The rapid growth of distributed solar in a number of states has raised questions about its potential effects on retail electricity prices, prompting concerns about cost-shifting between solar and non-solar customers. These concerns have led to a proliferation of proposals to reform retail rate structures and net energy metering (NEM) rules for distributed solar customers, often extending to states that have yet to witness significant solar growth. Such proposals have generally been met with a great deal of contention and often absorb substantial time and administrative resources, potentially at the expense of other issues that may ultimately have greater impact on utility ratepayers.
Given these trade-offs, one might ask: How large could the effect of distributed solar on retail electricity prices conceivably be? And how does that compare with the many other factors that also influence electricity prices – and over which state regulators and utilities also have some degree of control?
Galen Barbose
This article, which draws from a recent Lawrence Berkeley National Laboratory research paper, seeks to address these questions. Using a combination of back-of-the-envelope-style analyses and literature review, we at Berkeley Lab have estimated ranges for the potential effects of distributed solar on retail electricity prices, at both current and projected future penetration levels, and compared those estimates with a number of other important drivers for future retail electricity prices. The goal is to provide some rough sense of relative scale and, in doing so, help regulators, utilities and other stakeholders gauge how much attention to devote to evaluating and addressing potential cost-shifting from distributed solar customers.
What the analysis finds is that, in most circumstances, the effects of distributed solar will be relatively small compared with the myriad other issues also affecting electricity rates.
Estimating the effects
Debates about the existence and size of any cost-shifting from distributed solar have revolved mostly around how to value solar’s costs and benefits. We abstract from those important debates and show, more generically, how the effect of distributed solar on retail electricity prices is a function of three basic drivers: its penetration level, the compensation rate provided to distributed solar customers, and the net avoided costs to the utility. To generalize the effects on cost of service (CoS)-based retail electricity prices, we express these three key drivers in normalized (percentage) form:
• Penetration level is the total quantity of distributed solar generation as a percentage of total retail electricity sales;
• Solar compensation rate is the payment or bill savings per unit of solar generation, relative to the utility’s average CoS; and
• Net avoided costs are expressed as the net value of solar (VoS) to the utility (i.e., benefits minus costs) relative to the utility’s CoS.
Relying on those three terms, we can express the percentage change in average retail electricity prices resulting from distributed solar using the following formula:
Based on this relationship, the family of curves shown in Figure 1 illustrates the percentage change (either increase or decrease) in average retail electricity prices resulting from varying distributed solar penetration levels, with each curve corresponding to a particular VoS rate. If, for example, the value of solar is equal to half the utility’s cost of service (VoS/CoS = 50%), then a 10% solar penetration would lead to a 5% increase in retail electricity prices under this compensation regime. A higher VoS would result in smaller increases (or conceivably even decreases) in average retail prices.
The curves in Figure 1 correspond to the case in which solar compensation is equal to exactly the utility’s CoS, which roughly equates to full NEM with flat volumetric prices and no fixed or demand charges. This is typical of how residential solar customers are often compensated. However, most commercial customers – and, increasingly, residential customers as well – take service under rate structures with significant fixed or demand charges. In those cases, the curves in Figure 1 shift downward.
Benchmarking against other drivers
Based on the aforementioned relationship, Figure 2 compares the potential retail electricity price effects of distributed solar and a number of other important drivers. These estimates should be considered indicative and approximate, but they nevertheless help to illustrate a few key themes.
For the vast majority of states and utilities, the effects of distributed solar on retail electricity prices will likely remain negligible for the foreseeable future. At current penetration levels (0.4% of total U.S. retail electricity sales), distributed solar likely entails no more than a 0.03 cent/kWh long-run increase in U.S. average retail electricity prices – and far smaller than that for most utilities. Even at projected penetration levels in 2030 (slightly more than 3% of total U.S. retail electricity sales), distributed solar would likely yield no more than roughly a 0.2 cent/kWh (in year-2015 dollars) increase in U.S. average retail electricity prices – and less than a 0.1 cent/kWh increase in most states. These upper bound estimates are based on a relatively low VoS, equal to just 50% of the average utility CoS, and relatively generous solar compensation levels based on full NEM with volumetric pricing.
For states or utilities with particularly high distributed solar penetration levels, retail electricity price effects may be more significant but depend critically on the value of solar and underlying rate structure. Four utilities, all in Hawaii, currently have solar penetration rates on the order of 10% of electricity sales, and three other states are projected to reach this mark by 2030. Assuming a utility VoS ranging from 50% to 150% of its average CoS (based on a broad set of VoS studies reviewed), this level of distributed solar would yield between a 5% decrease and a 5% increase in retail electricity prices, under NEM with purely volumetric rates. Thus, for a utility with electricity prices otherwise equal to the national average, this would equate to a ±0.5 cent/kWh effect.
Energy efficiency has had a far greater impact on electricity sales than distributed solar has, and that is likely to continue. Distributed solar and energy efficiency can both impact retail electricity prices by virtue of reducing electricity sales. Utility energy-efficiency programs and federal appliance efficiency standards together reduced U.S. retail electricity sales in 2015 by an amount 35 times larger than that of distributed solar. Projected growth in energy-efficiency savings from those policies through 2030 is almost five times greater than projected growth in distributed solar generation. Assuming, for the sake of simple comparison, that the value of energy-efficiency savings to the utility is based on the same VoS range as previously mentioned (50%-150% of the utility CoS), growth in energy-efficiency savings over the 2015-2030 period would result in a change of up to ±0.8 cents/kWh in U.S. average retail electricity prices.
Natural gas prices impose substantial uncertainty on future electricity prices. Electricity prices have become increasingly linked with gas prices and are likely to become more so with continued growth in the share of electricity generated from gas. Although current gas prices are near historical lows, future prices remain highly uncertain, and that uncertainty is skewed upward. Gas-price confidence intervals suggest a 10% probability that gas prices in 2030 will be at least $1.90/MMBtu higher than expected (based on the current NYMEX gas futures strip). Based on a broad set of electricity market modeling studies, an increase in gas prices of this magnitude would lead to roughly a 0.8 cent/kWh increase in U.S. average retail electricity prices. Restructured regions, which have more acute sensitivity to natural gas prices, could see retail electricity price effects of more than twice that amount.
Though their historical effects on retail electricity prices appear small, state renewable portfolio standards (RPS) could lead to greater impacts if supply does not keep pace with demand. RPS compliance cost data suggest that the policies have thus far increased retail electricity prices by just 0.1 cent/kWh, on average, in RPS states. Rising targets over the coming years may put upward pressure on costs, which could be amplified if supplies of eligible renewable energy don’t keep pace. At the extreme (and, arguably, rather implausible) upper end – which assumes that renewable energy certificate prices in all markets are trading at their caps and that other administrative cost caps are not enforced – we estimate that retail electricity prices in RPS states could increase by 1.4 cents/kWh in 2030, on average, and by 3-4 cents/kWh in some states. Smaller retail price effects are expected in practice, and even decreases in average prices are possible, depending, in part, on how barriers to renewables development are addressed.
The effects of state and federal carbon policies on future retail electricity prices are highly dependent on program design and implementation details. Existing cap-and-trade programs in California and the Northeast have had limited impacts on retail electricity prices to date. In large part, this is because complementary policies have accomplished much of the targeted emission reductions, as well as because auction proceeds are used for ratepayer bill credits. Studies of the U.S. Environmental Protection Agency’s Clean Power Plan (CPP) – a policy that, as of this writing, is under stay and faces an uncertain future – have estimated that the CPP could result in an increase anywhere from 0.0 cents/kWh to 1.5 cents/kWh in U.S. average retail electricity prices. Much of that range reflects differences in how states implement the federal standard, such as whether they pursue rate-based or mass-based compliance, how allowances are allocated, the scope of allowance trading, and the degree of reliance on energy efficiency.
Future capital expenditures (CapEx) in the electricity industry will put upward pressure on retail electricity prices. CapEx in the electricity industry have been on the rise, increasing by roughly 6% per year in real terms (8% nominal) since 2000, despite relatively flat load growth. Going forward, the impacts of continued utility CapEx on retail electricity prices will depend on the pace of future investments, as well as on utilities’ cost of capital. Considering a plausible range of assumptions for those two factors, we estimate a 1.6-3.6 cent/kWh impact on U.S. average retail electricity prices in 2030 as a result of future CapEx by regulated utilities (some portion of which will be offset as existing capital investments become fully depreciated). For some utilities – for example, those making investments in new nuclear generation capacity or undertaking major grid modernization initiatives – the potential impacts on retail prices may be greater than that estimated range or may occur over a more accelerated time frame.
Conclusions
The most basic conclusion from these comparisons is that, in most cases, the effects of distributed solar on retail electricity prices are – and will continue to be – quite small compared with many other issues. That is not to say that reforms of NEM rules or retail rate structures for distributed solar customers are unwarranted. However, other objectives, such as economic efficiency, likely provide a more compelling rationale.
Where concerns about minimizing retail electricity price remain a priority, other issues may prove more impactful. Among the issues highlighted in this article, electric utility CapEx is anticipated to have the greatest impact and is clearly an area where regulatory oversight can play a crucial role in managing retail price escalation. Resource planning and procurement processes – where utilities and regulators can weigh the merits of fuel diversification strategies as a hedge against natural gas price risk and uncertainty over future carbon regulations – are another important point of leverage in keeping rates low. Finally, regulators and policymakers can limit the rate impacts of RPS policies by establishing RPS rules and other supportive policies that ensure renewable electricity supply keeps pace with growing RPS demand.
For states and utilities with exceptionally high distributed solar penetration levels, the effects on retail electricity prices could begin to approach the same scale as other important drivers (at least among residential customers). In these cases, questions about the value of solar become more important to both assessing and mitigating any cost-shifting. Efforts aimed at stimulating higher value forms of solar deployment can mitigate rate impacts, for example, by directing development toward geographic regions with the greatest transmission and distribution deferral opportunities, by developing mechanisms to leverage the capabilities of advanced inverters, or by incentivizing the pairing of solar with storage or demand response. Such strategies represent an alternative and potentially less contentious approach to addressing the effects of distributed solar on retail electricity prices.
Experiences with energy efficiency also offer lessons for states witnessing especially high levels of distributed solar penetration. In particular, these experiences show that short-term retail price impacts from distributed energy resources may be more acceptable, provided that they yield net savings to ratepayers over the long run and that adequate opportunities exist for all ratepayers (especially low- and moderate-income customers) to participate. As solar costs continue to decline, grid-friendly solar technologies advance and initiatives to broaden solar access continue, issues of cost-shifting from distributed solar will become more similar to those of energy efficiency. Therefore, concerns about solar cost-shifting may naturally subside.
Galen Barbose is a research scientist in the electricity markets and policy group at the Lawrence Berkeley National Laboratory. This article draws from a larger Berkeley Lab report titled, “Putting the Potential Rate Impacts of Distributed Solar into Context.”
