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May 2, 2013

The Calm Before the Solar Storm

 

As solar installations accelerate, a need for new business models on both sides of the meter

If I told you that a New York Times article described growing homeowner interest in solar power, spurred in part by declining solar module prices, interest in clean energy, and a (somewhat uncertain) landscape of incentives, that would probably sound pretty familiar. It wouldn’t exactly be surprising news. But here’s what would: the article published more than 20 years ago, in 1991.

For decades, we’ve been hearing that a solar PV-powered electricity consumer revolution is coming. Lately, this “coming” solar revolution has been posting some impressive numbers; it’s moving more rapidly than ever.

Consider California. To date, about 150,000 distributed solar PV systems, totaling 1.5 GW, have been installed on homes and businesses in that state. Last year, U.S. utilities interconnected nearly 90,000 net-metered solar projects totaling almost 1.2 GW-ac, a 46-percent increase over 2011. In total, there are currently 3.5 GW of net-metered projects in the country, the capacity equivalent of 3.5 nuclear plants. This growth is due in part to third-party solar ownership and financing. SolarCity, the biggest player in that game, enjoyed 117-percent growth in installations from 2011 to 2012, and expects 2013 to be another 60 percent higher again than 2012.

These numbers are impressive, but take note: solar is no longer coming. Why? Because solar is here. It has officially arrived.

How do we know? Some major electricity players are aggressively moving into the distributed solar market. NRG Energy, whose core business model has been based on providing central thermal power to distribution utilities, is now shifting gears to start offering solar and natural gas combinations direct to consumers. When a company like NRG starts to reposition itself to enable retail customers to bypass NRG’s own utility clients, it sends a signal that a more fundamental market shift is afoot.

Meanwhile, other major electricity players—especially vertically integrated, investor-owner utilities—are taking serious notice, even scared, of what distributed solar could mean for their futures. Grist had excellent coverage of the issue here and here, as did GreentechMedia here and here. But most importantly, so did the industry in the Edison Electric Institute's recent report.

Yes, amidst all of the sunny news of market growth and consumer empowerment, a potential storm is brewing. As rooftop and community-scale solar PV expands, it is driving a fundamental shift in economics, business models, and operations across the electricity sector, and right now not everyone is happy about it. Indeed, as penetration rates grow, solar could become—and arguably is already becoming—a lightning rod for conflict that could ultimately pose barriers to this renewable, climate-friendly, rapidly scalable technology.

What’s the problem?

RMI wrote about the issues contributing to this growing storm in a 2012 report, “Net Energy Metering, Zero Net Energy and the Distributed Energy Resource Future: Adapting Electric Utility Business Models for the 21st Century.” A number of factors are driving the discussion.

First, supportive policies, tax benefits, Renewable Energy Credits, and retail net-energy metering programs have combined with dropping solar prices to spur solar PV growth in many markets. Yet such mechanisms were designed for early market support of emerging technologies, not as long-term solutions. While the precipitously falling price of solar panels has helped the industry to plan for a future that relies significantly less on incentives and subsidies, there are growing questions about the sustainability of certain mechanisms, such as retail net-energy metering.

Certainly, such mechanisms have rightly supported an emerging clean energy technology, but they have focused primarily on solar’s low-cost deployment onto the grid without taking into account its performance costs and benefits of integration into the grid.

To be clear, net-metering in and of itself is not flawed. Rather, the problem is rooted in the underlying predominant utility rate structure that bundles the costs of all electricity services—generation, transmission, and distribution—into a single price per kWh. This can become problematic, such as when a net-metered net zero customer pays a $0 utility bill but still uses the grid, such as to export surplus power during the day, when solar panels are generating, and to import power at night, when they are not. Bundled pricing becomes inadequate for handling such complex transactions.

This combination of traditionally bundled rates and currently popular strategies like net-energy metering obscures the benefits and costs of distributed resources and fails to provide appropriate price signals that allow customers and utilities alike to realize maximum benefit for the electricity system. As a result, investment in new distributed PV capacity is taking place without regard for how the location and timing of those resources will influence operation of the grid. It’s time to start to explore a more mature approach to solar deployment. However, given the fundamental role that net-energy metering plays in today’s solar industry, changes to existing approaches will need to be made in ways that help to ensure a smooth glide path for the future.

More fundamentally, the regulatory ecosystem in which utilities operate was created on the basis of the control, ownership, and scale efficiencies from central station electrical supply, transmission, and distribution. The increasingly archaic business models that have evolved within this regulatory ecosystem are poorly adapted to quantify, capture, or optimize the value streams associated with distributed energy resources, such as solar PV. Under these institutional constraints, many utilities see distributed PV as a threat associated with revenue loss, increased transaction costs, and challenges to system operations.

Long-term solutions: eLab

We need to realign the electricity grid’s regulatory ecosystem, which defines the rules of the game for utilities and other players in the system. The realignment of the regulatory ecosystem won’t happen overnight. It’s a long-term effort and the driving motivation behind the Electricity Innovation Lab (eLab), a multi-year effort to accelerate the transition to a clean and increasingly distributed electricity system future.

eLab’s focus is on the distribution edge, that part of the electricity system where customers, utilities, and distributed energy resources (such as solar, battery storage, energy efficiency, demand response, and other mechanisms) all interact—across both sides of the customer’s meter. Among eLab’s efforts, two keys areas of focus are to:

  1. Develop a framework to accurately assess the values and costs of distributed resources, which will provide a foundation for effective business model and rate structure design, and
  2. Design and ultimately pilot new regulations, business models, and pricing structures to align the interests of utilities, customers, and distributed resource developers.

A new eLab discussion paper, New Business Models for the Distribution Edge: Transitioning from Value Chain to Value Constellation, is an important early step in that direction.

Meanwhile, we need to start building a transition now to better align the solar market for continued growth based on the real value it brings to the electricity system, customers, and utilities. There are steps we can take today, even while playing according to current rules, within existing regulatory environments.

Near-term actions: Innovative Solar Business Models

To date, strategies for solar market growth have primarily targeted cost reductions in manufacturing, construction, and financing. While cost reductions remain critical, focusing only on low-cost deployment onto the grid misses opportunities to recognize the delivered value of solar as it’s integrated into the grid. To deliver new energy services to customers and utilities alike, it's critical to recognize key cost and value drivers within the electricity system: location, timing, reliability, flexibility, predictability, and controllability. As with any generation source, where you install PV (e.g. close to demand) and when it generates electricity (e.g. during peak demand times) matters. To create a prospering solar market over the long term requires a better understanding of these real value and cost drivers and business models that are designed with them in mind.

What could that look like? Strategically deploying solar to reduce grid congestion and to displace other generation or grid investments could create tangible value for the system, customers, and utilities. Similarly, complementing solar PV with combinations of real-time data and predictive modeling, advanced inverters, distributed storage, and other strategies could bolster solar’s value. So could further leveraging PV’s value, shifting solar’s role from a passive energy source that may correlate with peak demand to one more defined by shapeable energy production, voltage regulation, and other service opportunities.

To move these opportunities from theory to reality, we designed the Innovative Solar Business Models (ISBM) project, a three-year project funded by the U.S. DOE’s SunShot initiative, to address key gaps in the industry.

First, the industry needs better analytical tools that can provide clearer insights into the real costs and values of distributed PV. While a growing body of demonstration projects and analyses are providing empirical data that demonstrate the technical viability of optimally integrating distributed PV to support the grid, there is comparatively little analysis to translate that into value. RMI has developed the alpha version of the Electricity Distribution Grid Evaluation (EDGE) model to do just that—incorporate the localized effects of distributed PV into the distribution network.

Second, we need to move beyond analysis to practical application. Building on the analysis derived through the EDGE model, we are strategically partnering with a handful of selected utilities to calibrate the modeling analysis, test value streams, and develop pricing mechanisms and business models that will optimize value. Additionally, we will evaluate regulatory implications in order to communicate barriers and opportunities to regulators. We also will disseminate lessons learned and best practices with the express intent of replication and scaling.

Clearer Skies Ahead?

We’re currently in the midst of a calm before the coming solar storm, but we needn’t let the storm overtake us. We must first chart the course, starting with business models that help utilities see the value of solar today.

In the coming weeks, we’ll be regularly writing about this work, key developments, and open questions that we continue to explore.

Recommended Reading 

Image courtesy Shutterstock.com

Join the Discussion


Showing 1-4 of 4 comments

May 3, 2013

These are terrific points Virginia! Re-partitioning the value chain in the context of "distributed" is crucial to long-term success.

I have a scenario that might be worth considering when testing/validating potential changes in the value chain, regulations, business models, etc. Imagine an on-grid solar light.

It's an efficiency device. The much more efficient LED technology reduces overall nighttime energy consumption relative to traditional HID lighting. Plus, on-board intelligent controls enable demand/response behaviors including time-based, motion-based and/or centralized on, off and dimming.

It's a distributed generation device. During the day, the solar engine generates at least enough energy to offset the energy consumption for lighting, and this energy is available during times of peak demand. The same intelligent controls enable revenue grade net-metering of each solar light so that business and pricing rules can be applied. How should such a device be treated by a utility? Assuming daytime energy generation and consumption remains a local phenomenon requiring little distribution and no transmission, and each solar light is net-positive from an energy standpoint, maybe there is no need for explicit pricing negotiations with the utility. The solar light does not pay for energy it consumes at night and does not expect payment for energy generated during the day, with excess generation covering distribution costs absorbed by the utility.

It’s a distributed storage device. Adding safe, economical, long-life battery capacity like LiFePO4 to each on-grid solar light and combining this storage with intelligent controls unlocks the potential of time shifting, frequency or voltage regulation and other valuable grid services.

And what if this three-in-one device could be financed in a way that is similar to SolarCity’s model?

Adding this scenario to the set of scenarios used to test and validate changes going forward - along with roof top solar, micro-wind, etc. – should help ring out the nuances needed to be successful.


May 23, 2013

This is a great, thorough, informative, and hopeful post. Thank you. Looking forward to seeing more.


May 23, 2013

A big problem is that some jurisdictions insist on double metering or a single meter with a double read out - same thing. Without "net metering" the customer is vulnerable to changes in the payment regime by the power company and the government at any time in the future. With net metering, there must be a "line charge" to be fair to the power company. After all they must maintain the lines that allow one to use the power company as a battery bank, saving the small generator huge capital costs. Critical is to legislate that the formula for power prices and line charges is the same for the simple customer and the customer/generator.
http://mtkass.blogspot.co.nz/2013/04/solar-electric-whats-missing.html
http://mtkass.blogspot.co.nz/2009/09/german-fit-system-brilliant.html
http://mtkass.blogspot.co.nz/2007/10/excess-energy-what-to-do.html


May 24, 2013

always pleased to see rmi ahead :)

greetings from berlin, germany

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