3. Agreement on Throughput Forecast,
Ratemaking and Rate Design Issues

PG&E, TURN, and ORA submitted an agreement during the hearings, which was identified as Exhibit 29. The agreement resolves a number of previously contested issues in this proceeding. No party protested any element of the agreement. PG&E represents that each element of the agreement is a "stand alone" resolution of a discrete issue in the proceeding and was the resolved "on the individual merits of that issue." We therefore consider each issue separately on the merits of the proposed resolution, consistent with the law and the record in this proceeding.

PG&E's application proposed a minimum monthly transportation bill of $5 a month to cover some of the cost to serve residences with extremely low usage during certain months. PG&E states these residences are mostly vacation homes and estimates an actual cost of about $10 a month to serve a customer that does not purchase any gas commodity. ORA was the only party to object to PG&E's proposal, suggesting a $2.50 bill rather than a $5 bill. The Agreement would implement a $3 minimum monthly transportation bill for residential customers.

We concur that a $3 minimum monthly transportation bill is reasonable because PG&E incurs costs even when a customer does not use any gas. The minimum bill will affect mostly second homes during periods of vacancy. Because the minimum bill would primarily affect second homes, it will not cause undue hardship on customers who pay the charge. We find that the proposed minimum transportation bill is reasonable and will adopt it.

PG&E originally proposed to reduce the differential between the first (baseline) and second tier transportation rates for residential customers. The differential is currently at 70%, which PG&E believes exacerbates high winter bills when most second tier usage occurs. TURN proposed a third baseline period to address this concern.

The Agreement would resolve this issue by adjusting the summer gas baseline allowance to include the month of April. It would also set the gas baseline differential between Tier 1 and Tier 2 for bundled rates at 20% using the weighted average cost of gas filed in the BCAP. This differential would be in effect as long as the transportation rate tier differential between Tier 2 and Tier 1 is no less than 1.6. Therefore, the Tier 2 transportation rate would always be at least 60% greater than the Tier 1 transportation rate.

We agree that this change in the way the residential tiers are designed would mitigate the impacts of winter bills on customers who go into the second tier of usage. It would do so without unduly affecting other customers or other billing elements. We will adopt it.

Most energy rates are averaged within classes and in some cases between classes of customers. Averaging simplifies rate design but results in some customers who are relatively inexpensive to serve paying a share of costs associated with customers who cost more to serve. The Commission has permitted PG&E to "deaverage" rates between small commercial and residential customers at a rate of 10% a year. The implication is that core customer rates would rise. In this application, PG&E proposed to accelerate the pace of deaveraging to 20% a year, which ORA and TURN opposed.

The Agreement provides that the pace of deaveraging small commercial and residential rates would continue at the 10% annual rate until PG&E's next BCAP or for up to four years if a BCAP order is delayed. Deaveraging would end after four years absent an additional Commission order.

We concur that accelerating the pace of deaveraging at this time would increase residential rates too much. The gradual approach proposed in the agreement is consistent with past decisions and otherwise reasonable.

Currently PG&E treats large and small core commercial classes as different customer classes. It proposed in this application to combine them into a single class with ten different rate schedules that would vary according to customer demand. ORA opposed the consolidation and proposed a more gradual phase in of additional rate tiers. The Agreement would retain the existing and distinct rate schedules for large and small commercial customers but add three rate tiers for small commercial customers, making a total of five rate tiers. The Agreement would better reflect the costs of serving small commercial customers and we adopt it.

PG&E proposed an updated forecast of gas throughput for the BCAP period for each customer class. Each forecast includes a calculation of marginal demand measures and customers. ORA and the CCC question the forecast of gas throughput for electric generation. The Agreement would apply a total throughput of 742,5445 MDth/year for all customer classes. It would increase the throughput forecast for electric generation to 264,913 MDth/year.

The amount adopted in the agreement is a reasonable compromise. PG&E's last BCAP set rates assuming average year throughput forecast for core customers at 306,965 MDth and noncore (Schedule G-NT) customers at 195,336 MDth.

Because of the delays in PG&E's BCAP filing, rates have been based on this throughput forecast since January 1, 2002, although the forecast was adopted assuming a two-year period. Throughput in recent years has decreased substantially. For industrial distribution rates - where PG&E has no balancing account protection - this disparity between the forecast and actual throughput has hurt PG&E's earnings. The industrial distribution throughput adopted in PG&E's last BCAP was 36,681 MDth compared to actual throughput of 26,422 MDth, a disparity which PG&E states caused it to lose about $8 million last year.

Adopting the throughput forecast presented in the Agreement would result in substantially higher rates. Most significantly, electric generation backbone rates more than double as a result of the change in the throughput forecast and electric generation transmission rates increase by almost 6%. However, the forecasts for each customer class that are the subject of the Agreement are reasonable in light of changes in actual throughput in recent years, and we adopt them.

PG&E recently learned that it has erroneously billed two wholesale customers transmission rates even though at least portions of their services have been provided at the distribution level. In its application, PG&E proposed to remedy this problem, which would increase the transportation rates of these customers by about 200%. The two customers, both facilities owned by West Coast Gas, objected on the grounds that had they known they would be receiving large rate increases, they may have taken action to enable them to continue eligibility at the lower rate.

The Agreement would phase in higher rates to cushion the rate impact on West Coast and to provide West Coast time to "consider its options." West Coast's revenue requirement would increase by 10% a year until PG&E's next BCAP. The shortfall would be allocated to other distribution customers.

PG&E may not unduly discriminate in favor of or against any customer. While we may permit an exception to current ratemaking practices which set forth methods for establishing distribution rates, we must have a strong justification for doing so, especially where the exception would impose ratemaking burdens on others. Here, West Coast is a utility serving residential customers. Increasing its rates to the level that would reflect distribution system costs would increase West Coast's customer bills by a factor of three. The amount of revenue that would be allocated to PG&E's other distribution customers is small relative to their total liability, about $200,000 annually. For these reasons, we adopt the settlement between PG&E and West Coast to limit increases to revenue requirement 10% a year for distribution services.

Unfortunately, neither PG&E nor West Coast explained the circumstances motivating their agreement as part of the record of this proceeding. Instead, we learned of West Coast's status as a utility serving residential customers in comments to the proposed decision and by reviewing a general rate case filed by West Coast. We remind these and all parties that we do not approve settlements just because they are uncontested. The law requires that we affirmatively find utility rates to be reasonable and makes no exception for settlements in this regard. Every settlement must be lawful, consistent with the record and otherwise in the public interest. For that reason, we require justification for settlements. At the very least, information to support the settlement must be in the record of the proceeding.

PG&E's application proposes an update to PG&E's gas transportation balancing accounts every year as part of the annual True-up Advice Letter on January 1 of each year rather than in the BCAP proceeding. PG&E believes the annual true-up would provide consistent rate changes because other rate changes occur on January 1. The Agreement incorporates this proposal.

This change in the timing of reconciling balancing accounts is reasonable and does not appear to create any administrative problems, inequities or inefficiencies.

PG&E proposed several minor modifications to its balancing accounts for gas services as follows.

1. Establish a new account to track revenues from the core customer charge;

2. Recover Canadian costs in the Core Pipeline Demand Charge Account instead of the Purchase Gas Account (PGA);

3. Refund the balance in the Core Subscription Phase-out Account and Core Subscription PGA to former core subscription customers; and

4. Terminate the El Paso Turned-Back Capacity Balancing Account and Noncore Brokerage Fee Account.

Only ORA commented on PG&E's proposals, supporting all of them with one exception. Instead of establishing a new account for the core customer charge, ORA would establish a subaccount of the Core Fixed Cost Account to track revenues allocated on an equal-cents-per-therm basis. The Agreement would have the Commission adopt ORA's recommendation on this item and all of the other account changes PG&E proposes, as follows:

a. Establish two subaccounts under the Core Fixed Cost Account, one for items allocated on an
equal-cents-per-therm basis and another for items allocated on an equal-percentage-of-marginal-cost basis;

b. Recover Canadian costs in the Core Pipeline Demand Charge Account instead of the Purchased Gas Account (PGA);

c. Refund the balance in the Core Subscription Phase-Out Account and Core Subscription PGA to former core subscription customers; and

d. Terminate the El Paso Turned-Back Capacity Balancing Account and Noncore Brokerage Fee Account.

These changes are lawful and mostly ministerial in nature. We take no issue with them and adopt them.

PG&E currently is at risk for collecting noncore distribution revenues based on an adopted forecast. In this application, it proposes to eliminate this risk and receive 100% balancing account treatment for all noncore distribution revenues. PG&E explains that increased market risk and economic volatility justify this change in risk allocation.

The Agreement would adopt a compromise whereby PG&E would be at risk for only 25% of its noncore distribution revenues. Customers would assume the risk for the remaining 75%.

In its brief, PG&E addressed the expressed concerns of the assigned Administrative Law Judge (ALJ) in this proceeding that the matter was pending before the Commission in another proceeding, R.04-01-025, the Gas Capacity Rulemaking. PG&E states that D.03-12-061 invited PG&E to raise the issue of balancing account treatment for noncore distribution revenues in its subsequent BCAP. This proceeding is the subsequent BCAP. PG&E's brief also observes the scope of R.04-01-025 involves transmission capacity, not distribution facilities or rates.

We agree with PG&E that R.04-01-025 is unlikely to address the issue of gas distribution rates or incentives. We also concur that D.03-12-061 anticipated that PG&E could propose a change to noncore distribution balancing accounts in a subsequent BCAP application. This is that proceeding.

PG&E makes a reasonable case that its risk for noncore distribution revenues should be limited. PG&E has little control over noncore throughput and markets have become more volatile in recent years. While these circumstances might not alone be adequate justification for shifting risk to customers, the proposal before us splits the risk between PG&E and its customers by imposing 25% of liability for noncore throughput on PG&E. This is a reasonable compromise and we adopt it.

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