HB 307—An Overview and Implementation

Published February 27, 2025

By Brian Kassof

This is the first of two articles on HB 307. This piece provides a detailed look at the bill’s provisions and their impact in the six months since the bill’s passage. Its companion article looks at HB 307’s complicated legislative path and why legislative action was necessary to form a Railbelt Transmission Organization.

This article discusses the Railbelt Reliability Council (RRC) at length, and mentions the Alaska Public Interest Research Group (AKPIRG) and Renewable Energy Alaska Project (REAP). In the interest of full disclosure, while AETP exercises full editorial independence, it receives its funding from AKPIRG. AKPIRG is an institutional member of REAP and currently holds the Small Consumer seat on the RRC’s board. Material published on AETP does not represent the views of AKPIRG or any associated organization.

In the final hour of its 2024 session, the Alaska Legislature passed a major energy bill, HB 307, which the governor signed into law on July 31. The bill’s provisions address a number of energy-related issues. It creates a Regional Transmission Organization (RTO) for the Railbelt, which will adopt a method of paying for transmission costs that should make it easier for utilities to buy power from other parts of the Railbelt. Another key provision establishes tax parity between utilities and independent power producers (IPPs). The bill also includes changes to state agencies and regulatory bodies involved with the electric sector.

(The Railbelt refers to the region between the Kenai Peninsula and Fairbanks. There are five Railbelt electric utilities, four of which—Homer Electric Association (HEA), Chugach Electric Association (CEA), Matanuska Electric Association (MEA), and Golden Valley Electric Association (GVEA)—are cooperatives. The fifth is the municipal Seward Electric System).

As the 2025 legislative session begins, it is useful to review what was included in HB 307, what progress has been made in implementing its provisions, and what related issues might come up in the current legislative session. This last category includes questions about matching funding for a $206 million federal grant to upgrade part of the Railbelt transmission system, as well as how to address the issues associated with anticipated shortfalls of Cook Inlet natural gas.

The creation of the RTO and tax breaks for IPPs are intended to remove two significant barriers to the development of utility-scale renewable energy generation projects along the Railbelt. This, it is hoped, will help lower energy costs and diversify sources of power generation, reducing the Railbelt utilities’ reliance on Cook Inlet natural gas, which currently fuels about 75% of generation. The RTO will eliminate the “wheeling fees” utilities charge one another to move power through their transmission lines, and replace it with an Open Access Transmission Tariff (OATT) that will allocate costs based on overall usage. New IPP-developed facilities will be exempt from local property taxes, lowering the cost of their power and placing them on an even footing with utility-owned generation sites, which are already exempt from these taxes.

The bill also contains provisions addressing regulatory and state agencies. Several changes concern the Regulatory Commission of Alaska (RCA), which regulates most Alaskan utilities. HB 307 increases the RCA’s funding, imposes new qualifications for the five commissioners who oversee its work, and raises the commissioners’ pay. It also expands the criteria the RCA uses to evaluate electric rates. The bill shifts some responsibilities from the Railbelt Reliability Council (RRC)—an electric reliability organization (ERO) for the Railbelt whose creation was ordered by the Legislature in 2020) to the new RTO. Finally, HB 307 creates an independent board for the Alaska Energy Authority (AEA).

HB 307 was the product of extensive legislative debate and negotiations with numerous stakeholders. It incorporates elements from a number of other bills, two of which—SB 217 (which began as HB 307’s Senate counterpart) and SB 257—also addressed the creation of a Railbelt transmission organization. Some versions of these bills called for a more expansive RTO, one which would also operate the transmission system and even own parts of it. Two of the Railbelt utilities—GVEA and MEA—supported this more robust RTO. CEA supported the creation of a more limited RTO similar to the one in the enacted law. HEA said it supported the creation of an RTO in the future, but argued against doing so now.

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Why Was This Legislation Needed?

HB 307 was one of the more substantial energy bills passed by the legislature in the last twenty years. While its various provisions reflect a range of issues, concerns about the ability of the Railbelt utilities to meet demand and to keep the cost of power affordable were key drivers of its development. Its provisions address long-standing issues (a lack of coordination by the Railbelt utilities) and more immediate concerns (anticipated shortfalls of Cook Inlet natural gas and questions about the capacity of regulatory agencies to respond to new challenges). Legislators were also driven by a belief that the Railbelt utilities would only work together to reform the transmission system if they were forced to do so.

The most recent push to create a unified Railbelt transmission authority gained steam after the release of a 2015 report commissioned by the Legislature. A fully integrated transmission system with sufficient capacity is a precondition to implementing “economic dispatch,” where an independent system operator uses the least expensive power available to meet demand, regardless of where that power is generated. Many hoped that the passage of SB 123 in 2020, which called for the creation of a Railbelt ERO, would lead to a more unified system. But the creation and startup of the RRC (which filled the role of the ERO) took longer than anticipated.

Meanwhile, two new developments fueled the need for transmission reform. One was the 2022 announcement by Hilcorp, which provides over 80% of the natural gas used by Railbelt utilities to generate power, that it would not renew existing contracts due to declining production. The integration of new, large-scale renewable energy projects is viewed as one tool to address impending gas shortages—many believe the development of such projects is only feasible if wheeling rates are removed and interregional transmission capacity expanded.

The second was the successful application by the Railbelt utilities (together with AEA) for a $206.5 million federal grant to build an undersea transmission cable linking the Kenai Peninsula to the rest of the Railbelt. The grant (currently frozen along with other federal funds) requires a full local match. Utility officials have said they believe state assistance will be necessary to match these funds, raising questions about who would own and operate the new infrastructure.

The Railbelt utilities themselves opened discussions about forming a transmission organization in the fall of 2023. But many observers believed that the differences between them over timelines and the new organization’s authority were serious enough that legislative intervention was required to see the project to completion.

Some other key provisions of HB 307—tax breaks for IPPs, strengthening regulatory capacity—reflect concerns or goals that have been developing for some time, but which were catalyzed by the discussions of the Alaska Energy Security Task Force (AESTF). This body, convened by the governor in 2023, was charged with charting a course for the state’s energy future and to find ways to reduce the cost of power. Many of HB 307’s provisions reflect AESTF recommendations.

A more detailed discussion of HB 307’s development and the need for legislative intervention can be found here.

Elements of the Bill

The Creation of an RTO (Sections 5, 10, 21-23, 26):

What is in the bill:

Reforming how the Railbelt transmission system operates was one of the bill’s key purposes. HB 307 creates a Railbelt RTO that is responsible for developing and administering an OATT. The RTO is overseen by a management committee consisting of representatives of the five Railbelt utilities and AEA, with the RRC’s CEO as a non-voting member. In its current form the RTO will not manage or own any section of the “backbone” Railbelt transmission system, although it could take on these responsibilities in the future.

The OATT will replace the present method of paying for the transmission system. Currently each utility owns and operates its own transmission lines, charging other utilities wheeling fees to use them to transfer power. The operation and maintenance of transmission lines is funded through rates paid by utility members and wheeling fees. Two parts of the Railbelt transmission system—the Northern Intertie that links the Interior with Southcentral Alaska and the Sterling-Quartz Creek line that connects the western Kenai Peninsula to the rest of the Railbelt—are owned by the state through AEA.

The OATT will not change system costs, only how they are recouped. The RTO will determine the overall annual cost of operating the backbone transmission system, then allocate these costs to the utilities based on the benefit they derive from it. These costs will be factored into the rates paid by cooperative members or other utility customers. The individual utilities will continue to maintain and operate their own transmission assets, with the costs of doing so factored into the OATT.

The OATT will also be “open-access” and “non-discriminatory”—all power will be treated the same, whether it comes from a utility or an IPP (although allowances will be made to ensure that utilities have the capacity required to meet their own internal needs). Any IPP that meets the technical transmission requirements will be allowed to connect to the system, so long as there is capacity.

The OATT will only apply to the Railbelt backbone transmission system. This means that radial transmission lines, which are only used by the utility who owns them, often to link power plants to the rest of the system or connect to large industrial customers, will not be included. The exact definition of the Railbelt’s “backbone” system is still being debated-- HB 307 simply says that the backbone system should be defined using “standards of the Federal Energy Regulatory Commission [FERC].” According to an AEA spokesperson, this refers to the “Mansfield Test,” a set of five criteria used by FERC to determine if transmission assets are backbone or radial. The RTO is responsible for applying these criteria.

HB 307 requires that the RTO model itself on the Bradley Project Management Committee (BPMC). Like the BPMC, the RTO’s Management Committee consists of one representative from each of the five Railbelt utilities and AEA. Because the two bodies need to coordinate their work, the RRC’s CEO is an ex-officio (non-voting) member. The bill left the RTO’s institutional status a bit vague—it states that “For administrative purposes, the transmission organization is a division of the Alaska Energy Authority.” Whether or not this means it is formally a part of AEA is unclear; in the Charter they drafted, the RTO’s members emphasize that it is a division of AEA “for administrative purposes only.”

In its current form, the RTO will not own or manage transmission assets, only create and collect the OATT. Some versions of the transmission legislation called for an RTO that would have greater responsibilities, and many consider this iteration as just a starting point. In testimony to the House Finance Committee in May 2024, Andrew Jensen, an advisor to the governor on energy matters, expressed the hope that this RTO was “a first step” and a “foundational piece” in a process that will lead to a fuller integration of the Railbelt grid.

The issue of the RTO’s responsibilities and powers may be raised again in the Legislature. If, as the Railbelt utilities hope, the state provides the bulk of the matching funds for the federal transmission grant (possibly through a General Obligation bond), or provides other funding for developing the Railbelt transmission system, the question of the ownership and operation of these assets will need to be decided, with the RTO as one logical candidate.

Impact to date:

HB 307 set firm deadlines for the RTO to achieve key milestones. It was required to submit an application for a Certificate of Public Convenience and Necessity from the RCA by December 31, 2024, and its OATT by July 1, 2025—if it misses either of these deadlines, the responsibility for developing the OATT would fall to the RCA. The inclusion of these deadlines was likely intended to prevent a repeat of the lengthy process required to stand up the RRC (see below for the RRC’s timeline).

Representatives of the Railbelt utilities started discussions about developing some sort of transmission organization and creating an OATT in the fall of 2023 and had even hired outside consultants. There were some questions about the form of the RTO’s application for a certificate (since it is not technically a utility), but these were settled by October. The RTO submitted its certificate application on December 20, 2024, along with its Bylaws and Charter. These are currently under review by the RCA, which will decide whether to grant a certificate by June 8, 2025.

 Watchdogs, including the Regulatory Affairs and Public Advocacy section of the Attorney General’s Office (RAPA, which represents the public interest in RCA hearings), the Renewable Energy Alaska Project (REAP), and the Alaska Public Interest Research Group (AKPIRG), have raised questions about aspects of the RTO’s application. These include the absence of required audits, a timeline for defining the backbone transmission system, and whether the RTO’s bylaws conform with Alaska’s Open Meetings Act.

The RTO Committee is continuing work on its OATT, which is due by July 1. Once it is submitted, the RCA’s review process could last from 2.5 to 11 months, with the longer timeline likely.

Tax Breaks for IPPs (Sections 9, 16)

What is in the bill?

HB 307 provides tax exemptions, primarily from local property taxes, to IPPs for generation or battery storage facilities opened after July 1, 2024. This is meant to level the playing field with generation plants owned by cooperative utilities, which are already exempt. Utilities do pay a state tax, but this is based on the number of kilowatt hours (kWh) they sell, regardless of who produces the power. IPPs taking advantage of this tax break are required to sell all their power to utilities serving the public.

Supporters of these provisions argued that tax parity will make IPPs more competitive, leading to greater development of renewable power projects and lower rates. Over the past 15 years, regulated utilities have only submitted power purchase agreements with IPPs for RCA approval if the power being bought was below a utility’s “avoided cost”—the amount they would spend generating the power themselves or buying it from other available sources—so even a small difference in price can have a significant impact.

IPPs say that property taxes make up a significant portion of their operating expenses. In a letter sent to the Senate Finance Committee regarding SB 217, Jenn Miller, the CEO of Renewable IPP (which currently operates two solar installations in the Matanuska Valley), said these taxes could account for as much as 30% of operating costs (renewable generation facilities have high construction costs, but low operating costs since they do not need to buy fuel). Miller estimated the elimination of these taxes would reduce the price of power IPPs sell to utilities by about 5%. Another section of HB 307 requires that these tax exemptions be factored into wholesale power agreements between IPPs and utilities, to ensure they benefit consumers.

Impact to date:

It is difficult to estimate the impact of these provisions so far. Only one significant agreement between an IPP and utility has been submitted to the RCA since the passage of HB 307--an agreement between Solstice Energy (a subsidiary of Renewable IPP) and HEA for a 30-megawatt solar farm in Nikiski (known as the Puppy Dog Lake project). A filing by Solstice Energy acknowledges the tax break, which was presumably factored into pricing, but work on the deal likely predated the bill. On February 13, Solstice Energy cancelled its agreement with HEA, citing economic reasons.

Changes to the RCA—New Commissioner Qualifications, Higher Pay for Commissioners, and an Increase in the Regulatory Fee Funding the RCA: (Sections 3-4, 7, 14, 24)

What is in the bill:

HB 307 includes several provisions intended to strengthen the RCA’s capacity as it faces considerable regulatory challenges. It imposes new qualifications for the commissioners who lead the body and increases their pay. It also allows the RCA to raise the regulatory fees paid by utilities to fund the Commission, which will allow it a bigger budget. This increase was one of the AESTF’s recommendations (Action F-3.1).

The RCA is expected to face a number of difficult challenges in the coming years. It will need to approve the RTO’s OATT (which is new for Alaska), consider innovative rate designs that utilities are adopting, address the growth of home energy systems (such as solar panels), consider the impacts of “beneficial electrification” (such as electric vehicles and heat pumps), and deal with regulatory issues arising from the Cook Inlet gas shortfall (such as contracts for purchasing LNG and how to pay for the infrastructure necessary for imports). The RCA also has to address other legislative mandates, such as the creation of regulations for community energy projects required by SB 152 (also passed in 2024).

These challenges come at a time when the RCA is facing on-going staffing challenges. In March 2024, the RCA’s Administrative Operations Manager, Naomi Johnston, told the House Labor and Commerce Committee that one-third of staff positions were vacant. Legislators and watchdogs had also raised concerns about the qualifications of three recent appointees to the Commission—Keith Kurber (appointed in 2021), Robert Doyle (appointed in 2022), and John Espindola (appointed in 2023). There are five commissioners appointed by the governor who serve 6-year terms. (For more on concerns about the RCA’s capacity, see this AETP article from October 2024).

The heightened qualifications for the commissioners and the accompanying higher pay were intended to attract and retain more qualified candidates. In March 2024, RCA Chair Robert Doyle told Nat Herz that the relatively low pay for commissioners was making it difficult to recruit good candidates. The situation continued to deteriorate over the course of the year. Commissioner Jan Wilson retired at the end of her term in March 2024, and two other commissioners—Kurber and Doyle—left in 2024 midway through their terms. As a result, the Commission did not have five members for most of 2024, and for a time only had three commissioners, the minimum number required to make rulings.

Before HB 307, commissioners were required by statute (AS 42.04.20) to meet one of the following criteria: be a member of the Alaska Bar, have a degree in a relevant field (engineering, finance, economics, accounting, business administration, or public administration) or to have five years’ practical experience in one of those fields. HB 307 raises these qualifications, emphasizing a combination of education and experience. Attorneys now need to be members of the Alaska Bar and have at least five years of practical experience. Engineers must be registered with the state and have at least five years’ practical experience. Those qualifying in other areas must have a degree in a relevant field and five years’ experience in the same field. These requirements are not retroactive, but currently serving commissioners will be held to them if they are reappointed. HB 307 also raised commissioner pay from Range 27 to Range 29 on the state salary scale.

HB 307 gives the RCA the ability to increase the regulatory fee it charges utilities—almost all of its annual budget comes from these fees. Previously it was allowed to levy a fee up to 0.7% of utilities’ gross revenue; that cap is now raised to 0.98%, an increase of about 40%. This cap is the maximum level the RCA can charge; the annual charge is set based on budgetary needs, and can be lower. HB 307 also increases the regulatory fee that funds RAPA, from 0.17% of gross revenues to 0.22%. In March 2024, Johnston told legislators that, if the RCA increased its surcharge to the new maximum, it would raise the average electric consumer’s bill by 27 cents a month.

Impact to Date:

The new level of commissioners’ pay is incorporated into the governor’s proposed 2026 operations budget.Under this budget, the cumulative pay of the five commissioners will rise from $755,157 in the proposed FY 2025 budget to $926,411, an increase of 23% (these figures include a proposed cost-of-living adjustment). This increase is not due to HB 307 alone—some of the new commissioners were placed on higher steps within Range 29, presumably because of their qualifications. Only two of the current commissioners were serving in January 2024. Commissioner Robert Pickett, who has served on the RCA since 2008, will see a substantial pay increase of about 30%, moving up not only in Range, but in step as well. Espindola, who previously had been the highest paid commissioner, despite being the most recent appointee, will see a more modest increase of about 2.5%.

With the appointments of John Springsteen (July), Steven DeVries (November), and Mark Johnston (December), the RCA again has a full complement of five commissioners. It is unknown what role, if any, the higher pay played in attracting these candidates. All three new appointees will be subject to legislative confirmation this spring. Based on their RCA biographies, they appear likely to meet the higher qualifications. If Espindola or Pickett are reappointed, they will be held to the new qualifications. Espindola’s term ends on March 1, 2025, Pickett’s in 2026.

The immediate impact of the higher surcharge cap is difficult to judge. The RCA set its FY 2025 surcharge before HB 307 was signed into law (the state fiscal year begins on July 1). The FY 2025 budget was approaching the limits of the old surcharge. However, because of understaffing, funds collected for FY 2024 were carried over. The proposed FY 2026 budget is 2.7% higher than FY 2025, although there will likely be another carryover of unspent funds, so the higher cap probably will not be activated before FY 2027.

Staff retention continues to be a challenge at the RCA, where the vacancy rate remains at about 30%, more than twice the reported average of 13.9% for state agencies (as of December 2024). Three vacant positions are being dropped from the FY 2026 budget, including two master utility analysts. The FY 2026 budget returns the RCA to its 2020 staffing level. Turnover is also high—of the 41 staff members listed in February 2024 (excluding commissioners), only 27 appeared on the RCA roster on February 14, 2025.

It is difficult to evaluate the impact of HB 307 on staff pay. The total personnel budget increased by several hundred thousand dollars from FY 2025 to FY 2026, but that includes the raises given the commissioners. Changes in step classifications due to staff turnover make direct comparisons difficult. Most RCA staff are subject to collective bargaining agreements, so additional wage enhancement would likely come through reclassification on the salary scale. The FY 2026 budget calls for non-bargaining employees to be moved up one step on the salary scale and to receive a 5% cost-of-living adjustment.

The FY 2026 budget indicates the RCA plans to upgrade its technical systems and website, to simplify the filing process for utilities and make information easier to access. These will be put out to bid in the coming year, so are not included in the current budget. The FY 2026 budget does include funds to hire outside experts to help the RCA evaluate the RTO’s OATT.

Expansion of the Criteria the RCA Can Use to Determine if Utility Rates Are Just and Reasonable (Section 8)

What is in the bill:

HB 307 amends the state statute (AS 42.05.381) that requires the RCA to ensure the rates charged by public utilities are “just and reasonable.” In the past, these evaluations have been made primarily on the basis of cost (although AS 42.05.141 allows the RCA to consider the “conservation of resources used in the generation of electric energy” and whether a contract will impact a utility’s ability to provide reliable service). HB 307 amends AS 42.05.381 to allow the RCA to consider “whether the purpose of the rate is intended to increase the diversity of supply, promote load growth, or enhance energy reliability or energy security” when evaluating rates or power purchase agreements.

The new language was taken largely from the AESTF’s recommendations (A-2.2, A-3.1). The first and third clauses—diversity of supply and energy security—are, at least in part, a reaction to the anticipated shortfall of Cook Inlet natural gas, which underlined the risks of reliance on a single source of fuel. Imported LNG will be both more expensive than Cook Inlet natural gas and subject to market volatility and potential supply disruptions due to international events. This language could allow the RCA to consider approving contracts for renewables or other fuel sources that may be higher than the current cost of generation using Cook Inlet natural gas. The language about the diversity of “supply” (as opposed to fuel type) could also be used to support arguments for a natural gas pipeline from the North Slope, which the AESTF also endorsed.

The clause about load growth is intended to make it easier for utilities to sign contracts offering special rates to new, large commercial customers. Increased loads can potentially lower the cost of power for other users, by spreading a utility’s fixed costs over more units of power. Governor Dunleavy has emphasized load growth as a way to attract businesses and reduce rates (he charged the AESTF to find ways to reduce Railbelt electric rates to 10 cent/kWh, about half the current average).

Impact to date:

AETP is not aware of this language being cited in any filings with the RCA or RCA orders as of February 21, 2025.

Changes to the RRC (Sections 11-13):

What is in the bill:

The RTO’s OATT will address some issues previously assigned to the RRC, including the development of standards for transmission tariffs and standards for open access transmission. HB 307 adjusts the statutes governing EROs (AS 42.05.760-790) to reflect these changes. It also instructs the RRC to “prioritize the reliability, stability, and cost to consumers” in its work. Lastly, HB 307 specifies that only interconnected electric systems with total sales of over 3 million megawatt-hours a year are required to form an ERO.

The decision to create the RTO was, at least in part, due to frustration with the perceived slow pace of the RRC’s work. Although the Legislature passed SB 123 in 2020, the RRC did not begin its work in earnest until 2024. The President of the RRC’s Board, Joel Groves, addressed the reasons for this in testimony to multiple legislative committees, including the Senate Resources Committee, during hearings on HB 307 and related bills It took the RCA nearly two years to develop the regulations required by SB 123 and create an application process; the RRC was not certified as the Railbelt ERO until September 2022. It was further slowed by challenges to its budget before the RCA by the utilities (although the utilities hold 5 of 13 seats on the RRC Board that had approved the budget).

The RRC was also slowed by difficulties in hiring a CEO, which took almost two years. This limited the development of the RRC’s products because the CEO was responsible for hiring technical staff. Work on reliability standards began in March 2024 after the Board hired a Chief Technical Officer to oversee initial work on standards until a CEO was hired.

Beyond its pace of work, there was debate about whether the RRC was authorized to create a uniform Railbelt transmission tariff or only a mechanism to pay for upgrades needed to meet its reliability and transmission standards. In testimony to the House Finance Committee in May 2024, Andrew Jensen, advisor to Governor Dunleavy, said that his understanding was that the RRC could set standards for individual utility transmission tariffs, but not impose a unified tariff itself.

Some versions of the transmission bills also transferred another of the RRC’s responsibilities, the creation of an Integrated Resource Plan (IRP), to the RTO. The IRP is a master plan for future development of generation and transmission assets along the Railbelt, intended to coordinate development to maximize the use of resources. Some, including Gwen Holdmann (a senior researcher at ACEP--the Alaska Center for Energy and Power at the University of Alaska, Fairbanks), believed that the RTO was the logical organization for transmission planning and that responsibility for the IRP should be transferred to it. Some versions of the bills split planning of generation and transmission between the two organizations. But some legislators and other stakeholders pushed for the IRP to be left with the RRC, arguing that its transfer would only further delay the IRP and that the RRC was better suited to this work because it incorporated a variety of viewpoints (as opposed to the utility-dominated RTO).

During hearings on HB 307 and related bills, Senator Cathy Giessel (R-Anchorage), who chaired the Senate Resources Committee and was one of the driving forces behind the energy bills, and Senator Jesse Bjorkman (R-Nikiski), Chair of the Senate Labor and Commerce Committee, advanced amendments to cap the RRC’s future budgets. Both expressed concern that the RRC’s spending (or potential spending) was too high given its small output to date. Giessel wanted to cap the RRC’s budget at 50% of the RCA’s (the RRC’s approved 2024 budget was about $5 million; the FY 2025 RCA budget was $10.8 million). Bjorkman, who was highly critical of the RRC during hearings, suggested a cap of $1.2 million dollars. He also proposed other amendments that would have had the effect of strengthening the utilities’ influence within the RRC. None of these were included in the final version of the bill.

There was no public discussion of the addition of statutory language requiring the ERO to prioritize reliability, stability, and cost. This may have been related to concerns voiced about the RRC’s budget. The provision exempting interconnected systems under 3 million megawatt-hours from creating an ERO was added at the request of legislators representing rural areas. They were concerned that the future interconnection of small grids could force them to create an ERO.

Impact to Date:

In January 2025, Ed Jenkins, the RRC’s newly hired CEO, testified to the House Energy Committee about the RRC’s status. Jenkins indicated the RRC is now making considerable progress in its work—it has already submitted its first four reliability standards to the RCA for approval, and expects to submit an additional three in February. He believes they will have completed all 28 required reliability standards by the end of the year. The RRC is also currently negotiating with consultants to help develop its IRP. Jenkins said they are looking at ways to modify the IRP development process to speed its completion, but without sacrificing opportunities for public input. The goal is to complete the IRP and submit it to the RCA by the end of 2026.

When asked about the RRC’s budget, Jenkins responded that its spending will probably peak in 2026, as they complete work on reliability standards and develop the IRP, and then begin to decrease. Although both the reliability standards and IRP will be updated periodically, these revisions will be less labor-intensive and staggered over different years. On January 31, the RCA opened a rule-making docket (R-25-001) to make the revisions required by HB 307 to the regulations governing the RRC’s work. Public comments will be accepted until March 3.

Changes to AEA—Creation of an Independent Board and the Ability to Acquire Battery Storage System(Sections 2, 17-20, 25)

What is in the bill:

HB 307 gives AEA an independent eight-member Board; since 1993, AEA had shared a board with AIDEA. The new board was designed to include individuals with expertise in different areas of Alaska’s energy systems. Six of the directors are appointed by the governor for 3-year terms (the other two are the state Commissioners of Revenue and Commerce, Community, and Economic Development).

In a presentation to the Senate State Affairs Committee in January 2024, AEA Executive Director Curtis Thayer said that AEA had grown considerably in recent years (its capital budget has increased tenfold since 2019) and that it would benefit from having a board focused on energy issues. The governor initially tried to create a separate AEA board through executive order (EO 128) in January 2024; however, legislative attorneys believed this action exceeded the governor’s powers, and the Legislature nullified the Order. But there was general agreement with the idea of creating a separate AEA Board, so the idea was reintroduced as SB 243, which was later merged with HB 307.

HB 307 also gives AEA the power to acquire energy storage systems, such as batteries. The Railbelt utilities have earmarked money from a 2022 bond issue associated with Bradley Lake for large-scale storage batteries to support grid stabilization and the use of Bradley Lake power. HB 307 allows AEA to use these funds to be full or part owner of such systems, reducing the utilities’ costs.

Impact to Date:

The newly constituted AEA Board held its first meeting on September 10, 2024. Its members have expertise with different aspects of the Alaskan electric sector. They are Tony Izzo (MEA’s CEO), Clay Koplin (CEO of Cordova Electric Cooperative), Ingemar Mathiasson (Energy Manager for the Northwest Arctic Borough), Jenn Miller (CEO/Manager of Renewable IPP), Duff Mitchell (Managing Director of Juneau Hydropower), and Robert Siedman (CEO of the Southeast Alaska Power Agency). Department of Revenue Commissioner Adam Crum and Department of Commerce, Community, and Economic Development Julie Sande are also board members. The new board has been extremely active, passing numerous resolutions since it took office, including one to try to sell renewable energy credits (RECs) associated with Bradley Lake.

The new board has already exercised its new power to purchase or lease energy storage systems. In November, AEA signed contracts with HEA, MEA, and CEA to purchase the “priority rights” for some of the capacity of their new battery storage systems (the CEA/MEA storage facility is jointly owned). A similar agreement with GVEA is under consideration.

Acronyms used in this article:

ACEP—Alaska Center for Energy and Power at the University of Alaska, Fairbanks

AEA—Alaska Energy Authority

AESTF—Alaska Energy Security Task Force

AKPIRG—Alaska Public Interest Resarch Group

BPMC—Bradley Project Management Committee

CEA—Chugach Electric Association

ERO—Electric Reliability Organization

FERC—Federal Energy Regulatory Commission

GVEA—Golden Valley Electric Association

HEA—Homer Electric Association

IPP—Independent Power Producer

IRP—Integrated Resource Plan

LNG—Liquified Natural Gas

MEA—Matanuska Electric Association

OATT—Open Access Transmission Tariff

RAPA—Regulatory Affairs and Public Advocacy section of Attorney General’s Office

RCA—Regulatory Commission of Alaska

REAP—Renewable Energy Alaska Project

RRC—Railbelt Reliability Council

RTO—Railbelt Transmission Organization

Legislation Mentioned:
HB 307—energy bill passed in 2024

SB 217—Senate companion to HB 307, introduced in 2024

SB 257—Senate energy bill introduced in 2024; some provisions were integrated into the final version of HB 307

SB 243—Bill creating independent board for AEA, passed in 2024

SB 123—Bill passed in 2020 requiring the creation of a Railbelt ERO.