4. Net Costs/Benefits of Expediting DWR's Removal as Supplier of Power
4.1. Framework for Assessing Net Cost/Benefits
As a basis to determine whether a directive for DWR and the IOUs to proceed with contract negotiations to remove DWR from its role as power supplier is in the public interest, we must consider whether, or to what extent, such efforts are justified by resulting in net benefits to ratepayers.
In order to provide a common reference point for evaluation of parties' estimates of the cost or savings impacts of removing DWR from its role of supplying power, parties were directed to assume a range of different target dates for completing all necessary contract negotiations. Because each of the DWR contracts expire at different points in time, and because certain contracts represent a disproportionate share of impacts, the assumed date for completion has a significant bearing on the assumed costs and savings expected to result on a discounted net present value (NPV) basis. These assumed target dates are January 2010, July 2010, July 2011, and October 2012.
The extent of net savings depends in large measure on how rapidly DWR can end its role of supplying power. The longer it takes to finalize and implement DWR's final exit from the power supply function, the more DWR contracts in effect now simply expire automatically due to the passage of time. Any estimate of costs/benefits thus excludes any DWR contracts that simply expire without the need to implement contract novation or renegotiation.
DWR submitted preliminary estimates of the net impacts of contract novation at the June 2, 2008 workshop. These estimates were considered in further written comments and at a follow-up workshop on July 1, 2008 and July 2, 2008. By comments filed on August 4, and 19, 2008 parties had the opportunity to submit their own estimates of net costs/benefits of undertaking to accelerate the removal of DWR from its role as supplier of power.
The three IOUs each submitted separate estimates of the net impacts of DWR contract novation applicable to their own customer base, and did not dispute or challenge the corresponding estimates made by other IOUs. Accordingly, we consider the IOUs essentially to be generally in agreement among themselves as to the sum total of net savings estimates based on the assumption that all remaining DWR contracts are novated or renegotiated by the designated target dates. In presenting their estimates, however, the IOUs caution that they are predicated on achieving full novation or other replacement of all DWR contracts by certain dates. The IOUs express doubts, however, as to whether such a goal is likely to be achieved.
SCE estimates net savings for its customers, based on an assumption of novation of all remaining DWR contracts on an "as is" basis, with no change in the permanent cost allocation methodology for DWR costs. SCE believes that the assumption of full novation on an "as is" basis may eventually prove unrealistic due to issues such as the PG&E bankruptcy settlement and counterparties' desire to renegotiate certain terms of DWR's contracts in the novation process. Nonetheless, SCE applies these assumptions in order to calculate the cost effectiveness of full novation. To estimate the costs or benefits of only a partial novation, SCE indicates that further information from DWR would be needed, although SCE believes that the net benefits would be diminished somewhat. Although a partial novation may reduce administrative costs incurred by DWR, such reductions would not likely follow a linear relationship with the reduction in contracts being administered. SCE notes that a partial novation would still likely require DWR to incur a significant share of its existing administrative costs even if a small number of contracts continue to be administered by DWR.
PG&E likewise calculates a net benefit for customers based on the assumption that all contracts could be novated by January 1, 2010. PG&E cautions, however, that the calculation of net benefits "may easily become a cost if certain assumptions change."12 PG&E indicated that it was unable to quantify certain costs, such as those resulting from contract renegotiation.
While the IOUs express doubts as to the likelihood of achieving full removal of DWR from all obligations under its contracts by the assumed completion dates, each of the IOUs estimate positive net benefits for ratepayers, to the extent they are able to measure the relevant impacts.
The only other parties to present a comprehensive estimate of net benefits were Reliant and AReM/CACES. These two parties each estimated significantly higher net savings to ratepayers than did the IOUs. Reliant presented a summary table comparing parties' estimates of costs and savings, as summarized below:13
Comparison of Parties' Costs/Benefits Assuming DWR Contract Novation as of January 2010 ($NPV Millions)
The IOUs, DRA, CFC, and TURN argue that the Commission should reject Reliant's and AReM/CACES's estimates of net benefits as exaggerated. DRA claims that the estimates of Reliant and AReM/CACES downplay potential costs and exaggerate potential benefits. As a result, Reliant provides estimates of net benefits that are nearly three times the total IOU estimate, and AReM/CACES provide estimates that are over 4.5 times the total IOU estimates, assuming full novation in 2010. DRA believes that the IOU estimates are more reasonable estimates of benefits assuming 100% novation.
DRA presented a modified table comparison assuming adjustments are made to exclude certain claimed savings assumed by AReM/CACES and Reliant. Making these adjustments (shown as shaded areas) brings Reliant's and AReM/CACES numbers much closer to the IOU estimate. DRA cautions that even these estimates may not accurately reflect the true potential net costs/benefits, and argues that the estimates relied on by the Commission should be as accurate as possible assuming a 2010 full novation scenario is achievable.
Comparison of Parties' Costs/Benefits Assuming DWR Contract Novation Completed as of January 2010, Adjusted for Disputed Costs and Benefits
($NPV Millions)
We recognize that there are various uncertainties associated with the precision and reliability of the estimates, and evaluate them taking into account their inherent limitations. The net benefit estimates are subject to uncertainties beyond whether (or how quickly) acceptable replacement contracts could be implemented. The estimates are also sensitive to changing conditions in the financial and natural gas markets over time. For example, since parties' estimates in this proceeding of savings from the early release of operating reserves were calculated, DWR has updated the estimates of required reserves in its Revised 2009 Revenue requirements Determination transmitted to the Commission on October 29, 2008. As fluctuations occur in the level of required reserves over time, the assumed benefit to customers resulting from the early release of those reserves will likewise fluctuate. The precise impacts can only be determined at the time that an early release of reserves actually occurs.
Moreover, there are possible benefits as well as costs from replacement of DWR contracts that cannot currently be estimated. For example, the disposition of existing contract claims or counterclaims relating to DWR contract disputes could have an impact, assuming such disposition were linked to acceptance of a replacement contract, or other concessions in prices or terms sought by a supplier as a condition of a replacement contract. We make no prejudgment as to such matters here. Replacement contracts will not become effective in any event until or unless reviewed and approved by the Commission.
Given the uncertainties and sensitivity of the estimates to changing conditions, DWR states that a periodic true up of the estimates would be useful to keep the analysis of benefits up to date. We agree, and shall make provision for appropriate updating of the net benefits analysis in Phase II (a)(2).
Moreover, we are not relying upon the estimates to set rates or revenue requirements, but are simply considering the estimates as an approximate benchmark to assess the merits of whether continuing support of novation or other negotiations of DWR contracts have a reasonable potential to benefit ratepayers.
As discussed below, we conclude that the combined estimates presented by the IOUs represent a reasonable benchmark of potential net benefits to be realized assuming the process of removing DWR as a supplier were to be completed by January 1, 2010. We decline to rely upon the higher estimates offered by Reliant and AReM/CACES, in view of the speculative nature of certain assumptions underlying their estimates. We conclude, however, that the potential for net benefits, as estimated by the IOUs, provide a sufficient basis for going forward with further efforts to reach the goal of relieving DWR of its current contract obligations by January 1, 2010.
As explained above, however, we recognize the potential risks that DWR may not be relieved of all of its contract obligations by January 1, 2010. While the potential net benefits estimates are imprecise and subject to changing conditions over time, we do not view the imprecision or sensitivity of the estimates as a reason to abandon efforts to achieve ratepayer benefits through early release of DWR from its contracts. Nonetheless, the potential for benefits justifies going forward to attempt to meet this goal, provided that appropriate monitoring is employed, as discussed in Section 6 below, to ensure that provision is available to make adjustments and revise strategies on a timely basis in response to negotiations and changing conditions in financial or energy markets that may affect potential benefits. We will consider the effects of any updated estimates of net benefits in Phase II (a)(2), as noted above.
We conclude, however, that a positive net savings to ratepayers is still a reasonable prospect, even assuming a date later than January 1, 2010 for completing the process. Positive net benefits are still estimated by the IOUs, albeit at more modest levels, as the assumed target date for final completion of the DWR contract replacement process extends. For example, if we were to extend the target completion date to October 2011, the IOUs' estimates still reflect net benefits, but are reduced to approximately $58 million, calculated as follows:
IOU - Estimated Costs/Savings Assuming DWR Contract Novation | ||||
PG&E |
SCE |
SDG&E |
Total | |
Novation Costs |
||||
Debt Equivalency |
$ 8.00 |
$ 0.90 |
$ 1.30 |
$ 10.20 |
Utility Collateral 14 |
$ |
$ |
$ 0 | |
Letters of Credit |
$ |
$ 0 | ||
Working Capital |
$ 0.10 |
$ 0.10 | ||
Administrative Costs |
$ 0.80 |
$ 0.08 |
$ 0.20 |
$ 1.08 |
Total costs |
||||
| ||||
Novation Benefits |
||||
Release of DWR Reserves |
$ 24.00 |
$ 31.50 |
$ 7.00 |
$ 62.50 |
Administrative Cost Savings |
$ 5.00 |
$ 1.90 |
$ |
$ 6.90 |
Total Benefits |
$ 29.00 |
$ 33.40 |
$ 7.00 |
$ 69.40 |
Net Benefits/Costs |
$ 20.20 |
$ 31.32 |
$ 5.50 |
$ 58.02 |
Source: Opening Comments of PG&E, SDG&E, and SCE (August 4, 2008)
DRA also presented a table of IOU estimates assuming that all then-remaining contracts are novated in July 2012, as shown below:
IOUs' Estimated Costs/Benefits Assuming DWR Contract Novation
Completed as of July 2012 ($NPV Millions)
As shown in this table, the total IOU estimated net benefits are still positive, but less than a quarter of the net benefits assumed if all contracts are novated in January 2010. DRA argues that the $30.5 million NPV benefit has a fairly small margin of error considering the magnitude of the potential costs and benefits that turn on the assumptions made (i.e., contracts novated "as is," all contracts are novated, etc.) Additionally, the transaction costs of the novation process - which TURN and CFC previously estimated to be in the millions15 - are not reflected in these estimates. DRA argues that the Commission must carefully consider potential reductions in net benefits from achieving only partial novation, in addition to potential transaction costs associated with the novation process.
Although the net benefits shown in the Table are significantly lower assuming a 2012 end date, the risks of having to deal with renegotiation of the Sempra and Coral contracts would also be avoided by extending the time horizon to July 2012. By that date, the Sempra and Coral contracts would expire and would no longer pose an impediment to removing DWR from its role of supplying power. We thus conclude that while any estimates are subject to uncertainties of changing conditions in the financial and energy markets over time, some potential for benefits is still estimated by the IOUs assuming complete removal of DWR from its role as power supplier for all remaining contracts, even limiting novation or renegotiation only to DWR contracts expiring after July 2012.
We next consider the categories of potential costs and savings that have been identified by parties, as a basis to assess whether the likelihood of overall net benefits are sufficient to justify continuing to the next stage of this proceeding.
4.2. Potential Categories of Savings
DWR maintains a certain level of operating reserves associated with its contracts, to cover any unanticipated costs and to manage cash flow volatility. Once a contract expires, the reserves associated with that contract can be released and credited back to ratepayers as a cost reduction. If a contract was novated, thereby removing DWR as a party to the contract, however, the reserves associated with that contract could be released early, rather than waiting for the original contract expiration date. The magnitude of the resulting savings is a function of the time value of money associated with accelerating the releasing of the reserves due to novation of the contracts as compared with the existing contract expiration dates.
DWR calculated the expected net present value savings from the early release of reserves at $145 million, assuming a release date of January 1, 2010. CACES accepted DWR's estimate. The IOUs similarly computed a savings of $145.6 million under the same assumption. Reliant calculated an estimated benefit of $156.3 million.
The IOUs also provided estimates of the savings from early release of reserves assuming later dates for releasing remaining contract reserves. The estimated savings from early release of reserves declines as the release of reserves is projected to occur later in time. The declining savings is also attributable to the fact that fewer DWR contracts continue in effect as time passes. Consequently, the savings decline in relation to the reduced amount of reserves remaining to be released early.
The principal point of controversy over savings from the early release of reserves has to do with the underlying timing of when the existing contracts could be novated or otherwise terminated through renegotiation. Accordingly, we accept the IOUs' estimates of savings of $145.6 million as a reasonable benchmark, but recognize that the likelihood of achieving savings from the early release of reserves will depend upon the progress toward meeting the January 2010 target goal. As noted above, we also recognize that the amount of savings from early release of reserves will vary as a function of changes in the natural gas market over time. As noted by DWR, parties' estimated savings from early release of reserves calculated for this proceeding were prepared prior to DWR's most recent update of its revenue requirement for 2009. The actual savings to be realized from early release of reserves will depend upon conditions in effect when a given contract is actually replaced. Yet, even if the target goal is extended to 2012, there are still estimated savings from early release of reserves, based on the assumptions underlying the IOUs' calculations in the amount of $37.2 million.
Parties are in dispute as to whether any potential savings could be expected by renegotiating contracts, and the amount of such benefit, if any. Two parties, AReM/CACES and Reliant, assert a potential benefit from renegotiating the DWR contracts on more favorable terms. As a potential indication of potential benefits from such renegotiation, AReM/CACES point to the benefits that DWR previously obtained through the renegotiation of contracts. Through the end of 2003, DWR renegotiated 35 contracts for an estimated savings of $7.5 billion, representing a 17.5% savings over the life of those contracts. AReM/CACES estimate that if the same percentage of savings were to be achieved for the remaining contracts, the resulting savings would be $1.6 billion. Even if only a fraction of the savings from previous contract negotiations could be achieved, AReM/CACES argue that the savings could still be substantial, and that a savings percentage as low as 0.3% could offset the net costs that DWR initially calculated to result from contract novation.
Reliant estimates that $182 million in net savings could be realized through renegotiation, based upon the lowest savings achieved in DWR's previous negotiations.
Other parties disagree, characterizing the Reliant and AReM/CACES claims of savings from renegotiation of DWR contracts as "unrealistic and highly speculative". DRA argues that the negotiation of improved terms of contracts that have already been achieved are not indicative of the prospects for similar success with the remaining contracts. Those earlier contracts were renegotiated as part of a settlement agreement that was reached in the context of pending litigation. DRA notes that there has been no settlement of the litigation over DWR's contracts with Sempra, Coral, or PacifiCorp, and that there is no basis for assuming that comparable savings could be achieved by another round of negotiations.
We recognize that a possibility may exist that customer benefits may be realized through the negotiation of replacement agreements to include more favorable prices or other terms, at least in some instances. The amount of-and prospects for-such savings, however are too speculative to rely upon as a basis for estimating a net benefit for purposes of our evaluation here. We agree that the market environment in which past DWR contracts were amended is not necessarily indicative of the environment in which prospective contract amendments may be negotiated. Accordingly, while we expect DWR, in conjunction with the IOUs, to negotiate in a manner that is in the ratepayers' best interests, we find insufficient basis at this point, to speculate as to what the substance of the negotiations will be, and as a result, to quantify an estimate for savings from contract negotiations. Accordingly, we will assume no savings associated with this factor for purposes of our analysis here.
Reliant argues that benefits will result from novation because as a result thereof, the statutory prerequisite for lifting the AB 1X rate cap will have been met. Reliant estimates that with the rate cap lifted, the IOUs will be able to offer residential customers with the ability to respond to price signals by way of time-varying rate structures, such as time-of-use pricing, which would otherwise be precluded by the AB1X rate cap. Reliant estimates $8.32 million in savings (assuming a January 2010 novation date) resulting from the IOUs being able to institute statewide residential time-of-use pricing. DRA disputes the claimed potential benefits from price-responsive load.
DRA challenges Reliant's claim that novation of the DWR contracts would result in the immediate lifting of the residential rate protection required by AB1X. SCE likewise argues that it remains very much in question as to whether the rate cap will be lifted in the near term, or concurrently with the novation of DWR contracts.
The disposition of this issue was before the Commission in the SDG&E General Rate Case proceeding (A.07-01-047). In D. 08-11-030 issued in that proceeding, the Commission concluded that a further record is required before the AB 1X rate cap issue can be decided. For purposes of this proceeding, it remains uncertain as to when the AB 1X rate cap could be lifted.
SCE further argues that even under the existing rate cap, residential customers can elect to be placed on a time-based rate structure, and thus, novation would offer no incremental benefit associated with customers' ability to respond to price signals.
We will not recognize any effects from customers' ability to switch to a price-responsive rate structure as a source of savings attributable to a DWR contract novation. As noted by SCE, residential customers can elect to be placed on a time-based rate structure already. Moreover, any presumed benefits attributable to the lifting of the AB1X rate cap would depend upon subsequent Commission action as to when the AB1X rate freeze may be lifted. Because disposition of this issue is uncertain, we cannot attribute any savings based upon speculation as to how the issue will ultimately be decided.
DWR argues that the IOUs have the information and expertise to manage power contracts more efficiently than DWR, taking into account the efficiencies associated with integrating the contracts into their own IOU portfolios.
AReM/CACES argue that while the specific savings from operational efficiencies and purchasing strategies is difficult to assess, even a small percentage reduction in costs would yield significant savings. Assuming only a 2.5% reduction in the $6.7 billion variable costs of the DWR contracts, AReM/CACES calculate a net present value savings of $169 million through 2015.
Other parties, including DRA and the IOUs, dispute the alleged savings of $169 million from greater operational efficiencies if the DWR contracts are integrated into the IOU portfolios, arguing that such an estimate is speculative. SCE argues that no quantified amount should be attributed as portfolio management savings beyond a general characterization as a potential benefit.
We recognize that a possibility may exist of customer benefits as a result of efficiencies from the IOUs taking over full responsibility for managing power resources that are currently under contract with DWR. We agree that the amount of savings of $169 million suggested by AReM/CACES is too speculative to be relied upon for purposes of our analysis here. Accordingly, while we recognize the possibility of such savings in theory, we will not assume any specific figure for purposes of assessing whether the potential net benefits are sufficient to justify going forward with a program for contract novation.
4.3. Potential Categories of Cost
One potential cost associated with the IOUs taking over financial responsibility for the DWR contracts involves "debt equivalence" impacts. In this context, "debt equivalence" (or "imputed debt") is a tool used by credit rating agencies to assess potential financial risks associated with a utility's power purchase agreement (PPA) obligations.16 The above-market costs of any resulting PPA obligations would be treated as imputed debt by the credit-rating agencies and would impact the IOUs' cost of capital.
Various parties contend that in order to avoid a downgrading of the IOUs' credit rating resulting from taking over the DWR contracts, the IOUs will require additional equity to offset this "debt equivalence." DWR initially calculated that based on an assumed novation of its entire portfolio (with other contract terms unchanged) as of January 1, 2009, would add $532 million in debt equivalence for all three IOUs. The extent of costs attributable to satisfying debt equivalence requirements is a function of the number of DWR contracts that would be novated.
PG&E estimates debt equivalence costs based upon a risk factor of 25%17 and discounted at PG&E's authorized cost of debt (6.05%). The debt equivalence costs represent the cost of equity needed to maintain PG&E's equity ratio of 52% less the savings on interest associated with debt replaced by the additional equity. PG&E derived the present value of the additional debt equivalence costs, by applying a 7.66% discount rate (representing PG&E's after-tax weighted cost of capital).
SCE and SDG&E also presented estimates of the funds required to satisfy debt equivalence based on their incremental costs of capital, and the forecast of fixed payments as provided in the DWR workshop materials.
Reliant argues that as a result of DWR contract novation, it is unlikely that any significant debt would be imputed to the IOUs by the credit rating agencies. Reliant also claims that any impact on the key credit ratios of the IOUs would be minimal. For purposes of its analysis, Reliant assumes a 25% risk factor, which is the factor currently used by Standard & Poor's (S&P). The IOUs likewise applied a 25% risk factor in their calculations.
AReM/CACES argue that it is inappropriate to consider debt equivalence as a cost associated with the power purchase agreements that would be taken over by the IOUs through novation. AReM/CACES point to D.07-12-052 in which the Commission found that "[debt equivalence] in and of itself, is not a cost that the utilities incur by entering into a [power purchase agreement (PPA)]."18 Therefore, the Commission ruled that "IOUs may no longer apply a [debt equivalence] `bid adder' as a bid evaluation tool when evaluating PPAs."19
SCE disputes the claims of Reliant and AReM/CACES, arguing that D.07-12-052 merely disallowed the use of the debt equivalence "bid adder" in the evaluation and comparison of bids in a competitive solicitation. SCE argues, however, that the novation of DWR contracts does not fall under the same competitive bid evaluation framework. SCE further argues that D.07-12-052 did not restrict the IOUs from requesting mitigation of debt equivalence in cost of capital proceedings.
AReM/CACES further argue that the DWR calculation of debt equivalence is overstated because it includes the effects of contracts with terms shorter than three years. AReM/CACES claim that S&P only considers contracts with terms exceeding three years for purposes of imputing debt equivalency. By excluding contracts with terms shorter than three years, AReM/CACES calculates that the debt equivalency costs decline from $159 million to just $12 million. SCE notes, however, that S&P no longer excludes contracts under three years in duration for debt equivalency imputation, and that it is therefore appropriate to include such contracts in the calculation of debt equivalency costs.
We agree that the costs of debt equivalence constitute a relevant cost to be considered in assessing the extent of any net benefits to ratepayers from novation of the DWR contracts. The Commission noted in D.07-12-052 that:
"debt equivalence is one of several considerations that rating agencies factor into their assessment of a utility's overall risk profile. The Commission considers the rating agencies' credit ratings in the cost of capital proceeding and thus considers debt equivalence when it determines the IOUs' cost of capital."20
Although the Commission excluded debt equivalence for purposes of evaluating PPA bids received in utility request for offers, the Commission explained that such exclusion
"in no way presupposes any related cost recovery, or adjustments to capital structures in future cost of capital proceedings. We continue to direct the IOUs, especially SDG&E, to raise any individual concerns it has with the impact of a particular PPA on its debt to equity ratio in its Cost of Capital proceeding."21
Accordingly, debt equivalency is a relevant cost in assessing the potential for any net benefits associated with IOUs taking over additional power contract obligations as a result of novation. We view the estimates of the debt equivalence as calculated by the IOUs as an upper bound, and incorporate them into our analysis as an offset to potential net benefit with that understanding.
We reject the lower estimates of debt equivalency by AReM/CACES which are based on exclusion of DWR contracts shorter than three years. We agree with SCE that inclusion of such contracts is appropriate based upon current rating agency guidelines for computing debt equivalency.
We also recognize, however, that the cost impacts of debt equivalence would only be incurred if a contract was successfully novated and a replacement contract was taken over by one of the IOUs. Conversely, if negotiations for a given replacement contract do not result in a successful outcome, there will be no replacement contract and, consequently, no additional costs attributable to debt equivalence. As a result, because debt equivalence costs would be incurred only if, or to the extent that, replacement contracts were successfully executed, any debt equivalence costs would be accompanied by the early release of DWR operating reserves, as discussed previously. While we have not separately isolated the debt equivalence costs and operating reserve savings for each separate contract, in the aggregate, the estimated savings from the early release of DWR operating reserves is almost three times greater than the estimated debt equivalence costs. Therefore given this mathematical relationship, it is reasonable to conclude that, on average, any additional debt equivalence costs associated with taking over a given replacement contract could be more than offset by savings from the early release of operating reserves.
DWR is not currently required to post collateral and does not incur costs of posting collateral or for maintaining a credit facility for potential collateral. DWR estimates, however, that if a replacement contract were assigned to an IOU pursuant to a DWR contract novation, and the replacement contract reflected an above-market price, the IOU would likely be required by the contracting counterparty to secure a letter of credit or collateral as protection against the risk of default. DWR provided an estimate of credit collateral costs of $15 million on a net present value basis over the remaining contract portfolio life. DWR also estimated an additional $6 million would be required to secure a line of credit to cover liquidity in a potential "stress case" scenario, assuming an annual liquidity facility cost of 125 basis points. The "stress case" collateral would cover increased costs until rate relief became available as provided for under the Energy Resource Recovery Adjustment (ERRA) trigger mechanism. SCE estimates, however, that if contract terms changed and SCE was required to post collateral, SCE would incur costs for both current collateral and stress case collateral to cover the risk of default on the contract.
1. Current Collateral - SCE estimates that it would incur an annual cost of $1.25 million based on an assumed cost of 125 basis points for a Letter of Credit for every $100 million of Mark-to-Market (MTM) exposure.
2. Stress Case Collateral - SCE estimates that it would incur an annual cost of $250,000, assuming 25 basis points for credit capacity for every $100 million of potential MTM exposure.
Parties' assumptions regarding collateral cost were made prior to the current credit crisis. SCE explains that credit costs have increased dramatically since that time. Based on the assumption that SCE would take over replacement contracts through a novation of DWR contracts "as is," however, SCE did not calculate any specific cost figure for the posting of collateral. In comments on the Proposed Decision, SCE indicates that the removal of any SCE estimate for collateral costs from the calculation of net benefits would accurately reflect its assumptions under the scenario of novation of all DWR contracts "as is." SCE strongly doubts, however, that all DWR contracts can in fact be novated "as is," particularly by January 2010. If contract terms changed materially as a result of negotiation of a replacement contract with an IOU, moreover, SCE expects that it would be required to post collateral.
PG&E estimated a cost for a line of credit needed to satisfy collateral requirements assuming: (1) there is no line of unsecured credit from the counterparties; (2) PG&E is required to post collateral for 60 days of deliveries; (3) the collateral costs are averaged over a 12-month period; and (4) lenders require 35 basis points to post a letter of credit. Given these assumptions, PG&E estimated costs of $700,000 for letters of credit on a net present value basis assuming completion of the contract replacement process by January 2010. Assuming a date of July 2010 for completion of DWR contract replacement, PG&E estimated a cost for letters of credit of $500, 000. The cost estimate for letters of credit would continue to decline as the assumed completion date is extended.
AReM/CACES question the need for an IOU to post collateral since the recovery of contract costs from ratepayers is assured through the Commission's approval of the contract. Reliant argues similarly that it may be possible to avoid collateral costs, and that Commission action to guarantee a stream of payments from the IOUs to the counterparties may alleviate any need for additional credit posting. Reliant agrees that each IOU may need to secure a letter of credit to cover its costs in the event that it under collects revenues relative to costs by less than the 5% trigger afforded under its Energy Resource Recovery Account. Reliant estimates a stress-case collateral for all three IOUs of $5.17 million, assuming a January 2010 novation date. Reliant's calculation is based on an assumed cost for a letter of credit of 1.75% per year. Reliant provided an estimate for each IOU's costs for stress case collateral based on an assumed 5% of the total contract costs that would be allocated to each IOU, as follows:
Reliant's Estimated Costs for Stress Case Collateral
(Dollars in Millions at Net Present Value)
Utility Assumed Target Date to Replace Remaining Contracts
1/1/2010 7/1/2010 10/1/2011 7/1/2012
PG&E $1.99 $1.14 $0.17 $0.08
SCE $2.59 $1.55 $0.35 $0.20
SDG&E $0.59 $0.34 $0.05 $0.02
We conclude that there are various uncertainties that preclude the identification of a precise estimate for the potential cost associated with collateral requirements. SCE has estimated a collateral liability based upon certain assumptions regarding changes in the terms of renegotiated contracts relative to market exposure, as noted above. SCE estimates a provision that is lower than what DWR estimates. SDG&E omits any estimate of a cost for collateral in their estimates of net costs from novation.
As noted above, DWR is not currently required to post collateral for its contracts and does not incur costs for posting collateral or for maintaining a credit facility for potential collateral. Assuming that the IOUs were to enter into replacement contracts that did not materially change the terms of existing DWR contracts, the IOUs may be able to avoid (or minimize) a requirement to post collateral on a similar basis.22
In the event that a replacement contract changed materially DWR's current contract terms, however, we recognize that some additional collateral may be required from the IOU. Without knowing what specific changes in contract terms may be negotiated, the record does not provide the basis to formulate a precise estimate of collateral costs.
Nonetheless, we acknowledge SCE's observation, however, that credit costs have increased dramatically since its original assumptions were made regarding the potential costs for collateral and letters of credit. Consequently, in negotiating any replacement agreements involving material amendments in terms, the contracting IOU will need to consider carefully any potential impacts of collateral and credit requirements as a result of such contract amendments. Any amended contracts submitted for Commission review would have to offer sufficient net benefits to ratepayers to counterbalance the costs of posting of any collateral and letters of credit.
We recognize, in any case, any actual amounts required for collateral will vary as a function of the market exposure that may apply under any replacement contracts, and the related perception of default risk ascribed to the IOU taking over the contract.
Each of the IOUs' estimates as to what costs they would incur for administration of the DWR contracts if the IOU assumes the replacement contracts through novation or renegotiation are as follows:
Assumed Date for Taking over Contracts
($ in millions)
January 2010 |
July 2010 |
October 2011 |
July 2012 | |
PG&E |
$0.8 |
$0.8 |
$0.80 |
0 |
SCE |
$0.7 |
$0.5 |
$0.08 |
0 |
SDG&E |
$1.2 |
$1.2 |
$0.7 |
$0.1 |
The IOUs' estimates of incremental costs for administrative and general expenses of $2.7 million are uncontested by any other party. We therefore will rely upon the IOU estimates of administrative and general costs for purposes of assessing the impacts of this cost, assuming the IOUs take over replacement contracts through DWR novation or renegotiation.
4.4. Cash Working Capital
SCE and SDG&E included a cost estimate for additional cash working capital that would be required if they become financially responsible for the contracts for power that is currently paid for by DWR. PG&E included no estimate for this item. Working cash costs are incurred to provide liquidity during the time lag between the payment of an expense and the revenue collection to cover that payment. The SCE and SDG&E estimates of additional working cash requirements associated with taking over the DWR contracts is set forth below:
Assumed Date for Taking Over Contracts ($ in millions) | ||||
January 2010 |
July 2010 |
October 2011 |
July 2012 | |
SCE |
$3.7 |
$2.4 |
$0.4 |
$0.09 |
SDG&E |
$0.8 |
$0.6 |
$0.2 |
$0.05 |
The estimates of SCE and SDG&E for working capital requirements are uncontested by any of the other parties. We therefore will rely upon the SCE and SDG&E estimates of working capital requirements for purposes of assessing the impacts of this cost, assuming the IOUs take over replacement contracts through DWR novation.
4.5. Transactional Costs
TURN argues that any assessment of net benefits should be offset by the administrative costs of regulatory and transactional processes to implement novation. TURN estimates costs incurred to date at about $1 million. TURN estimates subsequent contract negotiations will cost "at least a few million dollars" in administrative costs. CFC likewise indentifies regulatory transactions costs as an offset to potential ratepayer benefits.
CLECA argues that any transactions costs associated with pursuing DWR contract novation are likely to be nominal, and in any event, transactions costs would have to be incurred anyway to enter into new contracts as the DWR contracts expire. CLECA also notes that any transactions costs may be mitigated by potential improvements that may be negotiated in the replacement contracts, such as by providing for longer terms, or tailoring the terms more closely to an IOU's specific circumstances.
The dispute over regulatory and other transactional costs is essentially a difference over policy and philosophy as to how such costs should be viewed and attributed, rather than factual disagreements over specific dollars that have been or may be spent on transactional costs. Parties have had the opportunity to argue in workshops and in filed comments as to the conceptual merits of including or excluding this category of costs from the assessment.
While we recognize that some transactions costs will be incurred and constitute an offset to any net benefits that may be realized, no party has shown that such costs will be significant enough to overwhelm any potential savings that may otherwise be realized. To the extent that replacement contracts are executed pursuant to novation "as is," there shouldn't be extensive transactions costs relating to such novations. We agree with CLECA that even without contract novation, negotiations will be required to replace the DWR contracts as they expire. Transactions costs would have to be incurred at the time of such contract negotiations, in any event. If some DWR contracts could be replaced with contracts that extend the original DWR expiration date, such contracts could potentially defer the need to incur future costs to negotiate new contracts. We have also adopted safeguards as discussed in Section 6, to limit the risks of unproductive negotiations. In short, we find no basis to conclude that the potential for transactions costs is sufficient enough to offset the total savings, as to warrant abandoning further efforts to achieve DWR contract novation.
12 PG&E Comments dated August 4, 2008, at 11.
13 Although the table prepared by Reliant shows $1.3 million and $0.3 million, respectively as the SCE estimate for utility collateral and letters of credit, respectively, the values shown in the table do not represent SCE's total estimate of collateral requirements. As discussed in Sec. 4.3.2, the values in the table reflect only SCE's estimated costs per year for every $100 million of mark-to-market exposure. SCE assumed no additional collateral or letter of credit costs under the scenario of successful novation of all DWR contracts. SCE, however, expressed doubts that successful novation of all contracts is feasible, particularly by January 1, 2010. If contract terms changed materially as a result of renegotiation, SCE believes that additional collateral would be required, but did not quantify a precise amount.
14 Consistent with the discussion in Sec. 4.3.2, we have not reflected a specific estimate in the table above for utility collateral or letters of credit based on the assumption that contracts are novated "as is" with no material changes in credit risk. This assumption is subject to the outcome of negotiations and any potential changes in perceived risk exposure associated with the IOUs assuming replacement contracts.
15 TURN, Opening Comments, August 4, 2008, p. 2. Consumer Federation of California, Opening Comments, August 4, 2008, p. 14.
16 In certain circumstances, a rating agency may treat some portion of power purchase agreement costs as payments on debt obligations rather than as operating costs (treating them as "debt equivalent"), and in turn make corresponding adjustments to the utility's credit metrics and financial ratios used as part of the rating agency's overall assessment of credit quality.
17 The risk factor is an element applied by S&P in assigning risk to an entity. S&P usually applies a risk factor ranging from 0% to 50% depending on the regulatory environment and counterparty risk.
18 D.07-12-052, Finding of Fact 75.
19 Id, Ordering Paragraph 36.
20 D.07-12-052 at 162. In D.08-11-008, the Commission modified D.07-12-052 finding that "it is appropriate in some cases for the IOUs to recognize the effects of [debt equivalence] in their bid evaluation processes." (D.08-11-088, p. 16.)
21 Id. at 165.
22 See Declaration of Jeffrey D. Merola, attached to the August 4, 2008, comments of Reliant at page 12, referencing the July 2, 2008 workshop transcript at page 383, relating to DWR representative's discussion of the potential conditions under which IOUs would need to post collateral.
