2. Background
On June 7, 2007, the Commission issued D.07-06-013 which ordered that a rulemaking be instituted to undertake a review of the gas utilities' incentive mechanisms and the treatment of hedging under those incentive mechanisms. On December 6, 2007, the Commission issued D.07-12-002, which granted the Division of Ratepayer Advocates (DRA) petition to defer issuing the OIR to June 2008.3
First authorized by D.93-06-092 for SDG&E, gas cost incentive mechanisms were intended to be an improvement over traditional reasonableness reviews whereby costs were merely passed through to ratepayers with no recognition of superior management success in lowering costs. While certain details differ, all utility incentive mechanisms compare the cost of natural gas purchases to a monthly market gas price benchmark, and allocate a share of the performance that is either better or worse than the benchmark between shareholders and ratepayers. A "dead band" around the benchmark delineates the range of costs to be shared by ratepayers and shareholders.
Unlike the traditional reasonableness review, the incentive mechanisms reward utility management for lowering gas costs to ratepayers, but also reduce utility earnings if costs rise relative to the benchmark. At the same time, the incentive mechanisms eliminate the requirement for hindsight reasonableness reviews of costs, thereby reducing regulatory burdens and complexity for all parties. In this manner, the incentive mechanisms are designed to: (1) promote sound business decisions regarding gas purchases without micromanagement by regulators; (2) encourage innovative methods for improving performance; (3) allow flexibility to adjust to changing circumstances; and (4) preserve accountability for management actions.
The Commission has repeatedly expressed support for regulatory mechanisms that provide utilities an incentive to manage costs well through exposure to risks as well as opportunities for rewards for sound management decision-making.4 The potential for a shareholder reward or penalty has encouraged the utilities to make timely and appropriate decisions in a dynamic market to compete vigorously for the lowest-cost supply and delivery of gas.
In addition to the goal of minimizing the overall level of gas costs, another closely related management goal is to mitigate the volatility of gas prices paid by core customers. The Commission recognizes financial hedging as one of the tools to be utilized to protect core customers from extreme price increases. Financial hedging is a form of price insurance used to protect customers from excessively high and volatile natural gas price swings. The hedge involves one or more financial instruments arranged with a counterparty providing a guarantee that the price exposure for the hedged portion of gas supply does not exceed a designated level.5
As is true with all insurance, there is a cost involved in obtaining this price protection, and hedges entail their own risk. For example, if the utility hedges against an increase in the price of natural gas by agreeing to buy large quantities at a fixed price, and the market price of gas declines below the fixed price, ratepayers would be worse off with the hedge. Under such a scenario where gas prices decline, the utility's counterparty may demand collateral from the utility to mitigate the risk that the utility will not pay the agreed-upon price, and instead purchase lower cost gas from another party. The demand for collateral constitutes a "margin call." Depending on the counterparty, a margin call could be in the form of cash or letters of credit. The New York Mercantile Exchange (NYMEX) only accepts cash, while others accept cash or letters of credit. The potential for such risks is not merely theoretical. In D.06-11-006, for example, we provided PG&E with the ability to finance large margin calls on gas hedges by expanding PG&E's general short-term debt authority from $1.5 billion to $2.0 billion. Additionally, D.06-08-027 excluded from PG&E's Core Procurement Incentive Mechanism (CPIM) all of the costs and benefits of hedges resulting from PG&E's approved gas hedging plan. Thus, PG&E had no risk either for the costs of hedges or for margin calls on gas hedges that result from its approved hedging plan.
Therefore, in this OIR, we shall assess the value of price protections offered by hedging weighed against the associated costs of hedging, including the potential risks of margin calls. Moreover, it is essential to address whether or how potential risks and rewards involved with hedging should be shared between ratepayers and shareholders to provide the appropriate incentives and accountability for management decisions.
Prior to 2005, financial hedges were always a part of each utility's respective incentive mechanism. Each utility purchased hedging instruments over the years as part of its natural gas portfolio subject to its incentive mechanism. However, as a result of severe disruptions in natural gas supplies and prices in the summer of 2005, the utilities requested a modification in their respective incentive mechanisms.
The primary cause of these disruptions was Hurricane Katrina which struck on August 29, 2005, hitting the heart of the natural gas and oil producing region of the Gulf of Mexico. Hurricane Katrina-and to a lesser extent Hurricane Rita-had a major adverse impact on natural gas markets, contributing to significant increases in the price of natural gas throughout the United States. Gas prices for the following winter rose from $10 to above $12.00 per million British thermal unit (MMBtu) (or per decatherm, Dth) on NYMEX, and created the substantial possibility of further multi-dollar per MMBtu increases due to the resulting loss of gas production. The fact that these hurricanes came not long after the 2000-2001 energy crisis when natural gas prices at one point hit $60 per MMBtu contributed to the many perceived factors to act and protect core customers from gas price volatility.
With the-then upcoming 2005 winter, another hurricane in the Gulf of Mexico affecting gas supply could have had a significant upward effect on prices. Typically, September is the peak month for hurricane activity furthering the cause for concern.
Consequently, on September 13, 2005, PG&E filed a Petition for Modification, on an emergency basis, of D.04-01-047.6 That decision, among other things, approved the continuation of PG&E's Core Procurement Incentive Mechanism (CPIM). PG&E argued that emergency action was needed to protect its core gas customers from natural gas price spikes in the coming winter and in subsequent winters because the recent events highlighted the market's volatility and susceptibility to sudden and sustained price spikes due to events such as Katrina.7 PG&E requested that all costs incurred under its proposed hedging plan on behalf of its core gas customers for that winter be accounted for outside of the CPIM, with 100% of the hedging costs and benefits passed on to core customers.
On October 11, 2005, SoCalGas and SDG&E filed a similar emergency petition to modify D.02-06-023 and D.03-07-037. Similar to PG&E's request, SoCalGas and SDG&E sought to modify their respective Gas Cost Incentive Mechanism (GCIM) and Gas Procurement Performance Based Ratemaking (PBR) Mechanism so that they could undertake an expanded level of hedging of their natural gas purchases on behalf of their respective core gas customers for the coming winter. The emergency petition also requested that all of the costs and benefits of the expanded hedging plans, and the gas hedging that had already taken place for the 2005-2006 winter, be allocated directly to their core gas customers.
The utilities generally argued that the existing incentive mechanisms did not provide adequate protections to motivate management to engage in optimal levels of hedging needed to protect ratepayers. Based on their claim that hedging instruments generally entailed too much shareholder risk under the existing incentive mechanisms, the utilities requested that costs of the proposed hedging plans for that winter be removed from the incentive mechanisms.
On October 6, 2005, the Commission issued D.05-10-015, approving PG&E's confidential hedging plan and removing the expenditures of winter financial hedging from PG&E's CPIM. On October 27, 2005, the Commission issued D.05-10-043, likewise approving SoCalGas and SDG&E's confidential hedging plan and removing the expenditures on financial hedging from SoCalGas' GCIM and SDG&E's PBR.
On August 24, 2006, the Commission issued D.06-08-027 approving the confidential hedging plans of PG&E, SoCalGas and SDG&E8 for the 2006/2007 winter season. In this decision the Commission limited hedging expenditures for the three utilities to $14 per core customer on average for the 2006-2007 winter season, or to the utilities' proposed expenditure amounts-whichever was lower. (However, the Commission determined that these limits would not include any costs associated with swaps or futures.) Similar to the prior year's hedging decisions, D.06-08-027 removed the expenditures authorized for financial hedging from the utilities' respective natural gas cost incentive mechanisms. Instead, all of the costs and savings, if any, from hedging were assigned 100% to ratepayers.
In D.06-11-066, the Commission authorized PG&E to issue $500 million of additional short-term debt, for total short-term debt authority of $2 billion, for use in financing margin calls on gas purchase contracts and Commission-authorized hedges that could result from declines in the price of natural gas.9 This action further increased potential ratepayer risk from hedging.
On June 7, 2007 the Commission issued D.07-06-013 approving PG&E's Application 06-05-007 for authority to purchase gas hedges for seven years following a pre-approval of its annual plan by way of an annual expedited advice letter process. Financial hedges would be undertaken on a rolling three-year basis via an Annual Plan filing. There will be five Annual Plan filings beginning with the 2007-2008 winter season that will authorize a hedge plan for the current winter season and the subsequent two winter seasons. Thus, the final Annual Plan (Year five) will be filed for the 2011-2012 winter season and this plan will run through the 2013-2014 winter season. Starting in 2009, if any member of the Advisory Group10 desires to change or modify the program, it can notify the other members of the Advisory Group by February 1, and PG&E, after discussions with the Advisory Group, must file by June 30 before the Commission an application or other filing vehicle to continue, modify or terminate the program.11
D.07-06-013 authorized PG&E to continue to spend core ratepayer funds on hedging instruments outside of the CPIM. Ratepayers assume all costs of these purchases and receive all of the benefits, if any. The CPIM imposes some risk and provides some rewards to PG&E depending on whether PG&E's gas purchases are more or less expensive than a market-based benchmark.
On December 6, 2007, the Commission issued D.07-12-019 approving among other matters a three-year hedging period for SoCalGas and SDG&E, subject to reevaluation after the third year, which is the 2009-2010 winter hedge period. D.07-12-019 also consolidated the separate gas commodity procurement and management functions of SoCalGas and SDG&E into one gas portfolio to be managed by SoCalGas. It further adopted the proposal that the combined procurement function be subject to SoCalGas' GCIM.
SWG requested Commission approval of a gas cost incentive mechanism in 2004, and the Commission in D.05-05-033 granted SWG's request. In response to the other utilities' requests that prompted D.05-10-015 and D.05-10-043, SWG stated that since it had recently begun operating under its first GCIM cycle, it had already implemented its hedging program for the 2005-2006 period and that it did not recommend suspending its program. As explained in more detail below, SWG's GCIM contains a "Volatility Mitigation Program" (VMP) which involves fixed price contracts entered into for price mitigation. These fixed price contracts are the hedging instrument used by SWG to protect against extreme price increases. SWG does not engage in financial hedging. The VMP purchases are flowed through to its customers, and thus have no impact on GCIM rewards or penalties.
3 The Commission granted deferral to avoid scheduling conflicts with SoCalGas' and SDG&E's Biennial Cost Allocation Proceedings (BCAPs).
4 D.02-06-023, D.02-08-070, D.04-01-047.
5 Examples of financial hedging instruments include options to purchase or sell gas at a predetermined price or contracts for a future delivery of a fixed amount of gas at a fixed price.
6 That decision was in Rulemaking (R.) 02-06-041. PG&E served its petition on the parties to that proceeding.
7 D.05-10-015 at p. 1.
8 These hedging plans will remain confidential as there is highly sensitive market information involved and if released, could work toward the detriment of utilities' ratepayers.
9 We expressed concern in D.06-11-066 that PG&E margin calls on gas hedges could reach $900 million, which could signal an impending large-scale failure of PG&E's hedging activities. PG&E's ratepayers might then have to pay significantly more than the then-current market price of gas. In light of this risk, PG&E was required to provide notice whenever margin calls that are 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 (see D.08-01-010, OP 2).
10 Pursuant to D.07-06-013, PG&E established an advisory group comprised of TURN, DRA, & Aglet for purposes of representing the core interest.
11 D.07-06-013 at p. 5.
