Over the last few decades, utility companies have seen their monopolies eroded by deregulation. As utility customers increasingly begin producing their own energy, reliance on the grid for electricity is decreasing. The technology for distributed generation has evolved rapidly, and while it is still not “good enough” from a purely technical perspective, it has rapidly been approaching this threshold as supporting technologies such as electricity storage and demand response have begun resolving barriers to system integration. My good friends and classmates Meghan Sherlock and Ayman Awaluddin co-authored the following analysis with me based on Clay Christensen’s predictive models of disruption theory.
A brief history of the structure of the electricity industry in the U.S.
Throughout most of the 20th century, utilities were regulated local monopolies that controlled generation, transmission, and distribution in their territories. In 1984, congress enacted the Public Utilities Regulatory Policies Act of 1978 (PURPA), providing the legal basis for independent power producers (IPPs) to supply electricity generation. PURPA mandated that utility companies buy non-utility power whenever the cost was below the utility’s marginal cost of production. After PURPA, regulators also introduced the Federal Energy Policy Act of 1992, mandating that utility companies provide fair and equal grid access to independent power producers. Both policies effectively ended utility companies’ monopoly in the generation segment and as a result non-utility power generation increased from a mere 3% of total production in 1978 to 38.8% in 2012. This includes on-site cogeneration such as combined heat and power (CHP). (As seen in Exhibit 1.)
Growth of renewable energy in California
The state of California has been the pioneer of renewable energy deployment in the United States. In 2002, legislation established California’s Renewables Portfolio Standard (RPS), a renewable energy mandate that obligates the utility industry to convert 33% of its total power supply to renewable sources by the year 2020. In order to reach the mandate by 2020, the proportion of renewable energy production in California will need to grow at a compound annual growth rate (CAGR) of 10.0% from 2012 levels. Over the first ten years of the RPS, renewable energy has grown at a rapid rate in California. From 2002-2012, renewable energy production grew from 11.0% to 15.4% of the total from all sources, at a CAGR of 3.4%. During the same period, the share of solar in total California production grew from 0.3% to 0.9% in 2012, at a CAGR of 11.6%. As seen in Exhibit 2, the distributed portion of solar capacity (MW) has historically been more than half of total California solar capacity. From 2002 to 2012, total energy production in California grew at a CAGR of 1%, markedly slower than the rate of renewables.
The cost of solar energy has been falling rapidly in California. From 2007 to 2013, the average installed price of solar arrays less than 500kW (AC) in the service territory of PG&E, California’s largest utility, fell at a CAGR of 14.4% to $4.81 per Watt in Q2 2013. Comparatively, the Q1 2012 installed price in Germany was $2.05 per Watt. The difference is attributable to “soft costs” such as installation, permitting, and customer acquisition. Given that the learning-by-doing for most soft costs happens locally, these costs should converge across geographies proportionately to local scale. In 2012, solar installations in the US were 22.6% that of Germany, with 34.7% of US capacity being in California. The 2013 unsubsidized levelized cost of energy (LCOE) for solar in the US is $149 to $204 per MWh, compared with an average electricity rate for all sectors of $157.7 per MWh in California. In addition to reduction of soft costs, lower cost of capital from the securitization of solar assets is expected to decrease solar LCOE by 8%.
Net metering, a billing mechanism that bills solar-equipped customers based on their “net” energy usage, has grown exponentially from 2003 to 2011. (As seen in Exhibit 3.) Because solar customers are buying less electricity at the retail rate, the high fixed costs required to maintain and operate the grid, as well as charges for social programs, are unfairly shifted to non-solar customers. At the same time, solar customers are benefiting by using the grid as a storage device to compensate for intermittent solar generation. As a result, utility companies have been advocating for changes to the rate structure that would charge more for solar customers to use the grid. PG&E claims that solar customers are causing the company to lose up to $240 million each year to cover for grid operation and maintenance. The utility predicts that if current solar adoption rate were to continue, it could lose up to a staggering $720 million per year.
In 2010, PG&E sponsored and contributed $46 million to a campaign for “Proposition 16,” a law that restricts the formation of community choice aggregators (CCA), which allow municipalities to build community-owned portfolios of distributed generation assets. Despite the attempt, the proposition was struck down. This hints at the possibility that the electricity distribution business may soon be faced with yet another wave of monopoly erosion.
Interdependence vs. modularity
In the late 19th century, Thomas Edison’s pioneering technology required that electricity systems be designed to have local generation. Nikola Tesla’s invention of alternating current (AC) a few years later enabled long-distance transmission and brought the electricity industry into a long era of interdependence. The actual physics of electrical delivery warranted a vertically integrated system: since supply needed to match demand at any given time for seamless power delivery, it was efficient for a single central authority to control the entire supply side. Furthermore, vertical integration allowed the utility company to coordinate investment decisions at all stages of the chain from generators to low-voltage distribution lines. In order to better serve customers, utilities maintained an interdependent electricity system and a monopoly on the generation and delivery of electric power.
The introduction of IPPs through PURPA in 1978 was the first instance of modularization in the electricity industry structure, as it gave third parties access to enter the power generation business and sell electricity through the utility-owned transmission lines. This modularization occurred at a time when customers were becoming over-served by the centralized industry structure. In response to utilities favoring the dispatch of their own generation assets, the interface between generation and transmission was standardized through the introduction of independent system operators (ISO) in 1992, who impartially matched supply and demand for utility and IPP generation assets.
As depicted in Figure 1, the latest wave of modularization is underway: technological progress has enabled small-scale generation technologies to penetrate the market at the low end of performance. Technologies such as natural gas turbines and solar panels have become “good enough” for customers, making it feasible to generate electricity economically on a smaller scale. From 2008 to 2013, the cost of solar panels fell by more than 80%, driving installation of distributed generation assets to unprecedented levels. As of August 2013, one system is being installed every four minutes in the U.S. These smaller systems also enjoy an advantage in that they avoid many of the difficulties that larger plants encounter, such as siting restrictions, long construction times, expensive on-site labor, and cost overruns.
Figure 1: Interdependence vs. modularity in the U.S. electricity system
Despite their growing success, distributed energy technologies are not yet good enough to completely replace centralized electricity systems. For example, the biggest hurdle preventing utility customers from completely disconnecting from the grid is that distributed solar produces power intermittently. Because there is no sunlight during the night and some days have better sunlight than others, solar energy production fluctuates widely. Real-time energy storage would allow distributed generators to completely disconnect from the grid by storing excess electricity. As of December 2013, however, this technology has not been fully developed. Distributed solar generators therefore require the electrical grid or fossil-fueled generation as backup.
This latest wave has profound implications for the industry, with the basis for competition in generation assets beginning to change from centralized to localized generation that offers more resilience, control, and sustainability. As the technology becomes good enough to close the performance gap and centralized electricity increasingly over-serves electricity customers, even pragmatic or conservative customers are beginning to find reasons to invest in distributed energy.
The move toward a modular system has laid the groundwork for a low-end disruption of utilities by distributed solar electricity generation.
Traditionally, utility companies have benefited from regulation and a guaranteed rate of return in transmission and distribution and thus have had a disincentive to allow new entrants such as distributed energy into the value chain. Utilities first evolved by moving up a sustaining curve of innovation, investing in a vertically integrated system of generation, transmission, and distribution. Especially in regulated states, utilities have had an incentive to invest in projects that increase the overall amount of capital invested and therefore the size of returns. As deregulation forced a restructuring of utilities’ business activities and granted access to new entrants in generation, utilities began to “move up market” through investments in infrastructural improvements that allowed them to match supply and demand with increasing efficiency.
As of 2013, distributed solar generation has begun a low-end disruption, as depicted in Figure 2. This disruption has been enabled by rapid improvements in solar panel technology. Rapidly falling manufacturing costs have started to bring solar closer to the point where it is “good enough” for residential customers, commercial properties, and industrial complexes. The implementation of these technologies on a distributed basis creates a new model whereby customers can themselves enter the generation market as “prosumers,” or producer-consumers, lowering their own electricity costs and selling excess electricity back into the grid. Because stakeholders with an interest in distributed energy can essentially vote with their pocketbooks on a granular scale, it is extremely difficult to control entry and limit the development of substitutes to the generation of power by traditional utilities.
Figure 2: Low-end disruption of utility companies by distributed energy
This disruption threatens to decrease the attractiveness of generation for utilities like PG&E, who need a large base of customers in order to make a return on their fixed cost base and still charge reasonable rates. In states where utilities are guaranteed a rate of return, such as California, utility companies will be forced to raise electricity prices for the remaining consumers on the grid, reinforcing the cost advantage of distributed generation and initiating what is commonly referred to as a “death spiral.” As electricity customers choose to become prosumers, utilities will be faced with a choice between alienating a growing portion of their customer base and allowing their monopoly power to erode.
Theory would predict that utilities will lose control of electricity generation as it becomes less attractive and begin to “retreat up market” into the distribution, transmission, and system integration segments, using regulation to erect barriers to entry. As distributed energy itself moves up the curve of performance, we anticipate that utilities will gradually lose control of each successive segment, resulting in the full disruption of the utility business model. The recent emergence of alternatives to utility companies for the aggregation and coordination of energy needs foreshadows this change. For example, community choice aggregation (CCA) allows cities and counties to aggregate the buying power of individual customers within a defined jurisdiction in order to secure alternative energy supply contracts. This represents an initial foray by distributed generation up market into the distribution segment and likely presages movement into additional segments.
Evolution of the “job to be done”
While the U.S. energy grid ages and new technologies are developed, the “job to be done” (JTBD) for electricity customers is also shifting.
When the electrical grid was first developed, consumers “hired” utilities to connect them to power generation facilities that were large and relatively centralized. The “job to be done” for consumers, while the product was not yet “good enough,” could be described as “keeping the lights on for a reasonable price.” Utilities were able to keep the lights on (i.e., provide stability) by balancing supply and demand. Utilities also offered electricity at a “reasonable price” by spreading out the high fixed costs of generation and transmission across a large base of customers. The industry structure evolved to fulfill the JTBD given the existing technologies and regulatory structure.
Today, the rapidly evolving role that electricity plays in our economy, combined with new possibilities unlocked by advances in technology, is reshaping the JTBD for electricity infrastructure. The old JTBD of “keeping the lights on at a reasonable price” still exists as a baseline for most consumers, but new jobs have emerged around energy usage, which are summarized in Figure 3.
Figure 3: “Jobs to be done” for electricity usage
Now that distributed generation can fulfill the original JTBD of keeping the lights on at a reasonable price, utilities should worry about potential shifts in the basis of competition to one of these new jobs. The 2012 case study of University of California at San Diego’s microgrid demonstrates how distributed generation fulfilled many of these jobs better than their utility was able to. This new form of power generation and distribution can now accomplish the same basic JTBD without the same level of large-scale infrastructure, as well as accomplish the new JTBDs that have emerged in the 21st century.
Although executives at some utilities currently view distributed generation as a threat, we believe that they should frame this as an opportunity that would allow them to better fulfill the job to be done for customers, invest more efficiently in peak capacity, and prevent the disruption of their business. Based on our analysis, we recommend that utility executives and regulators turn their attention from the debate on net metering to embrace distributed solar generation as part of their business model and capture this nascent market while they still can.
As a final word, it should be noted that developments in responsive demand and energy storage, as well as caps on carbon emissions and restrictions on water usage, could dramatically change the economics of distributed generation. As such, it is in utilities’ best interest to consider those possibilities as real options in determining the expected value of different scenarios.