Legislature(2013 - 2014)BUTROVICH 205
01/16/2013 03:30 PM Senate RESOURCES
| Audio | Topic |
|---|---|
| Start | |
| Presentation: Petrotechnical Resources Alaska - Cook Inlet Natural Gas Supply Update Today Looking at Natural Gas Needs. | |
| Presentation: Analysis of Alaska Natural Gas Supply Issues | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
ALASKA STATE LEGISLATURE
SENATE RESOURCES STANDING COMMITTEE
January 16, 2013
3:29 p.m.
MEMBERS PRESENT
Senator Cathy Giessel, Chair
Senator Fred Dyson, Vice Chair
Senator Peter Micciche
Senator Click Bishop
Senator Lesil McGuire
Senator Anna Fairclough
Senator Hollis French
MEMBERS ABSENT
All members present
COMMITTEE CALENDAR
Who's Keeping the Lights and Heat On? Problems and Solutions:
-Presentation: Petrotechnical Resources Alaska - Cook Inlet
Natural Gas Supply Update Today Looking at Natural Gas Needs
- HEARD
-Presentation: Analysis of Alaska natural gas supply issues
- HEARD
PREVIOUS COMMITTEE ACTION
No previous action to consider
WITNESS REGISTER
PETER STOKES, Petroleum Engineer and Commercial Analyst
Petrotechnical Resources Alaska (PRA)
Anchorage, AK
POSITION STATEMENT: Gave presentation on Cook Inlet natural gas
supply.
ANTONY SCOTT, Senior Economist and Policy Analyst
University of Alaska Fairbanks
Fairbanks, AK
POSITION STATEMENT: Presented analysis of Alaska gas supply
issues.
ACTION NARRATIVE
3:29:59 PM
CHAIR CATHY GIESSEL called the Senate Resources Standing
Committee meeting to order at 3:29 p.m. Present at the call to
order were Senators Dyson, Bishop, French, Micciche and Chair
Giessel.
CHAIR GIESSEL introduced staff and said her goal was to begin
the Senate Resources meetings punctually at 3:30 and adjourn at
5:00 p.m. on Mondays, Wednesdays and Fridays.
^ Who's Keeping the Lights and Heat On? Problems and Solutions
Who's Keeping the Lights and Heat On? Problems and Solutions
^Presentation: Petrotechnical Resources Alaska - Cook Inlet
Natural Gas Supply Update Today Looking at Natural Gas Needs.
Presentation: Cook Inlet natural gas supply update
by Petrotechnical Resources Alaska
CHAIR GIESSEL said the agenda today was an informational review
of the natural gas needs in Alaska. She had included a
Southcentral Energy summary from the Institute of Social and
Economic Research, dated 2006. It forecasted a shortage of
natural gas pretty accurately then. Interestingly, she said, the
25th legislature's Resources Committee began its committee
meetings on this same topic.
3:33:08 PM
SENATOR MCGUIRE joined the committee.
CHAIR GIESSEL said this was the beginning in a series of
presentations entitled "'Who's Keeping the Lights and Heat On?'
Problems and Solutions" and today they would take a look at the
problems; with that she invited Peter Stokes to present studies
he had been doing on the Cook Inlet natural gas supply shortage.
3:33:54 PM
PETER STOKES, Petroleum Engineer and Commercial Analyst,
Petrotechnical Resources Alaska (PRA), said he had updated the
study the utilities in Southcentral, Enstar, Chugach and ML&P,
commissioned PRA to do in 2009. It was updated in 2010 as well
as 2012. Today he would talk today about the Southcentral Alaska
gas supply and demand forecast for 2012-2020 and discuss
possibilities that would allow them to meet the Southcentral
demand during that period, as well as the recent Cook Inlet
Natural Gas Storage Alaska (CINGSA) project operating in the
mouth of the Kenai River.
3:35:56 PM
MR. STOKES stated that study allowed the utilities to better
understand what the supply was for their gas needs as they are
very gas dependent. To do it PRA looked at the Department of
Natural Resources (DNR) 2009 forecast of existing wells and
overlaid it with additional compression that could be achieved
with very low reservoir pressures. That revealed several fields
in Cook Inlet with some geologic gas potential, which was
"feathered in" to meet Cook Inlet demand.
3:38:24 PM
PRA's current study found that in general both the study and
DNR's forecast show a pretty comparable steady decline through
2020. PRA also looked at what wells and gas had been developed
from 2000 to 2009 and used that information to project what
additional development would be required to meet shortfalls in
2013 and beyond. DNR estimated another 185 similar wells would
have to be developed and using a well cost of $10 or $15
million, that would added up to $2 to 3 billion.
3:40:01 PM
MR. STOKES said in 2011, DNR did a follow on study to their
geologic study of available resources looking at the costs of
developing Cook Inlet Basin. They concluded that it was capable
of meeting the needs through the 2018 to 2020 timeframe, but
they also concluded that not making the investments in lock-step
with demand would result in the need for alternative sources
coming into Cook Inlet sooner.
3:40:46 PM
In 2012, the utilities asked PRA to update the 2010 study, which
found that drilling and compressions had been done moving the
predicted shortfall from 2013 to 2014.
3:41:59 PM
MR. STOKES added that Cook Inlet had about 200 bcf/yr. of
production from 2000 to 2005. It supported not only the
utilities for their Southcentral customers, but also two
industrial export plants located in Nikiski: the Agrium Chemical
Plant (originally the Union Oil Collier Plant) and the LNG
export plant. In 2007 Agrium shut down, because they could not
source gas at the price they needed to continue operations. That
combined with the last few LNG exports have caused the
production fall off from 2006 to 2012. The current LNG license
expires in March 2013 and nothing has been said publicly said
about how it would extend or how the plant would be used in the
future.
3:43:07 PM
Beyond 2014 the production for the Southcentral utilities will
be the Tesoro refinery, fuel for the oil and gas facilities, and
mining fuel in the out years. The 2014-19 demand plateau will
come from ENSTAR with 44 percent with Chugach Electric, HEA,
MEA, ML&P making up another 35-40 percent; Tesoro refinery makes
up about 7 percent of that demand and providing fuel for the oil
and gas production facilities is about 13 percent.
3:44:09 PM
SENATOR FRENCH asked if this study assumed any power from the
Watana Dam.
MR. STOKES replied no; it assumes using Cook Inlet natural gas.
SENATOR FRENCH remarked that Watana Dam would "up-end" this
dramatically.
MR. STOKES replied that was correct, depending on when it comes
on. But he didn't think it would impact this particular
timeframe.
SENATOR FRENCH said with Watana they could probably back out
Chugach Electric, LNG fuel and gas, HEA and MEA, and maybe half
of ML&P.
MR. STOKES said that was not part of the PRA study, so it wasn't
addressed in this timeframe.
SENATOR DYSON asked what ML&P's "native load" means.
3:45:16 PM
MR. STOKES replied that it means their load in Anchorage without
supporting other utilities.
3:45:50 PM
SENATOR FAIRCLOUGH joined the committee.
3:46:50 PM
MR. STOKES explained they assumed LNG exports would discontinue
after March 2013 and then ramp up in 2019-20 and assumed there
will be a gas pipeline to Donlin Creek.
He explained the reason the utilities were interested in
updating the knowledge of future supplies in 2012 is because
they are very dependent on gas: Enstar is 100 percent dependent
on gas to provide customers with space heating; Chugach Electric
currently uses 90 percent gas for fueling their generators and
ML&P is about 88 percent dependent for generation. The other 10
percent are hydro or some other fuel.
3:48:02 PM
MR. STOKES showed a graph of what the utilities had and didn't
have under contract for their demand going forward that
highlighted the concern about securing gas contracts. He
reviewed that they did a decline curve of existing wells on a
well-by-well basis on the major fields and did a field-wide
decline curve analysis on the smaller fields and summed them up
together. It showed a 16-17 percent annual decline into the
future starting in 2014. Whereas the 2010 study forecasted the
need of 13 to 14 completions a year, they observed 5 to 8 wells
being completed annually. Additional exploration wells have been
drilled, but he counted only the wells that have been producing
and are currently hooked up to pipelines.
3:49:33 PM
SENATOR DYSON asked if his analysis could have included an
evaluation of individual wells or fields, some of which are more
prolific than others.
MR. STOKES replied that he looked at each individual producing
well and forecasted it based on the well's performance, but
didn't look at the handful that had been drilled but aren't on
stream yet; however, he had done some sensitivities to try and
account for their impacts. They showed a projected shortfall
starting in 2014 that increases annually. It's similar to the
graph for the uncontracted amount of gas that the utilities
require.
3:51:52 PM
He said he added the three years following the date of the study
to the combination of Cook Inlet drilling results from 2001. It
indicated an average of about 12.3 wells completed per year in
Cook Inlet; on average each well added about 3.6 mmcf/day.
Focusing on the last 2.5 years of that timeframe (2007-2009), 34
wells were completed, an average of 13.5 per year. The initial
production of each was a little bit lower than the 9-year
average. In the last 3 years he had observed 5 wells, 6 wells
and 8 wells being added each year. In 2010 to October 2011 fewer
wells were drilled and they weren't as good depending on where
they were drilled. So, they aren't at the 13 or 14 wells
completed a year that are needed to mitigate the shortfall.
MR. STOKES said he did a "sensitivity" of adding 10 mmcf/day
each year from 2013 to 2019 that would sort of equate to 3 or 4
new wells being completed each year. Once again, a shortfall was
seen as early as 2014.
He had added a second sensitivity - adding 20 mmcf/day - which
equated to about 6 to 8 new wells per year, which is similar to
the last 3 years; that pushed the shortfall out a year, but it's
still occurs in 2015 and stair-steps up through 2020. He said
this could be changed by near-term in-field developments above
and beyond 20 mmcf/day per year due to the activities of some of
the new players as well as the old (Hilcorp, ConocoPhillips,
Buccaneer, Armstrong and others).
3:54:51 PM
To meet the shortfall in Southcentral beyond what is in current
wells the options would be:
- In-field development by fields currently being produced by
Hilcorp, ConocoPhillips, Armstrong, Buccaneer, and others
- Exploration done on-shore by NordAq, Apache, and Buccaneer
- Exploration done off-shore by Furie and Buccaneer with a jack-
up rig each
- The instate gas line (ASAP)
- Gas imports
He added that Apache is doing a large off-shore 3D program, as
well, so no doubt, discoveries will be made off-shore in time.
3:56:21 PM
MR. STOKES related that Hilcorp (that had just taken over the
Chevron assets in Cook Inlet) has publically said they would
spend $200 million in 2012 and $150 million per year over the
two following years to develop oil and gas. This is a marked
increase over what had been getting spent by the previous
owners. Red Pad is one development that just got hooked up last
month and is now producing that is not in the analysis.
3:57:12 PM
SENATOR FRENCH asked if in-field development is also considered
a development well.
MR. STOKES answered yes; that is if you already have a field and
are doing some delineation or in-field development.
SENATOR FRENCH remarked that the 2010 report, on page 5, said
that development wells in Cook Inlet have a 90 percent success
rate.
MR. STOKES observed if you have a development and keep drilling
wells and you run out of wells to drill, then it doesn't matter
whether it's 80 or 90 percent.
SENATOR FRENCH pointed out that the report said 97 wells were
permitted and drilled and 87 were completed, and he thought that
was remarkable.
3:59:07 PM
SENATOR DYSON asked if it was likely that the producers would go
deeper into the stratigraphic traps of a reservoir once they had
started drilling an area.
MR. STOKES answered if they are able to drill and find gas they
will do it. Typically they drill through all the estimated
productive horizons and complete wells to maximize production.
He said ConocoPhillips had recently drilled two wells at Beluga
River, one good and one bad. Buccaneer is currently completing
Kenai Loop 4 following the Kenai Loop 1, which was good; the
Kenai Loop 3 was not good. Armstrong has permitted four wells at
North Fork and has drilled a couple wells and some smaller
companies are doing additional development. But this will not
solve their supply problem unless more wells are developed in-
field.
SENATOR MICCICHE asked how he would define a successful in-field
development gas well.
MR. STOKES answered a well that comes in at $2 to $3 million per
day depending on the depth of the well. Drilling a $20 million
well on the west side of the Inlet and bringing in only $1
million per day is not very successful. But drilling some
shallow targets and maybe getting $1 million per day might be
very successful.
4:02:24 PM
SENATOR DYSON said a major component of the cost is how close
wells are to infrastructure.
MR. STOKES responded that was correct and remarked that the
Kenai Loop discovery is right in the city of Kenai at the Wall
Mart parking lot.
SENATOR DYSON asked how they might differentiate between those
that are close to infrastructure and those that aren't and said
he could maybe respond in another venue.
4:03:29 PM
MR. STOKES said another avenue of getting new gas in Cook Inlet
is through the ongoing offshore exploration. Furie is drilling
exploration wells with Sparta 151 jack-up rig and announced a
discovery at Kitchen Lights 1 last year. They drilled and
suspended Kitchen Lights 2 and side tracked 2A this last summer.
Buccaneer mobilized the Endeavor jack-up rig and plans to drill
at cosmopolitan this winter. And as he mentioned, Apache is
shooting 3D offshore and that could lead to future exploration
drilling.
He estimated that it would take three to five years after a
discovery to production from offshore areas due to permitting
and construction lead times.
He explained that another option was the ASAP that could get gas
to Southcentral by 2020 at the earliest.
Finally, bringing gas into Cook Inlet via LNG or compressed
natural gas was another option that was being studied by a
utility group, bringing it from the North Slope through trucking
and compressed natural gas (CNG) were other options being
studied and CNG might be cheaper.
MR. STOKES summarized that in-field drilling won't meet demands
past 2015. Onshore exploration, if it's successful and near
infrastructure, could impact the shortfall; the same for
offshore and that would take three to five years to bring on
line. The ASAP line would be operational in 2020 and beyond;
importing of LNG or CNG could bridge the demand shortfall until
the exploration is successful.
4:07:44 PM
He moved on to the Cook Inlet Natural Gas Storage Alaska
(CINGSA) project update and explained that five horizontal wells
were drilled and compression installed in the mouth of the Kenai
River in the Old Cannery Loop Field. It allows for 11 bcf of
active storage, which allows the utilities to meet 140 mmcf/day
of peaking in the winter.
SENATOR FRENCH asked what would happen if the size of CINGSA
doubled. Would it allow meeting peaking demands for a longer
period of time?
MR. STOKES answered that storage projects need the right size
container so gas getting put in can get pulled out as fast as
needed.
SENATOR FRENCH said he meant five more wells, for example.
MR. STOKES responded that another container would allow more
storage allowing more peak demand, but it wouldn't increase the
supply.
SENATOR FRENCH asked if CINGSA is about half full.
MR. STOKES answered this is the first year it has been used and
they are getting it filled up. It should be filled by next
winter season.
4:10:00 PM
SENATOR BISHOP asked if there was enough base line data to say
for sure that this reservoir is working.
MR. STOKES replied that it is being used right now to meet
peaking demands and all equipment is working as advertised.
SENATOR DYSON said with the huge delta between gas and oil, they
always worry that producers will go for oil at the expense of
gas. Is that possible in Cook Inlet and how could they build
incentives to make sure they stay focused on gas?
MR. STOKES answered they didn't study that in this report.
However, prudent investors look for the best return on their
investment. If they can make more money drilling an oil well
than a gas well, they would drill the oil well.
CHAIR GIESSEL asked him to estimate what it would cost in money
and time to bring in a first load of LNG.
4:12:41 PM
MR. STOKES replied that next week's group could answer that, but
probably in the two to three year timeframe.
He concluded that Cook Inlet doesn't have large discoveries that
can be brought on in the one to two year timeframe and there is
a shortfall of natural gas as early as 2014. LNG or CNG imports
is the only certain method that the utilities have to know they
can continue to meet their demand. CINGSA storage is capable of
enough storing gas for the winter time. It would also be a way
of handling any gas brought into the Inlet.
SENATOR MICCICHE said it has been helpful to learn that activity
doesn't necessarily result in production.
CHAIR GIESSEL thanked him and invited Antony Scott to testify.
4:14:56 PM
At ease from 4:14 to 4:20 p.m.
^Presentation: Analysis of Alaska natural gas supply issues
Presentation: Analysis of Alaska natural gas supply issues
4:20:25 PM
ANTONY SCOTT, Senior Economist and Policy Analyst, University of
Alaska Fairbanks, Fairbanks, AK, said prior to working at the
University he had managed the commercial section of the State
Division of Oil and Gas and that today he would present some
results of a study he had been working on with the Alaska Center
for Energy and Power comparing a range of different energy
solutions for Fairbanks.
The list of projects was from a perspective of delivery cost to
Fairbanks consumers, not cash flow to the state or any broader
policy issues. He did not optimize anything; in many ways he
extracted the project from the project's components and hadn't
identified any sponsor as moving them forward, which impacted
the modeling. Similar financing assumptions were made across all
projects and the same cost indices to bring the project
sponsor's cost estimates up to date in 2012 dollars were used
and then projected forward. Some of the projects had
particularly innovative proposals for how they would like to
proceed, but they weren't used. For instance, the 12-inch fit-
for-purpose project proposed by Arctic Fox suggested purchasing
gas that had already been treated by the producers on the North
Slope in a bundled commodity sense. That is potentially
possible, but they didn't do that. Basically, he tried to
consider projects on an infrastructure basis and then provided a
way to compare them on an apples-to-apples basis.
Before going into the descriptions, he thanked the people who
provided data for the study: Jim Dobbs and Steve Hagenson,
Fairbanks Economic Development Corporation, the folks at Alaska
Gasline Development Corporation (AGDC) who provided key
underlying data, folks at Energy Acura at Fairbanks, experts at
Alaska Energy Authority (AEA) on the Susitna Dam, and people
interested in high voltage direct current (HVDC) transmission of
electricity off the North Slope.
4:25:39 PM
MR. SCOTT said he looked at trucking LNG off the North Slope and
at different configurations of a bullet line project - when Bob
Swenson looked at that project he looked at not just a 500
mmcf/day project (which is what AGDC is currently pursuing), but
also smaller throughput configurations at 250 mmcf/day - more or
less meeting the entire Railbelt energy demands as well as
larger throughput configurations at 1 bcf/day; a spur line off a
major gas sale (LNG project to Asia as opposed to an overland
project into North America with its consequences for pricing in-
state); a small diameter 12-inch fit-for-purpose pipeline from
the North Slope to Fairbanks; the Beluga to Fairbanks option
(piping gas from Cook Inlet north into Fairbanks); the
possibility of heating by wire - the Susitna/Watana project; and
a project configuration of HVDC which would provide both
electricity and heat by wire to Fairbanks.
He underscored that he included the two electric projects for
comparative purposes and to shed some light, but they are
different, because meeting electricity needs and doing
electricity planning is in many ways beyond the scope of this
work and because it requires so many project integration
considerations that exceeded the scope of his ability to address
in this study. Finally, he looked at the possibility of making a
liquids out of coal facility located in the Interior, which was
the initial justification for the study to begin with in terms
of its funding.
4:28:22 PM
MR. SCOTT said one of the things that drove the results in this
project was the focus on commodity price piece. He explained
that often projects are presented in terms of infrastructure
cost and have a fixed assumption on how to minimize
transportation costs - and while those costs are absolutely
relevant, they clearly don't tell the whole story. So, some of
his results were be surprising because they were a result of
focusing on commodity pricing regimes within Alaska.
4:29:35 PM
SENATOR MICCICHE wondered why a couple of alternatives weren't
mentioned: one was imported LNG and regasification and the
second was the potential for Nenana Basin natural gas
production.
MR. SCOTT answered that, in effect, he would present the results
of a Beluga to Fairbanks project within the context of moving
gas by pipeline from Cook Inlet into the Interior. He added also
that he didn't have any public data to work with to try to mock
up what the Interior energy development project would look like
and that was very limiting.
SENATOR MICCICHE said it would be interesting to see the
trucking option going north instead of just going south. The
Beluga to Fairbanks pipeline was an interesting concept but LNG
can be trucked both ways.
CHAIR GIESSEL added, "and by rail."
4:31:43 PM
MR. SCOTT said his assumptions that would significantly drive
the results were only a model and not how the future would
necessarily unfold. The working framework was based on actual
transactions in the market and a good place to start.
He explained that today one can purchase (untreated) stranded
gas on the North Slope and there is a market for that commodity.
Much of it is transacted using his formula: the price of a
barrel of ANS X 4.6 percent = price per mcf of the gas. This
formula came from a DNR settlement for valuing gas that was
agreed to in the early 1990s with the North Slope producers and
then it started being used as a benchmark for a number of
subsequent market transactions. Norgas Co.'s contract on the
North Slope was referenced to this formula, for instance. One
could do better than this formula by looking at royalty values
and how the settlements work and then back out some of the
values for gassing transactions. Some is higher and some is
lower, but one of the patterns that emerges is that gas isn't
purchased at a fixed price. It is typically indexed to oil and
that is something that looks like his formula.
LNG pricing under long-term contracts (not spot) in the Asian
Pacific is undergoing some change, he said, but the historical
industry standard looks something like his formula, which is:
ANS (or a waterborne crude) X 14.5 percent + $.90 and that
results in the price/mmbtu in Asia. The Alaska Gasline
Development Corporation (AGDC) used a formula like this in their
2011 work. Other support for this kind of a pricing arrangement
came from Gas Strategies that was hired for the AGIA process,
which suggested similar formulas going forward for pricing, as
well as Wood MacKenzie. He cautioned that prices could soften
and then the prospects for LNG exports dim considerably off of
any project.
MR. SCOTT explained that his model for Fairbanks heating oil can
be correlated tightly to ANS West Coast (WC) crude prices. The
formula for retail Fairbanks heating oil is: the price of a
barrel of ANS crude X 22.5 percent + $4.20 equals the
price/mmbtu. He used ANS oil price as a common denominator to
look at these different commodity markets.
4:37:32 PM
He said slide 5 ran actual historical ANS oil prices through
each of the formulae to produce different price paths. So the
blue line was actually what ANS oil prices were; the red line
was Fairbanks heating oil prices as a function of ANS oil
prices, the green line was the cost of LNG in South Korea as a
function of that formula; the purple line represented the cost
of stranded North Slope gas at Prudhoe Bay. The locations of the
commodities were different and the volatility of the pricing
regimes were very different, which meant that the risk profiles
of projects that access the resource from different places were
going to be very different.
MR. SCOTT said that one of the driving assumptions in his work
were three projects that export Alaskan gas as LNG: the bullet
line at 500 mmcf/day, a bullet line at 1 bcf/day, and one at 3
bcf/day. All of those export projects bring North Slope gas to
the LNG market. His working assumption in every case was no home
town discount, which means a North Slope producer will not sell
gas to Alaskans at a discount compared to the value they could
receive if they exported that gas. That logic was based on
economics and commercial behavior; there wouldn't be a problem
if the opposite was the case.
4:41:20 PM
He modeled all the projects on slide 6 on a private ownership
model, which means he assumed they were financed as 70 percent
debt, 30 percent equity, and that the return on equity was 12
percent and that cost of equity was 6 percent. It showed
delivered costs of energy in Fairbanks in 2023 (because that is
when all or any one of the modeled projects would be on line).
He added that he was trying to avoid discounted prices back to
today. The oil prices on the horizontal axis were real prices
per barrel for ANS crude, and that is because you can correlate
crude oil prices with the gas prices being modeled.
4:43:31 PM
From the Fairbanks perspective, he said a couple things jumped
out. Surprisingly, it turns out for the ASAP project (1
bcf/day), larger throughput doesn't mean cheaper prices to
Fairbanks. For oil prices above $70 barrel the delivered cost to
Fairbanks consumers was greater than the ASAP project (assuming
100 percent load factor) at 250 mmcf/day. This was counter
intuitive, because everyone knows that bigger throughput on the
same line should reduce the cost of transportation, but the cost
to consumers was a function not just of the cost of
transportation but included the function of commodity price.
The larger configuration project hits the LNG export market and
then Fairbanks consumers end up seeing the LNG export market
formula, which rises much more steeply as a function of oil
prices. So, at higher oil prices, it ends up that the lower cost
commodity ends up getting overwhelmed by the increase in the
commodities charge.
The black dash line represented Fairbanks heating oil, the
status quo that many consumers rely on today. If an energy
project does not come in below that line, it is not providing
energy cost relief.
MR. SCOTT pointed out that one of the things they see for all of
the projects at low enough oil prices is that none of them
provide material energy cost relief except the major gas sale.
4:46:41 PM
SENATOR FRENCH asked which hash mark corresponds to which oil
prices on the X axis (oil prices).
MR. SCOTT apologized for the "Excel foible" and said the labels
should really be on dead center.
He continued explaining that for a privately owned project, if
the only goal is providing energy cost relief for Fairbanks,
there is the potential risk that the project doesn't do that.
Further, he stated that everyone might believe that oil prices
north of $70 are here to stay, but that can be a wildly wrong
assumption. How would that happen? Shale oil could take off
worldwide, just like shale gas has.
He added that the dotted blue line looks at the cost of HVDC for
a project that meets all of Fairbanks' heating and electrical
needs if it were privately funded. In general, Mr. Scott
explained, heating by wire is not a super duper proposition and
the reason he didn't include the Susitna/Watana project is
because the cost of electricity from that project (once
converted to mmbtu) "kind of blows out the scale" being 60
percent higher than anything else on the graph. He wasn't
knocking the project, but its energy would be used for lights
rather than heating homes.
SENATOR MICICCHE asked him to clarify HVDC as well as other
acronyms.
4:50:27 PM
MR. SCOTT replied that HVDC would purchase stranded North Slope
gas and generate electricity in very large turbines at very high
efficiencies and transport that electricity on high voltage
direct current (HVDC) lines into Fairbanks where the electricity
would be transformed again into alternating current and be made
available to consumers.
4:51:47 PM
He said slide 7 showed the public ownership case for Bradley
Lake and assumed 100 percent state financing for everything, 4
percent debt for everything and no private capital. So there was
a dramatic reduction in the cost of all the projects resulting
in a large decrease in the cost of delivered energy. Here some
of the projects started to separate out, which was a function of
the large energy projects that are incredibly capital intensive.
He said reducing the cost of capital across the projects makes
an enormous difference. A clustering of projects using stranded
North Slope gas results, so the fit-for-purpose pipeline, the
smaller diameter ASAP project and the Fairbanks trucking project
all deliver energy in a parallel cost environment and all pretty
close together. Given cost uncertainties in terms of scope on
any of these projects and using the assumption that they are all
fully loaded, they are distinguishable.
The projects that use North Slope gas in an export function
through the LNG market paralleled each other and had much
steeper slopes and often delivered more expensive energy than
the stranded gas projects. Not always - it depended on oil
prices, but everything started looking a lot better compared to
heating oil.
4:54:17 PM
He pointed out how the previous two slides showed two dynamics:
the importance of how the projects are financed and the oil
price risk and that the next slide (9) showed ramp-up risk,
which means if you build a large infrastructure project and
don't necessarily sign up all the customers at once (which you
can't), the cost of providing energy in the very first year to
the customer will be much higher than it would be once the
customer base was fully subscribed. That is a material risk for
all the projects and it needs to get dealt with on a policy
level.
The state funding he used on slide 9 was much less and he
assumed $100 oil. It highlighted how the energy solution would
have to be enough below the black line that the customer wants
to pay the conversion cost to natural gas or anything else.
Revolving loan funds would help some, but wouldn't solve the
problems. In general, he said, these problems don't come up
because infrastructure projects like this get built on the basis
of very large industrial customers that create the economies of
scale such that everyone else wants to get in. Fairbanks doesn't
have that favorable of an environment for distributing natural
gas in terms of initial economies of scale. But the more you can
reduce costs through state financing and grants, or whatever,
the less the ramp-up risk will exist - and that risk has to be
dealt with. Slide 10 showed that ramp-up risk as a function of
the rate of ramp-up for Fairbanks local gas distribution as well
as the uncertainty in total Fairbanks heating demand. It was
news to him that people don't really know what Fairbanks needs
for heating load - unlike Anchorage where one can look up the
total number of btus of natural gas that are consumed by just
going to Enstar. As a result of that uncertainty the ramp-up
risk can't be fully captured, but it does matter.
4:58:40 PM
Slide 11 provided a scale on the range of total capital costs
associated with each project many of which are incredibly
capital intensive and would stretch the state's credit capacity.
So, choices have to be made about what the state wants to
pursue. And slide 12 modeled start dates of the different
projects, which for the Interior is an extremely relevant
concern.
4:59:58 PM
In summary, Mr. Scott said, the analysis focused on dimensions
of project risk, and he didn't have a chance to look at capital
cost risk or escalation risk, and others, but the whole study
does do that and he was trying to finish it. A key part is that
the commodity price terms are crucial. In seeking any of these
solutions, he urged them to focus on: the pricing terms and
their duration, at what events they get renegotiated and if they
are portable from one project to another. It's critically
important to nail those considerations down as soon as possible.
There is nothing stopping anyone from negotiating gas sale
contracts today - stranded North Slope gas contracts have been
negotiated - and they should be done as soon as possible a home
town discount is being considered. He advised that if they were
considering using state money as a carrot to get it that the
discount needs to be negotiated up front before spending the
carrot.
5:02:03 PM
SENATOR MICCICHE noted that his coal to liquids delivered cost
of energy price is the lowest in both cases, but dramatically
lower at higher fuel prices under state ownership and asked if
there was a reason he didn't include the ramp-up risk for that
project.
MR. SCOTT replied yes; because there is a market for those
liquid fuels today and conversions are not needed to build out
the demand for it. So, the assumption is if the state were to
build that project, it would have the ability to compete and
fully sell all of its product in the market today. The volumes
are less than the relevant total market demand in Alaska, so you
don't need to worry about ramp-up risk. However, the real reason
he didn't focus on the coal to liquids project is because it's
almost impossible for that project to deliver energy cost
relief. Why? Fuel oil, for example, is a commodity and in the
event a state sponsored project sold fuel oil below market
rates, people would purchase as much as they possibly could and
then turn around and sell it on the open market at market rates.
In other words, having price controls for a commodity like fuel
oil while not necessarily impossible is fraught with difficulty
and encourages fraud. It also raises enormous regulatory and
legal issues.
Also a coal to liquids project comes out on the bottom, but that
it is faced with very substantial technological risk and is an
extremely large project; and assuming state funding, it would be
extremely difficult to manage (much more so than a pipeline
project), since the state doesn't have that particular
expertise. And the capital cost associated with a coal to
liquids project is the most uncertain of any project; the
uncertainty bounds are plus or minus 40-50 percent, at least.
CHAIR GIESSEL said he was quite informative and thanked him for
his presentation.
5:05:59 PM
Finding no further business to come before the committee, Chair
Giessel adjourned the Senate Resources Standing Committee
meeting at 5:05 p.m.
| Document Name | Date/Time | Subjects |
|---|---|---|
| Presentation on {Energy Options for Fairbanks} by {Dr. Antony Scott}.pdf |
SRES 1/16/2013 3:30:00 PM |
Dr. Antony Scott |
| Cook Inlet Gas Supply and Demand Update SenResComm 011613 Final2.pdf |
SRES 1/16/2013 3:30:00 PM |