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Minnesota Stays the Course on Monthly Customer Charges

An electric utility, Minnesota Power Company, has been thwarted in its quest to increase its rates by $55 million after the Minnesota Public Utilities Commission entered an order allowing the company’s rates to rise by only around $12.6 million.

A key factor in the commission’s decision was its rejection of the utility’s proposal to raise the fee that customers pay each month to cover the utility’s fixed costs of service. Minnesota Power had recommended that the residential customer charge go up by 12.5%, from $8.00 per month to $9.00 a month. The commission, however, found that the customer charge should be maintained at its current level. Another critical element in the commission’s decision was adoption of a rate of return on common equity (ROE) for the company that was significantly lower than what the utility had suggested. Whereas Minnesota Power had relied on a 10.15% ROE in developing its revenue requirement, the commission authorized an ROE of just 9.25%.

When the utility initially submitted its rate application, it identified the loss of a large industrial customer as contributing to steadily declining electricity sales. According to Minnesota Power, the decrease in industrial usage also indicated a need to reallocate revenue responsibility among its various customer classes. Thus, while the company sought an overall rate increase of approximately 9%, it proposed a rate redesign under which residential customer rates actually would rise by about double that. The utility averred that such an increase for residential customers was necessary to bring that class closer to the systemwide rate of return.
After the company filed its rate case, however, the industrial customer (a mining facility) announced its intent to resume operations within the utility’s territory. And, in fact, the customer did once again start taking service from Minnesota Power before the proceeding was resolved. The sales made to that customer alone helped to mitigate the revenue deficiency that the company had been experiencing.

The commission determined that besides getting some revenue breathing room by virtue of the income from the resurrected mining customer, the record showed that some of the cost claims that formed the basis of the utility’s rate request were overstated. The commission drew particular attention to a couple of those expense categories, including storm response plans and extended depreciation schedules for a coalfired power plant.

The storm response costs related to a major weather event that hit the northern part of the state in July of 2016, leaving close to 50,000 Minnesota Power customers in the dark. The company first asked the commission for deferral treatment for the service restoration costs it incurred thereto. When the commission denied that request, the utility added the $1.68 million in such costs to its rate filing, but it did so after the proceeding had begun, at the rebuttal stage. In eliminating the storm response line item from the utility’s base rates, the commission reiterated its explanation for rejection of the deferred accounting proposal, which was that the storm was highly unusual such that a recurrence was unlikely and that the costs were actually not so great as to jeopardize the company’s financial integrity. The commission elaborated that the costs of the onetime- only storm did not provide a reliable basis for establishing a special storm response budget.

Moreover, the commission admonished Minnesota Power for its untimely addition of the storm costs to its rate application. The commission told the utility that by trying to add in the costs at the rebuttal stage, other parties and intervenors were afforded inadequate time to evaluate and respond to the utility’s proposal. As to coal plant depreciation costs, Minnesota Power had recommended that depreciation on the four units at its Boswell Energy Center, which schedules presently go from 2024 to 2035, be extended to 2050. Although the utility attested that its plan was nothing more than a mere accounting strategy, in that the company does not expect to operate the plants beyond 2035 at the latest anyway, the utility asserted that the longer depreciation timeline also could be viewed as a rate increase mitigation measure.

Other parties were not convinced, however. They questioned whether the utility’s proposal was really just a way of extending the useful life of the facilities. The commission ultimately provided a split decision, holding that Units 1 and 2 should adhere to a 2022 depreciation termination date inasmuch as the utility is under orders to retire those two plants by that date. But the commission concurred with the company that it would be reasonable, for purposes of rate moderation, to extend the depreciation deadline for Units 3 and 4 to 2050. While Minnesota Power was not totally successful in its efforts to recognize extraordinary storm response costs and extended coal plant depreciation expense in rates, the commission did agree to a couple of new and novel expenses not previously reflected in rates. Among those were (1) employee bonuses paid by way of gift cards, and (2) credit card processing fees.

In seeking to recover through rates costs associated with performance- based incentive compensation paid to exemplary employees, the utility commented that some of those “spot” bonuses are provided not directly through payroll, but through the distribution of gift cards instead. Some parties objected to that practice though, alleging that the cards represented “gifts” rather than pay and thus should be treated differently. From the commission’s perspective, however, there were no grounds for distinguishing between gift cards and bonuses reflected in pay checks.

The commission expounded that both served a useful and lawful purpose in helping the company to attract and maintain qualified key personnel since the utility’s pay scales are otherwise below-market. The commission added that even if it had elected to treat the cards as gifts rather than payroll bonuses, the outcome would have been the same. That is, it said, the expenses of either or both would have been recoverable from ratepayers. With regard to credit card processing fees, the commission noted that Minnesota Power currently permits customers to pay bills using a credit or debit card. However, such payments are administered by a thirdparty vendor and thus are assessed a separate transaction fee of $2.95 for each payment.

Going forward, however, the utility has proposed to cease imposing the separate transaction fee on each customer payment and absorb the fees itself, treating them as an ordinary operations and maintenance expense. A number of parties challenged the plan, contending that those customers who do not use credit or debit cards to pay their bills will be unfairly subsidizing those that do use such cards.

In deciding to recognize the credit card processing fees as an ordinary cost of business for rate-making purposes, the commission acknowledged that there could be subsidies flowing from check-writing customers to credit card-using customers. At the same time, though, the commission found that elimination of the separate transaction fee may encourage more customers to begin using a credit or debit card for payments.

And importantly, the commission pointed out that the issue is a twoway street. The commission stated that it could just as easily be found that those paying by credit card in the past were helping to underwrite other customers via the transaction fees that produced another avenue of revenue for the company. While the above-mentioned costs of service were the topic of vigorous discussion, they were not subject to as much debate as either the company’s cost of capital or its rate design proposals, the latter of which pertained primarily to the higher customer charges planned by the company.

As to an appropriate rate of return for Minnesota Power, the utility advocated for a 10.15% ROE, arguing that it should be afforded a risk adder in that a significant number of its industrial customers operate on a “highly cyclical” basis, leading to a quite uneven stream of revenue. The company also averred that its proffered ROE was in keeping with the ROEs authorized other electric utilities comprising its proxy group.

Opponents, however, deemed that ROE to be excessive, and they accused the company of being too selective in choosing what entities to include in the proxy group. The challengers faulted Minnesota Power for relying on just six companies, all of which had “greater relative investment risk” than the norm among electric utilities. The state’s Department of Commerce, for instance, used a proxy group comprised of almost three times as many companies as the utility’s. The department ended up recommending an ROE of 8.70%.

Upon examining the various party positions and ROE cost models, the commission ruled that a 9.25% ROE would be appropriate. It conceded that the issue of ROE always comes down to a “fact-intensive and recordspecific judgment.” In Minnesota Power’s case, the commission determined that once the highest and lowest ROE proposals were removed from consideration, the other ROE values were actually fairly close to one another. The commission concluded that a 9.25% ROE was sufficiently justified by the analytics provided.

Finally, as to the matter of customer charges, the commission found that the record simply did not support the company’s proposal to raise the residential charge from $8.00 to $9.00 a month. Minnesota Power had filed a cost-of-service (COS) study which purportedly showed that its actual fixed costs to serve the residential class come to $26.35 per customer per month. Thus, it claimed, its planned one-dollar increase was in reality quite modest and nowhere near as high as what it should charge. But the COS results presented by the utility were roundly criticized by other parties. A major flaw seen in the study was that it relied on embedded costs rather than marginal costs, leading to a skewed calculation of actual fixed costs. Others challenged the higher customer charge as detrimental to low-income customers and as a disincentive to energy conservation.

In finding that the utility’s residential customer charge should remain at its current level, the commission agreed that the company’s COS study was deficient in a number of ways. The commission likewise determined that higher customer charges would be unfair to both lowincome and low-usage customers. That is, the commission explained, a higher monthly charge affects lower-consumption ratepayers disproportionately because continued reductions in usage do not translate into lower bills. And lower-income customers and those on fixed incomes obviously are impacted when, regardless of how they try to conserve, a larger percentage of their income must go toward their energy bills. Consequently, the commission refused to authorize any change in the utility’s monthly residential customer charge.

The commission noted that its final decision permitting $12.6 million in additional revenues will not show up on customer bills right away. Indeed, it said, customers will initially see a slight decrease in their bills, because the $16 million increase the company was allowed on an interim basis exceeded the final amount approved, thus requiring refunds or rate credits for the first months the new rates are in effect. Re Minnesota Power, Docket No. E-015/GR-16-664, Mar. 12, 2018 (Minn.P.U.C.).