New policies on everything from climate change, wholesale market rules, and the greater adoption of renewable technologies are changing the risk calculus for the entire utilities industry. Many utilities executives believe that survival of the fittest will mean understanding the new risks better than other executives, and they are putting serious money behind that endeavor, according to some experts.
Steve Hanawalt, global energy and environmental executive at performance management software developer OSIsoft, says the race is on to develop better, faster, more comprehensive analysis and systems for this brave new world.
“As we start looking at the market, what we’re seeing is you have huge complexity coming at the market. We talked about the … markets going from zonal to nodal. Now you need these complex network models with the ability to forecast [locational marginal prices],” he says, addressing market developments in Texas and California.
Furthermore, Hanawalt says most of the industry not only believes that some sort of carbon legislation will be enacted by Congress, but the industry actively is building systems to model how carbon caps will change how the markets operate.
“You have carbon [legislation] coming, which for some assets adds from 1 to 20 percent of their variable cost. A coal unit that was on the margin is no longer on the margin. Gas might be on the margin now. You really could have a shift in which assets get dispatched based on a company’s exposure and their carbon footprint,” he says.
In fact, Hanawalt believes the recent decision by TXU to scrap its coal plants in response to environmental concerns may be the first of a trend where “utilities may want to divest coal assets.”
He says most of the system developers for energy trading and risk management are getting into the business of preparing their databases for pulling in the carbon position of the utility and being able to manage the risk of that carbon “and to trade around the assets of the carbon.”
Hanawalt says the Structure Group, Sungard, and others are all developing this capability.
Angela Ryan, director, the Structure Group, describes what is dominating risk management and energy trading system discussions.
“With the shift to asset-centric trading models, the top issue our clients face is how to holistically manage their risks across the enterprise while optimizing their assets to their fullest potential,” she says. Ryan says utilities want risk-management systems that have the ability to achieve an, “accurate view of all trading and asset positions and exposures, perform sophisticated portfolio analytics, and ensure hedging strategies are executed appropriately.”
On the assets-optimization side, she says utilities want to invest in systems that automate physical logistics and optimize generation, load forecasting, strategic bidding tools, and storage/transport capacity utilization.
But putting together the ultimate system, all agree, will be easier said than done given the new challenges.
Hanawalt predicts significant data management and analysis challenges, and thus risks, from the greater adoption of real-time metering as part of demand-response programs. Renewable portfolio programs that emphasize renewable energy technologies that are intermittent (such as wind) also are making risk analysis more complex as it is difficult to know when it’s being dispatched.
“So, if you look at what’s happening, the grid is getting really, really complex. The amount of dataflow that has to be assimilated by a utility to manage the reliability of the grid, while at the same time trying to maximize its portfolio value, has just gotten extremely complex.”
Even as the industry prepares for the new side of risk management, there still are some basic elementary business risks that many utilities are addressing. John England, Deloitte & Touche LLP’s managing partner, Global Energy Markets, says utilities continue to come to Deloitte more for risk-management performance measurement. His clients, both in regulated and unregulated utilities, have been asking to improve the communication of profit-and-loss and risk reporting.
“What we find is that a lot of utilities are struggling with the ability to get good daily and monthly reporting of profit and loss, and risk metrics like earnings at risk. The obstacle is that they tend to have multiple systems and because of that they need something that brings the information together and helps them report in a meaningful way.”
The problem, England explains, is that many utilities have data about their purchases and sales of energy on multiple systems. “They may have one system that handles coal, one system that handles gas, one system that handles power, or, in other words, silo issues.”
But he believes utilities have come a long way from the early days of risk management. He says utilities have become better at managing market risk and credit risk as a result of the lessons learned during the Enron collapse.
Furthermore, the industry is starting to evolve and is beginning to look at other risks such as operational risk and regulatory risk, he says.
“Utilities have known the importance of regulatory risk, but now they are trying to quantify the earnings impact of that. What we are encouraging companies to do is implement a truly enterprise-wide risk-management capability, what we call risk intelligence, where they look at all these risks across business units and risk types,” England says.
Of course, England admits that these risks are the most difficult to quantify, but necessary. Such as asking, “What is the impact on my earnings if I have an outage during peak period?”
These are the things that are on the cutting edge, he says. “We think if these companies can quantify these kinds of risks, they can make better investment decisions, better capital allocation decisions, and better performance management decisions,” he says.
Furthermore, England believes the best examples of the benefits of risk management are around capital allocation decisions.
“So, [if] I have a limited pool of capital to spend, I’m going to spend it in areas where I get the most return. So, I have to be able to look at potential investments on a risk-adjusted basis, which means I have to be able to identify those risks.”
For example, if a utility has to spend “X” and understands the risks of five potential projects, and can further identify the risks of each project and compare the risk-adjusted returns of those five projects and allocate X in the most cost-effective manner, England says that maximizes the utility’s risk-adjusted returns.
“The investment could be a new generating plant, building new transmission or gas transportation, gas storage facilities, or even putting a scrubber on a coal plant. As markets get more competitive, we believe that utilities [that] are able to evaluate investments on a risk-adjusted basis, they are going to have a real advantage.”
Meanwhile, Vincent J. Kaminski, professor of executive education at Rice University, in a panel discussion during the CERAweek 2007 conference earlier this year, cautioned that many companies shouldn’t engage in hedging unless they have a very strong risk-management culture and understand the consequences of the hedging.
“Putting on the wrong hedges or not understanding fully [the risks] are potential dangers,” Kaminski said.
“How utilities are focused on risk management depends on the type of utility,” says Mike Muse, New Energy Associates’ head of Energy Trading Risk Management.
“Non-competitive utilities which are not in an RTO and not facing any type of competition, they are not really worried about market risk or their exposure. They are focused on volumetric risk.”
Muse says regulated utilities are concerned with the risk of being brought before the commission and explaining why the lights went off.
Of course, that is not to say they are not interested in risk management. In terms of their systems, they have been focusing on reducing the number of older systems.
“They do want to show that they are doing their part [on risk management]. Some of the systems that they have make that process slower and more expensive. I think what we see in that niche is primarily driven around cost and making sure they can get information to regulators rather than actively managing exposure,” he says.
Utilities that are facing competition are “clearly worried about hedging their risk to prices just like everybody else playing in the wholesale market.”
Muse sees one trend among competitive utilities—their move to new metrics from value-at-risk (VaR) to an earnings-at-risk (EaR) model.
VaR is a measure of how the market value of an asset or of a portfolio of assets is likely to decrease over a certain time period (usually over 1 day or 10 days) under usual conditions.
EaR, unlike VaR, is used as a longer-term risk measurement to estimate and manage earnings volatility. And unlike VaR, which measures a period no more than days, EaR measures earnings volatility over monthly, quarterly, semi-annual, and annual time periods.
According to analysts, EaR is versatile, as it can be used to focus closely on the cost side (price and volume of the input fuel) as well as on the revenue side (price and volume of output).
Meanwhile, the Structure Group’s Ryan finds that “in today’s competitive markets, generators are constantly seeking to reduce costs by various means, including savvy fuel purchases, better risk management, more efficient operations, and fewer, but more productive, maintenance outages.”
Many experts believe the best way to meet the greater complexity and consequent risks utilities will face is to have more efficient and more liquid markets. That result can be achieved by continued rationalization or improvement of the way the market is run.
For example, Bob Levin, senior vice president of research at the New York Mercantile Exchange, is calling for the decoupling of the market from the grid manager.
“We’ve seen that the cash market by being part of an [independent system operator] is subject to the same governance as the ISO, and we believe we have seen the hampering of innovation and growth in those market mechanisms. So, we haven’t seen a lot of advancement there and we have seen some of the ISOs struggle as they try to introduce advancement,” he says, adding that he is skeptical that they will be able to produce innovation. “The idea of separating those functions makes sense,” he says.
“There’s inertia there. As long as you are talking about markets that are under the auspices of the ISO, they are going to change at the pace that ISOs processes change, and that’s slow,” he says.
Levin believes that if the cash market were allowed to evolve more naturally, it not only would offer innovation in that market, but also would result in more financial market solutions for risk management.
Similarly, New Energy Associates’ Mike Muse finds a need for the RTOs to become more standardized in their business practices.
“What needs to be standardized is the market approach. If you look at how the RTO in ERCOT functions, they have a huge Web site where you can read about all the different rules and how they set prices, for example. These are business standards. The cost of building a solution (whether internal or third party) goes up dramatically because of the lack of standardized business processes,” he says.
Muse says many of the markets like PJM and MISO will have similarities, as they have made efforts to standardize, but they are dramatically different from an ERCOT and [the California] ISO.
“Now you see ERCOT moving to an LMP model, and that’s a good indicator, but there are still vast differences between them,” Muse says. Astutely, Muse captures the reason why creating a common market and rational risk-management techniques for a new era is difficult. The reason for the continued differences in RTOs is partly due to “the actual grid and the actual assets on the ground,” and partly “because different people were responsible for starting different markets.”
Putting it another way, the comic-strip character Pogo would say: “We have met the enemy, and he is us.”