Bradley Lake Management Structure Considered for Proposed Regional Transmission Organization
May 13, 2024
By Brian Kassof
With just days left in the regular session, the Alaska Legislature is still considering a bill that would change the rules by which the Railbelt electric transmission system operates. These changes are being considered as the state and Railbelt utilities are applying for hundreds of millions of dollars in federal grants to upgrade significant portions of the existing transmission system. These upgrades are part of a nearly $3 billion transmission plan proposed by the Railbelt utilities.
The bill (SB 217 and its companion HB 307) would create a Regional Transmission Organization (RTO) as part of the Alaska Energy Authority. The powers of the proposed RTO have changed several times as the bill has made its way through the Legislature. The more slimmed down versions limit the RTO’s powers to developing and administering a new uniform method for paying for power transmission. This would eliminate “wheeling rates”--the fees that utilities currently charge one another to move power through the parts of the transmission system they own. More expansive versions of the bill also have the RTO managing and operating the Railbelt transmission system, overseeing the construction of new transmission assets, and engaging in long-term planning. As this article is published, it is unclear which version, if any, might make it to the Governor’s desk. (AETP will publish an in-depth examination of this legislation if it passes).
A key part of discussions about the RTO is how it should be organized and managed. While a few different governance models have been discussed, legislators, utility officials, and energy specialists have repeatedly pointed to the management committee that oversees the Bradley Lake hydroelectric project (the Bradley Project Management Committee or BPMC) as an excellent model for the proposed RTO. Language specifying the use of the BPMC template for the RTO has even been included in multiple versions of SB 217. As the Legislature moves swiftly to the end of its session, it is useful to look at the BPMC and consider the strengths and weaknesses of this governance model, as well as some concerning issues about accessibility and accountability in some aspects of the BPMC’s recent activities.
There are five Railbelt utilities—four cooperatives (Homer Electric Association (HEA), Chugach Electric Association (CEA), Matanuska Electric Association (MEA), and Golden Valley Electric Association (GVEA), along with the city of Seward’s municipal electric utility. The Alaska Energy Authority (AEA) is a state agency tasked with reducing the cost of energy.
The Bradley Project Management Committee Model:
The BPMC is what its name suggests—a simple management committee to oversee the 120-megawatt (MW) Bradley Lake project. Bradley Lake is the largest hydroelectric generation facility in Alaska and currently provides the Railbelt with about 10 percent of its annual electricity. The committee consists of the leaders of each of the five Railbelt utilities and the head of AEA, who represents the state.
Construction on Bradley Lake started in 1986 and it went into service in 1991. The project required legislative intervention to get off the ground, with the state providing some funding and exempting Bradley Lake from regulatory oversight by the Alaska Public Utilities Commission, the forerunner of the Regulatory Commission of Alaska (RCA). In return, the state required the participating utilities to sign a series of agreements binding them to the project and establishing the basic rules for its governance and operation.
One of these was a Power Sales Agreement (signed in 1987) that called for the creation of the BPMC and laid out some basic guidelines for the bylaws the Committee itself was to draft to govern its work. Each participating utility was given a seat on the Committee (these are now filled by their CEO or General Manager), along with a representative from AEA.
During the recent legislative discussions about creating an RTO, legislators and officials providing testimony have repeatedly pointed to the BPMC as a good template for a governance structure. They have emphasized how the BPMC’s rules for decision-making and dispute resolution have created a space where the often-contentious Railbelt utilities have been able to work together productively for over thirty years.
The BPMC Bylaws set the rules for decision-making and dispute resolution. The decision-making rules have two key elements. First, they are designed to push the Committee to work by consensus, with a supermajority required for many decisions. Second, they give AEA veto power over major financial decisions, a reflection of the state’s ownership of the project.
Decisions are sorted into four tiers. The lowest require only a simple majority. More consequential decisions, like scheduling power deliveries, require a supermajority of four members who collectively receive at least 51 percent of the project’s power. Important financial questions require the same supermajority and the assent of AEA, giving the state effective control over financial decisions. Bylaw revisions also require a supermajority and AEA approval, with one exception: Changes to the Dispute Resolution section of the bylaws require a unanimous vote of the Committee.
This last requirement points to the importance of dispute resolution for the BPMC. The rules spelled out in the bylaws provide clear incentives to find mutually-agreeable solutions to major problems. In at least one particularly contentious case, the BPMC created a special Dispute Resolution Committee to try to settle the matter. If internal attempts to solve a problem fail, committee members can request it be referred to outside arbitration. If all other measures at dispute resolution fail, the BPMC can then impose a solution through a simple majority vote, avoiding long-term gridlock.
Utilities can appeal decisions they believe to be unreasonable or in violation of the terms of Bradley’s founding agreements to the Alaska court system. But if the courts rule in the BPMC’s favor, its decision stands. This system generally seems to work to settle disputes, although one particularly contentious disagreement between HEA and the rest of the Committee ran for over five years and was eventually settled when the Alaska Supreme Court affirmed the BPMC’s authority over the matter.
Supporters of using the BPMC governance model for an RTO also point to the BPMC’s low cost. AEA provides meeting space and logistical support (it houses the BPMC website), and the actual work of operating the Project and its related transmission assets are contracted out to participating utilities. Sub-Committees are usually staffed by utility employees. As a result, BPMC technically does not have direct employees (just consultants) and no physical offices. The claims of cost savings do not account for the considerable amounts of utility staff time that have been dedicated to BPMC projects, as discussed below. These costs do not appear on BPMC balance sheets, but are instead passed on to the ratepayers at the individual utilities as administrative costs.
Transparency Concerns:
The legislation that helped create the Bradley Project required that its meetings be open to the public (AS 42.05.431(d)). The BPMC follows these requirements–its meetings are properly noticed, open to the public, and provide time for public comments. Agendas, audio recordings of meetings, and minutes are posted in a timely manner. There is a BPMC archive on the AEA website that appears to have meeting materials going back to 2003–however at the time this article was published, there are only live links for materials since 2021.
While the BPMC follows open meetings rules, there are still transparency issues around its work. In recent years it has spent extensive portions of its public meetings in closed executive session. In 2022 and 2023 the BPMC spent nearly two-thirds (63 percent) of its meeting time in executive session, including a span of 22 consecutive meetings where at least half the meeting was spent in executive session. (For details, see the tables at the end of this article.) The ability for a board or committee to go into executive session is a prerequisite to having otherwise open meetings, and the BPMC provides the required generic justifications (such as the discussion of confidential legal or financial material) for doing so. But when it is used too extensively, executive session severely limits public understanding of a body’s work. The timing of when executive session is held can also be an issue—until mid-2023 the BPMC frequently held executive session near the beginning of meetings, meaning that visitors had to leave (and those attending remotely had no way to know when executive session had ended or mechanism to reenter the meeting).
Remote attendance at BPMC meetings is also difficult. The only option for remote attendance is by telephone—the meetings are held on Teams, but the public cannot join this way (the Railbelt cooperative boards allow members of the public to join their meetings via Teams).
The BPMC Bylaws also allow it to conduct extensive discussions outside of structured meetings—Sub-Committees are exempt from open meeting rules and the bylaws explicitly permit committee members to meet informally, so long as they do so as representatives of their individual organizations, not as members of the BPMC, and no BPMC business is conducted. The BPMC can also delegate some of its powers to its Sub-Committees, so long as this is done in an official resolution.
Questions of Accountability:
As mentioned above, the legislation that helped enable the creation of the Bradley Lake Project exempted it from RCA oversight. This is in contrast to the four electric cooperatives that make up most of its membership, as well as the Railbelt Reliability Council (RRC, the electric reliability organization created by SB 123 in 2020 to oversee aspects of the Railbelt transmission system). Gwen Holdmann of the Alaska Center for Energy and Power, who has generally spoken favorably of the BPMC format as a model for an RTO, has pointed to a lack of regulatory oversight as one aspect that could be improved. In testimony to the Legislature this session, Holdmann argued that aspects of an RTO, particularly its transmission tariff (the rate charged for moving power through the system) should be subject to RCA approval.
The BPMC’s lack of transparency and the absence of RCA oversight are of interest because, since at least 2022, the Railbelt utilities have been using the BPMC as a venue to engage in a number of Railbelt-wide initiatives that appear to push the boundaries of the organization’s mandate. Foremost among these are a $2.87 billion plan to expand and rebuild the Railbelt transmission system and applications for federal funding to cover some of its costs. Although the execution of this plan would have a significant impact on everyone living in the Railbelt, this work has been carried out largely behind closed doors, with little or no public input or participation, independent review, or the type of public interest determinations made by the RCA when evaluating utility proposals. It also appears to have proceeded with limited oversight by the boards elected to guide the cooperatives’ work.
This use of the BPMC to develop Railbelt-wide projects dates to at least March 2022, when it hired Brian Hickey as a consultant. Hickey, who at the time was preparing to step down from his role as CEA Chief Operating Officer, was given the title Executive Director of Railbelt Regional Coordination (EDRRC, a title that has caused some confusion, given that the RRC was just starting its work at this time). One of Hickey’s initial responsibilities was to help coordinate a series of projects, to be paid for by bonds issued by AEA using surplus Bradley funds, to improve the transmission lines that take Bradley power off the Kenai Peninsula.
Hickey’s initial charge also included a number of projects that, while of interest to the Railbelt utilities, appeared to go beyond the BPMC’s remit. These efforts included lobbying on the Renewable Portfolio Standard (RPS) legislation (HB 301/SB 179) introduced in 2022, meeting with a working group looking into carbon capture opportunities, and discussions around the impending shortages of Cook Inlet natural gas. Hickey began to work with a “Tactical Team” (also known as the Railbelt Subcommittee on Infrastructure and Policy) consisting of staff from the Railbelt utilities and AEA to support these efforts. Later, in 2023, Hickey and his team also helped prepare the recommendations that MEA CEO Tony Izzo presented to the Railbelt Sub-Committee of the Alaska Energy Security Task Force.
Among Hickey’s original tasks as EDRRC was to pursue federal grants. This soon became the main focus of his work as the United States Department of Energy (DOE) rolled out the Grid Resilience and Innovation Partnership (GRIP) program in 2022. Using funds from the 2021 Infrastructure Investment and Jobs Act (IIJA), the GRIP program will award $10.5 billion dollars in federal grants for transmission system upgrades in four phases of funding through 2026.
At the BPMC’s behest, Hickey and his team began to prepare applications for three different Phase 1 GRIP grants due in 2023; ultimately the DOE encouraged them to apply for two of these. To date the BPMC has spent almost $1.5 million to pursue GRIP funding (this includes Hickey’s salary, consultants, grant-writers, and lobbyists). This expense is in addition to the considerable staff time donated by Railbelt utilities—a proposed budget for fiscal 2023 estimated 1040 hours of utility staff support time for Hickey’s work (valued at $200 per hour). In February 2023 GVEA’s Board was told that the demands on staff time to help prepare the GRIP applications had delayed work on GVEA projects, such as a community solar initiative.
To support the GRIP applications, Hickey and his team also worked up an extensive $2.87 billion plan to completely remake the Railbelt transmission system. This plan, named the Grid Modernization and Resiliency Plan (GMRP), draws on various proposals made over the past two decades, and includes an expansion of the system to encompass the region from Valdez to Delta Junction along the Richardson Highway (the ‘roadbelt’ expansion).
In October 2023 AEA announced that one of the Phase 1 GRIP applications had been successful, and that it had been awarded $206.5 million for a high-voltage DC cable linking the Kenai Peninsula and CEA’s Beluga power station. (Although the BPMC prepared the GRIP applications, they needed to be submitted under the name of AEA or a specific utility). In April 2024 AEA submitted a Phase 2 GRIP application (also prepared by Hickey’s team) for $365 million to build a high-voltage DC transmission line linking the Beluga power station to Healy. Both grants require a 100 percent local match.
Preparing the GRIP applications through the BPMC expedited the process in a number of ways. By using BPMC funds to pay for it, the utilities avoided having to get approval from the RCA or their boards (which could slow the process considerably). The BPMC also offered a venue for coordination and collaboration outside public scrutiny. The entire planning process was conducted within the BPMC, without public discussion of whether or not these were the most effective ways to upgrade the grid or of any cost-benefit analysis that may have been conducted. Hickey has provided updates on the GRIP applications and GMRP to a number of other stakeholders (legislative testimony, cooperative board meetings, the RCA, the RRC). But these presentations were informational or to seek support for the project, not opportunities for feedback or detailed input.
Utility boards were aware the GRIP applications were being prepared, but it is not clear how much detail was shared with them. Hickey made presentations in January 2023 to the GVEA and the MEA boards that provided a broad overview of the GMRP and the GRIP proposals that were being developed. Many board members were uncertain about what their cooperative’s financial commitment would be if a grant application was successful. In response to a question about this by MEA board member Mark Hamm, Izzo replied that, while nothing was certain, he believed there was political support for the state to provide matching funds if an application was successful. Hickey added that the cooperative did not have to make any commitments until the negotiation period with the DOE that would follow a successful grant application.
Similar concerns were expressed by the members of the CEA Board at their February 2023 meeting. Although they were aware the grant applications were being prepared, they had not seen anything specific until a staff presentation at that meeting, which occurred just weeks before the Phase 1 grant applications were due. The board members were clearly surprised by the scale and timeline of the proposals—one board member described the “perplexed faces” around the room at the end of the presentation. CEA board members protested that they were being asked to approve the submission of the GRIP applications before they had adequate information or time to consider them. In response, Dustin Highers, CEA’s Vice-President of Corporate Programs (and a member of Hickey’s Tactical Team) repeated Hickey’s belief that no board action would be needed until after a grant was awarded. At that meeting both board members and some staff sounded skeptical of this strategy.
Three weeks later, however, at a CEA Board Operations Committee meeting on March 15, these concerns seemed to have been resolved. Staff told board members that no board action was needed to submit the applications. They also said that the board would have an opportunity to vote to accept funds on a project-by-project basis if a grant was received. CEA’s letter of support for a different Phase 1 GRIP application reflected this approach, listing four conditions that needed to be met before it would accept the grant.
If the GRIP grants are awarded and accepted, ratepayers and/or the state have to match funding for plans made without public input, independent review, or a publicly disclosed cost-benefit analysis. The state and utilities are currently discussing how to raise the $206.5 million needed to match the first GRIP grant they were awarded, even as AEA applies for an additional $365 million.
All of these activities appear to push the boundaries of the BPMC’s designated functions. According to its governing documents, Bradley-related work (beyond regular operation and maintenance costs) must improve or expand the project. Development of the GRIP applications and GMRP has been justified in BPMC reports as necessary to ‘unconstrain’ Bradley’s power potential. Due to present transmission constraints, Bradley can only dispatch about 75-85 MW, less than its potential production of 120 MW. The Dixon Diversion, a planned addition to Bradley that would divert additional water to the lake and raise the height of the dam, would increase potential output by another 50 percent if completed.
While some transmission upgrades will clearly facilitate the movement of Bradley power, the use of the BPMC to develop the GRIP applications and GMRP suggests that any upgrade to the transmission system can be justified as relevant to Bradley Lake. In internal BPMC documents, other potential benefits of the transmission upgrades, such as allowing for the integration of other large-scale renewable energy projects or eventually implementing a system of ‘economic dispatch’ (where the lowest cost power is dispatched to meet demand, regardless of where on the Railbelt it is generated) are listed as ‘ancillary’ benefits.
This framing largely flips on its head how these projects have been described to cooperative boards, in the GRIP applications, and in presentations to the Legislature. In these contexts, other benefits--decarbonization, reduced power costs, greater system resiliency, transitioning away from Cook Inlet gas, the integration of large-scale renewables, and economic dispatch—are all presented as the primary benefits of the new system, with unconstraining Bradley power listed as one of many upsides. There is no mention of unconstraining Bradley Lake in a concept paper supporting the latest GRIP application.
During the CEA board meetings in February and March 2023 cited above, staff suggested that only a portion of the GRIP-related projects were likely to be defined as essential for Bradley (the official term is “Required Project Work”--this is a legal definition based on the Power Sales Agreement that impacts how projects are paid for). Currently the BPMC is waiting for a ruling from the Alaska Department of Law on whether the undersea high-voltage DC line funded by the Phase 1 GRIP grant can be defined as required Bradley work. If it is, then they will be able to use $20 million from Bradley bonds as an initial matching payment.
During the recent legislative hearings on the creation of an RTO, another example of the BPMC being used for unsupervised and unregulated utility coordination has emerged. In testimony to the Senate Labor and Commerce Committee in April, Keriann Baker, Chief Strategy Officer at HEA, described how the four Railbelt cooperative CEOs had drawn up an informal agreement outlining the main elements of a transmission organization on the back of a napkin during an ACEP-sponsored trip to Iceland. Upon their return from Iceland, they formed a transmission committee under the auspices of the BPMC to flesh out this agreement. Over the past two weeks, representatives of multiple Railbelt utilities have described this group in testimony before the Legislature—Baker and GVEA CEO John Burns referenced it in testimony to the House Finance Committee, and CEA CEO Arthur Miller did the same in testimony to the Senate Finance Committee. This new committee consists of utility staff, aided by two outside consultants. Hickey has also referenced working with a team within the BPMC on plans for a ‘transmission service organization.’
In testimony to the Senate Finance Committee, GVEA’s Chief Operating Officer, Travis Million, explained that this group has been working to develop both a governance structure for an RTO and a cost-recovery methodology. The fact that they are working on their own governance structure as the Legislature is crafting a bill that addresses the same issue is unusual, and it is unclear what role, if any, the utilities’ governing boards are playing in this process.
In their testimony, utility officials have also revealed deep differences of opinion about the form and responsibilities of a future RTO. This raises questions about how well this group will be able to cooperate and collaborate, especially if the more expansive version of the RTO wins out in the Legislature. The Railbelt utilities have demonstrated a unity of purpose in pursuing the GRIP funding–it remains to be seen if they can sustain that unity around the development and operation of the system that money will help build. It also remains to be seen who will ultimately pay the cost of the upgrades envisioned in the GMRP if they are built.
Acronyms:
AEA—Alaska Energy Authority. Agency tasked with reducing power costs in Alaska
BPMC—Bradley Project Management Committee. Committee that oversees Bradley Lake hydroelectric project
CEA—Chugach Electric Association. Electric cooperative serving Anchorage area
DOE—United States Department of Energy
EDRRC—Executive Director of Railbelt Regional Coordination. Title given to Brian Hickey by the BPMC
GMRP—Grid Modernization and Resilience Plan. $2.8 billion plan created by BPMC to upgrade the Railbelt transmission system
GRIP—Grid Resilience and Innovation Partnership. Program administered by DOE to provide grants for transmission system upgrades
GVEA—Golden Valley Electric Association. Electric cooperative serving Fairbanks area
HEA—Homer Electric Association. Electric cooperative serving the western Kenai Peninsula
MEA—Matanuska Electric Association. electric cooperative serving the Ma-Su Valley
RCA—Regulatory Commission of Alaska. State agency that regulates some utilities
RRC—Railbelt Reliability Council. Electric reliability organization created to oversee aspects of Railbelt transmission system.
RTO—Regional Transmission Organization. Organization proposed in SB 217 and HB 307
