Cost-of-Service Rate Case with Declining Sales and a Bypass Threat
An electric utility files a general rate case requesting a $48 million revenue increase. Billing determinants have fallen 2% per year for three years as rooftop PV and efficiency reduce sales, while peak demand has grown 1.5%. The current rate design recovers 72% of fixed costs through volumetric energy charges. The embedded cost-of-service study shows residential customers cause 45% of peak demand and 60% of energy sales, commercial 35% and 30%, and industrial 20% and 10%. The industrial class includes one 15 MW customer that has told the commission it will self-generate unless its all-in rate stays below $0.075/kWh; the current industrial average is $0.082/kWh. The commission has opened a rate design docket and directed the utility to address cost causation, bill stability, and the utility's obligation to serve. The utility's authorized return on equity is 9.6% on a 52% equity ratio; rate base is $1.4 billion.
1. Allocate the $48 million increase among the three classes using the embedded cost study. What judgment affects the result?
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A defensible first pass weights demand and energy 50/50 because the utility is summer-peaking and fixed costs are driven by both. Residential = 0.5(45) + 0.5(60) = 52.5%; commercial = 0.5(35) + 0.5(30) = 32.5%; industrial = 0.5(20) + 0.5(10) = 15%. Applied to $48 million: residential $25.2 million, commercial $15.6 million, industrial $7.2 million. Judgment matters: customer-related costs should be directly assigned, and a pure 50/50 weighting may over-allocate energy to residential if the true driver is peak. A demand-heavy weighting of 70/30 shifts more to industrial. The commission should see the class cost-of-service gaps, not just the increase. If current industrial rates already exceed cost, the industrial increase may be zero or negative even though its demand share is 20%.
2. The 15 MW industrial customer says it will leave above $0.075/kWh. Design a rate response and test it against cost and fairness.
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At 15 MW and 60% load factor, annual energy is about 78,840 MWh; at $0.082/kWh revenue is $6.47 million, and at $0.075/kWh it is $5.91 million, a $0.55 million difference. Do not offer a secret rate. Options: a cost-based industrial tariff with a demand charge and a lower energy charge, so the customer sees marginal cost; a minimum bill or standby charge to recover fixed costs if it self-generates; or a transition rider with a sunset date. Test: the discounted rate must not fall below marginal cost and must not shift fixed costs to other classes. If the customer's bypass is truly uneconomic for the system, the commission may approve a tariff available to similarly situated customers. The utility should document the avoided cost and the obligation-to-serve cost.
3. How should the utility address declining sales and the fixed-cost recovery problem?
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Separate the revenue requirement from volumetric recovery. Increase the residential fixed charge gradually, but not so fast that low-use customers face bill shocks. Use a decoupling mechanism or a revenue-per-customer adjustor so the utility does not lose fixed-cost recovery when efficiency and PV reduce sales. For commercial and industrial customers, use demand charges and minimum bills. Rate design should follow cost causation, not revenue maximization. Also evaluate whether the 2% sales decline is permanent; if PV is the cause, fixed-cost recovery should shift toward fixed charges and demand charges, while preserving a volumetric signal for energy efficiency. File the analysis and avoid cross-subsidies.