Legislature(2023 - 2024)BUTROVICH 205
04/05/2024 03:30 PM Senate RESOURCES
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| Presentation: National Renewable Energy Laboratory | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
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+ teleconferenced
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ALASKA STATE LEGISLATURE
SENATE RESOURCES STANDING COMMITTEE
April 5, 2024
3:31 p.m.
MEMBERS PRESENT
Senator Click Bishop, Co-Chair
Senator Cathy Giessel, Co-Chair
Senator Bill Wielechowski, Vice Chair
Senator Scott Kawasaki
Senator James Kaufman
Senator Forrest Dunbar
Senator Matt Claman
MEMBERS ABSENT
All members present
COMMITTEE CALENDAR
PRESENTATION: NATIONAL RENEWABLE ENERGY LABORATORY
- HEARD
PREVIOUS COMMITTEE ACTION
No previous action to record
WITNESS REGISTER
PAUL DENHOLM, Senior Research Fellow
National Renewable Energy Laboratory (NREL)
Jefferson County, Colorado
POSITION STATEMENT: Presented an overview of the National Energy
Laboratory (NREL).
ACTION NARRATIVE
3:31:00 PM
CO-CHAIR CATHY GIESSEL called the Senate Resources Standing
Committee meeting to order at 3:31 p.m. Present at the call to
order were Senators Wielechowski, Dunbar, Claman, Co-Chair
Giessel, and Co-Chair Bishop. Senators Kawasaki and Kaufman
arrived thereafter.
^Presentation: National Renewable Energy Laboratory
PRESENTATION: NATIONAL RENEWABLE ENERGY LABORATORY
3:31:36 PM
CO-CHAIR GIESSEL announced a presentation by the National
Renewable Energy Laboratory (NREL). She noted that this study
was published in March 2024.
3:32:28 PM
PAUL DENHOLM, Senior Research Fellow, National Renewable Energy
Laboratory (NREL), Jefferson County, Colorado, stated that he
has worked at the National Renewable Energy Laboratory (NREL)
for the past 20 years, focusing on renewable energy integration,
power optimization, and analyzing the associated costs,
benefits, and impacts. His expertise in the field led to his
recognition as a fellow of the IEEE Power and Energy Society,
the primary international association for electrical engineers.
NREL, part of the National Lab System established after World
War II, originally centered on nuclear research but has since
expanded to support a broad array of scientific and engineering
initiatives within the Department of Energy, with a primary
focus on renewable energy technologies like wind, solar, and
geothermal. Within NREL, he collaborates with approximately 100
electrical and other engineers to explore how renewable energy
can be effectively integrated into the national power grid,
aiming to enhance grid reliability, resilience, and cost
stability. He noted that, while he has studied most of the U.S.
power grid, the Alaska power system was one of the last regions
he analyzed. The Alaska project originated from requests by the
governor and Senator Murkowski's office, focusing initially on
assessing the feasibility of achieving an 80 percent renewable
portfolio standard (RPS) in the state. The first study,
published three years ago, confirmed that there were sufficient
wind and solar resources for such a target, although it did not
address economic feasibility. The current study aims to provide
a comprehensive cost analysis of deploying renewable energy on
the Alaska Railbelt system. Funding for the study was sourced
exclusively from the Department of Energy, without state or
advocacy funding.
3:34:16 PM
SENATOR KAUFMAN joined the meeting.
3:34:59 PM
MR. DENHOLM moved to slide 4 and explained the scope of study
for the Alaska Railbelt:
[Original punctuation provided.]
Scope of Study The Alaska Railbelt
About 75 percent of state's electricity demand Average
Railbelt residential electricity cost in 2022 was
about 23 cents/kWh. U.S. average was about 14
cents/kWh.
[Data table on presentation slide]
MR. DENHOLM emphasized that Alaska's electricity costs are
already significantly higher than those in the lower 48 states,
with residential consumers in the Railbelt paying approximately
60 percent more on average. A major concern is the potential
rise in costs due to Alaska's increasing reliance on imported
liquefied natural gas (LNG), driven by declining natural gas
production in the Cook Inlet.
3:35:37 PM
MR. DENHOLM moved to slide 5 and spoke to a graph and table
demonstrating potential cost increases for liquified natural gas
(LNG) imports. He explained that, based on utility projections
in the Railbelt region, illustrated by the purple line on the
left-hand graph, natural gas prices are expected to rise
significantly. Current costs of approximately $8 per million BTU
are projected to increase to over $12 per million BTU by 2028
2029, primarily due to the need to import liquefied natural gas
(LNG). This price surge is anticipated to add approximately $75
million per year in electricity costs. Given that Alaskan
electricity rates are already 60 percent higher than those in
the lower 48 states, these increases underline the study's
importance. The study seeks to determine whether renewable
energy can help stabilize or offset these rising costs.
3:36:28 PM
MR. DENHOLM moved to slide 6 and summarized the fuel purchase
price trends for the four most efficient natural gas generators
in the Railbelt region. This includes the Eklutna Generation
Station, the George Sullivan Plant, Southcentral plants (two
separate facilities in the Chugach region), and the Nikiski
Plant in Kenai. These four plants supply the majority of the
region's natural gas-fired electricity. By the 20282029
timeframe, fuel costs for these plants are expected to exceed 10
cents per kilowatt-hour, or $100 per megawatt-hour. He raised
the critical question of whether long-term power purchase
agreements could enable these utilities to procure electricity
at rates below this threshold. Within this study, wind and solar
energy are considered solely for their fuel-offsetting
potential, without attributing reliability benefits. Since wind
and solar are not reliable during peak demandgiven that
sunlight is unavailable, and wind is intermittent during such
timesthese renewable sources are assumed only to reduce natural
gas usage. The goal is to allow natural gas to remain available
for heating, a critical need for Railbelt customers, rather than
exhaust it on electricity generation.
3:38:14 PM
SENATOR CLAMAN noted past criticisms of renewable energy sources
like solar and wind, and to a lesser extent hydro, regarding
their inability to generate power when the sun isn't shining or
the wind isn't blowing, which limits their capability to provide
a stable base load. He confirmed his understanding of Mr.
Denholm's comments, suggesting that while alternative energy
sources do not replace base load power, increasing their usage
reduces dependence on base load generation. This approach could
preserve more base load power in reserve for critical heating
needs during cold periods.
3:38:55 PM
MR. DENHOLM confirmed that wind and solar cannot replace
Alaska's existing thermal and hydropower capacity. These
resources are essential for providing energy during periods of
low wind and solar output. The role of renewable energy in this
context is to reduce fuel consumption for these plants, thereby
saving costs, but not to substitute base load power sources.
3:39:17 PM
MR. DENHOLM moved to slide 7 and detailed approaches to
offsetting energy. He discussed the potential for wind and solar
to offset the anticipated 10-cent-per-kilowatt-hour fuel costs
in Alaska. He highlighted the historical and projected declines
in wind and solar costs, referencing power purchase agreements
in the lower 48, where wind is now available for as low as two
cents per kilowatt-hour in some areas. However, he noted that
Alaska's wind resources are less optimal, and installation costs
are higher, so such low prices are not achievable in the state.
Instead, Alaska's wind energy costs are more comparable to
higher-cost regions like New England and New York. For a more
accurate projection, the study utilizes Alaska-specific cost
analyses to estimate realistic renewable energy costs for the
region.
3:40:26 PM
MR. DENHOLM moved to slide 8 and briefly highlighted the cost
differences that were considered in the study. He said this does
not demonstrate a comprehensive rate study predicting consumer
electricity rates. Instead, the analysis aims to assess the
costs involved in investing in renewable energy, including
expenses for wind turbines, solar systems, integration costs,
natural gas, and storage. In exchange for these investments,
renewables primarily offset fuel costs. He explained that the
study seeks to determine the trade-offs between continuing to
purchase natural gas and using alternative technologies to
reduce natural gas consumption, providing insight into future
cost dynamics.Top of FormBottom of Form
3:41:31 PM
MR. DENHOLM moved to slide 9 and spoke to the modeling approach
that follows the standard integrated resource planning process:
[Original punctuation provided.]
Modeling Approach Follows Standard Integrated
Resource Planning Process
• Capacity Expansion model to determine cost-
optimal mix of resources
• Production cost modeling to validate load balance
and operating reserves
MR. DENHOLM outlined the analysis process, which follows the
integrated resource planning (IRP) methodology, a decades-old
practice adopted by utilities globally. This approach involves
running a series of utility-grade computer models, including
both standard commercial software commonly used by utilities and
proprietary internal models for maximum transparency. The goal
is to determine the least-cost mix of resources while simulating
the power grid on an hourly basis. The simulation covers every
hour from 2024 to 2040 to ensure reliability is maintained. He
emphasized the importance of validating that the proposed
solutions adhere to or exceed existing reliability standards.
The process involves extensive testing to identify potential
system failures, addressing them to develop solutions that
consistently meet reliability requirements. Results that do not
meet these standards are not published, as doing so would render
the results invalid.
3:42:56 PM
MR. DENHOLM moved to slide 10 and described the analysis
framework:
[Original punctuation provided.]
Analysis Framework
• Three reliability zones. MEA/CEA combined into
"central zone"
• We assume resources are planned and dispatched in
a coordinated manner
• But we do not assume consolidated utilities.
MR. DENHOLM highlighted key caveats in the analysis framework
regarding the optimal approach for advancing renewable energy
integration. A primary assumption is that consumer resources
will be planned, dispatched, and operated in a more coordinated
manner than currently practiced. While the analysis does not
prescribe a specific pathway to achieve this coordination, it
acknowledges that significant changes will be necessary. He
provided examples from the lower 48 states, where large power
plants, such as nuclear and coal facilities, often involve
multiple utilities sharing ownership. For instance, a 1,000-
megawatt plant might have ownership percentages distributed
among various utilities. In Alaska, a similar model could apply,
such as a new 200-megawatt wind farm being 50 percent owned by
one utility and 25 percent by another. While specific ownership
ratios are not defined in the analysis, this type of
collaboration is expected to help maximize economies of scale.
Additionally, the framework assumes coordinated dispatch of
resources to ensure that effectiveness is maximized and costs
are minimized.
3:44:23 PM
MR. DENHOLM moved to slide 11 and listed potential scenarios:
[Original punctuation provided.]
Scenarios
• No New RE only existing renewables, new fossil
allowed
• Reference all generation resources allowed
• Reference with RE cost +20 percent and -10
percent
• RPS - meet the 80 percent by 2040 RPS
o Eligible technologies based on SB 101: wind,
solar, geothermal, tidal, hydropower,
biomass, and landfill gas, and include both
existing and new deployments
MR. DENHOLM outlined the range of scenarios considered in the
analysis, starting with the baseline scenario, which represents
a "no new renewables" case. This scenario examines the existing
generation fleet while allowing for the construction of new
fossil fuel plants, including a few small facilities. The
primary objective is to assess the costs associated with
continued reliance on natural gas, coal, and oil, particularly
in regions like Fairbanks, where oil is predominant and natural
gas is used in the southern areas. He described the reference
case as one that permits the construction of any resource deemed
least costbe it renewables or fossil fuelswithout
restrictions. The goal is to identify the most economical
options available. Additionally, the analysis included an RPS
(Renewable Portfolio Standard) case, which mandates achieving 80
percent renewable energy by 2040, with eligible technologies
determined based on SB 101. This structured approach aims to
evaluate the implications of different pathways for integrating
renewable energy into the system.
3:45:16 PM
MR. DENHOLM moved to slide 12 and highlighted generation
options. He noted that one conservative limitation of the study
is the exclusion of new hydropower options. While a small amount
of run-of-river hydro is permitted, larger projects like the
Dixon diversion and other significant hydro plants that could
potentially reduce costs were not included in the analysis. He
emphasized that the study presents a conservative estimate of
costs, acknowledging that lower-cost options may exist but were
excluded due to the availability of high-quality data sets. The
study focused solely on technologies that have been deployed at
scale. Although there are promising tidal resources in southern
Kenai and good offshore wind potential, these technologies have
not been implemented at scale in the U.S. despite successful
deployments in Europe. Therefore, he opted not to include these
somewhat speculative technologies. The analysis is grounded in
established technologies, relying on the National Renewable
Energy Laboratory's (NREL) well-defined annual technology
baseline to ensure accurate component cost understanding. As
such, the study allows for the construction of new coal and
natural gas plants, alongside commonly built renewable
technologies in the U.S.
3:46:47 PM
SENATOR BISHOP asked whether the hydro technology to model
conventional hydro is available.
3:47:00 PM
MR. DENHOLM confirmed the capability to model hydro resources,
stating that NREL regularly models all existing hydro and
evaluates options for new hydro across the U.S. However, he
expressed discomfort with the quality of the data sets available
for assessing potential costs and development timelines for new
hydro projects, which led to their exclusion from the current
analysis. He expressed a desire to explore hydro options in
future work, acknowledging that these technologies could
significantly reduce the cost of renewables.
3:47:39 PM
MR. DENHOLM moved to slide 13 and spoke to assumptions about
load growth:
[Original punctuation provided.]
Load Growth
• Scaled based on projected population growth
(about 4 percent) by 2040
• Electric vehicle adoption values from ACEP, about
20 percent of vehicles by 2040 adds abound
additional 16 percent growth in electricity
demand
MR. DENHOLM highlighted NREL's commitment to transparency in
conducting these studies. He explained that the projected growth
used was modest, based on population projections from the State
of Alaska and a conservative estimate for electric vehicle
adoption provided by the Alaska Center for Energy and Power.
Combined, these factors contribute to an anticipated 20 percent
increase in electric demand by 2040.
3:48:16 PM
CO-CHAIR GIESSEL asked why AI is not mentioned in the analysis,
noting that AI technology is known for its high energy demands.
3:48:30 PM
MR. DENHOLM said that increased electricity demand for AI and
other computer-related activities, such as data centers, is
generally occurring in areas with low electricity rates. He
noted that while renewable technologies could help stabilize
Alaska's electricity costs, Alaska is unlikely to become a low-
cost electricity provider in the near future. Consequently, he
expects data centers and similar energy-intensive facilities to
develop in regions like Iowa, where electricity costs are
substantially lower.
3:49:29 PM
CO-CHAIR GIESSEL said while that makes sense, she noted that
everyday citizens using AI on their personal computers are
consuming significantly more energyup to four times the amount
used in a typical Google search.
3:49:44 PM
MR. DENHOLM confirmed that increased electricity demand from AI
use in Alaska would likely raise the load beyond current
projections. He explained that while there are limited forecasts
on electricity usage specific to Alaska, any growth in demand
would likely enhance the cost-effectiveness of renewables. As
renewables become relatively lower-cost options, their benefit
increases with higher demand. This reinforces the conservative
nature of the current estimates, as increased demand would
likely improve the financial outlook for renewable energy
options in the state.
3:50:35 PM
SENATOR WIELECHOWSKI mentioned that the committee is currently
discussing whether transmission planning should be managed by
the same organization responsible for generation planning. He
inquired whether he has any expertise in this area.
3:50:50 PM
MR. DENHOLM expressed that while he is unable to discuss various
ways to achieve the integration of renewable energy, he is
uncomfortable delving into specific policies most suitable for
Alaska. He emphasized his preference for exploring different
methods to reach the goal without endorsing any particular
approach.
3:51:18 PM
MR. DENHOLM moved to slide 14 and explained transmission and
interconnection:
[Original punctuation provided.]
Transmission & Interconnection
• AK Intertie 78 MW of available transfer
capacity. No upgrades. Kenai intertie 75 MW.
Upgraded to 185 MW in 2033 in all scenarios as
part of the Railbelt Innovative Resiliency
Project. Solar and PV interconnections are added
as needed and optimized by the model (assumed
eligible for ITC).
MR. DENHOLM said there are two major lines in Alaska that can
use major power in Alaska. He said the lab feels comfortable
through group funding that the line is upgraded to 185 mW, but
it did not complete any upgrades to the Alaska Intertie. He said
upgrades would likely increase the efficiency of power.
3:54:06 PM
CO-CHAIR GIESSEL inquired about the variation.
3:54:18 PM
MR. DENHOLM replied that the variation is tied to resource
quality.
3:54:56 PM
CO-CHAIR GIESSEL asked whether that includes AC lines.
3:55:01 PM
MR. DENHOLM replied yes, absolutely. It can be accomplished with
AC lines.
3:55:14 PM
MR. DENHOLM moved to slide 16 and spoke to costs of acquiring
new renewables:
[Original punctuation provided.]
Costs of Acquiring New Renewables All Included in This
Study
• Capital cost - Captured in a power purchase
agreement
• Fixed O&M - Captured in a power purchase
agreement
• Interconnection
• Transmission spur lines
• Integration costs
MR. DENHOLM discussed the financial considerations when
transitioning away from natural gas to renewable energy sources.
He explained that costs related to acquiring new renewables,
including capital and fixed operation and maintenance, were
factored into the study, primarily captured in power purchase
agreements (PPAs). He addressed a critical question: whether
utilities would need to incur new debt. He clarified that there
is no mandate for utilities to take on debt, though they may opt
for debt financing if they choose to handle developments
independently. In the lower 48 states, he noted, 84 percent of
wind projects are managed by independent power producers (IPPs)
and are acquired by utilities mainly through PPAs. However, some
investor-owned utilities have recently begun developing
renewable technologies in-house, similar to when they managed
coal or nuclear plants. This approach allows them to leverage
rate basing, available expertise, and labor. PPAs offer
utilities a delivered energy model, with payments made per unit
of power purchased, avoiding debt, capital, or upfront costs.
However, utilities must still address certain costs requiring
additional financing, such as interconnection expenses,
substation upgrades, and a whole host of integration costs
associated with renewables. He noted that renewable energy
integration poses uncertainties, particularly due to Alaska's
limited spatial diversity, which can increase fluctuations in
solar and wind output compared to the more expansive grid
systems in the lower 48. Calculating integration costs while
maintaining reliability is a significant part of his role.
Failing to address these costs could lead to reliability issues,
underscoring the necessity of precise calculations to ensure
grid stability without redundant or inflated costs.
3:58:55 PM
SENATOR WIELECHOWSKI asked whether he assumed that an economic
dispatch system was in place.
3:59:04 PM
MR. DENHOLM affirmed that NREL assumes a joint dispatch system
with coordinated energy dispatch but noted certain limitations.
He explained that NREL does not assume shared operating reserves
or the use of interties for reliability, recognizing that
interties may occasionally fail. Each zone is expected to
maintain independent resource adequacy, operating as an isolated
system when interties are down. Under normal conditions, the
zones are expected to coordinate to minimize costs.
3:59:40 PM
SENATOR WIELECHOWSKI asked whether an economic dispatch system
dramatically impacts the output.
3:59:46 PM
MR. DENHOLM replied that he is unsure. This is the most
economical way to do it. If forced, NREL could absolutely figure
out what the costs of an uneconomic dispatch is. We have done
that in the past. But given the limited costs of actually
creating economic dispatch through whatever mechanism you want,
I would assume that is the direction you take, and calculate the
benefits that way.
4:00:21 PM
MR. DENHOLM clarified that all costs discussed would be in 2023
dollars. He emphasized the importance of assuming the
availability of a 40 percent investment tax credit, contingent
on the entire Railbelt region qualifying as an energy community.
4:00:37 PM
MR. DENHOLM moved to slide 18 to discuss a graph illustrating
the renewable cost multiplier in Alaska. He acknowledged
uncertainty in the total costs but noted that NREL analyzed
available data to estimate the increased expense of renewable
energy in Alaska. He explained that solar installation costs are
expected to be about 50 percent higher in Alaska compared to
other regions, due to both purchase costs and Alaska's lower
solar resource quality. Similarly, wind installations are
assumed to be approximately 85 percent more expensive than in
the lower 48, although this cost multiplier is projected to
decrease over time as the marketplace matures. He clarified that
NREL's assumptions do not rely on technological advancements but
rather on the emergence of a more competitive market,
potentially requiring regulatory initiatives. He outlined the
types of electricity markets in the U.S., noting that a
wholesale restructured market, common in two-thirds of the
country, is unlikely in Alaska due to its smaller market size.
Instead, Alaska could adopt a model similar to states with
vertically integrated monopolies, such as Colorado, where
utilities issue all-source requests for proposals (RFPs). This
process invites diverse bids from various developers for energy
supply, without specifying technology, allowing utilities to
select the most cost-effective option. The regulatory push
behind Renewable Portfolio Standards (RPS) aims to foster
competitive bidding and a diverse resource base. NREL
anticipates that a similar approach in Alaska could yield a
competitive marketplace that would drive down costs. However,
NREL does not expect renewable energy costs in Alaska to ever
fully align with those in the lower 48, estimating that wind
renewables will consistently remain around 60 percent higher in
costs and photovoltaics are always 35 percent more expensive
than they are in the lower 48.
4:04:14 PM
CO-CHAIR BISHOP asked why that assumption was made.
4:04:20 PM
MR. DENHOLM explained that NREL's cost assumptions rely on an
anticipated increase in the number of developers in Alaska to
help lower costs. He clarified that if the state does not see a
growth in developer presence and instead only attracts a few
developers, the expected cost reductions may not materialize.
Thus, the assumption of an expanded competitive marketplace is
crucial for achieving these projected cost decreases.
4:04:55 PM
MR. DENHOLM moved to slide 19 and explained a bar graph
depicting renewable capital costs, specifically for current wind
and solar projects. The graph illustrates costs per kilowatt
(KW), a standard measure for new power plant expenses. Dotted
lines on the graph represent NREL's estimates of wind and solar
costs in both the lower 48 states and Alaska. He noted that the
projected price reductions on the graph are driven by two
factors: increased market competition and ongoing technology
improvements, shown by the lower dashed lines indicating lower
48 prices as technology advances. He pointed to the label "GFM"
at the top of the graph, referring to grid-forming inverters, a
stability measure. Due to stability limitations on the Alaska
Railbelt grid, additional hardware, including GFMs, will be
needed starting in the late 2020s, which will slightly increase
costs for these renewable technologies.
4:06:03 PM
SENATOR KAUFMAN asked about the role of federal subsidies in
building the cost models. He inquired whether there is any risk
factored into the estimate that the costs could increase if
federal subsidies were to be removed. He expressed concern that
the technologies may have been significantly driven by subsidies
and sought clarification on how this factor is accounted for in
the model.
4:06:34 PM
MR. DENHOLM clarified that the assumption in the cost models is
that the 40 percent investment tax credit (ITC) remains
available, as per current IRS guidance and statute. He
acknowledged that if the ITC were to be removed, there would be
a significant decrease in the cost competitiveness of these
renewable technologies. While the reduction in costs is not
exactly 40 percent, it is close enough to consider it a rough
estimate. Without the subsidy, the technologies would still
provide a net benefit, but that benefit would be much smaller.
4:07:34 PM
SENATOR KAUFMAN inquired about the potential for revenue loss in
Alaska, noting that as oil and gas production is displaced by
renewable energy, the state would lose royalty and tax revenue,
as renewable technologies do not pay royalties. He asked whether
any modeling has been done to account for this, particularly
considering that the state currently benefits from revenue
generated through oil and gas, which would be lost if these
resources are replaced by renewables. He sought insights on how
this revenue stream loss is factored into the transition to
renewable energy.
4:08:33 PM
MR. DENHOLM replied that the consideration is not part of this
analysis. However, most of the natural gas avoided here is based
on the assumption of LNG imports. He noted that he doesn't
believe there would be revenue loss from this, as the main focus
is displacing imported LNG. He acknowledged that any potential
revenue loss could be tied to oil used in the Fairbanks area,
particularly for the North Pole combined cycle unit. However, he
emphasized that, as he is not an oil and gas expert, he could
not speak definitively on the matter.
4:09:23 PM
SENATOR KAUFMAN said that if the assumption is that LNG imports
are being displaced rather than in-state production, he agrees.
He noted that displacing costly oil would likely result in a net
benefit. However, he emphasized the need to consider the
potential loss of revenue when evaluating the shift to other
energy sources.
4:09:52 PM
MR. DENHOLM moved to slide 20 and noted that the dotted chart on
the far-left side of the slide demonstrates the average
agreement in the lower 48, which was around $30 per MWh or about
3 cents per kWh. He mentioned that while this is a fairly
sizable range, most of these projects were designed well below 4
cents per kWh. The working assumption for Alaska is that costs
are north of 6 cents per kWh. He acknowledged that these are
higher costs, but emphasized that they reflect the comparison of
higher natural gas costs in Alaska, which pays quite a bit less.
4:10:35 PM
SENATOR WIELECHOWSKI said the state has plenty of generation
capacity with natural gas but asked how this might play out with
major wind and solar farms potentially coming online. He assumed
that a 200 MW wind farm would negotiate a 25-year power purchase
agreement and questioned whether this could crowd out other
projects. He noted that Alaska is constrained and lacks
sufficient demand. He asked if there could be a crowd-out issue
where future smaller independent power producers (IPPs) might
struggle to find a market for their energy due to capacity being
filled by larger projects and whether this was factored into the
analysis.
4:11:22 PM
MR. DENHOLM replied that there are absolutely limits to how much
wind and solar can be added to the grid before it becomes
unusable. He explained that the state reached 76 percent
renewable energy and stopped building more renewables because
they couldn't use it effectively. He noted that while the 80
percent scenario wasn't significantly more expensive, the model
was concluded due to the saturation of wind and solar capacity
in meeting electricity demand for many hours of the year. He
highlighted that there are still several hundred hours each year
when the wind isn't blowing and the sun isn't shining, requiring
reliance on hydropower and thermal plants. He stressed that this
limitation is not unique to Alaska and is seen in other places
like California, where solar energy value drops in the middle of
the day due to excess supply.
4:12:21 PM
SENATOR WIELECHOWSKI cited slide 20 and pointed out that costs
are declining, at least on the left side of the chart. He asked
whether the addition of a couple of major producers in the next
few years would crowd out any future wind farms.
4:12:37 PM
MR. DENHOLM asked whether, when talking about crowding out, the
concern is due to the resource being used up or because there is
no longer a market left.
4:12:46 PM
SENATOR WIELECHOWSKI clarified his question, and wondered if
400-500 MW of wind and solar come online and secure 25-year
power purchase agreements, the state would be at peak capacity
at that point. He questioned whether there would be no more
capacity to sell and whether utilities would no longer be able
to buy additional energy.
4:13:07 PM
MR. DENHOLM replied that the bottom line is that NREL models
about 1500 MW of wind and several hundred MW of solar in their
scenarios. He acknowledged that it might seem strange to build
1500 MW of wind in an 800-MW peaking system, but emphasized that
wind doesn't blow consistently at full capacity. Most of the
time, the wind produces between 0 and full capacity, often
generating around 400-500 MW of energy. During many hours of the
year, excess wind energy is discarded by shutting down turbines
because they produce more than is needed. He explained that 1500
MW of wind, on average, only produces about 500 MW, which is
well within the grid's capacity to accommodate. He noted that
his work focuses on determining how much of this energy
displaces gas. NREL sees substantial potential for around 1500
MW of wind and several hundred MW of solar.
4:14:37 PM
MR. DENHOLM moved to slide 21 and detailed wind sites. He
explained that the best wind resources are in the Kenai region
or around Fairbanks. He highlighted that the slide shows
locations and sites evaluated by NREL, but noted that these are
not the same sites being evaluated by utilities. NREL's dataset
is generated by mass and provides broad geographical coverage,
but lacks the specific site details of individual locations. He
emphasized that evaluating specific sites requires installing an
anemometer or using laser-based instruments to measure local
wind speeds, and that complete data for these sites is often
proprietary to individual developers. He also pointed out that
having more developers is beneficial as it leads to more
resources being explored. He clarified that while NREL's dataset
provides a general idea of potential wind sites, the mix they
built is unlikely to reflect the exact sites, but rather gives a
broad overview of where these sites may be located.
4:15:46 PM
SENATOR DUNBAR referred to the map on slide 21 and expressed
surprise and noted that from a layperson's perspective, the Mat-
Su Valley seems like a very windy place, and most people in the
region likely think the same. He asked what it is about the
nature of the Mat-Su area that prevents any wind projects from
being developed in that whole region.
4:16:09 PM
MR. DENHOLM replied that, based on the map on slide 21, he would
guess that there are restrictions on the amount of developable
land in the Mat-Su region due to local conditions. This could
include state or national parks, land that is not developable,
or particularly unfavorable terrain, such as hilly or marshy
areas that pose challenges for development. He mentioned that it
has been 23 years since he was in the area, so he couldn't
provide a more specific answer about the terrain. He clarified
that the map shows dark greenish-blue colors indicating better
wind resources, while white areas represent either very poor
wind resources or areas where developers are not allowed to
build. He noted that dedicated geospatial analysts evaluate each
land parcel to determine suitability for wind projects and
offered to provide that specific information in the future.
4:17:18 PM
SENATOR DUNBAR noted that it was just a curiosity, as it always
seems like the wind is blowing in the Mat-Su Valley.
4:17:27 PM
MR. DENHOLM moved to slide 22 and presented an example of
potential opportunities for developing wind and solar to achieve
costs lower than 10 cents per kWh. He explained that by signing
a long-term power purchase agreement for these technologies, the
cost of purchasing 7-cent wind or solar instead of 10-cent gas
would result in savings of three cents per kWh, which could be
passed on to consumers. However, he clarified that this
calculation is before accounting for the cost of integrating the
wind or solar power. He noted that while the analysis includes
the cost of the spur line and other costs, it doesn't provide a
complete picture of potential savings. He explained that this is
the starting point for the analysis, after which more complex
simulations are needed to determine the necessary steps to
integrate wind, ensuring that every kWh produced by wind or
solar can offset gas plant operations for a period of time.
4:18:44 PM
SENATOR DUNBAR expressed confusion about the graph, noting that
it seems to be missing a lot of detail. He pointed out that
below the avoided cost of natural gas, there is no line
indicating the avoided cost of natural gas. He said the graph is
missing the line that indicates the avoided cost for natural
gas. He noted costs are in dollars and asked if there was a line
for natural gas would it run horizontally at $0.07 - $0.10 per
kWh ($70 or $100 per MWh).
4:19:16 PM
MR. DENHOLM explained that the numbers on the graph represent
dollars per mW which are typically used for wholesale
electricity pricing. To convert this into cents per kWh, you
shift the decimal place, so $70 per MWh corresponds to $0.07
per kWh. He clarified that although this graph does not show the
avoided cost of natural gas, he mentioned earlier that around
2028 - 2029, a spike will occur when the cost of natural gas
fuel reaches $0.10 per kwh or $100 per MWh.
4:20:00 PM
CO-CHAIR BISHOP asked him to clarify whether the graph depicts
the imported cost of gas or the current cost of gas in Cook
Inlet.
4:20:13 PM
MR. DENHOLM moved to slide 6 and explained that the graph
represents the assumed cost of natural gas paid by utilities for
their large power plants. He stated that, for 2028-2029, the
assumption is that LNG imports will need to be purchased at
roughly $12 per million BTU. This translates, based on the heat
rate and the power plant's efficiency, into approximately 10
cents per kWh for fuel costs.
4:21:00 PM
CO-CHAIR BISHOP asked whether the assumption is for LNG imported
prices.
4:21:02 PM
MR. DENHOLM replied yes, that is the marginal or avoided cost
for these power plants.
4:21:10 PM
MR. DENHOLM moved to slide 23 and discussed integration costs.
He explained that this slide shows some of the integration costs
considered, including physical hardware and connections. Due to
the fluctuating output from natural gas plants, additional
natural gas storage will likely be required. Alaska's extensive
natural gas network offers some buffer against this, unlike
lower 48 states, where such storage is a larger concern. Other
costs include communication with multiple power plants, as
currently, dispatching the Railbelt system involves fewer plants
compared to potentially a dozen or more when integrating
renewables. Further costs arise from the increased frequency of
starting and stopping power plants, which incurs direct fuel
costs, additional operation and maintenance (O&M) costs, wear
and tear, and thermal stresses. By 2040, the increased cost of
starting plants will add an estimated $3-4 million per year.
These additional costs will be incurred by local utilities due
to the integration of renewables into their power grid, which
reduces the overall value of renewables.
4:23:57 PM
MR. DENHOLM moved to slide 24 and discussed the reliability
benefits of renewables. He explained that in places like
Arizona, there would be a discussion about effective load
carrying capability. However, in Alaska, this is not a major
consideration, as there are no reliability benefits from
renewables. Renewables cannot offset the need to keep existing
power plants operational. Instead, their primary benefit is fuel
savings.
4:24:25 PM
SENATOR DUNBAR cited slide 24 and asked if, when referring to
renewables, he is primarily talking about wind and solar energy,
rather than new hydro plants.
4:24:39 PM
MR. DENHOLM replied yes, some renewable resources, particularly
geothermal, biomass, and hydropower, add reliability benefits,
especially when you have water stored behind a dam, allowing you
to schedule and ensure availability when needed. However, since
wind and solar are the major providers, these resources
primarily offer fuel savings benefits rather than capacity
credits.
4:25:17 PM
MR. DENHOLM moved to slide 26 and spoke to key findings. Given
the high cost of natural gas and the ability of renewables to
provide energy at a lower cost, modeling efforts indicate that
by 2040, approximately 76 percent of the Railbelt's electricity
could be generated by renewables. Significant growth is expected
in the early years due to high natural gas costs. The model
suggests keeping existing power plants operational but reducing
their generation to avoid fuel costs as much as possible until
further integration of renewables becomes uneconomical. The 76
percent figure reflects the point where marginal costs exceed
marginal benefits. He added that significant uncertainty remains
regarding the future cost of natural gas in the 2030s and the
potential for further cost reductions in renewable energy.
4:26:27 PM
MR. DENHOLM moved to slide 27 and spoke to the primary goal of
annual costs. He reiterated the importance of examining the cost
objectives of study tools, highlighting potential costs,
savings, and benefits. The analysis focused on specific cost
components that may fluctuate over time, excluding general costs
associated with billing and maintaining the distribution
network. He explained that the left-hand curve represented
fossil fuel purchase costs, the middle curve showed renewable
purchase costs, and the most critical curve, on the right,
displayed the cost differences. Investing hundreds of millions
of dollars in renewable energy technologies includes integration
costs but offsets these by avoiding even greater fossil fuel
expenses. By the early 2030s, this investment approach is
projected to yield a net savings, with all integration costs
factored in, underscoring the importance of net savings in this
analysis.
4:27:39 PM
MR. DENHOLM moved to slide 28 and projected approximately $100
million per year in net savings, contingent on the numerous
assumptions previously discussed. This annual savings translates
to cumulative net savings exceeding $1 billion by the end of the
analysis period. He clarified that the analysis considers an
initial $2.9 billion investment in building wind farms, solar
power plants, and related integration infrastructure, resulting
in $4.2 billion in avoided fuel and other expenses. This
approach yields a cumulative net savings of $1.3 billion,
underscoring the financial benefits of renewable energy
investment over the analysis period.
4:28:13 PM
CO-CHAIR BISHOP asked how much of the $100 million in annual
savings will reach the consumer.
4:28:23 PM
MR. DENHOLM explained that all projected savings should directly
benefit consumers through pass-through charges incurred by the
utility. He compared this mechanism to fluctuations in natural
gas prices, stating that if prices doubled or decreased by 50
percent in a day, these cost changes would similarly flow
through to the consumer, impacting their utility charges
accordingly.
4:28:51 PM
SENATOR DUNBAR referred to slide 27 and asked for confirmation
of his understanding that, while the graph may not depict it,
the $100 million in net savings does not represent a decrease in
consumer billing amounts. Rather, costs will continue to
increase but at a slower rate than they otherwise would have. He
clarified that the $100 million net savings may not reduce
consumer bills outright but would likely mean that rates
increase less than they otherwise would. He asked if this
interpretation was accurate.
4:29:14 PM
MR. DENHOLM replied that he thinks that is the correct
description.
4:29:27 PM
CO-CHAIR BISHOP questioned whether the information on the graph
needed restating.
4:29:31 PM
SENATOR DUNBAR replied no, the graphs show that overall costs
are going up so bills will go up; but they will go up less than
if the state relied on very expensive LNG imports. While
consumer bills will rise, they will increase more slowly
compared to reliance on higher-cost energy sources.
4:29:51 PM
MR. DENHOLM moved to slide 29 and explained that the energy mix
is primarily wind-based, with wind resources in Alaska proving
more favorable than solar, though the solar resource is better
than initially expected. By 2040, approximately 50 percent of
electricity generation is projected to come from wind. He
emphasized that physical capacity will be maintained by keeping
the existing fossil and hydro power infrastructure, with Healey
Unit 2 as the only planned retirement. This capacity retention
is essential for system reliability, with wind and solar
primarily offsetting fuel purchases rather than replacing
capacity.
4:30:33 PM
MR. DENHOLM moved to slide 30 and spoke to installed capacity.
He discussed the anticipated locations for renewable energy
development, noting that precise sites would depend on
developers prospecting optimal wind and solar resources.
Preliminary assessments indicate high-quality wind resources
near Fairbanks and on the Kenai Peninsula are perhaps the best,
with additional viable resources in central Alaska. Development
is expected across regions, with particular emphasis on
utilizing the upgraded Kenai intertie and the new HVDC line to
support growth on the Kenai. Additionally, the Alaska intertie
will be maximized to transmit energy from Fairbanks and central
regions. He highlighted a major operational shift: currently,
energy flows predominantly from south to north along the Alaska
intertie, but this shift would reverse, flowing north to south
most of the time under the new system. While this directional
change does not impact the physical infrastructure, it
represents a significant contractual and policy adjustment,
diverging from the usual operations. Implementing these changes
will require extensive documentation and legal supports to
support this transition from traditional practices.
4:32:01 PM
MR. DENHOLM moved to slide 31 and explained finding 3. He
referenced the 80 percent Renewable Portfolio Standard (RPS)
target, explaining that most of his discussion thus far had
centered on a reference case aligned with this goal. He noted
that the 80 percent RPS could potentially be slightly cheaper or
more expensive, but that the greater impact lies in fluctuations
in renewable and natural gas costs, which drive overall system
costs more significantly. While he suggested that 76 percent
renewable integration might be optimal based on current
assumptions, he acknowledged that this could vary. Nevertheless,
a substantial level of renewables is likely to be cost-optimal,
resulting in notable net savings. He highlighted the role of
contingency measures, or "escape valves," in many RPS plans,
which provide flexibility if circumstances changesuch as
economic disruptions from events like COVID-19 or geopolitical
conflicts impacting supply chains. Although the last two years
of the 80 percent RPS period carry the most uncertainty, he
expressed confidence that a significant investment in renewable
energy remains a cost-effective strategy for reducing natural
gas costs in the near and midterm projections.
4:33:51 PM
SENATOR DUNBAR questioned the rationale for setting an 80
percent RPS target when the projected optimal renewable
percentage is around 76 percent, noting that even a 70 percent
target appears viable based on market trends. He asked if the
market could naturally reach or even exceed this level.
4:34:09 PM
MR. DENHOLM replied that the choice of an 80 percent RPS target
for the study reflects the proposed 80 percent RPS. He
emphasized that his role is to provide the data, leaving it to
others to adjust the target as they see fit.
4:34:26 PM
SENATOR KAUFMAN wondered about the supply chain risk,
referencing the large percentage of solar panel production
currently coming from China, highlighting the significant
reliance on this source.
4:34:48 PM
MR. DENHOLM clarified that the U.S. does not currently import
solar panels from China. While most solar panels are imported,
they primarily come from other parts of Asia, such as Vietnam
and Korea, rather than China.
4:35:06 PM
SENATOR KAUFMAN expressed concern about supply chain risks,
particularly in the event of a disagreement with China. He
inquired whether the precursors, such as glass and active
components used in solar panels, are sourced from China and if
this could lead to a significant supply shock.
4:35:38 PM
MR. DENHOLM noted that while the U.S. imports solar panels
primarily from Asia, the basic materials used in solar panel
production, such as sand, silicon, and glass, are often locally
sourced and are not significant supply chain risks. Similarly,
for wind energy, most of the materials, including steel,
concrete, and copper, are sourced domestically. There are some
concerns about rare earth elements, particularly neodymium in
wind turbine magnets, which are primarily sourced from China,
but overall, the supply chain for wind energy is diverse. He
emphasized that while there are challenges, particularly related
to critical materials like neodymium, both wind and solar have
robust supply chains. He noted that batteries are a different
story and offered to provide more detailed market reports and
highlighted the U.S. Department of Energy's dedicated program to
address these concerns regarding critical materials.
4:37:31 PM
MR. DENHOLM moved to slide 32 and emphasized the importance of
hydropower and fossil resources during periods of high demand.
He explained that wind resources were not credited with any
capacity and solar was given almost zero capacity credit,
recognizing that these resources are not reliable during peak
demand times. This approach was taken to ensure that the
analysis accounts for reliability concerns, ensuring that there
would be no over-reliance on intermittent renewable sources like
wind and solar for grid stability.
4:38:22 PM
MR. DENHOLM moved to slide 33 and highlighted a "scary" graph
that illustrates the shift in how the power system will operate
in 2040. The graph shows that, on an hourly basis, between zero
and nearly 100 percent of electricity demand will be met by wind
and solar, particularly inverter-based technologies. This shift
requires new methods for monitoring the grid, responding to
variability, and integrating new hardware. He emphasized that
while this transition presents challenges, there are successful
examples, such as Kauai in Hawaii, and the committee would
benefit from a trip to Kauai, which has been operating with over
90 percent of its electricity from renewables for years.
Although Kauai's grid is smaller and primarily solar-based, it
demonstrates the technical feasibility of achieving high
renewable penetration. MR. D acknowledged that the transition is
difficult, but the resulting savings, including the estimated
$100 million annually, make it a worthwhile goal.
4:40:33 PM
SENATOR KAUFMAN asked whether the modeling of wind energy took
into account the observation that the stillest days, which often
have low wind production, tend to coincide with the coldest
days, which are peak demand periods.
4:40:55 PM
MR. DENHOLM moved to slide 32 and spoke to a graph that
demonstrates wind production at a low point. He explained that
the modeling does account for periods with low wind production,
such as the evening of December 13, when wind production dropped
almost to zero. He explained that there are several instances
where this occurs, especially during the worst combination of
high demand and low wind. While some periods show lower demand,
there are indeed instances where wind production drops off
significantly.
4:41:34 PM
SENATOR KAUFMAN asked about the duck curve, a situation often
observed with solar generation, where there's an oversupply of
electricity during midday. He mentioned hearing about this
condition in Hawaii and noted that it typically occurs when
solar generation peaks. He inquired whether he had further
thoughts on this issue.
4:42:04 PM
MR. DENHOLM moved to slide 33 explained that his group was the
first to observe the now-known "duck curve" phenomenon, though
it was named by the California ecosystem operator. He clarified
that the duck curve phenomenon occurs when solar energy
saturates the grid during midday, leading to periods where
additional solar generation has no value. While storage
technology has helped mitigate this issue, it remains a concern
in regions with high solar capacity like California. In Alaska,
however, the solar resource isn't large enough to generate a
duck curve, but a similar issue exists with wind and solar
overproduction. The capacity of wind and solar exceeds what can
be used during certain times, leading to marginal curtailment.
He referred to a graph illustrating hours where wind and solar
production exceeds demand and noted that even though production
doesn't hit 100 percent, there are times when wind and solar
energy is effectively wasted, as shown by periods reaching 97
percent generation but still unable to fully utilize all
available energy.
4:44:13 PM
MR. DENHOLM moved to slide 35 and discussed the integration
costs associated with variable renewable resources, noting that
tens of millions of dollars in additional costs arise from
integrating these resources into the grid. He explained that the
left side of the graph lists these costs, with a significant
portion attributed to operating reserves, often referred to as
spinning reserves, though the term is outdated as reserves are
increasingly provided by batteries. Batteries, while not
"spinning," incur costs related to their use and the need to
maintain them as underutilized assets. He highlighted that the
opportunity cost of not utilizing these batteries for grid
benefits, just in case wind stops blowing, is a real expense.
The total operating reserve costs amount to tens of millions of
dollars annually. Despite these costs, he emphasized that the
analysis already accounts for them, and the $100 million annual
savings still reflects the inclusion of integration costs.
4:45:57 PM
MR. DENHOLM moved to slide 36 and emphasized the potential of
new renewable generation through long-term power purchase
agreements to offset the costs associated with gas-fired power.
He highlighted that this approach not only reduces costs but
also provides price stability, particularly for industrial
consumers in Alaska, who benefit from predictable energy prices
for their operations. While acknowledging the uncertainties in
the analysis, he noted that additional data on hydropower could
further reduce costs, though its impact remains unclear without
specific data. He addressed potential concerns from utilities
about grid stability, stating that the analysis, which includes
grid funding and inverters, addresses most of these issues, but
recognized the possibility of needing traditional spinning
machines to supplement renewable resources. He estimated that
incorporating spinning machines would reduce benefits by about
10 percent, which he considered the upper bound of potential
cost reduction. Despite these uncertainties, he believes the
analysis captures most of the costs and benefits of integrating
renewable energy.
4:48:41 PM
There being no further business to come before the committee,
Co-Chair Giessel adjourned the Senate Resources Standing
Committee meeting at 4:48 p.m.
| Document Name | Date/Time | Subjects |
|---|---|---|
| Renewable Portfolio in Alaska's Railbelt_NREL March 2024 Report_SRES 4.5.24.pdf |
SRES 4/5/2024 3:30:00 PM |
|
| NREL Renewable Portfolio SRES Presentation 4.5.24.pdf |
SRES 4/5/2024 3:30:00 PM |