Partner & Managing Director
San Francisco - Bay Area
The financing system for investing in and maintaining the electrical grid in countries around the world is rapidly eroding. At the heart of the problem is a mismatch between expenses and revenues. The cost of the grid that delivers electricity to homes and businesses in developed countries does not for the most part vary with usage—making it largely a fixed cost. The fees charged to end users to recoup grid investment and operating costs, however, are variable, based on a customer’s energy usage. The problem: the funds collected to support the grid will decline sharply as customers—especially homeowners and small businesses—adopt energy efficiency measures and, even more significant, install photovoltaic (PV) panels on their rooftops to generate their own power.
For utilities, the answer would seem to be simple: shift to a pricing arrangement that includes a fixed fee for use of the grid. But while such a change would better reflect the real cost of grid access and provide near-term relief, it would intensify financing challenges over the long term. That’s because the costs for solar and battery storage technology are falling precipitously. Our analysis shows that under a fixed pricing approach, and even with no subsidies such as tax breaks, off-grid solar will be cheaper in many regions within the next 10 to 15 years than either grid-connected solar or grid power alone. Consequently, a pricing structure that includes fixed fees for the grid would actually exacerbate the funding problem over the long term by accelerating the movement of customers completely out of the system.
Amid changes in the energy market, utility companies and regulators must adopt new approaches. For utilities, this involves action in several areas. Notably, they must reduce the fixed costs of grid operations and develop investment plans that reflect the type and extent of grid infrastructure that various regions will require. Without such planning, utilities run the risk of being hamstrung by stranded assets—overbuilt and underused “zombie” grids. Regulators, meanwhile, must strike a balance between supporting renewable energy sources and ensuring a robust, reliable grid.
To fully understand the dilemma facing utilities, one needs to understand the investments required to build and maintain a large grid and how that grid is currently financed.
The High Cost of the Grid. Over the past 15 years, OECD countries invested on average 0.2% of GDP per year in the development and refurbishment of transmission and distribution assets—commonly called the grid. In the US alone, for example, that amounts to $40 billion annually.
It is projected that $1 trillion to $2 trillion in combined grid investment will be required across all OECD nations from 2014 to 2035. Such investment will be directed toward building new grid capacity and maintaining things like power lines, substations, and connections to individual homes and businesses.
A portion of that investment will also be aimed at enabling the grid to handle increased amounts of both intermittent centralized renewable energy (produced at a central source such as a wind farm) and decentralized power (generated on the user’s premises from sources such as solar panels and small-scale natural gas–fired plants). The use of these sources makes it necessary to transform the grid from a one-way system for delivering power to one in which power flows in two directions and varies with sun or wind intensity. This requires upgrades to assets such as substations and investments in energy management systems to control the shifting flow of power across the grid.
The grid is not the only component of energy infrastructure that must be adapted to accommodate renewable energy. Conventional power generators must also upgrade their systems to enable them to handle the ebb and flow of demand from users who rely on the grid for backup energy.
The costs of building and upgrading the grid are mostly independent of how much energy flows through the system. So are the costs of operating and maintaining it. But while the costs are largely fixed, in countries around the world the fees charged to fund the grid are predominantly variable. A percentage of the user’s electric bill—a bill based on energy consumption—is earmarked for transmission and distribution costs. The percentage varies significantly by country and even at the state level in the US. In Germany, for example, 22% of the average household electric bill goes to supporting the grid, much lower than the 32% average in the US.
Solar’s Complex Subsidy System. Solar power is supported by a variety of subsidies, an arrangement that has significant implications for the grid funding model. The vast majority of people and businesses that have PV panels on their roofs are still connected to the grid. That connection allows them to buy energy when their PV system isn’t generating enough power (during evening peak demand or on cloudy days, for example) and to sell back to the grid the excess power their PV system generates at other times (sunny days when no one is home using energy, for example). Customers with this setup enjoy two separate subsidies as a result of power prices.
The first is an open subsidy. This stems from the fact that users sell power back to the grid at a price that exceeds the wholesale price: the price at which centralized power generators sell their production to the system. Two pricing approaches create this subsidy:
The second subsidy is a hidden subsidy. It stems from the fact that as customers use the solar power generated at their premises, the amount of energy they buy from the grid decreases. That lowers their overall bill, in turn cutting the funds from that bill that go toward grid costs. Given that these customers are still using the grid (a fixed cost), the reduction in what they pay for it is essentially a hidden subsidy.
Threats to Grid Funding. Through the combination of open and hidden subsidies, customers avoid paying for the grid—both when they use their own power and when they sell excess power back to the utility. Ultimately, both subsidies will be paid for by other customers—their neighbors. That’s because users relying entirely on centralized power will have to bear most of the costs of the grid, which will create an even stronger incentive for some of them to move off-grid entirely.
The combined open and hidden subsidies vary by country and by state within the US. In Germany, for example, the total subsidy amounts to 10 cents (in US dollars) per kilowatt-hour of energy consumed (¢/kWh). (See Exhibit 1.) In California, meanwhile, that subsidy is approximately 11¢/kWh. This represents money that previously was collected by utilities but is lost to them when users install PV panels.
On top of these open and hidden subsidies related to pricing, there are subsidies for homeowners and small businesses to support solar. In the US, for example, the solar investment tax credit (ITC) currently cuts the tax bill of individuals and companies that buy a PV system by an amount equal to 30% of the cost of the system.
In addition to the decline in grid funds collected due to the open and hidden subsidies, we can expect further erosion in funding due to the drive to improve energy efficiency. As regulators push to reduce greenhouse gas emissions, efforts to improve energy efficiency will probably increase. Europe has led the way, including through regulations such as the banning of incandescent bulbs and tax incentives to drive the adoption of energy-efficient appliances. The opportunity for improvement in the US in particular remains significant. Among the most powerful potential steps: the adoption of energy-efficient appliances, a shift to compact fluorescent or LED lighting, and a reduction in air conditioning usage. We estimate that a shift toward European levels of efficiency for US appliances and lighting alone could yield annual reductions in energy usage of more than 200 terawatt hours, equivalent to a roughly 15% reduction in residential electricity consumption. But as energy consumption declines thanks to such moves, the usage-based charges that support the grid will also drop.
The Push for a New Pricing Model. Given the likely decline of funds to support the grid under the current system, utility operators have reasons to push for a new pricing model. Under the model favored by utilities, the portion of the bill for supporting the grid would include both a substantial fixed fee and a (limited) variable component tied to usage. This change would enhance near-term funding for the grid by largely eliminating the hidden subsidy and requiring customers to make a fixed payment to support the grid. (Such a shift would likely be introduced gradually. Moving too quickly could create a backlash, because the fixed payment would be a greater burden for those who use relatively small amounts of energy, often low-income customers.)
Certainly, eliminating the hidden subsidy would be highly controversial. On the one hand, subsidies are a powerful government tool to encourage behavior such as adopting renewable energy sources, an action that benefits society at large. And users who embrace decentralized power can reasonably argue that they should not be forced to pay for an oversized grid for which they have little use. On the other hand, utilities point out that consumers who use decentralized solar power but still need the grid should pay a fair price to support it.
While moves to reduce the hidden subsidy are likely to face stiff opposition, changes to the open subsidy would be an even tougher sell. Some utilities, largely those that would like to slow the uptake of solar, are advocating a second pricing change, one that would eliminate the open subsidy. They argue that power should be sold back to the grid at wholesale prices. This would theoretically level the playing field between conventional energy and solar, making solar more expensive today than conventional power from the grid (given the current costs of PV technology).
However, major reductions in or the complete elimination of the open subsidy are unlikely to gain acceptance, because such a pricing change would dramatically slow the development of solar. In fact, as regulators introduce fixed charges in some jurisdictions, they are maintaining other subsidies, including the feed-in tariff.
There is no doubt that the fixed-plus-variable pricing structure that utilities advocate would better reflect costs and could provide some relief in the near term. Over the long term, however, it would not solve the grid financing issues and would make them even worse.
The primary reason: solar technology and energy storage systems are rapidly growing more cost competitive. Prices for PV panels have fallen by 60% since 2008—about 15% per year—thanks to investments in large-scale manufacturing operations that have produced powerful economies of scale. Over the next decade or so, we expect PV prices to continue to fall, by about 4% per year. These lower prices will help expand the uptake of solar in general. At the same time, battery prices have fallen 40% since 2007. And they are projected to drop 6% per year over the next decade or so as players like Tesla make large investments in the technology. (See Exhibit 2.)
As a result, in the not-so-distant future PV and battery technology will be cheap and widely available. In that environment, the pricing structure will be a key determinant of whether going completely off-grid makes the most financial sense.
Consider the case of a homeowner with a well-exposed roof suitable for solar panels. Under fully variable prices, grid-connected solar is likely to be the most economic option, even if open subsidies are reduced. But if that homeowner must pay substantial fixed charges for grid access (along with seeing a reduction in open subsidies), going entirely off-grid is likely to be the least expensive choice in the long run. (The homeowner would install a small generator as a backup, along with solar panels and substantial battery capacity.)
We studied these trade-offs in a number of regions, including the state of California. What would the market look like if the state moved to pricing with significant fixed fees? Our model analyzed costs ten years out under various pricing structures and energy configurations. (See Exhibit 3.)
The first scenario is variable pricing with a FIT that provides a premium to the wholesale price of 3¢/kWh. In this situation, grid-connected solar would be the most competitive option, at 14¢/kWh.
But under the second scenario, in which significant fixed fees are charged for grid access along with a FIT that provides a 3¢/kWh premium, the off-grid configuration is the most attractive, at 17¢/kWh. (It’s noteworthy that in either case, 100% grid power on its current trajectory would be one of the less favorable options.) Given those economics, many homeowners and small businesses, particularly in suburban areas, where exposed roofs are common, will have a strong economic case to move off the grid completely.
Think about that for a moment. Today, customers with PV panels who remain connected to the grid pay a reduced amount to support it—but they still pay something. In the second scenario above, customers would cut the cord completely and pay nothing to support the grid. The upshot: if utilities are able to garner fixed fees to cover grid costs, eventually that funding stream will be drastically cut as the pricing structure accelerates the movement of customers off the grid.
Ensuring a robust and reliable electric grid will require new thinking and strategies. This will be true not only for utilities but also for regulators. (See “The Balancing Act for Regulators.”)
For regulatory bodies in regions where decentralized solar power takes off, the aim will be to carefully calibrate rules and incentives to strike the appropriate balance between excess subsidization of solar and an overly rapid elimination of subsidies.
In some cases, regulators will need to trade off between competing aims in their pricing decisions. A shift to fixed-plus-variable pricing, for example, would better reflect the costs of the grid and ensure adequate grid funding in the short term. But that move could reduce the incentive for users to improve their energy efficiency. That’s because the decrease in their bill from such actions would be less under a fixed-plus-variable pricing arrangement than under a purely variable pricing scheme.
Our view is that despite that potential negative impact, the move to fixed-plus-variable pricing should win out. Pricing alone has historically not been effective at motivating customers to improve efficiency—regulations have been a better lever (as is the case in Europe). As a result, the slightly negative impact on energy efficiency efforts from fixed-plus-variable pricing would be more than outweighed by the benefits of ensuring grid funding.
Regulators must also address the social issues that may emerge as decentralized energy expands. One key issue is whether regulators should take steps to require those who completely opt out of the grid to pay something to support the grid infrastructure. And regulators will need to set policies that prevent a situation in which a small number of users remain on the grid—for example, in suburbs that are well suited to solar energy—and end up bearing unmanageable costs.
For utilities, the future poses both challenges and opportunities. To adapt, they must act on four fronts.
First, they need to reduce grid costs on a per-connection basis. Efficiency will be critical in a future with reduced total funding for the grid. Moreover, in a market with a shift toward fixed pricing, the failure to reduce grid costs will make going off-grid even more attractive. The wide disparity in grid costs on a per-connection basis across countries highlights the scale of the cost reduction opportunity. (See “Grid Charges: All Over the Map.”) A number of steps can be taken to cut grid costs, including adjusting the maintenance strategy, employing dynamic works planning, improving field force productivity, and finding savings in procurement and contractor management as well as in construction project management. (See Achieving Excellence in Energy Networks, BCG Focus, February 2013.)
Grid charges (the portion of the electricity bill that goes toward maintaining and operating the grid) vary significantly across regions.
The question is whether those differences stem from structural—and largely unchangeable—issues or from inefficiencies that should be stripped out of the system.
Consider population density. It makes sense that wide-open areas with a relatively small number of customers would have higher grid charges per household. Certainly, our analysis finds a relationship between those charges and population density. (See the exhibit.)
That connection, however, doesn’t completely explain the variation in charges. Why, for example, is the grid charge per household in California double that in Illinois and three times higher than in Spain even though the population densities of all three regions are similar?
Other factors also impact grid efficiency. Among them: labor costs, grid age, construction standards, service levels, and the return on assets that is earned based on pricing set by regulators. However, even accounting for all these factors, there remains a significant disparity in grid charges. For utilities in many areas, this means that there are sizable opportunities to take costs out of their grids.
Second, utilities need to adjust the way they plan grid investments so that the process adequately reflects the rapidly changing industry landscape. This means letting go of long-held assumptions and basing investment plans on a realistic assessment of the degree to which users will shift to new (and in particular decentralized) energy options. This also means considering new technologies and nonwire alternatives (approaches that do not involve expansion of the physical grid), such as mobile batteries, which can be deployed locally to bolster energy supply. Given the long life of grid assets, sound investment planning will reduce the risk of stranded assets.
Third, they must identify and exploit new opportunities. For example, users who shift toward decentralized power will have increasingly complex equipment on-site. Utilities are well positioned to offer services to those users because they have many of the technical skills required to install, maintain, and manage decentralized power systems.
And fourth, utilities must ensure that they have the capabilities to succeed in a fast-changing market. Among the many new skills that will be critical, for example, is the effective management of information and data. As an increasing amount of data is generated across the network, effective exploitation of that information can allow utilities to improve the management and operation of the grid. And in an industry that has typically been run by conservative managers accustomed to reliable forecasting and investments with long cycle times, utility leaders must now embrace flexibility and agility.
For many utilities, succeeding amid the massive shifts in the energy market requires real change. At the heart of that effort must be the development of a new culture. The business of electricity transmission has been stable for decades. As a result, companies have honed well-tuned, fixed processes. But moving forward, they need to tear up the old playbook. And they must adopt a new mind-set, one that views the growth of decentralized renewable energy not as a threat to their business but as an opportunity, one that has the potential to deliver significant benefits for society as a whole.
Many utility companies today have all the ingredients required to succeed. If they embrace that new mind-set, they can drive the careful and deliberate evolution of their capabilities and asset portfolio. Delaying such a shift—or, worse, rejecting the need for change—is dangerous. In the end, utilities that fail to adapt will find themselves with outdated skills and a mountain of stranded “zombie” assets.