Legislature(2015 - 2016)BUTROVICH 205
04/07/2016 03:30 PM Senate RESOURCES
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| Audio | Topic |
|---|---|
| Start | |
| SB130 | |
| Continuation of Additional Modeling and Scenario Analysis by Dor | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| + | HB 247 | TELECONFERENCED | |
| += | SB 130 | TELECONFERENCED | |
| + | TELECONFERENCED |
SB 130-TAX;CREDITS;INTEREST;REFUNDS;O & G
[Contains discussion of companion bill HB 247.]
3:30:55 PM
CHAIR GIESSEL announced consideration of SB 130 [version 29-
GS2609\A was before the committee]. She said today the committee
would hear from the utilities and the Regulatory Commission of
Alaska (RCA) before going back to the Department of Revenue
(DOR) for more fiscal numbers. She welcomed the Enstar Natural
Gas representatives to the table.
3:31:32 PM
JARED GREEN, President, Enstar Natural Gas Company, Anchorage,
Alaska, said Enstar is the largest purchaser of natural gas in
the Cook Inlet. Ultimately their customers are a beneficiary of
the tax credit program that has been in place since 2012. Their
customers depend on natural gas from Cook Inlet to heat their
homes, their businesses, their schools, hospitals, and
industries. Fundamentally, Enstar's interest is in fostering a
stable and appealing natural gas environment in the Cook Inlet.
Their number-one priority is safe reliable service to its
140,935 natural gas customers.
3:32:36 PM
SENATOR STOLTZE joined the committee.
MR. GREEN said, on average, their customers burn 33 Bcf/year
(power corporation load is separate), but this varies from as
little as 30 Bcf to 35 Bcf/year. He said overall production
coming out of Cook Inlet is about 80 Bcf/year.
He said that Enstar has high seasonality gas needs with a ratio
of 12:1 winter/summer gas along with substantial daily
variability due to weather. With their current customer base,
there is a potential daily demand of 287 mmcf/day and that is
most likely to occur on a cold January date of any given year,
but, depending on weather, that same January date could be under
100 mmcf/day.
When Enstar plans its natural gas portfolio it looks many years
in advance, Mr. Green said. It operates in a closed supply
system and, therefore, very long lead times are needed. Firm gas
contracts need to be lined up and in place at least two years in
advance. Anything less than that puts their 141,000 customers,
over half the population of Alaska, at risk of supply shortages.
To put the customer count in context, that number represents
over half of the South-central population in Alaska.
There is no doubt Cook Inlet is challenged, he said, and between
the producers and Cook Inlet Natural Gas Storage Alaska
(CINGSA), 287 mmcf/day needs to be available, although it is not
needed every day. This means producers need to have the
operational capability to ramp up production, but also the
capability to throttle it back when it's not needed.
MR. GREEN said Cook Inlet is a very different world than what is
in the Lower 48. With the integrated transmission and storage
network, producers down south can simply drill a well and open
up their taps and the large market simply absorbs the gas. The
utilities have an easy role also: they have a line-up of
marketers who are trying to sell them gas from various places
and if a contract that a utility has is not being fulfilled, the
utility simply goes back to its marketing stream, and source gas
from any one of the thousand other producers who are willing and
able to supply them gas. Cook Inlet does not have that luxury;
it is a very small and illiquid marketplace.
3:35:42 PM
SENATOR COSTELLO joined the committee.
MR. GREEN said Cook Inlet has a handful of buyers and an even
smaller number of suppliers. The fact that ConocoPhillips is
selling its assets to ML&P will take another supplier out of the
marketplace, but then ML&P will be self-supplied. That places
Enstar in a somewhat delicate position with respect to supply.
However, Enstar is in a much better position now than in 2012.
They have transitioned from a time of supply and deliverability
shortages to signing a contract with Hilcorp that takes them out
through 2023. However, that 2023 date would be just outside the
range of short-term planning. This contract is now before the
Regulatory Commission of Alaska (RCA) for approval.
3:37:54 PM
Enstar has fairly good visibility for gas needs out through
2021, Mr. Green said. With continued activity by Hilcorp and
Furie along with hopeful growth and added stability from Cook
Inlet Energy and AIX, and the new players - BlueCrest Energy and
others - he is optimistic that he can see the supply horizon
moving out into the 2025s. But that hinges on fostering an
environment that keeps both existing and new producers engaged.
MR. GREEN said he feels strongly that the utilities in the Cook
Inlet have a very large responsibility for providing reliable
gas, and Enstar has designed its portfolio to balance their
number-one priority of safe, reliable gas service with the need
to foster the long-term viability of the Inlet. Enstar has put
their support behind Furie's development of the Kitchen Lights
Unit and signed a three-year contract with them that is now
before the RCA. This is a core underpinning to their
development. Enstar has left about 10 percent of its supply
portfolio open for other producers to be able to come in.
He said that since 2012, the state has provided huge support to
the viability of Cook Inlet gas supply and that Enstar is
conscious of the state's budget crisis. They would love to see
the state continue to encourage this marketplace in whatever
form it can to keep it an attractive investment for producers.
MR. GREEN said finally, Cook Inlet is in a good place right now,
but they have had the advantage of two very warm years in a row
and 2016 looks like another. If Alaskans had experienced three
cold years in a row, the current facilities might have been
stretched. Today there is only one well in the Kitchen Lights
Unit and there are no gas productions wells in the Cosmo Unit,
as BlueCrest is purely focused on oil. Cook Inlet has four large
fields, which are aging every year. With cold weather or even if
one of the existing platforms or fields had an issue, it has no
large contingency of backup alternatives. As this committee
knows, Mr. Green said, Alaska has no interties to the Lower 48
or Canada; it is 100-percent dependent on this small, illiquid
market to keep half of the state's population warm.
3:41:12 PM
MOIRA SMITH, Vice President and General Counsel, Enstar Natural
Gas Company, Anchorage, Alaska, said slide 3 was an actual
representation of daily supply/demand in each day in 2014 and
2015 and illustrates why Enstar is a complicated customer. She
noted the extreme daily variability and how their job is to have
the gas in the pipeline to meet the customers' demand when they
turn the thermostats up or down in winter and summer.
MS. SMITH said they have contracts with AIX (succeeding
Buccaneer's bankruptcy), with Cook Inlet Energy, with Anchor
Point Energy (which sold its assets to Cook Inlet Energy), with
Hilcorp and ConocoPhillips. All of those contracts supplied
their customers in each of the days in 2014/15.
She also noted how injections from the Cook Inlet Natural Gas
Storage Alaska (CINGSA) plays a critical role in Enstar's
ability to meet its customers' needs on a day-to-day basis by
allowing them to inject gas in the summer time.
CHAIR GIESSEL asked if CINGSA is owned by Enstar.
MS. SMITH replied that Enstar's parent company, SEMCO, owns 65
percent of CINGSA, along with First Alaskan Cook Inlet Region,
Incorporated, and a subsidiary of Berkshire Hathaway. She said
the top of the chart reflects the maximum daily peak
deliverability Enstar requires from the marketplace in the event
of a super-cold day.
3:44:03 PM
This event comes along every once in a decade and has only
happened four times in Enstar's history, but when that day
comes, Enstar's obligation is to ensure that the gas is there
for its customers, Ms. Smith said.
Slide 4 is a further illustration of the seasonality of Enstar's
demand on an average day in each of the months in 2019 through
2021. She noted that the dark blue lines represent firm volumes
Enstar will take under the Hilcorp contract. Optional volumes,
represented by light blue, are stacked on top and are also from
the Hilcorp contract. The dark green are the firm volumes take
from the Furie contract and then light green, which are optional
volumes from Furie.
MS. SMITH said Enstar worked very hard in their new gas supply
portfolio to ensure that they not only have their base load
contracts in place, but options for more volumes. So, on any day
they can choose to withdraw from CINGSA instead of drawing on
the firm volumes. This allows the flexibility to manage their
storage volume and ensure they have sufficient storage to get
them through each winter, but at the same time buy from the
market as needed. The expected daily injections from CINGSA were
represented in orange on the chart.
3:45:46 PM
She said slide 5 illustrates what Enstar was thinking when they
sat down in 2014 to issue their request for proposal (RFP) for
supply contracts through 2023. Enstar's gas portfolio for 2016
and 2017 consisted of relatively small contracts, and because
they knew that every gas supply contract would expire in 2018,
in late 2014, they sent out an RFP to all comers in Cook Inlet
who were either actually producing gas, had publically stated
their intention to produce gas, or even were in the process of
doing seismic work or exploring for oil, to try to ensure that
anyone who might have gas available was able to respond.
Then, Ms. Smith said, Enstar engaged in intensive and protracted
negotiations with these entities throughout 2015/16, the first
priority being to secure an anchor contract at reasonable
prices, which would form the foundation for gas supply in the
post-2018 world. These negotiations took over one year and
resulted in APL-14, the new contract with Hilcorp that was filed
with the RCA in February.
She explained that APL-14 was signed on December 23 and
represents approximately 70 percent or 110 Bcf of Enstar's gas
supply needs from 2018 through 2023. It will supply around 22
Bcf/year. The contract has optional volumes, which allow Enstar
a great degree of flexibility to manage the weather variability
they deal with not only on a daily basis but also on an annual
basis.
Another key element of this contract is its reasonable price. In
2013, the State of Alaska entered into a consent decree, which
resolved an anti-trust investigation and set price caps that
escalate at 4 percent annually. The weighted average annual
price under APL-12, which is Enstar's contract with Hilcorp that
was based on the consent decree prices, during its last contract
year will be $8.33 mcf. By contrast, the weighted average annual
price per firm delivery during the first contract year of APL-14
will be $7.56 mcf, almost a 10-percent decrease.
3:48:26 PM
SENATOR STEDMAN asked if a conversion for a btu equivalency to
oil was available.
MS. SMITH said yes and that she would follow up on that. She
noted that importantly, this contract doesn't meet all of
Enstar's gas supply requirements and as of December 23, 30
percent of their portfolio was left open for other producers to
fill. As a public utility, Enstar values safety and reliability
above all else, but they also understand that in the Cook Inlet
market they have to have a diversified portfolio. This contract
not only diversifies supplier risk, but it also helps to foster
investment and drilling, which are good for the long term
stability of Cook Inlet supply.
3:49:13 PM
SENATOR WIELECHOWSKI joined the committee.
MS. SMITH said that Enstar also entered into a second contract
with Furie, which begins at the same time as APL-14 and goes for
three years. It will supply 20 percent of Enstar's annual gas
supply needs, and like the Hilcorp contract, it offers both firm
and optional volumes. Both contracts are pending before the RCA
for approval. These two contracts ensure that Enstar has 90
percent of its needs met through 2021. To ensure the entire
market had yet another opportunity to participate in selling gas
to them, Enstar sent another RFP to producers at the end of
February to recruit participants for the remaining 10 percent of
their open portfolio starting in 2018.
3:50:11 PM
MS. SMITH said they believe that the Hilcorp and Furie
contracts, if approved, represent a huge measure of stability in
the Cook Inlet gas market. They will be the most significant gas
contracts entered into in 15 years, laying the foundation of
Enstar's gas supply well into the next decade. Given where they
were just three years ago, they consider this to be very good
news.
MR. GREEN added that they are working in a very delicate market
with a small number of buyers and a very small number of
producers. Enstar has contracts that meet most of its needs out
to 2021 and 2023, but extensions will have to be negotiated in
the next couple of years. It is important to all of Southcentral
Alaska to have a capable producer marketplace to be there to
provide the gas and the deliverability that their customers
need.
3:51:17 PM
SENATOR COSTELLO said over the state's history, gas contracts
have spanned decades and asked him to explain how things have
changed with the shorter contracts.
MR. GREEN replied that a few decades ago, from Enstar's
perspective, the utility was in "the place that a utility wants
to be." They were a tiny percentage of what the overall
marketplace was producing and buying, and their significant
seasonal needs were easily absorbed by the large assets and
large production that was occurring with the big players in the
marketplace. They were almost inconsequential to the load
challenges that were going on. With that, opportunities were
available for very long term contracts. They were also sitting
with four very large reservoirs of significant reserves that
were easily developable, especially along with the large wells
coming off of both Agrium and the LNG export facility.
Today, Agrium is closed and only a couple of loads of LNG went
out in the last couple of years. He was surprised when LNG hit
the high $8-range and then went down to under $5, recently.
Enstar is now the largest buyer in the marketplace, and its
variability requirements make it a challenge to be there. It's
tough for producers to commit to make their assets available to
hit the peaks for a 10, 15, or 20-year period, because the
production Enstar actually pays them for is significantly less
than that. He said it makes longer term contracts a little more
difficult and Enstar is very happy with the five-year contract
they have in place, because it is significantly longer term than
what they could see back in 2012. This contract is showing a
measure of stability, and a 20-year commitment just isn't
available right now.
3:54:27 PM
BOB PICKETT, Chairman, Regulatory Commission of Alaska (RCA),
Anchorage, Alaska, said he had been a commissioner since 2008
and that the RCA is involved in a number of very critical
proceedings regarding Cook Inlet gas. They have the Hilcorp
purchase agreement with extension options before them, a five-
year agreement that covers 106 Bcf/gas, and a three-year
Hilcorp/Enstar contract with extension options of approximately
19 Bcf. In a little over a week, the RCA will have a hearing
concerning Municipal Light and Power's (ML&P) and Chugach
Electric's proposed purchase of ConocoPhillips's interest in the
Beluga River Unit, so he would not be able to comment on those
matters.
He said the RCA does not have a position on the specifics of SB
130, but it's fair to say, that the commission realizes the
positive role the tax credits have played in the Cook Inlet gas
market over the last few years. A couple of years ago the
conditions were much different and conditions in 2009/10 were
much worse.
3:56:56 PM
The RCA absolutely does not regulate the producers of natural
gas in Cook Inlet, Mr. Pickett said, nor do they regulate the
well head price of natural gas. However, they do evaluate gas
sale agreements between the utilities and the producers. In the
standard review they consider whether the utility acted in a
prudent manner, whether the terms of the gas supply agreement
are reasonable, whether the process to secure offerings to
provide gas to the various utilities was reasonable, and whether
the gas supply agreement assures reliable and reasonably-priced
utility service.
A big contention in Cook Inlet historically is that it has not
been an open and transparent natural gas market, particularly in
2001-2009. In 2001, the RCA approved what was termed a "Henry
Hub Order," which included a variety of pricing proxies that
were considered by the utilities, the producers, the attorney
general, and the RCA. But from 2001 to 2009, not a single one of
those pricing proxies resulted in an RCA-approved gas supply
agreement that delivered gas to utility customers. That led to a
bit of a marketplace issue that was reflected in investment and
the number of wells being drilled, and ultimately, and the exit
from the marketplace of Marathon and Union. In 2010, the
utilities were concerned about where they would get their gas,
and in 2010 Enstar, Chugach Electric and ML&P contracted with
PetroTechnical Resources of Alaska for a study. The conclusions
at that time were quite alarming. In part, the legislature
responded by giving direction to the commission as to how to
evaluate gas supply agreements and modified a section of AS
42.05.141 dealing with the general powers and duties of the
commission adding section (d) as follows:
3:59:51 PM
Section (d) when considering whether the approval of a
rate or a gas supply contract proposed by a utility to
provide a reliable supply of gas for a reasonable
prices in the public interest, the commissioner shall
(1) recognize the public benefits of allowing a
utility to negotiate different pricing mechanisms with
different gas suppliers and to maintain a diversified
portfolio of gas supply contracts to protect customers
from the risks of inadequate supply or excessive costs
that may arise from the single pricing mechanism; and
(2), consider whether a utility could meet its
responsibility to the public in a timely manner and
without undue risk to the public if the commission
fails to approve a rate or a gas supply contract
proposed by the utility.
MR. PICKETT said this general guidance has been helpful over the
past six years and a number of gas supply agreements were
approved within that timeframe with a great variety of pricing
and peaking mechanisms, as evidenced by the most recent
contracts before them. He commended the utilities for
recognizing the importance of leaving a slice of business open
for the smaller producers to become part of the solution to the
needs picture.
He shared Mr. Green's concerns about where they will be in 2023,
because it will take significant investment for gas to continue
being produced in Cook Inlet.
SENATOR STOLTZE asked what some of the triggers are that concern
him as an advocate for consumers and what cautions should
legislators consider on a policy level.
MR. PICKETT answered that one of the most important things on a
policy level is to make decisions that encourage stability and
movement towards a more competitive gas market in Cook Inlet.
One of the things that has helped the Cook Inlet natural gas
market is the rationalization of the pipeline system, which was
very fragmented, Balkanized system. That will make it easier
over time for smaller producers to access the pipeline system
and to know what the rules of the road are and what the
aggregate tariff is on that.
It would be nice to have more competition, too, Mr. Pickett
said, but the RCA has to play the hand that it is dealt. The
legislature has strongly cautioned the commission to not reject
contracts on the belief that something better may come when
there actually is nothing better in the timeframe for which the
contracts are being proposed. It is a very tough thing to say,
because at the end of the day it is the ratepayers who end up
paying.
MR. PICKETT also said he would be cautious with the tax credits
and that the RCA had not taken a position on SB 130. But the
existing investment decisions that have been made in the Inlet
are based on the fact that they can get utility contracts they
can count of for some reasonable extended period of time. The
credits paid a role in those investment decisions.
SENATOR STEDMAN asked if he knew the Btu crossover is between
natural gas and oil, so they could have an idea of a benchmark
in the price of the energy source.
MR. PICKETT responded that he didn't know off the top of his
head, but he would get that information in the next day.
CHAIR GIESSEL thanked Mr. Pickett for taking the time to talk
with the committee today and invited the next presenter to
testify.
4:07:22 PM
TONY IZZO, General Manager, Matanuska Electric Association
(MEA), Palmer, Alaska, said he had been in the utility industry
for 30 years and was with Enstar Natural Gas from 1999 through
2007 and was president for a period of time.
4:08:46 PM
His PowerPoint presentation was labelled "MEA, Natural Gas
Supply, Senate Resources Committee, April 7, 2016." Mr. Izzo
said MEA is the oldest electric co-op in the Railbelt and will
celebrate its 75th anniversary this year. They are now serving
the second largest population center in the State of Alaska with
over 62,000 customers, a service area the size of West Virginia.
Their generation portfolio is 90 percent gas and 10 percent
hydro.
He said the last two bullets provide some perspective in terms
of how much gas MEA buys. It is somewhat unfortunate, based on
his experience, that MEA is the third largest gas buyer in the
Cook Inlet today. It is a reflection of the fact that even
Enstar was kind of background noise in comparison to the two
large industrial users, the Kenai LNG plant and the Agrium
facility. At 6 to 6.5 Bcf, for MEA to be the third largest
electric utility is significant. Their annual cost is in the
$45-to-$46 million range, not including the transportation. This
is a significant number for a utility like MEA, because it
represents 40 percent of the total cost of a kilowatt hour for a
customer.
MR. IZZO said he would answer three questions (slide 3):
1. What is MEA's gas supply forecast?
2. What has changed in the Inlet over the past five years?
3. How have tax credit programs in Cook Inlet affected gas
supply?
4:11:11 PM
He said MEA is coming off a period when it was very difficult to
contract for up to two years of supply (slide 4). They have all
the supply they need through March 31, 2018 (green), and that is
the year the unmet requirements (red) start, going out to 2026.
MR. IZZO said MEA negotiated a supply contract that has board
approval, and they are preparing a filing for RCA approval that
will fill up the red through 2022 and the first quarter of 2023.
He said slide 5 addresses what has changed in the last 5 years
in Cook Inlet. Five years ago, gas supply was available in small
quantities and for short terms. He was at Enstar in 2001 when
they signed an agreement that was linked to the Henry Hub that
was capped at 450 Bcf. This large agreement was linked to a
three-year trailing average of the Lower 48 prices. In response
to some concerns, in 2005, they filed their next agreement,
which was a 12-month trailing average of Lower 48 prices that
would have filled up all of the gas utilities' needed
requirements through 2016. That contract was not approved in
2005/6. If those were in place today, prices in the Lower 48 are
in the $2 range and South-central utilities are currently paying
in the $7.42 range, which is the consent decree price negotiated
by the Attorney General.
4:14:59 PM
MR. IZZO said the reason he raises the issue is when the
contract was rejected, Marathon and others slowly decreased
investment and interest in the region, eventually devolving to a
point where they left the Inlet entirely once their contractual
obligations were either met and/or sold to others. That's what
took them to the point of five years ago, but it's an important
point, because he would hate to repeat history. Utilities could
not support things like extended LNG export, industrial growth,
or exporting gas to other parts of the state. It was not a sign
of success; it was a sign of dysfunction. A market is needed
that is growing, expanding, and attracting investment.
The most significant positive change in the last five years has
been the Hilcorp investment and the consent decree. The best
price he could get four or five years ago was $10 for 20 percent
of MEA's supply. He also joined with the other utilities in
looking for LNG imports. However, another significant change
brought multiple new players into the Inlet who have invested
significant capital, one of them being Hilcorp.
MR. IZZO said all of the gas MEA has under the existing
contracts are through 2018, and maybe beyond. They are from the
same three or four mature fields that were discovered in the
late 50s and 60s. It's Hilcorp's core completeness in increasing
production from mature aging fields combined with the investment
that has made the significant change in Cook Inlet.
MR. IZZO said all can agree that what has not changed is that
they know where gas is in Cook Inlet: the Cosmopolitan Field off
of Anchor Point and the Kitchen Lights Unit, which Furie has
begun producing. The concern he has as a buyer is that he has to
look at gas in terms of if it's behind pipe and commercially
available for him to get deliverability.
He said that slide 6 illustrated the impact of the tax credit
program on Cook Inlet. The good news is that multiple new
investors are available for gas supply discussions, the lives of
mature fields have been extended, and some additional proven
reserves have been put behind pipe. Another bit of good news is
energy security, but that is temporary. Part of the bad news in
terms of the impact of the tax credits is that significant new
reserves are not behind pipe and doing so will require
significant current and future investment, and very long lead
times. The impact of the tax credits has brought on access to
gas that has been behind pipe for a long time and maybe wasn't
producible or economic to produce and simply required a lot of
investment.
4:20:42 PM
MEA is an island in the sense of energy infrastructure (slide
7). They are the only climate with both seismicity and a sub-
Arctic climate, which means curtailing rolling blackouts to
preserve supply, which most Lower 48 markets find unacceptable.
Finally, he summarized that uncertainty is the enemy of energy
(security). Exploration and production risks are not typical
core competencies of a regulated utility.
MR. IZZO stated that if he finds himself in a situation like
four or five years ago, where it's going to take $4-5 million
for exploration and production and a pipeline connection to
maybe get gas into an area where he has no core competence
versus importing LNG for a price that is a little bit higher, he
believes - as he did prior to the consent decree - that
importation would be in the best interest of his customers.
He said that bringing new gas reserves to the point that they
can be prudently purchased by a regulated utility requires
extensive investment and many years. Because he spent so much
time in the private sector part of this investor-owned utility
business, he believes in metrics. If a program is designed to
deliver a result, there should be some key metrics to determine
what the results are. In terms of Cook Inlet and the impact of
the tax credits the real metric is investment, and when that
went away in 2005/6, there were rolling blackouts and energy
curtailment drills. The Cook Inlet Recovery Act and CINGSA
turned things around. He doesn't want investment to go away,
because getting it back will take a long lead time and be a
capital intensive activity.
4:23:49 PM
SENATOR STOLTZE asked Mr. Izzo for a narrative about cooler
winters and the dynamics that will lead to MEA's ability to
provide power if there is a shortage. Is there a prioritization
of how the utilities supply for space heating over electricity?
MR. IZZO answered that Mr. Green's 12:1 ratio swing between
summer and winter load is consistent with his experience. He has
seen an extreme case of almost 19:1. For an electric utility
like MEA that is 94 percent residential customers, the
difference in demand between summer and winter follows daylight
almost more than weather. For that they see a 2:1 ratio.
He explained that prioritization is subject to a number of
factors, but deliverability is king. That is the measure of
being able to get the volume of gas at the moment that is
needed. Sometimes it's based on production at a well, or
compressor capacity, or pipeline capacity. It can be based on
where the demand is located. Most jurisdictions in the Lower 48
use a variety of measures. One thing is for sure, if the gas
goes out, there is a much longer process of shutting off,
repairing, purging, reintroducing gas, and unlocking meters.
Therefore, MEA would curtail power, because it is the right
thing to do. He said MEA is not a signatory to what is called
the 2009 Gas Emergency Letter, an agreement amongst the
utilities that rather than let the gas system go out, they would
attempt to reduce demand through a process of rolling blackouts
a couple of hours at a time, and moving it around the system. If
that were to occur, his members and ratepayers would become much
more concerned about what plans are in place to address that.
The Lower 48 gas utilities have access to imports from Algeria
to Massachusetts, and it can be trucked and stored for when it
is needed on those coldest days.
4:29:04 PM
MEA is designed differently for a variety of reasons, Mr. Izzo
said, and they probably wouldn't build a second one like it, but
their engines are dual fuel and are run at an efficient range of
RPMs. It's ultimate efficiency, unlike others, does not occur
when the plant is running full throttle. They store about 1
million gallons of diesel, which would provide enough backup
power for approximately 4.5 days of peaking days and to offset
any rolling blackouts. And if it's not too presumptuous, because
it is something they purchase, he stated that one needs 7.3
gallons of diesel for 1 million Btus to equate to 1 Mcf/gas. He
is buying diesel right now in the range of $1.38, which means he
is paying about the equivalent of $10.07/8 per Mcf for an
equivalent Mcf of gas, which is costing him $7.42.
SENATOR STOLTZE said up until sometime in 2015, he attended
regular meetings of the Energy Security Committee led by the
Municipality of Anchorage and MatSu Borough and asked if those
types of meetings are still being held or if the crisis is over.
MR. IZZO answered that he was chair of the mayor's Energy Task
Force and always appreciated seeing Senator Stoltze there. With
the change in administration, that group was able to shift its
initial focus away from the immediate crisis, partly because of
having the availability of supply, and the Municipality of
Anchorage utilities continue to meet in unprecedented
cooperation for contingency planning. He feels very comfortable
because all of their generation units are linked; each unit can
see what the other is doing. The daily number of transactions -
buying and selling the most efficient energy back and forth -
has increased from zero or one a year ago to five and seven per
day. These transactions are purely based on win-win economics
between the electric utilities. If that coordination continues,
he is confident in their ability along with Enstar to address
any type of emergency.
SENATOR STOLTZE said he appreciated the information.
4:32:26 PM
SENATOR STEDMAN commented that energy supply is clearly a
function of price; when the price gets low the supply dries up
and vice versa. If the gas into the Railbelt is somewhere around
$1.00, the so-called cheap hydro energy in Southeast is still
about $3.50/oil. He remarked "if $3.50/oil is cheap, $1/oil must
be free!" He said that places like Iceland have a flat energy
price around their whole island to levelize the economic
advantages or disadvantages that each section has.
CHAIR GIESSEL thanked Mr. Izzo for joining the committee today.
^Continuation of Additional Modeling and Scenario Analysis by
DOR
4:33:55 PM
CHAIR GIESSEL invited the Department of Revenue (DOR)
representatives to continue their presentation from the previous
meeting on oil and gas tax credit reform in SB 130 labelled
"Additional Modeling and Scenario Analysis." She noted that
legislators have a "quick reference" summary of the statutes
addressing the credits.
4:34:12 PM
RANDY HOFFBECK, Commissioner, Department of Revenue (DOR),
introduced himself.
4:35:13 PM
KEN ALPER, Director, Tax Division, Department of Revenue (DOR),
introduced himself and related that he had added a column for
North Slope production beginning in FY09 and forecasted forward
through FY25 onto slide 4, which made it slightly more complex
but maybe more understandable. Because they had an "alternative
reality" that was leading to FY16, they then said, if they are
going to really forecast, they have to reset the present day to
zero and look at the issues of stacking-up, carried-forward, and
net operating loss (NOL) credits from there. The new orange row
is FY16 as it is and what the future will look like based on
certain assumptions.
4:36:09 PM
MR. ALPER said yesterday they talked about the history and what
would have happened had they only appropriated money per the cap
through the guideline language in AS 43.55.028. The general idea
was to endow a fund and build up a balance approaching $600
million, spend that down in FY15, and then be right around where
they are in FY16, the difference being perhaps a different level
of expectation and assumption as to the nature of the state's
role in funding ongoing tax credits. He had updated this slide
with information from the final version of the spring forecast,
which the commissioner released at about 2:00 today. It doesn't
make a whole lot of difference, just some small differences in
revenue assumptions.
Looking down into the FY17 row at the end of FY16, no matter
what is done, the credit account will be zero. The governor
vetoed the number at $500 million last year and $500 million was
transferred to the fund. By the end of the year it will have
been spent. There will be roughly $775 million of claimed
credits in FY17. Should the legislature appropriate either the
$73 million that is in the current budget or the $29 million
that is the revised figure from the credit cap, obviously the
fund would be highly short-funded by over $700 million.
4:38:13 PM
Continuing along those lines, Mr. Alper said, the forecasted
credit spend (column known as "Actual Claimed Credits") starts
to stack up. The appropriated column is called the "Credit Cap
per AS 43.55.028," and the credits that are owed by the state
start to stack up going from year to year. Meanwhile, happening
almost in parallel to this, is the idea of non-cashable NOL
credits, the credits earned by the major producers. Those
numbers have a couple of small revisions. The department
switched from an accrual system to a more cash-based system. In
other words, they are not going to count any credits that are
earned at the end of FY16 until the end of calendar year 2016
(CY16), because they are NOLs. Because of that, there is a zero
in the FY16 row. The $618 million NOLs represent the operating
loss credit really for CY16. Those credits will have to be paid
some day indirectly, meaning that once the price of oil
recovers, the major producers will subtract that number from
their production taxes to the state.
When will that money be paid? The chart indicates roughly in
FY21/22, when the big numbers go down from $600 million to $100
million. In those years the difference is there will be a tax
liability to subtract the NOL credits from and the taxes will be
paid in smaller rates as the NOLs are "billed down."
MR. ALPER said the last column on the right is the sum total of
both the cashable credits plus the non-cashable credits that are
awaiting the return of higher oil prices. At the end of the day,
the state would owe $2.8 billion in FY25.
SENATOR WIELECHOWSKI said it looks like the FY17 numbers have
been revised to the actual claimed credits of $775 million. Then
the state receives a production tax of $59 million, which leaves
the state paying out $715.6 million more in tax credits than it
is receiving in production taxes. He asked if this math is
correct.
MR. ALPER answered yes; so long as he is just talking about the
production tax.
SENATOR WIELECHOWSKI asked if any other jurisdiction in the
world pays out more in credits than it receives in taxes.
MR. ALPER answered not to his knowledge, but he didn't claim to
have a comprehensive knowledge of world tax regimes. Alaska has
an unusual system and it's an unusual time given the collapse in
oil prices.
SENATOR STEDMAN said it's a complex subject, so it's nice to see
it in black and white. His concern was that in the future, the
state would have to pay off its projected liabilities of around
$2 billion, and then it will be hard to explain to public the
advancing prices without advancing revenue to the state. How
will they deal with that?
COMMISSIONER HOFFBECK responded that the Revenue Sources Book
projects revenues separate from expenditures. The cashable
credits are not going to show up as a negative against the
revenues. A line item shows them as an expenditure.
MR. ALPER added for example, last year when the department
anticipated more credits than there was money appropriated, that
$200 million shows up in this year's forecast as part of the
$775 million. Should something similar happen at the end of this
year when they are doing the revenue forecasting in the fall,
that one-time carry-over number will roll into the FY18
forecast. It is hard to forecast credits more than one year
ahead, he said.
4:44:37 PM
SENATOR WIELECHOWSKI went back to his same question about how
much more the state is paying out than it is taking in and said
it looks like in FY15 the state paid $628 million in tax credits
and brought in production tax of $363 million. So, the state
lost money in FY15/16, and it is projected to pay out more in
production tax credits than it receives in production taxes all
the way out to 2024. Is that correct?
MR. ALPER answered yes; that is the way the chart reads.
SENATOR WIELECHOWSKI said then in 2025 the state is projected to
pay out $250 million and to receive $275 million in production
taxes, but then when the credits are applied against
liabilities, the state is still projected to have a loss that
year. Is he reading that correctly?
MR. ALPER answered no, and explained that the $275 million is
after subtracting the credits against liabilities. The reason
for that is the column to the right of that has $370 million,
which is the tax liability based on the calculation and then the
$95 million would come off of that in various credits against
liabilities, and $275 million would actually be received by the
state.
CHAIR GIESSEL asked what percent of decline is being projected.
MR. ALPER answered if the production is at 300,000 barrels in
2025, the difference between 500,000 and 300,000.
COMMISSIONER HOFFBECK added that amounts to a 4-5 percent
decline per year.
CHAIR GIESSEL asked if he based the projection on the assumption
that companies that are losing money now will continue to
invest, and that the state will have the projected 4-5-6 percent
decline, when in fact if companies stop work, the state would be
looking at 12-15 percent per year decline rate. Has the
commissioner taken any of those "rational decisions" that a
company losing money would make into account?
4:47:27 PM
COMMISSIONER HOFFBECK answered some of that is already embedded
in the forecasted decline. They only project investment that is
currently ongoing or that is planned and sanctioned. Any new
investment is not part of the forecast. As for the 15 percent
decline, he explained that fields decline at a hyperbolic rate
and kind of flatten out as they age. He didn't know where the
field is on that decline curve.
4:48:24 PM
CHAIR GIESSEL said before SB 21, the state was experiencing a 6
percent decline and that was with significant investment to keep
that decline at only 6 percent. With the withdrawal of three
rigs, which she didn't know was in his calculation, that decline
curve will accelerate.
MR. ALPER responded that the spring forecast does somewhat
account for the withdrawal of the three rigs announcement made
by the Prudhoe Bay operator earlier this spring.
SENATOR COSTELLO said at some point with companies experiencing
net operating losses, that the amount of revenue the state will
get from royalty will exceed the production tax, and asked if
that was correct.
MR. ALPER answered that is currently the case.
SENATOR COSTELLO asked since companies are paying income,
royalty, and property tax in addition to the production tax, if
it would be possible to have a column showing the complete tax
picture of what the state is receiving from the companies.
MR. ALPER answered yes, and added that the numbers had been
"thrown around" in the last couple of weeks since the spring
forecast and there had been some controversy over what the
appropriate numbers are, and he wanted to make sure they have
the right ones. Some attention has been paid to the idea of
total unrestricted general fund petroleum revenue, because for
the first time that number is below the credit forecast. There
is also the entirety of petroleum revenue, which includes such
things as the Permanent Fund deposits from royalty, CBR deposits
from assessments and that kind of thing and his preference was
to put both of those additions into columns.
CHAIR GIESSEL said members have the document that was released
this afternoon on their desks and revenue coming in from all of
those things was on page 14.
MR. ALPER responded yes, and added that the number shouldn't be
terribly different from what they had a couple of weeks ago. He
just hadn't had time to look at them today.
4:51:27 PM
SENATOR STEDMAN said in 2012 under Alaska's Clear and Equitable
Share (ACES), SB 21 wasn't even a concept; testimony in Senate
Finance during that time stated production was approaching the
2-3 percent decline rate, and there was testimony in Senate
Finance about the parabolic curve. No testimony was brought
forward to the committee at that time about getting off of that
parabolic curve. The geology of the basin can't be changed by
changing tax codes, he said. This parabolic curve has been
studied for decades and it can be brought forward in time, but
no more oil can be created in the ground. As policy has changed,
production has increased in the near years, but the rate of
decline also increased, and that has become a problem with a lot
of sovereigns around the planet. That 2-3 percent decline curve
was forecasted in testimony in Senate Finance in 2012 and maybe
2011, because they spent two years having hearings on ACES as
they tried to restructure it.
SENATOR WIELECHOWSKI recalled the many advertisements saying
that the "drop was stopped" after passing SB 21. In fact, the
bill was labelled the "More Alaska Production Act." Production
in the last year of ACES (2012) was 579,000 barrels and
production is forecast to be 302,100 barrels in 2025. He asked
if it is fair to say under the More Alaska Production Act the
drop was neither stopped nor production added.
COMMISSIONER HOFFBECK responded that the decline has continued
but it is not justifiable to say production has not been added.
There has been added production, but not enough to totally stop
the decline.
CHAIR GIESSEL asked if he was comfortable with the committee
checking the Division of Oil and Gas on that statement related
to production.
COMMISSIONER HOFFBECK answered absolutely, but he was just
trying to parse the difference between the two.
SENATOR WIELECHOWSKI said virtually all production is new
production and asked Commissioner Hoffbeck if he would agree
that 302,000 barrels of oil being produced in 2025 is less than
579,000 barrels that were produced in the year before the More
Alaska Production Act was passed.
COMMISSIONER HOFFBECK answered yes.
CHAIR GIESSEL asked Commissioner Hoffbeck how certain he was of
the production forecast out to 2024.
COMMISSIONER HOFFBECK answered that the forecast uses a lot of
conservative assumptions.
CHAIR GIESSEL asked if he had considered the Repsol/Armstrong
field that is potentially coming on line in the next five years.
COMMISSIONER HOFFBECK responded that it is not in the forecast.
SENATOR COSTELLO asked if he knows the opportunity cost to the
state of capping the Tax Credit Fund and not providing cashable
credits.
4:56:27 PM
MR. ALPER answered that it's hard to project what might not
happen. Later in this presentation they show how project
economics might affect a particular project going forward or
not. However, the opportunity cost is only a cost if something
doesn't happen and that is what becomes very hard to calculate.
SENATOR COSTELLO asked if he was suggesting that there are no
opportunity costs in some scenarios.
MR. ALPER answered no; he was just saying that on one hand there
is the opportunity cost of spending money on credits that
weren't necessary if the project was going to happen anyway, and
then a cost in the other direction is when the state has paid
money that it is going to get the same revenue on in the future.
He was just saying there are too many variables to conclusively
say what will and will not happen with the changes. That is why
they have a deliberative process.
CHAIR GIESSEL asked Mr. Alper if he feels that hardening the
floor will help or exacerbate the carry-forward issue that is
illustrated on his chart.
4:58:12 PM
MR. ALPER answered that hardening the floor was conceived of as
an issue last year when the department realized significant NOL
credits were going to be used against the floor. Other states in
a gross tax regime (like Alaska) actually get their gross tax,
and Alaska might be getting to a place where it might not be
getting it. Now suddenly, they are seeing a new variable: the
stacking up of carry-forward losses. To answer her question
directly, no, hardening the floor actually makes it worse. If
company X earns $500 million in carry-forward losses and they
can use $200 million to offset their minimum tax and therefore
carry forward $300 million, the state would be asking them to
carry forward all $500 million, and therefore the impact in the
future when prices go up would be even more. This larger problem
of the NOLs is not being addressed in this legislation.
4:59:13 PM
SENATOR STEDMAN commented the he thought he saw a marginal
increase in production since 2011/12 versus what was expected,
but it would be interesting to measure how much and compare that
to what was going to be done anyway. That is hard to do because
corporate politics are involved in slowing down particular
projects to get a benefit in the tax structure. Clearly the
numbers are going down and even if production were flat at
490,000 or 500,000 barrels it would still lead to the state
taking carry forward OL credits very seriously and there has to
be some sort of plan to deal with them.
COMMISSIONER HOFFBECK responded that in regards to the forecast
of production, they need to be cognizant of the fact that laying
down the rigs and those kinds of things are being driven by the
oil price. The state can do very little with credits to
overwhelm $38 oil. The decisions being made are simply because
companies can't produce with a profit at $38/oil. It has nothing
to do with the state's tax policy.
5:01:43 PM
SENATOR STEDMAN said it looks like laying down rigs will impact
production at some point, and it would be nice to get a briefing
on that just for general knowledge. You can't lay down rigs and
have it be beneficial for production; he also understands that
getting them up takes a while. It looks like what is going on
today will affect production four or five years out, and at the
same time the state is trying to deal with the NOLs - "And we
end up in the pickle." Maybe that can be mitigated through
legislation.
SENATOR STOLTZE apologized since his question was not a hardball
question, such as whether 300,000 is less than 500,000. He
apologized further, since he forgot the question in light of the
complexity of previous questions.
SENATOR MICCICHE said the decline rate for 15 years following
FY14 is an absolute flattening for seven years, even with
conservativism designed into the model, and if that is the most
they accomplish in forward tax policy dealing with some of the
credits and hardening the floor and other options, it is
certainly a better direction than where we are heading.
CHAIR GIESSEL pointed to 2025 with 300,000 barrels and said, "We
will be in a really bad place regardless of what the price is."
SENATOR WIELECHOWSKI clarified he will not ask anymore hardball
questions, and asked if companies can write off the cost of
laying down rigs or are they eligible for tax credits.
MR. ALPER answered that he knows the department has denied
credits for rig standby fees and his expectation is that those
sorts of costs won't be allowed to be deductible, but he would
find out the precise way that is done.
SENATOR STEDMAN said as long as they were "digging up old bones
and throwing them around the table," he would like DOR to run
the current tax structure at $40 relative to the economic limit
factor (ELF) and ACES at $40.
MR. ALPER replied that he would do that and that ELF will
probably win at $40 oil. But one thing the department has
stopped doing over the last couple of years is track and project
what the ELF multiplier is on a field-by-field basis. So, they
are left with a little bit of theory about what the ELF tax rate
would have been had it been in place all these years. To the
extent they can "fake that a little bit based on past trend
lines" they should be able to answer his question.
5:07:46 PM
At ease
5:08:16 PM
CHAIR GIESSEL called the meeting back to order and Mr. Alper
continued with slide 5.
MR. ALPER said slides 4 and 5 were both supplemental slides
added after questions after he had gone through an analysis of
the credit applications that were before the Tax Division on
April 2. The request was made to break them out into Cook Inlet
and Middle Earth versus North Slope, which was done. They worked
from the number of $675 million in credits, consisting of the
so-called older NOL credits versus the older exploration
credits. The big pile of credits from the end of last year
reverses a little bit of the trend line for the prior two years,
which was a very Cook Inlet-heavy spend. In 2015, $335 million
in credits were NOLs from North Slope spending and $217 million
from Cook Inlet and Middle Earth, in general; breaks into about
a 50/50 split. Companies that get the drilling credits and can't
be split out on a chart, because that would impinge on their
confidentiality, because there aren't too many of them.
The last minute exploration credits were tied to the sunset and
were particularly relevant in the North Slope area, because it
had 85 percent credit support for a limited window of time (40
percent exploration credits, stackable in CY15 with the 45
percent NOL). His sense was that companies were saying if they
were going to drill an exploration well in the next few years
they might as well do it in 2015, because the system was
calibrated to their maximum benefit. The few credits that are
going to be refiled are North Slope heavy, but the general
thrust is $422 million versus $253 million. He offered to keep
the committee updated through the year, but that is the best he
knew at the moment.
5:10:56 PM
MR. ALPER said slides 6 and 7 have the meat and detail of SB
130. Section 7 is on the topic of interest rates, not an oil and
gas specific section, but general statutes of the DOR describing
how interest is charged and how delinquent taxes are dealt with.
The historic interest rate was quite high, 11 percent and
compounding in the 70s. SB 21 reduced it from a fixed 11 percent
to 3 percent above the federal discount rate. However, there was
an awkwardness with SB 21; it did not have enough votes in the
Senate to pass an effective date clause. That meant when the
bill got to the first House committee, they needed something of
a workaround, and "applicability language" was used. It said
production prior to January 1, 2014 is X; prior production after
January 1, 2014 is Y. The new interest was in the after section,
but meanwhile, even though the compounding language found its
way through the system in all versions including House
Resources. There was a technical error in House Resources. The
last committee substitute (CS) in House Finance (slide 8) fixed
that technical error, but added back the higher 11 percent
language that was in the original law with the compounding
language.
He explained that for most big bills after the work draft CS is
put on the table there is often a technical amendment by the
chair that cleans up a lot of the smaller provisions in the bill
that are brought to the chair's attention. This amendment was by
Chairman Austerman and contained six or eight different changes,
miner things. But in doing so, while eliminating the annual rate
of "11 percent whichever is greater phrase" it also deleted the
"compounded quarterly as of the last day phrase." No one caught
it and the bill passed the House, was concurred with in the
Senate, and became law, and low and behold, Alaska no longer had
compound interest on any of its taxes for the first time in 30-
some years. So, that is the state Alaska is in now, which is a
simple interest calculation on all delinquent taxes. This
quarter, the number is 4 percent (1 percent federal discount
rate plus 3 percent).
CHAIR GIESSEL asked if this interest rate applies to other
industries as well as oil and gas.
MR. ALPER answered that it applies to other taxes as well:
corporate income tax, tobacco, mining, fish, etc. etc.
5:14:56 PM
He said the intent of the legislation was to find middle ground
(slide 9) between the historic 11 percent and the current
effective 4 percent. The underlying idea is that right now the
state is funding the budget out of its savings. That is the
reality; therefore a dollar that is not received in taxes is
another dollar out of those savings. Consequently, when the
state finally gets paid that dollar because it has gone back to
the taxpayer in whatever industry and said this is the tax you
owe plus interest, the interest should in some way compensate
the state for the cost for not having had it in savings for the
intervening years, effectively the opportunity cost. So the
intent of section 7 was to try to find a number that roughly
approximated what the Permanent Fund expected to earn on its
money, because that is the biggest savings account the state has
that might in the future be used to fund ongoing government
operations. The Permanent Fund estimates that number to be about
7 percent right now.
CHAIR GIESSEL pointed out that the same also applies if the
state has collected too much tax; the state owes it back plus
the interest.
MR. ALPER agreed with that and said this applies not just if
someone overpays their taxes but if someone pays the amount the
state assessed and contests it, goes through the process, wins
or even partially wins, and the state pays them back; the same
rate of interest from the original assessment is used.
COMMISSIONER HOFFBECK added that the intent was not to make it a
revenue source or revenue loss, but to make it as revenue
neutral as possible.
5:17:10 PM
MR. ALPER said slide 10 attempts to model that with the
expectation of a July 1, 2016, effective date. For example, if
the state had $1 million in debt for the first two quarters, at
4 percent per year, that is a straight $10,000 per quarter. So
over the six quarters in the current law, there would be $60,000
worth of interest, but beginning in the third quarter of 2016,
with the amended version of the language, first the interest
would double to roughly 8 percent and, second, the interest
would be applied not to just the original $1 million, but to the
$1 million-plus interest that was accruing.
MR. ALPER said the committee has to make two decisions in
addressing section 7: should the state switch to compound
interest in the first place, the deletion of which he believes
was an inadvertent technical error, and secondly, should they
increase the rates to make interest something more of a revenue
neutral phenomenon for the state.
CHAIR GIESSEL asked how the interest is compounded: monthly,
quarterly, annually.
MR. ALPER answered quarterly.
5:18:44 PM
He said slide 11 summarized the interest change section and that
it's hard to quantify revenue impact, because they don't know
what they are going to assess. The department completed the CY09
production tax assessments last week and the total was $132
million, about one-third of that was interest. This is a change
that will build up value over time; there is very little near-
term impact. When it comes to oil and gas, it doesn't go to the
General Fund (GF) anyway. Any tax conflict/appeal money goes to
the Constitutional Budget Reserve (CBR). The only GF impact from
this change will be the other industry taxes the chair referred
to earlier.
CHAIR GIESSEL asked if the Tax Division took the full statutory
limit to complete 2009 audits.
MR. ALPER answered yes and explained that they had to slow down
their audits for a few years to build up to the new software and
catch up with some things. They are doing 2010 and 2011
concurrently and should be caught up one year from now.
SENATOR STEDMAN said when they take money out of the CBR they
are technically borrowing it and asked when they put interest
back in, does that count as a partial repayment back to the CBR
or is the whole amount owed from some other source. It's a
nuance and he was curious.
5:20:25 PM
COMMISSIONER HOFFBECK answered that those would be new deposits
to the CBR, so the liability would remain. However, he would
confirm that.
CHAIR GIESSEL said she saw another appropriation to upgrade that
software more.
MR. ALPER answered that the software contract was in excess of
$25 million originally; the full appropriation was $34 million
and change to cover other costs involved with implementation and
consulting services. The fiscal note for this bill is $1.2
million. He explained that all DOR bills have some degree of a
fiscal note involved in the reprogramming and testing. It is a
laborious process. This one is bigger, frankly, because it is a
more comprehensive bill, and because they are going to be
changing the interest rate formulas in all 25 of the state's
taxes makes it more of a comprehensive task.
5:21:40 PM
MR. ALPER said slide 12 illustrates what increasing the minimum
tax does. A couple of different sections of the bill deal with
the minimum tax itself, but section 12 is purely about the raise
from 4 to 5 percent, as proposed by the governor. This slide
shows the 35 percent production tax under SB 21 and both a 4
percent and 5 percent minimum tax after credits for FY17.
SENATOR STEDMAN asked if this slide takes the NOLs into account.
MR. ALPER answered no.
SENATOR STEDMAN said at some point they will want to see the
impact from the NOLs.
MR. ALPER responded that if the NOLs were accounted for on this
slide, in the second or third year of low prices the revenue
would turn out to be about zero. This is a snapshot of the first
year. If you start using NOLs against taxes, depending on how
high the stack of NOLs is, it's going to drag the overall
revenue curve down in the future years. That would not be so
much a function of this year's price, but it would be a function
of last year's NOLs.
SENATOR STEDMAN said that he therefore shouldn't expect revenue
in the millions because at some point the potential couple
billion in credits are going to be accounted against the state.
MR. ALPER agreed and said this graph assumes there isn't that
drag of the NOLs from the past.
5:25:42 PM
He explained slide 13 was just more graphics showing the fiscal
impact of increasing the minimum tax. Gross value at the point
of production is roughly the equivalent of market price minus
$10 for the transportation cost to get it there. About $160
million taxable barrels per year are produced, so 4 percent of
whatever that would be, and then the additional 1 percent at
$30/oil is about $20 million, and it goes up as the price of oil
increases to upwards of $80 million at $75/oil and then it drops
off. And the reason for that is past $75 to $78/oil they are out
of the minimum tax and into the regular tax, and so at higher
prices there is no impact from increasing the minimum tax; it's
purely an academic exercise.
He related that for all the years the state had a minimum tax,
it never kicked in until the last months of 2014. That's roughly
the fiscal impact of this specific section of the bill; for
simple terms they have called it $50 million, but it is actually
a somewhat variable number tied to the price of oil.
5:27:12 PM
Meanwhile, elsewhere in the bill, Mr. Alper explained that more
complex sections "harden" the minimum tax. He explained that SB
21 made the minimum tax stronger than it previously was, and it
did so by saying that the sliding-scale zero to $8/per-barrel
credit for legacy oil on the North Slope (AS 43.55.024(j) cannot
go below the floor (slide 14). However, the other credits
(arrows) can in fact under many circumstances go below that
number all the way down to the so-called basement, to the zero
percent production tax. Those include the Net Operating Loss
Credit, the GVR eligible per barrel credit (fixed $5/barrel for
new oil), as well as the small producer credit, and the
alternative credit (exploration credit). All of those can go
below the floor, and the intent of the bill is to harden the
floor, meaning those credits should also be held to 4 percent
minimum tax rate.
CHAIR GIESSEL asked if small producer credits and alternative
credits are both going away, true or false?
MR. ALPER answered that is true; the small producer and
exploration credits would have a very limited short duration
impact if the floor were hardened (slide 15).
5:28:30 PM
He explained that the exploration credits will be gone one year
from now except for Middle Earth and the small producer credits
will be phased out over the next seven, eight, or as many as
nine, years.
MR. ALPER said there are really three different policy decisions
before the committee and they all pertain to the North Slope:
1. Should the producers who have an net operating loss credit
(NOL) be able to use those to go below the floor and should this
be retroactive to January 1 (the only section of the bill they
have asked to be retroactive because of the current circumstance
this year of receiving payments below the minimum tax and are
hoping to backfill that (in the governor's original proposal))?
2. Should new oil production be allowed to pay at the zero rate?
3. Should everyone be forced to pay the minimum tax and not just
the major producers?
CHAIR GIESSEL thanked Mr. Alper and said slide 17 was a good
breaking point.
[SB 130 was held in committee.]
| Document Name | Date/Time | Subjects |
|---|---|---|
| SB 130-Enstar Presentation to SRES-4-7-2016.pdf |
SRES 4/7/2016 3:30:00 PM |
SB 130 |
| SB130-Revised Slide #4 from DOR 4-4-16- Presentation 4-6-16.pdf |
SRES 4/7/2016 3:30:00 PM |
SB 130 |
| SB130-MEA Presentation to SRES-4-7-2016.pdf |
SRES 4/7/2016 3:30:00 PM |
SB 130 |