4. The Role and Significance of Hedging in Managing Price Volatility

As a starting point for considering regulatory reforms, we identify the role and significance of hedging as a tool to manage price volatility. Next we consider, how hedging cost recovery currently works.

The potential for volatility in gas prices warrants serious consideration of measures to promote the appropriate use of hedging to protect against price spikes. At the same time, the regulatory treatment of hedging costs should not be driven solely by short-term market conditions. Regulatory policies should accommodate different market conditions over time, during periods of market stability as well as where sharp price swings may be more likely.

We have repeatedly acknowledged that gas prices exhibit significant volatility, particularly with the devastating hurricanes that struck the Gulf Coast in 2005. For example, as stated in D.05-10-015:

...Hurricane Katrina has had a major adverse impact on natural gas markets, contributing to significant increases in the price of natural gas throughout the United States...The problems caused by Hurricane Katrina have come on the heels of several years of sustained high gas prices. Prices for natural gas already had been on an upward trajectory since early 2002.

In D.06-08-027, in reviewing hedging plans for the 2006-2007 winter season, we found "evidence that natural gas markets have become increasingly volatile, which has increased the costs of and the risks associated with purchasing hedging instruments."

In D.07-06-027, the Commission stated:

...natural gas prices have continued to remain both volatile and high in 2007 compared with historical averages and do not appear likely to return to historical experience any time soon.

...The threat of price spikes this winter cannot be ruled out. Hence, prudence dictates that we act now to protect customers from further price run-ups by providing SoCalGas flexibility to respond quickly to the changes in the natural gas market instead of reacting to an unforeseen event. (D.07-06-027 at 4.)

By moderating the volatility in gas prices, hedging can promote the goal of reliable gas supplies at a reasonable cost, consistent with the Commission's Energy Action Plan. Therefore, we consider hedging to be important as part of an overall utility strategy in providing reliable gas supplies at a reasonable cost.

Financial hedging is a form of insurance designed to protect customers from extreme natural gas price volatility. Hedging is implemented through financial instruments arranged between the utility and a counterparty to transfer certain price risks to the counterparty. Examples of hedging instruments may include:

· Futures contracts obligate a buyer (i.e., the utility) to take delivery and obligate the seller to provide delivery of a fixed amount of natural gas at a predetermined price at a specified location.

· Call Options give the purchaser the right, but not the obligation, to purchase a New York Mercantile Exchange (NYMEX) Henry Hub natural gas futures contract⁶ at a predetermined fixed price (or "strike price") on or before a specific date (an "expiration date").

· Put Options give the purchaser the right, but not the obligation, to sell a NYMEX futures contracts at a predetermined fixed price on or before a specific date.

· Basis Swaps give the buyer the obligation to pay or receive the value difference between the purchase price and the settled spread between the NYMEX Henry Hub futures and a defined locational index.

· Fixed Price Swaps give the buyer the obligation to pay or receive the value difference between the purchase price and a natural gas index settlement price. It involves no up-front premium.

Hedge instruments transfer price risks associated with future price uncertainties at the time when gas supplies are actually delivered. Hedges, however, entail their own separate risk. Moreover, some hedging instruments entail greater risk than others, while offering the opportunity for greater savings. For example, "swaps" offer the potential to essentially pay below-market rates for gas, if commodity prices rise, but also entail the potential risk of greater loss compared to options, if commodity prices fall. Call options also do not provide for cost savings until the commodity price rises above the "strike price" of the option.

Hedges can lose value or expire worthless depending on their terms and market conditions. A utility may be required to provide collateral in form of a "margin call" to counterparties to mitigate default risk if a hedge loses value. For example, in D.06-11-006, the Commission authorized PG&E to issue short-term debt to finance margin calls on hedges that could result from declines in natural gas prices.⁷ In authorizing this authority, the Commission expressed concern that such margin calls on gas hedges could reach as much as $900 million. As stated in D.06-11-006, if this were to occur, it could signal a possible large-scale failure of PG&E's hedging activities. PG&E's ratepayers might then have to pay $900 million more than the then-current market price of gas. In order to monitor the process, the Commission required PG&E to provide notice when margin calls not offset by other hedges reached prescribed levels.⁸

Managing a hedging strategy successfully is a complex undertaking. Insufficient hedging may expose customers to undue risks of gas price spikes. On the other hand, a poorly managed hedging plan may cost more than its value as a protection against price volatility.

While hedging can mitigate volatility in wholesale market prices, it should be coordinated with other tools to manage overall price stability. On a longer term basis, infrastructure investment in pipeline transmission and storage facilities can reduce vulnerability to market price instability. The utility has discretion in managing its core gas supply portfolio price, and the core customer's gas utility bill.⁹ For example, even if the wholesale market price for natural gas exhibits volatility, the utility may be able to mitigate the effects on its core supply portfolio to some extent through timing of storage injections and withdrawals.

Moreover, even where the utility experiences additional volatility in its core supply portfolio, the effects on customer retail bills may be mitigated through retail billing plans that average out month-to-month gas supply cost swings over a prescribed period. These plans smooth out the impact on bills due to both variations in physical energy consumption as well as changes in unit cost. The use of this bill payment option does not eliminate the ultimate effects of large price increases, but may in some instances allow the timing of bill payment to be smoothed out in a more manageable fashion. Such retail bill payment plans are not a substitute for hedging and do not provide the price mitigation that hedging offers.

4.1. Operation of the Incentive Mechanisms in Relation to Hedging Costs

We next review how procurement incentive mechanisms work in assigning both risks and benefits relating to gas hedging and commodity costs. Prior to 2005, utility costs and offsetting benefits from financial hedges were shared between customers and investors, along with commodity costs, as part of the utility gas procurement incentive mechanism. We briefly review how these incentive mechanisms work.

Procurement costs for the combined SoCalGas/SDG&E portfolio are recovered under the GCIM.¹⁰ PG&E utilizes a similar CPIM. SoCalGas' GCIM is somewhat similar to PG&E's CPIM in structure and concept, but uses a more flexible metric which adjusts to account for the location of actual monthly purchases based on indices of gas prices at these various locations, and adjusts for actual storage activity. Such differences should be considered in developing guidelines and policies regarding hedging among the utilities.

SWG's GCIM is based on transportation, storage and gas commodity costs, and is relatively new compared to that of PG&E and SoCalGas. SWG's hedging activities were negotiated and integrated into SWG's regulatory regime upon its inception. SWG's hedging program does not change from year to year.

The incentive mechanisms measure gas purchasing performance by comparing actual performance against a benchmark cost of gas intended to emulate actual market conditions on a monthly basis. Any resulting difference is allocated as a net cost or savings between shareholders and ratepayers. A "dead band" around the benchmark delineates the range of costs or savings not subject to sharing by ratepayers and shareholders.

These incentive mechanisms replaced reasonableness reviews as a means to ensure the reasonableness of costs incurred on behalf of core customers. Under the previous era of reasonableness reviews, gas costs were passed through on a dollar-for-dollar basis subject to any disallowances for imprudent actions but with no recognition of superior management success in lowering costs. By contrast, the incentive mechanisms reward utility management for lowering gas costs, but also reduce utility earnings if costs exceed the benchmark. The incentive mechanisms eliminated hindsight reasonableness reviews, thereby reducing regulatory burdens and complexity. In this manner, the incentive mechanisms: (1) promote sound business decisions without micromanagement by regulators; (2) encourage innovative methods for improving performance; (3) allow flexibility to adjust to changing circumstances; and (4) preserve accountability for utility management.

DRA has monitored and evaluated the results of the incentive mechanisms for many years and has continuously and unequivocally concluded that both ratepayers and shareholders derive benefits under the incentive programs, as exemplified in its comments.

4.2. Exclusion of Winter Hedging from Incentive Mechanisms Since 2005

From the 1990s up until 2005, both the costs and payouts from winter hedging were fully included in the procurement incentive mechanisms. The Commission changed the treatment of hedging beginning in the fall of 2005, however, in response to petitions filed by the utilities. The utilities sought a change in the regulatory treatment of hedges in response to severe disruptions in natural gas supplies and resulting price volatility beginning in the summer of 2005.¹¹ In anticipation of significantly rising prices in the coming winter season, the utilities sought to increase hedging activity significantly. The utilities were concerned, however, that utility shareholders would be exposed to excessive risks if the costs of this significant expansion in hedging continued to be subject to risk sharing through the existing incentive mechanisms.

Consequently the utilities requested to modify their incentive mechanisms to expand the amount of winter hedging authorized and to assign 100% of those hedging costs to core customers. PG&E was the first to file such a request.¹² In the fall of 2005, SoCalGas and SDG&E filed a similar petition¹³ to assign to core gas customers all costs and benefits of expanded hedging plans for the coming winter, as well as for gas hedging already incurred for the 2005-2006 winter. The utilities argued that without the modification, an expanded hedging program would entail too much risk for investors, and create a disincentive to hedge at a level needed to protect core ratepayers.

In October 2005, the Commission approved PG&E's request, assigning all costs and payouts from winter hedging to ratepayers, and approved a similar arrangement for SoCalGas and SDG&E. In winter hedging plans approved since 2005, the Commission has continued to assign all winter hedging losses and gains 100% to core customers.¹⁴

We next consider whether the current treatment of hedging costs best serves ratepayers' interests, and whether reforms are warranted going forward.

⁶ Henry Hub is a natural gas pipeline supply point located in Louisiana. Futures prices set at Henry Hub are generally considered to be the primary price set for the North American natural gas commodity market.

⁷ D.08-01-010, Ordering Paragraph (OP) 2.

⁸ PG&E was required to serve notice when margin calls not offset by other hedges reached $300 million, $600 million, $900 million, and each $300 million increment thereafter for the first time in each calendar quarter. Most recently, PG&E served notice that on November 13, 2009, margin calls subject to this notification requirement exceeded $600 million. The posting of collateral for margin calls, by itself, has no significant impact on the customer, other than the financing costs associated with posting cash or letters of credit. The financing costs on $600 million of collateral posted would, by themselves, have a negligible per-customer impact.

⁹ See December 9, 2008 DRA Comments at 2.

¹⁰ Since April 1, 2008, SoCalGas' Gas Acquisition Department has become responsible for supplying both its own core customers as well as those of SDG&E through a combined portfolio.

¹¹ The disruption to natural gas supply production was caused largely by Hurricane Katrina-and to a lesser extent Hurricane Rita-which had a major adverse impact on natural gas prices beginning in late August 2005, creating the substantial possibility of further increases due to the loss of gas production.

¹² See PG&E Petition for Modification of D.04-01-047 in Rulemaking (R.) 02-06-041.

¹³ See Petition to Modify D.02-06-023 and D.03-07-037.

¹⁴ See D.05-10-043, D.06-08-027, D.07-06-013, and D.07-12-019.