6. Adopted Treatment of Hedging Incentives for Specific Utilities

Based on the general principles discussed above, we conclude that some sharing of risks and rewards from hedging transactions is appropriate for PG&E and SoCalGas. Because SWG relies on fixed price contracts, but does not actively engage in changing of hedging strategies, we do not impose any change on SWG's existing recovery mechanisms. We next turn to the adoption of specific amounts of risk sharing that should be applied with respect to hedging costs, starting with PG&E.

6.1. Adopted Treatment for PG&E

With respect to PG&E, we conclude that the Proposed Settlement offers a reasonable outcome, consistent with our determination that the utility should bear some financial consequences for hedging. We likewise conclude that the settlement's proposed risk sharing of hedging transactions is reasonable. We accordingly adopt the settlement for purposes of a hedging incentive policy for PG&E, as outlined below.

A motion for adoption of the Proposed Settlement was jointly filed on July 10, 2009, by DRA, TURN, and PG&E. The parties jointly filed a motion to file under seal a confidential unredacted version of the Proposed Settlement which describes detailed parameters of the proposed hedge program. We grant the motion to file the confidential version of the Proposed Settlement under seal, consistent with our past policy recognizing that customers' interests are protected by not disclosing confidential information that could compromise the effectiveness the utility's bargaining position in the procurement of gas.

6.1.1. Sponsoring Parties' Positions Based on the Proposed Settlement

The key provisions of the Proposed Settlement call for the following treatment of hedging transactions:

· 80% of net realized gains or losses and associated transaction costs will be included in the CPIM Commodity Benchmark. Net hedging losses (inclusive of net option premium outlays) are added to the Commodity Benchmark. Net hedgings gains (inclusive of net option premium outlays) are subtracted from the Commodity Benchmark.

· 100% of the net hedging realized gains or losses and associated transaction costs will be included in the Cost side of CPIM. Net hedging losses (inclusive of net option premium outlays) are added to the Costs. Net hedging gains (inclusive of net option premium outlays) are subtracted from the Costs.

· The CPIM sharing mechanism will be modified such that total shareholders earnings will be capped solely at 1.5 percent of annual gas commodity costs. The hard dollar cap of $25 million on shareholder gains is removed effective November 1, 2009.

· All other aspects of customer/shareholder sharing above and below the CPIM dead-band under the current CPIM mechanism remain the same.

· The winter hedge portfolio design and implementation is left to the discretion of PG&E.

· PG&E will have a combination of storage, physical fixed-price contracts, and financial instruments to cover the targeted core portfolio customer average forecast demand.

6.1.2. Other Parties' Responses to the Proposed Settlement

Shell and SoCalGas each filed a response to the Proposed Settlement. In its response to the Settlement, Shell expresses opposition, arguing that the Settlement fails to address or resolve most of the key issues in this proceeding. Shell argues that the Settlement would not mitigate gas price volatility, would not adequately balance risks and rewards between ratepayers and shareholders, and would not provide increased transparency regarding PG&E's hedge solicitation process.

Shell disputes sponsoring parties' claim that the Settlement will "ensure that PG&E [takes] proactive steps to mitigate gas rate volatility." (Joint Motion at 8.) Shell points to its proposal to establish a "portfolio price volatility target," expressed as a percentage of the utility's benchmark price volatility, as discussed above. Shell believes that the target must provide a meaningful opportunity for (and impose an enforceable obligation upon) PG&E to manage price risk and mitigate price volatility in its core portfolio.

Shell further argues that the Proposed Settlement exposes the shareholder to little or no risk based on the level of winter hedging likely to be undertaken and based on the operation of the CPIM. Shell provided calculations to show that even if PG&E hedged 70% of its winter core demand, PG&E shareholder exposure for hedging under the CPIM would be no more than $1.1 million. Shell believes this calculation likely overstates the risk exposure since it assumes extreme conditions in effect in the immediate aftermath of Hurricane Rita and Katrina. Shell also notes PG&E's comments that allocating as much as 25% of the net costs of hedges to PG&E's CPIM would "not directly remedy the lack of alignment between customer and shareholder interests."22

SCE also filed a response to the Settlement. SCE continues to disagree conceptually with the treatment of hedging in the Proposed Settlement. SCE does not oppose the Settlement, however, as long as the Commission is clear that the provisions of the Settlement do not apply to any other gas utility. Because SCE does not interact in PG&E's service territory in a significant way, SCE does not believe it would be directly affected by the Settlement. Conceptually, however, SCE continues to believe that hedging and gas cost minimization (which is the current objective of the procurement incentive mechanism) constitute different and potentially contradictory objectives. SCE believes that combining these functions within a single incentive mechanism could produce unintended conflicts of interest.

6.1.3. Discussion

Under Rule 12.1(d) of the Commission's Rules of Practice and Procedure, we will not approve settlements, whether contested or not, unless the settlement is reasonable in light of the whole record, consistent with the law, and in the public interest. In reviewing a settlement, we consider individual provisions, but we do not base our conclusion on whether an isolated provision is, in and of itself, the optimal outcome. Instead, we determine whether the settlement, as a whole, is in the public interest. Since the Proposed Settlement here is not sponsored by all parties, we also weigh objections or concerns raised by other parties.

In this rulemaking, our responsibility is to establish policy in a manner that serves the public interest. As the starting point for evaluating the PG&E Settlement, we are guided by an overarching responsibility to establish policies that promote the public interest. In considering the Settlement, therefore, we must determine whether it represents the broad public interests. In this regard, we note that the parties sponsoring the Settlement include not just a utility, but also DRA and TURN, both of whom represent the interests of core ratepayers.

In reviewing the Settlement, we also look to prior precedents. In D.88-12-083 for example, we approved a settlement proposed by PG&E and Commission staff that resolved issues relating to the Diablo Canyon Nuclear Power Plant that was vigorously opposed by other parties.23 In that instance, the Commission stated that in a settlement affecting all PG&E customers, the factors used by the courts in approving class action settlements provided appropriate criteria for evaluating the Diablo Canyon settlement. The Commission stated:

...When a class action settlement is submitted for approval, the role of the court is to hold a hearing on the fairness of the proposed settlement...

In order to determine whether the settlement is fair, adequate, and reasonable, the court will balance various factors which may include some or all of the following: the strength of applicant's case; the risk, expense, complexity, and likely duration of further litigation; the amount offered in settlement; the extent to which discovery has been completed so that the opposing parties can gauge the strength and weakness of all parties; the stage of the proceedings; the experience and views of counsel; the presence of a governmental participant; and the reaction of class members to the proposed settlement. [Citations omitted.] In addition, other factors to consider are whether the settlement negotiations were at arm's length and without collusion; whether the major issues are addressed in the settlement; whether segments of the class are treated differently in the settlement; and the adequacy of representation. [Citations omitted.]24

We apply similar principles in reviewing and approving the Proposed Settlement here. We will only approve the settlement if it assists us in carrying out our responsibility to resolve the identified issues in a manner that best serves the public interest.

We conclude that the Proposed Settlement is reasonable in light of the record as a whole, resulting in an outcome that holds the utility financially responsible for the consequences of its hedging activities, but limits the extent of investor risk exposure. The balanced outcome in the Settlement is consistent with our general analysis of the relevant goals, constraints, and considerations that guide our policies relating to cost recovery and incentive treatment for hedging. The compromise reached in the Settlement strikes a reasonable balance, providing some incentive to hedge prudently while also avoiding the risk of large losses that could act as a disincentive to hedge at levels warranted to protect the ratepayer.

Under the terms of the Settlement, PG&E will no longer be required to seek formal Commission approval of its hedging plans, but must report to DRA and TURN on the total amount of hedge coverage in accordance with Section C.3 of the Settlement.

We are not persuaded by the objections raised by Shell in its opposition. Shell contends that nothing in the Settlement requires PG&E to reduce its gas price volatility, and does not make PG&E accountable for mitigating customer exposure to gas price volatility. Shell contends that the Settlement appears to enable PG&E to replicate the hedging approach that it undertook in all of its winter hedging plans since 2005, and does not impose an enforceable obligation upon PG&E to reduce price volatility.

In criticizing the Settlement, however, Shell does not give due recognition to the risk sharing effects of the Settlement in providing an incentive for PG&E to manage its hedging program more effectively than it has in the past. The incentive mechanism rewards PG&E if hedges produce positive results and requires PG&E to share in losses if hedges produce negative results. To this extent, the interests of ratepayers and shareholders are aligned.

Shell is correct that the Settlement does not impose a specific volatility target for PG&E to meet. But by relying on financial incentives to encourage sound management, it is not necessary to mandate a specific volatility target. Moreover, no party in the proceeding, including Shell, provided empirical analysis to quantify a specific volatility target figure for PG&E. Accordingly, the Settlement provides a workable solution that does not require picking some mandated figure as a volatility target.

Shell also argues that the level of risk exposure in the Settlement is not sufficient to impose added accountability on PG&E with respect to its hedging activities. We disagree. We conclude the proposed risk sharing balances the offsetting considerations of avoiding an excessive risk of loss so as to create a disincentive to hedge, while maintaining some degree of accountability for hedging results.

The Proposed Settlement, by its own terms, was to apply to winter hedge transactions executed by PG&E on or after November 1, 2009, for CPIM years beginning on or after November 1, 2010. Since this order will take effect subsequent to November 1, 2009, we adopt the Settlement, amended to apply to winter hedge transactions executed beginning on the effective date of this decision. In other respects, the term and notice provisions of the Settlement will apply, as set forth in Section C thereof, for an initial period of seven years, with a possible extension for two more years.

6.2. Adopted Treatment for SoCalGas/SDG&E

For SoCalGas/SDG&E,25 we adopt an incentive treatment for hedging that is not based on the Settlement, but rather is based on the record apart from the Settlement. As discussed in Section 5 above, we conclude that some degree of risk sharing is warranted for SoCalGas hedging. The record in the proceeding, apart from the Settlement, supports certain common principles that apply to SoCalGas' incentives as well as to those of PG&E. Thus, while we adopt somewhat different measures for SoCalGas, in terms of the specific sharing of hedging risks and benefits compared with PG&E, we conclude that similar general considerations apply to both PG&E and SoCalGas with respect to the treatment of incentives.

As with PG&E, we conclude that some level of financial accountability should apply to SoCalGas for the consequences of its hedging. At the same time, we conclude that placing all hedging costs and gains within the GCIM could expose the investor to excessive risk, as illustrated in the calculations below.

The following tabulation shows the effects on the GCIM reward of including versus excluding winter hedging costs and gains from the GCIM based on hedging costs over the period from 2002-2003 through 2007-2008:

These hypothetical calculations illustrate how the GCIM reward would have been impacted if all SoCalGas hedging costs had been included within the GCIM after 2005.27 We conclude that utility investors' risk exposure should be limited to avoid creating an undue disincentive to hedge at an appropriate level for core ratepayers. Under the current process, however, there is no affirmative financial incentive to hedge at an appropriate level, and to make sure that hedging is neither too limited nor excessively costly.

Although the utilities oppose bearing any risk associated with hedging, the fact remains that hedging costs were included in the GCIM/CPIM prior to 2005. Even though hedging costs were at a more modest level then, the utilities did engage in some hedging, and bore a shared of the risks and rewards of hedging. Yet, no utility has claimed that the hedges executed before 2005 were imprudent as a result of a perceived disincentive to hedge. Including hedging costs within the incentive mechanisms did not lead the utilities to refrain from hedging at all.

SoCalGas' categorical opposition to sharing any gains or losses from winter hedging as an incentive to promote better performance is also at odds with other statements extolling the merits of incentives. In the omnibus gas proceeding (A.06-08-026), SoCalGas argued that an incentive mechanism can make a difference in how well the utility manages. In seeking approval of an incentive award for interruptible access charge revenue, SoCalGas argued that without a financial incentive, utility employees would not apply "the same level of vigor and innovation" in the marketing, discounting, and promoting interruptible access rights.28 We believe that in the case of gas hedging, the utility is likely to pursue more vigor and innovation if there are financial consequences resulting from how well the hedging program is managed.

The policy of insulating the investor from 100% of winter hedging gains and losses was adopted in response to specific short-term risks of price spikes in view of Hurricane Katrina and Rita. While markets continue to be subject to future uncertainty, the specific market conditions today are different than in 2005 when we modified the GCIM/CPIM to exclude winter hedging. At that time, the concern was to protect ratepayers from rapidly escalating natural gas prices as a result of temporary supply disruptions caused by Hurricane Katrina. Over time, however, natural gas prices can move dramatically downward as well as upward, or may remain flat. We acknowledge the utilities' concerns regarding the need to limit investor risks while allowing flexibility to hedge sufficiently to protect ratepayers. On the other hand, the treatment of winter hedging plans, and their associated gains and losses, adopted since 2005 in anticipation of potentially extreme short-term price spikes is not necessarily suitable for purposes of a more lasting approach for promoting appropriate hedging.

We conclude that an appropriate incentive should be provided by holding SoCalGas financially responsible for some share of its hedging activities. Identifying an appropriate share of hedging risk and reward requires some degree of judgment, as there is no bright line test that can precisely delineate an exact allocation which is optimal. Previously in R.04-01-025 proceeding where we considered how to allocate hedging plan risks for the 2006-2007 winter season, DRA had suggested an allocation of risk whereby 25% of each utility's hedges would be included in its procurement incentive mechanism, with the remaining 75% to be allocated outside of the incentive mechanism. While declining to adopt such an approach for the 2006-2007 winter season due to an insufficient record, the Commission noted that this alternative may deserve additional consideration in the design of a permanent hedging ratemaking mechanism for the treatment of hedging plans.29

In this proceeding, we have now given additional consideration to this alternative. By ALJ Ruling dated January 15, 2009, parties were directed to address the potential impacts of including 25% of hedging transactions within the procurement incentive mechanism, with ratepayers bearing the remainder. In consideration of the record developed on this issue, including 25% of hedging costs and gains within the GCIM is a reasonable incentive approach for purposes of SoCalGas.

SoCalGas produced calculations showing how the GCIM would have been impacted if theoretically a maximum of 25% of winter hedging transactions had been included within the GCIM over the three years of 2005-2006 through 2007-2008.30 SoCalGas calculated that shareholder awards would have been impacted as follows:

For SDG&E, the totals are:

These calculations illustrate that although a 25% share of hedging costs are included in the GCIM, the actual reduction in the GGIM award would be more modest.

Depending on market conditions over time, however, any actual losses would vary, and the investor could also experience hedging gains in some years. In the interest of caution, however, we conclude that investors should not be placed at risk for the effects of including 100% of hedging costs in the GCIM. As noted above, exposing the investor to excessive levels of risk for hedging could act as a disincentive to hedge at levels needed to protect customers. At the same time, however, for the reasons discussed above, we are not inclined to continue to shield the investor from 100% of the risks resulting from winter hedging.

We conclude that 25% of hedging costs and gains represents a reasonable share of hedging transactions to include in the GCIM. The resulting impacts on investor risk should be modest enough to avoid potential disincentives to hedge at appropriate levels, but sufficient to encourage cost-effective management of hedges. The tolerance bands within the GCIM serve to mitigate the investor's risk exposure, in conjunction with the utilities own discretionary decision whether and to what extent to undertake any hedging.

We thus shall adopt a 25% allocation of winter hedges to the GCIM to replace the current regulatory policy of assigning 0% of winter hedging gains and losses to utility investors. The percentage allocation of each hedge instrument shall be applied in a consistent manner. This requirement will preclude the selective allocation of high-risk hedge instruments differently than lower risk instruments.

Without bearing any risk, the utility investor is financially indifferent to the success or failure of the hedging program, whereas the ratepayer has a significant financial stake in the program. Assigning a uniform 25% share of such gains/losses and improving/offsetting savings to the GCIM provides a reasonable balancing of ratepayer and shareholder interests.

We recognize that our adopted approach does not produce a precise matching of investor allocation of costs or benefits of hedging with the quality of utility management of hedging. Depending on market conditions, the utility may receive hedging gains as a result of external events over which it has little or no control. Likewise, the utility may absorb added costs as a result of hedging losses where market prices decline unexpectedly. Nonetheless, the sharing of risks and gains will provide some level of heightened motivation for the utility manager to devote more resources to effective management of hedges over time. Moreover, our adopted approach has the advantage of simplicity and ease of administration. The proposals for index-specific hedging incentive mechanisms, as discussed above, lack this advantage.

SoCalGas proposes certain administrative modifications to help streamline the existing application process, specifically: (1) preauthorization to file winter hedging plans under seal; (2) adoption of a standardized protective order for winter hedging plans; (3) adoption of standardized deadlines for winter hedge applications, responses, and prehearing conferences (if needed); and (4) adoption of procedures that would enable utilities to proceed with their applications earlier, such a true-up to reflect March 31 storage levels and natural gas prices, and other relevant conditions. Since we will be relying upon the incentive mechanism to motivate the utility to manage its hedge program in a cost-effective manner, we will no longer require SoCalGas to file annual applications for Commission approval of a hedging plan. We shall, however, require SoCalGas to continue existing practices in providing ongoing hedging transaction information to DRA, TURN, and the Energy Division. All future winter hedging transactions executed by SoCalGas shall be subject to DRA monitoring and review within the GCIM through the same process applied to other transactions under the GCIM, consistent with existing DRA audit and report procedures. SoCalGas shall cooperate fully with DRA's review process.

6.3. Treatment for SWG

SWG's GCIM is a relatively new program. SWG's hedging activities were integrated into its GCIM upon its inception. Because of its use of storage assets and the modest size of its market, SWG's hedging is comprised of volume-limited purchases of physical, fixed-price supplies. In the GCM, the cost of these supplies is passed through to customers without any incentives or penalties. After a vetting with the DRA, the hedged volumes were established at a percentage of forecasted annual demand. SWG acquires these volumes through a regimented program over time for each annual period.

SWG opposes any revision that would assign a share of hedging gains or losses to investors. SWG supports continuation of the existing program of assigning all hedging gains/losses to ratepayers. SWG suggests a revision to its GCIM and hedging program to include the use of fixed-for-floating index swaps. SWG also suggests reexamining the percentage of its purchases currently included in its hedging program. SWG believes that it may be desirable to increase the hedged percentage to somewhere between 25 and 50% to align with hedging activities in its Arizona and Nevada jurisdictions where about 50% of the portfolio is hedged.

DRA opposes the changes suggested by SWG, arguing they are beyond the stated scope of the Order Instituting Rulemaking (OIR). The OIR states, "This rulemaking is not intended to be a broad reexamination of the utilities' gas incentive mechanisms. Each year these incentive mechanisms go through an application process where there is an opportunity to propose modifications."31 DRA argues that SWG's proposed changes should be developed and addressed in an appropriate proceeding, but they are not within the scope of this rulemaking.

Given the fact that the SWG's GCIM is relatively new and its hedging is limited to utilization of fixed price contracts, we find no need to change the SWG incentive mechanism at this time. We agree with DRA that changes in SWG's California program to include the use of index swaps or to mandate the amount of hedging to be utilized are issues beyond the scope of this proceeding. Such changes do not relate to the issue of incentives that should be adopted to motivate effective management of hedges.

22 See PG&E comments filed February 20, 2009, on a Ruling Soliciting Further Information Regarding Hedging Issues," at p. 5.

23 Re Pacific Gas and Electric Company (1988) D.88-12-083, 30 CPUC2d 189 ("Diablo Canyon").

24 Id. at 222.

25 References to SoCalGas also include applicability to SDG&E by implication.

26 As reported in SoCalGas' annual GCIM proceeding, Application (A.) 03-06-021, A.04-06-025, and A.05-06-030, respectively.

27 The calculations are based on costs actually incurred, without speculating as to how utility hedging behavior may have changed if different incentives had applied.

28 See D.07-12-019, mimeo. at 88.

29 See D.06-08-027 at 15.

30 See SoCalGas Comments dated February 20, 2009, Attachment B, reproduced in Appendix B of this Decision. SoCalGas produced these calculations in response to the ALJ Ruling dated January 15, 2009. As noted by SoCalGas, the calculations do not consider how hedging strategies and outcomes might have been affected if the revised risk sharing had applied at the time.

31 See OIR at 22-23.

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