Rooftop solar is booming in U.S. cities.

One of the most exciting infrastructure developments within metropolitan America, the installation of over a million solar photovoltaic (PV) systems in recent years, represents nothing less than a breakthrough for urban sustainability — and the climate.

Prices for solar panels have fallen dramatically. Residential solar installations surged by 66 percent between 2014 and 2015 helping to ensure that solar accounted for 30 percent of all new U.S. electric generating capacity. And for that matter, recent analyses conclude that the cost of residential solar is often comparable to the average price of power on the utility grid, a threshold known as grid parity.

So, what’s not to like? Rooftop solar is a total winner, right?

Well, not quite: The spread of rooftop solar has raised tricky issues for utilities and the public utilities commissions (PUCs) that regulate them. 

Specifically, the proliferation of rooftop solar installations is challenging the traditional utility business model by altering the relationship of household and utility—and not just by reducing electricity sales. In this respect, the solar boom has prompted significant debates in states like New York and California about the best rates and policies to ensure that state utility rules and rates provide a way for distributed solar to flourish even as utilities are rewarded for meeting customer demands. Increasingly, this ferment is leading to thoughtful dialogues aimed at devising new forms of policy and rate design that can—as in New York—encourage distributed energy resources (DERs) while allowing for distribution utilities to adapt to the new era.

However, in some states, the ferment has prompted a cruder set of backlashes. Most pointedly, some utilities contend that the “net-metering” fees paid to homeowners with rooftop installations for excess solar power they send back to the grid unfairly transfer costs to the utilities and their non-solar customers.

And so in a number of states, utility interests have sought to persuade state regulators to roll back net-metering provisions, arguing they are a net cost to the overall electricity system.  Most glaringly, the local utility in Nevada successfully wielded the cost-shift theory last winter to get the Nevada Public Utilities Commission to drastically curtail the state’s net-metering payments, prompting Solar City, Sunrun, and Vivint Solar—the state’s three largest providers of rooftop panels—to leave the Nevada market entirely. The result: New residential solar installation permits plunged 92 percent in Nevada in the first quarter of 2016.

All of which highlights a burning question for the present and future of rooftop solar: Does net metering really represent a net cost shift from solar-owning households to others? Or does it in fact contribute net benefits to the grid, utilities, and other ratepayer groups when all costs and benefits are factored in? As to the answer, it’s getting clearer (even if it’s not unanimous). Net metering — contra the Nevada decision — frequently benefits all ratepayers when all costs and benefits are accounted for, which is a finding state public utility commissions, or PUCs, need to take seriously as the fight over net metering rages in states like Arizona, California, and Nevada.  Regulators everywhere need to put in place processes that fairly consider the full range of benefits (as well as costs) of net metering as well as other policies as they set and update the policies, regulations, and tariffs that will play a critical role in determining the extent to which the distributed solar industry continues to grow.

Fortunately, such cost-benefit analyses have become an important feature of state rate-setting processes and offer important guidance to states like Nevada.  So what does the accumulating national literature on costs and benefits of net metering say?  Increasingly it concludes— whether conducted by PUCs, national labs, or academics — that the economic benefits of net metering actually outweigh the costs and impose no significant cost increase for non-solar customers.  Far from a net cost, net metering is in most cases a net benefit—for the utility and for non-solar rate-payers.

Of course, there are legitimate cost-recovery issues associated with net metering, and they vary from market to market. Moreover, getting to a good rate design, which is essential for both utility revenues and the growth of distributed generation, is undeniably complicated.  If rates go too far in the direction of “volumetric energy charges”—charging customers based on energy use—utilities could have trouble recovering costs when distributed energy sources reach higher levels of penetration. On the other hand, if rates lean more towards fixed charges—not dependent on usage—it may reduce incentives for customers to consider solar and other distributed generation technologies.  

Moreover, cost-benefit assessments can vary due to differences in valuation approach and methodology, leading to inconsistent outcomes. For instance, a Louisiana Public Utility Commission study last year found that that state’s net-metering customers do not pay the full cost of service and are subsidized by other ratepayers. How that squares with other states’ analyses is hard to parse.

Nevertheless, by the end of 2015, regulators in at least 10 states had conducted studies to develop methodologies to value distributed generation and net metering, while other states conducted less formal inquiries, ranging from direct rate design or net-metering policy changes to general education of decisionmakers and the public. And there is a degree of consensus.  What do the commission-sponsored analyses show? A growing number show that net metering benefits all utility customers:

• In 2013 Vermont’s Public Service Department conducted a study that concluded that “net-metered systems do not impose a significant net cost to ratepayers who are not net-metering participants.” The legislatively mandated analysis deemed the policy a successful component of the state’s overall energy strategy that is cost effectively advancing Vermont’s renewable energy goals.

• In 2014 a study commissioned by the Nevada Public Utility Commission itself concluded that net metering provided $36 million in benefits to all NV Energy customers, confirming that solar energy can provide cost savings for both solar and non-solar customers alike. What’s more, solar installations will make fewer costly grid upgrades necessary, leading to additional savings. The study estimated a net benefit of $166 million over the lifetime of solar systems installed through 2016. Furthermore, due to changes to utility incentives and net-metering policies in Nevada starting in 2014, solar customers would not be significantly shifting costs to other ratepayers.

• A 2014 study commissioned by the Mississippi Public Services Commission concluded that the benefits of implementing net metering for solar PV in Mississippi outweigh the costs in all but one scenario. The study found that distributed solar can help avoid significant infrastructure investments, take pressure off the state's oil and gas generation at peak demand times, and lower rates. (However, the study also warned that increased penetrations of distributed solar could lead to lower revenues for utilities and suggested that the state investigate Value of Solar Tariffs, or VOST, and other alternative valuations to calculate the true cost of solar.)

• In 2014 Minnesota’s Public Utility Commission approved a first-ever statewide “value of solar” methodology which affirmed that distributed solar generation is worth more than its retail price and concluded that net metering undervalues rooftop solar. The “value of solar” methodology is designed to capture the societal value of PV-generated electricity. The PUC found that the value of solar was at 14.5 cents per kilowatt hour (kWh)—which was 3 to 3.5 cents more per kilowatt than Xcel's retail rates—when other metrics such as the social cost of carbon, the avoided construction of new power stations, and the displacement of more expensive power sources were factored in.

• Another study commissioned by the Maine Public Utility Commission in 2015 put a value of $0.33 per kWh on energy generated by distributed solar, compared to the average retail price of $0.13 per kWh — the rate at which electricity is sold to residential customers as well as the rate at which distributed solar is compensated. The study concludes that solar power provides a substantial public benefit because it reduces electricity prices due to the displacement of more expensive power sources, reduces air and climate pollution, reduces costs for the electric grid system, reduces the need to build more power plants to meet peak demand, stabilizes prices, and promotes energy security. These avoided costs represent a net benefit for non-solar ratepayers.

These generally positive PUC conclusions about the benefits of net metering have been supported by research done by a national lab and several think tanks. Important lab research has examined how substantially higher adoption of distributed resources might look.

In a forward-looking analysis of the financial impacts of net-metered energy on utilities and ratepayers, Lawrence Berkeley National Lab found that while high use of net-metered solar generation may decrease utility shareholders' earnings, it will have a "relatively modest" impact on ratepayers. The report examined solar penetration levels that are "substantially higher than [those that] exist today" — 10 percent compared to today's 0.2 percent — and concluded that “even at penetration levels significantly higher than today, the impacts of customer-sited PV on average retail rates may be relatively modest." The report further said that utilities and regulators "may have sufficient time to address concerns about the rate impacts of PV in a measured and deliberate manner"

Similarly, a growing number of academic and think tank studies have found that solar energy is being undervalued and that it delivers benefits far beyond what solar customers are receiving in net-metering credits:

• For instance, a review of 11 net metering studies by Environment America Research and Policy Center has found that distributed solar offers net benefits to the entire electric grid through reduced capital investment costs, avoided energy costs, and reduced environmental compliance costs. Eight of the 11 studies found the value of solar energy to be higher than the average local residential retail electricity rate: The median value of solar power across all 11 studies was nearly 17 cents per unit, compared to the nation’s average retail electricity rate of about 12 cents per unit.

• A 2015 cost-benefit study of net metering in Missouri by the Missouri Energy Initiative found that even accounting for increased utility administrative costs and the shifting of some fixed expenses, net metering is a net benefit for all customers regardless of whether they have rooftop solar. The study used values for two kinds of costs and two benefits and concluded that net metering’s “net effect” is positive. The typical solar owner pays only 20 percent less in fixed grid costs and costs the utility an estimated $187 per interconnection. Meanwhile, solar owners benefit the system through reduced emissions and energy costs.

• Likewise, a study by Acadia Center found the value of solar to exceed 22 cents per kWh of value for Massachusetts ratepayers through reduced energy and infrastructure costs, lower fuel prices, and lowering the cost of compliance with the Commonwealth's greenhouse gas requirements. This value was estimated to exceed the retail rate provided through net metering.

• In yet another study, researchers at the University at Albany, George Washington University, and Clean Power Research have found that solar installations in New York deliver between 15 and 40 cents per kWh to ratepayers. The study noted that these numbers provide economic justification for the existence of incentives that transfer value from those who benefit from solar electric generation to those who invest in solar electric generation.

In short, while the conclusions vary, a significant body of cost-benefit research conducted by PUCs, consultants, and research organizations provides substantial evidence that net metering is more often than not a net benefit to the grid and all ratepayers.

As to the takeaways, they are quite clear: Regulators and utilities need to engage in a broader and more honest conversation about how to integrate distributed-generation technologies into the grid nationwide, with an eye toward instituting a fair utility-cost recovery strategy that does not pose significant challenges to solar adoption.

From the state PUCs’ perspective, until broad changes are made to the increasingly outdated and ineffective standard utility business model, which is built largely around selling increasing amounts of electricity, net-metering policies should be viewed as an important tool for encouraging the integration of renewable energy into states’ energy portfolios as part of the transition beyond fossil fuels. To that end, progressive regulators should explore and implement reforms that arrive at more beneficial and equitable rate designs that do not prevent solar expansion in their states. The following reforms range from the simplest to the hardest:

• Adopt a rigorous and transparent methodology for identifying, assessing, and quantifying the full range of benefits and costs of distributed generation technologies. While it is not always possible to quantify or assess sources of benefits and costs comprehensively, PUCs must ensure that all cost-benefit studies explicitly decide how to account for each source of value and state which ones are included and which are not. Currently methodological differences in evaluating the full value of distributed generation technologies make comparisons challenging. States start from different sets of questions and assumptions and use different data. For instance, while there is consensus on the basic approach to energy value estimation (avoided energy and energy losses via the transmission and distribution system), differences arise in calculating other costs and benefits, especially unmonetized values such as financial risks, environmental benefits, and social values. In this regard, the Interstate Renewable Energy Council’s “A Regulator’s Guidebook: Calculating the Benefits and Costs of Distributed Solar Generation” and the National Renewable Energy Laboratory’s “Methods for Analyzing the Benefits and Costs of Distributed Photovoltaic Generation to the U.S. Electric Utility System” represent helpful resources for identifying norms in the selection of categories, definitions, and  methodologies to measure various benefits and costs.

• Undertake and implement a rigorous, transparent, and precise “value of solar” analytic and rate-setting approach that would compensate rooftop solar customers based on the benefit that they provide to the grid. Seen as an alternative to ‘traditional’ net-metering rate design, a “value of solar” approach would credit solar owners for (1) avoiding the purchase of energy from other, polluting sources; (2) avoiding the need to build additional power plant capacity to meet peak energy needs; (3) providing energy for decades at a fixed prices; and (4) reducing wear and tear on the electric grid. While calculating the “value of solar” is very complex and highly location-dependent, ultimately PUCs may want to head toward an approach that accurately reflects all benefits and costs from all energy sources. Value of solar tariffs are being used in Austin, Texas (active use) and Minnesota (under development).

• Implement a well-designed decoupling mechanism that will encourage utilities to promote energy efficiency and distributed generation technologies like solar PV, without seeing them as an automatic threat to their revenues. As of January 2016, 15 states have implemented electric decoupling and eight more are considering it. Not surprisingly, it is states that have not decoupled electricity (such as Nevada) that are fighting net metering the hardest. Typically, decoupling has been used as a mechanism to encourage regulated utilities to promote energy efficiency for their customers. However, it can also be used as a tool to incentivize net metering by breaking the link between utility profits and utility sales and encouraging maximum solar penetration. Advocates of decoupling note that it is even more effective when paired with time-of-use pricing and minimum monthly billing.

• Move towards a rate design structure that can meet the needs of a distributed resource future. A sizable disconnect is opening between the rapidly evolving new world of distributed energy technologies and an old world of electricity pricing. In this new world, bundled, block, “volumetric” pricing—the most common rate structure for both residential and small commercial customers—can no longer meet the needs of all stakeholders. The changing grid calls, instead, for new rate structures that respond better to the deployment of new grid technologies and the proliferation of myriad distributed energy resources, whether solar, geothermal, or other.  A more sophisticated rate design structure, in this regard, would take into consideration three things: (1) the unbundling of rates to specifically price energy, capacity, ancillary services,  and so on; (2) moving from volumetric bloc rates to pricing structures that recognize the  variable time-based value of electricity generation and consumption (moving beyond just peak versus off-peak pricing to  fully real-time pricing); and (3) moving from pricing that treats all customers equally to a pricing structure that more accurately compensates for unique, location-specific and technology specific values.

• Move towards a performance-based utility rate-making model for the modern era. Performance based regulation (PBR) is a different way of structuring utility regulation designed to align a utility’s financial success with its ability to deliver what customers and society want. Moving to a model that pays the utility based on whether it achieves quantitatively defined outcomes (like system resilience, affordability, or distributed generation integration) can make it profitable for them to pursue optimal grid solutions to meet those outcomes. The new business model would require the PUC and utilities to make a number of changes, including overhauling the regulatory framework, removing utility incentives for increasing capital assets and kilowatt hours sold, and replacing those incentives with a new set of performance standard metrics such as reliability, safety, and demand-side management. New York’s Reforming the Energy Vision  proceeding is the most high-profile attempt in the country to implement a PBR model.

Options also exist for utilities to address the challenges posed by net metering:

• Utilities, most notably, have the opportunity to adjust their existing business models by themselves owning and operating distributed PV assets (though not to the exclusion of other providers).  On this front, utilities could move to assemble distributed generation systems, such as for rooftop solar, and sell or lease them to homeowners. In this regard, utilities have an advantage over third-party installers currently dominating the residential rooftop solar industry due to their proprietary system knowledge, brand recognition, and an existing relationship with their customers. Utilities in several states such as Arizona, California, and New York are investigating or have already invested in the opportunity.

• Furthermore, utilities can also push the envelope on grid modernization by investing in a more digital and distributed power grid that enables interaction with thousands of distributed energy resources and devices.

Ultimately, distributed solar is here to stay at increasing scale, and so state policies to support it have entered an important new transitional phase. More and more states will now likely move to update their net-metering policies as the cost of solar continues to drop and more homeowners opt to install solar panels on their homes.

As they do that, states need to rigorously and fairly evaluate the costs and benefits posed by net metering, grid fees, and other policies to shape a smart, progressive regulatory system that works for all of the stakeholders touched by distributed solar.

Utilities should have a shot at fair revenues and adequate ratepayers. Solar customers and providers have a right to cost-effective, reliable access to the grid. And the broader public should be able to expect a continued solar power boom in U.S. regions as well as accelerated decarbonization of state economies. All of which matters intensely. As observes the North Carolina Clean Energy Technology Center and Meister Consultants Group: “How key state policies and rates are adapted will play a significant role in determining the extent to which the [solar PV] industry will continue to grow and in what markets.”

The debate surrounding net energy metering (NEM) and the appropriate way to reform this policy is under scrutiny in many U.S. states. This is highly warranted since NEM policies do indeed need reforming because NEM often results in subsidies to private (rooftop) solar owners and leasing companies. These subsidies are then “paid for” by non-NEM customers (customers without private rooftop solar installations). The fundamental source of the NEM subsidy is the failure of NEM customers (customers with private rooftop solar installations) to pay fully for the grid services that they use 24/7. These subsidies are well-documented and underpin much of the regulatory reform efforts underway across the United States.[1]

In a recent Brookings paper, “Rooftop solar: Net metering is a net benefit,” Mark Muro and Devashree Saha contend that net metering is a net benefit for non-NEM customers.[2] I fundamentally disagree with their findings, and argue that NEM is not a net benefit; it is, in fact, a tariff that much of the time results in a subsidy to NEM customers and a cost shift onto non-NEM customers. As Executive Director of the Institute for Electric Innovation, a non-lobbying organization focused on trends in the electric power industry, I have followed this debate and written about it for several years.

Much of the talk about NEM focuses too often on the “value” of the energy that is sold back to the grid by a NEM customer. In reality, the amount of energy sold back to the grid is relatively small. The real issue is the failure of NEM customers to pay fully for the grid services that they use while connected to the grid 24/7, as shown in Figure 1.[3] Customers need to constantly use the grid to balance supply and demand throughout the day, and the cost of these grid services can be sizeable. In fact, for a typical residential customer in the United States with an average electricity bill of $110 per month, the actual cost of grid services can range from $45 to $70 per month–however, the customer doesn’t see that charge.[4] That means, in the extreme, if a customer’s energy use “nets” to zero in a given month because the customer’s private solar system produced exactly what the customer consumed, that customer would pay $0 even though that customer is connected to the local electric company’s distribution grid and is utilizing grid services on a continuous around-the-clock basis.[5]

Although exactly netting to zero energy in a month is highly unlikely, this example demonstrates the point that the customer would pay nothing, despite using grid services at a cost ranging from $45 to $70 per month. Over the course of one year, this customer could receive a subsidy resulting from NEM of between $540 and $840. Over the life of a private rooftop solar system, which ranges from 20 to 25 years, this is a significant subsidy resulting from NEM.

Granted, this is an extreme example, and most NEM customers will pay for some portion of grid services. However, the fundamental source of the NEM subsidy is the failure of NEM customers to pay fully for the grid services that they use 24/7, and the cost of these services can be quite substantial. When a NEM customer doesn’t pay for the grid, the cost is shifted onto non-NEM customers.[6] It is a zero-sum game; plain and simple. This is the elephant in the room.

This issue was directly addressed by Austin Energy when the company implemented a “buy-sell” arrangement for the private rooftop solar customers in its service territory. The rationale for the buy-sell approach is that the customer buys all of the energy that is consumed on-site through the electric company’s retail tariff and sells all of the energy produced by their private rooftop solar system at the electric company’s avoided cost. This addresses the “elephant in the room” because, by buying all energy consumed at the retail tariff, the customer does pay for grid services that are largely captured through the retail tariff. It is an unfortunate fact that under ratemaking practices today in the United States, the majority of fixed costs (i.e., grid and other costs) are captured through a volumetric charge.

Hence, I fundamentally disagree with the Muro/Saha paper–NEM does need to be reformed. NEM is not a net benefit; it is a tariff that the much of the time results in a cost shift onto non-NEM customers. One of the first studies to quantify the magnitude of the NEM subsidy was conducted by Energy+Environmental Economics (E3) for the California Public Utilities Commission (CPUC) in 2013. There was no mention of this analysis for the CPUC in the Muro/Saha paper. The E3 study estimated that NEM would result in a cost shift of $1.1 billion annually by 2020 from NEM to non-NEM customers if current NEM policies were not reformed in California.[7] A cost shift of this magnitude–paid for by non-NEM customers–was unacceptable to California regulators. As a result, California regulators set to work to reform rates in their state; many other states followed suit and conducted similar investigations of the magnitude of the NEM subsidy.

In reviewing NEM studies, Muro and Saha chose to focus on a handful of studies that show that net metering results in a benefit to all customers. In this small group of NEM studies, they included a study that E3 conducted for the Nevada Public Utilities Commission (PUC) in 2014–perhaps the most well-known and cited of the five studies included in the Muro/Saha paper. Very soon after the E3 Nevada study was published, the cost assumptions for the base-case scenario which showed a net benefit of $36 million to non-NEM customers (assuming $100 per MWh for utility-scale solar) were found to be incorrect, completely reversing the conclusion. The $36 million benefit associated with NEM for private rooftop solar turned into a $222 million cost to non-NEM customers when utility-scale solar was priced at $80 per MWh.[8] Today, based on the two most recent utility-scale contracts approved by the Nevada PUC, utility-scale solar has an average lifetime (i.e., levelized) cost of $50 per MWh, meaning that the NEM cost shift would be far greater today. In February 2016, the Nevada PUC stated that “the E3 study is already outdated and irrelevant to the discussion of costs and benefits of NEM in Nevada…”[9] Hence, because the E3 study for the Nevada PUC that the Muro/Saha paper included has been declared outdated and irrelevant to the discussion and because costs for utility-scale solar have declined significantly, that study does not show that NEM provides a net benefit.

No doubt there is an intense debate underway about NEM for private rooftop solar, and much has changed in the past two years in terms of both NEM policies and the growth of private solar projects:

• First, several state regulatory commissions now recognize that the NEM cost shift is both real and sizeable and that all customers who use the grid, including NEM customers, need to pay for the cost of the grid. As a result, many electric companies have proposed and state regulatory commissions have approved increases in monthly fixed charges over the past few years; this partially addresses the issue of NEM customers paying for the cost of the grid services that they use.
• Second and related, getting the pricing right for distributed energy resources of all types is important because we expect those resources to grow significantly in the future. Work is underway in this area and it is one focus of the New York Reforming the Energy Vision proceeding; but there is still much to be done.

By focusing on a select group of studies that show that NEM benefits all customers (as stated by the authors); by excluding the E3 study for the CPUC which was fundamental to the NEM cost shift debate; and by not providing an update on the NEM debate today, I believe that the Muro/Saha paper is misleading.

In the second part of their paper, Muro and Saha suggest some helpful regulatory reforms such as moving toward rate designs that “can meet the needs of a distributed resource future” and moving “toward performance-based rate-making (PBR).” Some electric companies have already implemented PBR or some type of formula rate and PBR is under discussion in several states.[10] Lawrence Berkeley National Labs is looking closely at this and related issues in its Future Electric Utility Regulation series of reports currently underway.[11]

Mura and Saha also suggest decoupling as a way forward–I disagree. In my view, decoupling is a not solution for private rooftop solar. Revenue decoupling is currently used to true-up revenues that would otherwise be lost due to declining electricity sales resulting from electric company investments in energy efficiency (EE). Decoupling explicitly shifts costs from participating EE customers to non-participating EE customers causing the same cost-shifting problem that is created by NEM. However, a fundamental difference is that the magnitude of the cost shifting onto non-NEM customers is on a much larger scale than the cost shifting due to EE. A recent study revealed that decoupling rate adjustments for EE are quite small–about two to three percent of the retail rate.^[12] In contrast, as described earlier in this paper, a NEM customer could shift a significant cost onto non-NEM customers (and the NEM cost shifting is essentially invisible to customers, which is one reason that NEM customers do not believe they are subsidized).[13]

Finally, Muro and Saha suggest that electric companies should invest in a more digital and distributed power grid. In fact, electric companies across the United States are doing just that. In 2015, electric companies invested $20 billion in the distribution system alone and this is expected to continue. Over the past five to six years, electric companies invested in the deployment of nearly 65 million digital smart meters to about 50 percent of U.S. households. In addition, electric companies are investing in thousands of devices to make the power grid smarter and more state-aware. Today, in states such as California, Hawaii, and Arizona, electric companies are investing to enable and integrate the distributed energy resources that are growing exponentially. And, in some states–where regulation allows–electric companies are offering rooftop solar or solar subscriptions to their customers.

No doubt, the electric power industry is undergoing a period of profound transformation–our power generation resource mix is getting cleaner and more distributed; the energy grid is becoming more digital; and customers have different expectations.[14]

Collaboration, good public policy, and appropriate regulatory policies are critical to a successful transformation of the power sector. In the context of this paper, this means reforming NEM so that private rooftop solar customers who use the energy grid pay for the grid. One straightforward approach is to require NEM customers to pay a higher monthly fixed charge thereby reducing the cost shift.[15] Ultimately the challenge is to make the transition of the electric power industry–including the significant growth in private rooftop solar and other distributed energy resources–affordable to all customers.

Lisa Wood is a nonresident senior fellow in the Energy Security and Climate Initiative at Brookings. She is also the executive director of the Institute for Electric Innovation and vice president of The Edison Foundation whose members include electric companies and technology companies.

The Centers for Medicare and Medicaid Services (CMS) recently released more detailed ACO-level data for participants in first two years of the Pioneer ACO Model. The program, which is designed for health systems with more experience assuming financial risk for patient populations, has generated savings and improvements in quality measures, but has also struggled to retain participants. The program began with 32 provider organizations; following a series of recent announcements there are now 19 total participants.

Last month, CMS announced that the Pioneer Program was able to yield total program savings of $96 million in its second year and resulted in ACOs sharing in savings of $68 million. CMS also reported that the Pioneers were able to improve mean quality scores by 19 percent and increased performance on 28 of 33 measures between performance year one and performance year two.

Financial Results

The latest financial results provide more participant-level data and allow for a new level of analysis of performance across all these ACOs. In year one of the program, financial performance for individual Pioneers ranged from a gross loss of $9.31 million to a gross savings of $23.34 million. Thirteen Pioneers reduced costs enough to qualify for shared savings, with an average of $5.85 million returned to the ACOs, ranging from $1.00 million to $14.00 million. One ACO owed shared losses of $2.55 million. The remaining eighteen ACOs were within the minimum savings or loss rate and did not earn shared savings or owe money to Medicare due to losses.

Following year one, nine Pioneer ACOs either left the Medicare ACO program entirely, or moved to the lower risk Medicare Shared Savings Program (MSSP). Eight of the nine Pioneers that left the program failed to reduce spending in their first year. Out of the remaining 23 participants in the second performance year, three of these ACOs opted to defer reconciliation until the end of Performance Year 3. The 20 Pioneers with final Performance Year 2 data had financial performance ranging from a gross savings of $24.59 million to gross losses of $6.26 million. Fourteen ACOs reduced spending in Performance Year 2, eleven of which reduced enough to qualify for shared savings. The average shared savings for these ACOs was $6.55 million, ranging from $1.22 million to $13.41 million. Three Pioneers shared losses, averaging $2.33 million back to the Medicare program.

The table below shows the breakdown of ACOs according to whether they reduced spending, increased spending, shared in savings, or owed money back to Medicare due to losses. More than half of the Pioneers were able to reduce spending in year one (18/32) and year two (14/23), with more than one-third of total ACOs earning shared savings in each year as well.

The data also suggest that those ACOs that were most successful in reducing spending in the first year were also more likely to reduce spending in their second year. As the chart below shows, three ACOs that earned shared savings in year one owed money back to Medicare due to losses in year two, while no ACO that had shared losses in year one was able to attain shared savings in year two.  

Quality Results

CMS also released ACO-level performance on all 33 measures for Pioneer participants in year one and year two. The 23 ACOs that remain in the Pioneer Program showed overall improvement in average quality scores from the first to second performance year. The ACOs also improved overall on 28 of 33 measures, as the chart below shows.

The quality domain with the greatest improvement in year two was Domain 4 (At Risk-Populations) which saw an overall improvement from 67.5% to 83%. The marked improvement in this domain suggests that ACOs are making progress at better coordinating and delivery care for high-risk patients, many of whom have multiple chronic conditions. Chronic care management for conditions such as diabetes, coronary artery disease, and hypertension is critical for the continued success of accountable care efforts. All other domains saw average quality improvement as well, summarized below.

Likewise, almost all of the individual Pioneer ACOs improved their performance on quality measures from year one to year two. Of the ACOs that remained in the program for year two, all but one ACO was able to improve its overall quality score in its second year.

Additionally, the percentage of Pioneer ACOs performing in the 80^th or 90^th percentile in quality scores also increased from year one to year two, as shown in the chart below.

Putting Together Financial and Quality Results

In year one of the Pioneer Program there appeared to be no direct correlation between average quality scores and gross savings or losses for individual ACOs. This may not be unexpected, especially since Pioneer ACOs in their first year are eligible for shared savings simply by reporting their quality. In subsequent years, however, the ACO’s quality score impacts the level of shared savings that the Pioneers are eligible to receive, so we might expect a bit more alignment between quality and financial performance. Average quality scores and level of savings or losses for each of the 32 first year Pioneer ACOs is below.

After year two, there still does not appear to be a direct relationship between higher quality scores and level of savings or losses in the Pioneer Program. Further examination of results begs additional questions about why certain ACOs clustered in different parts of the grid relative to others.

Of those ACOs in the red circle above— higher total savings and relatively average quality scores—two of the ACOs are from the Boston area and the remaining ones from other large metropolitan areas (New York City; Orange County, CA; Phoenix, AZ; and Detroit, MI). The average per capita Medicare spending for the counties corresponding to these ACOs is $11,544, compared to an average of $10,384 for counties corresponding to all 23 of the Pioneer participants.

Meanwhile those ACOs within the yellow circle had the highest quality scores, but also experience financial losses or slight savings. Many of these ACOs are from less densely populated areas, such as Maine, Wisconsin, and Illinois. There are a number of factors that could be contributing to their quality success, but little financial savings—healthier patient populations, a smaller or more engaged patient population, financial baselines impacted by lower per capita spending in these areas, or other factors driven by their region. Further analysis of these ACOs and the other public and private ACO programs, including both their characteristics and regional market characteristics, will provide needed further insights on the factors most likely to drive success.

Next Steps

These ACO-level data reflect the range of experiences across Pioneer participants. Some ACOs have sustained positive performance to date, while others have seen diminishing rates of return. Those organizations more committed to clinical transformation, patient outreach, and organizational change may be more likely to do better, but further analysis of differences in performance could enable the Pioneer Program and ACOs to achieve bigger impacts over time.

It is hard to know what the third performance year of the Pioneer program will show, but as noted earlier, the Pioneer Program has already lost over a third of its original 32 participants. Despite the decline in participation and mixed results so far, CMS remains optimistic and committed to the program, and the overall number of Medicare, Medicaid, and privately-insured individuals in ACO arrangements continues to rise. We can anticipate a proposed rule impacting the MSSP, likely later this Fall, which will impact elements of the Pioneer ACO program. Regulatory changes that may help increase the ability of the Medicare ACO programs to support better care while ensuring sustainability include: adjustments to attribution methods, benchmark calculations, collection and sharing of data with ACOs, updating performance measures, linking to other ongoing payment and delivery reforms, and creating more financial sustainability for program participants. The current Pioneer program can be a key step toward effective payment reform, but further steps are needed to assure long-term success.

Analysis of dozens of publicly created redistricting plans shows that map-making technology can improve political representation and detect a gerrymander.  In 2012, President Obama won the vote in Ohio by three percentage points, while Republicans held a 13-to-5 majority in Ohio’s delegation to the U.S. House. After redistricting in 2013, Republicans held 12 of Ohio’s House seats while Democrats held four. As is typical in these races, few were competitive; the average margin of victory was 32 points. Is this simply a result of demography, the need to create a majority-minority district, and the constraints traditional redistricting principles impose on election lines—or did the legislature intend to create a gerrymander?

Crowd-Sourced Redistricting Maps

In the Ohio elections, we have a new source of information that opens a window into the legislature’s choice: Large numbers of publicly created redistricting plans.

During the last round of redistricting, across the country thousands of people in over a dozen states created hundreds of legal redistricting plans. Advances in information technology and the engagement of grassroots reform groups made these changes possible. To promote these efforts we created the DistrictBuilder open redistricting platform and many of these groups used this tool to create their plans.

Over the last several years, we have used the trove of information produced by public redistricting to gain insight into the politics of representation. In previous work that analyzed public redistricting in Virginia^[1], and in Florida^[2], we discovered that members of the public are capable of creating legal redistricting plans that outperform those maps created by legislatures in a number of ways.

Public redistricting in Ohio shows something new—the likely motives of the legislature. This can be seen through using information visualization methods to show the ways in which redistricting goals can be balanced (or traded-off) in Ohio , revealing the particular trade-offs made by the legislature.

The figure below, from our new research paper^[3], shows 21 plots—each of which compares legislative and publicly-created plans using a pair of scores—altogether covering seven different traditional and representational criteria. A tiny ‘A’ shows the adopted plan. The top-right corner of each mini-plot shows the best theoretically possible score. When examined by itself, the legislative plan meets a few criteria: it minimizes population deviation, creates an expected majority-minority seat, and creates a substantial majority of districts that would theoretically be competitive in an open-seat race in which the statewide vote was evenly split.

Figure 1: Pairwise Congressional Score Comparisons (Scatterplots) - Standardized Scores

In previous rounds of redistricting, empirical analysis would stop here—unless experts were called in to draw alternative plans in litigation. However, the large number of public plans now available allows us to see other options, plans the legislature could readily have created had it desired to do so. Comparison of the adopted plans and public plans reveal the weakness of the legislature’s choice. Members of the public were able to find plans that soundly beat the legislative plan on almost every pair of criteria, including competitive districts.

So why was the adopted plan chosen? Information visualization can help here, as well, but we need to add another criterion—partisan advantage:

Pareto Frontier: Standard Criteria vs. Democratic Surplus

When we visualize the number of expected Democratic seats that was likely to result from each plan, and compare this to the other score, we can see that the adopted plan is the best at something— producing Republican seats.

Was Ohio gerrymandered? Applying our proposed gerrymandering detection method, the adopted plans stands in high contrast to the public sample of plans, even if the overall competition scoring formula is slightly biased towards the Democrats, as strongly biased towards the Republicans on any measure of partisan fairness. Moreover analyzing the tradeoffs among redistricting criteria illuminate empirically demonstrates what is often suspected, but is typically impossible to demonstrate—that had the legislature desired to improve any good-government criterion—it could have done so, simply by sacrificing some partisan advantage. In light of this new body of evidence, the political intent of the legislature is clearly displayed.

However, when politics and technology mix, beware of Kranzberg’s first law: “Technology is neither good nor bad; nor is it neutral.”^[4] Indeed there is an unexpected and hopeful lesson on reform revealed by the public participation that was enabled by new technology. The public plans show that, in Ohio, it is possible to improve the expected competitiveness, and to improve compliance with traditional districting principles such as county integrity, without threatening majority-minority districts simply by reducing partisan advantage—this is a tradeoff we should gladly accept.

Event Information

This program was aired live on CSPAN.org » 

With the demand for its services constantly evolving, the Department of Veterans Affairs (VA) faces complex challenges in providing accessible care to America’s veterans. Amidst a history of long patient wait times, cost overruns, and management concerns, the VA recently conducted a sweeping internal review of its operations.  The result was the new MyVA program.

How will MyVA improve the VA’s care of veterans? What will it do restore public confidence in its efforts? What changes is the VA undergoing to address both internal concerns and modern challenges in veteran care? 

On June 20, Governance Studies at Brookings hosted VA Secretary Robert McDonald. Secretary McDonald described the VA’s transformation strategy and explained how the reforms within MyVA will impact veterans, taxpayers and other stakeholders. He addressed lessons learned not just for the VA but for all government agencies that strive to achieve transformation and improve service delivery.

This event was broadcast live on C-SPAN.

Join the conversation on Twitter at #VASec and @BrookingsGov

Audio

• Can the Department of Veterans Affairs be modernized?

Transcript

• Transcript (.pdf)

Event Materials

• 20160620_veterans_affairs_mcdonald_transcript