This section addresses the capital expenditures that PG&E plans to incur in 2004 to operate and maintain its gas transmission, storage and gathering system. For 2004, PG&E's forecast of capital expenditures is $143.3 million in 2001 nominal dollars.47 The capital expenditures are used to calculate the cost of service, which is discussed in the next section.
Of the forecasted total for capital expenditures, $60.2 million is for base capital expenditures48 for pipeline related work. The pipeline related work is made up of the following seven Major Work Categories (MWCs):49 (1) Pipeline Safety & Reliability; (2) Work Requested By Others; (3) New Business; (4) Pipeline Capacity; (5) Power Plant Connections; (6) Power Plant Metering Costs; and (7) Pipeline Safety Law.
The 2004 forecast of pipeline related work is almost double the amount of base pipeline related work in 2001. PG&E attributes the increase in spending to primarily two factors: (1) installation of capacity, service extensions, and meters to serve gas-fired power plant demands; and (2) anticipated modifications to PG&E's gas transmission pipeline system in response to pipeline safety legislation.
Much of the assessment required by the Pipeline Safety Act will be accomplished by smart pigging. PG&E estimates that for 2004, the capital expenditures needed will be $11 million, with a continuous investment of $11 million per year from 2005 through 2013.
PG&E estimates that $28.5 million of the forecasted $143.3 million in 2004 capital expenditures will be for base capital expenditures for station reliability,50 and $23.5 million will be for base capital expenditures for environmental work.51 Base capital expenditures for work related to other MWCs52 is estimated at $5 million.
Of the $143.3 million in 2004 capital expenditures, PG&E estimates that non-recurring capital expenditures of $26.1 million will be needed to incrementally expand PG&E's transmission capacity or improve overall system reliability.
As part of the $26.1 million, PG&E proposes to use $2 million to reinforce the local transmission system in order to improve noncore reliability to a 1-in-10 year cold temperature event, as mentioned earlier in PG&E's Winter Reliability Standard proposal. The total cost of reinforcing the local transmission system to meet the Winter Reliability Proposal is estimated at $42 million from 2004 through 2007.
CCC/Calpine claim that the backbone level rate proposal will reduce costs on PG&E's local transmission system by eliminating PG&E's costs of reinforcing local transmission facilities.
PG&E provided estimates of PG&E's capital expenditures for inclusion in plant in service for 2004. These estimates of investments in Power Plant Connections and Power Plant Metering were itemized in Figure 10-2 at page 10-6 of Exhibit 3. As a result of the slowdown in new power plant service extension requests, PG&E's March 2003 update to this testimony reduced the estimates of power plant metering investments from $9 million to $4.8 million for combined years 2003 and 2004. Mirant asserts that it is unclear whether this reduced estimate was incorporated by PG&E in calculating its revenue requirement.
Mirant also asserts that PG&E's proposed Gas Rule 27 could affect future power plant connection and metering costs. PG&E's projections of capital expenditures are substantial, and include $35.8 million for capacity additions and new business connections. Mirant contends that there has not been an adequate accounting and review of these projected capital expenditures.
Mirant also points out concerns regarding PG&E's projections of capital investments on pipeline safety projects. PG&E's Figure 10-2 shows $86.5 million of capital costs in this category for 2001 through 2004. There is also $11 million in 2004 for investments related to the Pipeline Safety Act. Mirant contends that PG&E's witness was unfamiliar with the elements that made up the total.
Mirant is also concerned that PG&E's inclusion in rate base of $80.5 million in non-cycled working gas costs is another example of why rates should not be based on a cost of service study that has not been adequately analyzed. PG&E's witness acknowledged, this was contrary to historical practice whereby PG&E receives only the short-term interest rate on that investment. Although PG&E had been compensated at the short-term commercial lending rate for this working gas, the inclusion of $80.5 million in rate base to earn the authorized rate of return is cause for concern. Since this issue was buried in the cost of service study and the workpapers, and parties have not had an opportunity to study this issue, the Commission must carefully consider whether it should implement rates based on a cost of service study that has not been adequately reviewed.
Mirant recommends that, pending a full rate review for year 2005, rates remain the same, or the Commission should allow no more than the Gas Accord's annual escalation factor of 2.5%. PG&E's cost of service study and the revenue requirement conclusions that flow from the study, should not be implemented until it has been thoroughly reviewed by ORA.
NCGC recommends two changes to PG&E's proposed revenue requirement.
The first change is to reduce the customer access charge revenue requirement by approximately $500,000 for 2004. NCGC contends that this change is needed because of the significant slowdown in new power plant service extension requests, which the customer access charge appears to be premised on. As a result, there should be a reduction in PG&E's rate base, which should reduce the customer access charge revenue requirement. NCGC recommends, at a minimum, that PG&E be required to reduce the customer access charge revenue requirement by $0.5 million in 2004 to reflect the revised projection of power plant metering costs contained in the testimony of PG&E's own cost of capital witness.
The second change that NCGC recommends is to remove the cost of non-cycle working gas from PG&E's proposed rate base. PG&E's total working gas is 100.6 MMdth. Of this total, approximately 60 Bcf of this working gas is non-cycle working gas. The capital cost of the 60 Bcf of non-cycle working gas is $80.5 million, which has been included in rate base for 2004.
PG&E is currently earning the short-term interest rate, rather than the utility authorized rate of return, on the non-cycle working gas. PG&E's current estimate of the 2004 short-term interest rate is 2.37%, based on the April 2003 commercial rate forecast. If this estimate were applied to the total $80.5 million, the annual revenue requirement would be $1.9 million, including the cost of franchise fees and uncollectible account expenses associated with the assumed collection of the revenue requirement in rates.
PG&E is proposing in this proceeding to include the $80.5 million in rate base. If rate base treatment were approved, PG&E would be permitted to earn its full allowed return and associated taxes rather than the short-term interest rate on the $80.5 million. The 2004 estimated revenue requirement associated with the $80.5 million of non-cycle working gas in inventory is $10.7 million, based on PG&E's current authorized cost of capital of 9.24% and on current income tax rates of 35% for federal income taxes and 8.84% for state income taxes. This estimated revenue requirement also includes the cost of franchise fees and uncollectible accounts expenses associated with the assumed collection of the revenue requirements in rates.
NCGC asserts that PG&E has not made any showing in this proceeding that the $80.5 million cost of non-cycle working gas should be included in rate base, and there is no testimony supporting a change from the short-term interest rate treatment. Some of PG&E's testimony implied that PG&E would continue to earn only the short-term interest rate on the gas. For example, in its request that PG&E be permitted to sell 4.5 MMdth of the non-cycle working gas, and that it retain all the gain from such a sale, PG&E noted that it had only received the short-term interest rate on the gas. NCGC asserts that it is contradictory for PG&E to propose rate base treatment for non-cycle working gas while simultaneously arguing that it should be permitted to retain the full gain on sale because the gas earns only short-term interest.
NCGC also points out that PG&E earns revenues by loaning non-cycle working gas to customers, which is a hub service. This is also contradictory because it allows PG&E to recover its allowed return on non-cycle working gas while simultaneously recovering incremental revenues by lending the gas to third parties.
Absent a showing that rate base treatment for the non-cycle working gas is appropriate, NCGC contends that PG&E should not be permitted to earn its allowed return and associated taxes on the capital cost of its non-cycle working gas in 2004.
Palo Alto is opposed to the Winter Reliability Standard, and raised concern over the accuracy of the capital expenditures estimate proposed by PG&E for the upgrade of local transmission to meet the 1-in-10 year reliability standard.
Palo Alto concurs with the various recommendations of other parties to adjust PG&E's capital expenditures for the non-cycle working gas, the costs associated with the Gerber Compressor Station, and to reduce power plant metering costs.
The Gerber Compressor Station burned down on November 6, 2001. PG&E replaced the facility, including the gas turbine compressor unit, at a total cost of $35.8 million. The Gerber station was operated remotely from a location over a hundred miles away. The fire was caused by a crack on a nozzle which broke when the unit was starting up, igniting 200 gallons of lubrication oil.
Although TURN has not had time to fully examine all the data and information related to the fire, PG&E's documents raises questions about the cause of the accident, whether the nozzle crack could have been prevented, and whether plant operation practices may have exacerbated the fire.
TURN recommends that the rates covering return, depreciation and taxes on the Gerber station replacement, approximately $6 million, be subject to refund. TURN recommends that a second phase of this proceeding be established to conduct a prudence investigation regarding the cause of the accident that led to the fire, and the operating conditions that allowed the fire to burn down the building.
TURN also points out the potential for a significant insurance recovery, even though PG&E's insurance policy has a deductible of $25 million. TURN recommends that 90% of any insurance recovery be flowed through to ratepayers immediately as a reduction to rate base. The remaining 10% of the insurance recovery should ultimately be used to reduce rate base, but PG&E should be allowed to hold this 10% until the next gas rate case as an incentive to pursue insurance recovery.
PG&E asserts that is has presented sufficient evidence to support its capital expenditures proposal.
Palo Alto raised concerns over the accuracy of the capital expenditures estimate proposed by PG&E to upgrade its local transmission to meet the 1-in-10 year reliability standard. PG&E demonstrated in its rebuttal testimony that the scope and list of projects did not change from January 16 to March 18, 2003. PG&E merely revised the installed unit cost ($/ft) to reflect current pipeline installation costs.
TURN proposes that the Commission conduct a prudence investigation into the cause of the fire that destroyed the Gerber gas turbine compressor unit. PG&E contends that a prudence investigation is not warranted because its actions at all times, were prudent, and within the applicable laws, regulations and industry standards.
CCC/Calpine claim that the backbone level rate proposal will reduce costs on PG&E's local transmission system by eliminating PG&E's costs of reinforcing local transmission facilities. PG&E says that this argument of CCC/Calpine assumes that every new customer will be physically connected to PG&E's existing local transmission system, which may not be the case.
Several parties recommend adjustments be made to PG&E's forecast of capital expenditures for 2004. The five proposed adjustments address the following areas: (1) non-cycle working gas; (2) Pipeline Safety Act; (3) Winter Reliability Standard; (4) reduction in metering costs and power plant costs; and (5) the Gerber Compressor Station.
In just several lines of text in PG&E's prepared testimony, without mention of the rate base amount of $80.5 million,53 PG&E seeks to change the way in which it is compensated for non-cycle working gas that is used in its storage operations. Instead of earning the short-term interest rate on the non-cycle working gas, PG&E seeks to change the treatment in 2004 to obtain a return on rate base of $80.5 million.
As Mirant points out, this is one reason why careful analysis of the capital expenditures and other costs contained in PG&E's application are required. Although PG&E's request is buried in two places in its text, PG&E does not describe the revenue effect that this change in treatment will have. Had it not been for the cross-examination of PG&E's witness by NCGC's counsel, this issue might have gone unnoticed. Interestingly, PG&E did not comment on the rate base treatment of the non-cycle working gas in either its opening or reply briefs.
NCGC correctly points out that PG&E's position regarding its non-cycle working gas is contradictory. On the one hand, PG&E seeks to sell 4.5 MMDth of non-cycle working gas, for which it says it earned the short-term interest rate on, and to retain all of the proceeds. On the other hand, PG&E seeks to have ratepayers pay PG&E for a rate of return on the same kind of non-cycle working gas. PG&E cannot have it both ways. PG&E has not justified why the treatment of its non-cycle working gas should be changed in 2004.
It is appropriate, therefore, to adjust PG&E's forecast of capital expenditures for 2004 by removing the entire $80.5 million of non-cycle working gas from rate base. This adjustment is reflected in Table 2 of Appendix A.
PG&E expects that the Pipeline Safety Act will result in required assessments of its transmission facilities. PG&E forecasts capital expenditures of $11 million per year starting in 2004 through 2013.
As noted in the O&M section, the work required to comply with the Pipeline Safety Act will occur. However, the deadlines for starting the work do not occur until June and December of 2004.54 Since we do not anticipate that the major part of the work effort will begin until the second half of 2004, as discussed earlier, it is appropriate to adjust the capital expenditure of $11 million in 2004 to reflect six months of work. That is, the rate base for 2004 should be reduced by $5,500,000. This adjustment is reflected in Table 2 of Appendix A.
The amount of $2 million has been included in the 2004 forecast of capital expenditures to upgrade the local transmission facilities to meet PG&E's proposed Winter Reliability Standard. PG&E had forecasted that the capital expenditures for the local transmission upgrade project would amount to a total of $42 million for 2004 through 2007.
Since we do not adopt PG&E's proposal for a Winter Reliability Standard, the capital expenditure in 2004 of $2 million is not needed. The $2 million that PG&E forecasted shall be removed from PG&E's forecast of capital expenditures for 2004. This adjustment is reflected in Table 2 of Appendix A.
In Exhibit 3 at pages 10-8, PG&E testified that:
"A significant slowdown has occurred in new power plant service extension requests. As a result, cost estimates for MWC 91 are anticipated to drop to $1.5 million and $3.3 million in 2003 and 2004, respectively."
Further down on page 10-8 of Exhibit 3, PG&E notes that "Requests for new business power plant connections have dropped off significantly since mid-2002."
Several of the parties believe that the customer access charge should be reduced because of the reduced number of new power plants. Mirant noted that it was unclear whether the reduction noted at page 10-8 of Exhibit 3 had been incorporated by PG&E. Reading PG&E's testimony at page 10-8 of Exhibit 3 at lines 7 and 8, and 22-23, in conjunction with the cross examination of PG&E's witness, it is clear that a reduction has not been made for Power Plant Metering, MWC-91. In accordance with PG&E's own testimony, the forecast for 2004 for this item should be reduced from $5.1 million to $3.3 million. PG&E shall reduce its forecasted rate base by $1.8 million. This adjustment is reflected in Table 2 of Appendix A.
Since Power Plant Connections are related to new customers coming onto the system,55 we believe that a similar reduction should be made to the 2004 forecast of Power Plant Connections. Although PG&E's witness testified that the Power Plant Connections reflect the downturn in new power plants, pages 16 and 17 of Exhibit 42 suggest that the amount of $5.4 million may be "a placeholder for speculative new power plant connections." (7 RT 662-663.) Accordingly, the capital expenditure for Power Plant Connections for 2004 shall be reduced from $5.4 million to $3.5 million.56 This adjustment is reflected in Table 2 of Appendix A.
PG&E has included in its forecast of 2004 capital expenditures $35.8 million for the Gerber Compressor Station. TURN questions whether this amount should be in rate base at all, but suggests that the 2004 rates include the return, depreciation and taxes on the Gerber Compressor Station, approximately $6 million, and the amount be subject to refund in a separate prudence investigation.
TURN also raised the issue that there may be a significant insurance recovery associated with the fire. Although the deductible on the insurance is $25 million, there may be proceeds from an insurance claim that ratepayers have an interest in.
PG&E contends that no prudency investigation is needed, and that it should be permitted to include the Gerber Compressor Station into rate base. PG&E does not mention the possible insurance recovery in its briefs.
We believe that the insurance recovery issue is an issue that we should explore. PG&E has not explained whether it has filed a claim for insurance, the status of such a claim, and how it would apply any insurance proceeds. The recovery amount could be as high as $10 million.
Whether or not the Commission should look into the prudency of PG&E's actions with respect to the fire at the Gerber Compressor Station, shall be determined in the proceeding we will order PG&E to file.
In order to determine the status of possible insurance claims with respect to the fire at the Gerber Compressor Station, what should be done with any insurance proceeds, and whether the Commission should look into the actions of PG&E with respect to the plant fire, we will order PG&E to file an application within 90 days of today's date to address those issues. The scoping memo in that proceeding will determine whether the request for a prudency hearing is needed.
We will adopt TURN's request to establish a memorandum account to track all the revenues that PG&E receives in rates for the Gerber Compressor Station, and all the proceeds PG&E may receive from any associated insurance claims, plus interest, and to make those revenues subject to possible refund to ratepayers. PG&E shall file an advice letter filing to establish this memorandum account. The disposition of this memorandum account shall be decided in the proceeding in which PG&E's application will be filed.
We adopt PG&E's forecast of its capital expenditures for 2004, less the adjustments we have made. PG&E shall file its application regarding the Gerber Compressor Station issues, and shall file an advice letter to establish the memorandum account.