Legislature(2009 - 2010)HOUSE FINANCE 519
03/11/2010 03:00 PM House ENERGY
| Audio | Topic |
|---|---|
| Start | |
| Overviews on Comparative Railbelt Energy Project Analysis | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
ALASKA STATE LEGISLATURE
HOUSE SPECIAL COMMITTEE ON ENERGY
March 11, 2010
3:19 p.m.
MEMBERS PRESENT
Representative Bryce Edgmon, Co-Chair
Representative Charisse Millett, Co-Chair
Representative Nancy Dahlstrom
Representative Kyle Johansen
Representative Jay Ramras
Representative Pete Petersen
Representative Chris Tuck
MEMBERS ABSENT
OTHER LEGISLATORS PRESENT
Representative Carl Gatto
Representative Craig Johnson
Representative Bob Herron
COMMITTEE CALENDAR
OVERVIEWS ON COMPARATIVE RAILBELT ENERGY PROJECT ANALYSIS
- HEARD
PREVIOUS COMMITTEE ACTION
No previous action to record
WITNESS REGISTER
JIM STRANDBERG, Project Manager
Alaska Energy Authority (AEA)
Department of Commerce, Community, & Economic Development
(DCCED)
Anchorage, Alaska
POSITION STATEMENT: Discussed the Railbelt Integrated Resource
Plan (RIRP) project, along with a PowerPoint presentation
titled, "A Comprehensive Plan for the Alaska Railbelt; gave a
PowerPoint presentation titled, "Susitna Hydroelectric Project."
KEVIN HARPER, Project Manager
Black & Veatch
Issaquah, Washington
POSITION STATEMENT: Participated in the PowerPoint presentation
titled, "A Comprehensive Plan for the Alaska Railbelt."
BOB BUTERA, Civil Engineer
HDR Alaska
Anchorage, Alaska
POSITION STATEMENT: Assisted in the presentation titled,
"Susitna Hydroelectric Project."
ERIC YOULD, Program Director
Chakachamna Hydropower Project
TDX Power, Inc.
Anchorage, Alaska
POSITION STATEMENT: Gave a PowerPoint presentation titled,
"Chakachamna Status Report."
BOB SWENSON, Project Manager
Alaska In-State Gas Pipeline Project
Department of Natural Resources (DNR)
Anchorage, Alaska
POSITION STATEMENT: Gave a PowerPoint presentation titled, "In-
State Gas Pipeline Project Update."
ETHAN SCHUTT, Vice President
Land and Energy
Cook Inlet Region Inc. (CIRI)
Anchorage, Alaska
POSITION STATEMENT: Gave PowerPoint presentations on Fire
Island Wind and Underground Coal Gasification projects.
PAUL THOMSEN, Director
Policy & Business Development
Ormat Technologies, Inc. (Ormat)
Reno, Nevada
POSITION STATEMENT: Gave a PowerPoint presentation titled, "The
Mount Spurr Geothermal Project."
ACTION NARRATIVE
3:19:39 PM
CO-CHAIR CHARISSE MILLETT called the House Special Committee on
Energy meeting to order at 3:19 p.m. Present at the call to
order were Representatives Millett, Edgmon, Dahlstrom, Petersen,
and Johansen. Representatives Ramras and Tuck arrived as the
meeting was in progress. Also in attendance were
Representatives Gatto, Johnson, and Herron.
3:19:56 PM
^Overviews On Comparative Railbelt Energy Project Analysis
Overviews On Comparative Railbelt Energy Project Analysis
3:19:58 PM
CO-CHAIR MILLETT announced that the only order of business would
be overviews on comparative Railbelt energy project analyses.
The 20-minute overviews also include responses to seven
questions that were posed by the committee to each of the
invited participants.
3:21:21 PM
JIM STRANDBERG, Project Manager, Alaska Energy Authority (AEA),
Department of Commerce, Community, & Economic Development
(DCCED), noted that the state sponsored integrated planning
process came about through the efforts of Representative Craig
Johnson and Senator Joe Thomas; in fact, $1 million was directed
to this study, and $1.5 million was directed to analysis of the
Susitna Hydroelectric (hydro) project. Railbelt utilities also
contributed to the completion of the plan. The goal of AEA was
to create a plan useful within the Greater Railbelt Energy and
Transmission Corporation (GRETC) concept, and supported by the
Railbelt utilities. Mr. Strandberg explained that an integrated
resource plan [for energy] is "a grouping of defined power
generation and transmission line projects arrayed on a time
schedule for development that will allow for leased, long-run
costs of wholesale power at acceptable levels of reliability."
The analysis also included fuel supply portfolios, as well as
transmission analysis. Mr. Strandberg concluded that the role
the Railbelt Integrated Resource Plan (RIRP) plays in the
creation of GRETC is to define what energy projects, on an
economic evaluation process, should be constructed for the
future of the Railbelt. He presented slide 2 and said the
Railbelt Electrical Grid Authority (REGA) was a business
structure analysis funded by the legislature that formed the
business model for GRETC, thus the major components for GRETC
were the REGA study of business structure, and the RIRP that
identified actions and projects.
3:27:15 PM
KEVIN HARPER, Project Manager, Black & Veatch, clarified the
following four points regarding the plan: (1) an integrated
resource plan is not a state energy plan; (2) it is a document
that identifies the direction "the region ought to go," albeit
not at a level of detail, such as the site for a wind project;
(3) any integrated resource plan (IRP) should be updated every
three to five years, especially as uncertainties and risks
influence the results of the report; (4) there are four specific
scenarios, 1A, 1B, 2A, and 2B. He further explained that the
designation of "A" indicated "least-cost," and the designation
"B" indicated "forced ... renewables," and thus determines
whether there is incremental cost associated with achieving the
target of 50 percent renewables by 2025. Further, scenario "1"
assumes today's load and some growth, and scenario "2" assumes a
load increase of 50 percent by 2025, and an increase of an
additional 50 percent by the year 2040.
3:31:29 PM
MR. HARPER advised that one issue with energy for the Railbelt
is its size; in fact, the Railbelt is too small to economically
justify many of the proposed projects. He presented slide 3,
Scenario 1A/1B, that illustrated the energy output by technology
[source] over a 50-year period. Mr. Harper pointed out that the
resource plans for scenarios 1A and 1B are the same, therefore,
based upon today's load with some growth, there is no
incremental cost associated with reaching the target of 50
percent renewables by 2025. In fact, 63 percent of the energy
generation is by renewables by 2025. This percentage is
achieved by the increase in hydro generation. Conversely, there
is a corresponding reduction in the use of natural gas. Mr.
Harper stressed that the least cost path is dependent on
renewables, such as the Chakachamna hydro project, coming on-
line. Importantly, natural gas remains a base-load source of
generation.
3:34:46 PM
REPRESENTATIVE RAMRAS recalled that representatives from the
Office of Fossil Energy, U.S. Department of Energy (DOE),
identified natural gas as the "bridge fuel" for the next 50
years. He pointed out that on slide 3, natural gas is shown as
a modest fraction of the projected energy portfolio. He asked
whether the graph is reflective of gas pipeline projects such as
Denali-The Alaska Gas Pipeline, the Alaska Gasline Inducement
Act (AGIA), or in-state gas.
3:36:53 PM
MR. HARPER responded that slide 3 is based upon the base-case
gas supply and price forecast. To develop the forecast, his
company relied on currently published studies, discussions with
state agencies, producers, and utilities, and a probabilistic-
based analysis of supplies and prices. Looking at the supply of
energy, the forecast was also based on the following: most
recent forecasts from the Department of Natural Resources (DNR)
on the resources remaining in the Cook Inlet; the assumption
that a generic in-state pipeline will be operational in 2015-
2016; the assumption that a source of imported liquefied natural
gas (LNG) would be available for the short- and long-term.
3:38:44 PM
REPRESENTATIVE RAMRAS has heard that Black & Veatch wants to
undermine discussion about an in-state gas pipeline.
3:39:21 PM
MR. HARPER relayed that the [forecasted] non-Cook Inlet supplies
of natural gas are from the North Slope. He advised the issue
is the assumption of the price of the gas; his firm assumed the
price of the gas from the North Slope to Southcentral will
reflect the world market price, "with world LNG prices as being
essentially a cap, if you will, as to what prices would be." In
Black & Veatch's assessment, there would be enough gas to meet
the needs of the Railbelt, but at a market price. He opined
those assumptions are also held by DNR.
3:41:19 PM
REPRESENTATIVE RAMRAS asked:
What kind of factors did you have for the importation
of LNG? When do you see Alaska, which is so energy-
rich, importing gas, and at what price are we going to
import gas? And give me, [information] other than
prevailing indices of world gas prices: I need you to
break it down...
3:42:22 PM
MR. HARPER said the gas supply after 2015-2016 is essentially
from Cook Inlet and the North Slope. The Cook Inlet pricing of
new gas, plus the pricing of the North Slope gas, would be based
on world market prices; therefore, the gas supply does not
include LNG long-term, except in the near-term as a bridge fuel.
3:43:54 PM
REPRESENTATIVE RAMRAS re-stated his question.
3:44:06 PM
MR. HARPER answered from 2015-2016 on, the gas is coming from
Cook Inlet and the North Slope. The LNG price is used as a
benchmark for what the price would be, after taking out
transportation.
3:44:27 PM
REPRESENTATIVE RAMRAS asked whether Black & Veatch is advocating
for the importation of LNG to Alaska.
3:44:53 PM
MR. HARPER said his firm has no position on that. In further
response to Representative Ramras, he said the plan "essentially
is in-state gas."
3:44:59 PM
MR. HARPER continued speaking about slide 3, and noted that the
capital investment for this portfolio of projects is about $9
billion over 50 years. Based on the assumptions used, the model
chose large hydro, and the version chosen was the Chakachamna
project over the Susitna project. However, he pointed out the
Susitna project has been evaluated since the early 80's, and the
cost estimates are "solid." The assumptions around Chakachamna,
such as permitting and costs, were reviewed in a limited way,
and he was unsure of their accuracy.
3:46:59 PM
REPRESENTATIVE GATTO assumed the Chakachamna project is simpler,
easier, and cheaper, but results in less power.
3:47:20 PM
MR. HARPER further explained that the Susitna cost and output
estimates used in the study were based upon a study done by HDR
Alaska. HDR took work done in the 1980's, and determined the
impacts due to inflation. The HDR study also looked to "right
size" the Susitna project for the region, because the 1980's
work assumed the energy load for the Railbelt in 2010 would be
8,000 megawatts, and it is actually less than 1,000 megawatts.
3:48:51 PM
CO-CHAIR MILLETT asked for the reason the study chose a specific
hydro project.
3:49:14 PM
MR. HARPER stated there are generic and specific identified
projects in the portfolio. In the case of hydro, there was
Susitna, Chakachamna, Glacier Fork, and three generic potential
projects. It made sense to identify the projects that were
under development; in fact, not including the identified
projects has a negative effect on the quality of the work,
especially for hydro, because the costs and operating parameters
are site-specific. Mr. Harper then presented slide 4 that
listed the generation projects in the preferred resource plan
based upon scenario 1/B. These are the projects that would be
operating and generating electricity by 2020. The first item
was Demand Side Management/Energy Efficiency (DSM/EE) programs.
He explained that DSM/EE programs were included because of the
assumption that when residential or commercial customers reduce
their use of energy by investing in a high efficiency appliance,
there is an incremental cost. Also, there was the assumption
that the utility, GRETC, or the state, will pay 50 percent of
that cost. These DSM/EE programs equate to about 8 percent of
the total energy requirements of the region. Although in
certain states, energy efficiency is at 15-20 percent, the study
uses an 8-10 percent rating for Alaska due to limited data, the
isolated network, severe weather conditions, and the limited use
of electric space heating. The next project was the Nikiski
Wind project that is under development and would provide 15
megawatts of power. The next item was the Healy Clean Coal
Project (HCCP).
3:53:43 PM
REPRESENTATIVE RAMRAS asked for the amount of the average
kilowatt cost for the Railbelt that was used in the draft
report.
3:53:54 PM
MR. HARPER said the draft report contained an error, and the
actual estimate is an average, wholesale cost of power of 17.5
cents per kilowatt hour (kWh) in nominal dollars, or about 12
cents in 2009 dollars.
3:54:34 PM
REPRESENTATIVE RAMRAS asked when Black & Veatch caught the
mistake.
3:54:50 PM
MR. HARPER said the mistake had no impact on the analysis in
terms of the selection of the resources. The kWh estimate was
calculated after the resources were selected and the models run,
thus it did not impact the resource selections made in the
draft, or the final report. In further response to
Representative Ramras, he said the mistake was found when the
draft report was released. The models were re-run to
incorporate changes from the public comment period and the
correction to the estimate.
3:55:57 PM
REPRESENTATIVE RAMRAS asked for the month and year of the period
of the distortion to the models.
3:56:08 PM
MR. HARPER said there was no distortion in the models because
"the calculation was done outside of the models and is an
output." He further explained that the change was made within a
six-week period when Black & Veatch went from the draft to the
final report, and after a four-week public comment period. Mr.
Harper returned to the list of preferred resource projects and
said the Fire Island Wind project is expected to begin
operations in 2012, providing 54 megawatts. The remainder of
the projects are: the Southcentral Power Plant, that is being
developed by Chugach Electric Association (Chugach Electric) and
Anchorage Municipal Light & Power (ML&P), providing 180
megawatts; Glacier Fork Hydro that is expected in 2014,
providing 75 megawatts; two municipal solid waste (MSW) projects
that are expected in 2015 and 2017, providing 22 megawatts and 4
megawatts; Golden Valley Electric Association (GVEA) North Pole
retrofit project; Mt. Spurr Geothermal projects expected in 2020
and 2022, providing 50 megawatts from Unit 1 and 50 megawatts
from Unit 2. Also recommended was the parallel pursuit of the
Chakachamna/Susitna/Glacier Fork hydro projects. He reiterated
that the next step for Susitna is development, and the next
steps for Chakachamna and Glacier Fork are analyses to determine
whether the projects can be built. The final item was a full
list of 19 identified transmission projects that total $1.6
billion. Slide 5 was a list of near-term transmission projects
that are needed within the next five years to maintain the
reliability of the existing system. The near-term transmission
projects are: Soldotna-Quartz Creek transmission line for $126
million; Quartz Creek-University transmission line for $165
million; Douglas-Teeland transmission line for $63 million; Lake
Lorraine-Douglas transmission line for $80 million; static-var
compensators (SVCs); Southern Intertie study for $1 million.
Also included is a battery energy storage system (BESS) which is
a generic program to address the issue of frequency regulation.
4:00:23 PM
MR. HARPER presented slide 6 that illustrated the 8 percent
impact of DSM/EE programs on the required energy load. Slide 7
showed the wholesale cost of power, in 2010 dollars, for
selected scenarios. He pointed out there are two sensitivity
cases that have power costs less than the preferred resource
plan 1A/1B. The first is the scenario that assumes there are no
CO2 taxes; however, future CO2 taxes are included in the base-
case. Mr. Harper advised that three years from now, the state
will have a better sense of whether there will be CO2 federal
legislation and the costs thereof. The other sensitivity case
doubles the impact of DSM/EE on the energy load. Also shown on
slide 7 was the sensitivity case with the cost of power using
Susitna hydro instead of Chakachamna hydro; therefore, in 2025,
under traditional utility ratemaking practices, there is a jump
in the cost at the point Susitna comes on-line. Slide 8, he
said, was the "capital gap slide." In conjunction with the
report, AEA hired Seattle-Northwest Securities Corporation (SNW)
to look at the ability of the current Railbelt utilities to
finance future capital infrastructure, and to mitigate the rate
impact thereof. The graph showed that the remaining high and
low debt capacity of all of the six utilities together is $2-$4
billion. Also illustrated were the cumulative capital
expenditures of the preferred resource plan that reach about $9
billion in 2059. Therefore, the capital gap is a difference of
about $5 million that according to SNW, the six utilities cannot
finance independently.
4:06:21 PM
MR. HARPER presented slide 9 that was a comparison of costs
between plan 1A/1B and plan 1A/1B with committed units. He
described committed units as projects that are currently being
planned or developed by the utilities, but that were not
selected as regional resource projects, such as Healy Clean Coal
and the Southcentral power plant. Mr. Harper explained that the
utilities are moving forward with these projects because of the
uncertainty about the formation of GRETC, or another regional
entity. Although the chart shows a difference about $450
million, the report concludes that the difference would be
greater, because the independent utilities would not see the
impact of the 8 percent DSM/EE. Moreover, the independent
utilities may not be able to finance the needed $1.6 million
build-out to the transmission system. Finally, slide 10 showed
the results of SNW's financial analysis on alternative financing
available to the utilities. He reiterated that the utilities
cannot "finance the future on their own." However, the base-
case used standard capital market financing on all of the
projects thus SNW considered the following alternatives:
collection of a one cent per kilowatt ratepayer benefit
surcharge; "pay-go" financing; construction work in progress
(CWIP) financing; state financial assistance such as a $2.4
billion zero-interest loan. He emphasized that SNW is not
advocating for any of these alternatives. Mr. Harper then
called attention to the results of the analysis: a base-case
maximum rate of thirteen cents per kWh and average rate seven
cents per kWh; an alternative case maximum rate of eight cents
per kWh and average rate six cents per kWh. He stressed that
these numbers represent the incremental cost associated with the
capital of the projects only. Also, although the average rates
are almost the same, the big difference in the maximum rate is
tied to the cost of the Susitna hydro project in 2025. Mr.
Harper concluded that there are options that allow the cost of
the $9.1 billion capital program to be spread out along
generations.
4:12:47 PM
REPRESENTATIVE GATTO expressed his concern about ratepayers
paying a one cent surcharge for years without receiving any
benefit.
4:13:22 PM
MR. HARPER said the surcharge and CWIP would have ratepayers
begin to pay before the project is running.
REPRESENTATIVE GATTO asked whether those who are charged without
benefit could be reimbursed.
4:14:20 PM
MR. HARPER said that is a policy call.
REPRESENTATIVE GATTO asked where nuclear power fits in the plan.
4:14:56 PM
MR. HARPER acknowledged that nuclear power was considered as a
small modular option, but was not chosen as a resource for the
future, based on economics.
4:15:28 PM
REPRESENTATIVE GATTO heard that nuclear would cost less than
eight cents per kWh, and has the other benefits of clean air, no
CO2 capture, continuing base-load, and long life. He asked
whether Black & Veatch decided to eliminate nuclear power from
the study.
4:16:18 PM
MR. HARPER explained that there are two types of nuclear
options, conventional and new technology. Conventional nuclear
plants are too large for the Railbelt region. The newer
technologies are promising, but are not commercially available
based on cost estimates. He opined "it is a technology that's
worth considering in the future, but it is not commercially
economical, in our view."
4:17:13 PM
REPRESENTATIVE JOHNSON referred to slide 4 and asked for
clarification on the process.
4:18:04 PM
MR. HARPER explained that the preferred resources were chosen
based on the output of two specific models, both of which are
based on economic selection. One model determined which
resources are the best to build, and the other determined how
much is used of each resource. Both models are based upon
assumptions with regard to capital, operating, and fuel costs
for the different technologies.
4:18:32 PM
REPRESENTATIVE JOHNSON re-stated his question regarding when the
estimated cost of power becomes part of the model.
4:18:53 PM
MR. HARPER said the five cent and seventeen cent estimates are
calculations of what the total average wholesale cost of the
entire resource plan is, based upon which resources are chosen,
and how much the resources are used. That modeling comes from
capital, operating, and fuel cost assumptions for each of the
technologies. Therefore, the selection of resources was based
upon many detailed economic assumptions for each technology.
From there, came the calculation of the overall average cost of
power, for example, the five cent and seventeen cent estimates.
Mr. Harper said, "... this list says, that based upon the input
assumptions that we use for all of the technologies, these are
the most cost-effective resources to bring on in the first ten
years of the plan."
4:20:07 PM
REPRESENTATIVE JOHNSON referred to slide 7, and asked for an
explanation of the cost of the first year of Susitna, and the
reduction of that cost after only one year.
4:20:27 PM
MR. HARPER advised that the curve in the cost for the Susitna
project is the result of traditional ratemaking methodology in
that ratepayers are not charged until a project is generating
power. Therefore, in the initial year, there is a jump in the
cost due to depreciation. Furthermore, a large hydro project
such as Susitna has high up-front capital costs, and low ongoing
costs. Regarding the selection of the resources, the model was
based on 50 years, with a fixed-charge rate, and based upon the
life of the technology. For example, for natural gas, the
fixed-charge rate was based on 30 years, and for large hydro,
the fixed-charge rate was based on 100 years; thus the capital
costs are recovered within the appropriate time period. This
led to the selection of Chakachamna, because the project was not
as large as Susitna, but still has a 100-year period of recovery
of capital in the economic analysis.
4:23:09 PM
REPRESENTATIVE JOHNSON asked for an explanation of the recovery
term.
4:23:20 PM
MR. HARPER responded that the cost associated with capital is
based on the life of the project. Therefore, the economics of
Susitna and Chakachamna are based upon a 100-year recovery of
capital cost. The modeling horizon was 50 years, and the model
factors in the value of projects that extend beyond 50 years.
4:24:14 PM
REPRESENTATIVE JOHNSON observed this may be a comparison of
apples and oranges.
4:24:35 PM
MR. HARPER opined there would not be a material change in
resources selected for a model of 50 or 100 years.
4:25:07 PM
REPRESENTATIVE JOHNSON asked whether a model has been run based
on a 1984 construction of Susitna.
4:25:42 PM
MR. HARPER said no. However, 2008 actual results from the
individual utilities were used.
4:28:12 PM
CO-CHAIR EDGMON asked about the cost to update the model every
three to five years.
4:28:19 PM
MR. HARPER observed that the model is not proprietary to Black &
Veatch, and new files could be run for a fraction of the cost by
the utilities, consultants, or GRETC, if staff is available.
4:29:07 PM
REPRESENTATIVE RAMRAS asked for the cost of the report. He also
asked for additional testimony at a later date addressing the
deliverability and cost of natural gas during the first five
years.
4:29:46 PM
REPRESENTATIVE JOHNSON assumed the model was created at a time
of extraordinary high costs of steel and labor.
4:30:06 PM
MR. HARPER assured the committee the report was not based at the
peak of prices; however, a decline in prices will result in a
lower total cost, but would not necessarily have a material
effect on the choice of resources.
4:31:10 PM
REPRESENTATIVE JOHNSON asked whether the change in prices would
cause projects to be added or removed from the list.
4:31:39 PM
MR. HARPER said he was unsure. He guessed that projects
selected for the first 10 years would not change much.
4:32:23 PM
REPRESENTATIVE JOHNSON asked whether there are projects that are
right at the line.
MR. HARPER said he was unsure without further study.
4:32:55 PM
REPRESENTATIVE JOHNSON encouraged additional research into
projects that "were on the bubble."
4:33:17 PM
CO-CHAIR MILLETT read the seven questions posed to the invited
presenters [original punctuation provided]:
1) Project timeline-completion date and the date power
will be turned on:
2) Total cost of project and funding request (state
revenue):
3) Transmission needs to grid - who pays?:
4) Cost of power to consumer (KWH):
5) Amount of power supplied to railbelt:
6) Likelihood of completion:
7) Permitting roadblocks-Environmental challenges:
4:34:20 PM
MR. STRANDBERG said he was representing AEA on the Susitna
Hydroelectric (Hydro) Power Project. He pointed out that AEA
was participating not as a project advocate, but as a project
custodian. Mr. Strandberg reminded the committee that in the
'80s, $132 million was expended to develop the Susitna Hydro
Power Project culminating in a Federal Energy Regulatory
Commission (FERC) permit application. Although the project was
halted by the legislature in 1986, remaining from the earlier
study are conceptual designs, records, and records of extensive
field work for environmental and geotechnical conditions in the
Susitna basin. He noted that the work undertaken in the last
two years has been to understand the body of the previous work,
and from that AEA has developed a project concept and cost
estimate that is right-sized for the needs of the Railbelt for
the next 50 years.
4:36:28 PM
MR. STRANDBERG related that AEA has found the work done on the
project in the '80s to be "durable and sound, and worthy of use
as we, at the direction of the legislature, review this
project." He noted that the Susitna Hydro Project is a high
first-cost project, with significant power availability benefits
and expansion capability. Relatively speaking, the project has
low development risk. Mr. Strandberg also noted that the work
done on the project was coordinated with the RIRP contractor,
thus the parties used the demand curve over the 50-year period
to look at the potential sizes of the projects proposed.
4:39:31 PM
BOB BUTERA, Civil Engineer, HDR Alaska, informed the committee
HDR Alaska was contracted about two years ago to AEA to look at
the Susitna hydro project. The first phase of the study began
before the RIRP study, and his firm looked at the original
project proposed in the '80s and reevaluated the cost estimate
of $5 billion. Mr. Butera noted the new study also included an
additional 20 years of stream flow records. At the time of the
RIRP process, HDR Alaska worked with Black & Veatch and AEA.
The project is located about midway between the Southcentral and
Fairbanks regions of Alaska, and would service all of the
utilities in the Railbelt. Slide 4 was a map that illustrated
three potential dam sites on the Susitna River: Watana Dam;
Devil Canyon Dam; High Devil Canyon Dam. Slide 5 showed eight
alternative projects for the river.
4:42:52 PM
MR. BUTERA presented slide 6 which was a chart summarizing the
results of the study on the following factors: alternative; dam
type; ultimate capacity of megawatts; construction cost in
billions of dollars; energy generated in gigawatts per hour per
year; schedule in years from the start of licensing. The Low
Watana Expandable project was the option selected; in fact, it
is basically the same project that was proposed in the mid '80s.
The project has a rock fill dam, a 600 megawatt capacity, and a
construction cost of just under $5 billion in today's dollars.
Slide 9 listed the following conclusions about the Susitna
project: of the renewable resources it is the most studied and
best understood; the project is considered to be technically
feasible even when compared with new technology; there is
potential to expand in stages and meet future loads; large hydro
provides an energy source to stabilize the grid; environmental
risks can be resolved, for example all of the projects are
upstream of the passage of anadromous fish due to the Devil
Canyon rapids; seismic risk is manageable through design; it is
a long-term and stable source of power.
4:47:19 PM
REPRESENTATIVE GATTO observed that the river has a lot of silt.
He expressed his concern about the accumulation of silt in the
river, and potential damage to the turbines.
4:48:15 PM
MR. BUTERA said those issues were studied in the 1980's and the
conclusion was that the heavy silt will drop out at the head of
the reservoir, and the small fines will reach the turbines; in
fact, the storage of a reservoir is divided into active and dead
storage, and the study estimated that less than 10 percent of
the dead storage would be filled by silt in 100 years.
4:49:16 PM
MR. BUTERA then responded to the committee's questions. The
project timeline is 15 years from the start of licensing,
assuming there is no major litigation. The total cost of the
Low Watana Expandable Dam project is just under $5 billion. The
project cost includes transmission to the grid at the existing
power line from Anchorage to Fairbanks, and this power line
would be upgraded by a separate project. The cost of power to
consumers [is fifteen cents per kWh]. The amount of power
supplied to the Railbelt is 2,600 gigawatt hours per year, which
is about 40 percent of the current load. There is a high
likelihood of completion. The next steps are to look at the
design, and concurrently engage stakeholders, agencies, fish and
wildlife [agencies], and communities. Mr. Butera concluded that
the project must bring forward all of the work that was done in
1985, and look for new issues. This would be done by a
"resource workgroup" working separately from the FERC process in
order to understand the issues prior to the FERC application.
4:52:45 PM
REPRESENTATIVE JOHNSON asked whether financing was considered.
4:52:52 PM
MR. BUTERA said the study of financing was done through the
RIRP.
REPRESENTATIVE JOHNSON asked whether the cost of carbon credits
was included in the estimated power cost to consumers.
4:53:24 PM
MR. STRANDBERG said the cost is the "basic wholesale levelized
... power rate assuming 2,600 gigawatt hours of power produced
over the year and the total construction cost, and it basically
assumes a financing approach which ... is similar to the Bradley
Lake model."
4:53:42 PM
REPRESENTATIVE JOHNSON referred to the "advantages, in terms of
carbon, that hydro delivers." He asked whether there is an
allowance for using carbon credits as a bonding mechanism to
finance hydro projects.
4:54:42 PM
MR. STRANDBERG advised that the study did not go that far; in
fact, there was an effort to keep the comparisons "apples to
apples." An answer to Representative Johnson's question will be
provided.
4:55:35 PM
REPRESENTATIVE JOHNSON expressed his understanding that the
capital cost of a coal fired plant was figured without any
consideration of upcoming carbon issues.
4:55:51 PM
MR. STRANDBERG explained that the integrated plan assumed a CO2
tax for all fossil fuels; however, there was no tax assumed for
the renewable energy projects. Furthermore, the base-line
analysis included CO2 and carbon taxes for all of the fossil
fuel projects. The study looked at the possibility of no carbon
tax in a sensitivity analysis, and in the data one can see the
effect of a carbon tax on the cost of power.
4:56:36 PM
REPRESENTATIVE JOHNSON requested an opportunity to further
explore this issue.
4:56:57 PM
ERIC YOULD, Program Director, Chakachamna Hydropower Project,
TDX Power, Inc., informed the committee TDX Power is the
electric utility that holds a FERC permit for the assessment and
development of the Chakachamna Hydropower Project. The
Chakachamna Hydropower Project was originally considered in the
late 1940's by the Department of Interior|Bureau of Reclamation
and by the U.S. Army Corps of Engineers in the late 1970's. The
project was then considered by the Alaska Power Authority as an
alternative to the Susitna dam project, along with Bradley Lake
and other power generation projects. At that time, it was
determined that Chakachamna and Bradley Lake were worthy
projects; however, Bradley Lake was already authorized by the
federal government, thus Chakachamna was put on the shelf,
although it was as economically desirable as Susitna. Mr. Yould
explained that this project is a high head lake with a tap, and
a power tunnel that brings water to a power plant at a lower
elevation. The elevation at Chakachamna Lake is about 1,000
feet, and the project would tap the lake and bring the water
through a 12-mile power tunnel to the underground powerhouse in
the MacArthur drainage basin, thus developing 300 megawatts of
power that is equal to about 25 percent of the use in the
Railbelt today. The cost of the project is $1.7 billion in
today's dollars. Originally the project included a dam;
however, the present project uses the lake as a reservoir
without the construction of a dam. The powerhouse would be
located 40 miles from the transmission line at the existing
Chugach Electric Beluga substation. Mr. Yould displayed a map
showing the Beluga substation, the natural gas transmission line
under Cook Inlet to Anchorage, and the plan of development for
the Chakachamna project. He noted that the project would divert
about 80 percent of the water flowing into the Chakachamna Lake,
which is a major environmental issue that must be investigated.
5:06:06 PM
MR. YOULD displayed a schematic figure of the intake and gate
shaft section, and further described the lake tap and power
tunnel. He pointed out that this technique has been done in
Alaska at the Snettisham hydro dam, the Lake Tyee hydro plant,
the Lake Dorothy hydro plant, and the Eklutna hydro power plant.
The surface elevation of the lake would be drawn down to about
80 feet to accommodate winter power generation, and in the
spring the lake would fill and stay full all summer. He
displayed a plan of the powerhouse. In the winter, to ensure
downstream flow and the successful migration of fish, there
would be a two-mile long fish passage tunnel, but in the summer
normal fisheries migration should continue without artificial
means. On the issue of land ownership, he noted that most of
the land around Chakachamna Lake and river is state land, except
for Lake Clark National Park, and the transmission lines will
cross over a portion of land owned by Cook Inlet Region, Inc.,
(CIRI).
5:09:59 PM
MR. YOULD further addressed the fish migration issue. There is
a fish run up the Chakachamna drainage basin, and a 1982 study
indicated 78,000 sockeye salmon entered the basin. He expressed
confidence that this migration would be protected. Regarding
wildlife in the area, there are 56 species of birds and 16
species of mammals, and although none are on the endangered
species list, the potential impact to the Beluga whale in Cook
Inlet may become a factor. Geotechnical considerations in the
area are the Castle Mountain fault, the Mount Spurr volcano, and
the possible movement of four glaciers. He showed slides of the
topography of the site of the vertical shaft and gated structure
at the outlet of the lake, and the site of the McArthur
powerhouse. Mr. Yould turned to the subject of development
costs and stated that TDX Power has spent about $2.5 million
over the last three years. In addition, he estimated that a
total of $30 million is needed to complete the permitting
process over a period of five years, including additional
fisheries work. Beyond that, construction costs are estimated
to be $1.7 billion, including $90 million for the transmission
line. Mr. Yould concluded that using the AEA model-a 50-year
assessment and 5 percent money, no equity, and set operational
costs-the cost of power was in the range of six cents to eight
cents per kWh. However, using expected higher costs of money,
operations, and management, a more realistic estimate is nine
cents per kWh. He opined that a net present worth levelized
cost of power for Chakachamna is less than Susitna. The
schedule for the project is as follows: five years for
preliminary permits and the FERC licensing; forty-eight to
fifty-four months for project construction; power on-line in
2019.
5:16:08 PM
REPRESENTATIVE JOHNSON asked for details about the 2006 FERC
permit.
5:16:29 PM
MR. YOULD responded that in 2006, FERC issued a preliminary
permit for a three-year exclusive right to assess the project.
Although that permit expired in 11/09, TDX recently applied for
and received a second permit for another three years.
5:16:57 PM
REPRESENTATIVE RAMRAS recognized Mr. Swenson for his work in
geothermal energy.
5:18:08 PM
BOB SWENSON, Project Manager, Alaska In-State Gas Pipeline
Project, Department of Natural Resources (DNR), said he accepted
the project manager position in 1/10 and expressed his
excitement about the project. Mr. Swenson advised that although
this project is not far enough along in the process of cost
estimation to have all of the answers to the committee's
questions, all of the information will be provided as soon as
possible, perhaps in May or June. He presented slide 2 which
illustrated that the historical production of natural gas in the
Cook Inlet levels off in the period between 2011 and 2012. Also
shown are possible reserves based on analyses, well logs, and
seismic data. Slide 3 showed the historical daily gas usage for
power and heating in Southcentral. The demand for power ranged
between approximately 370 million cubic feet per day (MMcf/d) in
winter and 110 MMcf/d per day in summer. It is important to
know that spikes in demand are a problem for producers and
consumers, as it is very expensive to provide for deliverability
all year when demand is fluctuating. In the late 1960's, an
industrial infrastructure was developed to utilize the gas
throughout the year and industry provided the basin with
relatively inexpensive gas for many years. He mentioned his
experience in resource assessments and displayed slide 4 which
illustrated thirty-five trillion cubic feet (TCF) of natural gas
reserves in the North Slope region, and two TCF of natural gas
available in Cook Inlet, as of 2005. Slide 5 illustrated known
gas reserves in the Prudhoe and Kuparuk regions, and many other
possible gas reserves in the "gas-rich basin."
5:23:59 PM
REPRESENTATIVE RAMRAS observed that Anadarko Petroleum
Corporation (Anadarko) has suspended drilling in the Gubik area.
5:24:23 PM
MR. SWENSON clarified that Anadarko is evaluating data acquired
from wells recently drilled. Slide 6 illustrated undiscovered
conventional gas potential of 119 TCF in the National Petroleum
Reserve in Alaska (NPRA) and other large potential areas
offshore. Slide 7 illustrated potential gas hydrates in the
North Slope area that could be up to 85 TCF. Mr. Swenson spoke
of resource activity in sub-permafrost hydrates and shale gas.
5:26:34 PM
REPRESENTATIVE RAMRAS asked who is participating in the resource
activity.
5:26:47 PM
MR. SWENSON answered Alaskans and the U.S. Geological Survey,
along with the state. Mr. Swenson stressed the importance of
infrastructure to the development of potential resources, and
the small diameter gas pipeline would be part of that
infrastructure. Slide 8 showed potential pipeline routes for a
24-inch diameter pipeline from the North Slope to Cook Inlet.
He noted that the information presented is part of the work
performed in the previous fiscal year, including a study of the
Richardson Highway and Parks Highway spur routes, stand-alone
routes, and pre-build. Slide 9 listed the purpose of the
state's effort as follows: evaluate a stand-alone gas pipeline
project that transports gas from the North Slope to tidewater in
the Cook Inlet, with off-takes points for Fairbanks and resource
development; provide a back-up plan for the large diameter gas
line with spur lines to Southcentral for in-state use; reduce
risk to potential project by acquiring major permits, determine
cost of transport and economic feasibility; prepare permit and
project data package to transfer project to pipeline developer.
Mr. Swenson further explained that the methodology of the
project is to reduce risk by defining costs, acquiring major
permits, and acquiring letters of intent to bring buyers and
sellers together and to let the marketplace decide the scope and
timing. He related that the work completed includes alternative
route analysis, the initial project description for permitting,
the commercial group scoping document, the initial review of
ENSTAR Natural Gas Company Capital Cost Estimate - Pipeline, and
that all major permits have been applied for. The work underway
includes updating pipeline cost estimates, developing cost of
facilities and the cost of transport analysis, preparing
detailed project descriptions, continued engineering support for
the environmental impact studies (EIS) and rights-of-way (ROW)
processes, identifying commercial entities to finalize costing
and permitting for construction sanction, developing data
package for full economic analysis, and working with the
producer group and identifying new market potential.
5:31:51 PM
MR. SWENSON turned to the subject of facilities scenarios, and
advised that one early option for the in-state gas pipeline was
a line through the Gubic field. That option has now been
identified as an alternate route, rather than the primary
option. The focus now is on gas from the Prudhoe Bay Unit,
under four scenarios. The chemistry of the gas from the
Foothills area is similar to Cook Inlet gas in that it is a
methane gas and is dry and very clean, and is "pipeline ready
essentially." Alternatively, the North Slope gas will require
significant conditioning thus the project is looking at four
different configurations of pipe that vary with gas handling
facilities and gas cleaning facilities at the North Slope, or at
Cook Inlet, as well as pulling untreated gas with stabilizers
down the pipe. Mr. Swenson stressed that the facilities are
very important in order to understand the different options and
the associated costs. In addition, each scenario is evaluated
at 250, 500, 750, and 1000 MMcf/d, thus the study will evaluate
16 different scenarios simultaneously. In response to a
question from Representative Tuck, he said all of the scenarios
take North Slope gas from the Prudhoe Bay Unit reserves.
5:34:17 PM
CO-CHAIR MILLETT asked whether the in-state gas pipeline study
would include scenarios "way out of the AGIA requirement of
nothing more than half a Bcf [transported] a day."
5:34:52 PM
MR. SWENSON clarified that the study looks at each scenario to
see the volumes and the economics associated with each of the
volumes. This is a back-up plan to the AGIA process; in fact,
in the alternate analysis, it is clear the cost of the pipeline
as a spur line is less than a stand-alone pipeline, however,
there is a risk associated with the completion of AGIA.
Therefore, Mr. Swenson stressed that even the 750 MMcf/d and 1
billion cubic feet per day (Bcf/d) evaluations must be
considered in case the spur line does not work. He acknowledged
that if a pipeline is built with AGIA, and the in-state line is
completed first, there will be a penalty for gas over 500
MMcf/d.
5:36:09 PM
CO-CHAIR MILLETT asked how long the project would wait on the
AGIA process.
5:36:32 PM
MR. SWENSON expressed his understanding that the current
timeline shows the sanctioning date is 2014, following the first
and second open season.
5:36:55 PM
CO-CHAIR MILLETT assumed the administration would wait to go
forward on the in-state gas line until 2014.
5:37:08 PM
MR. SWENSON advised that the project will not wait at this time;
however, if either AGIA or Denali - The Alaska Gas Pipeline,
looks like it will be completed, this project slows down. He
assured the committee this project will continue to "get the
package, make the deal with the development companies and the
North Slope producers and the Cook Inlet marketplace."
CO-CHAIR MILLETT observed that the state will not be making a
decision on an in-state gas line for two years, and completion
is nine years away.
5:38:52 PM
MR. SWENSON recommended looking at the cheapest way to transport
gas from the North Slope to the Cook Inlet and points along the
route. Therefore, right now the state must gather information
and build models to decide what the costs will be. He opined
the sanctioning points of the pipeline are the "end member of
the decision process."
5:40:12 PM
CO-CHAIR MILLETT questioned whether the in-state gas line is
really a priority for the administration.
5:41:03 PM
MR. SWENSON explained that the initial cost estimates will be
done in July and the cost of service models will determine
tariffs and the cost of natural gas in the basin. In July 2011,
the project will be at the final stages of the EIS process. At
that time decisions will be made on whether to continue in
concert with the AGIA process or not. He opined the cost
estimates are an important point of this decision.
5:42:32 PM
REPRESENTATIVE RAMRAS expressed his respect for Mr. Swanson. He
stated he has concerns about Black & Veatch detailing the
importation of LNG in its 50-year plan, and that the committee
has glossed over this point. He noted his desire for his
community of Fairbanks, and all of the residents along the Yukon
River, to migrate from diesel to gas, liquids, or propane as
soon as possible. Representative Ramras commented on the House
Finance Committee's removal of state money to fund the in-state
gas pipeline. He remarked:
DNR is setting [Mr. Swenson] up in a very peculiar,
impossible situation. For many of us AGIA is going to
fail when we come out of July 31 with a heavily
conditioned open season ... and in the meantime the
price of oil closed at $82 a barrel ... for that part
of the state that is on an ever dwindling supply of
natural gas, for those of us that are on diesel ...
it's just part of a misery index ... and that doesn't
even begin to consider our friends that live in rural
Alaska ...
REPRESENTATIVE RAMRAS encouraged Mr. Swenson to realize that the
state needs natural gas now, and to have the project ready to go
in October 2010. He said:
And keep those guys at Black & Veatch out of your
workroom, because they are just a hack job for DNR ...
I watched them do it ... they should not have any
access to our work products until Baker Engineering
has delivered its work product to the legislature in
June or July of this year.
5:46:56 PM
REPRESENTATIVE TUCK asked if the pre-build alternatives will
begin in Cook Inlet and head north.
5:47:32 PM
MR. SWENSON said yes. He expressed his understanding that
either the Richardson Highway or Parks Highway pipeline would be
pre-built from Cook Inlet to meet the large diameter pipeline on
its way to Alberta or Valdez. Prior to the opening of the large
diameter line, if there is a market and there are producers in
the Cook Inlet, the pre-built pipeline would supply gas into the
Fairbanks region.
5:48:04 PM
MR. SWENSON directed his comments to Representative Ramras. He
opined that the present time is similar to the 1960's in Cook
Inlet, when the current marketplace could not support the supply
of gas; however, although all of the options must be carefully
considered, he agreed that time is of the essence. He said his
orders, both from the legislature and the administration, are to
proceed as quickly as possible. Mr. Swenson said the best
engineers in Arctic pipeline design and building are working
incredibly hard on the project.
REPRESENTATIVE JOHANSEN referred to slide 12, which listed work
underway, and noted one task was to identify new market
potential. He acknowledged that the report covered permits and
the source of gas, but asked when the committee will find out
about new markets and tenants that will help pay the tariffs for
the pipeline.
5:51:47 PM
MR. SWENSON answered that new market potential is based on what
can be done in the basin to increase the market, such as a gas
to liquids (GTL) proposal and Agrium, Inc. He advised that this
task will be worked on though FY 11; in fact, there will be a
meeting with commercial groups to bring up the issues of the in-
state gas market in the Cook Inlet region. He agreed that the
per unit volumes of gas in any pipeline are very important for
the cost-of-service analysis. Mr. Swenson anticipated
discussion of how the state can encourage, and possibility
incentivize, the development of large consumers in the basin in
order to benefit those living in the Railbelt and on any
distribution system.
5:54:03 PM
REPRESENTATIVE JOHANSEN re-stated his interest in the source of
a sufficient market.
CO-CHAIR EDGMON observed that the project needs a private entity
to build the pipeline, a demand for gas, and a supply of gas.
He asked whether the state abandoning the AGIA effort and
focusing on the in-state line, would push the project along.
5:55:27 PM
MR. SWENSON said he did not believe the answer was to abandon
AGIA; however, more funds could be directed toward encouraging
industry into the basin. The current plan is to put the package
together with the permits, preliminary engineering, and cost
estimates, and encourage private development of the project. If
not, the state will have to make sure that gas is available to
the Railbelt region through incentivizing development, or by
owning part of the pipeline. A significant portion of the
information necessary for the policymakers to make this decision
will be available on July 1.
5:57:08 PM
REPRESENTATIVE RAMRAS asked how often Mr. Swenson was in touch
with Tom Irwin, Marty Rutherford, and Gene Therriault.
5:57:27 PM
MR. SWENSON answered that he talks with one of them once each
week. He assured the committee of their support and provided an
example of DNR's support.
5:59:04 PM
MR. SWENSON displayed slide 15 that listed the status of three
permits. Slide 16 showed the current state share of the project
was $8.3 million for FY 10, and that $6.5 million is requested
for FY 11. Also, there will be a negotiated agreement with
ENSTAR for the use of its data. All of the expenses are to be
reimbursed upon transfer to a commercial entity. Regarding the
project timeline, the target is 2016, providing there are no
legal challenges or problems with facilities and ordering
equipment.
6:00:54 PM
REPRESENTATIVE PETERSEN recalled that the chance of obtaining a
permit to export gas from Alaska is "close to nil." He asked
how this would affect the volume of the gas pipeline.
6:01:25 PM
MR. SWENSON acknowledged that one of the issues with the
pipeline is the uncertainty about using the current LNG facility
in order to use its permit that is "grandfathered in." He said
he plans to talk with ConocoPhillips Alaska, Inc. Building a
new facility either in Cook Inlet or Valdez will take time; in
either case, the question of exporting natural gas to a foreign
country must be addressed.
6:02:46 PM
CO-CHAIR MILLETT asked why there are two state agencies, the
Alaska Natural Gas Development Authority (ANGDA), and the In-
State Gas Pipeline Project, working toward the same goal, and
whether they are sharing information or duplicating work.
6:03:06 PM
MR. SWENSON explained that he is working closely with ANGDA to
be sure there is no duplication of effort. ANGDA is primarily
focused on the spur lines and the line to Valdez off of the
large diameter pipeline, with a spur route from Glennallen into
the basin area. This project is focused on the stand-alone
pipeline up the Parks Highway.
6:04:22 PM
REPRESENTATIVE JOHANSEN asked whether the timeline incorporates
the construction of industry that will consume the gas.
MR. SWENSON pointed out that on slide 19 other facilities are
listed under "Project Review & Sanction." In further response,
he said that was in 2011 and 2012.
6:06:45 PM
REPRESENTATIVE JOHANSEN assumed that was the time other
companies will look at building gas conditioning plants or new
Alaskan industry and investment.
6:07:16 PM
MR. SWENSON indicated yes.
6:08:17 PM
ETHAN SCHUTT, Vice President, Land and Energy, Cook Inlet Region
Inc. (CIRI), informed the committee Fire Island is located about
three miles offshore of Anchorage. The wind project on the
island consists of 36 1.5 megawatt GE wind turbine generators
with a total nameplate capacity of 54 megawatts. The project
has an approximate 33 percent capacity factor and the
transmission interconnect is a 34.5 kilovolt (kV) dual
transmission line to Chugach Electric's station on International
Road. He continued to explain that the project will displace
1.5 billion cubic feet (Bcf) of natural gas per year and will
meet the electrical demand for thousands of households. Slide 4
was a map of the project layout showing the locations of wind
turbines, roads, gathering lines, and the subsea portion of the
transmission line that connects to the grid. Mr. Schutt relayed
that the project has been considered by various entities in the
past; however, CIRI believes that now is the time to build
because the energy solutions for Southcentral are the same as
for the nation: a diversified mix of energy products using as
much domestic, renewable, and non-fuel as possible. He opined
this project is the best chance to put a significant amount of
non-fuel, new, electrical energy into the grid. He agreed with
previous testimony that Southcentral and the Railbelt face
imminent shortages of power. Coincidentally, the American
Recovery and Reinvestment Act of 2009 provides federal financial
incentives to renewable projects that are developed by private
taxpaying entities, such as CIRI. In fact, federal funds will
pay an incentive of about 30 percent of the capital costs of the
Fire Island Wind project, and CIRI is committed to credit 100
percent of the federal dollars to the cost of the project thus
ultimately benefitting ratepayers. He pointed out that the
incentive funding also requires a stringent timeline for
completion of the project. Project milestones for 2009 include:
micrositing studies for the turbines, clearing, geotech for
roads, borings at each turbine location, and substantial
infrastructure. Slide 10 was the critical path timeline:
11/2009, fieldwork completed; 12/2009, geotech results; 3/2010,
35 percent design completion; 5/2010,
integration/interconnection agreement; 6/2010, execute power
purchase agreements. He noted that over 5 percent of the
federal funding must be spent in 2010 to qualify, so CIRI will
be constructing roads and preparing turbine sites. Tower
erection, the installation and commission of the transmission
line, and commercial operations are planned for the fourth
quarter of 2011.
6:14:08 PM
CO-CHAIR MILLETT passed the gavel to Representative Johansen.
6:15:43 PM
REPRESENTATIVE PETERSEN asked whether the towers are similar to
those in Kodiak.
REPRESENTATIVE JOHANSEN returned the gavel to Co-Chair Millett.
6:16:07 PM
MR. SCHUTT indicated yes. The machines are very large,
industrial machines installed on 80 meter towers. He then
turned to the underground coal gasification (UCG) project that
is designed to produce an alternative power source by 2014. The
project is an underground coal gasification facility that will
produce synthesis gas (Syngas) sized to fuel a new 100 megawatt
combined-cycle power plant. Syngas can be used to generate
electricity and is an ideal feedstock for chemical manufacturing
processes such as upgrading to natural gas through methanation,
and Fischer-Tropsch synthetic liquid fuels. Slide 14 was a map
showing the location of the project area that is on the west of
Cook Inlet and northwest of the Beluga Power Plant and gas
field. The UCG project area is roughly 24 square miles and is
connected to existing infrastructure by road, but is not
connected to Anchorage or the Mat-Su valley by road. Mr. Schutt
indicated that transmission interconnect is not much of a hurdle
for the project because of the power plant at Beluga. He
presented slides of drill rig work on the project. Slide 19
listed four reasons CIRI is pursuing the project: (1) committed
to a diversified source of energy; (2) believes the technology
is on the verge of commercialization in North America; (3)
believes the technology provides an environmentally responsible
way to harness coal energy; (4) believes the technology provides
a long-term supply of energy from a domestic resource at a
reasonable price.
6:19:12 PM
REPRESENTATIVE RAMRAS observed that the state should pursue in-
state gas with the same purposes.
6:20:34 PM
MR. SCHUTT explained that CIRI believes it can make a fair
profit from providing reasonably priced energy to the domestic
market; in fact, the profit motive is not to be impugned. Slide
20 displayed the current timeline for the project. At the
present time, the first resource assessment hole is being
drilled, and core samples are being collected. This is the
first of six holes that will be drilled in the next six weeks
for data on geology and coal resource. After that, the next
round of drilling will be at a specific site for site
characterization and project permit applications. At the same
time, CIRI will undertake early-phase commercial negotiations
with partners, investors, and off-takers. An advantage of
producing Syngas is that it has many market opportunities, such
as feedstock for Agrium, Inc.; as a matter of fact Agrium can
also use the CO2 that is produced as a by-product of coal
gasification. Finally, commercial operations for the project
are scheduled for early 2014.
6:24:04 PM
CO-CHAIR MILLETT asked whether there are other locations in the
United States where this technology is being advanced.
6:24:15 PM
MR. SCHUTT responded that two projects have been announced for
the Powder River basin in Wyoming, and there are three projects
in Alberta, Canada. At this point, these are small research and
development projects built with public money and grants.
However, CIRI believes the technology is ready for commercial
development.
6:25:33 PM
MR. SCHUTT displayed slide 21 that listed the development
challenges to the project. The first challenge is that of
carbon management, assuming there will be a carbon incentive or
carbon tax. CIRI is committed to carbon management, even though
carbon management is in the early phases of policy and
technological development. The second challenge is that UCG is
in an undefined regulatory regime, although CIRI has a good
working relationship with DNR which is the primary permitting
agency. Finally, because the technology has not been
commercially deployed, financing structures will involve venture
equity investors comfortable with risk, or loans from the U.S.
Department of Energy (DOE). Opportunities for the project
include access to previously inaccessible resources, and power
plant emissions comparable to those from natural gas. In
addition, the project has the potential to increase by 300-400
percent recoverable coal reserves on land owned by CIRI.
Finally, the technology utilizes a modular-system design easily
expanded to accommodate additional production volumes.
6:29:18 PM
MR. SCHUTT displayed slide 23 that showed CIRI land interests of
joint ownership, surface interest, and subsurface interest in
the Beluga coal field area. To the committee's question of the
price of delivered energy, he did not say what the price of Fire
Island electricity will be because CIRI is entering commercial
negotiations with the Railbelt utilities. He opined the price
will be attractive to the utilities given that it will be for a
fixed, 20-year term. Mr. Schutt said he expects to produce
Syngas at a competitive price with current pricing on natural
gas from Cook Inlet on an energy equivalent basis. He concluded
that the project is not requesting any financial support from
the state at this point.
6:31:16 PM
REPRESENTATIVE JOHANSEN asked about in-state markets for UCG
products.
6:32:01 PM
MR. SCHUTT said the principal objective is to complete a
commercial scale, first phase of a UCG facility and power plant.
Ideally, the product will be produced with pricing attractive to
Agrium. Agrium is a natural market and only requires a pipeline
across Cook Inlet. Another product possible after further
capital investment is methane, which would be marketed to
ENSTAR.
6:34:31 PM
PAUL THOMSEN, Director, Policy & Business Development, Ormat
Technologies, Inc. (Ormat), informed the committee Ormat is the
largest developer of geothermal energy in the U.S., and owns and
operates 520 megawatts of geothermal generation worldwide,
mostly in the U.S. His firm has also supplied equipment for
1,300 megawatts of generation in 24 countries for geothermal
development. Ormat is a vertically integrated company that
designs and manufactures turbines, owns and operates power
plants and negotiates power purchase agreements, and provides
drilling and resource assessment in-house. Currently, his firm
is developing six projects in the U.S., and employs over one
thousand people. He displayed slide 5 that was a map showing
Ormat's geothermal locations in 71 countries. Mr. Thomsen
pointed out that Ormat began in Alaska in 1975 by supplying
remote power units to the Trans-Alaska Pipeline System (TAPS).
He explained that Ormat has developed projects from 250
kilowatts to up to 160 megawatts located on remote site such as
volcanic areas and Arctic environments. Slide 7 illustrated
Ormat's business in Alaska from 100 remote power units in 1975,
and the first geothermal unit tested at Manley Hot Springs in
1979. Slide 9 was a diagram of an air-cooled binary geothermal
power plant. Mr. Thomsen explained that hot water brought up
from the ground heats a secondary working fluid in a heat
exchanger, and the brine is reinjected into the ground. The
closed system does not allow evaporation, so there is no release
into the atmosphere. The working fluid, which is isopentane,
vaporizes, thus building up pressure to spin a turbo-expanding
turbine, and produce electricity. The working fluid is cooled
by air and recycled through to provide continuous power "whether
the sun is shining or the wind is blowing." The key attributes
of geothermal technology are a base-load capacity factor of 95
percent, and competitive costs with a long-term fixed contract.
Ormat has proven the technology by 10,000 megawatts deployed
worldwide. Further, this project insulates ratepayers from
volatile fossil fuel prices; in fact, there should be no
variation in the price of heat coming from the reservoir. The
closed loop system produces near zero emissions, and there is no
water consumption at an air-cooled facility. In addition, there
is minimal surface and visual impact as a typical plant covers
about five acres, and the well area can be reclaimed after
drilling and capping. During construction, many jobs are
available; however, operating jobs are limited to a few highly
paid positions at the site. Mr. Thomson displayed slide 12
which was a map showing Mount Spurr, the Beluga Power Plant,
Tyonek, Anchorage, and the land area leased to Ormat from the
state. The site of the power facility would be on the eastern
section of the leased area with wells sited throughout.
6:41:42 PM
MR. THOMSEN displayed slide 13 that illustrated the project
timeline, and noted that Ormat purchased the leases in 10/2008
for $3 million. Non-intrusive exploration work began in 2009,
and the drilling of slim holes and production wells will begin
in the summer of 2010, with full exploration drilling in 2011.
The goal is to have the project generating power by 2016. He
estimated the total cost of a 50 megawatt project to be $250-
$300 million. The funding requested to date was a matching
grant from the renewable energy grant program in the amount of
$1.9 million, which Ormat considers to be a commitment from AEA
to be a partner in the project. The project will also need
about 40 miles of transmission to reach the Beluga Power Plant.
Mr. Thomsen assumed the transmission infrastructure would be
built by a utility, or the state, given the proximity of other
projects. The cost of power to the utility is expected to be
eleven cents to fourteen cents per kWh depending on the royalty
rate on the leases and whether there are state incentives. With
no incentives and royalty rate of 10 percent on gross sales, a
power purchase agreement rate of about fourteen cents per kWh is
needed to make the project "pencil." It is estimated that the
reservoir will produce between 50 megawatts and 100 megawatts of
power which is equal to about 416 gigawatt hours per year.
6:46:03 PM
MR. THOMSEN turned to the subject of the project's likelihood of
completion. Looking at the technology, he said there was no
technology risk because Ormat has a track record for the
construction of geothermal power plants. Considering business,
he acknowledged the project needs to reduce the price in order
to execute a power purchase agreement; however, the utilities
are interested. Ormat considers the likelihood of adequate
resource to be moderate, due to insufficient data. There have
been no roadblocks or major challenges to permitting identified
so far. He concluded that through contact with the Railbelt
utilities and local participants, Ormat has received a great
deal of support for developing the project in order to supply an
alternative base-load energy resource to the Railbelt.
6:48:11 PM
REPRESENTATIVE RAMRAS asked for the temperature at Mount Spurr.
6:48:36 PM
MR. THOMSEN replied that the best temperature for the technology
is in the range of 300-500 degrees Fahrenheit. Because Mount
Spurr is a volcanic resource, Ormat expects to find sufficient
heat as the binary technology allows for the use of lower
temperatures.
6:49:45 PM
REPRESENTATIVE RAMRAS described the situation in the community
of Naknek.
6:50:10 PM
MR. THOMSEN observed that Ormat is always interested in selling
its technology to third parties. He opined that Ormat would be
interested in bidding for a project in Naknek when the community
is ready.
6:50:38 PM
REPRESENTATIVE RAMRAS encouraged Mr. Thomsen to schedule a site
visit.
6:51:55 PM
MR. THOMSEN said he and the senior geologist would be happy to
visit the site at Naknek.
6:52:31 PM
REPRESENTATIVE JOHANSEN asked whether Mr. Thomsen was familiar
with Bell Island.
6:53:02 PM
MR. THOMSEN said no.
REPRESENTATIVE JOHANSEN observed that Bell Island is directly
connected to an intertie system with the potential to connect to
a community with 85 percent unemployment. He also encouraged
site visits by Ormat.
MR. THOMSEN said Ormat was very interested in building the first
geothermal project on tribal or Native land. Ormat's corporate
structure is that 25 percent of its revenue comes from the sale
of equipment, and 75 percent from the sale of electricity, thus
it is very interested in facility development.
6:54:21 PM
CO-CHAIR MILLETT announced the co-chairs will produce a side-by-
side comparison of the projects for the committee.
6:55:18 PM
REPRESENTATIVE PETERSEN observed that a lot of information was
received to help the committee make decisions.
6:55:28 PM
REPRESENTATIVE JOHANSEN noted that Mount Spurr and Chakachamna
Hydro are two projects in the same area. He expressed concern
that CIRI and the in-state gas pipeline are pursuing the same
limited market.
6:56:48 PM
REPRESENTATIVE RAMRAS stated that he wants a commitment from
Black & Veatch.
6:57:03 PM
CO-CHAIR EDGMON relayed that Bush Alaska would be interested in
paying fourteen cents per kWh for electricity. He pointed out
the legislature is debating energy policy legislation and
hopefully funding streams as each project requires some
participation by the state, and in addition to the gas pipeline,
projects in outlying areas are also very important. Co-Chair
Edgmon would like to continue the conversation with the
presenters at the Rural Alaska Energy Conference in April.
6:58:28 PM
CO-CHAIR MILLETT announced upcoming hearings and expressed her
appreciation for the presentations and the opportunities for
energy in Alaska. She noted that her constituents in the
Railbelt need to hear when there will be additional power coming
into the grid.
ADJOURNMENT
There being no further business before the committee, the House
Special Committee on Energy meeting was adjourned at 6:58 p.m.
| Document Name | Date/Time | Subjects |
|---|---|---|
| House Energy - RIRP[2]-031110 final.pdf |
HENE 3/11/2010 3:00:00 PM |
|
| House Energy - Susitna rev6BC031110-brian.pdf |
HENE 3/11/2010 3:00:00 PM |
|
| CIRI Energy briefing_AK Leg Com_3.11.10.pdf |
HENE 3/11/2010 3:00:00 PM |
|
| House Energy 3_11_Swenson.pdf |
HENE 3/11/2010 3:00:00 PM |
|
| TDX House Energy March 2010.pdf |
HENE 3/11/2010 3:00:00 PM |
|
| Mount Spurr_House Special Committee on Energy 20-Feb-2010 (2).pdf |
HENE 3/11/2010 3:00:00 PM |
|
| Seven Questions.pdf |
HENE 3/11/2010 3:00:00 PM |