The State(s) of Distributed Solar + Should Utilities Be Buying New Gas Plants?

DATE: 12 MAR 2019 
2018 Year-End Update

Renewable energy continued to expand across the country in 2018. This expansion in renewable energy complements a growing number of states, utilities, and cities that have set ambitious goals to transition to 100 percent renewable and carbon-free power generation.

New solar photovoltaic capacity, including from small-scale distributed solar systems (such as arrays on the rooftop of a home or business), shared community solar gardens, as well as larger utility-scale systems, has played a significant role in the overall transition to clean energy.

A growing number of states are making investments in solar a priority.

The following map illustrates the size of each state’s solar market at the end of 2018 with pie charts that show the corresponding share of smaller distributed solar systems (1 megawatt and smaller). Exploring this map, we can see which states have the largest shares of distributed solar, investments that help build wealth locally and allow individuals and communities to take greater ownership over their energy future.

In this year’s map, we have added a snapshot of data from Minnesota’s leading community solar garden program to flag this program’s success and illustrate an alternative model to larger-scale solar projects that does not defer entirely to incumbent utility ownership.

Since community solar systems are typically larger than 1 megawatt of rated capacity, we plan to begin tracking and disaggregating similar data in the growing number of states that have passed similar policies enabling or requiring robust shared renewable programs (as of 2018, 18 states and the District of Columbia have done so to varying degrees). This will allow us to include community solar capacity in future analyses of the country’s solar market.

For more information on state community solar and renewable energy programs, explore our interactive Community Power Map. Learn more about what makes these programs successful by reading our in-depth report on the topic entitled Beyond Sharing: How Communities Can Take Ownership of Renewable Power.

Total Solar and Percent Distributed by State — 2018

As this map illustrates, a greater number of states than ever are making solar a priority. As of 2018, 11 states now claim more than 1000 megawatts of total solar capacity (shown in red), and 37 have more than 100 megawatts (states shown in yellow, orange, and red).

Of the 11 states that now contribute more than 1000 megawatts of solar power, three leaders continue to boast shares of distributed generation greater than 50 percent: New Jersey (2195 megawatts of total solar, with 67 percent from small-scale sources), Massachusetts (2156 megawatts, also with 67 percent from small-scale), and New York (1499 megawatts of total solar), where 83 percent of total solar comes from small, distributed sources.

Established solar markets are not the only ones to have seen success.

Burgeoning distributed solar markets in Midwestern states like Ohio and Illinois have also benefited from policies that support greater access and more local control of energy infrastructure. Residents of Athens, Ohio, for example, have been working to support great investment in clean energy by exercising community choice, which state policy has helped enable. Illinois has seen rapid growth in its solar market since passage of its sweeping Future Energy Jobs Act in 2016. The state has supportive net metering and interconnection rules that encourage distributed energy and is developing a shared renewable energy program to increase access to solar among renters and households or businesses that may have shady rooftops. Such policies helped the state receive an “A” grade in ILSR’s 2019 Community Power Scorecard.

In general, we find that those states with policy landscapes that are more supportive of local energy decision-making typically see a greater percentage of distributed solar, which further benefit communities by building wealth locally and allowing communities to take more ownership in their clean energy future.

Unfortunately, not all states have policies in place that make it easy to invest in distributed and shared solar systems. We see this playing out in the number of states that rely more heavily on larger and utility-scale solar systems, relative to small-scale distributed solar.

Read more about why state energy policies matter when it comes to enabling local renewable energy, in our recent companion analysis to ILSR’s 2019 Community Power Scorecard. Stay-tuned for a future in-depth comparison between states’ distributed solar capacity and their scorecard performance, as well.

In a majority of states in 2018, large utility-scale solar projects claimed more total solar capacity overall and a greater share of that total. These larger scale solar projects require more capital upfront, more time to construct, and are typically left to investor-owned utilities to operate and manage.

Is bigger best? ILSR’s 2016 report skewers the myths and shows how small-scale solar provides a competitive alternative to utility-provided electricity, and much larger local benefits.

Many of these same utilities are actively involved in tilting the playing field to their favor by fighting a future of greater customer choice and control. Recently, legislators in New Mexico have considered a bill giving handouts to one of the state’s incumbent utilities and that risks shutting out local ownership from future renewable energy investments.

Is the future energy monopoly or energy democracy? States have an important role to play in determining which path communities ultimately choose.

This States of Distributed Solar analysis is updated annually. For a historical snapshot, explore our archived analyses of distributed solar by state in 2017 and 2016. Stay-tuned for a future in-depth comparison between states’ distributed solar capacity and their scorecard performance, as well. This article originally posted at

Should Utilities Be Buying New Gas Plants?

DATE: 25 FEB 2019 | Facebooktwitterredditmail

In a report entitled Reverse Power Flow released last year, ILSR warned that the widespread availability of affordable energy storage would have major implications for the electricity market, upending traditional planning. In particular, it suggested that new investments in fossil fuel power plants were likely bad bet for electricity customers.

So when a monopoly electric company in Minnesota recently went shopping to buy a new gas plant, we offered our candid assessment to the state’s regulators:

Resource Plans Belong in Resource Plans

The comments start with a reference to a December meeting of Public Utilities Commission in which the utility now wanting to buy a gas plant won a delay in filing their next resource plan. This process is supposed to incorporate all of the utility’s resource acquisitions over the next 15 years. Commission staff, already concerned by this utility’s use of the legislature to end-around the process in 2017, had this to say in their briefing papers to the decision makers:

“One of staff’s hopes for the next IRP is that Xcel will not bypass the Commission’s resource acquisition process.” –– Briefing papers, Xcel IRP extension

The utility, Xcel Energy, already has contracts to buy the electricity from this power plant through 2026, and a reduced amount through 2039. However, owning the power plant changes the calculus.  As explained in greater detail below, the acquisition of a power plant carries significant financial and environmental risks that are only fairly evaluated when measured against alternatives. Presumably, the existing power purchase contracts have been vetted in such a manner. The ownership of the power plant has not.

The coincidence in timing of this proposed acquisition and the recently approved delay in resource planning should be noted.

Short-Term Benefits for Shareholders, Long-Term Risks for Customers

Xcel shareholders will see immediate benefits from the gas plant acquisition, as the Company can begin collecting a rate of return on expended capital immediately.

In contrast, customers will be liable for many costs (some already committed and others newly acquired). Customers already bear the risk that fuel cost estimates are unrealistically low against a history of gas price volatility, as illustrated in the following chart (in eight other states, shareholders would be required to risk-share with customers).

With Company ownership in the years beyond 2026, customers also assume new and significant risks. In its initial petition, Xcel Energy states that, “Company ownership will mitigate the risk associated with the termination of the MEC I [power purchase agreement] in 2026.” Even setting aside the fuel price risk that customers, not shareholders currently bear, data from the Company’s Colorado subsidiary contradicts the Company’s assertion of customer risk.

In January 2018, responses to a request for proposal issued by Xcel Energy’s Colorado subsidiary show that projects with a go-live date in 2023––three years prior to the power purchase agreement’s expiration––would undercut the combined cycle plant’s costs by a significant margin. The following chart provides a simple comparison based on the tendered bids and Lazard’s estimate of the levelized cost of energy from a combined cycle gas plant.

In other words, the utility purchase of the facility and the commitment to operating the plant far beyond the expiration date of its existing power purchase obligations extends customer exposure to fuel price risk into a period in which options that are even cheaper than current gas plant costs are almost certain to be available. If the utility thinks that an extended commitment to natural gas is a wise investment, then it should––like utilities in eight other states––share in the risk that natural gas prices will sharply rise. The tenuous financial performance of most major domestic natural gas producers, at a minimum, should give Commissioners pause in allowing long-term commitments to natural gas.

Finally, Company ownership also confers operations and maintenance risks currently held by the plant owner onto customers.

An Economic Investment in Tension with Company Commitments

With ownership of the Mankato Energy Center, the Company commits to earning a return on its investment for shareholders beyond its power purchase obligations that could be in tension with its commitment to the City of Minneapolis climate action goals through the Clean Energy Partnershipand the utility’s own public carbon reduction goals, which include a commitment to carbon-free electricity by 2050 – within the life of the second of the two Mankato Energy Center units. In other words, Xcel Energy would likely have to close at least one of the two units before the end of its useful life in order to make its own carbon commitments. Even if there is a potential to operate these units until the end of their economic life that doesn’t violate these commitments, it creates undue tension between the utility’s shareholders and its customers.

A Worrying Double Precedent

The recent approval of the Nemadji Trail Energy Center (another gas power plant for neighboring utility Minnesota Power) raises questions about whether the Commission has created two potential precedents:

1) that regulated utilities can make resource decisions outside of the resource planning process, and

2) that such decisions will not respect the evidentiary requirements of need and cost-effectiveness.

Approval of the Mankato Energy Center acquisition will send a clear message to Minnesota’s utilities: the regulatory compact to do resource planning within the approved integrated resource plan is more a goal than a requirement. And, shareholders need not wait for strong proof of need to bring big ticket proposals before the Commission.

ILSR’s Recommendation: No New Gas

The Commission should reject the Company’s proposed acquisition of Mankato Energy Center because it would violate the resource planning process, saddle customers with many additional risks (that shareholders do not share), likely increase customer costs, likely violate the utility’s existing carbon commitments, and create poor precedents for utility resource planning. Should the Commission decide otherwise, it should––at a minimum––require utility shareholders to share fuel price risk and provide other financial safeguards for customers.

Thank you for the opportunity to comment; we appreciate that there has not been any legislative preemption of this regulatory process.

This article originally posted at For timely updates, follow John Farrell or Marie Donahue on Twitter, our energy work on Facebook, or sign up to get the Energy Democracy weekly update.