MEA says economics of single transmission co. overstated
Matanuska Electric Association is questioning the benefits of transferring regional transmission infrastructure to a single utility.
In a Dec. 29 letter to the Regulatory Commission of Alaska chair T.W. Patch, MEA General Manager Joe Griffith cited eight reasons why the Southcentral electric utility believes forming a Railbelt electric transmission company could be unnecessary and possibly add costs to participating utility ratepayers.
Among the issues raised by MEA is the utility’s belief that a $903 million estimate for needed performance and reliability upgrades to the Railbelt electric system is a “grossly inflated number,” the letter states. The hefty sum is based on reliability standards that don’t return a justifiable value, according to Griffith.
He said in an interview that all the Railbelt utilities — there are six — could reap significant benefits from as little as $50 million invested strategically.
“The ($903 million) study was done properly for the boundaries and conditions they studied it under,” Griffith said. “It isn’t a bogus study; it’s probably right, but the first question you have to ask is, ‘Do we need it?’”
The Alaska Energy Authority commissioned the 2013 study that came to the $903 million conclusion. It was based on a single-loss contingency standard, known in the industry as N-1, meaning the entire Railbelt electric transmission system, from Fairbanks to Homer, would be able to absorb the loss of a single transmission line or substation without consequence.
The authority is currently updating that study to include double contingency and status quo costs; that study is expected in March.
MEA uses an N-1 standard in its system, Griffith said, and his letter noted that while system-wide planning for a single contingency is prudent, the utilities have consistently determined the cost of reliability improvements is not justified.
The 173-mile, state-owned transmission intertie is a single line between Willow and Healy, and a lone connection ties Anchorage to the Kenai Peninsula.
Adding redundancy to the interties would allow for the cheapest power to flow freely and continuously, but because each utility has its own generating capacity, improved reliability is not imperative.
The utilities are working to finalize a set of system-wide reliability standards that will go a long way towards determining what level of contingency planning will be used where, according to MEA representatives.
Griffith concurred with other experts in the field when he said loosening access to Bradley Lake, the 120-megawatt state-owned hydro project near Homer, is the Railbelt’s most pressing need.
A lone upgrade of the single-line intertie between Anchorage and the Kenai Peninsula from the decades-old 115-kilovolt line to a 230-kilovolt line would de-constrain Bradley Lake and add needed capacity to the transmission system, not unnecessary reliability, he said. Griffith ballparked a southern intertie upgrade cost at about $50 million.
AEA has estimated that full investment to add capacity and reliability to the system could save Railbelt ratepayers between $80 million and $240 million per year simply by accessing the lowest cost power through economic dispatch. MEA contends those cost savings are unsubstantiated.
The RCA demanded the Railbelt utilities move to establish a united electric system last June. In a letter to legislative leadership, the commission stated it would seek the authority to mandate the utilities to take action if they failed to heed the warning on their own.
In December 2014, American Transmission Co., or ATC, a Milwaukee-area transmission-only utility, inquired about the possibility of developing a Railbelt transmission company to spur investment in the system. The utilities ultimately signed a memorandum of understanding with ATC to investigate the feasibility of a Railbelt transmission company, or TRANSCO.
A TRANSCO would centralize management of the transmission system and allow participating utilities to invest in, and thus benefit from, projects across the system, not just those in their service area. ATC has experience with the TRANSCO model and would provide access to capital through its Lower 48 investors.
The utilities expect to apply for a license to form a TRANSCO in the third quarter of this year, according to a Dec. 22 update report to the RCA.
Griffith also noted that adding another utility with its own workforce and rate of return to the Railbelt could actually increase costs to ratepayers.
The progress report to the RCA estimates the net cost of a TRANSCO would be about $7 million per year once it is fully up and running. Beyond operational costs, a for-profit TRANSCO would also require a rate of return — another cost to ratepayers, Griffith said.
ATC spokesman Eric Lundberg said the company currently earns a 12.2 percent return on its Midwest business, but added that the Federal Energy Regulatory Commission regulates any return in the Lower 48. Similarly, the RCA would set profit parameters for an Alaska Railbelt TRANSCO, Lundberg noted.
ATC operates like most utilities in that it seeks long-term business, understanding its return will ebb and flow with market conditions and regulations, he said.
“We don’t look to flip investments; we look to be there,” Lundberg said.
The “weak link” of a TRANSCO is the inherent incentive to invest in infrastructure because each investment makes a return, Griffith said.
A major selling point of a TRANSCO has been the prospect of a single transmission tariff across the Railbelt — the elimination of “rate pancaking” for power producers needing to cross multiple utility service areas to get power to a buyer.
Independent power producers have argued the stacked transmission tariffs are an economic barrier to developing low-cost renewable energy in the state’s most populated region.
Griffith said a postage stamp tariff would simplify the cost, but is not likely to lower it for everyone because each utility has a different tariff rate. The transmission tariffs are set by the RCA to allow the utilities to service debt on their transmission infrastructure.
“You’ve got to recognize the legacy investment each utility has made. If you don’t do that it’s a dead-bang loser,” he said.
Turning over transmission infrastructure to a TRANSCO through a lease or direct change of ownership also provides a disincentive for local reliability investments, according to Griffith’s letter to the RCA.
“MEA members could be faced with bearing the burden of both the total cost of their own future transmission improvements while subsidizing the system-wide legacy assets largely serving the retail loads of others,” the letter states.
System operator benefits
MEA’s concerns about forming a TRANSCO do not mean the utility is averse to changing the structure of the Railbelt electric network.
Organizing an independent, or unified, system operator, often referred to as an ISO or USO, along with transmission capacity upgrades, would reap the greatest benefits of economic dispatch without adding unnecessary costs, according to MEA representatives.
“(A system operator) is where all the money is because that lets you maximize the efficiency of the (generating) machines as well as the gas contracts and that’s got to be folded into all this because that’s millions and millions of dollars annually,” Griffith said.
Southcentral utilities relying on Cook Inlet natural gas as their generating fuel source sign contracts with producers that have a tiered pricing structure — typically base load, swing load and peak load.
When demand peaks a utility can pay a 50 percent to 65 percent premium for natural gas. In theory, a system operator acting as a central power dispatcher would work to distribute as much base load power as possible, regardless of which utility owns the generation.
MEA spokeswoman Julie Estey said the new, more efficient power plants coming online in the Railbelt — Municipal Light and Power and Chugach Electric Association’s joint Southcentral Power Plant and MEA’s Eklutna Generating Station — have already started this coordination between the utilities in an informal “loose pool.”
For example, the 10 small generators that power the 171-megawatt Eklutna Generating Station can be powered up and down to meet fluctuating demand more efficiently than some of the larger gas turbine generators at other power plants in the region, Griffith said, so the utilities purchase power amongst themselves without a structured agreement.
MEA’s vision of a system operator would have each participant represented on a board of directors, with board seats for independent power representatives as well.
Alaska’s independent power producers often contend that the utilities control the Railbelt system and have pushed for a system operator to make dispatch decisions separate from the utilities.
Estey, of MEA, said other issues the independent power producers raise with the utilities, such as who pays for interconnection fees to independent power sources, would likely be solved with a system operator.
“It seems to me there has been more unified support (from the utilities) around a system operator, but ATC has been doing such a good job of driving the utilities around the TRANSCO model that that seems to be making more progress and has more legs, but that’s because more resources have been put into it,” Estey said.
Elwood Brehmer can be reached at email@example.com.