Legislature(2015 - 2016)HOUSE FINANCE 519
03/31/2016 01:30 PM House FINANCE
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| Audio | Topic |
|---|---|
| Start | |
| HB247 | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| += | HB 247 | TELECONFERENCED | |
| + | TELECONFERENCED |
HOUSE FINANCE COMMITTEE
March 31, 2016
1:35 p.m.
1:35:17 PM
CALL TO ORDER
Co-Chair Thompson called the House Finance Committee
meeting to order at 1:35 p.m.
MEMBERS PRESENT
Representative Mark Neuman, Co-Chair
Representative Steve Thompson, Co-Chair
Representative Dan Saddler, Vice-Chair
Representative Bryce Edgmon
Representative Les Gara
Representative Lynn Gattis
Representative David Guttenberg
Representative Scott Kawasaki
Representative Cathy Munoz
Representative Lance Pruitt
Representative Tammie Wilson
MEMBERS ABSENT
None
ALSO PRESENT
Ken Alper, Director, Tax Division, Department of Revenue;
Randall Hoffbeck, Commissioner, Department of Revenue.
SUMMARY
HB 247 TAX;CREDITS;INTEREST;REFUNDS;O & G
HB 247 was HEARD and HELD in committee for
further consideration.
1:35:57 PM
Co-Chair Thompson discussed housekeeping.
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."
1:36:48 PM
AT EASE
1:38:33 PM
RECONVENED
KEN ALPER, DIRECTOR, TAX DIVISION, DEPARTMENT OF REVENUE,
introduced the PowerPoint presentation, "New Alaska Plan:
Pulling Together to Build Our Future - Oil and Gas Tax
Credit Reform - CS HB247(RES), Department of Revenue
Presentation to the House Finance Committee, March 31,
2016" (copy on file). He addressed Slide 2:
What We'll Be Discussing
1. History and Development of Credits
2. Credits- What Worked, What Didn't?
3. Credit Cost in Perspective
4. Overview of the Tax & Credit Calculations
5. Bill Summary- What is in the CS?
6. Changes from Governor's to Resources
Version
7. Fiscal Impact of Changes
8. Summary of Scenario Analysis and Life Cycle
Modeling: Economics of Changes
9. Implementation
1:41:00 PM
Mr. Alper addressed Slide 4:
History of Oil and Gas Production Tax Credits
• First "modern" Oil and Gas credit was the
Alternative Credit for Exploration (AS 43.55.025)
passed in 2003 while Alaska still had the "Economic
Limit Factor" (ELF) Gross Tax
• Several added in 2006 with passage of the "Petroleum
Production Tax" (PPT) and switch to net profits
taxation.
Included Cook Inlet tax caps as well as the first
"state repurchase" provisions
• Credits substantially modified with passage of
"Alaska's
Clear and Equitable Share" (ACES) in 2007; state
repurchase made more open-ended
• Cook Inlet Recovery Act and related legislation in
2010
• Frontier Basin credits added in 2012
• SB 21 passed in 2013, dramatically changed North
Slope credits, replacing "spending" with "production"
focus
Mr. Alper elaborated up until 2006 Alaska's oil and gas
production tax had been based on gross value and was known
as the Economic Limit Factor, or ELF. During the ELF era
the legislature added credits, most prominently the
exploration credit, which was a percentage of a company's
expenses that could be off-set from their taxes if they
performed a desired activity. The credit regime was
expanded in 2006, when the legislature passed the Petroleum
Production Tax (PPT), which switched to net-profit taxation
and added new credits as well as the Cook Inlet tax caps.
The caps were a hold-harmless provision that was built into
PPT that kept the Cook Inlet taxes what they were before
the effective date of the tax bill. He said that the state
began to cash out certain credits at that time. He said
that the Alaska Clear and Equitable Share (ACES) bill in
2007 substantially increased taxes and was the moment when
the repurchase of credits by the state became open-ended.
Prior to that there had been a cap of $25 million, per
company, per year. In 2010, the Cook Inlet Recovery Act and
related legislation were passed. The act tried to encourage
new exploration and development in Cook Inlet, mostly in
light of supply shortfalls. Similar credits were added to
the frontier areas in order to encourage people to look for
and develop oil in undeveloped areas of the state,
primarily the interior. He said that the North Slope oil
tax rewrite, or SB 21, passed in 2013, eliminated the
spending credits. All of the capital credits for the North
Slope were replaced with a per barrel credit tied to
production.
1:43:37 PM
Mr. Alper turned to Slide 5 and continued to address the
history of oil and gas production tax credits:
· Credits initially added to encourage certain desired
behaviors, tied to anxiety over declining production
and a need for new investment
· Later credits were added as core components /
offsets of the net profits system
· At times credits were layered on top of each other,
creating unanticipated circumstances
· Credits can either be used against tax liability,
· sold / transferred to a taxpayer, or cashed out
("repurchased") by the state
· Per AS 43.55.028(e)(4), a company producing over
50,000 bbl/day cannot have their credits repurchased
by the state
Mr. Alper relayed that the passage of SB 21 had been based
on the desire for more exploration and putting new oil in
the system. He said that the hope had been that new
companies would invest in Alaska. He elaborated that
eventually the new credits became "baked in" to the tax
formula; higher taxes were designed to be off-set by large
credits tied to capital expenditures or base production. He
noted that the cashing out, or repurchasing, of the credits
was the primary focus of HB 247. He noted that there were
currently 4 major companies working at the 50,000 bbl/day
in the state.
1:45:50 PM
Mr. Alper moved to Slide 6, which listed a summary of the
major credits in AS 43.55:
Major Credits Available (current law):
· .023(b) Net Operating Loss (25-45%)
This is the main refundable credit on the North
Slope and the largest statewide credit. "Stackable"
· .024(i&j) Per-Taxable Barrel ($0 to $8)
Only on North Slope
Only can be used against tax liability
· .023(a&l) Capital and Well Expend (20-40%)
Only outside North Slope, usually refunded
· .025(var) Exploration Credit (30-40%)
Expires 7/16 in North Slope and Cook Inlet
Extended in Interior / Frontier Areas until 2022
· .024(c) Small Producer Credit (up to $12 mil)
Closed to new applicants in 5/16
Co-Chair Thompson asked Mr. Alper to avoid the use of
acronyms, or to explain them.
1:49:39 PM
Vice-Chair Saddler pointed to the spreadsheet provided by
the department, "Table of Tax Credits under AS 43.55 - The
Alaska Oil and Gas Production Tax and Comparison to
Proposed Changes in HB 247" dated March 2016 (copy on
file). He asked whether QCE was an acronym for Qualified
Capital Expenditures, and WLE stood for the Well Lease
Expenditure.
Mr. Alper replied in the affirmative. He clarified that the
.023(l) was the suite of well lease expenditure credits and
the .023(a) was the QCE, or capital expenditure credits.
Vice-Chair Saddler noted that consistent nomenclature would
help to limit confusion while discussing the bill.
Mr. Alper noted that the spreadsheet referenced the
proposed changes to the bill and the credits; however, the
spreadsheet had not been updated for the committee
substitute currently before members.
Representative Edgmon referred to Slide 6. He requested a
breakdown of the 5 credit categories in terms of what the
state was liable for monetarily in the FY 17 budget
1:51:37 PM
Mr. Alper referred to Page 2 of the document, "Preliminary
Spring 2016 Forecast Production Tax Credits Detail, FY 2007
to FY 2025" (copy on file). He explained that over the past
few years the credits had been 50/50 between the North
Slope and Cook Inlet. He said that the North Slope credits
were comprised of approximately 90 percent operating loss
credits, the rest were exploration and miscellaneous
credits. The credits in Cook Inlet were split between the
operating loss credits and the capital/well credits, in
addition to a small amount of exploration credits. He
stated that the credits used against liability in the North
Slope were the per taxable barrel credit and a small amount
of small producer credit. In Cook Inlet, because the
underlying taxes were so low due to the statutory tax caps,
there were very little actual credits used against
liability.
Representative Edgmon asked for a rough ball park number of
the total that the state would pay in oil credits in FY 17.
Mr. Alper replied that he could try to provide a number,
but that the per taxable barrel credit was contingent on
the price of oil. He noted that the price in FY 14 had been
$600 million, but would be $28 million in FY 16. He
asserted that it would be easier to "carve out" the
refunded credits from credits against liability, of those,
three-quarters were operating loss credits. Approximately
20 percent were the capital and well credits and less than
5 percent were exploration credits.
Co-Chair Thompson welcomed Commissioner Hoffbeck to the
testifier table.
1:54:20 PM
Mr. Alper turned to Slides 7 and 8:
Credits - What Worked, What Didn't?
Some Credits have Never Been Claimed
· Middle Earth "New Areas" $6 million Credit
(AS 43.55.024(a); part of HB3001/PPT, 2006)
· Cook Inlet "Jack Up Rig" 100% Credit
(AS 43.55.025(m); part of SB309, 2010)
· Frontier Basin 80% Drilling Credit
(AS 43.55.025(n); part of SB23, 2012)
Companies did some of the activities incentivized by
these, but were able to get better results from
"stacking" other credits
All of these programs are sunsetting in 2016
Mr. Alper turned to Slide 9:
Credits- What Worked, What Didn't?
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 continued to Slide 10:
Credits- What Worked, What Didn't?
Credits Remaining if HB247 Passes
· Carried-Forward Annual Loss Credit
(also called "net operating loss")
o 35% on North Slope and 25% in Cook Inlet and
elsewhere (non-NS reduced to 10% by H(RES))
· Non-North Slope Drilling Credits
o "QCE" and "WLE" were repealed in governor's bill;
maintained at 20% in H(RES) version
· Exploration Credits outside North Slope and Cook
Inlet ("middle earth exploration")
o 30-40% depending on location
o Sunset January 1, 2022
Mr. Alper addressed Slide 11:
Credits- What Worked, What Didn't?
· Cook Inlet Tax Caps
Oil tax of zero, gas tax averages 17 cents / mcf
Sunset January 1, 2022
· Middle Earth Tax Caps
4% of gross value (first seven years of production
that begins before 2027)
· LNG Storage Facility Credit
Lesser of 50% of cost or $15 million
· Refinery Infrastructure Credit
40% of cost up to $10 million/year per refinery,
before 2020
Mr. Alper expounded that, as the state went about a new tax
regime on the North Slope under PPT, it had been written in
statute that the tax rates and the price of oil and gas
stay as they were in the year before the effective date of
PPT; the period between April 2005 and March 2006, which
was what was used to establish the tax rate on oil and gas
in Cook Inlet. He noted that HB 247(RES) would establish a
working group that would explore a new tax regime for Cook
Inlet, and other areas of the state, that will replace the
sunsetting Cook Inlet tax caps. He elaborated that the LNG
Storage Facility Credit would provide state assistance for
major tanks for the Interior gas utility.
2:00:18 PM
Vice-Chair Saddler queried the evaluation criteria that the
department used to determine which credits worked and which
had not.
RANDALL HOFFBECK, COMMISSIONER, DEPARTMENT OF REVENUE,
replied that there were three categories that had been
determined: credits that had not been used at all, credits
that had worked and had served their purpose, and those
that had an ongoing need and were incentivizing activity;
the governor had left those intact within the bill.
Vice-Chair Saddler agreed that it was possible to assume
that a credit that had never been claimed did not work. He
asked about the second category. He wondered whether an
analysis could be done to determine the effects of credits
that had "served their purpose."
Commissioner Hoffbeck answered that the department had not
parsed out what portion of the credit's success had been
due to lifting Regulatory Commission of Alaska restrictions
on price, versus an increased price environment, versus the
credits themselves. He said that the department had worked
to determine the best places to continue to invest.
2:04:43 PM
Vice-Chair Saddler lamented that the department could not
provide an analysis on how they determined the areas
affected by the credits and the extent of effect of the
credits.
Commissioner Hoffbeck replied that all of the changes in
the Regulatory Commission of Alaska restrictions had
occurred in a tight timeframe, and it would be hard to
determine which credit drove gas exploration. He said that
the $6 to $8 dollar price point for gas in Cook Inlet would
be sufficient to incentivize exploration and development
anywhere in the world, and would not need an underlying
credit structure at that price point.
Vice-Chair Saddler spoke to the goal of incentivizing
without spending more than necessary. He hoped for evidence
of a precise methodology that allowed the level of the
credit to be set.
Mr. Alper interjected that the overarching theory that the
governor had hoped to maintain in the modified system
moving forward was to protect the concept of the operating
loss credit, which provided a level playing field between
the incumbent and the new players. He said that the caveat
of the fields in Cook Inlet being profitable was that there
would be somewhere to sell the gas. He said that there
would be no problem if enough wells could be drilled to
produce the gas from the new fields correctly. But, if a
well needed to be drilled every three years for lack of
customers, the economics of the fields would be problematic
and could result in the need for additional credit support.
2:08:09 PM
Co-Chair Neuman queried the market conditions within Cook
Inlet and exporting to Japan.
Mr. Alper replied that the base utility consumption in Cook
Inlet was approximately 80 to 90 billion cubic feet per
year. He said that a trillion cubic feet was nearly enough
to last 12 years for the utility market in Cook Inlet. He
said that the exporting from the Conoco Phillips facility
was sporadic and had no regular deliver schedule. He stated
that the proven reserves held nearly a 15 year supply for
that market, and those which had been claimed to be proven
by producers would add several years to that. He thought
that once drilling began there would be more than was
initially claimed. He said that there was 1.2 to 1.6
trillion cubic feet that was known of in the ground, and
much more was theorized: possibly 10 to 15 trillion cubic
feet of gas.
Co-Chair Neuman probed whether the state was getting a net
loss or a net benefit from the credits. He hoped that the
department could provide information on the measured value
of the credits.
Representative Gara spoke to the different types of fields
that a paid profits tax, but that also got to write-off 35
percent from their taxable income.
Mr. Alper answered that with the assumption that the price
of oil was higher and the net profit tax was in play, the
capital and operating spending would be subtracted from the
price that was received from selling the oil. He relayed
that the newer fields that were eligible for the gross
value reduction had a further reduction from that figure on
adjusted net; a 35 percent tax was taken from the adjusted
figure.
2:12:11 PM
Representative Gara referred to a past discussion about
whether credits would work to get gas to Southcentral
Alaska. He asked what portion of the credits were being
paid for that had not been intended, mainly oil and gas in
Cook Inlet that was being exported by Conoco Phillips.
Mr. Alper answered that part of how Cook Inlet had adjusted
to the supply uncertainty had been to downsize to base
needs. He said that approximately one-third of the Cook
Inlet credits had supported oil development, and two-thirds
gas development.
Representative Gara understood that the state received $.17
per million cubic feet for gas exported by Conoco Phillips.
Mr. Alper replied in the affirmative. He said that all
production from Cook Inlet was subject to the $.17 per
million cubic feet price. He added that most producers in
Cook Inlet fell into the category that qualified them for
the small producer credit, which could off-set the $.17
down to zero.
Representative Gara stated that one-third of the credits
were paid for oil. He wondered whether year-to-year figures
of the portions of the credits for gas that were exported
to Asia could be provided by the department.
Commissioner Hoffbeck responded that gas wells preferred to
have a steady state of production. He said that the excess
summer production did not have a market demand, versus
something specifically developed for export. He thought
that it would be difficult to attribute credits that may
have been wrongly applied to summer gas and that the wells
could not simply be shut off.
Representative Gara contended that the intent of the
credits had been to incentivize local production. He
wondered how much money was being spent for producers that
were exporting the gas.
Mr. Alper replied that the department could study the
issue. He asserted that looking at the demand in
Southcentral Alaska monthly, rather than annually, showed
that it could be 10 times as high in January as it was in
July because people were heating their homes.
2:15:49 PM
Vice-Chair Saddler felt that it was important to discuss
the dynamics of natural gas production. He said it was not
a zero sum game, and wondered whether the production of gas
that was exported benefitted the production of gas for the
state.
Commissioner Hoffbeck answered in the affirmative.
Vice-Chair Saddler asked whether a distinction could be
made between incentives used to generate gas for
consumption in-state versus what was exported.
Mr. Alper replied that he was unsure that a distinction
could be made other than applying the multiplier that he
referenced earlier. He said that there was a successful
credit that had yet to be mentioned: the Gas Storage
Facility Credit. The credit had been part of the Cook Inlet
Recovery Act, and had provided economic support to build
underground storage that had enabled seasonal stability.
Representative Pruitt spoke to credits in Cook Inlet. He
asked whether any stipulations to gain the credits included
listing gas as the specific resource. He believed both oil
and gas would be produced in Cook Inlet, he worried that
the credit might only be applied to gas.
Mr. Alper answered that no stipulation had been made; oil
versus gas had not been specified. He said that once
drilling began the drilling credits became eligible for
work-overwork, where and active well is modernized and
improved. He asserted that companies understood the way
that the credit worked.
2:19:18 PM
Representative Gara asked whether the administration
thought that the $0.17/mcf, or lower, tax on exported gas
was fair to residents of the state.
Mr. Alper clarified that the tax had been $0.17 since 2005,
and had a 15 year lifespan written in to statute. He shared
that the legislature had chosen to no change it. He said
that in the development of the bill, the Governor had been
careful not to change the Cook Inlet Tax Caps prematurely;
although, Cook Inlet taxes on oil and gas would need to be
comprehensively examined, and a long-term tax regime for
Cook Inlet would need to be established.
Commissioner Hoffbeck reference the discussion with Vice-
Chair Saddler about credits that had not performed as well
as expected. He expounded that oil was still "king" even
though gas was important to the state; oil was more
important than gas from the perspective of for-profit
resource development. He stated that the fact that the
credits could be used to incentivize oil production, in a
regime where an oil tax was not being paid, was reflective
of how the credits could be problematic.
Representative Guttenberg reminded the committee that
Alaskan's paid very high home heating prices, the most
recent mild winter being an exception, and felt that the
credits should be targeted towards in-state use of
affordable, long-term energy. He assumed that the credits
had been designed to affect the behavior of the industry.
He noted that some people wondered about the effectiveness
and transparency of the credits. He wondered whether the
department would delineate which aggregated credits would
monetarily benefit the state.
2:23:20 PM
Mr. Alper responded that life-cycle modeling was included
at the end of the presentation, and would speak to the
question of what the state would receive, even without the
production, and what would be the net benefit to the state
over time. He opined that as prices fell the possibility
that the state might never recoup money became an issue. He
felt that the state could benefit in areas other than the
treasury, such as employment and energy security. He added
that the department faced challenges when addressing the
nuances of the credits using the normally employed methods
of analysis.
Representative Guttenberg requested that the range of costs
used in price models be included in future tax credit
related presentations.
Mr. Alper replied that the numbers would be provided. He
asserted that the administration had worked to avoid the
politics that usually surrounded the issue of oil taxes. He
stated that part of the reason the state found itself in
the current fiscal climate was because prices were very
low, and past participants had not adequately considered
what might happen with the tax structure when prices
plunged for a prolonged period of time. He shared that
there were oddities to the system at very low prices; when
ACES had been before the body in 2007, people failed to
examine what would happen when the price reached over $70 -
$80 per/bbl. He stressed that what the administration was
attempting to do was to put in place a system that worked
at all plausible rage of prices.
2:25:41 PM
Representative Pruitt understood that the administration
was endorsing Section 31, which would establish a working
group that would evaluate whether or not adjustments should
be made with Cook Inlet credits. He wondered whether
discussing those credits now was necessary since they would
be analyzed by the working group in summer 2016.
Mr. Alper responded that right now, state support for
ongoing development work in Cook Inlet was at 50 to 60
percent. The state had spent $404 million on credits for
the inlet in 2015. He said that gaining the support for the
short-term desire of ramping down the Cook Inlet credits
was necessary and important. However, even with the change
it would still be important to discover what the tax would
be in 2022, when the caps went away. He concluded that the
primary purpose for the working group was for future
planning and not for immediate gratification.
Representative Pruitt asked whether the working group had
been included in the legislation by the House Resources
Committee.
Commissioner Hoffbeck replied in the affirmative. He
thought that the language had been included in response to
credits being put back into the system. He felt that
reviewing the credits was urgent. He pointed out that there
had already been several working groups that had met on the
subject, and felt that the issues had been fairly
established. He hoped that all action would not be delayed
until 2017 simply to accommodate another working group.
Representative Pruitt asked whether the House Resources
Committee would concur with the administration's
summarization of the working group established in Section
31.
Commissioner Hoffbeck interpreted that the House Resources
Committee had felt that a working group would be necessary
in order to further understand how to proceed with the
credits in the future.
2:29:18 PM
Vice-Chair Saddler stated that the legislature had been
criticized for not forecasting a drop in oil prices when
establishing the credits. He thought that it would be
beneficial to research the credits thoroughly.
2:29:53 PM
Mr. Alper spoke to Slide 13:
Credit Cost in Perspective
FY 2007 thru 2016, $8.0 Billion in Credits
North Slope
· $4.4 billion credits against tax liability
o Major producers; mostly 20% capital credit
in ACES and per-taxable-barrel credit in
SB21
· $2.3 billion refunded credits
o New producers and explorers developing new
fields
Non-North Slope (Cook Inlet & Middle Earth)
· $0.1 billion credits against tax liability
o Another $500 to $800 million Cook Inlet tax
reductions (through 2013) due to the tax cap
still tied to ELF
· $1.2 billion refunded credits (most since 2013)
Mr. Alper continued to Slide 14:
Credit Cost in Perspective
Of the $3.0 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
2:32:47 PM
Mr. Alper advanced to Slide 15:
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
o This number will decrease over time due to
additional production from these fields
· Lease expenditures for these projects, through
FY15, were $4.94 billion
o Credit support was 29% of lease expenditures
Mr. Alper turned to Slide 16:
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
o This number will decrease over time due to
additional production from these fields
· Lease expenditures for these projects, through
FY15, were $1.09 billion
o Credit support was 40% of lease expenditures
2:34:42 PM
Mr. Alper explained Slide 17:
Credit Cost in Perspective
Cook Inlet Tax Caps
· Estimated value to industry $550-$850 over the
years 2007-2013
· Total Production Estimate
o Gas: ~ 250 million cubic feet / day for
seven years = 640 BCF of gas or 106 million
BOE
o Oil: ~ 10,000 barrels / day for seven years
= 26 million BOE
o Total Production = 132 million BOE
· Using midpoint $700 million estimate, value of
caps = $5.30 / barrel or $0.88 / mcf
Mr. Alper stated that adding up the Cook Inlet tax caps and
the direct credits reflected a $2.18 total for state
support of gas development in Cook Inlet over the past 8
years.
2:35:47 PM
Vice-Chair Saddler queried the total value of the oil
produced for which the credits were earned from 2007 to
2015. He wondered whether the ratios of the total values to
the value of the tax credits could be provided to the
committee.
Mr. Alper replied in the affirmative. He understood that
Vice-Chair Saddler was requesting the specific resource
that was incentivized thorough the credits; the oil and gas
produced by the companies that received the tax credits.
Vice-Chair Saddler asked for both options.
Mr. Alper replied that he would provide numbers for all
production; the $4.4 billion would be a function of a great
bulk of the oil that was sold for Alaskans livelihood, the
refunded credits would consist of the targeted, smaller
numbers referred to in subsequent slides.
Vice-Chair Saddler asked whether the state retained seismic
3-D and 2-D work and well data from wells that had been
drilled using credits.
Mr. Alper replied in the affirmative; if the work was
incentivized with an exploration credit the data was made
public after 10 years, which the Department of Natural
Resources (DNR) used for marketing of state lands to entice
future new investment.
Vice-Chair Saddler understood that the information was
retained in the Geologic Material Center, and was available
to help the state in marketing for future lease sales and
drilling programs.
Mr. Alper understood that DNR had the data and could use it
immediately for modeling and internal confidential
purposes. He reiterated that the information would become
available to the public after 10 years.
Vice-Chair Saddler believed that explorers who were
interested in doing business in Alaska would sign
confidentiality agreements and visit the center to examine
well logs and other data before making a bid.
Mr. Alper said that the commissioner of DNR had tried to
value the seismic and other data that the state had
received. He said that the issue of seismic data was
somewhat tied up in the impending sunset of the exploration
credits. He said that depending on what the legislature did
with the credits, the hope was to write into statute a
continuing mechanism to ensure that the state could get the
data should the exploration credits eventually end.
2:39:29 PM
Representative Pruitt noted that the tax regime under SB 21
was in its infancy. He reference Slide 13, and probed the
credit amount under ACES, versus SB 21.
Mr. Alper responded that the type of company that had been
eligible for refunded credits during the final years of
ACES, was receiving approximately 45 percent of their
expenses repurchased. He said that SB 21 had eliminated the
capital credit and replaced it with the 35 percent
operating loss credit and the sliding scale. He relayed
that concern that a reduction from 45 percent to 35 percent
could harm projects, a two-year hold harmless had been
built into SB 21, which increased the net operating loss
credit to 45 percent for calendar years 2014 and 2015. All
of the credits that had been repurchased, to-date, from the
North Slope had been at the 45 percent rate. He added that
the credits against liability was the 20 percent capital
credit under ACES, which was $3-4 million on a typical
year, and allowed companies between $1.5 billion and $2
billion, per year, in allowable capital expenditures. He
said that a comparable credit since the passage of SB 21
was the per barrel credit, which was over $500 million in
FY 14 and 15 the two years it was in effect. The credit had
dropped with oil prices; the per barrel credit was
estimated at $28 million in 2016, and $16 million in 2017.
Representative Pruitt asked whether the state could expect
the refundable credits to decrease in the future.
Mr. Alper replied that the department had expected the
credits to remain the same; most companies that were
receiving the loss credit were also getting the capital
credit, holding the credits at the 45 percent level. He
said that the credits were expected to decline to 35
percent and that the department's forecasted a decline in
repurchase credit numbers.
Representative Pruitt spoke of the hold harmless carry-over
from ACES to the current structure under SB 21. He asked
whether credits would be further reduced under SB 21.
2:43:31 PM
Mr. Alper responded that the numbers had been rising. He
said that $628 million had been paid in FY 15, which was
the largest number of refunded credits the state had ever
paid. He believed it was fair to say that the North Slope
credits had been on a downward trend the last 3 to 4 years.
Representative Pruitt pointed to Slide 14 and the $1.45
billion that had gone into the six producing projects. He
queried the total amount that was spent on the projects.
Mr. Alper responded $4.94 billion.
Representative Pruitt asked how much the state could expect
to receive for the $4.94 billion investment.
Mr. Alper replied that it was highly contingent on the
price of oil. He said that low prices were forecasted over
the next 8 to 10 years, with very little revenue coming to
the state from those smaller fields that had the tax
reductions.
Commissioner Hoffbeck thought that it was difficult to
separate the credit related oil from the non-credit.
Representative Pruitt whether the credit related oil
included production tax, royalties, and property tax.
2:46:51 PM
Mr. Alper replied in the affirmative. He explained that the
modeling explored 3 different analysis: the production tax
credits, the total state take of royalties, corporate
income tax, and property tax, and the producer's economics.
Representative Pruitt pointed to Slide 16. He understood
that there had been no qualifying capital expenses from
2007 to 2010. He wondered why there had still been a fear
of brown-outs in areas of the state when a boom had been
going on in Cook Inlet.
Mr. Alper answered that at the time PPT was being debated
in the legislature, the Cook Inlet "Gas Wars" were
underway. He understood that much of the conflict had been
with the RCA; at the time the Southcentral facilities had
been used to a long history of very low prices, but there
had been a boom in prices in the Lower 48. He continued
that proposals for gas sales contracts had been brought to
the RCA, in order to try to match Cook Inlet to the Henry
Hub price. He said that the RCA had rejected some of the
contracts, which had led to disinvestment. He stated that
the stage had been set for pricing issues of the gas
supply. He said that brown out conversations made a storage
facility essential in order to solve the seasonality issues
in Southcentral Alaska.
Co-Chair Thompson asked members to hold their questions
until the end of the presentation.
2:50:44 PM
Mr. Alper addressed Slide 19:
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 turned to Slide 20:
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
Mr. Alper continued to Slide 21:
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
2:55:15 PM
Mr. Alper spoke to Slide 22:
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
Mr. Alper relayed that the slide reflected the calculation
of the high operating loss credit carry forward due to many
years of expected low prices, which had been forecasted in
the department's 2016 spring forecast. He qualified that
this was the baseline scenario for legacy oil from the
North Slope. He spoke to slide 23:
· This is just the "baseline" scenario, for legacy
oil from the North Slope.
· Does not account for the fact that roughly 9% of
production qualifies for the "Gross Value
Reduction" new oil tax break
· Can also provide example calculations for North
Slope GVR Eligible Production as well as Cook
Inlet scenarios
Mr. Alper explained that 91 percent of the oil from the
North Slope used the above calculation, the other 9 percent
was new oil that qualified for the Gross Value Reduction
(GVR), the difference being that at higher prices the tax
would be lower. The new oil would not be subject to the
minimum tax and could pay zero under current law.
Mr. Alper addressed Slide 25:
Bill Summary - What is in the H(RES) CS?:
Exploration Credits
HB247 Proposed / Kept in CS
· Allowing the .025(a) "alt. credit for
exploration" to expire on 7/1/16, for North Slope
and Cook Inlet
o 025(a) credits remain for "Middle Earth"
until 2022
· Also allowing the "Jack up Rig" and "Frontier
Basin" credits to expire at the same time
· Preemptively repeal other exploration credit
programs that are not currently being used, in AS
38.05.180(i) and AS 41.09.
2:58:53 PM
Mr. Alper addressed Cook Inlet credits on Slides 26 and 27:
Bill Summary- What is in the H(RES) CS?
Cook Inlet Credits, Current Conditions
New Field Developer
· Currently receives a 25% Net Operating Loss (NOL)
credit stacked with either the 20% Capital (QCE)
or 40% Well (WLE) credit. Generally a weighted
average of the two "spending / drilling" credits
· State typically refunds 50-60% of costs
Existing Producer
· Currently pays low to zero taxes due to Cook
Inlet tax caps, yet is eligible for 20% Capital
or 40% Well Lease Expenditure credits
· State typically refunds 25%-35% of costs
Bill Summary- What is in the H(RES) CS?
Cook Inlet Credits, Changes in CS
New Field Developer
· NOL (Loss) credit reduced from 25% to 10% in 2017
· WLE (Well) credit reduced to 30% in 2017 and 20%
in
· 2018 (effectively repealing it)
· QCE (Capital) credit remains until 2022
(anticipating sunset of Cook Inlet tax caps)
· State will typically refund 35% of costs in 2017
and 30% in 2018 and beyond
Existing Producer
· Tax caps remain until 2022. Continuation of 20%
QCE credit means state will continue to refund
20% of capital spending
CS sets path for broader Cook Inlet tax reform by 2022
3:01:49 PM
Mr. Alper addressed repurchase limits on Slide 28:
Bill Summary- What is in the H(RES) CS?
Repurchase Limits
Changes in Committee Substitute
· Adds an annual "cap" on per-company credit
repurchases of $200 million
· Multiple partners in the same project can
each claim
· $200 million. However, a single company
cannot artificially split themselves to
multiply the benefit
· Cash flow protection in the case of a large
"outlier" project such as proposed by
Armstrong
o Modeling showed annual credits from a
similar project of up to $800 million
Mr. Alper continued to Slide 29:
Bill Summary- What is in the H(RES) CS?
Repurchase Limits (cont'd)
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
Mr. Alper turned to Slide 30:
Bill Summary- What is in the H(RES) CS?
Remove Exceptions / Loopholes
CS retains two proposed changes to prevent
artificially inflated net operating losses
· Can't use GVR (new oil value reduction) to
increase the size of a Net Operating Loss (has
led to credits greater than 100% of loss)
· If a municipal entity owns production and sells
only a portion of that production to an outside
party, only the pro-rata share of expenses can be
deducted against revenue
3:05:49 PM
Mr. Alper addressed slide 31:
Bill Summary- What is in the H(RES) CS?
Brief explanation of GVR / NOL Problem
(Sec. 12; AS 43.55.23(b)(2))
· CSHB 247 would prohibit the gross value reduction
(GVR) from being used to increase size of net
operating loss and by extension, the NOL credit
· In the low oil price / low cost example shown on
the next page, the net operating loss would be
limited to the net value before GVR, which is $6
per barrel instead of $12 per barrel
· The resulting credit is 35% of the actual net
operating loss, reducing the credit liability to
the State by 50%. For a GVR-field producing
10,000 taxable barrels per day, the difference is
$7.6 million
Mr. Alper elaborated on the topic of current law allowing
the gross value reduction to increase a net operating loss
credit (Slide 32).
3:08:18 PM
Mr. Alper turned to Slide 33 and provided a brief
explanation of municipal utility problem. If a municipal
utility owned a portion of a gas field and used all of the
gas to generate its own power, the gas would not be
taxable. However, if a portion of that gas was sold to a
third party, those sales would be taxable. Current law
allowed all lease expenditures to be used to offset the
comparably small amount of sales, which could potentially
generate late credits. HB 247 proposed to limit the lease
expenditure calculation to just the pro-rate share of the
expenditures equal to the proportion of the gas that had
been sold.
Mr. Alper turned to Slide 34 and addressed other
provisions:
Bill Summary- What is in the H(RES) CS?
Other Provisions
Interest Rate Reform
· Fixes a technical error in SB21 that prevents
compound interest on underpayments and
assessments. Since 2014 we have collected only
simple interest
· Interest rate remains 3% above federal discount
rate
Bankruptcy & Debt Protection
· Credit certificates can be used to satisfy
obligations to the state for the company's oil
and gas business before repurchase
· Surety bond of $250,000 for developers, to
protect unsecured creditors in event of default
Mr. Alper
3:12:07 PM
Mr. Alper addressed the changes made from the Governor's to
the House Resource Committee version of the bill to the
bill beginning on Slides 36:
Changes made in House Resources
· Kept and improved many of the technical fixes,
including inadvertent "double dip" credit for new
oil on the North Slope
· Reduced Cook Inlet credits, with different
emphasis and delayed phase-out
· Increased repurchase "cap," limiting its impact
to just very large 'outlier' projects
· Removed all changes to minimum tax "floor,"
transparency provisions, interest rate increase,
and several smaller provisions
· New legislative working group to review tax
regimes outside the North Slope
Mr. Alper moved to slide 37, which addressed Cook Inlet
credits:
Changes made in House Resources
Cook Inlet Credits
Original proposal was to repeal 20% Capital (QCE) and
40% Well (WLE) credits on 7/1/16, while maintaining
the 25% Operating Loss (NOL)
· Effectively, three substantial changes:
1. Timing: CS phased in the changes over 18
months, taking full effect on 1/1/18
2. Total: CS retained a 30% level of development
support vs. 25% in original bill
3. Applicability: CS maintained 20% credit
support for producers who earn a profit, vs. no
support in original version. Means additional
companies will still qualify for cash credits
Mr. Alper continued to Slide 38:
Changes made in House Resources
Repurchase Limits
Original proposal added four limits to repurchase:
· Per-company / per-year cap of $25 million
· Large companies, with annual revenue over $10
billion, are ineligible for credit repurchase
· Percentage of repurchase tied to percentage of
Alaska resident hire
· 10-year carry forward sunset
Impact of Changes
· A large percentage of projected savings were in
these provisions, although tighter repurchase
limits would increase the total amount of
"carried forward" credits that could offset
future production
3:16:38 PM
Mr. Alper turned to Slide 39 and continued to address
changes made to the bill in the prior committee:
Changes made in House Resources
Strengthen Minimum Tax
CS eliminated- items that impact legacy producers:
· Can't use an operating loss credit, to reduce
payments below the 4% floor
· This was the largest "added revenue" component
· Prevent per-taxable-barrel credits earned in
one month from being used against another
month's taxes at true-up
· Increase in minimum tax from 4% to 5%
CS eliminated- items that impact new oil producers:
· Extend minimum tax to GVR-eligible "new" oil
· Not allow small producer credit to reduce tax
payments below the floor
Co-Chair Thompson
Mr. Alper addressed the fiscal impact of the bill beginning
on Slides 40. He noted that the fiscal note for the bill
was 5 pages. He said that the provisions of the bill could
be broken out into three main sections: two related to
spending, and one to increased revenue. He relayed that
when originally proposed the bill would have had a total
fiscal impact of $500 million, but the number had increased
to $785 million after the spring forecast. He said that the
bill would have little impact in FY 17 because it would not
take effect until January 1, 2017, which would be halfway
through the fiscal year. He stated that the provisions that
deferred credits and hardened the floor had been removed.
He said that the $200 million cap was the remaining credit
deferring provision in the current bill, and did show as
fiscal impact in the fiscal note because the department had
not predict any companies would earn $200 million, or more,
in the 6 year period covered by the note. He noted that FY
18 offered a more appropriate comparison because the bill
would be more fully implemented. He concluded that the
numbers on the slide reflected larger and more detailed
fiscal note, with all of the associated narrative that had
been previously provided to the committee.
3:22:27 PM
Mr. Alper spoke to the spring forecast and the reason the
numbers differed from fall 2015 to spring 2016 (Slide 42):
Fiscal Impact
Impact of Changes from Fall 15 to
Preliminary Spring 16 Forecast
· Much lower prices for longer period means:
o Larger company operating losses
o Status quo, production tax goes to near zero
as all of it is offset by NOL credits
o Large carried-forward NOL's, $630 million
after FY17
· Refundable credit estimate for FY17 increases by
$200 mil
o Larger company operating losses
o Higher than expected work on exploration
projects, before expected sunset this year
(up to 85% on NS)
Mr. Alper turned to Slide 43:
In future years, our "status quo" credit forecast
appears to decrease.
This can't really be built into future budgets.
· Our credit forecast only includes "known"
projects
· Most "new" projects would add to the amount of
projected credits
· Credit projections use the same conservative
methodology as DOR's production forecast
Mr. Alper noted that the numbers would need to be
recalculated if Armstrong continued forward with their
project. He suggested continuing the next section of the
presentation when more time could be made available.
Co-Chair Thompson discussed housekeeping.
ADJOURNMENT
3:26:06 PM
The meeting was adjourned at 3:25 p.m.
| Document Name | Date/Time | Subjects |
|---|---|---|
| HB247 DOR for HFIN 3-31-16 (002).pdf |
HFIN 3/31/2016 1:30:00 PM |
HB 247 |
| HB 247 Applicability by geography and owner_v2_ 3-14.pdf |
HFIN 3/31/2016 1:30:00 PM |
HB 247 |
| HB 247 AS 43 55 Credits Table with HB 247 changes 3-7-16.pdf |
HFIN 3/31/2016 1:30:00 PM |
HB 247 |
| HB 247 Table 8-4_PRELIMINARY Spring 2016 Forecast_MGM_20160329.pdf |
HFIN 3/31/2016 1:30:00 PM |
HB 247 |