Legislature(2009 - 2010)Anch LIO Rm 220
06/05/2009 01:00 PM Senate RESOURCES
| Audio | Topic |
|---|---|
| Start | |
| Incentivizing Cook Inlet Natural Gas | |
| Chevron Alaska - John Zager, Alaska Assets Manager | |
| Concophillips Alaska - Dan Clark, Cook Inlet Manager | |
| Marathon Oil Company - Carri Lockhard, Alaska Production Manager | |
| Aurora Gas, Llc - Bruce Webb | |
| Armstrong Oil and Gas - Ed Kerr, Vice President, Land and Business Development | |
| Escopeta Oil Company - Bruce Webb, Spoke for Danny Davis, Consultant | |
| Dnr/office of the Governor - Kevin Banks, Acting Director, Division of Oil and Gas | |
| Regularoy Commission of Alaska (rca) - Chairman Bob Pickett - Gas Pricing | |
| Gas Storage & Other Infrastructure Issues - Mark Slaughter, Enstar's Manager of Gas Supply; Ethan Schutt, Senior Vice President, Ciri Land & Legal Affairs; Kevin Banks, Dnr; Rca Chairman Bob Pickett; Suzanne Gibson, Chugach | |
| Access Issues - Kenai National Wildlife Refuge, Robin West, Refuge Manager, and Ciri Ethan Schutt, Senior Vice President, Land & Legal Affairs | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| + | TELECONFERENCED | ||
ALASKA STATE LEGISLATURE
SENATE RESOURCES STANDING COMMITTEE
ANCHORAGE LIO
June 5, 2009
1:06 p.m.
MEMBERS PRESENT
Senator Lesil McGuire, Co-Chair
Senator Bill Wielechowski, Co-Chair
Senator Charlie Huggins, Vice Chair
Senator Bert Stedman
Senator Hollis French
Senator Gary Stevens
Senator Thomas Wagoner
MEMBERS ABSENT
All members present
OTHER LEGISLATORS PRESENT
Senator Dennis Egan
Senator Gene Therriault
Senator Johnny Ellis
Representative Paul Seaton - via teleconference
Representative Mark Neuman
Representative Mike Chenault
Representative Pete Peterson
Representative Chris Tuck
Representative Les Gara
Representative Craig Johnson
Representative Wes Keller
Representative Jay Ramras
COMMITTEE CALENDAR
Incentivizing Cook Inlet Natural Gas
-Chevron Alaska - John Zager, Alaska Assets Manager
-ConcoPhillips Alaska - Dan Clark, Cook Inlet Manager
-Marathon Oil Company - Carri Lockhard, Alaska Production
Manager
-Aurora Gas, LLC - Bruce Webb
-Armstrong Oil and Gas - Ed Kerr, Vice President, Land and
Business Development
-Escopeta Oil Company - Bruce Webb
-DNR/Office of the Governor - Kevin Banks, Acting Director,
Division of Oil and Gas
-Regulatory Commission of Alaska (RCA) - Chairman Bob Pickett -
Gas Pricing
-Gas Storage & Other Infrastructure Issues - Mark Slaughter,
Enstar's Manager of Gas Supply; Ethan Schutt, Senior Vice
President, CIRI Land & Legal Affairs; Kevin Banks, Department of
Natural Resources (DNR); Bob Pickett, Chairman, RCA; and Suzanne
Gibson, Chugach Electric Association
-Access Issues - Robin West, Refuge Manager, Kenai National
Wildlife Refuge - Ethan Schutt, Senior Vice President, Land &
Legal Affairs, CIRI
PREVIOUS COMMITTEE ACTION
No Previous Action to Report
WITNESS REGISTER
JOHN ZAGER, General Manager
Chevron Alaska
POSITION STATEMENT: Commented on Cook Inlet natural gas
development issues.
DAN CLARK, Cook Inlet Assets Manager
ConocoPhillips Alaska
POSITION STATEMENT: Commented on Cook Inlet natural gas
development issues.
CARRI LOCKHARD, Production Manager
Alaska Operations
Marathon Oil
POSITION STATEMENT: Commented on Cook Inlet natural gas
development issues.
BRUCE WEBB, Manager
Land and Regulatory Affairs
Aurora Gas, LLC.
POSITION STATEMENT: Commented on Cook Inlet natural gas
development issues.
ED KERR, Vice President
Land and Business Development
Armstrong Cook Inlet
Subsidiary of Armstrong Oil and Gas
POSITION STATEMENT: Commented on Cook Inlet natural gas
development issues.
BRUCE WEBB, Manager
Land and Regulatory Affairs
Aurora Gas
POSITION STATEMENT: Commented on Cook Inlet natural gas
development issues.
KEVIN BANKS, Acting Director
Division of Oil and Gas
Department of Natural Resources (DNR)
POSITION STATEMENT: Commented on Cook Inlet natural gas
development issues.
JOE BALASH, Intergovernmental Coordinator
Office of the Governor
POSITION STATEMENT: Commented on Cook Inlet natural gas
development issues.
BOB PICKETT, Chairman
Regulatory Commission of Alaska (RCA)
POSITION STATEMENT: Highlighted the statutory role of the RCA
with natural gas development.
MARK SLAUGHTER, Gas Supply Manager
Enstar Natural Gas Company
Representing Enstar, a division of Semco, and
The Alaska Pipeline Company, a wholly-owned subsidiary of Semco
POSITION STATEMENT: Commented on Cook Inlet natural gas
development issues.
SUZANNE GIBSON, Director
Energy Resources
Chugach Electric Association (CEA)
POSITION STATEMENT: Commented on Cook Inlet natural gas
development issues.
ETHAN SCHUTT, Senior Vice President
Land and Energy Development
Cook Inlet Regional Inc. (CIRI)
POSITION STATEMENT: Commented on Cook Inlet natural gas
development issues.
ROBIN WEST, Refuge Manager
Kenai National Wildlife Refuge
POSITION STATEMENT: Commented on Cook Inlet natural gas
development issues.
KIM CUNNINGHAM, Director
Land and Resources
Cook Inlet Regional Inc. (CIRI)
POSITION STATEMENT: Commented on Cook Inlet natural gas
development issues.
ACTION NARRATIVE
1:06:46 PM
CO-CHAIR WIELECHOWSKI called the Senate Resources Standing
Committee meeting to order at 1:06 p.m. Present at the call to
order were Senators McGuire, French, Huggins and Wagoner,
Wielechowski.
1:07:44 PM
^Incentivizing Cook Inlet Natural Gas
Incentivizing Cook Inlet Natural Gas
CO-CHAIR WIELECHOWSKI said the purpose of today's meeting was to
identify and discuss any potential barriers to additional
investment by natural gas producers in Cook Inlet. Put another
way:
What can the state do to encourage or facilitate
additional investment? Cook Inlet production has
declined considerably. In the last three years it has
declined by more than 50 bcf. Current demand is about
140 bcf; so the decline is significant. By 2012,
annualized instate demand will exceed supply from
existing wells. This assumes no export of Cook Inlet
gas. It also does not consider the fact the peak
demand could exceed supply as early as this coming
winter. By 2019, annualized instate demand will exceed
supply from development of probable reserves in the
region.
In other words, we have three years before we have a
supply problem if we looked at production from
existing wells only. We have an additional seven years
if we assume probable reserves will be developed;
additional exploration could give us more years. But
time is of the essence. Because of its proximity to
Anchorage and other Railbelt population centers, Cook
Inlet gas could be the least expensive energy source
available to more than half the state's population.
CO-CHAIR WIELECHOWSKI said they would hear from six Cook Inlet
explorers and producers, the Department of Natural Resources
(DNR), the Governor's Office, the Regulatory Commission of
Alaska (RCA), Enstar, Chugach Electric, Cook Inlet Regional
Incorporation (CIRI), and the Kenai National Wildlife Refuge.
^Chevron Alaska - John Zager, Alaska Assets Manager
Chevron Alaska - John Zager, Alaska Assets Manager
1:09:26 PM
JOHN ZAGER, General Manager, Chevron Alaska, said that more
production and deliverability is needed to meet peak needs, and
made the following points:
· There are no quick fixes to annual production in Cook
Inlet, but peak deliverability can be addressed in two or
three years.
· Peak deliverability can potentially be increased more
quickly through new storage within two-three years
1:11:50 PM
MR. ZAGER said the Cook Inlet basin has infrastructure,
resources, and a market, but incentives are needed to attract
sufficient capital to develop them. However, the remaining
resources are not similar to the current ones. Large existing
fields are declining and new fields will be more difficult to
develop because the reservoirs are smaller and other
infrastructure will be needed.
So, Mr. Zager said, the risk-reward appears to be out of
balance. He summarized that the Inlet has significant geologic
risk because the new reservoirs are smaller and discontinuous
and that makes them more difficult to predict; the costs are
high in terms of the reservoirs being in remote locations along
with all the other higher costs from developing in Alaska - like
wages and vendors.
Market risks exist as well - one is that demand is cyclical,
which means you need excess capacity to serve summer peaks and -
for new entrants especially - they have an extra problem of
paying for exploration without having a contract to sell the gas
and at the same time of not being able to get a contract without
having any proven reserves to sell.
1:14:00 PM
There is also regulatory risk in the form of once you agree with
a party it has to be approved by the Regulatory Commission of
Alaska, which takes more time and significant money.
1:14:25 PM
MR. ZAGER said the state does not control a few things like the
geology, the high cost environment, and the attractiveness of
outside investments.
1:15:15 PM
SENATOR WAGONER asked how a bullet line coming down from the
North Slope (NS) into the same market in Cook Inlet would affect
current exploration and production of gas there.
MR. ZAGER answered that in general it would suppress exploration
in the Cook Inlet. However, if you had an existing contract in
Cook Inlet and didn't have any NS gas, you might choose to
continue to explore in the Inlet to fulfill your contract from
local markets. But new entrants would have another significant
obstacle to exploration in Alaska.
1:17:53 PM
MR. ZAGER said to encourage more production and deliverability
the state needs to promote or at least allow a competitive gas
price in Alaska. Nobody shows up at Cook Inlet gas sales now,
but they used to. The price must be sufficient to attract
applicants no matter where in Alaska it comes from.
He said that today Union Oil, a subsidiary of Chevron, has a
2001 contract with Enstar, the last gas contract approved by the
RCA delivering any gas to customers. It was controversial
because it tied their price to the three-year rolling Henry Hub
price, the first time it had been pegged to an outside number.
He thought it a very successful contract because they originally
committed to spending $10 million in exploration, but they spent
several hundred million dollars since then - exploring,
developing, putting in pipelines and the first gas storage in
the Cook Inlet - all in preparation to serve that market. So,
today they sell 19.5 bcf/yr. to Enstar and provide approximately
60 percent of their market. They are backing off this level in
the out years, because they don't feel they have sufficient gas.
Storage in all forms should be promoted, Mr. Zager said. All
storage in the Inlet today is below-ground using depleted
natural gas reservoirs. Storage facilities are also owned by
Marathon. Storage investment could be promoted through tax
credits, and he argued that he thought the state got a much
better bang for the buck on storage investments than it did on a
single well, because storage can be there year after year and it
can help move larger volumes of gas from the summer to the
winter and manage the existing peak issues.
1:21:17 PM
CO-CHAIR WIELECHOWSKI asked if he envisioned storing in depleted
wells or building large storage tanks.
MR. ZAGER replied that Chevron would look at underground storage
first because that is where their experience is. Other companies
because of their characteristics, in terms of how much volume
they could ship and how much peaking they could get for a given
volume, might have different solutions. To manage this situation
well they would need to have a portfolio of storage
opportunities going forward.
He suggested treating storage costs like transportation costs
that are deductible for royalty purposes. He said that storage
adds value to gas in moving from summer to winter, but the cost
of preparing that gas for market is not recognized.
Another suggestion he had was to lower costs where possible by
streamlining permitting and expanding the annual access period
to the west side drilling in the State Refuge. He explained that
they have a couple of fields in the Refuge and now they are
limited to drilling only in the coldest months of the winter.
This adds costs and makes it a remote operation similar to a NS
operation.
Another suggestion was to try to remove other barriers - like
encouraging access to public lands for exploration. The current
RCA process is a disincentive and should be streamlined. For a
smaller contract you have to wonder whether if even the cost of
going through the RCA process is justified. Many interveners in
the process are marginally related to the direct issue at hand
and try to use the process for other needs.
1:24:50 PM
Finally, he said the RCA should prioritize security and supply
over price. Over the last couple of years it has tried to get
the best price even at the risk the people may not want to serve
that contract because of the peaking requirements in it.
1:25:33 PM
MR. ZAGER said having a year-round industrial market is
important, because restarting a field would be more difficult
and costly than just diverting the gas that is already in the
line to - the LNG plant, for instance. Production costs would be
higher, too, because a lot of the same fixed overhead costs
would have to be allocated amongst much smaller volumes. With no
summer market then there would be no winter back stopping.
Finally, he explained that a year-round industrial market
encourages investment not only by offering a summer market, but
by providing alignment amongst the working interest owners, many
of which co-own the peak units in the basin. So, if one company
didn't have a market that would make it much harder for the
other companies to go ahead and invest - and stay aligned on
development plans in the field.
1:27:36 PM
MR. ZAGER clarified that Chevron is not exporting LNG, and they
have no ownership of the plant. He strongly advised that
conservation should seriously be promoted by everyone -
especially during peak times!
SENATOR HUGGINS asked what Chevron's storage capacity is and
what they would like to achieve.
MR. ZAGER replied that their capacity is in the 3-5 bcf/annual
volumes, and they haven't studied basin-wide storage because of
their market size.
^ConcoPhillips Alaska - Dan Clark, Cook Inlet Manager
ConcoPhillips Alaska - Dan Clark, Cook Inlet Manager
1:30:12 PM
DAN CLARK, Cook Inlet Assets Manager, ConocoPhillips Alaska,
said he had four main discussion points: a description of
ConocoPhillips assets in Cook Inlet and their Kenai LNG
facility, a highlight of the recent agreement with Chugach
Electric Association, and what they see is the major issue
confronting the Cook Inlet gas developer.
He said that ConocoPhillips has operated in the Cook Inlet for
over 40 years and has three assets: the on-shore Beluga River
unit, the off-shore north Cook Inlet unit, and the Kenai LNG
plant. Between the Beluga River and the north Cook Inlet unit
they operate approximately 180-190 mcf/day of natural gas
production. It has invested almost $100 billion/gross throughout
the life of these three assets, and has played a significant
role in developing and maintaining those gas supplies and a
market outlet in the Cook Inlet for decades. They are currently
in the process of executing development programs in both fields.
During 2008-09 they anticipate investing over $150 million/gross
in six new wells plus an additional major work-over of another
one. ConocoPhillips does not hold any prospective exploration
acreage in the Cook Inlet, and their future developments are
finite and in the two fields; so the extent of the future
development depends on the success of their current work
program.
MR. CLARK stated that the Kenai LNG plant has played a vital
role in providing a market outlet for gas as well as providing
significant employment opportunities and revenue to the state.
Additionally, the ability to divert volumes from the plant into
the local market in order to meet peak demand during times of
extreme cold temperatures has been very beneficial to the
Southcentral Alaska gas market. ConocoPhillips and Marathon, the
joint owners of the LNG plant, have a federal license to export
LNG through March 2011.
1:33:21 PM
Pursuing another extension of their export license depends on
the result of their ongoing development program, the
deliverability from other fields in the Inlet, and the level of
support from the various stakeholders. ConocoPhillips is
currently in the process of evaluating the performance of their
ongoing development program dependent on those results and
considering the other factors he just mentioned. They will
decide in consultation with Marathon whether to pursue another
export license extension or not.
MR. CLARK said with respect to local utility demand, they have
recently signed a seven-year 68-bcf gas sales agreement with
Chugach Electric that has been submitted to the RCA for
approval. It will provide a substantial portion of Chugach's
unmet needs going forward. The contract provides a fair
compromise on the key contractual terms and they hope for prompt
approval. With respect to the future in the Cook Inlet,
ConocoPhillips will continue to produce natural gas to honor
their commitments to the local market.
The major issue that confronts the Cook Inlet gas developer is a
limited amount of room to place gas into the market, he stated.
Furthermore the local gas market is relatively small and highly
cyclical. The combined local demand is approximately 85 bcf/year
or an average of 230 mmcf/day for the entire year. A huge swing
in demand happens between winter and summer primarily due to
variations in required space heating. A peak day demand could be
upwards of 450 mmcf/day and the lowest about 100 mmcf/day, a
significant variance.
1:35:32 PM
If wells flow only seasonally, they are at risk of water
encroachment and possible loss of producability. Such negative
operational impacts will lead to less supply and deliverability
being available to the market. So, from a producer's perspective
it is very important to have assurance that gas will be able to
flow into the market at stabilized flow-rates from the wells.
This provides some economic predictability and allows the
possibility that both rate and reserves can be maximized.
MR. CLARK observed that the Cook Inlet needs more gas storage to
levelize production, and anything that can be done to increase
the overall demand in the market such as continued operation of
the LNG plant and/or the reopening of the Agrium facility would
be very helpful in creating a stable market into which producers
could flow gas consistently. ConocoPhillips feels that this
issue must be adequately addressed in order for additional
deliverability to be developed.
1:36:55 PM
SENATOR FRENCH asked what storage ConocoPhillips has in place
now.
MR. CLARK answered that the only storage they have is at the LNG
plant and they don't have any underground storage.
SENATOR FRENCH asked if their focus is on existing
ConocoPhillips assets or were they exploring.
MR. CLARK replied that they are focused on existing assets.
SENATOR FRENCH asked how many wells they will drill over the
next three years.
MR. CLARK answered depending on the results of this phase of
development, they will go forward.
SENATOR FRENCH asked how ConocoPhillips will report those
results.
MR. CLARK replied that they have conversations with the DNR as
part of the annual plans of development (POD) approval process.
SENATOR FRENCH asked if they are drilling year-round.
MR. CLARK answered that drilling is dependent on the location.
At Beluga River it has been seasonal in the summer when they can
get access; at the north Cook Inlet unit they drill through the
winter.
SENATOR FRENCH asked for any other good news.
MR. CLARK responded that the drilling rig had just been
"demobed" at the north Cook Inlet unit and those wells were just
brought on line. At Beluga River, last year's well was producing
for a few months, but it had mechanical issues and those are
being worked on right now. So, it's too early to tell.
1:39:36 PM
CO-CHAIR WIELECHOWSKI asked if they have the ability to increase
the amount of gas they export out of their LNG plant.
MR. CLARK replied that their license limits the amount for
export. The plant is currently operating at half-capacity -
about 120 mmcf/day. "So, there is room beyond that for
essentially up to 230 mmcf/day."
CO-CHAIR WIELECHOWSKI asked if ConocoPhillips was even able to
import LNG to solve the short term problem.
MR. CLARK answered yes they could use their marine terminal to
import gas, but they would have to invest in modifying their
facilities to regasify the LNG that came in. "It's definitely
possible."
CO-CHAIR WIELECHOWSKI asked the quality of Cook Inlet gas.
MR. CLARK replied it's dry and clean, and has a high methane
content - not a lot of other heavier components.
^Marathon Oil Company - Carri Lockhard, Alaska Production
Manager
Marathon Oil Company
Carri Lockhard, Alaska Production Manager
1:42:10 PM
CARRI LOCKHARD, Production Manager, Alaska Operations, Marathon
Oil, said the Southcentral Alaska natural gas supply gap has
been recognized for a year. In 2006, the Alaska Oil and Gas
Conservation Commission (AOGCC) and local municipalities
sponsored the Southcentral Alaska Energy Forum at which Science
Applications International Corporation (SAIC) Manager, Charles
Thomas, showed the Department of Energy (DOE) Natural Gas Supply
and Demand chart prepared with data from the 2004 Southcentral
Alaska Natural Gas Study. It predicted that supply would equal
demand on an annual basis by the year 2012. She said the
question is: Do ongoing efforts across the entire value chain
facilitate overall resource developments in energy reliability?
At that same forum Mr. Thomas also concluded that Alaska has
potentially 15 tcf of undiscovered resources in the Cook Inlet,
but large portions of the land are federal and State Wildlife
Refuge and parks; potentially 30-50 percent of the prime
exploration areas have restricted access or are otherwise off
limits. So, she said another question is: Is enough being done
to open up exploration areas to tap these potentially abundant
undiscovered resources? And is history doomed to repeat itself?
At the same forum, Carolyn Dunmire, Dunmire Consulting,
presented a report prepared for the Alaska Natural Gas
Development Authority (ANGDA) that listed both energy supply and
demand alternatives for the Cook Inlet. This leads to the
question: Is enough being done to introduce other energy
alternatives or to replace or retrofit gas-fired electrical
generation with dual-fuel capabilities to address natural gas
conservation and a demise of an unusually low natural gas
pricing environment.
MS. LOCKHARD stated that in the Lower 48, the FERC-regulated
wellhead prices started in the 1930s because of concerns
regarding monopolistic tendencies of interstate gas pipelines.
It set artificially low price ceilings for natural gas which
resulted in strong demand surging. Consumers received good
value, but at a cost to producers that received little incentive
to invest capital for exploration and development of new
reserves. Gas shortages resulted in 1976-77 forcing many public
schools and factories in the Midwest to close. Due to these
negative consequences, wellhead gas prices were fully
deregulated in 1989.
1:45:14 PM
So, another question is: Should the role of regulation be to
help insure long-term energy security, supply to consumers, or
to simply focus on gas price?
She said their region is facing a future supply gap, but an even
more immediate issue is the Cook Inlet's challenge to meet
contractual daily peak demand requirements for the utilities
from natural gas fields that were primarily discovered in the
1960s. Although these gaps in supply and deliverability have
been discussed over recent years, little has been accomplished
that remedies the pending situation. A significant effort now is
being focused on the apparent larger term solution of bringing
NS gas into Southcentral Alaska. He stated:
However, if they do not fill the immediate and short
term supply and deliverability gap, it is Marathon's
view that the decision must be made now and plans
implemented that will address the short term and
medium term realities. We believe that all
stakeholders should recognize and accept key
ingredients and compromise in efficient, effective and
competitive natural gas markets, namely - with no
intent to prioritize - access to resource, access to
market and the correct pricing signals that allow new
sources of gas supply to be explored and developed.
Gas storage should be developed as required including
proprietary and third party storage.
MS. LOCKHARD said it is important to point out that demand,
conservation and access to market are not mutually exclusive.
Gas exploration and drilling in Cook Inlet is a very high cost
proposition. There is room for small funded producers; they play
an important role in meeting the overall demand, but it is
unlikely they alone can help meet the needs of Cook Inlet. The
local Cook Inlet market is relatively small and by itself it is
unlikely to be sustainable.
"If a significant natural gas discovery were to be made today,
the local Cook Inlet market simply could not support the
economic development of the resource," she said. Additional
demand would be required. Without having a large industrial
consumer acting as the base tenant, the high deliverability
swings and the cost of gas to the local utilities will increase
dramatically. She said actions should be taken to ensure that
new exploration, drilling and production activity takes place in
Cook Inlet. The state should provide the proper fiscal, legal
and economic incentive to insure a natural gas supply to meet
the needs of consumers in Southcentral Alaska.
1:48:44 PM
To insure energy reliability from the supply side, she said,
Marathon believes that Cook Inlet needs new investment, not only
in new production projects, but also gas storage peaking
facilities, transmission infrastructure and utility redundancy
projects. Companies need market access, effective and fair
regulation, fiscal certainty, available surface access and
reasonable returns that enable projects to compete at the
corporate level for finite funding.
In this regard she offered the following:
First, fiscal incentives and predictability are
necessary to compensate for project risk and high cost
of exploration and development.
Second, state statue should provide clarity on
regulation jurisdiction, and procedures should be
well-defined. Current sales to regulated utilities are
subject to unduly burdensome procedures. These
procedures may be well-intended, but in our view have
been subjected to inconsistent regulatory guidance and
have been unduly influenced by a number of provincial
commercial interveners with narrow self-serving focus.
This eliminates any potential for reward for risk-
taking, and as a result places the public at risk for
supply reliability. Undue regulatory demands cost
companies and consumers, alike, millions of dollars in
recent years without facilitating long-term natural
gas reliability.
Three, companies large and small must have access to
market - market-driven pricing entrance and
transparency. Contrary to prior decades, the current
environment in Cook Inlet is no longer conducive to
long-term full deliverability contracts. Projects in
Alaska must compete with projects world-wide for
finite funding on an annual basis. To be clear, this
means companies generally invest in projects that
provide the best economic returns in this competitive
environment and economic projects are left unfunded in
today's environment.
Four, winter peak deliverability requirements must be
fully valued to facilitate storage development and
other peaking mechanisms. Additional storage projects
must be developed to provide system flexibility and
efficiency in meeting seasonal and [indisc.] peaking
demands. The best way to make this happen is to have
independent storage development where real value or
costs can be recognized in the market place and in the
regulatory process. This all comes out of costs
regardless of whether the deliverability is fully
utilized or not. Unfortunately, Marathon's experience
in the APL-5 docket demonstrated that the commission
was unable to appropriately recognize the value of
this service.
Five, the Cook Inlet has limited surface assets. Given
the amount of federal acreage and the ongoing
uncertainty with the critical habitat designation as
part of the Endangered Species List, access to federal
acreage to explore for new hydro-carbon deposits is an
option not only to fill the shorter-term supply gap,
but also should used as comparator metric for longer
term options such as gas from the North Slope. So, in
essence, it is an access issue, and without the land,
we can't even assess for the resource potential as
defined by the DOE and USGS report.
In terms of natural gas pricing, there is a wide
divergence of opinion. Assuming that the other market
essentials are in place, it is intuitive that if
natural gas prices are too low over a period of time,
the result will be reduced supply availability. If
prices are high over a period of time - for example,
if prices are higher than the next best alternative -
that will result in further demand destruction. It is
critical that we have an environment where free market
forces are embraced.
Insuring energy reliability is also a function of
demand efficiency. The state must provide proper
incentives and regulatory oversight to encourage
energy efficiency and conservation, such as at power
plant efficiency projects, energy diversification and
consumer conservation. Consumer conservation isn't
highlighted in Mr. Zager's talk, and that is something
that has pretty immediate response, more so than an
exploration project. So, I believe conservation plays
an important role in this, certainly during peak
winter demand.
In the light of the current situation, we continue to
recommend that the total local utilities install dual
firing capabilities at the proposed generation
projects at the very least to meet peak demand
requirements.
In closing, decades of abundant supplies-driven
behaviors created expectations, and perhaps influenced
the ability to adapt. Maintaining the status-quo will
have unintended and undesirable consequences in the
not-too-distant future. Peak deliverability is
declining and industrial demand continues to be
destroyed. Stabilizing and maintaining the supply
reliability will not be possible without vision,
commitment, cooperation, collaboration, process
efficiencies and appropriate action by all. It is not
an obligation by one party, nor can one party solve
the problem of shared demand and supply
responsibility. Together we must establish the proper
regulatory framework and incentives to attract new
investment for exploration, development and production
of natural gas. Simultaneously, we must provide proper
incentives and regulatory oversight to drive energy
efficiency and conservation.
We at Marathon have a long-standing commitment to be a
good partner with industry, government, regulators and
community to help find and implement appropriate
solutions to challenge we all face. We have been a
major provider of energy to the local market for 55
years and we are the largest natural gas producer in
the Cook Inlet. We have always reliably met our
contractual obligations to our customers in Cook Inlet
and we will continue to do so. The corollary of this
is that we have not and will not take on supply
obligations which we cannot meet.
1:54:42 PM
SENATOR WAGONER said they negotiated two contracts in the last
7-8 years that had been disallowed by the RCA, and he asked what
the terms of the first contract were and what the gas would have
been sold for.
MS. LOCKHARD replied that she didn't have the exact terms, but
it was a 60 bcf contract over a ten-year period which would have
met all of Enstar's unmet needs at that time. That was based on
a Henry Hub price, a precedent the Chevron contract set a couple
of years earlier. That contract was declined because of the ties
to Henry Hub, because at that time the RCA felt that was not
appropriate pricing.
They went back to the Commission with a 38 bcf contract for five
years, and this time it had a different pricing mechanism; but
again it was disapproved, so that left a significant gap for
Enstar. Since then, they are working under an 8 bcf two-year
contract and [indisc.] pricing that didn't need Commission
approval. She said a two-year contract makes it difficult to
engage in exploration because it doesn't provide the proper line
of sight for the security of being able to get rid of the gas.
In addition, they have nothing to show after five years of
negotiation for their efforts, which has literally cost them
millions. It has taken a toll on their plans as far as
development goes.
1:56:44 PM
SENATOR WAGONER stated that ConocoPhillips testified earlier
that it cost them an average of $45 million to drill an
exploratory well, and he asked if it was the same for Marathon.
MS. LOCKHARD replied that their costs are different as they are
with many companies. It depends on what fields you are in -
offshore, onshore, and what type of completions you need to
install. They have invested nearly a half-billion dollars over
the past six years in Cook Inlet for about 60 wells. So, it's
$8-10 million. It's not just about wells costs, but
infrastructure - compression and maintenance.
SENATOR FRENCH asked if they are still going to drill four wells
this year.
MS. LOCKHARD replied yes; that is an average of 40-60 percent
reduction in number of wells they typically drill in a year.
SENATOR FRENCH said one of the drawbacks of this format is that
the RCA doesn't get to respond to some of the things she said
now, but they would get a chance later. One of the things he
thought they would say about setting the contract prices is
that they have recommended to the legislature that it explore
more deeply what Marathon's actual cost of production is, since
it is sort of one of the hidden elements in Cook Inlet gas
pricing.
1:59:01 PM
MS. LOCKHARD replied that the value of gas is not based on
costs, but on the next best alternative, and "That's where the
focus needs to be." She is not convinced that any business would
open their books to make direct comparisons to the competitors.
Business just doesn't work that way.
Her portfolio is very different from Chevron's and
ConocoPhillips'. Ninety percent of her gas is from wells drilled
over the past decade in a very high cost environment. The focus
needs to be on value and not on costs, because it doesn't work
that way. What she gets from her projects have to compete with
those in equatorial Ghana, and Texas and the Rockies.
SENATOR FRENCH asked if he was to compare Cook Inlet natural gas
to hydro power developed by the Chakachamna Dam, how could he
know she wasn't setting natural gas prices a penny above or
below that without knowing what it costs to get the gas out of
the ground.
MS. LOCKHARD replied she had no idea what hydro or other
alternatives cost, but she said that reports are out there that
provide general data to the industries.
CO-CHAIR WIELECHOWSKI asked if it's just not affordable to drill
for gas in Cook Inlet or does it have limited gas resource.
MS. LOCKHARD replied that Cook Inlet has opportunities, no
doubt, but they are limited because of access. She explained
that their supply has been from wells drilled in the 50s and 60s
and it is a by-product of oil production.
CO-CHAIR WIELECHOWSKI asked what kind of storage is needed, and
if they have storage to lease or sell to Enstar.
MS. LOCKHARD replied that they have developed storage for their
proprietary interest so they could execute on their contracts.
It would be very difficult to open it up to a third party due to
existing commercial arrangements. Their portfolio has other
opportunities that are likely storage candidates. All options
should be on the table both above and below ground. But this is
not a producer issue; it is a utility issue to service customers
unless Marathon agrees to take on more full-requirement
contracts, which would be difficult for them to do.
2:03:24 PM
CO-CHAIR WIELECHOWSKI asked when Marathon decides it is more
profitable to drill somewhere else, and they don't drill on
leases that they own in Cook Inlet, do they give them back to
the state.
MS. LOCKHARD replied that Marathon has no leases with the
exception of one drilling obligation where they will be engaging
in an exploration well at the end of the year if they can get
the final approvals.
CO-CHAIR MCGUIRE asked if Marathon would take advantage of tax
credits for capital investment in storage.
MS. LOCKHARD replied that it would be considered, but she would
have to look at where the opportunities lie.
2:04:38 PM
CO-CHAIR MCGUIRE asked how the tax incentives the state put into
place for Cook Inlet five years ago have worked out and asked if
she would be looking for more of an incentive.
Ms. LOCKHARD answered that five years ago the environment was
very different; now there is more a sense of urgency to engage
in further exploration and development. Some companies have been
able to take advantage of the incentive and have helped Marathon
to successfully get projects through the corporate hurdles in
Ninilchik. Carrying that forward would be very beneficial for
all of them.
2:06:08 PM
CO-CHAIR WIELECHOWSKI asked how having a big enough market for a
big find could be remedied.
MS. LOCKHARD replied that is a good question; the whole overall
market structure has a problem. The regulatory process could be
changed, but she said she would have to do more thinking on it.
Having negotiated contracts with utilities declined by the RCA
is an impediment to having free market choices.
CO-CHAIR MCGUIRE asked if she considered adding another ship for
their LNG facility.
MS. LOCKHARD replied that they had two ships in the past and
just recently went down to one, but it is an ongoing question
with their partners, ConocoPhillips.
CO-CHAIR MCGUIRE asked if she knew that FERC just permitted the
first LNG receiving terminal on the West Coast in a decade - in
Oregon. Some of them just had discussions about how to expand
Alaska's market and know from FERC and DOE that they will not be
approving export licenses out of the country, but she thought
Oregon might be a market for Marathon.
MS. LOCKHARD responded that other legalities would have to be
explored to make that happen, and she leaves that to her
marketing group.
CO-CHAIR WIELECHOWSKI said he was interested in all of their
ideas about how they could streamline the regulatory process or
encourage storage.
^Aurora Gas, LLC - Bruce Webb
Aurora Gas, LLC - Bruce Webb
2:09:25 PM
BRUCE WEBB, Manager, Land and Regulatory Affairs, Aurora Gas,
LLC, said from Aurora's perspective the problem is fairly
simple:
Available gas is decreasing to levels that will fail
to meet demand in the near future and despite the
obvious need for more supply, the investment necessary
to avoid shortages are not being made. By available
supply I mean proven reserves, reserves that have been
drilled and are available to be sold into the market.
This should not be confused with total reserves.
Numerous studies have estimated tremendous amounts of
natural gas that remain in the Cook Inlet. They are
not available until someone invests the money and
takes the risk to drill them. Alaska is reported to
have more oil and gas resources than any other state;
yet we consistently have the lowest operating rig
count in the country.
Two weeks ago the Cook Inlet areawide lease sales
produced one of the most dismal results ever in the
history of such lease sales with bids on only four of
the 815 tracts available, a mere 7,000 of the 4
million acres that were offered. Not one of the
existing operators in the Cook Inlet, including
Aurora, bid on any tracts. In fact, none of the
apparent high bidders had an exploration or production
history at all.
Recent announcements indicate that some companies with
operation plans are planning to significantly reduce
their drilling budgets. We have to ask ourselves why
with such obvious need for more natural gas in Cook
Inlet in a geologic basin with considerable additional
reserves waiting to be explored and developed is no
one buying leases or trying to drill a gas well on
state land. Aurora submits for your consideration the
following reasons:
1. Lack of access to market
2. Lack of adequate financial incentive
3. Lack of access to the resource
Access to the market is limited contractually and
physically. For the entire history of natural gas
production in the Cook Inlet the market has been
dominated by relatively few players, utilities, and
major producers. With the luxury of market and
oversupply, utilities were constantly able to contract
for supply many years in advance for the contracts
that obligated the major producers to meet all of the
utilities requirements. In exchange, the producers
expected to sell all of their gas that the utility
required. These are to so-called 'full-requirement
contracts.'
Full requirement contracts are the two-edged sword.
They provide the utility with the badly needed
security of supply and they provide the producer with
the economic incentive to drill and produce gas.
However, they also close the market to potential
competition thereby setting the stage for future
shortages.
Recent contracting between utilities and major
producers have trended away from full-requirements.
With the contracts currently in place, we are still in
a situation whereby a new company that desires to
drill for gas in the Cook Inlet has no assurance that
they can sell their gas for several years out if they
are successful in finding it. Unlike the Lower 48
states, there is no spot market for gas in the Cook
Inlet. Therefore, we are compounding the geologic risk
of drilling with development and commercial risk.
In addition to the contractual barriers to the market,
there are also physical barriers to the market. The
same network of a utilities and major producers that
control the gas contracts also operate and control the
pipeline infrastructure in Cook Inlet. Their reaction
to the shrinking supply situation in Cook Inlet is to
tighten-down the system with more rules for the
delivery of gas. Aurora believes that tariffs should
protect the integrity of the pipeline and its
reliability of service. However, the rules need to
make sense and not serve to discourage additional new
resources of gas coming into the system. The rules
should not create a playground whereby only a select
few players get to play in it. We need more
flexibility in the system, not less.
The lack of adequate financial incentives can also be
described as price uncertainty. None of us has a
crystal ball that tells us what the prices will be in
the future, but in Alaska the situation is worse
because we can't even agree on an appropriate pricing
mechanism for the gas. This situation must be
resolved. Alaska's Cook Inlet is a high cost
environment and natural gas exploration is a high risk
proposition. The Cook Inlet Basin is competing with
other basins around the country and around the world,
and they compete for a limited amount of investment
dollars. Those dollars will simply go elsewhere if the
basin doesn't yield competitive reserves that provide
the explorer the adequate financial incentives.
2:15:00 PM
Low prices benefit the consumers, but if they are too
low, the benefit only lasts for a short term.
Ultimately they will pay the price associated with the
lack of supply because drilling will cease. The state
has the ability to offer financial incentives to
encourage additional drilling in the Cook Inlet. These
incentives can be structured in a variety of ways, but
they must be clear and easy to administer. All too
often well-intentioned incentives passed by the
legislature are complicated subject to interpretation
and administration by and agency whose primary job is
to protect the state's interests. This makes it very
difficult for the explorer or producer to actually get
those incentives without a fight.
The third case we see for the lack of Cook Inlet
drilling is a lack of access to the resource. Similar
to the access to the market, the lack of access to the
resource also has both contractual and physical
aspects. Contractually the lack of access manifests
itself in the regulatory and permitting process. For
many years the industry has been united and consistent
in its pleas to the state for easier access to lands
for purposes of exploration and development. The
state's permitting process is overly burdensome,
onerous and expensive. It serves only to incent those
seeking to drill wells.
It seems to us that the message from the top levels of
government, that is we are open for business and
drill, baby, drill simply do not get communicated
effectively into the trenches of the few specific
agencies charged with permitting and overseeing oil
and gas exploration and development. Aurora has
experienced several recent unreasonable permitting
snags which have only served to delay and discourage
our desire to drill for natural gas on state lands. In
one case our application to permit a one-acre
temporary gravel pad, which is immediately adjacent to
the existing gravel road known as the Beluga Highway,
and in an areas surrounded by four other producing gas
fields between the Enstar Pipeline and the Chugach
Electric Power lines was denies on the basis that it
would cause an unacceptable impact to the coastal use
and resources resulting in an irreparable level of
damage to the peat bog habitat. This one-acre pad sits
amidst the 270,000 acre state game refuge. Aurora is
now faced with the probability of the leases expiring
and the associated potential gas reserves totaling
approximately 70 bcf going undrilled. Alternatively,
had we had the funding earlier, we could have drilled
the well in the winter time at a significantly higher
cost and subjecting our crews to harsher less safe
work conditions.
In a more pressing example, Aurora is extremely
frustrated with our current efforts to permit the next
well in our exploration development plans at Nikolai
Creek number 11. As a result we are forced to drill
another well on CIRI land and after that well, we may
be forced to stack the rigs until the Division of
Coastal and Ocean Management can complete a 50-day
review process. That review process has not even yet
begun.
While it is probably not appropriate to get too far
into the specifics of this permit application in this
forum, we stand willing to provide you with more
details if you are so interested. Cook Inlet needs new
exploration; we can no longer simply rely on infield
drilling of existing reservoirs to keep up with the
long-term demand. The permitting process must be
streamlined and managed by people who understand the
big picture. Physically the lack of access to the
resource results in a lack of infrastructure and
appropriate access to areas with prior disturbance.
Explorers need roads and bridges and areas adjacent to
existing roads and areas with prior surface
development need to be opened for exploration. Any of
the prospective lands are either difficult and
expensive to reach or burdened by excessive and
unreasonable restrictions.
2:19:40 PM
Aurora's operations are approximately 60 miles from
Anchorage, and we have to barge or fly virtually
everything and everyone in and out. We could give you
specific recommendations about road and bridges, but
that would be selfish and specific to our case. That's
why under reasonable restrictions I sight the
mismanagement of the Susitna Flats State Game Refuge,
specifically in and around the Beluga industrial
development. The general idea I want to leave with you
is that throughout Cook Inlet if there were more roads
and bridges, and less restrictions it would lead to
more drilling and natural gas suppliers.
Aurora Gas is committed to its ongoing efforts to
develop and produce natural gas in the Cook Inlet.
Alaska needs more companies like Aurora Gas and the
state needs to incentivize us and others to continue
this effort.
1. We need contractual access to the market. We need to
know if we are successful in the search for natural
gas that we won't have to wait for years to sell the
gas.
2. Physical access to the market. Pipeline tariffs
should be structured in a manner that does not
provide advantage to existing players and makes it
difficult for new smaller players to deliver gas.
3. Adequate financial incentives. Clear pricing signals
that encourage companies to take the risks
associated for drilling gas.
4. Contractual access to the resource. More flexible
lease terms, a streamlined centralized permitting
process managed by agency personnel that can
adequately waive the need for proper oversight
balanced by the urgency and benefit of promoting
additional drilling instead of discouraging it.
5. Physical access to the resource. New roads and
bridges are ways that oil and gas exploration can be
made more attractive. Access to lands without
unreasonable restrictions are a must.
6. Gas storage. We note that gas storage is on the
committee's agenda this afternoon. We wanted to let
you know that Aurora Gas is actively pursuing the
storage project at our Nikolai Creek unit on the
west side of the Cook Inlet. Preliminary technical
review by our consultants has revealed that we do,
in fact, have a viable reservoir conducive to gas
storage operations. We plan to present a technical
presentation of the project to all interested
parties in the near future and assess the interest
level of the third parties that may be interested in
contracting for the storage services. Aurora does
not yet have a gas storage lease with the State of
Alaska that would give us the right to move forward
with the project, but we are working with the
Department of Natural Resources to obtain such lease
terms comparable to those extended to other
producers in the Cook Inlet that have developed
storage units.
The extent to which our project may or may not be
subject to regulation by the RCA is being evaluated
and we certainly intend to keep them informed on our
progress along the way.
^Armstrong Oil and Gas - Ed Kerr, Vice President, Land and
Business Development
Armstrong Oil and Gas - Ed Kerr, Vice President, Land and
Business Development
2:24:04 PM
ED KERR, Vice President, Land and Business Development,
Armstrong Cook Inlet, a subsidiary of Armstrong Oil and Gas,
said this issue is the highest priority for the RCA, Chugach
Electric, Enstar, the Legislature and so many more.
MR. KERR said that while he was going to sound redundant, he
felt it was important for legislators to get a true cross-
section of outlooks from various entities with differing
perspectives. "In order to be successful in increasing
production within the Cook Inlet I believe it will take a
concerted effort from multiple disciplines within various
companies and agencies."
He listed the following key parameters or issues that are
stumbling blocks to increasing production in the Cook Inlet:
1. The reality that recoverable reserves on a per well basis
have been consistently shrinking over the past 50 years. It
is difficult to quantify the severity and impact of this
decline until it has already occurred.
As evidence of this they used an IHS data set to make certain
observations. His slide showed that during the 1960s the peak
four-year production for gas wells drilled resulted in a gas
recovery of 11.9 bcf/per well. During the 1980s the peak gas
production for all wells drilled resulted in a gas recovery
during the same period of 5.1 bcf/per well. During the timeframe
of 2000-2008 the peak four-year gas production was 3.2 bcf/per
well. The conclusion they reached is that it is taking more
wells to obtain fewer reserves. Obviously, more wells require
more capital to explore, find and produce gas.
MR. KERR stated that Cook Inlet has some of the best gas wells
in the world, but they are now very old and declining rapidly.
New gas wells are much smaller, and as such, more wells are
needed to achieve substantive increases in production.
2:27:31 PM
2. Next issue they identified is there simply are not enough
companies looking for gas in Cook Inlet. Ninety eight
percent of gas within the Cook Inlet is produced from wells
operated by just three companies. This gives such a high
concentration risk for so much of the reserve base. He
hastened to add that Chevron/Texaco, Marathon and
ConocoPhillips have done an excellent job there; they
represent the best of the best. The fact that they are not
drilling more wells is purely a function of this area not
providing them with the rate of return that is competitive
with their other opportunities for capital investment
across the world.
2:28:27 PM
3. A lack of wells being drilled in Cook Inlet - 1,298 wells
have been drilled. Their opinion is that Cook Inlet is a
vastly underexplored province and with good signs that
there is a tremendous amount of gas yet to be found in the
area. In 2007 according to IHS a total of 14 wells were
drilled by three operators in Cook Inlet. Conversely two
similar basins within the Lower 48 show a much higher level
of activity. In the San Juan Basin a total of 45,884 wells
have been drilled to date; and 999 wells were drilled in
2007 by 56 different operators. In the Big Horn Basin a
total of 14,080 have been drilled; 107 wells were drilled
in 2007 by 17 different operators.
Finally he said the combination of higher costs due to a lower
number of wells being drilled, smaller reserve size on a per
well basis, wide swings in production due to realities of
Alaska's climate and challenging prices dictate that something
new must be done to avert the decline in gas production.
2:30:17 PM
MR. KERR said their opinion is that the solution is drilling
more wells, especially exploration wells. They believe it can
only be achieved by the following:
1. Increasing the price paid for the commodity. Ultimately all
oil companies are driven by economics, especially
independents who make up over 90 percent of the gas wells
being drilled in the U.S. today. Oil companies must be
incentivized to take the risk of exploring for and
producing natural gas in the Cook Inlet.
2. Considering additional tax incentives - although he thought
the State of Alaska has already done a good job of creating
a favorable tax environment for the Cook Inlet - but it is
a way of enhancing the economics for companies and that
ultimately drives what will get wells drilled.
3. Streamlining approval of gas contracts. The RCA is in a
difficult situation in needing to approve gas contracts and
looking over the best interests of Alaskans, but somehow
companies need to know that they can get an agreement
approved in a timely manner so that the logistics of
permitting, shooting geophysical data, obtaining rights-of-
way and necessary equipment, procuring drilling contracts,
purchasing tubular, mud and all of the other things that
come into play when drilling and producing gas wells can be
done as efficiently as possible. If companies do not feel
they can get a gas contract approved, no one will develop
the huge reserve potential in the Cook Inlet.
2:32:08 PM
At ease
^Escopeta Oil Company - Bruce Webb, spoke for Danny Davis,
Consultant
Escopeta Oil Company - Bruce Webb, spoke for Danny Davis,
Consultant
2:38:33 PM
CO-CHAIR WIELECHOWSKI called the meeting back to order at 2:38.
BRUCE WEBB, Manager, Land and Regulatory Affairs, Aurora Gas,
said he is also the owner of the Webb Petroleum Service that
provides consulting to independents like Escopeta Oil, Pacific
Energy Resources and Fox Petroleum. He is also the President of
Webb Exploration and Production and holds three offshore Cook
Inlet leases. Prior to becoming an employee for Aurora Gas, he
worked for 20 years for the State of Alaska, 11 of which he
spent in the Division of Oil and Gas in lease administration,
permitting and compliance. Before that he spent five years
working on drilling rigs on the North Slope and on the Kenai
Peninsula.
He said there are currently only five natural gas exploration
well plans in the Cook Inlet on state lands; two are with Aurora
Gas, two are with Fox Petroleum and one is with Escopeta Oil
Company. He prepared all five of those permits. In permitting
these exploration wells it was his goal to have an arch going
across the Cook Inlet following the Enstar natural gas pipeline.
By permitting several wells in sequence explorers can share
certain things like drilling fluids, cost of ice road
construction, and things of that nature. Of the five wells that
are currently in the process of being approved or permitting,
four of them have been stalled in the ACMP process. The Nikolai
Creek 11 wells, which Aurora was planning to drill after its
current well is held up with technicalities in the review
process.
The Hanna well's special area permit, which is in the Susitna
Flats State Game Refuge, has already been denied. The Coastal
Management Program has considered the denial of that permit as
an insufficient application, so they are refusing to start that
permit review.
Fox Petroleum's Two Catchers' Mitt Prospects - the Grand Slam
and the Home Run - are also stalled in the ACMP process. That
leaves only one well, Escopeta's North Alexander, and it was
permitted last year in March; but Escopeta is not going to drill
that well unless they can do cost sharing agreements with Fox
Petroleum on the expensive cost of the ice road. That leaves
zero; and no other exploration wells are planned on state lands
for natural gas in the Cook Inlet. They just need the process to
work a little better.
SENATOR WAGONER said that Escopeta has said for years it was
going to bring a floating drill rig to the Kitchens Unit, and he
asked what the status is of them getting together with other
people in the Cook Inlet with that drill rig.
MR. WEBB answered that the DNR had coordinated the Corsair Unit,
the Kitchen Unit and the Northern Lights Unit into one
consolidated unit which is going to be called the Kitchen Lights
Unit. The application is in the process of getting approved this
month. Danny is getting the other investors necessary to bring
the jack-up rig to the Cook Inlet to start drilling in the
Kitchen Lights Unit; he has the Jones Act waiver and is
negotiating a couple of drilling rig contracts. Costs of
contracts on drilling rigs are going up in the Gulf of Mexico
because of the economy. The current plan is that by March 2010
the drilling rig will be on its way to the Cook Inlet and the
first well needs to be drilled according to the plan of
exploration by December 2010.
2:44:51 PM
At ease
^DNR/Office of the Governor - Kevin Banks, Acting Director,
Division of Oil and Gas
DNR/Office of the Governor - Kevin Banks, Acting Director,
Division of Oil and Gas
3:01:57 PM
CO-CHAIR WIELECHOWSKI called the meeting back to order at 3:01.
KEVIN BANKS, Acting Director, Division of Oil and Gas,
Department of Natural Resources (DNR), showed a slide of what
would happen to production in Cook Inlet with no new
exploration. It is what is called "the waterfall slide." He said
the blue line showed how peak demand is satisfied in the Inlet
while the average production for the year is considerably lower.
A forecast of demand is the black line that indicates current
production at 140 mmcf/day now, assuming after 2011 no new
exports are licensed.
3:04:54 PM
The P1 reserves are based on the productivity of existing wells;
behind the pipe reserves (P2) are reserves that are accessible
from existing gas fields, but need further investment in new
drilling. Most of the gas production in the past several years
has been drawn from these kinds of reserves.
MR. BANKS said a possible 470 bcf of gas is available in the
Cook Inlet. Folks are drilling today and converting P1 to P2
kinds of reserves to meet their commitments to the Cook Inlet
consumers. The division is revising these graphs and is working
with the DGGS to quantify potential undiscovered resources. They
want to target incentives to the resources where the economics
play out. As that information is developed, they engage with the
producers about costs. They have had a few meetings already.
It is fair to say he is sensitive to Carri Lockhard's remarks
that cost represents part of the equation for calculating price
and he has to accommodate for the fact that risks are involved
so that the cost of a single well does not represent what the
cost of an exploration play may really be.
He said that the Cook Inlet is fairly deep - 25,000 ft. at the
deepest place, and a lot of oil has been developed on both sides
of it. Federal lands are not accessible to oil and gas
development within the Inlet. CIRI land includes a lot of
subsurface underneath the Kenai Wildlife Refuge; U.S. Fish and
Wildlife owns the surface. Some land is owned by Mental Health
and the University; some is now owned by the Beluga Habitat,
another influence from outside of the state determining whether
surface access can be attained. The areas in the Knik and
Turnagain Arms have critical habitat rules that prohibit any
kind of surface entry. So, not a lot of acreage is left in
prospective areas.
3:13:38 PM
The disappointing last lease sale where only four leases were
acquired happened because little acreage has come back into the
market as leases have turned, and because some of the most
prospective areas are already under lease. Some of the most
prospective areas in the Cook Inlet lie under federal control.
3:14:42 PM
CO-CHAIR WIELECHOWSKI asked if companies are aggressively
exploring on areas already leased.
3:15:55 PM
MR. BANKS replied that they just heard Mr. Webb describe the
wells he is trying to drill and how most of them are being held
up and how Ms. Lockhard is meeting their commitments. Not a lot
of exploration is going on in the Cook Inlet to bring
undiscovered resource into a reserve.
CO-CHAIR WIELECHOWSKI asked what efforts the state is making to
make sure the lessees are meeting their obligations to develop.
MR. BANKS answered that the state had done "a pretty good job."
The Kitchens Unit is an example of converting what seemed to be
an intractable situation where investment money from a couple of
companies is drying up. Escopeta is committed to bringing a
jack-up rig into the Cook Inlet to begin exploring there. He is
planning to drill by December 31, 2010, but he has also made a
commitment to drill a well each year after that for four wells.
CO-CHAIR WIELECHOWSKI asked if he agreed with the criticisms of
the regulatory and permitting processes.
MR. BANKS said that was difficult to answer; the department
tries to be as progressive as it can, but Cook Inlet has
resource conflicts everywhere.
3:18:31 PM
CO-CHAIR WIELECHOWSKI asked to what extent his division or the
department deals with storage issues. Do further steps need to
be taken to incentivize storage?
MR. BANKS answered they have done a couple of things already.
Cook Inlet already has three storage facilities on state land
with Marathon and Chevron. Chevron also has storage in the
Swanson River field, which is a federal property. Aurora has
asked them for storage in one of their units and he is drafting
a lease that would allow for a third-party use of that storage,
an important advancement.
3:20:27 PM
JOE BALASH, Intergovernmental Coordinator, Office of the
Governor, briefed them on the incentives that are currently
available under the Alaska tax code. Under the state's
production tax in AS 43.55, there are basically two functioning
components that help drive exploration and development
incentives; the deductions allowed for single-year capital write
offs and the credit that may be claimed.
How that works on the North Slope, depending on what tax bracket
you are in (if progressivity has kicked in or not), you get to
write off capital expenditures in a single year, and that has
the effect of being a 25 percent incentive. If you are into the
progressivity zone above the trigger price, that rate could be
even higher. This works for the deduction side of the equation
on the North Slope.
On the credit side when a capital expenditure is made, depending
upon the area in which that exploration target is - seismic or
drilling - if it's far enough away from existing wells or units,
it can qualify for as much as a 40 or 30 percent credit. Even if
it doesn't qualify as an exploration credit under the rules, it
would still be eligible for a 20 percent qualified capital
expenditure credit that is available not only in the North
Slope, but also in the Cook Inlet.
MR. BALASH said the exploration credit rules vary a little bit
in the Cook Inlet region because of the maturity of the basin;
some of the distance requirements are shorter, but they are
still available for what would be considered "rank" exploration
outside of known reserves.
3:22:54 PM
The biggest difference between the North Slope and Cook Inlet is
in the operation of deductions due to the transition-type of
work that was done in the production tax code when it was moved
from the ELF-based system in 2006 into the net-based under PPT
and ACES. Under ELF a large number of producing fields in Cook
Inlet were at a zero percent tax rate, primarily the oil fields
and some of the gas fields were down in the 4-5 percent range.
To prevent any jarring tax increases for either oil or gas, a
ceiling was put in place to grandfather in the old ELF-rates. He
explained further:
So, when you take an expenditure in Cook Inlet and
start deducting that from the production value, that
comes down and brings the overall production value
lower, but unless you have a significant expenditure,
you're not ever going to fall below the old ELF
ceiling. As a consequence, you don't see the tax
benefit of a deduction in Cook Inlet the same way you
do on the North Slope. As a consequence you don't have
the same combination of incentives to apply to
exploration projects in the Cook Inlet that you do up
in the North Slope and in the Brooks Range and NPRA.
So the bottom line is that we do have tax credits, but
because the tax rates are low the opportunity for the
additional incentives in the capital deductions are
not present in Cook Inlet.
SENATOR FRENCH asked if North Slope credits are transferable out
of the Cook Inlet Basin.
MR. BALASH replied the credits can be applied to production tax
due in other regions, but the deductions can't be exported
outside of the Cook Inlet Basin.
CO-CHAIR WIELECHOWSKI asked what he thought about Chevron's
suggestion about making tax credits available for storage
investments and treating storage costs like transportation
making them deductible from royalty.
MR. BALASH replied the manner of determining what qualifies as a
deduction under the tax code is a defined term in the point of
production, and storage takes place above or beyond the point of
production. So, it would require changing the definition, which
would have to be done very carefully, because a it would affect
not only the Cook Inlet, but the North Slope as well.
3:26:54 PM
As the economic impacts of where that line is are examined, one
can see potential enormous changes in the way of looking at the
economics - particularly in Prudhoe Bay gas development where a
gas treatment plant that would cost billions of dollars. By
moving the point of production to a place where storage would be
included, he couldn't imagine how the definition would be
written without including treatment first.
CO-CHAIR WIELECHOWSKI suggested stopping it at the North Slope,
because one of the key issues in Cook Inlet is storage.
3:27:51 PM
MR. BALASH replied that providing credit for storage could be
"bolted on separately" in a couple of ways without creating
other problems; definitions wouldn't have to be changed. He
observed because of the ways they have tried to treat Cook Inlet
differently than the North Slope, they just need to be very
careful in making changes to the code so as to not create what
might be considered loopholes between the two basins.
3:28:48 PM
CO-CHAIR MCGUIRE asked if he could use her bill on capital
investment for alternative energy that has an earned tax credit
that gets applied generally as a model.
MR. BALASH replied that could be considered. The question is who
would have access to that credit - the producers, utilities or
third parties? It would be a policy decision.
SENATOR FRENCH for summaries of what DNR's ideas are for solving
the Cook Inlet gas issues.
3:30:04 PM
MR. BANKS recapped that the department has been called upon by
many parties to offer some kind of baseline information with
respect to reserves and resources and possibly costs in order to
help inform to date. To a certain extent that is what the
Division of Oil and Gas is trying to do, and they should have a
better estimate of reserves by the end of the summer; the
resource estimates would take longer. They are at the "very
front end" of cost information and they haven't completely
scoped out what kind of work that might entail in terms of
offering potential solutions.
He said he had been prepared to talk about direct subsidies for
gas exploration, but he hadn't heard a lot of people asking for
that. They seem to be more concerned about access to the market,
access to land, and price, all of which are beyond the
department.
^Regularoy Commission of Alaska (RCA) - chairman Bob Pickett -
gas pricing
Regulatory Commission of Alaska (RCA) - chairman Bob Pickett -
gas pricing
3:32:05 PM
BOB PICKETT, Chairman, Regulatory Commission of Alaska (RCA),
said he would first highlight the statutory role of the RCA.
They do not regulate producers of natural gas in the Inlet, but
they do evaluate gas sale agreements to the utilities. Their
standard review considers whether the utility acted in a prudent
manner and if the terms of the agreement are reasonable, and
whether the gas sale agreement insures reliable and reasonably-
priced utility service. They are guided by AS 42.05.431(a) and
under this subsection, the RCA has to determine if terms of a
gas sale agreement are unjust, unreasonable, unduly
discriminatory or preferential. The RCA makes this determination
on the basis of the record developed for each gas sale
agreement.
3:34:09 PM
He explained that the gas sale agreements are filed as tariff
actions (TA filings) and are publicly noticed. After the public
notice period is over, the Commission will evaluate all the
comments that are filed and then make a determination as to
whether they will allow the filing to go into effect or suspend
it into a docket for further investigation. Because of the
critical importance of the gas sale agreements most have been
suspended into dockets. They are a huge component of a utility's
electric bill or in the case of Enstar, it probably accounts for
80 percent of their dollar figures. The record is developed
through successive rounds of prefiled testimony and discovery on
the prefiled testimony, and further developed through
evidentiary hearings and commissioner enquiring. The Commission
must base its findings of law in findings of fact on the record.
When the RCA decisions don't afford all the parties their due
process rights based on the record, they are subject to reversal
by the Superior Court or the Supreme Court - as what happened
with the 2004 RCA decision concerning an Anchorage utility.
3:35:54 PM
He commented that the Cook Inlet gas market is truly unique,
because it is isolated, and the gas was found as a result of
looking for oil - so the costs associated with the initial
exploration which identified the largest Cook Inlet fields were
by and large borne by the oil side of the equation at a time
when the cost structure was entirely different. There is no
commonly accepted pricing mechanism in Cook Inlet for natural
gas. It has been only since 2001 that a variety of pricing
proxies have been considered by the utilities, the producers,
the attorney general and the RCA, but none have resulted in an
RCA-approved GSA that currently delivers gas to utility
customers.
3:37:05 PM
MR. PICKETT explained that utility gas supply agreements use a
variety of pricing mechanisms - the Henry Hub averages, crude
oil futures, NYMEX 36-month future contracts, contractual terms
tied to specific base prices identified in some of the legacy
contracts with an index escalator, and in the case of Enstar,
the "weighted average cost of gas" for Cook Inlet (WACOG), which
is $8.75(2009). For reference he said the July 2009 NYMEX was
$3.80.
He said they should factor in some recent development into their
decision-making process. After the conclusion of the last sale
agreements (EO858) in which Enstar relied on a tariff provision
allowing them to enter into agreements with producers as long as
the price doesn't exceed the weighted average cost to Cook Inlet
gas (the two one-year contracts that were referenced), the
Commission realized that several key points were identified -
one is that storage is a critical component of the immediate
future and it is going to be the shock absorber that will get us
them through deliverability crunches, and he said, "I fully
believe we do have a severe deliverability problem."
He said that Enstar recognized the problem in 2007 after a cold
snap and again in January 2009 when the average temperatures
were no lower than -15 when the system was stretched "from the
wellhead clear to the burner tip." This needs to be factored
into their thought processes collectively.
3:39:18 PM
MR. PICKETT allowed that the RCA has not done an adequate job of
describing the Cook Inlet gas situation to the public. He is at
the receiving end of many phone calls and the RCA is at a
balancing point trying to strike the right balance between the
utilities and the ratepayers. That is what the legislature in AS
42.05 tasked them with. He has heard the RCA referred to as a
rubber stamp for the producers, but he thought Enstar "would be
quite shocked to hear that characterization." But when they are
hit with 22 percent rate increases, they are frustrated and are
looking for some sort of relief.
In February the RCA decided to investigate at their public
meetings whether there was a need for regulations or a rule-
making (R-dockets) docket on the issue of natural gas storage.
Before entering into that, they had a scoping process in which
affected parties are offered the opportunity to comment. After
reviewing comments on the storage issue and with some input from
the Department of Law that there were some jurisdictional
issues, commissioners decided not to proceed with a docket at
this time because it would probably have a chilling effect on
investment in storage. If a utility is going to be directly
investing in natural gas storage for utility purposes they are
clearly covered under AS 42.05, but as far as producer storage,
the RCA has jurisdictional issues and other "gray zones" that
are better to not take up now.
The Commission did feel it was important to have a scoping
process on how the gas pricing and gas sale agreements work. So,
comments were solicited and in April they received comments from
four producers, four utilities, land owners, the Attorney
General, DNR, ANGDA, and a member of the legislature. The nature
of the comments ranged from some strong encouragement clear to
"this is a fool's errand." As a result, the RCA decided to open
a docket and issue a notice of inquiry covering a couple of
different areas. First is the issue of whether the RCA even has
jurisdiction in gas sale agreements (raised by one of the
utilities) and the Department of Law is looking at. The RCA is
also reviewing the practice of prior approval of gas sale
agreements. One option is that the utility negotiates it and
then down the road some place in the context of a rate case the
RCA evaluates it. Given recent history, he didn't think the
utilities would do that. In the absence of some certainty,
utilities are not going to be second-guessed in the rate case.
That's why the practice of prior approval has evolved over the
years.
He said the RCA would also be looking at the standard of review
for the gas sale agreements and then look at the question if
there is a role that the RCA currently has under statute for
creating incentives for natural gas exploration and production -
a big question mark.
MR. PICKETT remarked that on May 12, the gas supply agreement
between Chugach Electric and ConocoPhillips was filed with the
RCA along with a request for an expedited public notice period,
which was granted. It has been noticed and comments are due back
to the RCA by June 19, 2009. He said the RCA website has the
three-page notice with a description of the pricing points. As a
further consideration for this contract Chugach Electric agreed
to drop its appeal before the Ninth Circuit Court of Appeals on
the DOE/King Island LNG export license and authorization.
3:44:11 PM
SENATOR STEDMAN joined the committee.
CO-CHAIR MCGUIRE asked what he thought about Marathon's
testimony earlier that the way a price is considered competitive
or not is to compare it to the alternatives that are available
as opposed to the market itself.
MR. PICKETT said he would speak for himself, because the five
commissioners have very different personalities and approaches
to things. He thought it was fair to say that some elements of
the record point to that opinion. The Commission was criticized
by a number of different entities that it did not take cost
considerations into account, but from his read of the 10,000-
page record of three and a half weeks of hearings is that none
of the parties ever introduced cost elements into the record.
He said it is very unclear that the Commission has a role in
incentivizing exploration; obviously approval of gas sale
agreements is a critical component just because it creates the
market for the producers. But he didn't think the Commission was
well equipped to make judgments on exploration costs because it
was very fast moving. The collapse of the commodity markets
makes it even truer today than it was a year ago. Different
companies have entirely different rates of return (ROR) and he
didn't think they wanted to put the Commission in a position of
evaluating on a field by field basis what the ROR should be.
CO-CHAIR MCGUIRE said Mr. Banks testified that he had seen
evidence that people are converting their P2 fields to P1 fields
to meet existing contracts, and she wondered if part of the
crisis they are facing is because of the lack of fiscal
certainty surrounding the long term contracts that could be
associated with exploration.
3:47:32 PM
It appears in that one example movement is detected when there
is an underpinning contract. This dovetails into a larger
question which is that the RCA has a statutorily defined role on
behalf of consumers and she wanted to know to what extent
availability of a resource comes into play.
3:48:15 PM
MR. PICKETT answered that is a good question and if you go back
to 2001, the Mineral Management Service (MMS) had an estimate of
2.7-2.8 tcf of proven and probable reserves in the Inlet. In
February Mr. Banks had an estimate of 1.35 tcf and it sounds
like that may be on the conservative side. The fact is that the
proven and probable reserves have been "on a fairly relentless
decline in this decade, at least." That means the fields are
being developed. So part of the answer is incentives, but it's
important that the market as a whole can function. That is why
in EO858 the Commission strongly supported the export license.
Availability of the resource is an overriding consideration, but
the RCA has to make decisions based on the record. The courts
have and will overturn their decisions; and the Commission
doesn't have time to redo them. Perhaps the Legislature could go
into the statutory citation about the standard of review for gas
sale agreements and arrive at some kind of pricing mechanism
that made sense in the overall state's best interest. The
Constitution mandates particular for the resources that they are
managed for all Alaskans, and that isn't just the ratepayers in
Southcentral Alaska.
^Gas storage & other infrastructure issues - Mark Slaughter,
Enstar's Manager of Gas Supply; Ethan Schutt, Senior Vice
President, CIRI Land & Legal Affairs; Kevin Banks, DNR; RCA
Chairman Bob Pickett; Suzanne Gibson, Chugach
Gas storage & other infrastructure issues - Mark Slaughter,
Enstar's Manager of Gas Supply &
Ethan Schutt, Senior Vice President
3:50:49 PM
CO-CHAIR WIELECHOWSKI said he wanted Enstar's thoughts on
incentivizing gas exploration in Cook Inlet and on storage.
MARK SLAUGHTER, Gas Supply Manager, Enstar Natural Gas Company,
representing Enstar and the Alaska Pipeline Company, said that
Enstar is a division of Semco, and the Alaska Pipeline Company
is a wholly-owned subsidiary of Semco. They serve about 128,000
customers and that translates into about 350,040 citizens of the
state. They run 350 miles of high pressure transmission lines
and another 2,800 miles of distribution lines.
He said they do not have a gas contract currently; the Unocal
2001 contract is the last one. They have entered into
negotiations and contracts between various parties using pricing
methods that the Commission indicated would be acceptable prior
to their hearing and review process, but then they were
rejected.
In 2011 they will have a shortfall of roughly 10.5 bcf of gas,
which is a third of their portfolio. They do not like to be in
this position and would normally contract for long periods of
time like 10-20 years. He said they are actively negotiating
with producers and he was optimistic that they would bring
something forward before then, but he hoped the RCA process
would not be too difficult.
CO-CHAIR WIELECHOWSKI asked if he had talked to anyone about
using depleted wells for storage.
3:55:18 PM
MR. SLAUGHTER replied they had been evaluating storage for
several years. With the APL6 contract they had a commitment for
purchasing storage gas and were in negotiations with storage
field owners to purchase the storage field. In 2011 Enstar knows
it will need approximately 1.2 bcf gas with a deliverability
rate of 50 mmcf/day. He said they had spent a significant amount
of time evaluating properties, but only a limited number of
fields in Cook Inlet are reasonable storage facilities, and even
then some risk is involved. For perspective, he said, even if
they were to start on storage today, one entity has estimated
that it would take until 2013 to get a storage field on line.
This is too late.
3:56:52 PM
CO-CHAIR WIELECHOWSKI asked what the legislature should do to
incentivize Cook Inlet gas production in relation to the Enstar
issue.
MR. SLAUGHTER replied that they need to be able to enter into
contracts with producers that will be approved by the RCA. They
are not interested in a retroactive cost approval basis. Storage
is needed, and Enstar is actively working on it.
3:58:44 PM
SENATOR WAGONER asked what they are going to do if
ConocoPhillips' plan is not approved for export in 2011 and they
don't have that as a backup for their shortfall.
MR. SLAUGHTER replied that the plant is only licensed through
March 2011, and their peaking shortfall right now is 87 mmcf.
They will try to contract for it and they are trying to get
storage developed storage by that time. The gas that is being
diverted from that plant is going to Enstar to CEA to meet other
contractual obligations. That is why they are hearing storage is
needed in the Inlet.
Enstar has received rough estimates of $25-30 million for
installing the regasification facility on the plant. If the
plant is shut down, one idea is that they can fill the tanks up
at the end of the 2011 and then they would be able to get
through 2012. But who would operate it? And the plant is too
large to keep a number of people employed year-round just to
fill the tanks up once a year (about 2.2 bcf).
4:01:00 PM
SUZANNE GIBSON, Director, Energy Resources, Chugach Electric
Association (CEA), said there are no easy answers in Cook Inlet.
One thing they can all readily agree on is that third-party
storage is critical to the development of a competitive liquid
natural gas market. Storage would provide needed summer time
markets for Cook Inlet producers and create opportunities to
reduce dependence on producers' ability to provide critical
winter time peak demand. It would improve flexibility and
reliability for both electric and gas utilities; it would allow
new producers to enter into the Cook Inlet market because it
reduces the risk that they will not be able to find a market.
However, third-party storage is not without its difficulties,
she said. It would be the beginning of a spot market in Cook
Inlet, which means that utilities would have the ability to
purchase gas on a daily basis to meet their needs. They could
also make decisions about whether to store that gas and burn it
at a later time, which would require some refinements to current
regulatory rules about having preapproval for certain portions
of natural gas contracts.
MS. GIBSON said the largest hindrance to a new third-party gas
storage facility is that as far as Chugach is aware, there are
no empty reservoirs in Cook Inlet that are available for
utilities or an independent storage operator to come in and
utilize in order to provide the necessary tool that will bridge
the gap between what producers can produce on a daily basis and
what utilities require.
As was pointed out, the ConocoPhillips LNG facility is not
capable of regasifying the gas that goes into the facility and
returning it to the local utility market at this point. FERC
recently ruled that any modification to the LNG facility will
require the whole facility to be brought up to code. So in
addition to adding the regasification, other regulatory hurdles
will have to be met.
MS. GIBSON concluded that Chugach believes that third-party
storage is the gateway to real price discovery and the genesis
of a spot market that reflects the true value of gas in Cook
Inlet.
4:04:29 PM
SENATOR FRENCH asked in other jurisdictions, is it typically the
producer or the utility that takes authority over storage.
MS. GIBSON replied that producers can own their own storage; it
is also very common for independent storage operators and
utilities to own and operate storage. In some cases those
storage facilities are regulated and sometimes not.
SENATOR FRENCH asked in the absence of a reservoir and an LNG
regasification facility, what other options are there.
MS. GIBSON replied that they need a third party to get their
hands on a reservoir, and she didn't know how to get that to
happen.
SENATOR WAGONER asked if a facility for compressed natural gas
could be built to help smooth out peak demand.
MS. GIBSON replied that she didn't have any first-hand knowledge
about the cost of such a facility, but all options should be on
the table at this point.
CO-CHAIR WIELECHOWSKI asked how to incentivize storage
facilities.
MS. GIBSON replied that Chugach is a not-for-profit non-taxable
entity; so from a utility perspective they need capital and the
ability to get an adequate reservoir. She couldn't speak to tax
incentives.
4:06:54 PM
CO-CHAIR WIELECHOWSKI asked how big of a storage facility is
needed in Cook Inlet.
MS. GIBSON replied that Chugach, Enstar, and ML&P are working on
consolidating their needs to figure that out. Most likely one
single reservoir wouldn't provide a the whole solution.
CO-CHAIR WIELECHOWSKI said the open market hadn't taken care of
this problem, and he asked if she thought the state needed to do
something.
MS. GIBSON replied that there is a free market, but not a liquid
market, and "the two kind of go hand-in-hand." She stated:
It's difficult to value storage at anything other than
cost unless there is a market. That kind of leads you
down the path of a utility-owned regulated storage
facility. To incent independents to come in and build
storage which will be utilized by utilities, it would
necessitate spot market. I don't think that you can
have one without the other. But if you have
storage....it opens up all kinds of opportunities.
Because now it means if an independent comes in and
drills and they have gas, the utility can buy it
because they are not tied up with full requirement
contracts that don't allow them to purchase gas from
anyone who can't meet some portion of their full
requirement. So it is, I believe, the genesis of the
improvement of this market, and also it will lead to
true price discovery.
CO-CHAIR WIELECHOWSKI asked if Enstar agrees.
4:10:34 PM
MR. SLAUGHTER responded that from Enstar's perspective, storage
is one aspect of the whole equation. If the price is high enough
to absorb the dry well or cost overruns, people will take the
exploration risks. A third-party independent doing storage
services will want a market rate instead of a cost of service
model. So, then you get back to the question of how the utility
will be able to store gas in a storage facility if the storage
operator wants market rates. Then you're going to go down the
path of what their costs are to operate that storage facility,
and it's doubtful that a producer "will open up their books on
that."
4:11:11 PM
ETHAN SCHUTT, Senior Vice President, Land and Energy
Development, Cook Inlet Regional Inc. (CIRI), said he would talk
about CIRI's storage infrastructure. CIRI has reservoir and
reservoir lands, so they have perspective structural storage,
but today they come to the meeting as a third party that has
looked at participation in the private market to develop a non-
producer, non-utility storage solution that would be available
to utilities or independent producers. He said they have
perceived a need for storage by smaller independents. Normally
the term "producers" refers to Unocal and Chevron or Marathon,
the large incumbent producers.
He said that this uncertain market environment makes it an
unattractive proposition for private investment to develop an
independent and open storage market. To serve this market they
probably need storage on both sides of the Inlet - subsurface
structural storage for peak needs as well as surface storage
that would help ease the utilities' costs as the contracts
transition over to having punitive clauses for missing predicted
gas rates with their producers to supply their gas. It's not
easy to alleviate those hourly shortfalls with structural
storage because you have the issue of whether you can produce
more gas out of your geological structure that was probably once
a gas field in its own right.
4:14:50 PM
MR. SHUTT said the real uncertainties that make this
unattractive have to do with the utility customer market
uncertainty. He explained that Chugach is the largest generator
right now of electricity on the Railbelt, but two of their large
wholesale customers are coming up on the ends of their contracts
- Homer Electric and MatSu Electric. Both of those are talking
about their own energy systems. So, at this point it isn't clear
who the utility customers will be. Couple this with the
uncertainty that the RCA would regulate third-party storage just
because the customers are utilities and it's not clear the
developing a third-party storage would be able to achieve an
attractive rate of return.
A third layer of uncertainty is the market uncertainty and the
perception that a desperate situation is looming for energy
supply to the Railbelt. Developing a storage facility is not a
cheap undertaking and when you talk about bullet lines or the
construction of a large LNG import facility as solutions to a
desperate problem, one doesn't want to invest a lot of capital
in large storage facility that might be unnecessary before being
able to recover amortized costs for developing it.
4:17:17 PM
CO-CHAIR WIELECHOWSKI asked how much storage would be needed.
MR. SCHUTT replied it's hard without knowing what the utilities
would need. A lot of the facilities are old and inefficient and
everyone is talking about installing new gas turbines, but they
should work together to try to quantify what is needed.
SENATOR FRENCH asked if CIRI land has producing gas wells.
MR. SHUTT answered yes on both sides of Cook Inlet.
SENATOR FRENCH asked who operates them.
MR. SHUTT answered Marathon, Aurora, and a few others.
SENATOR WAGONER asked when they are going to start drilling
Sunrise.
MR. SCHUTT answered that is slated for November/December.
^Access issues - Kenai National Wildlife Refuge, Robin West,
Refuge Manager, and CIRI Ethan Schutt, Senior Vice President,
Land & Legal Affairs
Access issues - Kenai National Wildlife Refuge, Robin West,
Refuge Manager, and CIRI Ethan Schutt, Senior Vice Pre
4:19:50 PM
ROBIN WEST, Refuge Manager, Kenai National Wildlife Refuge, said
the Refuge was established in 1941 as the Kenai National Moose
Range. Shortly after that came a growing interest in petroleum
production in the area. The only legal guidance in those days
was the Minerals Leasing Act of 1920. In 1957, the Secretary of
Interior at the time carved off part of the Kenai National Moose
Range and opened it to oil and gas activities. The remainder was
placed off-limits. Those lines haven't changed much over the
years. They have seen additional withdrawals and additions with
the Alaska Native Interest Land Claims Settlement Act (ANILCA),
the Wilderness Act and the Refuge Administration Act.
They have three lease areas: the Swanson River field which came
on in 1957, the Beaver Creek Filed in 1967, and Birch Hill which
is not yet in production. CIRI has access rights to nearly a
quarter million acres of subsurface oil, gas and coal that are
adjacent to existing federal leases under ANILCA. The areas that
are adjacent to those in the uplands and foothills are close
either by law or regulations.
More acres are closed than are open, but he has been told 80
percent of the open lands have the potential for exploration.
Last year a six-mile road was built in the Refuge out to the
satellite project at Sunrise, and probably in January the drill
rig will go in there.
On June 2 a pre-application meeting was held with Nordic Energy,
Inc. on a proposed 2.5-mile ice road to do a subsurface
exploratory gas well for CIRI. So, he will be issuing a special
use permit for their survey within a few weeks. Union Oil has
also applied for a right-of-way permit to build a three-mile
permanent road to access Birch Hill, and that project will begin
this winter.
4:24:05 PM
CO-CHAIR WIELECHOWSKI said people have heard there are large
reserves in the Kenai National Wildlife Refuge, and he asked
what the state could do to access them.
MR. WEST replied in the 14 years that he has been a Refuge
Manager, he has had no requests to explore outside of authorized
areas, and he has never denied a permit in the areas that have
interest.
4:25:02 PM
KIM CUNNINGHAM, Director, Land and Resources, CIRI, said they
hold significant surface and subsurface acres in Cook Inlet and
also within the Kenai National Wildlife Refuge. They have
received 186,380 acres of the subsurface within the Refuge
through their entitlement. CIRI is seeking responsible lessees
to explore their subsurface estate both inside and outside the
Refuge. Most of their research indicates that Cook Inlet has
significant resources remaining that need to be discovered and
explored.
Within the Kenai National Wildlife Refuge, CIRI has ownership
interest in the productions coming from the Beaver Creek Unit
operated by Marathon, the Swanson River Unit operated by
Chevron, and the Birch Hill Unit that has gas, but it is not
being produced yet. In addition, CIRI has leased acreage to
Marathon and Nordic Energy. Of the total CIRI acreage in the
Refuge, Union holds approximately 21,000 acres, Marathon holds
approximately 26,000 acres and Nordic Energy has 11,000 acres.
MS. CUNNINGHAM said their lessees have many prospects within the
Refuge, but it is time consuming and costly to obtain the
permits required to explore in the Refuge. She remarked that
from the lessees she works with on a regular basis, they are
very complimentary regarding how well everyone works together.
She said an example of the process for a lessee interested in
exploring for oil and gas in the Refuge is best served by
talking about the Sunrise prospect, on which Marathon will drill
one exploratory well this winter. This requires permitting for
the road, pad, and an initial well. There are and have been at
least seven agencies and programs involved - the Department of
Interior, the U.S. Fish and Wildlife Service, U.S. Corps of
Engineers, the U.S. Environmental Protection Agency, the Alaska
Department of Fish and Game, Division of Habitat, the Alaska
Coastal Management Program, and the Office of Project Management
and Permitting.
Participants have to determine who the lead agency will be
before they do anything else at the time they start to plan for
an exploration program. In the case of Sunrise, it was
determined that it would be the U.S. Department of the Interior,
U.S. Fish and Wildlife Service.
4:30:09 PM
She said the most important permit is the Environmental Impact
Statement (EIS) because it sets the guidelines for the entire
project and is subject to both agency and public comment. It
helps determine which state agencies and permits are required
for project approval. The lead federal agency has a 16-month
window to complete its review of the EIS for projects within the
Kenai National Wildlife Refuge. This timeline is from a
provision in ANILCA giving Native groups the right to develop
resources within an in-holding selected under the ANCSA. Without
the ANILCA stipulation, agencies have no mandated timeline or
due date for approving the EIS.
Producing an EIS takes extensive research on the part of the
applicant who has to gather environmental data before they begin
the application process in order to meet the schedule. Data
gathering is seasonal work - mostly in the summer - and can take
up to a year and a half to complete. After completing the EIS, a
Coastal Zone Consistency Determination for the project is
required for the issuance of the necessary state and federal
permits. While the EIS requires addressing the full scope of the
project, the consistency review can be phased to accommodate
first, and once they know they have something worth pursuing
they would proceed with the development component.
In the case of Sunrise the initial permitting for the EIS began
in late 2000 and was completed in January 2003. It included
issuance of the right-of-way permits by the Department of
Interior and also in their case, to transfer that permit when
they had operator issues. Once the transfer was complete in
early 2004 they applied for the consistency determination and
had all the permits in hand by the end of 2004. At this point in
time, the lessee has moved forward and followed through with a
seismic program and processing of the seismic data - looking at
it to make sure the well is at the most optimal location. They
are trying to allocate their resources and in the light of
recent economics figure out how to meet their commitment to do
the exploration, a condition CIRI built into the lease.
In addition to the EIS, the Corps of Engineers was also involved
in the application process to obtain approval to construct the
access road across wetlands. State agencies were also involved
in permitting the Sunrise project; a permit from ADF&G was
necessary because the road crossed the tributary to the Swanson
River, and the ADEC had to review water quality impacts as part
of the 401 process associated with the 404 permit, which is
issued by the Corps of Engineers. If after the well is drilled,
Sunrise is determined to be an economic discovery, a second
round of permitting will begin. This phase is necessary because
you need to know what type of facility is needed before they get
permitted.
If Sunrise is determined to be a large project, the Office of
Project Management and Permitting will become involved. Air
permits may be required and modifications for the right-of-way
for the pipeline may be required. New EPA guidelines have
extended the Corps of Engineers' permitting process which can
take over 120 days. Gas is easier to permit than oil.
4:33:50 PM
In closing, she said, their concern in leasing to somebody is
that smaller independents don't have the sophistication
necessarily to do everything that has to be done to get an
exploration started in the Refuge.
4:34:46 PM
CO-CHAIR WIELECHOWSKI asked if there is anything the state can
do to change the process since that is a federal refuge.
MS. CUNNINGHAM replied that she didn't think they could impact
the federal permitting process, but in the Lower 48 BLM has had
a pilot project in which they have been looking at the timelines
for permitting. After two years of that pilot project, they came
out with a report in February 2009 that significantly reduced
permitting time by coordinating the efforts of all the agencies.
So it may be possible to find ways for agencies to work and
coordinate their information better.
Also, as a person who hears from lessees, particularly some of
the new independents, she has heard that they need access to
pipelines and markets. If they find gas they are not sure who
they can sell it to. Nordic Energy is one of their lessees and
this is their first foray into the Kenai National Wildlife
Refuge, a good prospect. Armstrong Oil and Gas is another
lessee; they drilled a well in the North Fork Unit and they also
have acreage around that, but the problem for them also is
pipeline access and the ability to get that gas to market.
CO-CHAIR WIELECHOWSKI asked if they are having problems with
pipeline access.
MS. CUNNINGHAM explained that the North Fork Unit is not CIRI's
and it doesn't have a pipeline. She understands the gas from
that unit was being trucked, and Armstrong doesn't want to do
that.
4:42:08 PM
CO-CHAIR WIELECHOWSKI closed public testimony and thanked
everyone for their excellent testimony. He outlined six areas he
wanted the committee to look into: promoting conservation
because it is the cheapest and quickest way to start saving gas,
looking at ways to incentivize storage, streamlining of permits,
increasing access to lands, exploring AS 42.05.431 to see if the
regulatory structure needs to be changed, and expanding access
to the market. He also wondered why the LNG plant is operating
at only half capacity. He also didn't get a sense that taxes
were a prohibiting factor in getting people to do more
exploration. He invited people to submit their ideas. There
being no further business to come before the committee, he
adjourned the meeting at 4:42.
| Document Name | Date/Time | Subjects |
|---|---|---|
| Armstrong - Cook Inlet Gas.pptx |
SRES 6/5/2009 1:00:00 PM |
|
| Chevron - Cook Inlet Gas.ppt |
SRES 6/5/2009 1:00:00 PM |
|
| RCA - Cook Inlet Gas.ppt |
SRES 6/5/2009 1:00:00 PM |
|
| DNR - Cook Inlet Gas.ppt |
SRES 6/5/2009 1:00:00 PM |