Legislature(2015 - 2016)BARNES 124
02/25/2016 08:30 AM House RESOURCES
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| Audio | Topic |
|---|---|
| Start | |
| HB247 | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| += | HB 247 | TELECONFERENCED | |
| + | TELECONFERENCED |
HB 247-TAX;CREDITS;INTEREST;REFUNDS;O & G
8:34:59 AM
CO-CHAIR NAGEAK announced that the only order of business would
be HOUSE BILL NO. 247, "An Act relating to confidential
information status and public record status of information in
the possession of the Department of Revenue; relating to
interest applicable to delinquent tax; relating to disclosure of
oil and gas production tax credit information; relating to
refunds for the gas storage facility tax credit, the liquefied
natural gas storage facility tax credit, and the qualified in-
state oil refinery infrastructure expenditures tax credit;
relating to the minimum tax for certain oil and gas production;
relating to the minimum tax calculation for monthly installment
payments of estimated tax; relating to interest on monthly
installment payments of estimated tax; relating to limitations
for the application of tax credits; relating to oil and gas
production tax credits for certain losses and expenditures;
relating to limitations for nontransferable oil and gas
production tax credits based on oil production and the
alternative tax credit for oil and gas exploration; relating to
purchase of tax credit certificates from the oil and gas tax
credit fund; relating to a minimum for gross value at the point
of production; relating to lease expenditures and tax credits
for municipal entities; adding a definition for "qualified
capital expenditure"; adding a definition for "outstanding
liability to the state"; repealing oil and gas exploration
incentive credits; repealing the limitation on the application
of credits against tax liability for lease expenditures incurred
before January 1, 2011; repealing provisions related to the
monthly installment payments for estimated tax for oil and gas
produced before January 1, 2014; repealing the oil and gas
production tax credit for qualified capital expenditures and
certain well expenditures; repealing the calculation for certain
lease expenditures applicable before January 1, 2011; making
conforming amendments; and providing for an effective date."
8:35:28 AM
KEN ALPER, Director, Tax Division, Department of Revenue (DOR),
on behalf of the governor, continued the presentation, "Oil and
Gas Tax Credit Reform- HB247, Additional Modeling and Scenario
Analysis - Part 1a." He advised that the presentation delves
into the deep sectional [analysis] and reviewing some of the
more complicated pieces of the bill and how they work. The
presentation goes into modeling of specific new field scenarios
and the overall economic impact of the bill. He noted that the
last slide of his previous presentation was slide 44, "Section
17(c): Strengthen the Minimum Tax," which was the end of the
conversation of "strengthening minimum tax by moving per barrel
credits from month-to-month or preventing that from happening."
MR. ALPER turned to slide 45, "Section 18: GVR Can't Increase
Net Operating Loss (NOL) Credit" and said the concept would
prohibit a producer operating at loss who is eligible for the
gross value reduction (GVR) for the new oil benefit from being
used to increase the size of net operating loss. For example,
he said, this scenario is akin to the current day of low oil
price/low cost. In the event a producer is losing money because
the prices are low, it earns an operating loss credit based upon
its loss but is allowed to increase the size of that credit by
taking the "so-called" gross value reduction (GVR) and
subtracting it from the loss to make it appear, on paper, to be
a larger loss. He offered that the result of the change would
reduce the credit to 35 percent of the actual net operating loss
rather than a calculated number that is somewhat higher. Within
the upcoming case, he explained, was that the state's liability
would be reduced by approximately 50 percent, or in the context
of a $10,000 taxable barrel per day field, of approximately 7.6
million per year.
8:37:59 AM
MR. ALPER moved to slide 46, "Section 18: GVR Can't Increase Net
Operating Loss (NOL) Credit - Current law allows GVR to increase
an NOL credit." He reviewed the example depicted on the table
in a world of $40 oil, and pointed out the following: West
Coast price $10 transportation - shipping and pipeline tariffs;
the well head value, which is also the gross value, $30 a
barrel; lease expenditures - the lifting cost $36; and the loss
is $6 a barrel. He advised that the model being looked at is
based on a single barrel of taxable oil, and for the purposes of
this example this producer lost $6 a barrel producing that oil.
The way the GVR works, he explained, is to determine the
wellhead value ($30 gross value), and take 20 percent which
equals 6, and subtract it from the net value (negative 6), and
the resulting subtraction equals negative $12. For purposes of
the credit calculation, under current law, although the producer
lost $6, it appears as though it lost $12, and the 35 percent
credit (operating loss credit) applied to that $12 results in a
$4.20 cash rebate for the operating loss credit. The $4.20 is
roughly 70 percent of the $6 a barrel loss. The bill
contemplates that although the GVR is important, for the
purposes of reducing the tax burden of profitable new producers,
"we don't want that reduction to be useable in the event of a
loss," and by by-passing that calculation only the $6 actual
cash flow loss would be eligible for the credit, 35 percent of
$6 equals $2.10. Therefore, the state's credit liability would
be cut in half - $2.10 per taxable barrel, or when multiplied
across the year with a 10,000 barrel field, $7.6 million a year
in credits instead of $15.3 [million].
8:40:11 AM
MR. ALPER addressed the second example on slide 48, "Section 18:
GVR Can't Increase Net Operating Loss (NOL) Credit - Current law
allows GVR to increase an NOL credit." He said this example
looks at a slightly different type of scenario with a higher oil
price, but the company may still be losing money. He described
it as a quite plausible scenario especially for a new field
because typically the producer drills its first couple of wells,
it begins production and has oil flowing, and the producer
continues to drill major wells causing additional costs that
could cause cash flow losses over the course of the first
several years of production. He explained that the scenario
depicts higher costs based upon field buildout and also higher
prices, still generating a $10 per barrel cash flow loss, and as
the example points out the GVR could lead to very high credits.
He then explained that the scenario started with $80 oil which
is now high priced oil, and pointed out the following: there is
the same expense of transportation, wellhead at GVR of $70,
lease expenditures at $80 per barrel, and now that company lost
$10 per barrel last year. Based upon the $10 barrel, under
normal circumstances the company would receive a $3.50 credit
(35 percent of the loss) except, due to the application of the
GVR, it is necessary to go back to the $70 wellhead value, 20
percent of that $70 equals $14. The company would then subtract
the $14 from the negative $10 to get the red circled number of
negative $24. For the purposes of the credit calculation and
only for that purpose, the company is considered to have lost
$24 a barrel, and apply the 35 percent credit to that number,
which results in an $8.40 credit, or 84 percent of its loss is
paid by the state's operating loss credit. He said that by
making the change envisioned in HB 247, the actual credit paid
would be limited to 35 percent of the loss, or $3.50. In this
circumstance, based on a 10,000 barrel field, the difference
would be a savings to the state, or a reduction in the state's
credit liability, of $17.9 million.
8:42:37 AM
REPRESENTATIVE SEATON surmised that the state allows a
calculation of net operating loss at 35 percent of the
expenditure, and the purpose is to say that in the calculations
the net loss is carried forward and could be no more than 35
percent of the company's loss.
MR. ALPER clarified that the loss carry forward credit of 35
percent is 35 percent of the loss itself, statutorily. He said
Representative Seaton was absolutely correct because the bill is
saying that the amount the state is paying isn't going to exceed
a number greater than 35 percent of the loss. He posited that
the application of the GVR calculation being used to increase
the size of that loss was an unintended consequence of an
unforeseen circumstance that was in the formula of the previous
legislation that lead to very high credits. Last year and the
year before, the operating loss credit was 45 percent, and he
said he has seen circumstances where the state was paying
credits of more than 100 percent of the loss.
8:43:57 AM
REPRESENTATIVE JOSEPHSON referred to paying more than 100
percent of the loss and asked whether a model of that is
contained within the presentation.
MR. ALPER replied it isn't modeled in any of the slides because
it's looking going forward with a 35 percent operating loss
credit. He offered that when getting to the $24 paper loss, the
calculated loss after the application of GVR in this status quo
scenario, if a person takes 45 percent of that, it would be
another $2.40 on top of the $8.40 which would be $10.80. In
this case, he pointed out, it would be 108 percent of the $10
cash flow loss the company actually experienced in its
operation, if it was eligible for 45 percent credit if the
example on slide 48 were a 2015 example instead of a future year
example.
REPRESENTATIVE JOSEPHSON responded that within that scenario for
purposes of production tax only, not property and equipment or
royalty, the state took absolutely nothing - there's no
production tax in that scenario.
MR. ALPER answered that if the company is losing money, unless
it is susceptible to the minimum tax of which new oil is not,
the state would generally take nothing. In this circumstance,
the discussion is minimizing the size of the operating loss
credit paid rather than any amount of take. Representative
Josephson is correct, he stated, in this circumstance that
company would not have paid any production tax.
8:45:34 AM
REPRESENTATIVE JOSEPHSON pointed out that during yesterday's
meeting, Mr. Alper testified that he had reviewed the minutes on
the question regarding the monthly calculation of tax and the
migration issue, and that he saw only an exchange between a
former deputy commissioner and Representative Seaton. Now, he
pointed out, Mr. Alper is saying that relative to this "you
didn't say an oversight, but that was the essence of it," and
asked why that is so.
MR. ALPER reiterated that he does not believe there was much
contemplation of what happens in a very low cost scenario and
how losses might be treated. The GVR was specifically discussed
as a means of reducing tax liability for qualified new oil, and
there have been multiple hearings on the debate about what
qualifies for new oil, such as new fields, how to define that,
new participating areas expanding, expansions to existing, and
will there be a menial requirement. The regulatory process, he
pointed out, was regarding what would qualify but the actual
calculation of how the new oil benefit would be treated in the
event of a loss was never contemplated. In speaking with
several professionals within and outside the division, the
department's attorneys, and people who closely follow the
process, "I've received something like consensus that this was
an unforeseen circumstance ... this is not something that we
thought of ourselves." He reiterated that when a credit came
before [DOR] with this type of calculation, it was stopped in
its tracks and given to the lawyers to be certain this was being
treated correctly because it appeared intuitively wrong. The
law is the law and it was interpreted strictly, he advised, and
a strict interpretation led to these calculations. Although it
will take money out of the pockets of several companies, that
money is greater than 100 percent or very high loss credits that
[DOR] believes was outside the intent of the legislature. He
said he views it as more of a technical cleanup, although there
is a material value to the state to prevent this circumstance
from occurring in the future.
8:48:11 AM
CHERYL NIENHUIS, Acting Chief Economist, Commercial Analyst,
Anchorage Office, Tax Division, Department of Revenue (DOR),
added that when "we were reviewing this bill, it did come to our
attention that a ... net operating loss could be increased by
the GVR, and I believe that the administration was made aware of
that." Having not been part of the legislative process, she
said that she does not know what was communicated.
REPRESENTATIVE JOSEPHSON asked who "we" represents, and assumed
that if there is a license plate bill, the governor is advised
by the license plate people whether to sign the bill.
MS. NIENHUS stated "Yes, I'm talking about the previous
administration which could explain why Director Alper may not
know that we had those conversations."
8:49:21 AM
REPRESENTATIVE SEATON related that many of the current members
of the House Resources Standing Committee were on the committee
during the previous administration. He remarked that there was
quite a bit of discussion as to whether the 45 percent net
operating loss should be allowed because the number was high and
it was limited to two years as "kind of a ramp-down to 35
percent net operating loss credit." He stressed there was never
an indication, that the committee could be discussing the state
picking up 70 percent, 80 percent, over 100 percent of a
company's net operating loss. That would have risen to a level
of high concern and however the numbers are calculated here, he
opined, that it was not the intent of this committee at any time
to say that the net operating loss would exceed 45 percent, and
that only for two years. This calculation needs correction back
to the [prior] committee's intent, he emphasized.
8:50:37 AM
REPRESENTATIVE TARR concurred with Representative Seaton and
noted that the materials and modeling the previous committee
reviewed were well above today's price range and that it was a
shortcoming on the part of the committee. She then referred to
the fiscal note from Senate Bill 21, and asked what the
anticipated fiscal impact of the provisions of that bill were
versus the actual fiscal impact. While the comparison may not
be available today, it might be a useful comparison to determine
whether the committee "over-shot/under-shot" in terms of the
committee's expectations.
MR. ALPER described the Senate Bill 21 fiscal note as an
excellent historic document, with a table breaking down the
various components of that legislation into its sub-sections,
wherein the department tried to the best of its ability to
calculate the fiscal impact of the specific sections. The
section related to the GVR "bounced around a lot" as the
definitions of GVR changed as the bill worked its way through
the legislative process. At the end of the day, it was
estimated in the early years to be approximately a $25 million
fiscal impact, meaning a negative revenue on the state, he said.
The ability of the GVR to effect refundable credits was not
contemplated within the fiscal note, which is the circumstance
currently before the committee. The fiscal note was based upon
the forecasted price at the time, he reiterated, which was in
the low one hundreds.
8:52:21 AM
MR. ALPER drew attention to slide 49, "Sections 26-27: Credit
Refund Limitations - Four New Limitations on Cash Refunds," and
said that the bill discusses restrictions on the state
repurchase of credits. This is different from the elimination
or the disqualification for credits because it envisions
circumstances where credits will be earned but the company will
not be able to receive cash for those credits. Additional
requirements where companies would be forced to hold those
credits and either sell them to another company, or use them in
some future year when they owed taxes and had profitable
production, he explained. Under current law, he pointed out,
there is a restriction that only one set of companies can
attach; those are the companies that produce greater than 50,000
barrel a day, the major producers. He said that "the ability to
refund open-endedly might be unaffordable for Alaska in the
current circumstances" and depending upon the companies that
might be attracted to investing in Alaska, some may have a
greater ability than others to hold credits on their own balance
sheets for the future. He pointed out that with some of the
companies "we do want to continue to offer money to because it
helps them with their financing and their ongoing operations."
8:53:31 AM
MR. ALPER said there are four different limits that will affect
different companies differently, as follows: The first
restriction is that in addition to this 50,000 barrel a day (the
three major producers in Alaska), the world's other major
producers don't need cash for their credits. He conveyed that
if a company has gross global revenues of greater than $10
billion in the previous year and should those companies be
investing in Alaska, they have the means and balance sheets to
hold their credits until a future date when they have oil
production, and those credits will retain their value and be
used against their taxes.
MR. ALPER explained that the second restriction is separate and
distinct, and is for those companies smaller than the $10
billion threshold. For these companies "we are going to say,
'here are your credit certificates, we will cash them out up to
the amount of $25 million per company per year.'" He noted that
that number was pulled from the original credit buyback language
in the production profits tax (PPT) bill (2006 House Bill 3001).
In 2007 it was removed and HB 247 would restore it to statute.
For a company in Cook Inlet, for example, if the state is
currently paying 50-60 percent of costs and the company says it
is investing $200 million this year, "that means we would be
paying $100-$120 million of that cost through the refundable
credit program." Under HB 247, he continued, "We're saying
we're only going to issue $25 million in cash, the rest of those
credits would be rolled forward, used against the next year, and
it would be a first-in/first-out type of calculation."
8:55:16 AM
REPRESENTATIVE JOSEPHSON offered that he is not saying that it's
not a good policy, but it seems that the fallout would slow
development and suppress economic interest.
MR. ALPER recognized that any change improving the state's
fiscal picture by reducing the producer's fiscal picture will in
some manner affect decision making. He said he comes before the
committee mostly from the position of affordability, in that the
state is paying hundreds of millions of dollars a year that it
does not have. Therefore, in looking to conform the system to
the state's abilities, to ask "what can we do ... we want to
help, we want to encourage new development, we don't want anyone
leaving, or we don't want to throw uncertainty in anyone's
financing." He said it is important to get the limitations
pinned down because it creates even more uncertainty if credits
are being issued that the state can't afford to buy back, which
is something that could be occurring before too many more years.
There is no particular magic to $25 million, he reiterated, as
it was the number used in the PPT bill. All of the credits are
transferrable and can be sold, there is a free market in
credits. For example, if a company has tax liability it can go
to another company that has extra credits and purchase credits,
generally at a discounted rate, and the company purchasing the
credits would be able to use them to offset its own tax.
Although, he noted, there are certain limits and restrictions on
that in existing statute but that is another certain
circumstance that occurs.
8:57:11 AM
REPRESENTATIVE SEATON commented that the committee has seen the
situation where the state has a large liability for a large
percentage of a project which is used as a financing mechanism,
and the companies without adequate balance sheets come in and
then go bankrupt, thereby leaving people in the state on the
hook through the bankruptcy court going back 90 days. The
bankruptcy court then recovers money from the Alaskan supplier
because it was within 90 days of the bankruptcy. He pointed out
that the problem is being stimulated by the excessive amounts of
credits available for people to finance operations when they
don't have balance sheets to support the operation. Then if
something happens, as has happened in Cook Inlet, all of a
sudden the citizens of the State of Alaska who have been doing
business are left on the hook for that. He stressed that
something must be done and if the limitation of $25 million a
year assists in the situation of ascertaining that the state has
companies with reasonable balance sheets to support their
activities, it would be helpful but it is not the whole answer.
8:58:55 AM
REPRESENTATIVE JOHNSON pointed out that the committee is looking
at one portion of the tax. He said he appreciates the
affordability aspect, but asked whether the state can afford to
potentially lose the royalties and property taxes, "basically
what's the total government take for lack of a better term." He
further asked how, if the aforementioned is lost, that stacks up
against losing this particular one segment of the tax structure.
As an overall picture, what happens when a company decides it is
not going to do anything, can the state afford that in terms of
those other taxes the state would be missing out on? He asked
that that be part of the calculation as well, including the
cities and state, and the total government take, because this
presentation is a small piece of a very large puzzle.
MR. ALPER agreed and said the upcoming presentation starts to
drill into those issues, the total government take, how the
royalty fits in, the producers' profitability, and net present
value calculations reviewing cash flow, which is important
because the royalties are more back-loaded and these credit
obligations more front-loaded. Without question, the royalty
does compensate the state, even in circumstances where the
state's value from the production tax might be zero or negative.
He noted there is some danger in that there is no restriction
that these credits have to be used on state lands; therefore,
the credits could also be going to projects that do not generate
royalties to the state. He pointed out that it is not a fix
contemplated in HB 247 but it is worthy of discussion.
9:00:56 AM
REPRESENTATIVE JOHNSON said it is important to keep in mind that
when it is all rolled together the total take is still a net
profit even though the discussion has been that the state is
paying 100-110 percent of this tax. There is no scenario, he
opined, where someone drills a well, with everything included,
that the state loses money. The state loses it in this
particular segment, but overall when someone puts a straw in the
ground and starts producing oil the state does generate revenue.
He asked whether there is a scenario where it wouldn't.
MR. ALPER responded that if the project is unsuccessful the
state could be out the credits and then not have the revenue.
If the company is drilling on state land there may never be
enough revenue just in the property or corporate income tax to
compensate for the negative cash flow from the production tax.
Frankly, he pointed out, some of the smaller producers, the
startup companies that Representative Seaton referred to, are
not necessarily "so-called C Corporations," and are not paying
the state's corporate income tax, and then the state is left
with the property tax. Property tax issues are different in
different parts of the state. In the North Slope the state only
receives 7.5 percent of the property tax and the North Slope
Borough gets the rest, in Kenai it is a little closer to 50-50
percent. For the most part, he explained, if there is a
successful project the state will have positive cash flow; if
the cash flow is discounted over time because of the negatives
up front, the state may not make money.
9:02:34 AM
REPRESENTATIVE JOHNSON said he knows that "we are a state entity
but we can't discount the money that we're going to have to come
up with at some point for schools and everything else, that that
property tax that goes to those cities." He continued, "So, we
can't discount the fact that when the cities are making a
dollar, that's a dollar we don't necessarily have to deal with
on a state level. So, I don't want to discount the fact that
50-50 or 17 percent, it's all part of that total government."
At some point, he said, he would like to see how this fits into
that and take a big picture of a realistic and hypothetical
project and determine what is being jeopardized if one of the
plugs is pulled. He said he wants to make it clear that the
total government take is an important issue as well.
MR. ALPER answered that his current presentation jumps around in
the bill and is drilling down at specific provisions because at
the original presentation of the sectional there was a lot of
confusion in that it is a big technically complex bill. He said
it is his hope to provide the committee members an understanding
of the bill's intent and vision. The next presentation has a
total government take analysis, how it changes in different
price scenarios with or without the bill, and how the features
of the bill affect the project. The next presentation creates
some theoretical field sizes, "what's a 50 million barrel field
look like, and on the North Slope what's a big field if someone
finds a 750 million barrel field, an Alpine plus type field ...
how would these credit changes impact their development." Now
that the model exists it is quite robust and can run additional
scenarios per any member's desire.
9:05:07 AM
REPRESENTATIVE JOSEPHSON referred to Representative Johnson's
point and said he looks forward to that presentation. He
referred to Middle Earth and Doyon lands, which he noted is a
different thing in that the state does not receive royalty. He
opined that everyone is a cheerleader of that project because
they are the underdogs who are trying to make this happen. He
surmised that that would be an example of no positive income
there unless things turn, and Doyon says that things might turn.
MR. ALPER replied that the royalty picture varies wildly in
different areas of that state, and Representative Josephson is
correct in that Alaska doesn't have a tremendous amount of
private land outside of the urban areas. The various blocks of
federal land have different revenue sharing formulas. For
example, on the National Petroleum Reserve-Alaska (NPR-A) the
state receives 50 percent of the federal government's royalty,
although that royalty is currently somewhat restricted in what
the money can be used for. The largest private land owners are
the Native corporations and the state doesn't receive royalty.
9:06:38 AM
MR. ALPER resumed his review of the credit refund limitations on
slide 49 and explained that the third restriction is the Alaska
hire provision. For example, if a company is eligible for $10
million in a refunded credit, the state looks to the company's
labor statistics for the prior calendar year and if they were 80
percent Alaska hire, only 80 percent of that credit would be
eligible for refund. The rest would not be lost, but would be
carried forward into the next year and usable against the next
year's taxes.
9:07:12 AM
REPRESENTATIVE JOHNSON opined that he had introduced a bill on
oil taxes wherein this was a key portion and he was told
repeatedly that it was unconstitutional. He further opined that
other members introduced a stand-alone bill that did the same
thing, and legal opinions were that it was unconstitutional. He
asked whether Mr. Alper had a legal opinion on this.
MR. ALPER responded that it is obviously a highly controversial
concept and it may not survive court challenge, and should it
survive through final legislation will almost certainly be
challenged. Governor Walker brought this idea forward as it is
important to convey the message that the state wants its
partners in the oil industry to hire as many Alaskans as
possible. In the event there is a constitutional hook, if it is
a more constitutional than some other Alaska hire requirements,
it's because no one is losing value. The value remains, a
company would just have to carry it forward into a future year
rather than be cashed out. Structurally, he explained, if the
attorneys leave "a tell" behind in the bill -- all of the other
restrictions on cash refunds are in Sec. 26, and this one was
carved out and placed separately in Sec. 27 with the
understanding that it was a little bit more challengeable.
REPRESENTATIVE JOHNSON offered that if the state is going to
fight a constitutional battle, local hire is the ground he wants
to be on, and he is not opposed to it.
MR. ALPER appreciated Representative Johnson's moral support and
said he, too, believes it is a fight worth fighting. If HB 247
progresses with this language in it, he said, it is important to
obtain written legal opinions on the record. Currently there
are verbal assurances from the attorneys that it is plausible.
9:09:57 AM
MR. ALPER returned to slide 49, explaining that the fourth
restriction on credit refunds is the sunset of the certificates
themselves. In the event anything rolls forward a full 10 years
the credits would start to expire and not be useable. He noted
that within most of [DOR's] modeling scenarios it did not have a
material impact and the credits started disappearing in some of
the very large fields and very low priced scenarios. The idea
is to not have these credits last forever and to make sure
people use them. In addition to the economics of new field
development, he noted, anecdotally there is a handful of older
credits on DOR's books that DOR can't seem to get anyone to
claim; but DOR can't make them disappear either, so DOR would to
find a way to erase them.
MR. ALPER stated that Sections 26-27 have an estimated fiscal
impact in the aggregate of approximately $150 million per year.
When looking at the suite of work ongoing today - how much money
is being spent and how much will be refunded - [DOR] thinks that
about $150 million less will be paid out. Those $150 million
will roll forward and will be used against future years' taxes
with the expectation, frankly, that there will be future years
taxes, that the price of oil will recover to the level where
companies have a tax liability and could use those carried
forward credits to offset their taxes. The numbers for future
years will depend on the actual project. He reiterated that the
fiscal note tends to decline in the out years simply because
DOR's forecasting of the amount of spending of companies isn't
that precise two, three, or four years down the road.
9:11:39 AM
REPRESENTATIVE JOHNSON referred to the statement that the fiscal
note declines over future years because DOR just can't predict.
He asked whether Mr. Alper was sure it's not declining because
"we think it's going to reduce production."
MR. ALPER replied that the fiscal note for HB 247, as far as
savings in the future, is really tied to the fiscal note for the
future credit spend. He said, "What we're told we're going to
be refunded based upon the knowledge that we have, which is
itself based on our estimate of company lease expenditures
that's built into our production forecast. Really, that's our
core mission." [The department's] production forecast data set
comes from the producers themselves, they have fairly frank
conversations every fall, they tell the state what they plan to
do, but they themselves don't know what they are doing more than
a couple of years out and everything gets a bit more vague
moving deeper into the six year fiscal note.
9:12:48 AM
MR. ALPER moved to slide 50, "Section 31: Gross Value can't go
below Zero." He reminded committee members that the gross value
and the tax calculation is the market value, the sales price of
the oil minus the cost of getting it there, it's the so-called
wellhead value. Historically, this has never been an issue but
the current market price is approximately $30 a barrel and could
possibly be going lower. Under what circumstances could the
state see transportation costs of more than $30 that would lead
to negative gross values at the point of production? He said
there are one or two properties where that could start to
approach that, if prices go lower than $20 a barrel more
properties could be affected.
MR. ALPER turned to slide 51, "Section 31: Gross Value can't go
below Zero - Jan. 2016 TAPS and feeder pipeline tariffs (these
are before adding the $3.37 marine transport costs)." He
explained that this information is for various properties on the
North Slope. The $6.13 number is just from the Trans-Alaska
Pipeline System (TAPS) - going from Pump Station 1 to Valdez.
Additionally, the oil must get to Pump Station 1. He used
Kuparuk Pipeline as the biggest example in that Kuparuk's feeder
pipeline is only $0.32 per barrel because there is a lot of oil
flowing from Kuparuk, plus it's a depreciated pipeline so the
cost of operating it is low enough that it only costs $0.32 a
barrel. The Endicott Pipeline coming from the Duck Island Unit
costs $2.22 simply because there is a lot less oil moving
through that supply pipeline. Before the committee now is an
unusual circumstance with Pt Thomson which is about to come
online, in that Pt. Thomson has built a very robust pipeline
designed to carry a larger amount of oil that might be produced
in a full field development circumstance related to the natural
gas pipeline. It as a new, very large pipeline that once it
begins operating will pump a relatively small volume of oil.
Pt. Thomson filed for an approximate $19 tariff to move its oil
from the Pt. Thomson production facility to the connection to
the existing infrastructure at Badami. From Badami it still has
to get to Pump Station 1 and then finally the TAPS pipeline,
leading to a total estimated tariff of $28.49 per barrel, should
it be in production right now.
9:15:09 AM
MR. ALPER drew attention to slide 52, "Section 31: Gross Value
can't go below Zero - Example of gross value potentially going
below zero." Focusing on Pt. Thomson, he said that if a person
presumes on top of that number the $3.37 average of the marine
transportation to get the oil from Valdez to the market, the
refinery or wherever the oil is being sold, it leads to
transportation costs of $31.86 against a potential West Coast
price of around $30 today. He explained that if the $1.86 loss
on just the transportation is multiplied by the estimated 10,000
barrel a day initial production, there would be a negative gross
value at the point of production of negative $5.9 million.
While not a massive amount of money by the economics of much of
the North Slope, he continued, it is still material and it would
typically be used to offset positive gross values from other
fields, resulting in the state losing taxation from the
companies who own that production at about 35 percent of the
difference, which would be a loss to the state of approximately
$2 million. Going back to the Alaska's Clear and Equitable
Share (ACES) bill, he said there is language inserted in the
tariff language that says "in the circumstance ... where the
actual tariff is not reasonable, we use a reasonable cost
calculation, that reasonable language is tied to arms-length
relationships and a few other factors." Colloquially, it is
being said that "to have a tariff that's more than the value of
the oil itself is not reasonable, that we want to make the
maximum tariff equal the value of the product itself so that the
gross value can't be reduced to less than zero."
9:16:49 AM
REPRESENTATIVE HAWKER asked how solid the number of $19.17 is
for the Pt. Thomson pipeline tariff.
MR. ALPER responded that it is a filed tariff that the state has
protested so it's in the process of appeals and he believes it
is before the Regulatory Commission of Alaska (RCA) right now.
However, he noted, this is not his area of specific expertise.
REPRESENTATIVE HAWKER advised there are protests on that from
both sides and said the tariff on a cash basis is probably a lot
more than that with the very limited production underway and
foreseen there. He asked who mandated that the state establish
that limited production of 10,000 barrels of condensate.
MR. ALPER replied that the 2012 Pt. Thomson settlement agreement
requires that this initial production and reinjection be created
in part as a test and in part to get to production, and also to
provide the infrastructure in expectation of a full field
development. He offered his belief that there is a decision
point in 2019 regarding Phase Two and whether to expand full
cycling, whether to commit to a major gas sale, or whether to
ship more gas over to Prudhoe Bay for reinjection.
9:18:07 AM
REPRESENTATIVE HAWKER asked whether as part of retaining the Pt.
Thomson lease the state has demanded and insisted that this
production be created at a loss knowing the billions of dollars
required to get a minuscule amount of oil into the pipeline, and
now the state is going to deny the company, that the state
demanded incur this loss, the benefit of that loss as part of
the company's overall portfolio. He expressed his concern with
the state taking that heavy handed approach with anyone. "Quite
frankly," he added, "I don't like ExxonMobil any better than you
do, but we have to be fair."
MR. ALPER answered he does not dislike ExxonMobil, it is one of
the world's great companies and has done a lot of impressive
things over the last 100-plus years. He said it's not about
ExxonMobil or about any specific company, there are multiple
partners there. "I'm not quite sure 'demanded' is the exactly
correct word," he said. "There was a settlement, a legal
agreement, to do that; there was conditional on retaining the
leases, the previous versions of the Alaska state government
fought to take those leases back beginning and around 2005." He
agreed that [ExxonMobil] would not be able to earn the full
benefit of those losses should they happen at a loss, and once
again the state is at a circumstance that was never envisioned.
He pointed out that there are a lot of losses out there that
were not contemplated, and minimum tax calculations that were
not contemplated. The state is in new territory with all of the
existing statutes that were passed and is trying to determine
how to adapt the statutes to the current reality.
9:19:43 AM
REPRESENTATIVE HAWKER said that's his point exactly. He added:
We the state have got to stop changing the playing
field on everybody when we're asking them to make long
lead decisions and every time something comes up that
you don't like, we end up sitting here completely ...
very much starting over and redefining things so that
the state gets what it wants, but we are creating
absolutely no certainty, no ability to continue to
attract people to this state. While we may have ...
issues that we can tighten up here, but again, my
biggest concern and this is a classic example, we
incent ... we tell someone to do something in a
settlement and then we literally want to pull the rug
out from under them when we discover that ... the
world has changed around us and now we don't have
what, as you said yourself, the whole motivation
behind this, the state doesn't have enough money from
our oil fields to continue to operate at the levels
we're looking. Frankly, I'd ask you guys at the state
to start figuring out some ways we can reduce the size
of government, rather than trying to chase industry
out of the state.
9:20:50 AM
REPRESENTATIVE JOSEPHSON pointed to the three lines at the
bottom of slide 52, which read:
This negative GVPP could be used to offset positive
values from elsewhere on the North Slope, resulting in
a tax reduction of 35% of the difference (about $2
million)
REPRESENTATIVE JOSEPHSON commented that ConocoPhillips Alaska,
has an interest in Kuparuk and Greater Moose's Tooth. For
purposes of the company's final tax payment, he asked whether
the two are aggregated so that one can be offset by the other.
MR. ALPER responded yes, for the purposes of taxation the entire
North Slope is called a segment, all of the company's profits or
production tax value are combined and aggregated. The specific
change here is that it's a multi-step calculation as follows:
"First you get to this thing called gross value at the point of
production, and then you start subtracting your lease
expenditures, your operating and capital costs." The change in
Section 31 would make the gross value calculation somewhat
higher by not allowing, in this case, the $5 million deduction
for the loss from Pt. Thomson, and therefore the net value would
be, likewise, $5.9 million higher. The end result is yes, it's
all a commingled tax for each producer across the North Slope.
9:22:17 AM
MR. ALPER moved to slide 53, "Section 37: Municipal Utility
Limitation," and said it is a provision of law that [DOR] is
fairly certain was also unforeseen and technical in nature. He
said there is language in the section amended by Section 37 that
says "a municipal utility that is a producer gets to the benefit
of their credits ... to the same extent as any other producer."
MR. ALPER advised that the somewhat vague language says that the
municipal utility is also eligible to receive credits.
Typically if a municipal utility owns a gas production, it is
for the utility's own purposes - it has turbines somewhere and
wants to burn that gas and generate power for its citizens. In
some cases, if the municipal utility happens in a given day or
given month to produce more gas than it needs to burn in its own
turbine, the municipal utility is as free as anyone else to sell
that gas to a third party that might need more gas.
9:23:23 AM
REPRESENTATIVE OLSON said it appears that Pt. Thomson was
singled out and asked why.
MR. ALPER responded that Pt. Thomson was not singled out. The
specific economics of Pt. Thomson made this issue rise to
[DOR's] attention, but the impact would affect possibly several
other developments, especially the more remote developments that
might have high tariffs associated with them. There are a few
pending but currently none of the state's fields have tariffs
that would approach $30, let's say, except for Pt. Thomson; so
it was used for illustrative purposes and was by no means
singling Pt. Thomson out.
REPRESENTATIVE OLSON asked Mr. Alper to name the other fields.
MR. ALPER said he has no idea of the economics of ConocoPhillips
Alaska's "string of pearls" as they get deeper into NPR-A, but
in moving to Moose's Tooth 1, 2, and all the way out to Bear
Tooth, he guesses that by the time they get to the last string
of that pearl the tariffs are going to get fairly high to bring
that oil all the way back to Pump Station 1. Caelus Energy
Alaska is investing in its Smith Bay project much further out
along the coast of NPR-A, and he is certain that should Caelus
find meaningful amounts of oil and try to ship it back towards
Prudhoe Bay and TAPS, it's going to be a very expensive project
to get that pipeline built. Offshore projects certainly will be
expensive. This is something the state would need to look at as
new projects come on, obviously. But the corollary for these
remote projects and their tariffs is that quite probably none of
them are going to happen if the price of oil stays at $30-$40 a
barrel anyway, so it's an academic conversation.
9:25:10 AM
REPRESENTATIVE OLSON referred to the first two and commented
that conceivably they will be much higher than Pt. Thomson.
MR. ALPER replied that he doesn't know, they will be built for
their expected production. There is an unusual circumstance
that Representative Hawker spoke correctly to, that the Pt.
Thomson pipeline was overbuilt, it was built for future
production that might not come for a substantial number of
years, or whatever feeder lines they build in NPR-A will be
sized for expected levels in the near term. He reiterated that
everyone gets to deduct all of their tariffs so long as it
doesn't bring them below zero, no one is going to make any
investment if they expect the value to be zero. As [DOR's]
modeling will show, nothing, including the status quo scenarios,
work at $40 oil, which is the current reality.
9:26:14 AM
REPRESENTATIVE OLSON asked whether that would be 42 inch or 48
inch pipe.
MR. ALPER responded he is happy to say that it is not his job.
MR. ALPER returned to slide 53, and said that these are, for the
most part, small dollar items, but they do add up. He presented
a model of a basic scenario as follows:
Let's say a company produces 20 million cubic feet a
day ... and 18 of it goes into their own turbines.
Those 18 million cubic feet a day are not taxable,
that is an internal transfer that is not a sale; the
Tax Division of the Department of Revenue does not
interject itself into that part of the equation.
However, if they sell 2 of them to somebody else, to
someone else's utility, that 2 of them is taxable
income and they are paying the production tax like any
other producer on that 2 million cubic feet per day.
So, just working that through the equation, 2 million
cubic feet a day, $8 just to pick a price, that's $5.8
million a year in revenue subject to taxation. Now,
so, here's the interesting part, let's say their lease
expenditures are $3 per thousand cubic feet. The way
the current law is structured, they get to take all of
their lease expenditures on the whole 20 million
they've produced and offset them against ... only the
2 that they sold. So that leads to, if you work your
way down the left hand column, $21.9 million dollars'
worth of lease expenditures against $5.8 million in
sales - they show on paper a $16 million dollar
operating loss and would be eligible, using the Cook
Inlet figure, the 25 percent net operating loss credit
in Cook Inlet, we would be paying this company a $4
million dollar credit in this circumstance because
they sold a small amount of their gas. Usually this
is a somewhat unreasonable and unintended consequence
of a literal interpretation of statute. The change in
Section 37 is brief, but it says, colloquially, that
we are pro-rating their expenses to the share of the
gas that was actually sold. So, if they sell 10
percent of the gas they get to claim 10 percent of the
lease expenditures, if they sell 99 percent of the gas
they get to claim 99 percent of the lease
expenditures. And in the example before us here where
10 percent of their gas was sold and they had $21
million in lease expenditures, 10 percent of that is
$2.1 million, that gets reduced from their revenue and
now instead of getting a big operating loss they have
a small profit that would be subject to the production
tax, although the numbers are small enough that in the
current circumstance, small producer credits and the
like, they would not be likely to be paying any actual
taxes and that's fine at this scale. The issue is
that we the state don't feel that we should be paying
a large operating loss credit to a company simply
because they're selling a small amount of their gas
... to a third party.
9:29:09 AM
REPRESENTATIVE JOHNSON asked whether this is limited to
municipalities or would include a co-op such as Chugach Electric
Association. He further asked whether it means that because a
municipality sells gas to Chugach Electric it is going to get
this tax credit.
MR. ALPER answered it doesn't matter who the municipality sells
it to. The idea is that by selling it, a transaction with money
is involved, [that is a taxable] event. Regarding whether this
would apply if, for example, Chugach Electric had its own gas
field, production, and turbines, he said his understanding is
that yes, a co-op would be treated like a municipality in this
change. The co-op would be eligible for the oversize credits.
To his knowledge, Chugach Electric does not currently own
production, but he knows it is buying some and so this is going
to be an issue. If Chugach Electric owns more production than
it needs and sells some of it, [the administration] would like
to prevent the circumstance where the co-op is receiving
disproportionate credits.
9:30:24 AM
REPRESENTATIVE JOHNSON asked whether, if the state does this,
that would make that acquisition impractical, and further asked
whether it is marginal enough that this is the difference
between Chugach Electric Association becoming partners which, in
theory, would lower the cost for all consumers. He said he
wonders if by doing this, it would take that off the table and
possibly cost consumers in his hometown more money. He said
that this is something to look into.
MR. ALPER responded that he cannot answer regarding the
economics of a project. He said it is worth asking Chugach
Electric and the other potentially impacted players. The
credits are out of scale with the sales because of the nature of
the conversation. These are issues that have been appealed and
have been adjudicated. "We're dealing with literal
interpretation of law issues," he said. "We certainly don't
want to harm the economics of your constituents to get gas, this
one was perceived as somewhat excessive and ... I'd like to hear
from the individual players how this might impact them."
9:31:52 AM
REPRESENTATIVE TARR surmised that this particular instance has
not occurred to date, but that Mr. Alper wants to prevent this
from happening.
MR. ALPER answered he cannot actually say that because he cannot
talk about specific credits earned by specific companies.
9:32:16 AM
MR. ALPER resumed his presentation, advising that slides 55-58
were put together by the Department of Natural Resources (DNR).
The issue was raised about Cook Inlet gas supply. Because HB
247 looks to sunset or repeal some of the capstone Cook Inlet
credits and reduce the state's support of ongoing development
from roughly 50-60 percent to 25 percent, the question arose as
whether that is going to affect gas supply. That is one of the
more important questions before the committee. He continued:
So the first question we asked is, How long can the
known supplies meet the regional demand? And as ...
DNR are the resource people, they understand rocks,
they understand pipes, they understand things like
that much better than any of us at [DOR] do. We
mostly understand dollars. And so they said ... it
depends on how fast the known supply can remain
available and by extension how much new supply comes
on. So, they looked at ... rapid response, that's
them saying we gave them a couple days to please
answer these questions for us. We have the known
ready to pump reserves of a bit less than 1.2 trillion
cubic feet ... that's what they call 2P (proven and
probable), all you need to do is drill the well, you
know it's there, the infrastructure is in place, all
of that. And then there are two new field
developments, and the two new field developments ...
their names you're all familiar with - the Cosmo
development from BlueCrest and Furie's at least
[indisc.-technical difficulties] Kitchen Lights Unit
in the deep water in the middle of the inlet.
Building those ... in round numbers without getting
into anyone's confidential data they can comfortably
say we have about 1.6 billion cubic feet available,
numbers that can go up dramatically depending on full
delineation of those fields and how much development
they do, and future work that would have to.... But
with known information we could say that.
9:34:27 AM
MR. ALPER continued his discussion of slides 55-58:
And then they're looking at three different demand
cases. Now a good number to have in our mind is, What
is the actual utility demand in Cook Inlet in an
average year? That number is about 80 billion cubic
feet ... per year or a little over 200 million cubic
feet per day. That's the utility and field use and so
on that then ... goes into the existing facilities.
The high end of that would be 140 billion cubic feet,
that would be what we have, and plus the limited
amount of export from the Conoco export facility, plus
the Donlin Gold which would require a dedicated
pipeline from Cook Inlet heading out to Southwest
Alaska where that gold mine is, and then a two train
full development of the Agrium plant restart. That at
the high end, at least with the medium terms of about
140 billion cubic feet per year. And then you say,
well if we know what we have and we know what we might
need, how many years do we have and recreate some
lifespan scenarios.
9:35:25 AM
So, Supply Case 1 ... 1.2 trillion or 1,100 billion
cubic feet in the legacy field from the Division of
Oil and Gas, 1.6 with the additional ballpark
estimates for Kitchen Lights and Cosmopolitan.
Demand Case 2 is sort of the middle. That was the
addition of Donlin and the one-train Agrium. The
second-train Agrium brought it from 116 to 140 billion
cubic feet per year. And just to put the numbers in
perspective too, the flow from the AK LNG Project is a
bit less than 3 billion cubic feet per day. So even
at the full demand level, we're talking less than 2
months production from the North Slope should that ...
proceed to construction and development.
So, how much gas do we have behind pipe? The current
circumstance, we have 15 years of life span. ... And
that's 15 years with high deliverability. That's an
important distinction from where we were five or eight
years ago when there wasn't the storage capacity, the
ability to put gas in in the summer when there is less
demand, pull it out in the winter when there is high
demand. So they're telling us that we have about 15
years' worth of current demand. If the additional
production continues on and comes on line that is
under development, or about to be under development,
hopefully in Kitchen Lights and Cosmo, that increases
to 15 years. Knowing that, what happens if the demand
increases - if Agrium restarts with a single train,
Donlin Creek moves forward with what they think is 12
billion cubic feet per year - that reduces what we
have to 14 years. The full development of Agrium and
Donlin brings it down to 11 years. If those things
are happening, we're all confident, DNR would agree I
hope, that that would encourage substantial additional
development of those and additional fields to make
sure that the supply stays on line. But even with
full development, which obviously isn't happening
overnight, they're looking at 11 years of supply.
9:37:24 AM
REPRESENTATIVE HAWKER requested Mr. Alper to explain the
disclosure in the box under the title of Slide 57, which read:
These supply "lifespan" estimates require significant
continued investment to ensure reserves and discovered
resources will be produced in time to meet demand.
MR ALPER explained that even when a producer has a gas or oil
field, the company must continue drilling wells due to the
nature of the geology. For example, when drinking a Slurpee and
begin sucking air it is necessary to pick up the straw and move
it over one-half inch to get more Slurpee. He related that the
expectation is that ongoing investment happens, but that is
among the least risky investment in the industry because there
is a known proven reserve with a market, and the cost is known,
and it is known the gas or oil is down there because it is in
between two producing wells. Continuing ongoing investment will
absolutely be required because if everyone stopped drilling the
decline curves are inherently more rapid.
9:38:25 AM
REPRESENTATIVE HAWKER said:
You keep saying that it's a very attractive basin,
don't worry your pretty little head Mike. Well, I
worry about my community. If it's such a great
opportunity why ... three years ago where we were
having blackout drills in my community, literally,
because we were trying to train our public with what
to do because they had no heat or lights on the
coldest days of winter. If it's such a great
attractive prospect, why were we doing that?
MR. ALPER stressed that he was by no means saying that
Representative Hawker should not worry about his community as it
is his job to worry about his community. Representative Hawker
has done many great things for the energy security in Cook Inlet
through the credits he helped work through the system several
years ago. Probably the most important one was the storage
credit. "That storage credit has created essential seasonal
deliverability security that didn't used to exist," he said,
"especially in the absence of the flexible users like the export
facility, say, that isn't operating at full capacity." He
offered his understanding that many of the issues behind that
blackout drill were because of deliverability more than supply.
Also, he continued, additional supplies have been discovered
that are more easily developable and there is a very high price.
There were regulatory issues in the years leading up to those
blackout drills where gas supply contracts were being denied.
He said he doesn't want to delve into the history and politics
behind those....
REPRESENTATIVE HAWKER interjected that those were fixed in the
Cook Inlet Recovery Act.
MR. ALPER agreed and acknowledged that there was language in
that bill discussing the RCA having to show its work at the very
least and explain its reasons. Suddenly now, gas supply
contracts are coming at higher levels, higher dollar values,
that support drilling. He said he has heard from others that
Cook Inlet has among the most generous fiscal regimes and one of
the highest gas prices in the world. That doesn't say it's
extremely attractive, just that maybe it doesn't quite need the
same level of ongoing cash support that it currently enjoys,
which is the state paying 50-60 percent of a company's
development costs.
9:40:54 AM
REPRESENTATIVE HAWKER noted that Mr. Alper acknowledged that the
economic situation created in Cook Inlet attracted sufficient
investment to increase production. He posed the question of
significantly taking away, as HB 247 proposes, some of the
incentives in the basin and how it will affect continued
investment - how much reduction in investment Cook Inlet can
expect - and how that will affect these lifespan calculations.
MR. ALPER responded that the type of decision making
contemplated in the question relates to new supplies in addition
to the supplies stated in this slide. He explained that the
supplies in this slide are, for the most part, discovered and
should the price support it, "we believe will continue." If the
discussion is regarding the next tranche of supply beyond this,
"we will come to the committee with field analysis, with
economics." It's tricky to look at field economics in Cook
Inlet because a tax regime kicks in in 2022 that is very high
and unstable. It has been discussed that a new Cook Inlet tax
system is needed. He said he cannot say with certainty whether
a new project will or won't happen, with or without the tax
change envisioned in this bill.
REPRESENTATIVE HAWKER stated that Mr. Alper just said that it's
going to be all these new discoveries that are going to be the
things that are affected by continued investments. He asked
whether it doesn't also take continued investment to maintain
the level of production from the known and proven reserves.
MR. ALPER replied that it takes continued investment but that's
a much less riskier investment in a proven developed field where
it is known what is there. If there is a market and a sales
price, he explained, that is a far less risky investment than
going out and looking for new gas.
9:43:02 AM
REPRESENTATIVE HAWKER recited the adage, "The best place to find
oil is in an oil field." Yet, he argued, there is the law of
diminishing returns, too, where it becomes increasingly
expensive to extract those final resources, the more-difficult-
to-achieve resources in the fields. He reiterated that he would
like Mr. Alper to be able to stand up in front of his entire
community and tell them that his proposal is not going to place
them at risk of having insufficient energy to meet their needs
in the foreseeable future.
MR. ALPER responded that a hearing or two ago Commissioner
Hoffbeck said something along the lines of, "Is it time to
declare at least partial victory?" Should the state find itself
in a circumstance where supplies are becoming risky to get in
Cook Inlet, he said:
We believe we have sufficient lead time to reinstitute
certain benefits, certain incentives to go and find
more gas. Right now there is enough gas, we believe,
that given the state's fiscal situation, we cannot
afford to continue to support ongoing development to
the rate that we have been. We want to continue to,
to the extent that we can, to the maximum benefit of
the community, within what is reasonable given the
state's fiscal limitations.
REPRESENTATIVE HAWKER stated that what Mr. Alper just said
scares him and makes him pity the people in his community.
9:44:25 AM
MR. ALPER referred to slide 58, "Cook Inlet Undiscovered
Resources (USGS resource assessment, 2011)." He explained that
the map on this slide shows the extent of the Cook Inlet basin,
which has an estimated nearly 600 million barrels of oil. The
green line represents roughly where the oil is believed to be.
The conventional gas is almost 14 trillion cubic feet and the
unconventional gas is another 5.3 trillion cubic feet on top of
that. In the context of the current annual use consumption in
Cook Inlet, as currently fully developed with both heat and
electric utilities almost entirely dependent upon gas, a
trillion cubic feet will last about 12 years. If there are in
fact 13 trillion feet of undiscovered technically recoverable
gas, there is approximately 150 years' worth of gas in Cook
Inlet currently, and "obviously that is much more speculative
and will require far more additional work to bring any of that
sort of gas to market, but you are living on top of a robust gas
basin, or at least so the professionals in that field believe."
9:46:10 AM
REPRESENTATIVE JOHNSON referred back to his previous question
regarding the utilities and said:
I want to throw Fairbanks in the mix. What does it do
to Fairbanks gas deliverability because they are
involved in the trucking now and ... there's
challenged projects both ways north or south on that
one. And right now I think the plan is to truck gas
to the north. What does that do to their
deliverability if these credits.... So maybe you
can't answer these ... we're outside the realm of some
of the state, but we're very heavily invested in that
Fairbanks gas utility as a state. So ... I just want
to focus on some of things that unintended
consequences ... I want to make sure that we're not
burying Fairbanks or Anchorage or anyone in this, and
all of a sudden we've got great ideas and no gas. So,
I want to make sure that we're dealing with those kind
of aspects. ... I don't know where they fit in
because I don't know if they're even a utility,
they're not regulated, they may have to pay the full
taxes. I mean there's a lot of moving pieces in that.
They could end up a lot of difference ways. ... I
certainly understand that if you want to beg this
question for a later time, but I want to at least put
it on the table.
9:47:34 AM
MR. ALPER offered to take a first crack at understanding the
transactions embedded in the aforementioned scenario by
Representative Johnson. He said that the Fairbanks utility is
not a producer, it's a consumer, and will be buying gas from
someone. He said he thinks the issue being raised by
Representative Johnson is more an issue of gross values being
less than zero; that whoever is selling that gas and the market
price is low and the cost of trucking it up there is high, the
circumstances could be that the gross value is less than zero.
Although, he advised, he is not certain how trucking fits into
the calculation of allowable transportation.
REPRESENTATIVE JOHNSON advised that he does not need an answer
now, but wants it on the table because it is an issue that the
committee has spent a lot of time on, and he would hate to see
all of those investments go to the wayside for lack of at least
talking about them. The committee has not talked about some
things that have come up - low oil prices, high oil prices - and
he would like to get everything on the table this time.
MR. ALPER agreed and said:
We don't want to keep doing this. We want to envision
all of the possible circumstances. ... I like to
think we're spiraling in towards the center of
something rather than zigging and zagging back and
forth. But I don't have a nuanced answer to give
Representative Johnson's question. It is important to
contemplate how both the Section 31 and Section 37
changes might impact the Fairbanks utility, and we
will look into that, absolutely.
9:49:45 AM
The committee took an at-ease from 9:49 to 9:53 a.m. and another
from 9:53 to 9:54 a.m.
9:54:19 AM
CO-CHAIR NAGEAK advised that the next meetings on HB 247 will be
at 1:00 p.m. today, and 10:00 [a.m.] tomorrow, 2/26/16.
[HB 247 was held over.]
| Document Name | Date/Time | Subjects |
|---|---|---|
| HSE RES - 2.24.16 HB 247 2nd Presentation- fiscal details part 1a.pdf |
HRES 2/25/2016 8:30:00 AM HRES 3/7/2016 6:00:00 PM HRES 3/8/2016 1:00:00 PM |
HB 247 |