Legislature(2015 - 2016)BILL RAY CENTER 208
05/10/2016 09:30 AM House RULES
| 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 | |
HB 247-TAX;CREDITS;INTEREST;REFUNDS;O & G
9:35:02 AM
CHAIR JOHNSON 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."
CHAIR JOHNSON stated that the fiscal challenges before the state
are unprecedented. He said the state must stop writing checks
to the oil companies. He explained that resource exploration
incentives of the past have worked - Cook Inlet is now energy
sufficient and for the first time there has been an increased
flow in the pipeline - but under today's fiscal situation, he
opined, the state cannot continue [to give those incentives].
Chair Johnson stated that a proposed committee substitute (CS)
would make significant cuts to future spending. He pointed out
that the industry "faces those same, harsh decisions that we're
making on a daily basis"; the fates of the industry and Alaska
are intertwined, and the solution is not about "us versus them,"
but about working together. He said the proposed CS for HB 247,
Version 29-GH2609\D, Nauman/Shutts, 5/6/16 would phase out the
tax credit system for some small producers. He added, "They
create jobs; they found many more resources; and there's still a
lot to be done."
CHAIR JOHNSON specified that what he does not want is to trim
back spending so much that Alaska is "not open for business any
longer." He said the CS would also give new companies the
chance to develop new plans and finance new structures by
phasing out the credits. He reemphasized that the state "cannot
sacrifice future oil production for today's budget." He said
the proposed CS would strike a balance and is the result of many
conversations and review of many other bills that have been
heard in previous committee [hearings]. He described it as a
starting point that would not go far enough for some and would
go too far for others, but expressed his belief that it would
allow the state to move forward with a system for generating
revenue while maintaining the opportunity for its partners to
continue to do business.
9:38:15 AM
REPRESENTATIVE OLSON moved to adopt the proposed committee
substitute (CS) for HB 247, Version 29-GH2609\D, Nauman/Shutts,
5/6/16, as a working document.
CHAIR JOHNSON objected for the purpose of discussion.
9:38:45 AM
RENA DELBRIDGE, Staff, Representative Mike Hawker, Alaska State
Legislature, presented the proposed CS for HB 247, Version 29-
GH2609\D, Nauman/Shutts, 5/6/16 ("Version D"), on behalf of
Representative Hawker, member of the House Rules Standing
Committee, sponsor by request of the governor. She said Version
D would close out the state's tax credit program, beginning in
January 2017 through January 2020, with the exception of one
Middle Earth exploration credit, which currently is scheduled
under statute to sunset by 2022. She said in phasing out the
credit system on the North Slope, the state would transition to
a method of carrying forward lease expenditures such that if a
business is not able to deduct in the current year while credits
are being phased out, then industry would still be able to have
the net profit tax system benefit of carrying forward losses.
9:39:38 AM
MS. DELBRIDGE named the following statewide provisions proposed
under Version D: a $75 million cap per company in the amount of
credits that can be cashed back annually; a priority on refunds
from the oil and gas tax credit fund for credit to those
companies that have at least 80 percent Alaska hire; and a
required disclosure of some information to the public. She said
the Department of Revenue (DOR) would make public each year the
name of the company receiving refunds for credit from the oil
and gas tax credit fund, as well as the total dollars refunded
to that company each year.
MS. DELBRIDGE stated that Version D would maintain some
provisions that have been in a number of previous iterations
through the legislative process, including: provisions relating
to unfunded liability that would allow DOR to withhold the
amount of an outstanding liability from a company's refund; a
requirement for a $250,000 surety bond and provisions for
prioritizing those claims; and a requirement for municipal
producers to allocate their lease expenditures to taxable
production, so that they are not receiving credits for
production that is not taxed.
MS. DELBRIDGE relayed that the income tax credits currently in
statute to support instate refineries and liquefied natural gas
(LNG) storage facilities would, under Version D, be maintained
and be refundable, but no longer would come out of the oil and
gas tax credit fund. The interest rate on delinquent taxes,
including those undergoing audit, would increase from three
points above the federal discount rate to five points and from
simple interest to being compounded quarterly. She stated that
new under Version D would be a provision that says that the
gross tax the state assesses on private royalties paid to
private land owners may never be less than zero. She said the
aforementioned make up the broad, statewide provisions.
9:41:33 AM
MS. DELBRIDGE moved on to the provisions under Version D that
would be specific to Cook Inlet and Middle Earth: credits would
end January 1, 2019. She reiterated that Middle Earth would
retain its exploration credit through 2022, as currently
provided in statute. She said a legislative working group,
during the 2016 interim, would develop a new oil and gas tax
regime for Cook Inlet and Middle Earth, and it would present
that regime to the legislature in 2017. The intent would be for
[the new regime] to take place in 2019, after the expiration of
all the credits. She clarified that for 2016, all the credits
currently in statute for Cook Inlet and Middle Earth would
continue. She said this is a 25 percent qualified capital
expenditure credit; a 40 percent well lease expenditure credit;
and a 25 percent net operating loss (NOL) credit. She stated
that in order to receive any credit for Cook Inlet work from
2017 going forward, a company will have to have had oil or gas
production in Cook Inlet in calendar year 2016. She said that
at the end of 2016, the 20 percent qualified capital expenditure
credit would be repealed. Companies would be eligible in 2017
and 2018 for a reduced 20 percent well lease expenditure credit
and, in 2017 only, for a 25 percent NOL credit. She reiterated
that the legislative working group would be designing a new oil
and gas tax regime to take effect with the expiration of those
credits.
MS. DELBRIDGE related that specific to Middle Earth, there would
be, under Version D, an extension of one credit for the Copper
River Basin only. She indicated that under current statute that
credit is set to expire in July 2016; under Version D, the
credit would be extended to the end of 2016. She said this
would provide an opportunity to a company in the process of
drilling wells and "not quite able to meet those deadlines."
9:43:35 AM
MS. DELBRIDGE stated that on the North Slope, the one remaining
credit, after the expiration in July 2016 of an exploration
credit, will be the NOL credit of 35 percent, which would remain
in statute for the next three years, through 2019. She
continued as follows:
The only way that you can get this three-year
transitionary measure is if you ... have production in
the North Slope of less than 15,000 barrels per day in
2016 or, if you are not yet in production but you are
developing as a unit, with an approved plan of
development or plan of exploration, after those three
years, the net operating loss credit expires
completely on the North Slope. Meanwhile, we will
shifting to a system of lease ... expenditure carry
forward, so that expenses that are not able to be
deducted but are still eligible lease expenditures in
a current year are carried forward against your
liability in a future year. That ... shift to carry
forward of lease expenditures has the effect of
hardening the gross minimum tax floor at 4 percent.
MS. DELBRIDGE, also regarding the North Slope, said the gross
value reduction (GVR) received for new oil - a timeless benefit
under current statute - would, under Version D, be limited to a
10-year benefit beginning once regular production starts. She
said the proposed Version D also addresses how, for tax
purposes, oil receives a new oil benefit once it "graduates and
becomes normal oil."
MS. DELBRIDGE noted that previous bill versions all included
provisions that would prevent the use of the gross value
reduction from amplifying the size of an NOL, and Version D
would retain that provision, as well. She offered to answer
questions from the committee.
9:45:54 AM
REPRESENTATIVE TUCK asked Ms. Delbridge to offer more details
regarding the surety bond.
MS. DELBRIDGE noted that the surety bond provision could be
found on pages 26-27 of Version D. She said it was a provision
added by amendment in the House Resources Standing Committee,
following concerns, particularly in the Cook Inlet Region, over
some companies that have gone into bankruptcy over the past
couple years and been unable to pay their bills to local
businesses and contractors. She said that in exchange for a
business license to conduct oil and gas activities, under
Version D, a company would need to file a $250,000 surety bond
with the Department of Commerce, Community & Economic
Development, and Version D lists what the company would be
promising to pay. She said language on [page 27], lines 16-31,
and continuing on page 28, lists the order in which the claims
would be prioritized.
MS. DELBRIDGE stated that the bond could be waived by the
commissioner of the Department of Commerce if he/she finds the
company is producing oil and gas in commercial quantities. She
said the surety bond claims "against us" would be satisfied with
material, equipment, and supplies delivered in the state; labor,
including employee benefits; taxes and other amounts to cities
and boroughs; repair of public facilities; and taxes and other
amounts due to the state.
9:47:46 AM
REPRESENTATIVE HERRON asked if the bond had been fully vetted
and whether a bankruptcy lawyer had been consulted. He offered
his understanding that "even the $250,000 could get caught up in
the bankruptcy claim."
MS. DELBRIDGE replied that she had not been in contact with a
bankruptcy attorney. She said the provision had been in the
proposed legislation since it was heard by the House Resources
Standing Committee, and it [remained in the bill through its
hearing by] the House Finance Committee. She offered her
understanding that the Department of Law (DOL) had reviewed [the
provision], and she said the administration may have some
additional comments on the provision when its representative
comes to testify before the committee on 5/11/16.
9:48:31 AM
REPRESENTATIVE KREISS-TOMKINS asked if the provision that
relates to municipal production relates to the Beluga field, to
Municipal Light & Power (ML&P), or any other entities in Alaska.
MS. DELBRIDGE offered her understanding that [the provision]
would be limited to ML&P, which has "ownership at Beluga." She
added that a municipal producer like that would produce, and
some of its production would go to its own generation, while
some of it could be sold to other entities for other uses. She
said the provision that was in the governor's original bill and
"has carried through the process" essentially says that a
municipality that produces and uses that production for its own
generation is already not subject to taxes on that portion;
therefore, [Version D] would clarify that "you do not receive
credits on that portion." She continued, "If you sell a portion
of your production, and it's taxable, in that instance you ...
can receive credits for that portion ... of your production."
9:49:45 AM
REPRESENTATIVE CHENAULT asked Ms. Delbridge if by production she
meant the actual sale of natural gas to some other entity or if
it could mean the natural gas could be turned into electricity
and the electricity could then be sold to someone else.
MS. DELBRIDGE answered that there is no distinction in that, per
se. She clarified, "Essentially, if you're selling your gas to
someone else for generation, rather than to your own use, then
you ... would have that limitation; ... you would need to
allocate your lease expenditures to receive credits only on the
taxable portion."
9:50:34 AM
REPRESENTATIVE HERRON asked Ms. Delbridge to give examples of
lease expenditure deductions.
MS. DELBRIDGE stated that lease expenditures are currently
defined in statute, under AS 43.55.165, as the cost of getting
oil or gas out of ground that is upstream of the point of
production. She said it is the cost of actually working in the
field and taking the oil or gas to the processing facility; as
soon as it is fed into a transportation line, it is past the
point of production. She said lease expenditures have to be
upstream, they must be necessary and ordinary costs for the
Internal Revenue Service (IRS), and they have to be direct
costs. She said there is a long list in statute of those things
that are excluded, including royalties paid, the cost of
acquisitions, and lobbying or public relations. She offered to
pull up the list to read.
REPRESENTATIVE HERRON said he had just wanted some examples
stated for the record.
9:52:15 AM
The committee took a brief at-ease at 9:52 a.m.
9:52:28 AM
MS. DELBRIDGE next presented the sectional analysis for Version
D, included in the committee packet, which read as follows
[original punctuation provided, with some formatting changes]:
Section 1 Adds a new subsection to AS 31.05.030,
Alaska Oil and Gas Conservation Act. Requires the
Alaska Oil and Gas Conservation Commission to verify
the start of regular production of new oil. Effective
Jan. 1, 2017.
Secs. 2-6 Amend AS 38.05.036 (a), (b), (c), (f)
and (g), Alaska Land Act, Audit of royalty and net
profit payments and costs. Conforming to the Section
50 repeal of AS 41.09, an old Department of Natural
Resources exploration credit program. Effective Jan.
1, 2017.
Section 7 Amends AS 40.25.100(a), Public Record
Disclosures, Disposition of tax information.
Conforming to Section 9, which requires the Department
of Revenue to make public some taxpayer information.
Effective Jan. 1, 2017.
Section 8 Amends AS 43.05.225, Administration of
Revenue Laws, Interest. The interest rate on
delinquent taxes is five points above the 12th Federal
Reserve District rate, compounded quarterly. Effective
Jan. 1, 2017.
Section 9 Adds a new subsection to AS 43.05.230,
Administration of Revenue Laws, Disclosure of tax
returns and reports. Requires the Department of
Revenue to make public by April 30 of each year, the
name of a company from whom the department purchases a
tax credit certificate and the total amount of tax
credit certificates purchased from each company.
Effective Jan. 1, 2017.
Section 10 Amends AS 43.20.046(e), Alaska Net
Income Tax Act, Gas storage facility tax credit. The
Department of Revenue will no longer use the Oil and
Gas Tax Credit Fund to refund gas storage facility
credits. The credits remain refundable by DOR. Also,
definition of "unpaid delinquent taxes" is removed, as
a new definition for "outstanding liability"
applicable to AS Title 43, Revenue and Taxation, is
added in Section 49. Effective Jan. 1, 2017.
Section 11 Amends AS 43.20.047(e), Alaska Net
Income Tax Act, Liquefied natural gas storage facility
tax credit. The Department of Revenue will no longer
use the Oil and Gas Tax Credit Fund to refund LNG
storage facility credits. The credits remain
refundable by DOR. Also, definition of "unpaid
delinquent taxes" is removed, as a new definition for
"outstanding liability" applicable to AS Title 43,
Revenue and Taxation, is added in Section 49.
Effective Jan. 1, 2017. 2
Section 12 Amends AS 43.20.053(e), Alaska Net
Income Tax Act, Qualified in-state oil refinery
infrastructure expenditures tax credit. The Department
of Revenue will no longer use the Oil and Gas Tax
Credit Fund to refund instate refinery credits. The
credits remain refundable by DOR. Also, reference to
"unpaid delinquent taxes" is removed, as a new
definition for "outstanding liability" applicable to
AS Title 43, Revenue and Taxation, is added in Section
49. Effective Jan. 1, 2017.
Section 13 Amends AS 43.55.011(i), Oil and Gas
Production Tax. Ensures the tax assessed on private
royalties is not less than zero. Effective Jan. 1,
2017.
Section 14 Amends AS 43.55.011(m), Oil and Gas
Production Tax. Conforming to the Section 50 repeal of
the DNR credit programs in AS 38.05.180(i) and AS
41.09. Effective Jan. 1, 2017.
Section 15 Amends AS 43.55.023(b), Oil and Gas
Production Tax, Tax credits for certain losses and
expenditures. The 35% net operating loss credit on the
North Slope terminates at the end of 2016, except the
35% credit (refundable) is available through 2019 for
companies producing less than 15,000 barrels per day
in 2016, and for companies without production
operating under a unit plan of development or plan of
exploration approved by the Department of Natural
Resources. The 25% net operating loss credit in areas
other than the North Slope remains at 25% in 2017,
then terminates. To receive the credit in Cook Inlet,
a company must have regular production of oil or gas
in Cook Inlet in calendar year 2016. Also, ensures
that the application of a gross value reduction for
new oil cannot increase the size of a loss. Effective
Jan. 1, 2017.
Section 16 Amends AS 43.55.023(d), Oil and Gas
Production Tax, Tax credits for certain losses and
expenditures. Conforms to the Section 50 repeal of AS
43.55.023(a), qualified capital expenditure credit.
Effective Jan. 1, 2017.
Section 17 Amends AS 43.55.023(e), Oil and Gas
Production Tax, Tax credits for certain losses and
expenditures. Conforms to the Section 50 repeal of AS
43.55.023(a), qualified capital expenditure credit.
Effective Jan. 1, 2017.
Section 18 Amends AS 43.55.023(l), Oil and Gas
Production Tax, Tax credits for certain losses and
expenditures. Reduces the well lease expenditure
credit from 40% through 2016, to 20% in calendar years
2017 and 2018. To receive this credit in Cook Inlet,
the producer must have regular oil or gas production
in Cook Inlet in 2016. Effective Jan. 1, 2017.
Section 19 Amends AS 43.55.023(n), Oil and Gas
Production Tax, Tax credits for certain losses and
expenditures. Conforms to the Section 50 repeal of AS
43.55.023(a), qualified capital expenditure credit.
Effective Jan. 1, 2017. 3
Section 20 Amends AS 43.55.024(i), Oil and Gas
Production Tax, Additional nontransferable tax
credits. Companies may apply the $5 per-barrel new oil
credit only for oil receiving the 10-year gross value
reduction. Effective Jan. 1, 2017.
Section 21 Amends AS 43.55.024(j), Oil and Gas
Production Tax, Additional nontransferable tax
credits. Once new oil is no longer eligible for new
oil benefits and is being taxed as normal oil, the oil
is also eligible for the sliding-scale per barrel
credit. Effective Jan. 1, 2017.
Section 22 Amends AS 43.55.025(m), Oil and Gas
Production Tax, Alternative tax credit for oil and gas
exploration. Extends a Middle Earth credit for work in
the Copper River Basin only, to Jan. 1, 2017. A
company that has spudded but not completed a well by
Jan. 1, 2017, is also eligible. The AS 43.55.025(a)(6)
credit covers 80% of eligible costs, up to $25
million. Effective immediately.
Section 23 Amends AS 43.55.025(m), Oil and Gas
Production Tax, Alternative tax credit for oil and gas
exploration, as amended by Section 22. Conforming to
the Section 52 repeal of AS 43.55.023. Effective Jan.
1, 2020.
Section 24 Amends AS 43.55.025(o), Oil and Gas
Production Tax, Alternative tax credit for oil and gas
exploration. Conforms to the Section 50 repeal of AS
43.55.025 (a)(7) and (n). Effective Jan. 1, 2017.
Section 25 Amends AS 43.55.028(a), Oil and Gas
Production Tax, Oil and gas tax credit fund. Removes
the authority to use the fund to pay refunds for the
income tax credits related to the instate refinery,
LNG storage facility, and gas storage facility.
Effective Jan. 1, 2017.
Section 26 Amends As 43.55.028(a), Oil and Gas
Production Tax, Oil and gas tax credit fund, as
amended by Sec. 25. Conforming to the Section 52
repeal of AS 43.55.023. Effective Jan. 1, 2020.
Section 27 Amends AS 43.55.028(e), Oil and Gas
Production Tax, Oil and gas tax credit fund. Limits
the maximum state repurchase of tax credits to $75
million per company, per year. Requires the Department
of Revenue to, before purchasing credit certificates,
find that the applicant is not the result of the
division of a single entity into multiple entities
that would reasonably have been expected to apply as a
single entity. Effective Jan. 1, 2017.
Section 28 Amends AS 43.55.028(e), Oil and Gas
Production Tax, Oil and gas tax credit fund, as
amended by Sec. 27. Conforms to the Section 52 repeal
of AS 43.55.023. Effective Jan. 1, 2020.
Section 29 Amends AS 43.55.028(g), Oil and Gas
Production Tax, Oil and gas tax credit fund. Requires
the Dept. of Revenue to adopt regulations granting
preference to companies with at least 80% Alaska hire,
in case there is not enough money in the 4 Oil and Gas
Tax Credit Fund to cover all applicants. Also, as
credits for LNG storage facilities, gas storage
facilities and instate refineries would no longer be
refunded through the fund, makes conforming
adjustments. Effective Jan. 1, 2017.
Section 30 Adds a new subsection to AS 43.55.028,
Oil and Gas Production Tax, Oil and gas tax credit
fund. Ensures an outstanding liability to the state
related to oil and gas activity is withheld from the
amount of a tax certificate purchased by the Dept. of
Revenue using the Oil and Gas Tax Credit Fund. The
department may use the withheld amount to satisfy an
outstanding liability, providing the liability is not
being contested through an appeal or adjudicatory
process established in law, without the taxpayer's
consent. Satisfying a liability in this manner would
not affect the applicant's ability to contest a
liability. Effective Jan. 1, 2017.
Section 31 Amends AS 43.55.029(a), Oil and Gas
Production Tax, Assignment of tax credit certificate.
Conforming to the Section 50 repeal of the qualified
capital expenditure credit in AS 43.55.023(a).
Effective Jan. 1, 2017.
Section 32 Amends AS 43.55.029(a), Oil and Gas
Production Tax, Assignment of tax credit certificate,
as amended by Sec. 31. Conforms to the Section 51
repeal of the well lease expenditure credit in AS
43.55.023(l). Effective Jan. 1, 2019.
Section 33 Amends AS 43.55.029(a), Oil and Gas
Production Tax, Assignment of tax credit certificate,
as amended by Secs. 31 and 32. Conforms to the Sec. 52
repeal of the net operating loss credit in AS
43.55.023(b). Effective Jan. 1, 2020.
Section 34 Amends AS 43.55.030(a), Oil and Gas
Production Tax, Filing of statements. Conforms to the
repeal of the qualified capital expenditure credit in
Section 50. Effective Jan. 1, 2017.
Section 35 Amends AS 43.55.030(e), Oil and Gas
Production Tax, Filing of statements. Conforms to the
Section 50 repeal of the qualified capital expenditure
credit, AS 43.55.023(a). Effective Jan. 1, 2017.
Section 36 Amends AS 43.55.075(b), Oil and Gas
Production Tax, Limitation on assessment and amended
returns. Conforms to the Section 50 repeal of the
qualified capital expenditure credit, AS 43.55.023(a).
Effective Jan. 1, 2017.
Section 37 Amends AS 43.55.160(d), Oil and Gas
Production Tax, Determination of production tax value
of oil and gas. Conforms to the Section 52 repeal of
AS 43.55.023(b). Effective Jan. 1, 2020.
Section 38 Amends AS 43.55.160(e), Oil and Gas
Production Tax, Determination of production tax value
of oil and gas. Requires that, for the purposes of
calculating a carried-forward annual loss, any
reduction due to the Gross Value Reduction for new oil
is added back to the tax calculation. This prevents
the GVR from 5 increasing the amount of a loss. Also,
conforms to the new lease expenditure provisions in
Section 42. Effective Jan. 1, 2017.
Section 39 Amends AS 43.55.160(e), Oil and Gas
Production Tax, Determination of production tax value
of oil and gas, as amended by Sec. 38. Conforming to
Section 52 repeal of AS 43.55.023(b). Effective Jan.
1, 2020.
Secs. 40-41 Amend AS 43.55.160(f) and (g), Oil and
Gas Production Tax, Determination of production tax
value of oil and gas. For the gross value reduction
for new oil, reduces the period in which the reduction
applies from a lifetime benefit in current statute, to
a 10-year benefit, beginning once regular production
starts from a lease or property. The Alaska Oil and
Gas Conservation Commission will determine when
regular production begins. For new oil already
receiving the gross value reduction, the benefit
terminates Jan. 1, 2026. Effective Jan. 1, 2017.
Section 42 Amends AS 43.55.165(a), Oil and Gas
Production Tax, Lease expenditures. For the North
Slope, lease expenditures include lease expenditures
incurred in a prior year that have not been previously
deducted in determining oil and gas taxes and were not
the basis of a credit. This section allows lease
expenditures to carry over from a prior year. Also,
conforming to the Section 50 repeal of AS 43.55.165(j)
and (k). Effective Jan. 1, 2017.
Section 43 Amends AS 43.55.165(f), Oil and Gas
Production Tax, Lease expenditures. Conforming to the
Section 50 repeal of the qualified capital expenditure
credit, 43.55.023(a). Effective Jan. 1, 2017.
Section 44 Amends AS 43.55.170(c), Oil and Gas
Production Tax, Adjustments to lease expenditures.
Conforming to the Section 50 repeal of the qualified
capital expenditure credit, AS 43.55.023(a). Effective
Jan. 1, 2017.
Section 45 Amends AS 43.55.180(a), Oil and Gas
Production Tax, Required report. Conforms to the
Section 52 repeal of 43.55.023. Effective Jan. 1,
2020.
Section 46 Amends AS 43.55.895(b), Oil and Gas
Production Tax, Applicability to municipal entities.
Requires allocation of lease expenditures and tax
credits between taxable and exempt production for a
municipal entity. Effective Jan. 1, 2017.
Section 47 Adds a new paragraph to AS 43.55.900,
Oil and Gas Production Tax, Definitions. Defines
"regular production" as defined in AS 31.05.170.
Effective Jan. 1, 2017.
Section 48 Adds new sections to AS 43.70, Alaska
Business License Act. Requires a $250,000 surety bond
for oil and gas businesses, allowing the Department of
Commerce commissioner to cancel the requirement once a
business is producing oil or gas in commercial
quantities. Provides a framework for people with
claims against a business required to post the surety
bond; prioritizes satisfaction of types of claims.
Effective Jan. 1, 2017.
Section 49 Adds a new paragraph to AS 43.99.950,
Revenue and Taxation, General Provisions, defining
"outstanding liability to the state." Effective Jan.
1, 2017.
Section 50 On Jan. 1, 2017, repeals multiple
sections of statute, including the old DNR exploration
credit programs; the qualified capital expenditure
credit; and pre-2010 tax statutes. (See attached
Summary of Repeals)
Section 51 On Jan. 1, 2019, repeals the well lease
expenditure credit. (See attached Summary of Repeals)
Section 52 On Jan. 1, 2020, repeals all credits
remaining in 43.55.023. (See attached Summary of
Repeals)
Section 53 Adds a new section to uncodified law
creating a Legislative Working Group to develop a
comprehensive tax regime for oil and gas in Cook Inlet
and Middle Earth, to take effect Jan. 1, 2019, once
the current credits are phased out. The working
group's proposal is to be presented to the Legislature
in the 2017 regular session, and should include
evaluation of incentives other than direct monetary
support, including loan guarantees. Effective
immediately.
Section 54 Applicability language.
Section 55 Transition language related to the Jan.
1, 2017, repeal of the qualified capital expenditure
credit, AS 43.55.023(a). Effective Jan. 1, 2017.
Section 56 Transition language related to the
repeal of the well lease expenditure credit. AS
43.55.023(l) and (n). Effective Jan. 1, 2019.
Section 57 Transition language related to the
repeal of the carry-forward annual loss credit, AS
43.55.023(b). Effective Jan. 1, 2020.
Section 58 Transition language related to credits.
Effective Jan. 1, 2020.
Section 59 Transition language related to lease
expenditures and the repeal of AS 43.55.165(j) and
(k). Effective Jan. 1, 2017.
Section 60 Transition language related to
exploration and seismic expenditures. Effective Jan.
1, 2017.
Section 61 Transition language authorizing the
Department of Revenue, Department of Natural
Resources, Department of Commerce, Community and
Economic Development, and the Alaska Oil and Gas
Conservation Commission to adopt regulations for this
act. Effective immediately. 7
Section 62 Transition language authorizing the
Department of Revenue and Department of Natural
Resources to adopt retroactive regulations. Effective
immediately.
Section 63 Immediate effective date for sections
22 (extension of Middle Earth credit for a well
spudded but not completed), 53 (Legislative Working
Group), 61 (authority to adopt regulations) and 62
(authority to adopt retroactive regulations).
Section 64 Jan. 1, 2019, effective date for
sections 32, 51 and 56.
Section 65 Jan. 1, 2020, effective date for
sections 23, 26, 28, 33, 37, 39, 45, 52, 57 and 58.
Section 66 Jan. 1, 2017, effective date for all
other sections.
10:05:39 AM
The committee took an at-ease from 10:06 a.m. to 10:07 a.m.
10:07:43 AM
CHAIR JOHNSON announced that the committee would hear a
presentation from Janak Mayer.
10:08:50 AM
The committee took a brief at-ease at 10:09 a.m. to address
technical difficulties.
10:09:38 AM
JANAK MAYER, Chairman & Chief Technologist, enalytica, noted
that enalytica is the legislative consultant to the Alaska State
Legislature on the topic of fiscal terms, oil and gas taxation,
and natural gas commercialization [of] Alaska Liquefied Natural
Gas (AKLNG). He said the presentation would provide a summary
of the core issues related to the proposed Version D. He said
the first two slides compare differences between the latest
version of the bill that passed out of the House Finance
Committee and [the proposed committee substitute, Version D].
The next slide looks at areas of commonality between the two.
The remaining slides provide additional analysis on a couple of
key issues.
10:10:39 AM
MR. MAYER drew attention to slide 2. He stated that the core
focus of Version D is on the issue of refunded tax credits. He
indicated that in fiscal year 2016 (FY 16) those credits would
cost the State of Alaska approximately $500 million, "with
substantially more than that in FY 15 and will again be more in
2017." He said it is a staggering amount of money compared to
the relatively small amount of money that the overall oil and
gas fiscal system brings in "at these low prices." He said the
proposed legislation aims to steadily reduce that amount over
time until the refundable tax credits are completely eliminated
by 2019/2020. He said there is a substantial difference between
the tax credits and how they work for Cook Inlet and the North
Slope. For Cook Inlet, the credits are used to incentivize
activity in what is already a low and very attractive fiscal
regime where there is no production tax on oil and a low tax on
gas.
MR. MAYER reiterated that the proposal for Cook Inlet is a
gradual reduction to no credits by 2019. Crucially, he
continued, the bill would hold the existing credit system in
place until the end of the year. He explained that is important
because numerous companies have entered solid contracts between
now and the end of the year for work programs, in particular for
drilling and other capital works, premised on the basis of
receiving those credits. He said there are numerous companies
that have not received new credits for that work to be performed
between now and the end of the year, which he indicated could
result in a question of fundamental financial liability and even
bankruptcy. He said the aggressive approach to ramping down and
eventually cutting off the credits was crafted with a timeframe
that is fairly thoughtfully calibrated in terms of understanding
what is required of new companies that are most financially
vulnerable to complete their capital programs in order to reach
a point of enabling themselves to a sustained cash flow.
10:13:45 AM
MR. MAYER stated that for the North Slope, the issue was also
about ended refunded credits. He noted that for the North
Slope, there is only one major refundable credit left in the
system. He mentioned some others that have been available in
the past, including the capital credit that exited under
Alaska's Clear and Equitable Share (ACES), but said the one
major one is the NOL tax credit. Unlike other credits, this one
simply enables producers to recover costs they incur for which
they do not have tax liability in the year in which they incur
the costs. He said typically a new developer is incurring major
expenses to develop a new project, which has little to no tax
liability to deduct that against. However, in the current tax
environment, there is a situation where even major producers -
because of low prices and substantial ongoing reinvestments -
have expenses they cannot deduct. He relayed that under the
current system, those companies with more than 50,000 barrels a
day can take this credit but have to claim it in the future
against liability, while those with under 50,000 barrels a day
can take this as a refund - a tax credit - and get cash.
10:15:18 AM
MR. MAYER said the ability to deduct all expenses, whether they
are less than the tax liability or exceed it, is the defining
feature of any net profit tax. Under a gross tax system, he
added, expenses are not considered or deducted. However, under
a net tax system they are; what is being taxed is the profit at
the end after subtracting the expenses. He stated that because
in the oil and gas industry, as in many industries, investments
and subsequent revenue occur at different times in the cycle, it
is crucial to say that all expenses, whether able to be deducted
in this year or other years, will eventually be deducted. He
said the vast majority of oil and gas tax systems do that by
saying that anything that cannot be deducted in the current year
can be carried forward. He opined that Alaska has been somewhat
unique, in that instead of carrying forward expenses to deduct
in future years, it offers the NOL tax credit. He said that for
companies with more than [50,000] barrels a day, it performs a
role similar to carrying forward an expense deduction to the
future, while having the unique feature for smaller companies of
allowing them to take the benefit of cash right now, which has
enhanced project economics and reduced the amount of working
capital needed to pursue various projects.
10:17:27 AM
MR. MAYER said that for larger producers without tax credit
calculated after the tax liability is calculated, there is no
longer the ability to reduce the amount of tax paid below the
gross minimum floor. He said this has the effect of hardening
that gross minimum floor against future losses. He stated there
are a number of key differences in the way that would happen
[under Version D] versus the way it would happen in the
governor's original version of HB 247, wherein an elevated 5
percent hard floor is "completely hardened" and the NOL credits
"can't take you below." He said the $5 per-barrel credits and
the small producer credit are not changed by this; therefore,
the economics of new production are less impacted.
MR. MAYER emphasized that for companies that had incurred
expenses last year they were not able to deduct and hold - NOL
credits for future deduction - and for companies undertaking
work this year for which they are earning NOL credits because
they are spending money in excess of their revenues and
reinvesting during difficult times, the impact of hardening the
floor immediately would be that those companies could no longer
claim those credits they assumed they would have when they made
the decision to undertake the work. He indicated that "they
have to be claimed at some point in the future." He added, "And
that's a substantial change in ... terms of investment for a
company that had made decisions on that basis."
10:19:34 AM
MR. MAYER continued, stating that this approach is quite
different, because it says to companies that the NOL credits
that they earned in previous years and that they are earning
this year can be continued and deducted against the tax
liability over the next several years and continue to reduce the
tax liability over the next couple years below the 4 percent
gross floor. He continued as follows:
Going forward though, for new expenses, effectively
that 4 percent floor is hard against those new
expenses. And so, by the time, for instance, when one
looks at a fiscal note, when we get out to the later
years - 2019, 2020, and beyond - the impact starts to
look very similar to floor hardening, but then in the
intermediate times it'll sort of graduate and move
toward that harder floor regime, because credits that
have already been incurred because companies made
decisions understanding that they would receive the
net operating loss credits - that isn't suddenly
changed under these companies the way it would be by
immediate floor hardening. I think that's the key
difference that ... means that in terms of how the
regime is perceived from a stability perspective what
companies making these decisions can live with, this
might be an entirely viable way to achieve that end in
a way that the pure floor hardening, I think though,
many, many more problems.
10:20:53 AM
REPRESENTATIVE TUCK commented that he was having difficulty
hearing Mr. Mayer.
10:21:12 AM
CHAIR JOHNSON made inquiries to attempt to improve the audio,
then asked Mr. Mayer to continue with his presentation.
10:22:15 AM
MR. MAYER continued with slide 2. He said one fundamental
distinction that needs to be understood is that the switch to a
loss carried forward system has the effect of hardening the
floor against future losses, while not changing the fundamental
treatments of NOL credits that have been earned thus far. For
those companies deeply affected by any move from refunded
credits to a system of loss carry-forwards, there is a
transition between now and the end of 2019, on the North Slope,
where some form of refundable credits will still be given. He
said the refundable NOL will continue to exist for companies
with less than 15,000 barrels a day production or with approved
plans of oil development or exploration between now and 2019,
but will be capped at a maximum of $75 million per company. He
said this would be effective in reducing and eventually
eliminating the state's liability on the refundable tax credit
fund.
MR. MAYER stated that the refundable credits allow many smaller
companies to undertake substantial work, in some cases new
projects of $1 billion or more in capital expenditure, with
substantially less total capital than they would otherwise have
acquired and with the ability to achieve total rates of return
that are attractive to outside financing groups, such as private
equity firms, in a way that might not otherwise be the case. If
legislation dramatically changes that, a number of companies
will have some difficult decisions to make about whether they
can continue without anticipated programs and restructure in a
way that will allow them to continue, for example, by bringing
in larger or better capitalized partners or finding other
working interest owners to share the burden or making a
substantial change in their work program. The refundable NOL
credit on the North Slope has enabled an entire class of much
smaller companies to be present and do work on the North Slope,
and taking that away, even gradually, will have substantial
impacts. He emphasized the importance of understanding that and
thinking through that tradeoff and how the tradeoff should be
made.
10:25:36 AM
MR. MAYER showed slide 3 and said another difference between the
committee substitute for HB 247 that was created by the House
Finance Standing Committee and the one being proposed by the
House Rules Standing Committee is regarding time limits on the
gross value reduction (GVR). He said currently there are no
time limits on how long new developments benefit from the gross
value reduction. The House Finance Committee's committee
substitute would have allowed the benefit of the gross value
reduction for only five years from first production. He said
that effectually eliminates a vast amount of the benefit of the
gross value reduction, because in most cases, for the first five
years of production, there are substantial, ongoing drilling
expenses. These drilling expenses mean the company has
relatively little tax liability, if any, in that time period
anyway, so the gross value reduction applied to those first five
years has relatively little effect. He said a 10-year horizon
allows for much more benefit of the gross value reduction to be
retained; 15 years would allow almost all the benefit, but 10
years would allow at least a substantial portion of the gross
value reduction to be returned. He said the House Rules
Standing Committee's version would allow 10 years, during which
"the gross value reduction should end over time and new oil
should, as they say, graduate to old oil, but it should happen
at a point in time when some substantial part of the intended
purpose of the gross value reduction of that benefit has been
able to be realized."
MR. MAYER said in terms of Middle Earth tax credits, the House
Finance Standing Committee's version and the House Rules
Standing Committee's version are similar: there is a steeper
cut-off, with an eventual full elimination of credits. He said
that applies to all Middle Earth credits, with the exception of
one specific exploration credit that would otherwise sunset July
1, 2016, but is extended to the last completion of wells
(indisc.) of July.
10:27:42 AM
MR. MAYER, regarding interest due on delinquent taxes, said the
House Finance Committee's version set it at 5 percent compounded
quarterly for three years, then a [5 percent] simple interest
after that point. He continued as follows:
That gets enormously complex when you think about the
fact that we have [federal] plus 3 percent ...
uncompounded at the moment we're already changing, and
then this question of how that change is applied when
you add a ... second change into the system that says
that some period of time is one system, but then
another. It gets very difficult to figure out how
exactly this should work. This is going ... with a
much simpler approach of saying there is one change,
which is the 5 percent compounded quarterly.
MR. MAYER, regarding Alaska hire, echoed Ms. Delbridge's summary
that [the House Rules Standing Committee's version] would create
a preference for Alaska hire, not through the amount of refunded
credits, but by placing companies with greater than 80 percent
Alaska hire "higher in the queue for refundable credit
payments." Further, he stated that private royalties could not
go below zero.
10:02:42 AM
MR. MAYER directed attention to slide 4, which reflects common
proposed changes in the House Finance Committee's version and
the House Rules Standing Committee's version. He indicated that
both versions address the issue of refundable credit
withholding; the House Rules Standing Committee's version
clarifies that a company would have to dispute a liability in
order for withholding not to be used to settle that liability.
Regarding .025(a)(6) Middle Earth exploration credits, "this
simply specifies though they have to be in Copper River Basin."
Regarding municipal production expense deduction, he said
credits and deductions could only be claimed in proportion to
taxable production for [municipalities] that own production and
"used for their own purposes." He indicated there would also be
the addition of a surety bond that had been seen in previous
versions of the bill.
10:30:13 AM
MR. MAYER directed attention to slide 5, titled "Refunded
Credits Reached New High in FY 2015." The bar graph on slide 5
shows, for example, that the amount involved would be more than
$800 million in FY 17. He stated, "It's an enormous amount of
money relative to the state's finances as a whole at the moment;
under current forecast those exceed $1.3 billion between FY 15
... [and] FY 17." He said it is split fairly evenly between the
North Slope and the non-North Slope, the latter of which he
indicated includes Cook Inlet, which has accounted for a
substantial bulk of those credits. He stated, "These are
essentially what are being eliminated over time by this CS."
MR. MAYER turned to slide 6, titled "Big Difference Between
North Slope and Cook Inlet." He highlighted the following
regarding Cook Inlet: no production tax, a much smaller basin
with much smaller production, less royalty revenue, and -
looking back at FY 15 - vast amounts of credit outflow,
indicated by the light gray bars on the bar chart. Of the three
bars, he noted: the left-hand bar shows the total for the state
for FY 15; all the colored bars above the zero line are the
revenues that come in through the oil and gas fiscal system; the
gray bars show credit outflow in refundable tax credits of $628
million. He said, "Fully $404 [million] of that [credit
outflow] in FY 15 was in the Cook Inlet." He said the two bars
to the right of that show estimated numbers for the North Slope
and Cook Inlet and clearly illustrate the great difference
between the two, and "ending the ... outflow of credits in the
Cook Inlet is clearly a particular priority in terms of I don't
think anyone can look at that situation and think that that's
sustainable." He said the North Slope numbers show a greater
degree between expenditures and incoming revenue, and because
almost all the money being spent, in terms of refundable
credits, is in the form of the NOL tax credits, the question is
one of "recognizing expenses and whether we do it now or whether
we do that later." He continued:
Through the refundable tax credit, we effectively
recognize those expenses now and simply pay that
amount out. The alternative is to have companies hold
those expenses as things that they can deduct in
future years, and that's what this bill would do.
10:33:21 AM
REPRESENTATIVE TUCK asked Mr. Mayer to confirm that very little
in the way of corporate income taxes for Cook Inlet is
collected.
MR. MAYER offered his understanding that is correct and is a
function of a couple things: partly that Cook Inlet is a
smaller basin with less production, but it is also a function of
the corporate structure wherein Alaska levied corporate income
tax on C Corporations, and the only companies that have to be C
Corporations are those that want to list publicly and have
access to capital markets. He concluded, "So, if you're able to
be, for instance, privately held, you can use other structures
like S corporations and LLCs, for instance, that don't pay
Alaska's corporate income tax, and ... that also goes part of
the way to explaining what you see there."
REPRESENTATIVE TUCK responded, "And it just looks like - to me -
... it's a sliver of everything else, too."
10:34:38 AM
MR. MAYER stated that slides 7-9 address the issue of changes on
the North Slope in terms of ending refundability of the NOL
credits, and eventually ending the NOL credit itself on the
North Slope, what that would do to new developments by
developers that currently rely on that credit being refunded,
and what the impact is of the timeframe over which the gross
value reduction can be taken. He drew attention to slide 7,
titled "How Do Changes Impact New Field Development?" He said
the chart on the left shows cash flow, and the modeling is for
an 80-odd million barrel field that would produce at a peak of
about 20,000 barrels a day, drilling from 30 wells, including
producers and injectors over a period of eight years, with total
combined capital and drilling costs of $1.3 billion.
MR. MAYER explained the colors on the left-hand chart. Purple
and light blue indicate drilling and capital costs,
respectively. He said negative capital amounts were in the
early years. He related that capital expenses have to be
incurred before, for example, drilling pads, basic facilities,
and infrastructure are built. The light blue indicates the
drilling that occurs after that point in time. He said the
green indicates the revenue that comes after the project comes
on line; there are ongoing drilling expenses for many years
"after this project starts bringing in revenue and even after
this becomes cash flow positive." Mr. Mayer said the dotted
black line indicates the after-tax cash flow that the project
receives, while red indicates the government take. He
continued:
You can see red, in this case, is a positive amount
from a company's perspective in the early years, and
that's the impact of those refunded tax credits that
we're talking about. And so, for instance, the fact
that those are refunded and ... received as a payment
by this company - that also means that the cash flow
that they receive is not as steeply negative as it
would be if they were paying, effectively, the full
amounts of the CAPEX or the blue bars, because that's
being offset by the credit that's being received.
MR. MAYER said the chart shows that for the first five years,
there were substantial expenses being incurred. He said, "The
red bars of government take are now negative; ... things like
royalty, corporate income tax, and also production tax are
relatively small compared to what they are later in the
picture." Because of all that ongoing drilling and cost, there
is little production tax liability for a project like this in
the first five years. The bulk of the production tax liability
occurs only after several years of production, which he said is
crucial to understanding why a five-year gross value reduction
limit is not that different in many ways to taking away the
gross value reduction altogether.
10:37:56 AM
MR. MAYER turned to slide 8, titled "10 YR GVR LIMIT MITIGATES
IMPACT ON PROJECT VALUE." He said the chart on slide 8 shows
comparisons between the status quo and various results from
limiting the gross value reduction. The "X" axis is the number
of years a limit is imposed, while the "Y" axis is how much of
the original value is being taken away by making the change.
The colored lines indicate different price changes: red is
$60/bbl; orange is $70/bbl; [yellow is $80/bbl]; green is
$100/bbl; and blue is $130/bbl. He said the project is marginal
at $60/bbl; almost all of the net present value that exists in
this project at this rate can be attributed to the gross value
reduction. Without that, there would be no net present value
left in the project. He continued:
For instance, when I say take that away, that's
essentially, cost projective, the same thing as saying
a zero-a-year limit for the gross value reduction, and
you can see that at zero, the red line's at $50/bbl -
all of the value is gone. If you allow the gross
value reduction for five years, that's still taking
away about ... $60/bbl - ... more than 60 percent of
... the project value. So, it's a very ...
substantial impact by having a five-year limit.
That is less the case at higher prices, but you're
still talking higher prices of somewhere between 20
and 45 percent of the value of a project being taken
away by going from an unlimited GVR to a five-year
GVR; it's a very, very substantial change to the
system. Whereas, in a ten-year case, those amounts
are all much less, and in general sort of at the 20
percent mark or at higher prices - 10 percent or less
of ... value that's being taken away - and that's why
consistently we've said if ... the desire is to see a
limit - a point in time where new oil incentivized
under the gross value reduction becomes old oil - 10
years or above makes a lot more sense to us than ...
five years does, and that 10 years, of course, is what
is represented in this bill.
10:40:34 AM
MR. MAYER directed attention to slide 9, titled "ENDING CREDIT
REFUND IMPACTS CAPITAL NEEDS, IRR." He emphasized the
importance of understanding the substantial impact that ending
credit refunds on smaller companies would have. He said
refunded credits have enabled a suite of smaller companies that
may not otherwise have the resources to undertake major
investments on the North Slope. Ending those credits would
force major questions for those companies in terms of how they
continue. He said the chart on the bottom-left of slide 9 shows
cumulative cash flow of a model with $1.3 million in
investments.
MR. MAYER said a company "under this current credit system"
needs to have about $350 million of capital, because once it has
spent it, the project would be on line and generating revenue,
with a self-sustaining cash flow. He said eliminating the
refunded credit changes that substantially. For example, a
company may need $150 million to undertake a project like this.
So, for companies that have already made decisions about certain
projects, the question is whether they will be able to continue
those investments without refunded credits or with only the next
three years of credits at a $75 million cap. He said it is a
difficult question. He said there would be many for whom that
sort of activity is possible if they bring in another partner -
ideally one that can add substantial capital. He continued:
That's particularly the case when you think about the
fact that what you've also done is sort of push up,
effectively, the ... break-even or hurdle price, ...
so that for any given IRRs that ... one might need to
achieve to satisfy investors, the price level at which
that occurs ... costs ... only about $10 higher. And
obviously it gets more difficult to ... bring in more
capital when your entire rates of return and other
things have deteriorated again because ... the
refunded credit is going away.
MR. MAYER stated that clearly refunded credits are a difficult
expense for the State of Alaska at the present time and need to
be brought under control. He said that is particularly the case
in the Cook Inlet where what the bill would do is "aggressive"
in "a well thought out way." He said in terms of the North
Slope, there is a difficult trade-off that needs to be made
regarding the impact of the refunded credits paid out to oil
companies and the substantial impacts that would be brought by
eliminating them. He said it would have a substantial impact on
what sort of companies could operate in the basin; it would
bring hard choices to those companies as to whether they could
continue and what would be required to enable that to occur.
MR. MAYER announced that that completed his presentation.
10:44:12 AM
REPRESENTATIVE HERRON referred to slide 8 and noted that the
House Finance Committee's version of the bill had proposed a 5-
year GVR, while the House Rules Standing Committee's version
proposes a 10-year GVR. He noted there had been conversation in
the legislature about considering a 7-year GVR. He asked what
the project value would be at $60/bbl and how a 7-year GVR limit
might benefit the state.
MR. MAYER answered that a 7-year time limit would wipe out about
45 percent of current project value at a $50 level, which is a
substantial impact. He said bearing in mind that only a small
portion of North Slope oil qualifies for the gross value
reduction at the moment, "the key purpose here ... is to say
what we're worried about is that eventually, over time, ... if
there is no limit, more and more oil will become under the
rubric of the gross value reduction." He stated, "In that
context, whether it's 7 years or 10 years, it's not clear to me
that that is quite so crucial from the state's perspective, ...
as long as there is a limit that says at some point you graduate
and become old oil, so more and more isn't cumulatively becoming
new oil over time." He continued:
Whereas, while it's not a major difference, it seems
to me, from the state's interest perspective, it is a
major difference in terms of the impact on a new
investment and what the original purpose of the gross
value reduction was, and that's been the reason that
we have said so far that if a limit's going to be put
in place, we really think that 10 years is the sort of
responsible minimum amount.
10:46:19 AM
REPRESENTATIVE KREISS-TOMKINS asked Mr. Mayer to confirm that
slide 9 was supposing the same hypothetical project that is
outlined on slide 7.
MR. MAYER answered that's correct. He added that slide 9 refers
to the outcomes outlined on slide 7.
REPRESENTATIVE KREISS-TOMKINS asked how many barrels of GVR-
eligible oil are projected to be produced next year and what
"the effective value on reduced tax liability" would be for GVR-
eligible oil. He then referred to the marked difference for the
GVR and GVR limit in varying price environments on project
value, as shown on slide 8, and asked if there had been thought
or conversation related to tying GVR eligibility to a certain
price environment so that the GVR is not triggered [until the
price of oil drops below a certain level], because he said in
high-price environments, GVR eligibility is maybe not that vital
to project viability.
MR. MAYER responded that he did not know how much GVR oil is
forecast in the next year, but deferred to the Department of
Revenue for that information. In terms of tying the GVR benefit
to the oil price, he said Alaska's oil and gas production tax
system started out with a few simple ideas back in 2006 and has
become increasingly complex over the years. He continued:
Trying to take a benefit like this - particularly
given that there are ... key other things that depend
on that, such as ... if you're eligible for the gross
value reduction or if it determines whether you're
eligible for a fixed $5 versus sliding $8 credits - it
seems to me likely only to add substantially more
complexity. Which (indisc.) creates a lot of
instability for the companies involved, right? A key
part of all this is to say to any company that as much
as possible, at the time you make a final investment
decision, you can nail down and know as much as you
can, okay? You have certain exposures that you can't
change, like commodity price environment. But to the
extent that we can make things as certain for you as
possible, we want to do that to ... enable you to
accurately evaluate your economics and know what
you're getting into. And so, to ... the extent that
you sort of make benefits like this contingent on the
oil price environment seems to me adds a lot of
complexity, doesn't necessarily provide a huge amount
of benefit to the state in the broader context, but
also adds, sort of, instability into the system, as
well.
10:50:24 AM
CHAIR JOHNSON asked Mr. Mayer if it is normal for smaller
companies to have partners or more usual for them to be "going
it alone."
MR. MAYER answered that it is usual for small companies to have
partners. He added that to some extent, credits have allowed
small companies to do work in Alaska without a partner. He
indicated that withdrawing the credits would force smaller
companies to consider how to come up with the necessary capital
if bringing in a working interest partner is not a viable
solution. He suggested the counter consideration is whether it
has been difficult to get as many independent companies into
Alaska as the state might have liked. He listed the North Slope
being an expensive place to invest and produce and the issue of
fiscal instability as reasons that Alaska, despite its enormous
resource potential, has not "attracted as many independent
players as one might like." He emphasized the huge role that
credits have played, and suggested there would be cases where
some smaller companies could make it work in Alaska without the
credits, while others could not. He concluded, "I don't think
anyone has a completely firm answer to that ... question."
CHAIR JOHNSON asked what impact the hardening of the floor would
have on the industry and the state. He commented that it
certainly would be a tax increase.
MR. MAYER confirmed that Chair Johnson is correct about the
implicit hardening of the floor that occurs by taking away the
NOL credits and switching to a pure, expense carry-forward
system that has the impact of effectively raising the floor
against future years' expenses. That is a substantial tax
increase. He continued:
It, on the one hand, provides that sort of basic level
of protection of the amount of revenue the state
receives should we have an extended period of ... low
prices. It also ... creates a corresponding
liability, if you will, that says ... in the same way
as that the pure hardening [of] the floor would mean
that should prices stay low for a long period of time
and companies' expenses not adjust, you could have
mounting net operating loss credits, and you've seen
that in some of the fiscal notes that the Department
of Revenue has handed out previously, in the same way,
under this system, you have, sort of mounting
expenses. One of the things that's important to
understand ... is because those expenses are at above
the line rather than below the line amount, when you
see them in credit terms, they're one amount of money;
when you see them as expenses, they're about almost
three times as much, because, of course, the question
of multiplying them or dividing by 35 percent of the
amount of the credits. Those two amounts are
effectively the same thing, right? Above the line
they look almost three times greater, because they're
not being multiplied by 35 percent, but in terms of a
sort of ongoing liability that effectually, you know,
is what's being held over to be claimed against
companies' future tax liabilities, those two things
are the same. So, one shouldn't sort of see bigger
amounts in terms of expenses being carried forward on
fiscal notes and be suddenly terrified by the fact
that they grew three times bigger. That's simply an
artifact of the fact that they're being shown as
expenses to ... be deducted in the future rather than
credits to be claimed in the future; they're still
basically the same thing.
MR. MAYER said in terms of the impact on companies, they have
already been paying effective tax rates in Alaska, at current
prices, at or above 100 percent. He stated, "Obviously,
hardening the floor makes life that much more difficult if we
have an ongoing low-price environment for those companies." He
continued:
The key difference here is that you're at least
allowing the credits that have been earned so far -
through work last year, through work being undertaken
this year - that companies have already factored into
all their planning in making those investments, but
those can still taken, ... including against the
floor, and that sort of more gradual imposition of the
harder floor, I think, is crucial in creating
something that on the one hand, provides some of the
... revenue certainty for the next couple years the
state wants if we have an extended, ongoing period of
low prices, while doing that in a way that doesn't
fundamentally disrupt things for companies the way
that pure ... floor hardening might have.
10:56:10 AM
REPRESENTATIVE TUCK requested that Mr. Mayer slow his pace of
speaking when answering questions. He offered his understanding
that the manner in which the floor is hardened is related to NOL
credits, but asked if there is another way that the floor is
hardened.
MR. MAYER answered that "while this bill doesn't explicitly
harden the floor the way the others have done," it would have
the implicit effect of doing so by ending the NOL credits and
switching, instead, to a system of carrying forward expenses.
He continued:
Because those expenses are carried forward above the
line, as it were, there is no credit any more that can
take you down below the floor. And so, for legacy
production, that means that when we look solely from
this point forward at future expenses and what those
future expenses can do for companies, they can't take
them below the gross minimum floor any more. The only
thing for legacy production that could take those
companies below the floor is net operating loss
credits that they have already incurred before the end
of 2016 that they can continue to claim against their
gross minimum tax liability in the future, if we stay
in that gross minimum tax world. And once those have
worked their way through the system, the floor is at
that point, effectively, for legacy production,
completely hard. That's slightly different for new
production, where ... things like ... small producer
tax credits and other things that ... remain in the
system could still reduce liability for new producers
and for ... new production below the floor amount.
REPRESENTATIVE TUCK said it sounds like there is a hardening of
the floor by cancelling net operating losses for any producer of
over 15,000 barrels per day, whereas there is no floor for those
with less than 15,000 barrels per day. He said, "I'm trying to
find out where we were on how far the legacy wells can continue
taking those net operating losses. Apparently they can still do
the ones that they have now." He asked, "How far does that
carry forward?"
MR. MAYER said for legacy producers there will not be any more
credits after 2016; the credits they have earned up to that
point can be taken against their tax liability for the next
several years, depending on what that tax liability is. He
clarified that once those tax credits work their way through the
system, they will be done and completely eliminated.
10:59:54 AM
REPRESENTATIVE TUCK asked if it is possible to forecast when
those credits would run out.
MR. MAYER recommended that Representative Tuck could get
specific information from the Department of Revenue, because
enalytica does not have access to that sort of tax payer data.
He relayed that a fiscal note he had seen indicated that "the
revenue difference between this and floor hardening was pretty
similar" by 2020.
11:01:01 AM
REPRESENTATIVE KREISS-TOMKINS referred to slide 5, regarding
past expenditure payouts, and - relating that to Chair Johnson's
opening comments about Alaska's fortune waxing and waning - said
he would like to know what the quantitative relationship is
between credit investment in the industry and marginal increased
production or revenue to the State of Alaska - the return on
investment relationship.
MR. MAYER responded that when looking at slide 5, he would
emphasize that Cook Inlet and the North Slope differ in terms of
credit outlay and benefit to the state. In the Cook Inlet, he
explained, there is no tax on oil and a very low tariff tax on
gas, and credits are purely a means by which the state
incentivizes behaviors that it wants to see. He continued:
What we have said so far in our analysis is when ...
we look at the state of things in the Cook Inlet -
particularly from the perspective of ongoing and
additional investment in gas, which seems to us has
always been the key ... aim of the credit program in
the Cook Inlet - that ongoing drilling in the mature
field is highly economic under most circumstances that
one can imagine, particularly when one has ... $6 or
higher gas price.
... Development of new resources is fundamentally made
difficult by a very limited gas demand - a very
limited market to address - and ... unless one can
find a way of changing that, credits have some effect
at the margin, in terms of making almost impossible
projects otherwise possibly vaguely viable and, as a
result, we've seen ... one, new substantial gas
project in ... the Cook Inlet on that front. But
then, ultimately, unless that question of market ...
size and market access can be addressed, credits by
themselves haven't got a huge weight in solving that
problem, and mostly what they've done is incentivize a
lot of drilling for oil and cover a lot of costs for a
lot of activity that in many ways is probably economic
regardless.
... This is a program that, I think, made a lot of
sense when the overall fiscal system was bringing in
up to $10 billion in annual revenue, these were small
amounts of money we're talking about to try to
stimulate activity in the Cook Inlet and turn that
basin around. The cost of that program is much, much
harder to justify, I think, in ... the current time,
given all those things.
MR. MAYER reiterated that the North Slope is a different
situation, because the only substantial credit remaining is the
NOL credit, and that really is a question of the timing of cash
flows rather than absolute amounts. He said that credit is
given in recognition of expenses that have been incurred that
would otherwise be held over and deducted against future
revenue. He said, "It's a cash outlay now in place of lower
revenue in the future. By not having that now, you're solving a
major, sort of, cash flow timing problem for the state, but
that's revenue that one might have in the future, instead." He
continued:
So, understand in that sense that the question on the
North Slope about net operating loss refundable tax
credits is all about timing of cash flow and the fact
that the outlay and ... spending that money and then
providing it to smaller companies now who qualify is
really difficult from a cash perspective at the
moment, but it doesn't change fundamentally the amount
of revenue that the system over time itself will
generate.
11:06:40 AM
REPRESENTATIVE HERRON remarked to Chair Johnson that by FY 17
nearly all the credits already will have been earned, so there
will be "a significant invoice when those come due." He asked,
"But is this version - your version - is it your intent to get
rid of them over time and then not pay credits to people that
will not seek reduction in the future?"
CHAIR JOHNSON answered that he thinks that is, in general, an
accurate statement. He indicated that the state would like to
continue to incentivize companies, but it needs to ask what it
can afford. He questioned whether the state could continue to
write checks to oil companies "in this environment." He said he
thinks Representative Kreiss-Tomkins "hit the nail on the head"
with his remark that the state had incentives that worked in the
Cook Inlet and on the North Slope, and the state continues to
pay those out while in the midst of a revenue shortfall. He
opined that the state certainly does not want to be paying
credits to companies that are never going to pump a barrel of
oil, but wants to incentivize those that might. He added, "But
this is what we can afford and what's ... out there."
11:08:44 AM
REPRESENTATIVE TUCK restated that he had had trouble hearing Mr.
Mayer's presentation, but would listen to the audio recording
before the next meeting.
CHAIR JOHNSON said Ms. Delbridge would be available to anyone to
answer questions, and he proffered that Ms. Delbridge could get
specific questions answered by Mr. Mayer.
[HB 247 was held over.]
| Document Name | Date/Time | Subjects |
|---|---|---|
| HB 247 Version D.pdf |
HRLS 5/10/2016 9:30:00 AM |
HB 247 |
| HB 247 Version D Summary.pdf |
HRLS 5/10/2016 9:30:00 AM |
HB 247 |
| HB 247 Version D Sectional.pdf |
HRLS 5/10/2016 9:30:00 AM |
HB 247 |
| enalytica RULES CS.pdf |
HRLS 5/10/2016 9:30:00 AM |
HB 247 |