Legislature(2023 - 2024)BELTZ 105 (TSBldg)
05/05/2023 01:30 PM Senate LABOR & COMMERCE
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| Audio | Topic |
|---|---|
| Start | |
| SB101 | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| *+ | SB 101 | TELECONFERENCED | |
| + | TELECONFERENCED | ||
SB 101-UTILITIES: RENEWABLE PORTFOLIO STANDARD
1:32:47 PM
CHAIR BJORKMAN announced the consideration of SENATE BILL NO.
101 "An Act relating to a renewable portfolio standard; relating
to electrical energy transmission; relating to distributed
energy systems; relating to power cost equalization; relating to
the Alaska Energy Authority; and providing for an effective
date."
He asked Senator Tobin to introduce the legislation.
1:33:15 PM
SENATOR LÖKI TOBIN, District I, Alaska State Legislature,
Juneau, Alaska, sponsor of SB 101, stated that she would discuss
why the state should have Renewable Portfolio Standards. On
March 20, 2023, the United Nations released the "Climate Change
2023 Synthesis Report," focusing on the ongoing impacts of
global warming, particularly vulnerable populations and
ecosystems worldwide. She noted that Alaska experienced these
effects during Typhoon Merbok which caused devastation and
communication challenges.
She stated that more than a century of fossil fuel consumption
has highlighted the urgency of addressing climate change to
mitigate extreme weather events, especially in the Arctic.
Implementing a Renewable Portfolio Standard in Alaska is a
practical way forward, leveraging evolving and cost-effective
renewable energy sources, including wind, solar, tidal, and
geothermal energy.
Senate Bill 101 proposes a renewable portfolio standard for
Alaska's power companies and utilities. Currently, 85 percent of
the energy for the Railbelt is derived from fossil fuels. SB 101
aims to increase renewable energy to 25 percent by 2027, 55
percent by 2035, and 80 percent by 2040. The bill also
establishes a March 2025 reporting deadline for Railbelt
utilities to track their progress in meeting these standards.
SB 101 encourages compliance by authorizing fines for utilities
that fail to meet the standards, but it emphasizes incentives
over penalties. It offers an exemption for the first non-
compliance fine and allows fines to be satisfied through
customer-installed distributed energy systems or energy-
efficient projects.
SENATOR TOBIN stated that the bill affects utilities serving
Railbelt communities and those under the Electric Reliability
Organization (ERO), known in Alaska as the Railbelt Reliability
Council (RRC). The RRC must incorporate Renewable Portfolio
Standards into its resource plans, and the Regulatory Commission
of Alaska (RCA) determines compliance.
SB 101 permits the use of renewable energy credits to support
interconnected grid services, enabling the purchase of renewable
resources within service areas or from power cost equalization
customers.
SENATOR TOBIN stated that SB 101 is a positive step towards
reducing pollution and climate impacts. It promotes resilient,
reliable, renewable technologies and energy security by
diversifying power supply options, making it a valuable
initiative for the State of Alaska.
1:39:45 PM
CHAIR BJORKMAN asked Michael Mason to present the sectional
analysis for SB 101.
1:39:50 PM
MICHAEL MASON, Staff, Senator Löki Tobin, Alaska State
Legislature, Juneau, Alaska, presented the following sectional
analysis for SB 101, version R:
Senate Bill 101 Utilities: Renewable Portfolio
Standards
Version R Sectional Analysis
Section 1 Amends the uncodified law the State of
Alaska and clarifies the purpose of this Act is to
establish a standard for certain utilities to meet
renewable electricity generation goals established
under Section 5 of the Act. Nothing in the Act is
intended to constitute implementation by the
Regulatory Commission of Alaska under the federal
Public Utility Regulatory Policy Act of 1979.
Section 2 Amends Sec. 42.05.391 to stipulate that
public utilities that offer net metering to customers
with installed distributed energy systems are not
engaging in rate discrimination. This section
references Sec. 42.05.930 which defines a "distributed
energy system" as renewable energy resources located
on any property owned or leased by a customer within
the service territory of the load-serving entity that
is interconnected on the customer's side of the
utility meter.
Section 3 Amends Sec. 42.05.780, which governs
integrated resource plans for electric reliability
organizations, to require integrated resource plans to
include options by which each load-serving entity may
satisfy the renewable portfolio standard.
Section 4 Amends Sec. 42.05.785, which governs large
energy facility project preapproval, by stipulating
that a public utility which is part of an electric
reliability organization may not construct a large
energy facility unless the Regulatory Commission of
Alaska determines that the facility is not detrimental
to a load-serving entity's ability to meet the
renewable portfolio standard.
1:41:20 PM
Section 5 Adds new article under Sec. 42.05 entitled
Article 11A. Renewable Portfolio Standard (RPS). AS
42.05.900 requires a load-serving entity that is
subject to the standards of an electric reliability
organization comply with the renewable portfolio
standard and requires regulated Railbelt electric
utilities diversify their current generation portfolio
by increasing the proportion of net electricity
production from renewable energy sources in three
successive steps: 25 percent by 2027, 55 percent by
2035, and 80 percent by 2040.
Sec. 42.05.900 also stipulates that a purchase power
agreement entered into between a load-serving entity
and a renewable electrical producer will satisfy all
or part of the percentages required under the previous
subsection if three conditions are met: (1) the
effective date of the agreement is before the end of
the compliance period, (2) the renewable electrical
energy producer delivers the energy to the load
serving entity not later than two years after the
compliance period, and (3) the purchase power
agreement is approved by the Regulatory Commission of
Alaska (RCA). Purchase power agreements not approved
by the Commission may result in the load-serving
entity being subject to a noncompliance fine.
Sec. 42.05.900 governs the qualifications for a load-
serving entity's renewable portfolio which stipulate
that the renewable energy resources must be located
within the load-serving entity's service area, the
same interconnected electric energy transmission
network, or located within the service area of an
electric utility whose customers receive Power Cost
Equalization (PCE).
Sec. 42.05.900 also stipulates that load-serving
entities may satisfy the RPS with energy produced by
distributed energy systems, regardless of whether the
energy is acquired by the load-serving entity or used
by the customer. Under this statute, energy produced
by customers may count toward the RPS of the load-
serving entity.
Article 11A also governs the data needed to determine
compliance with the RPS and the accounting system
needed to verify compliance.
1:42:43 PM
The RCA is directed to adopt regulations to develop a
proxy system for the energy produced from distributed
energy systems which shall be updated every five
years.
Sec. 42.05.900 authorizes a load-serving entity to
satisfy the RPS through renewable energy credits that
are authorized by Sec. 42.05.910 (new statute) and
allows a load-serving entity to use energy efficiency
investments to satisfy the RPS if the displaced energy
consumption is established by the State of Alaska.
Sec. 42.05.905 establishes reporting requirements for
load-serving entities subject to the RPS. Beginning
March 1, 2025, a load-serving entity must submit an
annual report to the RCA documenting the progress
toward satisfying the RPS in the preceding calendar
year. The annual report must include the entity's
total production from distributed energy systems and
net electricity sales from renewable energy resources.
The annual report must also document the load serving
entity's satisfaction of penalties imposed under the
noncompliance section of this Act. The RCA must adopt
regulations related to reporting and is authorized to
investigate and collect information about a load-
serving entity's compliance with the RPS.
Sec. 42.05.910 governs the use of renewable energy
credits. To qualify as part of a load-serving entity's
portfolio, renewable energy credits must be bundled
from generation located within the entity's service
areas or connected to the same interconnected electric
transmission network. Credits can also qualify if they
are purchased from renewable sources located within
the service area of an electric utility that serves
customers who receive PCE.
A renewable energy credit may only be used once, and
renewable energy credits must be tracked in compliance
with the RPS. Credits may be traded, sold, or
otherwise transferred for value and revenue received
by a load-serving entity from renewable energy credits
is to be credited to the entity's cost of power
adjustment to the benefit of the load-serving entity's
customers.
1:44:09 PM
Sec. 42.05.915 establishes a noncompliance fine for a
load-serving entity that fails to meet the RPS, set at
$20 for every megawatt hour that the entity is below
the RPS.
The RCA may waive noncompliance fines if it is
determined that a load-serving entity is unable to
meet the RPS because of reasons outside the reasonable
control of the load-serving entity as set out in
subsection (c) of this section or if the entity
establishes a good cause for noncompliance as set out
in subsection (d) of this section. The RCA may require
additional reporting by a load-serving entity if the
commission waives all or part of a noncompliance fine
and a load-serving entity is prevented from passing
along the cost of non-compliance fines directly to
customers through rate increases.
A load-serving entity must satisfy a noncompliance
fine by paying a customer all or a portion of the
costs of installing a distributed energy system or
energy efficiency technologies. If the total requests
for costs exceed the amount of the noncompliance fine,
the load-serving entity shall prioritize customers
with mean household incomes at or below 80 percent of
the mean annual income where the customer is located.
1:45:16 PM
Sec. 42.05.920 establishes exemptions for entities
related to RPS compliance if the aggregate net
electricity sales for all load-serving entities on the
interconnected electric energy transmission network
meets or exceeds the aggregate renewable portfolio
standard for all load-serving entities on the
interconnected network.
Additionally, a load-serving entity is exempt from its
first RPS noncompliance fine. An exemption under this
subsection does not apply for the compliance period
ending December 31, 2040.
1:46:12 PM
Sec. 42.05.925 requires a load-serving entity subject
to the RPS to credit a retail customer for the number
of kilowatt-hours of electric energy supplied by the
customer's distributed energy system. The tariff may
not limit the aggregate capacity that customers may
install unless the RCA finds that capacity limitation
is necessary to protect system reliability. This is
also known as net metering. A credit under Sec.
42.05.925 which exceeds the customer's monthly bill
for service will roll over to the following month and
continue to roll over until used. Unused credits
expire on March 31 of each year for up to seven years
after a customer's distributed energy system is
connected to the load-serving entity and generates
power.
Sec 42.05.930 provides for definitions used under
Article 11A.
Section 6 Amends Sec. AS 42.45.110 to exclude
revenue from the sale of recovered heat, or revenue
from the sale of renewable energy credits from
calculating PCE.
Section 7 Amends Sec. 44.83.940 by adding a new
subsection requiring the Alaska Energy Authority to
submit a report to the Alaska State Legislature
identifying the authority's progress in developing
renewable energy resources in rural regions of the
state, evaluating renewable energy resource
development in rural regions, identifying
infrastructure necessary for rural renewable energy
projects, and evaluating the feasibility and cost of
rural renewable energy projects.
Section 8 Establishes an effective date of July 1,
2023.
1:47:42 PM
CHAIR DUNBAR asked the sponsor whether she would entertain the
idea of amending the bill to extend an offsetting credit to the
utilities that are impacted by the restoration of the Eklutna
River. He explained that years ago the Eklutna Dam hydropower
project was created without consulting the Native village of
Eklutna and it destroyed their traditional salmon stream.
Current efforts are underway to restore the river but this will
reduce the hydropower going to Matanuska Electric and Chugach
Electric, perhaps significantly.
1:47:57 PM
SENATOR GRAY-JACKSON joined the meeting.
1:49:28 PM
MR. MASON replied that he and the sponsor are both pro fish so
it sounded like a good idea. He suggested that it could be
accomplished through an amendment, a committee substitute, or
the regulation process.
SENATOR TOBIN added that she didn't believe it would be
necessary to reduce the compliance measures because there was
ample opportunity to invest in other types of renewable energy
generation to help those utilities offset that loss of power
generation and meet the requirements.
1:50:24 PM
SENATOR DUNBAR said there are different mitigation options and
the governor ultimately makes the decision due to a complicated
agreement with the US Fish and Wildlife Service and other things
that occurred in 1991 without any input from the Eklutna people.
He said his concern is that some of the involved utilities in
the project or the Governor's Office will point to this as one
of the reasons for choosing a different mitigation option
because they cannot reduce the flow of water that goes to the
Eklutna Power Project. He would like to work with the sponsor's
office to ensure this will not stand in the way of restoring the
Eklutna River.
MR. MASON responded that he would be happy to share some of the
options he's identified that might achieve that goal.
1:51:55 PM
CHAIR BJORKMAN transitioned to invited testimony and asked Chris
Rose to begin his presentation.
1:52:08 PM
CHRIS ROSE, Founder and Executive Director, Renewable Energy
Alaska Project (REAP), Anchorage, Alaska, gave a presentation
supporting SB 101 titled, "Why the Railbelt Needs a Renewable
Portfolio Standard (RPS)." He advised that the presentation
would lay out the economic reason that a Renewable Energy
Portfolio Standard is important for the Railbelt. The state of
Alaska currently is facing the problem of overreliance on a
supply of natural gas that is dwindling and getting more
expensive.
MR. ROSE began on slide 2 and described the Renewable Energy
Alaska Project:
Renewable Energy Alaska Project (REAP)
Established in 2004, REAP is a statewide, non-profit
coalition of over 60 diverse energy stakeholders,
including developers, consumer groups, electric
utilities, Alaska Native organizations and businesses.
REAP's mission is to increase renewable energy
development and promote energy efficiency in Alaska.
REAP runs programs for, and collaborates with, a
number of state and federal agencies, national
laboratories, universities and other NGOs.
REAP is focused not just on technology, but also the
policy and financing, and especially the people, that
are necessary for Alaska to transition to local,
affordable, stably-priced renewable energy and energy
efficiency.
1:55:53 PM
MR. ROSE advanced to slide 3 and spoke to the following points:
Presentation Overview
• Railbelt electricity rates have been rising much
faster than in the Lower 48
• Cook Inlet natural gas prices have also been rising
quickly
• Alaska DNR says Cook Inlet gas production will see a
shortfall as soon as 2027
• If the Railbelt imports LNG to make up for the
shortfall:
• Natural gas costs will dramatically increase,
raising rates for Railbelt consumers
• PCE reimbursements across rural Alaska will
take a steep hit
• The volatility of electricity prices across
the state will increase
• Renewable energy costs have fallen precipitously
worldwide, making it the cheapest electricity that
can be generated in most jurisdictions
• The Railbelt needs a renewable portfolio standard
to diversify our sources of electricity, and
accelerate the deployment of local renewable energy
resources to protect consumers
1:57:55 PM
MR. ROSE displayed the graph on slide 4, Railbelt Residential
Electric Rates Have Risen Quickly. He stated that the colored
lines show the rates for the four different co-ops from 1/1/2013
to 1/1/2022. The green line running along the bottom is the
national average which is about $0.14 per kilowatt hour (kWh).
This clearly illustrates that all four Railbelt utilities have
much higher electricity prices than the US national average. The
ratepayers on the Kenai Peninsula and in the Fairbanks area pay
the highest at $0.25- $0.35/kWh. High electrical rates make the
area less attractive for investors and as a place to live.
1:58:40 PM
MR. ROSE advanced to slide 5, Cook Inlet and US Natural Gas
prices, $/Mcf. He noted that the Henry Hub natural gas spot
price is the index in the lower 48; the dotted and solid blue
lines show the recent declines in price. The orange lines
reflect Cook Inlet prices that have been rising steadily since
2000 from just over $2.00/Mcf to closer to $7.50/Mcf. He said
that's really what's been driving up the price of electricity.
1:59:36 PM
MR. ROSE advanced to slide 6, Forecast Proved Developed and
Proved Undeveloped. He explained that this Department of Natural
Resources (DNR) graph illustrates the impending shortage of
natural gas in Cook Inlet. In 2027, a significant shift is
apparent; as the graph indicates, natural gas production in Cook
Inlet will fall below the level of consumption for the first
time. The horizontal blue line that is hovering around 70
billion cubic feet (BCF), represents the annual natural gas
usage by the four electric utilities and Enstar for electricity
generation and heating purposes. The orange section on the
graph, which represents proved undeveloped gas reserves, is
highlighted as an area that necessitates substantial investment.
To ensure a steady gas supply until 2027, it is apparent that
around 15 wells per year need to be drilled in Cook Inlet.
2:01:11 PM
MR. ROSE explained that the graph on slide 7 illustrates the
world's LNG spot prices the last two years and reflects a
considerable degree of volatility. It particularly focuses on
various indices associated with the Asian Pacific region. He
noted the Henry Hub (HH) index, in the US where there are
pipelines, is relatively low and stable compared to the more
volatile Title Transfer Facility (TTF) index that is European.
He advised that gas imported to Alaska would not come from
Europe. The orange, green, and gold lines represent indices in
Asia. They are of significant relevance because they are
indicative of the sources from which Alaska would likely import
its natural gas. This gas would potentially be redirected from
regions like British Columbia, resulting in pricing patterns
aligned with what is depicted in the graph. The goldish bar that
runs across the graph represents the Japan Organization for
Metals and Energy Security (JOGMEC) index, which is comparable
to energy indices in the United States, such as the Energy
Information Administration (EIA). This provides a reference
point for understanding that the expected pricing dynamics of
imported natural gas in Alaska is closely tied to the Asian
indices.
2:02:38 PM
MR. ROSE reviewed the chart on slide 8, Japanese LNG import spot
price versus Cook Inlet average gas prices ($/Mcf). He explained
that the graph features a comparison between the blue JOGMEC
line and the Cook Inlet average gas price. This visual
representation underscores the remarkable stability of Cook
Inlet gas prices over an extended period. For a considerable
time, they have remained at approximately $7.50 per thousand
cubic feet (MCF). However, this is likely to change
significantly by 2027, possibly even sooner, particularly for
utilities like the Homer Electric Association (HEA), which has
contracts with Hilcorp that are set to expire next year.
The context of this shift is that approximately 85 percent of
the gas extracted from Cook Inlet is developed and sold by
Hilcorp. The catalyst for the ongoing developments can be traced
back to Hilcorp's public announcement from a year ago. They
indicated uncertainty about their ability to fulfill existing
contracts with both Enstar and the four electric utilities in
the Railbelt. These contracts are set to expire between 2024 and
2028, and it was clear that Hilcorp was unsure about maintaining
the same volume or price levels. This announcement served as a
signal to the utilities that a change in gas prices was
imminent.
In essence, the graph highlighted the contrast between the
prospective costs of entering the Japanese spot market for LNG
and the prevailing stability of Cook Inlet gas prices, which
have been consistently around $7.50. The significance of this
comparison lay in the fact that all of these contracts are
scheduled to conclude between 2024 and 2028.
2:04:11 PM
MR. ROSE advanced to slide 9 Average Imported LNG Price
Scenario's (Current Prices to 2028). He stated that this graph
illustrates potential future scenarios. The green line
represents the stable Cook Inlet gas price, approximately
$7.50/MCF, which is the current average price that Matanuska
Electric, Chugach Electric, and Seward Electric pay. He directed
attention to the colored dotted lines that represent three
different price scenarios for LNG: $12, $18, and $25/MCF.
The $25 price aligns with the current spot target price. The $12
and $18 prices were derived from multiple sources, including a
report by Chugach staff regarding the Dixon Diversion Project by
Bradley Lake and DNR's projections for incentive prices in Cook
Inlet for more development to take place. He explained that the
relatively small market, with 500,000 to 600,000 natural gas
users in Cook Inlet, had limited competition due to the absence
of major gas exploration activities. The dominance of one major
player, Hilcorp, with an 85 percent share in gas supply, created
a situation akin to a monopoly. As a result, the utilities and
Enstar have limited market leverage.
2:06:53 PM
MR. ROSE displayed slide 10, "Avoided Cost," and spoke to the
following:
• "Avoided Cost" is an electric utility industry term
of art.
• It refers to the cost of generation that a utility
avoids when it purchases electricity from a third
party.
• Avoided cost is composed of fuel and O&M costs
attributable to the "last" MWh generated.
• A utility's "avoided cost" is the most expensive
power it would otherwise generate over a given
interval of time.
• If the cost of renewable energy is less expensive
over the life of a project than the utility's
avoided cost, then consumers will be better off with
the renewables.
• MEA's Willow solar power purchase agreement (PPA)
was justified by the RCA based on the utility's
avoided cost at the time the PPA was signed.
2:09:20 PM
MR. ROSE advanced to slide 11, 2028 Railbelt Avoided Cost
Scenarios (At Three Different Potential LNG Prices). He directed
attention to four different bands of bar graphs. The first band,
represented by Chugach Electric in blue, MEA in orange, and HEA
in gray, depicts the current situation where these utilities are
paying approximately $7.75/MCF, which is their current avoided
cost. Today, Chugach's weighted cost is slightly over six cents,
making it the benchmark to beat. To surpass Chugach's avoided
cost, one needs to go under six cents. Both MEA and HEA already
have higher avoided costs.
He turned to the $12 gas scenario, stating that this is a likely
best-case scenario for new natural gas prices, but even then,
the contract cost is a little over $0.07/KWh in 2028. That cost
beats Chugach's new avoided cost and it also beats both Homer
and MEA's costs. This means that whenever gas reaches $12/MCF,
solar will beat that price. He said the solar price comes from a
relatively small six-megawatt solar farm that lacks the
economies of scale associated with larger solar developments,
but developers are exploring the potential for much larger wind
and solar projects in the Railbelt. In such cases, the cost of
power is likely to decrease over time. He highlighted that there
was already one solar contract close to MEA's avoided cost and
poised to beat other avoided costs if natural gas prices
increase.
2:11:45 PM
MR. ROSE displayed slide 12, Impact of Three Possible LNG Import
Prices on Annual Household PCE Reimbursements, stating that this
graph reflects an interesting element because the cost of power
in Fairbanks and Anchorage has a statewide impact.
2:11:57 PM
CHAIR BJORKMAN summarized that SB 101 is a government mandate
for utilities to generate a certain percentage of their power
from renewables. He noted that the presentation thus far had
discussed the rising cost of gas and why those same utilities
are under market pressure to adopt a portfolio of Renewable
Energy Standards. He further noted that MEA and HEA already were
engaged in this process with independent power producers (IPP).
He asked why a government mandate is needed if market forces are
encouraging utilities to include renewables as part of their
power generation and certain utilities are already including
renewables to diversify their power generation.
MR. ROSE replied that one reason is that there isn't a
competitive market. The four utilities are monopolies that each
act independent of the others. The Railbelt Reliability Council
(RRC) was established, but there isn't an Independent System
Operator (ISO) to operate the grid efficiently as one grid. Most
jurisdictions in the lower 48 have an ISO. The Regulatory
Commission of Alaska (RCA) has ordered both Matanuska Electric
(MEA) and Chugach Electric Association (CEA) to start acting in
a tight power pool which is moving toward an ISO. This isn't
fully fledged, and it doesn't include Homer Electric Association
(HEA) or Golden Valley Electric Association (GVEA). To move
forward efficiently, the utilities have to address system
operation.
MR. ROSE stated that it is also necessary to deal with what is
called pancaking transmission tariffs. Each utility owns a part
of the transmission and they charge a toll to move the electrons
through their separate service areas. These accumulate or
pancake one on top of the other potentially making the cost of
delivering the power up and down the Railbelt more expensive
than the cost to generate it. REAP believes that if there were a
mandate, the utilities would be forced to operate more
efficiently. This means that each of the utilities would not be
charging a toll to move the electrons through their respective
service areas.
2:15:06 PM
MR. ROSE said another issue is that there are transmission
constraints that make it more difficult to move power between
the Anchorage/MatSu area, Fairbanks, and the Kenai Peninsula.
These constraints limit transmission to 80 megawatts. The area
around Willow has a similar constraint and all the utilities
agree that these need to be fixed. The utilities have applied
for federal grant money that's available for this but there
isn't complete agreement about how much transmission is needed
for reliability without "gold plating" the system.
MR. ROSE returned to the first point about not having a
competitive market. He explained that the four utilities are
able to calculate their avoided costs using different
methodologies so there isn't a target price for the entire
Railbelt. Independent power producers (IPP) that want to sell
into the market have to deal with each utility separately
because transparency and consistency in the market price is
lacking.
2:17:20 PM
MR. ROSE returned to slide 12 and explained that the Power Cost
Equalization (PPE) program is based on equalizing the cost of
power in Anchorage, Fairbanks, and Juneau with the cost of power
outside of those areas. As the prices in Anchorage and Fairbanks
have increased, it has reduced the amount of the subsidy for
people outside the Railbelt. The impact becomes more significant
on PCE consumers in a $12, $18, or $25 gas price scenario.
2:18:22 PM
MR. ROSE advanced to slide 13, Importing LNG Should Not be the
Answer. He noted that all of the utility executives who were
quoted talked about importing natural gas into Alaska.
Unfortunately, they did not identify renewables as the answer.
The slide read:
When asked what the option for natural gas would be if
the AK LNG project does not go forward, Railbelt
Utility Mangers all had the same answer for the Senate
Resources Committee:
"I think that option is going to be importing LNG."
Arthur Miller, Chugach Electric Association
"LNG import is going to be the answer." Tony Izzo,
Matanuska Electric Association
"I think whether I want to say it out loud or not, at
some point, imports will be part of the transition
plan from everything I've heard so far." Brad
Janorschke, Homer Electric Association
"I have been steadfast in looking at my three peers
here and saying we are in this together and so if it
is imported natural gas, so be it." John Burns, Golden
Valley Electric Association
2:19:07 PM
MR. ROSE advanced to the US map on slide 14, Renewable & Clean
Energy Standards. He explained that this shows the states that
had Renewable Portfolio Standards and those that had Clean
Energy Standards as of November 2022. He noted that eight states
now have a Renewable Energy Standard of 100 percent by 2045 or
2050. REAP believes that 80 percent is eminently doable for
Alaska and that the state should be following in the footsteps
of some of these other states that have established standards.
2:20:07 PM
MR. ROSE advanced to slide 15, Costs of Wind and Solar
Electricity Power Purchase Agreements (PPA). He explained that
the colored circles on the graph represent contracts in the US
for wind and solar that have occurred since 2009. The gold
circles represent power purchase agreements (PPA) or contracts
for solar power and the blue-gray circles represent wind power
contracts. The larger the circle, the larger the contract. The
graph shows that by 2022 the price of wind and solar was about
$0.03/MWh. He noted that the dashed black line represents what
the Energy Information Administration (EIA) has been projecting
for natural gas prices in the lower 48. He emphasized the huge
activity for renewables in the lower 48 where natural gas costs
one third as much as in Cook Inlet.
2:21:32 PM
MR. ROSE advanced to slide 16, Levelized Cost of Energy
Comparison - Unsubsidized Analysis. He explained that the chart
comes from Lazard, an international consulting firm that
annually conducts an unsubsidized comparison of electricity
production, providing a clear breakdown between renewable and
conventional energy sources.
Lazard's findings reveal that, in today's context, the cost of
utility-scale solar photovoltaic (PV) and onshore wind energy
lies within a range of roughly $24 to $75/MWh for wind, and
$96/MWh for solar. He said it's worth noting that the most
competitive options fit squarely within the $26 to $30 range,
which can be translated to approximately $0.02 to $0.03/KWh.
Moreover, the chart serves as a window into the world of
conventional energy, presenting a price spectrum for combined
cycle gas units ranging from $39 to $101/MWh. Freshly harnessed
natural gas-fired electricity falls in the ballpark of roughly
$0.07 to $0.10/KWh. The chart also shows the prices associated
with generating power from a new nuclear plant, which span from
$141 to $221/MWh, corresponding to approximately $0.15 to
$0.22/KWh. He clarified that these figures specifically
represent the foundational costs of electricity generation, not
factoring in any additional overhead expenses which allows a
closer look at where the costs lie.
2:23:32 PM
MR. ROSE advanced to slide 17, Percentage of Net Generation from
Solar in 2022 (Selected States). He said this slide is
interesting because it shows that solar already accounts for a
large percentage of power generation in many states. This is
important to Alaska because rooftop solar could quickly displace
the use of natural gas for six to eight months of the year. The
gas could instead be used for heating. He pointed to the data
for California which has a population of about 40 million. Solar
accounts for 25 percent of the power generation for that state.
He also pointed out that Massachusetts generates almost 20
percent of its electrical power from solar. He emphasized the
untapped potential for Alaska to adopt more solar innovation. He
noted that a provision in SB 101 requires utilities to pay new
rooftop solar customers a retail rate up to seven years which
aligns with net metering. This could increase the number of
people who want to take advantage of the 30 percent tax credit
and receive the retail rate for any excess generation they sell
into the grid.
2:25:28 PM
MR. ROSE advanced to slide 18, Renewable Portfolio Standards
(RPS) with Solar or Distributed Generation Provisions. He
explained that the US map shows the states that have carved out
certain technologies. Specifically, the states colored blue-gray
have special solar provisions in their Renewable Portfolio
Standard. He highlighted that the special solar provision that
SB 101 proposes is consistent with the states that have done
this successfully.
2:25:57 PM
MR. ROSE advanced to slide 19, U.S. Net Capacity Additions by
Source (Gigawatts). He explained that the color-coded graph
shows new power generation in the lower 48 since 2010. The
green/bronze represents wind, the gray represents solar, and the
orange represents fossil fuels. Since 2010, the power generated
from wind and solar has increased and the power generated from
fossil fuels has decreased to below zero. He described this as
net negative fossil fuel generation capacity which means that
more fossil fuel plants in the lower 48 are being retired than
are being built. Most new generation in the lower 48 comes from
wind and solar.
2:27:19 PM
MR. ROSE advanced to slide 20, An RPS Bill Similar to [Senate
Bill] 121 Was Introduced by Governor Dunleavy in 2022. He spoke
to the following:
HB 301 passed out of both the House Energy and House
Labor & Commerce Committees before the 32nd
Legislature ended.
He stated that REAP is pleased that this bill was reintroduced
this year.
2:27:49 PM
MR. ROSE advanced to slide 21, which the National Renewable
Energy Lab (NREL) provided upon request from Governor Dunleavy.
He spoke to the following:
Renewable Portfolio Standard Assessment for Alaska's
Railbelt
Overall Finding 1: Multiple pathways exist for
achieving an 80% RPS while balancing supply and demand
under major outage conditions with appropriate system
engineering.
Overall Finding 2: An 80% RPS achieves a substantial
reduction in fuel costs, which could be compared to
capital cost expenditures for a comprehensive impact
assessment.
MR. ROSE conveyed that in the time NREL had to conduct the
study, they were not able to do a detailed analysis of the
capital cost to get enough wind, solar, and batteries to achieve
an 80 percent RPS. He highlighted that the lab is currently
working on an updated report that includes the cost analysis.
2:29:02 PM
SENATOR MERRICK asked for confirmation that slide 20
misidentified the companion bill to HB 301. It was Senate Bill
121, not House Bill 121.
MR. ROSE replied that's correct; he neglected to correct the
slide to show it was a Senate bill.
SENATOR MERRICK said she wonders why SB 101 didn't reflect the
changes that were made in those bills.
MR. ROSE said he didn't know the respective sponsors' thought
process, but REAP supported moving back to a real Renewable
Portfolio Standard (RPS) that is focused on renewable
technologies like 29 other states. By the end of the session in
2022, House Bill 301 had moved from an RPS that measures
megawatt hours generated to a clean energy standard that
measures the reduction in carbon emissions. REAP believes that
megawatt hours generated is a much cleaner way to measure
compliance. REAP is also concerned that measuring the reduction
of carbon emissions is more difficult to control and more easily
"gamed." He opined that more people are interested in renewable
energy than carbon emissions. REAP wanted to focus on an RPS
like other states have done.
2:31:51 PM
MR. ROSE advanced to slide 22, Preliminary Benefit/Cost Analysis
of 80% by 2040 RPS (NREL Scenario #3). He explained that absent
a cost analysis from NRES, Alan Mitchell with Analysis North did
an analysis in February 2022. He looked at how much it would
cost to purchase and install the amount of solar, wind, hydro,
and batteries to achieve 80 percent renewable generation in the
Railbelt. The costs and benefits of RPS Scenario 3 are
summarized as follows:
• Capital Cost of implementing RPS Scenario #3
(predominantly wind + solar) is $3.2 billion, relative to
the Base Case.
• Present Value Benefits (fuel savings, with small offset
from renewable operating costs) are $6.7 billion.
• Capital costs could more than double and Scenario #3
would still be cost effective.
• This analysis was done before federal tax credits for
renewable energy were extended for 10 years.
He described the analysis as very conservative.
2:33:37 PM
MR. ROSE advanced to slide 23 and spoke to the following points:
Analysis Assumptions
• Renewable capacity and fuel savings were used
without modification from NREL RPS Study Scenario
#3.
• NREL fuel savings are based on an AEA Fuel
Price Forecast
• Capital cost includes addition of hydro,
biomass, wind and solar
• All necessary transmission upgrades and battery
energy storage are included in all of NREL's five
scenarios, including the Base Case.
• Wind capital costs were estimated at $2,912/kW, a
conservatively high estimate of 1.94 times the Lower
48 average in 2020, based on the ratio of the costs
of the Eva Creek Wind Project built in 2012 to the
national costs for wind in that same year.
• Solar capital costs were estimated from existing and
proposed Railbelt projects at $1,750/kW, roughly
1.46 times the average cost in the Lower 48.
• A 3% inflation adjusted discount rate was used for
calculating present value.
2:34:47 PM
MR. ROSE advanced to slide 24 and spoke to the following points:
Additional Benefits That Were Not Considered in the
2022 Analysis
No federal Production Tax Credit (PTC) or other types
of federal support. Those 30% tax credits were
extended by Congress for 10 years in August 2022.
Higher LNG prices. The AEA gas price forecast
projected $11 Mcf gas in 2030.
No further decline in wind and solar costs between
2020 and 2035
No increase in fuel prices beyond general inflation
after 2040
No carbon tax avoided
2:36:29 PM
MR. ROSE reviewed the chart on slide 25, U.S. 2023 Planned
Capacity Additions (gigawatts). He reported that EIA estimates
that 54 percent of the new electrical generation in the US this
year will come from solar, 11 percent will be from wind, and 17
percent will be from battery storage.
2:37:00 PM
MR. ROSE advanced to slide 26 and spoke to the following points:
How Much Renewable Capacity Gets Us to 80 Percent
• In 2021 Railbelt generated 4,685,898 MWh
• Equivalent to 535 MW capacity, operating at 100%
capacity factor (24 hours/day, 365 days)
• Renewables are currently 15% of total energy
• 80% RPS lozenge Need an additional 348 MW
• One case with only wind and solar (roughly emulating
NREL Scenario 3):
• 535 MW of installed solar @ 12% capacity factor
= 64 MW fossil equivalent
• 860 MW of installed wind @ 33% capacity factor
= 284 MW fossil equivalent
2:39:35 PM
MR. ROSE advanced to slide 27, and reviewed the following:
The Railbelt Reliability Council Would Implement an
RPS
For decades, there was no mandate for the Railbelt
utilities to plan together or adhere to regional
interconnection and reliability standards.
In 2020, the passage of SB 123 required the Railbelt
to establish an Electric Reliability Organization
(ERO) to develop and enforce standards and execute
regional planning for generation and transmission.
The Railbelt Reliability Council (RRC), made up of 13
utility and non-utility stakeholders, was certificated
in September 2022 as the Railbelt Reliability Council
(RRC)
New generation and transmission portfolios will be
developed by the RRC through an integrated resource
plan (IRP). The first regional IRP for the Railbelt
will be a public process that will analyze the
technical and economic feasibility of a range of
options, select a preferred portfolio and develop an
action plan before submitting the IRP package to the
RCA for final approval.
2:40:45 PM
MR. ROSE advanced to slide 28 and spoke to the following:
The $2.5 Billion Utility Transmission Ask
The Railbelt Utilities are asking the State for:
• $250 million for five years running the
equivalent of $400/year for each of 625,000 PFD
recipients
• $125 million per year for another 10 years the
equivalent of $200/year for each of 625,000 PFD
recipients
How other states do it: plan transmission corridor
requirements around where renewable resources are, and
rely more on storage
Instead of waiting for silver bullets and federal
grants we need to make incremental progress now
We can do more than one thing at a time!
2:43:00 PM
MR. ROSE advanced to slide 29 and spoke to the following:
A Railbelt RPS Would:
• Diversify the region's generation portfolio and
protect consumers from rising rates.
• Displace high-priced natural gas fuel used for
electricity and help reserve Cook Inlet gas for the
region's heating needs.
• Utilize local, renewable resources like wind and
solar that have no fuel costs.
• Stabilize Cook Inlet energy costs.
• Increase the region's energy independence and keep
Alaska competitive in a fast changing world.
• Create jobs, spur statewide innovation and keep
hundreds of millions of precious energy dollars
circulating in the state's economy.
• Establish a standard that triggers action before we
import LNG.
2:44:10 PM
MR. ROSE advanced to slide 30 and spoke to the following points:
Time is of the Essence
The Railbelt utilities and Enstar are meeting
regularly to discuss importing LNG
The next NREL study will come out in late May
The Governor's Energy Security Task Force will not
report until the Fall
The Railbelt Reliability Council is about to start
getting staffed up
The Legislature will reconvene in January
REAP respectfully suggests ongoing RPS hearings over
the interim
2:45:22 PM
SENATOR TOBIN stated that SB 101 is a policy call about the plan
going forward to ensure that Alaskans have stable and reliable
energy generation after fossil fuels expire. She cited examples
of standards that have been implemented into law. To the
question about why SB 101 doesn't look like the bills that were
heard in previous years, she said the decision was to focus on
Renewable Portfolio Standards because wind and solar technology
is proven, reliable, and affordable. It is ready today so SB 101
is narrowly focused on renewables.
2:47:21 PM
SENATOR DUNBAR said wind are solar are clearly renewable but he
wanted assurance that the expansion of Bradley Lake fits into
the model. He also wondered whether the hydropower project he
mentioned earlier would be considered renewable under the
standards of the bill.
2:48:33 PM
MR. MASON answered that the definition of a renewable energy
resource is found on page 9. He confirmed that the Bradley Lake
hydro project and the Dixon Diversion would fall under the
Renewable Portfolio Standard legislation. The sponsor has looked
at language that would provide exemptions to some of the
compliance that could be used in the Eklutna example. To Senator
Merrick's question about House Bill 301, he said there was
discussion about whether to add nuclear energy to the bill and
it was eventually added. After considerable discussion, the
sponsor chose not to include nuclear in SB 101. He cited three
examples to explain why: Fukushima, Chernobyl, and Three Mile
Island. He reiterated that the bill includes non-compliance
waivers which would allow additional technologies without making
them part of a true Renewable Portfolio Standard.
SENATOR DUNBAR said he appreciates that there's a waiver
process. He added that he supports nuclear power but doesn't
believe it pencils out in Alaska.
2:51:43 PM
CHAIR BJORKMAN opened public testimony on SB 101.
2:52:13 PM
MICHAEL JONES, representing self, Homer, Alaska, voiced
opposition to the creation of the Renewable Portfolio Standard
outlined in SB 101, citing several concerns. His stance was
substantiated by the testimony he had submitted online. He
argued that the RPS approach imposed artificial renewable
targets and deadlines, potentially leading to a suboptimal
generation mix. Instead, he advocated for supporting a robust
generation planning effort that considers a wide range of
potential solutions without restricting choices or favoring
certain options based on arbitrary criteria.
MR. JONES contended that the RPS provided a one-size-fits-all
solution that hindered the thoughtful, science-based generation
resource planning efforts the Railbelt utilities had undertaken.
He believes that a state-mandated RPS removes local decision
making from those who would bear long-term financial
consequences. Such mandates, in his view, demand too much too
quickly, resulting in high electricity costs that could be
mitigated with a more gradual, bottom-up approach.
MR. JONES also raised concerns about special interests,
particularly the solar lobby, influencing net metering
requirements for their profit. He saw this as a costly, long-
term investment plan, with the burden falling on electric
customers for decades.
Finally, he questioned the necessity of the legislation, noting
that if wind and solar generation were genuinely more cost-
effective than gas-fired alternatives, market forces should
determine the best technical and economic solutions without
legislative intervention.
2:54:45 PM
MATTHEW PERKINS, Co-Founder and Vice President, Alaska
Renewables (AR), Fairbanks Alaska, expressed appreciation for
the previous speaker's comments and highlighted the importance
of a bottom-up approach to technology, emphasizing that
regulatory clarity was crucial for the investment community. He
stated that the economists at Alaska Renewables (AR) who are
involved in multiple wind projects across the state have
stressed that clarity in regulations is vital. This is
particularly important for renewables because investing in such
projects is a long-term commitment, and investors seek certainty
that aligns with their energy policies.
MR. PERKINS acknowledged that no policy was perfect but
underlined the overdue nature of a Renewable Portfolio Standard
(RPS). AR's engineers and economists recognize the challenges of
energy transitions and believe that regulatory clarity would
benefit both utilities and the investment community. It would
provide guidelines and stability for those involved in project
development, ensuring that the rules of the game wouldn't
suddenly change.
MR. PERKINS acknowledged the importance of a thorough
environmental review in the U.S. for renewable energy projects.
He affirmed AR's support for the RPS policy in Alaska,
considering it long overdue and expressing eagerness to continue
assisting the state in its energy transition efforts.
2:57:14 PM
BOB BUTERA, representing self, Anchorage, Alaska, testified in
support of SB 101. He voiced his support for adopting Renewable
Portfolio Standards in Alaska. He pointed out that similar
standards had been suggested by both Governor Palin and Governor
Dunleavy in the past and now was the time to formalize them in
state law.
MR. BUTERA highlighted the concerning trend in the Railbelt,
where Cook Inlet gas production was rapidly decreasing, causing
gas prices to rise. He raised the issue that within four years,
there might not be enough gas to meet the demand, as indicated
by Hilcorp's announcement that they couldn't guarantee gas
delivery for future contracts. He emphasized the limited options
for quickly changing the way buildings are heated but noted the
potential to transition rapidly to renewable electricity
generation, extending the availability of gas for heating homes
and businesses.
In addition to enshrining renewable standards in statute, Mr.
Butera stressed the significance of an amendment that would
require integrated resource plans to include options for meeting
renewable standards. These plans, especially in the Railbelt,
would shape the future of the region's electricity generation.
To ensure a decisive and cost-effective approach, he believed
that updating the plans with renewable standards was crucial. He
expressed concern that without a renewable mandate, conservative
utilities might continue to downplay the impending crisis,
opting for a slow and cautious path, ultimately resulting in
high energy costs. He encouraged the committee to advance these
critical components of SB 101.
2:59:20 PM
MIKE CRAFT, representing self, Fairbanks, Alaska, expressed
support for SB 101 and provided some background. He owns the
Delta Wind Farm and recalled setting up the first wind farm on
the Railbelt grid in 2008, driven by the economic opportunities
renewable energy offered. He highlighted the economic benefits
of renewables and the growing awareness of the health and
environmental impact of hydrocarbons on their community in
Fairbanks. He and his partner shared their 17-year commitment to
renewable energy in Alaska and urged those listening to consider
whether they wanted to be part of a national plan that had
proven to be reasonable, effective, and economically viable.
MR. CRAFT emphasized the positive changes that renewable energy
could bring, both in terms of health and cost savings. He urged
everyone to be part of the plan for Alaska's energy future,
expressing a sense of disappointment about Alaska falling behind
in various aspects and a determination to make a difference,
particularly for future generations.
MR. CRAFT stressed his commitment as a developer to
environmental responsibility and mitigating the environmental
impacts of various projects.
3:01:58 PM
CHAIR BJORKMAN closed public testimony on SB 101.
CHAIR BJORKMAN applauded the sponsor for introducing the bill
and complemented the Railbelt utilities for their efforts to
improve the grid and diversify power generation adhering to
local goals to generate power from renewable sources. He said
the existing utilities have two responsibilities to the Alaskan
people: to keep the lights on in a reliable way and to do so at
the cheapest cost possible. When utilities face rising natural
gas prices, it makes sense for them to pursue cheaper methods to
generate power. The presentation made it clear and it's been
demonstrated that there is space for renewables to sell
electricity to the local co-ops.
CHAIR BJORKMAN described the mandate outlined in SB 101 as an
aspirational goal. He articulated his preference that local
utilities fulfill their mission of ensuring reliable electricity
and cost efficiency, relying on the specific conditions in their
respective regions. He voiced support for infrastructure
buildouts through the intertie and improving transmission
without passing the costs along to ratepayers.
3:05:32 PM
SENATOR DUNBAR concurred with much of Senator Bjorkman's
viewpoint but stressed the importance of acknowledging that
change requires time. The state has, whether deliberately or
unintentionally, implemented policies that, in some instances,
explicitly favor hydrocarbons. An illustrative case is the
provision of cashable credits for gas production in Cook Inlet,
involving the allocation of hundreds of millions of dollars as
direct subsidies to the hydrocarbon industry. He clarified that
this is not a critique of such a decision, as ensuring
affordable gas is crucial. However, had a similar approach been
applied to renewable projects, the outcome might have been
different. He expressed a willingness to explore this as part of
an energy diversification strategy and expressed optimism for
further examination of this issue during the interim.
3:06:53 PM
SENATOR MERRICK asked which stakeholders participated and
whether the RRC participated or would be included going forward.
MR. MASON stated that he had worked on this matter for several
years and was pleased when Senator Tobin was similarly
passionate. He worked with Mike Craft and Chris Rose who is part
of the Railbelt Reliability Council. He relayed that he had
already pledged to work with the utilities and stakeholders
through the interim to craft a piece of legislation that both
Senator Bjorkman and Senator Tobin could support.
SENATOR MERRICK asked whether her constituents, who are
Matanuska Electric ratepayers, were consulted when SB 101 was
drafted.
MR. MASON answered no.
CHAIR BJORKMAN held SB 101 in committee.
| Document Name | Date/Time | Subjects |
|---|---|---|
| SB 101 ver R.pdf |
SL&C 5/5/2023 1:30:00 PM |
SB 101 |
| SB 101 Sponsor Statement 03.28.23.pdf |
SL&C 5/5/2023 1:30:00 PM |
SB 101 |
| SB 101 Sectional Analysis 03.28.23.pdf |
SL&C 5/5/2023 1:30:00 PM |
SB 101 |
| SB 101 Fiscal Note DCCED-AEA 04.28.2023.pdf |
SL&C 5/5/2023 1:30:00 PM |
SB 101 |
| SB 101 Fiscal Note DCCED-AIDEA 04.28.2023.pdf |
SL&C 5/5/2023 1:30:00 PM |
SB 101 |
| SB 101 Fiscal Note DCCED-RCA 04.28.2023.pdf |
SL&C 5/5/2023 1:30:00 PM |
SB 101 |
| SB 101 Presentation to SL&C-Chris Rose_REAP 05.04.23.pdf |
SL&C 5/5/2023 1:30:00 PM |
SB 101 |
| SB 101 Research NREL RPS Assessment 03.28.23.pdf |
SL&C 5/5/2023 1:30:00 PM |
SB 101 |
| SB 101 Public Testimony-Received by the Committee through 05.04.23.pdf |
SL&C 5/5/2023 1:30:00 PM |
SB 101 |