Legislature(2015 - 2016)BARNES 124
02/27/2016 10:00 AM 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
10:00:57 AM
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."
10:01:33 AM
JANAK MAYER, Chairman & Chief Technologist, enalytica,
Consultant to the Legislative Budget and Audit Committee,
continued his analysis (begun on 2/26/16) of the projected
impacts that HB 247 would have on the oil and gas industry in
Alaska. He resumed his PowerPoint presentation entitled,
"IMPACT OF HB 247: COOK INLET ASSESSMENT," by turning to slide
6, "COOK INLET OIL AND GAS PRODUCTION: BASIC FACTS." Reviewing
the history of Cook Inlet oil and gas production and the
evolution of the basin over time, he reminded members that oil
peaked in 1970 and then steadily declined to a trough of 7.5
thousand barrels a day (mb/d) in 2009. Since that time oil has
had a substantial uptick and is now at 18 mb/d, more than double
what the inlet produced less than a decade ago. Gas production,
however, has not seen that resurgence in production in
particular because gas is limited by local demand conditions.
But, there has been a flattening of the gas decline and a
plateau. An initial decline in gross production occurred in the
1990s, but then plateaued into the 2000s. The plateau was due
to production of gas that had previously been reinjected at
Swanson River Oil Field. A decline then began after 2005, and
in the last half decade there has been stable production as a
result of new drilling in mature fields.
10:04:07 AM
MR. MAYER moved to slide 7, "OIL UP FROM WORKOVERS, NEW WELLS IN
EXISTING FIELDS," to discuss the cause of the oil turnaround
post-2010. Drawing attention to the chart on the left, "COOK
INLET: GROSS OIL PRODUCTION BY WELL VINTAGE," he explained the
chart depicts which decade a well come on line as well as the
total production of all the wells. He noted that production
from wells drilled between 1991 and 2000 (green line) came down
to a trough of about 2 mb/d in 2009, then production began a
substantial uptick. That uptick was not new wells, but rather
increased production from mature wells that had had substantial
capital spent on workovers, the result being more production now
than a decade ago. This same increase from workovers also
happened with wells drilled pre-1970 (red line). Substantial
new drilling began in 2011 (purple line), he pointed out. So,
new oil production is coming from a mixture of workover work and
the new drilling that began in 2011.
MR. MAYER then brought attention to the chart on the right side
of slide 7, "COOK INLET: GROSS OIL PRODUCTION BY FIELD." He
pointed out that each of the major oil fields has a substantial
uptick in the latter years, the biggest uptick being in the
McArthur River Oil Field. However, he noted, almost all of the
fields come from a fairly low base and have substantial
increases in the last half decade.
10:06:52 AM
MR. MAYER displayed slide 8, "GAS FLATTENING FROM NEW WELLS IN
EXISTING FIELDS," and stated that gas production is a slightly
different picture than oil. Drawing attention to the left-hand
chart, "COOK INLET: GROSS GAS PRODUCTION BY WELL VINTAGE," he
explained that the increased production, or at least flattening
of decline, is more a question of new wells drilled rather than
well workovers. The previous vintages by and large continue a
constant decline curve relatively speaking; there is no
discontinuity of a moment in time where suddenly a lot of new
capital was being spent on old wells. Rather, a number of new
wells were drilled in the post-2011 period that have come on
line and boosted production and that has helped flatten out that
decline. Mr. Mayer turned to the chart on the right side of
slide 8, "COOK INLET: GROSS GAS PRODUCTION BY FIELD," and noted
that an increase can be seen in only a handful of fields. In
particular, some growth occurred in the Kenai and Beaver Creek
fields; a new field, Kenai Loop, came on line in 2012; and some
incremental production occurred in Swanson River. Not shown on
this chart is the initial production from the first well at the
Kitchen Lights Unit that began in December 2015.
10:08:20 AM
REPRESENTATIVE SEATON said the reason HB 247 is before the
legislature is tax credits and the value on the tax credits. He
inquired as to how much per barrel of oil and how much per
thousand cubic feet (Mcf) of gas the $400 million in Cook Inlet
credits translate into. He explained he would like to know what
the state's cost-to-benefit ratio is for this production.
MR. MAYER replied he does not have these figures due to the
limits on publicly available data. The Department of Revenue
(DOR) is restricted on what it can release in terms of naming
specific taxpayers and what specific activities the credits go
to. Teasing out is a big part of the problem - a substantial
amount is spent on credits in Cook Inlet and undoubtedly a lot
of that is spent on oil production and exploration. A large
part of the concern when it comes to credits is insuring
adequacy of gas supply for Cook Inlet. However, it is very
difficult from the publicly available data to tease out what is
being spent on developing new gas resources versus what he
suspects is a lot of the spending, which is either on
incentivizing new oil production, exploration, or a range of
activities that do not necessarily translate into increased gas
security for Southcentral Alaska.
REPRESENTATIVE SEATON remarked that there should, at the least,
be the ability to get the gross amount paid by the state and the
gross amount of per barrel oil equivalent (BOE) or Mcf and, if
there is increased production, how much that increased
production cost the state in refundable tax credits.
10:11:06 AM
CO-CHAIR TALERICO surmised that the chart on slide 4, "BIG
DIFFERENCE BETWEEN NORTH SLOPE AND COOK INLET," depicts the
credits in their entirety for the North Slope and for Cook Inlet
and does not distinguish between gas and oil.
MR. MAYER responded correct, and said a lot of that undoubtedly
goes towards incentivizing new drilling for oil exploration or
other activities that are not necessarily directly related to
the question of gas supply for Southcentral Alaska. The focus
of his presentation is on the question of maintaining credits,
he explained, but in regard to policy concerns there is no
question that the current regime and carriage of spending is on
a lot of things that are not necessarily tied directly to gas
supply for Southcentral Alaska.
10:12:15 AM
MR. MAYER returned to his presentation and reviewed slide 9,
"COOK INLET GAS HAS GONE THROUGH MAJOR TRANSITION." He outlined
the major transition that has taken place in the Cook Inlet gas
market over the last several decades. He described the old Cook
Inlet gas market as one with a substantial degree of gas surplus
that could be exported via liquefied natural gas (LNG) or the
(now closed) nitrogen facilities owned by Agrium U.S., Inc.
("Agrium"). There was period of low wellhead prices where the
Regulatory Commission of Alaska (RCA) looked at contracts that
proposed pricing based on the Henry Hub. The RCA said the Henry
Hub was much too high and could not be done, which is very
different than today's world. The overall market view was that
gas was long and plentiful and it was an era where gas was
produced by large international players. The old market was
also one where Southcentral utilities looking to ensure
stability and security of supply could get very long-term stable
contracts that gave the utilities exactly what they needed. In
addition to long-term contracts the producers were willing to
offer the utilities a high degree of seasonal flexibility. That
seasonal flex largely came from supplies, the fields themselves
could flex up and down to quite a substantial degree in a way
that they no longer can. But, Mr. Mayer continued, the new Cook
Inlet gas market is the opposite of the old. There is now very
limited surplus. In off-peak periods there is still some degree
of export, but by and large gas is all absorbed into the local
market. Today has high wellhead prices, a general market view
that gas is short. It is now a gas market where the producers
are mostly smaller more focused players. Sales contracts
between producers and utilities are for much shorter terms.
10:14:45 AM
REPRESENTATIVE OLSON said another variable at that point in time
was the long-term gas contracts with the Japanese. During the
four to six weeks of cold snaps, he recalled, the British
thermal unit (Btu) content going to Japan could be shorted and
then made up for on the next load; this was basically done over
the phone. There was enough supply in Japan to be able to
absorb that readily and it worked out for years.
MR. MAYER answered that in terms of where supply flexibility
occurred in the past versus where it occurs now, there was
enormous supply flexibility solely on the upstream side.
Looking across the years between the summer and winter months
and what was exported by the Kenai LNG Plant [owned by
ConocoPhillips Alaska, Inc. and located in Nikiski], the
difference between those two was pretty muted until just the
last three years. In the last three years the Kenai facility
has suddenly become a big seasonal component of how the seasonal
nature of demand can be managed in a way that it was not
necessarily in the past.
10:15:59 AM
REPRESENTATIVE HERRON asked whether the old should be wished for
or whether the new is just as good.
MR. MAYER replied the old would always be very nice to have
back, but unfortunately it is not always possible. Someone
responsible for planning, contracting, and purchasing gas at a
utility would be very nostalgic for the old. The new is not
impossible to live with, it is just harder to figure out what
needs to be done to get the security of supply that is needed.
REPRESENTATIVE SEATON requested that as Mr. Mayer continues his
presentation he point out if it makes a difference on what the
state's policy goal is. For example, if the policy is securing
long-term gas for in-state usage and whether that creates
definitely different policy options, or if policies are being
enacted to allow people to export more gas or to privately
market other than within the local supply.
MR. MAYER responded he is aware of those as critical questions
and will delve into those as much as he can in later slides.
10:17:47 AM
MR. MAYER returned to slide 9 and continued his review of the
transition from the old to the new Cook Inlet gas market.
Fundamentally, the mature fields have much less seasonal
flexibility than they used to have and that flex in what can be
delivered largely instead now comes from the storage side now
that there is the Cook Inlet Natural Gas Storage Alaska (CINGSA)
facility and then other demand factors including for instance
seasonal cargoes from Kenai LNG Plant.
MR. MAYER displayed slide 10, "MATURE BASIN HAS LIMITED SEASONAL
PRODUCTION FLEX," to elaborate on the much more limited seasonal
production flex seen today as compared to the past. Bringing
attention to the left-hand chart, "COOK INLET: GAS PRODUCTION,"
he specified it depicts gross production [red line], reinjected
gas [green line], and net production [orange line]. It is the
same chart as that on the right-hand side of slide 6, he noted,
but instead of looking at the production in a smoothed annual
data series it looks at a monthly data series so that the intra-
year volatility in production can be seen. [Between 1970 and
about 2006] there was a really wide degree of variation versus a
much tighter band of what can be produced at the wellhead in the
last decade or so. Turning to the right-hand chart, "COOK
INLET: SEASONAL SWING (MAX MONTH - MIN MONTH)," he explained
that the red line represents subtracting the minimum month of
the year from the maximum month of the year to see the annual
degree of swing of flexibility of what could be delivered from
the upstream fields themselves. Between the early 1990s and the
latter part of the last decade, a huge amount of ability was had
to deliver seasonal flexibility. The gap between the minimum
and the maximum could be as high as 200 or 250 million cubic
feet per day (Mmcf/d), so a lot of seasonal variability in the
structure of demand could be accommodated. Directing attention
to the end of the most recent years depicted on the chart, he
stated that the large peak seen is probably an artificial one
that has more to do with an outage than a long-term pattern. In
terms of a long-term pattern, the swing capacity at the upstream
end is now down to about 50 Mmcf/d as opposed to the almost 250
Mmcf/d that was had a decade ago.
10:20:13 AM
MR. MAYER moved to slide 11, "DEMAND HAS, MEANWHILE, BECOME MORE
SEASONAL," to review the reasons for why demand has become more
seasonal than ever before. He explained that the left-hand
chart, "ALASKA: GAS DEMAND BY SECTOR," breaks down the demand
between residential, commercial, industry, and power generation,
while the right-hand chart, "ALASKA: GAS DEMAND," depicts the
sum total of those four sectors. As would be expected, the big
sources of seasonality in demand are residential and commercial.
Power has its own degree of seasonality but is much more muted
compared to residential and commercial consumption of gas. The
industry sector was of major importance prior to 2006/2007; the
shutting of Agrium's nitrogen facility being the big difference
since then. There are two big impacts from that. In the early
2000s there was very little seasonality to the nature of the
industrial demand and, because that demand was such a big piece
of the total and was fairly stable, in general the total was
more stable. A period of short gas supply began in those middle
years of the previous decade and industrial usage then became
effectively counter-seasonal, it was being used primarily in the
off-peak months of the residential and commercial sectors,
thereby essentially balancing out the seasonality of the
residential and commercial demand. But now that industrial is
no longer a major piece of the pie, the overall picture is
dominated by the residential and commercial sectors which is
where the overwhelming seasonal nature of the demand is. As
seen on the right-hand chart, the seasonality of overall demand
has gone from a much tighter to a much broader swing - going
from less than 150 Mmcf/d to more than 250 Mmcf/d of total
demand. So, there is now much less seasonal deliverability on
the upstream side, but yet much more seasonal consumption
patterns on the demand side. Getting these things to match is
obviously a key difficulty for utilities to meet that seasonal
demand profile. That is why the Cook Inlet Natural Gas Storage
Alaska facility (CINGSA) and the ability to use the Kenai LNG
Plant in off months have become critical in trying to manage
some of these things.
10:23:15 AM
MR. MAYER reviewed slide 12, "RECENTLY, EXPORTS HAVE OFFERED A
SEASONAL OUTLET," reporting that in recent years exports have
started to offer a seasonal outlet. He said the chart on the
left, "US LNG EXPORTS FROM KENAI," depicts [the volume] of
exports from the Kenai LNG Plant during the timeframes of
October to March (red line) and April to September (green line)
[for the years 1975-2015]. When the two lines are identical, he
explained, it is a non-seasonal export profile - export in the
winter months is largely the same as in summer months. When the
two lines diverge is when the seasonality is seen in the use of
that export facility. By and large those two lines track each
other pretty well until about 2013. It is in 2014/2015 that
that the export facility becomes a substantial component in the
seasonality of demand and being counter-cyclical in terms of
providing demand during the otherwise off-peak periods for the
residential and commercial sectors. In 2014 and 2015 the Kenai
LNG Plant exported 13 and 16 Bcf, respectively, which helped
support the seasonal flexibility that is required.
MR. MAYER then directed attention to the right-hand chart on
slide 12, "KENAI LNG: PRICE OF EXPORTED CARGOES," and noted that
until the end of 2014 the Kenai LNG Plant received $14-$16 per
million British thermal units (MMBtu). It is easy to see how
that was profitable business even if the plant was buying gas in
the Cook Inlet rather than producing the gas itself. However,
[beginning in 2015] prices dropped into the range of $6-$8/MMBtu
and in more recent months have been much closer to $6 than $8.
Thought must be given about the combination of two things: 1)
ConocoPhillips' divestiture from its Cook Inlet assets that
produced the gas historically used for export through the Kenai
LNG Plant, and 2) the question of how the future commercial
structure works - whether that gas is being tolled or whether
ConocoPhillips is buying it at the wellhead. He said he does
not know enough about those structures to comment, but warned
that if the low prices for exported cargoes continue for a
substantial period of time there is a real question as to how
viable that is as a route to manage seasonality.
10:26:13 AM
MR. MAYER addressed slide 13, "GAS PRICES HAVE RISEN
CONSIDERABLY POST 2004," stating that pricing has clearly been a
major factor in enabling additional flattening of decline in gas
production. Referring to the left-hand chart, "COOK INLET GAS
PRICE VS HENRY HUB," he related that, historically, prices in
the Cook Inlet (red line) have usually been substantially below
the Henry Hub (green line), or sometimes equal to the Henry Hub.
He recalled the "famous" Regulatory Commission of Alaska (RCA)
price-making case where the RCA looked at the idea of Henry Hub-
based pricing and thought it was outrageously expensive. It is
now ironic to see that in recent years the Henry Hub price has
been about $2 per thousand cubic feet (Mcf) lower than the Cook
Inlet prices, which have stabilized during these recent years.
This price stabilization, he explained, is in part the result of
the "consent decree" [between Hilcorp Alaska, LLC, and the State
of Alaska, approved by the Alaska Superior Court on 1/17/13] and
the set prices put in place under a number of gas contracts.
Price stabilization is also related to the RCA having to take
into account in making pricing decisions the changes that were
made by the Cook Inlet Recovery Act [House Bill 280, passed in
2010 by the Twenty-Sixth Alaska State Legislature]. The average
Cook Inlet prevailing price is around $6/Mcf.
MR. MAYER then brought attention to the right-hand chart on
slide 13, "ENSTAR: ANNUAL GAS SUPPLY CONTRACTS," and explained
the data source is from publically available information about
ENSTAR Natural Gas Company's ("ENSTAR") gas contracts from its
RCA cost of gas adjustment determination. The chart shows the
supply stack by volume and it can be seen that the $6 figure
conceals a big variation. A substantial amount of gas is being
bought at prices as low or lower than $4/Mcf, an even bigger
amount is in the range of $7-$8/Mcf, and there are some smaller
contracts with the price as high as $14/Mcf. At this point the
consent decree prices are mostly at $7 plus/Mcf. Other
jurisdictions have tried to put in place higher gas pricing to
incentivize some of the most expensive production around. For
example, Argentina trying to incentivize expensive shale and
Egypt trying to incentivize expensive offshore deepwater gas.
Prices of $5, $6, and $7/Mcf have in most of those cases been
sufficient to produce some of that most expensive gas. There is
no question that the increase in gas pricing in Cook Inlet has
played a major, major role in the flattening of the decline that
has been seen and incentivizing the discovery and development of
some of the new resources that is being seen at the moment.
10:29:48 AM
MR. MAYER discussed slide 14, "GAS SUPPLY AND DEMAND DYNAMICS IN
COOK INLET." On the supply side, he said, gas production in 2015
was [103] Bcf. Recent studies by DNR estimate the proven and
probable reserves ("2P reserves") from the legacy fields at
about 1.2 trillion cubic feet (Tcf). Additionally, the
department estimates about 400 Bcf at the Kitchen Lights and
Cosmopolitan fields. Presumably, the department's estimate is
intentionally conservative, because it is very different from
the statements that have been made by some of the operators of
those fields. However, if DNR's figure is used for the moment,
the estimate of 2P gas reserves adds up to about 1.6 Tcf.
MR. MAYER qualified that when it comes to the amount of gas at
Kitchen Lights and Cosmopolitan, he has no more data than anyone
else. He advised that since DNR is clearly authoritative and
intentionally conservative, the department's number should be
looked at more than any other. He recounted that at the
September [2015] hearings on the state's overall credit system,
a representative of Furie Operating Alaska, LLC, ("Furie")
testified that Furie currently has one well with peak production
at about 18 Mmcf/d, but that in principle Furie could be
drilling many, many more wells and be producing 200 Mmcf/d for
15 years. Doing the math for the gas resource that would be
required to produce 200 Mmcf/d for 15 years, he estimated the
size of the resource to be about 1.5 Tcf. So, he counseled,
there are substantial questions yet to be answered in any
authoritative way as to the nature of that resource.
10:32:26 AM
MR. MAYER then addressed the demand side for Cook Inlet gas,
saying he will use DNR's figure of 1.6 Tcf to think about what
that means in terms of the overall supply security situation.
He noted that the 2015 consumption of 100 Bcf pretty much
matched the supply [of 103 Bcf]. Of that, 80-85 Bcf was in-
state demand and another 13-16 Bcf in 2014-2015 was exported
through the Kenai LNG Plant. According to the Alaska Gasline
Development Corporation's (AGDC) forecasts out to 2030, demand
could rise to 115-130 Bcf/year, he related. He offered his
understanding that that is mostly not a growing demand in the
current areas, but rather additional penetration/new uses of
gas. If the nitrogen facility were to restart, AGDC estimates
that that would add another 28 Bcf/year per train, or almost 60
Bcf/year given the facility has two trains.
MR. MAYER explained that one set of math could be to take either
1.2 or 1.6 Tcf of gas in 2P reserves and divide that by current
or forecast future demand. However, he continued, enalytica
hesitates to do that because gas is not produced at a nice
constant plateau, but rather on a decline rate. Just because
there are reserves that could be produced at that rate at the
moment does not necessarily mean it can be done into the future.
But, if both Kitchen Lights and Cosmopolitan are able to be
developed, it seems there is enough currently known resource to
meet current levels of demand at least for the next decade and
beyond.
10:34:42 AM
MR. MAYER pointed out, however, that the market side continues
to hold its long-time perception and deep concern of gas supply
shortage. On the other hand, the public testimony of developers
of new resource, such as Furie and BlueCrest Energy, Inc., is
that the challenge is lack of demand and the impact of lack of
demand in developing their resources. At first blush this seems
hard to reconcile and hard to understand. He said this was the
question that most perplexed him and Mr. Tsafos when they first
began this analysis. He explained that the modeling on the next
several slides spell out that picture and why both of these
things can be true at the same time. The analysis starts with
some hypotheses. For example, is market timing the issue? Is
the market currently covered by existing contracts so there
isn't an opening for new producers now, but there will be a
window in the future that might enable larger scale development?
Is this a natural negotiation process between buyers and sellers
who are still trying to figure out the right pricing point to
enable development of this resource? How much of it is about
fundamentally different views on resource certainty? What is
actually at some of these new fields and how reliably
deliverable is that gas? All these questions are part of what
play into the uncertainty on both sides of this picture. The
next several slides are the results of some high level economic
modeling done by enalytica to understand what this picture looks
like, particularly for someone currently trying to develop new
gas resource in the Cook Inlet.
10:36:49 AM
MR. MAYER showed slide 15, "PROJECT #1: MARKET CONSTRAINED
(ASSUMPTIONS)," and stated that the modeling does not represent
any particular project and is not based on any particular data
other than some publically made statements by some of the
companies around spending on such things as facilities and
wells. Referring to the left-hand chart, "PRODUCTION AND
DRILLING," he outlined a hypothetical scenario in which the
company has spent $400 million on a facility because it does not
have any existing mature fields with production. As an entirely
new development, a platform, pipeline, and other facilities had
to be built. The company must size the development to
eventually produce a substantial quantity of gas. The
development could produce, say, 150 Mmcf/day for 10 years.
However, the constrained gas market will only allow for the
contracting and selling of 15-20 Mmcf/d, so the company only
drills one well. (For example, last year Furie testified it
drilled one well that could produce on about 18 Mmcf/d.) So,
because of the constrained demand in this hypothetical scenario,
the company only drills that one well for the first several
years. Several years later the company attains the ability to
sell 25-30 Mmcf/d and it takes several more years to hit the
mark of 30 Mmcf/d. The company therefore spends a whole decade
during which it only drills four wells.
MR. MAYER, continuing his discussion of Project #1, turned to
the right-hand chart on slide 15, "CASHFLOW AND COMPONENTS:
$6/MCF," to review the economics of the hypothetical project.
He explained the economics look really, really difficult because
the company had the upfront capital expenditure ("capex") of
$400 million (blue bars) for building the platform and other
facilities. However, the after tax cash flow ("ATCF") (black
dashed line) is nowhere near as negative as capex; this is due
to the impact of the substantial credits that are available.
Stacking the 25 percent Net Operating Loss (NOL) Credit with the
20 percent Capital Credit results in 45 percent of that cost
being borne after the fact by the State of Alaska. The
remaining 65 percent is borne by the company. That ratio
changes for drilling expenditures ("drillex") where it is as
high as 65 percent effective support for spending. Even with
the impacts of those credits, he continued, it is still
difficult economics to make work, because the company must
struggle with the big upfront capital expenditure that had to
happen and cannot produce at anything like an optimal rate to
justify that capital expenditure due to the constrained demand.
10:40:11 AM
MR. MAYER brought attention to slide 16, "PROJECT #1: MARKET
CONSTRAINED (RESULTS)," to look at the six charts summarizing
the economic results for this hypothetical project. He noted
that the top three charts depict the split of net present value
(NPV) across a range of price cases discounted at a 10 percent
rate between the company, the federal government, and the state
[one chart representing the status quo under Senate Bill 21,
passed in 2013, Twenty-Eighth Alaska State Legislature; one
chart representing HB 247 for NOL only, and one chart
representing Senate Bill 21 with the Gross Value Reduction
(GVR)]. He further noted that the bottom three charts depict
[the investment metrics] of government take and investor
internal rate of return (IRR) [under the status quo, HB 247 for
NOL only, and Senate Bill 21 GVR]. He explained that under the
status quo there is: no tax on oil, although this hypothetical
scenario is looking at a dry gas development; 45 percent in
stacked credits for facilities capital spending; and 65 percent
in stacked credits for drilling expenditures. As seen by the
investment metrics chart for the status quo, Alaska's fiscal
regime is one of the most generous in the world with 40 percent
or less in government take, but the project's rate of return is
still quite challenged. At [lower] prices the rate of return is
below 10 percent and at higher price levels the return goes into
the high teens. Some of those price levels are enough for a
larger, more established player that can get cheap financing to
sanction a project. However, smaller players without
substantial assets must look for mezzanine financing, which is
possibly 20 percent or more. It would therefore be really
difficult for smaller players to make this project happen even
with the existing substantial credits. It would be possible,
but would require further tweaking and optimization and a whole
range of other things to make it happen. Drawing attention to
the chart for the split of net present value under the status
quo, Mr. Mayer pointed out that [at wellhead gas prices between
about $5 and $7/Mcf] this project over its lifespan would be net
present value negative, value destroying; and at prices [over
$7/Mcf] such a project would be net present value positive,
value creating for the company. The federal government would
always be well protected. The State of Alaska, across all the
depicted prices for this project, would be in a pure subsidy
zone, the state in-net would be handing over cash. The credits
are always greater than the combination of the royalty and the
mineral production tax, the state would in-net be handing over
cash on a net present value basis in order to incentivize gas
development, essentially it would be a subsidy.
10:43:01 AM
MR. MAYER, continuing on slide 16, reviewed the two charts
depicting the economic summary of what HB 247 would do in the
Project #1 scenario of a constrained market. Rather than the
45-65 percent in credits, there would only be the 25 percent Net
Operating Loss Credit. In those years before production occurs
and assuming the company does not already have production and is
able to claim a Net Operating Loss Credit, the impact would be
to further reduce internal rates of return. The return would go
down into the low single digits at the lowest prices and would
only get above a 10 percent rate at the highest prices. At most
of the depicted prices, government take would be in the zone of
50 percent rather than 40 percent, and would get up towards 60
percent at the [highest prices]. The state would be value
negative at some prices and value positive at others, and the
company would only look value positive in the highest prices and
would be loss making in all the rest.
MR. MAYER turned to the two charts for Senate Bill 21 with the
GVR, explaining that the charts are included here not as a
recommendation, but simply as an interesting point of comparison
for how things would look if the North Slope regime for new oil
was extended to the Cook Inlet. In this case there would be
high government take of around 60 percent across all prices,
which is pretty much what that regime was designed to do.
Compared to the internal rates of return under the existing tax
structure but with only 25 percent net operating loss, the rates
of return don't look all that different. They are a little bit
lower, but relative to the difference in government take they
are not much lower and the reason is that this is a regime with
a 35 percent net operating loss rather than the 25 percent. On
the other hand it is a regime with an actual tax liability at
the end when a company is producing cash. The basic idea is
that if a company is a smaller producer that cares in particular
about internal rate of return rather than the value that is
created over the life of the project, a higher credit at the
outset has a bigger impact than the cash in the tail. That is a
different set of priorities than would apply to a larger and
better capitalized company. The basic story here is that when a
company is facing market constrained demand and has to spend
hundreds of millions of dollars on a new facility, the economics
look really, really tough even with credits at this level. The
basic impact of the credits is to make what isn't a very
marginal investment maybe just possible.
10:45:36 AM
MR. MAYER moved to slide 17, "PROJECT #2: MARKET UN-CONSTRAINED
(ASSUMPTIONS)," and posed a second hypothetical scenario with
the same resource base as Project #1. For hypothetical purposes
he stated the assumptions of 600 Bcf of gas, that there would be
a plateau rate, and that the resource would be developed in an
optimal manner of about 130 Mmcf/d of gas. Rather than drilling
one well every couple of years, three wells a year would be
drilled for the first three years to reach that plateau rate.
To maintain the plateau rate of production, another one well a
year would be drilled for the next many years. Referring to the
right-hand chart, "CASHFLOW AND COMPONENTS: $6/MCF," he pointed
out that this change in drilling profile looks much healthier
for cash flow and is more recognizable as the cash flow profile
of an oil and gas investment.
10:46:37 AM
MR. MAYER turned to slide 18, "PROJECT #2: MARKET UN-
CONSTRAINED (RESULTS)," to look at the six charts summarizing
the economic results for this second hypothetical project.
These numbers all look much healthier, he said. The internal
rate of return under the status quo would range from 20 percent
[at a wellhead gas price of $5/Mcf] to 40 percent [at $9/Mcf],
making this a very attractive investment, and the split of net
present value would be positive for everyone. Under the status
quo, the company would be highly positive relative to the state,
a function of a fiscal regime with only 50 percent government
take at those prices along with the substantial credits. Those
credits, he continued, are clearly essential to get a project
that is constrained by market demand to happen; if the market
constraint was solved the credits are much less necessary.
MR. MAYER next looked at the summary charts for Project #2 under
a scenario of HB 247 with only a Net Operating Loss Credit. He
noted the rates of return would be substantially reduced, going
from 15 percent [at $5/Mcf] to 30 percent [at $9/Mcf]. If a
company could make a development look like that, had certainty
when it started the initial investment, and was capitalized to
do so, "it's hard to see that that wouldn't be an economic
investment sort of under that sort of structure," he continued,
he said. Regarding what Project #2 would look like under a
scenario of Senate Bill 21 with the GVR, he advised that the
same sort of lesson would apply. The upfront credits would be
slightly higher, but there would also be higher take in the tail
years. Again, lower total value for the company and higher
total value for the state, but not fundamentally dissimilar
internal rates of return.
10:48:27 AM
REPRESENTATIVE HAWKER observed hypothetical Project #1 assumes a
very constrained marketing ability, limiting the frequency and
number of wells that can be pursued. Hypothetical Project #2
assumes an unconstrained gas market where wells are drilled
every single year and keeping growing production, clearly the
economic differential. When Cook Inlet had the consumption by
Agrium and the operating/production buffer of exports, it was
essentially a completely unrestrained market, he said. As much
gas could be moved out of the inlet as could be produced. Today
there is not the luxury of that regular export. He asked
whether Mr. Mayer has any suggestions for how today's market
could be unconstrained or whether export or a new anchor client
are the only choices.
MR. MAYER replied that to truly unconstrain the market he thinks
export or a new anchor client generally are the only choices.
He added that there is possibly some degree of a chicken and egg
problem in that an export anchor client would need a substantial
degree of certainty of supply before it would be willing to
invest substantial money in reopening a facility and the
developer of new gas would need to know that that demand is
going to be there to make the investments required to prove that
the gas can be delivered. There is a role in that world for
government to bridge that gap, he advised, whether it is with
credits or loan guarantees or other things that can come
together and make that happen. But at the moment, he continued,
there is substantial spending on a very targeted and tailored
set of things in Cook Inlet through the credit program.
10:50:13 AM
REPRESENTATIVE HAWKER said another element that might be at play
here is prospectivity. Until a few years ago, producers were
operating off the five major gas domes, essentially all it took
to get gas was to punch down another straw in those major domes.
However, those major domes are now approaching or are depleted.
While the argument is made that there are trillions of cubic
feet of gas in the inlet, it is an entirely different effort to
go find it. He asked whether the committee should consider the
prospectivity factor.
MR. MAYER responded that that is absolutely an excellent point.
For the next decade or decade and a half of gas security for
Southcentral Alaska, he said, it seems that overwhelmingly the
biggest challenge is simply development of the known but
undeveloped resource base. But, looking out beyond that [time
period], it is always important to keep that in mind as well.
10:51:21 AM
REPRESENTATIVE OLSON related that the value-added plant, Agrium,
was shut down six or seven years ago, but in the summers of 2013
and 2014 the company looked at the plant to see what it would
take to bring it back online. The plant was found to be quite
deteriorated and without state assistance in one form or
another, he said, he doesn't think the plant will be re-opened.
MR. MAYER answered that he understood and pointed out that part
of what makes the next level of analysis really tricky is to
understand the cost-benefit analyses. If targeted measures of
government support are wanted to enable and ensure development
of these resources to provide gas supply to Southcentral Alaska,
what is the most effective and efficient means of providing
that? Is that effectively subsidizing one or two developments
to ensure that even though they would otherwise be uneconomical
they can happen without a gas anchor tenant for additional gas
demand? Is it providing instead a different measure of subsidy
to enable an anchor client? What are the costs and benefits of
some of those things? Those are very difficult and tricky
questions that are major programs for analysis.
10:52:53 AM
REPRESENTATIVE SEATON stated that the unconstrained assumptions
would be a situation in which supply was available so there
would be competition for contracts. When the Agrium plant was
operating it relied on low-cost gas, he recounted. In looking
at the export costs previously given by Mr. Mayer, if the export
market after liquefaction and transportation is the same price
or less than the domestic supply market, then that means the
only way a company could do that is to have its own gas or else
it would lose money. He inquired as to how much of what is
being talked about with adding somewhat massive credits into a
system, is intentionally disrupting the supply and demand market
to get cheap gas to enable a project to go forward that cannot
stand on its own economic feet.
MR. MAYER replied those are excellent points and good questions.
Regarding role of pricing versus role of credits, he said there
clearly is some interchangeability between these two things.
The lower prices are, the more things require credits to be
viable; the less there are credits in this scheme, the more that
higher prices are needed instead. Looking at the curve of
internal rate of return in the world of full credits versus the
world of only a Net Operating Loss Credit, he advised there
would not be many investors willing to do projects this risky
for a 10 or 15 percent rate of return. However, he continued,
imagining that as possible, there is ultimately a gas price - a
higher gas price - that is capable of delivering the equivalent
return as in the world of full credits. Therefore, the credits
allow a project to go forward at a gas price at which the
project otherwise would not have happened.
10:55:53 AM
REPRESENTATIVE SEATON said he is trying to ascertain whether the
high amounts of credits to get an unconstrained market actually
distort and lower the price so that the effectiveness of lower
price goes away unless legislation or regulation are used to fix
a higher price in order not to diminish that incentive for all
of the other players.
MR. MAYER responded that that depends on a lot of factors. The
gas price in Cook Inlet is currently one of the few commodities
in the world that hasn't fallen dramatically over the last
several years, a nice environment to be in. Suddenly, some
initial contracts have been signed between utilities and new
sources of supply at slightly lower prices than the consent
decree pricing that has governed the majority of those
contracts. That said, when it comes to the question of exports
and export availability, all of those prices remain on the high
side as compared to the export pricing for LNG to Japan that is
seen on slide 12. So, at least until LNG into Asia or other
export uses of gas have a much higher value, it is hard to see
that prices in the Cook Inlet are artificially low. Relative to
the rest of the world, they remain artificially high.
10:58:07 AM
REPRESENTATIVE SEATON clarified he is trying to get to the
interaction between the credits which have the goal to stimulate
production that isn't sold locally and so is exported or used
industrially. That excess supply is going to change the price
throughout the market, because more players having more gas will
lower [the price]. "I would think that you would have that
market condition," he said, "but it seems like we're changing
the market condition solely with by applying the credits."
MR. MAYER answered that if it were possible to develop some of
these resources at substantial scale and there were nowhere else
for that gas to go, that would clearly have an impact on market
pricing. The bigger question is whether it is possible to
develop these resources without a substantial external source of
demand in the first place. He deferred to his colleague, Nikos
Tsafos, to further answer the question.
10:59:22 AM
NIKOS TSAFOS, President & Chief Analyst, enalytica, Consultant
to the Legislative Budget and Audit Committee, explained how he
looks at the supply and demand picture by turning to slide 14.
Recalling the constrained and unconstrained market scenarios
previously discussed, he said it is clear that an unconstrained
market would be great and all these things would be economic.
Alaska is sort of stuck in this world of having a lot of credits
but also pretty high prices relative to the rest of the world.
On the one hand it is being said that Alaska has to get this
market going. The challenge with that proposition, he said, and
to which he does not yet have an answer, is that if AGDC thinks
there is market demand in the state that could go up to 115-130
Bcf/year once some of the potential demand in the Interior is
added, plus another 50-60 Bcf/year of nitrogen demand, it is
hard to reconcile that demand picture with the supply picture of
1,600 Bcf. It is almost like saying if the demand was there
this resource could be developed now, but if this resource is
developed now it would probably run out much sooner and maybe
not have the supply security for someone like Agrium. Agrium is
not going to reopen the plant on the basis of five years of
supply, Agrium would probably need longer-term supply. The
question goes back to what Mr. Mayer asked about whether the
right number is this 1,600 Bcf or 1,800 or 1,200 or 2,000.
Drawing attention to the bottom half of slide 14 about timing,
Mr. Tsafos discussed how this market would ultimately develop
under the assumption that both the supply and demand picture are
correct. The base market would be pretty well covered by the
resource and the existing fields with new wells would be able to
meet demand. At some point that will run out and will create a
wedge for new fields to be able to come in and capture that
demand. It is similar to discussions about the Alaska LNG (AK
LNG) Project, which is that the project couldn't be brought on
line now, but looking out to 2024-2025, some of the existing
supply will have fallen, some of the new demand will have come
in, and there will be a window.
MR. TSAFOS said if the aforementioned numbers are correct, that
would be the market way to resolve this. Essentially there is
stranded gas, gas that doesn't have a clear market right now to
come in but is not big enough to create that market. It is more
than just a chicken and egg thing, there is also a time
component which makes it a little more complicated. Going to
Representative Seaton's question, there is clearly some market
inconsistency and inefficiency here - there is only a handful of
buyers and there is only a handful of sellers and there is a
price discovered process and there is a time process and that
can get messy. If this is the resource base, it is difficult to
see how it would be said to bring in all this demand, unless it
was thought that by virtue of bringing this demand it would
incentivize exploration that gets into the undiscovered
resource. Folks looking at this market right now would say that
there is nowhere to sell the gas that they might find because
they would be fourth in line, whereas if a new market for the
gas is created then maybe those folks would think differently.
So, that is the only dynamic aspect to that.
11:04:05 AM
MR. MAYER added that a big part of the aforementioned is what
the nature is of the known but undeveloped resource base. If it
is the size of DNR's current estimate, then it is really talking
about mechanisms to aid the economics of developing the resource
in a constrained gas market because it is not really sufficient
to provide long-term supply at the level of demand that would be
had, for instance, with the reopening of the nitrogen facility.
If it is substantially bigger than that, and the operators of
those places have made some claims that are much higher than
DNR's numbers, then higher levels of production and export
demand start to make sense. What is the optimal solution to
that problem depends a lot on what is the nature of the known
but undeveloped resource base.
11:05:04 AM
REPRESENTATIVE SEATON stated he is trying to get to the crux of
the question, which can be seen in the top left chart for the
status quo on slide 16. In every price scenario shown, $5-
$10/Mcf wellhead gas price, the State of Alaska has a net
present value loss, meaning the state's credits are so large
that the state will never recover its investment. It may be
that some additional production could be stimulated by
subsidizing all of that production. In other words, the state
is paying an unknown amount per Mcf for production that will go
somewhere other than to the local supply base. It is switching
profitability from the state to an exporter, whether exported
through industrial use or through LNG. Those credits are giving
the state a net present value loss for the entire value of the
project even at the highest prices, and that is what committee
members are here considering - are the credits needed in
addition to the price being the highest price in the world? If
a price of $5-$6 is sufficient to develop the highest priced gas
fields in the world, as stated by Mr. Mayer, should the state
double up when the entire double up on the credit system in the
status quo is a total net loss to the state and not necessary to
achieve the goals of even higher priced gas development? These
slides get to the crux of that question, he opined, and he sees
that as the only question that the committee is here is to
answer: Have the credits done their job and are they necessary
though for future production unless the state is just trying to
help some private export project? It is fine if [legislators]
want to do that, he said, but the credits are not showing up as
necessary for domestic production.
11:08:13 AM
REPRESENTATIVE OLSON commented that when Cook Inlet was
operating most efficiently it wasn't really relying on the tax
incentives or anything else. It was a situation where one of
the major producers in the inlet owned the urea plant for 20 or
25 years, the producer always had enough gas one way or another,
and the producer always made money on both sides. It worked out
really well until the producer started shutting assets and
Agrium picked up the property for five years and was unable to
do the same thing. There was also additional demand coming from
the Anchorage utilities at that point in time. It was extremely
profitable without a whole lot of assistance because it was
basically a monopoly on the stranded gas with the exception of
the export. He said he thinks Agrium, then the export, and then
the Anchorage utilities was the way the pie was divided. It
worked extremely efficiently, he opined, but it probably won't
be seen again and it probably wouldn't be allowed by the state.
11:09:22 AM
REPRESENTATIVE HAWKER inquired whether enalytica's modeling is
of exact circumstances and specific cases that actually exist in
the Cook Inlet or is of hypothetical cases.
MR. MAYER replied they are very much hypothetical models. He
quoted statistician George Box who said, "All models are wrong,
some models are useful." Continuing, Mr. Mayer said these
models are definitely wrong, but he hopes they are useful. The
models are not based on any confidential detail of any actual
existing project. They are a set of educated assumptions as to
what various scenarios might look like and are intended to give
a directional idea as to the nature of certain circumstances and
the basic directional conclusion that says market constrained
development is very, very difficult. Market constrained
development may well be NPV negative for the state, but it is
effectively a subsidy to make a development possible that is
still only barely possible with that subsidy. Unconstrained
development certainly looks a lot more viable, and potentially
viable, without the degree of support. Pure drilling within
mature fields is generally quite economic in most circumstances.
That, he said, is the high level nature of the conclusion that
should be drawn from these.
11:11:07 AM
REPRESENTATIVE HAWKER compared slide 15, "PROJECT #1: MARKET
CONSTRAINED (ASSUMPTIONS)," to slide 19, "PROJECT #3: DRILLING
IN EXISTING FIELD (ASSUMPTIONS)," and surmised that the same
data set for production and drilling is used for both slides.
MR. MAYER responded that he used a lower assumption on initial
production from a well. The key differences, he explained, are
no upfront capital spend and lower initial production from wells
from mature fields versus wells in completely new reservoirs.
MR. MAYER then addressed slide 19, "PROJECT #3: DRILLING IN
EXISTING FIELD (ASSUMPTIONS)," stating the final idea here was
to make exactly those two changes. What does it look like if
there is no upfront capital spend of $400 million and if the
well productivity is reduced somewhat because they are mature
reservoirs with less reservoir pressure? He reiterated that the
modeling is not anyone's actual infill drilling program; rather,
it is a series of very level assumptions. It ignores entry or
acquisition costs and treats those as sunk. People actually
owning these assets entered at some point, paid a substantial
amount of money for those assets, and made those investment
decisions based on a tax regime and a tax regime extending into
the future, he said, and those are all important provisos.
11:12:57 AM
MR. MAYER moved to slide 20, "PROJECT #3: DRILLING IN EXISTING
FIELD (ASSUMPTIONS)," to look at the six charts summarizing the
economic results for this third hypothetical project.
Addressing the bottom left chart, "INVESTMENT METRICS," for the
status quo, he pointed out that the internal rates of return
would be enormously high. Once a 50 percent rate of return is
exceeded, he explained, those numbers are no longer particularly
meaningful because it is really just about the nature of a small
initial upfront capital investment and the cash flow that comes
afterwards. No one should quote these as knowing what the rates
of return are for additional drilling in Cook Inlet; that is not
the purpose of this. Enalytica's conclusion from testing these
assumptions over a wide range of drilling costs, well
productivities, and the other key variables, and treating the
past as sunk and looking solely towards the future, is that it
is hard to see circumstances under which drilling additional
wells in mature fields in Cook Inlet isn't profitable even
without credit support.
11:14:08 AM
MR. MAYER showed slide 21, "THE COOK INLET OIL AND GAS MARKET:
A SCORECARD," to summarize his presentation. Oil production has
turned around dramatically and gas production has stabilized but
not turned around, he said, and part of that is due to
constrained demand. There has been a major change in the basic
structure of supply, demand, prices, competition, and
expectations in the Cook Inlet market. Looking at the future,
in most circumstances and particularly circumstances under which
the known but undeveloped resource could be developed, there is
a degree of security of supply for the next decade and beyond.
But, understanding how to ensure that resource is developed and
best developed requires a better sense of how substantial is the
resource base and whether it is best incentivized by credits, or
by other means of subsidizing the development, or trying to
provide access to a substantial external source of demand. Lots
of these variables depend on better understanding the nature of
that resource base in terms of how it can be best incentivized
for development. Enalytica's final conclusion is that based on
the amount of revenue currently generated from Cook Inlet and
the amount spent on credits, it's hard for anyone to look at
that and think it is a long-term sustainable picture. Plus,
additional uncertainty was injected into the picture last year
through the line-item veto and all the rest. Currently, there
is enormous uncertainty over the future of what this regime
looks like, how bankable these credits are, and what actual
economics to apply even to something like additional drilling in
existing fields, because it is unknown what the tax regime will
be next year or the year after. That more than anything else is
possibly the biggest inhibitor to ongoing investment and ongoing
development. Finding a way to set a stable and sustainable
system that investors know will stay as the regime for the next
decade plus is crucial and absolutely paramount.
11:16:33 AM
REPRESENTATIVE HERRON, regarding the statement on slide 21, "Gas
production has stabilized after years of steadier decline,"
interpreted "steadier" to mean no fluctuation decline.
Regarding the analysis of HB 247 related to Cook Inlet, he
inquired what is good about this proposed legislation, what is
bad that should be discarded, and what is ugly that needs work.
MR. MAYER answered that on the good side he would say it is time
to be having a serious conversation about Cook Inlet credits -
what the state's policy aims are through those credits, what the
most efficient way to achieve those aims are, and whether the
current credits fulfill that aim. He said it is hard for him to
see that there aren't potentially more efficient ways of doing
that than the existing system. On the bad side, he continued,
he would say removing the Capital Credits that exist at the
moment, and particularly making that effective July 1, 2016,
seems like a rash decision given there are a number of producers
at the moment that have committed to drilling programs for this
year and those drilling programs rely on the credit system as it
currently exists being in place. A number of those cases are
developments that one would really like to see go ahead and he
thinks July 1 is probably inadequate lead time to enable that
adjustment. Regarding the ugly side, Mr. Mayer noted that the
proposal in HB 247 is to leave everything as it currently is,
which includes sunsetting of the regime in 2022, taking away the
Capital Credit, and leaving in place the Net Operating Loss
Credit. He said the fundamental question here is, What is the
optimal fiscal regime for the Cook Inlet in the long term and
what is the optimal means? If subsidies are necessary to enable
certain activities to occur, what is the optimal means of
delivering that? Being worried about the outflow of credits and
simply saying to get rid of the Capital Credit because that
mostly goes towards some of the ongoing development of mature
fields rather than to new development is a crude answer to that
question. More analysis and a more refined approach is possibly
required to say not just what can be cut now so the state will
be okay, but to say what is actually necessary to provide by way
of subsidy and how to target those as intelligently as possible.
How to craft, not a regime that sunsets in 2022, but an ongoing
stable and sustainable regime for the inlet that achieves all of
these measures?
11:19:56 AM
REPRESENTATIVE SEATON said he is trying to get to an
understanding that an unconstrained market is not going to be
created in the immediate term. He continued:
And if we don't and if we spend a lot of state cash on
credits to allow greater production, are we actually
turning around and saying, "Okay, we are going to make
a surplus that has no market in Cook Inlet to drive
down prices which are actually going to be
counterproductive in incentivizing other well drilling
programs or other supply programs that have been
effective around the world of having higher prices
actually meaning the market conditions drive the
exploration instead of us artificially trying to come
in and basically pick winners and losers, whether it's
going to be old fields or new fields, ... and giving
cash to it.... Can the effect of supplying huge
amount of credits be that we distort the market into
an effect so that we don't get additional market-
driven drilling and exploration?
MR. MAYER deferred to Mr. Tsafos for an answer.
11:21:45 AM
MR. TSAFOS responded that he and Mr. Mayer have spent the last
month pouring over data and he still has no clear answer to some
of these questions. What happened in Cook Inlet is something
that happens in a lot of places: big basin, big export, then a
decline starts, and then it transitions to mostly local supply
of market from big companies to small companies. That is pretty
typical around the world. Having said that, it is also pretty
clear that some of the more natural market forces that come in
to help make that transition didn't quite work here. Whether
talking about having a contract between a buyer and seller that
is not approved by the regulator and therefore creating
uncertainty for both sides about what the price structure is,
for some reason getting new players to come in and take over
assets from bigger companies, something that happened in the
United Kingdom (UK) and Norway, happened a little bit later
here. There is a pretty clear need to think about how to get
this market to work better as a market. Regarding price
signals, Cook Inlet has very high pricing but it is not clear
that there is enough liquidity of competition that these prices
are as dynamic or send as much of a signal as would be liked.
MR. TSAFOS said enalytica has been thinking about, but does not
yet have an answer to, the question of, How can a better market
be made? This is followed by the question of, How can policy
interventions be made along the way to correct distortions in
the market? The distortions over time seem to have been more
important than the core market mechanisms, he continued, and
that makes it difficult to figure out exactly what that market
would look like. The market answer would be that [the inlet]
has stranded gas that doesn't get developed and that is not a
really good answer. It may be the answer, but it is not a very
pleasant or satisfactory answer to come to because people have
been incentivized to come in and spend money and then it is said
that nothing can be done with this gas.
MR. TSAFOS stated that figuring out the answer, which he is
still trying to do, goes back to the core principles of how to
build a real market here, how to reinforce the market approach
of this. As was stated by Mr. Mayer, the taking away of some
credits would raise the equilibrium price at which things make
sense. The current price is fairly good for some investments
and not particularly good for others. The question is whether
there is enough of the luxury on the resource base to see how it
could play out for a few years, to which he does not know the
answer because there is an enormous amount of uncertainty over
the resource base. He said it seems there is enough of a
cushion for a few years to see how those market forces could
play out and whether there is a pricing system that could bring
both the buyers and the sellers together to find a nice
compromise and enable some of these investments. He offered his
general agreement with Representative Seaton that rather than
trying to just artificially prop up a market that isn't quite
working, to try to think more generally about how to make this
market work better.
11:26:18 AM
REPRESENTATIVE HAWKER pointed out that in looking at the real
market today, Cook Inlet has one really significant player and a
few smaller players around the edge. The one significant player
has been operating under essentially government price controls
that came about through the consent decree in order to enter
this market. Regarding creating distortions in a market, he
said he is wondering whether it is really known how the inlet
would work today or if it is being distorted by those government
imposed price controls in the consent decree. He inquired
whether the market would be different without those price
controls and, if so, how different would it be.
MR. TSAFOS replied that Representative Hawker's question is what
he was saying before: there are enough factors getting in the
way of what would normally be thought of as a well-functioning
market, there just aren't have enough buyers and sellers. In
the Cook Inlet's case, an overwhelming majority supplier in the
market is not going to lead to a very well-functioning market.
But, going back to basic economics, if a higher price is
ultimately being charged then other folks would come in and
undercut that major supplier. As has been seen, some of the
recent contracts are below the consent decree, so in some ways
that response is happening although not very speedy. The
biggest challenge is that the market signals and the market
forces are there but they are just not operating very quickly.
The evolution must be seen before some of these distortions or
restrictions can be corrected. Representative Hawker is right
that in the current structure it is not clear that there would
be a much different system based on the reality of who the
buyers and the sellers are and how the market is structured in
Cook Inlet. The question is how to go beyond the current
structure and think about what could be a different structure
that doesn't require the same level of state support but still
has a goal of a well-functioning gas market in the inlet.
MR. MAYER added that clearly one of the biggest impacts of the
consent decree has been to substantially raise the gas price
that has been paid over that period. Activity levels were low
before that. The higher prices of the consent decree and the
changes included in the Cook Inlet Recovery Act for how the RCA
assesses pricing decisions, have all been key and as important,
if not more so, as the credits in the level of activity that has
been seen since then. Because it is one large supplier and
because it is an essentially immovable and regulated price
decision, it is not one that necessarily responds well to market
forces and it is hard to see, other than through some of the new
contracts that have been signed, what sort of underlying market
signaling that might be.
11:30:28 AM
REPRESENTATIVE HAWKER noted that this discussion is about
distorted markets, market inefficiency created with the limited
buyers and limited sellers, and the unknown impacts of the
consent decree. He recalled that Mr. Tsafos spoke about a need
to relook at the tax structure and system in the Cook Inlet. He
posited that the Cook Inlet not currently operating in truly a
free market would argue that [legislators] ought to be careful
about making systemic changes now and to look at what needs to
be done sometime, say, after 2018 when things actually are
working in a free market environment. Care must be taken not to
throw a disruption into a market that will be changing by the
expiration of that agreement and how that might affect buyers
and sellers.
MR. MAYER answered that Representative Hawker raises an
excellent point and enalytica would say that any changes need to
be crafted with a view of not just looking at the tax system but
the overall functioning of the market and how the overall
functioning of the market can be improved and that that
particular point in time is clearly key. In a range of price
environments and price mechanism scenarios, there are probably
better and more efficient ways of targeting state support to
achieve the aim of security of gas supply than the existing
system. But it is important to take time to think through what
that optimal system is, he continued, and set that for the
future rather than make immediate tweaks today simply because
one can and because one is concerned about the cash outflow
which is substantial. This needs to be thought about as a
holistic package of reforms rather than a one-time change.
11:32:44 AM
REPRESENTATIVE HERRON, following Representative Hawker's train
of thought, noted that HB 247 proposes to make some of these
adjustments. So, following Representative Hawker's comment, he
requested examples of pitfalls in HB 247 about those proposed
adjustments.
MR. MAYER answered the biggest pitfall comes from the July 1,
2016, effective date. He presumed there will be testimony over
the coming weeks of investment programs that are currently
committed to by companies on the basis of the existing credits
and are programs that one would like to see carried forward.
Because in principle it is thought that this can be withdrawn,
and therefore it should happen on July 1, poses some substantial
risks in his opinion.
REPRESENTATIVE HERRON thanked Mr. Mayer for that reinforcement.
11:34:00 AM
REPRESENTATIVE JOHNSON stated he is troubled by this whole plan.
However, something that he keeps thinking about and that has not
been discussed, is that to pay these credits [the state] is
actually borrowing the money. No one has talked about that
opportunity loss, the cost of borrowing that money whether it is
from the permanent fund, earnings reserve, or the Constitutional
Budget Reserve (CBR). If the state had the money on hand that
would be one thing, but this is going into savings to pay these,
and so he is troubled by changing it and he is troubled by
having to borrow to continue with it. It is very perplexing and
not an easy decision to be looking at. He said consistency is
probably the most important thing the state could offer, but he
hates to borrow the money to be consistent, because it is
leveraging the state's future, which is what is being done with
the tax credits anyway. It is therefore concerning.
MR. MAYER agreed those are very difficult choices to make, not
only in and of themselves, but also in terms of the way the
broader market sees what is going on and responds. It is
difficult to see that set of choices and think that the current
system is stable or sustainable for any significant period into
the future. All of those things are reasons to be thinking now
about all of the detailed analysis that needs to occur to set a
sustainable regime for the future and to try to make that happen
sooner rather than later. That may not necessarily be the same
thing as making an immediate cut to a credit this year.
11:36:02 AM
REPRESENTATIVE SEATON posited that there are two forces intended
to disrupt the market - the consent decree and the credits. The
question is whether they conflict with each other. Based on
enalytica's examples of the net present values and what works in
the three [hypothetical] examples, it seems it is being said
that under almost no scenario are the credits needed for infield
drilling; that those can be supported and are economic entirely
on their own without those credits. He inquired whether the
following is what Mr. Mayer is suggesting would make more sense:
... if we are looking at ... changing that credit, we
do a timing so that such as infield credits which ...
can be supported on their own, are economic, aren't
relying on the credits to make the project economic.
That those could be July 1 and then at a later set
date we could be looking at certain other projects
that are already sanctioned and going forward and the
credits through that to a certain date, not ... too
long in the future, but through the projects that are
already sanctioned.
MR. MAYER replied he would place a nuance around that. While
enalytica's analysis suggests it is hard to see circumstances
under which ongoing drilling in mature fields is not economic
even without credit support, a number of other things need to be
taken into account in thinking about that. One of those is the
sheer degree of uncertainty that exists around the future of the
entire tax regime and what that means for anyone making
investment decisions even in terms of drilling in the mature
fields. What are the other impacts of credits on that activity?
If more than 60 percent of a company's drilling cost is
effectively borne by the state, the timeframe the company is
looking at in terms of measuring those economics is probably
short enough that it doesn't really care if in a year or two the
entire fiscal system changes because relatively speaking there
is so little upfront cash that the company is worried about. If
that is not the case, the company probably cares a lot more
about what happens in year two, three, four, five, and beyond of
this system. If he had a concern about withdrawing credits from
those activities, it would be that to ensure those activities
continue one would want to know that a stable, competitive,
sustainable fiscal regime was in place that applied to those
activities that when companies made investment decisions about
what they were doing, they were doing it based on that regime,
not on a wildly risked set of assumptions because they are
simply not sure about what the future looks like.
11:39:54 AM
REPRESENTATIVE SEATON argued that if the consent decree is in
place through 2018, then there is certainty among the price
support. If the price support was sufficient around the world
to get that, especially if some of these are being offered lower
but some much higher price contracts for gas, why would there be
an expectation that that price support which is being sustained
throughout the domestic market would go away, he asked.
MR. MAYER responded that his problem is less about pricing as it
is about the rest of the fiscal structure. Is a producer
running its economics assuming the ongoing system of no
production tax on oil and $.17 on gas? Or is a producer saying
it has no idea what next year or the year beyond this fiscal
system looks like? Is the producer having to make a series of
assumptions as to what it could be and a series of worst case
assumptions as to what it could be as opposed to knowing what it
actually looks like and the economics of that activity look very
different in those two scenarios?
11:41:07 AM
MR. TSAFOS added that high prices and strong state support
provide a double support for this system. So, intuitively, one
would say that less of either of those two things could be done.
But, regarding the economics that enalytica ran on the last few
slides, there is a big disclaimer on slide 19 that it is all
point-forward. For a company to be drilling at a field it has
to be in the field - it has to have platforms, the assets, and
the people to do that to begin with - and the major producers in
Cook Inlet came in recently based on a fiscal system that they
were modeling and they were expecting. While enalytica's
modeling is ignoring those costs that are sunk, they are not
sunk from the perspective of the company and what it is that
brought them here. Going back to Representative Johnson's
comment, it is really tough because if nothing is done it is
clear it is unsustainable and it is clear everyone agrees it is
unsustainable. No one can make an investment decision based on
this system because no one believes this system is going to
last. Not doing anything creates an enormous uncertainty and
just pushes it down the line. At the same time it is not really
clear what kind of interventions or changes would be best. But
it is clear that [the state] must come to something that is
going to be seen as durable and sustainable. Cook Inlet is much
more difficult than the North Slope to begin with, especially
from the gas side. So, it is not hard to see how the enthusiasm
of folks in the Cook Inlet disappears very quickly if some
substantial changes are made to the system.
MR. TSAFOS reiterated that the transition from big international
players to smaller players probably took a little bit longer
than it took other places. That could have been based on the
market's perception of Alaska, the risk profile, the opportunity
set. These things matter. Investors are looking closely around
the world about who is raising taxes and who is cutting taxes.
The UK has come out with a tax break. Russia was thinking about
raising taxes and chose to raise some and not to raise others.
Rio de Janeiro came out recently with a tax hike. In today's
global environment investors are super sensitive to thinking
about what kind of changes Alaska is making. It is going to be
a very tough balance. Something has to be done to make it
sustainable, otherwise no one believes it. At the same time,
whatever is done must be grounded in enough analysis and reason
to do as little harm as possible. It is going to be a tough
balance. Even with all the time spent analyzing these things,
enalytica is not quite there yet.
11:45:20 AM
REPRESENTATIVE SEATON said he hopes [the state] gets there
sometime because it is spending $400 million a year that it
doesn't have and a decision must be made someplace as to where
that goes. Whether the high gas price is the consent decree or
what people are willing to pay, he continued, he has not heard
from his constituents any objection to the price they are
paying, which is $1 more per Mcf than elsewhere in the Cook
Inlet basin in order to support the building of a transmission
line down to Homer and Anchor Point. He said he challenges the
idea of needing to stimulate to get a lower price on gas for
domestic use. Maybe people in Anchorage are telling folks
different things, but he has not heard any complaints or
concerns on the gas heating bills being received within
Southcentral. He said he does not know where the pressure,
other than oversupply, would be to drastically lower prices
unless oversupply is driven. If these credits are used to drive
oversupply and drive down prices, that would cause all those
smaller players to not participate in the inlet and further
concentrate the supply in one person. He noted the committee
has requested more analysis from enalytica regarding more of the
policy decision and exactly how those intermingle. He offered
his appreciation for all of the testimony.
11:47:40 AM
REPRESENTATIVE JOHNSON stated he hasn't disagreed with anything
that has been said. However, he said, he would like for the
focus from the administration or future presentations to be on
the consequences of now, the consequences of later, the
realities of now, and long term versus short term. Right now he
is not convinced that the legislation before the committee will
accomplish the things that the committee has heard need to be
done. He would therefore like to concentrate on what some of
those solutions are and concentrate on the doable as opposed to
the presented that is in front of the committee. He urged that
the committee focus on ways to touch this that do the least
damage and that solve the problems so this does not have to be
revisited by future legislatures.
11:49:12 AM
CO-CHAIR TALERICO spoke in regard to Mr. Mayer's point about
making a change when the state has made a promise and people are
locked into a system. He posed a scenario in which a person
with a home mortgage is told by the lender that the lender's
fiscal situation has changed and so now the lender is raising
the interest rate despite the starting agreement. He said he
sees that as being a horrible image for the State of Alaska and
it will make the state look unstable. He recounted that he has
looked into the criteria the state has structured in order to
bring investors into the region. Although he wasn't in the
legislature then, it appears from the history that consideration
was given to ensuring everyone was treated fairly. There have
been some failures in Cook Inlet that have cost the state money
as well as the private sector. He asked how important Mr. Mayer
thinks it is for the state to establish particular criteria to
get a stable and sustainable system that goes out in future
years. He further asked whether tightening that up is something
that Mr. Mayer definitely recommends.
MR. MAYER answered enalytica would certainly say that no one can
look at the amount of cash outflow and think it is a sustainable
program. It is very difficult to look at the sheer amount of
cash outflow also compared to what probably is, in most cases, a
relatively limited cash need to assist development of resources.
If the overwhelming public policy purpose of this program is to
stabilize and provide security of supply to Southcentral gas, it
is a much smaller subset of needs than the cash currently goes
to. Precisely because of the uncertainty that exists around the
future regime and precisely because of the difficult cash
position that the state finds itself in, it is worth trying to
do as much analysis sooner rather than later to try to figure
out what that regime is. It is also better to take the time to
do that analysis and set a sustainable regime for the future,
rather than to make changes as soon as possible because one is
concerned about the cash and everything else is secondary.
11:52:45 AM
CO-CHAIR NAGEAK said the aforementioned discussion needs to be
taken into consideration. He requested Mr. Mayer to follow up
in this regard and thanked Mr. Mayer and Mr. Tsafos for their
presentation.
CO-CHAIR NAGEAK apologized to the Department of Revenue for
running out of time for the department's presentation and
announced another time will be scheduled in the near future.
[HB 247 was held over.]
| Document Name | Date/Time | Subjects |
|---|---|---|
| HSE RES 2.26.16 enalytica Cook Inlet February 2016.pdf |
HRES 2/27/2016 10:00:00 AM |
|
| HSE RES HB247 DOR Fiscal Details and Scenario Modeling (Part 2a) 2-26-16.pdf |
HRES 2/27/2016 10:00:00 AM HRES 3/7/2016 1:00:00 PM HRES 3/7/2016 6:00:00 PM HRES 3/8/2016 1:00:00 PM |
HB 247 |