Legislature(2011 - 2012)ANCH LIO Rm 220
06/12/2012 10:00 AM Senate JUDICIARY
| Audio | Topic |
|---|---|
| Start | |
| Point Thomson Settlement: Analysis and Legal Issues | |
| Department of Law | |
| Department of Natural Resources | |
| Point Thomson Plan of Operation: Exxonmobil | |
| 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
ANCHORAGE, AK
June 12, 2012
10:07 a.m.
MEMBERS PRESENT
Senator Hollis French, Chair
Senator Bill Wielechowski, Vice Chair
Senator Joe Paskvan
Senator Lesil McGuire
Senator John Coghill
MEMBERS ABSENT
All members present
OTHER LEGISLATORS PRESENT
Senator Bettye Davis
Representative Chris Tuck
Representative Shelley Hughes
Representative David Guttenberg
COMMITTEE CALENDAR
POINT THOMSON SETTLEMENT:
Analysis and Legal Issues - Donald Bullock Jr.
Department of Natural Resources - Deputy Commissioner Joe
Balash; outside counsel Jon Katchen and Matt Findley
Department of Law - Attorney General Michael Geraghty
-HEARD
POINT THOMSON PLAN OF OPERATION:
ExxonMobil
-HEARD
PREVIOUS COMMITTEE ACTION
See Senate Judiciary Standing Committee minutes 4/27/12.
WITNESS REGISTER
DONALD BULLOCK JR., Legislative Counsel
Legislative Legal Services
Legislative Affairs Agency
Juneau, AK
POSITION STATEMENT: Discussed legal issues related to the Point
Thomson settlement agreement.
MICHAEL GERAGHTY, Attorney General
Department of Law (DOL)
Anchorage, AK
POSITION STATEMENT: Clarified aspects of the Point Thomson
settlement agreement.
JOE BALASH, Deputy Commissioner
Department of Natural Resources (DNR)
Anchorage, AK
POSITION STATEMENT: Provided information and answered questions
related to the Point Thomson settlement agreement.
MATT FINDLEY, Attorney
Ashburn and Mason P.C.
Anchorage, AK
POSITION STATEMENT: Answered questions as outside counsel to the
state on the Point Thomson settlement agreement.
JON KATCHEN, Attorney
Crowell & Moring
Anchorage, AK
POSITION STATEMENT: Answered questions as outside counsel to the
state on the Point Thomson settlement agreement.
LEE BRUCE, Senior Project Manager
Point Thomson project
ExxonMobil Corporation
Anchorage, AK
POSITION STATEMENT: Delivered a PowerPoint and discussed the
Point Thomson Plan of Operation.
CHARLES MCKEE, representing himself
Anchorage, AK
POSITION STATEMENT: Testified during the Point Thomson hearing.
WARREN CHRISTIAN, President
Doyon Associated LLP
Anchorage, AK
POSITION STATEMENT: Testified in support of the Point Thomson
project.
JERRY MCCUTCHEON, representing himself
Anchorage, AK
POSITION STATEMENT: Testified that the only Alaska gas pipeline
will be from Cook Inlet.
BARBARA HUFF-TUCKNESS, Director
Governmental and Legislative Affairs
Teamsters Local 959
Anchorage, AK
POSITION STATEMENT: Stated support for the Point Thomson project
and thanked the committee for continuing the hearings.
RICK ROGERS, Executive Director
Resource Development Council (RDC)
Anchorage, AK
POSITION STATEMENT: Testified in support of settling the Point
Thomson lease litigation and stated support for monetizing North
Slope gas.
BILL WALKER, representing himself
Anchorage, AK
POSITION STATEMENT: Clarified that he appealed Commissioner
Sullivan's decision to enter into the Point Thomson settlement
agreement because the process bypassed the public.
JOHN MACKINNON, Executive Director
Associated General Contractors of Alaska
Anchorage, AK
POSITION STATEMENT: Testified in support of the Point Thomson
project.
DAVE CHAPUT, Program Director
Alaska Frontier Constructors (AFC)
Anchorage, AK
POSITION STATEMENT: Testified in support of the Point Thomson
project.
GARY DIXON Jr., Vice President
Alaska Teamsters Local 959
Anchorage, AK
POSITION STATEMENT: Testified in support of the Point Thomson
project.
KATHLEEN O'CONNELL, Vice President of Projects
PRL Logistics, Inc.
Anchorage, AK
POSITION STATEMENT: Testified in support of the Point Thomson
project.
ACTION NARRATIVE
10:07:05 AM
CHAIR HOLLIS FRENCH called the Senate Judiciary Standing
Committee meeting to order at 10:07 a.m. Present at the call to
order were Senators Coghill, Paskvan and Chair French.
^Point Thomson Settlement: Analysis and Legal Issues
10:08:21 AM
CHAIR FRENCH said his interest in the hearing today is to look
at both the settlement agreement itself and the policy
implications going forward for this and future projects. As DNR
pointed out in a summary of the Point Thomson history, an
agreement struck in 1983 had the unintended consequence of
leaving Point Thomson undeveloped for decades. The obvious
intention is to keep that from happening again.
He said that the legality of the settlement is not in question
today, but there will be discussion of the overall breaking
point of that idea. The committee will also address the
legitimate question that many members of the public have asked
about whether a secret deal crafted between the administration
and ExxonMobil is really in the public interest. He welcomed Mr.
Bullock.
10:09:20 AM
DONALD BULLOCK JR., Legislative Counsel, Legislative Legal
Services, Legislative Affairs Agency, stated that he primarily
does oil and gas work for the legislature.
CHAIR FRENCH asked him to review the June 8, 2012 memorandum
that he prepared.
10:10:16 AM
SENATOR WIELECHOWSKI joined the committee.
MR. BULLOCK cautioned that he was unfamiliar with and not
prepared to speak about several things. He was not familiar with
the particulars of the agreements made regarding the leases in
Point Thomson or the negotiations between the Department of
Natural Resources (DNR) and the Attorney General. He suggested
the committee ask the parties directly about those issues.
MR. BULLOCK said he looked at the authority of the attorney
general to enter into settlements and agreed with what the
committee heard during the April 27, 2012 hearing. In that
forum, the attorney general has broad discretion to settle cases
on behalf of the state. If the settlement takes place at the
administrative level, the attorney general can advise the
commissioner of DNR regarding a particular action to take;
during the litigation phase, the attorney general has the
authority to enter into settlements.
10:11:51 AM
CHAIR FRENCH asked what the outer boundaries are for that
general rule.
MR. BULLOCK replied it is a separation of powers issue; the
legislature writes the laws within which the attorney general
and the commissioner can operate. The legislature passed AS
43.23.020, which specifically authorizes the attorney general to
settle cases like this.
CHAIR FRENCH asked if the legislature could modify the statute
to authorize the attorney general to settle cases valued up to
$5 billion, but anything above value that would require
legislative approval.
10:12:58 AM
MR. BULLOCK replied that would probably be challenged under the
separation of powers doctrine. The scenario in which it would be
a problem is if the executive branch negotiated a settlement
that the legislature didn't approve, and the beneficiary of the
settlement challenged in court the legislature's power to
approve the contract.
He said there was some confusion when the legislature passed the
Alaska Gasline Inducement Act because it gave the commissioners
of natural resources and revenue the authority to make a
recommendation, which the legislature would then approve.
Arguably, the executive branch had the authority to approve the
AGIA contract without legislative confirmation.
10:14:15 AM
CHAIR FRENCH asked if his analysis on that point extends to the
Stranded Gas Development Act.
MR. BULLOCK offered his belief that the SGDA suffers from that
problem in addition to the issue of contracting away the power
to tax.
CHAIR FRENCH asked if he was saying that it was potentially
unconstitutional when the legislature considered the AGIA
contract that the Murkowski administration and ConocoPhillips,
BP and ExxonMobil negotiated.
MR. BULLOCK said yes; there probably would have been
constitutional litigation based on the separation of powers, had
the legislature withheld its approval.
CHAIR FRENCH summarized that absent a constitutional change to
give the legislature the authority to intrude into executive
branch matters, the attorney general and the administration have
the power to settle litigation with essentially no boundary.
10:16:41 AM
MR. BULLOCK said the one exception is that the legislature has
the power of appropriation; the legislature it can ask what the
money is for and withhold part of all of the funds. However, the
appropriation issue is probably irrelevant at Point Thomson. The
issue is more about when the state will receive money from
development of the resource.
CHAIR FRENCH asked what the result would be if the
administration agreed to a settlement that was clearly in
violation of state law.
MR. BULLOCK responded that any taxpayer in the state could
challenge the action in court. He noted that Baxley v. State,
which he mentioned in the June 8, 2012 memorandum, involved a
citizen-taxpayer challenge to an action that was taken. He noted
that the courts will generally defer to the discretionary action
of a person in state government, subject to abuse of that
discretion or some fatal flaw. A difference of opinion doesn't
qualify.
10:19:13 AM
SENATOR PASKVAN asked if the scope of the litigation was part of
the question.
MR. BULLOCK said yes. The litigation began because the
commissioner of natural resources took the administrative
position that it was time to break up the unit. That was
appealed and in the context of the litigation the attorney
general looked at where the best interests of the state lay. The
action had gone on for more than seven years and what the state
would ultimately gain was at issue. The attorney general did not
act in the dark or independently, the commissioner of natural
resources signed the settlement too.
SENATOR PASKVAN asked if it was fair to assume that filing
litigation would not give the parties carte blanche to decide
any issue that may be tangentially related.
MR. BULLOCK responded that the attorney general has both the
statutory and common law authority to act in the best interests
of the state.
SENATOR PASKVAN questioned whether eliminating administrative
procedures or limiting the scope of review might prospectively
exceed the scope of litigation.
MR. BULLOCK said the settlement agreement addressed that issue
by including dispute-settling provisions. Any disputes under the
agreement will be handled in the way that is discussed in the
settlement agreement. Issues that are not within the settlement
will continue to be handled in the normal means for handling
administrative appeals for the department.
10:23:44 AM
SENATOR MCGUIRE joined the committee.
SENATOR PASKVAN asked if provisions in the settlement agreement
prospectively limit what the AOGCC can look at.
MR. BULLOCK said the settlement affects some things outside the
settlement such as how to divide the state's royalty gas between
Point Thomson and Prudhoe Bay if it is used to pressurize
Prudhoe Bay. He noted that he addressed that thoroughly in the
June 8, 2012 memorandum. There are also things that the
settlement doesn't address and doesn't have the authority to
mandate particular outcomes. He offered his belief that AOGCC is
in that category.
10:25:47 AM
CHAIR FRENCH expressed concern with the representations from the
administration that the agreement generally self-executes and is
without appeal. He asked Mr. Bullock if he had reviewed those
parts of the settlement.
MR. BULLOCK confirmed that he looked at those generally and they
seem to be the result of policy decisions and agreements between
the parties. The settlement recognizes certain issues and says
that the actions they require will happen without further
appeal. The parties gave up options they would otherwise have to
reconsider what was happening and make decisions along the way
in order to keep things moving forward. He opined that the
purpose of the settlement was to relate to the management of the
unit, through 2019 in some cases.
CHAIR FRENCH read the following from paragraph 5.1.4 of the
settlement agreement:
Any Party may dispute whether a specified event has
occurred that pursuant to the terms of this Agreement
would result in termination of the Point Thomson Unit
Without Appeal or release of acreage Without Appeal
He asked what it meant to him as an attorney that "any party may
dispute whether a specified event has occurred."
10:28:38 AM
MR. BULLOCK said his response would be general, because he had
not looked specifically at that paragraph. He relayed that under
any settlement agreement certain actions are expected, but
whether a particular action has taken place will be a factual
issue. The impact of a particular action would be subject to the
terms of the settlement because that is the consequence of an
action, but there would still be a dispute as to whether
something should have happened at a particular point and whether
it did happen.
CHAIR FRENCH asked what would happen under the following
example. The agreement says ExxonMobil has to drill three wells
within five years or the unit would be terminated without
appeal. At the end of five years, the state says that ExxonMobil
drilled just 2.5 wells and ExxonMobil says it drilled 3 wells.
MR. BULLOCK said the issue is whether drilling to the targeted
depth constituted a well, and that would have to be clarified.
CHAIR FRENCH asked who would resolve that factual dispute.
MR. BULLOCK said the parties would do it within the settlement
agreement if the issue was addressed.
CHAIR FRENCH read the second part of paragraph 5.1.4 as follows:
In the event of such dispute, termination of the Point
Thomson Unit Without Appeal or the release of acreage
Without Appeal shall not be required until there has
been a final judicial determination as to the
occurrence of the specified event, or upon an
Abandonment determination via arbitration under
Paragraph 4.2.3, This Paragraph 5.1.4 does not apply
to DNR decisions referenced in Paragraph 5.1.2(b).
He asked if the factual determination of whether 2.5 or 3 wells
were drilled would go to the commissioner or a judicial
determination, and if the latter would be in a courthouse.
MR. BULLOCK suggested he ask the attorney general and ExxonMobil
what they envisioned. It is obviously a product of policy
decisions and agreement between the parties as to what things
the action of the agreement itself would settle, the disputes
they anticipated, and how they would be resolved.
CHAIR FRENCH asked if a final judicial determination would be
done in a courthouse.
MR. BULLOCK answered yes; it would be a judicial branch action.
10:31:50 AM
CHAIR FRENCH said another concern is that the settlement
agreement adopts a different definition of "major gas sale" than
is used in the Prudhoe Bay operating agreement. He asked Mr.
Bullock to summarize the analysis he gave in the June 8, 2012
memorandum.
MR. BULLOCK stipulated that because he wasn't familiar with unit
agreements and leases, he didn't fully understand the
consequences of a finding that a major gas sale has occurred.
The settlement agreement has lynch pins concerning whether there
is a major gas sale or not, and for the purposes of Point
Thomson, "major gas sale" is defined as 0.5 billion cubic feet
per day (bcf/d). He said he did not know how that number was
reached outside the context of a competing natural gas pipeline
under the Alaska Gasline Inducement Act, which entitles the
licensee to triple damages of qualified expenditures. He
suggested the parties may have a better answer.
CHAIR FRENCH said he found it odd and worrisome that the
definition does not specify the amount of gas that must be
moved. It says that a pipeline has to be built that is capable
of moving a major amount of gas, but nowhere does it say that a
major amount of gas actually has to be moved. Moving a few
molecules satisfies the definition under the agreement.
10:35:47 AM
MR. BULLOCK said a critical part of settlement is that an event
triggers the state to take its royalty gas. That event is when
gas is produced into the gas pipeline from Point Thomson to
Prudhoe Bay. AS 38.05.182(a) guides the taking of the royalty in
kind, which is consistent with the settlement agreement. What
the settlement doesn't say is how much or even that the state is
in the position to sell its gas. However, if gas is produced
from Point Thomson and used to pressurize Prudhoe Bay, the gas
effectively will be stored in the Prudhoe Bay unit until there
is an opportunity for sale.
CHAIR FRENCH commented that it was a highly interesting
arrangement to move gas from the Point Thomson reservoir and
inject it into the Prudhoe Bay reservoir. He asked if the state
had the same one-eighth royalty interest in both reservoirs.
MR. BULLOCK said he didn't know, but he'd heard comments that
the royalty agreements vary in the Point Thomson leases. He
added that the use of Point Thomson gas to pressurize Prudhoe
Bay would not be considered for taxable purposes, as the
production of gas. The settlement cites the regulation, but
there is actually statutory authority for that.
10:39:39 AM
SENATOR COGHILL observed that the settlement says that if a
pipeline is built, the state could take its royalty in kind for
either in-state use or for pressurization.
MR. BULLOCK responded that the in-kind gas belongs to the state
but if there isn't a place to put it, it will stay in the gas
cap. The settlement agreement provides two options for what to
do with Point Thomson gas. One is to cycle the gas, which would
maintain the pressure in the Point Thomson reservoir. The other
option is to take the gas off the unit, at least as far as
Prudhoe Bay.
SENATOR COGHILL expressed interest in knowing how Point Thomson
gas that's used to pressurize Prudhoe Bay will be measured once
it's produced. He said his understanding is that it would be
another agreement.
MR. BULLOCK confirmed that the terms of the agreement include a
delivery point definition. He suggested asking DNR where the gas
will actually be measured and accounted for.
CHAIR FRENCH reiterated how different the definition of "major
gas sale" is in the settlement agreement compared to the
definition in the Prudhoe Bay operating agreement. The Prudhoe
Bay operating agreement defines a major gas sale as the movement
of at least 1.75 bcf/d of gas off the North Slope.
He asked what major issues are not addressed in the settlement
agreement and will still need to be resolved.
10:42:00 AM
MR. BULLOCK said two things stand out. The first is how the
state will account for and take its royalty for Point Thomson
gas that is used to pressurize Prudhoe Bay, once the gas is
produced along with other production. The other open question is
specifically how the Point Thomson unit participants will work
to get gas off the North Slope. This can be a problem because
the interests of the state and the producers aren't always in
alignment. It can be money in the bank for the producer to keep
the reserve in the ground as long as the pressure isn't lost and
AOGCC standards are followed. The state, on the other hand,
needs money every year.
10:43:30 AM
CHAIR FRENCH observed that it will be a recurring question about
the agreement that DNR put AOGCC forward as the final overseer
in protecting the state's interest against waste with regard to
the decision for full field cycling or blowdown. He asked if the
role of AOGCC is the same as DNR in making that determination.
MR. BULLOCK answered that AOGCC has a separate function to look
at the optimum development of the resource in order to maximize
production. One of the issues in Point Thomson is that if the
gas comes off too quickly, it may leave too many liquids behind.
That is a concern of AOGCC and something it has authority over,
not necessarily when the resource is produced.
CHAIR FRENCH thanked Mr. Bullock for the overview.
MR. BULLOCK reiterated that his focus in the review was to make
sure that the royalty terms were consistent with the law and
that the tax event was properly addressed.
10:46:13 AM
CHAIR FRENCH welcomed Attorney General Geraghty.
^Department of Law
MICHAEL GERAGHTY, Attorney General, Department of Law (DOL),
said he agreed with Mr. Bullock's opinion, but wanted to clarify
two issues. The first is that there was no intent to have the
court review and approve the settlement agreement, although it
was submitted to the court as part of the settlement papers to
dismiss the case. Given the timing of the dismissal, it was
unlikely that the court reviewed and approved the settlement, he
stated.
10:48:34 AM
The second clarification relates to the authority of the
attorney general to settle cases that may abrogate certain
aspects of state law. He agreed with Mr. Bullock's opinion
regarding the authority of the attorney general, but did not
believe that this particular agreement abrogates or abridges
state law or DNR regulations. He noted that he addressed that to
some extent in the letter he submitted.
ATTORNEY GENERAL GERAGHTY noted that Mr. Bullock raised the
question of how gas injected into Prudhoe Bay and eventually
sold in a major gas sale will be allocated between the two
reservoirs. The answer is that there is an agreement and
allocation in place so it is clear when the gas goes into the
pipeline, what goes to the state, what goes to the producers,
and what, for example, is Point Thomson gas and what is Prudhoe
Bay gas.
CHAIR FRENCH asked if that agreement was separate from the Point
Thomson settlement agreement.
ATTORNEY GENERAL GERAGHTY answered yes.
REPRESENTATIVE CHRIS TUCK joined the meeting via teleconference.
10:51:24 AM
CHAIR FRENCH asked his view of the boundary of his authority as
attorney general - the point beyond which an issue is too large
or involves too much money for him to sign and announce a deal,
without any public process or input.
ATTORNEY GENERAL GERAGHTY answered that he didn't know, but he
didn't believe there was a legal, dollar boundary. Cases worth
hundreds of millions of dollars have been settled in the past,
and the Point Thomson case doesn't have a specific dollar amount
per se.
CHAIR FRENCH pointed out that Point Thomson is worth at least a
couple of billion dollars.
ATTORNEY GENERAL GERAGHTY opined that the break point is not a
dollar figure; it is the good judgment and discretion of the
attorney general to approve a settlement. He said some things
are better negotiated in private, but it was not his position
that he would never consult with the legislature.
10:53:20 AM
SENATOR PASKVAN asked why the administration didn't ask for
legislative input after the agreement was crafted and during the
several months that ExxonMobil took to present the terms to the
working interest owners.
ATTORNEY GENERAL GERAGHTY said his understanding is that all the
interest owners were involved in the negotiations to some
extent. He also opined that there was a substantive difference
between sophisticated commercial entities discussing an
agreement and approving it among themselves, and submitting such
an agreement to the political branch of government.
10:57:01 AM
CHAIR FRENCH said DNR pointed out in the June 7, 2012 letter
that its decision in 1983 to remove the automatic termination
provision from the unit agreement had an unintended consequence.
The consequence of that modification was that the unit continued
for decades without production.
He questioned what might have happened in 1983 if that agreement
had come in front of the legislature or been publicly reviewed,
and if it could have saved the state 30 years of trouble. He
said he hopes that the settlement agreement is without even a
small flaw, but he wonders if such a large question shouldn't be
reviewed by another set of eyes.
ATTORNEY GENERAL GERAGHTY responded that it was strictly a DNR
process in 1983 and DNR clearly had the authority to make that
decision. There would have been no precedent to consult the
legislature. Given the circumstances of this particular case,
the settlement was handled appropriately. However, he was not
taking the position that this was a blanket conclusion on all
settlements.
CHAIR FRENCH referenced paragraph 5.1.4 and asked his thoughts
as to when the commissioner of DNR would have omnipotent
authority to make things happen under the settlement agreement
and when there would be a judicial determination.
11:03:14 AM
ATTORNEY GENERAL GERAGHTY said his perception is that in certain
circumstances there may be a right to challenge whether a
factual event took place, but the consequences of the event
cannot be challenged. They are without appeal. He described the
settlement as a compromise that was probably the best the state
could achieve under the circumstances. The arbitration provision
was something the state actually asked for to avoid challenges
of whether a lease was abandoned or not. The state wanted a
strict, timely arbitration for that particular circumstance. He
deferred to DNR for further details.
CHAIR FRENCH asked if he had any concerns as an attorney that
the agreement has no volumetric aspect for moving gas off the
North Slope in order for there to be a major gas sale.
ATTORNEY GENERAL GERAGHTY replied he didn't have any concerns as
an attorney. As a practical matter, he couldn't see the
producers making the investment required to ship even some gas
off the North Slope for the sole purpose of meeting the
requirement.
11:08:45 AM
SENATOR PASKVAN referenced page 6 of the June 8, 2012 letter
that says the settlement agreement provides that the working
interest owners may sanction a major gas sale at any time prior
to the end of 2019 in order to retain acreage. He asked why it
should take so long to get just a decision and how it fits with
the understanding that Alaska's natural gas resources will be
developed timely.
ATTORNEY GENERAL GERAGHTY said his understanding is that the
timeframes were rigorously negotiated, and 2019 was the shortest
timeframe that DNR could get. He said he shares the frustration
but the scope and investment of these projects are huge.
11:13:38 AM
SENATOR PASKVAN asked how it happened that the settlement
agreement defines a "major gas sale" as just a molecule over 0.5
bcf/day, because that's not what Alaskans have been considering
for the last 30 years.
ATTORNEY GENERAL GERAGHTY said his perspective is that the
producers do not have an interest in building a line that is
only 0.5 bcf/d. It only makes economic sense to build the
largest line reasonably possible. The interests of the state and
the producers are aligned on that issue. He deferred to DNR for
specifics.
11:16:10 AM
CHAIR FRENCH recessed the meeting.
11:28:28 AM
CHAIR FRENCH reconvened the meeting and welcomed DNR.
^Department of Natural Resources
JOE BALASH, Deputy Commissioner, Department of Natural Resources
(DNR), introduced himself, Jon Katchen, and Matt Findley.
11:30:18 AM
MATT FINDLEY, Attorney, Ashburn and Mason, introduced himself
and relayed that his company had been outside counsel to the
state on Point Thomson since the litigation commenced in 2007.
MR. BALASH thanked the committee for the opportunity to put in
writing the points he didn't have time to cover in the April 27,
2012 meeting, and that he would be happy to provide written
answers to any further questions that may arise regarding how
the agreement came into being and the consequences moving
forward.
CHAIR FRENCH informed the listening public that Commissioner
Sullivan and the three presenters were the team that crafted
this agreement.
MR. BALASH explained that the negotiations on the settlement
agreement began with the prior administration. The legal
milestones that occurred were the decision in 2008 by Judge
Gleason, the remand, and the decision by Judge Gleason again in
2010. In between was the 2009 interim decision by then
Commissioner Tom Irwin authorizing the drilling of wells PTU 15
and PTU 16 for the Initial Production System (IPS).
CHAIR FRENCH asked when the first work on the settlement
agreement commenced.
MR. BALASH answered that the plan of development that was
submitted in 2008 - POD 23, formed the basis of this IPS. It is
the foundation and technical plan for the settlement.
Commissioner Irwin rejected POD 23 for two reasons. One was the
concern about the commitment of the working interest owners to
follow through on the activities proposed in the plan. The
second concern related to what would happen after the IPS came
on production. The 2009 interim decision authorized those first
two wells and set this path to put the IPS on production.
11:35:40 AM
Following the 2009 interim decision was Judge Gleason's decision
in 2010, which was devastating to the state's interests and
ability to manage Point Thomson through the POD process. The
state filed an interlocutory appeal with the Alaska Supreme
Court. The petition was accepted and that probably helped
crystalize and move along negotiations that began in 2009.
CHAIR FRENCH commented that that didn't sound very good because
ExxonMobil had the upper hand in the negotiations. He asked his
perception.
MR. BALASH said it was a struggle, but it was wind in their
sails when the court granted the petition. That probably helped
bring closure on what was a term-sheet level agreement.
CHAIR FRENCH asked what term-sheet level agreement means.
MR. BALASH explained that many of the key terms and features of
the agreement were agreed upon in late 2010. At that time, the
team consisted of former DNR Deputy Commissioner Marty
Rutherford and then Attorney General Dan Sullivan from the
Department of Law (DOL). He said that a term-sheet level
agreement was reached at that stage.
CHAIR FRENCH observed that the term-sheet agreement occurred at
the low point of state's legal posture.
MR. BALASH offered his perspective that it was the Alaska
Supreme Court's granting of the petition for review that allowed
the team to move as quickly as it did to that agreement. The
state's resolve was not shaken; it was going to do whatever it
took to get the field into timely production. That resolve
helped result in an agreement that is quite strong.
11:38:50 AM
SENATOR PASKVAN asked what the consequence would have been to
the state if: 1) the supreme court had upheld the trial court on
the petition for review and 2) the supreme court had overturned
the trial court decision.
MR. BALASH clarified that the interlocutory appeal came before
the final decision from Judge Gleason in 2010. If the supreme
court had upheld the original decision, DNR would have then gone
back to Judge Gleason for finalization of her decision. That
could have led to a Section 21 hearing under the agreement,
which would have placed the entire burden on the state to
identify and justify what should happen next in the development
of the field.
Had the decision gone in the state's favor, DNR would have gone
back to Judge Gleason to reconsider the particular decisions and
findings that related to Section 21 and who carried what burden.
She would have formulated that and then issued a final decision.
He expressed confidence that one party or the other would then
have appealed to the supreme court on that final judgment.
SENATOR PASKVAN said his assumption is that Judge Gleason
determined that the state somehow erred in its termination
process. He asked what DNR had done to avoid a similar error if
it were to terminate a lease in the future.
MR. BALASH said there were two points. First, the original
dispute and decision in 2008 found that DNR did not provide
sufficient notice to the working interest owners that
termination was forthcoming, and that the remedy was termination
of the unit. After 2008, there was a hearing where the working
interest owners provided what they thought was the right POD and
proper remedy in the event of a rejection.
11:43:49 AM
In 2010, Judge Gleason found that the question of remedy was to
hold a hearing conducted pursuant to Section 21 of the unit
agreement. That was somewhat different from the discussion that
took place in her court in 2008.
SENATOR PASKVAN asked if DNR formally modified its procedures to
make sure that the due process issue doesn't happen again if the
state should decide to terminate a lease in the future.
11:45:31 AM
MR. FINDLEY said Judge Gleason's rulings raised issues regarding
how DNR implements its existing regulations and the specific
things that happened. That does not imply that the regulations
need to be changed.
11:45:49 AM
JON KATCHEN, Attorney, Crowell & Moring, added that Section 21
of the Point Thomson unit agreement is unique. Judge Gleason
read that the POD process flowed into a Section 21 process,
which shifted the burden and then reversed how DNR manages land.
No other unit agreement has a similar provision.
CHAIR FRENCH asked when that unit agreement was crafted.
MR. KATCHEN answered it was written in 1977 and amended several
times in the early 1980s.
CHAIR FRENCH asked when the term sheet was developed.
MR. BALASH answered that it was an October 2010 agreement with
just the operator.
11:47:22 AM
CHAIR FRENCH summarized that it was a five or six page agreement
between DNR and ExxonMobil that developed into the 85-page
document that the legislature saw first on March 29, 2012.
MR. BALASH recounted some of what took place after October 2010
as DNR and ExxonMobil continued negotiations. Following the
November election, Governor Parnell went through a transition
process and then Attorney General Sullivan became commissioner
of natural resources. He essentially retained the portfolio on
the negotiations and settlement.
CHAIR FRENCH asked if this process accounted in part for Mr.
Sullivan's transfer from the position of attorney general to
commissioner.
MR. BALASH suggested he ask the Governor. His understanding was
that Mr. Sullivan demonstrated a broad understanding of the
complex issues in the oil and gas arena to manage this and other
cases.
CHAIR FRENCH asked if any consideration was given to presenting
this settlement agreement to the legislature for preview before
finalization.
MR. BALASH described the process that unfolded following the
October 2010 term-sheet agreement. He said the negotiations and
exchange of papers perhaps took longer than it should have, but
the "fully papered" agreement was finalized in the summer of
2011. Commissioner Sullivan mentioned to a legislative committee
that there was an agreement with the operator. It was at that
time that the other working interest owners were apprised of the
specific terms and the relative positions of both the operator
and the state.
CHAIR FRENCH recalled that the news reports at that time
indicated some pushback from the other operators about their
lack of involvement in the structuring of the settlement
agreement.
11:50:15 AM
MR. BALASH confirmed that there was some dissatisfaction. He
continued to explain that the ongoing conversations clarified
the need to find a means of monetizing North Slope gas in order
to realize the value at Point Thomson. In the summer of 2011,
ConocoPhillips and BP terminated their jointly sponsored Denali
pipeline project, and it was in the fall of 2011 that the
Governor started to make clear his willingness to pivot from the
North American market to the LNG market in order to
commercialize the state's North Slope resources.
CHAIR FRENCH asked at what point in the process ExxonMobil
announced it was joining TransCanada in its AGIA pipeline.
MR. BALASH recalled that it was in the second quarter of 2009.
CHAIR FRENCH asked if there was a connection between the Point
Thomson settlement agreement and ExxonMobil joining forces with
TransCanada to build a large-scale pipeline.
MR. BALASH opined that there was nothing direct or specific, but
it was fair to observe that ExxonMobil was looking for ways to
work with the state to meet the state's goals and objectives
represented through the AGIA license.
MR. BALASH relayed that the Governor met with the CEOs of BP,
ConocoPhillips and ExxonMobil early in 2012 to work to finalize
the agreement and come to an understanding of how all parties
would fit together, particularly in light of the state's
relationship with TransCanada through the AGIA license.
Commercializing North Slope gas via an LNG project was going to
occur within the AGIA framework.
11:54:06 AM
CHAIR FRENCH asked why DNR chose such a different definition of
"major gas sale" in the settlement agreement than the definition
under the Prudhoe Bay operating agreement. He also asked why the
definition did not include specific volume requirements.
MR. BALASH recapped the answer Attorney General Geraghty gave to
the question and highlighted that the 1.75 bcf/d threshold in
the Prudhoe Bay operating agreement was an agreement between and
among the working interest owners, not the unit agreement to
which the state is a party. To the extent that DNR looked to any
particular frame of reference, 500 mmcf/d was identified in 2007
in the AGIA statute, and is double the amount that Alaskans
need. The intention in setting the 0.5 bcf/d threshold in this
agreement is to ensure there is room to meet Alaskans' needs,
not to identify the minimum needed to retain the acreage.
11:57:43 AM
CHAIR FRENCH said it was extremely troubling that the settlement
agreement uses "major gas sale" as a functioning milepost
throughout the document, but the definition in the agreement
does not require the movement of more than a single molecule of
gas off the North Slope. He acknowledged that it was unlikely
that someone would build a pipeline that could carry more than
0.5 bcf and not move gas, but it was possible. ExxonMobil is
arguably the most sophisticated company in the world, and it
doesn't make a move without thinking ahead ten steps. The state
doesn't have that capability. He asked to be convinced that his
concerns were unfounded that when ExxonMobil agreed to the
definition in the agreement, that it didn't put one over on the
state.
MR. BALASH asked him to consider the MPV reports in the AGIA
finding that identified that size matters. It matters to the
overall efficiency and economic performance of any investment by
anybody. The Brookings Institution analysis recently confirmed
that particular finding with regard to exports of Alaska North
Slope gas to Pacific markets.
CHAIR FRENCH said he was in complete agreement that to make
money moving gas, the bigger the pipeline the better. He asked
why the settlement agreement didn't define a major gas sale as 2
bcf/d or larger.
MR. BALASH said the work done in 2008 and the findings document
demonstrated that there is no way to predict with any certainty
what the "right" number is. The placement of LNG into the market
will occur over a number of years, so the issue is how big to
make the pipeline before the deliveries start. He said that
while the repeated use of the definition "major gas sale" is
critical, the use of the term "project startup" is also
important. That is when hydrocarbons enter the pipeline.
He said that the results of the concept selection agreement
between the parties and TransCanada are expected by the end of
the year; at that time everyone will get a sense of the
magnitude and scale of the project. He emphasized that it isn't
the end of the discussion with these companies in realizing the
full potential of the North Slope.
12:03:09 PM
SENATOR PASKVAN asked if a first binding open season is expected
under this concept.
MR. BALASH said that LNG projects in North America typically do
not develop through the use of a conventional open season.
However, the AGIA licensee has an obligation to solicit the
market every two years. That will happen by the end of this
year.
SENATOR PASKVAN noted that he said that this gas pipeline
project would occur within the AGIA framework. His understanding
was that there were statutory provisions under AGIA for a first
binding open season. He asked if the intention was that those
statutory provisions would be retriggered and result in a
coupled tax structure for the first 10 years of production.
12:05:06 PM
MR. BALASH said that with regard to this license, there is only
one first binding open season and it occurred in 2010. The
referenced upstream tax inducements have expired, and it would
require legislative action for that particular inducement to be
available again.
CHAIR FRENCH asked if his view was that the opportunity for a
tax freeze that was offered under AGIA has passed.
MR. BALASH said yes.
SENATOR PASKVAN asked for confirmation that the administration
would not protest the removal of the royalty inducements under
the AGIA statutes, so there would be no question that they would
not apply to any pipeline operated through an AGIA framework.
MR. BALASH replied he was not prepared to endorse that today,
but would review that with counsel to make sure that amending a
portion of the AGIA statute did not affect the contractual
arrangement with TransCanada. He said he would provide a written
response.
SENATOR WIELECHOWSKI asked if the administration briefed or
discussed the terms of the settlement with any legislators prior
to settling the case.
MR. BALASH answered he did not believe so.
12:07:43 PM
SENATOR WIELECHOWSKI asked if a major gas sale, as defined in
paragraph 2.16 of the settlement agreement, could be done
outside of the AGIA process.
MR. BALASH said yes.
SENATOR WIELECHOWSKI asked if a major gas sale could be done
under a small pipeline such as the one proposed in HB 9.
MR. BALASH replied that the question will go to the size and
throughput of the pipe. The legislature will authorize the
construction of the project it wants, knowing the boundaries and
consequences.
SENATOR WIELECHOWSKI asked if under paragraph 2.16 a "large-
scale pipeline" does not mean a small pipeline such as the
bullet line proposed in HB 9.
MR. BALASH said the intention of the agreement in that
definition is to reserve the ability for the state to do
whatever it needs to meet the needs of Alaskans. He opined that
had HB 9 become law, some provisions within that statute would
have prevented AGDC from eclipsing that 0.5 bcf/d threshold. It
is a matter of speculation as to which words would have changed
before it became law.
12:09:51 PM
CHAIR FRENCH cautioned that if the legislature authorizes an in-
state pipeline, it should make sure it does not have a design
throughput greater than 0.5 bcf/d, because the state could
inadvertently build the pipeline that ExxonMobil was supposed to
build for the state.
MR. BALASH said even if the state were to build a pipeline with
a design throughput of 750 mmcf/d, this agreement says that
ExxonMobil and the other working interest owners would then fall
under the regular POD process.
12:11:28 PM
SENATOR WIELECHOWSKI recalled that the AGIA statute prohibits
state contributions towards a pipeline larger than 500 mmcf/d.
He asked if that was correct.
MR. BALASH replied that the project assurance provision allows
TransCanada to receive a buyout if the state takes that kind of
action on a competing project. If the state offers a specific
tax or royalty deal or grants cash to a project, other than
TransCanada, that exceeds 500 mmcf/d, it has violated that
project assurance and is liable for the damages identified in
the statute.
SENATOR WIELECHOWSKI observed that there was no way the state
could contribute to a gas pipeline larger than 500 mmcf/d and
meet this requirement.
MR. BALASH said the state could do that, but additional cost
would attach.
SENATOR PASKVAN asked if the additional cost the state would pay
is according to the breach provisions of the AGIA contract.
MR. BALASH answered he believed that was correct.
12:13:43 PM
CHAIR FRENCH turned the discussion to full field cycling versus
blowdown.
MR. BALASH said the letter he submitted to the committee
discussed the evaluation that DNR and DOL have undertaken since
the 2008 PetroTel study was released.
SENATOR PASKVAN returned the discussion to the previous topic.
He asked if a state-supported in-state line with a design
throughput of less than 0.5 bcf/d would violate some statutory
provision or the Point Thomson settlement if it included an
export component. He asked, "Can, for example, 0.3 bcf be
exported?"
MR. BALASH said the number that matters is how much gas goes
through the pipeline leaving the North Slope, and how much North
Slope gas is going through that pipe. Hypothetically, a 400
mmcf/d pipeline travels through the state. Gas is found either
in the Yukon Flats or the Nenana Basin and another 200 mmcf/d is
put into the pipeline at those points. The pipeline would be
carrying more than 500 mmcf/d of gas, but not more than 500
mmcf/d of North Slope gas.
Another variation is 400 mmcf/d of North Slope gas going through
the system and 230 mmcf/d is used nominally to fill the Nikiski
plant. That leaves 170 mmcf/d of North Slope gas that could be
used in state. That is still well within the threshold regarding
the license and the agreement.
SENATOR PASKVAN summarized that an in-state line could be built
using state dollars and 0.5 bcf/d could be exported.
MR. BALASH said yes, as long as the amount of North Slope gas in
the pipeline stays below 0.5 bcf/d.
12:17:11 PM
CHAIR FRENCH asked Mr. Balash to discuss full field cycling
versus blowdown.
MR. BALASH said any talk about liquids and the potential loss of
liquids should specify if the talk is about Brookian horizon
liquids, natural gas liquids in the gas layer and reservoir at
Point Thomson, or the oil rim that sits adjacent to the high-
pressure gas reservoir and sands.
CHAIR FRENCH suggested he take any discussion about the Brookian
off the table, because it's not at risk. Regardless of what
happens with the Point Thomson reservoir, Brookian oil will not
be lost.
MR. BALASH agreed that the Brookian oil could be developed by
these working interest owners or somebody else, someday.
CHAIR FRENCH clarified that this discussion was about Point
Thomson liquids. They are unique and depending on how the field
is developed, tens of millions of barrels of liquids may or may
not come out of that reservoir. Not everyone knows what full
field cycling and blowdown means, but it means enormous
differences in liquid recovery. He asked him to talk about the
differences.
12:19:54 PM
MR. BALASH said the oil rim in particular will be technically
challenging to recover. He noted that written correspondence
submitted to the committee says that the potential for that thin
oil rim is much smaller than was estimated in the 2008 PetroTel
study.
CHAIR FRENCH identified that as on page 25-26 of the June 7,
2012 DNR letter. Footnote 99 says there may be less oil than
thought in the past, but it's still in the 300 million barrel
region of oil available.
MR. BALASH said the technical staff advises that that oil rim
should be viewed as a potential upside as development plans move
forward.
MR. BALASH said that natural gas liquid condensate is the term
generally used when talking about the liquids entrained in the
gas. They're entrained at high pressure so they are in a gaseous
state. When the condensate is brought to the surface and
depressurized, the liquid falls out. It can then be recovered
and moved through a conventional liquid pipe.
CHAIR FRENCH asked if that liquid pipe will connect with the
current Badami pipeline.
MR. BALASH said yes.
CHAIR FRENCH asked if the volume initially is expected to be
between 10,000 and 20,000 barrels a day
MR. BALASH said the commitment in the agreement to put the IPS
on production will result in 200 mmcf/d of gas being cycled;
liquid will be recovered and the dry gas reinjected into the
reservoir. The expected result in the initial production system
is 10,000 barrels per day of liquid recovered at the surface and
moved through the pipeline. In the agreement, that has to be on
production by year-end 2015. TAPS throughput will be impacted in
2016.
CHAIR FRENCH asked how high the IPS could go.
12:23:37 PM
MR. BALASH explained that the IPS will be designed to
accommodate 200 mmcf/d, and depending on condensate yield rate,
the 10,000 barrels could be higher or lower. In 2016 the working
interest owners will begin to evaluate whether to expand cycling
at the field or pursue one of the other two development paths.
12:24:30 PM
CHAIR FRENCH noted that the June 8, 2012 DNR letter takes issue
with the fact that Dr. Myers based his analysis on the estimates
in the 2008 PetroTel study, because it was an initial study. He
read the following from page 26:
After completing this extensive review, the Division
of Oil and Gas concluded that the potential amount of
liquid condensate and oil that could be lost if Point
Thomson were "blowndown" early for a Major Gas Sale
would be significantly less [than] the estimates found
in the 2008 PetroTel study that Dr. Myers and Mr.
Walker rely upon. DNR cannot disclose the revised
estimate because this information is protected under
Alaska law.
He said it raises another goosebump to see that secret data is
being used to support the deal that was made in secret. He asked
why he should have confidence.
MR. BALASH said everyone recognizes the value of proprietary
information, but he would be willing to explore the outer
boundaries of what could be shared in confidence, if the
committee wanted to do that. The negotiating team relied on the
technical staff within the Division of Oil and Gas and the
contractors they worked with to understand the information in
order to make the policy choices that were made in the
negotiation and resolution of this dispute.
CHAIR FRENCH summarized that the physics of the reservoir and
the complexities of the analysis aren't something that can be
kicked around at this hearing.
MR. BALASH said that is correct. He suggested thinking about the
challenges both above and below ground and the consequences for
each with regard to the ultimate viability of cycling on a
larger scale. The way that the reservoir performs below ground
and the way the equipment performs at the surface are both
important. The 2008 PetroTel study just wanted to understand how
the reservoir might perform and didn't consider the above ground
constraints.
12:28:38 PM
One of the scenarios brought 8 bcf/d to the surface and
reinjected it at Point Thomson, but neither the cost of cycling
that amount of gas nor the location of the pads and facilities
was taken into consideration. The reservoir itself is below
water in the shallow Beaufort Sea so it is a challenge. Another
above ground constraint is the highly engineered machinery that
is necessary to handle gas at extremely high pressure.
MR. BALASH suggested the members think about it in terms of the
way the USGS estimates resources. There is a resource estimate,
a technically recoverable estimate, and an economically
recoverable estimate. The 2008 PetroTel study is between the
first and second estimates. How best to optimize recovery of
hydrocarbons in the field, moves closer to the economically
recoverable estimate. That is where the state relies on the
expertise and financial interests of the working interest owners
to help identify the broad link for development of that unit.
DNR's perspective takes into account a broad range of things,
whereas the AOGCC looks purely at the question of waste. The
evaluation of whether to cycle Point Thomson at more than 200
mmcf/d and beyond 10,000 barrels of condensate recovery per day
will begin in 2016.
12:31:56 PM
SENATOR PASKVAN asked what duty the administration has to
disclose to the legislature in the future, if the current
confidential information materially changes.
MR. BALASH reiterated his willingness to explore the bounds of
the confidentiality agreements and obligations.
SENATOR PASKVAN said he appreciated that, but he wanted to know
what duty there is to disclose in the event that there is a
material change in that information.
MR. BALASH responded that under the agreement, the working
interest owners have an obligation to share with the Division of
Oil and Gas what they have learned and are thinking with regard
to the defined objectives and pathways in the agreement. The
results in 2016 will lead to further evaluation as to whether
the state agrees with the direction and if it is consistent with
the agreement and state law. There will be opportunity for that
to be understood on the executive branch level and then with the
legislative branch and broader public. However, it is likely
that there will still be limits to what information becomes
public.
SENATOR PASKVAN asked what duty there is to disclose that there
has been a material change.
MR. BALASH deferred the question to counsel.
MR. KATCHEN asked if he was asking about the duty of the working
interest owners to disclose.
SENATOR PASKVAN said he understands that in the agreement there
is some obligation of the working interest owners to disclose
information to the executive branch. He asked if there is a
legal duty for the executive branch to disclose to the policy
making legislative branch when there is a material change in
substantive and factual information.
MR. FINDLEY said he was not aware of any statutory or regulatory
obligation or duty, but that didn't mean there shouldn't be
communication.
CHAIR FRENCH quoted Thomas Jefferson saying, "The price of
freedom is eternal vigilance." and promised that the legislature
will watch carefully to see if it would be better to reinject
the gas. He offered his perspective that the state comes out
ahead if the gas is cycled for a long time. The legislature may
have to hire its own experts to be convinced about what the best
way forward is. He asked how the settlement agreement handles
the decision to do full field cycling or blowdown.
MR. BALASH explained that post IPS there is provision in the
agreement for a POD to be submitted.
CHAIR FRENCH asked if he believes it will be public.
12:38:49 PM
MR. BALASH replied he would have to look at the statute and
regulations to see what becomes public and when, but notice and
review processes for both plans of operation (POO) and plans of
development (POD) will take place over the life of this
agreement. DNR has agreed to approve the POD if it is consistent
with the agreement, but in a blowdown scenario, the definition
in the agreement describes the project as one that has gotten
AOGCC approval. He declined to specify the order of those steps.
12:40:21 PM
CHAIR FRENCH said the next line of questioning relates to
enhanced oil recovery (EOR), specifically the difficulty of
tracking Point Thomson gas when it is used to pressurize the
Prudhoe Bay reservoir. He asked if the state royalty interests
were the same in Prudhoe Bay and Point Thomson.
MR. BALASH said no. The Point Thomson unit has a variety of
leases; some are one-seventh, some are one-sixth, and some are
net profit share leases.
CHAIR FRENCH said it was his understanding that the accounting
details have not been worked out.
MR. BALASH clarified that some features will not change.
Specifically, there has been no change to the Point Thomson
royalty percentages in the leases and the resulting volumes in
the EOR case.
CHAIR FRENCH asked who will keep track of the volumes once the
Point Thomson gas joins an undifferentiated mass of Prudhoe Bay
gas and sits there for some period of time.
MR. BALASH directed attention to the provisions on page 47,
paragraph 4.16.2.4 of the agreement. When a volume of gas leaves
Prudhoe Bay, 75 percent is Prudhoe Bay volume and 25 percent is
Point Thomson volume. Within that 25 percent volume the working
interest owners and the state will account the relative royalty
share that has gone in. The agreement requires gas balancing
agreements be struck to ensure that all parties, including the
state, know whose gas is where and when.
12:44:49 PM
CHAIR FRENCH reviewed subsection ii on page 47 and asked if the
affected parties are Point Thomson and PBU working interest
owners and the state.
MR. BALASH answered yes.
CHAIR FRENCH asked what "gas balancing agreement" means.
MR. BALASH replied it is a standard feature of accounting for
the gas in the field and who owns that particular gas. If the
state were to sell its Point Thomson RIK gas in Prudhoe Bay to
some third party, there would have to be some accounting
mechanism for when that gas is put in Prudhoe Bay, when it is
taken out, and under what circumstances it is taken out.
CHAIR FRENCH said it was a fair answer, but he was still uneasy.
MR. FINDLEY added that injecting nonnative gas into another
reservoir and accounting for the molecules is not novel. The
accounting is not a simple procedure, but it's not uncommon. He
said the next question is what happens if the state wants to
withdraw that gas.
CHAIR FRENCH asked if he was talking about an option whereby the
state says it wants its royalty gas from the Prudhoe Bay
reservoir.
MR. FINDLEY answered yes. The state can withdraw its royalty
gas, but it has to live with the physical constraints of the
reservoir and within the constraints that Prudhoe Bay is still
an oil-producing field. The settlement contemplates an
agreement, including the possibility of over balancing the 75
percent 25 percent split for a short period.
He highlighted that this agreement also makes it clear that the
various Point Thomson royalty rates attach when the gas
molecules come out of Prudhoe Bay.
12:50:04 PM
SENATOR PASKVAN asked if the provisions on page 47 apply to
Alternative C, a pipeline for in-state use that is smaller than
0.5 bcf/d.
MR. BALASH confirmed that the RIK gas allocation principles
apply to Alternative C. Under the scenario that 1.2 bcf/d of gas
is moved to Prudhoe Bay, roughly 200 mmcf is going to be saved
as RIK gas. If a major gas sale project has not been sanctioned,
these rules apply going forward.
SENATOR PASKVAN said the public needs to understand that royalty
in kind gas applies solely to Alternative C, and that the only
way there will be an in-state line is if the state assumes some
of the cost.
MR. BALASH said how the state might use that in-state gas isn't
defined, but DNR views it as added value to the state. Under an
Alternative A scenario where a major gas sale project has been
sanctioned and is moving forward, the state will have a royalty
share of the gas that moves through that project, and it could
be used for in-state purposes. He reiterated that these
particular RIK provisions only apply to Point Thomson gas, not
Prudhoe Bay gas.
SENATOR PASKVAN reviewed the three alternatives. Under
Alternative A the producers essentially sanction a major gas
sale; under Alternative B the producers cycle at Point Thomson;
under Alternative C Point Thomson gas is injected into Prudhoe
Bay and that is the only option that triggers royalty in kind.
MR. BALASH said that in an Alternative A scenario Point Thomson
gas very likely will be moving into the system and provide
opportunity to take that gas in kind or in value.
12:55:36 PM
MR. KATCHEN clarified that the three options are not mutually
exclusive. A major gas sale would not eliminate the other
options.
SENATOR PASKVAN highlighted that under Alternatives B and C, a
large diameter gas pipeline may be many years into the future.
MR. BALASH agreed. In an Alternative C scenario, the gas would
be moved from Point Thomson to Prudhoe Bay and there would be an
opportunity to market that gas to Alaskans by some means. A
commitment in the agreement is that if by 2019 the working
interest owners haven't committed to cycling and a major gas
sale, the rough volumetric equivalent of Prudhoe Bay gas will be
commercially available to Alaskans.
12:59:57 PM
SENATOR COGHILL asked what has to happen to get to sanction of a
major gas sale.
MR. BALASH said the process to get to a sanction point is
measured in years. Today, because permits are not in hand the
boards of directors are not practically able to say yes, there
will be a pipeline. The 2016 date is realistic and somewhat
aggressive.
1:02:29 PM
MR. FINDLEY added that the definition of "sanction" in paragraph
2.28 requires documentary evidence of corporate approvals, firm
transportation service agreements, and necessary federal
regulatory certificates that have been issued and accepted.
CHAIR FRENCH said he had decided to formulate his questions
about the aspects of the agreement that are within the total
discretion of the commissioner versus judicial determination and
submit them to both legislative legal counsel and DNR for a
written response. He asked for summary comments.
MR. BALASH said DNR feels this is a good agreement for the
state. It achieves the objective of getting the field into
production and it puts the working interest owners back on the
clock. Either the resource will be produced or the state will
get the land back.
1:07:54 PM
Recess for lunch
^Point Thomson Plan of Operation: ExxonMobil
2:14:52 PM
CHAIR FRENCH reconvened the meeting and welcomed Mr. Bruce who
would deliver the ExxonMobil presentation.
LEE BRUCE, Senior Project Manager at Point Thomson, ExxonMobil
Corporation, stated that ExxonMobil and the Point Thomson unit
owners are committed to putting in the Initial Production System
(IPS). He delivered a PowerPoint and discussed the project
accomplishments to date; a summary of the project and schedule;
the project as it stands today; and the plans going forward to
meet the production startup date in the winter season 2015/2016
and extending no later than May 1. Responding to a question, he
confirmed the intention at startup is for ExxonMobil to begin
cycling 200 mmscf/d of gas. He further explained that the
project is located on the eastern flank of the North Slope, west
of ANWR and 25 miles east of Badami. The location is remote, the
environment is hostile, and there is limited access to any
established infrastructure. Supplies are delivered by ice road
and barge and personnel travel by helicopter.
2:20:01 PM
He highlighted that Point Thomson represents about 25 percent of
the discovered North Slope natural gas resources and that
ExxonMobil is committed to the long-term, responsible
development of these resources. He reviewed the progress on
wells PTU-3, PTU-15, and PTU-16 on the Central Drilling Pad
starting in July 2008 and that drilling in the hydrocarbon zone
is limited to November 1 to April 15 due to permitting
requirements from the North Slope Borough and the Department of
Environmental Conservation (DEC) to facilitate clean up in the
event of a spill. These rules continue in the yet to be approved
North Slope master plan.
MR. BRUCE reviewed the field layout and infrastructure, which is
all that will be needed outside of expanding for the next phase.
About 12 miles of road will be permitted to connect the outlying
east and west pads to the 56-acre central pad. This is specific
to ExxonMobil's operations at Pt. Thomson; no road will connect
to Badami. Site developments include a gravel mine, an airstrip
that can handle a Hercules-sized aircraft, and water reservoir.
2:33:49 PM
CHAIR FRENCH asked when the developments depicted in slide 5
would actually be on the ground at Point Thomson.
MR. BRUCE answered that the gravel and infrastructure will be
installed by the winter season 2014/2015, but not the
facilities. Gathering lines will bring gas from the east and
west pads to the central pad so it can be treated. The export
pipeline, which is in the same right-of-way as the west
gathering line, will go on to Badami. Responding to a question,
he confirmed that the export pipeline will have typical
pressures, whereas the gathering lines will be very high
pressure. Due to the corrosive flow stream at Point Thomson,
carbon steel lined pipe from Germany will be used.
2:36:11 PM
MR. BRUCE reviewed the plans for the initial production facility
on the central pad that will be in place winter season
2015/2016. The scope is to produce 10,000 barrels/d of
condensate into TAPS, cycling 200 mmcf/d of natural gas at
10,000 psi. He highlighted that this will be the highest
pressure cycling project in the world.
SENATOR PASKVAN asked for a definition of "cycling" and other
terminology.
MR. BRUCE explained that cycling is the process of producing oil
and gas from the ground. The liquids are separated from the gas
and the residual gas is then compressed to reservoir pressure
and reinjected. The produced condensate or liquids are treated
to meet pipeline-quality specifications and pumped into the
pipeline to join Badami and then on to TAPS.
He explained that the Point Thomson reservoir underlies the
Beaufort Sea. Extended-reach drilling techniques will be used to
enter the reservoir. The reach is 9,000-13,000 feet. He noted
that prior to PTU-15 and PTU-16, 19 wells were drilled in the
Point Thomson area in efforts to gain a better understanding of
the geology and resource.
2:42:20 PM
SENATOR PASKVAN asked the maximum gas capacity and the capacity
for processing liquids.
MR. BRUCE answered the design gas capacity is 200 mmcf/d and the
design liquids capacity is 10,000 barrels/d. The treatment
facility design is for these capacities.
CHAIR FRENCH commented that this appears to be an enormous
investment to produce a modest amount of oil. He questioned how
much capacity can be added for oil production in the future.
MR. BRUCE responded that capacity can't be added to this
facility. He added that part of this project is to determine the
next step by better understanding how the resource reacts in a
cycling mode, the connectivity of the wells, and what it takes
to work in this remote environment.
CHAIR FRENCH asked if production and injection will take place
in the same or different locations.
2:45:57 PM
MR. BRUCE answered that they take place in different locations
in order to sweep the reservoir, and a producer well is paired
with an injector well. For example, if PTU-15 is an injector
then PTU-16 can be a producer. The settlement agreement requires
a third well by the winter season of 2016/2017. That will be the
west pad well.
He reviewed the timeline and recapped the status of the project.
The detailed engineering for the IPS facilities is about 40
percent complete and the engineering for the pipeline and gravel
infrastructure is essentially finished. The expectation is that
the final EIS will be published in July and the Corps will issue
the record of decision on September 21. Civil and pipeline
construction can begin thereafter phased over two seasons.
Module installation will take place in the summer of 2015 and
additional drilling will take place in the winter season
2014/2015. The latter is for a saltwater disposal well,
completion of PTU-15 and PTU-16, and the west pad well.
MR. BRUCE outlined the construction goals for the upcoming
winter season, January through mid to late April.
CHAIR FRENCH asked how many jobs will be created by the upcoming
construction season.
MR. BRUCE estimated it would be about 600 jobs. He continued to
describe the project sequencing until startup in April 2016, as
described in the plan of operations.
3:07:31 PM
CHAIR FRENCH again mentioned that the facility as described
doesn't have the space to accommodate additional capacity in the
future.
MR. BRUCE responded that the existing facilities will be used in
conjunction with the yet to be identified next phase. He then
displayed a contractor tree with ExxonMobil at the bottom
followed by WorleyParsons FLUOR and many in place
subcontractors. Aside from Haskell Corporation, all are Alaska
based.
SENATOR WIELECHOWSKI asked how many people will be employed in
the next year and what percent will be Alaska hire through the
contractors and subcontractors.
MR. BRUCE answered that he could not give a percentage, but
there is a content requirement for Alaskans and North Slope
Borough residents. About 80 people are working on the project
team; half are employees and the rest are experts and
contractors. More people are working on the project itself, but
the day-to-day hiring has not been done. He reiterated that the
workforce is expected to peak at about 600.
SENATOR WIELECHOWSKI asked what steps ExxonMobil is taking to
ensure that the subcontractors are hiring Alaskans.
MR. BRUCE said the contracts have requirements to maximize
Alaska hire and ExxonMobil is working with contractors to ensure
those requirements are met once hiring starts in several months
or the fourth quarter. However, this is dependent on getting the
permits.
MR. BRUCE reviewed some of the community engagement and
consultation that has taken place and noted that Appendix I in
the plan of operations has 4-5 pages of the interactions with
residents of the North Slope Borough. He highlighted the direct
benefits to the state from the Point Thomson project and
concluded that the IPS lays the foundation for future gas
monetization on the North Slope. ExxonMobil's vision is to
distinguish the project with superior performance, be a good
neighbor and partner, and build trust with the State of Alaska.
3:18:34 PM
CHAIR FRENCH thanked Mr. Bruce and recessed the meeting.
3:25:50 PM
CHAIR FRENCH reconvened the meeting and opened public testimony.
3:25:59 PM
CHARLES MCKEE, representing himself, reviewed the materials he
was entering into the record including his ownership letter and
letter of sovereignty, a statement from the Congressional Record
in 1934 by Lewis T. McFadden, and pages from the fourth edition
of Black's Law Dictionary. He referenced earlier testimony,
mentioned the palming off doctrine, and raised the question of a
conspiracy chain. He relayed that when he worked on the pipeline
he witnessed the secrecy-shrouded delivery of a scale model of
the complete pipeline that included a gas pipeline running
alongside the oil pipeline. That model was destroyed, the actual
pipe disappeared, and the gas line was never built. It was a
lost opportunity, he said.
3:31:56 PM
WARREN CHRISTIAN, President, Doyon Associated LLP, stated that
Doyon is a union pipeline construction company and part of Doyon
Limited whose shareholders mostly reside in Alaska. In past
construction projects they attained over 90 percent Alaska hire
and over 30 percent Alaska Native hire and used local Alaska
companies to every extent possible. He stated support for the
Point Thomson project, which will help ensure a healthy economy
via increased flow through the pipeline and an opportunity for
contracts and employment. Doyon Associated will directly hire
over 200 employees over the next two years in support of this
project in addition to the Alaska subcontractors and vendors it
will utilize. This project will also provide an opportunity to
train the next generation of Alaskan construction workers with
the help of the individual union apprentice programs and the
Fairbanks training facility.
3:34:21 PM
JERRY MCCUTCHEON, representing himself, said the law of oil and
gas production is that maximum recovery can only be had when a
reservoir is produced at or above the bubble point. Because
there is no exception to this law, the only Alaska gas pipelines
will be from Cook Inlet to the Donlin Creek Mine and possibly
one from Cook Inlet to Fairbanks. A gas liquids pipeline will
run from Prudhoe Bay to Cook Inlet and the lower leg may be a
gas pipeline from Cook Inlet to Fairbanks.
He said that beginning in 1974 ExxonMobil said that Prudhoe Bay
would produce only 9 billion barrels of oil with or without a
gas pipeline, which flew in the face of all known reservoir
action. Even when challenged with engineering facts they would
not back down. That falsehood persists today, even though
Prudhoe Bay has produced more than 6 billion barrels of
additional oil because no gas line was constructed, and more
will be produced. Even the AOGCC in 2008 testified that the
state would be broke today if the gas pipeline of the 1980s had
been constructed.
MR. MCCUTCHEON cautioned that Alaska is nothing more than a cash
cow to ExxonMobil or any other oil company.
3:39:12 PM
BARBARA HUFF-TUCKNESS, Director, Governmental and Legislative
Affairs, Teamsters Local 959, thanked the committee for
continuing the hearings; they have elicited valuable
information. She stated for the record that Teamsters Local 959
is not part of the litigation, but is excited about the job
opportunities the members and employers statewide.
CHAIR FRENCH asked how many local 959 employees will work at
Point Thomson project.
MS. HUFF TUCKNESS said she's been told that about 100 members
would be employed. She also extended thanks for the ongoing
funding for the Fairbanks Pipeline Training Center.
3:42:27 PM
RICK ROGERS, Executive Director, Resource Development Council
(RDC), said RDC is grateful that the Point Thomson lease
litigation has been settled because it has been one of the
barriers to monetizing North Slope gas. The settlement appears
to be a commercially reasonable agreement with firm timelines
and work commitments as well as significant consequences for
failure to perform. It also has flexibility to accommodate the
unknowns.
He said ExxonMobil and the other leaseholders are among the
best-capitalized and technically capable companies in the world,
and that is required in a project of this magnitude. It is now
possible to move forward. He extended thanks to the
administration, the leaseholders, and this committee.
3:47:45 PM
BILL WALKER, representing himself, said he wanted to clarify the
reason that he appealed Commissioner Sullivan's decision to
enter into the Point Thomson settlement agreement. He said he
doesn't have an issue with ExxonMobil or those who negotiate on
behalf of the state. He was challenging the fact that it was
done outside the public process.
He said he was an aggressive proponent of developing Point
Thomson and he applauded those who were moving forward to do
some development after 47 years. However, the settlement
meandered beyond the core issue of the litigation, and was
presented as a final deal. He said he believes there is already
too much confidentiality in the state on issues associated with
oil and gas development. The public and the legislature need to
know more about what is happening. Negotiating the settlement
behind closed doors was a quantum step in the wrong direction.
3:53:50 PM
JOHN MACKINNON, Executive Director, Associated General
Contractors of Alaska, said this is a construction trade
association with roughly 650 members. He relayed that he first
met with ExxonMobil about four years ago to discuss how to
maximize Alaska hire and the use of Alaskan contractors on this
project. ExxonMobil committed to try to maximize the use of
Alaskan companies and they fulfilled that commitment. He said he
was pleased that the litigation was settled and would like to
see Point Thomson move forward to construction this winter.
3:56:01 PM
DAVE CHAPUT, Program Director, Alaska Frontier Constructors
(AFC), and Board Member, Resource Development Council, said that
for the last few years he has worked with ExxonMobil on the
Point Thomson project. He was testifying to highlight the
excellent job that ExxonMobil has done with regard to the safety
and health of the Alaskan workforce and protection of the
environment. The AFC workforce is looking forward to going to
work at Point Thomson helping to bring North Slope resources to
market.
3:57:49 PM
GARY DIXON JR., Vice President, Alaska Teamsters Local 959, said
that 150-200 teamsters will be employed on the Point Thomson
project at the peak. He talked about the union apprentice
program and the recruitment efforts in Alaskan communities.
Apprentices have a trade and can fulfill a good working career
on the North Slope. Point Thomson will provide a great
opportunity for the members and he is appreciative.
3:59:22 PM
KATHLEEN O'CONNELL, Vice President of Projects, PRL Logistics,
Inc., said that PRL recently received two large contracts with
the Point Thomson project to transport materials and people. She
explained that PRL does not have assets so it will use more than
25 companies to execute the two contracts This is the way that
ExxonMobil allows one company to manage the work that leverages
the powers of other companies. PRL is an Alaskan-owned company
that is currently 100 percent Alaska hire. It is committed to
responsibly developing Alaskan resources.
4:01:35 PM
CHAIR FRENCH asked how many people are directly employed by PRL.
MS. O'CONNELL said PRL currently has about 20 employees and
growth is anticipated during the course of the contracts. She
reiterated that the real power of PRL is its ability to leverage
all the other companies.
4:02:30 PM
CHAIR FRENCH closed public testimony and thanked everyone for
coming to the meeting.
4:03:13 PM
There being nothing further to come before the committee, Chair
French adjourned the Senate Judiciary Standing Committee meeting
at 4:03 p.m.
| Document Name | Date/Time | Subjects |
|---|---|---|
| 6.7.12 Sen French PT (2).PDF |
SJUD 6/12/2012 10:00:00 AM |
DNR Point Thomson Settlement |
| 6.7.12 Exhibit A to French letter (00033666).pdf |
SJUD 6/12/2012 10:00:00 AM |
DNR Point Thomson Settlement |
| 6.7.12 Exhibit B to French letter (00033603).pdf |
SJUD 6/12/2012 10:00:00 AM |
DNR Point Thomson Settlement |
| Dept of Law letter PTU 06.07.12.PDF |
SJUD 6/12/2012 10:00:00 AM |
Pt Thomson Settlement |
| Leg Legal Analysis PTU Settlement.pdf |
SJUD 6/12/2012 10:00:00 AM |
Point Thomson Settlement |
| Sen. Paskvan letter PTU 04.30.12.pdf |
SJUD 6/12/2012 10:00:00 AM |
Point Thomson settlement |
| Dept of Law response Paskvan letter 06.08.12.PDF |
SJUD 6/12/2012 10:00:00 AM |
Point Thompson Settlement |
| 3 - Point Thomson Settlement Agreement (March 29, 2012).pdf |
SJUD 6/12/2012 10:00:00 AM |
Point Thomson Settlement |
| ExxonMobil 6-12-12.pdf |
SJUD 6/12/2012 10:00:00 AM |
Point Thomson Settlement Exxon presentation |