8. Operational Benefits
Operational benefits include (1) the elimination of labor costs currently required for manually turning on or off a customer's electrical usage at the premises; (2) bad debt reduction resulting from earlier collection of outstanding balances and earlier shut-off; and (3) cash flow savings from these earlier collections and shut-off. Also, PG&E has identified a tax benefit from meter retirement that is included under this category of benefits.
8.1. Field Technician Labor Savings
PG&E proposes to install integrated load limiting connect/disconnect switches in the solid state meters for all single phase residential meters with a maximum of 200 amperes (amp). While deployment of these switches could begin in the latter half of 2008, for purposes of its benefits analysis, PG&E expects that activation of these switches will occur once enabled through PG&E systems in July 2009.
Electric field technicians typically perform four types of connect/disconnect services at premises with a single-phase residential meter with a maximum of 200 amps: customer move-out, customer move-in, Shut-off for Non-Payment (SONP), and reinstatement of SONP (RSONP). PG&E estimates that it will realize a total of approximately $6.9 million in incremental operational benefits during 2009 and 2010 that relate to the savings from the elimination of labor costs currently required for manually turning on or off a customer's electrical usage at the premises. That is, PG&E offsets the overall O&M labor savings from the integrated load limiting connect/disconnect switches with the O&M labor savings for the 600,000 disconnect collars it included in the original AMI Application.
No party has challenged either PG&E's inclusion of field technician labor savings as a benefit or PG&E's quantification of these savings. We will include the undisputed amount as part of the benefits adopted by this decision.
8.2. Reduced Bad Debt Savings and Cash Flow
According to PG&E, the integrated load limiting connect/disconnect switches will also help PG&E reduce bad debt and improve the timing of cash flow. Each month, approximately 41,000 PG&E residential customers are eligible to be SONP. Due to manpower constraints, only an estimated 13,000 of these 41,000 SONPs (i.e., 32%) are physically turned off each month by sending a field service representative to the premises. The remaining 28,000 (i.e., 68%) are not shut-off and continue cycling for another month. Further, there are two categories of SONPs: (1) those that ultimately remit the balance due; and (2) those that do not and for whom their owed balance must be written-off as bad debt. Based on historical data, PG&E collects approximately 92.2% of SONP balances; the remaining 7.8% are written off.
For the SONP balances that are ultimately written off (i.e., 7.8%), the benefit of performing the turn-off remotely is that the turn-off is done more quickly, which results in a lower balance to be written-off as bad debt. The incremental benefits of the load limiting connect/disconnect switch vary, however, depending on whether that SONP would have been processed during a given month. PG&E forecasts that it will realize a total of $1.7 million in bad debt savings in 2009 and 2010.
No party has challenged PG&E's inclusion of bad debt savings as a benefit or PG&E's quantification of these savings. We will include the undisputed amount as part of the benefits adopted by this decision.
For the SONP balances that are ultimately collected (i.e., 92.2%), the benefit of performing the turn-off activity remotely is that the turn-off is done more quickly, which results in making a collection sooner. That is, the benefit is the time value of money associated with the collections. PG&E forecasts that it will realize a total of $0.7 million in the improved timing of cash flow in 2009 and 2010.
No party has challenged PG&E's inclusion of these cash flow savings as a benefit or PG&E's quantification of these savings. We will include the undisputed amount as part of the benefits adopted by this decision.
8.3. Tax Benefit from Meter Retirement
Since PG&E proposes to replace all existing electromechanical meters with solid state meters, PG&E will need to retire the existing electromechanical meters. PG&E explains that for tax purposes, there will be a loss on the retirement that will be recognized to the extent that the remaining (i.e., undepreciated) tax basis of the assets exceeds the net salvage value, after subtracting the cost of removal. Since for purposes of this calculation, PG&E assumes that the salvage value and removal costs are approximately equal, the loss on retirement would be equal to the remaining (i.e., undepreciated) tax basis of the asset. The associated benefit is the time-value of money associated with receiving a current deduction for the loss on retirement, instead of waiting for the depreciation deduction over time, based on the tax-life of the asset. PG&E compared the present value of the tax benefit associated with the expected depreciation stream of the assets (assuming they remained in service) with the present value of the tax benefit associated with the expected loss on retirement of assets, to derive a net benefit of approximately $11.8 million.
According to TURN, tax retirement benefits are actually an accounting treatment and not an increase in efficiency or a savings in operational expenses. Essentially, the tax benefits only mitigate the stranded costs that will arise from PG&E retiring all of its existing electromechanical meters. TURN does not consider this to be a "benefit" of the project.
In response, PG&E states that, regardless of the categorization of these benefits, there is no debate regarding the savings to ratepayers that result from these tax benefits. These savings rebound to the benefit of ratepayers through lower requested revenue requirements both in this case and for future proceedings where the tax savings are realized. According to PG&E, whether these tax benefits are categorized as an operational benefit that reduces costs to ratepayers or as an accounting treatment that reduces project costs, the end-result is the same. PG&E argues that TURN's distinction is one of semantics and should be disregarded.
No party has challenged PG&E's calculation of this tax retirement benefit. Whether it is identified as a benefit or a reduction to costs, the net effect with respect to a benefit/cost analysis will be the same, and, in either case, that net effect should considered in evaluating the cost effectiveness of the Upgrade. For the purposes of this proceeding, it is reasonable to include the undisputed amount of this tax benefit as a "benefit," and we will do so.
8.4. Remote Programmability
In rebuttal testimony, PG&E raised the issue of a remote programmability benefit. PG&E states that the upgraded meter and communication device will have enhanced processing, storage, and remote programmability benefits that will allow the meters to be upgraded remotely via a network download. According to PG&E, this type of capability will have tangible operational benefits and presents the following example:62
PG&E states that in the next 20 years we can expect computing power needs at the endpoints to increase at a high rate, and that one of the needs and drivers for this computing power is the issue of data, device and operational security. According to PGE, the upgraded meter and communication devices have the ability to be remotely programmed, much like today's modern computers, and the capability to transmit or implement security or functionality patches will be critical to ensuring a reliable and secure network over time.
PG&E believes the benefits associated with the ability to implement this one capability alone through the remote downloading of the necessary software updates and security upgrades to meter endpoint platforms capable of taking advantage of those downloads are significant. According to PG&E, the benefit arises because the ability to remotely reprogram an advanced meter allows PG&E to avoid the need for a field visit to each meter needing reprogramming.
Based on a cost of about $20 per meter, PG&E estimates the cost of reprogramming all of PG&E's 5.4 million electric meters would be $108 million (nominal). PG&E goes on to state there are several reasons that system-wide software upgrades or patches are likely to be required over the 20-year system life. First, there is the issue of security discussed above. Second, there are likely to be several software updates over the course of 20 years. Seven-year replacement intervals are to be expected for many types of software. Furthermore, in between replacements, software and security patches are frequent.
For these reasons PG&E determines it is reasonable to assume that it would have to perform system-wide software patches or replacements at least every three years. Assuming modest labor escalation and system growth, PG&E estimates the incremental benefit of installing endpoints and systems robust enough to handle these expected upgrades remotely to be at least additional $520 million (PVRR) over the 20-year life.
In its opening brief, PG&E states that the significance of this very important addition to the project should not be overlooked.
DRA indicates that in evaluating this example, one must be clear about what "status quo" reference point is being used to calculate the benefit. According to DRA, the calculation of any benefit is always in reference to some other state. If benefits are to be calculated on an incremental basis relative to the DCSI-based AMI system examined in A.05-06-028, then the reference point is that system. If benefits are calculated on a total basis, including those achievable by the AMI system examined in A.05-06-028, then the reference point is the pre-AMI stock of electromechanical meters with no communications capability.
DRA states that it should be obvious that the pre-AMI meters had no security problems other than a minor amount of energy theft. The meters were mechanical and did not include any components that could be reprogrammed. Hence, no truck rolls were required to change software for the entire stock of meters. DRA also states that the situation is similar with the DSCI system examined in A.05-06-028, since the DCSI system is relatively impermeable to security threats.63 DRA notes that had there been a security problem, the business case evaluated in A.05-06-028 would have had to include an additional $520 million to cover the cost of such truck rolls, adding there was no money included for this purpose.
DRA asserts that PG&E's argument collapses into nothing more than a solution to a problem created by the enhanced functionality added by the AMI upgrade. It was not a problem with the system examined in A.05-06-028, or with the pre-AMI meter stock. Thus this benefit does not belong in the benefits stream.
TURN also asserts that the Commission should reject the use of this benefit for cost effectiveness purposes. TURN first states that the inclusion of this operational benefit in rebuttal testimony is procedurally incorrect as PG&E raised the issue for the first time in rebuttal and the issue was not responsive to any party's testimony. TURN then states that the benefits cannot be justified as an incremental benefit of the SmartMeter Upgrade, since the purported costs could not and were not included in the original AMI application. According to TURN, in order to claim a $520 million benefit of avoiding reprogramming costs, PG&E would have needed to be burdened with those costs in the first place, either before the AMI program ever existed or, at least, as part of the original AMI filing. However, the old electromechanical (non-AMI) meters did not require reprogramming nor did the DCSI electromechanical AMI meters require such servicing.
We agree with DRA and TURN on this issue and will not reflect remote programmability as a benefit in the Upgrade cost effectiveness analysis. As both parties indicate, the need for reprogramming the advanced meters is caused by the added functionality of the programmable meter itself. The $520 million in potential costs are just that. They are potential costs that never existed. They are avoided because the meter that necessitates the costs can accomplish the task remotely. To assign this purported benefit as an incremental benefit in the cost effectiveness analysis of the Upgrade is illogical and inappropriate.
62 See PG&E, Exhibit 8, pp. 3-17 - 3-18.
63 See PG&E, Vahlstrom, 1 RT 133.
