The Chugach Rate Case—A Wrap Up
Published January 14, 2025
Updated February 4, 2025
By Brian Kassof
In the interest of full disclosure, while editorially independent, AETP receives its funding from the Alaska Public Interest Research Group (AKPIRG)—AKPIRG is an institutional member of REAP, which is discussed in this story.
After 18 months of filings and hearings, the Chugach Electric Association’s (CEA) rate case is near its conclusion. The Regulatory Commission of Alaska (RCA, which regulates public utilities) issued a lengthy order on September 25, 2024, resolving all disputed issues. CEA was instructed to submit a new rate proposal based on the RCA’s findings, which it did on October 24; at the time of publication, the RCA had still not approved these new rates. (On January 30, 2025, the RCA approved CEA’s new permanent rates and refund plan. The new rates went into effect on February 1.)
CEA’s proposed new rates are lower than those submitted in July 2023, and, on average, lower than the interim rates that went into effect in September 2023. However, the new rates’ actual impact will vary considerably depending on customer class and location. In general, South District Residential and Small General (business) members can expect a rate increase, while their North District counterparts can expect a rate reduction. (CEA’s South District encompasses the area served by CEA before its purchase of Anchorage’s Municipal Light & Power (ML&P) in 2020, while the North District is former ML&P territory). The new rates will apply to all members, ending their separation into rate zones (although the BRU surcharge/rebate will continue based on district). The RCA also approved the introduction of a pilot Time of Use (TOU) program and for CEA to provide power to docked ships.
CEA’s rate case was unusually complicated for several reasons. It involved the resolution of numerous outstanding issues connected to CEA’s 2020 acquisition of ML&P (CEA’s last rate case was in 2015). The case also drew considerable interest from other institutions and utilities, who challenged aspects of CEA’s initial filing during the quasi-judicial process used by the RCA to evaluate proposals. A total of 13 different parties (intervenors) took part in the case, far more than in most RCA dockets. The intervenors represented large commercial customers, public and environmental advocates, and other Railbelt utilities. (The Railbelt is the region running north from the Kenai Peninsula to Fairbanks).
Intervenors raised concerns about many aspects of CEA’s rate proposal. One of the most hotly debated was the size of CEA’s margins (revenues above expenses). CEA’s proposed transmission rates were challenged by the other Railbelt utilities. Intervenors also questioned the allocation of costs to different customer classes. One intervenor, the Renewable Energy Alaska Project (REAP), argued that CEA’s rate proposal did not do enough to encourage the conservation of Cook Inlet natural gas. The complexity of the rate case was evident in the RCA Order (Order 12) settling the major issues, which ran for 89 pages and included 19 rulings. (The RCA issues its finding and rulings in “orders” which are numbered sequentially for each case).
The end result is a reduction to the rates CEA proposed in 2023, due in large part to the RCA’s denial of its request to increase its margins. CEA’s new permanent rates will go into effect after RCA approval. They are likely to be adjusted almost immediately, however, as on December 20 CEA submitted a Simplified Rate Filing (SRF) asking the RCA for an 8% increase to the new base rates. (SRFs are a mechanism that allow Alaskan electric cooperatives to adjust their rates on a semi-annual basis to reflect their actual expenses). The RCA also imposed a few other conditions on CEA, including reporting progress on the integration of its generation system with that of Matanuska Electric Association (MEA), and the submission of an equity management plan to the RCA in the fall of 2025.
Rate Impacts:
The overall impact of the new rates will be a 1% decrease from the interim rates in effect since September 2023. However, changes to individual members’ rates will depend on three factors—customer class, district, and usage. In general, South District members will see a rate increase, while North District will see a decrease from the interim rates. Members whose new rates are lower than the interim rates will receive a refund for the difference between the new and interim rates since September 2023. This will appear as a credit on a future bill. The difference in impact is because North District members have been paying higher rates (which CEA inherited from ML&P) than their southern counterparts.
South District Residential members will see their monthly customer charge jump from $8 to $12.79 a month, which will make up most of their rate increase. Their energy charge—the per kilowatt hour (kWh) cost of generating and delivering power—is rising by less than 1% from the interim rates. Because most of the increase is from the monthly charge, the percentage increase will be higher for those who use less power. According to CEA’s rate case bill calculator, a household using 400 kWh a month will see their bill go up by 5.1%, while a household using 600 kWh a month will see a 3.6% increase.
North District Residential members, on the other hand, will see their monthly customer charge decrease from $13.62 to $12.79. Their energy charge will fall by about 11%. As a result, North District Residential members will see about an 8% drop in their total bills—this means that their rates will not only be lower than the interim rates, but also the rates in effect before September 2023.
Small General (business) members in the South District will see a considerable hike in rates, with monthly bills rising about 17% for all usage levels. The impact on members in this class in the North District will vary, depending on usage, with those using less power seeing savings of 3-5%, and those using more a slight increase of 1-2%. The impact on Large General Service (industrial) customers will vary considerably, depending on their location, usage, and class. It will range from increases of up to 19% to decreases of 12%, with most falling between +/-10%.
CEA’s original rate proposal called for some customer classes (Residential and Large General Secondary) to subsidize the rates of others (Small General and Large General Primary). This was done to prevent the latter from suffering from “rate shock” (a proportionally higher increase in rates than other customer classes). CEA’s July 2023 proposal included about $4 million annually in cross-class subsidies. The revised rates do not mention such subsidies, and it is not clear if any remain. If they do, they are likely far smaller. Order 12 only mentions this issue once (on p. 60), noting that a reduction to CEA’s allowed margin reduces the need for such cross-subsidization “substantially.”
New or Removed Rates:
The RCA also approved CEA’s request to create two experimental rates, a pilot TOU program and a rate for shore power, and to drop “demand rachets” from its Large General rates. The TOU program is designed to smooth power demand by incentivizing members to use more power during non-peak periods. It does so by offering a much lower rate for energy during non-business hours (9 p.m. to 9 a.m.) and by charging more for power used between 9 a.m. and 9 p.m.
Spreading demand more evenly allows generation plants to run more efficiently. CEA’s main consultant in the rate case, Dr. Carl Peterson, said spreading demand will be important if more households adopt technologies like electric cars and heat pumps. If the program is successful, CEA plans to expand it in 2030. The pilot program will open enrollment in October 2025, and will be limited to 500 Residential members and 500 Small General members. Although CEA had originally sought to exclude members enrolled in its net-metering program from participation (net-metering is a program that allows members with home solar installations to sell excess power back to their utility), this restriction was removed as part of a stipulation agreement reached between CEA and the intervenors in June 2024.
The other new program is a Shore Power Service. This will allow ships docked in ports in the CEA service area (including Whittier) to connect to the grid, instead of using diesel generators for power. It would also allow CEA to provide energy to recharge electrically-powered ships in the future. Ports or ship-owners will be responsible for building any infrastructure necessary to provide service.
CEA dropped demand rachets from its rate structure. These are minimum purchase requirements for some Large General customers based on past usage. Their discontinuation was due in part to district rate unification (they were in use in the North District, but not the South). Members currently using these rates will have the option to continue, but they will not be available to new businesses.
What is A Rate Case and How Does It Work?
Alaskan utilities subject to the RCA’s economic regulation have a few ways to adjust their rates. These include quarterly Cost-of-Power-Adjustments (COPAs) for fuel and purchased power. Cooperatives can also file semi-annual SRFS to adjust their revenue to match their expenses—these are limited to increases of no more than 8% a year or 20% over three years (SRFs can also reduce rates). CEA’s ability to file SRFs had been suspended until this rate case as part of the ML&P deal. But certain changes can only be made through a rate case, such as changes to monthly customer charges, increases that exceed the SRF limits, changes to profit/margin levels, or how costs are apportioned among customer classes.
Alaskan regulations require utilities to operate under the principle that the cost-causer should be the cost-payer. This means that rate setting requires some reverse engineering. Rate design is done through a three-step process. The first step is determining a utility’s annual expenses. This is done through a ‘revenue requirement study’ that looks at a specific test year—2022 in CEA’s case—and breaks expenses down into detailed categories.
The second step is to classify these expenses and then assign responsibility for them to specific customer classes. This is done through something called a Cost-of-Service Study (COSS), which sorts expenses by function and purpose, then assigns proportional responsibility for them to different customer classes. CEA has seven customer classes—Residential, Small General, three types of Large General, street lighting, and Wholesale.
The final step is rate design, which involves deciding how to break up the allocated costs into different parts of a bill (customer charges, energy charges, and, for some classes, demand charges). Much of this work typically is done by outside consultants.
Once all these elements are prepared, a utility can start a rate case with the RCA. On July 3, 2023, CEA filed its revenue requirement study, COSS, and rate proposal with supporting documentation. A public comment period followed, with the RCA receiving over 80 comments from the public. On August 17, 2023, the RCA suspended CEA’s submission for investigation, kicking off a pseudo-judicial review process of the proposal and invited other interested parties to apply to participate in the proceeding as intervenors. This is standard RCA practice in cases where it wants more information or to allow interested parties an opportunity to raise issues of concern to them.
The 13 intervenors represented other Railbelt utilities (GVEA, MEA, Homer Electric Association (HEA), and Seward Electric System (SES)), several large commercial customers (Enstar, JL Properties, RSD Properties, the University of Alaska, Anchorage, and the federal government on behalf of Joint Base Elmendorf-Richardson), AARP (a non-profit that advocates for people over age 50), and REAP (which advocates for clean energy in Alaska). There was also one individual intervenor, Ethan Schutt, who had concerns about the finances of CEA’s Beluga River Unit (BRU) gas field and the associated power plant (Schutt’s active involvement ended in June 2024, with an agreement that he would intervene in a different RCA docket concerning the BRU). The Regulatory Affairs and Public Advocacy section of the state Attorney General’s office (RAPA), which represents the public interest in RCA proceedings, also was also an intervenor.
What followed were months of testimony and discovery, culminating in a 16-day long judicial-style hearing in June and July 2024, with testimony by expert witnesses representing CEA and some intervenors. The commissioners then considered the arguments and evidence, and on September 25, they issued Order 12. The order addresses 19 specific points. CEA was ordered to redo its revenue requirement study and COSS based on the decisions included in Order 12. CEA submitted its revised rate proposal on October 24. In one filing, MEA suggested that the collective costs of the rate case ran into the millions of dollars.
The RCA has still not approved CEA’s new rate proposal. The delay may be connected to a dispute between CEA and other Railbelt utilities about transmission rates, which was only resolved on January 3 (for details, see below). It is possible that the RCA was waiting to approve the entire tariff proposal at once.
What follows is a discussion of some of the key issues that were debated during the rate case.
Issues of Debate: Rate Unification
When the RCA approved CEA’s purchase of ML&P, it allowed CEA to retain the existing rate structures for its pre-merger members (the South District) and those coming over from ML&P (the North District), with the requirement that they be unified during CEA’s next rate case. Although CEA’s July 2023 proposal included unified rates for most classes, it retained separate rates for the Small General class. CEA argued that full alignment of this group would result in too great of a rate increase for South District members (even with subsidization from other customer classes), and asked to delay full unification of this class until its next rate case.
During the case, two intervenors, AARP and RAPA, argued against unifying rates for residential customers, again because of the burden it would place on South District members. In Order 12, the RCA denied these requests and ordered complete rate unification. The commissioners acknowledged that steep increases for some members would be unfortunate, but said that a failure to unify rates would violate AS 42.05.391(a),which forbids utilities from having rates that favor any customer or group of customers. CEA’s revised rate submission has unified rates South and North district rates for all customer classes.
Issues of Debate: Revenue Requirement and Surplus Revenue (TIER)
Two of the most consequential disagreements in the rate case concerned how much revenue CEA could collect from its members. Intervenors questioned some costs included in CEA’s revenue requirement study. They also challenged CEA’s request that it be allowed a higher margin (the additional revenue cooperative utilities collect above expenses). In both cases, the differences amounted to millions of dollars a year.
CEA’s July 2023 revenue requirement study put its annual non-fuel cost of operation at $264 million. The intervenors said that some of these costs either fell outside the RCA’s allowed categories or were incorrectly calculated. After considerable back and forth, in June 2024 CEA and the intervenors reached a stipulation agreement that reduced CEA’s revenue requirement to $262 million. About half of the difference was due to an extension in the amortization period of CEA’s main debt from the ML&P purchase.
A larger battle was waged over CEA’s request to increase its margins. As a cooperative, CEA does not make profits, but it is allowed to collect and retain revenue above its expenses, to build equity, provide operating capital, and deal with unexpected contingencies—these are its margins. Technically these funds are being loaned to the cooperative by its members (these are the capital credits that are assigned each year). If, after a period of time, the cooperative’s board of directors decides that it has adequate capital, older credits are “retired” and credited to the members who paid them earlier. CEA recently announced it was retiring $4 million in capital credits allocated in 1992.
The RCA assigns cooperatives a target margin that they are not supposed to exceed. Margin targets are based on a ratio of income to interest payments on debt known as a TIER (Times Interest Earned Ratio). Margins are included in rate setting. CEA had previously been operating with a target TIER of 1.55x, but was asking to have that figure raised to 1.75x as part of the rate case. At the 1.55x TIER, CEA’s annual margin would be $21.2 million; raising it to 1.75x would add an additional $7.725 million a year.
CEA argued that it required a higher TIER for a number of reasons. It needs to build its equity level (the relationship of its assets to its debts), which had fallen to 13% in 2020 due to the debt used to fund the ML&P purchase (most Railbelt utilities have a target equity level around 40%). CEA argued that its low equity level (which had risen to 16% by 2023) threatened its credit ratings. CEA also said that higher equity levels could make future borrowing less expensive. So even though it would raise rates in the short term, it argued that a higher TIER would save members money in the long run, making it, in the words of one CEA lawyer, “a cost saving rate increase.” CEA also provided other arguments for a higher TIER, such as comparisons to other utilities and claims that larger cash reserves were needed for potential new renewable generation projects or to deal with cyberattacks.
The intervenors almost universally opposed raising CEA’s TIER to 1.75x. They argued CEA’s credit rating was already good and that it had shown it could build equity at the lower TIER, albeit at a slower pace. They also noted that CEA has not been achieving its target TIER since it was raised to 1.55x in 2020—the actual figure has been about 1.2x (which CEA attributes to declining sales and its inability to file SRFs to deal with inflation). Intervenors pointed out that in 2019 CEA had claimed that the savings achieved by merging operations with ML&P would allow it to operate comfortably with a 1.35x TIER, and that the RCA had insisted on setting it at 1.55x.
The intervenors also stressed that, beyond the need to build equity faster, CEA could not articulate what it would do with the additional $7 million it would be collecting from members annually. In his opening statement, Robin Brena, an Anchorage-based attorney representing RSD Properties, said that CEA’s request for higher margins without a clear explanation amounted to “a money grab from their ratepayers.”
The RCA sided with the intervenors on the issue of the TIER. In Order 12 the commissioners stated that the evidence “supports a finding that Chugach will be able to maintain its financial integrity and creditworthiness at a 1.55x TIER.” They agreed with the intervenors that CEA had not provided sufficient evidence to justify the additional burden a higher TIER would impose on its members.
There was also a second debate around CEA’s TIER in the rate case. CEA had a so-called “split TIER”—1.35x for its transmission and wholesale customers (the other Railbelt utilities and SES, respectively) and 1.55x for its retail customers (members). This system was instituted in the 1980s, when CEA provided wholesale power to other cooperatives such as HEA and MEA. SES is its only remaining wholesale customer-- their contract expired at the end of 2024, but they are negotiating a new one. The split TIER was also connected to long-expired debt covenants.
CEA requested that the split TIER be ended, arguing that the reasons for its creation no longer applied. Not surprisingly, the other Railbelt utilities were vigorously opposed to paying higher margins. The RCA ruled in CEA’s favor and eliminated the split TIER, putting everyone at 1.55x. CEA was allowed to retain a special TIER for its BRU gas field, due to its unique nature.
Issues of Debate: Conservation
One intervenor, REAP, said that CEA’s rate proposal did not do enough to encourage the conservation of resources. REAP argued that, given the dire warnings about impending shortages of Cook Inlet natural gas, this should play a more prominent role in setting rates. CEA currently relies on natural gas for 80% of its power generation. Although concern about this issue is generally shared—in December 2024, RAPA petitioned the RCA to adopt rules on utility curtailment of service if gas supplies run short—it was barely mentioned in CEA’s rate filing. CEA did claim that the TOU pilot program would help conserve gas, but given the program’s small size (less than 1% of CEA members, and an even smaller percentage of overall use), its impact will be minimal.
REAP, with support from the environmental legal non-profit Earthjustice, argued that CEA’s rate design focused too much on historical costs without considering future factors, such as the higher price of imported liquified natural gas. REAP said that CEA’s rate plan did not conform to AS 42.05.141(c), which reads “In the establishment of electric service rates under this chapter the commission [the RCA] shall promote the conservation of resources used in the generation of electric energy.”
REAP proposed its own rate structure, which used a tiered-pricing structure known as inclining block rates. Under REAP’s plan, a household would have been charged a lower rate for the first 450 kWh used a month, and a higher rate for additional kWh (average residential use at CEA is in the 550-600 kWh range). REAP believed this would encourage lower power consumption, as well as creating additional incentives for households to install renewable generation equipment like solar panels, both of which would conserve local gas supplies.
REAP’s proposal was criticized by CEA and some other intervenors, who said it called for a radical change in rate design without evidence that it could achieve its goals. In its closing statement, CEA pointed out that REAP’s witnesses were unable to quantify how much natural gas their proposal would save. The commissioners acknowledged REAP’s arguments about conservation in Order 12, but did not engage with them.
Issues of Debate: How to Assign Costs to Different Customer Classes
There was considerable debate during the rate case over how CEA had classified and allocated costs among different customer classes in its COSS. Particular attention was given to whether specific costs were connected directly to the production of energy (energy-related) or to building and maintaining the infrastructure needed to meet peak demand (demand-related). These discussions were often technical, but they had a significant impact on how much revenue would be expected from each customer class (and therefore their rates).
In the end, the RCA only required a few changes to the COSS. The most significant of these concerned the Coincident Peak Allocator (CP) that CEA’s consultant had used to allocate costs to different customer classes. A CP looks at each class’s contribution to a utility’s peak load. CEA had used a CP 1 for its COSS—this looks at the single period of peak usage during the year. In the past, CEA had used a 3 CP, which uses an average of each class’s share of the peak load during three different months. AARP and REAP argued that the use of a CP 1 unfairly shifted costs to residential customers, and asked that a CP 3 or CP 12 (which looks at an average of peak load from every month) be used for allocating costs. The RCA required CEA to redo the COSS using a CP 3, saying it had not provided evidence to justify altering its previous methodology.
Issues of Debate: Transmission Rates
A final major topic of dispute was the transmission rates that CEA charges other utilities to move power across its system. These include eight different rates for the transfer of power (“wheeling fees”) and ancillary support services (such as voltage control) needed to transmit power over long distances. CEA had proposed to raise most of these rates, including a 17% increase for wheeling fees.
The other three Railbelt cooperatives—MEA, HEA, and GVEA—challenged these increases, arguing that CEA had included non-relevant expenses when it calculated the costs of providing transmission service. (Transmission revenues are determined based on a separate revenue requirement study, which breaks out transmission-related expenses. Alaskan cooperatives use revenues from sales of transmission services to offset their COPAs).
They wanted two sets of costs excluded. One was expenses associated with radial transmission lines to the Beluga Power plant and Cooper Lake hydroelectric project. The other utilities argued that since wheeled power was not sent over these lines, their cost should not be included. CEA said that these lines bolstered system reliability, and that the RCA had allowed it to include them in calculations of transmission costs in a previous case.
The other utilities also argued against including expenses associated with CEA’s acquisition of ML&P. CEA argued that the addition of ML&P’s transmission lines strengthened its system overall and thus benefitted transmission customers. The other utilities claimed that CEA was able to provide reliable transmission services before the acquisition, and that the purchase had been made to benefit CEA’s members, not other utilities.
The RCA ruled that CEA could include the costs of the radial lines in its transmission tariffs, but not those associated with the purchase of ML&P. The ML&P costs were far more significant, and their exclusion changed CEA’s wheeling rates considerably. Its proposed tariff called for a 17% increase in wheeling fees, but when those costs were excluded, the new wheeling fees are slightly lower than they were before the rate case (although increases for some ancillary services remained).
The transmission rates continued to be an issue after Order 12. After an unsuccessful appeal of this part of Order 12, CEA submitted a new rate schedule as part of its updated tariff. But on November 7, 2024 GVEA filed a complaint with the RCA, saying that CEA had violated Order 12 by including elements of ML&P-related costs in a number of transmission rates. HEA, MEA, and RAPA all supported GVEA’s position. CEA replied on November 18, arguing it had followed Order 12 and that GVEA was in error.
On January 2, the RCA issued an order supporting GVEA’s position and ordering CEA to make the necessary corrections. It termed CEA’s November 18 filing to be “wasteful and duplicative,” saying that it had an opportunity to make these arguments during the rate case. CEA filed corrected transmission tariffs the following day.
It is possible that the continuing dispute over transmission rates has played a role in the RCA’s delay in approving the rest of CEA’s tariff. CEA acknowledged a possible connection between the two in its November 18 filing, where it explicitly asked the RCA not to delay the approval of the rest of tariff until the dispute over the transmission rates was settled, pointing out that the resolution of the transmission tariff has no bearing on its other rates.
Other Required Filings:
Order 12 also required additional actions by CEA. It was asked to provide an update on progress toward creating a single load balancing area with MEA—this is a project that predates the ML&P acquisition, and its completion by April 2022 was a condition of the sale. CEA has been providing periodic updates to the RCA on this project, although these reports are not coordinated with MEA. It estimates the single load balancing area could be created by May 2025, with the caveat that “misalignment” between MEA and CEA could slow the process.
In Order 12 the commissioners also expressed concern about CEA’s equity situation. This issue had been raised by MEA in its closing statement (which cited similar concerns by a witness for SES). MEA’s lawyer wrote that “It appears that Chugach may be in need of regulatory assistance to navigate its present financial difficulties.” MEA also expressed dissatisfaction that CEA had not presented senior executives as witnesses during the rate case hearings, something that it had done in 2015 (SES and HEA also noted the absence of testimony from senior management during the hearing).
The commissioners expressed similar concerns about CEA’s reliance on debt and lack of working capital in Order 12. They said they were worried that these could make it difficult for CEA to take advantage of federal or state grants that required matching funds. They also wondered why CEA is retiring capital credits when faced with limited liquidity. CEA is required to file an equity management plan with the RCA by September 26, 2025, so the RCA can determine if CEA is “engaging in prudent investment practices.”
Acronyms and terms used in story:
AARP—(formerly the American Association of Retired People)—non-profit organization advocating for people over the age of 50)
BRU—Beluga River Unit. Gas field owned jointly by CEA and Hilcorp.
CEA—Chugach Electric Association
COPA—Cost of Power Adjustment. A mechanism utilities can use to adjust their rates to reflect rising or falling fuel or purchased power prices.
Margins—”profits” earned by cooperative utility—technically equity lent to the cooperative by its members as part of their rates. Cooperative members are issued “capital credits” in the amount they pay in margins.
MEA—Matanuska Electric Association. Cooperative utility serving the Matanuska-Susitna Valley.
ML&P—Municipal Light and Power. City-owned utility that provided electricity to northern areas of Anchorage. Purchased by CEA in 2020.
North District—part of CEA service area previously served by ML&P.
RAPA—The Regulatory Affairs and Public Advocacy section of the state Attorney General’s Office. Represents the public interest in RCA proceedings.
RCA—The Regulatory Commission of Alaska. A five member body that oversees Alaskan utilities.
REAP—The Renewable Energy Alaska Project. A non-profit that advocates for clean energy in Alaska.
South District—part of CEA service area that was served by the cooperative before the ML&P merger.
SRF—Simplified Rate Filing. A tool available to Alaskan electric cooperatives that can be used semi-annually to adjust their rates upward or downward to reflect changes in their actual expenses and sales.
TIER—Times Interest Earned Ratio. A formula expressing the ratio between a business’ income and interest payments on debt. Cooperative margins are based on their TIER.
TOU—Time of Use. A billing method used by some utilities that charges customers different rates depending on the time of day (or, in some cases, overall demand). Used to incentivize consumers to move power consumption to off-peak hours, reducing the strain on electric systems.
