Legislature(2015 - 2016)BARNES 124
03/01/2016 01:00 PM House RESOURCES
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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 |
HB 247-TAX;CREDITS;INTEREST;REFUNDS;O & G
1:00:11 PM
CO-CHAIR NAGEAK announced that the only order of business is
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."
CO-CHAIR NAGEAK noted that the committee will continue hearing
invited testimony from the oil and gas industry regarding the
potential impacts of HB 247.
1:01:01 PM
REPRESENTATIVE JOHNSON requested that Mr. Seckers of ExxonMobil
Corporation provide his qualifications as a tax expert.
DANIEL SECKERS, Tax Counsel, Upstream Business Services,
ExxonMobil Corporation, stated that was previously a chief
appeals officer for the Internal Revenue Service (IRS), has an
undergraduate degree in accounting, a minor in economics, two
masters degrees, and two law degrees of which one is Masters in
Law on Taxation. He has worked for ExxonMobil Corporation
("ExxonMobil") for nearly 30 years and has done Alaska taxes,
international taxes, and transactional taxes.
REPRESENTATIVE JOHNSON commented that he wants the committee to
know it is dealing with people who are qualified.
CO-CHAIR NAGEAK requested that all witnesses provide comment on
the impacts that the changes proposed in HB 247 would have on
their respective companies.
1:02:56 PM
MR. SECKERS thanked the committee for listening to ExxonMobil's
views on this troubling legislation. He stated that in today's
economic environment, ExxonMobil is committed to Alaska and
continues to actively pursue all attractive investment
activities in the state. ExxonMobil has had a presence in
Alaska for over nine years, has invested over $20 billion to
date, and Alaska remains a very important part of ExxonMobil's
worldwide investment portfolio. He recognized that legislators,
as policy makers, have the very difficult task of trying to
resolve the state's budget problems, trying to maintain current
revenue streams, and yet trying to maintain Alaska as a
competitive and attractive place for companies to invest.
MR. SECKERS said tax policy decisions fundamentally impact the
economic health of Alaska and the companies that are doing
business in the state. ExxonMobil believes that tax policy
decisions need to move the state forward, not away from, its
vision of oil and gas development. It is critical for
legislators to maintain every stable and competitive investment
environment. ExxonMobil believes the question that really is
before the committee is whether or not to raise taxes on the oil
and gas industry at the very time when the companies are
reporting significant losses on the very activities that HB 247
is trying to tax. Is it sound tax policy for legislators to do
that? Do legislators believe that such action will actually
help the state weather these hard times or make matters worse?
1:05:01 PM
MR. SECKERS said he will break down his comments into three
areas: substantive law changes, procedural changes, and tax
policy changes. He said ExxonMobil agrees with yesterday's
testimony from the Alaska Oil and Gas Association (AOGA), and
from each of the other companies, that HB 247: represents a
significant tax increase on the oil and gas industry; will not
improve Alaska's overall investment climate; will not lead to
more jobs or opportunities in the state; and will not help,
maintain, or increase oil and gas production levels. ExxonMobil
believes that HB 247 will do the exact opposite and for these
reasons ExxonMobil opposes HB 247.
MR. SECKERS first addressed the substantive provisions of the
bill. He said raising the minimum tax from 4 percent to 5
percent is a tax increase of at least 25 percent on companies on
the North Slope on their gross revenues. Raising taxes on
companies that are reporting record losses, losses on the very
activity that HB 247 is trying to tax, is not sound tax policy.
The hardening of the minimum tax floor is also very troubling.
Section 17 of the bill would prevent companies from realizing
the true economics of their investments by preventing critical
tax credits from being used to offset the minimum tax.
Disallowing companies from using earned or available tax credits
to reduce the minimum tax would represent an immediate and
significant tax increase. It would penalize companies that have
made prior year investments even when they were losing money.
It would penalize companies today that are continuing to make
investments even though they are losing money and that are
continuing to make investments despite the low price
environment. The impacts of Section 17 were summed up well when
yesterday AOGA stated that both large and small companies that
may have new oil tax credits, exploration credits, drilling
credits, tax loss credits, sliding scale credits, new oil
credits, and that may be in a loss due to low prices, are all
going to be at risk to having such valuable credits either
denied or deferred. In either case, it is a current year tax
increase.
1:07:31 PM
MR. SECKERS offered ExxonMobil's belief that in order to
maximize investment in Alaska it is critical to provide
investors the opportunity to capture the economic benefit of the
investments they've made, especially given the inherent downside
long-term risks of capital investments on the North Slope.
Section 17 will significantly and negatively impact Alaska's
investment climate and the perception of Alaska's investment
climate to any future investors by announcing to the world that
Alaska is willing to adversely affect the economics of prior,
current, and future year investments simply for short-term
revenue needs.
MR. SECKERS said Section 17 is also troubling because it would
further increase taxes by preventing a company from fully
utilizing all available earned or available tax credits from any
month to offset the tax for the entire calendar year. This is
nothing more than a disguised tax increase, he continued. The
production tax is an annual tax that is paid in monthly
installments and it has been that way since this provision was
put on the books back with the production profits tax (PPT). It
is not and has never been a monthly tax. But this change in
Section 17 would, in effect, convert, or at least migrate, this
tax to more of a monthly tax. This is a significant change in
substantive law. Despite what the administration may be
alluding to by focusing only on sliding scale tax credits, this
provision is much broader than that. This provision would
impact every single tax credit available under the production
tax law. That means companies with all the credits - small
producer credits, Middle Earth credits, and tax loss credits,
all of them - would be at risk to having tax credits deferred,
or worse, lost forever. That is a tax increase.
1:09:25 PM
REPRESENTATIVE OLSON asked whether ExxonMobil has done any
models on Section 17 that are not proprietary and therefore
available to the committee.
MR. SECKERS responded that any modeling done on the bill by
ExxonMobil would have confidential data. However, he noted,
ExxonMobil agrees with the presentation provided by enalytica
and he therefore Representative Olson could run his question
through enalytica for modeling purposes. He reiterated that
Section 17 is troubling and is without question a tax increase.
REPRESENTATIVE OLSON inquired whether Mr. Seckers knows of any
other political subdivisions, provinces, states, countries, or
emirates that have a tax mechanism that has changed six times in
ten or eleven years.
MR. SECKERS replied, "Not to my knowledge."
1:10:29 PM
REPRESENTATIVE SEATON referred to Mr. Seckers' statement that it
has not been monthly since PPT. He said his recollection is
that the progressivity element in the taxes was specifically
monthly, so it would seem like this element is comparative to
that more than to PPT.
MR. SECKERS answered that Representative Seaton is correct that
the progressivity piece that was present under PPT and Alaska's
Clear and Equitable Share (ACES) was a monthly determination of
the rate for that particular month, but tax itself was a year
tax. He said the tax itself is calculated on a yearly basis as
provided in statute and is the way the Department of Revenue
(DOR) has administered the tax since its inception.
1:11:24 PM
MR. SECKERS continued his testimony regarding Section 17, saying
that the monthly payments made by ExxonMobil are estimates. A
lot of variables go into it - for example, estimates of the
company's expenses as well as estimates of one-twelfth of the
company's credits. There is then a final true-up at the end of
the year so the taxpayer can determine and pay the tax based on
the entire calendar year of operations.
1:11:58 PM
REPRESENTATIVE SEATON offered his understanding that the
progressivity was a monthly calculation that was not trued up at
year end or annualized later. To his knowledge, he continued,
the sliding scale was put in there specifically to be the
progressivity piece and reverse going at low prices, but was
specifically put in there to emulate the progressivity that was
had in the previous tax bill. It was pretty clear that that was
providing progressivity. He requested Mr. Seckers to comment in
this regard.
MR. SECKERS responded that, in regard to the sliding scale tax
credits, he cannot address the intent behind the thoughts of
each legislative member. He agreed it was put on the books as
an offset to the elimination of progressivity. He said that the
regulations in law today, as well as the way the statutes work,
clearly allow that credits that could be used in one particular
month are still available for the entire calendar year. So,
while the sliding scale credits were determined on a monthly
basis, should the economics of that month change, and the
economics for the entire year change, the credits that would
otherwise have been used that couldn't have been used in a
particular month are still available for the entire calendar
year. He said Representative Seaton is correct in the sense
that the determination of the sliding scale credits is based on
monthly production, but it is an annual tax in terms of its
actual determination for the year.
1:13:39 PM
MR. SECKERS returned to his testimony. He said Section 31 would
prevent the gross value at the point of production from going
below zero, thereby increasing the production tax by changing
the way the gross value at the point of production is determined
and applied. He allowed that this change may sound harmless at
times, and that intuitively it may seem to make sense that a
gross tax at the point of production should not go below zero,
that there should not be a negative tax. However, he continued,
this provision represents another tax increase. It would
adversely impact the economics of investments and penalize those
producers that made prior-year investments and would create
uncertainty as to how a company is to calculate its tax return.
Currently, if the price of oil fluctuates, or a company's marine
transportation or pipeline tariff costs are such that it forces
the gross value at the point of production to go negative at a
particular field or unit, the economics of that investment are
not lost. Why? Because when a company files its tax return
under current law, it is not filed on a field-by-field or unit-
by-unit basis; rather, it is filed by segments. In Alaska there
are four segments that were created under PPT: two for Cook
Inlet oil and gas, the North Slope, and Middle Earth. For the
North Slope, ExxonMobil files a consolidated return for the
entire segment. So, if there is a negative gross value at the
point of production because of an expensive investment or an
investment with troubled economics, the negative gross value at
the point of production gets offset or combined with the
company's gross value of the entire segment and therefore the
economics of that investment are not lost. That's a very
valuable thing when companies look at making investments. This
provision would instead say that those costs are now lost, that
the gross value at the point of production from that field or
unit will now be limited to that field or unit. The law doesn't
say that, this provision just says it cannot go below zero.
There is no indication of how [DOR] is going to apply that.
Does that mean by segment or by field? Based on what was
testified by the Department of Revenue, a company would have to
interpret it by field. If that's the case, then that's a
substantive change in the law because it is not determined by
field - it is consolidated and a company files one return of all
the company's gross value at the point of production minus the
expenses. This would be nothing more than a tax increase.
1:15:58 PM
REPRESENTATIVE TARR understood that the concern is whether it is
applied per field or per segment since it is currently being
done by segment. She asked whether ExxonMobil would still
oppose the provision if it was instead more specific to say that
it would be applied per segment.
MR. SECKERS replied certainly, because it would still be a tax
increase. The only difference there is if the whole segment is
going negative for any big company, then everyone is in a world
of hurt. The point is that what will happen by applying this
section is that the investments a company has made for its
pipeline, its tankers, and so forth - if it forces the economics
of that particular investment to go negative - then the company
would lose recovery of that part of its economic investment,
which would be a change in the tax law and therefore a tax
increase.
1:16:59 PM
REPRESENTATIVE JOSEPHSON maintained that it is a transparent tax
increase, not a disguised tax increase as stated earlier by Mr.
Seckers. The administration has a number of measures to raise
revenue given the state's fiscal situation, he said, and these
were not hidden to Mr. Seckers and these are understood by Mr.
Seckers.
MR. SECKERS allowed Representative Josephson is right in the
sense that it would be apparent to someone who knows what he/she
is looking at. However, the reason he chose those words is
because HB 247 is being couched as a tax credit reform bill.
[Section 31] has nothing to do with tax credits, it goes to the
gross value at the point of production and substantively changes
the way a tax is calculated. When the bill was first testified
to, this was just glossed over as basically conforming language
and it was an alarming provision for that reason. It wasn't
flushed out until very later on, causing him concern that "a
fast one" was being pulled.
1:18:25 PM
REPRESENTATIVE JOSEPHSON addressed the issue of monthly versus
annual calculation raised by Representative Seaton. He argued
that if kept in its current form, and price variability is such
that companies cannot use all the credits in a month and so some
are carried over, then the state would bear that variability in
just about every instance.
MR. SECKERS responded, "Not with the provision as drafted."
There are more variables that could cause that event, he said.
For example, a company's expenses can go up and down, some
expenses are unknown until the end of the year and that's why
they are estimates. But, the law says that if, for example, a
company claims 12 credits in a given month but should have only
claimed 11, then the company must refund that back, it has
underpaid its tax at that point. This law says, "oh by the way
you claimed 11, you could have claimed 12, you had 12, you can
only claim 12, sorry, you don't get to keep them." He noted
that consultant Janak Mayer of enalytica stated that this is a
one directional tax increase, it doesn't go back and forth.
1:19:29 PM
REPRESENTATIVE SEATON referred to Mr. Seckers' statement that if
this was applied by segment [the costs] would be lost. He asked
whether Mr. Seckers was meaning they were lost in that year or
would roll over as net operating loss credit.
MR. SECKERS answered he is not certain this has ever been tested
because he's unaware of a tax credit that's had a negative gross
value at the point of production, but he is not saying it hasn't
happened. He explained that the calculation would start with
the gross value at the point of production to the extent there
is negative to it, and then the lease expenditures would be
subtracted to determine the net operating loss. He offered his
belief that the net operating loss would be increased by those
additional deductions and suggested that Mr. Alper [Director of
the DOR Tax Division] be asked this question.
REPRESENTATIVE SEATON stated, "We would be doing basically the
same thing as the net loss carry forward as we have now, it
would just be that the tax wouldn't go below zero in any one
year."
MR. SECKERS replied the law is very specific that a company
cannot have a negative tax, the worst it can go is to zero.
1:21:00 PM
MR. SECKERS continued his testimony and offered his agreement
with the comments made yesterday by Mr. Foley of Caelus Energy
Alaska about the removal of the gross revenue exclusion from the
determination of a net operating loss. He said he agrees with
Mr. Foley that it is in the law and is an incentive to help
develop smaller fields and those with troubled economics. Mr.
Seckers said it is a provision that is clearly a tax increase
and one that will make those fields more difficult to produce.
MR. SECKERS stated that Section 8 of the bill raises significant
concerns in regard to the disclosure of tax credit information.
1:21:56 PM
REPRESENTATIVE TARR noted that the committee is trying to come
up with a reasonable resolution that potentially meets in the
middle. In regard to the proposed $25 million cap, she asked
whether there is an amount that Mr. Seckers would consider
reasonable. She recounted that yesterday no one who testified
would give her a number.
MR. SECKERS qualified he isn't sure he understands the question,
but said the proposed "$25 million annual limit applies to the
ability of refundable credits for a company to say this is the
most you can have the state refund in any given year subject to
other limitations - the local hire and things of that nature."
ExxonMobil has never qualified for that, he continued, has never
had a refundable credit and will not ever have a refundable
credit as long as it can keep its production high enough. So,
it may be unfair for ExxonMobil to comment on this provision.
REPRESENTATIVE TARR noted that ExxonMobil would have to use the
proposed change against its future tax liability. She inquired
whether this is what ExxonMobil is considering a substantive tax
increase.
MR. SECKERS answered absolutely. From a general policy point of
view when companies make investments and prices tank, they're in
a loss position through no fault of their own and they want to
recover some of that economic investment. Yesterday the Alaska
Oil and Gas Association (AOGA) said that this is critical to
some of the companies to continue to make necessary investments
in the state - those companies need the recovery today. To deny
that recovery by forcing them to be unable to use it against,
say, the minimum tax is a pretty big tax increase and, in his
opinion, is a major substantive change.
1:24:16 PM
REPRESENTATIVE JOSEPHSON recalled Mr. Seckers' statement that
under Senate Bill 21 there can never be a negative tax. But, he
said, it's the credits that can drive it underneath the zero
floor and there have been some instances where the net operating
loss put the state in a position of paying more than 100 percent
of the costs of development.
MR. SECKERS replied that the aforementioned is a two-part
question. What he is meaning by a negative production tax, he
explained, is that a company cannot go to the state saying it
has a negative production tax of $100 and is owed a check.
Under the law, a company goes to zero and that's it; if there is
a loss it is carried forward to use against future opportunities
or against future production tax or is possibly certificated and
transferred. So, a company cannot get a negative current year
production tax. As for the ability of the Net Operating Loss
(NOL) to go above the cost of development, he said he is
uncertain how that gets there. That is not to say that a
company couldn't, for example, have a gross revenue exclusion or
stackable credits, of which the number can get pretty high.
But, in order to have an NOL, a company spends the $1 and gets a
35 percent recovery, so the company is still out 65 cents. To
the extent that that number can get over 100, he said he has not
seen it. He suggested asking a smaller company this question.
REPRESENTATIVE JOSEPHSON asked whether Mr. Seckers would agree
that it is egregious if it was shown that it could [get over
100].
MR. SECKERS responded it would depend on what the policy of the
state is in terms of trying to encourage whatever is causing
that investment to go that low - it would have to be a pretty
risky investment with a lot of costs. From a tax practitioner's
point of few, he said he is not certain he has ever seen that,
so his knee-jerk reaction is that it's pretty rare. However, if
the state says it's happening to certain taxpayers, then he
believes the state but he has not seen it.
1:26:31 PM
MR. SECKERS resumed his testimony about Section 8 of the bill,
which would allow the Department of Revenue (DOR) to make public
information concerning a taxpayer's uses of tax credits as well
as information concerning the activities of that taxpayer that
gave rise to those tax credits. This information is currently
confidential and for good reasons. ExxonMobil is partners with
BP, Conoco, and others at Prudhoe Bay and other fields. As
partners, certain information is shared in the co-development of
the field. But, on a global scale the companies are competitors
and, as such, are bound by certain laws to keep certain things
confidential; for instance, prices and taxpayer sensitive
information. To now allow DOR the liberty of publishing this
kind of data, with who knows what limit or no limit, is
troubling. He said he agrees with yesterday's testimony by BP,
AOGA, Conoco, and others that this is a troubling section.
Going down this path opens it up to a risk of full disclosure of
taxpayer sensitive, as well as confidential, information.
1:27:42 PM
REPRESENTATIVE TARR imagined that if this legislation went
forward as written, the regulations implementing this provision
would be more specific and the companies would have an
opportunity to participate in that process to define it. She
asked whether this gives Mr. Seckers any level of comfort that
ExxonMobil would be able to participate or whether Mr. Seckers
thinks it needs to be more clearly defined in the statute.
MR. SECKERS answered that the administration of the tax law
belongs to the Department of Revenue, but the regulatory process
is not always a give and take. Many times industry will present
comments that don't go anywhere. His personal preference is
that there always be language in the statute that is extremely
clear, extremely point, so that the regulations cannot vary from
it. If open-ended language is given to allow the department to
interpret it and issue regulations, those regulations can get
changed without legislators knowing it and therefore there is
not as much check and balance as going through the statutory
process.
REPRESENTATIVE TARR requested Mr. Seckers to suggest some
changes that would make this grey area more clear.
MR. SECKERS agreed to look at it and said he will try to run it
through AOGA so that it would be a consolidated view from the
industry.
1:29:24 PM
REPRESENTATIVE SEATON recalled conversation from yesterday that
divulging Net Operating Loss Credits would yield taxpayer
information. He asked whether excluding those from the process
would have that same consequence to ExxonMobil where it wouldn't
relate to taxpayer information, it would simply be the amount
that the state is paying to individual companies and projects.
He pointed out that legislators are at a loss without knowing
where hundreds of millions of dollars are being spent; the money
is just gone and legislators cannot find out to make policy.
MR. SECKERS allowed it is a good point and said he understands
the concerns. Clearly, he continued, the Net Operating Loss
Credit is one of the most concerning because in order to get to
that number there could theoretically be a lot of data as well
as sensitive data relating to how that credit was earned. The
general notion of publishing information by specific taxpayers
raises red flags in that it may allow one company to gain favor
over another in public press and things of this nature. The
devil is in the details, it depends on how it is written and how
it is administered and what it actually relates to. He
suggested that it could possibly be done by field or unit as
opposed to individual companies because companies are investing
jointly in that well. That may be a way to provide information
that is not so concerning but yet gives legislators the
information they need regarding credits. It is really more
field or unit specific in this case, he reiterated, than it is
the individual taxpayer.
REPRESENTATIVE SEATON said he would appreciate it if Mr. Seckers
could suggest a reasonable compromise in this regard.
MR. SECKERS replied he will go back to AOGA to see if language
can be found that everyone agrees with - something that is good
for one should be good for all. He said he isn't trying to hide
behind AOGA, but an advantage of AOGA is that it is looking at
it from a global industry perspective, and the stronger the
industry is in the state, the stronger is everyone.
1:32:41 PM
REPRESENTATIVE OLSON asked whether, from ExxonMobil's
perspective, there is anything in HB 247 that is salvageable.
MR. SECKERS responded that ExxonMobil believes that as a whole
HB 247 is a bad bill. He said he is not certain he sees
anything in the bill that would make Alaska's investment climate
better or that would lead to more jobs or more production. From
the perspective of ExxonMobil it is troubling legislation.
1:33:32 PM
MR. SECKERS returned to his testimony to discuss the procedural
matters of HB 247. As if the bill isn't bad enough, he said,
two of the provisions are made retroactive to January 1. Any
time there is a retroactive tax provision there is concern from
a tax practitioner perspective. He pointed out that, not only
from a business perspective and a policy perspective about
investments and judging the regime, by the time the bill was
passed taxpayers would have already filed several monthly
installments under the current law. This retroactive change
would put all the taxpayers at risk of having filing incorrect
monthly installments and put all taxpayers at potential risk of
penalties and interest through no fault of their own. It would
also jeopardize investment decisions that the companies are
making, commitments on expenditures, and so forth. Making any
law retroactive is troubling and is bad tax policy.
MR. SECKERS reiterated ExxonMobil's belief that enacting HB 247
would impact Alaska's global overall effectiveness and
competitiveness. Raising taxes when many companies are
reporting record losses, losses on the very activities that HB
247 is trying to raise taxes on, is poor tax policy. This bill
will force companies to re-examine short-term and long-term
investment behavior and is inconsistent with the state's long-
term vision of promoting oil and gas development. The state
enacted the PPT and ACES in recent years with the goal of
increasing taxes as prices rose. Enacting HB 247 will signal to
the global investment community that Alaska's tax policy is to
raise taxes when industry makes money and then again when
industry loses money. ExxonMobil believes Alaska needs to
remain globally competitive for critical capital investments.
Increasing taxes on companies that are losing money today will
not lead to more jobs, will not lead to more investment, will
not lead to more production, and will not lead to more long-term
sustainable state revenues.
1:36:12 PM
MR. SECKERS again said Alaska remains a very important component
of ExxonMobil's worldwide portfolio; that the company has been
in Alaska a long time and looks forward to being in the state
for a lot longer. ExxonMobil will continue to pursue attractive
investment opportunities in the state, but if HB 247 is passed
and the state raises taxes when the company is losing money on
the North Slope, then all those opportunities are diminished.
MR. SECKERS concluded by stating that the need for Alaska to
maintain a competitive and stable fiscal environment that
attracts and encourages critical long-term investments,
especially in today's low price environment, is one of the most,
if not the most, important issues facing the state. As policy
makers, legislators need to decide whether increasing taxes on
companies that are losing money, losing money making investments
that every Alaskan needs the companies to make, including his
own company, is sound long-term policy and will lead to jobs,
investments, and sustainable revenues. Is it sound tax policy?
ExxonMobil believes the answer to that question is no.
The committee took a brief at-ease.
1:38:47 PM
J. Benjamin Johnson, President, CEO, BlueCrest Energy Inc.,
began his PowerPoint presentation on HB 247 by noting that while
BlueCrest Energy Inc. ("BlueCrest") is a Texas-based company
now, it has Alaskan roots. He said he grew up in Kenai,
graduated from school there, and worked his way through college
on the Cook Inlet platforms and on Prudhoe Bay. After college
he worked for ARCO and worked on some of the early engineering
studies for Prudhoe Bay and Kuparuk. BlueCrest management has
over 40 collective years of experience in Alaska. Since
BlueCrest only operates in the Cook Inlet, he said he will limit
his testimony to those issues that apply to BlueCrest. He noted
that BlueCrest concurs with the Alaska Oil and Gas Association's
(AOGA's) presentation to the committee yesterday. He continued:
First, I want to emphasize that with regard to what
BlueCrest is doing in the Cook Inlet, the tax program
has been a very, very good investment for the State of
Alaska. The credits have been a tremendous success in
attracting outside investment in the industry, and
most importantly, generating significant royalty and
tax income for the state throughout the future.
As I'll explain today, BlueCrest is in Alaska as a
direct result of the state's incentive programs. And
it is the state's investment - in the forms of the
credits - that have facilitated our success in the
Cosmopolitan Unit. I'm going to show you that the
state's investments in Cosmopolitan tax credits will
provide high returns to the state even at low oil
prices. In fact, the tax credit investments under the
current laws can actually provide higher rates of
return to the state than the average investments of
the permanent fund.
Secondly, I'd like to just give you a really quick
overview of Cosmo, [the Cosmopolitan Unit], and I'll
explain the difference between our onshore oil and our
offshore gas developments. And I'll show you ... both
BlueCrest's calculations and our summary of the DOR's
calculations on the value of the tax credits. Lastly,
I'll wrap up with just our specific factors in the
existing draft of HB 247 and their impact to BlueCrest
in particular.
1:41:30 PM
MR. JOHNSON turned to slide 2, "Cosmopolitan Project Area," to
describe this project that is located in the Cook Inlet. He
said the field is three miles offshore and is just a few miles
north of Anchor Point. All of these are state leases, he noted.
BlueCrest also has an onshore surface-use lease where the drill
site and production facilities are located. Moving to slide 3,
"1967: Pennzoil Found the First Oil - Drilled from Offshore," he
outlined the history of the Cosmopolitan Unit. Pennzoil first
discovered the Cosmopolitan oil accumulation in 1967 when it
drilled an offshore well at Anchor Point. However, that well
just barely clipped the edge of the accumulation and there was
no way Pennzoil could know what was there. And since 1967 was
about the time that Prudhoe Bay was discovered, everyone's focus
subsequently turned to the North Slope.
1:42:24 PM
MR. JOHNSON drew attention to slide 4, "2007: ConocoPhillips and
Pioneer had drilled 3 wells and 3D," to continue the history of
the Cosmopolitan Unit. He said:
In the late 1990's, ARCO/ConocoPhillips got interested
in the area again, and they called it the "missed-pay"
prospect thinking that Pennzoil may have just missed
it. Well, in 2001 and 2003, ConocoPhillips drilled
two new wells, and Pioneer purchased ConocoPhillips'
interest and drilled another new well. Pioneer also
acquired 3-D seismic over the area and what that
showed was that it looked like there was a big dome
down there, but they couldn't see anything in the
middle of the dome on the top because it had what
looked like it could be a gas cloud. There was no way
Pioneer could really tell what the shape of the top of
it looked like. They knew there was definitely
producible oil down at the bottom but they didn't
know, couldn't know what was up top. By 2010, Pioneer
had already developed a plan to develop the field they
were ready to go when in 201 their board of directors
decided to invest in West Texas shale plays rather
than in the Cook Inlet.
Well, about that time, BlueCrest had just formed by a
group of former major oil company executives, each of
whom have extensive experience in developing large oil
and gas assets. So, our plan was to look for, to find
some oil and gas properties that could potentially be
improved using our backgrounds and knowledge of
industry technology. Now, we evaluated dozens of
acquisition opportunities around the US (offshore
California, Gulf of Mexico, Wyoming, Colorado, Texas,
Louisiana and Alaska). Alaska's huge handicap was,
and it continues to be, that the exploration,
development and operating costs in the state are at
least 300 percent of any other major hydrocarbon basin
in the US. But we ultimately decided to invest in
Alaska because, through the credit programs, the state
was investing in itself, and that investment - the
state's credits - offset the higher cost of drilling
and development. So we acquired our interest in Cosmo
in 2012, and our team came up with a new idea. Our
concept was to drill a vertical well offshore.
1:44:45 PM
MR. JOHNSON moved to slide 5, "2013: BlueCrest Drilled a
Vertical Well from Offshore," and continued:
In 2013, we drilled the Cosmopolitan State Number 1
well. It passed through every geologic zone from the
sea floor down to about a mile and a half deep. As it
turns out, almost every sand we penetrated down for
the mile deep was full of producible natural gas. And
then all the sands below that to the bottom of the
well were full of oil. So, we also completed a
vertical seismic profile in the well and then we were
able to clear up some of the questions about the
previous seismic data. We flow-tested several of the
larger new gas sands and a couple of the newly
discovered oil zones. We took samples of the rocks,
gas, and oil. In summary, not only did we confirm the
existence of the two previously known oil sands that
Pennzoil, ConocoPhillips, and Pioneer had encountered,
we also discovered at least six new large gas zones
and four more oil zones.
1:45:40 PM
MR. JOHNSON turned to slide 6, "Cosmopolitan Unit Development
Concept," and explained:
The Cosmopolitan Unit is really two separate
development projects, just one on top of the other,
they're not connected. The oil zones are deep enough
that we can reach them from an onshore drill site
about three miles away using a very powerful drilling
rig. The gas zones are just simply too shallow to
make drilling from [onshore] a possibility. So the
gas zones will need to be developed by drilling gas
wells offshore with a jack-up rig and then producing
that through platforms and back to our onshore oil
production facility.
... Given the success of our 2013 drilling program
with the Cosmo well, we then were faced with the
challenge of how to pay for the development of this
new field. I mean right now, BlueCrest is a small
private company with a single focus of developing the
Cosmopolitan Unit. The members of our management team
now all have extensive technical and business
experience in developing projects like this, but the
potential costs of Cosmo far exceeded our personal
financial capabilities. So we teamed with a group of
oil industry investors and then we ... very carefully
created our plan for financing the development of
Cosmopolitan.
1:46:58 PM
MR. JOHNSON outlined the life-cycle cash flow of a typical
project. Displaying slide 7, "Typical Project Life-Cycle Cash
Flow," he stated:
This next chart shows the cumulative cash flow over
time for a typical life cycle of a successful oil or
gas development. The very beginning here is the
exploration phase. And when you see this [curve] go
down below the horizontal axis that means that ... the
company at this point is spending more money than
they're bringing in. So, if it's pointed down we're
losing money. If it's pointed up we're starting to
increase. What's important to understand is that we
never get to the point where we break even until we're
all the way back up over that horizontal axis. Only
at that point can we make the very first profits on
this deal.
We need to understand that the first part of any
project is exploration and it is spending money that
we may or may not get back. At this stage there's no
assurance, in exploration there is no assurance that
anything is going to be found. The only way to know
that an area will be productive is to spend money to
drill expensive wells, and then test them if it looks
like there's something there. The vast majority of
exploration prospects are, in fact, dry holes - the
money spent will never be recovered. Just because you
drill a lot of wells doesn't mean you're going to
discover anything. I mean if there's nothing down
there, drilling wells won't make it appear. On the
other hand, and very important to understand, you'll
never be able to get to the development phase of a
successful project if you haven't made the discovery
and haven't drilled those exploration wells. So, both
pieces are very important.
1:48:45 PM
MR. JOHNSON continued his explanation of slide 7:
But in the minority situation, like we're in now with
Cosmo, where the exploration process was successful,
the really huge cost of developing the field comes
into play. In other basins of the world, people
aren't so concerned about the environment and the way
things are done, and that's not the way it's done in
Alaska. We take a very strong stance on the
environment and safety and it costs money to that, but
we do it right. ... Before we sell the first barrel
of oil from a well, we have to be ready to make that
work and that's what we're doing with Cosmo right now.
We've got a well that would produce, but we've been
working two years on the facilities to be able to turn
it on and produce it - the gas pipeline that's
connected, all of that has to be done up front. So,
it's important to understand that no profits can be
generated on an oil and gas development project until
that curve has crossed back up and become positive.
... Remember this represents a successful exploratory
project that has been developed. The vast majority,
industry statistics now at two-thirds to 90 percent of
all exploration projects do not find economic oil or
gas. So, for the industry to survive, we have to be
at least able to generate enough profits on successful
developments to pay for the losses on the exploration
phase.
1:50:11 PM
MR. JOHNSON addressed slide 8, "Cosmopolitan Progress as of
03/01/2016," to talk specifically about Cosmopolitan. He said:
Right now, we're just a couple of months away from
starting up. We'll have production from that first
old well that was drilled. In order to do that, we
have spent two years building these production
facilities and the drill site. Then we bring in our
new drilling rig (in fact it's the most powerful
drilling rig in Alaska) and start spending over $40
million a well to bring on this new oil and gas. So
here we are in March. After years of working on this
project and investing all the money we have, we're
just about ready to start the new drilling. And that
new drilling is going to occur mostly in the second
half of this year. And HB247 is proposing that tax
credits end on July 1 of this year, even though that
is just the culmination of what we have been working
on.
These pictures show you the progress we've made. ...
We're 38 acres on the site ... we've got room for 20
wells. The first phase of this is 10,000 barrels a
day of capacity. We have a 50-person man camp. We're
also designed to allow for a lot of expansion of this
facility as needed. ... We are on schedule and on
budget for starting the first oil production in April
of this year.
1:51:37 PM
MR. JOHNSON continued his discussion of slide 8:
With regard to the offshore gas, we're at a point now
where we could begin the drilling the gas wells this
year and set one or two platforms next year. Without
the benefit of the tax credits, the gas is just simply
too expensive to do right now. We could begin
production of the Cosmo gas in 2018 if we started
right now. The issue is if we're not able to start
this year, we risk losing the existing offshore
drilling rig that's been ... in Seward right now
waiting for us. If the rig owners take the rig out of
Alaska, we're afraid that it could be a long time
before we're able to get another one back in the Cook
Inlet that would be available for us to use; we
understand there could be others in, but one that we
could use.
... Thanks to the work that Hilcorp has done in the
Cook Inlet, there are sufficient supplies of gas in
the Cook Inlet that have already been developed to
meet the requirements for several years for
Southcentral users. There is not enough gas developed
to allow re-opening of the Agrium facility or allow
for significant new uses such as mines or LNG
distribution throughout the rural communities of
Alaska. As this Committee has heard in previous
presentations, there is a lot of Cook Inlet gas that
has recently been discovered, including Cosmo in those
numbers. But discovery is just the first phase of
actually bringing new gas to market. It takes many
years to bring a new gas field on production, and if
we don't get started soon, we're risking a serious
shortage years down the road.
1:53:16 PM
MR. JOHNSON drew attention to slide 9, "Tax credits for
development of previously discovered proven reserves are a
solid, low-risk investment for Alaska." He discussed what the
tax credits mean to Alaska from a successful development project
like Cosmopolitan. He said that when used for development of
new proven reserves in the state, the tax credits are without
question a valuable low-risk investment. He maintained that
speaking of the credits as costs or a give-away ignores the
value that is received by the state. The tax credits make
projects work and they bring new sources of long-term revenues
to the state for decades to come.
MR. JOHNSON turned to slide 10, "Summary of DOR Analysis Cook
Inlet Oil Development 2/19/2016, Net Cash Benefit to State With
Continued Tax Credits at Various Oil Prices," and continued:
At Cosmo, we're sitting on a large proven resource of
future oil and gas that now simply requires additional
investments to bring it to full production. Last
December, Representative Seaton here asked the
Department of Revenue for its analysis on the impact
to the state on development of a new Cook Inlet oil
field. On February 19, DOR produced its analysis and
DOR's analysis modeled an example Cook Inlet field
that is basically equivalent to a conservative
forecast for Cosmopolitan. It assumed 50 million
barrels of ultimate oil recovery and a maximum oil
producing rate of about 17,000 barrels a day, which
would represent the low side of our future Cosmo
expectations. The total capital costs it assumed were
about $600 million, and it assumed that the full tax
credits under existing law would continue indefinitely
into the future. So, it assumed no changes to the tax
law.
This chart is a summary of the calculations the DOR
provided in their letter to Representative Seaton. It
includes a summary of the total net benefit received
by the state and municipalities, including taxes and
royalties. We contend that you certainly need to
consider the entire benefit of the state to look at
the return on the investment from the tax credits
here. You can't reasonably exclude the bulk of the
value - that is the royalties that are received as a
benefit of these credits. So this chart shows that
the tax credits for this example Cook Inlet field
break even at about $35 a barrel. At about $60 a
barrel, the state would net double the amount of the
tax credits paid. Basically that would be $900
million received for the $300 million in tax credits,
or a net of $600 million on that chart.
1:55:50 PM
MR. JOHNSON moved to slide 11, "Summary of DOR Analysis Cook
Inlet Oil Development 2/19/2016, Comparison to Permanent Fund
NPV Return (6.15%) to State at Various Oil Prices Assuming All
Tax Credits are Continued In Full." He stated:
DOR also provided the calculations that showed the
impact of the tax credits as a pure investment, with a
head-to-head discounted-cash-flow comparison to the
investments by the permanent fund. According to DOR,
the permanent fund's September 2015 earnings were at
6.15 percent. So if an alternative investment earns
less than 6.15 percent, it would have a worse
performance than the average investments in the
permanent fund. On the other hand, if it earned more
than 6.15 percent, it would be a better investment
than the average of the permanent fund.
So, this chart shows that, even in the case where
there are never any changes to the tax system in the
Cook Inlet (that is, all credits stay in place forever
and there's no oil production taxes until 2022), the
state's investment in those credits for the example
field is still better than the average investment in
the permanent fund as long as oil prices over the next
30 years average about $44 a barrel. And it makes a
profit for the state at any price greater than about
$35 a barrel.
1:56:54 PM
MR. JOHNSON drew attention to slide 12, "Specific Comments on HB
247 - Section 21," to provide comments on the specific portions
of the bill that apply to BlueCrest and the Cosmopolitan Unit.
He said:
First of all, the termination of the 023(a) and (l)
credits will result in a significant reduction of our
ability to continue making the investments in the
Cosmo wells in particular in a low oil price
environment. It's been said that the NOL credits in
the Cook Inlet are somehow duplicative with the (a)
and (l) credits, but ... it's not really the case for
BlueCrest. From the beginning of 2017, we'll be on
production with our two new wells and we may not be in
an NOL situation at that point depending on oil price.
To make matters even any worse, in the event that the
023(a) and (l) credits were terminated and we were to
be able to claim an NOL credit in the future, the NOL
credit would only be 25 percent instead of the 35
percent that ... would apply to the North Slope.
We've done some interesting analyses of the value to
the state in keeping the 023(a) and (l) credits as
they apply to Cosmopolitan. We looked at the
effective return using just a simple and a
conservative calculation looking at only the
incremental royalty for each new Cosmo well drilled.
And this calculation doesn't include production taxes
that would be paid after 2022 under the existing law,
nor does it include property taxes.
Of course, we've also looked at the impact the loss of
the (a) and (l) credits would have on us. We could be
drilling Cosmo wells for the next five to seven years,
we have a lot of locations to be drilling to there.
For each new well we have to decide if the return to
BlueCrest is worth spending the investment. The
bottom line is that, particularly in periods of low
oil prices, these (a) and (l) credits allow us to
continue drilling the Cosmopolitan oil wells at
approximately $10 a barrel lower oil prices. So, that
would encourage us, it would allow us then, to be able
to drill at lower oil prices and get these wells on
production. And that's likely to be an important
factor in our 2017 drilling program next year.
1:59:03 PM
MR. JOHNSON addressed slide 13, "State's Investment Return From
Individual New Cosmopolitan Well Royalties." He said the chart
depicted on the slide is an undiscounted cash flow including
only the royalties from the .023(a) and (l) credits. He
reviewed the chart as follows:
A 100 percent on investment here means that 100
percent of the tax credit would be repaid out of
increased royalties over the life of the new well.
And what this shows is that these (a) and (l) credits
break even at about an average oil price of $24 a
barrel. At $40 a barrel the total return would be 170
percent, and at $60 a barrel the return is about 250
percent. Now this is BlueCrest's analysis, not DOR's,
but it's actually pretty similar to DOR's calculation
that they had done for their entire example Cook Inlet
field. They showed about 300 percent return at $60
oil. So you can see that continuation of these credits
for Cosmo, at least for Cosmo, are likely to be a good
investment for the state.
2:00:07 PM
MR. JOHNSON turned to slide 14, "Specific Comments on HB 247 -
Section 26," to comment on the proposed $25 million per year
limitation. He said this limitation doesn't recognize the
differences in qualified investment made by different parties.
He continued:
This [$25 million limitation] is particularly damaging
to small companies like BlueCrest who have invested in
good faith based on the tax policy in existence when
we entered into the commitments on our investments.
We came to Alaska based on these credits. We invested
our cash, we borrowed a lot of money and committed to
spending a lot more - all based on these tax credits.
The timing of the receipt of those payments for the
credits is paramount in our ability to make the
payments on the loan used for making those
investments.
MR. JOHNSON moved to slides 15-16, "Specific Comments on HB 247
- Section 27," and said:
BlueCrest, along with the ... entire rest of the
industry, tries really hard to hire as many Alaskan
workers as is practical. ... Adding in the further
restriction of reducing the credit payment by amount
of the percentage of non-Alaskan workers is just
simply impractical. In our case, for example, we've
hired 100 percent Alaskans for our full-time operator
positions at Cosmopolitan. And, to my knowledge, I
think our drilling staff is the same percentage.
We've always offered Alaskan companies the opportunity
to bid on new contract jobs and we've have employed
over 100 different Alaskan companies in the
construction of our Cosmo facilities. But Alaska
companies have got to be competitive, of course, both
from a cost and quality standpoint. Sometimes there
are specialized fields that are needed in construction
and drilling that [is] just simply not available from
Alaskan companies. So, we've tried to do everything
we can to ... let Alaskan crafts people work. For
example, we've given Alaskan welders several extra
tries to pass the required welding quality test. We
didn't do that to other people, but we have for
Alaskans. Now, of course, we're zero tolerance on
drug testing, no matter where the worker is from. ...
Bottom line, we support Alaska hire, but it doesn't
make sense to penalize companies after-the-fact for
their business decisions ....
2:02:22 PM
REPRESENTATIVE JOSEPHSON remarked that Mr. Johnson made a good
case relative to BlueCrest's oil fields on the net return to the
state, essentially arguing it's a win-win, which is compelling.
He asked whether Mr. Johnson has any arguments relative to the
gas credits.
MR. JOHNSON replied that BlueCrest has those calculations and
they look similar to the oil calculations. However, he said,
the gas is a function of when it's going to be sold, what will
the price be in the future, and right now there are a lot of
uncertainties about that. BlueCrest has not commenced the gas
development at this phase.
2:03:18 PM
REPRESENTATIVE TARR requested Mr. Johnson to talk about the
relative importance of Well Lease Expenditure Credits, given she
thinks those and the other Capital Credits are what will go away
for BlueCrest's Cook Inlet operations and then BlueCrest would
have to rely on the net operating loss (NOL). She noted that
the committee has tried to talk about the different phases of
development and making sure the state has enough activity in
each phase for providing supply going forward.
MR. JOHNSON responded that AS 43.55.023(a) and (l) are the Well
Lease Expenditure Credits: 20 percent is rebated on tangible
type equipment, which is pipeline facilities, and 40 percent is
paid on the intangibles, which is the majority of drilling of
the wells. BlueCrest will be finished with the facilities by
July 1 or certainly by the end of this year. However, the
really big costs begin with drilling. Each well is roughly $40
million and the credits received, even without the NOL if the
company is in a cash positive position, are really significant
for BlueCrest determining the economics of whether it can afford
to drill the wells. In high oil prices the economics are great
whether or not the credits are there. In low oil prices it
really makes a difference and BlueCrest's discounted cash flow
analysis showed that these credits effectively make a difference
of anywhere from $10 to $14 a barrel price difference, so it is
important to BlueCrest.
2:05:35 PM
REPRESENTATIVE TARR posed a scenario in which the 20 and 40
percent credits were scaled back rather than eliminated. She
asked whether there is a way to assess the relative impact of
the credits becoming less generous; for example, the 40 percent
credit being scaled back to 20 percent.
MR. JOHNSON answered that BlueCrest would have to look at each
one of those. He said 20 percent is certainly better than zero
because maybe it makes a difference of $4 a barrel in the oil
price versus the $10 that was calculated for the 40 percent. He
advised that BlueCrest will have to base its spending in the
future on whatever changes, if any, are made to these credits.
2:06:37 PM
MR. JOHNSON reviewed slide 17, "Specific Comments on HB 247 -
Section 46." Of all of the bill's provisions, he said, the
single most important point to BlueCrest is the timing of the
implementation of the changes, whatever those changes may be.
He explained:
It's now March, and the proposed changes are supposed
to take place on July 1. BlueCrest being small as we
are has had to be very, very careful in our financial
planning process. Before we ever started the oil
development project, we made sure that we'd have
enough funds to allow us to complete construction of
everything - the onshore drill site facilities, bring
in the most powerful drilling rig, and to drill at
least the first two new oil wells. So, our
calculation showed that we would need approximately
$525 million to get to that point of self-sufficiency
where we wouldn't have to be going and borrowing more
money or asking our investors for more, and that
should occur in early 2017 for us, depending on oil
price. In order to make ... that work, our
shareholders invested approximately $200 million in
cash. We've borrowed $30 million from [Alaska
Industrial Development and Export Authority (AIDEA)]
for a loan on the drilling rig.... We obtained a $150
million high-interest development loan. ... To date
we have received $24 million in tax credits, and that
goes into that formula, and the balance is $121
million to get us up to $525 [million]. That $121
million is what ... we would receive, hopefully we
will receive, from the tax credits on the investments
that we've made basically for 2015 and 2016 spending
under the current tax laws. We've spent a lot of
money to get to the point where we can now start
drilling, but an abrupt termination of these tax
credits on which we've based our entire financial
planning would be devastating.
2:08:35 PM
MR. JOHNSON continued:
We've finally reached the point, by completing all
this work and spending all this money, to where we'll
finally have our drill site and rig ready to drill the
second half of this year. We need the production from
the first new wells to pay for the costs we have spent
so far. Those drilling costs, at least through early
2017, are all based on the assumption that we will be
able to obtain the credits under existing law for
those investments and be fully paid for those credits
on time. We've done all this work and we've spent all
this money to date, and it only seems reasonable for
us to ask to be able to claim the existing credits for
the spending that is the result of our investments
made in good faith based on the expectation that the
state would honor its share of the investments.
We need to be able to be able to get to the finish
line here. Not paying the credits that were the basis
for the investments we've made over the last couple of
years, as close as we are, is kind of like saying
"well, you can spend the money for a new house, but
you can never move into it." We've got to get to the
finish line.
2:09:39 PM
MR. JOHNSON concluded with slide 18 which states, "When we are
driving on slippery icy roads, the most dangerous thing we can
do is suddenly slam on the brakes!" He said:
In conclusion, I'd like to reemphasize the importance
of phasing into any changes over a reasonable time
period. Everyone in this room today understands that
when we are faced with driving on dangerous, icy,
slippery roads - like the State of Alaska and Alaska's
oil and gas industry is faced with right now - the
most dangerous thing we can do is suddenly slam on the
brakes.
2:10:09 PM
REPRESENTATIVE SEATON inquired whether Mr. Johnson is asking
that the credits earned through the credit expiration date be
paid on time or asking that those credits be extended beyond
their statutory expiration date.
MR. JOHNSON replied yes, BlueCrest is definitely expecting that
it will receive the credits in a timely manner as they have been
earned under current law. A change in current law on July 1
will result in a huge impact to BlueCrest in terms of the amount
of credits because the last half of 2016 is the company's
largest, most expensive drilling expenditure time. By the end
of 2016, early 2017, BlueCrest will have to make an economic
decision about what to do drilling-wise. But, he pointed out,
BlueCrest has already committed that money for all of 2016, the
company has already signed contracts for the money to be spent
the last half of 2016.
2:11:26 PM
REPRESENTATIVE TARR recalled Mr. Johnson mentioning that the Net
Operating Loss Credit should be 35 percent like it is for the
North Slope producers. She noted that BlueCrest has different
levers it can pull here. The state is trying to incentivize
certain behaviors. Say, for example, the Well Lease Expenditure
Credit and the .023(a) and (l) credits go away, and then that
other change happens simultaneously. That is different once
BlueCrest is producing net positive. She asked how that makes
things look favorability-wise.
MR. JOHNSON responded that the NOL Credit is important for a
company just getting started and has been important for
BlueCrest. The .023(a) and (l) credits are important as
BlueCrest goes down the road drilling and continuing to drill.
BlueCrest has five to seven years of drilling that it could do
at Cosmo. The .023(a) and (l) credits facilitate drilling at a
lower oil price, these credits make the economics more feasible
to drill those wells.
2:12:53 PM
REPRESENTATIVE TARR surmised Mr. Johnson is anticipating a
situation where BlueCrest is net positive but continuing to
drill, and so the company is ineligible for a Net Operating Loss
Credit but wants to have a credit that would help incentivize
the continued drilling activities.
MR. JOHNSON answered yes, and that is what the .023(a) and (l)
credits do. For example, if BlueCrest had $10 million of
positive cash flow, what would the company do with that? The
company's plan is to reinvest everything it gets. If that is
applied against an NOL Credit in a new well that costs $40
million, then instead of being able to claim the credit on all
$40 million BlueCrest would get credit on only $30 million of
it. But if the company is in a positive cash flow of, say, $40
million and it drills one well, that just brings the company to
$0 and the company never gets a credit at all. That's why the
.023(a) and (l) credits are important for continued development
after a company has started up and finally made it to the
positive point.
2:14:14 PM
REPRESENTATIVE TARR remarked that she is trying to think about
what other opportunities there are for how to address this
without unintended consequences that are more costly than the
state can afford. She posed a scenario in which a company could
claim credits for its drilling activity for a certain number of
years, and asked whether Mr. Johnson would see that as being an
appropriate application.
MR. JOHNSON replied that that's a tough decision legislators are
faced with. He said industry will take whatever is done into
account and will make actions based upon that. Most
importantly, he cautioned, is that the action taken not be done
immediately - that industry be given some time so it can plan
accordingly. For example, a few months to July 1 is impossible
to plan for, but one to three years can be planned for. If the
credits go down, the result will be less development; if the
credits apply to exploration, then the result will be less
exploration also. That's a choice that legislators have to
make.
The committee took an at-ease from 2:16 p.m. to 2:20 p.m.
2:20:19 PM
DAVID WILKINS, Senior Vice President, Hilcorp Alaska, LLC, noted
that he is fairly new to Alaska and is a petroleum engineer with
30 years of industry experience all over the world and U.S. He
said he moved his family to Anchorage last summer to lead the
Hilcorp Alaska, LLC, ("Hilcorp") team and looks forward to
continuing the legacy of responsible development of Alaska's
resources so that his children might also have the opportunity
to live and work here. He noted that Hilcorp is the largest
privately held oil and gas company in the U.S., is headquartered
in Houston, Texas, and operates in the Gulf Coast of Texas and
Louisiana as well as the Northeast U.S. Hilcorp entered into
the Cook Inlet in 2012 and into the North Slope in 2014.
Founded in 1989, Hilcorp has over 1,350 full-time employees.
Just over 500 employees support Hilcorp's operations in Alaska,
of which 90 percent are Alaska residents.
2:23:06 PM
MR. WILKINS said that Hilcorp operates approximately 53,000
gross barrels of oil a day in Alaska and 150 million cubic feet
of gross gas per day from approximately 500 producing wells, for
a total net production to Hilcorp of approximately 57,000
barrels of oil equivalent (BOE) per day. He continued:
Hilcorp's assets are primarily, although not
exclusively, older fields with extensive production
histories, steady and predictable performance that
carry an incredible opportunity for getting more oil
and gas out of the ground safely and responsibly while
extending production life through efficiency and
thousands of smaller scale projects. We hope the
state sees a need to attract more companies like
Hilcorp as fields and infrastructures continue to age
here in Alaska.
That brings me to why I sit before you here today.
Hilcorp's production in Alaska represents
approximately 40 percent of what we produce company-
wide, so our success here in Alaska is critical to
Hilcorp's overall success. I absolutely agree with
all of what the Alaska Oil and Gas Association
[(AOGA)] presented yesterday on HB 247. It's our view
that the credits in question have resulted in more
investments here in Alaska and we stand by our
commitment to serve Alaska's energy needs first.
It's no secret that Hilcorp has been a big part of
reviving the energy security in Southcentral Alaska.
Over the past four years we've invested over a billion
dollars in projects and have drilled over 50 wells in
the Cook Inlet Area. As a result of this investment
and the positive results, we're sending more oil to be
refined and used here in Alaska and we're currently
making gas supply commitments into the year 2023 with
local utilities and continue to work to ensure a
reliable and affordable energy source for Alaska's
largest population hub. As you are well aware, prior
to Hilcorp's entry into Alaska, there was widespread
concern that utilities would need to import natural
gas to meet demand. I've heard numbers like LNG
[liquefied natural gas] imports being on the $10-$20
per MCF [thousand cubic feet] basis, which would have
been a very bad impact on the economies in
Southcentral Alaska.
2:26:01 PM
MR. WILKINS continued:
These commitments certainly don't come without
challenges. Developing oil and gas in the Cook Inlet
basin carries a very high cost of production coupled
with decline rates that vary from 15-50 percent
annually depending on the field. Let me restate that.
We have wells in areas in the Cook Inlet that lose
half of their production in one year. The simple fact
is that if we are not spending money on projects that
bring on new production we cannot curb these declines
and we will very quickly get back into the situation
we were in prior to 2012 to where supplies were in
question. So we believe it is in both Hilcorp's best
interest and the state's best interest that we
continue to spend dollars on trying to produce more
oil and gas in the Cook Inlet as well as on the North
Slope.
It's also no secret that Alaska's tax credit system
and the Cook Inlet Recovery Act were key drivers in
bringing Hilcorp to Alaska and in our investments to
date. Since 2012, Hilcorp has spent $3.2 billion
dollars in capital and acquisition costs here in
Alaska. Those investments were aimed at one primary
goal - increasing oil and gas production. Since 2012
we have increased our organic, meaning non-
acquisition, production by approximately 40 percent in
the Cook Inlet. A lot of people ask how we do it, and
the answer is simple. First, we have talented and
dedicated people here in Alaska and, second, we have
and continue to make significant investments;
investments that were encouraged by the state's tax
credit program and investments did just what the
credits meant to do - increase energy supply needs for
Alaska.
2:28:14 PM
MR. WILKINS continued:
I would argue that our success has been meaningful to
many, including the state. Increased production
levels of oil and natural gas in the Cook Inlet basin
has resulted in increased royalty, property taxes,
jobs, and more. One example of this is looking at our
Monopod offshore platform. In January 2012, right
after Hilcorp took over operations, the realized oil
price was approximately $95 a barrel. Production from
the platform was approximately 600 barrels of oil a
day, a marginal rate for an offshore platform in high
operating costs. As the royalty owner, the state's
take from the Monopod at that time was approximately
$90,000 per month - again, that was when oil prices
were $95 a barrel. Because of this marginal rate and
low profitability, the Monopod qualified for royalty
relief under House Bill 185 that was passed in the
year 2003. The royalty rate was restructured to help
maintain profitability for the platform so that it
would not be shut-in and/or permanently abandoned.
Over the past four years, Hilcorp has done over 150
projects on the Monopod alone, most of which were
smaller in scope, and we have increased production to
a current rate of approximately 3,000 barrels of oil a
day. Because of this increase the state's royalty
share is back up to the standard 12.5 percent take and
even with oil prices at $35 a barrel, the state's
royalty take from the Monopod has increased from
$90,000 a month to over a half a million dollars a
month. That's over a ten time increase in royalty
barrels and a five time increase in dollars going to
the state despite oil prices declining 60 percent.
Furthermore ... the Monopod platform was probably one
to two to three years from being plugged. Because of
the increase, we have increased and extended the
Monopod 15-20 years and added on the reserves on the
books 8 million barrels of oil.
2:31:01 PM
MR. WILKINS continued:
I would offer we need more results like this. I would
also offer that the industry needs a system in place
that incentivizes, not jeopardizes, continued
investment of this type of activity. It's a really
good of example of the state putting good policy in
place aimed at and achieving a positive result and we
delivering the result.
I can tell you today that the credits Hilcorp earned
were absolutely reinvested in Alaska. Our current
production rates prove it. We have managed to work
our way above the 50,000 BOE per day mark through
acquisition and a lot of hard work. Breaking the
50,000 mark means we can no longer cash in the credits
that HB 247 proposes to take away. But other budding
companies, like you heard from BlueCrest and Furie
you're going to hear form, can. And Hilcorp is a
company that always welcomes competition in the
market. We want to help promote a healthy industry
throughout the state. As others have said, an active
industry means additional service companies will be
attracted to Alaska, which creates competition and
will help drive down costs.
A lot of the discussion around HB 247 has involved the
Cook Inlet basin, primarily because of the notable
increase in production and activity that the existing
tax structure intended to generate and was wildly
successful. Our success in the Cook Inlet is what
fueled Hilcorp's interest in expanding to the North
Slope. And we did just that in November 2014 when we
purchased 20 percent of BP's assets on the Slope.
2:33:04 PM
MR. WILKINS continued:
It's been over just a year since we arrived on the
North Slope and I am very excited about the amount of
opportunity we see on the Slope. We have a
comprehensive list of projects that we can invest in -
small and big - facility recompletes, drilling, we see
lots of opportunity. Projects that will put more oil
in the pipeline and support literally hundreds, if not
thousands, of jobs in the state of Alaska.
But, in today's price environment and in the face of
an uncertain state fiscal structure, it's difficult to
determine what projects will move forward and when.
We have been very, very thoughtful with every penny we
spent. We have to continue to work hard to build
efficiencies and cut costs while ensuring we do it
safely and protecting the environment. Cutting costs,
not corners, is the only way we will survive the
current downturn.
I know we aren't the only ones faced with difficult
decisions and realities during this challenging time.
I also recognize the members of this committee and the
legislature have much to consider about what's best
for the state and our future. In closing, I'd just
like to remind you that the uncertainty we are
currently facing threatens our ability to plan our
investments and that the decisions you make today will
impact the economics and the opportunities to increase
tomorrow's production both in the Cook Inlet and the
North Slope.
2:34:50 PM
REPRESENTATIVE OLSON inquired whether the platforms in Cook
Inlet are all being worked on.
MR. WILKINS replied that Spark, Spur, Dillon, and Baker have
opportunity to them but are not producing right now. He said
Hilcorp is doing everything it can to lower the costs and save
them for another day. Currently, Hilcorp is looking as to
whether it can make investments to turn those platforms back on.
REPRESENTATIVE OLSON asked whether platforms A and C belong to
Hilcorp.
MR. WILKINS responded yes, Hilcorp recently acquired platforms A
and C from XTO Energy Inc., but right now those platforms are
not making money.
2:35:49 PM
REPRESENTATIVE JOHNSON commented that it is heard from both big
and small producers that they want stability, and he is
interested in stability for his constituents. He asked whether
HB 247 would enhance stability for his constituents so there
would be no need for rolling blackouts.
MR. WILKINS answered that over the last four years Hilcorp has
invested a lot of money, especially in oil production. In
regard to natural gas production, the issue in 2012 was that
there wasn't availability, especially over a longer period of
time, to give confidence in the market. He said he thinks
Hilcorp has demonstrated through significant investment that it
has brought stability and extra capacity to the market, as well
as deliverability in the places it needs to be. Hilcorp is
convincing the local utilities that, yes, that capacity is there
and at the same time Hilcorp is providing that gas at an
affordable rate for the customers. If Hilcorp doesn't spend the
continued investments the wells are going to decline and it
could very quickly return to the situation where there isn't
enough gas to meet the market demands. He, too, is concerned
going forward about the stability, but as long as Hilcorp keeps
doing what it is doing and bringing on new gas....
2:37:53 PM
REPRESENTATIVE JOHNSON understood that Hilcorp is working on
contracts to the year 2023. He inquired as to what effect, if
any, HB 247 would have on Hilcorp's ability to fulfill those
contracts.
MR. WILKINS replied that Hilcorp is very confident it has the
projects to bring on to meet the demands in the future. Hilcorp
doesn't execute on those projects today because it doesn't need
to deliver the gas today. But Hilcorp is very confident that
when it needs to deliver that, it will do the projects, spend
the money, and bring the gas on. All that said, Hilcorp hasn't
stopped looking for new gas. Hilcorp is drilling exploration
wells and will continue to look for new gas and new oil in the
Cook Inlet basin. Hilcorp will be drilling a new well on the
Monopod in the next two weeks and Hilcorp plans to do an
exploration well or two in the Kenai area. Hilcorp just
finished drilling an exploration well in the Kenai area that
unfortunately wasn't successful. Hilcorp spent over $12 million
on that well, but the geology there is very complex and Hilcorp
is trying to employ new technology to find new oil and gas in
that area.
2:39:25 PM
REPRESENTATIVE JOSEPHSON remarked that the testimonies of Mr.
Wilkins and Mr. Johnson have been very interesting. He
recounted that the legislature's consultant, Janak Mayer of
enalytica, told the committee that the Cook Inlet credits are
exceptionally generous and Mr. Mayer questioned their
sustainability. Representative Josephson further recounted that
Mr. Mayer seemed to be speaking as the secondary source as if
he'd spoken to someone who is a primary source of the data.
Representative Josephson further recounted that yesterday Mr.
Armstrong noted that this is the most generous tax regimen in
the world. He asked whether Mr. Wilkins thinks these are
sustainable.
MR. WILKINS responded that all he knows from his perspective is
that they've worked, they've done what they intended to do.
Hilcorp is in a little different situation. It has invested
billions of dollars and is not looking to get that money back in
a year or two; Hilcorp is making long-term decisions. Right now
Hilcorp is looking to get its money back over a five to ten year
period. Hilcorp is all the time projecting its long-term
investment and what Hilcorp desires is predictability and
sustainability in the fiscal regime so it can make decisions.
From the tax credit standpoint, he would still argue that
Hilcorp has done exactly what the state wanted it to do and the
state benefitted from the work that Hilcorp has done.
REPRESENTATIVE JOSEPHSON thanked Mr. Wilkins for that work.
2:41:59 PM
REPRESENTATIVE OLSON understood that Hilcorp now has some of the
longer gas contracts in the inlet, primarily to ENSTAR Natural
Gas Company ("ENSTAR"). He inquired whether, if the tax
structure changes during that period, Hilcorp is allowed to pass
that on to ENSTAR or Hilcorp is stuck with whatever was in
effect when it signed the contracts.
MR. WILKINS answered that Hilcorp has multiple contracts and all
the time Hilcorp is renewing and giving contracts. He said the
price of gas is actually coming down because Hilcorp has been
successful. Hilcorp looks to be successful and provide energy
needs to Southcentral Alaskans that's affordable and reliable.
REPRESENTATIVE OLSON posed a scenario in which the tax goes up
significantly and Hilcorp is in the middle of a contract. He
asked whether that is an allowable item that Hilcorp can pass on
to ENSTAR.
MR. WILKINS replied that he would see it that way. He said
Hilcorp incorporates the tax credits into its overall long-term
decisions and investment decisions. Hilcorp is a little
different than some of the other companies that are using the
tax credits because Hilcorp incorporates that in its decision
making. Hilcorp is going to spend money in Alaska doing
projects and doing them economically as Hilcorp sees it can.
So, the tax credits going away will have an impact on Hilcorp's
investments, on the level of Hilcorp's investments, but he still
sees Hilcorp meeting the energy needs and meeting the market for
the foreseeable future for the life of its contracts.
2:43:58 PM
REPRESENTATIVE SEATON recalled that enalytica told the committee
that $5-$7 per thousand cubic feet (MCF) is sufficient price to
produce the most expensive gas in the world. He noted that the
[November 2012 consent decree between the State of Alaska and
Hilcorp Alaska, LLC,] will go [until sometime in 2017]. He
further noted that Hilcorp is working on contracts through the
year 2023. He stated that [legislators] are in a dilemma with a
$3.8 billion deficit and yet these refundable tax credits were
$500 million this last year and are estimated to be $623 million
next year. Taking $1,000 from every resident's dividend would
just about equate to the $623 million that will be provided in
reimbursable tax credits. Therefore, he is trying to figure out
where, as a policy, [the legislature] breaks this where the
credits are needed. He said it seems to him that the credits
for gas in Cook Inlet are liked, but given the price structure
of Cook Inlet gas, they're really not needed. He requested Mr.
Wilkins to comment on this statement.
MR. WILKINS responded that Hilcorp is an example of where the
tax credits worked and both benefitted. He said he appreciates
that the state needs to make difficult choices, but all of the
companies are faced with the same dilemma. There isn't a magic
elixir decision here. Will removing the tax credits impact
investment in Alaska? Yes. How much? It will depend on the
levels that are being talked about.
2:46:31 PM
REPRESENTATIVE SEATON related that he has been thinking about
how to parse which credits to pay and which credits must be
withdrawn. He asked whether Mr. Wilkins would see it as being
reasonable if those people who have committed to final
investment decision (FID) and have a DNR-approved plan of
development were grandfathered for some period of time.
MR. WILKINS answered that it is tough for him to say without
knowing all the specifics. He said Hilcorp would welcome the
opportunity to evaluate and provide comment. He added that he
agrees with ExxonMobil's comment that a response can be provided
from an industry perspective through AOGA because he does not
want to make a comment that is favorable to Hilcorp but
detrimental to another company.
REPRESENTATIVE SEATON clarified that he is not asking a "gotcha
question" but is trying to figure out how to move forward in the
current economic environment, what is the state's net present
value on investments, and how to give companies enough latitude
to amortize their investment and decision making. The state
cannot invest in everything. He urged Mr. Wilkins to talk with
others and provide the committee with ideas on how to parse
things.
2:49:07 PM
REPRESENTATIVE TARR offered her understanding that Hilcorp's
development for the Cook Inlet is separate from the company's
development for the North Slope. She said she thinks she is
seeing very different scenarios for these two areas in terms of
the generosity of the credits. She inquired as to which credits
have been used by Hilcorp.
MR. WILKINS replied he is not a tax person and therefore doesn't
have specific line-by-line answers. But, he said, Hilcorp takes
the tax credits very seriously and the credits get incorporated
into all of Hilcorp's investment decisions. Within a company
like Hilcorp, dollars can go several places and he would love
for capital dollars, investment dollars, to come to Alaska to
where Alaska benefits and to where Hilcorp benefits. Hilcorp
takes everything into account when making those investment
decisions because they can go to Texas, Louisiana, or elsewhere.
2:50:34 PM
REPRESENTATIVE TARR stated that the very generous bonuses that
went to Hilcorp employees is something her constituents have
reacted to. This is a consideration here, she said, because she
represents an area where 39 percent of the families in one of
the neighborhoods make less than $25,000 per year. So, for her
constituents it seems there is opportunity to make adjustments
in the system that seem fair.
MR. WILKINS responded that if the implication is that Hilcorp
took money from the state to pay the bonuses, the answer to that
is categorically no. He explained that Hilcorp uses any kind of
tax credit to promote the projects within Alaska and increase
production, which Hilcorp has demonstrated. He said he has been
with Hilcorp for 10 years and the aforementioned bonus program
was the latest of two bonus programs.
REPRESENTATIVE TARR understood the other bonus program was a
car.
MR. WILKINS continued his response and said that Hilcorp met
both of its bonus programs. This last program was started five
years ago in 2010 before Hilcorp was in Alaska. Hilcorp went to
its employees and told them it wanted a long-term incentive goal
to incentivize the behaviors that the company wants. For five
years Hilcorp planned on paying those by having a systematic
measure to reward the employees when they were successful.
Hilcorp also views that as a compensation; it's a long-term
compensation incentive within Hilcorp and the company benchmarks
those against other companies. Lots of companies in the U.S.
have long-term incentive programs. Some give stock options, but
Hilcorp gives what it calls "a BHAG bonus - Big Hairy Audicious
Goal" and it's a five-year goal. The actual program is to
double the size of the company: double production, double
reserves, double equity value of the company. When looking at
the structure of the program on a per-year basis, the goal is
actually less per employee than what Hilcorp provides in
healthcare and so is not out of line at all. What does the
company get when its employees do that? It gets 1,350 employees
pulling every day for a common goal. When the goal was started
in 2010, did Hilcorp anticipate oil prices crashing? No. The
company had to decide whether to honor its commitment because it
impacted the bottom line and it hurt. Over half of Hilcorp's
employees are field workers, hard-working folks that got
energized about this goal. When he talked to employees about
what they did with their bonus, some people said they paid down
debt, some sent kids to college that otherwise wouldn't have,
and one person bought a house. He said he knows Hilcorp did the
right thing - a deal is a deal - and he is proud of doing that.
REPRESENTATIVE TARR appreciated Mr. Wilkins response and said
members feel similarly in terms of the expectations of Alaskans
of having a deal on receiving a permanent fund dividend or other
programs. It is a challenge to balance those things, she added,
and it will be difficult to work through.
The committee took a brief at-ease.
2:56:59 PM
BRUCE WEBB, Senior Vice President, Furie Operating Alaska LLC,
explained that Furie Operating Alaska LLC ("Furie") started out
as Escopeda Oil Company buying the first leases in the Cook
Inlet between 2002 and 2006. The president at the time, Mr.
Danny Davis, formed a unit and tried to get investors involved
in what would be a very expensive endeavor bringing a jack-up
rig to explore the offshore Cook Inlet resources. Escopeda
found such an individual, a German citizen with a German
investment company, and in October 2010 Escopeda became Furie
Operating Alaska LLC. The company's main investments came from
Germany and those investments were raised by touting the State
of Alaska as its business partner. The state, through the tax
credit program, basically subsidized Furie's exploration and
development. It was widely praised in Europe that the State of
Alaska was a partner in trying to get more exploration and
development in the Cook Inlet. Furie was able to bring up the
Spartan 151 jack-up rig in August 2011, the first time in 20
years that a jack-up rig had been in the Cook Inlet. Furie has
been on the leading edge of everything throughout this project,
there has been one hurdle after another. Furie is proud to say
that it has drilled five different wells in five years and put
in the first platform in the Cook Inlet in about twelve years.
MR. WEBB played a video showing the magnitude of the project and
the number of employees and contractors involved in the jack-up
rig. The video starts in Corpus Christi, Texas, he explained,
with the monopile structure being made and then all the
facilities being constructed. The rig moves from the Gulf of
Mexico through the Panama Canal up to Seattle and then into the
Cook Inlet.
3:03:16 PM
MR. WEBB stated that, without a doubt, this project would not
have happened without the tax credit program. While other Cook
Inlet explorers have talked about wells that cost $12-$40
million, he continued, drilling a well in the offshore Cook
Inlet is $60-$80 million - a huge investment. When Furie went
into this with the tax credit program it had a 10-year goal in
mind and certain financial commitments to make along that goal.
If the tax credit program goes away, he said, it will have a
significant impact on the company. Furie just set the platform
and first production was in November [2015]; to date about 700
million cubic feet (MMCF) has already been produced. Furie's
first real contract starts in April, but even that contract
doesn't meet just the debt commitment. Furie's debt commitment
doesn't fully get met until the contract that was just signed
last week that starts April [2018]. So, between 2016 and 2018,
Furie has this period of being at the bottom of the curve (the
curve as was discussed by Mr. Johnson of BlueCrest) and will not
start moving up until 2018, and that is with the tax credits.
If the tax credits go away, Furie's ability to explore and do
further developments will really be hindered.
3:04:44 PM
MR. WEBB, regarding the unintentional consequences mentioned by
Representative Tarr, noted that the Kitchen Lights Unit is
83,000 acres; Furie just developed a 300 acre area that's going
to have significant gas reserves and the gas price in the Cook
Inlet has already gone down. But, if Furie doesn't continue to
meet exploration and development targets, the Department of
Natural Resources will systematically reduce those 83,000 acres
down to just what is the producible area. What does that mean
to the state? That means that those leases go back up for bid.
How many companies are going to bid on a lease with the price of
oil at $30? Then, when they do start getting the leases there
is going to be a non-contiguous ownership so it will probably
take decades before a contiguous unit is formed and a company
has the ability to bring up another jack-up rig. Furie has a
new jack-up rig that will be arriving in Homer next week.
Without the tax credit program, Furie probably won't be able to
keep that rig here. That's just the economics. The exploration
and development window in the Cook Inlet is only six months, so
Furie must pay for that rig during the six months that it is not
using it. It is too costly [to keep the rig] unless a company
has a goal and a financial structure in place that can be relied
upon. The bottom line is that Furie came into this with a tax
structure that it thought was reliable and could be counted on,
and now it's being changed in the middle of Furie's game. This
is not going to be good for the company. In just the last year,
two Cook Inlet producers have already filed bankruptcy and one
has left the state. This is a very expensive environment,
especially the offshore, and the offshore is where the biggest
resources are. Furie has huge wells, but they are very
expensive to get to the market and it is going to take Furie 10
years before it starts seeing a profit.
3:07:05 PM
DAVID ELDER, Chief Financial Officer, Furie Operating Alaska
LLC, began the PowerPoint presentation regarding the impacts
that HB 247 would have on Furie Operating Alaska LLC. Turning
to slide 1, "Overview: Tax Credits = Jobs," he said the bottom
line is that Furie never would have undertaken a project as
large as this without the tax credits. Furie did exactly what
the tax credits were intended to do: a small independent
exploration and production company that could move quickly and
was willing to make these commitments came to the Cook Inlet,
and over a five-year period it developed and began producing
significant new natural gas reserves. The tax credits support
investment in the state, they create jobs, they bring revenue,
and Furie is just at the phase now where it will begin making
its repayment back to the state for the benefits it has
received. Furie has invested $700 million in Alaska over the
last five years, and over the next two to three years will
invest another planned additional amount of approximately $300
million, depending on what happens with the credits.
MR. ELDER noted that Furie's investment horizon has to be long.
The unique nature of the Cook Inlet gas markets, the contract
structures that are in place, mean that it takes a while for
Furie's cash flows to build up to the point where it breaks even
and meets all of its obligations to the state as well as to
lenders and investors. Furie is looking at probably a seven to
ten year horizon before it has recovered its investment in the
Cook Inlet. Furie estimates that it employed over 300 people in
Alaska at the peak of its construction phase last year. Furie
likes to compete, it's a little guy that has come on the scene
to help compete and lower prices. The declining prices in the
natural gas market in Southcentral Alaska reflect, in part, what
Furie has done, as well as other people's investments. If Furie
doesn't have these tax credits going forward, the company will
be forced to significantly reduce its investment, probably to
absolute minimum levels. The ability to continue to explore and
develop the 84,000 acres could be significantly lost to Furie.
3:09:55 PM
MR. ELDER addressed slide 3, "Tax Credits Help Alaskans by
Supporting Development," and said the lower energy prices are
going to benefit the people of Southcentral Alaska. It is going
to help produce new jobs and every month it will save families
when they pay their utility bills. Furie uses over 100 local
companies as vendors. Furie is lowering the risk of shortfalls
in natural gas in the future. While Furie respects what other
people have said on their ability to continue to increase
reserves, the company's studies show that it is going to be
critical to the Southcentral region that Furie continue to
develop these resources offshore.
MR. ELDER stressed that all of the tax credits have benefitted
Furie. The company needed the 20 percent credit for tangible
spending, he said, and the 40 percent on intangibles has been
critical because of the high cost of drilling a well in the Cook
Inlet. Offshore is automatically more expensive. Furie totally
agrees with the figure of at least 300 percent more expensive
that was presented earlier. Regarding keeping rigs on contract
365 days a year, he noted that Furie brought some of the first
new supply vessels back up to the Cook Inlet. A lot of these
resources materials, as well as some specialized skills, must be
brought up from the Lower 48. The 25 percent loss credit is
critical in the early phases of development. Provided that the
other credits are retained, Furie will be very happy when it
gets to a point where it no longer qualifies for loss credits
and becomes a positive taxpayer.
3:12:07 PM
MR. ELDER moved to slide 4, "Benefits for Alaska," and
reiterated that Furie helped create 300 jobs this [past] summer.
He provided some examples of the results of Furie's investment
and the payback that Furie will begin giving to the state. For
the first five years, Furie paid $3 million in local property
taxes, an average of $350-$600 a year. Furie estimates that in
2016 it will be paying close to $5 million annually, which
reflects the investment in property, plant, and equipment that
the company has done. Furie has paid lease rentals to the state
of about $1.6 million, and is very conservatively predicting
that it will be paying royalties of $300 million to the state
[over the life of the reserves].
3:13:14 PM
REPRESENTATIVE SEATON recalled that enalytica, the legislature's
consultant, provided committee members with three different
scenarios, of which one was a constrained market for gas in Cook
Inlet. In that scenario, he related, the state was in a net
present value loss over the entire life of the development,
regardless of the gas price; it was only with an unconstrained
market that it turned around the other way. He asked whether a
constrained market will be maintained such that it will be a
huge investment up front that will not be recovered. He said
committee members are trying to balance the scenarios provided
by the consultants to putting massive amounts of credits for a
large project if it isn't going to pay the state back over time
unless it is an unconstrained market.
MR. ELDER replied that Furie recognizes and appreciates the
constraints had by the state. Industry is now going to see a
lot of hurt and loss of jobs and Furie appreciates that the
state has residents who struggle and work hard. He said his
answer to the question is that in the early phases Southcentral
was having brownouts, prices were rising, and there were
shortages that justified generous incentives at the time because
of having to mobilize. Furie sees significant resources that
will enable it to justify the investment and deliver the supply.
However, he pointed out, to the largest companies it is not
large enough. Companies like Furie that are capital constrained
must pay more for those investment dollars. So, at least in the
beginning of these developments, the credits were absolutely
critical. Part of the challenge of this market is that it is a
unique, localized market. But, because of the contracting of
the utilities and the need to lock in supply, a cycle is being
seen of where there is now gas supply but it will take a couple
of years to get that supply into the market. So, there is
continued need of these credits to do that. Over the long run
Furie could see the credits being phased reduced at some point
in time, but his message today is that Furie needs certainty in
the next few years to complete what it has already started.
3:16:41 PM
REPRESENTATIVE SEATON inquired whether plans of development and
final investment decisions is the correct point for decision
making of where a timeframe is given to continue, but the state
would no longer be able to financially do speculation and
leasing of new areas without there being a final investment
decision.
MR. WEBB responded that that is very hard to answer because if
the state gives certainty to Furie for this current development,
it gets the company over the hurdle and allows it to meet its
commitments for its future gas contracts and do some additional
development drilling to maybe get more gas contracts in the
future. However, the problem is that future exploration and
development is so expensive. Until Furie gets to where it has
profit, it is unable to commit to the type of investment needed
to find another field and set another platform; Furie cannot do
that out of its pocket.
3:18:23 PM
MR. ELDER resumed his presentation. He drew attention to the
list of about 100 local businesses on slide 5, "Alaska Partners
Supporting Exploration and Development," and said that these
businesses provided both services and goods to Furie. He noted
that the list includes local operations of multi-national oil
and gas service companies as well as local hardware stores and
vendors that rely upon income from Furie's operations to help
employ people and support their businesses.
MR. ELDER turned to slide 6, "Tax Credits Helped Furie Bring
Cheaper Gas to Southcentral Alaska," and said the tax credits
have done what [the legislature] told Furie it wanted the
company to do. Furie developed more natural gas which increased
supply. Under its first contract with Homer Electric
Association Furie is selling significantly lower than the
consent decree pricing. The other day Furie signed a new gas
contract that will provide a large amount of gas significantly
below the Hilcorp pricing and below the pricing in the renewed
Hilcorp and Chugach Electric Association contracts. The tax
credits have done that. Furie estimates that that is worth $75
million a year to the residents of Southcentral Alaska and that
does not take into consideration the jobs that can be retained
through lower cost energy sources.
3:20:13 PM
MR. ELDER moved to slide 7, "General Comments about HB 247," and
specified that these comments are from a Cook Inlet perspective
only. He said that repeal of the 40 percent and 20 percent
credits [AS 43.55.023(a) Qualified Capital Expenditure (QCE)
Credits and AS 43.55.023(l) Well Lease Expenditure (WLE)
Credits] will definitely have a negative impact on future
investment, at least for Furie. Retention of the 25 percent
loss credit [AS 43.55.023(b)] is helpful, but it is not adequate
with the repeal of the other credits, especially with the $25
million limitation on purchase of the cash credit certificates.
The proposed changes have really hit and hurt Furie's ability to
finance its operations. Small companies have to borrow money
and get competitive money, he explained, and Furie has to pay
back that money this year. If changes are not made [to HB 247's
proposals], Furie will have a hard time paying back its lenders.
He also noted that the proposed change of July 1, rather than a
phase-out over a reasonable time period, will cause confusion
and loss because Furie put its plans in place two years ago.
3:21:42 PM
REPRESENTATIVE OLSON asked whether HB 247 will have any impact
on Furie's long-term contracts that are already in place; for
example, whether Furie will be able to pass that on to Homer
Electric Association and others that it has sold gas to.
MR. WEBB answered no. The contracts are based on firm prices
and firm commitments, so there is no way for Furie to re-enter
the negotiation and say it now wants a higher gas price because
the tax credits changed and now Furie is at a loss. Furie would
be stuck, it negotiated a gas price and has to stick with it.
3:22:21 PM
REPRESENTATIVE OLSON postulated that depending upon the length
of the contract, Furie could have new gas coming into it that
was done under a different structure. He asked whether Furie
would still have to sell that gas at the original price.
MR. WEBB replied that if Furie had a new contract it could
negotiate a different price and that price would be based on
what Furie's investments and capital costs are. However, for
the contracts that Furie has right now, the price is set.
REPRESENTATIVE OLSON presumed that Furie doesn't have 100
percent of the gas for the contracts, so Furie would have gas
coming in that was under a different well, but he understood
that Furie would have to sell that gas at the same price.
MR. WEBB responded correct, under Furie's last contract it has
to drill three more wells.
REPRESENTATIVE OLSON concluded that Furie could then be
competing on that.
MR. WEBB answered right, Furie has to drill the wells no matter
what.
3:23:12 PM
REPRESENTATIVE JOSEPHSON inquired whether the contracts with the
Homer Electric Association are confidential or public.
MR. WEBB replied that they are public through the Regulatory
Commission of Alaska (RCA).
3:23:27 PM
MR. ELDER returned to his presentation. He displayed slide 8,
"Tax Credits Enable Development Companies to Access Low Cost
Capital," and noted the importance of the tax credits to
financing. Regarding unintended consequences, he stated that
the actions last year on the line-item veto and the confusion
that that generated throughout the financial community froze
Furie's borrowings at that time. Furie is thankful that members
of the legislature, the governor's office, and the Department of
Revenue took time to meet with potential lenders, because only
through that was Furie able to access that funding. Those
actions instantly cost Furie $30 million in funding and hit
Furie right in the largest development phase it had ever done.
Furie was eventually able to get a lot of that back through
discussions with the state. The problem Furie has right now is
that lenders are unsure whether Furie will get paid the 2015
credits it has earned and lenders have stopped lending in 2016.
3:24:29 PM
REPRESENTATIVE JOSEPHSON allowed the veto was very significant
in terms of its impact, but said that if he were counsel to the
oil companies he would have advised each time he met with his
client that the statute says the state only has to pay 10
percent. He inquired whether Furie was aware of this.
MR. ELDER responded that Furie was aware. But, he added, the
state had a history of not doing that and there was faith in
that. When Furie started the applications were submitted
quarterly and were processed and paid within about six or seven
months. Furie recognized that changes were occurring and
restructured its programs. All Furie is trying to do is use the
existing program to finalize and fund a program that started two
years ago. Furie is asking for certainty. A question was asked
earlier about what is most important - the absolute level of the
credits or this current system and dependability? He would say
that a company like Furie has to have that certainty because it
has to meet its financial obligations. Furie needs the credits,
but certainty is needed too.
3:25:53 PM
REPRESENTATIVE TARR observed the bullet on slide 8 about being
able to access low cost capital and pointed out the provision in
HB 247 for a fund under the Alaska Industrial Development and
Export Authority (AIDEA) from which companies could borrow. She
asked whether that fund could be similarly used to leverage low
cost capital for the investments.
MR. ELDER answered that the $25 million limit is not enough.
The cost of capital for a development stage company is extremely
high, he explained, and such a company also has the constraints
of how to fit in a different lender with the company's other
lenders that don't want to get any collateral or consideration
of anybody else. Just $25 million won't do it, especially when
combined with the $25 million cap on these credits. While
helpful, it isn't enough. Furie has talked to AIDEA in the
past, but it was explained that the risk of oil and gas
investment doesn't necessarily fit what AIDEA's investment
profile is.
3:27:04 PM
REPRESENTATIVE TARR pointed out that another piece of
legislation [HB 246] would capitalize the aforementioned fund
and would provide another opportunity to revisit the cap, at
which time Furie could provide comment as to what would be more
favorable to advancing its projects.
MR. ELDER replied that he does have some good ideas on that but
didn't have a chance to talk about them during his last visit
with [DOR Commissioner] Hoffbeck. He suggested that a fund be
structured that financed these credits; this would allow the
state some flexibility and give industry certainty.
MR. ELDER thanked the committee for the opportunity to comment
on HB 247.
[HB 247 was held over.]
| Document Name | Date/Time | Subjects |
|---|---|---|
| HSE RES 3.1.16 BlueCrest Testimony Slides.pdf |
HRES 3/1/2016 1:00:00 PM |
HB 247 |
| HSE RES 3.1.16 Furie Alaska.pdf |
HRES 3/1/2016 1:00:00 PM |
HB 247 |
| HSE RES 3.1.16 HB 247 - Hilcorp written testimony.pdf |
HRES 3/1/2016 1:00:00 PM |
HB 247 |