Legislature(2011 - 2012)Anch LIO Conf Rm
08/16/2011 09:00 AM Senate RESOURCES
| Audio | Topic |
|---|---|
| Start | |
| Presentation: Agia Update | |
| Alaska Oil and Gas Conservation Commission Update | |
| Presentation on Cook Inlet Activity Update and Dnr Natural Gas Studies by Paul Decker, Petroleum Geologist & Resource Evaluation Manager and Jeff Dykstra, Commercial Analyst | |
| Presentation on Usgs Assessment of Cook Inlet Natural Gas Reserves by Brenda Pierce, Program Coordinator, Energy Resources Program | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
ALASKA STATE LEGISLATURE
SENATE RESOURCES STANDING COMMITTEE
August 16, 2011
9:02 a.m.
MEMBERS PRESENT
Senator Joe Paskvan, Co-Chair
Senator Thomas Wagoner, Co-Chair
Senator Bill Wielechowski, Vice Chair
Senator Bert Stedman
Senator Lesil McGuire
Senator Hollis French
Senator Gary Stevens
MEMBERS ABSENT
All members present
OTHER LEGISLATORS PRESENT
Senator Charlie Huggins
Senator Fred Dyson
Representative Paul Seaton
Representative Les Gara
Representative Wes Keller
Representative Mike Hawker
Representative Chris Tuck - via teleconference
Representative David Guttenberg - via teleconference
COMMITTEE CALENDAR
Presentations on Cook Inlet oil and gas
TransCanada's AGIA Update
Alaska Oil and Gas Conservation Commission Update
Department of Natural Resources Update
USGS Update
- HEARD
PREVIOUS COMMITTEE ACTION
No previous action to consider
WITNESS REGISTER
TONY PALMER, Vice President
Major Projects Development
TransCanada Pipeline Corporation
POSITION STATEMENT: Provided update on the Alaska Pipeline
Project (APP).
CATHY FOERSTER, Commissioner
Alaska Oil and Gas Conservation Commission (AOGCC)
POSITION STATEMENT: Commented on the AOGCC's role in the state's
gas production and answered questions about production of Cook
Inlet oil and gas.
PAUL DECKER, Manager
Resource Evaluation Section
Division of Oil and Gas
Department of Natural Resources (DNR)
Anchorage, AK
POSITION STATEMENT: Commented on Cook Inlet gas and oil
production from the state's perspective.
JEFF DYKSTRA, Commercial Analyst
Division of Oil and Gas
Department of Natural Resources (DNR)
Anchorage, AK
POSITION STATEMENT: Commented on commercial aspects of Cook
Inlet oil and gas production.
BRENDA PIERCE, Manager
Energy Resources Program
United States Geological survey (USGS)
Department of Interior
POSITION STATEMENT: Commented on USGS resource evaluation
methodologies and on Cook Inlet resource estimates.
ACTION NARRATIVE
9:02:28 AM
CO-CHAIR JOE PASKVAN called the Senate Resources Standing
Committee meeting to order at 9:02 a.m. Present at the call to
order were Senators Dyson, Stedman, Stevens, Co-chair Wagoner,
and Co-chair Paskvan.
^Presentation: AGIA Update
AGIA UPDATE
9:02:34 AM
CO-CHAIR PASKVAN announced the first order of business would be
to hear an update on the Alaska Gasline Inducement Act (AGIA)
from TransCanada Corporation, AGIA licensee.
9:03:49 AM
TONY PALMER, Vice President, Major Projects Development,
TransCanada Pipeline Corporation, said that he wanted to
highlight the requirements needed to make the Alaska Pipeline
Project (APP) a success. As the sponsors of the APP, TransCanada
is responsible for maintaining the technical and regulatory
schedule and for negotiating commercial agreements with
shippers. The state also has a significant role as the licensor
through the Alaska Gas Inducement Act (AGIA) to resolve the Pt.
Thomson and gas fiscals and in its role in support of AGIA by
appropriating for reimbursement.
The producers and shippers also play a key role because they are
ultimately potential customers; their role would be to negotiate
commercial agreements with TransCanada and to work with the
state to resolve the Pt. Thomson issue. The U.S. government has
significant roles as well because no project succeeds without
having regulatory approvals: Mr. Persily as the Pipeline
Coordinator and the Federal Energy Regulatory Commission (FERC)
have significant roles in facilitating project permitting.
MR. PALMER said there is also the issue of the federal loan
guarantee, which could be a large plus to this project. On the
Canadian side, the Northern Pipeline Agency (NPA) must also
facilitate project permitting. Despite all those roles, the
project is still subject, as any major infrastructure project
is, to external factors. That's the nature of this business.
9:06:38 AM
Gas supply and demand in North America changes globally, he
said, and gas price forecasts are different today than three
years ago. The parties that matter now are TransCanada's
potential shippers and their view of gas prices in the long run,
because they are the ones making the financial commitments. The
LNG export market is changing, as well. Three years ago folks
thought there would be significant imports of LNG into this
continent and now those are very modest and a number of
potential projects are being put forward by players in the Gulf
Coast and Western Canada to export LNG off this continent into
other markets.
9:07:37 AM
SENATOR FRENCH joined the committee.
MR. PALMER said that financial and debt markets have also
changed significantly with the late 2008 meltdowns and the more
recent changes affecting both national and global markets. It
has affected the debt capacity of major financial institutions
in this country as well as global institutions making the
federal loan guarantee part of this program even more important
- because the financial capacity of banks is what has
traditionally funded these types of projects. In the next three
years more changes will be seen. This project will be in service
by the end of this decade and will operate for 20 to 50 years
after that.
9:10:03 AM
CO-CHAIR WAGONER asked what would happen to the federal
guarantee if this project became a line to tidewater with a spur
into Cook Inlet and how that would relate to the original
project.
MR. PALMER answered that the original $18 billion federal
guarantee, originally passed in 2004, was for both the U.S. and
Canadian portions of the line. It wouldn't apply for an export
project outside of U.S. markets, and Congress has considered
upping the guarantee to $30 billion; but no regulations have
been put in place. This is like a banker not providing terms on
a mortgage, and many details still need to be resolved. The
federal loan guarantee could be a very large positive if LNG
went only to U.S. markets.
9:12:58 AM
SENATOR STEVENS asked Mr. Palmer to give a brief summary of
current and future LNG supply and demand in North America.
MR. PALMER replied that he is not an expert in that field, but
he had some views. For two decades U.S. production was in the
neighborhood of 50 bcf per day; the range of production in the
Lower 48 was the same. With the shale gas revolution in the last
several years, that has shot up dramatically and is projected to
hit 60 bcf per day. Thinking in terms of those numbers, that is
a couple of Alaskan projects, a very significant explosion of
supply in the Lower 48. As a result there has been some fall-off
in conventional gas. Because gas prices are lower,
unconventional gas, in many cases, struggles to compete on full
cycle economics at $4 gas. They can compete on half cycle
economics where the gas has been found and can be produced, but
to go find and develop conventional gas at $4 in many basins is
highly challenged. This is a very significant change in Lower 48
production over the last several years.
9:15:27 AM
On the demand side, Mr. Palmer said, a response is starting to
be seen. Low gas prices cause higher demand generally, but the
response is slow and residential consumers don't change their
consumption much whether gas prices are at $4 or $8. "We all
need to heat our homes..." he said.
Commercial usage is much the same. On the power generation side,
demand is increasing as a result of low gas prices, but the
established base of power production from coal, much of it 10 to
20 years old, is not going to be readily replaced. When those
plants do come to the end of their economic life, the owners and
regulators will have to decide whether or not they are renewed
or get replaced with a new coal or gas plant. Here is an
opportunity for gas if it stays at low prices on a long term
basis.
9:16:49 AM
Nuclear power has some ups and downs. The U.S. hasn't
commissioned any new nuclear plants for two or more decades.
TransCanada is refurbishing one now in Ontario and that should
be in service next year, but that is one of the few examples on
this continent. The Fukushima Daiichi disaster may have deferred
nuclear again, but that is still in question.
MR. PALMER said how long gas will remain in the $4 range is also
an open question. At that price, some basins are highly
economic, particularly if they have significant liquids. Liquids
are comparable to oil in value and they are getting somewhere in
the $80 to $100 per barrel range. Compare that with gas prices
at $4 and you have a ratio between oil and gas that is in the
20:1 range and it has traditionally been a lot lower than that.
For decades it was in the 8 to 12 range. Today, liquid-rich gas
fields are being developed quickly, a number of them shale
fields; dry gas fields are less economic. It is hard to predict
if $4 gas will be sustainable, and at this point he didn't know
what large producers think, but what they do think matters.
9:19:36 AM
SENATOR WIELECHOWSKI asked how Lower 48 shale gas will affect
this project and what the status of his Valdez evaluation was.
MR. PALMER reiterated that public gas price forecasts are much
lower today than they were three years ago. Economic forecasters
are influenced by current circumstances and their forecasts are
one of the external things customers will have to consider
before committing to this project. Gas supply is projected to be
higher in North America than it was three of four years ago.
The same impact hasn't been seen on the global side, although
changes are happening. No one knows if the shale gas revolution
will come to China. Currently, Asian gas prices continue to be
priced off oil and that, today, yields a very high LNG price.
Some LNG buyers are coming to North America seeking to purchase
potentially North American natural gas just as they seek to
purchase from Qatar, Australia, and so on. Some of those parties
have advised that they are seeking to get North American prices.
If successful in doing that they will break the linkage to oil -
but that is still an open question also.
MR. PALMER summarized that the shale gas revolution hasn't made
this project less economic to date. TransCanada is still
negotiating with potential customers who haven't walked away
from the table. TransCanada has two alternatives: one, to move
gas to Alberta and the other to move it to Valdez, but customers
haven't been obtained for either. The FERC regulations on this
project require them to take late bids, so they are open to
receive them. He reminded members that TransCanada has always
had a component for in-state gas on this project and if a large
line is put in service that will provide low cost gas to
Alaskans just because of the economies of scale.
9:24:57 AM
CO-CHAIR PASKVAN asked what would happen to the market in
general and in particular to the AGIA process if the shale gas
revolution would come to China.
MR. PALMER replied that is a highly speculative topic. The cost
of developing it is uncertain and more will be known in 2 to 5
years. If China has the same results North America has had, it
would be very significant. China has a shortage of natural gas;
they import from proximate countries via pipeline as well as
LNG, and they are expected to have a hugely growing market. A
domestic source at low prices will have a huge impact on how
they purchase gas and the price at which they purchase gas from
offshore. At the moment, they are principally purchasing gas on
a "Japanese Crude Cocktail" at a crude oil-linked price. If
there is no change and China continues to have growth that
leaves an opportunity for producers or other shippers to
nominate Valdez and sign a contract to move gas there. But if on
the other hand, gas prices are very low in China that makes it
much more challenging for Alaska gas to compete in the
marketplace, because there is no other dedicated market for
Alaska gas other than the domestic market within the state. If
the gas goes to Alberta on the way to the Lower 48, Alaska gas
will compete with Lower 48 and Canadian supplies. If Alaska gas
goes to Asia, it will compete with Australian gas, Sakhalin gas
and Qatar gas and potentially Lower 48 and western Canadian gas.
He said there are four announced LNG export projects potentially
from Kitimat [British Columbia] and three years ago there was an
import project, but none of these projects has established all
the necessary connections to go forward. Chenier out of the Gulf
Coast is looking at projects to turn re-gas terminals into
liquefaction terminals and exporting gas basically from the
NYNEX Hub.
9:27:24 AM
SENATOR DYSON said the credibility of TransCanada's project took
a big jump up in his view when ExxonMobil joined it. He has been
told that ExxonMobil is more experienced on the financial side
and that they are not all that impressed with today's prices,
but rather look at the ones 10 or 15 years out. Is that true in
general of major producers?
MR. PALMER replied that one division of ExxonMobil is
TransCanada's partner in the pipeline project and there exists a
distinct firewall between it and the ExxonMobil Production and
Marketing division, which TransCanada wants as a customer along
with the other producers. Those parties that are in every market
and generally in every supply basin in the world succeed, in his
view, by taking a very long view of markets - and their success
over the last half-century has been remarkable.
SENATOR STEDMAN asked who their customers are.
MR. PALMER replied that he can't say because of strict
confidentially provisions. He said this project has had
remarkable transparency and that TransCanada revealed its entire
commercial proposal before competitors had to "put their marker
down." That is unique in the industry.
He explained that the reason for confidentiality is because
until recently TransCanada's potential customers are the same
companies that were in competition for the same project and
secondly, because their potential customers, if they are
producers, have potential confidential information with regards
to where their gas will be received or delivered into the
pipeline, which can affect the value of land leases and
competitive markets at both ends of the pipe.
SENATOR STEDMAN asked, for the public's information, if their
potential customers are the companies that own the North Slope
leases: ExxonMobil, BP, ConocoPhillips and Chevron.
MR. PALMER responded that he didn't mean to be evasive; clearly
the companies he listed are potential customers on any project,
including theirs, but no contracts had been established yet and
while he didn't think it likely, because the project is so large
and long term there could be intermediaries like marketers as
well.
9:35:49 AM
CO-CHAIR PASKVAN asked if he heard anything about the ability to
off-take gas from the North Slope.
MR. PALMER asked if his question was in regards to the Alaska
Oil and Gas Conservation Commission (AOGCC) requirement.
CO-CHAIR PASKVAN replied yes.
MR. PALMER replied that in the past the AOGCC has indicated the
ability to produce 2.3 or 2.7 bcf/day off of the Prudhoe Bay
field. A larger volume would need an application by the lease
holders affirmed by the AOGCC if they were in favor of it and he
didn't know what the Pt. Thomson volume would be.
9:37:12 AM
SENATOR MCGUIRE joined the committee.
SENATOR WIELECHOWSKI said he supported this project, but the
state has to decide about how to proceed and it is increasingly
difficult to make decisions without information on where it
stands. When TransCanada had a direct competitor they had a
compelling reason to not disclose information, but now they are
also beyond the timeline, so he wanted to know if legislators
could sign confidentiality agreements with TransCanada to get
that information.
MR. PALMER replied that today he would tell him where they are
on the commercial side, within the boundaries of the
confidentiality agreement and while not putting anyone in a
compromising position, and about the technical and regulatory
work that has been done - as required by the AGIA statute.
9:41:23 AM
SENATOR DYSON remarked that a couple of years ago experienced
industry people told him there will not be a long term supply of
unconventional gas in North America for two reasons: the
startling decline rates generally on those plays and the
environmental push-back that is already happening and asked Mr.
Palmer his sense of what will happen with unconventional gas
production in North America.
MR. PALMER replied that was an open question. At the moment most
of the news about shale gas and unconventional gas is very
positive. The production increases have been remarkable and at
very low cost. As more development occurs in non-traditional
areas for natural gas local folks are starting to want to
understand that development a little bit better. It's clear that
shale gas is very real in the short term and likely in the long
run.
He continued that three years ago the Alaska legislature
approved a license, but it didn't come into effect until
December 2008 and said that TransCanada had met all of its
regulatory and technical targets over that timeframe. They
commenced work before the license was granted to maintain
schedule and two years ago ExxonMobil aligned with them.
He has been saying for seven years now that this project needs
five critical players to make it a success: the State of Alaska,
ExxonMobil, Conoco, BP, and TransCanada. At present three of
those are together: the State of Alaska, TransCanada and
ExxonMobil. A team of 110 individuals works on this project
full-time in addition to contract employees; 170 people are in
the field this summer in Alaska and Canada and more than that
last summer. This project is moving forward on the technical and
regulatory side completely on schedule, he said.
At FERC's request, a pre-filing application was made in May
2009. TransCanada has updated and optimized the project
technical and cost basis for the open season and published it,
making it public three months before their major competitor had
to put their marker in the ground.
9:46:14 AM
MR. PALMER stated that parties have said TransCanada needs to
engage with communities along the right-of-way and they have
held 56 community meetings in Alaska to date. He said the
environmental and field work TransCanada has completed in the
last three years is expensive, but it will continue, because
their AGIA license obligates them to make a FERC filing in the
fall of 2012 regardless of the outcome of the commercial open
season. Forty Alaskan businesses and 500 Alaskan workers have
worked on the project and they are on track to submit the FERC
permit application on time. TransCanada filed draft resource
reports 1 and 10 in April 2011 and FERC recently issued its
notice of intent to prepare an Environmental Impact Statement
(EIS) in August 2011; they are on track to file all the draft
resource reports with FERC by year-end, a "massive job." He
related that regulatory work is also progressing in Canada under
the Northern Pipeline Act.
In order for the project to succeed, he repeated, TransCanada
needs two things: customers and legislative and regulatory
approval. For any project to succeed, they must have both.
SENATOR MCGUIRE asked the status of TransCanada's negotiations
with First Nations along the route and if any are still holding
out.
MR. PALMER answered that TransCanada has a right-of-way through
the Yukon and has held it since 1983, but they continue to have
negotiations with both First Nations in Yukon and northern
British Columbia (B.C.) and have executive participation
agreements with several of them while continuing to negotiate
with others. They are "well down the path," but there are still
miles to go.
SENATOR MCGUIRE asked how many years of negotiations are left
and how many miles of pipeline are affected in those rights-of-
way.
9:50:11 AM
MR. PALMER replied approximately 1,000 miles for the Canadian
portion of the pipeline: Yukon is approximately half of that and
northern B.C., "traditional pipeline country," is the other
half. The original Northern Pipeline Act gave the First Nations
specific benefits, but TransCanada is negotiating to give them
more. Other stakeholders are negotiating, too. At the moment,
First Nations issues are not a roadblock for the Canadian
portion.
CO-CHAIR WAGONER asked when companies can book their reserves
and if it would be just ExxonMobil since they are already a
partner in this project. Would other people be able to book
reserves without being part of the project?
MR. PALMER replied that he didn't know that answer.
9:53:10 AM
MR. PALMER summarized that AGIA's commercial commitments to the
state have been more than met in the last three years.
TransCanada has aligned with ExxonMobil and invited BP and
ConocoPhillips or any other major player to join them, and they
are open to partnership discussions, as well.
He said they recognized that global gas markets are becoming
more competitive not just on this continent, but
internationally, and therefore significantly enhanced their
commercial offerings by $500 million per year in tolls over 25-
years, a reduction of $12.5 billion at 4.5 bcf/day. Yesterday he
heard Mr. Fauske say he could not find any players that would
take any of the development cost risk on the in-state bullet
line, but TransCanada has already shared risk with the State of
Alaska to the tune of $288 million to the end of second quarter
2011 and has received $94 million from the state in
reimbursements.
He said also when the license was granted, TransCanada expected
its floating rate of return (ROR) would be 14 percent and that
was reduced to 12 percent in their open season, the ballpark
figure Mr. Fauske said commercial parties would need in order to
invest in the in-state gas line. Third, the license approved a
60/40 debt/equity structure for expansion and 70/30 during
construction. In the open season TransCanada changed that to
70/30 during construction and 75/25 during in-service. Mr.
Fauske said parties would require 30 percent equity.
Last, the license had an approved recovery of capital over the
initial contract term of 20 or 25 years, so they would recover
100 percent of their initially invested capital over the life of
those initial contracts through depreciation. In fact, Mr.
Fauske indicated that's exactly what third parties would need to
invest in the in-state gas line. TransCanada, in its open
season, proposed to recover only 80 percent of its initial
capital over the term of the initial contracts.
MR. PALMER summarized that all of those components increase the
risk to the pipeline sponsors, TransCanada and ExxonMobil, that
have invested their capital in the development costs, taken on
more risk on the equity side, taken on more risk in terms of
recovery of their capital - and they are doing so for a return
of 12 percent. They have done all that to make this project more
competitive.
9:59:10 AM
SENATOR WIELECHOWSKI asked how much TransCanada and ExxonMobil
plan to spend until the issuance of a FERC license and how much
do they anticipate the additional state reimbursements will be.
MR. PALMER answered if they are unsuccessful in getting
customers and are still moving forward strictly with the
certificate and still struggling to get customers on a long term
basis, they have indicated spending in the order of $700 million
to get to the certificate by 2014. During the course of that
process, the state would have fully reimbursed the $500 million
and the two sponsors will have expended the residual couple
hundred million. If they do get customers, they would accelerate
the spending, because at that point they would not only be
seeking to get a certificate, but to actually be in service by a
certain date.
10:01:42 AM
SENATOR STEDMAN said Mr. Palmer talked about flexibility in the
negotiations he had with potential customers to make their post-
project more competitive, but TransCanada has no customers. How
are legislators to interpret that against other projects like
the in-state gas line?
MR. PALMER replied that the proposed toll based on capital costs
in their open season to Valdez was $2.45 to $3.15; their
proposed toll to Alberta was $2.80 to $3.50. TransCanada has
"negotiated hard" with customers post open season for a year and
TransCanada and ExxonMobil have made even further concessions,
and they are prepared to make even further concessions on other
components of commercial terms "to try and get over the finish
line."
He said the commercial side is behind schedule, but the pace of
commercial progress is dependent on diverse external factors
that they do not control like having collaboration with other
parties. This is one of the largest commercial projects to be
built in the world - two to three times the size of other
private gas projects in the world and with a 10 year development
timeframe. Commercial negotiations are highly complex. Progress
has been made on Pt. Thomson gas, which is necessary to make
this project viable to the North American market. But a smaller
volume to Valdez might change that.
10:09:29 AM
CO-CHAIR PASKVAN asked for his thoughts on the Denali project
folding and rumors of TransCanada's project folding soon, too.
MR. PALMER answered that the sponsors of the other project,
ConocoPhillips and BP, also had a firewall between sponsorship
of Denali and their shipping components. There are two ways to
look at the Denali demise. From a glass half empty point of
view, the sponsors were unsuccessful in getting customers and
decided they no longer wanted to pursue the project. He said 18
months ago TransCanada put out its commercial offerings in their
open season; it was public. Three months later Denali came out
with a remarkably similar proposal. The fact that Denali could
only match TransCanada's proposal suggests that the bid made
three months earlier was very competitive. Why did Denali go
away? TransCanada has always thought they have had an advantage
in Canada and that they have the skill set to advance this
project, and with ExxonMobil on board that was improved.
TransCanada has always welcomed BP, ConocoPhillips or any other
major player to join their project. So, if you're a glass half
full kind of person, you could say it was necessary for one of
these major projects to end. No one ever contemplated that both
projects were going to be completed.
10:13:29 AM
SENATOR WIELECHOWSKI said AGIA guarantees fiscal terms for a
decade so much so that if the gas pipeline would be turned on
today the State of Alaska would probably lose billions of
dollars because the price of oil and gas is coupled and asked
what other fiscal terms are needed.
MR. PALMER answered that he was not the party to answer that;
that is between the state and the producers.
10:15:10 AM
SENATOR FRENCH asked of the three issues he has talked about
being out of their control, which one is the biggest holding up
the project.
MR. PALMER replied it's not just what is happening in North
America, but what is happening in global markets as well. At
present, until the state and the producers have resolved their
issues, it's very challenging to get customers. Those issues
could be resolved and there could still be no project if the gas
price is not right. At the point those issues are resolved, it
has to be determined if the project is economic or not. The
first two are necessary conditions and they may or may not be
sufficient. As issues are resolved the next decisions must be
evaluated based on current economics.
10:19:36 AM
SENATOR WIELECHOWSKI said the lease terms signed by the oil and
gas companies require them to produce or develop their resource
gas when it's reasonably profitable and asked if the terms
TransCanada is providing makes gas production by those companies
reasonably profitable.
MR. PALMER replied that he is confident that they have offered
highly competitive pipeline tariff terms and they continue to
negotiate to make it even more competitive. And in order to
answer Senator Wielechowski's question you need to have a view
as to what gas prices are going to be in whatever market these
folks intend to deliver into and you need to have a view as to
what their take will be and the state take will be - all
questions that he couldn't answer.
10:21:09 AM
REPRESENTATIVE OLSON asked if TransCanada would still be doing
this project without the state's $500 million subsidy, because
that is the main difference between them and the project that
folded.
MR. PALMER replied when TransCanada received the license, they
knew their substantial obligations to the state but that they
also received certain benefits. Those obligations have been met,
but it's not a one-sided arrangement. At present, TransCanada
has invested $194 million in this project: they were obliged to
have a maximum of 30 percent equity, relatively low in the U.S.
pipeline industry; they were obliged to continue with this
project regardless of the outcome of the open season and in
order to meet the schedule they had to do work during the open
season and before it in order to maintain schedule; they also
took on tariff and terms that were distinctly laid out for any
party that wished to bid. In return they received the $500
million state contribution. So, when people say TransCanada is
somehow continuing with this project strictly because it is
receiving a "subsidy" from the State of Alaska, it's more like
the state is continuing to meet its obligations along with
TransCanada.
REPRESENTATIVE OLSON asked at what point TransCanada would reach
a decision on proceeding.
MR. PALMER replied if there is no optimism that the state and
the producers will resolve their issues - and yesterday he heard
a great deal of optimism about Pt. Thomson from Commissioner
Sullivan - nothing will be resolved. And TransCanada will
clearly have a decision point. If there continues to be optimism
that they will be resolved in a timely fashion, then "we're
going to let the game play out...."
10:26:48 AM
MR. PALMER said TransCanada continues to meet its obligations to
the State of Alaska under the license and they believe the state
is meeting its obligations to TransCanada. Their regulatory and
technical timelines are on schedule, but their commercial
timeline is behind schedule, primarily because of issues out of
their control. They are pleased with developments mainly at Pt.
Thomson. TransCanada wants to work through AGIA and get over the
finish line, but they need to see breakthroughs from the state
and customers.
10:29:45 AM
SENATOR WIELECHOWSKI said one of the reasons for this meeting is
because the state is at a crossroads and has to decide about
moving ahead on the big pipeline or the in-state line. He asked
if he had a chance to look at the Fauske report and if he agreed
that the tariffs are reasonable. Is $2 a good price for gas off
the North Slope?
MR. PALMER replied that he had read the report, but he had done
no evaluation as to whether their capital costs are accurate;
the producers will have to determine if the price is right. Mr.
Fauske's project is a $7.5 billion project; TransCanada has
completed the first part of the Keystone oil line from Alberta
to Lotoka and Cushing for $6 billion, a massive undertaking, and
is waiting for approval to do the second phase of that project
at a cost of $7 billion.
Any major project needs some things in common like customers
that can commit their gas to a project. And customers are saying
they need a long-standing fiscal arrangement between them and
the state. TransCanada needs long-term customer contracts with
credit worthy partners enough to pay a 20 or 25 year contract.
That is probably what Mr. Fauske is looking for. Both projects
need to get permits and customers for the full volume of the
project. Then you get into the debt/equity ratios that he has
already described.
10:34:21 AM
SENATOR DYSON said part of the selling point for TransCanada was
the spare capacity in their Alberta pipeline and asked if that
had changed or if it would change in the future.
MR. PALMER replied it has changed in that they have more spare
capacity now. The shale gas revolution and increased production
in the Lower 48 has resulted in lower production in western
Canada. Approximately 15 bcf/day of capacity leaves western
Canada for the market in eastern Canada and the Lower 48 and
that 15 bcf/day is not full today by a long shot. They hoped the
shale gas development in northeast B.C. will refill the pipe
over the course of the next decade.
10:36:24 AM
REPRESENTATIVE SEATON said they are pleased to see the
resolution of Pt. Thomson possibly on the table. During stranded
gas development legislators got a window into the Prudhoe
Bay/Kuparuk joint operating agreement, in which, uniquely, if
one of the companies decides not to invest or conduct a sale
that would actually veto the project. He asked if one of the
companies decides not to participate in this project would that
veto it for the other two or the entire unit. Is that a
negotiating point or an impediment for getting gas sales from
individual producers?
MR. PALMER replied that he wasn't privy to that information.
10:38:54 AM
SENATOR WIELECHOWSKI remarked that if a total of $288 million
has been spent and the state has reimbursed $94 million to
TransCanada and Mr. Palmer said they would spend $7 million
more, then there is $412 million left to be spent and the state
is on the hook for up to $406 million. He said when AGIA passed,
no one talked about shale gas and as a policy maker making
decisions whether or not to continue investing he needs more
information. He wanted to know if TransCanada's internal
calculations show that this project is still profitable and if
the producers are throwing up unreasonable stumbling blocks.
MR. PALMER responded that he appreciated that the state is
investing its dollars with TransCanada and that they have major
policy decisions to make, but what he is asking for is
completely outside the bounds of pipeline processes across North
America. He is asking him for highly confidential information,
circumstances between customers and the pipeline on this
project, to be put into the hands of 60 legislators.
Negotiations are still ongoing and may still take turns. He said
he would consider what he asked, but it is highly unusual.
SENATOR WIELECHOWSKI said he thought this was a highly unusual
project because no other state in the country is putting up
hundreds of millions of dollars and as a partner still has no
access to that information and stated, "I think we have a right
to have that information." He offered to sign a confidentiality
agreement saying it had been done in the past and that
legislators have been very careful when they received
information like that.
MR. PALMER replied that they have been able to share additional
information with the administration under the confidentiality
provisions of AGIA, but what Senator Wielechowski wants goes
beyond the statute.
10:42:49 AM
SENATOR STEDMAN said it sounds like TransCanada needs to come up
with another $20 million to go forward and the state has to come
up with another $200 million, so an appropriation request would
be needed this winter. At any rate, the $500 million is a "sunk
cost" the state makes one year at a time regardless of which way
the project goes.
10:44:32 AM
CO-CHAIR WAGONER asked if he had been faced with these types of
external problems on other projects.
MR. PALMER replied yes; significant external issues have been
out of their control with Keystone: one is if they will be
granted a permit. The review process for that project is
significantly beyond what it was for the original Keystone and
other pipeline projects. Yes, they have faced significantly more
opposition to what they thought was a straightforward pipeline
project and have ended up investing more money than they
expected, but they remain confident they will get to the finish
line. He said the customers for that project are not public
information; neither are the tolls. Contracts with this project
have remarkable transparency because of the statutes the
legislature has set up and FERC requirements; TransCanada has
had business with other governments that also come with certain
obligations and rights. It has faced other projects that have
items outside the project that can delay and potentially stop
it.
10:47:43 AM
SENATOR MCGUIRE said she understood if this project isn't
successful that the state retains the license and the data as
part of the $500 million it has contributed and asked what he
believes TransCanada's future rights are to the data and the
license itself and what their role will be in the future in the
event of a failed plan this go-around.
MR. PALMER replied that he didn't have the statute in front of
him, but the abandonment provision says if the administration
decided the project was uneconomic (both parties have the right
to claim that) and TransCanada agrees, at that point the project
is over and the state has the option, not the obligation, to
purchase the asset for their out of pocket dollars (the non-
reimbursed qualified expenses). Without an agreement, there
would be arbitration and the state would have no obligation to
buy TransCanada's assets. Another circumstance is if the project
isn't abandoned but they just never get to the finish line. He
recalled there were some obligations and rights for both
parties, but couldn't recall exactly what they were.
SENATOR MCGUIRE said she recalled that the state retained the
license, but she just understood him to say that the state has
the option to purchase it.
MR. PALMER answered that it's clearly set out in statute, but he
didn't have it in front of him.
SENATOR MCGUIRE asked in the final scenario if he had any
opinion or recollection about whether or not the 500 mmcf/day
goes away with FERC certification.
MR. PALMER replied that the rationale for the 500 mmcf/day
limitation is that TransCanada needs just about all of the
proven gas to make its project economic. In fact at 4.5 bcf/day
TransCanada needs more than the existing proven gas and since it
was taking on obligations to the state, they had to know they
had access to most or all of the gas.
10:55:01 AM
REPRESENTATIVE SEATON said Commissioner Sullivan talked about
synchronizing open seasons yesterday and it seemed like the only
way to do that was to discuss fiscal terms and asked if was he
was concerned that the administration might finalize fiscal
terms by the 2013 date.
MR. PALMER replied that he listened carefully to the
commissioner yesterday and felt that it clearly is in
TransCanada's interest to see resolution between the state and
producers as soon as possible, but when it happens is not in
their control. He said TransCanada has an obligation to solicit
the market again in 2012 and an obligation under FERC to take
late bids. He wasn't sure what context was intended in talking
about synchronizing open seasons.
10:57:16 AM
SENATOR FRENCH said Mr. Palmer could probably sense the
frustration here today that they are not further down the road
on this project, but he is "a glass half full person" and has
heard it suggested by one of Alaska's delegation on the floor of
the House that we somehow missed the boat on the gas pipeline
and the window is closed. He sees it differently; he's glad they
didn't go with the pipeline 20 years ago and that they are not
selling gas into a $4 market. That gas is still in the bank on
the North Slope. He appreciated the enormous effort Mr. Palmer
and his company has put into getting this far.
10:58:46 AM
CO-CHAIR PASKVAN, seeing no further questions, thanked Mr.
Palmer for appearing today.
Recess from 10:58 to 11:17 a.m.
^ALASKA OIL AND GAS CONSERVATION COMMISSION UPDATE
ALASKA OIL AND GAS CONSERVATION COMMISSION UPATE
11:17:00 AM
CO-CHAIR PASKVAN called the meeting back to order and asked Ms.
Foerster to come forward.
CATHY FOERSTER, Commissioner, Alaska Oil and Gas Conservation
Commission (AOGCC), said she is the engineering commissioner and
explained that the commission is charged by the Alaska
Constitution with ensuring that operators get greater ultimate
recovery of Alaska's hydrocarbon resource, that their operations
do not cause waste of that resource, that when they're
developing and producing that resource they keep fresh
groundwater from harm, that the development is in such a way
that correlative rights are protected and that operations under
their statutory control are safe (blowout prevention and well
safety systems, specifically).
She said their role in selling gas from the North Slope is in
ensuring that when those gas sales occur that the oil associated
with that gas is not put at risk of being lost and
unrecoverable.
SENATOR STEDMAN asked her to explain how gas is related to oil.
MS. FOERSTER explained that hydrocarbons can exist either as
natural gas reservoirs by themselves or as reservoirs that have
a combination of oil and gas. The reservoirs that have been
discovered on the North Slope that contain the natural gas they
are talking about are both associated with oil. The two big
reservoirs are at Prudhoe Bay that has about 24 tcf of gas
associated with the 2 bbl/oil left in the ground yet to be
recovered (11 bbl have come out already) and Pt. Thomson that
still has 2 bbl/oil left to recover. She said that gas is
necessary for getting oil out of the ground providing the
pressure necessary to make the oil move up a couple of miles
through these wells to the surface among other reservoir
phenomenon associated with producing oil.
So, when the AOGCC looks at how operators are managing, they
make sure that both the oil and the gas are being taken care of
as well as possible. For instance, if they were to just start
taking gas out of Prudhoe Bay the remaining 2 bbl/oil would be
put at risk of not being produced at all. To put that in
perspective Thunder Horse, the largest offshore discovery in the
Gulf of Mexico in the last 10 years, is 1 bbl/oil. So she said
"our poor, old, limp, tired Prudhoe Bay reservoir is still twice
as big as the biggest discovery in the Gulf of Mexico." It can't
be abandoned. Pt. Thomson has 9 tcf/gas and has somewhere
between .5 and 2 billion barrels associated with it as well. The
oil is more valuable and it needs the gas in order to be
recovered.
11:23:28 AM
SENATOR STEDMAN remarked that putting in a gasline in the 80s or
90s or even 10 years ago would have been a disaster.
MS. FOERSTER said she generally agreed.
SENATOR WIELECHOWSKI paraphrased concerns she expressed at the
end of last session about turning on the pipeline and shipping
gas and how that would impact the ability to recover additional
oil.
MS. FOERSTER responded that she typically says the longer you
wait the lower the volume of gas you produce and the more steps
that the operators have taken to get as much oil accelerated out
of the ground as possible.
SENATOR WIELECHOWSKI asked how dramatically a big pipeline or a
bullet line in 10 years would impact oil production on the North
Slope.
MS. FOERSTER replied if it comes on 10 years from now, it's
going to depend on how big the line is, how much of the oil has
been produced and what mitigating steps the operator has put
into place to prevent the loss of the gas. She has always said
that gas is not only useful for getting the oil out of the
ground from the reservoirs it's in, but it gets exported for
enhanced oil recovery (EOR) use in other fields and that gas has
potential to be very useful in the huge heavy oil and viscous
oil resource only beginning to be tapped up there.
She stated that the U. S. Geological Survey (USGS) says 100 tcf
of gas hasn't been found up there yet, and the reason it's not
being looked for is because it can't be sold. If we were to
build a gas pipeline, who is to say how much of that gas would
be found? So, do we worry about the gas being needed for the
oil? Yes. Is there hope that we start selling the gas; that we
find more gas and we quit worrying about it? Yes; and forecasts
will be wrong.
11:27:46 AM
CO-CHAIR PASKVAN asked her to explain how gas is important to
the development of viscous oil resources.
MS. FOERSTER explained the primary way that gas would be
valuable to the heavy resource development would be through
decreasing its viscosity; introducing gas into those reservoirs
in a variety of different ways makes oil more movable. She asked
them to imagine sand mixed together in a box with peanut butter
and how easy it would be to extract that peanut butter from the
sand and if you could magically change that peanut butter's
viscosity to where it flows like water so more could be gotten
out. Using steam and heat are other methods that need to be
tried; she didn't know which ones would be successful, but they
all require fuel and natural gas is the fuel to make those other
things happen.
11:29:51 AM
SENATOR STEDMAN asked how the AOGCC deals with valuation for oil
estimates.
MS. FOERSTER replied that the AOGCC just has to worry about the
science and not which is worth more. Their job is to get them
both out and it's easy to get gas out no matter what is being
done to the oil, but the opposite is not true. Oil is the more
valuable of the two resources, but the science says it's the
harder one to protect.
SENATOR DYSON said it was represented yesterday that the bullet
line hadn't gotten a commitment from the major producers on the
North Slope to sell it gas, but they are required to make gas
available. Yet he remembers conversations with the AOGCC and
folks who understand the reservoir that it's probably seven or
eight years before gas could be taken off without losing oil
production.
MS. FOERSTER responded that it will be several years before the
AOGCC will feel comfortable that gas off-take from the North
Slope is a prudent move. No matter when it happens there will
likely be oil losses unless all the oil is gone. Then there is
the balance between how late you can wait to extract the gas
before the infrastructure on the North Slope is starting to
"peter out." She said operators are forecasting that they will
be selling that oil until 2050, so she personally was not in a
hurry to get the gas out of the ground. But based on what is
publicly available about what the operators are doing to
accelerate production - they're drilling lots of horizontal and
multilateral wells - and what they are doing to mitigate losses
- they're putting in pilots for testing like gas cap water
injection - in the seven or eight-year timeframe, she thought
the state would be comfortable with the losses that will be
incurred if there is a gas sale. At that time the AOGCC wouldn't
be the bad guy.
SENATOR DYSON asked under the existing legal regime if the
producers are required to release gas.
MS. FOERSTER replied she didn't know what producers are required
to do in their DNR leases, but they could be in a real dilemma
if they are required to sell gas when the AOGCC told them they
couldn't because it would be causing too much waste of the oil.
If that's what their lease says, the AOGCC could probably trump
the DNR, but the legislature could overrule the AOGCC.
11:34:51 AM
SENATOR STEVENS asked her to reflect on the administration's
goal of 1 million barrels a day and what is best for Alaskans.
MS. FOERSTER replied that anything they can do to increase the
throughput in the TransAlaska Pipeline System (TAPS) is a good
thing. It's a lofty goal that is challenging and heavy oil
resource development using natural gas is integral to achieving
that goal.
SENATOR WIELECHOWSKI said in 10 years if the gas pipeline is
built and if the oil/gas ratio is the same (20 or 25:1) it
doesn't seem like there would be a whole lot of incentive for
the oil companies to put gas in the pipeline when they can still
use it to extract a much more valuable resource and asked to
what extent that is playing into oil company resistance to
commit gas to the pipeline.
MS. FOERSTER replied that she had three answers: one was that
her experience is what is good for the oil companies (that are
really working to maximize production) is good for the state and
two; they are in the business of making money. Stockholders want
that. And three, if the gas is still being used to get more oil
out of the ground she thought everyone in the state would want
them to do that.
SENATOR WIELECHOWSKI asked if they are being unreasonable
thinking they should North Slope gas can be committed to a
pipeline in the next decade in light of oil/gas ratios.
MS. FOERSTER replied that she didn't think it at all
unreasonable for the legislature to be asking the oil companies
to explain why they are doing what they are doing and why they
are not doing something else and to urge them to do things that
appear to be in the best interest of the State of Alaska and let
them explain why it's not if they don't see eye to eye with
them. It's also the legislature's responsibility to listen very
carefully and very open mindedly to their answers and be open to
the possibility that maybe they were wrong and as well as maybe
they were right.
11:38:50 AM
CO-CHAIR PASKVAN said he heard earlier that AOGCC approved 2.5
bcf to be taken out of the reservoir and asked if that was
accurate when that would commence and what her thoughts were on
a 4.5 bcf extraction. And last, they are here today as part of
the 0.5 bcf in-state gas line and how would that would affect
the 4.5 bcf needed for the big line.
MS. FOERSTER replied that the 2.7 bcf off-take was put in place
in the 70s. In 2006/7 after she had come to the AOGCC, that got
reviewed. They conducted a study in which BP and the other
Prudhoe Bay operators generously shared confidential data. At
the hearing they decided that there was no reason to change the
2.7 bcf - and that by the time anyone could build a pipeline it
would either be good or there would be plenty of time to see it
coming that they could change it if needed.
She said the AOGCC was asked for an opinion on the 0.5 bcf line
and used a similar rationale for saying that that small of a
volume would probably be okay five or six years from now.
MS. FOERSTER said a 4.5 bcf line depends on when it happens, how
much of the oil has been extracted and what mitigating steps the
operators put in place to prevent loss of the gas. But the AOGCC
could hold an emergency hearing and put a stay on production and
sales into that line until they came to a conclusion which today
would be no, you can't sell the gas.
11:42:58 AM
REPRESENTATIVE GARA asked if the legislature would still have to
authorize a 4.5 bcf line in 2020 or afterwards and would the
AOGCC say yes at that time.
MS. FOERSTER replied that is hard to say. By 2020, a 4 bcf line
might be good for the state. That's nine years from now and she
asked if they could even tell her what Alaska's operating budget
will be then? No. She related that the operator is accelerating
and putting in mitigation.
REPRESENTATIVE GARA stated that the governor says more oil is
needed in the pipeline and asked what she thought was realistic
to get out of the pipeline leaving aside offshore drilling for
now.
MS. FOERSTER replied that offshore is going to be the key. She
thought 1 million barrels was a very aggressive goal. She hoped
it would happen even though she wouldn't bet on it. She said
leaders are needed who will set goals.
SENATOR DYSON asked if she thought 500 mmcf could be taken off
in five or six years.
MS. FOERSTER replied that she didn't think that would be a
problem, but there will be losses; it's a balance.
SENATOR DYSON asked how realistic it is that rich gas plays are
in the area.
MS. FOERSTER answered that discovering at least 150 tcf on the
North Slope is very realistic. Every oil province she has worked
in has had gas associated with it and every province she has
worked in is where people have looked for the oil because it is
much more valuable than the gas. Until they had a market for the
gas, they flared it until they were told they couldn't because
it's wasteful. When people have drilled wells that have
encountered something that doesn't look like oil, they have
called it a dry hole and moved on.
SENATOR DYSON said people talk about how magic CO is for lifting
2
heavy oil and that is a by-product of gas conditioning.
MS. FOERSTER commented if there is a market for gas it's likely
that people will find more. It could be used for pressure or
sale. CO production is association with the gas produced at
2
Prudhoe and it will be the same at Pt. Thomson. She explained
that when you sell gas into a gas pipeline you have to extract
the things like CO and HS that are corrosive to the metals in
22
the pipeline. So CO will be extracted from the gas and something
2
will have to be done with it because it is not an
environmentally friendly byproduct and just letting it go is a
thing of the past. It will have to be sequestered. The best
place to put it would be in the ground where it could help get
more oil out. CO is known as an enhanced oil recovery substance.
2
These synergies will happen, but to what extent and where are
yet to be determined.
CO-CHAIR PASKVAN asked if natural gas pressure is important to
development of shale oil since Alaska may be entering into a new
phase.
11:51:31 AM
MS. FOERSTER replied that shale oil is a slightly different
animal. The reservoir is a harder rock and it won't have a gas
cap or an oil rim. There is pressure and that is essential to
the ability to lift the oil out of the ground. Other issues will
be equally important or more like establishing permeability
channels (through the hydraulic fracing process) to allow that
resource to get out of the rocks. If you have heavy fluid that
has to make it up out of the ground a mile or two it has to have
something pushing and that's going to be pressure.
REPRESENTATIVE SEATON asked if the potential settlement on Pt.
Thomson would override AOGCC criteria for hydrocarbon recovery.
MS. FOERSTER replied that she hadn't seen the settlement, but
couldn't imagine ExxonMobil signing a contract agreeing to break
Alaska law to get their leases back. She reminded people that
the Pt. Thomson reservoir, although it's been called a gas
reservoir by the state of Alaska's definition of what makes a
gas reservoir, it's not. It's an oil reservoir, because the
gas/oil ratio makes it fall within the definition of an oil
reservoir. So, Pt. Thomson would be another one of those
reservoirs that the operator would have to get permission from
the AOGCC to produce the gas, because producing the gas puts the
oil at risk. Pt. Thomson is a little different than Prudhoe in
that it's not a standard oil reservoir where the gas cap keeps
the pressure up. At Pt. Thomson the worry is that the gas exists
in the reservoir in a dense fluid phase; not really liquid and
not really gas. So, it's not adhering to the rocks. But if
pressure is dropped in this "retrograde condensate reservoir,"
then liquids (like liquid hydrocarbons) would drop out. As they
drop out, they adhere to the rock like a sponge and right now
they don't have a way to squeeze that sponge. As the Pt. Thomson
fluids go from that dense fluid phase into a liquid phase they
will adhere to a sponge which is the rock and a lot of it will
never be recoverable again.
11:55:56 AM
SENATOR WIELECHOWSKI said he expected to see Pt. Thomson
settlement terms soon and asked what specific rules the AOGCC
would apply to its development.
MS. FOERSTER replied "the monkey is on Exxon's back to prove to
us what the best way to produce the reservoir is." If it's
economically viable to produce the liquids, the commission will
make them do that. She added that the other place the liquids (a
150 ft. thick heavy oil rim) exist in Pt. Thomson is at the base
of the big gas condensate reservoir and that is a concern to the
AOGCC as well. So, Exxon has to demonstrate two things: they
have to put in a small cycling project and demonstrate how that
project will perform. Exxon is in the process of doing this. If
they can get enough liquid recovery associated with that cycling
project to justify the cost of expanding it, they will want to
do that and the AOGCC will make them do it.
If the liquid recovery from cycling is only marginally better
than the liquid recovery from blow down and that can be
demonstrated, then Exxon can't be forced to spend money that
they won't recover. At that point the AOGCC would back off.
Right now no one knows the answers, but Exxon has great models
and smart people and they are working on their small cycling
project.
11:59:34 AM
CO-CHAIR PASKVAN, noting the time, thanked everyone and recessed
the meeting at 11:59 AM.
^Presentation on Cook Inlet Activity Update and DNR Natural Gas
Studies by Paul Decker, Petroleum Geologist & Resource
Evaluation Manager and Jeff Dykstra, Commercial Analyst
DNR COOK INLET OIL AND GAS UPDATE
1:34:07 PM
CO-CHAIR PASKVAN welcomed everyone back and said this
afternoon's session would be an update on Cook Inlet.
PAUL DECKER, Manager, Resource Evaluation Section, Division of
Oil and Gas, Department of Natural Resources (DNR), said he is a
petroleum geologist and in response to some questions, that the
division is not equipped to evaluate undiscovered resources in
Cook Inlet. Their primary focus is on regulatory oversight and
providing the geological and engineering geophysical expertise
to make good regulatory decisions about where to lease lands and
once those leases are issued about how to manage them for
production of the resource. They make no attempt to conduct the
kind of probabilistic assessments that the USGS does.
He launched into an activity update for Cook Inlet: in June the
division conducted its annual Cook Inlet area-wide lease sale
and had a good turnout. One hundred and nine tracts were sold,
over 575,000 acres out of a total of 112 valid bids. The total
of all the high bids came in at about $11.2 million. This was by
far the best lease sale in the Cook Inlet in over a decade.
MR. DECKER said some of the key points to remember about this
sale is for the first time, at least in his recollection, they
created a Part B sale and held it as an exempt sale in which
statute authorizes them to differ from the sort of standard
leasing practices. In this case, specifically because there is
known oil at the Cosmopolitan or Hanson accumulation not too far
from Anchor Point, they decided to bundle the three open leases
together so that any bidder would have to buy not just one
lease, but all three.
1:38:00 PM
He said a couple of other tracts are still owned by Pioneer, the
operator of the former unit. That means the new owner will need
to come to terms with the previous operator of the other leases
and make a deal.
He said the department also raised the minimum bid
substantially, raised the rentals and shortened the primary term
of the leases to five years. The work commitment requires a plan
of exploration within six months and a well down to the oil zone
by the end of the fourth year. All of these special provisions
on those three tracts were geared at the same thing - to getting
whatever company would be interested in buying those tracts to
"get off the dime" and bring that accumulation into production.
Apache was the bidder that showed by far the largest interest in
the sale picking up almost all of it (95 of the tracts for about
$9 million).
MR. DECKER said the Escopeta Oil and Gas Spartan 151 jack-up-rig
that is the one that arrived in Kachemak Bay over a week ago has
its legs down and is rigging up for operation as he speaks.
Another really important consideration in Cook Inlet is the
status of gas storage. Three gas storage facilities are online
currently; together they have about 9 bcf of designed capacity
and when fully charged up with gas can produce gas at a design
rate of about 87 mmcf/day. The idea is to help temper the swings
on the coldest weeks of the year and to produce out of storage.
1:41:03 PM
CO-CHAIR WAGONER asked the highest rate that ConocoPhillips has
had to short their plant in order to meet peaking demand in the
winter time.
MR. DECKER replied that he would get those numbers for him.
SENATOR FRENCH asked if those storage facilities are public or
private.
MR. DECKER replied that he understands the three online storage
facilities are owned by single parties. Of the two more in the
works, the CINGSA/SEMCO facility is going to be the biggest and
will add about 11 bcf of designed capacity and 150 mmcf/day of
flow rate. It will to be open to third parties.
SENATOR DYSON asked if the enthusiasm over Cook Inlet leases was
the result of more oil potential or more gas potential.
MR. DECKER replied that his understanding from Apache's press
releases is that oil plays are being targeted and, of course,
drilling for oil in Cook Inlet is almost certain to find by-
catch gas.
SENATOR DYSON asked if at least a small expanding market for
Cook Inlet gas will make exploration more attractive.
MR. DECKER answered that he expected other companies would be
looking hard at what the more aggressive companies are doing and
that where one company goes others will follow.
SENATOR DYSON asked if the increasing gas market and higher gas
prices make this market more attractive.
MR. DECKER replied the expanding gas market and particularly the
presence of new gas storage projects will make a very large
difference for operators, because they can get a payout on gas
production all year round not only on the coldest parts of the
earth and they won't have to shut in wells to nearly the same
extent.
1:44:20 PM
MR. DECKER said the three storage facilities on the map are: the
Marathon Kenai facility that has a flow rate of 6 bcf/day and 6
mmcf/day of design capacity, and HilCorp at both Swanson River
and Pretty Creek; and the Aurora Nicolai Creek Field has
approached DNR about a gas storage facility, but has not made
great strides in accomplishing it. The big one is the
CINGSA/SEMCO project at the Cannery Loop, which would more than
double existing capacity in the basin.
He said Apache now holds over 800,000 acres and he added that
they will start a 3-D seismic program on the west side of the
Forelands this year. They just completed a test 2-D seismic
acquisition program that leads them to believe they will be able
to gather some superior 3-D data with new technology. Hopefully
they will start a well in 2012.
1:46:30 PM
CO-CHAIR PASKVAN asked his thoughts on the impacts the
additional 11 bcf/day of storage capacity will have on drilling
for gas.
MR. DECKER replied that it would give the operators market
assurance. As an example, Buccaneer has drilled a well (Kenai 1)
very close to the Cannery Loop called CINGSA Storage. That well
has helped them identify some reserves and just yesterday they
said they had reached an agreement with Enstar for production of
that gas directly into the CINGSA facility.
SENATOR WIELECHOWSKI asked if importing 500 mmcf/day from the
North Slope into South Central would have an impact on the
exploration in Cook Inlet.
MR. DECKER replied that he isn't an expert, but he thought it
would be positive.
SENATOR DYSON asked if he had any information on how productive
the formations (inholdings) under the Moose Range look.
MR. DECKER replied that he thought it be wonderful to explore
that area from a geologic perspective, but he hadn't seen data
about it first hand. It's clear that limitation to access to
lands in the basin is one of the key hurdles to overcome in
meeting the state's energy demands.
SENATOR DYSON asked if his map shows the total size of the Moose
Range.
MR. DECKER replied no; they do see the federal and state units
where leases are held by production, but those aren't the
private inholdings.
SENATOR DYSON asked if companies can only drill straight down in
the inholdings.
MR. DECKER answered that is his understanding.
1:51:08 PM
REPRESENTATIVE GARA asked if he thought just the discussion of
it happening might deter exploration in Cook Inlet and how long
before they get a good grip on what is producible and whether or
not there is enough gas to ship to Anchorage.
MR. DECKER answered that he didn't want to speculate on the
psychology of the explorers, but companies' philosophies about
how prospective an area is or how critical it is to them to
pursue an exploration program in a given area will change from
year to year, week to week and month to month. It's a very fluid
market and most investors are used to the concept of the
unknowns out there.
1:53:08 PM
REPRESENTATIVE GARA asked how long before they have a decent
picture of how much producible gas Cook Inlet has and whether or
not there is enough to satisfy Fairbanks demand with a pipeline.
MR. DECKER answered that he could show the department's
assessments of reserves in known fields, but Brenda Pierce,
USGS, would talk later about the undiscovered resource and its
potential.
He said that Hilcorp is the privately traded company that has
purchased the Union Oil Subsidiary of Chevron and has taken on a
lot of different properties including some of the gas storage
facilities. He hoped they would continue Union's progress with
the pipeline to bring the Nikolaevsk Unit into production in
2013. Escopeta has a rig in the basin for the first time since
1994. Buccaneer's Kenai Loop 1 has identified 26 separate gas-
bearing zones in the Beluga and upper Tyonek formations. They
are claiming 31.5 bcf of proven reserves that they expect to be
able to market - possibly directly to Enstar. Buccaneer has also
announced plans for another well, the Kenai Loop 2, and has
plans to bring a second jack-up rig into the basin next year.
Nordaq Energy drilled Shadura 1 well just west of the Swanson
River and hasn't released results, but has said they are
preparing permits for facilities. This sounds somewhat
optimistic. Anchor Point Energy is Armstrong and their working
interest owners working at the North Fork project; they recently
drilled and completed two wells, recompleted another one and
brought the North Fork gas accumulation onto production last
April. It is being produced now through a 7.4 mile pipeline over
to Anchor Point.
MR. DECKER said Cook Inlet Energy is mostly on the west side and
has restarted four of their oil wells in the west McCarthy River
Unit and two in the Redoubt Unit. Their plans include bringing a
custom rig to the Osprey Platform to drill more wells and
getting three onshore exploration wells permitted at the Sting
Ray Prospect.
Further north in the basin, CIRI is drilling some shall core
holes to understand the capability up there for underground coal
gasification.
1:57:02 PM
Linc Energy Alaska (LEA) drilled one well not far from Big Lake.
Initially they had encouraging press releases, but later
determined it wasn't commercial. They also have plans to drill a
well in the Trading Bay area on the west side and have a long
term interest in underground coal gasification in Cook Inlet, as
well. They have also just gotten active on the North Slope.
Which project goes first is to be seen; gas storage is a key
piece in the basin.
1:58:01 PM
MR. DECKER stressed that the department conducted two different
studies; the first completed at the end of 2009 and the second
in 2011. The 2009 study was an integrated engineering and
geological analysis to determine how much gas remains in known
fields using the department's figures; it didn't include
undiscovered gas resources, which is covered by the USGS.
SENATOR WIELECHOWSKI asked him where the 19 tcf gas number came
from.
MR. DECKER replied that Brenda would answer the detailed
questions about the USGS methodology, but the basic idea of
resource assessments is a probabilistic distribution from a low
side case to a high side case. The reality is they don't know
exactly where the resource lies and 19 tcf is simply the mean
expected case.
CO-CHAIR PASKVAN asked in working with the USGS numbers, how
much are they off compared to oil and gas probabilistic
interpretation.
MR. DECKER replied that it is impossible to quantify what hasn't
been seen. The DNR takes the opportunity to understand the
geological basis for the USGS assessments and collaborates by
giving them input - but USGS comes up with the assessment for
unit numbers by itself.
CO-CHAIR PASKVAN said he was trying to figure out what numbers
to rely on.
MR. DECKER advised that it's important to recall that how much
of that resource will ever come to market is very unclear. Their
task is to develop a wide range of estimates of what may be
present in the basin that would be technically recoverable. But
how much of that will become discovered resource and how much
will become commercial resource are two very different
questions.
2:03:14 PM
SENATOR WIELECHOWSKI said they have to decide in the next year
or so on whether to rely on the amount of gas in Cook Inlet and
build a bullet line to Fairbanks or to bring in gas from the
North Slope and asked if he had any advice.
MR. DECKER replied that he had no silver bullet words of wisdom.
CO-CHAIR PASKVAN asked if he believed that USGS estimate of 19
tcf is a reasonable number knowing there is variability.
MR. DECKER replied that he thought it was a good estimate, but
he didn't want anyone to believe that all of that gas will ever
come to market.
He went to the 2011 study that asked what sort of investment
would needed to get at those resources and reserves and how much
money would be attractive enough for investors to do so. So,
they assumed a 90 bcf/yr. to 2025 (different than historical
amounts because of the LNG facility and Agrium closings). They
generated dozens of development scenarios that consist of
drilling wells, adding compression and doing rig workovers if
necessary to specifically target the zones and fields where the
2009 study identified certain volumes of gas. Then they used a
Monte Carlo probabilistic simulation technique (establishing a
range of uncertainty and then sampling from all possibilities)
and derived what seems like the most likely outcome to model the
commerciality and production outcomes. He described various
charts related to the scenarios (slides 8-13).
He said Cook Inlet has biogenic (bacterial) gas and that is
being produced from the shallower horizons mainly from the
Sterling, the Beluga and the upper part of the Tyonek
formations. The Sterling has been a "gang buster" reservoir and
tends to produce high rates, but it is nearing depletion now.
Recent focus has been on the development of the less productive
zones in the Beluga and the upper Tyonek. The oil in the basin
has migrated up mainly from the lower part of the Tyonek
formation, the Hemlock and the West Foreland - those deeper in
the column, older rocks.
A contour map showed the base of the tertiary reservoir-bearing
section in the Cook Inlet Basin prepared by the DNR staff using
seismic data for which they have been given a generous license
from the CGGVeritas. Engineers prepared a decline curve
volumetric and separate material balance reserve volumetrics for
all 28 of the existing producing fields in the Cook Inlet Basin.
At the same time, the geologists and geophysicists prepared
reserve estimates for four of the largest five gas fields in the
basin. The four they chose were important because they are quite
significant in size and they also have sufficient data to make
this kind of analysis: the Beluga, the North Cook, the Trading
Bay Grayling Gas Sands and the Ninilchik. The answers were
compared and slide 13 showed green dots that are undeveloped gas
leads that the presence of gas can be inferred from previous
wells that were really looking for oil.
2:13:17 PM
MR. DECKER said the idea is to look at all the wells in all the
fields in all the zones and add up the thicknesses in the two
categories of pretty certain pay and potential pay and track
them; then make contour maps for each zone and each of the
fields. From those maps the bulk volume of the reservoir can be
calculated. Knowing the bulk volume of the reservoir and knowing
several other variables such as the saturation, the porosity and
the net thickness compared to the gross thickness, a calculation
can be run to determine how much original gas was in that
reservoir. The final step is subtracting out the gas that has
been produced to date from the original amount in each
reservoir. That leaves them with the reserves remaining in the
field figure.
Slide 16 is the summary slide coming out of the 2009 study
consisting of decline curve analysis and material balance
analysis (reserves in contact with existing well bores that can
be recovered with minimal investment), the green (relatively
certain pay) and the yellow (potential pay). The grey refers
back to exploration leads where previous wells have identified
from gas shows that might be worth following up. Forecasting the
volumes assumed about a 15 percent decline per year. This study
told them that the 90 bcf demand could be met with the
relatively high confidence resources and reserves through about
2018/19 assuming that gas storage is available and that people
make the investment. So, the state still has a few more years of
breathing room if the producers continue to invest.
Slide 17 is a slight tweak because a few months after they
published the 2009 study, Marathon and ConocoPhillips indicated
they would very likely be applying to renew their export license
for the next few years and that changed their demand forecast
for a couple of years out. The effect of that may be to shorten
the production life span from the reserves by up to a year.
He said slide 18 summarizes the geological, geophysical and
engineering analysis and identified substantial volumes of
producible gas that could be tapped in Cook Inlet. The volumes
of gas were defined in different "tranches" by different
techniques and the corresponding different levels of certainty.
The big "if" is if the investment is made in redeveloping the
older fields with infield drilling and other kinds of field
redevelopments. Those gas volumes in existing fields might be
enough to meet demand at least on a yearly annual basis through
2018 or so.
2:18:13 PM
MR. DECKER said the reason they feel redevelopment activities
are a good bet is because the Kenai gas field (Beluga and
Tyonek), for instance, shows three things. He explained that up
through 1994 fewer than 10 wells were producing at any given
time. Gas production peaked in 1979 (slide 19) and water started
being produced in the 1980s which is when the decline started.
In 1994/5 additional wells were drilled and water handling
facilities were added. But importantly, the gas rate really
increased dramatically by some 30 mmcf/day, which offset that
decline so far that they were able to add 90 bcf of reserves to
the field. This is their "local poster child" for why they
believe redevelopment efforts are very worthwhile in the older
Cook Inlet fields.
The 2011 study summarized how much investment it would take and
what sort of scenario would be required to go out and get the
gas identified in the previous study. So, the division put
together a study team (petroleum geologists, petroleum
geophysicist, petroleum engineers, commercial analyst and a
petroleum economist) and brought in consultants (Ryder Scott) to
do reservoir engineering and modeling, decline forecasting and
development scenarios and Solsten XP to do drilling operations
and facilities design requirements and costs. They also had a
peer review group both internal and outside. Before the study
was released it went through several iterations of peer review
with the staff of the Alaska Gasline Development Corporation,
Enstar, Davies Consultants, and PetroTechnical Resources of
Alaska.
MR. DECKER said the 2011 study developed conceptual development
scenarios (slides 21 and 22) including: how many wells it would
take in what zones, where they would be placed, how much they
would cost, how much compression should be added to a particular
facility that would allow that fuel to be produced at a lower
pressure and still get gas into the pipelines, et cetera. The
next part was handing off the assumptions to the economic side
of the study to estimate the risks and probabilities of success
for various scenarios achieving their intended goals and to come
up with other existing constraints.
2:23:33 PM
To determine what investments and revenue would be required to
generate specific rates of return from identified gas reserves
to meet demand of 90 bcf through 2025 the analysis was run
through a Monte Carlo simulation. Adding compression, they felt,
could add 288 bcf and drilling new wells to tap the untapped
parts of the fields where existing wells just aren't draining it
could add another 600 bcf. Taking a harder look at the
development leads revealed an expected case of around 250 bcf;
for a total of 1.8 tcf that "might be out there in these
existing fields." He stressed this does not include range
exploration or unconventional gas resources such as coal bed
methane, but what is just within the existing fields. And
because they were doing the Monte Carlo statistical technique,
each of their forecasts was built with a high side case and a
low side case (just like the resources assessments).
2:25:40 PM
JEFF DYKSTRA, Commercial Analyst, Division of Oil and Gas,
Department of Natural Resources (DNR), followed up saying his
division built on the information that Mr. Decker just went
through. All the caveats he mentioned are the same for the
commercial group (starting with slide 25). He said they had a
broader team of more than just the experts that reviewed the
results as they stepped through the analysis.
The economic flowchart was broken up into two classes; the first
class looked at baseline production wells (wells that are
currently producing without additional investment) and range
estimates were made as to how those are going to decline. The
second was categories of wells that need additional investment;
those were broke up into 38 different projects, some of which
were single wells and some multiple. A project was defined as
something that normally could be done in one drilling season; 26
projects were in existing fields and pools and didn't require
extensive infrastructure and 12 projects were in identified
leads and might require additional facilities and one or two
drilling seasons.
MR. DYKSTRA said the sources of data were DNR, Ryder Scott and
Solsten XP Consultants.
2:28:19 PM
SENATOR WIELECHOWSKI asked if they're assuming 1.8 tcf is the
total of all the extractions and if it assumed the new USGS
numbers.
MR. DECKER replied no; the idea here is that these numbers do
not include undiscovered resource whatsoever. These numbers work
with the known fields and those few development leads in the
gray category that previous drilling has already sort of
identified as candidates for follow up work.
SENATOR WIELECHOWSKI asked if the 1.8 tcf is part of the total
19 tcf.
MR. DECKER replied that it would be in addition to.
SENATOR WIELECHOWSKI asked if it would be possible to do an
analysis like this regarding the 19 tcf of undeveloped reserves
over the next couple of months.
MR. DECKER replied that would use a very different methodology
that he couldn't really define it right now, but he noted the
suggestion.
MR. DYKSTRA said slide 28 indicated reasonable rates of return
assuming the existence of proper storage. He explained the
"Expected Monetary Value" chart for particular rates of return
and that most of the projects are in the less than $10 million
range and about 25 percent are above.
2:34:52 PM
SENATOR WIELECHOWSKI asked if at $4/mcf a company is making far
in excess of the 20 percent internal rate of return.
MR. DYKSTRA replied given the assumptions of the study that
would be a correct interpretation, but that cost does not
include the cost of storage or transportation. The assumption of
storage is the biggest factor to evaluate.
SENATOR WIELECHOWSKI asked what cost of storage.
MR. DYKSTRA replied he meant the storage that must be available
so the wells could be immediately produced.
CO-CHAIR PASKVAN asked if he was talking about the 11 bcf
storage facility he mentioned earlier.
MR. DYKSTRA answered yes.
SENATOR FRENCH asked Mr. Dykstra if he knew of some uncertainty
about completion of the facility that he hadn't heard about; he
thought it was "on a very, very solid track for completion."
MR. DYKSTRA replied that they believe there is a very high
probability the facility will be built.
SENATOR FRENCH asked what the presence of that storage facility
would do to those numbers.
MR. DYKSTRA replied his numbers assume that storage is available
now.
2:37:03 PM
CO-CHAIR PASKVAN asked him to explain slide 27 again.
MR. DYKSTRA replied that the IRR10, IRR15 and IRR20 [figures on
the chart] solves the revenue requirements expressed as a dollar
per thousand cubic feet that would require an expected monetary
value of the euro discounted at those particular rates.
CO-CHAIR PASKVAN laughed and asked if he was saying less than
$3/mcf of investment was needed to produce enough volume to sell
at current prices (slide 28).
MR. DYKSTRA answered that would be the cost of the next mcf that
would be required to meet that 90 bcf/year demand. It's only one
financial metric and a lot of times producers look at multiple
metrics. If this is the only metric looked at people should be
investing like crazy. The other metric he used suggests it is
not as favorable as this one suggests. Both metrics (expected
revenue requirements and expected monetary value) have to be
satisfied in order for producers to invest.
2:39:42 PM
SENATOR FRENCH said the committee needed a little more
explanation of how the two slides [27 and 28] go together and
asked what the 0 - 4, 4 - 8, and 8 - 12 on the lower axis [slide
28] represented - the total return or the total investment?
MR. DYKSTRA replied that would be the total return expressed in
a net present value or expected monetary value (EMV) at those
particular discount rates. [The 0 - 4, 4 - 8, et cetera
indicates millions of dollars.] The other axis is how many
projects fit into that particular value range.
SENATOR FRENCH said for the first pair of bars 12 projects will
return a 15 percent EMV.
MR. DYKSTRA corrected that 12 projects would have an expected
monetary value of between $0 and $4 million with a discount rate
of 15 percent.
SENATOR FRENCH remarked that most projects will return a fairly
small total monetary value.
MR. DYKSTRA answered yes.
REPRESENTATIVE SEATON asked if the first 0 - 4 means there is an
additional eight projects that would be producing at 10 percent.
It looks like a greater number of projects get produced at 15
percent.
MR. DYKSTRA clarified that the chart shows the same projects and
it's showing the projects with a positive EMV. It's showing two
different discount rates, one at 15 percent and one at 10
percent.
CO-CHAIR PASKVAN stated that slide 25 identifies 38 projects and
asked if this was the distribution of those projects.
MR. DYKSTRA replied it is the distribution of the 38 projects
that showed a positive net present value; they all don't show
positive at that particular value. The negative ones were not
plotted. In other words, some definitely require more than the
$5.77 to have a positive net present value at those discount
rates.
CO-CHAIR PASKVAN asked at $5.77 and assuming a selling value of
$6.25 if more projects become recoverable.
MR. DYKSTRA answered yes. He said they did some projects both
onshore and offshore. Capital costs for an offshore gas-only
with no oil takes a substantial amount of revenue to offset the
required large capital costs. The analysis of those truncated at
$15/mcf showing at those rates projects were not economic.
CO-CHAIR PASKVAN asked if he used the $5.77 because he was
trying to project whether resources will be available to meet
that demand at current energy cost structures.
MR. DYKSTRA replied the assumption here as they looked at the
supply curve is there will be continued investments. So, they
were trying to see if there will be significant investment, and
some metrics suggest that there will be.
2:45:19 PM
MR. DYKSTRA said slide 29 illustrated the supply curve coming
out of the Monte Carlo simulation. For each of those projects
they estimated low cases, high cases and what the expected case
was; then used Monte Carlo techniques to simulate 5,000 possible
ways that information could manifest itself in the future. The
90 bcf/yr. supply target starts a decline in 2018 and they did
not see any point in extrapolating the "uncertainty band" of
data out to zero. His interpretation of slide 29 is that he
could say with 90 percent confidence that the blue curve or
better would be the future given the assumptions of the study
and that there is a 15 percent chance of a decline in the 2020
timeframe.
SENATOR WIELECHOWSKI went back a slide and said his
understanding of EMV is you have to assign a probability of
occurrence of a risk and then a monetary value to the impact of
the risk and asked what the risk is, what the probability of the
risk is and what the monetary value is.
MR. DYKSTRA answered that the risk is largely made up of the
probability of failure that you would drill and not be able to
monetize anything.
SENATOR WIELECHOWSKI asked what the expected probability of
failure is for infield and exploratory activities.
MR. DYKSTRA answered the study used a range of 5 percent for
certain failure and 90 percent for most uncertain.
2:48:48 PM
CO-CHAIR PASKVAN said slide 28 was based on $5.77 and asked what
the supply curve would look like if it changed.
MR. DYKSTRA replied that they didn't run that case, but they
could do it.
SENATOR WIELECHOWSKI referring to slide 27 said the in-state gas
line is scheduled to come on line around 2019 with a price of
$9.63 and at a 20 percent IRR gas is $7 and he asked if the
distribution costs would be more then.
MR. DYKSTRA answered that this would be the expected case and
was based on a revenue requirements model that is not
necessarily a proxy for the market.
SENATOR WIELECHOWSKI said it looks like at 10 percent ROR gas is
$5 gas, but at 20 percent ROR gas is $7. So, it looks like you
would get lower cost gas if this were correct and you were to
bring gas from Cook Inlet today. Is that correct?
MR. DYKSTRA replied that he was looking at only one metric and
there is danger in that. That is why they look at various
metrics. It's unclear whether producers are driven only by rates
of return and they most likely are not.
SENATOR WIELECHOWSKI asked if the other metric would be expected
monetary value.
MR. DYSTRA replied that is one, but he would assume the
producers are looking at a lot of different things and he didn't
know their business process.
2:52:09 PM
CO-CHAIR PASKVAN asked if the $5.77 is the cost at the well with
tariff and local distribution charges in addition to it.
MR. DYKSTRA replied that it does not include the tariffs, but he
wanted to verify that.
REPRESENTATIVE GARA said if the in-state line is built that
obligates people to 20 years of $11 or $17 gas and there could
be cheaper gas sitting in Cook Inlet. Will explorers keep
exploring in Cook Inlet because they know that they can beat the
price of the in-state gasline?
MR. DYKSTRA responded that was in the realm of speculation and
this study was based on what Cook Inlet can do by itself.
REPRESENTATIVE GARA said the last thing they want to do is to
leave $7 gas in the ground, sign on to a $30 deal for 50 percent
more expensive gas and then have to tell constituents they
didn't have the information. How do they get the information?
MR. DYKSTRA replied this particular study shows depending on how
they want to define their risk preference that the state will
need either additional gas or to have some success via
exploration. The question will be when to bring that gas in and
he didn't think that answer was needed quite yet if the study
suggests looking at what investment took place every year or
couple of years and redo the numbers.
2:56:21 PM
REPRESENTATIVE SEATON said this chart is capped at $15/mcf, but
they aren't anywhere near that. Through 2021 they are talking
about a maximum price of gas at less than $12 at a 20 percent
IRR. Is that right?
MR. DYKSTRA answered this chart is expected value and there are
two dimensions in play, one is price and the other is supply. In
2021 some cases in the study run out of gas. If you look at that
particular scenario, you would have been at that $15 cap
whenever it ran out of gas, but this particular graph aggregates
those 5,000 results into one number.
CO-CHAIR PASKVAN asked if he had discounted the USGS numbers to
zero, because he was only addressing the known reserves.
MR. DYKSTRA replied yes, and added that exploration can change
their results as can unconventional and some other things.
CO-CHAIR WAGONER commented that this didn't even include the
latest find by Buccaneer that was put into the known reserves.
MR. DYKSTRA replied that was correct.
REPRESENTATIVE SEATON asked if slide 28 in which the lower
investment projects have been used up earlier relates to slide
27 where projects incrementally go up over time and prices get
higher in the outer years.
MR. DYKSTRA answered yes; the modeling is done in stages so that
the most economical projects get done first.
2:59:38 PM
MR. DYKSTRA wrapped up saying that they have probably all come
to the same conclusion in that given sufficient investment the
results show there will be sufficient gas supply to 2018 and the
second point is that natural gas storage will play a key role in
that.
CO-CHAIR WAGONER asked if DNR's plan is to continually update
this study on a two-year basis so they can see what exploration
has been and how many proven reserves have gone into the system.
MR. DECKER responded that he had not heard discussion within DNR
that this was going to be an ongoing study. If it is to be
useful information, perhaps something it could be freshened with
new information.
CO-CHAIR WAGONER said he wanted to make that request right now -
at least on a two-year basis if not a one year.
CO-CHAIR PASKVAN added that the two co-chairs of Senate
Resources agree with that as certainly everyone on the
committee.
SENATOR DYSON underscored Representative Gara's point that they
need the best estimates they can get on what this basin will
produce in order to have a base on which to make big and
important decisions.
REPRESENTATIVE GARA asked since there is enough gas until 2018
or 2020 that given existing fields and new successful
exploration it could go beyond 2020.
MR. DYKSTRA replied that is correct.
SENATOR WIELECHOWSKI said this is critical information and he
looked forward to other presentations as they move forward. One
of the things he has heard is that producers of a lease will
tend to not produce or at least discover reserves more than
eight years longer than the demand will account for and asked if
that is normal and a good timeframe to use.
MR. DECKER replied that a long lead time is needed in Alaska as
compared to other jurisdictions, and the North Slope needs 10
years of lead time.
3:05:05 PM
CO-CHAIR WAGONER said the 10-year timeframe is not generic for
all wells drilled in Alaska and could maybe be used on the North
Slope from discovery until infrastructure is built out. But
Buccaneer just got a lease and permits, put in the pad and
drilled the well and will be in production by the end of the
year. That is an 11 or 12 month timeframe! It depends on the
logistics, the location and the availability of infrastructure
to put the product into.
MR. DECKER agreed and said he was thinking specifically of
remote large projects on the North Slope.
3:07:12 PM
Recess from 3:07 to 3:21 p.m.
^Presentation on USGS Assessment of Cook Inlet Natural Gas
Reserves by Brenda Pierce, Program Coordinator, Energy Resources
Program
USGS ASSESSMENT OF COOK INLET NATURAL GAS RESERVES
3:21:49 PM
CO-CHAIR PASKVAN welcomed Brenda Pierce to the meeting and
thanks her for coming all the way from the East Coast. He said
the 19 tcf in Cook Inlet has peaked a lot of interest in Alaska.
BRENDA PIERCE, Manager, Energy Resources Program, United States
Geological survey (USGS), Department of Interior, said the
department appreciates their interest in USGS work and she would
do her best to answer their various questions.
MS. PIERCE said she would first give them a summary of USGS
results, how they did what they did and where the resources
might be found. She said the USGS gives a range rather than just
a mean; it looks at the undiscovered resources that have great
uncertainty and are in addition to the known reserves. Even
though those are undiscovered they can be technically
recoverable with today's technology and industry practices which
the USGS goes to great lengths to determine using proprietary
databases and looking at other development in the area. In areas
that have no production and truly frontier areas, they look at
areas that might be analogous that are being produced.
For the Cook Inlet, Ms. Pierce said, they looked at the onshore
and state waters and not the outer continental shelf (OCS). They
found the mean, the 95 percent probability (F) and the 5
95
percent probability (F). Emphasizing again how uncertain these
05
numbers are because the resource is "undiscovered," she said
that Cook Inlet has about 600 million barrels of potential oil
at the mean, but it ranges from at least 100 million barrels to
more than 1 billion barrels. For gas, they found a mean of 19
tcf. There is a 95 percent probability that at least 5 tcf or as
much as 40 tcf of gas is there to be discovered.
3:27:48 PM
MS. PIERCE explained for perspective the mean amount of the
undiscovered gas in Cook Inlet is 19 tcf and almost 8 tcf has
been produced in the Cook Inlet to date. U.S. gas consumption in
2009 was about 21 tcf. Proved gas reserves on the North Slope
are about 35 tcf.
Using the same type of comparison, the mean amount of
undiscovered but technically recoverable oil in the Cook Inlet
is 600 million barrels. In 2010 cumulative oil production in
Cook Inlet was a little over 1 billion barrels. U.S. oil
consumption in 2010 was about 7 million barrels.
Slide 6 illustrated the four areas that are producing reserves
now which they didn't assess as well as areas of undiscovered
but technically recoverable oil. That doesn't mean they are
economically recoverable. She also pointed out that not all
areas are accessible for development and that it's important to
know what might or might not be possible and they think they
have a good understanding of the area's potential.
3:29:54 PM
SENATOR FRENCH asked how much of what is technically recoverable
is also an area that is not closed to development by refuges and
critical habitat.
MS. PIERCE replied when USGS assesses a basin or a province,
they break it down into assessment units. Some of them cover the
whole area and some are much smaller. They can allocate to
certain areas, but she didn't have those numbers today.
SENATOR WIELECHOWSKI asked how often she is right.
MS. PIERCE replied that their estimates are very viable, but
sometimes they are wrong. One of the uncertainties is whether
the resource is oil or gas; another is whether they are dry
holes or not. Industry is wrong all the time as well, but often
they are both right and sometimes discoveries are made exactly
where USGS predicted them. She couldn't give him a specific
answer because some resources are technically recoverable but
not always economically recoverable, and they hadn't done that
kind of analysis. And what a company will or will not develop
doesn't always depend upon just what is technically recoverable.
There are access issues and what a company wants to do with its
portfolio and the economics of the situation. Her numbers
provide a best estimate at a given time based upon available
geology and science and those numbers change sometimes because
of new information.
3:32:26 PM
MS. PIERCE said because USGS does undiscovered resources, it's
very important to get the best geology available to build their
geologic models and try to put the uncertainty in a quantitative
mode. They work very closely with geologists from the DNR, the
Division of Geological and Geophysical Surveys (DGGS) and the
Division of Oil and Gas (DOG) to develop very robust geology and
estimate the number of sizes and fields they think the geology
of the area can accommodate. That is what is run through a Monte
Carlo simulation.
She said the USGS has spent the last several years building a
new geologic map of the Cook Inlet region and have new seismic
reprocessing, interpretations and new gravity and magnetics
modeling. The rock has to be understood in order to know if
organic materials are there to begin with and that they have
been heated enough to form the oil/gas and that the timing was
right that conventional resources migrate through the system
into a trap. All of these pieces need to be present in the
geological models in the right sequence and with the right
parameters for the oil and gas to form to have even been
preserved.
Each part of the geologic model is risked and then it is run
through the Monte Carlo simulation to get the quantitative
numbers.
3:35:22 PM
CO-CHAIR PASKVAN asked if it's fair to assume that information
about an area with decades of production like Cook Inlet
increases the probability of accuracy.
MS. PIERCE replied that was a fair statement. USGS spends a
considerable amount of time developing these resources with a
lot of help from others, but they run the final numbers
themselves.
3:36:53 PM
SENATOR STEDMAN asked to spend a little bit of time on slide 9
"Geologic setting: Cook Inlet is a forearc basin."
MS. PIERCE said it is a fairly complicated and unusual area;
it's the only forearc basin in North American to have oil and
gas in it. The Pacific Plate is moving northwest along Alaska
being subducted under the Aleutian Plate (Megathrust) and that
is causing a lot of the volcanos and seismic activity. You don't
normally have oil and gas resource even expected in this type of
area. She went to slide 10 and said the Aleutian Range and Kenai
Chugach Mountains are not going to be prospective for oil and
gas at all. A lot of that is controlled by what is happening in
the larger geologic picture.
She said that Cook Inlet oil has 33 discovered fields with oil
and gas production; 8 are mostly oil and 25 are mostly gas. Even
so, large parts of the basin are undrilled or sparsely drilled.
3:39:26 PM
SENATOR WIELECHOWSKI asked if she anticipates any unconventional
or shale gas or oil in this reservoir.
MS. PIERCE replied there is unconventional, but a couple of
their geologists thought the sequences were too "clayey" to be
prospective for shale gas. However it has tight gas and other
kinds of unconventionals. She said because conventional and
unconventional are assessed differently different methodologies
are used. She said they built a new geological map out of this
assessment and inserted what is known about the oil and gas
using that as a starting place. She said the basin is very deep
and very thick, which is why it is so prospective. The non-
marine strata are fairly young from 0 to 66 million years ago.
Older strata are marine sedimentary rocks and they are underlain
by very thick volcanic rocks which are not prospective for oil
and gas. The brown, orange and tan areas have the coal beds that
are sourcing the biogenic gas (gas from microbial activity). The
greens indicate deeper rocks that have the thermogenic gas that
comes from cracking up the hydrocarbons and the higher
temperatures that has helped it migrate up the faults into
conventional reservoirs.
MS. PIERCE explained that those units of rock that have common
geologic traits but are unique from others are called assessment
units (AU). Cook Inlet has four assessment units (slide 14):
Cook Inlet coalbed gas, tertiary sandstone oil and gas, Tuxedni-
Naknek continuous gas, and Mesozoic sandstone oil and gas.
Stratographically they are overlying each other in the
subsurface.
3:43:32 PM
MS. PIERCE explained that the conventionals are discrete
accumulations that are water-bounded; they are either in
structural or stratigraphic traps. They can be oil or gas and
are relatively easy to find and develop compared to the
unconventionals. Unconventionals are called continuous because
they include shale gas or tight gas, and then there are the
truly unconventional like hydrates or oil shale. They are called
continuous because geologically they're continuous across the
basin - so they are coalbed gas, tight gas, basin-centered gas
and shale gas.
She explained the difference between stratigraphic traps versus
structural traps because it is important to know in Cook Inlet.
Production has all come from structural traps and none from
stratigraphic traps and there may still be significant resource
potential in the untapped stratigraphic traps.
The Tertiary Sandstone Oil and Gas AU was more detailed on slide
16 and she noted they looked at the Middle Jurassic shale near
the Red Glacier. The map had points for oil and gas fields and
wells and indicted significant well penetration. She pointed out
the reservoir rocks on slide 17 saying one of the biggest
differences between conventional and unconventional is source
rock and the reservoir rock. Conventional has been formed at
depth when organic material gets heated and forms oil and gas;
it rises up through the strata and becomes reservoired in
impermeable areas. The biggest difference between that and
unconventional tight and shale gas is that those are still in
their source rock; they have not moved. And because they haven't
moved they are more difficult to produce. You have to fracture
them or do something else. That is why until recently they have
really not been economic to produce.
She explained that the Tertiary Sandstone AU is a conventional
reservoir assessment and has about 1,200 well penetrations and
about 30 known accumulations. Over 1 billion barrels of oil have
been produced along with almost 8 tcf of gas. The source of the
oil and the thermogenic gas is in the marine shales in the
Middle Jurassic shale group, but the gas listed earlier is
mostly microbial (biogenic) forced from the coals. So there is
significant resource potential there. The reservoirs are mostly
tertiary fluvial sandstones and all the discovered traps are
structural. Stratigraphic traps are still out there and most
likely to be found. The undiscovered traps are probably both
structural and stratigraphic, but significantly stratigraphic.
They think this area is underexplored and has the most
potential. The source of gas is marine shale and that is also
underexplored and has the most potential.
3:49:16 PM
MS. PIERCE said it's important to understand that the thin
discontinuous sands show the potential with Cook Inlet geology
and a very important consideration there is that a well could
completely miss the sand that has oil and gas in it. Slide 20
showed seismic lines, potentially untested oil and gas,
potentially undrilled structures and potential stratigraphic
traps that are untested. Cook Inlet has a lot of potential.
Slide 21 was of land ownership that helps get at what may or may
not be available for both exploration and production.
SENATOR FRENCH asked if her estimate assumes that the
undiscovered oil and gas is uniformly distributed across the
area within the yellow boundary.
MS. PIERCE answered that they don't assume that the resource is
uniformly distributed, because the geology is not uniform. They
say that the resource is within this area. They don't assess the
parcels because that goes beyond what the available data
provides.
SENATOR FRENCH said this area seemed to be the source of the
greatest amount of undiscovered oil and gas.
MS. PIERCE agreed; more than 300 million barrels of oil and 12
tcf of gas.
SENATOR FRENCH asked how many penetrations it would take to get
to an "explored" basin level.
MS. PIERCE replied that she didn't have a pat answer. It would
take sitting down and looking at the seismic and what is known
and mapping out what they think is happening.
SENATOR FRENCH asked if she had just a ballpark figure. He
wanted a feel for how unexplored it is. "Do we have to double
the number of wells before we get there?"
MS. PIERCE repeated that there just isn't a good answer to that.
It's not so a much a number; it's an area that doesn't have any
data.
3:52:42 PM
CO-CHAIR PASKVAN said another issue is how long into the future
the reserves are created and, "Why spend the money for 30 years
if you only need to spend the money for 8 to 10 or 12 years?"
MS. PIERCE responded that companies keep the reserves on the
books fairly constant and replenish what they have produced.
That information is kept "on the back burner at all times." It
depends on what you need and the timeframe you need it in and
today's economic analysis may change tomorrow.
3:54:22 PM
SENATOR WIELECHOWSKI said Cook Inlet is a stranded gas market
and asked if she would expect to find companies booking 30 or 40
years of reserves when they have no market for it.
MS. PIERCE answered that she is a geologist; companies do very
different things and it's hard to judge.
She explained that the Mesozoic Sandstone AU is also
conventional and has more than 100 well penetrations, but few
reach the top of the Talkeetna formation. So, the stratigraphic
potential is below where most of the well penetrations have
reached. M-28 AU has one oil accumulation with cumulative
production of 300,000 barrels. She said there are oil seeps
onshore in this area and that indicates that there is other oil
potential. The source of the oil and thermogenic gas is from the
Middle Jurassic Tuxedni group, which has migrated up from the
depths. They also think there are potential and undiscovered
traps probably both structural and stratigraphic.
3:56:46 PM
SENATOR WIELECHOWSKI asked how deep Mesozoic is versus Tertiary
and how deep jack-up rigs get versus what typical rigs get in
Cook Inlet.
MS. PIERCE replied the Tertiary is about 25,000 ft. thick; the
Jurassic and Cretaceous is another 30,000 ft. thick.
REPRESENTATIVE SEATON asked her to define the difference between
structural and stratigraphic.
MS. PIERCE replied that stratigraphic and structural traps are
both conventional resources. So, if you had organic material at
depth that has been heated to sufficient temperatures to form
oil and/or gas, and because oil and gas is buoyant and if it can
move out of the source rock, it will and travel up through the
system until it hits an impermeable layer where it forms into
the pores as either structural or stratigraphic traps. The
structural trap is where the rocks have been flexed; so it has a
structure within like an anticline that has moved up in the
system and hit an impermeable layer, like a shale or a clay, and
fills the pore spaces (in a sandstone, for instance) in the
structural trap. A stratigraphic trap, on the other hand, is
something where a fault with two different rock types placed
upon each other that has formed an impermeable layer. The
structural traps are the ones that have been discovered and
produced in the Cook Inlet; none of the stratigraphic traps have
been explored.
SENATOR WIELECHOWSKI asked if one particular kind of formation
tends to hold more oil and gas.
MS. PIERCE replied the Tertiary Sandstone.
SENATOR WIELECHOWSKI asked if the structural ones tend to hold
more oil and gas versus the ones that haven't been explored.
MS. PIERCE replied that there has been no production from the
stratigraphic traps. All the gas and oil in Cook Inlet has been
produced from the structural traps.
SENATOR WIELECHOWSKI asked traditionally do the stratigraphic
traps have more oil or gas.
4:01:10 PM
MS. PIERCE replied that it depends on where you are in the
geology of a specific area and she didn't know about the Cook
Inlet because none of them are produced. Tuxedni-Naknek
Continuous Gas has no known accumulations. It's entirely
unexplored with no known well penetrations.
She recapped that the Mesozoic layer is mostly unexplored and is
a slightly small area geographically. The results from the
Mesozoic Sandstone oil and gas AU show a mean of more than 200
million barrels of oil and about 1.5 tcf of undiscovered gas.
REPRESENTATIVE SEATON asked if this indicates that M-28 AU and
four wells down in the lower left are the only penetrations.
MS. PIERCE answered the M-28 AU is the one that has produced
oil, but it is pretty unexplored. The Tuxedni-Naknek continuous
gas structural unit is a very small deep. It is hypothetical,
but bears looking at for the future. It has no known
accumulations, but it is thermogenic gas and there may be low
permeability sandstones at that depth that can be produced as
evidenced elsewhere.
The very large Cook Inlet Coalbed AU is also unconventional and
has no discovered commercial accumulations, but about 25 wells
have been drilled in search of coalbed gas by Wasilla. These are
microbial gas sources. Because there are no commercial
accumulations, they used the Powder River basin as an analogue;
it has very thick coals and is highly commercial. An area deeper
that 6,000 ft. was excluded, but has technically recoverable
potential. It is mostly unexplored, but they allocated it 4.6
tcf of gas.
In a nutshell, Ms. Pierce said they have recently completed this
assessment of volumes of undiscovered but technically
recoverable resource for both conventional and continuous gas
accumulations for the onshore state waters. The geology based
assessment is a probabilistic quantitative based on USGS and
State of Alaska DGGS and DOG data; it indicates 600 million
barrels of oil and 19 tcf of gas.
4:04:19 PM
SENATOR WIELECHOWSKI asked for a more detailed analysis of where
a find is.
MS. PIERCE replied that their results estimate for an entire
region. They can allocate certain parcels of land, but their
data simply don't support saying there is X tcf or X billion
barrels in a small parcel. These are not assessments but
allocations based upon their expert judgment of the geology of
the area from the assessment.
SENATOR WIELECHOWSKI said there must be some raw data somewhere
that would show traps.
MS. PIERCE replied where they have seismic data they have more
detailed information, but a lot of areas don't have the seismic
data.
SENATOR WIELECHOWSKI asked if their data is public and if it is
shared with the State DNR or the companies.
MS. PIERCE replied it's a combination. Companies often share
proprietary data with them, but they don't share that data;
rather they share the results of their assessment. USGS also
buys proprietary databases of production both in the U.S. as
well as globally. They look at what is being produced in areas
with similar geology and do field work themselves. They put
together geologic models to say if there is organic material
even in the area and if so, was it robust enough organic
material and what kind is it - and then build a burial history
curve for each basin while guessing if it got hot enough to form
oil and gas and if the timing was right.
4:07:52 PM
SENATOR STEDMAN said there is oil development off of coastal
B.C. and that Alaska has a lot of coastline running up to Cook
Inlet and asked if she knew of any oil in between.
MS. PIERCE replied that is a good question, but she hadn't
looked at that.
CO-CHAIR WAGONER asked what she meant. There has been some
drilling in the Gulf of Alaska.
MS. PIERCE replied that USGS hadn't assessed it.
CO-CHAIR WAGONER asked if it been assessed by USGS prior to the
drilling off of Yakutat.
MS. PIERCE replied that she would have to go back and look.
4:09:34 PM
CO-CHAIR PASKVAN asked where the concept of economic viability
comes in.
MS. PIERCE replied that is somebody's next study.
CO-CHAIR PASKVAN asked if one combines her 5 tcf with the 1.8
tcf of known reserves, would that mean a 95 percent likelihood
of 6.8 tcf. He was comparing that number to the 7.8 tcf of
production that has already occurred and was trying to determine
magnitudes of probabilities for the next 50 years. Is that a
reasonable way to look at that?
MS. PIERCE replied yes and that they have 95 percent confidence
that 5 tcf is there. There is real potential.
4:12:29 PM
SENATOR WIELECHOWSKI asked if the 5 tcf is on top of the 1.8 tcf
of known reserves.
MS. PIERCE replied yes. The USGS does not include reserves in
its estimates, but they do assess potential reserves.
CO-CHAIR WAGONER said until someone goes out there and proves
it's an economical reserve, they can't count on anything.
MS. PIERCE replied "absolutely correct."
SENATOR WIELECHOWSKI asked if an oil company could get detailed
information from USGS on where they believe those traps and
structural formation are.
MS. PIERCE answered it depends on where the data came from and
who it belongs to and what their agreement is.
4:15:17 PM
CO-CHAIR PASKVAN thanked her for traveling to Juneau and giving
the presentation. Finding no further business to come before the
committee, he adjourned the meeting at 4:15 PM.
| Document Name | Date/Time | Subjects |
|---|---|---|
| SRES_CI Activ Update DNR Gas Studies[1].pdf |
SRES 8/16/2011 9:00:00 AM |
|
| Cook Inlet 16 August 2011 AK Senate Energy Comm Briefing.pdf |
SRES 8/16/2011 9:00:00 AM |
|
| TransCanada_SRESCommitteeAug 16 2011FINAL.pdf |
SRES 8/16/2011 9:00:00 AM |