The Law of Unintended Consequences

The only rule universally observed in the electric power industry is the law of unintended consequences. There are so many different entities with an interest in, and in some cases control over, the power sector that it’s often difficult to align policy with practicality. In the case of technological developments in distributed generation and net metering, a new regulatory scheme will be necessary to ensure the recovery of utilities’ costs for maintaining the system that delivers electricity today.

Failing to adopt a regulatory strategy to manage the transition to new technologies can have a dramatic effect on cost allocation to consumers—and the reliability of their energy supplies. The evolution of telephone service provides an excellent example. The lack of coordination between the costs of wireless and the costs of legacy networks that still provide landline service across the United States has resulted in a heavy burden on non-participants in wireless, and threatens their system’s reliability.

The opportunity was there. Twenty years ago state regulators exercised control over all telephone services and their costs. Today, in New York State, one telecommunications company is a dominant provider of both copper wire and wireless telephone service. Yet by virtue of a regulatory scheme that didn’t factor in the success of a new technology, revenues from the moneymaking wireless services aren’t available to support the money-losing landline business, whose customer service metrics are in free fall. As a result, wireless users today contribute nothing to the cost of providing telephone service over landlines, and landline customers contribute nothing to the cost of providing wireless service. As the copper wire customer base rapidly shrinks, only its users—not all telephone customers—bear the cost of maintaining a system that’s easy to opt out of. However, many of the users of landlines who are unable or unwilling to switch to wireless also receive government support for living expenses, including landline telephone service, so taxpayers ultimately bear the cost of maintaining an obsolete technology.

The same regulatory standard that states apply to the telephone industry, “safe and adequate service at just and reasonable rates,” has always applied to utility services throughout the United States. Yet telephone service is an ongoing example of a new technology disrupting regulators’ ability to honor this standard and to treat all ratepayers fairly—whether they’re wireless participants or not. Had state regulators acted more thoughtfully, and then aggressively, this misalignment of interests could’ve been dealt with appropriately from the beginning.

In the electric sector, an analogous technological change is underway, and its long-term consequences have yet to be considered in depth by regulators. The effects of encouraging distributed generation (DG) behind the meter, through various subsidies and incentives, has gone largely unaddressed in regulatory proceedings. Everyone in the field seems to acknowledge that the effort to expand DG is a positive development, but without a national energy policy to guide them, state regulators are left to grapple with the rate consequences of policies such as net metering, which are used to promote DG.

With the best of intentions, regulators and lawmakers alike have encouraged DG through both tax and rate-related benefits, and required, through renewable generation mandates, the development of alternatives to large, fixed generating stations powered by nuclear, hydro, or fossil fuels. The trend toward DG, starting in earnest at the beginning of this century, is accelerating at a troubling rate. If it isn’t properly analyzed and addressed, it could trigger disruption and confusion in the provision of “safe and adequate service at just and reasonable rates.”

Perverse Incentives?

Among the financial inducements provided to sponsors of DG, the principal incentive, together with tax advantages, is net metering. Once a DG unit has served its sponsor’s needs, it sends onto the grid any unused electrons, with payment to the sponsor for this energy. In most cases, this payment comes in the form of net metering—in which the meter effectively runs backwards, compensating the DG owner at retail rates for each kilowatt-hour fed onto the grid.

Most DG is located behind the meter, on the customer’s premises and not in the utility domain. The reason for this can be summarized in two words: “tax benefits.” The federal tax credit for the installation of distributed wind and solar electric systems, like photovoltaic (PV) panels, is 30 percent; for combined heat and power, 10 percent. Additional federal tax benefits are available from accelerated recovery of tax depreciation that can provide substantial additional savings. At the state level, North Carolina currently provides a most generous state tax benefit: 35 percent of the cost of the installation of PV, up to $2.5 million. Other states have similar plans with lesser or greater benefits. For instance, Louisiana enables the homeowner to claim tax credits arising out of net metering for up to 50 percent of the cost of the installation of PV.

So for an individual with an appetite for a tax credit in North Carolina, the costs of installing PV can be shared with the federal and state governments; with depreciation included, governments provide at least 70 percent of the installed cost , and the sponsor less than 30 percent—and that’s before factoring in payments for any electrons sent into the grid via net metering. The sponsors of DG—in many instances customers with significant financial resources—see their actions, enabled by tax and other incentives, as reducing the demand on the electric grid. This reduction in demand, they assert, merits a dramatic decrease in what they must pay for utility service—to compensate the wholesale generators, transmission providers, and local distribution companies. Yet the requirement of safe and adequate service means that prudently installed utility infrastructure and the costs of running and maintaining it must continue to be shared in an appropriate fashion with all customers, including those sponsoring DG.

While state regulators usually have no direct involvement in tax-related subsidies, they often do in the non-tax arena. But invariably they have to deal with the unintended consequence of such policies on electric utilities and their ratepayers. An example of this misalignment of interests is the interconnection and integration of renewables, often required by a state’s renewable portfolio standard. These processes result in additional costs that are unique to the renewable generator, but often not borne exclusively by its sponsor; rather, they’re socialized among all ratepayers. A case in point: when a specific DG site must incur costs to connect its unneeded electrons to the grid, or to make the grid accept electrons going in two directions, its regulators must deal with the question of who bears these costs. Currently, in most jurisdictions, they’re paid by all ratepayers, perhaps unfairly.

Yet DG is new generation of electricity. The costs of providing this same location with the electricity it utilized before DG—the old electricity—still endure in the regulatory world for the financial life of the relevant assets.

This is particularly true for DG using variable resources, such as wind or solar, whose output might not be available to its sponsor at times of peak demand. At those times energy must be supplied by the existing utility system—the old electricity. These costs must, in some fashion, continue to be borne by all customers, both the sponsors of DG, as well as those not participating in DG (non-participants). If not, the sponsor would be deriving a windfall by not paying its fair share of the cost of the old electricity and the non-participants would thereby be subsidizing the DG sponsor. Unless the sponsor had determined to disconnect from the grid completely and run the risk of its facility not having access to electricity if its new installation fails or needs maintenance, the utility has to charge a fee to be available to deliver electricity (including generation, distribution, and commodity services) on an as-needed basis (a standby charge).

On the other hand, sponsors point out, quite correctly, that since DG is relieving certain demands on the provision of electric service—reducing the peak demand, the need for new transmission or distribution networks, etc.—then DG sponsors should be compensated for taking the risk of funding a new technology and any related cost benefits. They are right to seek regulatory focus on quantifying the benefit of their initiatives to the entire electricity system and, once the benefits are clearly identified, to receive compensation for their risk-taking through appropriate rate design.

However, the savings provided by DG to the utility system can be very case-specific, and could depend on the site of the DG facility, the periods it actually produces power, the demand profile of the DG sponsor, and other characteristics. Subsidies and rate programs that treat all DG the same—as tax benefits do—aren’t the best way to ensure the most efficient development of DG resources, nor do they deal fairly with all ratepayers.

Managing the Transition

Whatever the benefits of DG, there are unintended consequences for granting rate incentives for mandating DG system-wide, and as DG proliferates, so do these unintended consequences. While we transition to a new, technology-enhanced distribution system, we also need to revisit and update a number of key retail rate policies as part of a long-term strategy for handling the effects of new technologies. Five policies, in particular, need to be addressed:

• Retail rate design: The current regulatory model provides recovery of most fixed costs through volumetric (kWh) rates for residential and small business customers. Fixed costs are part of allowed revenue requirements, which are spread over the average per-customer kWh sales established in the test year for mass-market customers. Commercial and industrial customers have separate demand charges that recover fixed costs. This traditional approach worked well when per-customer energy use was growing. It produced incremental revenues that helped utilities fund new investments. In the future, however, as customers opt to deploy DG and other kinds of similar energy resources, per-customer kWh use likely will fall below levels assumed in the electric utility’s most recent rate case. This will cause the utility to under-recover some of its allowed fixed costs. As DG grows, such under-recovery has the potential to materially weaken the utility’s financial integrity and its ability to attract investor capital, which in turn can lead to higher rates. To avoid this unintended outcome, we need to move, over time, toward rates that recover fixed network costs through fixed charges to all ratepayers.
• Net metering: Forty three states and the District of Columbia have net-metering policies, which are intended to encourage DG by compensating DG sponsors for whatever power they actually supply to the grid. In most jurisdictions, this means running the meter backward at the full, bundled retail rate. This presents a problem because the bundled rate includes costs that the utility continues to incur even if the DG sponsor supplies power—such as costs for customer care, transmission, and distribution. The unintended consequence of net metering is that DG sponsors avoid some portion of their fair share of fixed costs. These costs must be paid by other customers or utility shareholders, and neither of these approaches is sustainable over the long term. One solution is to unbundle the retail rate so the DG sponsor is only credited for the value of generation, as well as the other measurable benefits it supplies to the utility. A further refinement is to take into account the time-of-use value of generation and transmission resources the DG sponsor needs to use.
• Backup and standby rates: Backup and standby rates are the terms and conditions under which the utility supplies the sponsor with electricity when its DG is off-line, either because it has failed, or because it’s down for scheduled maintenance. If DG sponsors pay only for the use of the network when they need it, they again won’t pay their fair share of the generation, transmission, and distribution that they continually rely on. This occurs because, as noted above, regulators have usually designed rates to keep fixed charges low, and instead to rely on volumetric (kWh) charges to recover fixed costs. Also as noted, this volumetric approach increases the probability that the utility won’t recover all of its DG support costs. A possible remedy is to implement fixed charges for DG sponsors to recover not only the costs needed to reserve backup generating and transmission capacity—so that it isn’t used for other purposes and is available when called upon—but also the fixed cost of these services when actually used, as well as the cost of fuel.
• Interconnection costs: Interconnection costs are incurred to link DG to the existing distribution system in a way that ensures safety and reliability. These include capital costs related to service connections for DG projects; circuit breakers to disconnect DG when needed to protect utility workers and first responders; distribution circuits and substation upgrades; as well as metering, sensors, controls, and communication infrastructure needed to accommodate the increasing amount of two-way power flows on the distribution network. As the use of DG increases, so does the cost of its interconnection. In addition to the capital costs, the utility bears operating and maintenance expenses related to the required incremental distribution infrastructure. Demonstrated interconnection costs need to be recovered from the DG sponsor.
• Integration of Various DG Resources: Where the DG is derived from a variable resource such as wind or solar, additional costs are incurred to provide the continuous balancing of power, thereby ensuring that demand is satisfied on a moment-to-moment basis, and reliability is maintained. This involves things like operating reserves, regulation, and load-following resources to maintain grid stability. To the extent integration costs can be demonstrated and are prudently incurred, they need to be recovered. A major regulatory question is in what proportion DG sponsors and all other customers should bear these costs. In some parts of the country, this is the responsibility of independent system operators or regional transmission operators; in others the state utility regulator has this task. In all events, allocation of costs and benefits should be transparent to whoever is paying for these services.

Modernizing Regulation

Today we stand at a crossroads in the electric utility industry, comparable in some ways to the crossroads we passed 20 years ago in telecom. In telecom we failed to anticipate and manage the introduction of disruptive new technologies, and we’re continuing to pay the price because of our inability to provide to all customers safe and adequate service at just and reasonable rates. Let’s not repeat this mistake in electricity. At a time when we’re embarking on the construction of a fundamentally new kind of distribution system, let’s seize the moment, and update rate policies to put electricity on a sustainable basis for the future—for all.

We have the insight necessary to address the unintended consequence of policies that force non-participants in a new technology to bear some of the costs without directly receiving any of the benefits. In so doing, three goals should guide us: fairness to ratepayers; appropriate allocation of fixed costs; and encouragement of efficient development.

To provide fairness, we need to cure the tendency under current rate policies to shift costs from DG sponsors to non-DG ratepayers. This change is needed to comport with utility regulation’s fundamental mandate to ensure that rates are just. It also would prevent a misalignment akin to what landline customers are experiencing because wireless customers of the same vendor are exempt from supporting its copper wire system, with the result that non-wireless service metrics are sorely deficient. At the same time, the real benefits that DG sponsors bring to the electricity system should be taken into account in ratemaking.

With regard to appropriate cost allocation, all the fixed costs incurred to preserve and modernize the grid must be recovered in rates. This is essential to preserve the financial health of utilities, and thereby, the long-term reliability of the system on which the public depends—and for which it pays.

Finally, to encourage efficient development, accurate price signals should be embedded in rates to allow both customers and utilities to make efficient investment decisions. Rate policies that encourage DG investments by shifting costs to others might not be the best or the least-cost way for society to explore this new technology. Incentives that might have been appropriate when DG was a fledgling business, with insignificant market penetration, now threaten consequences that, if not addressed by regulators, will harm the public interest.

As technologies continue to improve and incentives are enhanced—all with the best of intentions—ignoring the need for change will make such unintended consequences inevitable. The time to revisit and rationalize retail rate policies is now. This opportunity might not come again.