Wyoming Public Service Commissioners have their work cut out for them choosing from among three scenarios that have been laid out in meticulous detail regarding proposed Rocky Mountain Power rate increases that could come to nearly 30%.
Rocky Mountain Power, Wyoming Industrial Energy Consumers and the Wyoming Office of Consumer Advocate have all used Rocky Mountain Power’s computer modeling to crunch their own recommendations for the commission, producing almost 400 exhibits presented through the testimony of 29 witnesses over a seven-day period.
The parties, meanwhile, are not at all close with their recommendations.
Wyoming Industrial Consumers is recommending a $14.9 million rate increase, while Wyoming Office of Consumer Advocates is recommending a $60 million increase.
That’s compared to Rocky Mountain Power’s ask of $137.2 million more from Wyoming ratepayers.
WIEC and WOCA employed experienced energy consultants who used RMP’s own software, called Aurora, to model and number crunch their recommendations.
Because of the lengthy testimony involved, all of the parties have been asked to prepare briefs of their arguments, including any updates or changed opinions that have developed through the rate-making process by Nov. 20, after which the commission plans to begin its own decision-making process Nov. 28.
As Rocky Mountain Power Sees It
For its part, Rocky Mountain Power has acknowledged the pain of raising power rates 30%, but says Wyoming had been overdue for a rate adjustment and that, even with the increase, its rates will remain among the lowest in Wyoming and the region for investor-owned utilities.
“Given the rising cost environment, it is very likely that these other utilities will also increase their rates as soon as 2024, which will result in the company’s rates comparing even more favorably to the rates charged by other utilities in the state,” Rocky Mountain Power President and CEO Gary Hoogeveen testified.
While the renewable power generation that the company has invested in has been widely blamed for the company’s rising costs, Hoogeveen said without the renewables the company has procured, as well as its participation in the Energy Imbalance Market, Wyoming’s increased costs would have been $238 million instead of $137.2 million.
Instead of renewables, 95% of the rate increase is due to volatile fuel prices for coal and natural gas during 2022-2023, Hoogeveen said.
“Actual net power costs have increased over half a billion dollars, total company, since the last rate case (in 2020),” he said.
In addition, rising interest rates have added to the company’s cost of debt. That has led the company to recommend a return on equity of 10%, which is what it says it needs to attract capital. Otherwise, shareholders will have more attractive options for their money.
Hoogeveen also is recommending that the Wyoming Public Service Commission eliminate the 80-20 sharing band. The idea behind the sharing band is to incentivize the company to produce accurate forecasts. Earnings that far exceed the company’s forecast, for example, can result in revenue sharing with consumers, and expenses far above forecast can mean some costs the company cannot recoup.
Rocky Mountain Power has been pushing to eliminate sharing bands for a while now, and it’s something that the PSC has so far rejected.
Hoogeveen said that the company cannot influence prices in the energy market. It’s a price taker, not a price maker. Thus, instead of incentivizing the company, the sharing band ensures the company cannot recoup a significant portion of its prudently incurred costs.
If power costs did drop in the future, Hoogeveen added, the company wouldn’t be able to pass on 100% of the savings to customers because of the sharing band.
Through WIEC’s Eyes
Wyoming Industrial Energy Consumers, which represents the largest energy consumers in the state, takes the hardest line on Rocky Mountain Power’s rate case.
While RMP and WIEC have managed to agree on several points since the beginning of the rate case, there are still four outstanding areas that add up to a wide chasm — a $122.3 million difference between what WIEC recommends and what Rocky Mountain Power is asking for.
The first bone of contention that WIEC has with Rocky Mountain Power’s rate case is the Washington Climate Commitment Act, which established a cap-and-invest program for greenhouse gas emissions starting in January of this year.
That’s costing the company $63.4 million, $9.1 million of which is Wyoming’s share, WIEC’s expert Brad Mullins testified.
That cost is unfair to Wyomingites, Mullins said, because Washington has “effectively excepted its own state electric consumers from the application of the CCA by providing no-cost CCA allowances for in-state loads.”
Mullins disagrees with Rocky Mountain Power’s contention that the CCA is comparable to Wyoming’s wind tax.
“The CCA is not a tax,” Mullins testified. “It’s a policy, and the longstanding principle of cost allocation and the multistate process is that states are responsible for the policy costs that they impose on the system.”
Oregon, Mullins added, has already disallowed Washington’s CCA costs in Oregon rates.
Sen. Cale Case, R-Lander, meanwhile, has pointed out that Wyomingites are not exempted from Wyoming’s wind tax.
“Everybody pays it,” Case told Cowboy State Daily.
WOCA, for its part, agrees with WIEC that the CCA is unfair to Wyomingites and suggested it may even violate multistate protocols, which dictate that the cost of state-specific initiatives be levied only on that state’s residents.
“Clearly, the intention of Washington’s CCA is to dramatically tip the scales against the use of dispatchable or reliable thermal generation in favor of renewables generation, as well as an increased reliance on volatile Western power markets,” WOCA Administrator Anthony Ornelas testified. “This policy arbitrarily and needlessly increases the dispatch price of an important legacy thermal plant that Wyoming ratepayers have both paid for through their rates and relied upon for decades in order to meet its electrical demand.”
Throwing DARTS In The Dark
Both WIEC and WOCA have questioned the company’s day ahead-real time adjustment, which is a correction applied to the company’s model because the Aurora software tends to miscalculate how often Rocky Mountain Power will be able to take advantage of favorable pricing on the market.
Rocky Mountain Power, like other utilities, finds itself buying more when demand — and thus prices — are high and selling more when energy demand and prices are low. The company’s monthly market prices are calculated as an average, leaving the model far apart from reality.
To rein the model in, the company has created the day ahead-real time adjustment, or DART.
The company recently changed its methodology for calculating the DART adjustment in ways that both WIEC and WOCA said Rocky Mountain Power has failed to justify.
Mullins has recommended the change be rejected, which, in his calculation results in a $61.9 million reduction in overall rates, which works out to a reduction of $8.9 million for Wyoming.
He suggests tying the values to historical data, which would drop another $12.3 million total company, or $1.8 million from Wyoming rates.
WOCA questions including a DART adjustment at all, however, given the company’s plans to join the Extended Day Ahead Market.
The company has not accounted for how that would affect rates and the move “could certainly happen while the company’s proposed net power cost is still in effect,” Ornelas testified.
Market Caps Improperly Applied?
WIEC contends that Rocky Mountain Power has improperly applied market caps to the Columbia and Palo Verde markets, which it says are not illiquid.
“Contrary to RMPs assertion, the major power market hubs in the West continue to be liquid,” Mullins said. “I recommend that the established Commission-approved method, which excludes market caps from liquid market hubs be applied in this docket.”
That further reduces net power costs by $51.4 million total company, or $7.4 million in Wyoming.
WOCA, meanwhile, has recommended reduced delivery costs for several RMP generators based on an analysis by one of their experts, Colin Fitzhenry.
While Rocky Mountain Power has testified that Fitzhenry has incorrectly used Henry Hub prices in that analysis, Fitzhenry said he did take into consideration adjustments based on the company’s own work papers.
“I did not directly apply Henry Hub prices to Rocky Mountain Power’s natural gas generators as the company has suggested,” he said, adding that Henry Hub prices are a good mechanism for forecasting future natural gas prices because of the large trading volume, clear pricing transparency and high liquidity.
“Henry Hub prices are widely quoted by futures exchanges and other media sources.”
WIEC has also contended that some of Rocky Mountain Power’s rate increase is the result of a huge modeling error that overestimates the contingency reserves required by FERC.
This has the tendency of placing undue responsibility on Wyoming ratepayers for non-native or third-party services that Rocky Mountain Power provides.
Mullins recommends sticking to FERC-approved costs for third-party reserves in the net power costs. Doing that drops net-power costs by $47 million total company, or $6.8 million for Wyoming.
Rocky Mountain Power has disagreed that it’s holding more reserves than required, and testified that the recommendation isn’t something it can legally act on.
WOCA, meanwhile, has suggested that Rocky Mountain Power’s modeling of some thermal generation units is lowballing summer operating capacity.
Company witness Ramon Mitchell stated the dependable capacity at Current Creek Power plant is 550 megawatts, but the company has only modeled its summer operating capacity at 500 megawatts, Fitzhenry testified.
Wyodak, a different unit of Rocky Mountain Power’s, was modeled at 265 megawatts, when the company’s summer 2022 operating capacity for it was actually 268 megawatts.
“I continue to recommend the company update its Aurora modeling to reflect recent summer operating capacities of its thermal generating units,” Fitzhenry said.
WOCA’s experts are also crying foul on coal prices at two of Rocky Mountain Powers coal-fired plants because Rocky Mountain Power entered into new coal supply agreements with the same suppliers that made force majeure claims on their prior coal service agreements.
A force majeure is a claim that the company cannot deliver on a promised service or good because of unforeseen circumstances. If the companies, however, could just enter into new coal supply agreements, that raises questions about those force majeure claims, Fitzhenry suggested.
“I’m recommending that Rocky Mountain Power of Wyoming customers be insulated from any further impacts of force majeure claims with suppliers that PacificCorp has re-entered into contracts with,” Fitzhenry said.
Sharing Band Must Stay
Both WOCA and WIEC agree that the company’s 80-20 sharing band must stay, though WIEC would change it to 70-30. They were joined by the Sierra Club in the opinion that a sharing band of at least 80-20 is necessary.
Rocky Mountain Power has suggested the Extended Day Ahead Market will make the sharing band obsolete, and it objects to the sharing band on the principle that the company cannot actually influence market prices.
“Rocky Mountain Power is still responsible for several important functions that impact the ECAM (Energy Cost Adjustment Mechanism) such as fuel procurement, resource selection, generation maintenance, and scheduling generation maintenance,” Fitzhenry said. “Maintaining the 80-20 sharing band provides an important incentive for the company to continue to properly manage its costs with respect to the functions that continue to be under its control.”
The prudency review the company is subject to isn’t stringent enough to ensure RMP is doing all it can to control the costs related to those functions, Fitzhenry added.
WIEC and WOCA are also both for a switch to flow-through accounting for state income taxes.
WOCA’s expert Greg Meyer testified that flow-through accounting would produce near-term tax savings, instead of deferring accumulated income taxes.
Rocky Mountain Power contended that would lead to increased base rates over time, but Meyer pushed back on that.
“No, I don’t agree with that assertion,” Meyer said. “And the reason is that RMP like many utilities is in a heavy investment era. And, so to the extent that you continue to invest heavily in your infrastructure, you’re going to continue to get accelerated appreciation offsets applied to those new investments in the early years of those assets.”
This is the fifth and final story in a series unpacking the major issues raised in a seven-day marathon rate increase hearing for Rocky Mountain Power. Other stories:
Renée Jean can be reached at Renee@CowboyStateDaily.com.