San Antonio business energy: CPS Energy

San Antonio is a one-utility city, for power and for gas

CPS Energy is community-owned: the City of San Antonio acquired the predecessor company in 1942, and the utility today is the electric and the natural gas provider across its territory. That single fact separates San Antonio from every other Texas market covered here. In Dallas and Houston the wires company is fixed by the address while gas belongs to a separate distributor, and in Austin the electric utility is municipal but the gas arrives under a Railroad Commission tariff. In San Antonio one city-owned utility appears on both bills, and its electric and gas base rates are approved by the CPS Energy Board of Trustees and then by the San Antonio City Council, not by the Public Utility Commission of Texas. The tariff records that local character in its own text: the adjustment that amortises a regulatory asset cites City of San Antonio Ordinance No. 2022-01-13-0001 rather than a commission order. The pattern of local approval shows in the most recent base-rate action as well: Board approval on 4 December 2023, San Antonio City Council approval on 7 December 2023, and a 4.25% increase effective 1 February 2024.

• CPS Energy is owned by the City of San Antonio, which acquired the predecessor company in 1942.
• The same utility supplies and delivers both electricity and natural gas in its territory.
• Base rates are approved by the utility's Board of Trustees and the San Antonio City Council, not the PUCT.
• The tariff's regulatory-asset adjustment cites City of San Antonio Ordinance No. 2022-01-13-0001.
• The February 2024 base-rate action was a 4.25% increase approved in December 2023.

The class ladder runs from a general service rate to a five-year industrial contract

CPS Energy publishes its commercial electric schedules rather than bidding them, and the ladder is drawn on size, measured load and load factor. The General Service Base Commercial Electric Rate, labelled PL, is the catch-all: service for which no other rate is provided, supplied at one point of delivery through one meter. Large Lighting and Power Service, or LLP, serves larger premises, and Extra Large Power Service, ELP, applies where the monthly load is greater than 1,000 kW. Above that sits Super Large Power Service, SLP, and its applicability test is a monthly average load factor greater than 41% or 300 hours of use. An Industrial High Voltage Service schedule completes the list. The boundaries matter twice over. Each schedule prices demand in its own way, and the largest schedule carries a term commitment: SLP supplies service for an initial term of not less than five years. A site approaching a class boundary is therefore making a structural decision about its contract as well as comparing line items.

• PL is the general commercial catch-all for premises with no more specific schedule.
• ELP applies where the monthly load is greater than 1,000 kW.
• SLP requires a monthly average load factor above 41%, or 300 hours of use.
• SLP's initial term is not less than five years, while the smaller schedules follow the application and agreement.
• Each schedule prices demand differently, so the class boundary is a cost boundary.

Demand is billed on the worst quarter hour, and the summer peak follows you

The demand charge is set by the highest fifteen-minute demand reading the meter records in the billing month, which is how the tariff defines Monthly Demand. On the base commercial schedule, Billing Demand is that monthly demand in June through September. From October through May it becomes the greater of the month's own demand or 80% of the highest measured demand established during the previous summer, so one July afternoon can put a floor under eight months of billing. That is a ratchet, and it changes where demand work should be aimed: at the summer peak specifically, rather than at monthly peaks in general. The arithmetic is the reader's to run. Take the highest summer demand on the bill, multiply it by 80%, and compare the result with each non-summer month to see how many of those months the ratchet rather than actual use is setting the charge. SLP goes further, flooring Billing Demand at 5,000 kW in every month before the 80% summer test is applied on top in the non-summer period.

• Monthly Demand is the highest fifteen-minute demand reading in the billing month.
• From June to September, Billing Demand equals that monthly demand.
• From October to May it is the greater of the month's demand or 80% of the previous summer's highest demand.
• SLP floors billing demand at 5,000 kW every month and applies the 80% test on top in the non-summer period.
• Because the ratchet is seasonal, demand-reduction work belongs on the summer peak.

Power factor at 85%, and a high-voltage discount that runs the other way

CPS Energy adjusts billed demand where power factor falls below 85% lagging: the billing demand may be increased by adding 1% of actual demand for each 1% the power factor sits below the threshold. Two things about that are worth naming. The first is the threshold itself, because it is not universal. Austin Energy's commercial power factor adjustment begins at 90%, so a facility whose power factor sits between the two figures is penalised in San Antonio and untouched in Austin, which is why a multi-city operator should read each tariff rather than assume the clause travels. The second is that the adjustment changes the billed quantity instead of adding a discrete fee, and the quantity it raises is the same demand line the summer ratchet may already have raised. Motors running below full load, compressors, conveyors and transformers are the usual causes, and correction is capital work on the customer's side of the meter. The schedules carry a credit in the other direction too: a high voltage discount applies at a nominal distribution voltage of 13.2 kV or higher where the service needs no more than one step-down from transmission voltage of 69 kV or higher, discounting the energy charge for usage up to 200 kWh per kW of billing demand, for a demand-metered site that owns its own transformers beyond the point of delivery.

• Below 85% lagging, billing demand may be increased by 1% of actual demand for each 1% below the threshold.
• Austin Energy's equivalent adjustment starts at 90%, so the two cities differ for a site in between.
• The adjustment multiplies billed demand rather than adding a separate charge, and it compounds with the summer ratchet.
• A high voltage discount applies at 13.2 kV or higher with no more than one step-down from 69 kV or higher.
• The discount reduces the energy charge for usage up to 200 kWh per kW of billing demand; demand metering is required.

Supply is a fuel factor, not a contract with a renewal date

Because CPS Energy generates, buys and delivers the power, supply cost reaches a commercial account as a pass-through rather than a negotiated rate. The electric schedules carry a fuel adjustment that tracks the difference between the current month's unit fuel cost and a basic cost set in the tariff, where the unit figure is computed from the month's estimated generation mix and the unit fuel cost by fuel type, with true-ups that correct over-recovery and under-recovery across the recovery year, a balancing adjustment around January, and credits arising from litigation or settlements that affect fuel cost. A second adjustment amortises a regulatory asset authorised by the city ordinance, and a third passes through changes in taxes and required payments to governmental entities. The consequence for the buyer is structural: there is no supplier to bid, no term to negotiate and no renewal date to diary, so the annual review a competitive Texas account runs against its contract has no counterpart here.

• The fuel adjustment tracks the difference between the month's estimated unit fuel cost and a basic cost set in the tariff.
• True-up provisions correct over-recovery and under-recovery, with a balancing adjustment around January.
• A separate adjustment amortises a regulatory asset authorised by City of San Antonio Ordinance No. 2022-01-13-0001.
• Taxes and required governmental payments pass through on their own adjustment.
• No supplier, broker or term change alters these pass-throughs; consumption and load shape do.

Gas is the same utility, and it is billed in hundreds of cubic feet

San Antonio's gas distributor is CPS Energy, and its gas schedules are laid out the way its electric ones are. The Residential and Base Commercial Gas Rate, labelled G, covers gas used for cooking, heating and lighting through one metering station, priced per CCF, where one CCF is one hundred cubic feet, with a monthly gas cost adjustment measured against a basic cost per CCF that balances annually around August rather than in January. Above it, Class B covers commercial, industrial, manufacturing and processing use, steam generation for power purposes and heating or cooling plants, and the Large Volume Gas Rate, LVG, serves the largest commercial and industrial accounts by pricing gas in two parts: an energy charge per CCF plus a demand charge expressed per CCF per day. Both Class B and LVG exclude standby service, resale and single-family residential use. Both also supply gas at a nominal gauge pressure of four ounces per square inch, with measurements corrected to that basis when gas is metered at a higher pressure. The unit is the first thing to settle, because Texas gas tariffs quote volumes variously in therms, Mcf and CCF and only one of them appears on a San Antonio bill.

• CPS Energy is San Antonio's gas distributor as well as its electric utility.
• Commercial gas is priced per CCF, where one CCF is one hundred cubic feet.
• The base commercial gas rate carries a monthly gas cost adjustment that balances around August.
• Class B covers commercial, industrial and processing use, steam generation and heating or cooling plants.
• LVG prices gas as an energy charge per CCF plus a daily demand charge; both schedules exclude standby, resale and single-family use.

Two gas ratchets, and a winter priced as a daily demand

The gas schedules carry ratchet structures of their own, and they do not work like the electric ones. On Class B, the minimum bill steps up for a customer whose billed consumption reaches a designated monthly volume, and it stays at the higher level for eleven consecutive months after the most recent month at or above the threshold, which turns one exceptional month into nearly a year of higher floor billing. On LVG, demand is measured in CCF per day and priced in two seasons: winter, December to March, and non-winter, April to November. Winter billing demand is the greatest of the month's metered consumption divided by the days in the billing period, a floor of 600 CCF per day, or a higher figure specified in the customer's application and agreement. From April to November the billing demand is set by the maximum billing demand established during the previous winter, so one cold season fixes the floor for the rest of the year.

• Class B raises the minimum bill for a customer whose billed consumption reaches a designated monthly volume.
• That elevated minimum continues for eleven consecutive months after the most recent qualifying month.
• LVG prices daily demand separately in winter, December to March, and non-winter, April to November.
• Winter LVG billing demand is the greatest of monthly consumption per day, 600 CCF per day, or a contracted figure.
• Non-winter LVG billing demand is set by the maximum billing demand established during the previous winter.

The regional project standing behind San Antonio's load growth

San Antonio's transmission constraint is documented by ERCOT rather than described in the abstract. CPS Energy's San Antonio South reliability project went through ERCOT's regional planning group process to address thermal overloads in the San Antonio South area, and the scope is specific: an addition to the Howard to San Miguel 345-kV double-circuit line, a third 345/138-kV transformer, work along the Howard Road to Leon Creek 138-kV path, and expansion of the Beck Road 345/138-kV substation. The reliability analysis runs against a summer peak load base case, and the criteria it tests include a transformer-outage contingency in the X-1+N-1 category and a voltage deviation limit of 8% on non-radial load buses, alongside voltages exceeding their pre-contingency and post-contingency limits. The same load growth is why CPS Energy has been reviewing its large-load interconnection process and discussing flexible interconnection for very large new loads. The market structure around that load is its own thing too: CPS Energy's load carries its own ERCOT load zone designation, LZ_CPS, the label the company uses in its own filings about the four coincident peak charge. For a business planning a significant San Antonio expansion, the delivery side of the bill is being built to answer a regional constraint, and interconnection timing is a schedule question rather than a paperwork one.

• ERCOT's San Antonio South reliability project addresses thermal overloads in the San Antonio South area.
• The scope includes a Howard to San Miguel 345-kV double-circuit line addition and a third 345/138-kV transformer.
• The reliability study runs on a summer peak base case with X-1+N-1 transformer contingencies.
• Voltage deviations above 8% on non-radial load buses are among the criteria tested.
• CPS Energy's load carries its own ERCOT load zone designation, LZ_CPS, and the utility is reviewing large-load interconnection terms.

What to assemble before a San Antonio energy decision

In a market with no retail supplier, the preparation is about the utility account rather than a request for quotes. Start with the rate schedule printed on the electric bill and the service voltage, because every line item in the tariff is published per schedule and the class follows the service rather than the business type. Pull twelve months of kWh with the demand readings, and separate the summer months: on the base commercial schedule that summer peak sets the floor for the following eight months, and on the largest schedule billing demand is floored at 5,000 kW in any case. Check the power factor history if motors or compressors run the load, because the threshold here is 85% rather than the 90% used in Austin, and check the load factor against the 41% eligibility test for SLP, since that line decides whether a site can be served on the largest schedule at all. On the gas side, take twelve months in CCF, note the schedule, and model the winter daily demand and the minimum-bill carry-forward for that schedule. HighGround works as an advisor-assisted channel rather than a rate table, sourcing electricity and gas supply through the Broker Online Exchange supplier network and the adjacent categories through the AppDirect ecosystem. HighGround may receive provider compensation on completed purchases, and an inquiry places no order and switches no supplier.

• The electric rate schedule and the service voltage from the bill, plus whether the meter is demand metered.
• Twelve months of kWh with demand readings, with the summer months called out separately.
• Load factor against the 41% test for the largest commercial schedule, and power factor history if motors or compressors run.
• Twelve months of gas usage in CCF and the gas schedule printed on the bill.
• Competitive supply depends on the service address, the meter and the utility territory; municipal utilities, cooperatives and some jurisdictions have no choice at all.
• HighGround may receive provider compensation on completed purchases, and an inquiry places no order and switches no supplier.

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