Legislature(2007 - 2008)BUTROVICH 205
04/16/2007 01:30 PM Senate JUDICIARY
| Audio | Topic |
|---|---|
| Start | |
| SB104 | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| += | SB 104 | TELECONFERENCED | |
ALASKA STATE LEGISLATURE
SENATE JUDICIARY STANDING COMMITTEE
April 16, 2007
1:36 p.m.
MEMBERS PRESENT
Senator Hollis French, Chair
Senator Charlie Huggins, Vice Chair
Senator Bill Wielechowski
Senator Lesil McGuire
Senator Gene Therriault
MEMBERS ABSENT
All members present
COMMITTEE CALENDAR
SENATE BILL NO. 104
"An Act relating to the Alaska Gasline Inducement Act;
establishing the Alaska Gasline Inducement Act matching
contribution fund; providing for an Alaska Gasline Inducement
Act coordinator; making conforming amendments; and providing for
an effective date."
HEARD AND HELD
PREVIOUS COMMITTEE ACTION
BILL: SB 104
SHORT TITLE: NATURAL GAS PIPELINE PROJECT
SPONSOR(s): RULES BY REQUEST OF THE GOVERNOR
03/05/07 (S) READ THE FIRST TIME - REFERRALS
03/05/07 (S) RES, JUD, FIN
03/14/07 (S) RES AT 3:30 PM BUTROVICH 205
03/14/07 (S) Heard & Held
03/14/07 (S) MINUTE(RES)
03/16/07 (S) RES AT 3:30 PM BUTROVICH 205
03/16/07 (S) Heard & Held
03/16/07 (S) MINUTE(RES)
03/19/07 (S) RES AT 3:30 PM BUTROVICH 205
03/19/07 (S) Heard & Held
03/19/07 (S) MINUTE(RES)
03/21/07 (S) RES AT 3:30 PM SENATE FINANCE 532
03/21/07 (S) Heard & Held
03/21/07 (S) MINUTE(RES)
03/21/07 (S) RES AT 5:30 PM SENATE FINANCE 532
03/21/07 (S) Heard & Held
03/21/07 (S) MINUTE(RES)
03/22/07 (S) RES AT 4:15 PM FAHRENKAMP 203
03/22/07 (S) Heard & Held
03/22/07 (S) MINUTE(RES)
03/23/07 (S) RES AT 1:30 PM BUTROVICH 205
03/23/07 (S) Heard & Held
03/23/07 (S) MINUTE(RES)
03/24/07 (S) RES AT 1:00 PM SENATE FINANCE 532
03/24/07 (S) Heard & Held
03/24/07 (S) MINUTE(RES)
03/24/07 (S) RES AT 3:00 PM SENATE FINANCE 532
03/24/07 (S) Heard & Held
03/24/07 (S) MINUTE(RES)
03/26/07 (S) RES AT 3:30 PM BUTROVICH 205
03/26/07 (S) Heard & Held
03/26/07 (S) MINUTE(RES)
03/27/07 (S) RES AT 3:00 PM BUTROVICH 205
03/27/07 (S) Heard & Held
03/27/07 (S) MINUTE(RES)
03/28/07 (S) RES AT 3:30 PM BUTROVICH 205
03/28/07 (S) Heard & Held
03/28/07 (S) MINUTE(RES)
03/29/07 (S) RES AT 5:00 PM BUTROVICH 205
03/29/07 (S) Heard & Held
03/29/07 (S) MINUTE(RES)
03/30/07 (S) RES AT 1:30 PM BUTROVICH 205
03/30/07 (S) Heard & Held
03/30/07 (S) MINUTE(RES)
03/31/07 (S) RES AT 12:00 AM BUTROVICH 205
03/31/07 (S) Heard & Held
03/31/07 (S) MINUTE(RES)
04/01/07 (S) RES AT 11:00 AM BUTROVICH 205
04/01/07 (S) Moved CSSB 104(RES) Out of Committee
04/01/07 (S) MINUTE(RES)
04/02/07 (S) RES RPT CS 6 AM SAME TITLE
04/02/07 (S) AM: HUGGINS, GREEN, STEVENS, STEDMAN,
WIELECHOWSKI, WAGONER
04/02/07 (S) RES AT 3:30 PM BUTROVICH 205
04/02/07 (S) Moved Out of Committee 4/1/07
04/02/07 (S) MINUTE(RES)
04/04/07 (S) JUD AT 2:45 PM BELTZ 211
04/04/07 (S) Heard & Held
04/04/07 (S) MINUTE(JUD)
04/11/07 (S) JUD AT 1:30 PM BUTROVICH 205
04/11/07 (S) Heard & Held
04/11/07 (S) MINUTE(JUD)
04/11/07 (S) JUD AT 5:30 PM BUTROVICH 205
04/11/07 (S) Heard & Held
04/11/07 (S) MINUTE(JUD)
04/12/07 (S) JUD AT 3:30 PM BUTROVICH 205
04/12/07 (S) Public Testimony 5:30 pm to 7:00 pm
04/13/07 (S) JUD AT 1:30 PM BUTROVICH 205
04/13/07 (S) Heard & Held
04/13/07 (S) MINUTE(JUD)
04/13/07 (S) JUD AT 5:30 PM BUTROVICH 205
04/13/07 (S) Heard & Held
04/13/07 (S) MINUTE(JUD)
04/14/07 (S) JUD AT 10:00 AM BUTROVICH 205
04/14/07 (S) Heard & Held
04/14/07 (S) MINUTE(JUD)
04/15/07 (S) JUD AT 11:00 AM BUTROVICH 205
04/15/07 (S) -- MEETING CANCELED --
04/16/07 (S) JUD AT 1:30 PM BUTROVICH 205
WITNESS REGISTER
DONALD SHEPLER
Greenberg Traurig
Consultant to the Administration
Washington D.C.
POSITION STATEMENT: Presented information on SB 104.
ANTONY SCOTT, Commercial Analyst
Division of Oil and Gas
Department of Natural Resources (DNR)
Anchorage, Alaska
POSITION STATEMENT: Presented information on SB 104.
LARRY OSTROVSKY, Assistant Attorney General
Division of Oil, Gas, and Mining
Office of the Attorney General
Juneau, AK
POSITION STATEMENT: Presented information on SB 104.
MARCIA DAVIS, Deputy Commissioner
Department of Revenue
Juneau, AK
POSITION STATEMENT: Presented information on SB 104.
NANETTE THOMPSON, Unit/Tech Support
Division of Oil and Gas
Department of Natural Resources (DNR)
POSITION STATEMENT: Commented on SB 104.
BONNIE HARRIS, Senior Assistant Attorney General
Civil Division
Natural Resources Section
Oil, Gas & Mining
Department of Law
Juneau, AK
POSITION STATEMENT: Presented information on SB 104.
ACTION NARRATIVE
CHAIR HOLLIS FRENCH called the Senate Judiciary Standing
Committee meeting to order at 1:36:43 PM. Senators French,
Wielechowski, McGuire, and Huggins were present at the call to
order. Senator Therriault arrived shortly thereafter.
SB 104-NATURAL GAS PIPELINE PROJECT
CHAIR FRENCH announced the consideration of SB 104, and said the
topics of the meeting would be the Federal Energy Regulatory
Commission (FERC), rolled-in rates, and the Prudhoe Bay
operating agreement. Before the committee was CSSB 104(RES),
version K.
1:37:19 PM
DONALD SHEPLER, Greenberg Traurig, consultant to the
administration, said he would explain the FERC roll-in policy
and how it's based on congressional policy mandates. He added
that Antony Scott would present the requirements for rolled-in
rates in the Alaska Gasline Inducement Act (AGIA), and why such
rates are so critical for the state. He then explained his work
history with Greenberg Traurig, as a consultant for various gas
companies, and as an attorney for the FERC.
CHAIR FRENCH said that the committee had received paper copies
of the documents. He noted that Senator Therriault had joined
the committee.
MR. SHEPLER said that since the body of analysis from the FERC
orders was fairly compact, he thought it would be useful to the
committee in the full-text form.
1:40:36 PM
SENATOR THERRIAULT noted that last week there was reference to
quotes from the FERC documents, and asked Mr. Shepler to point
out the quotes.
CHAIR FRENCH remarked that he thought he had found one of the
quotes cited, and read it. He then asked if the document before
the committee was the entirety of the FERC order.
1:42:01 PM
MR. SHEPLER replied that he excerpted the discussion on
expansion prices within the order. He explained that the FERC
was not working in a vacuum when it issued its orders; it was
mandated by the Alaska Natural Gas Pipeline Act of 2004, which
contains two mandates to the FERC as it relates to expansion of
the line and expansion pricing. The first mandate was to
establish rules to promote competition, and the exploration,
development, and production of Alaskan natural gas. The second
was to provide the opportunity for the transportation of natural
gas other than from the Prudhoe Bay and Point Thompson units for
any open season for capacity exceeding the initial capacity of
the line.
1:44:21 PM
MR. SHEPLER explained that in implementing the policies, the
commission concluded that incremental pricing of expansion could
put expansion shippers at a significant rate disadvantage
compared to initial shippers; accordingly, that could discourage
exploration, development, and production of Alaska natural gas.
Congress mandates that FERC rules encourage such development.
Rolling in the cost of expansion is nothing new; from the 1960s
to 1999, the FERC preferred rolled-in pricing for new facilities
and expansions. This was set forth as a statement of historical
fact in the 1995 policy statement. In the Lower 48 the policy
changed in 1999 because it didn't fit with an industry
increasingly characterized by competition. The current Lower 48
policy holds that any expansions and new facilities have to be
incrementally priced; this policy is based on the fact of a
mature pipeline grid and pipeline competition. The FERC wanted
to establish a level playing field.
CHAIR FRENCH asked if the policy decision was based on the idea
that a company not being able to expand would be able to use an
existing pipe in a mature and complex pipeline network without
being charged an incremental rate.
MR. SHEPLER replied that was largely correct; the policy was
also predicated on the fact that an incumbent pipeline being
able to use rolled-in rates rather than charging incremental
rates for another company using its line would make for an
unlevel playing field. In Order 2005, the FERC said the Lower 48
policy didn't apply to the Alaska project because there will
likely be only one Alaskan pipeline.
1:47:28 PM
He said that rolled-in pricing is going to have the effect of
raising the price for the initial existing shippers; this may
happen in any expansion. At some point, there will be potential
rate increases as a result of rolling in prices. A low-cost
expansion that adds great volume to the system will have the
effect of reducing rates for all system users.
MR. SHEPLER said that the FERC has noted that a rate increase is
not necessarily a subsidy. In that regard, it has offered an
alternative view of what a subsidy might be in the context of
this particular project. In Order 2005 A, the FERC stated that
an alternate definition of subsidization could be whether the
expansion rate is no higher than the actual initial rate, or of
an initial rate without built-in subsidies. That suggests a
hypothesis previously made by Senator Therriault, where with a
day-one starting rate of one dollar, a low-cost expansion would
result in rates going down to eighty-five cents for other
shippers. The FERC doesn't see the existence of any subsidy as
long as the shipper's rate goes back up to the initial agreed-
upon rate. The issue then becomes what happens when the rate
goes above one dollar.
1:50:21 PM
MR. SHEPLER said in that situation the FECR will have to decide
whether a rate increase above the initial rate constitutes a
subsidy within the context of the application. The FECR would
consider the argument made by Pacific Star that the initial
rates are already the beneficiaries of so-called government
subsidies, including federal loan guarantees, accelerated
appreciation, tax credit for the gas treatment plant, and the
state's own potential contribution through AGIA. The FERC is
saying that the question of a subsidy will have to be determined
at the time of an expansion. It has also adopted a rebuttable
presumption in favor of the use of rolled-in pricing for
expansions of this particular line, irrespective of the Lower 48
policy. The FERC has advanced the process to the point where
AGIA picks it up by requiring the applicant to commit to using
rolled-in pricing for expansions up until the point that the
rolled-in pricing results in a rate increase of fifteen percent
above the day-one rate.
1:53:04 PM
MR. SHEPLER said that the state has tried to continue with the
process where the FERC left it. There will be rolled-in pricing
up until the point where the initial shippers signed up, and to
the point where state and federal contributions have been
consumed. That is the end of the obligation of the applicant to
continue to pursue rolled-in treatment.
SENATOR HUGGINS asked when the limit would go into place.
MR. SHEPLER replied it would do so at 15 percent above the
initial rate the shippers committed to. Presumably that would be
the recourse rate or the negotiated rate. That has the effect of
permitting the first expansion group, and perhaps the third - to
share in some of the government contributions that resulted in a
depression of the initial regulated rates that were enjoyed by
the initial shippers. That is the basis for how the FERC got to
its presumption in favor of rolled-in pricing and how the state
came to its position on AGIA.
He said there is an old industry adage stating that the pipeline
company proposes, but the FERC disposes. This means that a
pipeline company has to file a rate proposal, and how that
proposal gets resolved is up to the FERC. Nothing in AGIA
affects that requirement.
1:56:08 PM
CHAIR FRENCH asked if a company wants rolled-in rates and the
state forces the shipper to take rolled-in rates also, could
FERC decide that is unfair.
MR. SHEPLER replied it could. He added that AGIA requires the
licensee to propose rolled-in rates up to a cap, but at the end
of the day the FERC makes the decision based on its polices and
the facts that are presented in the specific instance for the
expansion pricing.
1:57:07 PM
SENATOR THERRIAULT asked if it is unusual for Congress to have
given that type of direction on what the FERC policy should be
through legislation.
MR. SHEPLER replied the Natural Gas Act, the main gas statute
that the FERC administers on the gas side, has nothing like this
requirement in it. Instead it requires that the FERC establish
just and reasonable rates and permit facilities that are
required by the public convenience and necessity. Against that
backdrop policy, mandates such as in this 2004 law are unusual.
Congress has certainly taken a step and told the FERC what the
end result of their rule-making process must achieve. The FERC
was certainly listening to that, because it concluded that
incremental pricing of this particular project could well fly in
the face of that first mandate.
1:58:47 PM
ANTONY SCOTT, Commercial Analyst, Division of Oil and Gas,
Department of Natural Resources (DNR), said he would be offering
two presentations that day. The first would be a review of how
government contributions - both federal and under AGIA, affect
rates. He began with a base rate of $2 not including fuel, but
including all government contributions, for a pipeline into
Alberta. Stripped of its federal loan guarantees and the reduced
borrowing cost that the feds provide to the cost of debt, that
rate would raise it to $2.10. Stripping out the seven-year
accelerated depreciation for tax purposes and instead using 15
years (industry uses this generally) makes the rates go to
$2.19. Taking into account the full amount of the $500 million
AGIA contribution, rates would rise to roughly $2.25. That
amounts to about 12.5 percent of the overall rate to the
shippers. Congress also provided the owners of the gas treatment
plant with an additional 15 percent federal tax credit. If
federal contribution were to be included, the total government
contributions to the project would exceed 15 percent.
2:01:20 PM
CHAIR FRENCH asked if the 15 percent cap would apply to the $2
tariff.
MR. SCOTT said yes.
CHAIR FRENCH said but the question of whether it's a subsidy is
where there will be an argument about whether it's a $2 or $2.25
tariff from the start.
MR. SCOTT agreed.
CHAIR FRENCH asked if it will be two separate arguments or the
same argument wrapped up as one.
MR. SCOTT said the foregoing was an attempt to arrive at the 15
percent threshold for rolled-in tariff treatment. Another
approach was to ask what modest percentage cap would permit the
kind of expansions that would fully unlock the basin's
potential. He offered to explain that in a moment.
2:02:45 PM
CHAIR FRENCH said it sounds like up until the 15 percent of the
$2-rate, the shipper has to agree to argue for rolled-in rates.
MR. SCOTT said the current committee substitute only requires
that the pipeline propose rolled-in rates. The original bill
referred to all parties.
MR. SHEPLER interrupted to clarify that the pipeline can propose
up to 15 percent. Originally the recipients of the upstream
inducements, presumably the shippers, had to agree that they
would not oppose at the FERC, the proposal the pipeline made per
its commitment in AGIA.
2:03:43 PM
SENATOR THERRIAULT said even if the pipeline and the shippers
agreed with the rolled-in rate up to 15 percent, if the FERC
determines there was a subsidy, the federal law would have
precedence.
MR. SHEPLER said that's right; AGIA does not require anyone to
bring home rolled-in pricing. It gets the company to the
proposed stage and then lets the FERC do its job.
SENATOR HUGGINS asked if the state could contest that FERC
determination.
MR. SHEPLER said the state can contest it; it's not giving up
any commitments through AGIA.
MR. SCOTT said next he would speak about three separate areas
relevant to the discussion of AGIA's rolled-in rate provisions.
First is how they affect competition and incentives for
exploration and development on the North Slope. Second is how
they affect the state. Third is how the data suggests the
provisions will affect the producers' decision to invest in the
project or not.
MR. SCOTT said the first point is that rolled-in rates promote
competition, which takes him to the second point which is that
those rates are in the state's best interest given the
uncertainty about where expansion gas will come from. Third, he
said, rolled-in rates do cost producers, but that is mostly
offset by the state's contributions in AGIA. The degree to which
rolled-in rates negatively affect the producers is unlikely to
affect their investment decisions.
2:07:03 PM
MR. SCOTT said he is using a 4.5 bcf/day scenario with two
expansions of 1 bcf/day with infill compression. He said a third
expansion would be achieved by looping volumes.
CHAIR FRENCH asked for an explanation of infill compression.
MR. SCOTT explained that infill compression has compressors
along the line instead of just at the pipe inlet and outlet. He
showed a graph of the AGIA rolled-in rates for the initial
shippers, the first expansion shippers in 2018, and the second
expansion shippers in 2021. The third expansion shippers' AGIA
rates aren't shown. Those are contrasted with the rates that
would apply under the FERC's Lower 48 pricing policy. He pointed
out that the third-expansion shippers will receive the FERC's
Lower 48 policy. He said the rates slightly decline with the
first expansion, so both initial and first-expansion shippers
would receive slightly reduced rates in 2018. At that point the
AGIA and FERC policy rates track, but at the second expansion in
2021 when fuel price effects are actually included, incremental
rates rise very significantly (by nearly $1). Under AGIA,
everyone's rates rise modestly - about 15 cents. For the third
and looped expansion in 2023, AGIA rates rise for all of the
preexisting shippers about 15 cents. But the rates on an
incremental pricing basis for the looped expansion, would be
$1.65 greater than the initial rates.
2:10:10 PM
SENATOR MCGUIRE asked him to explain first and second expansion
rates under AGIA as compared to the first and second Lower 48
FERC expansion rates in 2018. She observed that the Lower 48
rates appear to decline after a while, but the initial companies
that took the biggest risk have their rates increase.
MR. SCOTT said the graph had an optical illusion; the rates
didn't decline by more than a couple of pennies.
CHAIR FRENCH asked if that is due to depreciation.
MR. SCOTT said it is due to adding compressors along the line
along with substantial capacity. Compression is relatively
inexpensive compared to pipe, so the rates decline slightly.
However, compressors burn more fuel so that offsets the savings
somewhat.
SENATOR MCGUIRE asked for an explanation of later expansions.
2:12:20 PM
MR. SCOTT explained that in 2021, assuming incremental pricing,
there wouldn't be any rate increases because of the rolled-in
basis. The Lower 48 policy is not to allow rates to increase for
those shippers; there would be only incremental treatment. A
particular portion of the graph in question represented, for the
2021 expansion, the incremental rate paid by the second
expansion shipper, and the cost for all the shippers if other
costs were rolled in.
2:13:37 PM
SENATOR HUGGINS asked how reliable his data is.
MR. SCOTT replied his numbers are based on hired-out engineering
work done on ANGTS design, TransCanada's 48-inch pipeline data.
Unlike testimony received from TransCanada, the state doesn't
assume that all expansions occur in year one; they will occur
along the line. The cost of compression and pipe is escalating
worldwide, so the further off the expansion, the more expensive
it will be. The price of fuel will also increase. The chart
assumes a $5.50 Henry Hub price. The rates shown are nominal
dollar rates, so they will continue to inch up along with the
cost of fuel. Any modeling requires a number of assumptions, he
added.
2:16:01 PM
SENATOR MCGUIRE said her concern is that under AGIA the state is
asking the initial shippers to take on a big risk and in 2021
their rates rise slightly. The 2018 expansion shipper rates
would remain equal from 2021 to 2022, but in 2023 the lines on
the graph diverge. She asked why that is an acceptable policy.
2:17:10 PM
MR. SCOTT said he was incorrect when he said the graph had an
optical illusion and the rates didn't decline by more than a
couple of pennies. The line does decline because in 2023 it's a
looped expansion with no added compression. That means that fuel
use for initial and first expansion shippers declines so their
effective rate does decline. The green bar reflects the
consequence of rolling in the large capital cost of the
expansion. With regard to the policy, he again mentioned
government contributions to the project and the AGIA policy that
rolled-in rates ensures that later shippers participate in those
government contributions. He pointed out that it is also the
case that initial shippers bear the least risk. The shipping is
a substantial commitment, but it also confers significant
benefits - namely the right to ship an enormous crude gas
resource. Subsequent shippers have more risk because they don't
have the enormous reliability of proven reserves. They also face
geologic and deliverability risk because less is know about the
reservoir.
MR. SCOTT said it is too strong to say the initial shippers are
subsidizing later shippers because of rolled-in treatment.
Everyone is familiar with demand changes and how that changes
price. However, a price change doesn't indicate that the first
participants are subsidizing later participants. In general, one
sees a single price for a product; in this case if the total
demand increases, the cost of the supply to meet the demand is
typically the same for all parties.
2:21:08 PM
SENATOR MCGUIRE said she understands the policy - that the
benefits outweigh the risks - and in this case the goal is to
expand and encourage exploration and development. While overall,
she thinks the situation is fair enough, she just wants to make
sure he is able to justify the policy.
2:22:12 PM
CHAIR FRENCH said the initial shippers are also getting a tax
freeze all the way to the end of the chart.
SENATOR THERRIAULT said the amount of gas that can be put
through a certain diameter pipe through compression is pretty
much a science, but the cost of putting on compressors to push
the gas into the pipe is a bit of a guess. Looping is more an
artful guess. The data starts out at a negotiated rate of $1.00,
but considering the value of all the initial government
subsidies, the initial recourse rate should have been $2.30. The
initial shippers are actually getting a break - taking advantage
of the government subsidy from first gas flow into account.
2:23:51 PM
MR. SCOTT agreed that is a fair representation. In 2023 rates
will rise to the level where they would have been without
government subsidies.
SENATOR THERRIAULT said first gas is coming out of the ground
right now and the entire infrastructure that is needed is
already in place - pipes, buildings and dormitories. So there's
very little risk; they just need to coax the gas out of the
ground. But when new pipe needs to be put into the ground and
you just hope to find gas and coax it to the surface, and the
entire infrastructure has to be built to do so, that risk
balances the equation.
2:25:24 PM
MR. SCOTT explained that the green bar on the next slide
represents the AGIA rates for the initial, first, and second
expansion shippers; it doesn't apply to the third expansion
shippers because the looped expansion tops out past the cap. In
2023, the new blue bar on the graph represents the third
expansion shipper's rates. Those will be greater than those of
the other shippers because the expansion has exceeded the 15
percent cap. Exactly where those rates will be will depend on
negotiations between the parties and what the FERC decides. He
cautioned that there are good reasons to think that, given the
additional geologic and deliverability risks that that gas
faces, it might not be developed at all.
MR. SCOTT said the second subject is how AGIA's rolled-in policy
affects the state's interests. It is pro-exploration, but it is
conceivable that rolled-in rates could actually hurt the state's
interest. Under AGIA the state is free to do what it wants to
protect its interests, but this policy will play out under a
number of possible scenarios. No one can be sure which gas will
come from where for each expansion. Given the uncertainties, the
balance for the state's interests purely on a monetary, royalty
and tax basis clearly favors the AGIA rolled-in rate policy.
He pointed out that state lands have a royalty rate of 12.5
percent along with production tax. On federal lands, the state
typically gets half the federal royalty. Resources on the outer-
continental shelf (OCS) have no royalty or production tax.
MR. SCOTT said he would examine three possible cases with the
same expansion scenario as previously presented. One is the
state gas first case - A. The first bcf expansion would be
filled only with gas from state lands; this would be the biggest
state take. The second expansion would be from gas only from
NPRA (National Petroleum Reserve Alaska) lands resulting in
significantly less state take. The third expansion would come
from the OCS.
He said that case B is the state gas second and here there are
an infinite number of different combinations that can be
presented. The NPRA gas would go first, then state lands, then
OCS gas.
Case C, the final case, is state gas last - first OCS, then
NPRA, then state lands.
2:30:16 PM
MR. SCOTT said that without rolled-in rates it is very unlikely
that all expansions will occur. However, he said in the unlikely
event that all expansions occur (under incremental rates), the
first column showed the state revenue losses under the AGIA
policy (state gas first); The OCS expansion would only cost the
state. In case B, state gas second, rolling in the more
expensive expansion cost also costs the state. In the last case,
state gas last, rolling in costs benefits the state.
He speculated if you assume that each of these cases is equally
likely; in the unlikely event that all expansions would occur
regardless of rate treatment, the state's expected value is
negative. However, he emphasized that this is unlikely to occur
because incremental rate treatment doesn't favor looped
expansions.
2:32:20 PM
He said slide 8 assumes the last looped expansion wouldn't occur
without rolled-in AGIA rate treatment. In the case C scenario -
state gas last - the state would never get gas in without
rolled-in treatment and the costs for that never occurring are
very significant. If prices are low, the state would still lose,
but at more realistic prices the state would benefit.
2:34:19 PM
MR. SCOTT said if the full infill compression scenario doesn't
occur because of incremental rate treatment and if the looped
scenario doesn't occur, you'll see positive state value across
the board. Thus the rolled-in rate policy is important to insure
that expansions occur. Clearly there are scenarios under which
the state would be better off under incremental rate treatment,
but given the uncertainties about where state gas enters, the
robust policy for the state is with rolled in rate treatment.
The last slide shows different sustained real prices for
producer upstream investments as affected by rolled-in rate
treatment assuming the producers don't participate in the
expansions. That's a worst case scenario because it only raises
their costs and they get no benefit of incremental revenue.
Given the robust comparative investment opportunities the
producers have from an upstream perspective, the evidence does
not support the contention that rolled-in rates would preclude
participation in the project.
2:38:06 PM
SENATOR HUGGINS said at $5.50 what does minus 2.9 percent mean
in round dollars over the life of the project?
MR. SCOTT replied it'd be on the order of $400 million NPV.
SENATOR WIELECHOWSKI referred to slide 9 and asked if the state
would lose $5.83 billion if gas was at $5.50/mcf without rolled-
in rates.
MR. SCOTT said yes, on an expected value basis discounted to the
present.
2:40:44 PM
SENATOR THERRIAULT said he'd been looking at a briefing paper
that was previously presented to the FERC on the issue of
rolled-in pricing. It stated that the mere possibility of
incremental tariffs threatens exploration and competition and
may doom an Alaskan gas pipeline to transporting no more than
6/bcf. That was a concern in 2004 and was presented to the FERC.
2:41:45 PM
CHAIR FRENCH asked for discussion about the duty to produce and
the Prudhoe Bay Operating Agreement.
LARRY OSTROVSKY, Assistant Attorney General, Oil, Gas, and
Mining Section, Department of Law (DOL), said he provided a copy
of a DL1 lease to the committee. The lease addresses Prudhoe Bay
and Point Thompson, and has gone through many variations and
drafts since the first in 1959. It's similar to gas leases used
in the Lower 48 with some exceptions, and represents a basic oil
and gas lease, which is different from other contracts.
MR. OSTROVSKY said it is important to talk about the express
provisions in the lease; the state contributes land with the
prospect of mineral resources, and the oil company contributes
capital and expertise to develop. In payment, the state gets
bonus bids for major shares in royalty, specifically 12.5
percent; oil companies receive the lion's share. To understand
the structure of the leases, one needs to understand the
underlying goals. One goal of lessees is the right to develop
the lease without the obligation to do so. Secondly, if lessees
do produce on a lease, they want the right to maintain
production so long as it's economically profitable.
MR. OSTROVSKY explained that the state's goals are simpler: the
state wants production as soon as possible. Oil and gas leases
balance the goals with primary and secondary terms and savings
clauses. The initial primary term can be from 5 to 10 years in
Alaska; the only obligation of the lessee is to pay rent. But,
because the state wants production at some point, for a lessee
to hold a lease beyond the primary term it must take active
steps towards production or be excused by the state from
production. The lease may be extended so long as there is
production in paying quantities. If there is no production, one
goes to the savings provision, which describe how a lease can be
continued for a period of time beyond the primary term even when
there is no production. That includes commitment to a unit
agreement, suspension of operations with the consent of the DNR,
and shut-in production. Oil and gas leases were historically
drafted by industry; such companies prefer the option to
develop, so leases have tended to favor the oil companies. Over
time states have fleshed out the relationship with a series of
implied covenants that take into account contingencies and
protect the rights of states.
2:48:10 PM
CHAIR FRENCH asked why the implied covenants were not made
express covenants.
MR. OSTROVSKY explained that implied covenants tend to express
basic duties, which are not fiduciary duties but rather duties
of due regard. These are fleshed out through common law. It
would be difficult to express all those cases in a lease. The
basis is expressed in a certain paragraph of the lease, which
says that upon discoveries, lessees should drill wells. That is
the basis of the implied covenant to develop, test and market.
It is expressed in the leases, but not completely described.
2:49:40 PM
SENATOR THERRIAULT asked if that was the central issue the state
previously litigated over when the judge determined that there
was no fiduciary argument, but rather a covenant that there is
an obligation to develop and take the state's interest into
account. The producers can't place themselves on a higher
plateau than the state.
2:50:34 PM
MR. OSTROVSKY responded that was exactly correct. There was a
lawsuit about field costs and valuing oil where the state argued
that the covenant was fiduciary, and producers owed a higher
duty. The judge ruled against the fiduciary relationship and
ruled that there was a relationship of due regard. The producers
can't treat the state worse than themselves. That might be
manifest in favoring others over the state of Alaska.
SENATOR THERRIAULT said that is very critical; some think that a
company can demand that the state has to meet or exceed a
certain rate of profitability, and in fact that is not the
standard.
MR. OSTROVSKY agreed and cited a case where a lessee had a deal
with a lessor but because of a price change made a deal with new
lessors. The court held that the company could not play one
lessee against the other. A company must act in a reasonably
profitable way.
2:52:48 PM
CHAIR FRENCH asked what the difference is between a unit
production agreement and a unit operating agreement.
2:53:43 PM
MARCIA DAVIS, Deputy Commissioner, Department of Revenue,
explained that a unit agreement is a legal contract between
Alaska and its lessees. The focus of the contract is a
clarification and protection of the state's rights regarding
production, costs, and the manner of operation of a group of
leases as a whole. It also sets out the opportunity for the
state to have a say at different junctures in the development of
that unit.
CHAIR FRENCH asked how many units are on the North Slope.
NANETTE THOMPSON, Unit/Tech Support, Division of Oil and Gas,
Department of Natural Resources (DNR), said the North Slope has
about 20 active units.
2:55:27 PM
CHAIR FRENCH asked if it's too simplistic to say that there's
one agreement per field.
MS. DAVIS said a unit is formed because oil is discovered and
the resource is delineated. Relative ownership is determined for
all the different partners and the pool of oil is formed like a
state boundary. It is called a participating area because it
delineates the participants and the monies they're entitled to.
Once a unit is formed, there can be subsequent exploration and
work so that another pool could be discovered within that same
boundary. The Prudhoe Bay unit contains several different areas:
the initial participating areas - including the gas cap and oil
rim, the Lisbourne area, and Point McIntyre. A unit is the
initial boundary, and more areas can participate within it
subsequently.
2:57:40 PM
CHAIR FRENCH asked her to compare that definition to a unit
operating agreement.
MS. DAVIS explained that the unit operating agreement is the
document by which the owners contract with each other, not the
state. The owners come together and get an operator, and they
determine the level of control and flow of information. Voting
provisions are determined as well as an operating agreement.
When the Prudhoe Bay Operating Agreement (PBOA) was formed,
articles were created relating to the oil rim and gas cap areas.
When a new field was discovered, supplemental provisions were
created governing the new areas relating only to the new fields.
All of these are considered together as the PBOA, but within it
are provisions relating only to certain areas. The state is not
a party to these provisions, but does receive a copy of the
agreement.
3:00:07 PM
CHAIR FRENCH asked what level of oversight the state executes
over the terms of the operating agreement.
MS. DAVIS said the state has no oversight other than receiving
copies of the agreement. If an element of the agreement in
violation of the unit agreement or another issue, that unit
operating agreement wouldn't have immunity to other legal
requirements.
SENATOR THERRIAULT commented that as the different agreements
are peeled away, one arrives back at the original lease. He
asked if there is a way the unit operating agreement can release
a leaseholder from duties under the original lease.
3:01:06 PM
MS. DAVIS replied the lease is a contract between the state and
the lessee. Only to the extent that the state relinquishes or
modifies the lease could the rights be amended.
SENATOR THERRIAULT said from time to time one hears that a
producer might be precluded from producing even if it wants to,
because of the complexities of a unit operating agreement.
MS. DAVIS responded a producer could find itself in such a bind,
but there should be a way out. If there's a provision in a unit
operating agreement that would cause a company to violate unit
agreement terms or state or federal law, there likely wouldn't
be too much contractual debate. A company would rather sort out
issues. Against the state or federal government, debate would
not be excused.
CHAIR FRENCH asked if anything in the operating agreement
prevents one partner from selling when others won't.
3:03:04 PM
MS. DAVIS said typically when the owners form a participating
area, they're mindful of the obligation to make sure that
hydrocarbons are removed from a field without violating waste
requirements and how they are accounted for. A great deal of
care is put into contractual management of product removal and
accounting. The PBOA is one of the most complex agreements
because an oil rim and a gas cap are operating simultaneously
with different ownership interests. The original provisions were
meant to anticipate all kinds of outcomes, like a major gas
sale. It has provisions relating to what happens if gas is sold
at less than or more than a major gas sale and the different
consequences. Since the time the agreement was drafted, owners
resolved their differences and reintegrated their interests to
hold a single percentage in both; that removes complexity.
However, the unit operating agreement has not yet been amended
to reflect the new reality, so whether or not the owners are
working on changing provisions or modifying rights hasn't been
established yet. There might be additional changes, however.
3:05:43 PM
CHAIR FRENCH asked when that integration took place.
MS. DAVIS said she believes it took place in January 2000.
MS. THOMPSON added that there were a couple of realignment
provisions. A copy of the first is available, but none from when
Chevron and Force Energy were added. The state is aware of
negotiations for a new amendment to the operating agreement,
which haven't been concluded yet. The PBOA is a dynamic document
and is frequently amended.
MS. DAVIS said it is a difficult process to work through because
any party will look at the status quo and perceive its rights
therein. As the agreement moves away from the status quo toward
a revision, each player has concerns about its position
worsening. With the large number of players, it can take a lot
of time to reach new agreements.
3:07:20 PM
SENATOR MCGUIRE asked if there are legal opinions available
regarding the definition of "differentially harmed". That term
strikes a chord because gas has been used for re-injection. One
might argue that because one producer chose to sell its gas and
another two didn't, that might cause differential harm. She
asked if there are any related legal opinions.
MS. DAVIS replied the owners consolidated the oil rim and gas
cap. In their operating agreement they provided the rights an
owner has to take their gas in kind before and after a major gas
sale and what the obligations are for taking gas in kind without
harming other owners or unreasonably interfering with unit
operations. The producers have been specific about that point in
the process and the need for accounting for gas. Because the
facilities are unit-owned, an owner doing anything above the
bare minimum will ask for permission to take gas or use unit
facilities. The more economic approach is to reach an agreement
on how to use the existing infrastructure and make sure everyone
is treated fairly.
3:10:19 PM
CHAIR FRENCH said he has a copy of the basic operating agreement
and that it was very complex.
SENATOR WIELECHOWSKI asked if it has a provision where if one
party takes gas it needs to ask permission of the other owners
or if one party takes gas, then all the others must as well.
MS. DAVIS said under the PBOE, as it currently exists in the
hands of the state, any owner has the right to take gas, but not
an obligation to do so. If it chooses to do so, it takes it
subject to the provisions of operating agreement. There might be
need for additional discussion to talk about how the off-take is
performed. Other owner approvals are procedural; refusal of off-
take is not a unilateral right. The process is focused on
problem solving.
3:12:16 PM
She said that when a major gas sale is reached, defined as 2
bcf/day in the first month after production or 1.75 bcf/day
thereafter, all owners are required to take gas in kind.
SENATOR WIELECHOWSKI asked if ConocoPhillips wanted to sell its
gas in a 2 bcf open season, would every other producer have to
as well.
MS. DAVIS answered that she didn't know that ConocoPhillips
would have that large an allocation of gas; assuming a company
did do so, all other owners would be required to take gas in
kind.
3:13:28 PM
SENATOR THERRIAULT said although the committee may be on track
to move the legislation, legal questions would continue to come
up and further testimony could be useful.
CHAIR FRENCH said dates were being set in May for further
testimony.
Recess from 3:14:03 PM to5:39:30 PM.
CHAIR FRENCH said the committee would be addressing three
specific topics: confidentiality and public records (Sections
160 and 170 of SB 104); license transfer provisions; and
arbitration provisions, including definitions.
MS. DAVIS said that section 160 on page 10 of the CS was
designed as the primary proprietary information of trade secrets
section. It has gone through some revision since originally
introduced as a result of information gathered from the industry
and the last Senate Resource group. Under subsection (a) the
opportunity has been created for an applicant to identify
information in its application that it considers confidential as
a trade secret. The company is required to justify the
designation, and if the commissioners agree, the information is
treated as confidential from that point forward. If the
commissioners disagree, they do notify the applicant that it may
decide whether to have the information returned and proceed
without the benefit of that information. Second, if an applicant
is selected as the winner, all the associated information
associated with their application will be public. Third, any
company that challenges the award will have its information made
public.
5:42:09 PM
CHAIR FRENCH noted that Senator Therriault had joined the
committee.
MS. DAVIS said that section 170 addresses confidentiality also.
Under that provision, if information is designated as
confidential, commissioners must receive a summary of that
information. A summary of that information made available to the
public. While not in this CS, an amendment will put forward
language that gives legislators the right to review confidential
information from the time commissioners have the information to
the end of the process. Legislators must have signed a
confidentiality agreement to do so.
She added that other confidentiality-related agreements are on
pages 25 - 27, restating the statute that lists exceptions to
the public record inspection rights. A new subsection is also
added that addresses the proprietary trade secret designation
and applications being held confidential until complete.
5:44:01 PM
CHAIR FRENCH asked when an applicant submits information that is
determined to not be confidential, if the information would be
eventually made public if the company were successful.
MS. DAVIS replied only the information in the state's possession
would be made public.
CHAIR FRENCH turned to lines 13 - 14 on page 10 that said:
"After a license is awarded, all information submitted by the
licensee shall be made public."
MS. DAVIS acknowledged that "submitted by the licensee and
retained" should perhaps be added to clarify that section.
SENATOR THERRIAULT said the language regarding access to
information after the signing of a confidentiality agreement is
important for the legislature so it is able to start processing
the information as soon as a winner is selected.
MS. DAVIS added it might behoove the legislature to accelerate
some reviews and that is why the administration is encouraging
the addition of that language.
CHAIR FRENCH read a sentence on page 11: "If information is held
confidential under this subsection, the applicant shall provide
a summary of that is satisfactory, …." He wondered if this is
where the information is held confidential or if it is under
section 160.
MS. DAVIS responded that it is probably referencing subsection
(b), which is the core of applications received are not public
records and are not subject to disclosure until they publish
notice of the section. She speculated that this section is worth
reexamining because it needs to be precise enough.
CHAIR FRENCH said the determination of proprietary is made in
section 160 and he would ask the drafter if they should be
concerned. He then asked Ms. Davis to address license transfers
in section 550.
MS. DAVIS said that section 550 is on pages 22-23 and it
addresses the assignment of a license, the assignment of
resource inducements. A suggested amendment to this provisions
deals with assignment of the voucher that covers individuals
purchasing gas at the North Slope who will acquire vouchers
which entitle them to negotiate for the royalty and tax benefits
through the entity they are buying it from.
She explained that any assignment of a license requires state
approval. The license assignment must not diminish the value of
the project or the obligations to the state under the license or
its likelihood of success. This section also reserves the
state's right to enforce the audit provisions regarding monies
received by the original licensee prior to the assignment.
She continued saying the assignment by a person with resource
inducements took more thought; the state had to think in terms
of capacity for shipping and associated tax and royalty
benefits. It's more complex to track tiers of tax and royalty
treatment. It was determined that it would be an undue burden
for the administration to try to have a secondary market. So the
right to transfer inducements to a new company was restricted to
where the situation where either the entity itself has been
transformed by the sale or merger of a company itself
(essentially having a new company step into its shoes) or that
entity has sold all of its North Slope assets. She summarized
that because gas can be shipped from multiple fields into a
pipeline, so just the sale of one field as opposed to all the
fields would keep the state from having to split them up, they
made the balance call of saying it can be transferred, but only
in connection with the sale of the whole asset based on the
North Slope or the sale of the company itself.
CHAIR FRENCH said presumably the Regulatory Commission of Alaska
(RCA) would examine such a sale or merger thoroughly.
MS. DAVIS agreed and added that the standard the state is
suggesting for the voucher would be a transfer of the entire
capacity acquired by the purchaser entity.
SENATOR THERRIAULT asked if the issue would be addressed in
subsection (d) under this section.
MS. DAVIS replied yes.
CHAIR FRENCH said it seems as though there has been lots of
effort to select the licensee, but a licensee could almost
immediately hand the license off to another company. He asked
why that provision was there.
MS. DAVIS said the applications would be ninety percent focused
on the project itself. A portion of the associated analysis
would be for financial strength in an applicant, and its track
record. Any company stepping into the position would encounter
the same fixed analysis. The review on the assignment will be
very narrow and will include the unique parameters. Changing a
licensee wouldn't be allowed to affect the value of project or
the ability to perform. In a project of this size, commercial
evolution needs to be realistic. Identities within a consortium
will change and two limited liability companies (LLC) could form
a third. The state wants an ability to accommodate that somewhat
easily.
CHAIR FRENCH asked if it was conceivable that an initial
licensee could decide to sell its interest in the project and
the state would be asked to okay that.
MS. DAVIS replied that the state would only be looking at the
transfer of the license; it would focus on the validity of
assignee. If that was not approved, the licensee would be in
default or it would have to find a better assignee.
CHAIR FRENCH asked why the legislature must approve the
licensee, but have no role in the change.
MS. DAVIS replied that the state felt the criteria binding the
commissioners were sufficient. The financial community would be
supplying the financing for a large portion of that.
CHAIR FRENCH asked if there was any requirement for notice to
the public or legislature.
MS. DAVIS answered that had not been written in.
CHAIR FRENCH asked if she would object to writing that in.
MS. DAVIS said no.
SENATOR THERRIALT asked if that the section was meant to
accommodate the business structure of a situation like that.
5:58:10 PM
MS. DAVIS replied that is correct; the state wanted to be
commercially realistic in terms of how the license might end up
needing to be changed.
CHAIR FRENCH said the state is more concerned about protecting
the project than the entity and maintaining the integrity of the
project is the core of the state's role. He said some language
should be added regarding a public notice period and commented
that Senator McGuire had arrived.
5:59:40 PM
CHAIR FRENCH said the last topic to be addressed is arbitration
in section 43.90.120.
MS. DAVIS said that page 3 of the CS addressed the abandonment
of the project. The state may have the best licensee and project
possible and still could conceivably have an abandoned project.
This section provides the commissioners and licensee the ability
to agree that a project isn't economic. If they don't agree,
there is a third-party arbitration structure. As a result of
earlier discussion, the structure was converted from a one-
person situation to the American Arbitration Association's (AAA)
three-person structure. In this section, the arbitration
boundaries are supplied. In the earlier drafting the arbitrator
was asked to decide whether the project was uneconomic, but that
requirement also suggested a separate finding on whether the
project should be abandoned. The state recommended the latter
portion be removed, but it remains there awaiting a decision.
Missing from the section is a definition that the arbitrator
would use to define an uneconomic project. Such a definition has
been created, and would be presented to the committee shortly.
6:02:39 PM
SENATOR WIELECHOWSKI went to page 3, line 20, that says "each
party shall select an arbitrator" and asked if that was
envisioning an arbitrator from the AAA's national roster or from
somewhere else.
6:03:20 PM
MS. DAVIS asked Bonnie Harris to answer the question.
BONNIE HARRIS, Senior Assistant Attorney General, Department of
Law, said she would get an answer to that question; she assured
the committee that the arbitration provisions are very thorough.
SENATOR WIELECHOWSKI noted that typically parties select from a
list of 10. This drafting is unusual and it could allow the
selection of biased arbitrators, he said.
MS. DAVIS clarified that this section is meant to be written
this way. The sentence suggests that the third arbitrator would
come from the American Arbitration Association's national
roster, but it doesn't put that limitation on the first two
arbitrators that are selected by the parties. The way it is
currently written would allow each side to pick an individual
they wanted to put forward and without contest. That's their
arbitrator. Then they would have to get together and appoint a
third arbitrator from the roster.
CHAIR FRENCH said the committee would hear more on this issue
before sending out the CS.
MS. DAVIS said there may be other options within the American
Arbitration Association rules.
CHAIR FRENCH said each side picking its most vociferous champion
might make it difficult to agree on a third. He then asked where
the arbitration would take place.
MS. DAVIS replied there is no designated location.
CHAIR FRENCH said the only question that would require
arbitration would be whether a project is economic.
MS. DAVIS agreed that was correct, and said the definition would
be fact-based, which wouldn't appear to have any legal
principals associated.
SENATOR WIELECHOWSKI said the way this section is currently
written he thinks it means that Alaska law wouldn't necessarily
have to be applied unless specified and the arbitrators would
apply the general law of the nation.
MS. DAVIS said because the project doesn't have firm
transportation commitments, there is a question of contract. One
might want to designate the State of Alaska law for arbitration
purposes.
SENATOR MCGUIRE said even if one says the matter is only
factual, if legal principles come into play there is the implied
covenant of good faith and fair dealing; so the applicable laws
should be defined.
MS. DAVIS agreed.
6:08:10 PM
CHAIR FRENCH referenced page 4, lines 7-12, and said it looks
like if the licensee and the state agree a project is not
economic, the state keeps all the finished work including
engineering designs, contracts, permits and other data. If the
licensee says it's uneconomic and the state disagrees, if the
licensee wins in arbitration, the state still keeps it all.
MS. DAVIS agreed and added that the only situation in which the
state isn't covered is if the state "dumps out" by saying it is
uneconomic and wins the arbitration.
MS. DAVIS reasoned that if the state is saying the project is no
good, it seems fair that it doesn't get the work.
CHAIR FRENCH pointed out that the state would have paid for 50
to 80 percent of the work, however.
MS. DAVIS replied that a different policy call could be made.
The House version of the bill changed that section to allow the
state to keep the work.
6:10:46 PM
CHAIR FRENCH said there is no other area in the bill that called
for arbitration. There being no other business to come before
the committee, he adjourned the meeting at 6:11:30 PM.
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