Legislature(2017 - 2018)BUTROVICH 205
03/21/2018 03:30 PM Senate RESOURCES
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| Overview: Department of Natural Resources' Role in Natural Gas Commercialization Efforts | |
| Adjourn |
* first hearing in first committee of referral
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ALASKA STATE LEGISLATURE
SENATE RESOURCES STANDING COMMITTEE
March 21, 2018
3:30 p.m.
DRAFT
MEMBERS PRESENT
Senator Cathy Giessel, Chair
Senator John Coghill, Vice Chair
Senator Natasha von Imhof
Senator Kevin Meyer
Senator Bill Wielechowski
Senator Click Bishop
MEMBERS ABSENT
Senator Bert Stedman
COMMITTEE CALENDAR
Overview: Department of Natural Resources' Role in Natural Gas
Commercialization Efforts
- HEARD
PREVIOUS COMMITTEE ACTION
No previous action to record
WITNESS REGISTER
ANDREW MACK, Commissioner
Department of Natural Resources (DNR)
Juneau, Alaska
POSITION STATEMENT: Provided the overview: Department of Natural
Resources' Role in Natural Gas Commercialization Efforts.
ED KING, Gas Commercialization Advisor
Department of Natural Resources (DNR)
Juneau, Alaska
POSITION STATEMENT: Participated in the overview: Department of
Natural Resources' Role in Natural Gas Commercialization
Efforts.
STEVE WRIGHT, Senior Project Advisor
Alaska LNG Gasline Project (AKLNG)
Department of Natural Resources (DNR)
Commissioner's Office
Juneau, Alaska
POSITION STATEMENT: Participated in the overview: Department of
Natural Resources' Role in Natural Gas Commercialization
Efforts.
ACTION NARRATIVE
3:30:12 PM
CHAIR CATHY GIESSEL called the Senate Resources Standing
Committee meeting to order at 3:30 p.m. Present at the call to
order were Senators Bishop, Von Imhof, Wielechowski, Coghill,
Meyer, and Chair Giessel. Senator Stedman was excused.
^Overview: Department of Natural Resources' Role in Natural Gas
Commercialization Efforts
Overview: Department of Natural Resources'
Role in Natural Gas Commercialization Efforts
3:30:46 PM
CHAIR GIESSEL announced that today the committee would hear from
the Department of Natural Resources (DNR) about its role in the
state's natural gas commercialization efforts. She welcomed
Commissioner Mack who would go over the department's mission on
this goal, the tools that it possesses, and what legislators can
expect in the coming year related to natural resources.
3:31:29 PM
ANDREW MACK, Commissioner, Department of Natural Resources
(DNR), Juneau, Alaska, introduced himself and invited Steve
Wright, the Alaska LNG Gasline Project (AKLNG) Senior Project
Advisor and a consultant to the Commissioner's Office, and Ed
King, Gas Commercialization Advisor, to the table to help with
the presentation.
COMMISSIONER MACK said he would discuss royalty in kind/royalty
in value (RIK/RIV) and obligations the DNR has with respect to
that decision, the process of royalty gas disposition, lease
management considerations, and DNR engagement with the Alaska
Gas Development Corporation (AGDC) and related DNR contracts and
agreements, which are contemplated under SB 138.
3:33:55 PM
He said it's important to frame the first issue to give the
committee a very clear look at where he believes they stand in
the process. He has been asked how much progress they have made,
and the truth is they are in the early stages of the evaluating
portion, but under the AKLNG process, he feels they are in good
shape. A couple of critical points are:
1. SB 138, that created and established AGDC, is still
the law they follow, and they take those
responsibilities seriously.
2. They believe SB 138 as a legal structure fits very
well with the way the project is currently structured,
which is different than what was envision when it was
passed. They have not been aware of any
inconsistencies with how the project is currently
formulated.
3:36:01 PM
COMMISSIONER MACK said he wanted to describe how the department
is meeting its obligations, walk through where he feels the
project is from a DNR perspective, and tell them what resources
the department has available. In 2016, when he came to this
position, the DNR Gas Commercialization Team had a dedicated
budget and eight staff and facing a situation where the
companies had collectively indicated that as an equity-based
project they weren't sure it would pass muster. An offer was
made, and the state accepted, to take the lead in the project.
He views 2016 as a transition year, he said, and in that
process, he made the difficult decision of "right-sizing" their
effort by laying off or moving those eight employees from DNR
employment to other areas in DNR or other agencies. He worked
very hard to maintain critical pieces of the team including
Steve Wright, whose background is having been the working
interest representative for Chevron at the two North Slope Units
that are implicated by this project (Prudhoe Bay (PBU) and Point
Thomson (PTU); and maintained the contract with the consultants,
Black and Veatch.
COMMISSIONER MACK said that it's been pretty public that a
transition was going on where the data and underlying resource
reports which were provided to the Federal Energy Regulatory
Commission (FERC) to support the project were being tied up and
submitted. There was also the effort by the Governor, himself,
AGDC, Keith Meyer, and John Hendricks of going out in the
market, traveling, and meeting with potential interested
parties. They took a couple of trips in 2016 to Singapore,
Korea, and Japan and talked about the opportunity and the
opportunity in terms of a project. He was there specifically,
because he was talking about the great potential on the North
Slope.
3:39:37 PM
COMMISSIONER MACK said 2017 was really a marketing year, and
until late in 2017, they didn't have a "close bead" on what the
opportunity was. But obviously, with the announcement of the
Joint Development Agreement (JDA), the department can now set
its sights on that opportunity. This effort is being resourced
within the DNR Commissioner's Office and within DNR itself
including Mark Wiggin, DNR Deputy Commissioner, as the DNR Gas
Commercialization Manager; Ed King, DNR Gas Commercialization
Advisor; Steve Wright, AKLNG Senior Project Advisor; and they
still maintain Black and Veatch as a contractor for commercial
and upstream analysis.
For commercial support the Division of Oil and Gas (DOG) has
three individuals: Rebecca Kruse, DOG legal counsel; Greg
Bidwell, the lead commercial analyst; and Johnny Maisa, DOG
commercial analyst. For legal support they rely on the
Department of Law (DOL): principally on Martin Schulz, Peter
Caltagirone, and outside counsel Matt Finley with Ashburn &
Mason. For permitting needs, they have Heidi Hanson, DNR Deputy
Commissioner; Faith Martineau, the new Executive Director for
the Office of Project Management and Permitting (OPMP); Jason
Walsh in the DOG's State Pipeline Coordinator's Office; and Don
Perrin, the specific permit coordinator at OPMP for the AGDC
project.
3:41:09 PM
COMMISSIONER MACK said the reality is that none of these people
are exclusive to this project, but they all have many years of
experience; this is just a part of their job. They do have the
benefit of the experience of SB 138, which was passed in 2014.
With 2016 being the transition year, he said DNR didn't do a lot
of work on the project in 2017. But, at the end of the year they
saw the announcement of the JDA, and so they started to
restructure and ramp-up efforts. The project doesn't have a
dedicated budget, but it is poised, and this is the team that is
going to be doing the work.
SENATOR BISHOP asked him to provide the committee with an Office
of Research and Development (ORD) chart.
COMMISSIONER MACK answered, "Absolutely."
Slide 3: Primary responsibilities for DNR
COMMISSIONER MACK said AS 38.05.182 stipulates that DNR will
elect to receive Alaska LNG royalty gas in-kind (RIK), unless
the DNR Commissioner finds that taking gas in-value (RIV) would
be in the best interest of the state. The normal process is for
DNR to send a letter to the Senate President and the Speaker of
the House - the last letter was sent March 31, 2017, and it
stated that RIK is the default. However, in most cases, the
state takes RIV. The letter points out where the state has
actually gone through the process of determining where to take
RIK.
Briefly, he explained the process. If there is an indication of
interest before entering into an RIK contract, DNR has to do a
preliminary best interest finding (BIF), which is usually being
developed at the same time a contract is being negotiated. The
department has two contracts currently: one with Endeavor and
the other with Petro Star; both are in-state refiners which buy
royalty oil. Ultimately, this issue has to go out for public
comment and then to the Royalty Board before it comes to this
body for legislative approval.
This process has been ongoing since there has been a royalty
contract in Alaska. The most important parts of it are the BIF
and the fact that any RIK contract has to come before this body
for ratification. They would go through the same process if a
decision were made to propose a RIK contract for gas sales.
3:45:40 PM
CHAIR GIESSEL asked what criteria he uses when making the
decision to choose to do the default (RIK).
COMMISSIONER MACK said that decision implicates two statutes: AS
38.05.183(e) and AS 38.06.070(a). Generally speaking, biggest
criteria are the cash value and the "projected effects on the
state's economy." AS 38.06.070(a) provides that the decision is
based on the revenue needed and the projected fiscal condition
of the state, which he thinks is the most important element.
CHAIR GIESSEL asked what resources or experts he would rely on
in making that evaluation.
COMMISSIONER MACK said he would rely on the team he just
identified. Historically, when the state has done RIK contracts
for oil, they have been done exclusively internally by DOG
employees. Outside counsel has been used only a few times. For
this particular question, he would use both the lead commercial
analyst, Greg Bidwell, Mr. Wright, a contract employee, Deepa
Poduval with Black & Veatch, and other support employees. He
would also consult with the Department of Law and the Department
of Revenue.
3:49:28 PM
At ease
3:50:47 PM
CHAIR GIESSEL called the meeting back to order at 3:50 p.m.
COMMISSIONER MACK said he was able to find the criteria under AS
38.05.183 (e) and it says: the cash value offered, the projected
effects of the sale on the economy of the state (critical), and
a couple that are focused on the benefits of refining in-state,
which might not be particularly relevant.
Then the criteria lists AS 37.06.070, which talks about some
very broad concepts including the revenue needs and projected
fiscal condition of the state, the existence and extent of
present and projected local needs for oil and gas products and
byproducts, the desirability of localized capital investment,
social impacts of the transaction, and additional costs and
responsibilities which could be imposed upon the state and
affect political subdivisions by development-related
transactions.
These two statutes describe the criteria very thoroughly. Most
recently, he said, and this body and this committee reviewed the
Petro Star contract and ultimately ratified it. It has been done
a number of times for royalty oil contracts, and the department
has been able to show where the state can get a modestly
increased price.
CHAIR GIESSEL thanked him for the explanation and said the cost
of this project is massive and legislators want to make sure the
state is getting an equally massive value out of it. She asked
if legislators can expect the same level of detail in his
document outlining decision points and data the decision was
based on.
COMMISSIONIER MACK answered yes. He added that royalty contracts
contemplating selling royalty oil use a quantum of 10, 20, 30,
and 40 thousand barrels and most royalty oil contracts are five
years in length. Gas contracts are different in that they are
much larger and presumably longer. Most people would agree that
in order for this evaluation to be found in the interests of the
state for this body to deliberate, it would have to be a much
longer contract, which adds complexity.
3:55:14 PM
CHAIR GIESSEL said she totally appreciated that and expects to
see detailed modeling on those criteria and asked if he
envisioned a particular time he would make the best interest
findings (BIF).
COMMISSIONER MACK replied they are not on a specific time table,
but it is somewhat sequential in the sense that they have to
understand what the other gas sales contracts would look like
for comparison. Now they feel they are in a good position to
make that evaluation, but they are at the front end of it. A
couple of years ago, the person had been identified and hired to
start the process of writing the preliminary BIF on what an RIK
evaluation would look like, but that never materialized. So,
they know that is in front of them.
CHAIR GIESSEL said she thought it would be some ways down the
road when he actually has data about what the price of the gas
will be at the wellhead and what the construction costs of the
project will be and those might be in ranges, and she asked if
he would be able to provide the legislature with the analysis
for the different price and cost ranges in terms of making their
decision. They want to know how broad his data is and whether it
covers those kinds of variables.
COMMISSIONER MACK replied the statute has opportunities for
conversation around what those factors are. This is when they
have an evaluation in hand, which they are relying upon to make
a recommendation for an RIK selection, if that's the way it
goes.
CHAIR GIESSEL said she suspected that the co-chair of the
Finance Committee will be interested in that information.
3:58:34 PM
SENATOR VON IMHOF asked if he anticipated that the amount of RIK
gas the state may be able to take may change depending on
whether the state has a 25 percent, a 10 percent, or a zero
percent ownership.
COMMISSIONER MACK answered when the state makes its decision to
select RIK, a rate is set, but the producers also have to decide
they want to provide their tax as gas. There is an opportunity
for that percentage to go up and down during negotiations if
certain decisions are made with respect to other parts of the
project. From his perspective, they are looking at this as a
royalty portion and a TAG portion, a fairly well-laid-out
sequence in the law. Either they go down that road and end up
with 25 percent of the gas being available or it becomes an RIV
situation.
4:00:31 PM
SENATOR VON IMHOF asked if the state gets any take in the
scenario where a dominant equity investor owns the
infrastructure and chooses to purchase the gas right at the
beginning point before it goes into the pipe.
ED KING, Gas Commercialization Advisor, Department of Natural
Resources (DNR), answered that the royalties that were due are
lease-conditioned. At Point Thomson, 14.5 percent of the gas
that is produced belongs to the state. Then the state has the
option of either taking monetary value of that gas or taking
physical custody of it and trying to sell it for a higher price.
In Prudhoe Bay, all of the leases are 12.5 percent, so the state
gets 12.5 percent of all of that gas regardless of who the
leaseholder or purchaser of the gas is. The Department of
Revenue also has a tax component, which is not a lease agreement
but a compulsory requirement by the legislature that the state
owns 13 percent of the gas that is produced with the royalty
subtracted first. It works out that 24.2 percent of the total
gas that is produced belongs to the state regardless of who the
investor, lessee, or purchaser is.
4:02:30 PM
Slide 4: Royalty Gas Disposition - RIK
STEVE WRIGHT, Senior Project Advisor, Alaska LNG Gasline Project
(AKLNG), Department of Natural Resources (DNR) Commissioner's
Office, said he is engaged in North Slope gas commercialization
efforts for the state. He said slide 4 discusses a few of the
critical aspects to disposing of state's royalty gas under an
RIK scenario.
MR. WRIGHT explained that under the current AGDC-led project
structure, if DNR elects to receive RIK, the state could sell
its royalty gas and tax as gas (TAG) to the Alaska Gas
Development Corporation (AGDC), and AGDC has had extensive
conversations about how to monetize gas.
Custody transfer of the state's RIK and TAG gas share from the
Prudhoe Bay Unit (PBU) and the Point Thomson Unit (PTU) to any
potential buyer would take place on the North Slope, either at
the wellhead, at the fence line for either of the units, or at
the inlet to the gas treatment plant (GTP). This point is still
uncertain.
The DNR is actively engaged with AGDC on discussions regarding
development of the Gas Sales Agreement (GSA). A contract for
sale of the state's RIK and TAG gas will require a Royalty Board
recommendation and approval by the legislature.
4:04:41 PM
COMMISSIONER MACK said in regard to custody, one of the things
they are aware of (from the equity-based model with the three
producer companies) is that the application to the Federal
Energy Regulatory Commission (FERC) included the lateral between
the two units. That is still pending at FERC. The two units were
viewed as being critical to the development of the project,
because the resource was needed to bring down the cost. So, in
an equity-based project it was easy to foresee how that would
get built. Now that AGDC has taken the lead, it's not entirely
clear but it is contemplated that they would be the entity that
would take the lead in building the project. The reason the
second bullet point on slide 4 is unclear is because there is
still room for negotiation.
4:06:14 PM
MR. KING remarked that the department has two options when it
takes its royalty: it can take physical custody of gas in kind
and then it has the responsibility of disposing of it, which
requires a marketing team and a contract. Another option is to
effectively let the producers sell the gas for the state (coat-
tail on the producers' contracts), which is done by taking
royalty in value (RIV). This is where the state receives the
same value that the producers receive for the gas that it owns
as royalty gas. If the state does that, all it has to do is
determine what the value at the wellhead is in order to
determine how much money is due. In order to do that, the state
would need to be able to calculate what the royalty value is,
which would require the state to see the contracts, the tolling
arrangements, and transportation costs (the same as the state
does to back up the costs for the oil fields). If the state
can't beat the royalty value that the producers are selling
their gas for, then the department has the option to simply take
the same value that they are receiving.
MR. KING said SB 138 provided a provision to AS 38.05.180(ii)(2)
that allows the department to modify leases in order to clarify
the value of the methodology for determining the value of the
gas, something that is lacking in current law, just because the
North Slope has never had a commercial gas sale. If the state
were to decide to do RIV, it's likely that some of those
existing ambiguities would need to be rectified, and the
commissioner would have the authority to amend the leases.
SENATOR BISHOP remarked that the Alaska Oil and Gas Conservation
Commission (AOGCC) didn't provide the state authorization to
make a gas sale until a couple years ago.
MR. KING apologized and said he didn't mean to imply fault.
COMMISSIONER MACK added that October 15, 2015, is when the
Alaska Oil and Gas Conservation Commission (AOGCC) issued its
first order approving offtake to match some of the volumes the
project contemplated. It was a very critical juncture, because
they pointed out to 2020, 2021, 2022, 2023, 2024, and 2025 as
the probable dates when gas could be taken off the Prudhoe Bay
Unit.
CHAIR GIESSEL went back to slide 5 and asked him to list what
the "net allowable deductions" would be.
4:09:37 PM
MR. KING answered the lease terms require that payment be
received at the point of production. A lot of times - when
selling oil, for example - it has to be shipped down the
TransAlaska Pipeline (TAPS) and down to California, and all the
costs associated with that transportation are allowable
deductions. The lease terms also have costs that are associated
with producing the oil or gas that can be construed as allowable
deductions. However, leases have changed over the years and
companies have different allowable deductions called "field cost
allowances" or "unit cost allowances."
CHAIR GIESSEL commented that field cost allowances were brought
up in a written answer from questions to the AGDC implying that
field cost allowances were somehow brought before the
legislature for approval, and that is something she wasn't aware
of. She asked for clarification.
COMMISSIONER MACK answered that field costs in many cases have
been negotiated and settled and it is not unusual for the state
to be dealing with them. Most field cost allowances are
contained within the settlement agreements, although some are
outstanding.
He said that field costs at the Point Thompson Unit are
significant issues that need to be dealt with. It has a new
production facility, unlike Prudhoe Bay which has been in
production for a long time and the state has come to an
understanding with the operator.
CHAIR GIESSEL said those are decisions between DNR and the
producer or the company.
COMMISSIONER MACK added, "And the court, Madam Chair." A number
of those issues have been litigated. But other cases have been
negotiated and settled.
Slide 6: SB 138 Allows Lease Amendments
MR. KING said AS 138.05.180 (hh) and (ii) (authority and
standards) had provisions giving the commissioner the authority
to modify leases. The royalty contract terms are binding on both
parties. So, they can't just be changed without approval by all.
The department doesn't have general authority to renegotiate
contracts unless the legislature gives them explicit authority
or if the department takes the contract to the legislature.
However, under SB 138.05.180 (j), the department has royalty
modification authority to reduce royalty rates when it is
required.
SB 138 gives the department additional authority to modify
specific lease terms. One of those is the ability for the
commissioner to decide to take RIK or RIV within a certain
window. Usually, in a royalty oil contract, the tell the
producer is notified that in 90 days the state wants its oil in
kind, and that would satisfy the contract. When that contract
expires or if the buyer were unable to accept the state's oil
for some reason, the state has the ability to switch back to
RIV.
MR. KING explained that when they were talking about the AKLNG
project back in 2014 when SB 138 was passed, it was very
critical to all parties to have supply security during the
initial project term: producers were very afraid of the state
being able to make switches from RIK to RIV. So, the legislature
gave DNR the authority to remove that switching ability. They
also gave them the authority to modify or create a new
methodology for calculating the allowable expenditure deductions
(that generates the RIV amount).
As he said before, some ambiguities have been litigated in the
past. The legislature gave the department some authority to
remedy some of the ambiguities with the contract or on leases
that were not fixed rate royalties (a sliding scale royalty that
changes as production or price levels change or when there is a
net profit share term (NPST), which is an additional payment to
the state once capital is recovered). These two types of leases
also gave rise to the ability for the amount of gas that was due
to the state to change on a month-to-month basis. It was very
difficult under an equity structure - where the state had a
fixed amount of capacity - if it had fluctuating amounts of gas
supply it was trying to move over a fixed amount of capacity.
So, the authority was given to DNR to "levelize" the royalty
rate. For instance, for a 12.5 percent royalty with a 30 percent
NPSL, they would do the calculation and figure out what the
right number was that gives the equivalent value. The sliding
scales are similar where instead of being able to slide they
would just calculate the equivalent value.
4:17:21 PM
He said this issue isn't as big of an issue any more under the
new model, because the fixed capacity isn't really constraining
the producers or the state. It isn't as important, and
therefore, they have not done any work on it since the project
structure changed.
Slide 7: DNR Commissioner's RIK Finding.
MR. WRIGHT said the North Slope has no other competitive major
gas sales project to monetize the gas at PBU and PTU, and so a
noncompetitive sale is most likely, and that is contemplated
within the statutes. In that case, DNR must find that selling
the gas to AGDC in a non-competitive contract is in the state's
best interest. The gas sales contract will then need to be
ratified by the legislature. Before entering into an RIK
contract to sell gas, DNR must also issue a finding that in-
state gas demand would be met under the project design. AGDC has
said publicly that they anticipate setting aside up to 500
million cubic feet of gas, which is currently more than twice
the state's gas consumption for future and current in-state gas
needs. AGDC has the responsibility to assess those in-state gas
demands along with support from DNR.
CHAIR GIESSEL said that probably DOG staff would do that
assessment and determine if the 500 mcf is accurate.
4:20:00 PM
COMMISSIONER MACK answered that DNR has a lot of information and
technical staff to evaluate what those needs would be, although
they don't get into the distribution end of things too far. For
instance, the Cook Inlet Natural Gas Storage Alaska (CINGSA)
facility on the Kenai Peninsula had to have been approved.
CHAIR GIESSEL recalled that DNR originally was going to
participate in marketing of the gas and asked if they would
still be engaged in any in-state marketing for potential
resource development projects that would be using gas, like
mines.
COMMISSIONER MACK answered yes. DNR would be in a position to,
and be in a position of ensuring that if there is an RIK event,
that the project is poised to actually fill those needs. He
invited Mr. King to respond to an RIV scenario.
MR. KING said for an RIV scenario, the department is required to
make sure that domestic needs are met, which falls under the gas
sales statute, AS 38.05.183 (d). If the gas is going for export,
the department has to make a finding that domestic needs are
satisfied first. They would also be leveraging the work the AGDC
is doing in the same way. If the state were to sell its gas to
AGDC, AGDC would be required to meet those standards, as well.
4:22:43 PM
SENATOR MEYER asked where he would anticipate keeping this gas:
in Nikiski, on the North Slope, or build storage somewhere?
MR. KING replied that it wouldn't be prudent for the state to
elect RIK and then store the gas. An RIK election would be under
an RIK sales contract in which case the gas would be transported
through the pipeline to a consumer.
SENATOR MEYER responded that language says, "the AGDC
anticipates setting aside," and that was confusing.
COMMISSIONER MACK replied that was maybe not the most artful way
to say it, but it would be to commit a specific amount to sales
contracts. The project contemplates five offtake points for
domestic use. Presumably, if there is an RIK contract, that
demand might be met by the state as a seller of gas, but those
would be previously negotiated contracts to utilities that would
associate the costs of taking gas off the system and
distributing it. If it were an RIV event, that obligation would
probably fall to AGDC, and he didn't think a storage component
was contemplated.
4:24:31 PM
SENATOR MEYER said that Donlin Creek is anticipating building a
pipeline to its mine in Cook Inlet. He asked if DNR anticipates
selling them some of the gas and would they be competing with
the smaller companies in the Inlet.
COMMISSIONER MACK answered in an RIK situation, they would be
marketing the gas and would contemplate selling it to a project
like Donlin Creek. There would be competition because of
existing production in Cook Inlet. He assumed people were
talking about the energy needs for the project.
MR. KING clarified that the intent is that AGDC would not sell
all the gas to foreign export users. It would withhold 500
mcf/day of gas that is not under a long-term, fixed contract so
that it can meet in-state needs. It isn't intended to mean that
gas would be put in storage for future use. If the need existed,
it would be available; and if it wasn't needed, it could go to
export.
SENATOR BISHOP commented that it could just sit in Prudhoe Bay
until needed.
COMMISSIONER MACK said that was correct.
SENATOR COGHILL wondered how the gas would move through the pipe
and what that does to the cost of transportation.
MR. KING replied that the cost of transportation is going to be
effectively the cost of operations and capital divided by the
number of molecules that are transported through the pipeline.
So, AGDC would have to model a situation in which the gas was
suddenly diverted to a mine.
COMMISSIONER MACK supported that answer. He said the thought is
once the system is up and running that the pull will be so
strong that those costs won't be significant in the long run.
4:29:04 PM
SENATOR COGHILL acknowledged that this issue was way out in the
future, but if the state is selling its gas as RIV and then an
Interior community pulls off a small amount, 150 mcf, could the
value be backed up enough to make up for some of the costs.
CHAIR GIESSEL said she assumed that would be part of their
analysis.
COMMISSIONER MACK replied that the effect on communities is
specifically one of the criteria in their evaluation and it is a
big impact. Several communities have a rural energy component.
SENATOR VON IMHOF said earlier she asked what the state's RIK
would be if the state ended up owning zero percent of the
pipeline or a small percent. If the state ends up owning zero,
but it is going to set aside 500 mcf, the dominant equity
investor might not be happy about that. How is that addressed?
COMMISSIONER MACK responded that they have to be careful about
investment and ownership. Early discussions didn't include a
system owned by anybody other than the State of Alaska. The
investments come from another spot.
MR. KING remarked that investors are always going to find a
return on their investment and will require some revenue stream
in order to get that. The way that is done in a pipeline is by
charging a toll for moving gas through it, the transportation
cost. The owners end up paying a toll (a tariff) to the
midstream owners, the same as for the TAPS now. The big
advantage the state had as an investor under the equity model
was that the return on that capital would flow to the state
rather than to the owners of the pipeline. The same thing would
be true in this model if the state is going to put up its own
money; it gets return on that capital. If state were to take its
gas in RIK it would have to ship it over the pipe and pay a
toll. But that is not the model that is being contemplated now.
The model that is most commonly cited now would be a wellhead
sale and then the AGDC or its investors would be responsible for
the cost of transportation.
4:33:23 PM
SENATOR VON IMHOF recapped that as soon as the state takes its
24.5 percent, then it sets aside about 500 mcf in value for in-
state needs regardless of the ownership of the pipe and
infrastructure.
COMMISSIONER MACK replied that law states that has to be a
requirement/condition of the financing package.
SENATOR VON IMHOF followed up asking since investors haven't
been attracted yet, the department doesn't know what type of
conditions and terms will be negotiated - rational or irrational
- so, making any assumptions right now is theoretical. One of
her concerns is if legislators will be privy to those terms
prior to any inked signatures on the line.
4:35:04 PM
SENATOR BISHOP reminded them that "the law of the land is half a
'B' a day for Alaskans." He thought distance-sensitive rates had
been built into SB 138 for the five offtake points in Alaska.
MR. KING recalled that conversation, but he didn't think
distance-sensitive rates got into the final version of SB 138.
SENATOR MEYER followed up on Senator von Imhof's question asking
at what point in the project DNR will find that selling the gas
to AGDC in a non-competitive contract is in the state's best
interest.
COMMISSIONER MACK replied that he is referring to an RIK
situation, and that point has already been passed; DNR
determined to go down the path of taking RIK. Was his question
when that would happen?
SENATOR MEYER replied he already said he wasn't sure when that
would happen and asked if it will happen prior to any deal being
signed and ratified.
COMMISSIONER MACK replied they need to understand what the
fundamentals of an RIV contract would be and what the other gas
sales contracts fundamentals are and what the value to the state
might be under that scenario before starting to evaluate RIK.
DNR needs to figure that out before any final decisions about
the disposition of royalty gas.
SENATOR MEYER recapped his question: before the state makes any
commitments, that determination will have been made.
COMMISSION MACK responded "yes."
4:38:17 PM
Slide 8: DNR Commissioner's RIK Finding
MR. WRIGHT continued that AGDC currently contemplates buying gas
from Prudhoe Bay and Point Thomson Unit from the working
interest owners and possibly from the State of Alaska using an
alternative pricing mechanism that offers two alternative price
structures: the first is a fixed price structure selling a unit
of gas either in MMBtu at a fixed price set and determined in
advance or second, by using wellhead netback pricing with a
fixed floor. The objective is to establish a fair gas price
structure for the sellers and buyers that will incentivize the
completion and success of this very complex and unique project.
One of the key determinants on the state's side for revenue
realization from the project is whether revenues get shifted up
or down the value chain from the upstream units where it
receives title to the gas and could transfer it to a seller. A
key provision being discussed involves the terms for byproduct
or CO disposition and handling as it needs to be defined in the
2
gas sales contracts that AGDC hopes to develop. The cost
associated with byproduct handling and disposition could be a
real value lever for some of the other stakeholders in the
project in that the state doesn't want to work hard to establish
a good revenue stream at the wellhead and then see some of those
revenues or values eroded further downstream by a
disproportional high cost for CO handling and disposition. They
2
there will be many tcf of carbon dioxide and some other
impurities that will need to be disposed of, and at this point
very likely disposed of within the two participating units in
the major gas sales project. So, they are going to be very
careful to make sure that the provisions of the gas sales
agreements have terms that are favorable for the state in terms
of allocation of byproduct handling.
4:41:21 PM
CHAIR GIESSEL asked how the CO was going to be paid for under
2
the previous agreement with the three producer partners.
MR. WRIGHT answered that hadn't been firmly established, but
what had been discussed was that the very large gas treatment
plant (GTP) would be located in or adjacent to the Prudhoe Bay
Unit. The gas impurities would flow back to the Prudhoe Bay
Unit, which would incur operating costs to dispose of that gas
into an underground reservoir. The unit operator would then be
responsible for disposition of that gas and would receive some
relatively equitable compensation for managing it. Scenarios
were modeled around reinjection of the CO into the gas cap at
2
Prudhoe Bay Unit would be advantageous for additional liquids
recovery, whether there were shallower reservoirs that would be
technically capable of receiving those volume of CO, and whether
2
the reservoir has sequestration characteristics that would hold
and store CO volumes for an extended period of time as would be
2
required to make sure it didn't leak either into the producing
reservoirs or back up to the surface. A tremendous amount of
reservoir engineering work was going on around CO disposal and
2
none of it was fully completed on the last effort.
4:43:25 PM
SENATOR VON IMHOF said she is hearing that there are potentially
two opportunities to buy the gas from producers: once when it
comes out of ground or as clean gas if the GTP facility gets
built.
MR. WRIGHT replied yes, but what is being discussed now is
either within the production units at the wellhead or the flange
going into the GTP. So, the raw gas as its produced from the
unit would be sold and ownership transferred, and the byproducts
stream coming out of the GTP would be returned to the sellers.
That would be a viable setup for working interest owners. That
would prove to be problematic for the state without its ability
to participate in unit operations at Prudhoe Bay. That is one of
the aspects of a gas sales contract the state needs to work with
AGDC.
SENATOR VON IMHOF asked him to provide a range of dollar amounts
for raw gas.
MR. WRIGHT replied that speculative values have been placed on
it. AGDC negotiations with the producers are confidential and he
didn't know what terms are being discussed.
4:45:49 PM
Slide 9: RIK and RIV Benefits and Risks
MR. WRIGHT said slide 9 depicts a set of known and assumed
benefits and risks associated with either an RIK or an RIV
election to summarize some current understandings. Under the
benefits portion of the RIK column, AGDC's purchase of the
state's royalty and TAG gas would benefit and support the
state's LNG marketing relationships that are being developed
globally. The state in an RIK election process would also avoid
the necessity of having to audit the producers contracts and
procedures around gas sales. The audit process under RIK could
be fairly fraught and finding ways to mitigate that might be
considered beneficial by some of the project stakeholders.
Potential risks associated with RIK elections include the
possible disadvantage the state might pay in cost allocation for
byproduct handling and disposal. Also, locking in a long-term
RIK election for the initial project term, which is estimated to
be 20-25 years, could eliminate the opportunity to switch from
RIK to RIV if problems arise during the execution of the project
that hadn't been anticipated or if the economic outcome of the
project didn't match pre-investment for gas. Finally, field cost
allowance issues related to production and gas processing
certainly have the opportunity to shift value up and down the
value chain and could impact state revenues.
4:48:31 PM
On the RIV column, benefits include the state would have no
exposure to negative netback risk. This was a concern under the
previous project structure where it was envisioned that there
would be a wellhead netback pricing structure that didn't
include a fixed floor. Under the current pricing mechanisms that
AGDC is looking at currently, they seem to have found ways to
mitigate that negative netback risk using either fixed pricing
or a wellhead netback with a fixed price floor. Under an RIV
scenario the state would also receive its value if the producers
elect to market their own gas to foreign buyers and potentially
benefit from the global marketing expertise that these major
international oil companies who have LNG portfolios world wide
could sell into and could potentially capture greater value than
markets that the state or AGDC could tap into.
One of the risks in RIV is there is always future uncertainties
regarding the RIV value to the state around commodity price
fluctuations globally, transportation deductions which may
change over the life of the project, and scenarios where in an
RIV world the state revenues could be fairly dramatically
eroded.
MR. WRIGHT said they are now looking to characterize and compare
and contrast the relative benefits and risks around RIK as
opposed to RIV.
4:50:33 PM
Slide 10: Engagements with AGDC
COMMISSIONER MACK added that the DNR commissioner's office is
engaged with AGDC on a number of parallel paths, and actively
engaged on royalty and TAG gas sales. The OPMP Office is
providing agency coordination and support of the AKLNG project
and the very experienced Don Perrin has been retained to
coordinate that effort.
One of the things that has come up recently on the permitting
side is the activity at FERC, which is going very well. It's
common to have lots of questions. The application put together
as part of the process which was led by ExxonMobil is still
intact and moving forward.
COMMISSIONER MACK said he personally traveled and DNR
participate in engagements with potential LNG markets and buyers
in 2016 and those have led to successful securing of interest in
the project under the ADA that was signed last November. And
they are working on the integration of the LNG projects ongoing
commercial analysis, too, with a team of folks including some at
the table, Black & Veatch, and others.
4:52:48 PM
Slide 11: DNR's Role in Contracts
MR. KING said for completeness he wanted to talk about the role
of DNR in contracts and contract negotiations. Under SB 138, DNR
had two sections: one was a new authority for the commissioner
to enter into contracts related to North Slope gas sales; the
other being the lease amendments talked about earlier.
DNR now does have the authority to enter into contracts. That
was very important under the equity model when trying to figure
out things like gas balancing agreements. They were able to
enter into confidentiality agreements and enter into commercial
agreements with producer partners. But they aren't currently
under any of those contracts, but as they move forward, they
will probably need to use this authority to enter into contracts
in the future.
SENATOR BISHOP editorialized that the commissioner had some big
decisions to make and he didn't envy him.
4:54:58 PM
CHAIR GIESSEL said the committee is aware of the importance of
hearing from DNR. She thanked the presenters saying that members
would watch closely as they make the BIF and RIK decisions.
4:55:28 PM
CHAIR GIESSEL adjourned Senate Resources Committee meeting at
4:55 p.m.
| Document Name | Date/Time | Subjects |
|---|---|---|
| Senate Resources - Hearing Agenda - 3 - 21 - 18 .pdf |
SRES 3/21/2018 3:30:00 PM |
|
| SRES DNR Alaska LNG Presentation.pdf |
SRES 3/21/2018 3:30:00 PM |
AK LNG |
| DNR Gas Team Organization Chart, Rev 2 3.27.2018.pdf |
SRES 3/21/2018 3:30:00 PM |
AK LNG |