Assessing the risks and rewards of distributed energy strategies.
Hugo van Nispen is executive vice president, energy advisory, at DNV GL – Energy.
There’s an understandable feeling among utility executives that the longstanding regulatory compact under which they’ve operated is at significant risk. For years, the deal seemed straightforward: you invested in necessary infrastructure, you operated cost-effectively and reliably, and your investment yielded reasonable rates of return. Today, the regulatory and political situation for electric power has become increasingly volatile.
Facing the seemingly imminent arrival of large-scale distributed energy resources (DER), utilities are concerned. Regulatory rulings that support consumers bypassing the electric system, but remaining connected to it at no charge for failsafe back up, pose profound economic and regulatory consequences. Potentially disruptive innovation is underway in the global utility market in distributed energy resources, including energy storage, distributed PV, microgrids, demand response, efficiency, and load management, among others.
Utility executives are discussing with regulators the reality that this innovation in DER poses significant business and technical issues, including the effects of cost shifting between rate classes and consumer segments. Distributed solar PV is growing rapidly. But if the interconnection, net metering, and other rules to allocate costs and set rates aren’t handled carefully, the people who will take the brunt of the hit are consumers whose economics don’t allow them to install their own generation. Utility executives share concerns that if load dwindles and DER penetration grows, it could produce, in a worst-case scenario, a self-fulfilling collapse of the electrical system and the current mechanisms that support it.
Somewhat uncharacteristically, utility executives are talking very openly about this, and the issue is a hot topic in boardrooms and regulatory forums. Are DERs really a mortal threat to traditional utility business and regulatory models, or is the so-called “death spiral” threat being overplayed?
The answer will lie in the utility strategy roadmap that executives and regulators will embrace. The journey ahead must include portfolio strategy that takes advantage of the benefits of DERs, while avoiding the pitfalls inherent to particular local conditions or hindered by longstanding (and potentially outmoded) approaches to meeting consumer needs.
It might seem obvious, but it bears stating that each utility and its regulator must tailor an approach to DER to reflect local resources, needs, and circumstances. There are benefits and risks across the adoption life-cycle curve and they must be aligned with current customer conditions, resources, and regulatory frameworks. These localized solutions also must take into account the ability of the infrastructure to effectively absorb this innovation.
In his book The Innovator’s Dilemma, Clayton Christensen describes the pitfalls created when companies focus too narrowly on the near-term needs of customers while failing to embrace new technologies and business models that will proactively address changing customer needs in the future. The global electric utility industry – and by extension the governments and regulators charged with ensuring it meets the needs of stakeholders in the future – face a profound innovator’s dilemma today.
It’s one thing for Steve Jobs to knowingly and creatively destroy Apple’s iPod franchise in favor of the iPhone. It’s quite another thing for a highly regulated, reliable, and cost-effective global industry with a 100+ year history and vast sums invested in installed assets to consider the wholesale changes implied by Christensen’s thesis.
In many cases, what’s at stake is the creative destruction of longstanding interests and an upending of status quo business models in favor of new physical energy delivery architectures, performance-based rates, and new technology. Compounding the challenge for the industry is that utilities are among the most localized of global businesses. In the case of the innovator’s dilemma around DER, it’s at the local level that utilities and regulators must develop a strategy to exploit potential growth in the future.
Utilities and regulators have a series of interrelated questions to consider: Do we stay with coupled rates or consider decoupling? Do we compensate utilities proactively for stranded assets or do we encourage those assets to be run aggressively to end-of-life? Do we compensate utilities for efficiency services the same way we compensate other supply resources? Do we keep the industry vertically integrated, or do we unbundle it in the interest of business model innovation? The questions continue, but they must be considered against the backdrop of what many of energy observers are coming to accept as the new normal.
Three trends have developed that collectively comprise what many executives now consider the new normal. First, the traditional reliance on a continual and steady load growth to fuel both financial results and regulatory and resource planning is no longer a given for most utilities. Second, the transition away from coal and towards natural gas, renewable resources, (and, in some parts of the world, nuclear) is no longer a question of whether, but rather when, and how fast. The risks of this transition and the physical realities of increasingly dependent gas and electric infrastructures are generally underappreciated. In many cases, gas pipeline and distribution capacity expansions are a wildcard cost that will need to be considered. Finally, regulation and the inherent costs of regulatory compliance in all forms are increasing. Regulatory overheads – whether related to reliability challenges from increasingly volatile weather or related to limits on carbon and other pollution in the future – are going to increase regardless of how those limits will be enforced and how the cost of meeting those limits will be addressed.
Early or Late Adopter?
A primary benefit for a utility that moves quickly to embrace DERs is that, to some extent, a utility with strong customer and regulatory relationships might be well positioned to define the market playing field.
Utilities that gain a positive reputation for working with customers to more effectively manage their distributed energy resources and lower their energy costs could benefit in the long run. Some utilities are considering the notion of “owning the electrons,” regardless of source, and are supporting distributed energy resources by either owning the assets or doing power purchase agreements and call options with customers under power purchase agreements (PPA) for both supply- and demand-side DERs. The opportunity to define the playing field and deploy capital models that effectively reward stakeholders could put these utilities in a position to help investors understand and embrace the strategy. In doing so, these utilities could gain market value relative to their peers.
The converse is that a utility that chooses to move slowly and cautiously runs the risk that others will define the market in a manner that doesn’t provide an effective approach to transitioning the utility business, capital structure, and operating system. Being a taker of systems and business and regulatory models that have already been put in place puts a company in an inherently passive position, whereas a maker of markets and regulation can try to smooth the transition for the benefit of relevant stakeholders.
The cons for the early movers in DERs are clear: including the risk of embracing technology that is still young and unproven; the risk of absorbing high stakeholder costs, including the costs of systems to integrate DERs into current transmission and distribution infrastructure; necessary changes to longstanding engineering and business practices; and the potential to inadvertently expose the franchise to new (and possibly conflicting) regulatory regimes. In this context, the follower position has its appeal; provided a utility has the asset base resources and local regulatory relationships to do so, late adopters might more effectively drive value from existing assets for a much longer time.
Eventually, though, even lagging utilities will face the need to transition when the market hammer falls – or when regulation mandates it.
An investor-owned utility that embraces DER early might benefit from a market transition halo effect in the capital markets. Consider an integrated utility with a traditional portfolio mix and a strong relationship with its investors and capital markets. This utility could consider obtaining capital under traditional utility approaches and current low-risk premiums. By sourcing capital under today’s models and applying the resources to distributed energy models – before that distributed energy becomes visibly disruptive to the rest of the industry – a savvy utility might capture a first-mover premium. Such utility first movers would be financing activities at today’s lower rates, before the market adjusts to incorporate the risk inherent to an era of change.
The integrated big iron business model of power generation, transmission, and distribution has been proven and it works to provide cost-effective, reliable energy with predictable delivery mechanisms. It’s an open question whether or not the distributed energy business model can work for traditional utilities or provide the consumers the carefree experience of the current systems. Yet change is here. The era of partially distributed energy resources is already upon us.
An amalgamation of distributed and centralized energy – for both generation and storage – likely will define the future for decades to come. And it likely will look different as it’s shaped to meet the needs of local communities. In this era, utilities and regulators alike will face risks, surprises, and potential rewards as they adapt. The innovator’s dilemma now requires both to face these questions and to frame a strategy to ensure positive outcomes for all stakeholders.