Initial Comments of the Southern Alliance for Clean Energy and South Carolina Small Business Chamber of Commerce
regarding the
Proposed Santee Cooper 2025 Rate Increase
September 13, 2024
Dear Santee Cooper and Santee Cooper Board Members:
The Southern Alliance for Clean Energy (SACE) and the South Carolina Small Business Chamber of Commerce (SCSBCC), through their member customers of Santee Cooper, hereby submit these comments regarding your proposed 2024 rate increase for your consideration.
- Transparency: Santee Cooper should give customers a full picture of total near-term rate and revenue increases.
a. Fuel adjustment
We believe that Santee Cooper should give ratepayers and the public a full picture of its expected near-term rate and revenue increases. Santee Cooper’s rate documents describe two charges that will be imposed in addition to its general rate increase: a fuel adjustment and a Cook exceptions rider.
Regarding the fuel adjustment, Santee Cooper notes that “[p]rojections based on the 2024 Budget indicate that Santee Cooper’s retail customers could experience a price increase of approximately 7% from fuel costs alone in 2025; however, fuel commodity prices have moderated and the price increase may be lower.”[1] Santee Cooper’s 7% fuel cost estimate appears to date from December 2023, and is not further described in the rate case study that has been provided to the public.
On July 24, Rick Baumann, Santee Cooper commercial customer (Nance’s Shellfish Company) and who serves on the SCSBCC Board of Directors, asked Santee Cooper “What is Santee Cooper’s current projection of the amount of the fuel cost rate increase that will take effect in January 2025?” (emphasis added). In response, Santee Cooper referred us to the ” Projected Prop Fuel Adj Factor” worksheet of its Cost of Service Study (COSS) Appendix C. It appears that the provided worksheet did not include a tab labeled “Projected Prop Fuel Adj Factor.” Further, presumably any estimate included on a document prepared for this rate proposal would date back to its announcement. Santee Cooper’s response thus did not answer the question of what its current projection of fuel cost increases will be.
Taking into account the estimate within Santee Cooper’s COSS, residential customers could soon experience an 8.7% base rate increase plus a 7% increase due to increased fuel charges, for a total increase approaching 16%. We believe that Santee Cooper should make available as soon as possible its estimate of the size and timing of this potential fuel rate increase, including a transparent calculation of how it calculates the estimate.
b. Cook rider
Similarly, Santee Cooper states that “[e]stimates of how the Cook Settlement rate freeze exceptions will be recovered from customers are unavailable at this time and collection-related revenues are not included in the 2025 projections.”[2] This rider apparently would be added to the 16% rate increase above. We believe that the public should be given notice and time to understand the timing and size of any Cook Settlement rider, including a transparent calculation of how it is derived, before the new base rate increase is locked in.
c. Revenue increases.
We believe that retail customers also should be allowed to see and understand the overall revenue increase picture. For instance, are Santee Cooper wholesale customers paying a similar increase in rates and revenues from 2024 to 2025, comparing actual rates and revenues prior to the proposed rate increase, and projected rates and revenues after the rate increase?
Again, we noted that “while Santee Cooper estimates that it needs a 4.9% increase in retail revenue requirement for 2025 (COSS at 2), its projections indicate that, under the required rate increase, annual revenue will increase by almost 17% from 2024 to 2025 (Supplement at 14). Mr. Bauman asked Santee Cooper “why, specifically, is the revenue requirement increase so much larger than the 4.9% requested rate increase?” Santee Cooper’s response was that
the revenue requirement increases are system level expenses across all customers, including off-system and wholesale customers. The revenue requirement increase is also impacted by projected year over year load growth.
Respectfully, this response does not answer the question that was asked. Customers who are being told there will be a 4.9% increase but notice that revenues will rise 17% should be given a detailed, reasonable, component-by-component explanation of exactly what contributes to the revenue increase.
We also note that the proposed capital expenditures that appear to drive the rate increase have been described only in the most general terms, thereby not allowing any examination of their validity, reasonableness, or impact on Santee Cooper operations. Santee Cooper’s COSS explains that
Major factors driving the need for rate revisions and for this Study include:
A significant increase in Authority’s costs due to compliance with environmental regulations, increased transmission operations and maintenance expenses stemming from regional system constraints, and inflation . . .
It appears that the reasonable cost of each of these major factors driving the need for rate revisions are not detailed and specified in the COSS, in the supplement to the COSS, or in Appendix C. For instance, these documents do not list the projects that form the basis for transmission cost increases during the test year compared to the prior year, or explain why the test year transmission costs, without adjustment, are a valid basis to establish rates that likely will persist well beyond the test year. Also, for instance, the Company’s Integrated Resource Plan includes over $400 million in transmission costs associated with the retirement of the Winyah Generating Station. Does the requested revenue requirement in any way address these transmission costs, or have they been excluded? Similarly, the exact cost and nature of environmental upgrades is not listed in a manner that would enable verification that these costs merit the requested annualized rate increase.
Further, regarding transparency, we note that ORS has recently commented on Santee Cooper’s rate proposal. On page 31 of the ORS comments, ORS states that:
Santee Cooper applied a “test year adjustment” to the proposed rates to account for the proposed rates effective April 2025 (i.e., applied to the March bills onwards). This type of adjustment has not been seen by ORS while reviewing IOUs during rate proceedings.”
Much of the remaining page is redacted, apparently due to Santee Cooper (not ORS) requesting that information about its test year adjustment be kept secret from the public. Santee Cooper similarly redacts information about a “manual adjustment” to different rate classes to reallocate portions of demand costs [emphasis added].
We believe that Santee Cooper must be required to be entirely transparent about the method in which it calculates proposed rate increases. The General Assembly has provided that the public must be given notice and be afforded an opportunity to comment on Santee Cooper’s rate proposal. We do not believe that hidden rate methodologies constitute “notice” or that they reasonably allow the public to comment on those aspects of the rate proposal.
More particularly, in this regard, Santee Cooper’s adjustment of revenues may affect the calculation of the overall amount of revenue that will be collected from the residential, small business, or other rate classes. For instance, on Appendix C page 001-001465, Santee Cooper projects the future revenues for the residential class based upon two months of old rates (January, February) and ten months of new rates (March through December). It appears that these revenues total to equal Santee Cooper’s reported 8.7% rate increase for the residential class. This calculation thus appears not to include the revenue that would be collected in January and February under new rates. We note that January is the month with the highest residential billing determinants in terms of both kW billing demand and kWh sales. Absent a clear explanation of the hidden revenue adjustment described above, it appears that Santee Cooper is under-representing the amount of the residential rate increase.
A similar issue affects revenue projections for the small business class, and we further note that the first month of small business rate schedule GA billing appears to represent an 81% increase in monthly revenue, in part due to projected demand charges in March significantly exceeding demand in any other month, according to Appendix C, page 001-001466. According to this page, the small business class would pay $3.7 million to Santee Cooper for February, but then would be billed $6.8 million in March—normally a mild Spring month. This outcome may be a side-effect of Santee Cooper’s unexplained billing adjustment, or perhaps a demonstration of the wide-ranging billing results that small business customers will experience under a $17-per-kW, ½-hour demand charge. We merely note that such a large increase in billing for the small business class in the first month of new rates will cause rate shock.
- Fairness: Santee Cooper should implement TOU rates in a manner that is just and reasonable for all customer classes.
Santee Cooper’s proposed default residential rate would for the first time impose an approximately $10 per kW demand charge on residential customers during defined TOU periods. Alternatively, residential customers could opt into a TOU energy rate, but the demand charge rate is the basis of revenue calculations in the COSS.
Small business customers in the SGS rate class would for the first time be subject to an approximately $17 per kW demand charge. It appears that the SGS rate customers would not have an alternative non-demand charge rate.
While we acknowledge the validity in concept of TOU rates that are reasonably designed to send a price signal to customers to shift the timing of energy usage in order to reduce overall system costs, we oppose Santee Cooper’s residential and small commercial demand charge proposal as currently written.
We first note that, unlike smaller customers, larger customers would be allowed to choose TOU service and that, unlike the rates proposed for residential and small commercial customers, the rates for larger customers focus on peak seasons and allow them to gain off-peak cost savings by shifting usage to weekends or non-peak months. Only the small customers newly experiencing demand charges would be required to pay them in all seasons on all days—even during months and days that are unlikely to experience system peaks. Further, the overall rate proposal is not logically consistent because it defines “peak” differently for different classes and rate schedules, and for energy charges and demand charges.
We recommend that TOU service to residential and small commercial customers should be provided in the form of energy charges, rather than demand charges, for the following reasons:[3] Effectively, the demand charge approach could cost a residential customer over 150 times as much for the single highest kilowatt hour during the month as for all other kilowatt hours ($10.71 per kilowatt hour for the single peak hour and less than 7 cents per kWh for every other kilowatt hour). Across the country, demand charges have rarely been imposed on residential customers because they send an ineffective and somewhat arbitrary price signal for the management of residential loads, which leads to unpredictable, unfair results for individual customers.
Consider three hypothetical customers: Customer number one hits a 10 kW peak hour on the first day of a billing period, incurring over $100 of charges for this single hour. This could be true even if the first day were a Sunday in May, when it is extremely unlikely that the Santee Cooper system would be experiencing peak usage. For the remainder of the month, customer number one’s peak does not exceed 7 kW.
Customer number two could hit a 9 kW hourly peak usage every day of the month, never attempting to save energy. The first customer will pay a higher demand charge even though it is likely that the second customer puts more overall strain on the electric grid.
Finally, customer three hits a monthly peak demand of 10 kW for every peak hour of a day or month will pay the same demand charge as a customer one who hits a 10 kW demand for only a single hour.
These examples show why using a one-hour or half-hour demand charge to send a TOU price signal produces arbitrary results that diverge from the purpose of helping customers manage demand in order to reduce system costs. For instance, any customer who has already hit a high hourly peak demand has less reason to manage demand for the rest of the month under the new rates than under Santee Cooper’s current rates, because the new residential rates concentrate charges in a single hour and sharply reduce the remaining energy charges that reflect the total amount of energy used during the month.
Demand charges on small customers will produce widely different results for similarly-situated customers, with little corresponding benefit to ratepayers as a whole. For instance, the South Carolina Office of Regulatory Staff indicates that typical 1,000 kWh residential customers could experience rate increases ranging between 0% and 36% due to differences in the size and timing of demand.[4]
Small business customers could see even sharper inconsistencies in resulting bills because the proposed demand charges are higher ($17.08/kW) for them and are measured across a shorter, half-hour period. ORS estimates that some high-load-factor small business customers would see rate decreases while low-load-factor customers receive a 34% increase. For SGS customers generally, over half the monthly bill could easily be determined by a ½ hour of usage during the month.
The flip side of the high demand charges for a single hour or half-hour of the month are low per-unit charges for energy. This rate structure will send the mixed message that customers should use more energy overall in most hours of the month. Customers will thus be encouraged to use more, but penalized if even a single on-peak hour during the month is not controlled—even if the hour occurs during a low-demand shoulder month or weekend.
These flaws in these price signals sent by small-customer demand charges are worsened by the fact that small customers generally do not understand which equipment or appliances are likely to cause short-term peaks in demand. For instance, customer hot water heaters, air conditioners, and refrigerators generally cycle on and off without customer input. The accidental coincidence of these three appliances during a single peak hour could form the majority of a customer’s monthly bill, even if the customer is diligently moving clothes washing, dishwashing, or small business applications such as printing to off-peak periods in an attempt to save money. Customers may spend time trying to manage numerous incidental loads, such as laptop charging and cooking, without understanding that HVAC and water heating are the biggest elements of demand. And customers should be rewarded for moving dishwashing and clothes washing to weekends, not charged the same amount.
Worse, many residential and small business customers have limited means to move major energy usage to off-peak periods and legitimate reasons for retaining peak usage. Elderly, fixed-income customers dependent on medical devices should not be penalized for using these devices or for cooling their homes on hot afternoons. Further, while air conditioning, heating, and water heat are the most likely drivers of monthly peaks, renters have little control over the efficiency of these core equipment types. Many small businesses customers fall in this category: they rent or lease spaces in which the major energy uses are driven by equipment owned by the lessor. These customers either should have an option for a traditional, seasonally-adjusted energy rate (or tiered energy rate) like the one that Santee Cooper currently offers, or a TOU energy rate that produces less arbitrary billing results associated with short periods of on-peak or off-peak usage.
We also note that, under a demand charge approach, a single day of warm weather in March or October could produce high customer bills similar to months with frequent peaks such as June or December. This is particularly true of small business customers who would be assessed on a half hour of energy usage. The resulting high bills will tend to confuse, rather than educate, customers regarding the true drivers of high energy usage or utility system costs.
Overall, for customers who do not understand and closely monitor energy usage during every hour of the year, the proposed demand charge is likely to operate more like a simple fixed charge. For reasons the residential customer will not likely understand, they will always receive a bill with a $20 customer charge plus a demand charge that never falls below the peak usage of their air-conditioning or heating system. This means that over $50 of the monthly bill will likely be fixed in every month, and remaining energy charges will offer little potential for significant cost savings.
The small business customer will receive an even higher bill for the same usage: under Santee Cooper’s own example of 32 kW of demand, a single half hour of energy usage could result in over $500 of charges, regardless of what happens during the rest of the month.
We note further that Santee Cooper already has the largest fixed charge of any major utility in South Carolina. Santee Cooper’s fixed charge for residential customers is $19.50, roughly double the Dominion $9.50 fixed charge and Duke Progress $11.78 fixed charge. Based on calculations from Santee Cooper’s rate study Appendix C, fixed charges plus demand charges could account for 50% or more of residential revenue, leaving less than half of the bill within reasonable control of many residential customers.
- Leveraging customer resources for effective load management.
An increasing number of residential customers are adopting solar energy—either with or without energy storage. While other South Carolina utilities offer these customers a TOU energy rate that provides significant compensation for supplying energy to the grid during peak periods, Santee Cooper’s rate proposal retains its unique “hourly netting” approach for these customers.
Under Santee Cooper rates, during the 3PM-6PM summer afternoon peak period, when energy costs are high and the grid needs energy, Santee Cooper will charge customers very high prices for energy while compensating solar assistance at low rate that does not take peak value into account. While residential customers would pay 31 cents per kwh (under Santee Cooper’s TOU energy rate) or even over $10.00 per kWh for peak energy, a customer feeding the same amount of energy to the grid would be compensated less than 5 cents per kWh. This massive discrepancy is neither just nor reasonable.
Further, under the demand rate, a solar customer who helpfully zeros-out energy usage during the peak period nearly every day will be charged the full peak period demand charge if he or she fails on a single day during the billing period to zero-out peak energy usage. A customer with batteries, who could actually supply substantial energy to the grid when it is needed most, will be undercompensated at less than 5 cents per kwh. Santee Cooper should allow its customers with distributed generation and storage to participate in its TOU energy rate, with 1-for-1 monthly netting within the on-peak and off-peak periods, like neighboring utilities do.
Further, increasingly, utilities (including Duke Energy Carolinas, Duke Energy Progress) are instituting “Virtual Power Plant” programs that aggregate the controllable demand of solar customers, customers with battery backup, and customers with smart devices such as Nest thermostats and communicating hot water heaters. Such aggregation programs can be swiftly implemented through experienced third-party firms that specialize in aggregated load management. Santee Cooper should move quickly to engage one or more demand aggregators so that customers can assist in meeting its near-term capacity needs and reduce marginal system costs.
- Recommendations: Santee Cooper should provide a full picture of its revenue and rate increases; re-design its residential and small commercial rates to be based on fair TOU energy charges; and enable fair customer contributions to its energy and capacity needs.
Given all of these considerations, we make the following recommendations:
- Santee Cooper should provide a clear overall picture of the rate and revenue increases that it plans to impose in the near-term, such that customers can understand what the year-over-year increases in rates and revenues will be for each retail and wholesale customer class and what costs drive those increases.
- Santee Cooper should not impose TOU rates on small customers through a demand charge. Rather, it should pursue reasonably-based TOU energy charges that target times and seasons that are actual system peaks, leaving all other non-customer-specific costs to be recovered on a volumetric basis that enables and facilitates energy conservation. Also, customer fixed charges should be reduced to be in line with neighboring utilities, based upon the cost of billing services.
- Santee Cooper should reasonably and fairly enlist the cooperation of its retail customers in meeting energy and capacity needs by revising its distributed generation tariffs to include TOU-based compensation for solar and battery customers within a monthly netting construct. Santee Cooper should seek the services of a proven aggregator to maximize the growth and management of these customer resources.
Sincerely,
Eddy Moore Frank Knapp Jr.
Director of Decarbonization President & CEO
Southern Alliance for Clean Energy SC Small Business Chamber of Commerce
eddy@cleanenergy.org fknapp@scsbc.org
501-772-5426 803-600-6874
[1] https://www.santeecooper.com/Rates/Rate-Study/_pdfs/Supplement-Santee-Cooper-2024-Rate-Adjustment-Request-05.24.2024.pdf (“Supplement”), at page 5.
[2] Id.
[3] In this regard, however, we note that the ORS review of Santee Cooper’s rate proposal seems to indicate that the Santee Cooper’s proposed residential TOU energy rates produce significantly higher bills than its residential demand charge proposal, with bill increases ranging from 12% to 15%. The COSS, however, does not provide an estimate of revenues that would be collected under the residential TOU energy rate. Review of the Public Service Authority 2024 Request for Adjustment, ORS, Sept. 6, 2024, at p. 42 (file:///Users/eddymoore/Downloads/ORS%20Comments.Santee%20Cooper%202024%20Request%20for%20Rate%20Adjustment.REDACTED.pdf
[4]ORS report at 44-45 (file:///Users/eddymoore/Downloads/ORS%20Comments.Santee%20Cooper%202024%20Request%20for%20Rate%20Adjustment.REDACTED.pdf).