10. Replacement Power Costs

10.1. Positions of the Parties

In its testimony, DRA recommends that the Commission disallow $12,473,040, which is the amount DRA calculated that SCE paid for additional purchased power in order to compensate for lost power resulting from various forced outages. DRA states that despite three data requests, SCE failed to provide the cost of replacement power for forced outages. The methodology used by DRA for the recommended disallowance is based on the following assumptions:

1. Outages begin at the beginning of the first hour and end at the end of the last hour. If DRA did not have the beginning hour of the outage, it was assumed that the outage began at 08:00.

2. Effective lost capacity is the product of actual nameplate rating, the record period capacity factor, and proportionate ownership share. For hydro facilities, nameplate and capacity factor were derived from the bypassed MWh provided in SCE's testimony. Nameplate ratings and the capacity factors for other facilities were provided in SCE's testimony.

3. All outages are total; no partial output mitigated calculated total losses.

4. Replacement energy cost would be the marginal prices actually paid by utility for replacement energy; not having this data, DRA uses hourly average energy prices from CAISO.

5. Replacement cost would be mitigated by actual avoided costs during the outage; not having this data, DRA uses $0.

6. All outages are presumed to be equal energy lost per hour for duration of outage.

Based on this methodology, DRA calculates the disallowance related to the Palo Verde Unit 3 outage to be $615,000.

SCE asserts that DRA's replacement cost methodology is flawed for many reasons including:

· Because SCE utilizes least cost dispatch, the absence of any economic or "in-the-money" resource (like a nuclear, coal, or hydro unit) does not necessarily mean that SCE must or even should buy power to replace it. That decision is determined by SCE's residual net position (RNP) (i.e., the difference between the economic dispatch of all resources and SCE's forecast of customer load) after the outage is taken into account. The absence of an economic energy source would either make SCE's RNP less long, move the RNP from long to short, or make the RNP more short. Although it is not possible to calculate the exact cost of the economic loss due to a specific outage in any of these, one can estimate the value of the "lost energy," or opportunity cost, by considering appropriate published energy indices (with adjustments made, as necessary, for product type, delivery period, delivery point, and the bid-ask spread) and the unit's variable cost of production (fuel and variable O&M). DRA's simplified methodology ignores many of these considerations.

· The appropriate market value of lost energy is reflected at the delivery point of the unit in question. DRA ignores this consideration in its methodology, and instead uses only California (CAISO) prices for all of the outages, even though Four Corners is in New Mexico and Palo Verde is in Arizona; both of which are adjacent to trading hubs with published day-ahead index prices.

· DRA's methodology is further flawed by its use of only CAISO Real-Time Imbalance Market price data. By using this price data, DRA implicitly assumes that all of the energy transacted - whether sales if the RNP was long, or purchases if the RNP was short - was transacted as CAISO Imbalance Energy. This assumption is incorrect. Because the CAISO Real-Time Imbalance Market is subject to low liquidity and high volatility, SCE specifically strives to close out its energy positions in advance of real time by using a combination of hour-ahead, day-ahead, and beyond day-ahead transactions. Indices reflecting these transactions would be the more appropriate benchmarks to use; however, reliable prices are not published regularly for the hour-ahead markets and published forward prices tend to be for calendar months, quarters, and years, which do not correspond to the outages in question here.

· For the outages in question, the most appropriate prices to benchmark against would be the published day-ahead indices for power, albeit with a few adjustments. This is for a number of reasons. First, the published day-ahead prices are for "Firm LD Energy," and, in the case of non-CAISO energy, Firm LD with ancillary services or WSPP Schedule C. In the case of Four Corners and Palo Verde, the power they provide is unit contingent (WSPP Schedule B) energy, which doesn't include ancillary services. This energy trades at a significant discount (a few to several dollars/MWh, depending on the unit producing it) to the liquidly traded product published by the indices due to its unit contingent nature. In addition, as the published index prices represent an average, or "mid," of the transactions executed on that day, they should be adjusted for the "bid-ask" spread. The magnitude of the bid-ask spread depends on the liquidity of the product at the delivery point in question, and can vary between a few cents and a few dollars/MWh. Therefore, for this analysis, when SCE is purchasing, the published index price should be adjusted up by one-half the bid-ask spread, and conversely, should be adjusted down by one-half the bid-ask spread when SCE is selling.

· Although DRA acknowledges that a replacement cost methodology should include a credit for the fuel cost SCE avoids during the outage, DRA has assumed a credit of zero in its disallowance calculation. In addition, all generating units incur variable O&M costs when operating (covering consumables such as water, chemicals, lube oil, filters, run-hour based maintenance contracts, etc.) that DRA did not consider.

10.2. Discussion

Both DRA and SCE have put the Commission in an awkward position with respect to determining replacement power costs. While DRA has described its methodology and has calculated the replacement power costs for its proposed outage disallowances, it did not respond to any of SCE's specific criticisms of the methodology. On the other hand, SCE, while criticizing DRA's methodology and suggesting alternatives, did not provide any alternative data or calculations on which the Commission can rely in making replacement power cost adjustments. Also, SCE did not indicate whether DRA's methodology resulted in replacement power costs that were either too high or too low.

It would be pointless for the Commission to address and determine the reasonableness of forced outages, if financial consequences of unreasonable outages cannot be calculated and imposed. In order to do that for this proceeding, we will adopt DRA's calculated disallowance of $615,000 for the Palo Verde Unit 3 outage, the only unreasonable outage determined for this Record Period. We recognize that DRA's methodology may be flawed, but it provides the only quantification of replacement power costs. Absent anything better, we will use the results as an approximation of the replacement power cost associated with the Palo Verde Unit 3 outage. In doing so, we are not adopting the use of DRA's methodology and calculations for future proceedings. In the future, we would prefer that parties work towards an agreement on a methodology for calculating replacement power costs. In the absence of such agreement, parties should recognize that the Commission will determine such costs, if needed, based on the best available record evidence.