Priority Pricing: A Proposal for an Economic Demand-Side Program in ERCOT

1. Jay Zarnikau, PhD Frontier Associates Shmuel Oren, PhD UC-Berkeley Priority Pricing:A Proposal for an Economic Demand-Side Program in ERCOT ERCOT Demand Side Working Group June 8, 2007

2. Impetus for This Proposal • Continuing concerns over resource adequacy. • Additional steps are needed to promote the response of loads to wholesale prices, which will in turn promote economic efficiency, avoid or reduce some price spikes, and constrain the market power of generators. • While the BUL program is theoretically attractive, it hasn’t proven popular and will be terminated when the market structure changes. This proposed program could provide a substitute for the BUL. • This proposed program could complement the EILS program (or, if EILS is terminated, a modified priority pricing program could provide an alternative to EILS). • Disclaimer: This proposal has not be sponsored by, and does not necessarily represent the views of, any of our consulting clients.

3. Background • I proposed a “Long Term BUL Contracts” program to the Demand Side Working Group in October 2005. • Professor Oren suggested a call option program (which would involve both supply-side and demand-side resources) at a Resource Adequacy Rulemaking workshop in April 2005 (“Market Friendly Generation Adequacy Assurance”). • Our two proposals had some common features and are both based upon the same pricing theory that Prof. Oren helped to develop in the 1980s. • Consequently, we decided to collaborate on the development of a more refined demand-side program.

4. Program Overview • Program participants would contractually commit to curtail load at three preset strike prices. • Commitments would be for a period of one year. • The program participant would agree to curtail whenever the MCPE (balancing energy price) in the zone or LMPZ (zonal average of LMPs) exceeds the strike price at any time during the contract period. • Balancing energy settlement (or its equivalent in the nodal market) to participants during curtailment period based on strike price. • A reservation payment based on committed capacity and strike price would be paid to the program participant. • Participants can enroll for either: • One-Day Notice option (where curtailments are triggered by high prices in the Day-Ahead Market), or • Real-time Market option (where curtailments are triggered by a projection of a high real-time energy price).

5. Program Overview (cont.) • A higher capacity payment will be provided to program participants that offer their curtailments at a lower energy price. • Participants are insulated from the future RUC Capacity Short charges. • A bonus payment and priority status will be provided to any program participant that agrees to interrupt with no notice under ERCOT’s control. • A bonus payment will be provided to any program participant that would additionally agree to interrupt in the event of an ERCOT-declared emergency. (If market prices are raised to the wholesale price cap during an EECP, then this would not be necessary.) • Of course, this is a voluntary program.

6. Theoretical Foundation • This is consistent with the notion of “priority pricing,” whereby the price paid by consumers for energy is related to the level of reliability that they select. Pay more if you want higher reliability. Pay less (or get an payment or credit) if you are willing to accept more outages). • This is also consistent with financial options theory. The ISO is granted an option to curtail the usage of participating customers at the customer’s strike price (the MCPE at which the customer provides an offer to curtail). • This is really an “economic program” with some reliability features, rather than a reliability program. So, it is quite different from EILS.

7. Similarities to Other Programs • Prior to restructuring, HL&P offered a large menu of interruptible rate options (e.g., firm service with LOS; instantaneous interruptible service with IS-B; and interruptible with notice service through IS-10, IS-30, and IS-60). Higher prices were paid for greater reliability or firmness. However, system reliability conditions tended to trigger curtailments, rather than economic interruptions. • This is also analogous to a situation where a Real-Time Pricing program participant or a consumer that purchases through an MCPE Product always reduced usage at a predetermined price point. • If a BUL (if we had any) had a standing fixed offer into the balancing energy market in every interval over a year, it would look something like this program. • It is equivalent to a bilateral contract for load response since the fixed premium locks in the payment to committed load eliminating the risk of uncertain balancing energy settlement.

8. Benefits of This Approach • The necessary system changes should be minimal (but some work will be required to set baselines for some loads and forecast real-time prices). • Knowing that demand will be reduced at various market prices will have value to system operators. • Since the program involves a commitment to curtail in an emergency, demand reduction from these program participants could be recognized in a reserve margin calculation. Further, the committed load should receive a “gross up” that accounts for the reduction in needed reserves. • While demand-side offers to curtail into the day-ahead market (DAM) moves us in this direction, a priority pricing program would have more value since the curtailments under this program can be relied upon. DAM participation is voluntary and there is no long-term commitment by a load to curtail when at a given price level.

9. Likely Participants • Residential and small commercial direct load control program participants with advanced metering systems. • Good candidates for the Real-Time Market Option • Water heaters, air conditioners, and pool pumps could be controlled and cycled. Alternatively, the load at a facility could be limited with a fuse during a high price, requiring the homeowner or facility manager to decide which equipment to operate (like Demand Subscription Service at SCE in CA during the 80’s). • Advanced metering infrastructure facilitates performance monitoring • Industrial loads that can tolerate some interruptions. • Many of these would be good candidates for the One Day Notice Option. • LaaRs would not be good candidates.

10. Baseline for Measuring Curtailment Performance • We have the same problems that we encountered with EILS, namely: • It is difficult to predict load levels and the amounts that can be curtailed at a facility up to a year in advance. • Some loads are weather sensitive or have maintenance outages. • Consequently, the formulas and procedures used by the ERCOT Staff for EILS should be followed (treat as intermittent resources). • In addition, we’ll have some special complications involving residential direct load control (e.g., air conditions are not in use during winter). Fortunately, many ISOs and utilities have addressed these issues in the design of other programs and we can learn from their experiences. • Perhaps the NAESB effort (to be discussed later on today’s agenda) will also provide guidance.

11. Quantities Provided by Participants • For loads with “random” (i.e., difficult to predict) temporal load patterns, an average quantity could be offered. • For loads with a predictable pattern (e.g., a typical weekly production schedule with typical maintenance schedules), the pattern could be offered. • For weather-sensitive residential air conditioning loads, a formula expressing potential demand reduction as a function of weather could be offered. • Curtailment performance is considered to be adequate if the load level during a curtailment is at or below the baseline minus the quantity offered.

12. What the Participant Receives • Reservation or priority payment. • Avoids the high energy charges (as the customer would if it was engaging in voluntary load response). • There may be some mark-up of incentives for avoided losses. • Protection from RUC Capacity Short Charges • Receives price forecasts (if it subscribes to the Real Time Market Option). • If the load is controlled by ERCOT or a third-party, relieves the participant of the need to take any manual actions to curtail.

13. One Day Notice Option • Participant makes a “standing offer” to provide a curtailment into the DAM over the one-year duration of its contract. • Since this is an hourly market, the deployment/curtailment period is one hour when its offer is struck. • The Participant has roughly one day’s notice of the needed curtailment.

14. Real-Time Market Option • We need the Demand Side WG to first complete Item 2 on its Goals for 2007, so that we can provide a price forecast to loads at least a few minutes prior to each settlement interval when the nodal market is introduced: • There presently is a problem because the “real prices” will be calculated every 5 minutes (roughly). So, at the start of a 15-minute interval, the price for the first 5 minutes will be determined (with no advance notice). But the price for the entire 15 minute settlement interval will not be known. • Until we resolve this problem, there is no way of knowing whether the LMPZ for the 15 minutes will exceed the trigger price. • Regarding minimum duration of a curtailment: • Residential direct load control programs will want short durations. • If an industrial energy consumer is curtailed, it will want a guaranteed minimum curtailment period, and be paid an acceptable price for all intervals of that period. Let’s handle this in the same manner as we addressed it for the BUL program.

15. Price Triggers • We suggest: • $750 per MWh • $1000 per MWh • $1500 per MWh These are the price levels at which you could subscribe to curtail. As offer caps increase, these should change.

16. Calculation of Program Incentive:Risk Premium Approach • One option is to provide the participant with an upfront payment based on the expected value of the high balancing energy or LMPZ costs that the participant will avoid as a result of the customer’s participation in the program. • For example, the shaded area in the following graph might reflect the expected value of the costs avoided by the customer. Let’s say that (when multiplied by the customer’s expected load level) that the shaded area equals $1000. The program participant would be paid $1000. • In an actual year, the price spikes might be more or less frequent and higher or lower than the expected value. But, the program participant is paid $1000, and is protected from any risk.

18. Calculation of Program Incentive:Risk Premium Approach • Additionally, there would be a “scaling up” of the value of the shaded area of the curve to reflect the reduced line loss benefits associated with this demand-side program. • There is no distortion to the market (beyond all the distortions that we already have). Risks are just shifted from the participant to the market.

19. Calculation of Program Incentive:Risk Premium Approach (cont.) • Wouldn’t an energy consumer on an MCPE Product that curtails (outside of any formal program) achieve the same result? • Yes, on an expected value basis. But the customer removes some risk by participating in the program. Most energy consumers are risk averse when it comes to energy costs, so this is a benefit. • The participant also gets better price information and protection from RUC Capacity Short charges. • This approach would require ERCOT to calculate price duration curves (which might get a little contentious). • But, it is an open question whether this removal of risk will be sufficient to entice an energy consumer to participate in the program. Further, when the consumer commits to a year-long contract it surrenders some latitude to make operational decisions based on real-time economic conditions.

20. Calculation of the Program Incentive:Proxy Avoided Capacity Cost Approach • Yes, yes. We have adopted an energy-only approach to resource adequacy and generators do not receive capacity payments (unless they are providing an ancillary service or RMR service). • But if the risk premium approach does not provide sufficient incentives for load participation, then additional incentives should be considered. • We could either: • Administratively set a capacity payment, or • Administratively set a capacity price ceiling and a target quantity (for each price level) and then let the market determine the price.

21. Calculation of the Reservation Payment (cont.) • A price or price cap could be established based on: • Annualized capital cost of constructing a combustion turbine • Tied to the annual average price of non-spinning reserves or responsive reserves in the previous year. • A fraction of the PUCT’s Avoided Capacity Cost in its Energy Efficiency Rule. It is presently $78.50/kW. PUCT Subst R §25.181(e). • The PUCT-approved annual capacity payment for a load management program operated by a TDU could also be used. This number is roughly $15/kW/year for a summer-only program. See: http://www.txuelectricdelivery.com/electricity/teem/services/elmsop/incentives.asp • The estimated economic value of the program in reducing overall market prices to the entire market. • Or we could just pay make an additional payment to the participant based on the price of responsive reserves at the time of the curtailment.

22. Bonus for “No Notice” Service Participants that are willing to accept “no notice” can be treated as Regulation or Responsive Reserves and get a premium comparable to the average AS payment. The usual concerns over having “too much” load providing such services will need to be addressed. And any declining marginal value of additional load providing such services will need to be considered.

23. Market Prices During an EECP • The price should be automatically raised to the price cap during an EECP condition, if market prices as otherwise unlikely to reach that level. • If this occurs, then program participants (at least those who sign up for the Real Time Market Option) will be curtailed during an EECP (and will avoid those high prices). • However, we need a mechanism to notify loads of this price with sufficient notice time to accommodate their response.

24. Quantities to Procure • The procured quantity could be based on reserve requirements. • Alternatively the quantities can stay the same but the prices changed to reflect the expected price forecasts. • Or, perhaps there may be no need to limit this.

25. Performance for Payment Purposes • QSEs submit offers to participate or enroll program participants (consistent with how EILS program customers are enrolled). • The performance of industrial participants is evaluated on an individual customer basis. This is designed to avoid the problem with the current BUL where multiple BULs under the same QSE must be settled as a group, and the performance of a large BUL within the group could affect the payments to the whole group. • Residential and small commercial participants (e.g., a direct load control program) may be settled on an aggregate basis.

26. Who Pays for the Program? • The cost of the incentive payment could be assigned to load-serving QSEs based on their load ratio share. • A more sophisticated approach might be to assign the cost associated with each strike price as a surcharge on load that persists above that price. • Self provision can be done through passive load response or through participation in the program (depending upon the approach used to calculate the incentives made to program participants, the payment will offset the charge).

27. Penalties for Inadequate Performance • Nonperformance can take several forms. • If available load for curtailment is persistent below the original rating the rating can be adjusted going forward. • If, on the other hand the load does not curtail when asked, it should be liable for the difference between the MCPE and the strike price and pay a pro rata share of the program cost (including the scale-up portion for RUC charges and distribution losses).