5. Should Hedging Risks and Benefits Be Shared by Utility Investors?
5.1. Parties' Positions Apart from the Settlement
We first address the general policy of whether winter hedging risks should be shared by utility investors, considering the underlying record apart from the Proposed Settlement. We reach general conclusions, based on this review, that some degree of risk sharing is appropriate. We next consider the specific application of this principle to each utility separately. For PG&E, we consider the Proposed Settlement as a basis for specific modification in risk sharing. For SoCalGas and SWG, we separately consider modifications based on the record apart from the Proposed Settlement.
Parties' pre-settlement positions apply generally to all of the gas utility respondents to this proceeding. Accordingly, review of the pre-settlement positions provides a framework: (1) with respect to PG&E, for assessing whether the settlement offers a reasonable resolution in light of the whole record, and (2) with respect to SoCalGas and SWG, whether parties' arguments have substantive merit (since the settlement only covers PG&E).
In their pre-settlement proposal, the utilities support the status quo, with 100% of the risks and benefits of winter hedges assigned to the core ratepayers. TURN, in its pre-settlement position, also advocates maintaining 100% of winter hedging impacts outside the procurement incentive mechanism.
The utilities argue that the re-integration of winter hedging programs into their gas cost incentive mechanisms would create disincentives to hedge at a level that is appropriate to protect customers from possible price spikes in winter months when consumption is the greatest.
TURN agrees with the utilities that including hedging within the existing incentive mechanisms would disrupt the alignment between customers' and shareholders' interests. Because shareholders would face penalties for the costs of hedging, they would have the incentive to curtail the amount of hedging that would otherwise be performed absent such risk.
The utilities and TURN argue that the existing framework properly aligns the interests of ratepayers and shareholders, and that the objectives of hedging (i.e., limiting customer exposure to price risk) are distinct and potentially incompatible with the goals of gas cost minimization. They characterize hedging as a tool to reduce price volatility, but not the absolute level of costs.
The utilities maintain that gas cost minimization and hedging have diverging objectives that cannot be reconciled. TURN likewise argues that placing hedging within the gas cost procurement mechanism creates an inherent conflict between ratepayers and shareholders by penalizing investors when gas prices fall, thereby creating a disincentive to hedge.
TURN agrees with the utilities that integration of hedging into the existing procurement incentive mechanisms would not provide an incentive for optimal hedging. TURN argues that a tool such as hedging (designed to provide benefits only when commodity prices rise) is not compatible with an incentive that rewards utilities when prices decline. Hedging and commodity prices move in opposite directions. Thus, for example, in instances where hedging produces a gain due to a broader market commodity price rise, ratepayers would give up some hedging gain to shareholders in addition to paying a share of costs caused by higher commodity prices.
TURN thus argues that including hedging within the procurement incentive mechanism would break the alignment between shareholders' and customers' interests. Because utility shareholders would face penalties for the costs of hedging, TURN believes the utilities would have an incentive to curtail hedging, and would no longer be an impartial agent for ratepayers. TURN argues that forcing the utility to bear risk by including the effects of hedging within the procurement incentive mechanism will expose the utility to significant earnings volatility without an expectation of a positive return, thus negatively impacting the utility's credit rating, and making the cost of borrowing more expensive. TURN believes ratepayers could be subject to higher costs as a result.
The utilities also argue that gains and losses from hedging are primarily due to factors beyond their control (e.g., market fluctuations resulting from weather, macroeconomic trends, etc.). The utilities assert that the incentive mechanisms for gas commodity procurement costs are based on a factor over which the utilities can exert some control-its assets-whereas hedging strategies attempt to minimize market price volatility-an area outside of utility control, and not a reflection of the utility's acumen.
SoCalGas argues that if some or all of its winter hedging transactions were to be included within the GCIM, some sort of corresponding shareholder reward-or at least the potential for additional reward-might compensate somewhat for additional risk. SoCalGas suggests, as one possible approach, that the GCIM lower tolerance band (currently set at 1%) could be adjusted by an amount that roughly compensates for the amount of winter hedging options moved into the GCIM. By reducing the tolerance band, the utility could begin to share in GCIM savings earlier, and thereby receive some offsetting compensation for absorbing additional risks associated with winter hedges.
Although SoCalGas and SDG&E support the status quo as their primary position, they believe a separate benchmark index could be developed in the event the Commission desires such treatment. SoCalGas believes that a separate performance benchmark could be designed to track winter hedges based upon fixed-price forward transactions using the average of the posted settlement price for the first five days of each transaction month-not the settlement month. For example, the benchmark for a December 2010 NYMEX futures contract entered into in August 2010 would be the average daily settlement prices for December 2010 NYMEX futures contracts for the first five trading days of August 2010.
Forward price transactions would include physical contracts, futures, and swaps, but exclude options. Because of their low probability of payoff and the limited availability of settlement prices, SoCalGas does not consider options as being conducive to benchmarking. Actual performance would be compared against the benchmark, with differences (either positive or negative) shared between customers and shareholders in the same way as for any other GCIM input. SoCalGas argues that the benchmark would provide an incentive to actively follow the markets and trading patterns in order to enter transactions at times when the prices are more favorable.
PG&E does not believe that a separate incentive mechanism can be designed that aligns customers' and shareholders' interests in a fair and economically efficient manner. PG&E cannot find any transparent benchmarks or published end-of-day quotes of forward prices (particularly longer-dated forwards published on a consistent basis) or option values with which to construct benchmarks for use in designing a hedging incentive mechanism. PG&E does not believe that SoCalGas' proposal for the use of Henry Hub NYMEX futures (even if deemed useful for SoCalGas) would be as effective for PG&E. PG&E is concerned about the locational hedge effectiveness of using (and being benchmarked against) only NYMEX futures to hedge supply basin price risks in western Canada and San Juan in the Four Corners region of New Mexico and Colorado.
SWG similarly believes that benchmarks for hedging transactions do not exist because transactions in futures markets are not sufficiently transparent. SWG relies on its competitive bidding process to ensure that it purchases hedging instruments at the lowest cost available at the time of purchase.
DRA opposes establishing a separate incentive mechanism limited to hedging costs alone, arguing that such an approach is patently flawed. DRA likewise believes that there are no readily available, transparent benchmarks that could be applied to index the performance of a hedging program through a separate incentive mechanism.
DRA objects to SocalGas' proposed benchmark based on a NYMEX futures contract. The NYMEX gas futures prices move minute-by-minute and many related financial instruments are traded privately and/or "over the counter." DRA argues that it would be poor policy to design a separate hedging benchmark that is unverifiable. Incentive mechanisms, by definition, incorporate some type of reward/penalty structure for the utility. DRA argues that absent a balanced and equitable utility incentive structure, dedication of resources to such a regulatory effort carries little to no value, because the proper utility incentive and accountability to prudently manage costs is never pursued.
Shell also objects to using fixed-price forward transactions based on a NYMEX futures contract as a benchmark to measure SoCalGas' hedging performance. Shell argues that such a benchmark would not provide accountability for utility management since the hedge purchase price would simply be measured against itself. (See Comments at p. 11.)
Shell also argues that the use of the NYMEX price at Henry Hub would not provide a meaningful benchmark for SoCalGas' performance given that Henry Hub is in Louisiana, not in California. The NYMEX price would need to be translated to the Southern California border price through a basis swap, according to Shell, in view of the substantial variation between the NYMEX price and California border prices.
DRA, in its pre-settlement proposal, argues that insulating investors from 100% of winter hedging risks does not provide an incentive to manage hedging in ratepayers' best interest. DRA argues that the utilities are not subject to accountability for the consequences of their hedging activities. DRA has referred to PG&E's hedging program as a "shopping spree" and that "there is no evidence such hedging behavior helps reduce gas costs for PG&E customers."15 As its pre-settlement position, DRA proposed that all hedging costs be re-integrated into the existing gas cost incentive mechanisms.
DRA believes that the current deadband tolerances within the incentive mechanisms (equal to an amount of 2% above the commodity benchmark to 1% below the commodity benchmark) provide adequate flexibility for the utilities to conduct any hedging that each corporation determines to be appropriate. DRA suggests, however, that the existing incentive mechanisms could be modified to accommodate investors' added risks by expanding the tolerance bands to provide additional flexibility and an extra measure of protection in consideration of any perceived need by the utilities (and/or Commission) to increase the level of hedging activity.
If hedging costs are re-integrated into the existing incentive mechanisms, DRA believes that no Commission authorization of hedging plans would be needed, but that hedging gains or losses would simply be included within the utilities' actual procurement mechanisms, and measured relative to the benchmarks.
DRA argues that hedging should be discretionary rather than subject to Commission mandate. DRA would leave the responsibility with the utility as its strategy to hedge, subject to recovery within the incentive mechanism. DRA believes that this approach provides flexibility for the utilities to make prudent hedging decisions on a real time basis in conjunction with prevailing market conditions, and incorporates accountability for their discretionary decisions, providing the investor with a financial stake in the outcome of hedge transactions.
If the Commission retains winter hedging program costs outside the incentive mechanism structure, however, DRA believes that the current approval process (with some modification as explained below) is acceptable, in contrast to designing a separate hedging incentive mechanism (which DRA believes would offer no true accountability). If winter hedge program costs remain outside the incentive mechanism, DRA recommends that the utilities file an application or advice letter for plan approval, somewhat similar to the process used for interstate pipeline capacity approved in D.04-09-022.
If the utility obtains consensus with DRA and TURN as to the terms of its annual winter hedge program, then it would file for Commission approval of the plan by advice letter. If the utility is unable to obtain agreement with DRA and TURN as to a winter hedge program, the utility would file an application for approval of its plan. DRA intends to continue to audit all winter hedge plan costs and identify them separately in its annual audits of the incentive mechanisms.
Shell presented its proposals on hedging policies from its perspective as an independent marketer of natural gas. Shell argues that the existing regulatory process does not provide adequate assurance that hedging costs charged to ratepayers are reasonable. Shell believes that excluding the utilities' winter hedging plans from the incentive mechanisms relieves the utilities from any accountability for risks associated with hedge transactions. Shell claims that under the existing framework, the hedging programs have resulted in no tangible benefits to ratepayers.
Shell argues that the ability of DRA and TURN to assess utility hedging strategies and execution is limited, and that a more public and transparent process in the review of hedging costs is needed, with objective measures of performance. Shell proposes that a target be established to measure the volatility of the GCIM/CPIM benchmark price. Based on an annual assessment of the utility's performance in achieving a designated price volatility mitigation target, the utility would receive an award or incur a penalty in relation to its performance.
Shell proposes that the Commission establish a "portfolio price volatility target," expressed as a percentage of the procurement incentive mechanism's benchmark price volatility. This target would compare the volatility of the utility's gas purchases relative to the GCIM/CPIM benchmark price. Based on an annual assessment of the utility's performance in achieving the price volatility mitigation target, the utility would receive an award or incur a penalty in relation to its performance.
Shell proposes a four-step process for calculating the volatility of market benchmark prices: (1) list monthly natural gas prices in a column; (2) take the natural logarithm of the ratio of each monthly price to its value in the preceding month; (3) calculate the standard deviation of this data set; and (4) multiply the resulting standard deviation by the square root of 12. The resulting number, expressed as a percent, represents the annual price volatility of the market benchmark. Shell believes that the same calculation can be applied to each utility's actual prices to determine the volatility of the utility's supply portfolio. In this manner, the performance of the utility with respect to price volatility could be compared to an objective market measure.
Shell believes that the Commission should establish a targeted reduction in utility price volatility relative to the benchmark price volatility. Shell presumes that the specific figure or value for portfolio price volatility would be based on customer risk preferences. Until the Commission determines such values, as an interim measure, Shell proposes use of a volatility reduction target of 30%, representing hedging of 25% to 50% of each utility's portfolio (based on the range that SWG currently utilizes). Shell anticipates that the actual volatility value would be established based upon actual or projected customer preferences for price stability.
Shell supports the inclusion of all hedging costs and benefits within the gas cost incentive mechanism. In order to accommodate the inclusion of hedging, however, Shell proposes that the benchmark used to assess rewards or penalties under the incentive mechanism be modified to reflect "all utility procurement products, including hedges." The benchmark would thus include index prices representing fixed price contracts at each given location where the contracts are purchased. Shell proposes that the utility investor share in 15% of the gains and 2% of the losses related to utility procurement costs versus the benchmark, with no tolerance band. Under Shell's proposal, each utility's overall financial exposure for gas procurement, including hedging, would be limited to a gain of $38 million and a loss of $14 million. Shell believes that these percentages of sharing and caps will be sufficient to provide an incentive for the utilities to hedge.
Shell further argues that in order to ensure that utility hedging procurement is transparent and non-discriminatory, the Commission establish a protocol whereby a number of suppliers that meet credit and performance criteria can be qualified for any utility solicitation. Shell proposes that the utilities be required to rotate through suppliers over time on a non-discriminatory basis in order to maximize competitive opportunities among suppliers. Shell characterizes this proposal as an "open, transparent, and non-discriminatory hedge solicitation protocol" for each gas utility intended to mirror the electric utilities' hedge solicitation process. Shell argues that its proposal eliminates the need for a confidential hedge procurement plan and that core customers will be better served by an open process allowing for scrutiny of the utilities' hedging programs by "risk managers that are part of the solicitation process." (July 30 Shell Comments at 18-19.)
SoCalGas and PG&E oppose Shell's proposal to force the utilities to contract for a significant amount of fixed-price gas on a year-round basis. PG&E believes that a hedging strategy limited to the peak-demand winter months is best for its bundled core customers because it applies the appropriate price protection when high prices could coincide with high demand. PG&E argues that Shell's notion of year-round contracting for fixed-price gas has very little benefit to core customers during summer months when their usage and gas bills are generally low. SoCalGas states that while it would consider fixing the price of a portion of its core portfolio, if it could secure a very low price, it may very well consider such arrangements. SoCalGas, however, does not want to be forced into fixed price arrangements by a new mechanism that places an artificial and unwarranted premium on rate stasis.
DRA opposes Shell's proposal, arguing that there is no factual basis to establish the solicitation protocol proposed by Shell. Core purchases represent less than 50% of the gas sold in the California market, while the balance of gas supply is generally moved into the market by noncore customers and/or marketers/producers. DRA claims that Shell's proposal would create a double standard in the gas market - "full disclosure" of hedge products for utilities, and "no disclosure" for all other market participants (marketers, producers, large end-users, core aggregators, etc.).
5.2. Discussion
In reviewing parties' positions, apart from the settlement, we are not persuaded that any single proposal optimizes the goals of protecting customers against price spikes while minimizing overall gas costs over time. We conclude that if all hedging costs and payouts were included with the GCIM/CPIM without limits, the resulting perception of risk could create a disincentive to hedge at an appropriate level. We also conclude, however, that the record supports a regulatory approach that holds the utility accountable for the consequences of its gas hedging while limiting investor risk exposure. The utility will have a greater interest in managing hedges effectively knowing that its shareholders will participate in the consequences.
We disagree with the claim that hedging and minimizing gas prices are inherently conflicting goals and that investors' and ratepayers' interests with respect to the use of hedging cannot be reconciled. These goals are not inherently conflicting, but are complementary, namely to minimize overall gas costs consistent with risk preferences. The formulation of a hedging plan should be based upon appropriate goals for balancing customer risk preferences utilizing hedging in a cost-effective manner. Even under the present incentive structure without a monetary award available, the utility still has a duty to customers to manage the hedge program effectively even though the goals of hedging are different than the goals of seeking to minimize gas costs. The utility manager is currently responsible for pursuing both of these goals in a balanced and coordinated manner, even though their specific objectives differ. Imposing a financial consequence on the utility for the results of its hedging program will not lessen the utility manager's existing responsibility to coordinate these goals in a balanced and effective manner. Moreover, financial incentives are only one factor in the design and execution of a hedging plan. In providing reliable and reasonably priced service to customers, prudent hedging will be based on all of the relevant factors, including the nature of the hedge instrument, market conditions, and the needs of customers. As such, we do not believe that including at least some portion of hedging costs within the gas cost procurement incentive mechanism results in incentive signals that are inherently incompatible or contradictory. By placing the utility at some risk for the consequences of the hedge plan after it has been adopted, the interests of the utility investors and ratepayers can be reasonably aligned.
5.2.2. Merits of Adopting a Separate Index Versus Uniform Risk Sharing
We conclude that the best design of an incentive mechanism is the one which is the simplest to administer, and the least vulnerable to gaming. Thus, we decline to adopt proposals for a separate performance index based on futures contracts or volatility targets. We conclude that providing for a uniform percentage of the sharing of gains and losses from hedges offers a much simpler and easier approach to administer while avoiding the difficulties involved with a separate index.
If the Commission were to establish predetermined indices for hedging, for example, by specifying fixed percentages of the supply portfolio to be hedged, or maximum limits on price variability, a system of incentives could be crafted based upon the degree to which the utility attained the targets. The appeal of such a mechanism is that it matches rewards or penalties more directly with hedging management performance. The drawback of such an approach, however, is that it is only as effective as the index or performance target that the Commission sets.
We conclude that the potential complexity involved the proper design, tracking, and verification of a separate index mechanism outweighs any advantages in improving the utility's hedging performance. For the Commission to engage in the sort of detailed oversight entailed in designing and monitoring such a mechanism would not be an efficient use of resources. SoCalGas' benchmark would still call for Commission pre-review and pre-approval of a hedging plan which could insulate SoCalGas from any future allegations of gaming the benchmark. Simply including the costs of hedging within the incentive mechanism relieves the Commission of the need for detailed review of hedging transactions after the fact.
Also, under the index proposed by SoCalGas, the utility would only bear the risk that hedge trades be executed at the 5-day average price. There would be no risk associated with how closely the hedge price compared to the benchmark price in the procurement mechanism. The SoCalGas proposed index also would not account for the use of options, thereby unduly restricting potential hedging strategies. The index would also likely limit hedging activities to a period covering only 12 months or less.
We likewise reject the Shell proposal for a "portfolio price volatility target." Shell provides insufficient information to calculate and integrate it into the existing mechanisms. The proposed changes would introduce more complexity and uncertainty which could pose greater risk and the potential for higher ratepayer costs.
We recognize that hedging has been used by electric utilities to minimize or mitigate the potential for high electric bills. In several decisions in 2002 and 2003, the Commission developed a framework for its electric rate volatility mitigation policy.16 This policy is based on the Customer Risk Tolerance (CRT) guideline, which states that in any given 12-month period, the utilities should avoid having electric rates fluctuate from forecasted levels by more than one cent per kWh. The CRT target is subjective and based on Commission judgment. The Commission has never set a similar target for the utilities' gas programs, and we find insufficient basis to pursue developing a separate CRT target for purposes of a hedging benchmark here.17
Given the complexities involved in managing a hedging strategy, a preferable approach is one in which the utility manager has the flexibility to manage the hedging strategy on an ongoing basis without being constrained by a specific index that may not realistically measure the relevant performance results.
We reject Shell's claim that utility hedge plans should be provided to third parties, including gas marketers. As stated in past decisions, the utility hedging plan is to remain confidential, presumably containing highly sensitive market information which, if released, could work toward the detriment of ratepayers. Many hedging instruments can be purchased in a liquid and transparent market, however, and DRA publishes an after-the-fact review of the utilities' performance. Shell fails to justify why utilities, buying gas for core customers, should be compelled to establish a transparent, non-discriminatory "full disclosure" solicitation protocol for hedge products, while the rest of the market would not be covered within this protocol.
Shell asserts that its proposed solicitation process will increase the range of potential products. The gas market is competitive with a vast range of products already available, and is capable of developing new products when there is a demand for them. Shell fails to quantify any ratepayer benefits of its proposed changes to the incentive mechanisms relative to the current incentive mechanisms.
5.2.4. Merits of Risk/Reward Sharing of Hedging Costs/Gains As Incentives to Management
We next consider the merits of adopting a risk/reward sharing between utility investors and core customers of both the costs and potential payouts from hedging transactions. When we eliminated hindsight reasonableness reviews for gas commodity costs back in the 1990s, we did so with the understanding that the utility would still bear financial responsibility for gas costs by the sharing in gains and losses relative to a performance benchmark. In this manner, we maintained a balance between accountability and risk tolerance associated with gas procurement. Up until 2005, this balance applied to costs incurred to hedge natural gas prices, as well as for natural gas commodity costs, themselves.
The dramatic increase in the use of hedging beginning in 2005 caused us to revise how hedging costs were treated at least for the immediate winter seasons at issue. While we excluded hedging costs from the gas procurement incentive mechanisms in that context, however, we did not reinstitute hindsight reasonableness reviews.
While the Commission has the authority to approve or modify the utilities' hedging plans prospectively, the process for Commission review and approval of hedging plans, however, has significant limitations. The hedging plans submitted for Commission approval do not provide assurance as to how the purchasing strategy will be optimal for ratepayers as time passes and circumstances change. Unlike a contract for a utility product or service, purchasing hedging instruments requires knowledge of future purchasing decisions that we cannot evaluate in advance. Therefore, the process for advance approval of utility hedging plans is not comparable to advance approval of a pipeline contract or a gas storage facility.
Consequently, utilities are subject to no retrospective reasonable reviews of their hedging strategies, but also are largely not held accountable for the consequences of hedging prospectively. Although we have allowed this modified treatment for winter hedging plans approved since 2005, we have not conducted a comprehensive analysis of its longer-term implications prior to this rulemaking.
We have now considered the longer-term implications in this rulemaking. As a result, we conclude that the hedging treatment that has been approved for each winter season since 2005 should not be institutionalized as a permanent policy. The utility's hedging strategies should be based upon a balance of risks and rewards, with accountability for the consequences of management's hedging activity. The utilities don't want investors to be harmed by bearing downside risks of hedging, but the consequence is that core customers bear the entire downside risk. Utilities should share in the financial consequences for their hedging strategies, but subject to limits on the maximum risk exposure. The proper balance lies somewhere between the extremes proposed by opposing parties.
We thus reject the utilities' proposals simply to continue the status quo. Insulating investors from all risks of winter hedging programs without accountability does not promote the proper incentives for prudent hedging. At the same time, given the magnitude of potential risks involved, DRA's proposal to include all hedging costs within the procurement incentive mechanisms is not practical. Likewise, the proposal of Shell also fails to provide a satisfactory solution.
In characterizing the incentives (or disincentives) resulting from the inclusion of hedging within the procurement incentive mechanism, opposing parties selectively highlight only certain effects while downplaying or ignoring other relevant effects. DRA, for example, emphasizes the utility's lack of incentive to be cost-effective. DRA thus seeks to limit hedging only to what is truly needed to protect core customers. DRA, however, does not adequately address the potential of its proposal to cause the utilities to curtail hedging to the point where ratepayers may not be adequately protected against price spikes.
The utilities and TURN emphasize the risks of hedging when addressing the effects on investors, but emphasize the benefits of hedging when addressing the effects on core ratepayers. The fact is that hedging can potentially result in negative and beneficial effects to both investors and ratepayers. SoCalGas has argued that in most years, the investors would realize lower earnings if required to absorb hedge risks. Such hedging losses, however, would also produce higher bills for customers in most years. The same adjustment that would lower shareholder earnings would also reduce any shared cost savings that customers would otherwise realize.
It is unduly one-sided simply to focus on the potential hedging losses to investors without recognizing potential hedging losses imposed on ratepayers. Similarly, if the results of hedging are shared, any successes from hedging would yield benefits to investors as well as to customers.
In periods where hedging produces beneficial effects, those benefits can accrue to both customers and investors to the extent that both share in price variations through the GCIM/CPIM. Under the GCIM/CPIM, the investor is at risk for a share of the variance between the gas commodity price and a designated benchmark (subject to dead-band tolerances). If a hedge narrows that variance, investors' net earnings volatility attributable to commodity prices would correspondingly be mitigated to that extent.
In comments on the Proposed Decision, TURN observes that different time horizons apply in accounting for earnings or loss with respect to: (1) the multi-year duration between potential payouts from hedge instruments and (2) the 12-month cycle associated with earnings under the GCIM. TURN observes that in most years, hedges will result in the recording of a loss (since unexpected price swings do not typically occur every year). By contrast, most offsetting hedging gains may be expected to occur beyond a given 12-month GCIM period, and over intermittent intervals, due to the unpredictable nature of hedges. Consequently, TURN argues that assigning risk of hedging to the GCIM creates a disincentive to hedge at an appropriate level because of these differences in the timing of earnings-or-loss recognition.
We recognize that timing differences exist with respect to multi-year, intermittent hedging payouts versus annual GCIM adjustments. We are not persuaded, however, that such differences necessarily lead to a disincentive to hedge in ratepayers' interest. This argument implies that a utility manager focuses on the consequences of hedging exclusively within the 12-month time horizon used for calculating GCIM awards or penalties. We find no reason to believe that a utility manager makes decisions with such tunnel vision, based solely upon impacts during a 12-month regulatory cycle while ignoring effects due to hedging payouts that may occur beyond the current 12-month GCIM cycle.
A prudent manager would not ignore future earnings potential from hedging payouts in subsequent years merely due to the regulatory artifact of calculating GCIM earnings adjustments at 12-month intervals. While GCIM rewards or penalties are calculated annually, the GCIM process, itself, remains in effect continuously through multiple annual regulatory cycles. It is reasonable to expect a utility manager to be influenced by the full range of consequences from hedging decisions (both positive and negative), even if some consequences are expected to occur during later GCIM cycles. Some hedging effects may be beneficial to the investor, and others may entail potential negative consequences. Management incentives will be informed by the full range of expected future hedging impacts.
Nonetheless, to the extent that concern remains regarding potential negative incentive influences due to timing differences relating to the multi-year nature of hedging payouts, we have addressed this concern by including only 25% of winter hedging transactions in the GCIM. By adopting this limitation on shareholder risk during any 12-month GCIM cycle, we mitigate potential disincentive effects, as noted by TURN. In this way, the potential magnitude of earnings variations is mitigated, compared with allocating 100% of winter hedging transactions to the GCIM. The utility manager will still have incentives to exercise more careful attention to hedging, knowing that management actions may affect utility earnings. Our adopted approach is an improvement over proposals to shield the utility from any financial consequences of the management of winter hedges, while mitigating potential disincentives to hedge at an appropriate level.
The primary goal of utility hedging should not be to realize speculative profits, but rather, to manage price risk so as to promote stability in retail core customers' gas rates, and to protect customers against excessive price swings. TURN claims that the Proposed Decision does not differentiate between "speculative" versus "insurance" hedging. TURN claims that the whole idea of "managing" hedging positions implies an active market participation that is more akin to speculation rather than insurance. We disagree with inferences that establishing incentives for the prudent "managing" of hedging positions somehow implies the use of hedging mainly for speculation, rather than as a form of insurance. There is no reason to equate hedging as a form of insurance with passive management inaction. A prudent utility manager makes a variety of discretionary choices in management of hedging. While particular choices may differ depending on whether the hedges are for speculation or for use as insurance, the utility remains responsible to manage the hedges proactively. The incentives that we adopt promote the prudent management of hedging, and are fully consistent with the use of hedging as insurance to protect ratepayers against price spikes.
In considering incentives and disincentives for hedging, we conclude that any adopted treatment should provide a balance between opportunities to share gains and responsibilities for bearing losses. While some sharing of risk is appropriate to provide the proper incentive to hedge effectively, too much risk exposure could create a distortion in the incentive to hedge at a level conducive to protecting ratepayers from excessive price volatility.
We are not persuaded, however, that placing the utility investor at any risk for winter hedging would cause curtailment of hedging below what is needed to protect core customers. The claim that added risk creates a disincentive to hedge begs the question of what level of hedging is optimal to protect core customers. While the utility should have the incentive to hedge at the appropriate level to protect the ratepayer, no party has provided empirical analysis to establish that "appropriate" level.
There is a trade-off between the value of hedging against price risk versus the costs of hedging. The value of hedging is a function of risk aversion and preference for stability and predictability. The customer benefits only as long as hedging provides an offsetting value in the form of reduced volatility in retail bills. At the point where the additional value of enhanced price stability is less than the incremental cost of hedging, no further hedging would be beneficial for the customer.
In D.07-06-013, the Commission contemplated that PG&E would arrange for a market survey of the risk preferences of its core gas customers. The goal was to determine the dollar amount core customers might be willing to spend on hedging to mitigate the impacts of commodity price volatility.18 TURN supported considering the results of that customer risk preference study in this proceeding. By ruling dated September 17, 2008, in this proceeding, it was determined that the PG&E risk preference study might provide useful information in this proceeding.
The PG&E risk preference study has not been formally presented for review in this proceeding. Under the terms of the Proposed Settlement offered, the Commission would not set a predetermined hedging amount based on risk preference. Yet, since the Settlement only applies to PG&E, the question remains as to whether a study of customer risk preferences should be performed for SoCalGas, and if not, how the Commission would determine if a presumed "disincentive" to hedge might adversely impact customers.
SoCalGas expresses skepticism that a survey of customer risk tolerance would provide useful hedging guidance. SoCalGas believes that the risk tolerance of any individual customer will likely depend upon a host of variables, and that group behavior may be even more complex and subject to external variables that can change quickly.
SoCalGas did not formally assess customer risk tolerance when it designed its recent winter hedging programs, but its hedging strategy was based on what it believed was a reasonable and prudent approach to hedging for its core customers.19 Therefore, SoCalGas is asking the Commission to rely upon the utility to guess as to customer risk preferences, while imposing no financial accountability for a wrong guess.
We appreciate the difficulties and limitations involved in conducting and interpreting an empirical survey of customer risk preferences in relation to the cost of winter hedging. Nonetheless, absent empirical data quantifying customers' risk preferences, the utilities cannot demonstrate with certainty how changes in incentives to hedge may affect customers.20
In the absence of evidence measuring customers' risk preferences, the utility investors' own risk preferences provide some objective indicator of whether a hedging strategy reflects careful attention to its cost-effectiveness. If a utility manager is more cautious about entering into a hedge knowing that investors might be at some risk, that cautious stance may also provide more assurance that any hedges charged to ratepayers have been more carefully considered by the utility.
The assignment of some risk and reward creates an incentive for the utility to manage its hedging more cost-effectively. The Commission has repeatedly expressed support for mechanisms that provide an incentive for utilities to manage costs effectively through exposure to risks as well as opportunities for rewards.21
In comments on the Proposed Decision, TURN states that it is more appropriate for the Commission--rather than utility managers--to determine appropriate customer risk preferences for SoCalGas hedging targets. In the alternative, TURN states that the Commission should set a minimum hedge target for SoCalGas, as TURN discusses in reference to the PG&E Settlement. TURN, however, offers no specific proposals as to customer risk preference parameters that could be used to determine Commission-mandated hedging targets for SoCalGas. TURN also offers no insights as to how to overcome the practical difficulties involved in producing a valid customer risk preference study which might form a basis for Commission-mandated risk preference parameters or hedging targets. Likewise, no other party has offered such evidence. Consequently, we find no basis for the adoption of a Commission-mandated hedging target for SoCalGas in this rulemaking. In any event, while we do not mandate specific hedging targets, we emphasize that SoCalGas continues to be responsible for managing its hedging program in a manner consistent with its ongoing obligation to provide reliable customer service at just and reasonable rates.
We recognize that that the results of hedging are, to some extent, outside of utility management control, but driven by market forces. Nonetheless, the utility can control certain aspects of its hedging strategy, such as formulating overall risk preference goals, integrating hedging with other means of mitigating risk, and adjusting hedging positions in response to changing conditions. The utility can exert control over the degree of risk relative to benefits by proper selection and management of hedging instruments. Assigning risk sharing incentives therefore will motivate the utility to do a better job of managing those aspects of hedging over which it does have some control.
15 See R.04-01-025, DRA's Response to PG&E Petition to Modify D.04-01-047 and D.05-10-015, pp. 5, 7, filed May 26, 2006.
16 D.02-10-062, D.02-12-074, D.03-12-062.
17 In order to meet the CRT guideline, the utility was to monitor the expected volatility of the procurement portfolio by using the metric: "To Expiration Value at Risk" (TEVaR) initially set at 99%. Estimating the value of the TEVaR metric allows the utility to state, with 99% confidence, that rates will fluctuate over the next 12 months by no more than the TEVaR 99% value. Since then, the TEVaR was adjusted from 99% to 95%. (See D.07-12-052.)
18 See D.07-06-013 at 11.
19 See February 20, 2009 SoCalGas Comments at 4.
20 PG&E provided an illustrative analysis showing how customer tolerance for price variances provides a model for establishing hedging parameters, and no actual empirical study was presented.
21 D.02-06-023, D.02-08-070, and D.04-01-047.
