Legislature(2015 - 2016)BARNES 124
02/24/2016 01:00 PM House RESOURCES
| 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
1:04:31 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."
1:05:06 PM
CORRI FEIGE, Director, Central Office, Division of Oil & Gas,
Department of Natural Resources (DNR), on behalf of the
governor, began a PowerPoint presentation entitled, "Alaska's
Oil & Gas Industry Overview & Activity Update." She turned to
slide 2, "Overview," and advised that due to time constraints
the presentation has been broken into North Slope, Cook Inlet,
and Frontier Basins.
1:05:15 PM
PAUL DECKER, Petroleum Geologist, Central Office, Division of
Oil & Gas, Department of Natural Resources (DNR), drew attention
to slide 3, "North Slope Resources Overview," and explained that
it shows the land management areas on the North Slope. The
National Park Service administers the Noatak National [Preserve]
and Gates of the Arctic National Park & Preserve. The U.S. Fish
& Wildlife Service administers the Arctic National Wildlife
Refuge (ANWR). The coastal plain [1002 area] of the refuge is
shown in a different color because it's not yet permanently
protected and permanently off limits to oil and gas; he offered
his hope that it will not come to that. The other federal land
making up a big chunk of the North Slope is the National
Petroleum Reserve-Alaska (NPR-A), which is about the same size
as the State of Indiana. He then pointed out the state lands on
the North Slope:
So, the state lands are those encompassed by the red
lines where we have our annual areawide lease sales.
So starting along the shoreline from zero to three
miles off shore we have the Beaufort Sea areawide
sale, in the Central North Slope onshore we have the
North Slope areawide sale, and then to the south the
Foothills sale. And you'll also notice important
acreage within the Foothills sale and also on the
extreme western North Slope that is [Arctic Slope
Regional Corporation (ASRC)] surface and subsurface
estate, so yet another owner there. The coastal plain
areas that are in north of the dashed blue line, and
you can see that the black dots show a greater
exploration well density north of that blue line, so
that the coastal plain has been somewhat better
explored. The Foothills area to the south is a lot
lower exploration well density, less exploration
there, and what you'll also notice is two trends of
oil and gas accumulations, the oil in green and the
gas accumulations in red. The main producing trend,
of course, is near the shoreline within say 30 or 40
kilometers of the shoreline. And that's because
that's underlain by a huge feature known as the Barrow
Arch, which is really, really good petroleum habitat,
in essence. There is also a Foothills trend, mostly
gas accumulations discovered to date, Umiak being the
contrarian there, the exception. So, these are the
areas and most of these areas have been assessed
independently by the U.S. Geological Survey [(USGS)]
for their resource potential.
1:09:10 PM
MR. DECKER explained that slide 4, "Arctic Alaska Oil & Gas
Resources," rolls up all of those federal resource estimates
from USGS onshore and the Bureau of Ocean Energy Management
(BOEM) offshore for Arctic Alaska. The numbers on the bottom
line of the chart are correct: the 40 billion barrels of oil is
the mean estimate when combining the onshore and offshore oil,
and 207 or so trillion cubic feet (TCF) of undiscovered gas. He
reiterated that these numbers are the mean estimates of a
probabilistic distribution accounting for a large degree of
uncertainty about how much exactly remains in this category,
which is undiscovered, technically recoverable. These mean
estimates are not reserves and they are not necessarily
economically recoverable. He pointed out a typographical error
within the blue block entitled, "Mean Oil Estimate," and said it
should read millions of barrels, not billions, thus the number
is read as 15,908 million or 15.9 billion barrels of oil. It is
relatively evenly split between onshore and offshore. On the
oil side, the Chukchi and Beaufort seas appear to have more
undiscovered oil than the onshore acreage. Onshore is dominated
by about 10 billion barrels in ANWR, about 4.5 billion barrels
undiscovered in the central North Slope state lands, and less
than 1 billion in NPR-A.
REPRESENTATIVE HERRON asked whether the offshore estimates are
within 200 miles.
MR. DECKER replied yes.
1:11:20 PM
MR. DECKER stated that slide 5, "Arctic Alaska Oil & Gas
Resources," drills down to more along the lines of reserves as
opposed to just undiscovered resource. There are approximately
30 trillion cubic feet of associated gas that is estimated to be
recoverable in the existing producing fields, and primarily
that's Prudhoe Bay with Pt. Thomson lumped in, which is about a
3:1 ratio. Since there is not yet an Alaska Liquefied Natural
Gas (AK LNG) line, a gas transportation system is not in place
and it is best to consider those numbers as contingent resource,
he advised, and not as reserves per se.
CO-CHAIR NAGEAK requested an explanation of contingent resource.
MR. DECKER explained that contingent resource is the resource
that has been discovered but not yet approved for commercial
development, not yet sanctioned, not yet brought into
development. So, it's discovered and it may become reserves in
the future with a demonstration that those volumes are economic
to produce.
CO-CHAIR NAGEAK asked what has to be done to make it so.
MR. DECKER said that typically the threshold would be a sanction
decision, a final investment decision (FID) in the case of AK
LNG.
1:12:50 PM
MR. DECKER referred to the second bullet on slide 5, and said it
drills down within the actual currently producing fields and how
much is in the proved gas reserve category. He said that
according to the Energy Information Administration (EIA) there
is about 6.4 trillion cubic feet of proved associated gas
reserves, of which a little bit [about 0.5 percent] is Cook
Inlet gas and the bulk of which is North Slope gas in places
like Prudhoe Bay. He advised that the 6.4 trillion cubic feet
of reserves would be the portion of the gas in the existing
fields that actually has some sort of a market, and that's
really mostly a local market used on lease or in adjacent
fields. With regard to the oil reserves, he explained that the
EIA's latest report as of year-end 2013 gives the North Slope
approximately 2.8 billion barrels of oil reserves in the proved
category, which is not too different from what the Division of
Oil and Gas estimated in recent history from its own decline
analysis.
1:14:24 PM
REPRESENTATIVE HAWKER asked whether the division's definition of
"proved" resource requires being economically recoverable or is
simply the known proved existent resources.
MR. DECKER responded that proved reserves are specifically in
that economically recoverable, expected to be recovered, tranche
of volumes. When the division says proved reserves, it connotes
a 90 percent certainty that at least that much gas will be
produced.
REPRESENTATIVE HAWKER inquired about the division's standard for
economically viable recoverable resources.
MR. DECKER replied that the economic hurdle is considered to be
met when, for example, a project is sanctioned, the gold
standard is when a project is sanctioned to go into development.
1:15:26 PM
REPRESENTATIVE HAWKER concluded then that the entire 6.4
trillion cubic feet of associated gas reserves is a sanctioned
project that is behind pipe.
MR. DECKER replied no, that is a bit of an exception and is one
of the things about the North Slope that's a little odd. The
North Slope has its own local market where gas is sold back and
forth between the producers and used on site - things like
miscible gas injectant or fuel use. He said he will have to ask
the EIA why it describes that as proved gas reserves, but his
understanding is that it's because it is part of a local market
that is functioning on the North Slope.
REPRESENTATIVE HAWKER surmised that the 2.8 billion barrels of
oil reserves are currently in the process of being recovered
through a sanctioned project.
MR. DECKER replied "through all the sanctioned fields ... that's
correct."
1:16:36 PM
REPRESENTATIVE HERRON understood that the definition of a proven
reserve is 90 percent confidence in it.
MR. DECKER responded correct, 90 percent certainty that at least
that volume will be produced.
1:16:58 PM
REPRESENTATIVE TARR surmised that the oil reserves in the
sanctioned projects are over the life of that field. She asked
for specifics that break down [the number of 2.8 billion barrels
of oil (BBO)].
MR. DECKER answered he does not have that number today, but said
the division could work it out in an approximate fashion. He
noted that the largest part of that will be Prudhoe Bay, then
Kuparuk and Colville River Unit, and so forth.
REPRESENTATIVE TARR said she would appreciate understanding the
breakdown better.
1:17:44 PM
MS. FEIGE turned to slides 6-9, "North Slope Current Activity &
New Developments," to outline the current and new activities of
various companies. She explained that Accumulate Energy Alaska,
Inc. (AEA), is a newcomer to the state and is partnered with 88
Energy and Burgundy Xploration. They came into the state with
Burgundy Xploration acquiring a sizable lease position in 2014
in the central North Slope area, and are predominantly looking
at shale potential. They drilled the Icewine #1 exploration
well on the Franklin Bluff's pad, which is a pre-existing gravel
pad located along the Dalton Highway about 65 miles south of
Deadhorse. Based upon the results of the Icewine #1, Accumulate
is now getting ready to commence a seismic survey across its
leasehold in central North Slope, and it also participated in
the November 2015 lease sale and the partnership took about 130
additional tracts in that sale.
MS. FEIGE noted that ASRC Exploration, LLC (AEX), a wholly owned
subsidiary of the Arctic Slope Regional Corporation (ASRC), is
currently drilling an exploration well in the Placer Unit. The
Placer Unit is located immediately south of the Oooguruk Unit
which is held by Caelus Natural Resources.
MS. FEIGE said [BP Exploration (Alaska) Inc.] is one of the long
time foundation producers on the North Slope and continues to be
very aggressive at expanding and maintaining development and
production out of the Prudhoe Bay Unit. She pointed out that BP
has completed 8 wells, 46 new sidetracks, and well over 420
workovers just in the Initial Participating Area (IPA) in 2015.
The company completed additional wells in the Lisburne
Participating Areas (PA) and also some in-unit seismic in the
North Prudhoe Bay in 2015.
1:20:24 PM
MS. FEIGE reported that Caelus Natural Resources [Caelus Energy
Alaska, LLC] (slide 7) entered the state in 2013, acquiring
Pioneer Natural Resources position in the Oooguruk Unit. Caelus
continues with ongoing development and production at Oooguruk
with four to five long-reach wells drilled each year that are
stimulated through large multi-stage fracks. Caelus has
performed work recently optimizing that frack to optimize and
increase recovery in those wells. She said Caelus Natural
Resources is also undertaking the Nuna Development, a new
project development. The surface facilities sit within the
Kuparuk Unit immediately outside of the Oooguruk Unit, although
the accumulation is within the Oooguruk Unit itself on the
southeastern flank of that unit. Caelus's first production is
on track for late 2017. Caelus installed a gravel road and pad
last winter but is not performing construction work at Nuna this
winter. Instead, Caelus, with its partner NordAq Energy Inc.,
is in Smith Bay drilling the second of two exploration wells.
Those wells are being drilled from a grounded ice pad in shallow
water just off shore. Smith Bay is located approximately 80
miles southeast of Barrow.
1:22:11 PM
MS. FEIGE stated that ConocoPhillips Alaska, Inc. (slide 7), a
very active company on the North Slope, is working in the
Colville River Unit and initiated production at CD5 in October
2015, with that production rapidly exceeding its expectations.
Conoco plans to drill eight new wells in 2016 on the CD5
development. In late 2015, Conoco sanctioned the Greater Mooses
Tooth Unit (GMT1), which will be a new development located
inside the NPR-A. Conoco also continues work at the Kuparuk
River Unit with the first wells at drill site 2S coming online
in late 2015 and with significant drilling planned for 2016
throughout the unit.
MS. FEIGE reported the exciting news that ExxonMobil Corporation
will commence production of natural gas liquids (NGLs) in the
Pt. Thomson unit by mid-May 2016. Construction of the Initial
Production System (IPS) has been completed, as has construction
of the pipeline that connects Pt. Thomson into the Badami Field.
The Badami pipeline then connects to the Trans-Alaska Pipeline
System (TAPS) and the sail line.
MS. FEIGE advised that Great Bear Petroleum is currently
acquiring a very large three dimensional (3D) seismic survey.
Great Bear is another shale player located to the north of
Accumulate in the central North Slope region. Great Bear plans
to re-enter its Alkaid #1, drilled in 2014, and perform
additional well work after the completion of its seismic this
year and the Alkaid will come next year.
1:24:02 PM
REPRESENTATIVE HAWKER recalled that Great Bear was moving ahead
rapidly with this development with the support of Alaska
Industrial Development Authority funds, but its third-party
financing withdrew after the veto of the state tax credits last
year. He asked whether that has compromised the project, or the
division's assessment of its future viability.
MS. FEIGE replied she can't speak to whether it has compromised
the future viability, but that Great Bear did tell the division
that it has impacted the schedule under which it is taking
future work. The Alkaid #1 work was originally scheduled for
2016, and now has been pushed back to 2017. The division is
aware that Great Bear is in the process of bringing other
partners into its program on the North Slope.
1:25:03 PM
MS. FEIGE noted that Hilcorp Alaska LLC (slide 9), a large actor
in Cook Inlet, has moved onto the North Slope with the
acquisition of the North Star Unit where it promptly returned
two wells to production. Hilcorp acquired a portion of the
Milne Point Unit where it is now operator and in partnership
with BP has drilled three wells and undertaken some new facility
construction there. Hilcorp has plans to drill 10 new wells and
complete a slew of workovers in 2016.
MS. FEIGE said Repsol and Armstrong Oil & Gas (slide 9) are
working on the Nanushuk Project development, which the division
refers to as the Pikka Unit. Repsol and Armstrong formed the
Pikka Unit in June 2015 and to date, from 2012 to current, they
have drilled a total of 12 exploration wells and sidetracks on
that acreage, which led to the unit application. They have now
commenced the environmental impact study and the National
Environmental Policy Act of 1969 (NEPA) review for the overall
project development. The division expects that if there are no
hiccups, production will come online in five to seven years,
although they may try to fast-track that.
1:26:33 PM
MS. FEIGE turned to slide 10, "North Slope Wells Drilled &
Seismic Acquired," to provide a 10-year summary for the years
from 2004 to 2014. During this time period on the North Slope,
110 exploratory wells and well branches were drilled, along with
[1,646] development and service wells and well branches. She
noted that two dimensional (2D) and three dimensional (3D) data
is acquired through tax credit data under the rules of the tax
credit programs. During 2004 and 2014, about 870 line miles of
2D data was acquired and just shy of 10,000 square miles of 3D
data acquired. This is both onshore and near shore ground and
ice acquisition.
REPRESENTATIVE HAWKER recalled that in prior years the committee
would receive a colorful bar graph depicting, by year, the rig
count for exploration and development wells drilled. He further
recalled that there was one winter where no exploratory wells
were drilled. He asked whether Ms. Feige could obtain the rig
and well count data from the division's archives and prepare an
updated graph for the committee.
MS. FEIGE agreed to provide a by-year breakdown. She explained
that for purposes of summary and time for today's presentation,
the division rolled the numbers up into totals.
REPRESENTATIVE HAWKER recalled it may have been the Alaska Oil
and Gas Conservation Commission (AOGCC) that prepared the graphs
he is thinking of, but surmised Ms. Feige knows what graphs he
is requesting.
MS. FEIGE confirmed she knows which graphs are being requested.
1:28:54 PM
MS. FEIGE drew attention to slides 11-12, "Who's Working North
Slope?" to review which companies are investing and working in
the North Slope and what this shows about the evolution of the
basin or region. She described Alaska as having a very healthy
and robust cross-section of companies working on the North
Slope, and fundamentally that says the industry still views the
resource endowment and the environment of investing in Alaska as
being a good place to be. In terms of large companies, these
are predominantly the state's foundation producers, big legacy
producers, and for the purposes of breakout here the division
has classified these as companies with greater than a $40
billion market capitalization. These large companies include
BP, Chevron, Conoco, Eni, Exxon, and Shell. Behind the majors
are the large independents and mid-sized companies, such as
Armstrong and its subsidiary 70 & 148, Anadarko, Caelus, Repsol
[and BG Alaska, Halliburton, Hilcorp]. She advised that the
listing of Apache is an error and should be taken off this list
because it only operates in Cook Inlet.
REPRESENTATIVE HERRON inquired whether ExxonMobil Corporation
wouldn't now be called an "ultra-major" rather than a large-
major.
MS. FEIGE agreed that ExxonMobil Corporation and Shell with the
acquisition of BG Group could be called ultra-majors as they are
clearly greater than $40 billion market capitalization.
1:30:47 PM
MS. FEIGE continued her review of who is working on the North
Slope (slide 12). She explained that a cadre of small
independents have moved into Alaska as the exploration cycles
and production have begun to mature in the regions. She
explained that that many of the companies listed on slide 12
will partner together in developments. For example, Accumulate
Energy Alaska is a partnership of Burgundy Xploration and 88
Energy. She noted that Burgundy Xploration also holds leases
independently of the partnership. Brooks Range Development
Corporation is undertaking the Mustang Development and its
partners are Caracol Petroleum, Ramshorn Investments, and a
number of others. She explained that the nature of the smaller
companies is that they will be very fluid and their numbers will
grow when commodity prices are high and their numbers will
shrink a bit as commodity prices fall because they partner up
and sell their assets between themselves. For some companies it
becomes too high a cost environment, so they sell or partner
with others to manage those economic realities. Overall, the
state has a broad and healthy cross-section of players still
working on the North Slope.
1:32:14 PM
REPRESENTATIVE HAWKER referred to slide 12, and said that there
are issues in Cook Inlet where people come in, incented to be
there, but really were not able to perform, were not able to
provide the state the proper assurance for their financial and
environmental responsibility. He requested assurance as to what
the state is doing to be certain the folks on the North Slope
are economically capable and certainly have the ability to
provide the due diligence the state would want to have of
someone undertaking these sort of activities.
MS. FEIGE replied that the Division of Oil & Gas administers the
dismantlement, removal, and restoration (DR&R) program, which is
the end of economic life closure period for fields that are in
production. She said DR&R includes removal and remediation of
facilities, infrastructure, roads, pads, and so forth. Under
the leases, the lessees, and in this case the unit operators and
their partners, are required to work with the state at the end
of life in DR&R planning. The state works with them to
determine which assets the state deems valuable that it may want
to keep and carry forward, or which of the assets should be
removed and the area remediated. That final plan is put
together with a DR&R estimate that is maintained throughout the
life of the field. As leases are transferred and new parties
come in, or there is a shuffling of the interest, the parties
work with the division to establish a Financial Assurances
Agreement, a DR&R agreement that looks to the end of that
field's life. The parties either provide a bond or pay into a
Sinking Fund as production develops, so there is a pool of money
available to undertake that DR&R activity at the end of the
field life and the state does not find itself in a position
where a company may falter or fail and end up going under or
going away before the DR&R's work is finished. Thus, there is a
kitty or fund available for undertaking that work should that
circumstance occur.
1:34:59 PM
REPRESENTATIVE HAWKER asked about the current activities with
regard to the smaller entities where safety practices have been
compromised and the challenges that can come from an inability
to financially complete their work up front let alone the
backside of life. He further asked whether the division is
focused on the front end of field life.
MS. FEIGE confirmed that the division is doing this. She said
that in unit activities as well as lease hold activities, the
division has authority to request performance bonds to ensure
that not only is the activity undertaken but that the activity
is then remediated on the backside. The Alaska Oil and Gas
Conservation Commission (AOGCC) for anything downhole has a
bonding requirement as well that would cover the plugging and
abandonment of wells if the company can't perform, and the
division has and utilizes that same authority for the ongoing
early stage activities.
1:36:15 PM
MS. FEIGE turned to slide 13, "North Slope Leasing Activity
Trends, North Slope Foothills Areawide Lease Sale Results," to
show the generalized activity levels and interest in taking
leases since the beginning of the areawide leasing program. She
explained that the North Slope Foothills region is predominantly
a gas prone area just north of the Brooks Range. Its areawide
leasing began in 2001 with a flurry of activity with lease
taking in that area in the first couple years. She said these
would have been leases with the primary term of 10 years, but
over the life of leasing within the North Slope Foothills there
has not been much activity. She offered the division's belief
that this is due to the remoteness, no infrastructure, and very
high cost operating. She opined that until there is an AK LNG
or some sort of means to get that gas resource to a market the
state will see subdued activity.
1:37:25 PM
MS. FEIGE moved to slide 14, "North Slope Leasing Activity
Trends, Beaufort Sea Areawide Lease Sale Results," and advised
that this area is zero to three miles out. The Beaufort Sea
areawide leasing began in 2000 with a fairly robust and
consistent level of leasing. These were 10-year primary terms
on the leases. So, for example, if it was leased in 2000 and
wasn't developed and was allowed to come back into the lease
sale, it would not have been available again until 2011, and
that spike is seen on the graph. She opined that leasing for
the Beaufort Sea is somewhat hampered by the fact that beyond
three miles the federal government is not consistent in how
frequently it is willing to lease that acreage. Therefore,
there is a bit of an artificial boundary at three miles. So, a
discovery near that margin that extends past the three-mile mark
would be into federal territory, and without a lease to continue
it is too risky because the explorer doesn't own the resource.
Clearly, that has an impact on leasing in the Beaufort Sea.
MS. FEIGE discussed slide 15, "North Slope Leasing Activity
Trends, North Slope Areawide Lease Sale Results." She said that
this areawide leasing program commenced in 1998 with 10-year
primary terms on the leases. These track oil prices pretty
consistently knowing that companies are making those leasing
decisions and setting those finances aside, designating those
funds, at least one to two years in advance. She reiterated
that there is a robust ready sort of crew that is coming to
participate in the North Slope, and the graph indicates that the
interest and belief in the endowment of the resource remains.
1:39:21 PM
REPRESENTATIVE HAWKER referenced Ms. Feige's statement that the
trend lines were largely tracking oil prices, and asked whether
that is really what explains this very significant profound
growth from 2007-2011, the fall-off in 2012, but then that
incredible spike in 2014. He said that the 2014 spike seems
contrary to a claim of that kind of a proportionate increase in
oil prices.
MR. DECKER pointed out that beginning in 2010 the state had its
first shale play bidding wherein the state received
approximately 100 bids of that 117. That was a wakeup call to
the division and to the industry globally that Alaska may have a
shale play. Due to that flurry of activity in 2010, by 2011 the
division adopted a strategy whereby the division took its former
nine-square-mile tracts in the area deemed geologically
appropriate to the shale play, and cut its existing lease tracts
into four smaller tracts. He described it as a very deliberate
decision to protect the state's interest in order that large
areas would not be held without actually producing or being
penetrated by successful wells. In other words, he said, a well
would be needed on each lease to hold it forever and by making
smaller tracts they would have to drill more wells to hold the
same acreage, which is appropriate to the shale reservoir
behavior because one well does not drain nine square miles.
From that point on, the division has had the smaller tract
scheme in place and in 2011, 140 tracts were sold and part of
that is because to lease the same number of acreage they had to
bid four tracts and not just one. He said that in 2014, the 212
tracts offered were to parties like AD8 Energy, Accumulate
Energy, and Repsol bidding in some other areas. So partitioning
of lease tracts into smaller blocks means the selling of a
larger number of tracts.
1:42:37 PM
REPRESENTATIVE JOSEPHSON asked whether the aforementioned was
done administratively, and further asked for background on the
policy to create four units out of what had been one.
MR. DECKER clarified it was not four units, but rather four
lease tracts out of a single tract. The reason for that is that
with shale wells a horizontal well is drilled and fracked, but
one well can only drain a very limited area in the immediate
vicinity of that well. There is no way in shale play that one
well could adequately drain a nine-square-mile lease tract, so
the division carefully thought through the decision with the
commissioner's blessing that for the sales beginning in 2011
that would be part of the terms and conditions.
REPRESENTATIVE JOSEPHSON said it begs the question then that
that would have been true 50 years ago, so why the policy change
now. He asked whether someone was being dilatory.
MR. DECKER answered that the reason for the change is that now
the division was looking at shale plays as opposed to
conventional plays. Great Bear came in and then Royale Energy
and AD8 Energy came in and have forthrightly stated that they
are there to develop the shale plays, so that by itself requires
a different way of looking at the reservoirs and potential
reservoirs.
1:44:22 PM
REPRESENTATIVE HAWKER commended the division's foresight and
said the change was a "really wise decision" given the great
difference between shale development and the rest of the North
Slope. Since the restructuring was done in 2010-2011, he
continued, it cannot account for the incredible spike in 2014.
He asked what accounts for the spike in 201, and whether there
is a graph for 2015.
MS. FEIGE replied that once the division finishes issuing all of
those leases and has fully adjudicated numbers, it will update
the graph for 2015 for the committee. Speaking to the spike in
2014, she said it is a complex relationship and a complex
thought process that goes into making the investment decision to
take lease assets. Looking toward the future and planning for
that exploration work and more importantly the funding of that
exploration work. She asked the committee to bear in mind that
decisions would have been made a year or better in advance with
regard to taking a significant acreage position, and the
division believes that prior to that precipitous crash that
started in late 2014 with oil prices, the planning would have
been done and they would have pulled the trigger. Clearly, she
pointed out, there was a tax change within that time period, the
implementation of Senate Bill 21, the More Alaska Production Act
(MAPA), that became effective January 2014. She opined that the
conversation leading up to MAPA would have been factored into
decisions by companies as well, and she encouraged the committee
members to speak to the companies and lessees directly about
some of those decisions that are made.
1:46:40 PM
MR. DECKER moved to slide 16, "Cook Inlet Resource & Reserves
Overview," noting that the map comes out of the U.S. Geological
Survey's 2011 resource assessment for undiscovered, technically
recoverable oil and gas, which is not reserves and is not
necessarily commercial but just what is the undiscovered
resource out there that could be extracted with today's
technology. The USGS came back with a fairly robust estimate on
Cook Inlet in both oil and gas, he reported. The USGS believes
the basin has approximately 600 million barrels of oil to be
discovered and approximately 19 trillion cubic feet of gas to be
discovered. That is broken out by between about 14 trillion
cubic feet of conventional gas split between the Tertiary and
Mesozoic reservoirs, and about 5 trillion cubic feet of
unconventional gas split between Mesozoic sandstones and the
coalbed methane play that has never quite gotten off the ground
in Cook Inlet, but is still there with resource potential.
MR. DECKER then pointed to information released by the division
in late September 2015 regarding the current natural gas
reserves in the basin, which is gas in the legacy fields for
which there is a 50 percent or better likelihood of producing.
He explained that these are called "2P" or "proven and probable"
reserves and that estimate is 1.18 trillion cubic feet. So
that's not too different than the number that the division came
up with about five years ago, and is even a little bit higher.
While there's some plus or minus in the estimates, that says
that "we're holding relatively steady on our reserve space with
the investment that's going on in the basin; in fact, probably
increasing our reserve base slightly even though we've been
producing gas at the same time." So it's a good trend. The
division doesn't know how long exactly the reserve's growth can
continue to be the case, but it's certainly a good trend. Mr.
Decker drew attention to the southern portion of the map beyond
the limits of the areawide sale or the state lands where the
words "Cook Inlet" are written. He advised that that is outer
continental shelf and is assessed by the BOEM and BOEM gives
that area a mean undiscovered resource potential of about 1.2
trillion cubic feet, as well as some oil but mostly gas.
1:49:33 PM
MS. FEIGE drew attention to slide 17, "Cook Inlet Current
Activity & New Developments," and advised that Apache Alaska
Corporation came into Cook Inlet in 2011 with a very aggressive
acreage taking in the Cook Inlet lease sale. Apache continues
its extensive seismic acquisition program, both onshore and
offshore, and is in the process of permitting for a new well
which could be drilled in late 2016. ConocoPhillips recently
announced the sale of its interest in the Beluga River Unit to
the Municipality of Anchorage, Anchorage Municipal Light and
Power (ML&P), and Chugach Electric Association. Furie Operating
Alaska is the newest producer in Cook Inlet at the Kitchen
Lights Unit. In summer 2015, Furie set the offshore monopod
platform, completed all of its onshore facilities and pipelines,
and commenced first gas production from the Kitchen Light Unit
in December 2015. A second larger jack-up rig is scheduled to
reach Cook Inlet in mid-May [2016]. Furie needed that larger
piece of equipment for drilling of the development wells off the
monopod in that it is necessary for it to cantilever over the
top and anchor very securely. The smaller Spartan 151 rig would
be floating somewhat on the tide and anchored only by barges,
which would leave them with only 1 or 1.5 feet of clearance over
the monopod, which is a very dangerous situation. So Furie
decided to contract the second larger jack-up rig, and Furie
will utilize that rig over the next couple of years to drill out
the full field development and undertake some additional
exploration within the unit area.
MS. FEIGE pointed out that BlueCrest Energy has the Cosmopolitan
(Cosmo) Unit and will be bringing a large ground-based drill rig
for extended-reach wells into Cook Inlet in April 2015, and will
produce oil from the Cosmo Unit from onshore facilities rather
than offshore. BlueCrest would like to undertake gas
development and if BlueCrest does choose to undertake the
investment for development of the gas cap it could potentially
use the smaller Spartan 151 jack-up rig from offshore. However,
should BlueCrest choose not to proceed in the near term with the
gas development the Spartan 151 will leave Cook Inlet.
1:52:11 PM
REPRESENTATIVE SEATON asked where the jack-up rig originated
from and whether it had been active or inactive before coming to
Alaska.
MS. FEIGE replied that Furie Operating Alaska reported to the
division that the rig is coming out of Singapore and has been
actively drilling on deep water prospects there. It had not
been torn down and stacked out in storage as the Endeavor had
been. It is currently on a vessel coming from Singapore.
REPRESENTATIVE SEATON related that when the Endeavor came to
Alaska it had been out of the water for a month or so, but there
were encrusted mollusks and other things on the jack-up rig when
it arrived in Kachemak Bay. He asked whether the rig from
Singapore has been inspected for invasive species.
MS. FEIGE responded that she does not know the answer to the
question of inspection for invasive species but she does know
that AOGCC has a robust rig inspection and rig certification
program for new ground-based and offshore rigs coming into
Alaska, and AOGCC will be responsible for performing the initial
sign-off prior to operations. She said the division will
inquire about whether invasive species will now be part of that
inspection process, given the history with the Endeavor.
REPRESENTATIVE SEATON offered his appreciation because there is
nothing worse than getting held up by court filings, and
currently Alaska does not have a statutory requirement.
1:54:18 PM
REPRESENTATIVE HAWKER noted that slide 18, "Cook Inlet Current
Activity & New Developments," shows the significant amount of
work that Hilcorp is doing in Cook Inlet. He inquired about the
current and anticipated proportion of production coming out of
Cook Inlet today that is allocable to each of the participants,
and requested a guideline as to how much of that proportion is
oil and how much is gas.
MS. FEIGE responded that the division will drill down on that,
but said notionally from today's activity update: Apache Alaska
is not producing, Conoco is producing gas, Furie is gas only,
BlueCrest Energy will be oil but nothing on production
currently, and Hilcorp Alaska is clearly in production. At
present, Cook Inlet oil is nearly 18,000 barrels a day, which is
the highest level it has been at since 2005 with a steady
increase since 2009. She said that the increase in production
can be attributed to Hilcorp's activities.
1:55:55 PM
REPRESENTATIVE SEATON asked whether West Eagle plans to perform
seismic workovers with regard to Buccaneer's previous attempt
out there.
MS. FEIGE offered her belief that West Eagle was acquired by AIX
Energy, which is on the division's list of operating companies.
Although, the division has no active applications at the present
time so if AIX is planning work it has not brought it to the
division's attention at this point in time.
REPRESENTATIVE SEATON inquired whether AIX would have to come to
the division before it does seismic work.
MS. FEIGE answered yes, the company would be required to have
either a miscellaneous land use permit or, if it is on an oil &
gas lease, the requirement is a lease plan of operations
approval from the division.
1:57:03 PM
MS. FEIGE returned to slide 18, "Cook Inlet Current Activity &
New Developments," and said Hilcorp has been working diligently
throughout the basin bringing both gas and oil production on
line. Notably in late 2015, Hilcorp acquired the middle ground
shoal assets from XTO Energy, which is offshore in southern Cook
Inlet and included onshore facilities and one platform. Hilcorp
reports it has a projection of spending approximately $120
million in the Cook Inlet region in 2016.
MS. FEIGE moved to slide 19, "Cook Inlet Wells Drilled & Seismic
Acquired," to summarize the exploration and development wells in
the 2010-2014 period. She noted that 2010 would have been just
before the Cook Inlet Recovery Act came into play. During the
period of 2010-2014, 24 exploration wells and 65 development
service wells and well branches were drilled. She reiterated
that the seismic data acquired in Cook Inlet comes into the
division via the tax credit programs, and 2004-2014 takes in the
entire time period where the division would have been receiving
credit-related data. Approximately 725 line miles of 2D data
and roughly 660 square miles of 3D data was acquired for both
onshore and offshore.
1:58:46 PM
MS. FEIGE reviewed slide 20, "Who's Working Cook Inlet?" She
advised that ConocoPhillips is the one large major left in Cook
Inlet. Conoco has announced the sale of the Beluga River Unit,
and its North Cook Inlet Unit assets are still for sale. Mid-
sized independents that are still operating include Hilcorp and
Apache Alaska. Hilcorp has done a fine job of driving its
operating costs in the inlet down. Because Hilcorp owns such a
suite of properties it is able to aggregate its activities into
areas around the basin or into type of activity - so rather than
drilling one or two wells, which is the highest cost program, it
aggregates those and drills 10 wells, or does 15-20 workovers at
a time. This enables Hilcorp to obtain volume pricing from the
local service sector and if Hilcorp is not pleased with the
local pricing, it has been able to successfully bring additional
service companies into Cook Inlet thereby growing competition in
that service sector in the inlet. She said it has been a very
successful model for Hilcorp and the division fully anticipates
Hilcorp employing the same practices on the North Slope. Ms.
Feige noted that the small independents and LLCs in Cook Inlet
are partnered in developments around the inlet, and include AIX
Energy from West Eagle, NordAq Energy, Furie Operating Alaska
and BlueCrest. She pointed out that Furie's partners in the
inlet are Corsair Oil & Gas Company LLC and Cornucopia Oil & Gas
Company LLC.
2:00:45 PM
MS. FEIGE discussed the graph on slide 22, "Cook Inlet Leasing
Activity Trends," depicting the trends since the commencement of
areawide leasing in Cook Inlet between 1999 and 2015. Notably,
the big spike in the graph indicates when Apache came into Cook
Inlet in 2011. It can be seen that a robust presence and level
of activity continues across Cook Inlet. Interestingly, leases
in Cook Inlet have a primary term of seven years as opposed to
ten years because the exploration to development cycle within
Cook Inlet is shorter than on the North Slope because the inlet
is closer to infrastructure and there is less of a seasonal
control on access in the Cook Inlet than on the North Slope.
2:01:47 PM
REPRESENTATIVE HAWKER observed that the graph on slide 22 shows
a precipitous decline of activity between 2004 and 2009 and then
the jump in 2010-2011 with Apache coming in and then a fairly
robust activity continuing in the inlet. He asked whether DNR
has a sense of how efficacious the financial incentives awarded
under the Cook Inlet Recovery Act were in turning around the
2004-2009 decline and sustaining the level of investment
currently and whether DNR believes those incentives are still
needed and still working. Given that DNR does the forecasting
and the Department of Revenue (DOR) is no longer part of the
forecasting, he further asked how the passage of HB 247 would
affect DNR's forecasting for Cook Inlet.
MS. FEIGE responded:
I think first of all, we can see in Cook Inlet when
Cook Inlet actually stopped being over-supplied and
started actually behaving like a supply and demand
driven market. And you see that really start to take
hold in about 2002, and there was a ... fairly massive
... robust entrance of companies into Cook Inlet
because now you could actually sell your gas and there
was a market for the gas. Clearly, over time and in
Cook Inlet and it is a unique market, it is not
attached to the Lower 48.... Henry Hub today I think
is $1.87, or something like that, and we're about
$6.56 or something ... in Cook Inlet. So we're very
separate, but our market tends to become constrained
fairly rapidly because the majority of our demand
comes from those utilities. And we have, over time,
had large industrial anchors like Agrium and looking
forward we could again see Agrium ... and in a few
years we could hopefully see a Donlin Creek Mine also
needing to source gas out of the Inlet. So,
absolutely I think that those market dynamics have
played a role over time in Cook Inlet. And we were
clearly, as was part of the discussion in the Cook
Inlet Recovery Act, we were behind the power curve in
terms of investment and drilling to make sure that we
had enough ready supply of gas to meet our base
utility needs and that then precipitated the Cook
Inlet recovery. And we saw, I think, an upswing in
activity associated with that. I think we're seeing a
couple of things leading into the downturn in 2015.
Again a little bit of market constraint going on,
we're beginning to see our utilities out to ... some
five year contracts. Utilities really like, as you
all know, to have contracts out at 10 years as a
minimum and ... in the last few years the best they've
been able to do is 18 months, maybe 2 years, and then
very recently we've seen a few 5 year contracts
trickle out. So I think we're seeing the effects of a
bit of market constraint here....
2:05:39 PM
MR. DECKER also responded to Representative Hawker's questions.
Regarding the first question he said there is no doubt that the
credits were efficacious and helped stimulate some of the
drilling activity and reserve replacement activity. Also, the
price has been a leveraging factor. The Hilcorp takeover is
another pretty obvious point in that it is a single company that
can manage the basin as almost a portfolio. Another factor is
gas storage. Expansion of gas storage at the Cook Inlet Natural
Gas Storage Alaska (CINGSA) facility helps provide a little more
incentive for companies to drill a well - they may not be able
to sell the gas directly to the utilities year-round but they
can sell it into storage. Regarding the forecasting going
forward, Mr. Decker said his section of the Division of Oil &
Gas, the reservoir engineers, will be working with the
commercial section, as well as with some of the people in DOR's
Tax Division. He said DOR's contribution is still important in
that it has the rapport and history of going to the companies to
speak off the record about confidential issues for projects that
are under development or under evaluation. The goal is to
prepare a more probabilistic forecast that recognizes the
uncertainty at every level, whether the currently producing, the
underdevelopment, or the undervaluation.
2:07:39 PM
REPRESENTATIVE HAWKER offered his appreciation for DNR working
with probabilistic models. He asked when something like that
might be available to assist the committee in judging the true
impacts and consequences on production volumes of the tax
proposal that is currently before the committee.
MR. DECKER estimated that the change is intended to take place
in time for the fall revenue forecast.
REPRESENTATIVE HAWKER understood Mr. Decker to be saying that
DNR is the forecasting entity for the State of Alaska, with a
tiny amount of forecasting done by DOR, and that the legislature
will not have forecast information on the consequences of HB 247
until the fall revenue forecast.
MR. DECKER replied that this is his understanding, unless it is
contained in the spring DOR Source Book update.
MS. FEIGE added correct.
2:08:55 PM
REPRESENTATIVE OLSON, regarding Ms. Feige's mention of market
constraints, inquired whether she was referring to the
Regulatory Commission of Alaska (RCA) cutting back on the length
of the gas sales to Japan.
MS. FEIGE responded she thinks that certainly had an impact at
the time; it was clear that when the RCA lifted that restriction
more fluidity and flow in the development of the local utility
contracts was seen. After confirming that Representative Olson
was specifically referring to the export to Japan through the
Nikiski facility, she said she does not have an answer and will
have to look into that. However, she continued, once the RCA,
in general, lifted some of the constraints that were broadly
seen across Cook Inlet, there was more activity in that it was
one less barrier to development and sale of the product.
REPRESENTATIVE OLSON noted there was less demand as well.
MS. FEIGE agreed.
2:10:03 PM
REPRESENTATIVE SEATON noted he is trying to figure out the five-
year contract period. He surmised as follows:
Means that people bringing gas on right now unless
they have some other sales are sitting there with gas
not ready to sell if there's a five year filling of
the market, unless Donlin Creek or something else
comes on line. So, first of all, is that a correct
analysis of that with if the market is fully
subscribed and with a five-year contract, people that
bring gas on right now, unless it would go ... through
ConocoPhillips' Nikiski plant, there's really not a
sale for that gas.
MS. FEIGE answered that the five-year contract she referred to,
that DNR has seen, was for one of the Southcentral utilities and
it doesn't actually start until 2018, so it was forward looking
past the expiration of another contract. She said she thinks
Representative Seaton's assessment is correct in that DNR has
heard from Furie that it will need to scale the pace at which it
does its development based upon the company's ability to sell
its gas, which makes perfect financial sense that that is the
driver. In the event Furie can't sell the gas and recoup its
cost on drilling the wells and doing the development activity,
it does become a hindrance to that development work and the
timely fashion in which that development gets done.
2:11:38 PM
REPRESENTATIVE SEATON asked about the impact of credits versus
no credits and HB 247 on that modeling. He further asked
whether modeling by the Division of Oil & Gas incorporates those
elements and how that would influence actual wells drilled.
MR. DECKER replied that the question of how HB 247 will impact
the forecast has not come up in the division's technical
discussions with DOR about how the division intends to pursue
forecasting.
MS. FEIGE added that in the modeling the Division of Oil & Gas
undertakes, the assessment of the impacts of the tax credits and
the costing is outside the scope of what the division's
commercial section normally does. She explained that DNR does
not have access to the cost data that DOR has access to.
However, DNR notionally keeps a working inventory or sense of
how healthy production is at the various units around the state.
Therefore, DNR knows that in a low price stress environment like
today, some production might be taken off line or there might be
a shortening of the economic life of a field. She said the kind
of analysis the committee has asked for is what Director Alper
and his team at DOR have been working on and are planning to
present over the next couple of days. This type of analysis on
bill impacts would not be something DNR would normally take up
in the scope of its activities because DNR does not have access
to that costing information.
REPRESENTATIVE SEATON said he wants to be sure the committee
does not have expectations that the report it will receive is
"on something other than their modeling."
2:14:03 PM
REPRESENTATIVE HAWKER pointed out that Ms. Feige and Mr. Decker
are the experts tasked with doing the production projections.
He asked whether there is concern that these projections are
being done in a vacuum by not having access to the information
"that would seem really relevant to these production levels."
For example, DNR's charts depict very distinct changes in
leasing and resultant production as a result of policy calls
made in major tax increases and decreases in the state over
recent years. He asked whether Ms. Feige and Mr. Decker have
comfort in their ability to prepare accurate modeling without
better information as to the consequences of these policy
decisions.
MS. FEIGE stated that Representative Hawker makes an absolutely
valid point in that access to good information is needed and to
work with DOR in making those projections. She said the
division tries to drive its information and its look at how
industry is doing by talking directly with industry. She noted
that industry is forthcoming on its perceived impacts to what
industry has planned. She said, "We are in a bit of a box
because of the information and ... I think that's where I'd have
to leave it."
2:16:04 PM
REPRESENTATIVE HAWKER asked whether DNR has any position or
counsel for committee members on HB 247.
MS. FEIGE responded:
From DNR's standpoint and the division's standpoint, I
would just stress that balance is the key. We have to
keep a balance moving forward between exploration and
ongoing production. The exploration wells of today
and the exploration successes of today, and the next 5
years or so become the production 10, 15, 20 years
down the road. So, where we really want to focus in
and be very, you know, on the spot and somewhat
myopic, I think we have to be cautious not to take
that tact because we have to keep our eye on what's
going to be our production 5, 10, 15,... 20 years ...
down the road. I think that we can absolutely say
that incentive credit programs work. We saw it work
in Cook Inlet, but again it comes back to balance.
It's a balance of what can the state afford to sustain
going forward and I think that we have to keep talking
to our companies, hearing from them because that's
going to be the response to us all as we work through
this and try to make that decision of what can the
state afford to do going forward. Trying to keep our
eye on what is our production source going to be ...
10, 15, 20 years down the road.
REPRESENTATIVE HAWKER noted he heard Ms. Feige say to "keep your
eye on the ball."
MS. FEIGE replied absolutely.
2:18:01 PM
REPRESENTATIVE TARR addressed the statement about making sure
the state is holding lease sales so there is always that ongoing
activity. Regarding maintaining a balance in the current low
price environment, she asked how the department plans to keep
things moving forward from the lease sale side of things.
MS. FEIGE answered that the division undertakes a review of its
terms and conditions within about six months prior to each lease
sale, be it North Slope or Cook Inlet. The team looks at Cook
Inlet, for example, from the standpoint of the resource and
reserve and what the division understands about it. It looks at
the commercial side of things and what's the price projection,
how supplied is the Cook Inlet basin, and all of those complex
factors that can come to bear on the behavior of companies and
their participation in the lease sales. The division then sets
the terms and conditions for each lease sale and the
commissioner has the authority to raise or lower minimum entry
bids to reflect what the division believes may be stress points
on the industry. For example, she said, there shouldn't be a
minimum entry bid that is too high in a price stressed market
when companies do not have a lot of surplus cash sitting around.
It is in the state's interest for companies to take that acreage
and be able to hang onto it and perform their exploration
planning through the period of downturn and then be positioned
to really ride the wave as prices begin to come back up again.
Those are all factors the division considers and works through
in making its recommendation to the commissioner to engender and
establish a robust level of leasing activity across the state.
She pointed out that it is important that conversations like
this certainly come into play in those assessments of those
terms and conditions.
2:20:32 PM
REPRESENTATIVE HERRON inquired whether Ms. Feige believes her
division was able to get its opinion across to the
administration about how HB 247 will impact the industry. He
further inquired whether Ms. Feige could share any of the
concerns that industry has expressed to DNR about the bill.
MS. FEIGE replied that she and Director Alper spoke several
times during the development of the legislation; he would call
and ask questions about existing credits on the books, how long
they've been used, and did DNR perceive that there would be an
impact to industry if certain older credits were repealed. The
Department of Revenue would ask DNR's opinion as to how industry
may react if a credit program went away. She advised that she
and her division were not intimately involved in the development
of the bill that is before the committee, but DNR did add input
as it was asked of it from DOR and Director Alper's team. With
respect to the second question, she said the division has heard
from industry that taxes generally are lumped into the bucket of
cost for the overall project development or working in a
specific area. In the event costs go up companies need to be
able to compensate, and at a time when prices are very low that
sets off some alarm bells and the division has certainly heard
that from industry. The concern is over making big changes to
tax policy at a time that prices are very low, and at a time
when prices are not expected to come back into the $100 realm
anytime soon. Ms. Feige said the division has also heard from
companies that are halfway way through a development drilling
program in which they have factored the tax credit programs into
their expenditure equation, and if the credits go away their
world changes at that point. She said it's coming back to the
constant theme of stability, what can the companies expect?
They need to be able to plan more than six months out, they need
to plan one or two years out in order to line up their funding
and ensure that they can undertake those activities without
interruption.
REPRESENTATIVE HERRON commented that there has been discussion
about if there is a change "where do we stop it but not impact
the ones that are in play?" That is an important part of
factoring in amendments to the proposed legislation.
2:24:30 PM
REPRESENTATIVE SEATON remarked that there are two different
conversations, one on gas and especially Cook Inlet gas, and the
rest on oil. He noted there is gas at about $1.87 Henry Hub,
and worldwide LNG long-term contracts less than $5.00 spot. He
asked whether there is any place in the United States or
worldwide that has a better profit margin for producing gas than
Cook Inlet, which is selling at $6.85, with winter prices higher
than that.
MS. FEIGE responded that the answer clearly is no. The Cook
Inlet is at $6.50, the Lower 48 is $1.87, and currently Japan is
less than one-half of what it was two or three years ago in
terms of LNG import. Cook Inlet is a good place to be for being
in the gas business. "Our problem is that we lack those
industrial anchors," she said. Those large consumers, just like
in the power sector, shoulder the development of a big power
plant. An industrial anchor allows power generation at a steady
rate and then others can come into the power stream once the
plant is up and going. That same model applies to gas in Cook
Inlet. Cook Inlet has great resource and has a lot of companies
doing a lot of good work, but at the present time it runs out of
offtakes.
REPRESENTATIVE SEATON surmised that "the market is the
determiner of what is happening in Cook Inlet, but that ...
people drill, and if they have a market for it, is probably
about the best in the world."
MS. FEIGE agreed.
2:26:58 PM
REPRESENTATIVE TARR surmised that if the Agrium [fertilizer
facility] came back on line it would be large enough to be
considered an anchor.
MS. FEIGE replied yes. She noted that Agrium has two trains at
its facility and each train takes 24-25 billion cubic feet per
year, so if the full facility came on that would be 50 billion
cubic feet [per year]. Right now, the utility, field gas, and
refinery-based demand in Southcentral is 80 billion cubic feet a
year. Donlin Creek Mine would add another 12 billion cubic feet
a year. So, those large anchor potentials are out there.
2:27:43 PM
REPRESENTATIVE HAWKER referred to Ms. Feige's response to
Representative Seaton that the gross sales price for the
extracted resource in Cook Inlet is higher than Henry Hub
prices. He asked whether Ms. Feige would come to the same
conclusion when looking at the net income of a company
performing in Cook Inlet and when the cost structures are
considered. If a company develops gas in Cook Inlet and wants
to sell it to Japan, there is a large ocean in between. He
asked whether Ms. Feige was addressing the net profitability of
a company coming into Cook Inlet and operating, or was it more
in the context of a high gross price and at the end of the day
the company's gross doesn't matter, the net matters.
MS. FEIGE confirmed Representative Hawker is correct and said
costs have to be a consideration in any business decisions, and
both Cook Inlet and the North Slope are higher cost operating
environments in that labor costs more, services cost more, and
transportation costs from an export standpoint will certainly
come into play. If companies look for an area where they can
make a good return on the gas, their internal rates of return
will drive that. She said she still thinks that with a robust
market, Cook Inlet and Alaska are good places to be. She
stressed that Representative Hawker's point is very well taken
in that the net and the end-of-the-day margin matter and that is
driven by cost.
REPRESENTATIVE HAWKER identified himself as the sponsor of the
Cook Inlet Recovery Act and said it truly was the intent to make
the basin competitive, attractive, and attract the level of
production that has been seen.
The committee took an at-ease from 2:30 p.m. to 2:33 p.m.
2:33:10 PM
KEN ALPER, Director, Tax Division, Department of Revenue (DOR),
on behalf of the governor, continued his PowerPoint presentation
entitled, "Oil and Gas Tax Credit Reform- HB247, Additional
Modeling and Scenario Analysis - Part 1a." Before beginning his
presentation, he advised that Commissioner Randall Hoffbeck is
in transit from New York, and DOR's senior economists are
currently putting the finishing touches on a presentation that
will be given to the committee tomorrow morning. He spoke to
the evolution of DOR's forecasting process as follows:
The Department of Revenue is charged with forecasting
oil production primarily for the purpose of
forecasting revenue. That's our job, is to produce
the Revenue Sources Book and determine how much
revenue the State of Alaska can expect. Most of the
source data for that is tied to our own outreach from
industry. We don't make this up, we talk to people
from industry, multiple companies every year. They
tell us their drilling plans, their expectations, and
then we build that into a drilling forecast and then
we have, for many years, used the services of an
outside consulting engineer, a petroleum engineer who
would help us convert that data into decline curves
and expected volumes. And then to that, in more
recent years, we would layer on some risk factors and
delay principles, expectations for the new oil, the
under development and under evaluation. What we faced
in the last year or so, frankly, is because of budget
short falls, we re-looked at how we paid for these
services. That we thought rather than going to
outside consulting services that cost the state
substantial amounts of money, that much of that
expertise and professional knowledge in petroleum
engineering existed within the state's own system in
the Department of Natural Resources. So, we looked to
them to help us through it beginning this year. We
are the client and they are, in many ways, our
consultant. And they are going to be taking the same
data set, the information on what wells are going to
be drilled and helping us to turn it into the forecast
that we brought before this committee ... in the fall
Revenue Sources Book. If there are changes in
behavior, whether tied to market forces or any changes
in legislation, those will be reflected in the fall
forecast; we begin that outreach generally in the
months of August and September.
2:36:14 PM
REPRESENTATIVE HAWKER understood that Commissioner Hoffbeck was
back East discussing state fiscal prospects with the state's
rating agencies and securities analysts. He inquired as to what
the rating agency's responses were to the Alaska State
Legislature considering HB 247 and imposing a major tax increase
on its only sustaining industry at a time when that industry is
facing severe economic losses.
MR. ALPER replied he has not spoken to Commissioner Hoffbeck on
his experiences in New York, although he returns tonight and he
will speak with him tomorrow. He said that the rating agency is
concerned about the state's budget shortfall, and Alaska's
ability to prove that it can continue to balance its budget. He
said the Department of Revenue presents to them as it presents
to the legislature this bill as part of a package of reducing
that budget deficit.
2:37:16 PM
MR. ALPER drew attention to slide 2, "What We'll Be Discussing,"
to explain that the slide is from the Table of Contents of the
presentation he began on 2/22/16. He reminded members that he
had ended that presentation about half-way through the fourth
bullet which deals with the details of how the pieces work:
some of the historic cost information, overview of the oil and
gas economy, DOR's thoughts as to what has worked and what
hasn't, what is scheduled for sunset, what is expected to
continue, what is being repealed in this bill, and summarizing
the suite of credits in Alaska's portfolio. He noted that
appended at the end of this presentation are DNR's slides
addressing issues of gas supply in Cook Inlet, and that the
bullet shown in grey on slide 2 will be presented to the
committee tomorrow.
MR. ALPER noted that the last subject he discussed was what is
involved in strengthening the minimum tax by preventing certain
credits from being able to be used to reduce payments below the
so-called floor, the 4 percent minimum tax. He said he
previously reviewed the Gross Value Reduction (GVR) eligible
fields and the issues there and how DOR proposes to make the so-
called new oil pay at the 4 percent minimum, as well as the
issue of major producers who may have a Net Operating Loss (NOL)
Credit due to losing money in one calendar year from being able
to use that Net Operating Loss Credit in the next calendar to
offset their minimum productions taxes and pay something like
zero. He noted that slides 35-36, "Section 17(b): Strengthen
the Minimum Tax, How net operating loss (NOL) credits are earned
and used," are very complex but are more or less monthly cash
flow slides to show that with a second year of low taxes what
could happen by offsetting the minimum tax with the Net
Operating Loss Credit, and then yet more Net Operating Loss
Credits stack up into the future.
2:39:31 PM
MR. ALPER turned to slide 38, "Section 17(c): Strengthen the
Minimum Tax, Preventing per-taxable barrel credits from being
used in another month other than the month earned." He said
current law allows those monthly earned taxes to be used
anywhere in the year. This is only relevant with a lot of
volatility specifically with certain months of the year impacted
by the minimum tax and certain months of the year not impacted
by the minimum tax. In the months with the minimum tax,
typically the entire $8 cannot be used, the companies will start
to use that $8 per barrel credit, bump up against the minimum
tax, and then lose the rest of it. In the event there are other
months of the year, those lost credits have been able to be
applied to reduce earlier months' taxes down toward the minimum
tax level. He advised that he will provide graphs later in this
presentation that will show more clearly what he is discussing.
He said Alaska's Clear and Equitable Share (ACES) bill was a
true monthly tax, the progressivity, the entirety of the tax
rate, was monthly. That regime was eliminated three years ago
and the bill before the committee is more of a true annual tax
where one small component of the tax would be locked into the
month in which it was earned so as to prevent some upside risk
to the state. [The administration's] contention is that when
there are several months of high oil prices, the state should be
able to earn all of the taxes earned in those high months and
not have those high month revenues eroded by a possible credit
earned in low months later on in the year.
2:41:22 PM
MR. ALPER addressed slide 39, "Section 17(c): Strengthen the
Minimum Tax, Credits 'lost' to the minimum tax before annual
true-up," and explained that the graph is a model of the actual
conditions of what happened in calendar year 2014. He said:
The top of the yellow bar is the entirety of the
production tax based on 35 percent of production tax
value, the statutory calculation of what the tax would
be given the information provided by our producing
taxpayers. The top of the green line, or after
subtracting the yellow, is the actual tax paid after
application of the Per-Taxable Barrel Credit. So, you
could see ... in the early months of the year when
prices were higher, the grey line across the top ...
looks like it just might be a stray line. That's
actually a line tied to the axis on the right-hand
side, which is the price of oil. And you could see a
price of oil that was over $100, dipped under $100 for
the last time in the month of August and was down
around $50 by December. So in those earlier months of
the year the Per-Taxable Barrel Credit was either $5
or $6 per month. That number ... increases as the
price decreases to hit a peak of $8 at below a price
of oil of between $80 or $90. So that's why the
yellow bar got thicker in September and October, and
then into November and December what happened is there
is no more green bar. What the red bar is, is 4
percent of gross tax. The 4 percent of the gross is
what must be paid based upon the minimum tax
calculation and the dotted lines in the November and
December, those show those Per-Taxable Barrel Credits
that were effectively lost to the producers; they were
not able to use them because there wasn't enough delta
between the top of the yellow bar and the top of the
red bar.
2:43:14 PM
MR. ALPER moved to the graph on slide 40, "Section 17(c):
Strengthen the Minimum Tax, 'Lost' credits recovered at annual
true-up." He continued:
You could see what happened here ... you could see the
same dotted lines in November and December. What the
companies were able to do is migrate those credits to
effectively offset the great bulk of January's
production tax above the level of the floor. And what
that meant was at the time of our annual true-up in
April of 2015, we refunded companies $112 million.
That was the amount of lost credits that we were able
to migrate in to ... prior months' tax liability. So
that's the phenomenon that actually did occur. We've
created a second scenario that would show a more
extreme example of what I've just presented. In a
year of greater price volatility the credit recovery,
or the ability to migrate credits, could take up an
even greater share and could push a large portion of
the state's production tax even in high cost high
price months down to the minimum tax level. And this
occurs because ... the minimum tax calculation is an
annual tax so the credits that cannot be used within
the year ... could be recovered at the year's end.
2:44:27 PM
MR. ALPER explained that the graph on slide 43, "Section 17(c):
Strengthen the Minimum Tax, 'Lost' credits recovered at annual
true-up," is a more hypothetical and dramatic drop that occurs
earlier in the year. He said:
So here we have a scenario where in January of year X,
the price of price of oil is $90, by December it's
down to $50. And you'll recognize the structure of
this chart, the yellow bar is the production tax based
on the statutory 35 percent calculation. The green
bar is that tax after the application of the sliding
scale credit, which for most of these months would be
$8 per barrel. And then beginning in June and getting
larger in the later months, you see a growing dotted
line which is Per-Taxable Barrel Credits that are
lost, that are foregone because of the inability to
use them because of the minimum tax; the companies are
forced to pay at the red minimum tax level during
those months. [Returning to slide 42], you could see
the relative thickness of the green bars in January
and February in slide 42. [On slide 43], those bars
are completely wiped out by the migration of all of
those unused credits from June through December and
offset against February. And the total in this
calculation, which was something of a snapshot created
by our staff, leads to $233 million in lost credits,
or about a third of the total production tax revenue
for this theoretical year is lost at true-up. So,
what the bill before you is doing ... and the language
in it is somewhat complicated, but what it does is it
locks in the Per-Taxable Barrel Credit to the month in
which it was earned and doesn't allow it to migrate
from month-to-month within the calendar year.
2:46:05 PM
REPRESENTATIVE JOSEPHSON asked whether there was any discussion
in either body or in any committee about this phenomenon. He
noted that it is the law and arguably it doesn't matter if there
was a discussion, but he would like to know whether this came up
in any presentation that Mr. Alper is aware of.
MR. ALPER replied that he specifically reviewed the committee
record on this issue for the House Resources Standing Committee
at the time. The gentleman who did the bulk of carrying the
bill on behalf of the previous administration was DOR Deputy
Commissioner [Michael] Pawlowski. Mr. Alper related that when
asked a similar line of questioning by Representative Seaton,
Mr. Pawlowski's understanding was that this was a monthly
credit, a monthly calculation, and that it was intended to be
taken within the month it was earned. Mr. Alper continued:
To be fair, the committee record, nor the thinking at
the time, did not contemplate the minimum tax. Did
not contemplate that there would be years in which we
would be at the floor. That this phenomena which is
before you would be relevant. And I don't believe it
was addressed. In the context of a normal year in
which there is no minimum tax, Mr. Pawlowski was
absolutely correct - this is a monthly calculation.
The credit rate itself does change from month-to-month
as the price of oil might change from month-to-month,
but the ability to recapture it at true-up did not
become relevant until roughly 18 months ago ... when
the price of oil dropped to a level where for the
first time in our history of having a net profits tax,
we fell into the realm of minimum tax, of paying at
the floor.
2:47:48 PM
MR. ALPER turned to slide 44, "Section 17(c): Strengthen the
Minimum Tax," to summarize his previous comments. He said that
this particular issue of strengthening the minimum tax is only
an issue in years of relatively high oil price volatility where
some, but not all, of the months trigger the minimum tax. He
pointed out that the examples on the previous two slides showing
moderate to high oil volatility reduce the state's tax payments
by close to 30 percent, and an effective tax rate on net profits
would reduce that from about 14.5 percent to 10.5 percent as an
effective tax rate. This phenomenon causes the state to forego
some fraction of the upside in years where the monthly oil
prices might be very high, and otherwise would generate high
revenues; the state loses some of that revenue due to the offset
from the months in which prices are low. "Another phenomenon,"
he continued, "in the future as tariff rates begin to increase,
you'll start seeing wellhead values decreasing and that might
mean, for example, the Per-Taxable Barrel Credit itself will
start to trend toward the larger numbers, the $7-$8 range rather
than the $5 and $6 range that was envisioned in some of the
committee discussions during the last major fiscal change."
2:49:11 PM
REPRESENTATIVE JOSEPHSON, regarding when Mr. Alper talks about
an increase in tariff rates, asked whether that anticipation is
due to moving to more unconventional oil or some other reason.
MR. ALPER responded that the most prominent factor in increasing
tariff rates are declining production, when the cost of
operating the transportation system is relatively fixed and as
fewer barrels go through, each one has to pay a higher share of
the freight.
2:49:36 PM
REPRESENTATIVE TARR understood that everything in Section 17 is
retroactive to January 1. She surmised this is because at true-
up at the end of calendar year 2016, DOR wants to avoid this
problem for 2016. She inquired as to how difficult it would be
for the companies at true-up if, for example, it was started on
the fiscal year.
MR. ALPER answered that the intent of the retroactivity is to
have this phenomenon be eliminated for the current calendar
year. If the bill doesn't pass until the end of the legislative
session there would have to be some sort of make-up payment or a
way to account for that come the first monthly payment after the
passage of the bill. He offered the following:
The concept of a split year for many of these
provisions that affect the calendar year tax are very
problematic; they have caused complex situations
inside the audit staff in the past. The ACES bill,
for example, took effect on July 1, 2007 ... but it's
a calendar year tax, it lead to a situation where in
many ways they had to split 2007 into two separate tax
returns and do a full analysis of the first six months
separate and distinct from a full analysis of the
second six months. So, to the extent features that
impact the underlying tax calculation for the tax-
paying producers, changes in the middle of the year,
it will lead to some inevitable complexities in the
administering of that tax.
2:51:58 PM
REPRESENTATIVE TARR asked which of the two fiscal notes shows
this element.
MR. ALPER replied:
The one fiscal note that shows the fund capitalization
element also shows the negative numbers in spending,
and all of the provisions of the bill that reduce
credit payments or eliminate certain credits are
encompassed in that negative number. All of the
minimum tax changing provisions are in the other
fiscal note that shows the positive revenue numbers.
So, what you see in the early couple of years is $100
million revenue estimate declining to a $50 million
revenue estimate in the out years. The $50 million,
in every year, is the rough estimate for the annual
additional revenue from an increase in the minimum tax
from 4 percent to 5 percent. Now, previous slides and
this slide deck before you that we went through
Monday, show that there is some variability in that
and depending on the price of oil that could be a
number between roughly $30 and $70 million. And with
the next generation of this fiscal note, we will
incorporate some of that more nuanced modeling to that
element of the calculation. The second $50 million
that's in the early years is the impact specifically
of not being able to use Operating Loss Credits to
offset minimum tax payments from the major producers.
But based on our forecast, this is a phenomenon that's
only in place for the current and next year so it's
about a two-year problem, then it will go away of its
own accord if our forecasted prices hold because at
that point we don't expect any of our producers to be
losing money; therefore won't be earning an operating
loss credit. This specific provision in 17(c) that
I've been discussing thus far today, is not forecasted
at any value simply because our price forecasts do not
consider volatility. That we have a fixed number for
the year and this is a phenomena that's only relevant
in a year where there's a lot of up and down and we're
looking at annual average numbers and therefore can't
project the value of up and down.
2:54:03 PM
REPRESENTATIVE HAWKER stated that for the last two meetings Mr.
Alper has dialogued using one circumstance - the year 2014 - to
discuss and illustrate the inner play of truly major components
of the overall tax construct. This tax construct has evolved
since the end of the Economic Limit Factor (ELF). He asked
whether Mr. Alper has any support or evidence from his research
of past legislative sessions that would show the legislature
intended the state's major tax constructs to be anything other
than an annualized tax cycle to annualize activity that can be
volatile on both the taxpayer and the state as the tax
administrator. Representative Hawker said Mr. Alper is clearly
looking to have this parsed into a more granular tax cycle of
literally an isolated monthly cycle.
MR. ALPER responded that the specific provision addressed in
Section 17(c) of HB 247 relates to the application of the Per-
Taxable Barrel Credit. That is a new credit that did not take
effect until January 2014 with the passage of Senate Bill 21.
Senate Bill 21 describes that credit as a monthly credit and a
monthly calculation that very explicitly varies from month-to-
month depending upon the average price of oil in that calendar
month. If it's below $90 gross value it is $8, between $90 and
$100 it is $7, and so on. So, the value of the credit was quite
explicitly monthly. As for the ability to use it from month-to-
month it was neither addressed nor not addressed. To the extent
it was discussed, Deputy Commissioner [Pawlowski] described it
as a monthly calculation. He continued:
That one specific provision of the new law was said to
be a monthly calculation. All other provisions of the
calculation are absolutely an annual calculation. And
by the elimination of progressivity, which was the
most extreme monthly calculation in the prior tax
regime, in many, many ways Alaska's oil and gas system
was converted from a monthly to an annual based
system. But, the remnant of a monthly system that was
retained with the passage of Senate Bill 21 was this
specific calculation of the Per-Taxable Barrel Credit.
REPRESENTATIVE HAWKER respectfully disagreed with Mr. Alper's
characterization that the changes made moved the state from a
monthly to an annual calculation as the progressivity was
eliminated, and added that he and Mr. Alper are never going to
agree on this.
2:57:11 PM
REPRESENTATIVE SEATON asked whether this hypothetical scenario
on slide 43 only goes back and calculates what the tax would
have been by applying it to past months, or also moves the other
way and has a carry forward that would diminish forward months
as well.
MR. ALPER replied yes, this model was built with a declining oil
price much as the earlier set of 2014 actuals was a declining
price, but the phenomenon works the same exact way in reverse.
For example, if there are unused credits in January, but there
is adequate credit value in November and December because the
price of oil recovered, they could just as well be carried
forward. The one essential limitation is that this is a
calendar year tax and any such adjustment or migration must
occur within a calendar year.
2:58:24 PM
REPRESENTATIVE SEATON asked whether, in this situation and
making it retroactive to January 1, there would be any green
bars to take advantage of, or to apply it to, at this point in
time. He further asked whether the state would have to go back
and capture any payments because going forward there wouldn't be
any to apply.
MR. ALPER responded that to the best of the division's
knowledge, and it won't know for sure until the annual tax true-
ups are seen at the end of March, every single month of calendar
year 2015 was a minimum tax month. Therefore, whatever Per-
Taxable Barrel Credits were foregone, are foregone and not
recoverable. In calendar year 2016 and being only two months
in, everyone is hoping for a substantial price recovery, in
which case this will come into play at the end of the year in
April 2017 when those taxes are trued-up.
2:59:29 PM
REPRESENTATIVE SEATON questioned whether there would be any
going back and having a tax calculation that was paid previously
in January or February or March. He surmised that because they
were all at minimum tax an adjustment would not be made.
MR. ALPER answered correct. Pointing to the graph [on slide
43], he said that October and November look like what every
month in 2015 looked like. There is a minimum tax payment,
there's a certain amount of Per-Taxable Barrel Credit that was
used, it varied, it got smaller and smaller as the prices went
down later in the year, and then there was a certain amount of
those Per-Taxable Barrel Credits that was foregone. So, there
would literally be no green bar against which to apply anything
in all of calendar year 2015.
3:00:22 PM
REPRESENTATIVE HERRON asked why Mr. Alper continues to use the
word "phenomenon," and whether it is being used because Mr.
Alper questions the fact or the situation.
MR. ALPER apologized if the word seems inappropriate. He said
it was an unexpected occurrence based upon the division's
intuitive understanding of how the tax was supposed to work and
then in practice it was different. He offered that he doesn't
know what the appropriate word is to describe that, and it is by
no means magical. Everything the division has seen is a literal
interpretation of the statutes as they are written.
REPRESENTATIVE HERRON said he is trying to understand because
normally it means that it's a fact or a situation that is
happening or occurring, "but you're also at the same time,
you're questioning it, and I just want to make sure I understand
why you use the word so much."
[HB 247 was held over.]
| Document Name | Date/Time | Subjects |
|---|---|---|
| HSE RES 2.23.16 Alaska's Oil and Gas Competitiveness Report 2015.pdf |
HRES 2/24/2016 1:00:00 PM |
|
| HSE RES 2.23.16 DOR Tax Division - Fiscal Impact of Cook Inlet Production Tax Limitations 2007 to 2013 - 3 27 15.pdf |
HRES 2/24/2016 1:00:00 PM |
|
| HSE RES 2.24.16 - DNR Oil and Gas Industry in Alaska.pdf |
HRES 2/24/2016 1:00:00 PM |