The energy markets used to be easy to sketch on a cocktail napkin—you could draw a line from one seller to one buyer in a straightforward diagram marked by long-term contracts, fixed prices and limited geographic boundaries. One result was that risk-management tended to be relatively straightforward as well. But in 1996, when FERC’s landmark order 888 forced America’s then-insular power systems to open their transmission lines to energy generated and moved by other players, everything changed. Sixteen years later, in fact, our electricity markets are still adapting to this huge shift. The cocktail-napkin diagram for today, after all, would include scribbles for myriad suppliers, short-term contracts, tiered pricing schemes, variable hedge structures and a raft of power “products” customized for users’ diverse needs.
All of this evolution has led to fantastic opportunities, but this process has been about as efficient as, say, diverting traffic from Interstate 75 to an unpaved country road. Individual transmission systems continually bump into capacity constraints as they try to provide reliable energy supplies to multiple users. And it is not just the old transmission infrastructure that needs to evolve—the open-access era has created a host of new risk-management challenges as well.
Years ago, a big utility could focus its risk-management efforts on a narrow set of contingencies, but with the advent of an unbundled and open-access system, utilities made the jump from simple arithmetic to complex calculus. Thanks to the multiplicity of users and movers, for example, potential choke points are much more commonplace. In the earlier era, a utility could fairly quickly answer the question, “Will we be able to move X amount of power at 2 p.m. tomorrow?” Today, such a question cannot be answered without asking many more questions: What is the demand for firm (i.e., guaranteed) transmissions? Which entities need unit-specific power from particular locations within the grid? What will it take to meet demand for open-ended sales from broadly distributed points on the network? And more.
Generation reliability is the goal, of course, and this means utilities must fully understand, not only the physical capacities of their generators and grids, but also the ever-shifting demands of their customers. Practices such as locational marginal pricing (LMP), in which utilities charge variable price points based on the specific transmission paths of purchased power, can be used to help shape demand. But the analyses required in today’s world are vastly more complex than before. Fortunately, energy advisors and engineering companies can work together to conduct thorough audits for the utility, in part by relying on new software that can predict breakdowns. The advantages of such predictive data are considerable: If a utility knows where the greatest risk of a breakdown happens to be, then it knows where to focus its maintenance money. This also helps utilities target construction programs, plan workflows and assign employees. Yet, many utilities still have not taken advantage of predictive data. The upfront investment can be significant, but it is often worthwhile.
Prior to the open-access era, the fixed market meant that providing insurance against hedge-related risks was simply not part of the equation. But with the trading of various power products today, risk profiles are substantially more complex. Yes, long-term contracts continue to be low-risk, but shorter-term contracts have proliferated to such an extent that day-ahead transactions are now commonplace. This is part of the reason hedges have become more prominent, whether a physical hedge (“We will sell you power, and if we can’t deliver it, here’s a backup source that will”) or a financial hedge (“If we cannot deliver, here’s an insurance policy in the form of money you can use to get that power elsewhere”).
How a power company might manage the purchase of a hedge depends on the myriad transactions in play within the system. It also hinges upon factors such as the quality of the generators and the grid. The risk analysis here, too, is important: “Do we want to hedge all $1m of the power we’re selling? Or can we hedge half of this because our system is in good shape?” The various power products being traded today create distinct and variable risks, all of which must be carefully analyzed. For those on the buying side, meanwhile, hedging partners must be thoroughly vetted. The due diligence here should involve looking closely at lenders, financial statements and company histories.
Continually investing in new technology is also a bigger part of risk management today. It is particularly important to invest in high-quality control and monitoring equipment: Utilities must make sure their systems avoid local outages caused by having too much of somebody else’s power moving through them. They also need to minimize transmission loss. It is a far cry from the earlier era, when utilities could coast a bit with their technology investments. Failure to invest in maintenance and replacement for today’s sprawling systems also translates directly into higher risk. The same is true of failure to invest in new transmission capacity: The proverbial two-lane road can only handle huge volumes of traffic for so long.
Today, utilities also must be hyper-vigilant about changes on the regulatory front. The latest example is the Commodities Futures Trading Corp’s (CFTC) decision to regulate hedging in the electricity markets under the auspices of Dodd-Frank. Rules and regulations will be forthcoming as CFTC puts power industry compliance and reporting under the microscope. Meanwhile, 27 states now have renewable portfolio standards (RPS), and these rules, like all regulations, are subject to continual change. The injection of renewable energy into the grid creates certain operating risks. Failure to properly integrate renewable energy with the base-load, for example, could result in significant fines and penalties as companies fail to meet their RPS obligations.
In the earlier era, power companies faced some degree of environmental regulation, but things are far tougher today, with the Clean Air Act amendments, historic preservation requirements, watchdogs, whistleblowers and more. Today, utilities face a profusion of possible claims related to their operations. This is why it can be a good idea for utilities to work with experienced energy counsel to schedule periodic training sessions for in-house attorneys to keep them updated on new electric industry regulations and possible impacts on their utilities. The energy team can also set up education sessions in which utility executives describe the latest company and industry developments.
The power business has changed drastically and will never be like it was prior to open-access. There may still be old hands here and there who long for the stability of the past. This is understandable—anytime your business model changes, more obligations are created. But with obligations come opportunities. Ultimately, the function of best-in-class risk-management is to make it easier for companies to pounce on those opportunities and prosper into the future.
Roy M. Palk, Esq, a 40-year veteran of the electric power industry, is the former President and CEO of East Kentucky Power Cooperative. He is Senior Energy Advisor for the national law firm LeClairRyan and is a member of the firm’s Energy Core Leadership Team.