The winter of 2013-14 offered up a perfect storm of natural gas price spikes and threats to electric reliability. Expect more of the same.
Hedging Under Scrutiny
Planning ahead in a low-cost gas market.
quantitative analysis to determine that during the period following Hurricane Katrina (2005-2006), the utility’s hedges were close to breaking even, i.e., the premium paid for hedging nearly equaled the benefits it provided over spot market prices. But a break-even analysis of the hedging costs compared to spot market prices for the period 2005 to 2008 illustrated that the utility only regained approximately one third of every dollar spent on hedging. Ultimately, in its order, the commission supported the administrative law judge’s position that the utility’s hedging program should not be suspended. In his recommended decision, the judge wrote, “Preapproved elements of the [hedging] plan avoid hindsight evaluation of each program. Simply stated, [the plan] is to be evaluated based upon information available at the time, not in terms of whether the plan ‘beat the market.’ To the extent Public Service implements such a plan, as approved, the associated hedging costs should not be subject to disallowance in any subsequent gas cost prudence review proceedings.” 6
In another example, a commission decided to open a utility’s hedging program to further review. In May 2011, in response to PacifiCorp’s rate filing for Rocky Mountain Power, the Utah Industrial Energy Consumers filed direct testimony asking the Utah Public Service Commission to disallow $19.7 million in revenue requirements related to what the group called “imprudent hedging practices” by the utility. Rocky Mountain Power’s hedging program layered-in hedges 48 months into the future, hedging nearly 100 percent of its open commodity price risk. In the industrial group’s testimony, it commented that the utility’s hedging program wasn’t adjusted to account for changes in market conditions and the expanding supply of natural gas through shale gas production. 7 Hence, the industrial group suggested the utility was imprudent to hedge such a large percentage of its open positions and should have reduced its fixed-price hedges, to leave open one-third of its portfolio to spot market pricing.
In July 2011, a stipulation was filed with the Utah PSC where the parties agreed to a collaborative process to review possible changes to the company’s hedging practices. As part of the stipulation, it was agreed that the utility’s past hedges wouldn’t be disallowed, but that the utility would implement any changes that result from the collaborative process or commission order. Issues addressed in the collaborative process included: a new maximum hedge volume percentage limit or range; risk tolerance bands based on time-to-expiry value-at-risk (TEVaR) or value-at-risk (VaR) limits; position limits; a process for review of hedging transactions outside of accepted guidelines, including natural gas reserves or storage; liquidity, transparency, and other risks of different hedging tools such as financial swaps, fixed-price physical forward contracts, and options; a semi-annual confidential report on hedging status; and coordination and implementation issues relating to the inclusion of financial swap transactions in Rocky Mountain Power’s energy balancing account. 8 The stipulation was approved in a commission order on Sept. 13, 2011, and PacifiCorp and the other stakeholders were expected to complete discussions by January 2012.
In February 2011, the South Carolina Office of Regulatory Staff (ORS) requested