Legislature(2013 - 2014)BARNES 124
03/22/2013 01:00 PM House RESOURCES
| Audio | Topic |
|---|---|
| Start | |
| SB21 | |
| HB158 | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| + | SB 21 | TELECONFERENCED | |
| + | TELECONFERENCED | ||
| += | HB 158 | TELECONFERENCED | |
SB 21-OIL AND GAS PRODUCTION TAX
1:06:19 PM
CO-CHAIR FEIGE announced that the first order of business is CS
FOR SENATE BILL NO. 21(FIN) am(efd fld), "An Act relating to the
interest rate applicable to certain amounts due for fees, taxes,
and payments made and property delivered to the Department of
Revenue; providing a tax credit against the corporation income
tax for qualified oil and gas service industry expenditures;
relating to the oil and gas production tax rate; relating to gas
used in the state; relating to monthly installment payments of
the oil and gas production tax; relating to oil and gas
production tax credits for certain losses and expenditures;
relating to oil and gas production tax credit certificates;
relating to nontransferable tax credits based on production;
relating to the oil and gas tax credit fund; relating to annual
statements by producers and explorers; establishing the Oil and
Gas Competitiveness Review Board; and making conforming
amendments."
1:07:14 PM
MICHAEL PAWLOWSKI, Oil & Gas Development Project Manager, Office
of the Commissioner, Department of Revenue (DOR), first
highlighted the main provisions of CSSB 21(FIN) am(efd fld) as
compared to those previously considered by the committee under
the companion bill, HB 72 [slide 2]. He said the other body
added a provision adjusting the interest rate for delinquent tax
payments and refunds of tax overpayments, decreasing the rate to
3 percent above the annual rate charged by the 12th Federal
Reserve District. Another provision was added establishing a
corporate income tax credit for qualified oil and gas service
industry expenditures. The production tax rate was adjusted in
the other body to a 35 percent flat tax rate and the repeal of
progressivity was retained. Tax credits were adjusted to
eliminate the current 20 percent capital expenditure tax credit
for the North Slope after December 31, 2013, and the loss carry
forward credit was increased to 35 percent for the North Slope
after December 31, 2013. A $5 per barrel tax credit was added
by the other body as a balance mechanism to the 35 percent flat
tax. The gross revenue exclusion (GRE) was refined and
expanded, establishing the same 20 percent exclusion from the
gross value at the point of production for oil and gas produced
from: 1) new units; 2) new participating areas in existing
units; and 3) metered wells subject to demonstration by the
producer of certain conditions to the Department of Natural
Resources (DNR) and Department of Revenue (DOR). The other body
added a provision establishing an Oil and Gas Competitiveness
Review Board. As in the original bill, the committee substitute
(CS) holds harmless the provisions south of 68 degrees [North
latitude], which is the dividing line between the North Slope
basin and the areas referred to as Middle Earth and Cook Inlet.
1:10:45 PM
MR. PAWLOWSKI next provided details of the main provisions in
the bill, starting with the interest rate for delinquent taxes
[slide 3] in Section 4, page 2, lines 16-27, of the bill. This
issue relates to the tension between the time DOR has to conduct
audits and the interest rate that is charged by the state for
delinquent taxes, as well as charged to the state when a
producer overpays its taxes. Under existing language, the
interest rate is 5 percentage points above the interest rate
charged to member banks by the 12th Federal Reserve District or
an annual rate of 11 percent, whichever is greatest. It is
known that interest rates change over time as the Federal
Reserve policies are set as the markets move. The interest rate
of 11 percent or the federal rate was reasonable at the time it
was established, but since then the divergence between the
actual rate of interest and the 11 percent has widened. The
interest rate set by the other body is more similar to what goes
on in the federal Internal Revenue Service (IRS) provisions,
which is 3 percent above the greater amount of the Federal
Reserve district. The provision eliminates that tension between
a fixed rate and a rate that floats with the actual market rate
of interest because there could be a situation where under the
lesser of, interest rates would rise above that 11 percent rate
and the mechanism would have the same problem it has currently,
which is that the actual rates of the market are lower and the
11 percent rate is higher. The provision applies in both
directions - when someone overpays the state so the state must
provide a refund or when someone underpays the state so must pay
the state the underpayment.
1:13:11 PM
MR. PAWLOWSKI, responding to Co-Chair Feige, said the original
statute was established in 1991.
1:13:30 PM
MR. PAWLOWSKI, responding to Representative Tuck, confirmed that
under CSSB 21(FIN) am(efd fld) the applied interest rate would
be the same whether it is the state owing a taxpayer or the
taxpayer owing the state. In further response, Mr. Pawlowski
confirmed this is also the case under current law.
REPRESENTATIVE TUCK inquired whether lowering the interest rate
would incentivize taxpayers to be loose in calculating their
taxes, given the state has not audited the industry.
MR. PAWLOWSKI replied he would not describe it as loose, in that
it goes both ways and the rules often change. For example,
transportation regulations were recently changed by the Federal
Energy Regulatory Commission (FERC) that led to amendments to
tax returns. The federal government can make changes to tariffs
that have changes on taxes that were paid over time. The tax
rate under Alaska's complex net system varies monthly and an
outside action by a federal agency could have an impact on tax
payments going back years. Therefore, both the state and the
industry are at risk in that type of thing.
1:15:05 PM
BRUCE TANGEMAN, Deputy Commissioner, Office of the Commissioner,
Department of Revenue (DOR), addressing Representative Tuck's
statement about audits, stressed there are many misconceptions
regarding audits. He explained DOR is currently auditing 2007,
in which half the year was under the production profits tax
(PPT) and the other half was under Alaska's Clear and Equitable
Share (ACES). The department is well within the statutory
guidelines of six years; once through 2007 the department will
accelerate through the ACES years because it will be able
combine years for certain companies. The general misconception
being heard is that since DOR is auditing 2007, it has no clue
what happened during 2008-2012, which is not true. Corporations
pay taxes on a monthly basis under ACES, so DOR receives revenue
on a monthly basis and receives a vast amount of information on
a monthly basis. Every March 31, called the thirteenth month, a
true-up is conducted of the previous 12 months of information
that DOR has already received. It is in the taxpayer's best
interest to be as accurate as possible and it is in DOR's best
interest to review those monthly payments to make sure they are
as accurate as possible. On that thirteenth month true-up, DOR
does an analysis and then it goes into the queue for the audit.
1:17:10 PM
CO-CHAIR FEIGE asked whether DOR has noticed over the years a
systematic underpayment of taxes.
MR. TANGEMAN replied they seem to be fairly accurate and go both
ways with some overpayments and some underpayments, which is why
it is a two-way street for the interest rate provision.
MR. PAWLOWSKI interjected that the information can be seen by
legislators who are willing to sign a confidentiality agreement.
The audits are taxpayer-specific information along the same
lines as an individual's IRS personal tax information.
1:18:22 PM
REPRESENTATIVE TUCK said his concern is not so much the
information as it is ensuring that the taxes are done correctly.
He inquired how often there are overpayments to the state versus
underpayments and is DOR able to do that month by month.
MR. TANGEMAN responded the monthly payments are an estimated
payment using the taxpayer's estimated capital and operating
expenditures; so there will be pluses and minuses each month,
but they will not be large swings. It is the thirteenth month
in March that trues up those twelve months and brings in the
side boards that much tighter, and then it gets in the queue for
the audit.
MR. PAWLOWSKI added that in 2010, Senate Bill 309 made an
adjustment that these interest rates could be waived due to a
retroactive change in regulation. He encouraged members to be
very cautious about grabbing specific instances of overpayment
or underpayment because over time the rules have been changed
both prospectively and retroactively. When the department
retroactively changes a regulation or a federal decision is made
or the law is changed retroactively, it can result in
overpayment or underpayment. This interest rate is very
important in the relationship that happens when the rules change
on taxes that were already filed.
MR. TANGEMAN concurred there has been a number of changes
starting with PPT, then ACES, and through today. When a change
to regulations or statute is made and is retroactive and affects
a previous tax filing, both the taxpayer and DOR have the right
to re-open that if a change needs to be made. For example, for
2007 DOR received re-openers through 2010. The entire return is
not re-opened; the taxpayer is able to re-open the specific part
of that return that was affected and the clock starts ticking
again on that six-year window.
1:21:04 PM
CO-CHAIR SADDLER asked what the interest rate is on delinquent
tax payments in other jurisdictions.
MR. PAWLOWSKI answered the interest rate in CSSB 21(FIN) am(efd
fld) of 3 percent above the 12th Federal Reserve District rate
was modeled after a portion of the IRS rates. He offered to
research the rates of other jurisdictions.
CO-CHAIR SADDLER inquired whether that is what is normally
called the discount rate or overnight rate.
MR. PAWLOWSKI replied that is beyond his level of understanding,
but said this was an amendment entered by the other body.
MR. TANGEMAN offered to provide the committee with the specific
IRS language that will put it into context.
1:22:04 PM
REPRESENTATIVE TARR said it sounds like Mr. Tangeman is
suggesting these audits can be accomplished in a timely fashion
and that DOR is looking at this information regularly. However,
she continued, members still do not have that 2007 information,
so somewhere in that system it is perhaps not as easily
accomplished as is being suggested. She offered her belief that
the concern is not about retroactive adjustments due to changes,
but rather that members want to look at the overall picture of
whether the credits under ACES are actually working to
incentivize investments that will lead to new production.
Without that audit information, members do not have the full
picture of what is happening. Members want to know if there is
truth in reporting, which is why that audit information is
needed. She requested Mr. Tangeman to speak to this.
MR. TANGEMAN clarified re-openers are allowed if changes are
made to state or federal statutes. It is a misconception that
DOR does not know what happened in 2007 because an audit has not
been done. He said he strongly disagrees with that because DOR
does know what was provided on a monthly basis and then trued up
on March 31, 2008. The information DOR has provided and has
based decisions on takes into account actual information. The
state is in a much stronger position now because tax decisions
can be based on looking back at actual information and how the
state and industry has reacted under the net tax system of ACES.
In 2007 the state was not in that position. Last year DOR
presented a five-year look back specifically on the capital
credit; there are staff within the tax division that work solely
on tax credits. He said he will provide Representative Tarr
with a copy of the five-year look back on those tax credits. It
is very telling, he continued, because DOR was able to break it
down into five categories of where those credits were being
utilized in the state.
1:24:48 PM
MR. PAWLOWSKI resumed his presentation, noting the qualified oil
and gas industry service expenditure tax credit [slide 4] is in
Section 7, page 3, beginning on line 14 of the bill. He said
this provision recognizes that a healthy oil and gas service
industry is critical to having a healthy oil industry. Certain
work, such as the pads and drilling, can be done only in the
field in Alaska. However, work that supports the oil industry
does not necessarily have to be done in Alaska. This provision
attempts to create an additional incentive for encouraging
support work, such as modification and manufacturing, to happen
in Alaska. This tax credit is limited to 10 percent of the
qualified service industry expenditures or $10 million,
whichever is least. To qualify for this nontransferable credit
a company must be a taxpayer and must apply the credit against
its corporate income tax liability. The nexus to the oil
industry is that it has to be the in-state manufacture or
modification of tangible personal property that has a useful
life of three years or more that is used in the exploration,
development, or production of oil and gas. This would include
modules, additional work on infrastructure, and such things that
are actually used in the oil industry. This benefit goes
directly to those companies that are actually providing the
modified or manufacturing materials to the industry, not to the
oil and gas industry itself. Drawing attention to page 3, lines
30-31, he pointed out that these expenditures cannot then be
taken as a deduction, or as a credit and a deduction under
another provision in this title. An oil producer that has a
fabrication shop would therefore be unable to take expenditures
that qualify for this credit as a write-off against its
production tax.
1:28:05 PM
CO-CHAIR SADDLER asked for examples of the kind of process, or
product, or service most likely to enjoy this credit.
MR. PAWLOWSKI related that examples heard in testimony included
the hot oil units being built in Anchorage and modules
fabricated on the Kenai Peninsula. Modules could be purchased
and shipped to Alaska; or, they could be built in Alaska
employing people in the state, which is what this credit is
intended to incentivize. He said the limitation on the credit
that a person must be a taxpayer to receive the credit could
provide some incentive for companies to actually become
taxpayers under Alaska's corporate income tax code.
1:29:00 PM
REPRESENTATIVE TUCK asked whether the producer having a module
built would be able to write off what it pays to build or modify
that module, or would the tax credit go to the company that has
the contract to do the module.
MR. PAWLOWSKI answered the company that is actually doing the
manufacture or modification is the one that files for the tax
credit.
REPRESENTATIVE TUCK posed a scenario in which a module-building
company in Louisiana puts in a lower bid than a module-building
company in Alaska. He inquired what the incentive is for the
producer to pick the Alaska company since the producer would not
get a tax credit from picking the Alaskan manufacturer.
MR. PAWLOWSKI replied the company doing the contract does not
get the benefit. The company actually doing the work gets the
tax benefit, which allows that company to compete better on that
contract and that bid because it can put this tax credit into
its analysis of what it is doing as a company to compete better.
Representative Tuck's concern is shared by the other body and
the administration. A module, or work like that, is not
necessarily something that has to be done in Alaska, but
providing an incentive for that activity to happen in Alaska and
to make Alaska's businesses more competitive was seen as a
reasonable provision to support the overall effort.
1:30:49 PM
REPRESENTATIVE TARR observed the fiscal note states that there
is "no data with which to quantify the revenue impact of this
provision, although it is possible that the impact may be as
high as a negative $25 million per year" and "the revenue impact
of this provision is indeterminate". She asked what information
the committee should go on to determine the kind of exposure
this particular provision would give the state, particularly
given that it cannot go below zero which would be further
committing, which, technically, the state cannot do.
MR. PAWLOWSKI responded that in developing the fiscal note the
department looks at the total number of taxpayers that may be
eligible for this type of credit, and the level of their income
tax returns, in estimating the impact. He said it is correct
that the corporate income tax credit cannot be used to reduce a
corporate income taxpayer's liability below zero.
1:31:58 PM
REPRESENTATIVE TARR surmised that adding at least $25 million
per year would be the best thing to do for knowing the potential
fiscal impact of this provision.
MR. PAWLOWSKI answered the table on page 4 of the fiscal note
integrates all of the assumptions that go into the total revenue
impact. The $25 million per year upper estimate has already
been added on line 9 of the fiscal note; that is added into the
revenue impact and subsequently the bottom line fiscal impact of
the legislation. So, it has already been included.
1:32:47 PM
CO-CHAIR FEIGE understood "they would be able to claim the
credit if they received the work order from the company."
MR. PAWLOWSKI replied correct. "If the company made the
expenditures, the credit would be based on those expenditures,"
he said. For example, say an Alaskan company buys a truck from
out of state and then that company puts $200,000 into upgrading
that truck for use in arctic conditions on the North Slope. The
credit would be based on the $200,000 of modifications to the
machinery, not the overall value of the machinery. It is
limited to the modification expenditures, not the actual work
order.
1:33:35 PM
CO-CHAIR FEIGE concluded that each time there is a benefit, or
there is a credit, it does not necessarily mean that someone
took business away from a Lower 48 provider; rather, it gives
Alaskan welders, fabrication shops, and machinists at least a 10
percent leg up. A certain amount of new business could then be
expected to go to Alaska companies that otherwise would have
gone Outside and this could represent a significant amount of
money going into the Alaska economy.
MR. PAWLOWSKI concurred, adding it is important to note that to
qualify for this credit the company must be paying taxes to the
State of Alaska under the corporate income tax. Another
important nexus is that this is tangible personal property with
a useful life of three years or more use in the exploration,
development, or production of oil and gas. That type of
property is subject to the state's oil and gas property tax, so
it feeds into the overall equation that benefits the state
throughout. He further agreed it is about more spending for
actual additional work in the state, which is the intent of this
provision as it was added in the other body to accomplish.
1:35:09 PM
CO-CHAIR FEIGE commented that that could represent a significant
number of jobs and a significant amount of additional money
going into the Fairbanks and Anchorage economies which would
then flow through the rest of the state's economy.
CO-CHAIR SADDLER posited there are benefits to this kind of
thing that are outside the scope of the actual fiscal note and
not just the general fund. It also helps the industry and there
are benefits to having the presence of a healthy, capable
support industry, which tends to lower the cost of development
in Alaska and which speaks to the overall goal to reverse the
decline of production.
MR. PAWLOWSKI concurred there are ancillary benefits that are
impossible to model in the fiscal note. The ability to hold
down costs in the industry itself is critical to the state which
operates on a net tax system. The more efficient, the more
profitable the companies are, the more profitable the state's
share is.
1:36:30 PM
REPRESENTATIVE TUCK surmised this might be a way to get people
who do not have a corporate liability to change their status to
corporate to take advantage of this tax credit.
MR. PAWLOWSKI agreed, saying companies that file as limited
liability companies are not corporate income tax payers. To
qualify for this credit, a company would have to reorganize
under a structure that is subject to the corporate income tax.
REPRESENTATIVE TUCK inquired as to the percentage of service
companies that are currently limited liability versus corporate.
MR. PAWLOWSKI replied he could not venture a guess.
REPRESENTATIVE TUCK said it would be nice to know how many
companies this might affect.
1:38:08 PM
REPRESENTATIVE TARR returned to the fiscal note and maintained
that the $25 million mentioned in the note is not reflected in
the math. Additionally, she observed, if this is intended to be
a revenue generator, there is also no actual revenue-positive
portion included in the fiscal note.
MR. PAWLOWSKI answered if he implied there was an attempt to
model a revenue positive, there is not. It is a negative $25
million estimate. Drawing attention to page 4 of the fiscal
note, he reviewed the amounts in each line under the column for
fiscal year 2014, saying lines 9 and 10 are each a negative $25
million.
REPRESENTATIVE TARR responded she double checked the math and
the aforementioned is in the language but not the math for total
revenue impact.
MR. PAWLOWSKI said he will check the fiscal note and get back to
the committee afterwards.
1:40:28 PM
MR. PAWLOWSKI resumed his presentation, moving to the tax rate
provision [slide 5] in Section 9, beginning on page 4, line 29.
Referring specifically to page 5, line 5, he said the flat tax
rate of 25 percent was changed by the other body to 35 percent.
Repeal of the "sum of" language, he continued, is similar to
that in the original bill and reflects repeal of the
progressivity function. The provision applies to oil and gas
produced after December 31, 2013.
MR. PAWLOWSKI next reviewed changes to Section 2, page 2, lines
3-10, regarding the community revenue sharing fund [slide 6].
As originally introduced, the legislative discretion for
appropriations was linked to receipts from the corporate income
tax. The other body removed this reference since the corporate
income tax is functionally general fund revenue. The linkage
was made to the general fund, not to specific fund source. The
legislature's discretion to appropriate, the actual mechanism of
the appropriation, and the funding are not changed. Guidelines
for the appropriation, page 2, lines 8-10, are retained at
either $60 million or up to $180 million a year. There is no
change to the eligibility determinations for communities or the
actual program itself.
1:42:28 PM
REPRESENTATIVE TARR asked Mr. Pawlowski to provide a comparison
of the thinking from the original bill that made it more
specific as to the fund source. She related she has heard
concern from folks about the changes and said there is a feeling
that the original version left a little more stability as to
there being funding for the revenue sharing program.
MR. PAWLOWSKI replied the original bill linked it to the
corporate income tax. He understood it was a principle issue in
the Senate regarding interpretation of the constitution and the
dedication of funds. It is different in that the administration
had initially identified a direct stream of revenue that the
legislature then appropriates on an annual basis. A subsequent
argument was that it could be more stable by applying it to the
general fund more broadly and maintaining the appropriation
guidelines. He acknowledged there is some concern around it.
1:43:54 PM
CO-CHAIR FEIGE understood that when the legislature came up with
progressivity it tied the revenue sharing funds to that statute.
He inquired where the revenue sharing funds came from prior to
their being tied to progressivity.
MR. PAWLOWSKI responded it came from the general fund.
1:44:29 PM
REPRESENTATIVE P. WILSON offered her concern that municipalities
are facing the same problem of decreasing income as the state.
She said she would therefore like to return to this particular
provision at a later time.
1:45:08 PM
MR. PAWLOWSKI continued his presentation, addressing changes to
the qualified capital expenditure tax credit [slide 7]. He said
the substantive change in Section 15, page 13, lines 1-3, is no
different than what the committee had seen before in the
treatment of the qualified capital expenditure credit. The
capital expenditure credits for activity on the North Slope are
not available after January 1, 2014; therefore, expenditures
have to be made before January 1, 2014, to qualify for this
credit for the North Slope. A change made by the original bill
was that until this bill is passed, capital credits on the North
Slope and credits on the North Slope must be divided over two
years. The decision was to close out this program and allow the
tax certificates to be taken in a single year. An impact of
those credits is seen in the fiscal note for fiscal year 2014,
which is about $400 million to close out the state's obligation
for the credits that are based on the expenditures in 2013.
MR. PAWLOWSKI, in response to Representative P. Wilson, said
[Section 15] begins on page 12, line 14, but the actual
meaningful language is on page 13, lines 1-3. He further
responded this can be seen in the fiscal note on page 4, line 6.
He clarified he is flagging for members the fiscal obligation
that comes from the qualified capital expenditure credits being
taken in one year, as opposed to spread across two, because
closing out this program frontloads the fiscal impact in fiscal
year 2014.
1:48:02 PM
REPRESENTATIVE TARR asked why not let the capital expenditure
credit run out over the two years to reduce the fiscal impact
[in 2014], given the fiscal impact of the bill.
MR. PAWLOWSKI answered the fiscal impact is an obligation with
the state's credits that is based on industry expenditures. The
administration's concern was pushing that fiscal impact off into
the future when it is just a real fiscal impact. It is a choice
of deferring the state's obligation to fiscal year 2015 or
taking care of it in the near term, so ultimately it is a policy
call.
REPRESENTATIVE TARR presumed the program could be closed out and
administered over two years as it has currently been working so
that the fiscal impact could be divided in two.
MR. PAWLOWSKI replied the other intent in allowing recovery of
the credit in a single year was recognizing that ending the
qualified capital expenditure credit program has an impact on
some businesses that are making decisions. Providing an
additional boost as an exchange for ending that program would
allow the state to get an obligation off the books and also
provide a benefit to the companies that are currently in
development.
1:50:07 PM
REPRESENTATIVE ISAACSON inquired whether there is any discussion
with the industry to know if this would exclude any projects
that are currently being planned.
MR. PAWLOWSKI responded removal of this credit for sure has an
impact on companies. The qualified capital expenditure credit
is a piece of the system the companies look at in evaluating
work that can happen in Alaska. The context it needs to be put
in, however, is that the system is being made more competitive
overall compared to the current system. So there may be some
impact, but there is also an improvement in the overall economic
climate that goes along with the rest of the tax changes. To
some degree, loss of the qualified capital expenditure credit is
actually offset by the per barrel credit.
1:51:27 PM
REPRESENTATIVE TUCK understood the qualified capital expenditure
credit is for all companies on the North Slope, whether new or
existing. By making it for expenditures before January 1, 2014,
and the $5 per barrel [credit], it seems that these new
provisions will not apply to "those guys" for possibly many,
many years. He asked whether this is an intentional shifting
from the new players to the old players, given it takes about 10
years to go from exploration to production.
MR. PAWLOWSKI requested he be able to address this question when
he discusses the carried forward tax credit.
1:53:00 PM
REPRESENTATIVE TARR noted the qualified capital expenditure
credit has been characterized as allowing gold plating. Given
the date certain of the bill as written, she inquired whether
there are any concerns that people will try to hurry and take
advantage of that. She further inquired how that would dovetail
into the January 2014 implementation of these provisions that
would include the $5 per barrel and, thus, a "double-whammy
potential" for that to happen.
MR. PAWLOWSKI answered the issue of gold plating should not be
tied to the qualified capital expenditure credit. Rather, gold
plating is an effect of the marginal tax rate in conjunction
with the capital credits that provide state participation and
spending that can reach significant levels; that is actually a
function of the ability to buy down a company's tax rate that
can lead to some interesting distortions in behavior. When
talking about gold plating the focus should not be on a
particular credit, but rather taking a step back and looking at
the system as it currently exists as a whole. A dilemma of
walking through sectionals is the way these interact together.
The ability of companies to frontload expenditures and ramp up
activity to take advantage of credits and deductions before they
shift off into the future is part of the reason why the
effective date of January 1, 2014, was chosen rather than a
later effective date. Because the season is really over the
winter, it would be relatively difficult to frontload into 2013,
which is a reason why the administration decided not to put a
later effective date. The department has a good handle on the
rules and regulations about frontloading and prepaying, and the
administration believes the January 1, 2014, effective date
diminishes that possibility, although that is not say it cannot
happen under any circumstance.
1:55:45 PM
MR. PAWLOWSKI turned back to his presentation, saying the issue
mentioned by Representative Tuck is dealt with in Section 16,
page 13, line 4, regarding the carried-forward tax credit [slide
8]. Companies that do not have production do not have revenues
against which to write off expenditures, nor do they have the
ability to use that $5 per barrel credit. In the bill as
originally introduced by the administration, a company had to
carry forward the loss carry forward credit until production and
that was given a time value of money increase of 15 percent.
However, in CSSB 21(FIN) am(efd fld), page 13, lines 6-10, the
loss carry forward credit was increased to 35 percent to match
the base rate of the tax and allowed to be monetized, so no
longer does this credit need to be carried forward and applied
against production. A new entrant that does not have a
liability would be able to generate 35 percent credit based on
its lease expenditures and its loss and that would provide the
incentive that Representative Tuck was earlier asking about for
a new entrant that does not have a liability and is looking for
some of that state support up front.
1:57:58 PM
MR. PAWLOWSKI, continuing his response to Representative Tuck's
earlier question, stated the bill, as originally introduced,
required that a company without a production tax liability -
without production - had to wait to get this credit by carrying
forward the credit until the company had production. In the
original bill, the value of that credit increased at a rate of
15 percent a year. The other body heard testimony similar to
that heard by this committee, and the discussion resolved around
the state foregoing tax revenue in the future versus
participating for this group of companies. The other body
decided to simplify the system and allow the companies to come
to the state for the cash payment or transfer of this credit.
Under ACES, a company gets a 20 percent capital credit plus the
25 percent loss credit. Under CSSB 21(FIN) am(efd fld), those
companies would get a 35 percent loss credit that can be turned
into the state for a monetary payment. In further response to
Representative Tuck, Mr. Pawlowski confirmed this would be on an
annual basis.
1:59:36 PM
MR. PAWLOWSKI, responding to Representative P. Wilson, confirmed
this provision will enable a small company that does not have a
big cash flow to get some funds so it can continue its work.
1:59:59 PM
MR. PAWLOWSKI resumed his presentation, addressing the newly
created $5 per oil barrel tax credit [slide 9] contained in
Section 22, page 16, lines 4-9. He said this credit applies to
each barrel of oil that is subject to tax under the production
tax. This credit is applicable to the producer's tax liability
for the year the oil was produced, is not transferable, and any
unused portion may not be carried forward for use in a later
calendar year. Further, this credit may not be applied to
reduce the producer's tax liability below zero. The other body
added this provision to balance the high, high base rate of 35
percent. The provision essentially creates a progressive system
without using the progressivity mechanism that exists in current
statute. Under the current system, credits are provided for
upfront capital expenditures. This provision would provide a
credit for directly targeted production - if a barrel is not
produced, there is no $5 per barrel. For example, to earn $100
million in credits under the current system, the producer would
spend $500 million in capital (20 percent of $500 million would
be $100 million). Under CSSB 21(FIN) am(efd fld), the same $100
million credit would be earned by adding 20 million barrels of
production (20 million barrels at $5 a barrel is $100 million).
The other body shifted away from incentives that are directly
tied to the expenditure of funds to incentives that are directly
tied to the production of oil.
2:02:09 PM
REPRESENTATIVE TARR drew attention to page 4 of the fiscal note,
line 8, regarding the $5 per taxable barrel allowance. Noting
the provision's impact of negative $425 million in fiscal year
2014 that doubles to an impact of negative $825 in fiscal year
2015, she asked which DOR forecast the figures are based on.
MR. PAWLOWSKI replied it is based on DOR's fall [2012] forecast.
The impact is less in fiscal year 2014 because the law is
effective January 1, 2014, and therefore only encompasses half
that fiscal year; 2015 is the first fiscal year in which the
bill is in effect for the entire year.
2:03:18 PM
MR. PAWLOWSKI returned to his presentation, explaining that the
gross revenue exclusion (GRE) for North Slope oil and gas
[slides 10-11] is an additional incentive directly tied to
production. The GRE, Section 29, page 21, beginning on line 17,
provides an additional benefit for new production that is based
on 20 percent of the gross value of new oil or gas that meets
one of three criteria. As in the original bill, one criterion
is that the oil or gas is produced from a lease or property that
does not contain a lease that was within a unit as of January 1,
2003. This is for the new areas in new units, recognizing that
two of the units that qualify are ones that were brought on
during a period of multiple changes in the tax system. The
second criterion is oil or gas produced from a participating
area established after December 31, 2011, that was within a unit
formed [under AS 38.05.180(p)] before January 1, 2003. So these
would be new pockets of oil within the existing units. The
third criterion is that the oil or gas is produced from a well
that has been accurately metered and measured by the operator to
the satisfaction of the commissioner of the Department of
Revenue (DOR), the producer demonstrates to DOR that the well is
producing from a reservoir that the Department of Natural
Resources (DNR) has certified was not contributing to production
before January 1, 2013, and the producer demonstrates to DOR the
volume of oil [or gas] produced from that well. This was an
attempt by the other body to bring the GRE into the legacy units
in a way that targeted some of the harder to reach oil that is
not contributing to production in the currently producing
forecast of oil, so new production within the existing units.
In the other body it was easy to agree on the application of the
gross revenue exclusion to new units in new areas, but there was
a lot of work on how to get the GRE into the legacy fields to
apply to some of the harder to reach oil, which is where most of
the oil is in the near term.
2:06:30 PM
CO-CHAIR FEIGE, for purposes of investment and making a decision
whether to drill in a particular area, inquired at what point in
this timeline DNR would approve that particular production. He
further inquired whether DNR would wait for the company to
actually produce from that new reservoir or would approve it
ahead of time before the investment decision is actually made.
MR. PAWLOWSKI offered his belief that the intent is to push it
to something that can be done before the investment decision is
made.
CO-CHAIR FEIGE surmised DNR will address this in its comments.
2:07:11 PM
REPRESENTATIVE TARR noted discussion occurred in the other body
that the third criterion is too broad and would apply to areas
that are already planned for production. Regarding the January
2013 date, she suggested the date could be shifted to make it
more clearly only apply to new oil so as not to incentivize
development that was already going to happen.
MR. PAWLOWSKI responded [the administration's] perspective on
the idea that already-planned development, and the distinction
that it is not new oil, is very difficult and problematic and
deserves more thorough conversation. For example, Liberty was
planned to happen for years in the production forecast.
Counting that as new oil because it is in the revenue forecast
is a best guess of what might happen in the future, and saying
somehow that that is not new oil is perhaps a step too far. The
point in this language is that DNR is the one that defines what
is not contributing to production. The contributing to
production date of 2013 is because it comes into effect in 2014.
So, if that pool of oil, or that trapped pocket of oil in the
reservoir, was not contributing to production this year, then
that is new production. Because DOR must take a very
conservative look at what the fiscal impact of that might be,
there was much discussion regarding the range put on the
potential fiscal impact of this provision. The actual impact of
the provision will depend on what the companies can prove to
DNR. The issue DOR had in developing the fiscal note was
providing the broadest possible spectrum for policymakers to
make a decision, and that is why a broad range is seen in the
fiscal note. Many projects have been in the revenue forecast
over the years and then disappeared. The concept of what is
truly new oil is new oil that is being developed that is not
contributing to production today. The wellbores in the revenue
forecast are defined as the currently producing.
2:09:52 PM
REPRESENTATIVE TARR inquired whether the committee could get
more information if that date was pushed out one year to when
the new policy is actually implemented and then the fiscal
impact looked at.
MR. PAWLOWSKI offered to provide a letter that DOR prepared and
sent to the other body that had a description of where this
fiscal impact range comes from and the actual barrels that are
being forecast in the production forecast. He said the letter
would help provide an idea of the way the dates can work. He
cautioned members about looking at the production forecast as a
given because it has been seen over the years how much it is
actually not a given that that new production is going to
happen, Liberty being just one example.
2:10:54 PM
CO-CHAIR FEIGE asked whether it is the Alaska Oil and Gas
Conservation Commission (AOGCC) or the Division of Oil & Gas
that actually certifies that it is a producing well.
MR. PAWLOWSKI deferred to Deputy Commissioner Balash for an
answer.
2:11:27 PM
MR. PAWLOWSKI continued his presentation, noting the other body
added an Oil and Gas Competitiveness Review Board to statute
[slide 12]. This provision is in Section 33, page 22, beginning
on line 25, and is modeled after the competitiveness review
board created in the province of Alberta, Canada. The other
body's intent was to provide a venue for institutionalized
knowledge that is de-politicized by having both the public and
the private sector sitting together to look at the impact and
effects of regulations and fiscal terms on Alaska's place in the
world. The proposed new statute, AS 43.98.050 beginning on page
23, line 26, establishes the board's duties and requires the
board to provide annual written findings and recommendations to
the legislature. The provision recognizes that while fiscal
terms are critical to the health of Alaska's oil and gas
industry, the good work by DNR, as well as other activity the
state can do, matter as well. Page 24, line 3, states the board
"identify factors that affect investment in oil and gas
exploration, ... including tax structure, ... infrastructure;
workforce availability; and regulatory requirements". The
board's goal is to recognize that it is a broad spectrum of
issues affecting the competitiveness of the state. The board is
set to sunset December 31, 2022, and is made up of nine members.
2:13:38 PM
CO-CHAIR SADDLER, regarding the importance of stability and
predictability, inquired whether this review board will be seen
as a good or bad message to industry, given it will be looking
at what changes need to be made.
MR. PAWLOWSKI answered he understands the concern that industry
and many Alaskans have about the variability of the tax system.
He said it is important to note that those changes are not
always statutory; many over the years have been regulatory. For
example, the Murkowski Administration, through a regulatory
change, aggregated the economic limit factor (ELF) in the
Prudhoe Bay Unit, which led to a substantial tax increase. So,
it is important to recognize it is not just statutory changes
that can and have led to perceptions of instability. The other
body looked at the benefits that an institutionalized, de-
politicized board had on the province of Alberta, and saw it as
a positive and as a message to Alaskans that it is not just
deciding to take a step forward and saying things are done. The
world and technology are changing and Alaska needs to be ever
vigilant about how to consistently be competitive as well as be
more competitive.
CO-CHAIR SADDLER concluded the state actually still has the
capacity to do that kind of continual horizon scanning now, and
this just formalizes it for 10 years as a feedback loop.
2:15:56 PM
REPRESENTATIVE TARR understood Alberta is about $4 billion in
debt based on changes to its royalty structure for the oil
sands. She asked how such a board has worked in Alberta and why
Alaska would want to use that as a model.
MR. PAWLOWSKI confirmed the Oil and Gas Competitiveness Review
Board in Alberta led to the change in the province's royalty
terms, but said production and investment increased dramatically
after the change was passed. While Alberta is in a deficit
today, he proposed that Alberta is not necessarily in a deficit
because it changed its terms, but because growth in oil supply
in the mid-continent and transportation bottlenecks out of
Alberta are resulting in the province's oil selling for dramatic
discount to the world market.
2:16:50 PM
CO-CHAIR FEIGE inquired what that price is.
MR. PAWLOWSKI believed it was in the range of $50-$60.
CO-CHAIR FEIGE related that a parliamentary representative from
Alberta visited his office and was complaining about the
province getting $55 a barrel for its oil. He opined that an
"Excel pipeline" could move that oil and provide a better price
to Alberta.
2:17:10 PM
MR. PAWLOWSKI, speaking to the competitiveness review board,
reported Alberta's premier recently stated that despite the
short-term deficit Alberta is currently in, it is not the intent
of the province to change its taxes on the oil industry to
overcome that short-term deficit. Alberta is taking a long-term
look at the investment that is coming into the province, which
is huge.
2:17:48 PM
REPRESENTATIVE P. WILSON recalled that after Alaska made its
changes, Alberta's board also made changes. However, because of
the board, Alberta realized it before Alaska and changed things
right away. So, she surmised, having the board helped the
province be on the ball much better than what Alaska is doing.
MR. PAWLOWSKI said the aforementioned interpretation of what
happened in Alberta is fair, based on his work talking to the
province. He encouraged members to look at the benchmarking
slides provided to the committee by Econ One in an earlier
presentation for western Canada. There was a marked decline in
the rate of investments in Alberta and an increase in
Saskatchewan because Alberta made its changes, investment moved
to Saskatchewan and British Columbia because of the proximity.
In the other body, the legislature's consultant stated the
ability to quickly move things away from Alaska is much more
difficult than in the Lower 48 or Alberta. So, the delay in
reaction in Alaska has not been as severe as it was in Alberta,
but Alaska has had a similar decline, which is seen in the
benchmarking slides of Alaska's failure to keep up with the rate
of growth in investment that is going on around the world right
now.
2:19:41 PM
REPRESENTATIVE TARR inquired whether Mr. Pawlowski believes the
language under the duties of the competitiveness review board is
broad enough that the board would be looking at transportation
issues. She surmised the name "competitiveness review board"
could be interpreted to be broad enough to be looking at all of
those factors so as to prevent the oversights that happened in
Alberta.
MR. PAWLOWSKI, in response, drew attention to page 24, lines 3-
6, and said there could perhaps be additional language in that
section of the bill to talk about identifying factors that
affect investments. The administration, he added, is interested
in a dialogue with the committee about any changes or expansions
to the issues in the bill.
2:20:49 PM
CO-CHAIR FEIGE next turned to the Department of Natural
Resources' presentation about the gross revenue exclusion. He
noted that CSSB 21(FIN) am(efd fld) made some changes to this
provision from what was written in HB 72.
2:21:32 PM
JOE BALASH, Deputy Commissioner, Office of the Commissioner,
Department of Natural Resources (DNR), discussed the three-part
test for the gross revenue exclusion [slide 2], stating that a
producer can qualify its production for the gross revenue
exclusion (GRE) by satisfying one of the three parts, but cannot
qualify twice. The first of the three ways to qualify is for
production from a unit formed after 2003. The only two
currently producing units that fit that definition are the
Nikaitchuq and Oooguruk units. The second of the three ways to
qualify is for production from a unit formed prior to 2003,
provided that production comes from a participating area (PA)
that was formed after 2012. Moving to the third of the three
ways to qualify, he related that the other body wanted to
identify a way for production from legacy units and legacy PAs
to qualify. Thus, the third way is for production that is
demonstrated to DNR to be from a reservoir not currently
contributing to production. He said the GRE targets what
everybody wants, which is new production.
2:23:52 PM
MR. BALASH explained the North Slope has 18 units and within
those units are 38 separate participating areas [slide 3]. A
given piece of land that is a unit might have multiple
reservoirs and multiple formations that are at different depths.
The PAs are used as a way to define the ownership horizontally
and vertically. Leases and units are two dimensional and PAs go
to the third dimension. Regulations describe the authorities
and processes that DNR uses in managing its units to govern
these PAs [11 AAC 83.351, PA formation, expansion, contraction;
11 AAC 83.343, Plans of development; 11 AAC 83.371, Allocation
of production and costs; 11 AAC 83.303, Protect all parties].
Moving to slide 4, which identifies the PAs in nine of the North
Slope units and the year those PAs were formed, he pointed out
that Prudhoe Bay has the highest number of PAs and that the
Northstar Fido PA is no longer pending as it was approved in
2012.
2:25:40 PM
MR. BALASH said the North Slope's largest unit, and the mother
lode, is the Prudhoe Bay Unit. Using animation on slide 5, he
demonstrated "a topside view" of what the underlying PAs look
like, first showing the initial production area (IPA), and then
the PAs at differing depths: Lisburne; West Beach; Point
McIntyre; Niakuk, which was two separate PAs that were combined
later; Midnight Sun; Polaris; Aurora; Borealis; Orion; and
Raven. Most of the acreage in the Prudhoe Bay Unit is occupied
by at least one PA if not multiple PAs, he noted.
2:27:10 PM
MR. BALASH then demonstrated what the aforementioned look like
from the vertical perspective [slide 6], beginning with the IPA,
and mother lode, of Sadlerochit [in 1977]. The Lisburne PA came
in 1983; West Beach, Point McIntyre, and North Prudhoe Bay came
in 1993; the combined Niakuks came in 1994; and Midnight Sun
[came in 1998]. He explained these are all occurring sometimes
at different depths and other times at the same depth but from
separate formations that are distinct and defined differently
geologically, and the oil in each has different geochemistry. A
number of blocks of land have PAs in all four horizons, a
testament to the richness of Alaska's hydrocarbon system. These
are all distinct layers of reservoir rock that produce oil, but
they are different accumulations, and, generally speaking, are
not in communication with one another.
2:29:05 PM
MR. BALASH said the Division of Oil & Gas evaluates and approves
participating areas using the process spelled out in 11 AAC
83.351, PA formation, expansion, contraction [slide 7]. Very
important is that a PA may include only the land capable of
producing or contributing to production of hydrocarbons in
paying quantities. That means if a well is drilled into a field
it is going to drain oil from the reservoir in question, so the
participating area that is contributing to production is really
important to everybody - the owners of the field, the State of
Alaska, as well as the individual lessees inside the field. It
is important because that is how both the money and the costs
are divided up. Everybody "in the sandbox" has an interest in
making sure these PAs reflect reality to ensure everybody's
interests are protected. As the given PA moves into production,
it can be seen through differences in pressure or flow whether
there is acreage within the PA that is not contributing and
therefore should not be included. That portion of the PA would
then be contracted out and left back into the larger unit. It
is here that DNR uses its unitization criteria [11 AAC 83.303]
for evaluating whether and when to grant a PA. It goes to the
fundamental governance of the department's oil and gas leases,
which is to promote conservation, prevent waste, and protect all
of the parties.
2:31:38 PM
MR. BALASH, continuing his discussion of DNR's evaluation and
approval of PAs, explained that when preparing to move into
production, the operator of the unit submits application [slide
8]. Submittal includes [Exhibits C and D] which lay out the
legal descriptions of where and at what depths the PA is. The
exhibits also lay out the specific allocation factors; it is not
simply a matter of counting up the acres or square footage of
rock or pore space, but actually goes to where the oil is in the
reservoir and how much of it is on the specific properties in
question. [Exhibits E and F] are included if it is a net profit
share (NPS) lease; while there are not many of those, it is
important to call that out. Moving to slide 9, he added that
Exhibits C and D lay out specifically the amount of oil
contained in place and on which leases, as well as what tract
factor is going to be used in the allocation of cost and
production of the share of the barrels that get produced.
2:33:25 PM
MR. BALASH explained that once development activities commence
and a PA is formed, a Plan of Development (POD) [required under
11 AAC 83.343] is submitted to the department [slide 10]. That
POD lays out the process and means by which the lease and unit
is going to be developed and produced. Those plans come into
the Division of Oil & Gas for review and approval. They lay out
where the facilities are going to be, the pipelines, any
production islands that need to be made, and also identify any
gathering lines that bring production from outlying areas into
the production facilities and processing facilities themselves.
That POD is submitted annually for review and approval; it is
very rare that the division does not approve a POD, especially
once a field is in production. The POD is essentially the red
button on the desk, so if there is not a POD approved, the
operator is not supposed to be producing the oil. That is not
good for anyone, including the state, so what usually results is
a negotiation of sorts between the lessees, the operator, and
the Division of Oil & Gas. Those things are rather technical in
nature. It is part of the division's day-to-day business and
something [the department] thinks is going to be useful as it
moves forward in evaluating how this third bucket of
qualification for the GRE is going to actually play out.
2:35:17 PM
MR. BALASH informed the committee that the third qualifying
mechanism for the GRE will likely come into play in the tract
allocation factors, given the division goes through this process
on an annual basis [slide 11]. The department has a specific
regulatory process [11 AAC 83.371] for allocating production.
It is part of Exhibit C that is submitted when the PAs are
formed and which provides the bases for calculating the tract
factors of acreage, original oil in place, the amount
recoverable, and the value of the hydrocarbons. Each of the
working interest owners receive their revenue and pay their cost
based on these tract factors. It is part of the negotiation
that goes on among the private parties themselves as well as the
state. The state has its own interest in ensuring that those
tract factors reflect the state's ownership of the barrels in
the field, especially when there are leases with multiple
royalty rates. From time to time revisions need to be made to
the allocation factors, he continued [slide 12]. As production
unfolds, PAs either expand or contract and work is done with the
operators over time to make sure that those PAs remain as
accurate as possible.
2:37:29 PM
MR. BALASH provided an example of the aforementioned using the
Kuparuk River Unit, noting that slide 13 shows the unit boundary
as well as the main PA boundary inside the unit. He explained
that the various bubbles depicted inside the field show all of
the wells that have been drilled. [The green bubbles depict]
the wells that are producing oil [and the blue bubbles depict]
water injection; in some cases it is both, depending upon the
maturation of the field. Last year, ConocoPhillips Alaska,
Inc., drilled Shark's Tooth in the southwest portion of the
Kuparuk River Unit. It was billed as an exploration well, but
was in a participating area. Conoco announced a discovery and
DNR has had preliminary discussions with the operator about
whether the Shark's Tooth discovery is in the PA or is new
production [slide 14]. The department understands that the
accumulation itself probably lies beyond the original Kuparuk PA
boundary, but that some portion of it is clearly inside the PA
boundary. So, as the department thinks about this third test on
the qualification for the GRE, the operator is going to have the
burden of showing to DNR geologically, probably using four
dimensional seismic or other technical tools, why it believes
this particular accumulation is not contributing to the
production from the wells located to the northeast. This is
going to be an interesting dialogue that unfolds between the
division and industry, he posited, because for acreage to be
included in the PA it is presumed to be contributing to
production. The operator is therefore going to have to make the
argument, as well as demonstrate, that what it is targeting
through a given well or plan of development is actually going to
result in the production of barrels that are not currently
contributing to the production stream from that PA.
2:40:37 PM
MR. BALASH related the department thinks there are a couple of
ways to engage in that dialogue with the companies and will
probably look at establishing some regulations to govern that
process. Making it a part of the annual Plan of Development
reviews is one way to go about it, so DNR would have as part of
its approval a very specific element in that approval that
identifies the location in the PA that is going to qualify for
the GRE. Then, DNR's hands would basically be clean of the
issue, at which point it could be turned over to the Department
of Revenue to work with the lessees on how they are going to
account for those barrels and count them when calculating the
value of the GRE in the overall tax calculation.
2:41:42 PM
CO-CHAIR FEIGE, regarding using the third way to qualify for the
GRE, drew attention to slide 14 [Shark's Tooth Well] and asked
whether that is something DNR could determine fairly early in
the overall project timeline, even before an investment decision
would have to be made.
MR. BALASH replied yes, DNR thinks there are ways to do that.
However, in this particular case the discovery well itself was
drilled into a participating area, so conversation will start
with providing information on why the company thinks this
particular accumulation or part of the reservoir is not
contributing to production today. Whether that is a
conversation that needs to happen prior to the company's
planning that goes into the ultimate POD in a given year is
something that DNR will be sitting down and working out. Today,
with the legislation evolving the way it is, DNR does not have
everything mapped out specifically as far as what that process
will look like. But what the department does know, is that when
talking about a reservoir that is in a participating area
already, then industry is going to have to come to DNR and
demonstrate on technical terms why it is this well is not
contributing to production today.
2:43:38 PM
CO-CHAIR FEIGE presumed chemical differences in the oil and
differing reservoir pressures would be the kind of indicators
that DNR would be looking at.
MR. BALASH responded by providing an extreme example but one
that highlights how it really works. When BP discovered Badami
some 20 years ago and moved into development in the late 1990s,
BP had drilled the wells, tested the pressure, and shot the
seismic. Thinking it understood what was there BP built the
production facilities and a pipeline, but when the unit was
actually opened up for production, the production dropped off
rapidly, which was not expected. The reason was that this
accumulation of oil was actually separated by lots and lots of
faults, so there was not communication throughout the reservoir
rock as BP had expected and counted on.
2:45:12 PM
MR. BALASH continued, explaining that, today, four dimensional
seismic is used in the legacy fields of Kuparuk and Prudhoe Bay.
This uses the element of time to create a fourth dimension in
which it can be seen visually where the oil is moving and,
importantly, where it is not. If it can be seen that identified
oil is not moving into those production wells, then something is
keeping that oil from moving in. Today, industry is drilling
more sophisticated, directionally targeted wells that penetrate
those particular pockets to allow the production to occur.
Sometimes there is a sense that an oil field is like a balloon
or bag full of oil - just drill the well and suck out the oil.
In reality, especially in some of these more complicated
reservoirs, it is more like a Hefty bag full of all kinds of
bags, balloons, and Ziploc bags. A lot of them are filled with
oil, some are filled with gas, and others are filled with water.
When drilling the wells it is a matter of ensuring that all of
the fluids are actually being drained, not just some of the
isolated ones, by making sure there are penetrations into each
of the pockets of the rock that contains the oil. This
particular provision added by the Senate is going to require a
lot of work between industry and the departments, but it is a
provision that is going to be pretty powerful in ensuring that
more of the people's oil is produced.
2:47:42 PM
CO-CHAIR SADDLER inquired how it can be proved that a reservoir
in a participating area has not previously [contributed] to
production.
MR. BALASH answered one way is with four dimensional seismic, in
which multiple three dimensional images are taken of the same
area over time. So, over time, it can be seen graphically where
the oil, water, and gas are moving in the reservoir, and
specific parts of the reservoir that are not moving can be
identified. If they are not moving, it could be for any number
of reasons, but primarily it is likely due to some fault or
break in the rock itself or a penetration geologically with some
other strata that is shielding that portion of the reservoir
from flowing through the rest of the sandstone into the
production wells. He said another way is one he has been told
about by reservoir engineers. In this method, massive reservoir
models are used to track the pressures and fluid dynamics to
tell how much energy is in the reservoir, where it is, and where
it is going. Predictions are then compared against the actual
results to learn what is going on inside the reservoir itself.
Thus, reservoir models and four dimensional seismic can be used
to demonstrate to DNR that a given area is not in fact
contributing to production.
2:50:39 PM
CO-CHAIR SADDLER commented it sounds like there is no clear
answer of yes or no that there is contribution. He asked
whether there is a probability or reliability factor that must
be applied to this.
MR. BALASH replied the risk of undertaking the new activity is
on the operator. The risk is on the operator if an area that
looks like it is not contributing is drilled and then the
operator does not get anything out of it.
2:51:29 PM
CO-CHAIR SADDLER inquired whether acreage judged not to be
contributing goes into a "fallow" category in which there is no
point any more to drill in that area.
MR. BALASH responded he was told by a "guy with a lot of white
hair once that 'technology changes, markets change, but rocks
don't change.'" There are portions of the fields that 30 years
ago will be described as "fallow", but that today are worth
going after. The key is in the active management of the unit
and PAs, and that those parts contributing to production be
recorded as such in the PAs in these tract factors. If, over
time, it is found that it is not contributing, DNR contracts
that out of the PA and leaves it to the operator to possibly
find an opportunity in the future. Returning to slide 6, he
pointed out that the Kuparuk horizon has a lot of unaffiliated
acreage. While he cannot say how much of that might contain
hydrocarbons, to the extent that there are hydrocarbons present,
whether they are economic is going to be the question.
Something that is not a PA today is not being produced, but
technology improvements or market condition changes may make
some of those additional hydrocarbons commercial and worth
pursuing. That is the kind of opportunity that is trying to be
unlocked here. In further response to Co-Chair Saddler, he
confirmed that the GRE is supposed to encourage and incentivize
that.
2:54:06 PM
REPRESENTATIVE P. WILSON requested further elaboration on the
evaluation and approval of participating areas [slides 7-8].
MR. BALASH answered DNR follows an order in the management of
leases and the production of oil; the order starts with the
lease and then exploration is undertaken. For oil accumulation
that is thought to cover multiple leases the companies come [to
DNR] and get a unit. Once they have that unit the operator
provides DNR with a Plan of Development (POD) that tells what,
where, and when something will be built, what will be drilled
and where, and where the production, then, is going to come
from. The PA is really an expectation as the operator moves
into development and it is to include the depth of the unit
itself, and the acreage, that the oil is thought to be and where
the drilling will occur to produce it. For example, if the
depth is between 6,500 and 6,300 feet under the [surface]
outline of an area - that would be the participating area (PA)
inside the unit and that is what DNR records in the unit files.
The operator then executes the Plan of Development, moves into
production, and begins to count the money.
2:56:12 PM
REPRESENTATIVE P. WILSON understood there would be a PA for the
precise [aforementioned] area within the unit and surmised there
would have to be another PA if, within that unit, there is oil
at a different [depth].
MR. BALASH, using slide 6, confirmed and illustrated that there
can be separate PAs at different depths because they are, in
fact, different accumulations of oil.
2:57:06 PM
REPRESENTATIVE P. WILSON returned to slide 7, saying she does
not understand the three criteria [listed under 11 AAC 83.303]:
promote conservation, prevent waste, and protect all parties.
MR. BALASH replied DNR exercises its authority to form a unit
and manage the development of the resource for these three
[aforementioned] reasons; they are the criteria on which DNR
bases its decisions. In Texas 150 years ago, people used to
drill wells everywhere they could, causing energy in the
reservoir to be wasted because there would be less ultimate
recovery of the hydrocarbon. While the Alaska Oil and Gas
Conservation Commission (AOGCC) is ultimately responsible for
conservation of the resource, there is a role of DNR's
management that is incorporated when the department evaluates
units and participating areas.
2:58:24 PM
REPRESENTATIVE P. WILSON surmised, then, that Alaska does not
want to waste its resource, and if too many wells are drilled
there would not be enough pressure to get all of the oil out.
MR. BALASH responded yes, that is a part of it.
REPRESENTATIVE P. WILSON inquired how the state controls that.
MR. BALASH answered it is not so much the state telling how many
wells can or cannot be drilled, but the state ensuring there is
a clear plan for the development of the reservoir itself so it
is developed in a prudent way. The ultimate approval for wells
is granted by AOGCC, but as the owner of the resource [the
state] wants to ensure there are not "food fights" over who gets
to drill the wells and who gets to be in charge of the field.
It gets to be a very important point when there are multiple
lessees in the same unit, such as in Prudhoe Bay and Kuparuk.
REPRESENTATIVE P. WILSON understood the state also wants to keep
the land as environmentally good as it can, so does not want to
needlessly drill different places.
MR. BALASH replied correct.
3:00:14 PM
REPRESENTATIVE TARR inquired whether it would be better to
determine what would count as new production through regulation
or through more direct language in the bill.
MR. BALASH responded DNR thinks the language in the bill today
is workable, but the department is unsure whether it will be so
prescriptive as to set out a regulation that guides its approval
process. The department wants to be able to provide the lessees
with some clarity as to how DNR will go about certifying that a
portion of the reservoir is not contributing to production, but
the department has not landed on that exactly. In the end, it
will probably be a combination of both - there is probably going
to be an avenue through the POD process and probably an avenue
through something more rigid that is laid out in regulation.
The statute provides DNR with the authority and ultimately that
is going to be something DNR can spell out one way or the other.
The key words in the statute are "contributing to production".
3:02:03 PM
REPRESENTATIVE TARR posed a scenario where the reason for
previously not developing something was cost related and asked
whether that reason could be considered appropriate for
something to qualify as new production.
MR. BALASH answered it will probably be more of a technical
question than a cost question. The cost question will come up
in the decision of whether to undertake the activity necessary
to get at those hydrocarbons. For example, would it be worth
the money to drill a separate well in the portion of a reservoir
with an accumulation of, say, 100,000 barrels? That will be a
cost equation weighed by the operator, while DNR will consider
just the technical question of whether it is contributing and,
if it is not, then it is eligible for the GRE.
3:03:17 PM
REPRESENTATIVE TARR observed that on slide 4 the Nikaitchuq PA
is shown as coming in 2011, but the exhibits on slide 9 are
dated as received in 2010. She inquired whether it takes about
a year from the time the paperwork for a PA is submitted until
the PA is actually approved. She further inquired whether there
are any PAs under consideration right now that are not shown on
slide 4.
MR. BALASH replied all of DNR's processes take some time. The
department goes through a thorough evaluation of the material
that comes in because it is important. As far as whether it is
typical to take a year, it probably has more to do with the POD
cycle and how DNR goes about approving first the unit, then the
PODs, and then the timing of the PA coming in is pretty close to
when [the operator] is going to actual development drilling and
production. So, sometimes there is a lag between approval of
the POD, the actual construction, and then the PA itself. He
deferred to a representative of the Division of Oil & Gas to
address whether there are any pending PAs.
3:04:57 PM
TEMPLE DAVIDSON, Unit Manager, Central Office, Division of Oil &
Gas, Department of Natural Resources (DNR), stated there are
currently two PA expansion applications pending on the North
Slope, a PA formation application that just recently came in,
and a couple [of PA applications] that the division thinks it
may see later in the year.
3:05:30 PM
MR. BALASH, responding to Representative Tuck, confirmed that a
PA is determined by DNR.
REPRESENTATIVE TUCK surmised there would be coordination between
DNR and the Department of Revenue (DOR) in determining whether a
field or a PA qualifies for the GRE.
MR. BALASH responded not much coordination is needed for a unit
or a PA. The paperwork that DNR does in its normal course of
business will be used by the lessee to prepare the lessee's
taxes; therefore, that part will be relatively siloed. However,
it is this third category where the coordination between the
departments is going to have to step up a little bit, and an
example of that kind of coordination can be seen in the changes
to the production forecast that DOR puts together. He said
DNR's Division of Oil & Gas was much more involved over the past
year in helping DOR put those numbers together and risk weight
the future new production in a way that made sense.
3:06:59 PM
REPRESENTATIVE TUCK asked whether any other departments would be
involved for the third item to qualify for the GRE. He further
asked whether this would be a negotiations process with the
industry, given it may be hard to define exactly the PAs.
MR. BALASH replied he would not call it a negotiation so much as
a verification exercise. "They come in, they make application,
they demonstrate to us, they show us why it is they think
particular acreage should be included in the PA, and they
generally provide the kind of information our staff needs to
make those approvals. If they don't have the information, we
ask for more ...." A dialogue definitely takes place, but he
would not go so far as to call it a negotiation.
3:08:11 PM
REPRESENTATIVE TUCK inquired whether DNR has an appeal process
or other method for reaching agreement if it disagrees with the
package that is presented. He requested further detail on how
that agreement is reached.
MR. BALASH answered the POD process and the PA process each take
place at the division level and are signed off by the division
director. Those decisions can be appealed to the commissioner
and ultimately to superior court.
3:09:08 PM
REPRESENTATIVE TUCK understood there is an appeal, but asked
whether [the division] makes recommendations for modifications
in those cases where there is a disagreement. He explained he
is trying to see whether there is a partnership that is taking
place or whether it is a yay or nay answer that can be appealed.
MR. BALASH directed attention to slide 10 and stated that if the
POD submitted by the operator is deemed insufficient for
approval, then DNR can propose modifications. If the operator
agrees, the POD is approved. If the operator disagrees there is
the potential that the POD expires, which neither DNR nor the
operator wants.
3:10:05 PM
[CO-CHAIR FEIGE held over CSSB 21(FIN) am(efd fld).]
| Document Name | Date/Time | Subjects |
|---|---|---|
| HRES CSHB158 Tarr Amendment A.5.pdf |
HRES 3/22/2013 1:00:00 PM |
HB 158 |
| HRES HB158 Letter Packet 10.pdf |
HRES 3/22/2013 1:00:00 PM |
HB 158 |
| CSSB 21 SFIN Sectional for HRES 03 22 2013 .pdf |
HRES 3/22/2013 1:00:00 PM |
SB 21 |
| SB0021D.pdf |
HRES 3/22/2013 1:00:00 PM |
SB 21 |
| SB0021-7-2-031813-REV-Y.pdf |
HRES 3/22/2013 1:00:00 PM |
SB 21 |
| SB021CS(FIN)amS-DNR-DOG-3-22-13.pdf |
HRES 3/22/2013 1:00:00 PM |
SB 21 |
| SB021CS(FIN)amS-DOR-TAX-03-21-13.pdf |
HRES 3/22/2013 1:00:00 PM |
SB 21 |
| HRES SB21 DNR - GRE.pdf |
HRES 3/22/2013 1:00:00 PM |
SB 21 |
| Oil Tax Provisions Comparison 03222013 Final.pdf |
HRES 3/22/2013 1:00:00 PM |