Legislature(2009 - 2010)BUTROVICH 205
04/05/2010 03:30 PM Senate RESOURCES
| Audio | Topic |
|---|---|
| Start | |
| SB245 | |
| HB280 | |
| Instate Gas Testimony - David Gottstein | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| += | SB 309 | TELECONFERENCED | |
| += | SB 290 | TELECONFERENCED | |
| += | HB 280 | TELECONFERENCED | |
| + | TELECONFERENCED | ||
| *+ | SB 271 | TELECONFERENCED | |
| = | SB 245 | ||
HB 280-NATURAL GAS: STORAGE/ TAX CREDITS
3:36:25 PM
CO-CHAIR WIELECHOWSKI announced HB 280 to be up for
consideration. [CSHB 280(FIN) AM was before the committee.]
3:36:30 PM
REPRESENTATIVE MIKE HAWKER, sponsor of HB 280, asked the co-
chair if she had any questions.
CO-CHAIR MCGUIRE said she was comfortable with moving forward.
3:37:44 PM
REPRESENTATIVE HAWKER said he finished explaining Section 11 at
the last meeting. It is making sure that the information about
the disclosure provision for taxpayers receiving credits is
communicated between the Department of Revenue (DOR) and the
Regulatory Commission of Alaska (RCA). But, the meat of the bill
is in Section 12 about the gas storage facilities development
credit. It is a volumetric-based credit in the amount of $1.50
per thousand cubic feet (tcf) of storage capacity. The credit, a
financial support for reducing the cost of the supply chain of
gas, is to be passed on specifically to consumers. The storage
facility must be opened and commence operation during the years
2011-2015; so this bill, in fact, has a sunset. The credit is
capped at $15 million, which is the equivalent of a 10 bcf
facility. It has been estimated that between 10 and 15 bcf is
the realistic level of commercial storage to be brought forward,
and the credit was designed to not provide great excesses.
SENATOR FRENCH said that responsible commercial efforts are
already being made on a parallel track, and this has prompted
him to question how much stimulation is needed from the state.
REPRESENTATIVE HAWKER said he very much shared his thought
process, but HB 280, that develops a regulatory framework for
the development of gas storage that does not currently exist in
Alaska statute, is critical so that a potential investor knows
what they might be investing in. The reason for providing this
credit is not to incent development of storage capacity, because
that is already universally accepted as being critical to moving
forward in providing energy security, but rather to ultimately
to benefit the consumers at the end of the supply chain, because
that development will involve an incremental cost in the supply
chain.
REPRESENTATIVE HAWKER also said he recognized the potential
controversy from other regions of the state who might feel they
are not being supported equally. His answers to that are the PCE
endowment and the hundreds of millions of dollars the state has
put into alternative energy development balance it out.
3:42:55 PM
REPRESENTATIVE HAWKER said HB 280 also addresses deliverability
requirements to make certain the state is not providing a
subsidy for a facility that isn't fully used. Language on page 2
in Section 2 says to be considered for a credit a commercial
facility has to be moving more than 100 mmcf/year. The Alaska
Oil and Gas Conservation Commission (AOGCC) certifies the
storage capacity; a minimum of 500 mmcf is required. The credit
maxes out at 10 bcf.
CO-CHAIR WIELECHOWSKI asked if he sees the regulation component
kicking in under language on page 10, lines 11-12.
REPRESENTATIVE HAWKER answered that the regulatory provision is
a construct of a couple of elements and that is one of them.
That language specifically excludes proprietary storage from
being eligible for credits.
CO-CHAIR WIELECHOWSKI said he thought the term "available" on
page 10, line 11, was vague, and asked what he thought about
adding "at competitive rates to any producer or utility
operating in Cook Inlet."
REPRESENTATIVE HAWKER answered that wouldn't cause him any
concerns, but he needed to confer with counsel before making an
absolute commitment.
3:47:07 PM
JAN LEVY, aide to Representative Hawker, stated that what he may
have been asking on page 10, lines 11-12 that say "a utility
regulated under AS 42.05" is not the provision that causes the
storage facility to be regulated. This just means that they have
to be available to the utility gas. They wouldn't offer the
storage space at a competitive rate; they have to offer it at a
regulated rate, because they will be regulated by the RCA.
SENATOR FRENCH said Section 9 is the section that puts this
facility under RCA regulation.
REPRESENTATIVE HAWKER agreed and added that it defines what a
public utility is for the purpose of regulation; it specifically
defines a facility that is furnishing natural gas not to the
public for compensation, but to the utility-owned storage.
SENATOR FRENCH asked if that is the kind of facility this
measure envisions giving a credit to.
REPRESENTATIVE HAWKER answered yes.
CO-CHAIR WIELECHOWSKI asked if he intended to limit the scope of
this bill to below the 68th latitude, essentially Cook Inlet,
and where that language would be located.
REPRESENTATIVE HAWKER answered that the intent of the bill is
not to limit storage that is available for utility gas to the
Cook Inlet. This sort of facility would be an essential part of
adding the ability to provide gas delivery in the Fairbanks
arena. He didn't want to constrict the ability to meet utility
needs.
CO-CHAIR WIELECHOWSKI asked if the producers could possibly
attempt to define what they currently have in Kuparuk and
Prudhoe as a gas storage facility.
REPRESENTATIVE HAWKER answered that the proprietary storage
exclusion on page 9, line 8, doesn't include "storage of natural
gas owned or contractually obligated to the owner, operator, or
manager of the natural gas facility". So, if gas is being put
back into a well on the North Slope for pressurization or other
purpose, it would not qualify. The credit is intended for a
consumer delivery facility. Specific language excludes pipelines
as well. The intent is to pass the credit on to the consumer.
MS. LEVY added that this storage facility has to be built within
a certain timeframe and it would have to agree to being
regulated.
3:53:18 PM
REPRESENTATIVE HAWKER said section 13 increases access to
existing tax credits for developers, particularly in the Cook
Inlet, by eliminating the Cook Inlet penalty (the point in
statute where the differential tax is established between the
Cook Inlet and North Slope regions). The credits generated in
the Cook Inlet have to be discounted as if they were being used
in a higher state tax regime before they can actually be used
for credit. The idea is to keep Cook Inlet on an equal
competitive footing with other regions of the state for
attracting investment capital.
Section 14 is also in the production tax arena and is part of
the accounting mechanism. It talks about how all gas that is
injected into a storage facility is gas that is produced and
pays tax and royalties. When that gas goes in it is presumed to
be the first gas to come out. Native gas (at the bottom of the
hole) is the last gas produced, and it doesn't get taxed until
everything that was pumped into the reservoir is taken out. He
explained that this section is providing a regulatory structure
that makes it easier for the industry to build, manage, and
account for facilities, knowing that when they put gas in they
get it all out before producing any of the residual gas.
CO-CHAIR WIELECHOWSKI asked when Marathon Oil would get taxed
under this section when it puts gas in a third-party facility
and then pulls it out to sell.
REPRESENTATIVE HAWKER answered at the point they bring the gas
to the surface and move it into the marketing arena. Putting it
into another storage facility does not defer their payment of
tax.
MS. LEVY added that the producer is taxed as they produce gas.
Gas in a storage facility that is underground will have some
native gas already and that is the "cushion gas." This is the
gas that may eventually come out and people are wondering when
it will get taxed.
REPRESENTATIVE HAWKER said whether a producer flares the gas or
puts it in a cylinder above surface or pumps it below ground is
irrelevant. The point is that the point of production (POP) is
defined as the taxable point.
3:59:14 PM
SENATOR STEVENS joined the committee.
SENATOR FRENCH said native gas and cushion gas are not
synonymous in his mind. Gas might have to be pumped in that you
don't necessarily expect to get back out.
REPRESENTATIVE HAWKER explained that "cushion gas" is the amount
of gas that is needed to make the facility operate, but native
gas already exists in the bottom of the hole when the project is
started. Cushion gas is pumped in to get the well pressurized;
then "working gas" goes in and out. The bill says all the non
native gas has to be taken out before one starts paying
production taxes.
4:00:20 PM
He continued on to Section 15 and explained that ACES requires a
two-year amortization of the credits. In the interest of
incentivizing development, particularly doing their best to
bring in better capitalized independent players, he has
requested that the production taxes be available to the investor
in one year, the first year, rather than them having to amortize
it over two years. Section 16 is support for Section 15 and
clears up all the language they need to accomplish that mission.
Section 17 is the issue of what is allowable for these
development credits within the existing credits. This adds the
well-related expenses.
4:01:54 PM
CO-CHAIR WIELECHOWSKI said as he reads it, Sections 16 and 17
relate to Section 18, which is sort of the heart of the
incentivization.
REPRESENTATIVE HAWKER agreed, and said that Section 18 adds a
new subsection on applying for a tax credit for well lease
expenditures (page 16, line 2, (B)). This concept parallels a
proposal that the executive has introduced on a more state-wide
basis recognizing the difference between the existing tax credit
structure, which is typically for areas outside of existing
defined units, and this structure, which allows the state to
come back inside the unit and provide credits for the well lease
expenditures that are intended to increase, enhance, or mitigate
the decline of well production and are directly related to the
processes of operating a well and moving the fluids. Currently
those in-field expenses do not qualify.
CO-CHAIR WIELECHOWSKI said he understood that subsection (m) in
Section 18 is really increasing the ACES tax credit from 30 to
40 percent.
REPRESENTATIVE HAWKER agreed and explained that currently the
ACES system has a tiered 30 and 40 percent credit available to
exploration expenditures. That differential has to do largely
with how far away a project is from an existing site. With the
Cook Inlet's small footprint, it's advantageous and good public
policy to eliminate the requirement to be stepped out so far and
increasing the density of the wells in existing units needs to
happen. HB 280 asks to treat them just as a straight 40 percent
credit; the 30 percent tier is being eliminated.
CO-CHAIR WIELECHOWSKI asked if lines 16-17 still require that
the state gets the discovery data from the producers.
REPRESENTATIVE HAWKER answered yes; the bill was crafted
carefully to not change any of the technical aspects of the
various credits and policy decision previously made. They are
attempting to increase access the credits in the Cook Inlet.
4:05:13 PM
SENATOR HUGGINS joined the committee.
SENATOR FRENCH asked if the definition of "lease expenditure"
relates to the flow of the oil and gas from the casing head but
does not include the process of gathering, separating or
processing well fluids downstream of that assembly (subsection
(o) in Section 18 on page 16, lines 2-7). Did that mean up into
the well tree and the wing valve and the place where you control
the flow of the oil out of the ground but not the downstream
separators and gas compressors?
REPRESENTATIVE HAWKER answered yes. He said this language was
worked over very carefully with the Department of Revenue.
SENATOR FRENCH asked if that is the same approach ACES uses.
REPRESENTATIVE HAWKER answered that it follows along with ACES,
but increasing the credits.
4:07:32 PM
CO-CHAIR WIELECHOWSKI said it looks like Section 18 has three
essential changes; increasing the tax credit from 20 to 40
percent in subsection (m), changing the definition of "lease
expenditure" in subsection (o); and he asked if that is the same
as a lease expenditure under ACES.
REPRESENTATIVE HAWKER answered they are eliminating the existing
30-40 percent credit, not the 20 percent. A new subsection was
created to define this issue for Cook Inlet, and that language
was taken from current statute where the whole state was treated
as one.
CO-CHAIR WIELECHOWSKI asked if language on page 16, lines 8-10,
allows overhead expenditures to be included as a lease
expenditure.
REPRESENTATIVE HAWKER answered yes; it allows an overhead
component to expenditures that had been in previous versions of
the statute in an amount that is consistent with the calculative
methods already established in state regulation.
CO-CHAIR WIELECHOWSKI asked if a percentage is assigned to
overhead.
REPRESENTATIVE HAWKER recalled that overhead percentage is at
4.5 percent.
4:10:21 PM
CO-CHAIR WIELECHOWSKI asked if language on page 15, line 25,
makes the tax credit transferable and available for immediate
use and provides that it does not expire. He asked as a matter
of policy if the state wants tax credits that don't expire.
REPRESENTATIVE HAWKER answered in this case, they want to vest
in a developer the value for their development efforts. They
want this tax credit available immediately to all investors and
later on in the bill it allows small producers to access the tax
credit fund for immediate cash value for the same credit. He
thought fully vesting in the value is an appropriate public
policy in this arena.
4:11:33 PM
He went on to Section 19 and said this is where the state is
allowed to use funds from the oil and gas tax credit fund making
sure the cash flow moves to the front end of the discounting
calculation.
CO-CHAIR WIELECHOWSKI said that really is aimed at encouraging
small producers.
REPRESENTATIVE HAWKER said this one is specifically to reduce
the cost of adding the gas storage facility to the supply chain
to the consumer.
4:13:14 PM
He went on to explain that Section 20 eliminates the need for
proof of spending money in Cook Inlet in order to receive the
credits and promotes the independent small investors the state
is hoping to attract. Current law says that before the credits
can be sold back to the state further proof of spending an
amount equal to the credit in Alaska is needed.
Section 21 gives the regulation authority that is ubiquitous to
all bills.
4:15:04 PM
Section 22 is the new directive to the RCA to consider the
consequences of saying "no" to a long term supply contract that
is brought before them; something they have not had to consider
before. They have to consider the impact on the consumer of more
expensive gas or no gas. This section applies that same standard
to the Public Advocacy division of the Department of Law when
they intercede in a filing.
4:16:15 PM
Section 23 requests an immediate effective date.
SENATOR HUGGINS asked what the two largest hurdles have been in
working this bill through the process.
REPRESENTATIVE HAWKER answered getting folks to understand what
gas storage is and then reaching an accord about the equal
importance of allowing proprietary storage for the purpose of
inventory management by the producers - the overall policy call
of whether credits are a good thing or a bad thing. He believes
there is a place for both.
SENATOR HUGGINS asked the potential challenges of RCA's role in
this.
REPRESENTATIVE HAWKER answered that the chief RCA executive
helped craft HB 280. Earlier in the session the RCA asked him to
provide the commission specific guidance on whether they would
or would not regulate gas storage facilities. The bill makes the
policy call that says if a gas storage facility is a third-party
open-access facility or one that is owned by a public utility,
that it is, in fact, regulated by the RCA. It is also crafted so
that any proprietary storage that exists, inventory management
only, is not regulated by the RCA, but it also does not receive
any of the potential subsidization benefits available under the
bill to facilitate consumer deliverability.
4:19:32 PM
MARCIA DAVIS, Deputy Commissioner, Department of Revenue (DOR),
commented that she liked the way the sponsor used the expertise
of AOGCC, DNR, DOR and RCA and allocated to each agency what
their role is. However, some gaps still exist that need to be
solved so that it works well. One of the dominant concerns the
department has, especially when writing a fiscal note, is the
scope and where gas storage gets included. They heard testimony
saying this was originally intended and designed to solve the
deliverability problem for Cook Inlet and they assumed it was a
Cook Inlet gas storage bill, but as they went through it they
realized that the definition of "gas storage facility" was
simply the depleted or nearly depleted reservoir pool in the
state that is available for gas storage, and part of their job
is to think about "what if" and "what could go wrong." She said
their worst nightmares are obviously the large reservoirs on the
North Slope and how they are different from Cook Inlet. One of
the concerns, for instance, is on page 2, line 31, where it says
"depleted reservoir or nearly depleted reservoir or pool". DOR
needs an agency expert to say if something is going to qualify
as a gas storage facility. The North Slope might have reservoirs
that contain both oil and gas but they are located in different
horizons of that reservoir. And what if it still has a lot of
oil but all the gas is depleted or what if it has a lot of gas
but all of the oil is nearly depleted?
Furthermore, she said the North Slope has a long history of
straight-forward production, but now to optimize production
producers are being more creative. She thought they would begin
to see movement of resources into storage. For instance, if gas
is a limiting factor, it might come out; but if it's not yet
ready to be produced, because of sharing facilities, gas coming
out of one field might be going into another.
SENATOR FRENCH asked if this is a Cook Inlet concern or a North
Slope concern.
MS. DAVIS replied a North Slope concern. Generally in Cook Inlet
as gas is being produced a market is readily available, although
there are different times of the year when it will be stored
until it's needed in a higher quantity than it can be delivered
later on.
SENATOR FRENCH asked where North Slope gas would be sold to the
public.
MS. DAVIS replied that the North Slope has utilities; the Dead
Horse Utility is one and other owners actually utilize gas for
running their facilities. Nothing limits who the public or the
utility is.
CO-CHAIR WIELECHOWSKI asked if they could say this applies to
below the 68th degree latitude.
MS. DAVIS said she is sensitive to Representative Hawker's
comment that he doesn't want to harm the interests in Fairbanks,
if someone ever wants to store gas on the North Slope and then
move it to Fairbanks, and she was open to working that out with
him.
SENATOR FRENCH asked if one of the administration's concerns
could be alleviated by defining gas that goes into a storage
facility as that gas which has been taxed.
4:25:50 PM
MS. DAVIS replied that language actually leads to the second
large concern the administration has with the description of
native and non-native gas being produced in Section 14 on page
12. Representative Hawker was absolutely correct in his
description of the norm, which is that typically when a (Cook
Inlet) producer produces gas and sells it, that is the sale
point the DOR can readily look at to see the volume sold and the
price. In this instance, the concern is if a utility owner wants
to buy gas (from Marathon, for instance) and store it, and then
wants to draw it out in January and doesn't want o the DOR to
say that is "producing gas" and therefore they must pay a tax.
This is not the case, because the assumption is the tax got paid
when they bought if from the producer. With current language, a
producer could produce gas and because they don't have storage
they pay to store it until they "produce it when they need to
sell it." The department's dilemma is that a production took
place, but now it's held in suspension. The department wants the
freedom to work with that system and assess a gas when it "gets
produced out and sold." If language gets "hard wired" to say the
gas gets taxed when the producer produces it, a smart producer
could game the system by having it taxed in the summer when it
is cheap.
SENATOR FRENCH asked how the producers' proprietary storage
wells work now.
MS. DAVIS replied that she has done some investigation into
whether there is a long-standing rule or method of treating
proprietary storage and that is unresolved. The question came up
two or three years ago, and only one taxpayer is doing that.
SENATOR FRENCH asked if people within the department agree as to
where the point of production (POP) is.
MS. DAVIS answered that they know where the POP is, but the
question is on when the sale takes place and what value they use
to assess against that gas. Is it the prevailing value before a
sale has taken place or is it the value at the time the sale
actually takes place? The department would take the position
that it should be the value at the time the sale takes place.
4:29:40 PM
SENATOR FRENCH asked how much gas in Cook Inlet is sold like
that where the department doesn't know the price isn't the
majority of what is sold.
MS. DAVIS replied very little; but they are trying to get ahead
of the curve, because they want to see a lot of gas produced and
they want producers to have the freedom to store gas and not
worry about it. It seems fair to give the department the freedom
to tax it when it gets sold. A simple fix would be to say "non-
native gas owned and stored by a person other than the producer
of the non-native gas that is withdrawn...is not considered
produced."
4:30:42 PM
CO-CHAIR WIELECHOWSKI asked if she wants to change Section 14.
MS. DAVIS replied yes, on the bottom of page 12, line 30. An
insert would limit the application of that sentence to the
situation where the non-native gas has a change of ownership.
On page 2, line 31, it would be helpful to have some agency
advise the DOR when "depleted or nearly depleted" has happened.
In terms of administering the DOR credit on page 10, line 11
that says "must be available for the storage of gas that is
owned by a utility regulated under AS 42.05," their credit
hinges on the commencement of commercial operation and it
relates to a gas storage facility. She didn't previously
appreciate the nuance in this sentence until Representative
Hawker pointed it out. The way this phrase is used here the
concern is that a utility providing gas to the public is clearly
a utility that is regulated under AS 42.05. But in addition, a
public utility can also be the company that is providing the
storage service (page 8 - what a "public utility" is). So, two
entities would be regulated under AS 42.05 - the storage company
itself and the utility that is acquiring and using gas that the
storage facility is providing. To them, this means that the gas
storage facility must be usable and available for use by a
utility. It doesn't say that the gas storage facility itself is
a regulated utility, but she hoped that the section on page 8
applied.
4:34:25 PM
MS. DAVIS said she is having trouble connecting the dots, and
she wanted to make sure the intent is for the credit to only go
to a gas storage facility that is regulated and not to a private
proprietary one.
She wanted to make sure the DOR would be providing needed
confidential information to the legislature and interested
parties in reference to Section 11, on page 9, lines 17-21. If
you can imagine a company that owns more than one gas storage
facility, she explained, this language allows them to give the
name of the company and the total amount of the credit, but she
wouldn't be able to break it down by facility, which is what
they want to do since the credit is a capped on a per facility
basis. So, she suggested to insert "for each gas storage
facility" on line 19 after "claimed by that person under AS
43.20.046".
4:35:47 PM
A provision on lines 25-28, page 11, says a person claiming the
tax credit when they contract with a utility that is regulated
under AS 42.05 must reduce the price it would otherwise charge
that utility to reflect the tax credit. It is in the tax code,
but the DOR would have no way of enforcing it. Ms. Davis thought
this language duplicates section 7, which requires the RCA to
insure that that happens. Assuming her understanding is correct
she recommended dropping subsection (j).
4:36:58 PM
Moving away from gas storage, and looking at the Cook Inlet well
lease expenditure credit, Ms. Davis said she would juxtapose the
bucket of costs that will be subject to the 40 percent
production tax credits against the governor's bill of a
statewide 30 percent tax credit. She also wanted to point out
how it relates to the underlying ACES (Alaska's Clear and
Equitable Share) as well. Essentially, both of them attempt to
get at well-related expenses that don't qualify under the
exploration credit because they are too far away. It's the
"infield stuff" the extra work operators do to insure they are
getting more production out of fields that are already going and
that currently gets the 20 percent capital credit. Both of them
are lease expenditures, but Representative Hawker has pulled it
back to being just applicable to Cook Inlet and the Governor's
bill applies to the entire state.
MS. DAVIS said they both have to be directly related to a well.
The explanation for this under HB 280 is twofold. The first
phase is essentially exploration and development that is clearly
defined as a qualified capital expenditure under intangible
drilling costs in the current capital credit section. It also
includes another phase of credit that happens during production
and is intended to cover just the well valve assembly down hole
and expressly excludes the upstream gathering separation costs.
It includes an overhead cost of 4.5 percent of expenditures. So,
you multiply the total costs of expenditures in "buckets A and
B" by 4.5 percent, and that gets added on as a credit. It also
includes the seismic work within unit boundaries.
MS. DAVIS said language in HB 337 got simplified to essentially
the same thing, qualified capital expenditures and intangible
drilling costs. But a lot of members questioned what would
actually be in production. The department had envisioned a field
that was up and operating as being in production, but things
like well deepening, well testing, well completion,
recompletion, well work over, and sidetracking that are intended
to access new parts of the reservoir are actually viewed as more
development; it's not ongoing day-to-day work. So in the end
they disregarded the production piece out of concern that the
overhead allowance is not allowed under any other credit. And
both of them provide for seismic within the unit boundaries.
CO-CHAIR WIELECHOWSKI asked what an intangible drilling and
development cost is.
MS. DAVIS replied that it is defined under the IRS code as all
costs associated with drilling wells, which includes the pad
preparation, getting the ice road or access to it. It includes
all costs whether they are capital or operating. The question is
does it have salvage value at the end of the day. If it does, it
doesn't count. But if it's going to get consumed and used and
not really have any value and be depleted in the course of
drilling the well, it's going to be considered an intangible
drilling cost. One of the nice things about referencing the IRS
code is that it has a huge body of case law developed behind it
that makes it very clear. Companies know what this means and
won't have to wait around for the DOR to write regulations.
4:43:08 PM
KEVIN BANKS, Director, Division of Oil and Gas, Department of
Natural Resources (DNR), said the POP and value of gas are
concerns. He said the department considers the point of
production to be when a royalty event occurs - that is when gas
leaves the lease and goes into storage.
He elaborated that the department also has an issue with
deciding what value is and if they should try to ascribe a value
to royalty when gas is produced or when it comes out of storage.
In their discussions with the storage lessees and producers that
are using storage today, Mr. Banks said, they have actually
offered up something of a trade: that storage costs are not a
deduction for royalty, but royalty will be valued on the day
that it is produced. In other words, they "let go of the rope"
in terms of trying to figure out when the gas leaves storage to
come up with some sort of value methodology. So, if the value of
gas is sometimes low and that's when production is occurring,
that is the value they will use in calculating the royalty in
that case. It fits in nicely with HB 280 because now they don't
have to figure out whose gas is who's when it comes out of
storage.
4:45:12 PM
SENATOR STEDMAN joined the committee.
4:45:46 PM
MR. BANKS said when the bill came out of the House it had a
measure that says the credit allowed for storage is based on
$1.50 of the storage working capacity and limited it to $15
million; now it's limited to 25 percent of the cost of building
the storage. This puts a nice box around the state's exposure in
providing these kinds of credits - a good thing. At least they
know, when the state is committing funds, that there is some
kind of potential access that will be available to utilities
with respect to storage.
Lastly, on the question of tax credits for exploration and
development wells, he recalled discussions about potential
supply in Cook Inlet and he said all of the new production the
department examined involved the drilling of wells within
existing units. They are not looking to rank exploration to find
new supplies of gas. Having said that, none of that production
would have received tax credits under existing ACES law. This
bill then actually provides that tax credit for new supplies of
gas that will come from existing units in Cook Inlet - an
important point as they are now targeting the right development
activity.
4:48:39 PM
MR. BANKS went on to the question of whether storage should be
proprietary or third-party. He explained that the reason DNR is
involved at all is that the right to inject outside substances
into an existing lease for this kind of purpose does not exist
in the current oil and gas lease. So, the DNR has to have a
storage lease so that the owner of the oil and gas lease can
move ahead and operate a storage facility of any sort. That puts
the DOR "in the hopper" when it comes to extending a new right
that doesn't exist - that is to inject and withdraw gas from a
reservoir that is already under oil and gas lease. That means
there are no opportunities in the Cook Inlet for storage except
for those that are currently under lease. Most of that is under
state land with an exception of Swanson River where the federal
government has a storage lease.
From the perspective of the department, he thought a public
purpose should be served if it is going to extend a private
right over public land. Their principle then is that storage
should be offered to third parties and that there should be some
opportunity for others to use the storage in some way. That
position gets stated in the form of a lease that they gave to
some of their applicants. For him that was the start of the
discussion about what this would look like.
MR. BANKS said he would allow lessees to meet existing supply
contracts from storage, but as that obligation declined, the
access in the form of interruptible service, for instance,
should be available to others. Similarly, if there was a concern
on the part of the developer about getting back their investment
in the storage he was willing to take into account some
methodology where they become their own "anchor-shipper" in the
storage facility, so they would be assured of the amount of
storage they would need. But again, as that space became
available it should be offered to others.
4:52:59 PM
MR. BANKS said this bill has a commitment on the part of the
state to see storage developed and it provides a credit; in
order to get the credit you have to be regulated. He could work
with language in Section 4 that says the director cannot reject
an application solely because it's not third-party storage.
There could be a situation where they would reject an
application, for instance, if the surface facilities that are
built in conjunction with storage are on some kind of refuge or
there is some other land use conflict that arises because of
that. The word "solely" helps out in this regard.
CO-CHAIR WIELECHOWSKI invited Ms. Davis back. He asked both of
them if this bill gets them to the point mentioned in a
presentation from outside consultants hired by the utilities
that said 13 new wells a year are needed for the next decade as
well as gas storage.
MR. BANKS replied that the consultant was PRA, and they used the
department's study as a starting point and basically validated
their supply numbers. These credits target that kind of supply
and based on the last 10 years of experience in Cook Inlet.
Largely now, Cook Inlet producers have certain commitments to
supply gas to the utility with whom they have contracted with.
He thought any of them would drill wells in order to meet their
needs. These credits reduce the cost to the producer of making a
commitment to supply a certain amount of gas, and perhaps those
lowered costs will be reflected in slightly lower prices to the
consumer. There are no guarantees, and the outcome of this
measure won't be known until time passes.
MS. DAVIS responded that she believes the gas storage credit is
in the right direction simply because it hasn't been tried yet;
and they all know that deliverability is a crucial link in the
ability for producers to economically be able to drill expensive
wells. She also observed that less than three people have taken
advantage of the corporate income tax exploration incentive
credit that is currently on the books at 10 percent.
CO-CHAIR WIELECHOWSKI asked Enstar to comment on their pursuit
of a Cook Inlet storage facility with the TransCanada subsidiary
and if this bill is heading in the right direction.
4:59:47 PM
JOHN SIMMS, Manager, Corporate Communications and Customer
Services, Enstar Natural Gas Company, said he supported HB 280.
Enstar also supports anything that can be presented to the
consumer as a potential savings. They are moving forward with
storage and have notified TransCanada that they would like to
exercise their option to purchase the SS and work product, but
they weren't able to reach an agreement on commercial terms.
SENATOR STEDMAN asked if he had a timeframe.
MR. SIMMS answered that their goal is to have this project
initiated and under way by 2012.
SENATOR STEDMAN asked if their project would go forward without
this bill.
MR. SIMMS answered yes; both Enstar and South-central Alaska
need storage, but anything else is appreciated.
SENATOR FRENCH said when they spoke to Singh's (TransCanada
subsidiary) about the issue of regulation, they said they are
comfortable with it, and he asked Mr. Simms if he is comfortable
with RCA regulation.
MR. SIMMS answered yes.
CO-CHAIR WIELECHOWSKI asked him to talk about the size of their
facility.
MR. SIMMS said he couldn't talk about it at this point. They are
still in negotiations.
5:03:27 PM
CO-CHAIR WIELECHOWSKI asked if this facility solves all of South
Central's storage problems.
MR. SIMMS answered that it will help in the near term, but he
couldn't comment further.
5:04:10 PM
CO-CHAIR WIELECHOWSKI invited Representative Hawker back.
5:04:19 PM
REPRESENTATIVE HAWKER commented that DOR's issues have been
resolved amicably and everything else could be dealt with, too.
This bill is not a panacea for resolving all issues, but it is
targeting an important area.
5:07:01 PM
CO-CHAIR WIELECHOWSKI asked Mr. SIMMS if Enstar intends to
provide storage to others.
MR. SIMMS replied that he didn't know what the arrangements
would be.
CO-CHAIR WIELECHOWSKI set HB 280 aside for further work.
^Instate gas testimony - David Gottstein
Instate gas testimony - David Gottstein
5:08:37 PM
DAVID GOTTSTEIN thanked them for hearing his views on CSHB 369
and the gas pipeline in general. The following is his statement:
I come at the pipeline questions not only as an
interested Alaskan, but as a 20-year company analyst
and Registered Investment Advisor with degree from the
Wharton School, having also been a logistics and
supply chain manager in a major grocery operation for
almost ten years. Perhaps the intersection of these
two disciplines allows me to look at the question at
hand differently than most because any pipeline
project is largely a combination of economics,
logistics and finance.
The most important thing I have to say regarding
logistics is, since logistics is mostly about moving
weight and cubic volumes at the lowest cost per unit
of distance, that any effort to get Alaskan's gas to
Alaskans that doesn't include material export capacity
will be terribly short-sighted and will cost the State
of Alaska at least tens of billions of dollars over
time in lost opportunity, in addition to saddling most
Alaskans with much higher energy costs for decades to
come than they would have to pay otherwise by
piggybacking on top of an export volume-based and
efficient distribution network. That means at a very
minimum, a large diameter pipeline from the North
Slope to a logistical sweet spot in the Interior must
be the anchor of any pipeline project. We should
concurrently spur to Fairbanks and South Central and
then let the markets determine the fate of the
remaining logistical foot-print, or rather sizing and
routing, of any further distribution. When economics
justify it, albeit Canada, Valdez/LNG, and any value
added processing.
A bullet or rather small diameter line is a very high
cost alternative and makes everything else less
economic. Only by finding competitively cost efficient
ways to deliver gas and gas products on an export
basis will we be able to generate the economies of
scale for a gas pipeline sufficient to begin to lower
what will otherwise be high energy costs for Alaskans.
The oil and pipeline companies must wait until they
fill a pipeline through the open season process before
they can commit to build because they are looking for
immediate economic rent and returns on capital. And
they can't otherwise finance such a project.
Therefore, regardless of how they may be posturing
now, uncertainty about intermediate to long-term gas
pricing and demand means it could be a decade or more
before boards of directors will be in a position to
vote to dedicate the large capital investments
necessary for a massive project such as the Canadian
route. Everything they do in the meantime is the cost
of posturing to maintain an option to actually build
only when they want to.
But we can't afford, though, to freeze in the dark
waiting. Only the State of Alaska has the vested
interest in making sure we get Alaskan's gas to
Alaskans in the shortest amount of time and provide
for an efficient distribution network. One not offered
by a small diameter line. We also need no leave our
destiny to the calendars of outside boards of
directors with very different interests. CSHB 369
recognized that, and therefore could be the right
instrument to move forward on with some critical
adjustments, but the document must first conform to
the economics, I believe, and not the other way
around.
The most important thing I have to say regarding the
economics, and I am not suggesting this position, but
rather just offering the baseline economics, is that
the State of Alaska,...is the only entity as the owner
of the resource who could write a check for cash to
pay for the pipeline, charge zero for the tariff and
make between $50-100 billion. That is because we make
the vast majority of our money selling the resource
not in the transportation of it. When you start up
with the economic focus and calculate what you get by
investing the $3 billion extra it would take to
increase the size of the pipe from the North Slope to
the Interior suitable for export capacity, the
economic and business decision becomes quite simple
because the returns are enormous. Only the state can
afford to incubate or have a portion of the pipe idle
for a period of time and wait for the rest of the
market to come to it. It puts us in a very powerful
negotiating position. How long can we wait until the
pipe needs to be filled before we lost he bet? The
answer is 50-100 years if you look at it from an
economic and financial perspective. I would be happy
to share with staff how to make those financial
calculations.
5:13:09 PM
And I am not talking about having the State take any
construction risk, or to design, build, maintain or
manage the project. That would be done by private
sector partners who gain rights to future tariffs as
negotiated. Hopefully this would include the Big Three
and TransCanada. And we can further separate economic
rights from governance rights in our negotiations.
So here are 12 things that the State of Alaska gets if
it underwrites and elevates to Investment Grade a gas
pipeline with efficient export potential, made
possible by $3 billion extra dollars and a patient
development capital, which could be financed a number
of different ways:
· 1. We avoid saddling Alaskans with high energy costs
for 30 years or however long it might take to pay off
the bonds necessary for a small diameter high cost per
unit line. Only when export volumes are achieved will
economies of scale be available to pass on to
consumers in the form of lower energy tariffs and
costs.
· 2. We avoid putting an export project at materially
greater risk in terms of time and money by moving from
a highly inefficient logistical foot print to a highly
efficient one. Since we won't then have to build two
sets of pipe to move the same amount of gas that could
move much more efficiently the same amount of gas.
· 3. We get gas to Alaskans in as little as six to eight
years.
· 4. We put our future and destiny on our timeframe
instead of that necessary for an alignment of
unpredictable, disparate, and naturally competing
factors and interests outside of out control.
· 5. By announcing to the energy community that we are
prepared now to build, and we invite them to
participate, we force them to act for fear of being
left behind.
· 6. We greatly invigorate the potential for adding
volumes not only to the gas pipeline, but the oil
pipeline as well. This is because not only will we
also make it possible for new oil and gas explorers on
a spot basis, not having participated in an open
season necessary to secure capacity, the opportunity
to explore and produce, knowing they can get their
product to market. And when the look for gas, they
will find more oil and vice versa. Yesterday's
continental shelf rulings magnify this potential.
· 7. The Oil and Gas Conservation Commission (AOGCC),
for the first time will be empowered to maximize their
mandate by maximizing the trade-off of oil and gas
values, unconstrained by capacity limitations.
· 8. We position many parts of rural Alaska to benefit
with reliable access to lower cost energy over time
because of economies of scale.
· 9. We create the opportunity to approach Hawaii most
importantly about Alaska being a long-term significant
solution to their energy needs with a project that
could actually happen unfettered with any export
limitations.
· 10. We will jump start the economy and generate
decades of improved prosperity for all Alaskans. With
a long-term fiscal plan based upon the rational
management of our energy wealth resulting in being
able to continue contributing to the Permanent Fund in
material ways for many years to come.
· 11. We avoid to a considerable degree exposing the
state to long-term fiscal decay and hopefully put off
until long into the future pressures to use the
Permanent Fund to help pay for state government.
· 12. If we have buyers and a pipeline, the producers
will have no choice but to supply our gas. The view
that the producers hold the key to everything doesn't
have to be.
5:17:18 PM
So how do we do earn all this? By doing the following:
Appropriate enough money this session to fully vet
this approach. This can be done separately or by
amending HB 369 to focus on a large capacity line from
the North Slope to an Interior hub. Including what
role the State of Alaska could play in order to insure
the project moves forward as soon as possible, on an
Investment Grade basis. No research being done at the
state level currently contemplates this scenario.
If we get our gas to a hub, the ratepayers can afford
to take it the rest of the way. Just doing this alone
this year will put pressure on the majors to take this
upcoming season more seriously.
We can wait for multiple open seasons before we get
started, adding at least one to two years to a project
or we can start now. The sooner we announce to the
world we are doing this the sooner serious
negotiations can begin with potential buyers.
In terms of the legislation, I support legislation
that attempts to do something, but without focusing on
the economics, we lose the economics. Putting a time
limit on the process handicaps and limits the results.
I would rather see us engage in an expedited process
rather than mandate a timeframe that limits a result.
I have no prejudice in terms of what state entity
manages the process as long as the members are
qualified, could with any extra advantages that might
be inherent in a particular entity. I will offer that
one could it would seem, greatly expedite the process
by avoiding another time consuming RFP process simply
by renegotiating the AGIA license with TransCanada as
authorized within AGIA to convert the state to a co-
developer of the big pipe to the Interior owning
whatever rights the private sector chooses not to
adequately bid on. In the end, that could even be very
little.
5:19:12 PM
The only way we lose this bet is if China and India
don't grow sufficiently in the next 50-100 years to
make North Slope gas economic. That should be an easy
bet. The only tough decision there might be is if we
generate perhaps 2 BCF/day of demand from in-state use
and Hawaii, along with Japan and South Korea perhaps,
with an 80-90 percent chance of success and we are
also faced with a much larger Canadian opportunity,
and there isn't enough gas for both projects. Only if
the Canadian option rises significantly above the 50
percent likelihood in a predictable timeframe might
there be a real choice to make. But we don't have to
make that decision until we are faced with that
option.
Thank you, members of the committee, for allowing me
to present.
5:19:54 PM
SENATOR FRENCH asked the significance of the "investment grade"
labeling.
MR. GOTTSTEIN replied that it means a few things; on one end it
means that purchasers of gas can with reliable enough certainty
expect that the project will be done and that everything will
happen according to plan. For instance, a defined benefit
pension plan needs to achieve certain actuarial rates of return
with a high probability of doing so. If it buys a revenue bond
for a bridge and its debt service coverage ratio is 1 in 3
meaning it needs 100,000 cars a week to pass the bridge, but it
can pay for its debt service with only 75,000. There is a lot of
debt service coverage; so rating agencies and insurance
providers might say it's suitable for investment. Typically that
would mean a triple A or a double A rating. There in some sense
must be a tie to a revenue stream if it's a revenue bond. On the
other hand, that could be eclipsed while bringing the state's
considerable credit worthiness to bear and simply make a general
obligation of the state and instantaneously it would have
investment grade status because it wouldn't require the success
of the project in order to have the bond holders get paid.
He said he doubts that the pipeline project would not be
successful, but he is painting two ends of the spectrum about
what the state would have to do to be investment grade. He
explained:
Today we have a chicken and an egg situation keeping
us from being investment grade; that is the producers
won't commit to a pipeline until they fill it and
buyers won't commit to buying until they know it's a
real project and have some way of determining things
like tariff. So the only entity because we have a
vested interest in capacity that can, in effect, trump
that whole process and say we'll take the development
risk necessary to make this investment grade that will
take us much further down the road into a position
where we actually have pipe and we actually have the
opportunity to get buyers.
CO-CHAIR WIELECHOWSKI thanked him again for his testimony.
5:23:03 PM
DON ETHRIDGE, Alaska AFL-CIO, said the legislation is for
building a line and it states to use Alaska hire to the utmost
possible, and "There is only one way to do that; and it's with a
project labor agreement." That is what they want to see during
the planning process.
5:24:29 PM
CO-CHAIR WIELECHOWSKI thanked everyone for their input and
adjourned the meeting at 5:24 p.m.
| Document Name | Date/Time | Subjects |
|---|---|---|
| SB 271 - Bill Packet.pdf |
SRES 4/5/2010 3:30:00 PM |
SB 271 |