Legislature(2023 - 2024)BUTROVICH 205
03/13/2024 03:30 PM Senate RESOURCES
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| Audio | Topic |
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| Start | |
| SB217 | |
| Presentation: Alaska Energy Authority (aea) | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| += | SB 217 | TELECONFERENCED | |
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ALASKA STATE LEGISLATURE
SENATE RESOURCES STANDING COMMITTEE
March 13, 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
SENATE BILL NO. 217
"An Act relating to the taxation of independent power producers;
and increasing the efficiency of integrated transmission system
charges and use for the benefit of ratepayers."
- HEARD & HELD
PRESENTATION(S): Alaska Energy Authority (AEA)
Update by Curtis Thayer, Executive Director
- HEARD
PREVIOUS COMMITTEE ACTION
BILL: SB 217
SHORT TITLE: INTEGRATED TRANSMISSION SYSTEMS
SPONSOR(s): RULES BY REQUEST OF THE GOVERNOR
02/02/24 (S) READ THE FIRST TIME - REFERRALS
02/02/24 (S) RES, L&C, FIN
03/04/24 (S) RES AT 3:30 PM BUTROVICH 205
03/04/24 (S) Heard & Held
03/04/24 (S) MINUTE(RES)
03/13/24 (S) RES AT 3:30 PM BUTROVICH 205
WITNESS REGISTER
ANTONY SCOTT, Director
Economic and Regulatory Analysis
Renewable Energy Alaska Project (REAP)
Anchorage, Alaska
POSITION STATEMENT: Presented SB 217 on behalf of the
administration.
MATTHEW PERKINS, representing self
Anchorage, Alaska
POSITION STATEMENT: Testified in support of SB 217.
PENNY GAGE, representing self
Anchorage, Alaska
POSITION STATEMENT: Testified in support of SB 217.
DOUG JOHNSON, representing self
Anchorage, Alaska
POSITION STATEMENT: Testified in support of SB 217.
KEN HUCKEBA, representing self
Wasilla, Alaska
POSITION STATEMENT: Testified in opposition to SB 217.
DAVID BRAILEY, representing self
Eagle River, Alaska
POSITION STATEMENT: Testified in support of SB 217.
JENN MILLER, representing self
Houston, Alaska
POSITION STATEMENT: Testified in support of SB 217.
CURTIS THAYER, Executive Director
Alaska Energy Authority (AEA)
Anchorage, Alaska
POSITION STATEMENT: Presented an overview of AEA.
ACTION NARRATIVE
3:31:19 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, Kawasaki, Kaufman, Claman, Co-
Chair Giessel, and Co-Chair Bishop. Senator Dunbar joined
thereafter.
SB 217-INTEGRATED TRANSMISSION SYSTEMS
3:31:51 PM
CO-CHAIR GIESSEL announced the consideration of SENATE BILL NO.
217 "An Act relating to the taxation of independent power
producers; and increasing the efficiency of integrated
transmission system charges and use for the benefit of
ratepayers."
3:32:20 PM
CO-CHAIR GIESSEL announced invited testimony on SB 217.
3:32:11 PM
SENATOR DUNBAR joined the meeting.
3:32:39 PM
ANTONY SCOTT, Director, Economic and Regulatory Analysis,
Renewable Energy Alaska Project (REAP), Anchorage, Alaska,
presented SB 217 on behalf of the administration. He stated that
he is an economist and former commissioner at the Regulatory
Commission of Alaska (RCA), with decades of experience in
economics and policy analysis in the state. REAP is a member-
based organization. Its membership includes public utilities,
independent power producers, labor groups, Native associations,
consumer groups, and others. He moved to slide 2 and detailed
REAP support for SB 217.
[Original punctuation provided.]
REAP supports SB 217
• Creates favorable economic conditions for new
investment that will create ratepayer value by
solving two significant existing problems:
1. Inefficient cost recovery mechanism for
transmission system infrastructure costs impede
economic development and raise rates paid by
consumers
2. Inefficient and inequitable local tax burdens
for Independent Power Producers (IPP) increase
their investment costs and raise rates to
utility customers
• It offers a simple and understandable approach
• It does so with a minimum of overhead costs and
institutional disruption
• It refrains from using overly prescriptive
mechanisms
3:34:42 PM
MR. SCOTT moved to slide 3 and explained wheeling charges:
[Original punctuation provided.]
Inefficient Transmission System Cost Recovery
(current "toll-road" system)
• Significant portion of transmission system costs
are currently recovered through "wheeling rates"
Example: for Homer Electric Assoc to buy power
from a wind producer in Fairbanks, HEA pays for
both cost of generating the power plus the
combined costs to "wheel" the power across the
various components of the Railbelt transmission
system:
o $0.00531/kWh to Golden Valley Electric Assoc
(GVEA) to use its transmission system
o $0.00512/kWh to Alaska Energy Authority (AEA)
to use the Intertie,
o $0.00415/kWh to Matanuska Electric Assoc (MEA)
to use its transmission system
o $0.01412/kWh to Chugach Electric Assoc (CEA) to
use its transmission system
Total transmission wheeling charges = $0.0287/kWh
• The actual costs of transmission are not
increasing with this use, but
• These additional "toll" charges can prevent an
otherwise economic generation project from being
built
MR. SCOTT stated that the inefficiencies in transmission system
cost recovery are a significant issue. A portion of transmission
system costs are recovered not from a utility's own ratepayers
but through wheeling charges. When one utility uses another
utility's transmission system, they pay a $1 per kilowatt-hour
charge for moving electricity over that transmission system.
These charges essentially function as a tax on the transaction
of power generated in one area and consumed in another, and this
tax is quite inefficient. It can be likened to a toll paid on a
road because the costs of the transmission system do not change
even when it is being used. The result is that these individual
wheeling charges can render an otherwise economically beneficial
project uneconomic, preventing the project from proceeding. The
example on the slide illustrates that if Homer wished to
purchase wind power from a development north of the range in
Fairbanks, it would have to pay for the cost of generating that
power to the Independent Power Producer (IPP). Even if Golden
Valley built the wind power themselves, they would still have to
pay for the power's generation cost and the combined cost of
wheeling that power across various components of the rail belt
transmission system. These combined charges amount to almost
three cents per kilowatt-hour, which is enough to prevent the
transaction from happening. This would be unfortunate for
economic development in the Fairbanks region and a loss of value
for Homer ratepayers. It also increases Homer's difficulty in
incorporating more wind power into the system, as having a
geographically diverse source of renewables is beneficial for
overall system reliability. The cost reallocation in this
example, specifically the nearly three cents per kilowatt-hour,
raises concerns.
3:38:11 PM
SENATOR WIELECHOWSKI asked how the wheeling charges are set and
what exactly differentiates these rates. He expressed
appreciation for slide 3, noting that it was the first time he
had seen the information broken down in this way.
3:38:29 PM
MR. SCOTT replied that wheeling charges are set through general
rate cases. Each utility, excluding AEA, determines their rates
through a rate proceeding at the Regulatory Commission of Alaska
(RCA). Utilities calculate their total system costs, which
include their transmission, generation, and distribution
infrastructure. For example, Chugach Electric's transmission
system is used by other parties. In its rate case proceedings,
Chugach allocates a portion of their transmission costs to be
recovered from these other parties. This allocation is often
contentious, but once determined, it is converted into a dollar
per kilowatt-hour or cents per kilowatt-hour rate. Chugach's
total transmission costs are divided based on the agreed-upon
allocation percentage, and this amount is then applied to the
projected power transmitted over their lines by third parties.
3:40:46 PM
SENATOR WIELECHOWSKI noted that Chugach might argue that their
ratepayers have paid higher bills to cover the cost of building
their transmission systems, and that the wheeling charges are
their way of recovering those costs. He questioned how one would
respond to Chugach's position if the company says they are
losing revenue for each kilowatt-hour transmitted through their
system, which their ratepayers have already funded.
3:41:30 PM
MR. SCOTT replied that it is entirely reasonable for Chugach to
argue for cost recovery. However, the allocation of costs and
benefits of transmission infrastructure is inherently arbitrary.
As a former regulator, he explained that while there are various
mechanisms for determining the appropriate split, the process
often involves considerable debate and negotiation, similar to
choosing between different types of cuisine. If a utility can
build transmission infrastructure for the benefit of its own
customers and have others partially cover the costs, it might
not incentivize the construction of the most efficient
transmission systems. All users benefit significantly from being
part of an interconnected grid. This interconnection improves
reliability and increases opportunities for power transactions.
The current system of wheeling charges, which turns a fixed cost
into a variable cost, acts as a tax and reduces these overall
benefits. Moving to a lump sum collection system would allow for
a fairer allocation of system costs without treating them as a
tax on the movement of electricity. This approach would still
involve debate over the best allocation method, but it would
recover costs based on fair system usage rather than per-
kilowatt-hour charges.
3:44:24 PM
SENATOR WIELECHOWSKI asked if a levelized rate, such as seven or
eight cents per kilowatt-hour, would result in other utilities
receiving a bit more for their transmission while Chugach might
receive a bit less. He inquired about how much this might cost
Chugach's customers.
3:44:53 PM
MR. SCOTT replied that SB 217 wouldn't replace multiple wheeling
rates with a single wheeling rate; instead, it would eliminate
wheeling rates altogether. However, he acknowledged that the
question of cost responsibility and the best way to address it
remains. The bill recognizes the need for a gradual transition
to this new cost recovery mechanism, though it does not specify
the pace of this transition. This will be determined by the
interested parties before the RCA. SB 217 acknowledges the
current historical arrangements that produce specific cost
responsibilities and revenue streams. A gradual transition over
a period, such as one to three years or five, might be sensible.
In the interim, the hope is to build new transmission assets,
partly with federal support. REAP supports this and aims to
ensure that new transmission is used efficiently for economic
development and ratepayer benefits. Over time, the lump sum
approach to allocating costs is expected to benefit the greatest
number of people through the integrated planning process managed
by the RRC. This process will involve broad stakeholder input to
determine which transmission projects are needed, the cost
responsibilities, and the methods for cost recovery, ultimately
leading to a more efficient and fair system.
3:47:48 PM
CO-CHAIR BISHOP asked if debt is included in the cost recovery
equation.
3:48:05 PM
MR. SCOTT replied that debt is absolutely part of the cost
recovery equation. He explained that cost recovery encompasses
the entire cost of service, including debt payments,
depreciation, and operation and maintenance (O&M) expenses.
Therefore, the full cost of service associated with transmission
will be recovered.
3:48:32 PM
SENATOR CLAMAN asked if the importance of Grid Resilience and
Innovation Partnerships (GRIP) funding, which provides federal
support for building additional transmission infrastructure
without requiring utilities to finance it themselves and pass
those costs to their ratepayers, is a significant reason why
this approach makes sense today.
3:49:07 PM
MR. SCOTT replied that transitioning from the current system
makes sense regardless of the situation, but it is especially
important given the need to enhance the robustness of the
transmission system, which will involve significant expenditures
from ratepayers, the state, and the federal government. He
emphasized the importance of ensuring that these large
investments provide the greatest value for Alaska consumers.
While there is a strong reason to focus on this now, due to the
new transmission projects, he suggested that the current system
of wheeling charges should be fixed and eliminated even if no
new transmission were ever built.
3:50:21 PM
SENATOR CLAMAN asked if SB 217 would create a structure where
wheeling rates are eliminated for transmission. He inquired if
the bill mandates that, in the absence of federal funds, any new
transmission built will have its rates evaluated at a system-
wide level, ensuring that the transmission cost is uniform
regardless of where electricity enters the grid. He wondered
whether this approach is necessary even without federal funding,
to ensure an equal transmission rate across the system.
3:51:08 PM
MR. SCOTT replied that the legislation would eliminate wheeling
rates entirely. Instead of a unified transmission charge, the
bill proposes that transmission costs be allocated directly on
an annual basis to each load-serving entity. At the beginning of
each year, each utility would receive a bill from the
association detailing their transmission cost responsibility,
such as $25 million for one utility and $35 million for another.
These costs would then be recovered from the load customers. For
example, Chugach would receive a bill for its total transmission
cost responsibility and would recover these costs from its load
customers. This would replace the current system where
transmission costs are embedded in energy and demand charges on
customer bills, even though no separate transmission charges are
itemized. The issue with the current system is not that third
parties contribute, but how they contribute. The $1 per
kilowatt-hour or cents per kilowatt-hour wheeling charges act as
a tax on the movement of electricity.
3:53:36 PM
MR. SCOTT moved to slide 4 and spoke to the new freeway system:
[Original punctuation provided.]
SB 217 Eliminates wheeling rates
(Creates a new "freeway" system)
Steps
1. Adds up all transmission system costs
("ownership")
2. Allocates those costs on an annual lump-sum
basis to each loadserving entity (i.e.
utilities) based on their proportionate load
("cost responsibility")
3. Utilities then recover those costs from
their rate-payers
MR. SCOTT noted that all transmission system costs would first
be pooled into a single bucket. The total costs in this bucket
would then be apportioned to each load-serving utility, though
the exact method for proportionality is not fully detailed in
the legislation. SB 217 would direct the commission to allocate
costs based on each utility's proportionate electricity
consumption relative to the total system consumption. Every end
user benefits from being part of an integrated grid, which
enhances reliability and provides opportunities for transactions
that improve ratepayer value. In the final step, each utility
would recover its allocated transmission costs from its own
customers. Essentially, this replaces the per-kilowatt-hour
wheeling charge for electricity movement with a per-kilowatt-
hour charge included in the utility's overall billing to its
ratepayers. The rate may vary depending on how the cost
responsibility is ultimately apportioned.
3:56:10 PM
CO-CHAIR BISHOP asked for an explanation of the difference
between ownership and cost responsibility.
3:56:34 PM
MR. SCOTT replied that the percentages shown for ownership and
cost responsibility are hypothetical, as he did not have time to
review filings for the current actual numbers. He explained that
entities like AEA, Chugach, MEA, Golden Valley, and Homer own
various transmission assets, such as the Alaska Intertie. The
costs associated with owning these assets include interest
payments, depreciation, and operation and maintenance (O&M)
expenses. These ownership costs make up the annual cost of
maintaining the assets. If SB 217 becomes law, the cost
responsibility for the entire system would be allocated based on
percentages determined through a regulatory proceeding. These
percentages would be based on load ratio shares and other
factors reviewed during the regulatory process.
3:58:47 PM
MR. SCOTT moved to slide 5 and spoke to the transmission cost
allocation approach:
[Original punctuation provided.]
SB 217 Transmission Cost Allocation Approach
• An "Association" made up of all transmission-
owning entities calculates total system ownership
costs and files a tariff to be regulated by the
RCA
• The "Association" is essentially an accounting
construct established to manage the cost
allocation process
• Alaska's telecom industry employs a similar kind
of association currently the Alaska Exchange
Carriers Association (AECA) created via AS
42.05.850
• AECA has just one paid employee
MR. SCOTT addressed the cost allocation process and ownership of
the transmission tariff under SB 217. He clarified that the
tariff would not be levied on a cents per kilowatt-hour basis
but as a lump sum to each utility, which would then recover
these costs from their customers. The proposed association would
comprise all transmission-owning entities. Although it might
initially seem intimidating, he likened it to the Alaska
Exchange Carriers Association (AECA), established under AS
42.05.850. AECA, an industry association of intra-state and
interstate inter-exchange carriers, performs a similar cost and
revenue allocation exercise. He noted that AECA's role is
essentially an accounting exercise managed with minimal
overhead, as it operates with just one employee and files annual
tariffs with the Commission. The members, who are the affected
inter-exchange carriers, handle the necessary accounting tasks.
He emphasized that the intent behind SB 217 is to create a
straightforward, low-overhead organization focused on
bookkeeping, similar to AECA.
4:01:17 PM
MR. SCOTT moved to slide 6 and spoke to the taxation process:
[Original punctuation provided.]
SB 217 Addresses Inequitable Tax Burden For
Independent Power Producers (IPP)
• Municipal and Cooperative Electric utilities are
exempt from state income and local property taxes
• This helps ensure lowest cost of energy, as
property taxes are passed along to consumers in
their utility rates
• IPPs must recover all costs in the rates they
negotiate with purchasing cooperatives or
municipal utilities
• Property taxes can be a very substantial portion
of those rates
• Existing property tax rates can and do prevent
IPP projects from progressing, which ultimately
impact ratepayer costs
• No property taxes can be collected from unbuilt
or failed power projects
MR. SCOTT said that municipally or cooperatively owned electric
utilities are exempt from state income tax and local property
taxes. The policy rationale is that without these exemptions,
such taxes would be passed on to consumers through higher
utility rates. Independent power producers (IPPs), however, must
recover all their costs through the rates they negotiate with
purchasing cooperatives and municipalities. This means that any
taxes imposed on IPPs can significantly increase the rates
charged to consumers, potentially making some projects
economically unfeasible. This creates an uneven playing field
that can hinder project development and negatively impact
ratepayers in two ways: by increasing costs for projects that do
proceed and by preventing many projects from moving forward at
all. MR. SCOTT suggested that if it is reasonable to exempt
cooperatives from property taxes on their own generation and
transmission assets, it would also make sense to extend this
exemption to IPPs selling power to cooperatively owned
utilities. Addressing both issues would alleviate a significant
burden on project development in the state, delivering greater
value to consumers, creating jobs, and fostering a more robust
state economy.
4:04:01 PM
CO-CHAIR GIESSEL concluded invited testimony and opened public
testimony on SB 217.
4:04:39 PM
MATTHEW PERKINS, representing self, Anchorage, Alaska, testified
in support of SB 217. He introduced himself as the CEO of Alaska
Renewables and said the company is working on several large
power plants aimed at providing low-cost, reliable energy to the
Railbelt. He sought support for two critical policies: property
tax exemptions for independent power producers (IPPs) and the
elimination of tariffs between electric cooperatives and IPPs.
These changes would help reduce rates, remove barriers to
collaboration, and increase competition. The difference between
export resource financing and domestic renewable energy market
financing. IPP contracts are structured as long-term fixed-price
agreements with financial inputs contracted upfront, making any
taxes a pass-through cost to consumers. He also noted the
importance of removing barriers to collaboration among
utilities, citing the pooling of projects like Shovel Creek and
Little Mount Susitna as an example that could significantly
reduce no-wind periods. He raised concerns about specific issues
in the bill's wording: a redundant tax on kilowatt-hours
generated by IPPs and ambiguity regarding the removal of
wheeling rates. He requested support for these free-market
principles and limited government intervention, and asked for
amendments to the bill to eliminate the double tax and ensure
the full removal of wheeling tariffs.
SENATOR CLAMAN asked that Mr. Perkins be allowed to briefly
address Senator Wielechowski's question.
4:07:32 PM
MR. PERKINS said that in response to Senator Wielechowski's
question about the benefits to Chugach's members or any electric
cooperative members, the numbers are indeed calculable. He
mentioned that he is working with the dispatch and engineering
teams to determine specifics. He emphasized that the broader
economic benefit comes from allowing more arbitrage among
markets, aligning with fundamental free market principles. The
benefit, as shown by their modeling and other reviewed models
related to energy on the Railbelt, is significantly greater than
minor differences in individual gains, such as one group making
10 cents versus another making 11 cents. In response to Senator
Claman's question about transmission costs, he explained that it
is most likely that for each project, transmission lines will
need to be built, increasing the associated costs. These costs
would be included in the total Power Purchase Agreement (PPA)
for the project and recovered through the sale of electricity to
participating utilities.
4:09:02 PM
CO-CHAIR BISHOP asked if he is referring to building
transmission lines, meaning constructing a line from the project
to the substation.
MR. PERKINS replied yes.
4:09:37 PM
PENNY GAGE, representing self, Anchorage, Alaska, testified in
support of SB 217. She introduced herself as the Managing
Director for Launch Alaska, a nonprofit focused on accelerating
the energy transition by integrating the latest technologies
into Alaska's energy, transportation, and industrial sectors.
Launch Alaska works with a portfolio of 32 for-profit startup
companies from around the world, addressing climate challenges
and creating economic opportunities in Alaska. She expressed
support for SB 217, particularly the provision that would grant
independent power producers (IPPs) the same local tax exemption
received by non-profit electric cooperatives. Gage noted that
Launch Alaska's CEO, Isaac Vanderburgh, who was appointed by
Governor Dunleavy to the Alaska Energy Security Task Force, co-
chaired the incentives and subsidies subcommittee. This tax
provision change was a key recommendation in the final report of
that task force, which Mr. Vanderburgh championed. The provision
would attract private investment, support energy development,
and lower energy costs for Alaskans. However, according to a
Department of Energy (DOE) report, less than five percent of
Alaska's electricity is generated by IPPs, compared to over 40
percent in lower 48 states. SB 217 would send a positive market
signal to investors and developers, accelerate the deployment of
low-cost renewable energy, level the playing field, diversify
the electricity mix, and support job creation.
4:12:06 PM
DOUG JOHNSON, representing self, Anchorage, Alaska, testified in
support of SB 217. He introduced himself as the Director of
Development for Ocean Renewable Power Company and said the
company has been actively developing hydrokinetic power in
Alaska since 2006. SB 217 would provide a thoughtful, elegant,
and workable solution to two key problems facing the energy
industry. The first problem as the inequity in taxation of
independent power producers (IPPs), requiring the need for a
level playing field for all power producers. The second issue is
the application of wheeling charges across the Railbelt. He
highlighted the need for a standardized and proportionate cost
recovery mechanism as envisioned in SB 217. The bill offers a
straightforward approach to addressing these industry challenges
in Alaska. He expressed a desire for the swift resolution of
these issues through the passage of SB 217, emphasizing its
critical importance to the future of the emerging industry.
4:13:46 PM
KEN HUCKEBA, representing self, Wasilla, Alaska, testified in
opposition to SB 217. He stated that much of the support for SB
217 is based on fictitious claims. He characterized the bill as
a 'gold rush grab' for Inflation Reduction Act (IRA) funds by
opportunists seeking to advance the transition to green New Deal
policies. SB 217 focuses solely on eliminating transmission
charges, particularly benefiting independent power producers
(IPPs) of solar and wind energy. However, he argued that these
energy sources are unreliable, with wind farms producing only
around 30 percent of their capacity even on good days. On
windless, snow-covered days, they contribute nothing,
exacerbating costs for utilities and ratepayers who must back
them up with reliable power sources. Existing utilities, owned
by ratepayers and cooperatives, are forced to cover the costs
associated with the poor performance of these renewable energy
sources. He criticized the bill for allowing IPPs to operate
without contributing to the costs of maintaining and upgrading
the legacy energy system. The tax savings touted by the bill
come from taxpayers and existing infrastructure owners, rather
than some external source. He rejected the idea that renewable
energy sources are truly lower in cost. Their affordability is a
result of subsidies and the absence of charges for the
additional impacts they cause. He described SB 217 as a takeover
of infrastructure by special interests. He also criticized the
use of the term 'stakeholders,' asserting that these entities do
not represent ratepayers or taxpayers. The United States is a
representative republic that should prioritize the interests of
its citizens, not special interest groups or nonprofit NGOs.
4:16:27 PM
DAVID BRAILEY, representing self, Eagle River, Alaska, testified
in support of SB 217. He noted that he is one of the owners of
the Juniper Creek hydroelectric system in Eagle River, a 300-
kilowatt facility with a 60 percent capacity factor, meaning it
operates at full capacity 60 percent of the year. He
acknowledged that he could not improve on former Commissioner
Scott's explanation of why the bill is beneficial for the grid,
independent power producers, and ratepayers. He emphasized that
because the bill is good for ratepayers, it is also beneficial
for cooperative utilities. He shared his experience, noting that
he has been working on his project for about 13 years, though it
has not produced electricity for the past three years. He
expressed that the Alaska rail belt market is one of the most
disadvantageous for independent power producers in the United
States. He believes that SB 217 would help level the playing
field between independent power producers and utilities, turning
things around in favor of a more balanced energy market.
4:18:11 PM
SENATOR WIELECHOWSKI asked what recommendations could be made to
improve the situation so that the state is more open to
independent power producers (IPPs) and other potential utility
generation options.
4:18:28 PM
MR. BRAILEY replied that Alaska's Railbelt is one of the few
places in the United States where capacity has zero value,
despite being allowed by regulation. He noted that no renewable
energy producer or independent power producer (IPP) has ever
been paid for capacity in the Alaska Railbelt. Zero emissions
have no value in Alaska, as there is no market for renewable
energy credits. He explained that all power purchase agreements
between IPPs and utilities in the state require the IPPs to give
away at least 50 percent to 100 percent of their renewable
energy credits. He questioned why a private business would give
away something of value and explained that the condition of
interconnection, particularly with his utility, Matanuska
Electric, forces the IPP to cover all interconnection and
integration costs, including building the interconnecting power
line. Despite these costs, the utility still takes the renewable
energy credit. He described the situation as a monopsony system,
where utilities hold all the cards. If an IPP disagrees with the
terms of the agreement, they are told to find another buyer, but
that option is blocked by pancaking charges that prevent selling
to another utility. The system is rigged in favor of the
utilities.
4:20:41 PM
JENN MILLER, representing self, Houston, Alaska, testified in
support of SB 217. She stated that she is the CEO of Renewable
IPP, an Alaska-grown small business focused on developing,
constructing, and operating renewable energy projects in Alaska.
She mentioned their Willow and Houston projects and spoke to the
company's dual commitment to advancing renewable energy and
suppressing energy prices for Alaskans. She said she recently
served on the governing Energy Security Task Force, which
aligned with their mission to diversify energy generation,
improve affordability, and maintain reliability. Independent
power producers (IPPs) play a crucial role in this
diversification and affordability, while also meeting
reliability standards. For their projects to advance, they must
agree on power purchase agreements with utilities and remain
competitive with current generation costs. The Houston project
is currently 10 to 20 percent below the existing cost of
generation, making it essential to have a level playing field.
SB 217 would equalize their cost base by addressing property
taxes and eliminating pancaking charges. This would help reduce
their power purchase prices and, in turn, lower costs for
utility members. Additionally, having an established tax policy
for IPPs would reduce uncertainty for investors and incentivize
private investment in new generation projects. This would aid in
deploying various energy sources, including wind, solar, and
hydro, contributing to a more stable energy supply. She
emphasized the urgency of passing this bill to incorporate
reduced cost bases into power purchase agreements and pass those
savings onto members.
4:24:24 PM
CO-CHAIR GIESSEL closed public testimony on SB 217.
4:24:41 PM
CO-CHAIR GIESSEL held SB 217 in committee.
^Presentation: Alaska Energy Authority (AEA)
PRESENTATION(S): ALASKA ENERGY AUTHORITY (AEA)
4:24:44 PM
CO-CHAIR GIESSEL announced the consideration of a presentation
by Alaska Energy Authority (AEA).
4:25:14 PM
CURTIS THAYER, Executive Director, Alaska Energy Authority
(AEA), Anchorage, Alaska, moved to slide 2 and presented an
overview of AEA:
[Original punctuation provided.]
About AEA
AEA's mission is to reduce the cost of energy in
Alaska. To achieve this mission, AEA strives to
diversify Alaska's energy portfolio increasing
resiliency, reliability, and redundancy.
Railbelt Energy - AEA owns the Bradley Lake
Hydroelectric Project, the Alaska Intertie, and the
Sterling to Quartz Creek Transmission Line all of
which benefit Railbelt consumers by reducing the cost
of power.
Power Cost Equalization (PCR) - PCE reduces the cost
of electricity in rural Alaska for residential
customers and community facilities, which helps ensure
the sustainability of centralized power.
Rural Energy - AEA constructs bulk fuel tank farms,
diesel powerhouses, and electrical distribution grids
in rural villages. AEA supports the operation of these
facilities through circuit rider and emergency
response programs.
Renewable Energy and Energy Efficiency - AEA provides
funding, technical assistance, and analysis on
alternative energy technologies to benefit Alaskans.
These include biomass, hydro, solar, wind, and others.
Grants and Loans - AEA provides loans to local
utilities, local governments, and independent power
producers for the construction or upgrade of power
generation and other energy facilities.
Energy Planning - In collaboration with local and
regional partners, AEA provides economic and
engineering analysis to plan the development of cost-
effective energy infrastructure.
MR. THAYER stated that Alaska's Railbelt is one of the few
places in the United States where capacity has zero value,
despite being allowed by regulation. He noted that no renewable
energy producer or independent power producer (IPP) has ever
been paid for capacity in the Alaska Railbelt. Zero emissions
have no value in Alaska due to the absence of a market for
renewable energy credits. He explained that all power purchase
agreements between IPPs and utilities in the state require the
IPPs to give away at least 50 percent to 100 percent of their
renewable energy credits. He questioned why a private business
would give away something of value and explained that the
condition of interconnection, particularly with his utility,
Matanuska Electric, forces the IPP to cover all interconnection
and integration costs, including building the interconnecting
power line. Despite these costs, the utility still takes the
renewable energy credit. He described the situation as a
monopsony system, where utilities hold all the cards. If an IPP
disagrees with the terms of the agreement, they are told to find
another buyer, but that option is blocked by pancaking charges
that prevent selling to another utility. The system is rigged in
favor of the utilities.
4:28:57 PM
MR. THAYER moved to slide 3 depicting a map that illustrates all
the projects AEA operates across Alaska for a specific day or
month, highlighting both the Railbelt region and rural areas.
4:29:13 PM
MR. THAYER moved to slide 4 and explained the Alaska Energy
Security Task Force:
[Original punctuation provided.]
Alaska Energy Security Task Force
60+
Subcommittee Meetings
11
Task Force Meetings
150+
Hours of Public Meetings
8
Energy Symposiums with 16 hours of OnDemand learning
6
Subcommittees have created over 60 preliminary actions
for considerations:
• Railbelt Transmission, Generation, and Storage
• Coastal Generation, Distribution, and Storage
• Rural Generation, Distribution, and Storage
• State Energy Data
• Incentives and Subsidies
• Statutes and Regulations
MR. THAYER stated that the task force, convened by the governor
and chaired by the Lieutenant Governor with him serving as a co-
chair, included notable members such as Jen Miller and Senator
Bishop. The University facilitated 16 hours of energy symposiums
that offered educational sessions on topics including PCE,
hydro, and nuclear energy. He noted that while there is no
single solution for Alaska's energy challenges, the ideas and
concepts from the task force have influenced current
legislation, including SB 217, reflecting a collaborative effort
to address diverse energy needs.
4:30:49 PM
MR. THAYER moved to slide 6 and described the Bradley Lake
Hydroelectric project:
[Original punctuation provided.]
Bradley Lake Hydroelectric Project
• Bradley Lake is Alaska's largest source of
renewable energy. Energized in 1991, the project
is situated 27.notdefair miles northeast of Homer on
the Kenai Peninsula.
• The 120 MW facility provides low-cost energy to
550,000+ members on the Railbelt.
• Bradley Lake's annual energy production is ~10
percent of Railbelt electricity at 4.5 cents/kWh
(or ~54,400 homes/year) and over $20 million in
savings per year to Railbelt utilities from
Bradley Lake versus natural gas.
• AEA, in partnership with the Railbelt utilities,
is studying the Dixon Diversion Project which
would increase the annual energy production of
Bradley Lake by 50 percent or the equivalent of
14,000-28,000 homes.
CAPACITY: 120MW
• Bradley Lake generators are rated to produce up
to 120 MW of power
ENERGY: 10 percent
• Bradley Lake generates about 10 percent of the
total annual electrical energy sued by Railbelt
electrical utilities
GENERATION COST PER KWH: $0.04
• From 1995 through 2023 the project averaged
390,000 MWh of energy production annually at
$0.04 per kWh.
MR. THAYER noted that the Dixon Diversion project would displace
1.5 billion cubic feet of natural gas, or 7.5 percent of the
unmet needs by 2030.
4:32:05 PM
CO-CHAIR GIESSEL asked when the Dixon Diversion project would be
completed.
4:32:14 PM
MR. THAYER replied that AEA is conducting the field season this
year and potentially into next year. He anticipated that
construction could begin as early as 2026, with a projected
completion in 2030.
4:32:38 PM
SENATOR KAWASAKI asked whether there are maintenance
requirements.
4:33:02 PM
MR. THAYER said that the Bradley Lake Management Committee,
consisting of the CEOs of each of the Railbelt utilities and
AEA, oversees the management of the Bradley Lake facility. The
utilities handle the operation and maintenance (O&M) of the
facility through Homer Electric. Bradley Lake, a 32-year-old
facility designed for a 100-year lifespan, is well-maintained.
Recent work included a comprehensive maintenance review and
turbine overhaul, and the facility continues to perform well.
4:34:05 PM
CO-CHAIR GIESSEL noted that Juneau power is sourced from 100-
year-old dams.
4:34:12 PM
SENATOR CLAMAN asked if the Dixon diversion project is confirmed
to proceed. He inquired whether a final decision has been made
or if it is still under study. He wondered about the timeline
for construction.
4:34:25 PM
MR. THAYER replied that the Dixon diversion project is still
under study and is approximately 18 months away from a final
decision. He explained that the environmental studies related to
the Federal Energy Regulatory Commission (FERC) license
amendment are ongoing, and no issues have been identified thus
far. Regarding construction costs, he noted that the estimated
cost has been reduced. Initially, a 14-foot borehole was
planned, but testing indicated more seasonal water flow than
expected, allowing for an increase in the facility's size.
Additionally, the need for a road to the dam diversion has been
eliminated since the area is snow-covered for seven months a
year; a helicopter can be used instead. The utilities' modeling
suggests that the project can be built at a lower cost than
producing power from natural gas, and with rising natural gas
prices, the project appears promising. Further testing and work
will continue this summer.
4:35:53 PM
SENATOR CLAMAN inquired about funding sources assuming the
project moves forward.
4:36:02 PM
MR. THAYER stated that one potential funding method for the
Dixon diversion project is revenue bonds, which AEA could
utilize based on a power sales agreement for the sale of
electricity. This approach is similar to how Bradley Lake was
financed. Additionally, there is a federal grant available
through the EPA for up to $342 million, which AEA plans to apply
for. Although this grant is considered a long shot and does not
require a state match, AEA is pursuing it as an option. He
reiterated that the most straightforward approach remains the
power sales agreement.
4:36:39 PM
SENATOR CLAMAN commented that he hopes the federal grant
application is not merely a "Hail Mary."
4:36:42 PM
MR. THAYER replied that there is a competitive process for those
federal dollars.
4:36:47 PM
CO-CHAIR BISHOP acknowledged the potential impact of the data
presented. He highlighted that with 120 megawatts (MW) from the
project, it represents 10 percent of the total power on the
Railbelt. If Susitna were utilized, it could increase to up to
70 percent, potentially replacing all the gas-generated power on
the Railbelt.
4:37:10 PM
MR. THAYER replied that is correct.
4:37:17 PM
MR. THAYER moved to slide 7 and highlighted the Alaska Intertie:
[Original punctuation provided.]
Alaska Intertie
• AEA owns the 170-mile Alaska Intertie
transmission line that runs between Willow and
Healy. The line operates at 138 kV (it was
designed to operate at 345 kV) and includes 850
structures.
• A vital section of the Railbelt transmission
system, the Intertie is the only link for
transferring power between northern and southern
utilities.
• The Intertie transmits power north into the
Golden Valley Electric Association (GVEA) system
and provides Interior customers with low-cost,
reliable power between 2006 and 2023, the
Intertie saved GVEA customers an average of $36
million annually.
• The Intertie provides benefits to Southcentral
customers as well through cost savings and
resilience to unexpected events.
• Constructed in the mid.notdef1980s with $124 million in
State of Alaska appropriations, there is no debt
associated with the Alaska Intertie.
MR. THAYER noted that noted that the Alaska Intertie, spanning
170 miles from Windward to Healy, was constructed in the mid-
1980s to connect South Central Alaska with Fairbanks. This
intertie enables Fairbanks to purchase power more economically
from the Railbelt, resulting in annual savings of approximately
$36 million for Bonavista customers. The intertie benefits South
Central customers through cost savings and increased resilience
during unexpected events, such as severe cold weather in
January. He emphasized the need for modernization of the
transmission infrastructure. The SSQ line, which includes
Sterling, Scott, and Port St. Peninsula, was built in 1969 and
has not been updated since. Currently, it supports only 75
megawatts, while Bradley's 120-megawatt power plant operates at
full capacity. To accommodate additional renewable sources such
as solar, wind, or tidal energy, the transmission lines must be
upgraded to handle the increased load.
4:38:01 PM
MR. THAYER moved to slide 8 and explained the need to modernize
the Railbelt Transmission system:
[Original punctuation provided.]
Railbelt Transmission System Urgently Needs
Modernization
The majority of the Railbelt transmission system was
constructed over 40 years ago. A resilient, reliable,
and redundant Railbelt transmission system is not only
achievable but also necessary to create the needed
capacity to integrate additional renewable energy in
the future.
Grid Forming
A grid with alternate paths will increase reliability,
resiliency, and fuel diversification.
Fuel Savings
Upgrades and alternate paths will reduce line losses.
Energy Security
Natural or other events can isolate cities or regions
from energy
Generation Changes
New renewable energy projects are not located in
existing cities. New transmission to connect new
renewable projects to existing transmission paid for
by projects. However, existing transmission must be
upgraded to transmit energy to and between the
Railbelt regions.
MR. THAYER said that there is an urgent need to modernize
the transmission system, particularly the SSQ line, which
includes Sterling, Scott, and Port St. Peninsula. This
line, built in 1969, has not been updated since its
construction. Currently, the line supports only 75
megawatts, while Bradley's power plant operates at full
capacity with 120 megawatts. To integrate additional
renewable sources such as solar, wind, or tidal energy, the
state must upgrade the transmission lines. He spoke to a
photo showing part of the SSQ line, which depicts a
helicopter removing an old pole; part of an agreement with
Alaska Fish and Wildlife when the line was purchased. As a
commitment to being good neighbors, the line was removed
within two years of the agreement, even though the deadline
was set for five years. This demonstrates AEA's dedication
to maintaining positive relations and ensuring that
upgrades are well-regarded by all stakeholders.
4:39:11 PM
MR. THAYER moved to slide 9 and elaborated on GRIP funding:
[Original punctuation provided.]
Grid Resilience and Innovation Partnerships (GRIP):
HDVC Line
$413 Million (206.5 Million Federal and $206.5 Million
Alaska Match)
AEA secured $206.5 million for GRIP Topic Area 3: Grid
Innovation through the United States Department of
Energy's Grid Deployment Office. A cost share of 100
percent, or $206.5 million, is required for a total
project amount of $413 million. The Railbelt
Innovation Resiliency project will construct a high -
voltage direct current (HDVC) submarine cable to serve
as a parallel transmission route from the Kenai
Peninsula to Anchorage, creating a much -needed
redundant system in case of disruptive events.
Anticipated outcomes and benefits include:
Increases transfer capacity between regions that
enables higher renewable energy integration into the
electricity system.
Improves resilience and reliability for tribal and
disadvantaged communities in the Railbelt region, and
a reduction in reliance on fossil fuel generation and
associated emissions.
Supports the retention of high-quality jobs in the
region, including 650 highly paid jobs with
competitive employer -sponsored benefits.
Creates apprenticeship and internship programs to
train a new generation of line workers and wireworkers
to reinvigorate Alaska's energy workforce.
MR. THAYER said that the major focus is on the GRIP funding,
which aims to install a High Voltage Direct Current (HVDC) line
from Kenai to Beluga, crossing beneath Cook Inlet. This line,
highlighted by the broken yellow line on the map, has a total
projected cost of $413 million, with $206.5 million covered by a
federal grant and an equal amount required as a cost match from
other sources. The initial and most critical phase of the
project involves the HVDC line, which will provide essential
redundancy. In contrast to the lower 48 states, where redundancy
requirements are more stringent, we have been relying on a
single line for over 40 years. For example, during the recent
SSQ line fire, power was cut off for four months, costing
northern utilities an additional $12 million due to the
inability of existing infrastructure to handle the load.
Similarly, during recent winter storms, a week-long outage
between Goodwood and Whittier highlighted the vulnerabilities of
our current system. The HVDC line is crucial for improving grid
resilience. In the GRIP funding cycle, there were 700
applications, and our project was awarded the fifth highest
amount in the nation. This success is a testament to the
collaborative effort of the utilities and their collective
support for the grant application. Securing this funding
represents a significant step forward, but AEA still needs to
secure the remaining funds to complete the project.
4:41:26 PM
CO-CHAIR GIESSEL asked for confirmation of her understanding
that it makes that imperative for funding.
MR. THAYER replied yes.
4:41:34 PM
MR. THAYER replied that it is not necessary to secure all the
funding within the first year. The Department of Energy requires
a commitment to the total funding but will match contributions
as they are made. For example, if we contribute $20 million,
they will provide an additional $20 million. The project follows
a bell curve in terms of funding: initial costs will ramp up,
particularly during the ordering and construction phases of the
HVDC line, and then decrease as the project progresses. The
project is planned to span eight years, though there are several
challenges, including securing a manufacturer for the HVDC line.
Only five companies worldwide can produce this technology, and
we are competing with other HVDC projects both nationally and
globally. Despite these challenges, the aim is to complete the
project within the eight-year timeframe unless an extension is
mandated by legislative action, which is not the current plan.
4:42:27 PM
SENATOR CLAMAN inquired about the state match of $206.5 million,
asking if it needs to be provided over the course of the eight-
year project, rather than in the first year.
4:42:41 PM
MR. THAYER replied that is correct. He said the full amount is
not required in the first year. However, by years three and
four, we will need to reach peak cash flow levels. This is due
to the requirement to pay 20 percent upfront when ordering the
HVDC line, with the remainder due as production progresses over
the following three to four years, given the lead time involved.
4:43:03 PM
CO-CHAIR GIESSEL commented that the revenue does not increase.
4:43:08 PM
SENATOR CLAMAN asked whether the state is the only entity that
can provide the match, or if utility companies could bond and
provide the match independently of state funding.
4:43:21 PM
MR. THAYER replied that the match simply needs to be identified;
it does not have to come solely from the state. It can be
comprised of a combination of sources.
4:43:37 PM
CO-CHAIR BISHOP noted concerns about the reliability of
legislative commitments. He said his goal is to secure all
necessary funding this year with broad support to demonstrate a
strong commitment to upgrading the transmission line. He
expressed this sentiment based on historical information he has
shared with his office.
4:44:11 PM
MR. THAYER expressed his appreciation for that sentiment.
4:44:21 PM
MR. THAYER moved to slide 10 and elaborated on the Dixon
Diversion project:
[Original punctuation provided.]
Dixon Diversion Project
$5-7 Million for Studies and $342 Million for
Construction
AEA is studying the Dixon Diversion Project to
optimize the energy potential of the AEA-owned Bradley
Lake Hydroelectric Project. Like the West Fork Upper
Battle Creek Diversion Project, the Dixon Diversion
Project would divert water from Dixon Glacier in order
to increase Bradley Lake's annual energy production by
50 percent.
• Located five miles from Bradley Lake and would
utilize existing powerhouse at Bradley Lake
• Estimated annual energy 100,000-200,000 MWh
(~24,000-30,000 homes)
• Estimated to offset 1.5-1.6 billion cubic feet of
natural gas per year in Railbelt power generation
(equal to 7.5 percent of Alaska's unmet natural
gas demand projected for 2030)
• Estimated completion is 2030
• *Funding will be used for engineering studies
(feasibility, hydrological, geological) and
environmental studies (fisheries, water quality,
geomorphology).
MR. THAYER said that the Dixon diversion project, which is
currently underway, involves several components visible on the
map. The project includes Bradley Lake (marked in orange), where
the dam would be raised, and the powerhouse located above the
dam. The Dixon diversion, fed by Nuka Glacier and flowing into
Martin River, is shown as a hot pink line indicating a five-mile
diversion from Martin River to Bradley Lake. This diversion aims
to raise the dam by 14 feet. The project's estimated cost is
$342 million. The primary benefit is a 50 percent increase in
Bradley Lake's capacity, which would offset 1.5 billion cubic
feet of natural gas used in Cook Inlet. Currently, engineering,
feasibility, hydrology, and environmental studies, including
fisheries and water quality assessments, are in progress. Since
the project is an amendment to an existing license rather than a
new license, the approval process is streamlined. There is
consideration of whether the project could be completed by 2029,
although the current target is 2030. Displacing as much natural
gas as possible remains a key objective.
4:46:01 PM
MR. THAYER moved to slide 11 and explained the SSQ transmission
lines:
[Original punctuation provided.]
Sterling to Quartz (SSQ) and Soldotna to Sterling
Transmission Lines
$90 Million (Under Construction)
In 2020, AEA acquired the SSQ Transmission Line, a
critical component of the interconnected Railbelt
transmission system on the Kenai Peninsula, as part of
the Bradley Lake Hydroelectric Project.
• Location 39.4 miles of 115 kilovolt (kV)
transmission and out of use 69 kV transmission
from Sterling to Quartz substation (Kenai Lake)
• Benefits AEA ownership ensures better cost
alignment, increase reliability, and more timely
repairs and upgrades
• Status 69 kV line decommissioned & removed.
Engineers are designing and are procuring
equipment for the upgrade of the existing 115 kV
line to 230 kV. Upgrade will reduce line losses,
increase line reliability and system resiliency
• Cost Estimated cost to upgrade line to 230 kV
standards is $63 million for SSQ and $27 million
for Soldotna to Sterling
MR. THAYER said the next item is the Sterling to Port Creek SSQ
transmission lines, highlighted by the broken yellow line on the
map. This transmission line connects the Homer system to
Chugach, which is currently upgrading their system to 230 kV.
The Sterling to Port Creek line, however, has not been upgraded
in 55 years and is the weakest link in the system. The map shows
the two lines coming out of Homer and the connection to the SSQ
line. The project involves a 40-mile transmission line upgrade,
which cost about $2 million several years ago. When AEA bonded
against Bradley, excess payments from debt service utilities
were used for required project work. The Department of Law has
classified this transmission line upgrade as required project
work, so there is no cost to the state treasury or ratepayers,
as it involves reallocating existing funds. The project is
currently in progress, with ongoing procurement and engineering
activities.
4:47:54 PM
SENATOR DUNBAR asked if, once the HVDC line is complete, there
will be a consideration to reroute power through the HVDC line
to Anchorage, bypassing the Sterling line and the existing lines
coming from Homer.
4:48:11 PM
MR. THAYER replied that it goes back to needing redundancy - two
lines to move power. Beluga has one line and Heely has two lines
to Fairbanks.
4:48:40 PM
SENATOR DUNBAR asked if, once the HVDC line is complete, there
will be a consideration to reroute power through the HVDC line
to Anchorage, bypassing the Sterling line and the existing lines
coming from Homer.
4:49:07 PM
MR. THAYER replied that having redundancy with two lines and two
circuits is essential for reliable power transmission. The
ultimate goal is to connect the HVDC line up to Beluga and then
consider adding another HVDC line from Beluga to Healy. This
would provide redundancy throughout the system, extending
reliability all the way to Fairbanks, while maintaining the two
lines from Healy through Fairbanks.
4:49:50 PM
MR. THAYER moved to slide 12 and explained the battery energy
storage system:
[Original punctuation provided.]
Battery Energy Storage Systems for Grid Stabilization
$194 Million Total Cost ($57 Million Current Available
Funds)
• Scope
o The BESS projects consist of an upgrade to
the existing BESS system in the North, and
also new BESS systems in the Southern, and
Central regions of the grid. The Northern
BESS is located at Fairbanks, the Southern
BESS is located in Kenai, the Central Region
BESS will be located at Anchorage. BESS will
be needed to fully realize the benefits of a
230 kV bulk power supply system, regulate
energy from various generation, and increase
resilience.
• Schedule
o Estimated completion date is 2026:
o Southern (Kenai) In service
o Central (Anchorage) October 2024
o Northern (Fairbanks) To be determined
• Budget
o Estimated cost is up to $194 million
(depending on technology choices and
capacity)
• Benefits
o Increase system resilience, transfer
capability, more efficient use of system and
lowering impediments to additional renewable
generation development
MR. THAYER noted that part of the $166 million bonding accounts
for $57 million allocated for battery energy storage systems.
The total cost to install these systems across all three
locations is approximately $194 million, indicating that they
are currently only a quarter of the way funded. Homer currently
has its system in service, while Anchorage's system is under
construction with an expected completion date of October 2024.
AEA is collaborating with Chugach and MEA to determine the
ownership structure, particularly in terms of maximizing tax
credit benefits, which could potentially cover up to 50 percent
of the costs through tax credits. This is part of the
Infrastructure Investment and Jobs Act (IIJA) and Inflation
Reduction Act (IRA) funding mechanisms that are being explored.
He pointed out that the battery in Fairbanks is 20 years old and
only lasts seven minutes, whereas the new battery in Anchorage
will have a two-hour capacity for 440 megawatts, and Kenai will
have a 40-megawatt battery with a two-hour capacity. For
Anchorage and Fairbanks, the battery systems consist of Tesla
batteries housed in what appear to be white, 20-foot-long Conex
containers laid side by side. These systems can be expanded by
simply adding more connected units. These batteries will
eliminate the need for spinning reserves, where natural gas
generators are kept running in anticipation of power outages.
Instead, the battery will provide that reserve power. The
battery systems will help address minor frequency issues,
including those associated with the Bradley Lake hydroelectric
facility. Although the frequency issues have been largely
engineered out, the batteries will further stabilize the system.
Bradley Lake was designed to have three pits with 40-megawatt
generators. However, only two 60-megawatt generators were
installed, which has led to frequency issues that have since
been mitigated. The implementation of battery storage is the
final step in addressing these engineering challenges.
4:52:44 PM
MR. THAYER moved to slide 13 and spoke to the Grid Resilience
Formula Grant Program:
[Original punctuation provided.]
Grid Resilience Formula Grant Program, IIJA 40101(d)
$60 Million (Over Five Years)
Per IIJA section 40101(a)(1),8 a disruptive event is
defined as "an event in which operations of the
electric grid are disrupted, preventively shut off, or
cannot operate safely due to extreme weather,
wildfire, or a natural disaster."
• Over the next five years, Alaska will receive $60
million in federal formula grants to catalyze
projects to increase grid resilience against
disruptive events. In August 2023, the first two
years of allocations, $22.2 million, was awarded
to AEA. AEA's competitive solicitation for these
funds closed in February 2024. Notification of
sub-awards are expected Q2 2024, pending DOE
approval. For fiscal year 2025, AEA requested
$17,627,018, Alaska's formula allocation for year
3, in Federal Receipt Authority and $1,816,579 in
matching funds.
• Resilience measures include but are not limited
to:
o Relocating or reconductoring powerlines
o Improvements to make the grid resistant to
extreme weather
o Increasing fire resistant components
o Integrating distributed energy resources
like microgrids and energy storage
• Formula-based funding requires a 15 percent state
match and a 33 percent small utility match.
MR. THAYER stated that the state legislature has been very
generous over the past three years. It provided $1.8 million in
matching funds, while AEA leveraged to secure $39 million in
federal funds. The purpose of this program is to implement
resilience measures for utilities, such as relocating and
reconnecting power lines, enhancing resistance to extreme
weather, and installing fire-resistant components. These
improvements will benefit not just the Railbelt but areas across
the state. Once the program is fully implemented, over $60
million will have been allocated to these resilience measures.
He mentioned that the first portion of funding, totaling $22
million, was closed on February 16. AEA is currently working
through the process to allocate an additional $40 million this
spring. Furthermore, they anticipate receiving another $17
million later this year, which will also be distributed
similarly to their Renewable Energy Project (REP) program. The
overall goal is to ensure that over $60 million will be invested
in facilities statewide to bolster their resilience against
various challenges.
4:53:52 PM
MR. THAYER moved to slide 15 and spoke to the EV Infrastructure
Implementation Plan:
[Original punctuation provided.]
State of Alaska Electric Vehicle (EV) Infrastructure
Implementation Plan
• AEA and the Alaska Department of Transportation &
Public Facilities (DOT&PF), continue their
partnership in deploying the State of Alaska EV
Infrastructure Implementation Plan (The Plan).
• The first round of Alaska NEVI awards was
announced on September 25, 2023. AEA and DOT&PF
selected projects in nine communities for a total
investment of $8 million. The $6.4 million in
NEVI funding will be matched with $1.6 million
from private entities selected to install, own,
and operate the new EV charging stations.
• On September 29, 2023, the Federal Highway
Administration approved the fiscal year 2024
plan. This unlocked $11 million in addition to
$19 million available in the fiscal years 2022
and 2023.
• Phases 2 and 3 of The Plan will develop charging
infrastructure in more than 30 communities along
the Marine Highway System and in hub communities
as funding allows.
MR. THAYER said that federal funding opportunities for electric
vehicle (EV) infrastructure amount to $52 million, administered
through the Alaska Department of Transportation & Public
Facilities (DOT&PF). AEA developed an EV plan and has taken the
lead in managing this funding, with DOT handling the back-office
accounting. This arrangement has enabled $20 million to be
allocated for immediate projects. The primary focus is on
creating an alternative fuel corridor between Anchorage and
Fairbanks, which will feature nine charging stations. Plans
include extending the network south to Homer and north to the
Dalton Highway, as well as incorporating the marine highway
system. Communities served by the marine highway are eligible
for EV charging stations in their ports and service areas,
although not on the ferries themselves. AEA's EV plan was among
the top six in the country, leading to an early allocation of
funds due to the plan's high quality. The Federal Highway
Administrator specifically highlighted Alaska in the
announcement of the funding.
4:55:19 PM
MR. THAYER moved to slide 16 and spoke to home energy rebate
allocations:
[Original punctuation provided.]
Home Energy and High Efficiency Rebate Allocations
AEA is collaborating with the Alaska Housing Financing
Corporation to distribute Alaska's allocation of $74
Million
Home Efficiency Rebates
• Rebates for energy efficiency retrofits range
from $2,000-$4,000 for individual households and
up to $400,000 for multifamily buildings.
• Grants to states to provide rebates for home
retrofits.
• Up to $2,000 for retrofits reducing energy use by
20 percent or more, and up to $4,000 for
retrofits saving 35 percent or more.
• Maximum rebates amounts are doubled for retrofits
of low-and moderate-income homes.
• Alaska's Allocation is $37.4 million.
• No State match is required.
• Funding is estimated to be available between fall
2024 and spring 2025.
Home Electrification and Appliance Rebates
• Develop a high efficiency electric home rebate
program.
• Inclusive of means testing and will provide 50
percent of the project cost for incomes ranging
from 80 percent to 150 percent of area median
income. Rebates to cover 100 percent of the
proposed cost for incomes 80 percent of area
medium income and below, with similar tiers
applied for multifamily buildings.
• Includes a $14,000 cap per household, with an
$8,000 cap for heat pump costs, $1,750 for a heat
pump water heater, and $4,000 for electrical
panel/service upgrade.
• Other eligible rebates include electric stoves,
clothes dryers, and insulation/air sealing
measures.
• Alaska's Allocation is $37.1 million.
• No State match is required.
• Funding is estimated to be available between fall
2024 and spring 2025.
MR. THAYER added that Alaska Housing has taken the lead and AEA
would perform some of the accounting. However, the money will
not be available until late 2024-2025.
4:56:27 PM
MR. THAYER moved to slide 17 and summarized the Black Rapids
Training Site (BRTS) Defense Community Infrastructure Pilot
program:
[Original punctuation provided.]
Black Rapids Training Site (BRTS) Defense Community
Infrastructure Pilot Program
$15.7 Million
AEA partnered with Golden Valley Electric Cooperative
(GVEA) was awarded this grant from the Office of Local
Defense Community Cooperation under the Defense
Community Infrastructure Pilot Program. Federal
Receipt Authority of $12.7 Million received in fiscal
year 2024. A $3 million supplemental budget request
was submitted by AEA to complete additional work
requested by the Department of Defense. No State match
is required.
GVEA will use the funds to extend a transmission line
34 miles along the Richardson Highway to BTRS.
Currently, BTRS is powered by three diesel generators
that are nearing the end of their useful lives. This
extension will improve long-term sustainability and
reliability for BRTS by tying them into GVEA's power
grid.
MR. THAYER noted that no state match is required and highlighted
the quick turnaround of the application process, which resulted
in securing the grant.
4:57:14 PM
MR. THAYER moved to slide 17 and listed other federal funding
opportunities:
[Original punctuation provided.]
Other Federal Funding Opportunities
Energy Efficiency Revolving Loan Fund $4.5 million
$4,569,780 to establish and capitalize a revolving
loan fund, under which the State shall provide loans
and grants for residential energy audits, upgrades,
and retrofits to increase energy efficiency, physical
conform and air quality of existing building
infrastructure. AEA will administer the program in
collaboration with the Alaska Housing Finance
Corporation (AHFC).
State Energy Program $3.6 million
$3,661,930 to develop Statewide Energy Plan and
Statewide Energy Security Profile, as well as (1)
update AkWarm Energy Modeling Software to the
requirements imposed by the Inflation Reduction Act
and (2) modernize Alaska Retrofit Information Systems
database to accept the AkWarm modifications in
collaboration with AHFC.
Electric Vehicle (EV) Charging Equipment Competitive
$1.6 million
$1,670,000 to (1) increase access to vehicle
electrification in multiple rural and underserved
communities across Alaska; (2) demonstrate the
benefits of EVs to key decision-makers and the broader
public to accelerate clean transportation transition;
and (3) support the development of community charging
equipment. A 20 percent match is required, shared by
AEA and project partners. Funds will become available
in Fall 2023.
State-Based Home Energy Efficiency Contractor Training
Grant Program $1.3 million
$1.3 million to fund a State-Based Home Energy
Efficiency Contractor Training Grant Program to
develop and implement a state workforce energy program
that prepares workers to deliver energy efficiency,
electrification, and clean energy improvements,
including those covered by the Inflation Reduction Act
Home Energy Rebate Programs.
MR. THAYER reiterated that AEA will partner with Alaska Housing
to administer the programs.
4:58:21 PM
MR. THAYER moved to slide 19 and discussed solar for all
competition:
[Original punctuation provided.]
Solar For All Competition
$100 Million (Application Pending)
• AEA and AHFC collaborating to develop a Statewide
Solar Program:
• AEA focus on development of community solar
projects in disadvantaged communities using a
Renewable Energy Fundstyle grant program.
o AHFC focus on residential rooftop solar for
low income households.
• Program benefits include:
o energy cost savings, increased resiliency,
equitable access to solar, asset ownership
benefits low income and disadvantaged,
communities, workforce development, and
reduction in greenhouse gas emissions.
• This is a competitive grant program no match
required.
• AEA and AHFC submitted an application for a $100
million grant.
MR. THAYER said that, excluding bonding funds and the Bradley
Lake project, AEA has secured over $635 million in federal
funds, resulting in a 1,000 percent budget increase over the
past four years. This figure does not include GRIP funding or
additional funds for the current year. Partnering with AHFC, the
initiative also aims to support residential rooftop solar for
low-income housing. If successful, the grant could bring in an
additional $100 million, potentially increasing their total to
$750 million, with no state match required. AEA expects to know
the outcome by late this month or early next month.
4:59:58 PM
MR. THAYER moved to slide 21 and explained the Power Cost
Equalization (PCE) program:
[Original punctuation provided.]
Power Cost Equalization (PCE)
The PCE program was established in 1984 as one of the
components of a statewide energy plan.
The cost of electricity for Alaska's rural residents
is notably higher than for urban residents. PCE lowers
the cost of electric service paid by rural residents.
Ultimately ensuring the viability of rural utilities
and the availability of reliable, centralized power.
750 kWh: RESIDENTIAL
Residential customers are eligible for PCE credit up
to 750 kWhs per month.
70 kWh: PUBLIC FACILITIES
Community facilities can receive PCE credit for up to
70 kWhs per month multiplied by the number of
residents in a community.
$42M: FUNDS DISBURSED
In the fiscal year 2024, AEA disbursed $42 million to
rural electric utilities for the benefit of rural
communities
MR. THAYER mentioned that when he and his colleague began their
roles, noting that their focus was initially on specific
objectives outlined in their original mission slides. However,
over the past four years, AEA's responsibilities have expanded
significantly, including initiatives such as bonding and other
projects. He provided a brief recap of the Power Cost
Equalization (PCE) program, explaining that it provides up to
750 kilowatts of energy support for residential customers, while
public facilities receive 70 kilowatts. He reported that AEA
dispersed $42 million under this program, with the funding
source being the endowment.
5:00:29 PM
MR. THAYER moved to slide 22 and spoke to power system upgrades:
[Original punctuation provided.]
Rural Power Systems Upgrades and Bulk Fuel Upgrades*
AEA and Federal Partners, Denali Commission (*$2
Million)
Rural Power Systems Upgrade
• Capital Budget - $2.5 Million
• ~197 Eligible communities
• 35 Active projects
Bulk Fuel Upgrade
• Capital Budget - $2 Million
• ~400 Rural bulk fuel facilities
• 35 Active projects
MR. THAYER acknowledged the challenges associated with Rural
Power System Upgrades, noting that there are 197 eligible
communities with 35 active projects. He referenced the Rewarding
Efforts to Decrease Unrecycled Contaminants in Ecosystems
(REDUCE) Act project, explaining that while there should be
three generators on-site, only two are operational because one
is outside the building and not in use. He emphasized that
staying ahead of maintenance for these powerhouses is a
significant challenge, with approximately $300 million in
deferred maintenance. There are 400 bulk fuel facilities, which
are owned by the communities rather than the state. However, the
state, through the Alaska Energy Authority (AEA), has assumed
greater responsibility for these projects. He clarified that
while the statute permits the state to take on this role, it is
not mandatory, but AEA has consistently provided support. There
is a capital budget request similar to last year's, with federal
matching dollars available for these projects. He highlighted
the efforts made by the team, including conducting inventory
assessments of the powerhouses, traveling to each site, creating
3D models, and digitizing all manuals. This digitization allows
technicians to remotely access detailed information about the
equipment, such as the hours of operation and specific manual
pages, to troubleshoot issues efficiently. The team is applying
the same approach to bulk fuel tanks and working with the Coast
Guard to ensure compliance in these facilities.
5:01:56 PM
MR. THAYER moved to slide 23 and reviewed the electric emergency
response:
[Original punctuation provided.]
Electric Emergency Response
Capital Request: General Fund - $200,000
AEA provides support when an electric utility has lost
or will lose the ability to generate or transmit power
to its customers and the condition is a threat to
life, health, and/or property. Funding provides the
current level of technical support through the
Electrical Emergencies Program.
• During the fiscal year 2023 there were six (6)
electrical emergencies. Power was restored within
24 hours in each case.
• The average cost of an electrical emergency
assistance is approximately $45,000 each
MR. THAYER explained that as deferred maintenance in rural
powerhouses continues to accumulate, the need for funding to
address electrical emergencies is likely to increase. Although
the average cost of addressing an electrical emergency has been
around $45,000, one community experienced an emergency over
Christmas that may require close to $200,000 in assistance. AEA
maintains a watch list of certain communities that do not have
access to an Alaska Village Electric Cooperative (AVEC) or
another utility and rely solely on a clerk and an operator.
These communities have been identified as likely to face issues.
To prepare for potential emergencies, AEA has stockpiled
essential items like oil filters and other necessary equipment
in their warehouse, tailored to the specific needs of each
community's powerhouse.
5:03:00 PM
CO-CHAIR BISHOP commended AEA for its prompt response during
emergencies. He shared that when the Yukon River flood took out
the Yukon power plant, AEA acted swiftly.
5:03:18 PM
MR. THAYER moved to slide 24 and spoke to the Renewable Energy
Fund (REF):
[Original punctuation provided.]
Renewable Energy Fund (REF)
AEA, in concert with the REF Advisory Committee, has
forwarded to the Legislature a capitalization request
of $32 million for Round 16 of the REF. An
appropriation of $32 million would fully fund all 24
recommended projects. Funding approval for the REF is
at the discretion of the Legislature and Governor.
REF Highlights
• Round 13: 11 Projects $4.75M
• Round 14: 27 Projects $15M
• Round 15: 18 Projects $17M
• Round 16: 24 Projects - Pending
• $317 million invested in the REF by the State
since inception.
• 100+ operational projects and 60 are in
development.
The Department of Energy recently announced $125
million for solar and hydroelectric projects in rural
Alaska several of these projects benefited from seed
money from REF totaling almost $12 million.
MR. THAYER noted that AEA has provided seed money for several
projects in these areas. Specifically, the $12 million invested
by AEA has successfully leveraged $225 million in federal funds
for these projects. The Renewable Energy Project (REP) program
yields significant returns, noting that it has displaced 85
million gallons of diesel since its inception. The program has
gone through several funding rounds in recent years. Last year,
the legislature funded Round 16 with $17 million. The Renewable
Energy Advisory Committee, composed of five public members and
four legislators, recommended $32 million in funding, which is
currently pending before the legislature. The governor's budget
includes a $5 million allocation for the program, down from $7
million the previous year. The projects are ranked in priority
order, which aids in determining funding decisions. This
prioritization helps ensure that the most critical and impactful
projects receive the necessary support.
5:04:25 PM
MR. THAYER moved to slide 25 and spoke to the Power Project Fund
(PPF) Loan Program:
[Original punctuation provided.]
Power Project Fund (PPF) Loan Program
The PPF loan program continues to see an increase in
applications due to federal matching fund requirements
and other incentives. The Inflation Reduction Act
provides tax credits of up to 40 percent
A fund capitalization of $25 million would allow for
additional funds needed to support the increased
demand in funding.
Outstanding Loans
• $31 Million
• 16 Loans
Uncommitted Cash Balance
• Program in abeyance until additional capital is
secured
Pending Applications
• $755,500
• Loans Under Review
Competitive Rates
• Current PPF Interest Rate
• 5.43 percent as of March 2024
MR. THAYER noted that the project has no existing delinquencies.
The program features patient capital with a 12-month rolling
average interest rate of 5.43 percent. He highlighted several
projects supported by the fund, including solar projects in Hope
and Houston, a wind farm in Delta Junction, and a cogeneration
unit at Baxter Senior Living in Anchorage. The fund has been
committed fully, and they are working on cash flow analysis to
accommodate smaller loans. The program has been successful, not
only because it provides funding for projects but also because
it helps communities meet federal match requirements. Overall,
the PPF loan program has proven to be a successful initiative.
5:05:32 PM
MR. THAYER moved to slide 26 and showed a photo of the AEA team.
5:06:02 PM
MR. THAYER moved to slide 27:
[Original punctuation provided.]
Susitna-Watana At-A-Glance
The proposed Susitna-Watana Hydroelectric Project is a
large hydro project that would provide long-term
stable power for generations of Alaskans. The project
would result in approximately 70 percent of the power
generated in the Railbelt originating from renewable
sources, up from the current 15 percent a nearly
four-fold increase.
Dam Height - 705 feet
Dam Elevation - 2,065 Feet
Reservoir Length - ~42 miles
Reservoir Width- ~1.25 miles
Installed Capacity - 618 MW
Annual Energy - 2,800,000 MWh
Cost - ~$5.6 billion (2014$)
MR. THAYER noted that the project is located north of Donkey
Creek, 22 miles downstream from Devils Canyon. The proposed dam
would have a height of 700 feet and a length of 2,000 feet, with
an installed capacity of 618 megawatts. The estimated cost of
the project in 2014 was $5.6 billion, although this figure may
have changed and will need to be updated. He highlighted the
need to explore any available tax credits or other programs that
could impact the project's financials. The Susitna-Watana
project could potentially meet 50 percent of the current
Railbelt energy demand. This would significantly reduce the risk
of energy shortages and enhance energy security.
5:06:43 PM
MR. THAYER moved to slide 28 and explained the purpose of the
Susitna-Watana project:
[Original punctuation provided.]
Why Susitna-Watana?
50 percent estimated supply of current Railbelt energy
demand
100+ years is the project life providing long-term,
stable rates
$11.2 billion estimated energy cost savings ($2014)
over first 50 years
The Susitna-Watana Hydroelectric Project would offset
the need for 22.6 billion cubic feet per year of Cook
Inlet natural gas if it were operational today.
5:07:17 PM
SENATOR DUNBAR inquired about the permitting process for the
project.
5:07:28 PM
MR. THAYER moved to slides 29 - 31 and spoke to the history of
Susitna-Watana:
[Original punctuation provided.]
Susitna-Watana History
1950s
First studies conducted by U.S Bureau of Reclamation
1980s
Alaska State studies project but oil prices cause
state to postpone
2010
50 percent Renewable Energy Goal by 2025
2011
Alaska Legislature unanimously authorizes Alaska
Energy Authority to pursue Susitna-Watana Hydro
2012
Studies begin on Susitna River and surrounding areas
2017
Licensing Abeyance
2019
Abeyance Rescinded
MR. THAYER noted that if the Susitna-Watana project were in
operation, it would displace 22.6 billion cubic feet of natural
gas. Initial reports from the 1950s identified the location as a
potential hydro project before natural gas was discovered in the
inlet. The project was revisited in the 1980s as part of the
state's renewable energy goals. By 2010, the state aimed to
achieve 50 percent renewable energy, but current levels are
closer to 32-33 percent. In 2011, the legislature approved $200
million in funding to pursue the FERC licensing process for
Susitna-Watana. Currently, the project is about two-thirds
complete in the licensing process, with an estimated $80 to $100
million needed to finalize it. He mentioned the need to update
these figures and verify the validity of existing studies, as
FERC's standards have evolved and become more supportive of dam
projects. The studies for Susitna-Watana began in 2012, but by
2017, the project was placed on hold with no further funds
expended.
5:08:49 PM
MR. THAYER moved to slide 32 and highlighted job opportunities
in Susitna-Watana:
Susitna-Watana Employment Opportunities
Pre-Construction Employment
~5,000 Direct jobs
~3,870 Indirect jobs
Construction Employment
~12,000 Direct jobs
~11,305 Indirect jobs
Operations Employment (Life of Project)
~24-28 Direct jobs
~105 Indirect jobs
MR. THAYER estimated that the project would create approximately
17,000 direct jobs and 15,000 indirect jobs.
5:09:02 PM
MR. THAYER moved to slide 33 and spoke to a visual depicting the
timeline of the Susitna-Watana project. In response to Senator
Dunbar's previous question, he explained that while the pre-
application phase for review takes about two-to-three years, the
overall timeline for construction and operation would likely
extend to 15 to 20 years. The construction phase itself is
projected to last nine-to-11 years. He compared the project's
timeline to the Iceland model, noting that large hydro projects
in Iceland were developed about 40 years ago, whereas
discussions about Susitna-Watana began around the same time and
have yet to come to fruition.
5:10:57 PM
There being no further business to come before the committee,
Co-Chair Giessel adjourned the Standing Senate Resources
Committee meeting at 5:10 p.m.
| Document Name | Date/Time | Subjects |
|---|---|---|
| SB 217 Letter of Support 3.12.24.pdf |
SRES 3/13/2024 3:30:00 PM |
SB 217 |
| AEA Update SRES Presentation 3.13.24.pdf |
SRES 3/13/2024 3:30:00 PM |
|
| SB 217 REAP SRES Presentation 3.13.24.pdf |
SRES 3/13/2024 3:30:00 PM |
SB 217 |
| AEA Responses to Senate Resources-Wheeling Charges.pdf |
SRES 3/13/2024 3:30:00 PM |