Legislature(2011 - 2012)BUTROVICH 205
04/27/2012 01:30 PM Senate JUDICIARY
| Audio | Topic |
|---|---|
| Start | |
| Point Thomson Settlement Agreement | |
| Mark Myers Evaluation | |
| Walker Reconsideration Point Thomson Settlement | |
| Attorney General Michael Geraghty | |
| Department of Natural Resources (dnr) | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
ALASKA STATE LEGISLATURE
SENATE JUDICIARY STANDING COMMITTEE
April 27, 2012
1:33 p.m.
MEMBERS PRESENT
Senator Hollis French, Chair
Senator Bill Wielechowski, Vice Chair
Senator Joe Paskvan
Senator John Coghill
MEMBERS ABSENT
Senator Lesil McGuire
OTHER LEGISLATORS PRESENT
Senator Donny Olson
Senator Dennis Egan
Representative Mike Doogan
Representative Peggy Wilson
Representative Kurt Olson
Representative Beth Kerttula
Representative Steve Thompson
COMMITTEE CALENDAR
Point Thomson Settlement Evaluation
- HEARD
Point Thomson Settlement Litigation
- HEARD
Point Thomson Settlement/DNR response
- HEARD
PREVIOUS COMMITTEE ACTION
No previous action to record.
WITNESS REGISTER
MARK MYERS Ph.D., CPG, representing himself
Anchorage, AK
POSITION STATEMENT: Raised questions about the Point Thomson
Settlement agreement.
CRAIG RICHARDS, Attorney
Anchorage, AK
POSITION STATEMENT: Described the appeal he filed on behalf of
Mr. Walker to reconsider the decision to enter into the Point
Thomson settlement agreement.
MICHAEL C. GERAGHTY, Attorney General
Department of Law (DOL)
Anchorage, AK
POSITION STATEMENT: Provided supporting testimony for the Point
Thomson settlement agreement.
JOE BALASH, Deputy Commissioner
Department of Natural Resources (DNR)
Anchorage, AK
POSITION STATEMENT: Provided supporting testimony for the Point
Thomson settlement agreement.
JON KATCHEN, Inter-governmental Coordinator
Department of Natural Resources (DNR)
Anchorage, AK
POSITION STATEMENT: Provided supporting testimony for the Point
Thomson settlement agreement.
ACTION NARRATIVE
1:33:21 PM
CHAIR HOLLIS FRENCH called the Senate Judiciary Standing
Committee meeting to order at 1:33 p.m. Present at the call to
order were Senators Wielechowski, Paskvan, Coghill, and Chair
French.
^Point Thomson Settlement Agreement
1:34:06 PM
CHAIR FRENCH announced the business before the committee would
be a review of the Point Thomson settlement agreement. He
provided a backdrop for the discussion by reviewing three news
articles. The first was from 1992 when Governor Hickel began to
talk about changing the rules for state oil and gas leasing
because companies were "sitting on gas fields such as Point
Thomson, which could play a crucial role in the gas pipeline
project." The second article was from 1998, and was about the
state being satisfied with the 15 plan of development that
ExxonMobil submitted for development of the yet undeveloped
Point Thomson field that was created in 1977. The third article
was from 2004 when ExxonMobil agreed to begin drilling
development wells in the field by June 15, 2006 or face
automatic surrender of the acreage plus a $20 million penalty.
The article said that ExxonMobil recently backed away from plans
for a possible $1 billion project to move Point Thomson liquids
down the Trans Alaska Oil Pipeline because further evaluation
showed the project wasn't commercially viable without a
companion pipeline to the Lower 48 that could carry the gas
reserves.
He introduced former oil and gas director Mark Myers as the
first presenter.
^Mark Myers Evaluation
1:36:55 PM
MARK MYERS Ph.D., CPG, representing himself, described his 25
year history as a petroleum geologist working on the North Slope
in both exploration and development. He served as the director
of the Division of Oil and Gas from January 2001 until November
2005, and in that role ultimately defaulted ExxonMobil for
failure to develop.
MR. MYERS said it's not possible to understand the settlement
agreement without understanding the details of the very complex
gas condensate and oil field. He confirmed that he was only
using public data and emphasized the importance getting
briefings from experts in the fields of geology, engineering,
and economics to understand the significance of the concluding
information. He also emphasized the importance of getting the
best legal support possible from attorneys who are experts in
oil and gas law.
MR. MYERS said his presentation would have four parts: 1) a
technical discussion of the details of the Point Thomson field;
2) a description of a few previous development commitments; 3)
the current settlement; and 4) a summary.
1:42:09 PM
MR. MYERS described Point Thomson as the remaining crown jewel
on the North Slope on state lands. The combined reservoirs may
contain more than 1 billion barrels of technically recoverable
oil and condensate, and 7 trillion cubic feet of technically
producible natural gas. The field has two major reservoir
integrals - the Flaxman Sands and the Thomson Sands. The Flaxman
Sands was discovered in 1975 and is a conventional oil
reservoir. Although there are no public estimates of the total
amount, safe estimates of this reservoir are in the range of
several hundred million barrels. The Thomson Sands reservoir
contains large volumes of retrograde condensate, oil and natural
gas. He explained that a retrograde condensate field is under
very high pressure and most of the hydrocarbons are in a gaseous
state. But when those hydrocarbons are taken to the surface at
atmospheric pressure, much of it is liquids that tend to have
higher value sweet-like crudes.
Point Thomson nominally has gaseous state liquids along with
natural gas in place, and it also has liquid oil at the base of
the formation. He described it as a sandwich; the base beneath
the field is water, followed by oil, followed by condensate with
a little oil mixed in and natural gas mixed in the condensate.
The pressure is about 10,000 PSI, which is equivalent to about
five times the pressure of a scuba tank. This is good, but also
challenging. Because of the high pressure, the entire Point
Thomson field can be produced with perhaps 10 percent of the
wells it would take to produce a similar Alpine-type field. It
is technically feasible to cycle a field of this pressure.
Because it's a high pressure retrograde condensate field, the
way it's produced determines dramatically how much of the
hydrocarbons are recoverable. More than almost any other type of
field, this one is critically sensitive to the production, the
well, and facility design. It's important for the state to
understand the consequence of various production scenarios and
that some techniques bring in a lot more oil and liquids than
others, he said.
1:48:54 PM
SENATOR WIELECHOWSKI asked him to discuss the significance of
the Alaska Oil and Gas Conservation Commission (AOGCC)
classifying Point Thomson as an oil field rather than a gas
field.
MR. MYERS explained that the AOGCC by default calls Point
Thomson an oil field because of the amount of oil in the
liquids, and it will protect that field with respect to the
rules that relate to oil. That default ruling could change over
time and different rules would be applied to those pools.
SENATOR PASKVAN asked if the high price of oil relative to gas
was a reason to continue to classify Point Thomson as an oil
field.
MR. MYERS said the AOGCC is supposed to consider only physical
waste, but he presumes that the more valuable oil is the more
concerned the commission would be about loss of liquids and that
mechanisms that would strip gas rapidly and not produce oil to
the maximum should not be approved. He noted that he included in
the presentation two documents that were written by the AOGCC
chairman discussing how a condensate field works and supporting
the classification as a gas field. The article written in 2006
indicated some frustration that if the operators wanted to use
it as a gas field they should have approached the commission
earlier. Mr. Myers said the AOGCC believes as he does that there
is plenty of time to cycle the gas to produce the oil and
produce the gas at a later time.
1:54:08 PM
MR. MYERS reviewed the key findings of the 2008 PetroTel Inc.
study indicating that unless the Thomson Sands are developed
using full field gas cycling, the majority of the recoverable
condensate and oil will be wasted. The Department of Natural
Resources commissioned the study and provided the data. Over 70
full field model simulations were run using a range of values.
He explained the two major ways to produce a field. One is to
produce the field as a gas field in a process called blow down.
The second way is called full field cycling. The liquids are
stripped out after depressurizing and the gas re-injected to
keep the reservoir pressure up. A version of that is being done
at Prudhoe Bay in enhanced oil recovery using water alternating
with gas. He said the consequence of blowing down the reservoir
is that much (at least 50 percent and perhaps more) of the
condensate falls out of solution and is permanently locked in
the reservoir. Production is also lost when the gas drops out
into solution because it reduces the overall permeability of the
reservoir.
One model run indicates that with blow down only 26 percent of
the in place condensate is recovered, or 127-156 million stock
tank barrels (mmstb) of condensate. If the field is cycled for
20 years followed by blow down, 76 percent of the condensate is
recovered, or 370-450 mmstb. This is a difference of 50 percent
or 243-323 mmstb of additional liquids recovered. At today's oil
prices, saving 243 million barrels of condensate is equivalent
to more than half the value of the permanent fund.
MR. MYERS said PetroTel also modeled only 3-16 percent of the
oil or 30-150 mmstb of oil is produced in blowing down the
reservoir. By comparison, full field cycling for 20 years
followed by blow down produces 43 percent of the oil or 250-400
mmstb. This is a difference of about 200 mmstb of additional
oil. He said there are challenges to recovering the oil and
nobody knows how much can be recovered, but the scenarios run by
PetroTel indicate that 300-500 mmstb of additional oil are
recovered by cycling and most of the gas can be recovered 20
years later. How the Point Thomson reservoir is produced makes a
difference of billions of dollars to the state, and there are
also the challenges of physical and economic waste to consider.
1:59:50 PM
SENATOR PASKVAN recapped that he was advancing the notion that
gas should be re-injected into the Point Thomson reservoir for
the next 20 years to produce oil, and then the gas could be
extracted.
MR. MYERS said yes; that method is logical economically and
makes sense because there isn't a gasline. "In fact, in almost
any scenario I could draw up for a gasline, you have plenty of
time to cycle for 20 years before you're going to need Thomson
gas for a gasline."
2:01:08 PM
MR. MYERS discussed four reasons the state and the producer may
not agree on the method of production even if they agree on the
geology, engineering, technology and costs. First, cycling costs
more money up front, and in some cases the incremental oil
recovery might give a lower rate of return on the field.
CHAIR FRENCH talked about the specialized equipment and
associated challenges to cycle an extremely high pressure field.
MR. MYERS said another reason there may not be agreement is that
the lessee/producer bears much of the development and production
costs, although under ACES the state probably gives credit for
about 50 percent of the development costs in a field like Point
Thomson. Also, DNR has a mission and legal requirement as the
resource steward and regulator to protect the public interest,
promote conservation, and prevent the physical and economic
waste, primarily through 11 AAC 83.303(a).
He said one would generally assume that if cycling were feasible
and economic that the state would strongly argue for it. He said
he did that as director of oil and gas when he defaulted
ExxonMobil for failure to do the cycling project they committed
to do a year or two earlier.
MR. MYERS highlighted another potential reason for disagreement
on the method of production. The state of Alaska doesn't have
another option if it loses its resources, whereas a producer has
other investment options. It's not a criticism to recognize that
their economic interest is served at a higher rate of return and
that optionality is very valuable. Hypothetically, a company
that has other investments that have similar rates of return
might defer investment in Point Thomson because of not having a
market for the gas, but present the case that gas is the highest
use. The state logically wants development now, whereas the
lease holder with many options may choose to keep the option
value of the lease as the highest priority.
He said it's an important point that even given the same
technical information, economics and knowledge base, a producer
may have a different view than the state or any other subsurface
owner. There's only a partial alignment of interests.
2:05:18 PM
SENATOR PASKVAN summarized that the state risks permanent loss
of the oil resource if does not re-inject the gas, but if it
first cycles the gas for 20 years to produce the oil it can then
recover the gas.
MR. MYERS said that's right, but a small amount of gas is lost
because of the energy used to cycle. He added that full field
cycling was ExxonMobil's plan in 2001, and as oil and gas
director his perspective was that it made sense to see the
cycling come earlier.
He displayed a block diagram of the geology of the Point Thomson
area and directed attention to the lands on the east and central
side of the Thomson Sands reservoir that are delineated in the
settlement. The west side of the field is unknown and there's
only speculation as to how large it is.
2:07:42 PM
MR. MYERS said the Point Thomson Unit (PTU) was formed in 1977.
Eleven wells were drilled in 1979-1983 and no more were drilled
for a significant period of time. He said he was oil and gas
director in 2001 and ExxonMobil agreed through an expansion
agreement to test drill the western edge of the field and
commence development drilling by June 2006 or pay a $20 million
penalty. They were required to complete 7 development wells by
June 2008 or pay [$27 million in] damages and increased royalty
rates. The target of that production effort was about 75,000
barrels of condensate/day. It was a full field cycling project.
MR. MYERS said that in 2003 ExxonMobil decided it wouldn't
drill. When it was clear that there was no common ground and the
plan of development was unacceptable, he put the unit in default
in 2005. He confirmed the Chair's observation that the 7
development wells were never drilled.
In 2009 Commissioner Irwin agreed to reinstate 2 of 31 leases,
and ExxonMobil agreed to drill PTU 15 and PTU 16. He relayed
that Commissioner Irwin represents that ExxonMobil
unconditionally committed to drill the two wells by 2010. As
agreed, ExxonMobil drilled and tested the wells and began
permitting the pipeline to produce for a small scale cycling
project.
2:10:46 PM
He displayed ExxonMobil's 2008-2014 clear and committed timeline
for the Point Thomson project and the POD addressing DNR's
requests. He highlighted that the POD commits to three oil and
gas delineation wells and additional wells, and the timeline
indicates the delineation program drilling will be completed
[before mid-year 2012].
CHAIR FRENCH asked who prepared the slides.
MR. MYERS said the slides were prepared by ExxonMobil in late
2008. He reviewed the commitments through 2014.
2:11:48 PM
The Current Settlement
MR. MYERS described the current settlement as critical and
extraordinarily significant.
CHAIR FRENCH observed that the settlement springs from
litigation that essentially began when Mr. Myers put the unit in
default in 2005.
MR. MYERS said that's correct. Then Commissioner Menge confirmed
the decision and ExxonMobil appealed.
CHAIR FRENCH asked if it's fair to say that the 2012 settlement
represents the culmination of those 7 years.
MR. MYERS said he was the first to default, but he was in a long
line of frustrated oil and gas directors that wanted to see the
Point Thomson field developed.
He said it's important to note that many of the issues addressed
in the settlement are normally reserved for and resolved through
statute and regulations using established public processes.
However, the data that supports the decision making isn't
available so he can only interpret pieces in the settlement.
He reviewed some of the major issues in the settlement. First,
DNR is relinquishing its authority under 11 AAC 83.303(a) to
manage the unit for a significant period of time. All the
development options are at the sole discretion of the working
interest owners (WIO). In this settlement the state is not
determining whether blowing down the field is acceptable or
cycling it on a small scale is acceptable. Responding to a
question, he explained that ExxonMobil is the operator and the
WIOs are all the companies that own a partnership in the field
and are actually paying development costs.
2:15:23 PM
SENATOR COGHILL asked him to expand on the explanation of
relinquishing the authority to manage the unit.
MR. MYERS said a lot of the traditional processes that go
through the POD like the approval process, the unitization
process, the process of producing a participating area for
production are all either agreed to in the document or are at
the discretion of the producer, and DNR will not participate in
the process.
2:16:36 PM
SENATOR WIELECHOWSKI asked if he can envision any scenario where
it would be in the state's best interest or even constitutional
for the state to relinquish its authority to manage a unit.
MR. MYERS said, "Honestly, no." but a reason would be to get out
of the court case. The prevention of physical and economic
waste, appropriate development of a field, and protecting the
rights of all parties all require the state to have authority in
decision making as the subsurface owner. The lessee is obligated
to meet the terms of their lease and follow the statutes and
regulations. He said there's a natural tension, but in all cases
it's better for the state to manage according to statutes and
regulations.
SENATOR COGHILL asked if AOGCC retained its authority.
MR. MYERS said yes, but its authority is a little different
because it does not represent the state as subsurface owner.
SENATOR COGHILL said he just wanted to make sure the commission
wasn't out of the picture.
MR. MYERS added that under the settlement agreement, DNR
generally agrees not to oppose any proposal before the AOGCC
with the working interest owner.
SENATOR COGHILL asked if the POD is still in effect under the
settlement agreement.
MR. MYERS said there is a POD, but until about 2019 the
requirements are basically waived for most of the critical
issues generally regulated under the plan. He continued to say
that other pieces in the settlement relate to the typical
conditions under which the state gets economic benefit from its
oil and gas. One of the options is for the DNR commissioner to
take gas in kind rather than in value. This is unusual. Normally
there is a finding, a public process, and Royalty Board approval
for a royalty in kind sale. The Alaska Stranded Gas Development
Act (ASGDA) had language to do this, but it would have gone
through the legislative approval process.
2:21:15 PM
SENATOR WIELECHOWSKI questioned why that wouldn't be good.
CHAIR FRENCH asked for a layman's explanation of royalty in
value compared to royalty in kind.
MR. MYERS explained that the state has the right under its
leases to take its royalty share in value (money). There is a
complicated series of market baskets and settlements to
determine that value, and the state may pay tanker and pipeline
tariff structure costs on the oil, but it basically gets the
rough equivalent of what the producer sells the oil for.
Under royalty in kind the state assumes responsibility for its
royalty share of the oil as it leaves the unit. However, the
state historically hasn't taken physical possession of the oil,
electing instead to put a royalty sale forward for purchase of
its oil on the North Slope. Flint Hills, for example, has
purchased a huge amount of the state's oil on the North Slope,
thereby assuming the responsibility for shipping. There is a
very detailed and specific process including a finding and
acceptance by a Royalty Board in order for the state to do that.
And the state is required to get at least, if not more, value in
kind from the sale than if the oil was left in value.
MR. MYERS said one of the cases under the settlement agreement
is that the gas that's produced will be shipped to and cycled in
Prudhoe Bay. The state agrees to take the gas in kind even
though it really has no market for the gas, and it agrees to pay
field costs on that gas. He said he didn't know why that was
part of the agreement.
2:23:46 PM
SENATOR WIELECHOWSKI asked if this could conceivably cost the
state a lot of money.
MR. MYERS said the state agreed to take its gas in kind without
a market so a lot of valuation questions are without answers.
The state will own a lot of gas that's cycling in Prudhoe Bay,
and it will pay fuel costs on that gas. Whatever market the
state eventually has will depend on the pipeline that's built.
He relayed that when he was director of oil and gas he was very
constrained and careful in royalty sales to follow a formal
process that had Royalty Board blessing.
2:25:07 PM
SENATOR PASKVAN asked if taking gas in kind with no market would
expose the state to storage costs.
MR. MYERS said he didn't believe so, but the state has the
liability of owning the gas until it's sold, and it has field
cost obligations that have yet to be negotiated.
SENATOR COGHILL asked if the gas could be significant to
recovering oil at Prudhoe Bay.
MR. MYERS replied there certainly could be some gain, but the
countervailing argument is that there are lots of ways to
maintain pressure at Prudhoe Bay. He mentioned water flood, CO
2
injection, and increasing the cycling rate as alternative
mechanisms.
SENATOR COGHILL commented on its value along the Richardson
Highway corridor.
2:27:34 PM
MR. MYERS continued to highlight issues in the settlement. The
deferral of taxes on the gas injected into Prudhoe Bay is an
indication of how broad the settlement is. Also, there are a
number of options under which contraction of the unit is not
automatic if there is no drilling.
It is also highly unusual that there is no technical calculation
or review to figure out how much oil and gas is being
contributed from which lease. That allocation matters to the
state and producer because each lease has a different royalty
rate and lessees own different parts. The responsibility for
approving that tract allocation belongs to DNR, but the
agreement lets the producers make the call on at least the
initial participating area. This relates to plans of producing,
not to keeping the acreage.
2:30:22 PM
MR. MYERS questioned the validity term in the statement that
says the DNR commissioner has determined that the terms of the
agreement are necessary or advisable to protect the public
interest. This means that DNR has determined that whatever way
the producers decide to produce is in the best interest of the
state. This disregards the fact that the different production
mechanisms mean very different economics to the state.
SENATOR PASKVAN asked if that agreement has to be determined
valid under the settlement.
MR. MYERS replied the agreement is already made, even though the
three alternatives have very different outcomes to the state.
Another questionable provision is that DNR will not oppose an
application to the AOGCC to blow down the reservoir provided it
is consistent with applicable state law and the settlement
agreement, which says the highest and best use is to get a
gasline.
2:31:55 PM
MR. MYERS described the definition of "major gas sale" as
unusual and problematic, because 500 mcf/day is on the scale of
a bullet gasline. It is nine times less than the proposed AGIA
gasline and six times smaller than the proposed LNG projects.
Given the gas reserves at Prudhoe Bay, there's sufficient gas
for a 3 bcf line until 2040 and for a small line it's actually
2146. He questioned why the agreement is linked to Point Thomson
contributing to a major gas sale, and why the state used the
definition of such a small amount of gas relative to the scale
of gas that's already available at Prudhoe Bay.
SENATOR PASKVAN, referring to an earlier point, asked if the
settlement says that [DNR] wouldn't oppose [an application to]
blow down the Point Thomson reservoir despite the loss of
hundreds of millions of barrels of oil.
MR. MYERS affirmed that under the settlement DNR will not oppose
an application to the AOGCC that is consistent with the
agreement, which includes blow down, and follows state laws.
2:34:06 PM
SENATOR WIELECHOWSKI commented that DNR would say AOGCC is the
backstop to protect the state.
MR. MYERS said the statutes and regulations say that both
agencies have responsibilities that sometimes overlap, but DNR
has a wider mandate and a much more critical role and authority
for the development of the field in general. Because of the
economic interest responsibility, DNR also has a much broader
technical staff than the AOGCC. The AOGCC is a quasi-judicial
agency that was created in this and other states as an
independent party to equally protect the correlative rights of
all parties, because DNR is conflicted as landowner. The AOGCC
commissioners are appointed differently and have different
responsibilities. For example, DNR has no more standing in front
of the AOGCC than does ExxonMobil.
SENATOR WIELECHOWSKI drew an analogy between the court and the
quasi-judicial AOGCC with regard to protecting interests, and
observed that the settlement removes DNR from the role of
protecting the state's interest.
MR. MYERS responded that the AOGCC protects the public interest
the same way a court does, but that DNR has no more standing
before the AOGCC than does a private individual or company. By
comparison, the law provides a fair amount of deference to DNR
in terms of its responsibility as a subsurface owner and
regulator. The agencies also have different functions. DNR has a
stronger environmental role with respect to land management and
conservation, whereas the AOGCC has an important responsibility
with down hole safety. He spoke of balancing the parties'
correlative rights while still protecting the landowner.
2:38:45 PM
SENATOR COGHILL expressed interest in seeing where the agreement
supersedes statutory authority. He also questioned whether
removing gas from Point Thomson would blow down the reservoir or
if it was a reasonable amount.
MR. MYERS said at 500 mcf/day there is absolutely no need for
Point Thomson gas early on. At 3 bcf/day there would be need for
more mitigation, but there wouldn't really be challenges until
4500 mcf/day. At that point it would be reasonable to take 1
bcf/day from [Point Thomson] and 3500 mcf/day from Prudhoe Bay.
The old AOGCC rule allows 2 bcf/day from Prudhoe Bay, and the
settlement draws the line at one-fourth of that so it shouldn't
be a problem with the AOGCC.
2:41:39 PM
MR. MYERS displayed development options called Alternatives A,
B, C, and D and opined that there may be many other allowable
options because of the way the definitions and parts of the
settlement work together.
Alternative A defines "sanction" of a major gas sale as any
pipeline that has a volume greater than 500,000 mcf/day. It
doesn't require building it or even connecting the pipeline to
Point Thomson. A pipeline from Prudhoe Bay off the North Slope
qualifies as a major gas sale.
Alternative B is a cycling project that only requires 20,000 or
30,000 barrels per day depending on the type of compression used
in field. He said he believes the field is capable of much more
than that based on the reservoir studies and the previous work
done in 2001. He opined that this will result in the loss of oil
because there won't necessarily be production for 50-60 years
and because parts of the reservoir won't be reached. Full field
cycling costs more money, but there isn't an option for that.
[Alternative C is a cycling project for enhanced Prudhoe Bay oil
recovery and gas for in-state use.]
He said he believes that under Alternative D, if ExxonMobil
spends $2 billion they don't have to produce at all from Point
Thomson and can keep most of the acreage. If at a later date
they commit to study a cycling project or a major gas sale they
can keep basically all the acreage. Abandonment appears to be
permissible.
2:44:41 PM
MR. MYERS expressed surprise about the use of the terms "without
appeal." The settlement talks about losing acreage without
appeal, but paragraph 5.1.4 appears to allow appeal to the
superior or supreme court. He commented that the language in the
agreement appears to allow a tremendous amount of discretion.
2:45:30 PM
MR. MYERS provided the following summary points:
· None of the three development scenarios maximize economic
oil and gas recovery. They all could, and if produced will
lead to significant physical and economic waste of the
resource.
· The settlement provides several pathways that require
little or no actual production.
· The settlement removes DNR's authority to manage the field
through normal development procedures.
· Some of the settlement terms indicate fewer wells than
ExxonMobil seemed willing to drill previously.
· None of the contemplated gas pipelines will require gas
from Point Thomson for decades and, depending on the size
of the pipeline, it could be 120 years before it's needed.
Under any of the scenarios for an LNG project, the earliest
that Point Thomson gas would be needed is 2040, which means
that there is plenty of time for full field cycling.
· The royalty in kind provisions are inexplicable, and there
is no finding process.
· This is a major oil and gas decision of the decade, and it
was made without much public process. Given the breadth of
the issues and the normal use of public processes, it's
surprising what is contained in the settlement agreement.
· Damages were an integral part of the 2001 expansion
agreement. Monetary consequences at least compensate the
state for lost time and effort. Under the settlement, the
consequences and loss of acreages are either minimal or
nonexistent.
MR. MYERS concluded that it really does matter how Point Thomson
is produced, and the state ought to maintain a significant role
in that determination rather than leaving it as an option for
the producer under a settlement.
2:47:36 PM
CHAIR FRENCH asked if he would have signed the deal if he had
been commissioner.
MR. MYERS said no, but he was not impugning the current
commissioner.
SENATOR PASKVAN asked if he believes the Point Thomson
settlement is in the best interest of the state of Alaska.
MR. MYERS said his stewardship belief is strong and he wants the
oil to be developed in a way that would allow his kids to see
the benefit of the state developing its resources to the maximum
benefit to the people. He acknowledged there is a counter
argument, but he would have done more reservoir simulations, a
full field economic model, and made a determination that the
rate of return on the cycling project was reasonable. If it
wasn't reasonable but there was economic value, he would have
entertained options for royalty relief. He would also have
sought development beyond what Commissioner Irwin secured under
the lease agreement, and he would have looked for something more
akin to the previous agreements.
2:50:33 PM
SENATOR WIELECHOWSKI asked for an estimate of what it would cost
the state if ExxonMobil were to choose to blow down the
reservoir as opposed to full field cycling.
MR. MYERS replied he didn't have a number, and then talked about
what factors would go into the calculation.
SENATOR WIELECHOWSKI asked if the state could potentially lose
$12 billion.
MR. MYERS suggested that DNR or DOR might be able to do those
calculations but the numbers are staggering in scale because of
the size of the field and value of oil. He also mentioned the
value of the alignment agreement and the value of the Brookian
section, both of which could be significant.
2:54:10 PM
CHAIR FRENCH recessed the meeting.
3:01:50 PM
CHAIR FRENCH reconvened the meeting and recognized Craig
Richards as the next presenter.
^Walker Reconsideration Point Thomson Settlement
3:02:11 PM
CRAIG RICHARDS, Attorney, Anchorage, AK, said he represents Bill
Walker in an appeal filed on April 17, 2012 that asked
Commissioner Sullivan to reconsider his decision to enter into
the Point Thomson settlement agreement.
CHAIR FRENCH asked when he first learned about the settlement
agreement.
MR. RICHARDS replied he learned about it on March 30, 2012, when
it was announced in a press conference held by the commissioner
and governor.
CHAIR FRENCH asked if he had knowledge of the negotiations
before that time.
MR. RICHARDS replied he saw suggestions in the news that the
parties were working on a deal over the last year or so, and
that there was a rush in late March to meet the deadline the
governor set in his State of the State Address. He said he
wasn't privy to any of the specifics.
CHAIR FRENCH asked what happened after the settlement was
announced.
MR. RICHARDS said he and Mr. Walker read the agreement several
times, and with each subsequent reading more red flags were
raised. Mr. Walker ultimately decided that the deal had to be
appealed. Because of the 20-day appeal deadline, Mr. Walker's
appeal was about the last chance to keep the issue alive to
create some public process.
MR. RICHARDS said he would focus on why he believes the
settlement is illegal and how it exceeds the commissioner and
attorney general's authority to enter into. He would address
some of the specific terms of the deal in order to discuss
concerns about its legality. He acknowledged that his reading of
some or all of the provisions and their intent may be incorrect.
He stated that as an attorney he found the document to be
confusing and difficult to understand, because it is complex and
in many instances it is not clear on its face. For example, the
recitals do not fully reflect the substance of the deal. In
particular, Section 1.6 talks about the Initial Production
System (IPS) that appears to commit to [produce approximately]
10,000 barrels per day [of condensate.] But subsequent readings
make it clear that other paths provide that the unit can be
maintained where no development occurs. He described the
recitals as a rosy version of the agreement.
3:05:48 PM
CHAIR FRENCH asked if the settlement agreement trumps the
operating language in the recitals.
MR. RICHARDS responded that the more specific will control the
general in most instances.
CHAIR FRENCH asked if the normal expectation is that the
recitals would conform to the agreement.
MR. RICHARDS said yes or you would expect to see them used
differently. It's common for recitals to be a description of the
background without a summary of the deal. In this case the
recitals had both background and light summaries of what the
deal contemplated. This isn't generally done because it causes
conflict between the recital and the substance of the deal.
He said another concern with the drafting of the settlement
document is lack clarity. For example, if ExxonMobil chooses to
meet one option of work commitments with the 10,000 barrel per
day project, a major point is whether or not they spend $2
billion. If they spend $2 billion they get to keep a portion of
22 leases no matter what, whereas if they spend less than $2
billion they get less acreage. But the $2 billion is defined as
backdated to 2007, so it's unclear whether or not that threshold
was already met. The spending commitment doesn't have accounting
rules and is defined so broadly that previous work done on a
major gasline or bullet line or Prudhoe Bay re-injection project
could conceivably count toward that $2 billion. Because of the
lack of clarity he assumes that the $2 billion threshold is met
as a matter of course.
MR. RICHARDS said a final drafting concern relates to some of
the definitions in the document. The largest concern is that the
definition of a "major gas sale" is not the definition that is
commonly understood and used in the industry in Alaska. The
document defines a major gas sale as greater than 500 mcf/day,
whereas the Prudhoe Bay operating agreement defines a major gas
sale as 2 bcf/day. He described the change as a head scratcher.
He said the magnitude of the deal is sweeping in terms of what
it attempts to do and the value of the resources. Point Thomson
is one of the largest undeveloped oil and gas fields in the
world and the leases are some of the most valuable undeveloped
leases in North America, if not the world.
3:10:49 PM
MR. RICHARDS said he considered ExxonMobil's history of delaying
development and decided to look for the paths through the
agreement that allow the options to do the least. The first is
to undertake the 10,000 barrel/day IPS Project that ExxonMobil
agreed to in 2009 to maintain 2 leases. If they undertake that
project and spend $2 billion, they retain most of the unit. They
will get an additional 20 leases for no additional work
commitments in one of the richest oil and gas fields in the
world. Because of that 10,000 barrels/day production, ExxonMobil
and the other WIOs will own the unit in perpetuity with
virtually no additional work commitments.
The other path of least resistance option is to sanction a major
gas sale. He said his reading of that is that there has to be a
major gas sale of more than 500 mcf/day and there has to be
sanctioning. Sanction is defined in the context of a major gas
sale, but it's not a firm definition and doesn't have the
requirements he would expect to see. For example, internal
commitments have to be in place but it's not clear whether they
can be revocable. Also, there is no clarity as to the timing of
the commitments. He opined that the only part of the definition
of "sanction" that has teeth is the federal permitting
requirement. If they federally permit for a major gas sale,
they've met the obligations with no work (without the 10,000
barrels/day) to maintain the unit through 2020 and restart the
POD process back to 2005. Although the new POD process is less
favorable to the state.
He said the last point is that there doesn't have to be
production out of Point Thomson. A bullet line permitted to
Prudhoe Bay with no connecting infrastructure between Prudhoe
Bay and Point Thomson meets the requirements to maintain the
unit and restarts the POD process through 2020. He noted that
this was Mr. Myer's reading as well.
3:14:27 PM
MR. RICHARDS said this deal pre-commits the state to allowing
the WIOs to choose between a number of options to develop the
field in the future. The state has pre-committed itself to lease
dispositions, field development terms, and royalty and tax
commercial terms under various development scenarios. He said
his personal opinion is that the agreement is inconsistent with
Alaska law in a number of ways.
He said the first legal concern is lack of public notice and
comment. Art. IIX, sec. 10 of the Alaska Constitution provides
that the state may not dispose of leasehold interests without
public notice and the opportunity to comment. The Alaska Supreme
Court in the Baxley case indicated that DNR could renegotiate
terms of oil and gas leases in confidence and still meet the
public notice clause of the constitution, because of legislative
approval after the fact. He opined that renegotiating lease
terms and dispositions with no public comment or legislative
approval is extremely problematic under Alaska law.
3:16:09 PM
MR. RICHARDS said what past deals with British Petroleum,
ExxonMobil and Conoco Phillips have in common is the massive
public process and grinding debate about what is in the state's
best interests versus the producer's best interests. Then there
is either administrative or legislative action to get to
resolution. He cited the North Star leases and Baxley as
examples and opined that it was the legislative approval that
made the agreements legally binding on the state.
He expressed particular concern with the way this agreement was
made public and the associated multi-year litigation dismissed.
As far as he can tell based on the clerk's stamp and records
filed with the clerk, this settlement agreement was entered into
by the attorney general on March 28th and all the other parties
by March 29th. It was filed with the superior court at 3:20 p.m.
on March 29th and the settlement agreement was approved and the
case dismissed by 4:30 p.m. that same day.
3:19:01 PM
CHAIR FRENCH asked if he was saying it was agreed to within 60
minutes of its filing.
MR. RICHARDS replied, "Based upon the stamp of the clerk it does
appear that superior court Judge Brian Clark had this agreement
before him for less than an hour, assuming he approved it by the
close of business at 4:30. It's possible he approved it late ...
but in less than a day and it looks like maybe less than an hour
this was, in secret, brought to the court, all the cases
dismissed, and the deal announced the next day." He questioned
why the Point Thomson litigation would be dismissed before the
public had an opportunity to review the settlement. He suggested
the administration should answer that question.
MR. RICHARDS said the second legal concern is that there are
established processes for the state pre-committing to waiving
its right to take royalty in value and there are processes for
disposing of royalty in kind. To forgo royalty in value for a
long period of time for this large amount of gas and to so
heavily encumber the royalty in kind rights it seems clear it
would require Royalty Board and legislative approval.
CHAIR FRENCH asked him to remind the committee who the Royalty
Board is.
MR. RICHARDS explained that it's a board that was specifically
created to make sure that the state doesn't enter into a royalty
contract without a form of public process.
He said the third legal concern is that this is a DNR agreement
that encompasses tax issues yet the DOR commissioner has not
signed the document. Another provision says that production from
Point Thomson that is re-injected into Prudhoe Bay won't be
assessed the ACES severance tax until it is produced out of
Prudhoe Bay. It also provides in express terms that the state
won't tax that gas twice. The issue is that Art. IX, sec. 1 of
the Alaska Constitution prohibits contracting away the power to
tax. He noted that in 2006 some cited that as the fundamental
constitutional problem with the Stranded Gas Development Act. It
contracted away the power to tax.
The fourth legal issue with the agreement is that DNR is
forgoing its regulatory oversight function under 11 AAC 83.303.
The settlement allows the WIOs to decide the future course of
development for the field without public interest findings. He
noted that the Walker appeal letter lists, on pages 11-13, some
of the areas where regulatory authority was abrogated, and an
alternative process put in place by contract.
He said the core concept is that before many unit actions can
occur it's necessary to get the commissioner's stamp of
approval, and for many of those things the need for the stamp is
gone. From a legal perspective, that's probably one of the
biggest problems the settlement agreement has, he said.
3:25:39 PM
MR. RICHARDS said ExxonMobil has long argued that the state by
contract can change the department's regulatory obligations, but
the Alaska Supreme Court disagreed. He read excerpts from the
2001 ExxonMobil case that said the department should never need
to contract in violation of its own regulations because it has
the authority to change its regulations so long as the new ones
have a reasonable basis and are within the scope of the
Legislature's delegation of powers to the department.
He said he doesn't understand, given the explicit instruction
from the Alaska Supreme Court in the context of the unit
regulations, how many of the provisions that pervade through the
settlement agreement are legal.
MR. RICHARDS said the next area of legal concern relates to the
provision in paragraph 4.9 that says that within 90 days of the
effective date, the commissioner preapproves any changes in the
WIO alignment. He said it appears to have the practical effect
of preapproving the rumored but yet to be announced transfer of
Chevron's interest in Point Thomson. That's problematic for a
number of reasons the first of which is that major realignments
of lease sales within units have a public consequence and it's
been held a number times that department approval is necessary.
He cited the resolution of BP's attempt to acquire Arco Alaska
as an example of the concept that unit realignments have to be
approved by the commissioner.
He questioned the authority of the commissioner to pre-agree
without having seen the agreements and without having done best
interest findings to ExxonMobil, Conoco Phillips, or BP's
acquisition of Chevron, if that has in fact occurred.
3:29:12 PM
MR. RICHARDS said the last major legal concern is that this deal
abrogates regulatory authority and probably exceeds the current
legal authority of the commissioner so it needs to be approved
by the Legislature. He cited the Baxley case and the Alaska
Stranded Gas Development Act (ASGDA) as evidence. In Baxley the
saving grace for the BP in-state deal was legislative approval
and the process that went along with it. One chapter in the
ASGDA contract was the maintenance of Point Thomson and while it
didn't succeed there it appears that similar goals have been
reached through this settlement agreement.
MR. RICHARDS reviewed the attorney general's April 26, 2012 that
disagreed with his and Mr. Walker's interpretation of the
settlement agreement. The attorney general said paragraph 5.8 of
the agreement constitutes public interest findings and because
it's a settlement agreement those public interest findings are
not appealable. Mr. Richards said this agreement was negotiated
and the court cases dismissed before the deal was made public.
There are preapprovals and changes in regulations for a decade
to come, and it appears that it is not appealable by the public.
"As an Alaskan citizen, I am concerned about the lack of public
process," he stated.
3:32:55 PM
SENATOR WIELECHOWSKI asked if the executive branch has the
authority to agree to waive its statutory obligations in a
settlement agreement.
MR. RICHARDS said he didn't believe so. He offered the caveat
that his critique was not aimed at any one individual and that
he was an outsider with no financial interest in the deal. His
hope was to shine light on the process and outcome so that an
inquiry would be done to determine whether or not the deal is
legal, and if it is legal whether it's in the best interest of
Alaskans.
Recess from 3:34 p.m. to 3:39 p.m.
^Attorney General Michael Geraghty
CHAIR FRENCH reconvened the meeting and introduced Attorney
General Geraghty.
3:40:00 PM
MICHAEL C. GERAGHTY, Attorney General, Department of Law (DOL),
said he appreciates the opportunity to comment on the previous
testimony and would like to submit a more complete written
response.
CHAIR FRENCH assured him that his written comments would be
distributed to both the committee and the public.
ATTORNEY GENERAL GERAGHTY stated the following:
The authority of the attorney general to settle
litigation involving the state is plenary. The Alaska
Supreme Court addresses the issue in 1975. "Under the
common law an attorney general is empowered to bring
any action which he thinks necessary to protect the
public interest, and he possesses the corollary power
to make any disposition of the state's litigation
which he thinks best. This discretionary control over
the legal business of the state, both civil and
criminal, includes the initiation, prosecution and
disposition of cases. When an act is committed to
executive discretion, the exercise of that discretion
within constitutional bounds is not subject to the
control or review of the courts. To interfere with
that discretion would be a violation of the doctrine
of separation of powers."
This view has been reiterated and applied in a number
of cases and a number of attorney general opinions
since 1975. Those opinions point out that depending on
the circumstances, the decision to compromise or
settle a case is often a collaborative effort with the
affected executive branch agency. For example, in 1996
an opinion by the attorney general advised the then
commissioner of revenue Wilson Condon about the
compromise of taxes assessed against several operators
at Prudhoe Bay. Among other things, the opinion noted
that it is not "appropriate to articulate a static
standard of review for the attorney general to review
of a department recommendation to compromise a tax
assessment. Each individual compromise will vary in
many salient factors, including the degree to which
the compromise involves questions of law, policy, and
fact. The effect on the public interest, including the
dollar amount at issue and the effect on future tax
collections and the level of analysis which the
department has applied in arriving at its
recommendation are all considerations. The presence or
absence of these factors will determine whether the
attorney general's review should be more independent
or more deferential."
Later in that same opinion (opinion number 5 issued in
1996), it was noted that "As the current commissioner
of revenue you are extraordinarily well versed in the
legislative history or the statutes in question. It
would be foolish to adhere to judicial notions of
standards of review and independently review a matter
which you possess special expertise merely because the
matter could technically be classified as legal rather
than policy. Because we are both members of the
executive branch, I believe that I can choose to defer
to you on this legal question without compromising my
duty to protect the public interest."
3:43:47 PM
ATTORNEY GENERAL GERAGHTY stated that it was his opinion that
the Point Thomson litigation was a major impediment to the
commercialization of Alaska's natural gas. The settlement
achieved things the state sought in the POD process like firm
deadlines and commitments for the development of the Point
Thomson unit (PTU) and consequences to the owner if those
commitments aren't met. Many of the consequences upon breach are
automatic and without any right of appeal. The settlement also
lays to rest the argument advanced by the operators that
development of the field is not economic without a major
gasline. Acknowledging that many obstacles and issues remain, he
opined that any progress would have been impossible until the
issue of the ownership of the leases and the timely development
of the unit was established.
3:47:11 PM
ATTORNEY GENERAL GERAGHTY disputed some of the statements made
in previous testimony, the first of which was that someone else
would have negotiated a better deal. Also, the negotiations were
not a secret. In fact, he was informed that Commissioner
Sullivan briefed at least one committee. He also disagreed that
the Baxley case and the ExxonMobil case apply. None of the facts
support the claim of alleged violations of law and no other
cases were cited in the request for reconsideration. A lot was
said about unconstitutional disposal of state lands, but it was
unclear what interest in lands was being referred to because the
Point Thomson leases were sold 30 years ago. Mr. Myers did
terminate the leases in 2005, but by hanging on ExxonMobil
arguably never lost those leases. He maintained that there was
no disposal of state lands. There were modifications to PODs and
participating areas, but that does not require legislative
approval. He said the foregoing points out some of the
fundamental flaws in the previous analyses.
3:52:05 PM
ATTORNEY GENERAL GERAGHTY directed attention to the 2005 amended
decision (tab 7), and highlighted the use of the terms "may" and
"theoretically" in the explanation of the findings under
"Promote the Prevention of Economic and Physical Waste." He said
he would defer to the DNR representatives on some of the points,
but he had difficulty reading Mr. Myers' findings with some of
the sweeping statements and conclusions he was arriving at in
his testimony today.
He read from the Walker appeal on page 10, paragraph 7 titled
"Terms of Taxation on Injected Gas Are Established by Contract."
He said it's silly to say that paragraph 4.16 of the settlement
"attempts to establish terms of future taxation by contract." He
urged the committee to consider everything else that was said
today in the context of that comment because it's emblematic of
the entire analysis.
ATTORNEY GENERAL GERAGHTY asked for the opportunity to submit
more complete comments in writing.
CHAIR FRENCH said it was a fair request that would be honored.
3:57:23 PM
SENATOR PASKVAN said he had two basic questions. The first was
why the state would agree to take royalty in kind rather than
royalty in value. The second was why the agreement removes the
DNR commissioner's ability to oppose any proposal before the
AOGCC.
ATTORNEY GENERAL GERAGHTY said he would defer to the DNR
representatives on the royalty in kind issue, and his
understanding regarding AOGCC is that DNR's right to protest is
not forfeit if something is occurring that is inconsistent with
state law.
SENATOR PASKVAN asked about the procedural posture of the case
in light of the comment that there would be a remand one way or
the other. His understanding was that the case was settled.
ATTORNEY GENERAL GERAGHTY replied he meant to say that if there
was no settlement there would be a remand and the litigation
cycle would go on for an undetermined period of time.
CHAIR FRENCH clarified for the listening public that there would
be no remand; this case was settled.
ATTORNEY GENERAL GERAGHTY said his intention was to compare
where the state would be if it hadn't settled, and to highlight
that overwhelming uncertainty is a reason to settle a case. Each
party negotiates the best deal possible.
4:01:33 PM
SENATOR PASKVAN asked why the agreement changes the customary
definition of a "major gas sale" from 2 bcf/day to 500 mcf/day,
and how that connects to Point Thomson.
ATTORNEY GENERAL GERAGHTY deferred to the DNR representatives.
SENATOR WIELECHOWSKI referred to the comment about briefings and
relayed that his office contacted Commissioner Sullivan six
times within a three month period to get a confidential briefing
on Point Thomson, all to no avail. He asked if it was accurate
that the settlement agreement was approved by the court within
an hour of the filing. He also asked why the Legislature wasn't
briefed given the high level of interest and promise of
confidential briefings.
4:05:39 PM
ATTORNEY GENERAL GERAGHTY replied the dismissal of the case and
the post settlement motions were handled by outside counsel, and
he wasn't involved. He deferred to Commissioner Sullivan about
the briefings beyond the fact that he did tell the committee
that the negotiations were going on. He opined that it was with
good reason that the framers of the constitution did not have
the Legislature sign off on settlements. He said he respects the
Legislature's oversight role, but he's never been a fan of
trying to negotiate something in public.
4:08:04 PM
CHAIR FRENCH relayed that he received a letter from Commissioner
Sullivan expressing deep regret at not being able to attend the
hearing today. He said he knows that the commissioner is a
passionate advocate of the Point Thomson settlement agreement
and would like nothing more than to defend it before the
committee.
SENATOR WIELECHOWSKI cited AS 38.06.055 and questioned why the
state agreed to take its royalty in kind without approval by the
Royalty Board and the Legislature.
ATTORNEY GENERAL GERAGHTY said there has been no delivery of
royalty in kind gas, but he would defer to the DNR
representatives for further comment.
SENATOR WIELECHOWSKI cited ll AAC 83.303(a) and asked if giving
development decisions to the WIOs and removing the ability of
DNR to appeal to AOGCC adheres to that regulation.
ATTORNEY GENERAL GERAGHTY said yes; AOGCC has lost none of its
authority to prevent waste from occurring and DNR has not given
up the ability to participate if what is at issue is contrary to
law. Mr. Myers' opinion in 2005 regarding the waste scenario was
speculative.
SENATOR WIELECHOWSKI cited paragraph 5.7 of the settlement
agreement and expressed hope that the AG's interpretation was
that 11 AAC 83.303(a) does apply and DNR could oppose an
application to the AOGCC if there was waste.
ATTORNEY GENERAL GERAGHTY said there are two qualifications to
DNR not participating. One is that what is under consideration
is consistent with the agreement, and the other is that it is
consistent with applicable state law.
SENATOR WIELECHOWSKI expressed hope that all the parties agree
with that interpretation.
4:13:35 PM
SENATOR COGHILL asked for confirmation that keeping the leases
was dependent on completing the POD.
ATTORNEY GENERAL GERAGHTY deferred the question to the DNR
representatives.
CHAIR FRENCH read excerpts of paragraph 5.1.4 on page 52 of the
settlement agreement. He asked if he would agree that the state
might be litigating whether or not $2 billion had been spent or
other factual matters relating to the development of the terms
of the settlement agreement.
ATTORNEY GENERAL GERAGHTY said he would agree that some
potential breaches of the agreement would allow either party to
go to arbitration.
CHAIR FRENCH thanked him for appearing on short notice and
recognized the DNR representatives.
^Department of Natural Resources (DNR)
4:16:26 PM
JOE BALASH, Deputy Commissioner, Department of Natural Resources
(DNR), relayed that he was appearing in place of Commissioner
Sullivan because of the slight possibility that an issue raised
by Mr. Richards may be remanded to him by a judge. He explained
that his role in the policy debate dates back to 2005 when he
worked as legislative staff. In 2006 he transitioned into the
governor's office as a member of the gas team, and in 2010 he
moved into a decision-making position of as deputy commissioner
of DNR.
He emphasized that he supported every decision leading up to the
settlement and without reservation he supports the settlement as
in the state's interest.
4:17:16 PM
JON KATCHEN, Inter-governmental Coordinator, Department of
Natural Resources (DNR), stated that when he joined the
Department of Law (DOL) in 2007 he was assigned to the Point
Thomson matters of litigation. In 2010 he transferred with
Commissioner Sullivan to DNR and continued to be involved in the
settlement negotiations.
4:17:53 PM
MR. BALASH explained that he would use some of the slides from
the PowerPoint presentation that Commissioner Sullivan delivered
several weeks ago for illustrative purposes. He described the
presentation format. First he would discuss the structure of the
agreement, how it works and protects the state's interests. Next
he would talk about the technical plan embedded within the
agreement and how it will assist all parties in identifying the
optimal path for development. Finally he would speak about the
state's interests, why settlement of the litigation is in the
state's interest and why this settlement agreement in particular
is in the state's interests.
4:20:24 PM
MR. BALASH stated that the overarching structure and fundamental
premise embedded within the agreement is that this is the
state's land the lessees are obligated to explore, develop and
ultimately produce the field. If the field isn't put into
production the state gets the land back. This is without appeal,
even if they spend $2 billion. The operators have to undertake
certain activities to earn back portions of the leases and
retain title.
He described the agreement as a series of commitments,
timelines, and agreed-upon consequences for failure. These are
clearly spelled out and various scenarios are identified within
the agreement to make clear the understanding at the time the
agreement was settled. The agreement has three basic stages
through the end of this decade. The initial production phase
runs from now until the end of 2015, and if there is no initial
production system (IPS) or production or sanction of a major gas
sale, everything returns to the state without appeal. The second
stage, which occurs between 2016 and 2019, is the period during
which the operator and the other WIOs will develop plans to put
the field into further production. That timeframe includes a
commitment to submit a POD and produce the Brookian oil in the
unit. If there is no approved POD by 2018, that particular
acreage returns to the state.
4:23:01 PM
MR. BALASH displayed a block map of the PTU and explained that
the Brookian Unit is located in Area F. Mr. Katchen volunteered
that the block map is Exhibit D in the settlement agreement.
CHAIR FRENCH asked for an explanation of the provision on page
18, paragraph 4.2.2.3 of the settlement agreement, and why year
2007 was selected.
If the WIOs Abandon the IPS Project and have incurred
costs for Point Thomson Development during the period
between year-end 2007 and year-end 2015 of $2 billion
or more, then only acreage listed in Area E and Area F
on Exhibit C shall be released to the State Without
Appeal at year-end 2015.
MR. BALASH said the intention is for there to be immediate
consequences in year 2015 if the IPS is abandoned.
CHAIR FRENCH observed that the WIOs only lose Area E and Area F,
not the entire unit.
MR. BALASH said that's correct, but if there is no additional
work on the field or it's not put into production another way or
if none of the other remedies are undertaken, the state gets it
all back in 2019.
MR. KATCHEN said the decision was that they were entitled to
earn some acreage for a temporary period but if the WIOs abandon
the IPS Project, what the state will get back without appeal is
at least Area E and Area F in 2015.
CHAIR FRENCH commented that the assumption is that they agree
with DNR's definition of "abandoned the IPS Project" and the
amount of money spent.
MR. KATCHEN responded that the state will get back Area E and
Area F even if they spend $2 billion. He said another point that
both Mr. Myers and Mr. Richards raised is that they don't really
lose acreage if a major gas sale is sanctioned in 2016, 2017 or
2018, but the language in paragraph 4.5.7 on page 29 of the
agreement is unequivocal. Any acreage that contracts from the
PTU under the abandonment provision shall not be recommitted to
the PTU.
CHAIR FRENCH asked the meaning of "recommitted" in that context.
MR. KATCHEN replied it means the acreage is gone and there's no
way to get it back into the unit. He disagreed with the
characterization that the abandonment provision is illusory and
that the acreage comes back with the sanction of a major gas
sale.
SENATOR WIELECHOWSKI reviewed the consequences of abandonment
provisions in paragraphs 4.2.2.1-4.2.2.3 that include the $2
billion spending requirement. He asked how much the WIOs have
spent to date.
MR. KATCHEN said the amount that's been mentioned publicly is
about $1 billion. Responding to Senator French's earlier
question about why cost accounting for the $2 billion threshold
starts in 2007, he explained that's when the WIOs started work
on the IPS Project.
SENATOR WIELECHOWSKI asked how he would define "have incurred
costs."
4:28:45 PM
MR. KATCHEN replied DNR's understanding is that those are
development costs at Point Thomson that are submitted to the
other working interest owners of the field.
SENATOR WIELECHOWSKI asked if that definition was included in
the settlement agreement.
MR. KATCHEN replied paragraph 4.2.2.4 has to be read together
with the definition of Point Thomson development to understand
what costs can be claimed for the $2 billion expenditure.
MR. BALASH said year 2019 and beyond is the final or reckoning
stage when DNR can begin to settle out the acreage that will
contract out of the unit. At that point DNR will know what the
WIOs have or have not done or committed to financially and
contractually.
4:31:50 PM
MR. BALASH said the foundation of the settlement agreement is
the initial production system (IPS), and the technical plan
embedded within the agreement itself is essentially what was
proposed in POD number 23 that was rejected in 2008 by then
Commissioner Irwin. His primary concern was how he would know
that the operator would actually drill the wells and put in the
facilities and pipeline and start cycling 200 mcf/day and yield
10,000 barrels/day of condensate. He wasn't confident that would
actually take place. He was also concerned about what would
happen after the IPS was put into production because it wasn't
clear that the size or method of cycling was going to be
optimal. His assessment was that the IPS was the right technical
approach to understanding the field and how it was going to
perform. The AOGCC reservoir engineer commissioner, Cathy
Forester, concurred with his assessment.
4:34:47 PM
MR. BALASH said that when Mr. Myers highlighted the work done in
2008 by PetroTel, he put the committee's attention on a study
that did not take into account economic or physical constraints.
SENATOR PASKVAN asked Mr. Balash precisely what he means by
"economic constraints" because he was concerned about the
potential loss of the oil resource by an earlier as opposed to
later blow down of the reservoir.
MR. BALASH said he was referring to the costs of drilling wells
and installing facilities without year-around road access as
well as the cash flows induced by the ultimate production and
recovery of the hydrocarbons. He relayed that DNR was granted
access to ExxonMobil's confidential data room subsequent to the
2008 study and that caused both DNR and PetroTel to change their
conclusion about the loss of liquids.
4:38:45 PM
SENATOR PASKVAN questioned how economic constraints factor in
the issue of putting oil at risk.
MR. BALASH said the operator and the working interest owners
will have to satisfactorily demonstrate to both DNR and AOGCC
that ultimate liquid recovery is not being wasted.
MR. BALASH said the settlement agreement clearly and directly
addresses the two primary concerns Commissioner Irwin
articulated when he rejected POD number 23. A binding
contractual obligation for the WIOs to follow through on the IPS
schedule is embedded as an exhibit within the agreement, and can
be used in the event there is a disagreement as to whether or
not the WIOs are pursuing the project diligently and
expeditiously.
CHAIR FRENCH read the definition of IPS on page 8 of the
agreement.
"Initial Production System" or "IPS" means the gas
cycling facilities designed with capacity to produce
and re-inject (cycle) 200 million cubic feet of gas
per day utilizing reciprocal compression and with the
objective of a minimum of 10,000 barrels per day of
condensate for delivery into the Trans Alaska Pipeline
System ("TAPS").
He asked if that would be the minimum the state could expect to
get.
MR. BALASH said yes, but it's important to point out that while
there is a very real expectation that 200 mcf/day will result in
10,000 barrels/day of condensate recovery, there is no guarantee
and less recovery will not be a reason for declaring
abandonment.
CHAIR FRENCH asked about the potential circumstance of
recovering only 5,000 barrels/day of condensate.
MR. BALASH replied "that is going to tell us an awful lot about
how the field can be recovered."
CHAIR FRENCH said that wasn't the question.
MR. KATCHEN added that nobody thinks the yield will be just
5,000 barrels/day and if it only produces that amount there will
be serious questions about the viability of full field cycling.
But technically if they produce 200 mcf/day of gas, they're in
compliance with the agreement, he said.
4:43:56 PM
SENATOR PASKVAN mentioned an earlier description of the basin as
a layered sandwich with water at the bottom. He asked if the
agreement includes a requirement as to extraction points and if
location might make a difference as to quantities of liquids
that might be produced.
MR. KATCHEN said there is a requirement that they drill the two
wells from the Central Pad, which is close to Area A. Later the
contractual requirement is to drill the West Pad well, but there
is no requirement to bring that production to the Central Pad.
If there are problems with the two wells that are cycling the
gas, DNR's understanding is that they will be supplemented by
bringing Area B, the West Pad, into production.
There is no requirement as to specific locations to drill wells
for additional production, and everyone agrees that the real
focus is the Thomson Sands reservoir. As Mr. Myers testified,
there are real questions about the oil rim and its productivity.
SENATOR WIELECHOWSKI read an excerpt from paragraph 4.16.1 on
page 40 that exempts from taxation, gas that is injected at the
time of its production. He asked if the current law is that gas
is taxed when it's produced.
MR. BALASH explained that when gas is produced to the surface
and moved to another area of the state and injected for purposes
of enhanced oil recovery, it is not subject to production tax.
He said the agreement in this provision is that the sky is blue,
meaning that the current law will not be reinterpreted.
CHAIR FRENCH asked who would keep track if gas was pulled out of
a lease that has a 20 percent royalty and injected into a lease
that has a 12 percent royalty.
MR. BALASH said he'd talk about the royalty provisions shortly.
MR. KATCHEN added that ExxonMobil wanted it abundantly clear
that this is the law and it will apply to the gas and DNR
agreed, thus the sky is blue comment. He said the fear that the
agreement contracts away the right to taxation is misplaced.
4:51:06 PM
MR. BALASH discussed how the settlement agreement satisfies the
concerns with POD number 23. He said one of the more important
provisions related to the IPS stage is that the WIOs may not
rely on economic arguments for not pursuing the development of
the IPS. He said this was a big "gulp" for the operator and the
other WIOs because the costs will be significant on this
development.
MR. KATCHEN directed attention to paragraph 4.2.1 on page 17 of
the settlement agreement that in part says the "economics or
costs of the IPS Project cannot be used as a rationale or
justification for not completing the IPS Project." Mr. Myers
talked about the operator backing away in 2000-2001 because of
economics, but under this provision that is no longer an excuse.
4:53:06 PM
MR. BALASH explained that with the startup of the IPS the WIOs
earn Area A and Area B on the PTU block map. Start-up is a
defined term in the agreement and it means that hydrocarbons
have to go into the pipeline and make their way to Pump Station
One. Once there is production at Point Thomson the agreement
spells out that the WIOs will commit to additional production
under one of three alternatives.
MR. BALASH said Alternative A is the sanction of a major gas
sale. That is defined in the agreement as a project that
delivers more than 500 mcf/day of gas, but DNR believes it will
lead to something much higher. He explained that 500 mcf/day was
arrived at in the previous administration because it represented
100 percent more than the volume of gas that could be used in-
state for power and to heat homes. The idea is to develop an
export project to commercialize these resources, but a much
greater volume than 500 mcf/day of gas will be needed to satisfy
the demands of the three big companies.
4:57:41 PM
CHAIR FRENCH asked him to explain again, in the context of that
last sentence, why the number is so low.
MR. BALASH replied it's because it's an agreement with the WIOs
at Point Thomson who by themselves won't necessarily be the ones
to sanction a pipeline. It might be the state that sanctions a
pipeline and it was decided that 500 mcf/day is a threshold that
goes beyond anything the state is doing for itself, as an export
line.
CHAIR FRENCH commented that 500 mcf/day is half or one-fourth
the volume needed to make it economically viable.
MR. BALASH agreed and added that DNR anticipates there will
ultimately be a much larger project than that threshold.
4:59:43 PM
CHAIR FRENCH asked for assurance that the state doesn't pay for
a bullet line that gets ExxonMobil off the dime on Point
Thomson.
MR. BALASH said he finds it hard to believe that either this
Legislature or this administration would be party to letting
ExxonMobil and their WIOs off the hook in this agreement.
5:01:14 PM
MR. KATCHEN added that it misconstrues the agreement to say that
the producers don't have to do anything once they sanction a
major gas sale. The reality is that it is an express requirement
to then submit a POD and develop the gas. He cited paragraph 10
of the unit agreement and paragraphs 4.6 and 4.6.1 of the
settlement agreement as evidence.
5:02:27 PM
SENATOR WIELECHOWSKI expressed concern about giving ExxonMobil
the alternative to meet their commitments by what appears to be
a blow down of Point Thomson. He referenced slide 13 of the
presentation that describes Alternative A.
MR. KATCHEN interjected that the development alternatives come
after the IPS Project.
SENATOR WIELECHOWSKI questioned how it is that Point Thomson can
be so critical to the gas pipeline when DNR agreed that
ExxonMobil need only commit 500 million cubic feet/day to a gas
pipeline. He also asked if the settlement agreement allows
ExxonMobil to meet its commitments by taking 500 million cubic
feet/day of gas from Point Thomson and sending it in a small
diameter line to Prudhoe Bay for injection.
5:04:37 PM
MR. BALASH said to do that the WIOs would have to demonstrate to
DNR and the AOGCC that it would not waste liquids. If it happens
that Point Thomson gas is moved to Prudhoe Ban and injected, it
will be because the AOGCC ultimately determined that doing so
would result in greater liquid recovery on balance. He
reiterated that DNR retains the ability to appear before the
AOGCC to oppose an application by the WIOs if it does not meet
state law.
SENATOR WIELECHOWSKI asked if he agrees that under Alternative
A, "major gas sale" could be defined as a small diameter
pipeline from Point Thomson to Prudhoe Bay for the purpose of
enhanced recovery of oil from Prudhoe Bay.
5:06:25 PM
MR. KATCHEN said no; that development plan is more like
Alternative C. Alternative A is for a major gas sale off the
North Slope.
SENATOR WIELECHOWSKI asked if the AOGCC has ever allowed a cross
subsidization of one unit to another when it interpreted the
waste provision and requirement to get the maximum benefit for
the resource.
MR. BALASH said no, but DNR believes the AOGCC could take that
into consideration.
MR. KATCHEN added that it raises the question of do you look at
maximum recovery and benefit to the state from that individual
field or from the North Slope as an integrated whole.
5:08:11 PM
CHAIR FRENCH said the committee expects to get supplemental
testimony from DOL and because of time constraints DNR may elect
to submit written testimony as well.
MR. BALASH described Alternative B - expanded liquid production
into TAPS - as a "lip of the funnel" situation. It requires an
additional 20,000 barrels/day (30,000 bpd total) of condensate
recovery into TAPS. DNR believes that if the WIOs are going to
undertake the effort and expense to put the additional 20,000
barrels/day into the pipeline, they'll go well beyond that
volume. Whether they'll go as far as 70,000 barrels/day is yet
to be determined.
MR. BALASH discussed the important points of Alternative C -
expanded liquid production into TAPS, enhanced Prudhoe Bay
recovery, and gas for in-state use. He said the WIOs will have
to demonstrate the merits of this alternative to both DNR and
the AOGCC, including comprehensive information sharing with DNR.
With regard to the questions about the state taking its royalty
in kind rather than in value, he explained that if Point Thomson
gas is used for enhanced oil recovery at Prudhoe Bay its value
would be quite low. Rather than taking a very low value for the
gas at that time, the agreement was for the state to take the
gas in kind and retain the discretion to market that gas at its
choosing. DNR believes this is a benefit because for the first
time the state will be in a position to actively market a
significant volume of North Slope gas in and around the Prudhoe
Bay infrastructure.
5:14:59 PM
MR. KATCHEN added that it's ironic that this is being criticized
as being like the ASGDA, because the agreement establishes that
if there is a major gas sale the state may switch back and take
the royalty in value. He cited paragraph 4.16.2.2(b) on page 43
as evidence. He said another critical element is that the gas
will be available in 2019.
MR. BALASH said the commitment to Alternative C must take place
by year 2019, but the movement of gas from Point Thomson to
Prudhoe Bay will probably be a couple of years after that. The
agreement also obligates the WIOs to approximate the volume of
gas that would come over from Point Thomson if the state elects
to market it.
MR. KATCHEN pointed out that subsection (iii) on page 46 says
the state is not responsible for field costs for the RIK gas
delivered to the PTU, which is contrary to what Mr. Myers said.
Subsection (c)(i) on page 48 says the state may elect to take
its royalty share in kind or in value after a major gas sale.
5:20:01 PM
SENATOR WIELECHOWSKI asked for further explanation because the
last sentence on page 46 says the state will be responsible for
field costs for Point Thomson gas produced after project start-
up of a major gas sale.
MR. KATCHEN said that provision only triggers if and when there
is a major gas sale.
SENATOR PASKVAN asked if the decision as to a small diameter
pipeline or a large diameter pipeline will not be made until
2019.
MR. BALASH replied the decision on what project to sanction and
the decision on development of an LNG project to tidewater could
reasonably be made in late 2015.
SENATOR PASKVAN commented that anything the Legislature might do
between now and year-end 2015 potentially impedes the decision
under the settlement agreement for when a major gas sale would
occur.
MR. BALASH said if anybody sanctions a major gas sale between
now and 2019, the WIOs are required to produce a POD for the
development of Point Thomson.
MR. KATCHEN added that if full field cycling is viable and
concurrently there is sanction of a major gas sale, the WIOs can
still do full field cycling. They aren't required to produce the
gas. Also, the volume has to be more than 500 million cubic
feet.
5:24:26 PM
SENATOR PASKVAN asked if a major gas sale off the North Slope,
whether it's a small or large diameter pipeline, is a decision
that will be made by the WIOs between late 2015 and 2019.
MR. BALASH replied it could be but it doesn't have to be.
SENATOR PASKVAN asked if the WIOs will make the decision.
MR. BALASH replied anybody can sanction a major gas sale, but it
will depend on their ability to attract gas or customers to fill
that pipeline.
5:25:36 PM
SENATOR PASKVAN asked if a decision tomorrow to build an in-
state gas pipeline from Prudhoe Bay going south would conflict
with this settlement agreement.
MR. BALASH replied the state could sanction a pipeline under the
terms of this agreement, but he didn't believe it would do so
knowing it would obviate some of the obligations for fuller
development under the agreement.
SENATOR PASKVAN said that means the decision to build a large or
small diameter pipeline from the North Slope going south should
not be made until the end of 2015 at the earliest, and probably
between 2016 and 2019.
MR. BALASH said he expects the decision will be made after 2015
and his hope is that it will be private companies that make that
decision. This agreement is to step toward working together in
the mutual interest to commercialize the North Slope and realize
the associated benefits.
SENATOR PASKVAN asked why under this agreement the pipeline
would potentially be developed under the AGIA statutory
framework.
MR. BALASH replied it's important for a number of reasons the
first of which is that the pipeline has to operate in a way that
is consistent with the state's interests.
SENATOR PASKVAN questioned why a major gas sale under the
settlement agreement is defined as 500 mcf/day when the AGIA
structure is so much larger.
MR. BALASH offered to meet to discuss the matter.
5:30:37 PM
CHAIR FRENCH said the major gas sale definition from the Prudhoe
Bay Unit Operating Agreement implies a certain flow rate leaving
the North Slope, whereas the definition in paragraph 2.16 on
page 9 of the settlement agreement does not have a flow capacity
requirement. He asked for an explanation.
MR. KATCHEN explained that once a major gas sale is sanctioned,
the producers have the ability to choose the other development
options. However, gas won't be flowing once the sanction
happens.
CHAIR FRENCH asked him to submit the answer in writing.
5:33:44 PM
MR. BALASH discussed the choice to settle and whether or not the
state's interests were satisfied. In 2006 the estimate to
navigate the litigation was 3-5 years, but it didn't take into
account an adverse decision by Judge Gleason in 2007. In 2010
she issued a decision that was devastating to the state's
ability to manage its oil and gas fields. An important element
of the settlement agreement was that the decision was vacated
with prejudice. At the end of the litigation and assuming the
leases were terminated, they would be leased to new operators.
Optimistically, first production out of Point Thomson would be
somewhere in 2025. Under the settlement agreement, first
production will be in 2015. That ten years is critically
important to the state and the overall development of the North
Slope resource, he concluded.
5:37:34 PM
MR. KATCHEN concluded by saying he was troubled about the
representations about the lack of public process because it was
more than ample and both Mr. Walker and Mr. Richards submitted
hundreds of pages of documents during the proceedings that all
relate to this development.
5:38:59 PM
There being no further business to come before the committee,
Chair French adjourned the meeting at 5:38 p.m.