversight
council; and providing incentives for clean, renewable energy,
for which ACA believes this pipeline will be the bridge.
REPRESENTATIVE GATTO asked whether the 38,000 Alaskans are dues-
paying members.
MS. TROLL affirmed that.
REPRESENTATIVE GATTO surmised ACA also supports solar, wind,
geothermal, and hydroelectric power, but not coal, nuclear, and
diesel.
MS. TROLL replied that was a good summation. The gas is the
bridge, since there cannot just be a shift into renewables
because of the fossil-fuel dependency.
6:57:48 PM
CHAIR HUGGINS recognized DOR Commissioner Galvin representing
the administration and Tony Palmer of TransCanada.
6:58:15 PM
CAMILLE CONTE gave her understanding that last Friday the
governor's gas team recognized that the comparison between the
analysis of TransCanada's proposal and the in-state line was
based on a mathematical model that inadvertently produced skewed
numbers. She urged legislators to find out the accuracy of that
and report back to the public.
MS. CONTE also gave her understanding that some time ago the
governor said the state would use the in-state line put together
by the Alaska Gasline Port Authority ("Port Authority") for an
apples-to-apples comparison with TransCanada's project. While
Ms. Conte said she isn't against AGIA, which sets a framework
and has good aspects like the open season and items that put the
state in the driver's seat, she suggested possibly amending it,
looking at what may be transferable for what is done next.
MS. CONTE told members she doesn't support giving a license to
TransCanada. If the pipeline ends in landlocked Alberta, it
only allows shipping within North America, whereas an in-state
line to Valdez allows barging the gas to markets that pay the
most, such as Asia. She said ConocoPhillips is one of the
companies that own the majority of the tar sands, and to her
understanding AGIA doesn't guarantee that the state can control
how the gas is used once it leaves Alaska. Also, for an in-
state line the existing TAPS corridor doesn't require dealing
with the rights-of-way or environmental factors in a way that
can trip this up. And it doesn't require dealing with FERC.
MS. CONTE suggested this is a powerful time for Alaska to take
hold of this project, since AGIA has brought Alaskans to
understand that the TransCanada proposal doesn't give Alaskans
what they want. She opined that 80 percent of Alaskans say they
want the state to explore a line to Valdez. Highlighting the
importance of having an open mind, she asked the legislature to
thank TransCanada for its work, say no to the license, get the
numbers about the in-state pipeline, and get going on that line.
SENATOR BUNDE relayed what he understands from Washington, D.C.,
that an in-state line won't receive an export license to send
gas to Asia when the Lower 48 needs Alaska's energy. After
there's a line to the rest of the country, a spur line is
possible. An in-state line alone won't get an export license.
7:06:24 PM
BRIAN DAVIES told members he'd worked for BP over 30 years and
retired in 1994. He suggested there are four major players:
the State of Alaska, the producers, TransCanada, and Enbridge or
another pipeline company; each could delay the project, and all
except the state are signaling that they know they must come
together.
MR. DAVIES said while it now appears there'll be two competing
projects, only one can succeed at the open season because gas
can be committed to only one; he surmised that will be Denali.
He opined that Denali will need to deal with TransCanada, which
claims exclusive rights to build across Canada, as well as
Enbridge and other entities that are disputing TransCanada's
rights.
MR. DAVIES specified that he opposes granting an AGIA license
because he believes it will inhibit the necessary coming
together of these players and greatly delay the pipeline. He
urged legislators to focus on those impacts to Alaska and the
nation. While applauding AGIA for changing the nature of the
conversation, he said the process has limitations. He asked
legislators to think about a role for the state in facilitating
that coming together, rather than driving the projects apart.
MR. DAVIES agreed with Senator Bunde's response to Ms. Conte
about exporting natural gas. With energy supplies so critical
for the nation, Mr. Davies said he believes there is no hope for
exporting Alaska's gas.
7:12:04 PM
SENATOR McGUIRE noted some legislators have talked about
facilitating negotiations, but the result seems to be pushing
folks further apart. She asked whether Mr. Davies had any ideas
on how such negotiation might be facilitated.
MR. DAVIES replied he didn't, but cited the conversation about
the coming together of interests years ago for TAPS. He said he
believes the state and administration could really help this
project move forward. It is inefficient to have two separate
entities spend money on the same thing, with one spending the
state's money as well. He said TransCanada undoubtedly has a
huge database on how to build pipelines in Canada, but not in
Alaska. The producers have spent millions or billions of
dollars in the 1980s and now. These two entities should come
together as soon as possible.
SENATOR McGUIRE opined that the travesty is that the competing
companies do have complementary expertise in building pipelines
and production and were in the same room together as little as
three years ago. Now an up-or-down vote will change the face of
the state forever, with few tools. She said she has thought
about whether there could be an arbitrator with expertise, for
instance. She said they all deserve a seat at the table.
7:15:25 PM
REPRESENTATIVE GARA thanked Mr. Davies for his community
service, but asked why AGIA prevents the companies from coming
together, or the $500 million from the state, or rolled-in
rates, even though the major companies would rather have a lower
rate on their own gas and a higher rate on somebody else's.
REPRESENTATIVE GARA, while recalling that some major players
also oppose the five offtake points, said it doesn't prevent
them from coming into this line. He opined that if the
legislature voted no and just left it to Denali, the producers
would have the state over a barrel and demand tax concessions
and so forth.
MR. DAVIES replied that he had no specific items in mind with
respect to AGIA and that the aspects Representative Gara had
mentioned would be part of any pipeline project. He said his
concern is the constraints from granting an exclusive license.
It isn't really about the treble damages. It's about erecting a
barrier so folks aren't talking.
MR. DAVIES predicted that if granting the AGIA license keeps the
Denali project rolling, it would lead to an unsuccessful
TransCanada open season and a successful Denali open season;
however, TransCanada still would have to get on board because of
its claim in Canada, which he surmised will lead to the Canadian
courts and delay. Reiterating that the parties must come
together, he asked legislators to look at that and, if they vote
yes in order to keep the Denali project going forward, look for
some way to lift those constraints at some stage.
7:20:07 PM
REPRESENTATIVE GRUENBERG surmised that bringing people to the
table would mean voting down the current AGIA application,
putting the state back where it was. He asked how people would
be brought together then.
MR. DAVIES suggested, for instance, it could be voted down and
then the legislature could say everyone needs to come together.
REPRESENTATIVE GRUENBERG suggested approving it and then they
could come together afterwards.
MR. DAVIES asked that the legislature make sure it isn't
erecting another barrier.
7:22:10 PM
RON AKSAMIT asked that legislators approve AGIA, which he
believes won't impede TransCanada and the producers from getting
together. He said they need each other, whether they admit it
or not.
MR. AKSAMIT explained that while he isn't wildly in favor of
AGIA and is less enthusiastic about giving away $500 million, it
is important to keep TransCanada in the game. Prior to this,
the producers weren't enthusiastic about building a pipeline.
If AGIA didn't go forward, the producers could find 100 reasons
to halt the Denali project. He suggested when it's economical
to build a line and fill it with gas, it will happen.
MR. AKSAMIT told members he doesn't think government should try
to facilitate this partnership; in general, government impedes
private industry. He believes the ideal is that the producers
and TransCanada get together to build a line and fill it with
gas; there is little the state can do to in this regard that
they cannot do themselves. Economics will be the driver.
MR. AKSAMIT opined that the Denali project will stop at the
border when it gets to Canada unless a Canadian company is
involved. As for a line to Valdez for natural gas, he agreed
with Senator Bunde that it won't happen first. Citing the
history of failed government projects in Alaska, he spoke
against state involvement in this one. He surmised when the
economics and politics allow, there can be a spur line.
7:26:23 PM
TOM LAKOSH told members while there are numerous environmental
reasons why legislators should vote against AGIA, he would put
on his consumer-and-citizen hat today. He said only TransCanada
has all the pieces of the puzzle. The state turned to AGIA
because the producers failed to honor their lease at Point
Thomson and timely develop the oil and natural gas liquids.
MR. LAKOSH said while the producers complain about the
$800 million they invested, it will cost the state more. This
is because of not only lost revenues to date, but also paying
more for an oversized pipe in financing and so on. The major
underpinning of the leases is the requirement to drill until it
isn't profitable.
MR. LAKOSH proposed declaring Point Thomson a state scientific
study area and developing the natural gas liquids and oil as
quickly as possible to meet AOGCC requirements before taking off
the gas; the state could hire its own drillers and develop new
techniques for high-pressure gas fields and for using the
condensate to extract heavy oil.
MR. LAKOSH lauded AGIA for proving the gas is economical to
develop and ship to the Lower 48, for forcing the producers to
start Denali, and for providing resources to the DNR
commissioner. He asked legislators to honor their commitment to
develop the natural resources to the benefit of the people and
to vote yes on the TransCanada license.
7:32:10 PM
SHANNYN MOORE informed members that she has been talking to Bill
Walker and others about why an all-Alaska gas pipeline is best
for the state. No matter what, she said the experts that
testify all want to go forward. Saying over 40 million acres of
offshore leases have been granted in the last nine years but
only 10 million are being tapped right now, Ms. Moore asked why
some feel that incentives should be provided. She also said
existing refineries are at 89 percent capacity.
MS. MOORE expressed concern that global companies have colonized
the state and, in the past at least, took over legislators'
seats. Characterizing the $500 million incentive as money an
unpopular person would spend on a date, she said, "You're hot.
You've got it. You don't have to pay someone else to do this."
She encouraged legislators to amend AGIA. She also asked why
the attorney general hasn't investigated what she considers
sabotage with respect to the Port Authority's bid last year.
7:35:11 PM
RON ALLEVA, a 35-year resident, said he was appalled at the poor
turnout, especially of younger people. He spoke against AGIA
and in favor of the Denali project, saying he believes the
producers have the knowledge and Alaskans have a legislature
they cannot trust.
MR. ALLEVA expressed concern about the competence of Governor
Palin and the commissioner to negotiate, as well as wasting
$500 million as an incentive. He suggested the need for an
intellectual wave of students who will be interested in
defending the state now and in the future, saying the court case
with Point Thomson has nothing to do with producing gas, but
gives jobs to attorneys and is disgraceful.
MR. ALLEVA voiced concern that whereas he hears about ethics and
transparency from Governor Palin, she hides the polar bear data.
He suggested the state should go back to the table to get the
gas produced. Characterizing the Canadian courts as brothers
who know the gas industry, he said the Canadians are concerned
with jobs as well and Alaskans can get along with them. Noting
that the Denali project is moving forward, he proposed getting
out of the courtroom, going back to the drawing board, and
talking to the producers.
7:41:16 PM
CHRISTOPHER CONSTANT told members he has never been more
inspired about the future of Alaska. He believes it's a new
day, the house has been cleaned, Alaska has money in the bank,
and it's time to get to work and secure the future. Saying he
trusts that this body will do the right thing, he encouraged
making some changes to AGIA to ensure that Alaskan kids can get
the long-term benefit, which is the jobs and skills.
CHAIR HUGGINS thanked the testifiers. SB 3001 and HB 3001 were
held over.
CHAIR HUGGINS adjourned the joint meeting of the Senate Special
Committee on Energy and the House Rules Standing Committee at
7:43:32 PM.
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