Legislature(2013 - 2014)SENATE FINANCE 532
02/27/2014 09:00 AM Senate FINANCE
| Audio | Topic |
|---|---|
| Start | |
| SB138 | |
| Presentation: Sectional, Long and Short Term Fiscal Impacts | |
| Presentation: Decisions, Alignment, Price, Cost and Risk | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| += | SB 138 | TELECONFERENCED | |
| + | TELECONFERENCED |
SENATE BILL NO. 138
"An Act relating to the purposes of the Alaska Gasline
Development Corporation to advance to develop a large-
diameter natural gas pipeline project, including
treatment and liquefaction facilities; establishing
the large-diameter natural gas pipeline project fund;
creating a subsidiary related to a large-diameter
natural gas pipeline project, including treatment and
liquefaction facilities; relating to the authority of
the commissioner of natural resources to negotiate
contracts related to North Slope natural gas projects,
to enter into confidentiality agreements in support of
contract negotiations and implementation, and to take
custody of gas delivered to the state under an
election to pay the oil and gas production tax in
kind; relating to the sale, exchange, or disposal of
gas delivered to the state under an election to pay
the oil and gas production tax in kind; relating to
the duties of the commissioner of revenue to direct
the disposition of revenues received from gas
delivered to the state in kind and to consult with the
commissioner of natural resources on the custody and
disposition of gas delivered to the state in kind;
relating to the authority of the commissioner of
natural resources to propose modifications to existing
state oil and gas leases; making certain information
provided to the Department of Natural Resources and
the Department of Revenue exempt from inspection as a
public record; making certain tax information related
to an election to pay the oil and gas production tax
in kind exempt from tax confidentiality provisions;
relating to establishing under the oil and gas
production tax a gross tax rate for gas after 2021;
making the alternate minimum tax on oil and gas
produced north of 68 degrees North latitude after 2021
apply only to oil; relating to apportionment factors
of the Alaska Net Income Tax Act; authorizing a
producer's election to pay the oil and gas production
tax in kind for certain gas and relating to the
authorization; relating to monthly installment
payments of the oil and gas production tax; relating
to interest payments on monthly installment payments
of the oil and gas production tax; relating to
settlements between producers and royalty owners for
oil and gas production tax; relating to annual
statements by producers and explorers; relating to
annual production tax values; relating to lease
expenditures; amending the definition of gross value
at the 'point of production' for gas for purposes of
the oil and gas production tax; adding definitions
related to natural gas terms; clarifying that credit
may not be taken against the in-kind levy of the oil
and gas production tax for gas for purposes of the
exploration incentive credit, the oil or gas producer
education credit, and the film production tax credit;
making conforming amendments; and providing for an
effective date."
9:10:05 AM
^PRESENTATION: SECTIONAL, LONG and SHORT TERM FISCAL
IMPACTS
9:10:26 AM
Co-Chair Kelly welcomed the presenters.
9:11:39 AM
AT EASE
9:12:36 AM
RECONVENED
MICHAEL PAWLOWSKI, DEPUTY COMMISSIONER, STRATEGIC FINANCE,
DEPARTMENT OF REVENUE, (DOR) explained the document titled
"CS FOR SB 138 (RES): Commercial Production of North Slope
Gas SECTIONAL ANALYSIS: 28-GS2806\O" (copy on file):
Section 1 sets out the legislative findings that the
commercial production of gas deposits from the North
Slope is of vital public interest that will provide
benefits to the state; therefore it is the intent of
the legislature that further progress towards this
goal incorporate consideration of the provisions as
set out in this section.
Section 2 amends AS 31.25.005, related to the purpose
of the Alaska Gasline Development Corporation (AGDC),
to add new subsections (4) and (5) for the advancement
of a large-diameter natural gas pipeline project
through acquiring an equity interest in the large-
diameter pipeline project and developing treatment and
liquefaction facilities through the subsidiary created
in new AS 31.25.122.
Section 3 conforms AS 31.25.010, the structure of AGDC
related to dissolution, to include reference to a
large-diameter natural gas pipeline project.
Section 4 amends AS 31.25.080(f) to allow the AGDC in-
state gas pipeline project developers to continue to
coordinate with the developers of large-diameter
natural gas pipeline to the maximum extent practicable
without delaying the progress of developing the in-
state natural gas pipeline. In coordinating with the
developers of a large-diameter natural gas pipeline,
AGDC may use money appropriated for that purpose under
AS 31.25.110 but may not use money appropriated for
the in-state gas pipeline fund in AS31.25.100. This
section removes the description of a large diameter
natural gas pipeline, the 'common' status of pipeline
facilities, and portions of the area description
related to a gas pipeline from the North Slope.
Section 5 amends AS 31.25.100 to direct that money
appropriated to the in-state natural gas pipeline fund
may not be used for the large-diameter natural gas
pipeline project under new AS 31.25.005(4) and (5) and
AS 31.25.080(f).
Section 6 establishes AS 31.25.110, the Large-Diameter
Natural Gas Pipeline Project fund in order to fund the
purposes of the subsidiary established in AS
31.25.122. Money appropriated to the Large- Diameter
Natural Gas Pipeline Project fund may not be used for
the purposes of the in-state natural gas pipeline
under AS 31.25.005(1). Money appropriated to the
Large-Diameter Natural Gas Pipeline Project fund for
the purpose of AS 31.25.005(4) and (5), the large-
diameter natural gas pipeline project, is to be held
in an account created within the fund for that
purpose.
Section 7, related to subsidiaries created under AS
31.25.120 to specify that a subsidiary corporation
under this section may only use money appropriated for
the in-state natural gas pipeline under AS 31.25.100.
9:18:29 AM
Senator Dunleavy wondered if the subsidiary was modeled
after an existing model elsewhere in the world. Mr.
Pawlowski replied that the subsidiary was not modeled after
an existing structure. It was modeled with support from
contract counsel on corporate structures with the
Department of Law (DOL) with specific intent to provide as
bright a line within the Alaska Gasline Development
Corporation (AGDC) as possible. Recognizing that there
would be a discussion with the legislature how the
relationship should be structured for AGDC to fulfill the
mission that the legislature had tasked. He stated that the
AGDC sections understood that the subsidiary was based on
Alaska corporate law.
9:19:28 AM
AT EASE
9:20:16 AM
RECONVENED
Mr. Pawlowski looked at Section 8:
Section 8 adds new section AS 31.25.122 to establish a
subsidiary for a large-diameter natural gas pipeline
project as a public corporation and a government
instrumentality for administrative purposes but with a
legal existence independent from the state and the
AGDC. The purpose of the subsidiary is to acquire
state equity interests in components of a large-
diameter natural gas pipeline project, including
pipelines, treatment, liquefaction and marine terminal
facilities. The subsidiary may use money appropriated
under AS 31.25.110 and may not to use money
appropriated to the in-state natural gas pipeline
project fund in AS 31.25.100. Subsection (b) creates a
seven member board of directors of the subsidiary.
Subsection (d) sets out purposes, (e) allows the AGDC
to transfer assets, except for revenues as restricted
by AS 31.25.100 to the subsidiary created under this
section. Some of the statutory provisions applicable
to the AGDC are incorporated to aid in the operation
of the subsidiary. Subsection (f) relates to employees
of the subsidiary while (g) describes the conditions
of termination of the subsidiary.
Mr. Pawlowski explained Section 9:
Section 9 amends AS 31.25.390(5), the definition of
"in-state natural gas pipeline", by adding a reference
to AS 31.25.005(1).
Mr. Pawlowski looked at Section 10:
Section 10 adds new definitions in AS 31.25.390. New
subsection (7) defines a "large-diameter natural gas
pipeline project" and (8) defines a "subsidiary board"
as meaning a subsidiary under AS 31 25.122.
Mr. Pawlowski explained that the next sections would focus
on the process of the project, rather than the state's
specific involvement.
9:22:55 AM
JOE BALASH, COMMISSIONER, DEPARTMENT OF NATURAL RESOURCES,
(DNR) looked at Section 11:
Section 11 amends the authority of the commissioner of
the Department of Natural Resources (DNR) by adding
new paragraphs (10) - (13) to AS 38.05.020(b).
Effective immediately, the DNR commissioner may enter
into commercial agreements of not more than two years
duration for project services related to the North
Slope natural gas project. In consultation with the
Commissioner of Revenue, the DNR commissioner may
participate in negotiations associated with a North
Slope natural gas project. A contract negotiated in
which the state is a party would not be effective
against the state without legislative authorization
for the governor to execute the contract. Paragraph
(12) permits the DNR commissioner to enter into
confidentiality agreements to maintain confidentiality
throughout contract negotiations and contract
implementation. Confidential information obtained
under paragraph (12) shall be shared with the
legislature only in committees held in executive
session or under confidentiality agreements. Final
contracts subject to approval by the legislature would
not be confidential.
Commissioner Balash looked at Section 12:
Section 12 adds new paragraph (13) to allow the DNR
commissioner, in consultation with the commissioner of
revenue, to take custody of gas delivered to the state
under new AS 43.55.014(b), to manage project services
and the disposition of gas delivered to the state
under new AS 43.55.014(b).
Mr. Pawlowski explained effective dates were often the
reason that a section may seem like a repeat of a previous
section. He stressed that taxation was based on the
calendar year, not the fiscal year.
9:26:15 AM
AT EASE
9:27:01 AM
RECONVENED
Commissioner Balash looked at Section 12, page 15, lines 23
through 26. He stressed that the language was attempting to
ensure that there were no duplicating efforts between DNR
and DOR.
Commissioner Balash explained Section 13:
Section 13 clarifies AS 38.05.180(i) with a conforming
amendment that the exploration incentive credit may be
applied against the oil and gas production tax levied
under AS 43.55.011.
Commissioner Balash looked at Sections 14 and 15:
Sections 14 and 15 adds a new subsection (hh) to the
Alaska Land Act, AS 38.05.180, which deals with oil
and gas leasing, to permit the DNR commissioner to
propose modifications to existing oil and gas leases
relating to the state's ability to take royalty gas in
kind or in value, the establishment of values for the
state's royalty gas and deductions for transportation
costs, and the fixation of royalty rates of not less
than 12.5 percent and modifications to net profit
share terms in oil and gas leases. Modifications to
existing oil and gas leases would require a written
determination by the DNR commissioner that a North
Slope natural gas project has sufficient financial
commitment and commitment of gas from the leases to be
modified, in addition to concurrence of the lessees to
the modification.
Mr. Pawlowski explained that had been some mention of "tax
as gas." The Heads of Agreement (HOA) stated that in
addition to taking royalty in-kind, there would be an
opportunity instead of tax payments for the state to
receive a larger share of the molecules. The legislation
would allow DOR to leverage the expertise and the existing
mechanisms that DNR to dispose of royalty. There was no
desire to recreate a royalty and commercial section in DOR
to handle the molecules that would be received as tax
payments.
Commissioner Balash explained Sections 16 through 19:
Sections 16 through 19 amend AS 38.05.183, related to
sales of royalty oil or gas, by adding references to
gas delivered to the state under AS 43.55.014(b), the
levy of production tax on gas to be paid in gas for
certain North Slope leases.
Commissioner Balash highlighted Section 20:
Section 20 adds two new subsections (26) and (27) in
AS 38.05.965. Subsection (26) defines "North Slope
natural gas project;" subsection (27) defines "project
services."
9:32:32 AM
Mr. Pawlowski shared that the following sections referred
to specifically to tax provisions.
Mr. Pawlowski outlined Section 21 and 22:
Sections 21 and 22 amend AS 40.25.100 related to the
confidentiality of tax information to clearly
establish as confidential information related to
contract negotiations for a North Slope natural gas
project. Section 21 references new subsection (k) in
AS 43.05.230 to except from taxpayer confidentiality
provisions the name of each person that makes an
election to pay the gas production tax from modified
North Slope leases in gas and the amount of gas
subject to that election.
Mr. Pawlowski explained Section 23:
Section 23 amends AS 40.25.120(a) to establish an
exception in public records for information
confidential under the new provisions of AS
38.05.020(b) (related to contract negotiations for a
North Slope natural gas project).
Mr. Pawlowski addressed Sections 24 and 25:
Sections 24 and 25 amend the authority of the
commissioner of the Department of Revenue (DOR) by
adding new paragraphs (16) and (17) in AS 43.05.010.
Effective immediately, paragraph (16) provides that
the DOR commissioner may consult with the DNR
commissioner on negotiations associated with a North
Slope natural gas project. Section 24 amends AS
43.05.010 by adding paragraph (17) to provide that the
DOR commissioner direct the disposition of revenues
received from gas delivered to the state under AS
43.55.014(b) by entering into agreements with the DNR
commissioner.
Mr. Pawlowski outlined Section 26:
Section 26 adds new subsection (k) to AS 43.05.230 to
except from taxpayer confidentiality provisions the
name of each person that makes an election to pay,
after 2022, the gas production tax in gas and the
amount of gas subject to that election.
Mr. Pawlowski discussed Section 27:
Section 27 amends AS 43.20.144(f) to clarify that gas
subject to an election to pay the oil and gas
production tax on gas as gas under AS 43.55.014 is
included the extraction factor in the Alaska Net
Income Tax Act.
Mr. Pawlowski looked at Section 28:
Section 28 amends AS 43.55.011(e), the levy of the oil
and gas production tax, to add reference to the
separate levy under AS 43.55.014 for certain North
Slope gas. For oil and gas produced after January 1,
2014 and before January 1, 2022, AS 43.55.011(e)(2)
would levy on producers of oil and gas produced each
calendar year a flat rate tax of 35 percent of the
production tax value of taxable oil and gas produced
from each lease or property in the state. No change is
made to current tax ceilings that apply to Cook Inlet
oil and gas, gas produced outside the Cook Inlet basin
and used in the state, and oil and gas produced from
new fields outside the Cook Inlet basin and south of
the North Slope. For oil and gas produced on or after
January 1, 2022 (after expiration of the tax ceilings
for Cook Inlet oil and gas, and gas produced outside
the Cook Inlet basin and used in the state), AS
43.55.011(e)(3) would levy on producers of oil
produced each calendar year a flat tax rate of 35
percent of the production tax value of taxable oil
produced from each lease or property in the state and
on producers of gas, and a flat tax rate of 10.5
percent of the gross value at the point of production
of gas produced from each lease or property in the
state. (Oil and gas subject to AS 43.55.011(p)
continue to be taxed at no more than four percent of
gross value at the point of production until 2027.)
The tax on gas for which the DOR commissioner has
approved an election to pay in gas would be levied
under AS 43.55.014.
9:38:57 AM
Mr. Pawlowski outlined Section 29:
Section 29 amends AS 43.55.011(f), the alternate
minimum tax on North Slope oil and gas, to retain the
current minimum tax until January 1, 2022. After that
date, the minimum tax would apply to oil produced on
the North Slope. A minor amendment adds the reference
to the tax applying to leases or properties "that
include land" to ensure that property that straddles
68 degrees North latitude will be considered north of
68 degrees North latitude for purpose of the alternate
minimum tax.
Co-Chair Kelly asked for clarification of page 27, line 14.
Mr. Pawlowski responded it was in Section 29, and stated
the minimum tax on oil after January 1, 2022, because there
was a "carving out" of a minimum tax that was higher than
the 4 percent.
Mr. Pawlowski addressed Section 30:
Section 30 adds AS 43.55.014 which allows producers to
make an irrevocable election, under regulations
adopted by DOR, to pay the oil and gas production tax
in gas for gas produced from oil and gas leases whose
terms have been modified under proposed AS
38.05.180(hh).
9:43:38 AM
AT EASE
9:46:26 AM
RECONVENED
Mr. Pawlowski continued to discuss Section 30:
The levy would be 10.5 percent of the taxable gas when
and as the gas is produced. The producer would pay the
tax by delivering the gas to the state at the point of
production. The DNR would manage the custody and
disposition of gas delivered to the state. Gas subject
to this provision would not include gas flared,
released, or allowed to escape upstream of the point
of production, or to gas used in lease operations or
for repressuring. Tax deficiencies and interest and
penalties on any tax deficiency would be accounted for
as if the tax was levied for money under AS
43.55.011(e). This section would take effect on
January 1, 2015 to be applied to gas produced from
certain North Slope leases on and after January 1,
2022.
Mr. Pawlowski discussed Sections 31 and 32:
Sections 31 and 32 are conforming amendments to the
oil and gas producer education credit, AS 43.55.019,
to clarify that the credit can be applied to tax
liability under AS 43.55.011(e) only.
Commissioner Balash explained the construct was for the
state to participate in the project and take a share of the
gas. He stated that the gas was needed in order to run the
state's share of the infrastructure. There were contracts
with providers, so it was important to maintain consistent
and predictable gas production throughput.
Mr. Pawlowski spoke to Section 33:
Section 33 amends AS 43.55.020(a), monthly installment
payments of estimated tax, to add provisions for
payment of tax after January 1, 2022 and to clarify
the tax rates that apply to oil and gas produced after
a certain date. Monthly installment payments for oil
and gas produced on or after January 1, 2022 are in
new subsection (a)(7).
Mr. Pawlowski explained Sections 34 and 35:
Sections 34 and 35 are conforming changes to AS
43.55.020, monthly installment payments. Subsection
(g) is amended to account for new tax provisions for
oil and gas produced after January 1, 2022. A similar
conforming change is made in AS 43.55.020(h) to
account for interest on overpayments of installment
payments.
9:51:07 AM
Mr. Pawlowski addressed Sections 36 and 37:
Sections 36 and 37 amends AS 43.55.020(l) and adds
subsection (m), related to making settlements by a
producer with private landowner royalty owner, to
account for making a settlement with the royalty owner
for gas taxable before January 1, 2022 and under new
AS 43.55.014.
Mr. Pawlowski highlighted Section 38:
Section 38 amends AS 43.55.030, annual statements by
producers and explorers, to require reporting of the
amount of gas produced from a lease or property for
which tax is levied under AS 43.55.014 and the amount
of gas delivered to the state under AS 43.55.014.
Mr. Pawlowski discussed Section 39:
Section 39 amends AS 43.55.160(a), calculation of
annual production tax values, to clarify and conform
to the levy of tax under AS 43.55.011(e)(2) for oil
and gas produced before January 1, 2022.
Mr. Pawlowski outlined Section 40:
Section 40 amends AS 43.55.160(e), related to
determination of excess lease expenditures for the
purpose of calculating a carried-forward loss credit,
to account for annual production tax values for oil
produced on and after January 1, 2022.
Mr. Pawlowski looked at Section 41:
Section 41 amends AS 43.55.160(f), a 20 percent gross
value reduction for certain oil and gas produced north
of 68 degrees North latitude, so that gas produced on
and after January 1, 2022 would not qualify for the
gross value reduction in this section.
Mr. Pawlowski discussed Section 42:
Section 42 amends AS 43.55.160(g), a 10 percent gross
value reduction for certain oil and gas produced from
a unit north of 68 degrees North latitude made up
solely of leases that have a royalty share of more
than 12.5 percent in amount or value of the production
removed or sold from the lease so that gas produced on
and after January 1, 2022 would not qualify for the
gross value reduction in this section.
Mr. Pawlowski highlighted Section 43:
Section 43 amends AS 43.55.160, calculation of annual
production tax values, to add a new subsection (h) for
calculation of annual production tax values for oil
produced on and after January 1, 2022. On and after
January 1, 2022, gas would be taxed at a percentage of
gross value. Accordingly, there would be no need to
calculate a production tax value (gross value at point
of production less lease expenditures) for gas.
Producers would still calculate a production tax value
of oil taxable under AS 43.55.011(e) for the segments
set out in AS 43.55.160(h).
Mr. Pawlowski explained Section 44:
Section 44 makes a conforming amendment to AS
43.55.165, lease expenditures, to exclude as a
deduction from lease expenditures the tax levied under
AS 43.55.014.
Mr. Pawlowski discussed Sections 45 through 47:
Sections 45 through 47 amend, for purposes of the oil
and gas production tax, the definitions of "gas
processing plants" and "point of production" for gas
to be upstream of either the first point where
accurately measured, the inlet of a pipeline
transporting the gas to a gas treatment plant, or the
inlet of any gas pipeline system transporting gas to
market. Section 46 adds a definition of "gas treatment
plant".
Co-Chair Kelly asked what section was currently being
discussed. Mr. Pawlowski stated that he was broadly
speaking to Section 45.
9:58:40 AM
Mr. Pawlowski outlined Section 48:
Section 48 makes conforming amendments to AS
43.98.030, the film production tax credit, to limit
the applicability of the credit to the tax levied by
AS 43.55.011.
Mr. Pawlowski spoke to Section 49:
Section 49 amends uncodified law to add a new section
related to direction that at the time the commissioner
of natural resources submits the first contract to the
legislature for approval, the commissioner of revenue
shall present a plan and suggested legislation to
allow a resident of the state to participate as a co-
owner in a North Slope natural gas pipeline, and sets
out factors that must be in the plan.
Mr. Pawlowski outlined Section 50:
Section 50 allows the DNR and the DOR to adopt
regulations to implement this Act.
Mr. Pawlowski explained Section 51:
Section 51 instructs the reviser of statutes to make a
title change to AS 38.05.183 to include AS
43.55.014(b).
Mr. Pawlowski discussed Sections 52 and 53:
Sections 52 and 53 set effective dates for different
sections of the bill. Sections 1 -10, 12, 13 19, 20,
22, 23, 30, 31, 47 and 48 would be effective
immediately. The other sections would be effective
January 1, 2015.
10:00:58 AM
Co-Chair Meyer wondered if the state received 10 percent of
the gas that was produced on federal land. Mr. Pawlowski
replied that the tax for that gas would be 10.5 percent of
the gross value of that gas.
Co-Chair Meyer queried the federal take of the gas. Mr.
Pawlowski responded that he did not know the specific
royalties of the federal take, but shared that the federal
government received corporate income tax.
Co-Chair Meyer wondered if there would be problems
administering the public management. Mr. Pawlowski replied
that the provision in the legislation was uncodified
direction to DOR to manage those issues. He felt that there
may or may not be an administrative burden. He stressed
that it would not be determined until the work was
complete. He felt that the provision allowed for DOR to
conduct the due diligence in order to determine the
possibility of the management.
10:02:58 AM
Vice-Chair Fairclough noted that there had some
conversation about the subsidiary. She referred to the
Denali Project, and remarked that there was a partnership.
She wondered why AGDC was not considered a subsidiary. Mr.
Pawlowski replied that the administration looked at the HOA
as a proposal. He stressed that there was a focus on how
the stated participated in the project. He stated that the
pipeline was in recognition that AGDC was required by
statute to develop a standalone pipeline.
Vice-Chair Fairclough surmised that attorneys would be
evaluating those proposals. She looked at Section 13, and
queried the maximum credit that could be obtained at that
allowance. Commissioner Balash replied that the credit was
considered a DNR credit.
Mr. Pawlowski looked at page 16, line 5 and remarked that
the credit may not exceed 50 percent of the cost of the
drilling or geophysical work. Additionally, on page 16,
line 9 stated that the credit may not exceed 50 percent of
the payment. Therefore, one could only offset 50 percent of
the tax payment.
10:08:47 AM
Vice-Chair Fairclough wondered if there was a cap on the
credits that were taken against the oil revenues. Mr.
Pawlowski replied that he would provide more information
about the state's credit system. He furthered that the
state had many different credit provisions, and each one
may have specific limitations.
Vice-Chair Fairclough stressed that she was concerned about
returning value to the people of Alaska for participation
in the process. She wanted to ensure the best partnership
in a commercial relationship. She understood that gas was
used to run the oil producing facilities, and was not
calculated in a tariff. Mr. Pawlowski agreed.
Vice-Chair Fairclough surmised that the best practice for
gas production was receiving 25 percent value and 25
percent expense in a full partner in the commercial
relationship. She wondered if it was wise to allow
monetization of upstream gas on the downstream, but not
have it count in the project. Mr. Pawlowski responded that
Section 30 of the legislation addressed that issue.
Vice-Chair Fairclough agreed and added Section 43 also
addressed a similar issue, which dealt with lease
expenditures not counted as oil or gas. Mr. Pawlowski
agreed, and felt that Section 30 addressed more of her
concerns. He stated that the key difference was 10.5
percent of the gas produced at the point of production. He
stated that it was included to recognize that there was gas
used in the project as fuel for running the oil facilities.
A gross value calculation would have deducted the fuel
expenses. He stated that DOR wanted to ensure that the
state had the full molecules on the downstream side. He
explained that the upstream use was meant for molecules to
run the power and lifting the oil as part of normal oil
field operations. Development of the in kind provision was
careful to state that it was 10.5 percent of the gas
produced at the point of production, so DOR would not
undercount the molecules that the state was entitled to
meet its share of fuel cost and movement in the project.
Vice-Chair Fairclough perceived that if there was a penalty
or dispute, the interest would not be in molecules, but
rather be in cash. Mr. Pawlowski responded that the
provision was on page 28, line 18, and agreed that the
deficiency would be in cash.
Vice-Chair Fairclough understood that Commissioner Balash
said that the state must maintain its throughput of gas
moving through the line to protect the state's interests.
She wondered if the reason for taking the gas in kind
rather than in value at the point of sale was because, as a
full commercial partner, the state would carry the expenses
of the entire project. The state must ensure that the
throughput was high, so it would receive the maximum
benefit of being a full partner. If the state's percentage
of gas dropped below its ownership equity interests, the
state would carry a different burden of those expenses
because it did not receive the full value of what was
moving through the line. Commissioner Balash responded that
the HOA spoke to the offtake and balancing agreements that
were necessary for DOR and DNR to be comfortable entering
into those project services agreements downstream for all
facilitations. He stressed that the state would be seeking
its own certainty, in order to ensure that it could deliver
on the obligations to customers and citizens.
10:17:09 AM
Vice-Chair Fairclough surmised that Alaska would attempt to
hire someone to manage and purchase the throughput. Mr.
Pawlowski replied that the state would need certainty for
the gas coming into the project, and it would need
certainty for the LNG leaving the project. He stressed that
both ends of the equation was necessary.
Vice-Chair Fairclough felt that there could be a perception
in a few years about the energy company partners making
more money than Alaska. The perception may be a result of
the attempt to bring affordable to energy Alaskans. She
stressed that the partners were global organizations that
did not necessarily report profits in the same way that the
state reported profits inside of revenue books. Mr.
Pawlowski responded that her summation was very accurate.
Senator Bishop was not convinced that AGDC should be
considered a subsidiary. He felt that there should be
further analysis of the necessity of having AGDC as a
subsidiary. He felt that there needed to be extremely
qualified people to be a part of the board and run AGDC. He
stressed that there were a limited number of qualified
people in the state.
Senator Dunleavy wondered if it would be an all or nothing
proposal when the offtake and balancing agreements were
presented to the legislature. Commissioner Balash responded
that the interdependencies of all of the agreements would
be such that it would be difficult to modify an aspect of
one agreement, and not have it impact another agreement.
The expectation was that the contracts that would come back
to the legislature would look similar to the royalty sale
contracts.
10:23:23 AM
Senator Dunleavy surmised that the committee should not
consider amendments. Mr. Pawlowski responded that the
ultimate contract vote was taken differently than a bill
vote. The opportunity for legislative engagement was not at
the end of the process, and felt that interaction with the
legislature was imperative in the executive sessions.
Senator Olson remarked that there was a concern of the
North Slope Borough and other boroughs regarding what would
happen in the future. He did not see any provision giving
those boroughs satisfaction and stability. He felt that
those boroughs should be consulted regarding their real
estate taxing status. He wondered if there could be a
definition of the consultation, so those communities could
be comfortable with the legislation. Mr. Pawlowski replied
that when the administration and the companies engaged in
the development of the HOA, it was a problem solving
exercise. He stated that there were certain problems that
were not the responsibility of the parties involved in the
HOA. He stated that property tax was provided by the
legislature and local governments.
Senator Olson wondered if there would be opposition to an
amendment that would further define consolation with
municipalities. Mr. Pawlowski responded that DOR would be
open to discussion regarding that issue.
10:27:40 AM
AT EASE
10:41:26 AM
RECONVENED
10:41:45 AM
AT EASE
10:41:59 AM
RECONVENED
10:42:07 AM
^PRESENTATION: DECISIONS, ALIGNMENT, PRICE, COST and RISK
10:42:20 AM
JANAK MAYER, PARTNER, ENALYTICA, discussed the PowerPoint,
"In Kind vs. in Value, Risks and Midstream Options" (copy
on file). He stated that there was an attempt to provide a
high level overview the week prior, of some of the key
issues that the legislature needed in order to consider the
legislation. There was a discussion regarding some of the
questions associated with the choice of the state as a
taxing authority that took royalty and tax at the well
head, and the issues of the overwhelming value of the
project consumed at the midstream, leaving a relatively low
residual value at the well head. He felt that the state
might want to consider participating more broadly across
the value chain.
Mr. Mayer highlighted slide 4, "In Kind Vs. in Value:
Project Options." He stated that the slide reflected the
world of the HOA. It contrasted the status quo, of the
state taking value through the royalty and taxing with a
profit based production tax with value at the well head. It
was contributing to upstream costs solely and directly
through taxes and/or deductions in taxes and credits at the
well head, but had no share of the subsequent gas treatment
facility, pipeline, and liquefaction project. The state did
not have to take on any debt to finance any commitment,
because it did not have to contribute any of the capital
cost of the facilities. He stated that the slide also dealt
with the issue of the question of the tariff, subsequently
on the entirety of the midstream - gas treatment
processing, pipeline, and liquefaction. Those processes
were crucial to the question of how much residual value, if
any, there was for the state to tax at the well head. He
stated that the slide conversely envisioned the end point
of the HOA process, if the HOA could be successfully
negotiated. The state would define a share of gas that it
took through royalty and the growth production taken
instead as gas instead of tax, where it had defined a share
of ownership in the entirety of the midstream
10:49:22 AM
Mr. Mayer discussed slide 5, "RIV: Upstream Absorbs All the
Price Risk, Fixed nature of tariff in 'in value'
alternative amplifies impact of price movement on state
returns." He stated that the slide was a graphical version
of some slides from the Revenue Sources Book calculation in
the previous presentation. If the state was simply a taxing
authority, that took its royalty in value and took
production tax on a profit base, the state would, counter-
intuitively, become a "shock absorber." He stated that the
slide would show how the state should not be fully in and
transparent. He stressed that there was a large fixed
tariff payment, which was a very large portion of the total
value. He stated that the graph showed a barrel of oil
(BOE) equivalent terms and in corresponding dollar per BTU
terms to an LNG form delivered to an Asian market. He
stated that, when prices were high, there would be a higher
net price of oil, because LNG was priced at a discounted
relationship to oil.
10:52:33 AM
Mr. Mayer looked at slide 6, "'In Kind' with Equity Offers
More Downside Protection, 'In value' structure protects
producers, not sate, in low price environment because of
tariff component, Higher State of Alaska (SOA) equity
pushes up the price at which 'in value' is better than
equity." If one took slide 5's understanding and looked at
more results of what he saw as the overall assumptions
through an economic model through a lifetime of a project.
He felt that the slide reflected the outcomes of the
choices that the state faced about the value that it could
receive from the project through different modes of
participation, either as a taxing entity or as an in kind
participant. The green line was the accrued value in terms
of cumulative cash flows over the life of the project. If
all of the off tax cash flows that would come from the
project, the graphs showed what it would look like for each
participant. The left graph was the state of Alaska, the
middle was the producers, and the right graph was the
federal government. The Y-axis was the total cash flow
value across time to each party, and the X-axis was the
price of LNG delivered into Asia on a scale from $10/MMBTU
to $18/MMBTU. He stated that the slope of the green line of
the left chart was a much deeper slope. He stressed that
the state would have the greatest share of price risk in
the status quo in value scenario, because so much value
could disappear at the well head when prices decline due to
the fixed tariff that applied to the gas treatment,
pipeline, and liquefaction. The red and yellow lines
represented the world of in kind participation. The red
line represented a 20 percent share, and the yellow line
represented a 25 percent share. It showed that, at high
prices, the state was not as well off as it would be in an
in value world. Conversely, at low prices, the state was
substantially better. He remarked that in kind
participation protected the state better from price risk
than in value participation, because of the intuition in
the previous slide.
10:57:26 AM
Mr. Mayer explained slide 7, "SOA Share of value Higher
than Equity Share, SOA participation in midstream means
fixed tariff for producers no longer 'guaranteed'." He
stated that it was easy to look at the state bearing 25
percent of the cost, if the state had 25 percent of the
cost, and therefore the state had 25 percent of the overall
value that the project created. He stressed that that
assumption was not accurate. He pointed out that the state
would take much more than 25 percent in most circumstances.
The slide showed the net present value of those same cash
flows over the life of the project, and looked at the total
economic value accrual on a percentage basis. He pointed
out that in all cases, there was substantially more than 25
percent at the total value going to the state of Alaska. HE
stressed that there was a focus of a range from 30 to 50
percent depending. The state would have the highest share
of value in the lowest prices and would fall at higher
prices in-kind scenario. The in value scenario reflected an
opposite outcome for the state.
Mr. Mayer highlighted slide 8, "SOA Equity Leads to higher
Government take on Average; 'In value' entails lowest
government take, especially in low prices as cash goes to
producers; Split between Fed vs. SOA split depends on both
'in value vs. 'in kind' as well as SOA equity share." The
state showed the same figures in cumulative cash flows over
the life of the project in terms of the share going to the
state, producer, and federal government in the three
different scenarios: in value, 20 percent equity, and 25
percent equity.
Co-Chair Kelly handed the gavel to Co-Chair Meyer.
11:03:16 AM
Senator Bishop looked at the left column, and noted that it
showed 50 percent in value total government take between
the green and yellow bars. Mr. Mayer agreed, and stated
that it was at the lower price levels, but rose to the mid-
fifties at the higher levels.
Senator Bishop wondered if there could be a reflection of
the cash returned to the state, if there was an assigned
cash value. Mr. Mayer remarked that one should not look at
the sum of the green and yellow bars, but rather the take
to the state of Alaska. He remarked that there would be a
dramatic drop at lower price levels, and it was taken by
the federal government. He stressed that the state was
taking most of its value from taxing at the well head, but
the federal government was taxing at the entire value
stream.
Co-Chair Meyer handed the gavel to Co-Chair Kelly.
11:06:27 AM
Co-Chair Meyer looked at the price per BTU starting at $10,
but there were other contracts that were below $10. He
wondered why that was the case.
NIKOS TSAFOS, PARTNER, ENALYTICA, responded that, looking
at gas pricing, North America had some of the lowest gas
prices in the world. He stated that Europe was somewhere in
the middle, with pricing of between $9 to $12. Asia was
fairly high, with pricing near between $13 to 16. He
announced that there were some slides later in the
presentation that dealt with the structure of pricing.
Co-Chair Meyer felt that there should be a worst case
scenario represented in the presentation. He wondered if
the supply of gas was becoming more plentiful, so he
wondered if there would be more downward pressure put on
the prices rather than the upward price. Mr. Tsafos replied
that a worst case scenario would be beneficial to the
analysis. He stated that there could be a point where the
project was built, and the day the project goes online when
the prices would be much lower than expected. He agreed to
provide a worst case scenario analysis.
Co-Chair Meyer expressed concern with Russia, and their
aggressive low-rate contract acceptance. Mr. Tsafos replied
that Russia was not going to "under cut" Alaska, because
Russia had a very high cost structure do to environmental
and technical issues bringing the gas to market.
11:12:17 AM
Vice-Chair Fairclough remarked that Alaska had participated
in many different oil tax regimes, so as the worst case
scenarios were modeled, she stressed that there would not
be final investment decisions until the contracts were
signed. Mr. Tsafos agreed, and furthered that there would
be a slide related to how the state could contractually
protect itself from adverse effects.
Vice-Chair Fairclough looked at the bars on slide 8; it
appears that the producers make more than the state. She
felt that the producers should be reflected as three
different companies. Mr. Mayer agreed that the red bars
were the combination of three companies.
Mr. Mayer addressed slide 9, "Equity Boosts SOA Outlays to
$10.2 billion to $12.3 billion; Annual outlays could peak
at $2.7 billion (20 percent equity) to $3.3 billion (25
percent equity), assuming no debt; Even in status quo ('in
value'), state has outlays through the tax system." The HOA
set out a possibility of a total state share.
11:20:16 AM
Mr. Tsafos explained slide 10, "Price and Cost Risks; Cost
Escalation/Delays." When the state takes equity, it
functions like an oil and gas company. The slide was meant
to identify what could go wrong in the equity world. It
showed a list of LNG projects that were developed over the
previous decade, and what kind of delays they faced.
Mr. Tsafos discussed slide 11, "Buyers Often Take Equity in
LNG Projects."
In half of the world's LNG capacity, a share of the
LNG is sold to equity partners
Such deals can mitigate risk by aligning supplier -
buyer interest (e.g. output shortfall)
Buyers get sense of supply security, and these deals
often open up the project to third-party financing
Mr. Tsafos spoke to slide 12, "Project Finance Well
Established in LNG."
IHS estimates that LNG projects raised over $97
billion in third-party financing since 2000
Financing from project sponsors, export credit
agencies, multilateral banks and commercial banks
Commercial loans can also secure sovereign guarantees
as insurance
The Japan Bank of International Cooperation (JBIC) is
the largest single provider of funds
11:24:35 AM
Mr. Tsafos highlighted slide 13, "SOA Cash Call $4.8
billion - $5.5 billion with 70/30 debt/equity; Peak outlays
shrink to $1.2 to $1.3 billion depending on equity level
(20 percent or 25 percent)." He stated that the slide
compared a world along standard practice in LNG, which
showed that the peak outlays may be closer to $1.5 billion.
He remarked that the slide was not intended to downplay the
state commitment, but to take the overarching number and
qualify it based on standard industry practices.
Vice-Chair Fairclough referred to a presentation that
discussed a pipeline structure. She wondered if the 70/30
debt/equity was the best option for Alaska. Mr. Mayer
replied that it was important to differentiate between
capital structures for the purpose of tariff setting versus
capital structures for the state's share and how it chooses
to finance its obligations. Capital structures for rate
setting were reflective of the actual capital structure
underlying the project. He furthered that there was some
regulatory legal fiction that stated that regardless of the
actual capital structure, it would be treated as though it
was the set tariff. He stated that the MOU showed that
there was an assumption that started with the cost of debt
was 5 percent, cost of equity was 12 percent, and there
would be a capital structure of 75/25 percent split. As a
result, there would be a higher leverage with a lower
tariff from the state's perspective.
11:29:51 AM
AT EASE
11:30:07 AM
RECONVENED
11:30:45 AM
RECESS
5:05:20 PM
RECONVENED
Mr. Tsafos addressed slide 14, "Price Exposure Defined at
Contract Signing."
Oil linkage does not mean identical linkage to oil
(e.g. Taiwan, below); bargaining power defines linkage
New contracts do not impact existing deals (e.g. new
Henry Hub-based LNG vs. existing oil-linked SPAs)
But if price is seriously out of sync with
fundamentals, parties can trigger a review clause
Mr. Tsafos explained slide 15, "Expensive Projects can
Hedge Against Volatility."
"S-curves" are clauses that change the relationship
between oil and gas above or below thresholds
Instead of a linear link, gas prices do not rise/fall
as much if oil prices rise/fall above certain
thresholds
They reduce downside risk by forgoing some upside-they
can even provide a floor/ceiling on prices
5:16:09 PM
Mr. Tsafos looked at slide 16, "Midstream Options: Project
Structure." The slide was a simplification of the project,
breaking it into four components. He stated that there was
a status quo, HOA, MOU Option 1, and MOU Option 2. The
status quo was in value and the state had no ownership in
the facilities. The state took no debt, and there was a
tariff to haggle over matters of valuation. The HOA changed
in value to in kind, but not definitively. The HOA took the
GTP and LNG ownership from zero to 25 percent. Because
there was an ownership interest in the first column of
upstream GTP and LNG, the state was required to invest to
correspond with the equity. The MOU contemplated two
different options, but the in kind, up stream, and LNG
ownership stayed the same. The only thing that changed was
the ownership of the GTP, treatment plan, and the pipeline.
There were two options. The state had a starting point of
25 percent, and the 25 percent would be moved to
TransCanada. Therefore, TransCanada was responsible for
paying for the 25 percent of the costs of the studies that
were linked to the GTP and pipeline. There was an option to
buy back, so consider staying with zero or buy back a share
of the equity.
Mr. Tsafos explained slide 17, "Midstream Options:
Options." He remarked that there was an analysis necessary
to understand that there was gas in the North Slope and the
gas should be brought to market. A liquefaction plant
needed to be constructed. He stated that there were,
broadly speaking, four ways to structure the midstream, and
they were displayed on the slide.
5:23:25 PM
Mr. Tsafos discussed slide 18, "Midstream Options: State
Interests."
Producer-SOA Alignment
Minimize disputes over where value is allocated
Tariffs reflect value maximization across the
entire chain
Third-Party Expansion
Midstream becomes an enabler for further
exploration and development
Expansion principles favor development of
additional transportation capacity
In-state Deliveries
Alaskan consumers receive cost at the lowest cost
possible (given adequate
returns on investment)
Execution Pipeline is delivered on time and at
the lowest possible cost
Continuity and Momentum
Project maintains and accelerates current
investment interest
Project leverages work to date and is not delayed
by possible litigation
Mr. Tsafos displayed slide 19, "Producer Only: Alignment."
Producer-SOA Alignment
Significant potential for disputes over
allocation of value, and optimal level for
midstream tariff
Third-Party Expansion
Focus on commercializing producers' resources
over gas belonging to third parties
In-state Deliveries
Uncertain tariff for in-state deliveries (of
SOA's gas)
Execution
Strong and proven ability to execute, but
midstream becoming less of a core focus for
majors
Continuity and Momentum
Uncertainty about possibility of litigation and
loss of work done to date
Mr. Tsafos explained slide 20, "SOA Equity: More Expansion
Bias but Burdon on SOA."
Producer-SOA
Alignment Strong alignment between producers and
SOA
Third-Party Expansion
Relies on SOA to drive expansions, seeking new
entrants and / or new partners; SOA may not be
best placed to fill this role
In-state
Deliveries SOA can use its equity-entitled
capacity to carry gas to local markets at lower
cost
Execution
Strong and proven ability to execute for initial
investment; expansion will depend on securing
capabilities and/or another party
Continuity and Momentum
Uncertainty about possibility of litigation and
loss of work done to date
Co-Chair Kelly handed the gavel to Co-Chair Meyer.
5:27:54 PM
Mr. Tsafos looked at slide 21, "MOW: expansion Bias and
Momentum; Bus Best Deal?"
Producer-SOA Alignment
Strong alignment between producers and SOA;
capital structure for rate-setting purposes
appears within norm, but unclear if new bidding
could have produced lower tariff
Third-Party Expansion
TransCanada will be advocate for a project
structure that encourages expansion and will have
incentive to drive expansion of the
infrastructure based on market interest
In-state Deliveries
SOA can use its equity-entitled capacity to carry
gas to local markets at lower cost; proexpansion
bias further incentivizes possible in-state
deliveries
Execution
TransCanada brings execution knowhow and
expertise, while producers reinforce cost
discipline (to ensure lowest possible tariff)
Continuity and Momentum
Project maintains and accelerates investment
interest and leverages work done to date
5:31:08 PM
Mr. Tsafos discussed slide 22, "Bid: Will Reward Compensate
for Cost in Time and Money?"
Producer-SOA Alignment
Strong alignment between producers and SOA; new
bid could lead to a lower tariff, but it could
also lead to a higher one; low investor interest
could also slow down entire process
Third-Party Expansion
Third party will have incentive to drive
expansion of the infrastructure based on market
interest, but would likely have less influence
over current negotiations
In-state Deliveries
SOA can use its equity-entitled capacity to carry
gas to local markets at lower cost; proexpansion
bias further incentivizes possible in-state
deliveries
Execution
Third party would presumably bring execution
knowhow and expertise, while producers would
reinforce cost discipline (to ensure lowest
possible tariff)
Continuity and Momentum
Uncertainty about possibility of litigation and
loss of work done to date; HOA negotiations could
slow down in anticipation of new bidding process
and license award
Mr. Tsafos explained slide 23, "SOA Needs to Carefully
Weigh Key Questions."
What compensation might the SOA have to pay and what
intellectual property will Alaska LNG retain?
Will the HOA process slow down if the midstream is
tied in litigation?
What are the odds that a new selection process will
deliver better terms than those available today?
To what extent was the AGIA process representative of
the industry's interest in an Alaskan pipeline?
Would a new tariff offset absence from negotiating
table; reduced momentum; cost to dissolve AGIA?
Mr. Tsafos highlighted slide 24, "Financially, TransCanada
Deal is Akin to a Loan."
TransCanada shoulders a share of SOA's capital
commitments and Alaska repays over time with tariff
SOA outlays fall by $1,700 million (no buyback) to $1
billion (buyback) during development period
Mr. Tsafos explained slide 25, "TransCanada Lowers SOA
Outlays by $3 billion to $5 billion."
TransCanada's participation would lower SOA peak
outlays by $0.8 billion to $1.4 billion
Buyback option also lowers outlays before FID (pre-
2019)
5:44:05 PM
Co-Chair Meyer wondered what it would look like if
TransCanada was not involved, and it was only the three
producers and the state of Alaska, with one of the
producers building the pipeline. Mr. Tsafos responded with
slide 20. He stressed that the producers were in the
business of finding and developing oil and gas. The
infrastructure was generally seen as what the facilities do
to find and produce oil and gas. TransCanada was in the
business of building pipelines.
Co-Chair Meyer wondered if there may be more motivation to
get more involvement in the pipeline, if a producer owned
the pipeline. Mr. Tsafos responded that a producer built a
pipeline with a great capacity, but only used a limited
amount of the space, one could approach the producer to use
the spare capacity and the producer could make that
allowance.
5:50:26 PM
Mr. Mayer furthered that financially, the deal was
equivalent to a 7 percent interest loan. The state would
put up less capital and take slightly less of the
subsequent cash flows, because it needed to pay the tariff
to TransCanada. If there were no other benefits of
TransCanada's involvement, one may look at it and believe
that it was an expensive loan, because the state could
raise the capital more cheaply. He stated that one of the
benefits was that it is not a loan that the state would
carry on its balance sheet, so the overall calculation
would be considered based on many factors. He stressed that
there were considerations regarding expansion orientations
that were possible with the contract with TransCanada. It
could be argued that the state had a strong pro-expansion
orientation. He felt that the question was how much the
state wants to or thinks it is capable of becoming an
effective pipeline company. He stated that the current
issues were different for the pipeline and GTP than they
were for the liquefaction. He felt that the differentiation
was essential to determine where the third party
involvement would be in the different components of the
project.
5:55:04 PM
Co-Chair Meyer surmised that a partnership with TransCanada
may encourage expansion of the project in the future. He
wondered if RCE oversaw the expansion. Mr. Mayer deferred
to the administration for regulatory information. He
stressed that that MOU would codify in contract the actual
capital structure.
Vice-Chair Fairclough had a constituent that had concerns
regarding whether or not gas could be committed to the
project. She hoped that there would be an opportunity to
present the available of gas when the project goes online
for production. She shared that Larry Persily had contacted
her office regarding the federal guarantee. The federal
guarantee was for a North American project specifically. It
was his estimation that congress would probably not be
amenable to help the state move the gas to another country.
Co-Chair Meyer looked at the "TransCanada Capital Project
Performance" (copy on file). He stated that TransCanada's
history was substantial and impressive.
Vice-Chair Fairclough remarked that TransCanada was the
only North American pipeline company that had worked in the
Arctic.
Co-Chair Meyer pointed out that their history seemed very
impressive.
Vice-Chair Fairclough remarked that the federal government
may have some issues regarding the cost overruns of
TransCanada and the Keystone project.
SB 138 was HEARD and HELD in committee for further
consideration.
| Document Name | Date/Time | Subjects |
|---|---|---|
| 022714 SFIN, enalytica, Feb 27.pdf |
SFIN 2/27/2014 9:00:00 AM |
SB 138 |
| CSSB138(RES) Sectional Analysis Version O.pdf |
SFIN 2/27/2014 9:00:00 AM |
SB 138 |
| CSSB138(RES) Summary of Changes.pdf |
SFIN 2/27/2014 9:00:00 AM |
SB 138 |
| 022714 TransCanada Capital Project Performance.pdf |
SFIN 2/27/2014 9:00:00 AM |
SB 138 |