Legislature(2015 - 2016)SENATE FINANCE 532
04/14/2016 05:00 PM Senate FINANCE
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| Audio | Topic |
|---|---|
| Start | |
| SB130 | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| += | SB 130 | TELECONFERENCED | |
| += | HB 247 | TELECONFERENCED | |
| + | TELECONFERENCED | ||
| + | TELECONFERENCED |
SENATE BILL NO. 130
"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."
5:35:01 PM
KEN ALPER, DIRECTOR, TAX DIVISION, DEPARTMENT OF REVENUE,
noted the two documents, "Oil and Gas Tax Credit Reform -
CSSB 130(RES)" (copy on file), and "Sectional Analysis, CS
SB 130(RES)\H: Oil and Gas Tax Credit Reform Bill, April,
13, 2016".
He turned to Slide 3 of the presentation, "Oil and Gas Tax
Credit Reform - CSSB 130(RES) ":
FY 2007 thru 2015, $7.4 Billion in Credits
North Slope
o $4.3 billion credits against tax liability
ƒMajor producers; mostly 20% capital
credit in ACES and per-taxable-barrel
credit in SB21
o $2.1 billion refunded credits
ƒNew producers and explorers developing
new fields
Non-North Slope (Cook Inlet & Middle Earth)
o $100 million credits against tax liability
ƒAnother $500 to $800 million Cook Inlet
tax reductions
ƒ(through 2013) due to the tax cap still
tied to ELF
o $900 million refunded credits (most since
2013)
Mr. Alper turned to Slide four, which detailed historic
credits compared to revenue during the period of FY 07
through FY 15:
Total Petroleum Revenue FY 2007 thru 2015
North Slope
Production Tax - $32.8 billion
Royalties (unrestricted) - $15.0 billion
Other GF Revenue - $4.7 billion
Restricted Revenue - $8.7 billion
Total - $61.1 billion
Non-North Slope (Cook Inlet & Middle Earth)
Production Tax - <$0.1 billion
Royalties (unrestricted) - $0.5 billion
Other GF Revenue - $0.3 billion
Restricted Revenue - $0.2 billion
Total - $1.0 billion
5:37:14 PM
Mr. Alper noted that the $2.1 billion had been refunded to
producers in the form of tax credits; additionally, the
$4.3 billion received by the major producers had been in
addition to the $61.1 billion as reflected on the slide. He
highlighted that the production tax in Cook Inlet had been
di minims over the 9 fiscal years.
5:38:07 PM
Mr. Alper showed Slide 5, "Historic Credits compared to
Revenue", which offered a data set between 2007 and 2015.
He related that the Cook Inlet numbers had increased
dramatically after the passage of the Cook Inlet Recovery
Act, with the biggest numbers occurring in FY 14 and FY 15,
and continuing into FY 16.
5:38:45 PM
Mr. Alper discussed Slide 6, "Historic and Forecasted O&G
Revenue and Tax Credits." He noted that the slide showed
the FY 15, FY 16, and FY 17 data set for total unrestricted
petroleum revenue. The left side of the slide offered
historical and forecasted numbers for petroleum revenues
before and net of returnable credits. The right side of the
slide included unrestricted petroleum revenue after credits
used against tax liability and a blue line indicating net
operating loss credits (NOL) end-of-year balance. He noted
that as revenue had declined the system had been
overwhelmed by credits, which meant that the state was
paying a lot out in credits without the revenue to support
the payments. He added that the forecasted revenue
reflected weak general fund numbers. He said that the NOL
credits worked as a sort of bank account for companies; the
state would have to pay back the credits as prices went up.
He stated that although the price of oil was projected to
rise within the next five years, the state would not
experience any boost in production tax revenue because the
state would be buying down those NOL credits.
5:40:49 PM
Senator Bishop asked whether the reigning in of spending by
companies would affect future NOLs.
Mr. Alper replied that the numbers were tied to the price
of oil. He said that anything that companies did to ratchet
back capital spending would lower their break-even point
and eliminate the NOLs.
5:42:34 PM
Vice-Chair Micciche probed the cause of the net negative in
only FY 17 reflected on the slide.
Mr. Alper responded that the reason was threefold: one
reason was the price, another was the work that had been
done in anticipation of the sunsetting exploration credits,
and the third was the $200 million that had carried forward
from FY 16.
5:43:47 PM
Vice-Chair Micciche requested Slide number 6, minus Cook
Inlet, or North Slope only.
Mr. Alper replied that the information would be provided to
the committee.
5:44:08 PM
Co-Chair MacKinnon asked for the current average price per
barrel of oil for 2016.
Mr. Alper clarified that she was requesting numbers for the
current fiscal year.
RANDALL HOFFBECK, COMMISSIONER, DEPARTMENT OF REVENUE,
believed that the price was approximately $41 or $42, for
the fiscal year.
Co-Chair MacKinnon thought the number provided context
since past averages had been in the $70s and $90s.
5:45:06 PM
Mr. Alper specified that if the reflected price at the end
of 2016 was $42, and the department's official forecast was
$39/bbl, the $3 represented approximately $80 million. He
added that General Fund revenue fluctuated $25 to $30
million for every dollar increase in the price of oil over
the course of the year.
5:45:31 PM
Mr. Alper looked at Slide 7, "Historic and Forecasted
Production Tax and Credits," which mirrored Slide 6, only
restricted to the production tax. The numbers below the
line of less than production tax revenue had been negative
since FY 15.
5:46:17 PM
Mr. Alper discussed Slide 8, "Status of Credit Fund Demand
for FY16-17,"
• FY16 Appropriation Capped at $500 million
• $473 million paid out to date
• About $200 million North Slope, $273 million
non-North
Slope
• $27 million left in fund with $4 million in-
process claims
• Current DOR Work Pool $675 million
• $10 million in older NOL credits
• $22 million in older exploration credits
• $552 million in 2015 NOL, QCE, WLE credits
• $60 million in 2015 exploration credits
• $31 million additional 2015 NOL, QCE, WLE
expected via amended returns
5:48:29 PM
Mr. Alper looked at Slide 9, "Status of Credit Fund Demand
for FY16-17", which further detailed the numbers from Slide
8.
5:49:11 PM
Mr. Alper moved to Slide 10, "Status of Credit Fund Demand
for FY16-17":
Status of Credit Fund / Demand for FY16-17
•All the "in hand" applications, if eligible, result
in a known demand for FY2017 of $652 million
•This is very current information, based on the CY15
tax "true-up" which was due on Thursday 3/31
•Expected credit applications during CY2016, which
could also be paid in FY17:
•Another $40 million in quarterly requests for QCE and
WLE outside the North Slope
•Another $60 million in "last minute" exploration
claims
•About $20 million in LNG storage and refinery claims
•Total, matching "final" Spring 2016 forecast, $775
million-slight reduction from $825 million "prelim"
5:50:46 PM
Mr. Alper spoke to Slide 11, "Potential NOL Carry-Forward
Liability":
Growing Carried Forward NOL's: A New Problem
• Since the beginning (2007) all companies except the
three major producers have been able to receive cash
for their tax credits. Majors must "carry them
forward"
•Companies producing less than 50,000 bbl /day
•Hilcorp crossed over this threshold in 2015
• One or more of the majors had an operating loss in
2015.
That becomes an NOL credit that can be used against
taxes starting this January (to reduce payments below
the minimum tax, as far as zero)
•This only partly offsets minimum tax payments this
calendar year. We still have some positive production
tax income.
• With the Spring Revenue Forecast, we now see all
three majors with much larger losses in 2016, and
possibly for years beyond
5:54:16 PM
Mr. Alper turned to slide 12, "Potential NOL Carry-Forward
Liability," which reflected the Oil and Gas Tax Credit
Fund: Budgeted vs. Actual vs. Statutory Tax Credit Fund
Transfer Cap (Beginning with the first budget cycle after
the passage of ACES in November 2007.)
5:56:43 PM
Mr. Alper pointed out that at the current rate, it was
forecasted that the state would build an obligation to
industry of $2.8 billion by FY 25. He noted that the non-
cashable carried-forward liability would be zeroed out by
FY 24. He shared that the last column reflected the total
state credit obligation. He said that the price forecast
listed the e price of oil in FY 18 at $43/bbl, and FY 21 at
$60/bbl, which reflected a dramatic jump that would be
assumed to have an impact on the state's finances, but that
the revenue was only projected to raise from $16 million to
$33 million. He said this was because the industry went
from having a $750 million balance to only a $265 million
balance; there had been a half million dollars in
production tax liability that the state did not receive
because it had been used to offset the NOL carry forward
from prior years.
5:59:09 PM
Senator Bishop probed the stackability of the NOLs.
Mr. Alper offered an anecdotal scenario involving NOLs. He
said that if companies were earning the NOL credits faster
than they used them, they would continue to stack up.
6:00:54 PM
Senator Bishop referred to the numbers in red on Slide 12.
He understood that the fiscal outlook could improve if the
price of oil rebounded above $85/bbl.
Mr. Alper though that $80/bbl was a good price point and
would make a big difference in the budget.
6:02:04 PM
Co-Chair MacKinnon wondered how much of a net operating
loss could be expected, using the department's current
projections, if producers were laying down rigs.
Mr. Alper responded that the laying down of rigs by BP had
already been built into the forecast. He said that there
was a reduction of lease expenditures attached to that, as
well as a reduction of wells being drilled and a reduction
in future production. He stated that further reduction of
work would be captured in the next forecast. He contended
that if current prices maintained for another year there
would be a continued slowdown.
Co-Chair MacKinnon requested that the department run new
numbers with the most current projections that included
rigs that had recently been shut down.
Mr. Alper replied that he would provide the committee with
the information.
6:03:52 PM
Co-Chair MacKinnon noted Senator Stedman in the committee
room.
6:04:07 PM
Mr. Alper discussed Slide 13, "Potential Revenue Loss from
Reduced Credits":
· CSSB130 (RES) does impact project economics
· As part of a broader structural reform to
Alaska's finances, the state will be in a better
position to meet the credit obligations it does
have and provide a more stable fiscal climate
overall.
· DOR cannot predict specific projects that may be
accelerated or deferred as a result of CSSB 130
(RES) or other fiscal reforms
· Testimony by others has compared the impact of SB
130 to total royalty revenue received by the
state
· The following table shows how those two amounts
compare under the Spring 2016 revenue forecast
· By the final year of the fiscal note, the
midpoint impact of CSSB 130(RES) represents
approximately 14% of anticipated petroleum
revenue
6:05:42 PM
Mr. Alper looked at Slide 14, "Potential Revenue Loss from
Reduced Credits":
Production would have to drop by an additional 9% for
the cost to the state from lost royalties to exceed
the benefit of the bill. In 2022, this would mean
about 35k bbl / day
• This assumes that the "lost" production would
pay taxes and royalties at the same rate as
average production; more likely the marginal
projects would pay less
• Also, much of the fiscal impact of CSSB130 is
specific to
Cook Inlet, where revenue per barrel is
substantially less
He noted that the slide contained a table that included the
estimated fiscal impact from the current bill version
versus the spring 2016 total petroleum revenue forecast.
6:06:52 PM
Vice-Chair Micciche summarized the numbers on Slides 3 and
4. He asserted that the fiscal picture on the North Slope
was very different than that of Cook Inlet.
6:07:58 PM
Mr. Alper agreed. He thought that Cook Inlet was likely
unsustainable, and that companies would react negatively to
the unsustainability of the area.
6:08:32 PM
Co-Chair MacKinnon had heard the commissioner make
statements about the success in Cook Inlet. She asserted
that the Cook Inlet was energizing 60 percent of the state.
She wondered if there was any data to support the assertion
that activity in Cook Inlet was unsustainable.
Mr. Alper explained that a fiscally constrained state could
not maintain the activity indefinitely.
6:09:56 PM
Commissioner Hoffbeck interjected that cycling contracts
were being negotiated and discussions were underway for
contracts out to 2023, and beyond. He said that he had not
heard urgent discussion as to whether gas would be
available when it was time to put it under contract, but
that some of it was yet to be under contract.
6:10:48 PM
Co-Chair MacKinnon agreed that the state did not have the
cash flow to support the existing tax credits, but was
concerned that the overall region in 10 or 15 years would
need to import gas.
Commissioner Hoffbeck said that normal practice was to have
a 10 year supply or less on the books because it did not
make sense for a company to go out and develop a field that
could not be monetized for 10 years. He thought that
uncertainty would always be part of the equation.
6:12:09 PM
Co-Chair MacKinnon understood that companies liked to carry
large reserves on their books because it helped with
financing.
Commissioner Hoffbeck replied that that was true. He added
that companies could delineate the field, and know what the
reserves were, without actually developing and delivering
product.
6:12:34 PM
Vice-Chair Micciche lamented that striking a balance
between credits and supply would be challenging.
6:13:22 PM
Mr. Alper turned to Slide 15, and stated that he would be
discussing the "greatest hits" pertaining to the subject.
6:14:11 PM
Mr. Alper turned to Slide 16, "Credit Cost in Perspective":
Of the $3 billion in state-refunded credits through
the end of FY15:
• $1.45 billion went to six North Slope projects that
now have production
• $650 million went to 13 North Slope projects that do
not have any production. Some of these are abandoned,
and some are in process
• $450 million went to six non-North Slope projects
that have production
• $450 million went to eight non-North Slope projects
that do not have any production
6:15:14 PM
Mr. Alper looked at Slide 17, "Credit Cost in Perspective":
North Slope Refundable Credits
Of the $1.45 billion that was spent between FY07-
FY15 supporting six producing projects:
• Total production through end of FY15 is 38.5 million
barrels
• Total credits = $37.30 / barrel
• This number will decrease over time due to
additional production from these fields
• Lease expenditures for these projects, through
FY15, were $4.94 billion
• Credit support was 29% of lease expenditures
6:15:51 PM
Mr. Alper reviewed Slide 18, "Credit Cost in Perspective":
Cook Inlet Refundable Credits
Of the $450 million that was spent between FY07-
FY15 supporting six producing projects:
• Total production through end of FY15 is 55.9 million
BOE (much of this was gas)
• Total credits = $7.80 / BOE or about $1.30 / mcf
• This number will decrease over time due to
additional production from these fields
• Lease expenditures for these projects, through
FY15, were $1.09 billion
• Credit support was 40% of lease expenditures
6:16:56 PM
Mr. Alper spoke to Slide 19, "Credit Cost in Perspective,"
which was a continuation of Slide 18:
Cook Inlet Tax Caps
•Estimated value to industry $550-$850 over the years
2007-2013
•Total Production Estimate
•Gas: ~ 250 million cubic feet / day for seven
years = 640 BCF of gas or 106 million BOE
•Oil: ~ 10,000 barrels / day for seven years = 26
million BOE
•Total Production = 132 million BOE
•Using midpoint $700 million estimate, value of caps =
$5.30 / barrel or $0.88 / mcf
•Sum of Credits + Tax Caps: $2.18 / mcf
6:18:05 PM
AT EASE
6:19:13 PM
RECONVENED
Mr. Alper stated that the previous slides were the best
available information that the department could provide
within the bounds of confidentiality.
Mr. Alper showed Slide 21, "Key Provisions and Decision
Points":
Preventing certain credits from being used against the
minimum tax, or "floor"
This is really three different issues / policy questions
All of these only pertain to the North Slope:
1) Net Operating Loss for producers not eligible for
refundable credits (should major producers be able to go
below the floor?)
2) Per-Barrel Credits for GVR "New" Oil (should the tax on
production from new fields be allowed to go to zero?
Relation to GVR "graduation?")
3) Small Producer / Exploration Credits (should everyone,
not just major producers, pay a minimum tax?)
6:21:22 PM
Mr. Alper looked at Slide 22, "Key Bill Provisions and
Decision Points":
Repurchase Limits
Historic Notes on large annual credits:
Over the 2007-2016 history of the tax credit program:
· There has only been one instance of a company who
ever received > $200 million in a single year
· Five times ever when one company received between
$100 - $200 million in one year
· 11 times ever when one company received between
$50 - $100 million in one year
6:22:56 PM
Mr. Alper looked at Slide 23, "Key Bill Provisions and
Decision Points":
To-date cost of Sunsetting Credits
Exploration Credits (various) 2007-sunset
• North Slope Refunded: $270 million
• North Slope Against Liability: $190 million
• Non-North Slope Refunded: $160 million
• Non-North Slope Against Liability: $0
Small Producer Credits 2007-2016
• North Slope Against Liability: $340 million
• Non-North Slope Against Liability: $60 million
• (these cannot be refunded)
Total: slightly over $1 billion
Mr. Alper offered to cut the presentation short in order to
make time for the sectional analysis.
Co-Chair MacKinnon responded that he could take the next 35
minutes to finish the presentation; the sectional analysis
could be heard on another day.
6:24:58 PM
Mr. Alper turned to Slide 25, "Overview of Tax and Credit
Calculations":
How the Production Tax Works at $100 oil
Tax on a single barrel of taxable North Slope oil. We
currently have about 160 million taxable barrels/year
Market Price $100
Transport Cost $10
Gross Value $90
Lease Expenditures $35
Production Tax Value $55
Tax @ 35% $19.25
Per-Barrel Credit $6.00
Net Payment $13.25
Minimum Tax Gross x 4% $3.60
Higher Of (Actual Tax) $13.25
Approx. Annual Revenue $2.1 billion
Mr. Alper noted that the modeled calculation was what the
Legislature had envisioned when SB 21 was enacted.
6:27:16 PM
Mr. Alper moved to Slide 26, "Overview of Tax and Credit
Calculations":
At $70 Oil, the "minimum tax" takes over
Market Price $70
Transport Cost $10
Gross Value $60
Lease Expenditures $35
Production Tax Value $25
Tax @ 35% $8.75
Per-Barrel Credit $8.00
Net Payment $0.75
Minimum Tax Gross x 4% $2.40
Higher Of (Actual Tax) $2.40
Approx. Annual Revenue $380 million
6:28:31 PM
Mr. Alper moved to Slide 27, "Overview of Tax and Credit
Calculations":
At $40 Oil, producers have operating losses
Market Price $40
Transport Cost $10
Gross Value $30
Lease Expenditures $35
Production Tax Value ($5)
Approx. Operating Loss $800 million
Tax @ 35% ($1.75)
Per-Barrel Credit $8.00
Net Payment ($9.75)
Minimum Tax Gross x 4% $1.20
Higher Of (Actual Tax) $1.20
Approx. Annual Revenue $190 million
Carried Forward Loss Credit 35% $280 million
6:30:02 PM
Mr. Alper moved to Slide 28, "Overview of Tax and Credit
Calculations":
$40 for second year means Operating Loss credits can be
used to reduce payments below the minimum tax
Year 1 Year 2
Market Price $40 $40
Transport Cost $10 $10
Gross Value $30 $30
Lease Expenditures $35 $35
Production Tax Value ($5) ($5)
Approx. Operating Loss $800 million $800 million
Tax @ 35% ($1.75) ($1.75)
Per-Barrel Credit $8.00 $8.00
Net Payment ($9.75) ($9.75)
Minimum Tax Gross x 4% $1.20 $1.20
Higher Of (Actual Tax) $1.20 $1.20
Approx. Annual Revenue $190 million $190 million
Less Carried-Forward Loss Credit ($190 million)
Actual Tax Payment $190 million $0
Carried-Forward Loss Credit 35% $280 million $370
million
6:31:10 PM
Co-Chair MacKinnon asked how much of a percentage of the
operating losses could be attributed to personnel.
Mr. Alper responded that he did not know.
Co-Chair MacKinnon requested that he provide the
information to the committee at a later date. She felt that
the job losses were not reflected in the slides and were
one of the largest cost drives to the state. She requested
details concerning the drivers inside of the net operating
cost for companies, and how the department had determined
the static numbers included in the presentation.
Mr. Alper pointed out to the committee that the department
had used $45 - $46/bbl as a working average cost, and noted
that there had been a 10 percent increase in company costs
within the last year. He said that those efficiencies and
reductions involved people who would have been building and
doing things, and whatever it was that they were going to
build the equipment and materials associated with that work
had also fallen off the expense profile.
6:33:08 PM
Co-Chair MacKinnon requested any information that the
administration could provide concerning the cost set into a
non-static plan.
Mr. Alper agreed to provide the information to the
committee.
6:33:40 PM
Mr. Alper looked at Slide 30, "Introduction to Scenario
Analysis":
· The Tax Division has developed a new model,
looking at project life cycles
· Cash flow over the 30-40 year life of a project,
for the state's production tax and credits, all
state revenue, the producer's cash flow, and
discounted (NPV)
· Scenarios Analyzed at $40, $60, $80, and Fall
Forecast oil price
· Status quo modeled vs. Governor's original bill
· Full modeling runs can be provided as a separate
document
Mr. Alper noted that there were longer presentations that
included different runs of how the model worked. He said
that the scenario had been developed in response to
questions from individual legislators.
Mr. Alper spoke to Slide 31, "Introduction to Scenario
Analysis":
Fields Analyzed:
North Slope Oil Scenarios
• 50 million barrel
• 750 million barrel (12.5% Royalty / 20% GVR)
• 750 million barrel (16.67% Royalty / 30% GVR)
• 750 million barrel (50% Private Royalty)
Cook Inlet Oil Scenarios
• 50 million barrel (tax caps sunset)
• 50 million barrel (tax caps extended)
Gas Scenarios
• 670 bcf Cook Inlet Gas (tax cap sunset and
extended)
• 670 bcf Middle Earth Gas
6:38:22 PM
Mr. Alper spoke to Slide 32, "Sample of Scenario Analysis,"
which showed numbers for the smaller field on the North
Slope at $60/bbl. He noted that the upper left corner chart
reflected solely the production tax and the credits. He
spoke to the graph in the upper right hand corner, which
reflected the annual state net gains and losses, with 20
percent GVR, at $60 and price. The lower left chart
illustrated the total producer cash flows from the
company's point of view, and the lower right listed the
life cycle totals for the field. He pointed out that the
top four lines showed the production tax numbers, the
middle four reflected the all-state revenue, and the bottom
four lines showed the producer credits.
6:42:44 PM
Mr. Alper discussed Slides 33 through 37, which offered
scenario analysis on North Slope and Cook Inlet fields
using various tax structures and varying per barrel prices.
6:48:01 PM
AT EASE
6:48:24 PM
RECONVENED
Mr. Alper pointed out that by pushing the credit spend into
future years the state was paying the credits over a longer
period of time; for some of those years the state was
getting revenue from royalties while simultaneously
receiving the credits, which reduces the credit spend.
6:49:02 PM
Co-Chair MacKinnon asked whether a $25 million cap per
organization that was driving multiple partners together,
and could create a diversity of revenue, might also slow
progress.
Mr. Alper stated that the department had presumed that
entities would partner up on projects. He said that the $25
million number had been pulled from history, when the state
had first ventured into the credit repurchasing business.
6:50:25 PM
Mr. Alper spoke to Slide 37, "Sample of Scenario Analysis,"
and noted that the slides reflecte3d little difference than
the North Slope except that there was no production tax.
6:51:43 PM
Mr. Alper looked at Slide 38, which reflected the numbers
after the implementation of SB 130. He stated that the
department could come up with hundreds of similar scenarios
to examine.
6:52:41 PM
Co-Chair MacKinnon appreciated the testifiers' ability to
articulate the administration's position.
SB 130 was HEARD and HELD in committee for further
consideration.
Co-Chair MacKinnon discussed the schedule for the following
day.
| Document Name | Date/Time | Subjects |
|---|---|---|
| SB 130 DOR Additional Info for SFIN 4-14-16 final.pdf |
SFIN 4/14/2016 5:00:00 PM |
SB 130 |
| SB 130 Sectional CSSB130(RES) Oil Credit Bill 4-14-16 final.pdf |
SFIN 4/14/2016 5:00:00 PM |
SB 130 |