Final Railbelt electric plan cost estimate nears $900M
The Alaska Energy Authority is sticking with its belief that one of the state’s most critical pieces of infrastructure needs close to $900 million of improvements to truly be both reliable and efficient.
AEA’s final Railbelt Transmission Plan completed this spring concludes there are $885 million worth of projects to improve the economics and reliability of the electric grid from the southern Kenai Peninsula to Fairbanks.
Another $54 million of work to add substations and transmission lines primarily around Anchorage would improve system reliability but not significantly improve the economics of the Railbelt electric grid, according to AEA.
The Railbelt Transmission Plan was compiled for AEA by the Anchorage-based consulting firm Electric Power Systems Inc.
A draft version of the study released in early 2014 estimated the need to be $903 million, but that included some smaller projects to integrate the now-suspended Susitna-Watana hydropower project into the region’s transmission system, AEA Chief Operating Officer Kirk Warren said during the authority’s May board meeting.
Warren said about $400 million of the total estimate is for projects aimed at improving the flow of power from the 120-megawatt, AEA-owned Bradley Lake hydropower plant near Homer to the demand centers of Anchorage, the Mat-Su and Fairbanks.
However, leaders of the six Railbelt electric utilities have to varying degrees dismissed AEA’s assertions that all of the transmission upgrades — with a steep collective price tag — are necessary. They contend a smaller, more targeted work plan could provide improved efficiency with far less cost.
Matanuska Electric Association officials have said upgrading capacity of the southern Railbelt transmission intertie between the Kenai Peninsula and Anchorage could be done for as little as $50 million without the expensive reliability improvements that many in the utilities believe are unnecessary.
While there is disagreement over how much should be spent, there seems to be consensus among the key players that improving access to Bradley Lake power is imperative.
The current Kenai Peninsula transmission system, which is a single line between Soldotna and Anchorage, limits the availability of Bradley power when the hydro plant is operated at above 65 megawatts, or just more than half of its capacity.
The oldest part of the line was built originally in 1961 to move power from the small Cooper Lake hydro plant near Cooper Landing to Anchorage, according to the study.
It’s the inability to maximize the use of Bradley Lake whenever the utilities want it — at about 4 cents per kilowatt-hour, the hydro plant is the cheapest power source in the region — that limits its usefulness.
Additionally, AEA is pursuing a $50 million project to divert part of nearby Battle Creek into the Bradley Lake system, which would increase Bradley’s generation capacity by about 10 percent.
Specifically to combat the transmission line constraints and improve system reliability, AEA is proposing to run a new, subsea 100-megawatt, high-voltage direct current, or HVDC, line between Nikiski and Chugach Electric Association’s Beluga power plant on the west side of Cook Inlet. That standalone project is estimated at $185 million.
The cross-Inlet HVDC line improves reliability, but doesn’t completely free Bradley Lake power because the hydro plant would still have to be operated at a level that the existing intertie could handle in the event the subsea line was lost, according to the transmission plan.
As a result, more than $100 million in additional capacity upgrades to the existing transmission lines on the northern Kenai Peninsula, as well as a new, $66.6 million 115-kilovolt line between Soldotna and Bradley Lake are recommended.
The system redundancy created by the new subsea line could also allow spinning reserve, or backup, generation plants on the Peninsula to be shut down.
That could then save money for Peninsula ratepayers who would not have to support the full cost of their own backup generators if today’s line to Anchorage were lost or any reason, Warren said.
The southern intertie has been out of service for almost a month each year over the past decade, according to the study.
The lack of extra transmission capacity is also a direct impediment to new renewable energy projects, the study also notes.
A similar scenario with added spinning reserve costs plays out in Fairbanks, as much of the northern electric intertie between Willow and Healy is a single transmission line, too.
For the northern half of the Railbelt, AEA suggests a new 230-kilovolt line between Point MacKenzie and Willow at a cost of $128 million and another new $245 million line between Willow and Healy, which would de-constrain and add redundancy to the northern transmission lines.
AEA owns the northern intertie, which was built in the mid-1980s with direct state appropriations.
The second transmission line between the Interior and Southcentral “will prevent the loss of load in Fairbanks for single line outages and will allow (Golden Valley Electric Association) to access electrical and gas markets in the Southcentral system,” the transmission plan states. “It will also allow GVEA to evaluate the most economic solution for replacement generation capacity as its power production fleet continues to age or if coal resources are retired.”
AEA estimates the suite of projects — forecasted in 2030 dollars, when the work could be completed — would save Railbelt consumers between nearly $35 million and $83 million collectively on their electric bills each year strictly through allowing utilities to always use the cheapest power source and the potential to optimize spinning reserve Railbelt-wide.
The earlier draft of the transmission plan had much greater estimated savings, between about $80 million and $240 million per year, because it made assumptions that the utilities would minimize or eliminate their spinning reserve once redundancy was built into the transmission system, according to AEA’s Warren.
However, he said the final study focused on the most economic dispatch of power because each utility has its own requirements for back-up generation.
“Without additional transmission improvements, generation planning will continue to be completed by individual utilities, located in geographically dispersed areas,” The study concludes. “Capacity sharing and deferral will be limited by the existing transmission system and customer rates will not be at their lowest level possible.”
As is often the case, one of the biggest hurdles is determining who pays for what, particularly given the fact the State of Alaska won’t be offering the grant funds that have covered these types of infrastructure projects in the past.
The utilities could debt finance the projects themselves, Warren said, but that is quickly complicated by several factors.
“The real issue revolves around settlement amongst the utilities on who pays for what,” he said.
Partially because ownership of the transmission lines is fragmented to each utility’s service area, a utility that owns a segment of transmission and thus is on the hook for it may not be the entity to benefit from an upgrade or new line altogether — therefore eliminating the willingness to invest.
For example, Golden Valley Electric’s Interior ratepayers would undoubtedly see the benefits of more transmission capacity in Anchorage and the Mat-Su area to allow additional lower cost and cleaner natural gas-fired and renewable-sourced power to flow north.
But absent complex agreements to pay for the upgrades, the Southcentral utilities would have to pass along the costs of the transmission work to their ratepayers while most of the benefits would likely be realized elsewhere.
To that end, the utilities have been working with American Transmission Co., a Milwaukee-based transmission-only utility that has been pitching the idea of forming a Railbelt transmission company, or TRANSCO, for nearly two years, which the utilities could become member-owners of.
Ideally, the TRANSCO would be a vehicle for the utilities to collectively finance the major transmission investments; it could also set a flat, Railbelt-wide transmission tariff to encourage more selling of the most economic power amongst the utilities.
Currently, each utility adds its own tariff to power that travels across its lines, challenging the economics of moving power across multiple transmission jurisdictions.
Warren said AEA, as a transmission asset owner itself, has an interest in how the TRANSCO talks shake out and the utilities — each with their own transmission and generation profiles and internal requirements — “are all over the place.”
Elwood Brehmer can be reached at email@example.com.