Lacking regulatory oversight, financial hedges turn into risky speculation.
John A. Neri is a principal with energy consulting firm Benjamin Schlesinger and Associates, and is a lecturer in economics at the University of Maryland.
Natural gas distribution utilities have used financial derivative instruments such as futures, options and swaps to hedge gas commodity cost since the 1990s. The primary motivation on the part of utilities and their regulators is price stability to protect consumers against spikes in gas prices. Surveys conducted by the Natural Regulatory Research Institute (NRRI) and the American Gas Association (AGA) in 2008 and 2009 show most state regulatory commissions in the U.S. support or are neutral to local distribution companies (LDC) using financial instruments to hedge gas price movement. However, regulators now are questioning LDC hedging programs in light of large losses some utilities have experienced with them. Also, low price volatility and declining and stable gas prices since 2009 are causing regulators to question the need for hedging programs. Regulatory Commissions in Nevada and British Columbia have suspended hedging activities using financial instruments, and other jurisdictions are targeting financial hedging programs for additional review.
As currently structured, regulators see the costs to consumers of the hedge programs only after the fact when utilities file for cost recovery. But, it’s difficult for regulators to assess the benefits of hedging after the fact, because the benefits can’t always be determined with precision. It’s therefore necessary for regulators to be involved before the fact. Regulators must be actively involved in plan development and in overseeing the use of financial hedge instruments, requiring utilities to submit hedge plans for review and to file periodic reports monitoring the progress of hedge plans.
Moving upstream, you find that FERC-regulated pipelines aren’t in the merchant business of buying and selling natural gas and therefore don’t have a need to hedge gas cost. FERC hasn’t needed to address hedging of commodity cost. However, pipeline companies do trade financial derivative instruments purportedly to hedge other costs, such as debt cost. To the extent this practice is growing, it might be necessary for the FERC to adopt a policy on hedging.
Pipelines, sometimes through their unregulated affiliates acting as agents, use financial derivatives to, in effect, hedge interest rate risk. There’s no FERC stated policy on appropriate financial hedging processes or activities on the part of—or on behalf of—jurisdictional pipelines. For example, special concern might be warranted by apparent hedging activities undertaken at the parent level through the corporate financial office. Is the holding company using financial derivatives to protect the pipeline subsidiary’s customers, or is it trading around interest rate movements for shareholder gain with the understanding that, if the bet is wrong, the losses can be recovered at the regulated subsidiary pipeline level as a claimed debt cost? Without a stated policy, FERC is forced to determine after the fact whether the so-called “hedge” is undertaken to control cost for the benefit of customers or for potential speculative gains.
The recent widely-publicized loss of almost $6.0 billion by JP Morgan from supposed financial hedges clearly demonstrates the high level of risk associated with these instruments. If professional financial firms lose large amounts of money in short periods of time trading in their area of expertise, pipelines also might be likely to lose large amounts. This latest meltdown in financial markets resulting from trading financial derivative contracts should draw the attention of utility and pipeline regulators. The difference here is that pipeline companies trade in financial derivatives and have the incentive and the ability to pass losses from these financial bets at the parent level down to subsidiary pipeline subsidiary level—to be borne by captive pipeline and utility customers. Does this special ability create a different set of risks than JP Morgan’s losing trades, whose losses are borne strictly by shareholders and not the bank’s customers? Moreover, there are similar moral hazards in each case; Banks have the incentive to take on excessive levels of risk knowing regulators will bail them out if their bets result in catastrophic losses and insolvency. Utilities and pipelines have to incentive to take on excessive risk knowing they can pass the losses onto customers in the form of debt costs recovered in rates.
Utility and pipeline customers are protected only by their respective regulatory commissions, and commissions need to appreciate the potential hazards related to trading financial derivatives.
Interest Rate Swap Loss
In one recent case, a FERC-regulated pipeline has proposed to pass a $20 million loss on an interest rate swap contract onto its captive customers. Portland Natural Gas Transmission System (Portland) is substantially owned (61.7 percent) by TransCanada Corp., one of the largest energy infrastructure companies in North America, with natural gas pipelines in Canada, the United States, and Mexico.
Portland had $250 million in debt to refinance in March 2003. In October 2001, TransCanada’s treasury department entered into forward interest rate swap agreements to purportedly hedge against the possibility of higher interest rates 18 months in the future at the time of Portland’s debt refinancing. At the time the swap was entered into, U.S. government bond yields had fallen in response to stated Federal Reserve policy to lower interest rates in order to stimulate the level of economic activity in the U.S. The Federal Reserve in late 2001 and throughout 2002 stated its policy was to keep interests low for the foreseeable future. In effect, TransCanada’s forward interest rate swap contracts were a bet against U.S. policy to lower interest rates. The interest rate swap contracts were structured such that they resulted in gains to TransCanada if interest rates increased, and losses if interest rates decreased. The swap contracts were also structured such that relatively small upward or downward movements in market interest rates could cause a large gain or loss in a short period of time.
The forward swap agreement was a 10-year contract with a start date in March 2003, structured such that movements in interest rates at any point in time between the contract date and the start of the swap were essentially multiplied by a factor of 10—because of the 10-year nature of the contract. A 10-basis-point movement on a $150 million notional amount created a $150,000 loss, multiplied by 10, and then discounted to the present. In Portland’s case, interest rates moved down by 180 basis points, creating a loss of about $21.0 million over a 17-month period. TransCanada lost its bet as interest rates continued to fall.
In a rate case with the FERC, Portland filed to recover from its customers what it claimed was a hedge loss, arguing that the $21 million loss was a debt issuance cost related to the debt refinanced in 2003.
Portland’s customers saw this loss only after the fact. Their only recourse was to intervene, challenging the loss and pointing out other actions Portland could have taken to mitigate the risk of interest rates rising in the future. While Portland argued the forward interest rate swap contract was a hedge, the swap contract was in fact a speculation on the movement in U.S. Treasury interest rates. TransCanada had speculated against Federal Reserve stated policy at the time to keep interest rates low for the foreseeable future—a risky bet on the company’s part.
‘Woulda, Shoulda, Coulda’
Addressing the swap loss after the fact led a FERC administrative law judge to conclude the customer arguments were “woulda, shoulda, coulda.” Such a conclusion clearly highlights the need for regulators to address hedging programs beforehand and not after the fact in a rate case. As it stands now, customers only have a say after the fact, as part of a rate case. The pipeline or its parent can gamble, knowing the loss can be pushed onto customer. At the same time, it’s not clear whether customers would benefit from a gain.
Financial hedging is a complex and potentially costly activity that merits careful oversight by regulators. The FERC should consider the following kinds of involvement:
n Pipelines should be required to submit a hedge plan for Commission review. The plan should clearly lay out purpose, design, execution and risk control elements.
n After approval, the Commission should require pipelines to report on hedging activities on a regular basis.
n When a pipeline seeks recovery of claimed hedging costs, this must be reviewed against the hedge plan parameters.
Absent a FERC policy or requirement for plan review, pipelines at a minimum should be required to reach an agreement with their customers on the level of the hedge cost that customers find acceptable. This is clearly feasible for gas pipelines, which have dozens of customers with whom they must reach an agreement—compared to LDCs’ hundreds of thousands of customers.
The purpose of the hedge is to protect the customer, in this case, the pipelines’ shippers. These customers clearly have a stake regarding acceptable costs.
1. “NRRI Services: Survey on State Commission and Local Gas Distribution Company Actions in Addressing High Natural Gas Prices,” National Regulatory Research Institute, July 3, 2008.
2. McDowell, Bruce, “AGA Rate Inquiry: Regulatory Hedging Policies,” American Gas Association, Fall 2009.
4. If the bank were to become insolvent, creditors and the tax payers bear the burden. Depositors are protected by the government safety net provided by FDIC Insurance.