How to Avoid the Death Spiral

During my most recent chat with Utility Forecaster, Canadian Edge and Australian Edge subscribers, a participant questioned me about the impact the rapid adoption of solar power along with advances in storage technology would have on traditional utilities.

I replied that battery systems coupled with rooftop installation of solar photovoltaic (PV) panels indeed represents a potential game-changer, as the Edison Electric Institute (EEI) concluded in a January 2013 paper, Disruptive Challenges: Financial Implications and Strategic Responses to a Changing Retail Electric Business.

I also wrote that traditional utilities are beginning to see the potential for solar investment, either via utility-scale solar farms or through the establishment of separate business units that offer distributed solar capabilities to customers.
I concluded by noting that we’re watching developments on this front very closely.

Lo and behold, the Rocky Mountain Institute (RMI) this month put some serious meat on distributed solar power’s bones and provided a name for the phenomenon capable of catalyzing what the EEI described as a “death spiral” for the U.S. electric utility industry with its new paper The Economics of Load Defection.

The paper, a fuller exploration of questions the RMI first raised in February 2014, addresses “how grid-connected solar-plus-battery systems will compete with traditional electric service, why it matters and possible paths forward.”

Using Homer Energy’s modeling software and U.S. Energy Information Administration data, the new report modeled grid-only, grid-plus-solar and grid-plus-solar-plus-battery configurations to find the lowest-cost options over time based on systems’ per-kilowatt-hour levelized cost of energy equivalents.

The study modeled forecast economics through 2050 for median commercial and residential customers in five U.S. markets: Honolulu, Hawaii; Los Angeles, California; Louisville, Kentucky; San Antonio, Texas; and Westchester, New York.

It concluded that grid-connected solar-storage systems are already more cost-effective than grid-supplied electricity in expensive electricity markets such as Hawaii and will be more economic than grid power in three of five U.S. geographies studied, including California, New York and Texas, within the next 10 to 15 years.

That, in turn, could lead to more and more customers shifting their energy load from utility-delivered electricity to their own self-generated and stored power–thus the term “load defection.”

Load defection is what could set the U.S. electric utility industry on the death spiral described in the January 2013 EEI paper–though As customers leave the traditional grid, a potentially fatal chain of events ensues:

Start with the increased cost of supporting a network capable of managing and integrating distributed generation sources. Next, under most rate structures, add the decline in revenues attributed to revenues lost from sales foregone. These forces lead to increased revenues required from remaining customers … The result of higher electricity prices and competitive threats will encourage a higher rate of [distributed generation consumer projects] …. These competitive and financial risks would likely erode credit quality. The decline in credit quality will lead to a higher cost of capital, putting further pressure on customer rates.

This is a worst-case scenario that’s only possible in a world of incompetent investor-owned utility executives incapable of adapting to a changing world. It contemplates non-exporting solar PV, behind-the-meter solar-plus-battery systems and, ultimately, actual grid defection resulting in an overbuilt system with excess sunk capital and stranded assets on both sides of the meter.

The more likely scenario results in what the RMI calls an “integrated grid.”

This future includes grid-optimized smart solar, transactive solar-plus-battery systems and, ultimately, an integrated, optimized grid in which customer-sited distributed energy resources such as solar PV and batteries contribute value and services alongside traditional grid assets.

It’s a solution that maximizes efficiencies on both sides of the meter, for customers as well as utilities.

We are, as the April 2015 RMI paper describes the present situation, “at a metaphorical fork in the road.” At this juncture the deployment of solar-plus-battery systems–including their configuration, operation, and value to the grid and customers–will be greatly affected by utility and regulatory action (or inaction).

More and more of the country will see grid parity for solar PV systems, even without export compensation such as net metering. Geographies where PV is already at grid parity will begin to see grid parity for solar-plus-battery systems that will allow large amounts of load to self-provide and thus go off-grid.

And decisions made in the short term can set markets down extremely different paths, toward grid defection or toward an integrated grid.

The RMI identifies action on three fronts that will lead to the optimal outcome.

Pricing and rate structures must evolve to take account of location and congestion, time of use as well as attribute-based factors including energy, capacity, ancillary services and other components of the electric system.

And current business models have to get past the 20th century paradigm of centralized generation and the unidirectional use of the grid. The emerging 21st century reality includes cost-competitive distributed energy resources (DER) such as solar PV and battery storage and a two-way flow of electrons, services, and value across the meter.

Right now the relationships among and between utilities, DER companies, technology providers and customers are complicated at best and confrontational at worst. Aligning interests–which includes recognizing the value of DER companies–is critical.

And regulatory reform will be necessary for the electricity system to effectively incorporate new customer-sited technologies into the grid. This involves maintaining and enhancing fair and equal customer access to DERs.

It also involves recognizing, quantifying and appropriately monetizing both the benefits and costs that DERs such as solar PV and batteries can create.

New regimes will also preserve equitable treatment of all customers, including those that don’t invest in DERs and remain solely grid-dependent.

A March 2014 survey of utility insiders found that “95% anticipate that their utility’s regulatory model will change over the next 10 years, and 57% believe it will change significantly.”

And 70% of utilities already offer or plan to offer dynamic pricing to customer within the next five years.

Meanwhile, 54% of utilities say they face stakeholder pressure to supply cleaner and more sustainable energy.

Some see distributed generation as a threat. But the great majority sees it as an opportunity.

So minds are open.

But customers are driving distributed energy right now, not utilities. There are lots of things utilities could be doing to be more proactive, but momentum is gathering in a way that augurs a future with an integrated grid, in which traditional utilities have, for example, evolved to play a “control and coordination” role for customers with solar-plus-battery systems.

There is also movement by utilities to own and control solar PV inverters as a distribution grid asset, to offer community solar programs to customers who live in apartments or homes that aren’t well suited for rooftop solar and to create on-bill financing for customer-sited solar PV systems.

At another level, as the portfolio of distributed energy resources available to customers grows in number, volume, diversity and sophistication–including everything from on-site generation to storage to smarter appliances–customers will increasingly value service providers that can offer total energy solutions.

Such a package would include energy assessments, efficiency improvements, actual DERs (e.g., solar PV, smart appliances, batteries, controls, etc.), financing, monitoring and management of the same.

The integrated combination of these assets would allow customers new capabilities, such as responding dynamically to changes in pricing, adjusting consumption of on-site generation to maximize or minimize export, participation in demand response markets and other opportunities.

Traditional utility companies that recognize the opportunity will be able to not only offer to coordinate many different distributed energy resources at one location for a single but to manage such systems across many customers.

Leveraging their present advantages of scale, traditional utilities that take advantage of the opportunity will survive, evolve and thrive for decades.