Phoenix, AZ – Solar panels provide pollution free energy that delivers far reaching benefits to the environment and the electric grid, said a new report released today by Environment America Research & Policy Center. The report outlines how solar panels on homes, schools and businesses often provide more benefits than they receive through programs like net metering, counter to utility claims that solar owners don’t pay their fair share.
“Solar power’s rewards are far greater than its costs,” said Bret Fanshaw, Environment America’s solar program coordinator and report co-author. “We should be encouraging even more solar, not penalizing it.”
The Environment America Research & Policy Center report,Shining Rewards: The Value of Rooftop Solar Power for Consumers and Society (2016 edition) comes as policymakers around the country consider proposals from utilities to undermine successful solar energy programs, including net metering.
"Today, the vast majority of our electricity comes from sources like gas and coal, that are pushing us toward the brink of catastrophic climate change," said Gideon Weissman of Frontier Group, report coauthor. "Our analysis shows that the people and businesses who invest in rooftop solar aren't just guiding us away from the cliff, they're also providing benefits to society and to their fellow ratepayers."
Solar energy on rooftops can help communities to avoid greenhouse gas emissions, reduce air pollution harmful to public health and create local jobs, the report shows. Net metering programs credit solar panel owners when they generate more power than they use, providing electricity for other customers. Utilities then credit solar panel owners a fixed rate – often the retail price of electricity – for providing excess power to the grid, similar to rollover minutes on a cell phone plan.
The arrangements have helped solar energy skyrocket, but in recent years utilities have increasingly attacked them as unjustified “subsidies”, including in Nevada, where utility NV Energy urged regulators to end the state’s retail rate net metering program.
Today’s report tells a different story. An examination of studies from around the country shows that the dollar and cents value of solar is often higher than the credit utilities provide to customers.
"When value exceeds costs, everyone benefits through lower rates," said Karl R. Rábago, Pace Energy and Climate Center executive director and national expert in value of solar studies. "Utilities should start working with customers and regulators to make more solar and more savings happen."
Of the 16 studies reviewed, 12 found that the value of solar energy was higher than the average local residential retail electricity rate. The median value of solar power across all 16 studies was around 16 cents per unit, compared to the nation’s average retail electricity rate of about 13 cents per unit.
In other words: utilities were likely underpaying solar panel owners, not subsidizing them.
“Rooftop solar users are givers, not takers, when it comes to the value they provide to society and the electric system.” said Fanshaw, “In many cases it appears that solar programs are a bargain for utilities, not a burden.”
All 16 studies found that solar panel users offered the electric system net benefits.
Solar advocates hoped today’s report would shed new light on the way net metering and other pro-solar programs can benefit communities across the country, in the face of dozens of utility proposals to end or severely alter net metering programs.
“There’s so much to gain by going big on solar, but so much to lose if some utilities get their way,” said Fanshaw. “Let’s make sure we take full advantage of all the benefits by allowing solar to continue to grow in all our states.”
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Environment America Research and Policy Center is a statewide advocacy organization bringing people together for a cleaner, greener, hea
Community solar’s dilemma is described in the old saying that a giraffe is a horse designed by a committee.
Community solar was supposed to be the “promised land” where utilities, solar advocates, and environmentalists could forget bickering over net energy metering (NEM) and fight together for economically-viable clean energy. But instead of a boom, there are mostly unresolved debates over policies that seem to distort the promise.
Community solar, also referred to as “community shared solar” or “community solar gardens,” allow utility customers who cannot access rooftop solar to own a portion of a central-station array located near their power supplier’s distribution system.
The total U.S. installed community solar capacity will “reach 1.5 GW by 2020, growing an additional four-fold from 2020 to 2025,” Navigant Research reported in March 2016. Many say this underestimates the potential.
State policy is crucial to growth because it impacts “the economics of all customer solar options,” according to Navigant. “In the likely case that full retail net metering is replaced, more customers could see community solar as their best, competitive solar choice.”
But Jill Cliburn, principal investigator at the Community Solar Value Project, said state policies are not yet working.
“Community solar is an incipient technology and these programs are tests to see what works,” she said. Policies that keep utilities from working effectively with developers “could be a lost opportunity.”
Tom Stanton, lead author of the just-released “Ecology of Community Solar Gardening” report from the National Regulatory Research Institute (NRRI), agreed.
“There is concern about getting these policies right and some states are moving slowly,” he said. “Once a design proves it is driving growth without causing a cost shift, policymakers will likely implement it.”
There are now community solar laws, rules, or policies completed or in development in 15 states and DC, NRRI reports. Investor-owned utilities (IOUs), municipal utilities, and electric cooperatives in other states are pursuing individual plan approvals from regulators, it adds.
California should own half the market by the end of this decade because of a 2015 mandate requiring its IOUs to deploy a total of 600 MW of community solar by 2020, according to Navigant.
Yet results from California IOUs’ first solicitation will not be announced until early 2017, and community solar developers have low expectations.
“It is not that California policymakers’ intentions are bad,” said Tom Hunt, policy director at Clean Energy Collective (CEC), the leading U.S. community solar developer. “But it seems the commission did not fully think through the effects of adding requirements on top of one another.”
Many state policies have become complicated to the point that they could be described as “policymaking run amuck,” Hunt added.
“It effectively defines community solar and resolves debates about small and big subscriber participation without mandates,” he said, “but it’s easy to understand and comply with.”
Joseph Goodman, a manager at the clean energy think tank Rocky Mountain Institute, said the state’s policy aligns with many of the recommendations laid out in RMI’s recent marketplace paper on community solar.
The first theme is clarity in the program process, he said. Without clarity, proposed projects may fail to meet ill-defined standards and be dropped. “In some places, developers expect only one in ten proposed projects will be built,” Goodman said.
A second thing important in policy design is certainty in pricing and scheduling, he said.
Without certainty on the cost and time required by utilities forinterconnection reviews and for permitting, developers may lose financial backing by being unable to put investors' money to work on schedule, Goodman said.
His third policy key is making collaboration between utilities and developers on siting possible. In New York and Minnesota, promised booms fizzled because policies did not deliver utility system information to developers. That made siting “a unilateral pin-the-tail-on-the-donkey process, with developers largely blindfolded,” Goodman said.
When utilities and developers work together, the reduced risk compresses the project cycle and leads to better value for the utility, developers, and customers. Without collaboration, “interconnection prices are absurdly high,” Goodman said. “In NY, we have seen prices of $500,000 or $750,000 for a 2 MW site.”
A fourth policy key is effective consumer protections, Goodman said. “A lot of projects are being sold with charges that make my stomach churn.”
The charges are typically hidden in the complexity of an estimated utility rate escalation which starts at or near the current retail rate “but grows almost exponentially,” he said. “Some developers could be facing class action lawsuits.”
Clarity and certainty for output value, interconnection standards, permitting and siting are vital, CEC’s Hunt agreed, but several other elements come into play.
First, the output of the portion of the central station array owned by each subscriber should be applied directly to the utility bill. If it is not, the payment “will run afoul of securities law, limiting the market,” Hunt said. “Residential customers are virtually impossible to reach on a large scale without this.”
Value must fairly reflect the savings solar offers because those savings are why customers invest, he added.
Possibly the biggest challenge for policymakers is structuring an effective competitive market, Hunt said. “Community solar can work when led by third parties, when led by utilities, or when done by a variety of parties in competition."
Competitive markets can drive innovation and efficiency when developers and utilities have equal access, he added. With the right choice of private sector partners and practices, utility-led programs can also be “very effective.”
While the Massachusetts program is effective because it is relatively simple, simplicity can also be a liability, Hunt said. The controversy over co-location of projects that stopped growth in Minnesota showed “it is important to define some things so the system is not gamed.”
Case in point: Maryland
Maryland’s community solar program mandates 218 MW over three years and specifically defines product categories — so specifically that Hunt and Phillip VanderHeyden, a staffer at the PSC, agree it could complicate deployment.
“There are something like 36 different categories and they are good in and of themselves but it is confusing for developers,” Hunt said. “The commission’s working group is still trying understand how it will work.”
The policy makes the state’s three main intents clear, VanderHeyden said. It will create a community solar industry, obtain a practical understanding of community solar costs and benefits, and “provide distributed generation and net metering to customers who can’t participate in rooftop solar, including low and moderate income customers.”
The law targets obtaining 1.5% of Maryland’s peak demand from community solar over three years, he added. Each of the state’s four IOUs would be required to develop projects in Small, Open, and Low and Moderate Income (LMI) categories.
Each IOU must obtain 30% of its community solar kWh from projects of 500 kW or less in the Small category. They can be on rooftops, parking lots, roadways or parking structures or on brownfield locations. Or they can be located to deliver over 51% of their output to LMI customers.
For the Open category, each utility can obtain 40% of its portion from any array of up to 2 MW. This category is expected to be subscribed quickly, VanderHeyden said.
The last 30% of the community solar kWh obtained by each utility must serve LMI customers and 10% of the kWh must go to low income subscribers.
Multiple provisions in the law clarify precisely how kWh are to be divided in each category, how they will contracted for, how consumers will be protected, and how to guarantee that allocations meet the state’s intents, VanderHeyden said.
The regulations became effective in July. IOU tariff proposals are still being studied by the commission’s longstanding solar policy working group. When they are approved, each utility will begin accepting project applications.
“The tariffs will include interconnection and colocation regulations and how projects will be prioritized within the interconnection queue,” VanderHeyden said.
A subscriber organization authorized by the commission will administer the program. Developers will propose projects at the commission-approved tariffs for the categories, he added. “The policy allows utilities to credit the customer’s bill as a dollar amount on the bill or on a per kWh basis.”
The commission’s flexibility on tariff regulation will allow it to intercede if the program does not provide the same value to community solar subscribers that rooftop solar provides, VanderHeyden said. The commission is also charged with delivering a report to lawmakers when the three-year program ends or the 1.5% of peak demand capacity is deployed.
No new projects can be built until the report determines whether the program has had “tangible and observable benefits and until whatever recommendations it makes can be implemented,” he added.
Clarity is primarily lacking in the Maryland policy because there are so many categories, Hunt believes. Incentives might be more workable than mandates because they would allow the market to determine if and where policy goals make financial sense.
“By requiring these categories, the policy limits the flexibility to adjust to market conditions,” he said.
Case in point: California
California’s policy offers two other ways to complicate community solar programs, Hunt said.
First, the economics don’t work, largely due to an interpretation of the legislation that allowed a utility-backed reduction to the NEM credit and a special added charge.
“The way it is worked out delivers a pretty poor rate for the subscribers,” he said.
To protect against a perceived cost shift to non-participants, community solar subscribers will not get the full NEM retail rate credit. Instead, they will pay for generation, transmission, and distribution and get a bill credit for their solar generation.
The Power Charge Indifference Adjustment (PCIA) troubles solar advocates because the charge is likely to result in a premium on the price of electricity, according to Brandon Smithwood, California affairs manager at the Solar Energy Industries Association (SEIA).
“It is a departing load charge,” said Smithwood. “The commission’s original decision found that community solar customers do not depart but remain with their utility. But it was decided the PCIA could be used to protect non-participating customers.”
In addition to unworkable economics, the California policy has “a lot of programmatic restrictions that are hard to interpret and may not be very effective,” Hunt said. None of the restrictions are wrong on their own, “but they are stacked up to the point that it makes it hard to make the program work.”
California’s long and deep experience with solar shows there are positives and negatives with rooftop solar and utility-scale solar, said Mark Nelson, director of planning and analysis at Southern California Edison (SCE).
The reduced credit in the Green Tariff Shared Renewables (GTSR) program reflects policymakers understanding that community renewables are “squarely up the middle” between the rooftop and utility-scale segments, he said.
It is an effort by the stakeholder-led policy process to balance “the cost to program participants with the costs non-participants also bear,” Nelson added.
“We will need more experience with the current program to judge its success,” he said.
SEIA’s Smithwood, who has been part of the stakeholder group for 18 months, believes the structure of the policy allowing utility-led and private developer-led programs is not the issue.
“The challenge is how the credits and charges limit the customer value proposition,” he said.
One component of the GTSR program allows utilities to market premium-priced renewables-generated electricity from projects they develop.
Solar advocates’ concern is with the other component, the enhanced community renewables (ECR) program. Developers will contract directly with subscribers to deliver solar energy-generated electricity at a specified rate, and IOUs will apply the credits and charges to subscribers’ bills.
The real solution to a fair credit rate for community solar can only come with a full investigation of “whether, to what extent, and in what direction cost or benefit shifts actually occur between ECR customers and nonparticipants,” according to Smithwood. “Utilities should assign a zero-value placeholder until an appropriate indifference charge is calculated based on actual data.”
The PCIA does protect utilities against stranded costs, Smithwood acknowledged, but he said those charges are more commonly applied to utility customers who actually leave their utilities for alternative electricity suppliers such as community choice aggregators (CCAs).
Because of the reduced NEM credit and the PCIA, “it will be hard for private developers to meet the utilities’ community solar prices because their customer acquisition and marketing costs are likely higher,” Smithwood predicted.
Is locational value the answer?
Both the integration capacity analysis (ICA) in the California commission’s DRP proceeding and the locational net benefit analysis (LNBA) in the IDER proceeding are intended to identify where on the distribution system distributed resources will have the greatest value, SCE’s Nelson said.
Either or both analyses, which should be in place within the next year or two, could improve the value proposition of community solar and make it more economically viable, he said.
Maryland’s policy explicitly specifies “that utilities make reasonable attempts to assist developers in identifying locations that have system benefits,” VanderHeyden said. “We expect to have more insight into how to implement that after the initial projects are rolled out.”
community solar has many of the same economies of scale as larger central station arrays and should be able to “capture those economics,” RMI’s Goodman said.
The obstacle is a development and regulatory environment that is adding costs and constraints, he added. “We are hoping that attributing locational value with clarity and transparency will contribute significantly to resolving those constraints.”
The Community Solar Value Project (CSVP), funded in part by the Department of Energy’s SunShot program, is helping develop partnerships between utilities and private sector DER providers to demonstrate how community solar projects are “part of the DER puzzle,” CSVP’s Cliburn said.
The Sacramento Municipal Utility District (SMUD), Public Service Company of New Mexico (PNM) and other utilities are building “market-based laboratories” in which properly-sited community solar will be paired with energy efficiency, demand response, and storage.
Market research shows that if customers are told only that community solar will save them money, they will want the lowest cost offering, Cliburn said. “But a lot more value is possible.”
Policy should bring utilities and private sector providers together to do something more innovative than lowest cost projects, she said.
“When something is defined before it is completely invented, it is put in a box,” Cliburn said. “If a utility RFP gives no guidance on locational value, developers will make proposals without reference to locational value.”
It is challenging to identify where the greatest community solar locational value is but “no utility would procure poles or capacitors without specifying what they want and where they want it,” Cliburn said. “It is time for utilities to take up this challenge.”
NRRI’s Stanton said such an analysis would resolve one of utilities’ biggest concerns.
“A careful analysis that includes locational values along with energy and capacity values can identify where any cost shift to non-participants from deploying community solar can be avoided,” he said.
And, he added, not considering “specific locational values” could reduce a community solar project’s benefits to both participating and non-participating customers by as much as half.
Such an analysis should be based on carefully collected and analyzed real time system data, Stanton said. “If the price is not based on real time market data, it is just an estimate but it could result in an inaccurately set rate that is locked in for 25 years.”
Utilities and community solar developers should be gathering and reporting data now, Stanton said. A study based on transparently collected long term data analyzed in detail “would help reduce all the finger pointing and name calling about the value of the solar.”
Las Vegas casinos and other companies back the November ballot measure that would create a competitive retail power market where customers could choose their provider.PHOTO: AGF/ZUMA PRESS
November ballot measure backed by casinos would end monopoly of NV Energy, state’s largest utility
By CASSANDRA SWEET;
Nevada is the latest battleground in a national political fight over whether consumers and businesses should be able to choose where they buy electricity.
A November ballot measure backed by Las Vegas casinos and other firms would end the monopoly of the state’s largest utility, NV Energy, owned by Warren Buffett’s Berkshire Hathaway Inc., and create a competitive retail power market where customers could choose their provider.
The measure has bipartisan support from such figures as Sheldon Adelson, owner of Las Vegas Sands Corp. and a major donor to Republicans, and Senate Minority Leader Harry Reid, the retiring Nevada Democrat.
It would lead to lower electricity prices and greater opportunities to buy solar power for less than NV Energy charges, argues Matt Griffin, chair of Nevadans for Affordable, Clean Energy Choices, the group pushing the measure. Supporters are rolling out internet, billboard, radio and television ads.
The measure is opposed by the state’s AFL-CIO union, which represents 200,000 workers. It is urging voters to defeat it over concerns that the changes could boost consumers’ utility bills and cause utility job losses, said Danny Thompson, the union’s executive secretary and treasurer. Mr. Thompson pointed to California, where power prices rose sharply in 2000 after the state deregulated its power market and traders at Enron Corp. manipulated that market.
NV Energy, which supplies power to 90% of the state, says it is officially neutral on the measure, but it has warned lawmakers in an August document about unintended consequences, such as potential price increases and job losses that could follow if it passes.
The proposal, which would amend the state constitution, would direct the state legislature to draft new rules, and require another round of voter approval before becoming law. NV Energy would continue operating the grid and charging customers for delivering power over transmission and distribution lines.
If the campaign ultimately succeeds, Nevada would join New York, Texas and about a dozen other states where consumers and businesses can choose their electricity provider.
Nearly 19 million residential, commercial and industrial customers across the U.S. bought power in 2015 from suppliers that weren’t traditional utilities, up from less than 9 million in 2004, according to the Energy Department.
Power prices in states with restructured power markets rose from 1997 to 2007, according to a 2015 report from researchers at the University of California. But they fell in the following five years—along with falling natural gas prices—while prices in regulated states rose steadily over the 15-year period, the report shows.
About 72% of Nevada voters support the measure, according to a September poll by Suffolk University in Boston.
“We’d like to see energy choice because we want access to the best renewable energy resources and other cost effective sources,” saidRon Reese, a spokesman for Las Vegas Sands. Las Vegas Sands is backing the campaign along with MGM Resorts International,Wynn Resorts Ltd. and Switch Ltd., a data-storage firm based in Las Vegas.
All four companies asked the state Public Utilities Commission for permission to leave NV Energy service. The commission approved the casinos’ departure, in exchange for exit fees of $87 million for MGM, $16 million for Wynn and $24 million for Sands, but it denied Switch’s request. MGM paid the fee and is now buying power from Tenaska Power Services Co. Sands and Wynn didn’t pay the fee and still buy power from NV Energy. Switch is suing the commission in federal court.
Switch estimates it is currently paying NV Energy as much as 80% more for green power than it would pay a competitive supplier, said Adam Kramer, an executive vice president at the company. “In an open market, you get better prices because people are competing for your business,” he said.
NV Energy declined to comment on that estimate, citing the litigation between the companies.
The deregulation push is part of a larger wave of challenges hitting the U.S. utility industry, which include weak power demand and competition from new technologies such as rooftop solar panels, industry watchers say.
“In state after state, regulators are being pushed to revisit some core aspects of utility regulation in order to accommodate the future model of what electric utilities are going to look like,” said Kira Fabrizio, a professor at Boston University’s Questrom School of Business.
Wind energy companies in Indiana are attempting to mitigate the deaths of bats during migration season by slowing or stopping their turbines at night.
Wildcat Wind Farm, which operates 125 turbines in Madison and Tipton counties, and Fowler Ridge Wind Farm, which operates 355 turbines in Benton County, have worked with the U.S. Fish and Wildlife Service on the plans, the Herald Bulletin of Anderson reported.
In return, the companies could be eligible for an Incidental Take Permit, which allows a company to unintentionally kill or injure a small number of endangered animals while still allowing the companies to operate. The plan for the Incidental Take Permits is intended to help reduce the death of bats.
Wind farm owners could be held responsible and charged with harming an endangered species without the permit.
Wildcat Wind Farm's plan requires it to slow the turbines during the night and to purchase and provide for more than 250 acres of land for summer habitat.
"Wildcat Wind Farm seeks to maximize production of non-polluting energy by the project, while conserving bats and minimizing and mitigating, to the maximum extent practicable, the impacts of any incidental take," said Larry Springer, a public relations representative for Enbridge, the Canadian company that owns the wind farm.
Fowler Ridge Wind Farm's plan requires it to shut down turbines that are turned perpendicular to the wind during low-wind times between sunset and sunrise.
Although all migratory species of bats are vulnerable, the deaths in Indiana have been most harmful to the endangered Indiana bat and northern long-eared bat, which are also facing a decline due to the deadly white-nose fungal disease that has been killing roosting areas.
Bats play an important role in the ecosystem by eating night-flying insects, including many agricultural pests.
A study from academic journal Bioscience said 600,000 to 900,000 bats are killed by wind turbines each year in the United States.
Wildlife is a frequent victim of wind farms. The National Audubon Society says wind turbines kill an estimated 140,000 to 328,000 birds each year in North America, including birds of prey such as eagles, hawks and owls.
While policy questions have taken a back seat to controversy over the past weeks, the presidential election still offers a stark choice for those in the energy industry.
For one candidate, it is time to unshackle energy producers and end overregulation of fossil fuels. For the other, a focus on a cleaner energy future, including half a billion solar panels and more efficiency.
But though the power sector is in the midst of an undeniable evolution, energy policy debate has been scant on the campaign trail, overshadowed by the politics of personality. Even Ken Bone's question about the transition away from fossil fuels at the second debate was drowned out by a media obsession over his private life.
"Those with an energy-themed bingo card have not been doing well," said Kate Konschnik, the founding director of Harvard Law School’s Environmental Policy Initiative.
Konschnik was part of a team of experts who assembled a report on the energy issues that will be faced by the next administration, and the decisions they will need to make. From the appointment of federal regulators to the legal defense of rules and regulations, the next President's impact will be significant.
And yet, said Konschnik, the myriad decisions will also meet the existing momentum of market trends, meaning direct presidential control over the energy narrative will be limited.
Hillary Clinton and Donald Trump have incredibly divergent policy proposals. The real estate developer's ideas focus on loosening regulation of energy development, opening more offshore areas to production, and ending policies detrimental to the coal industry. He told fossil fuel industry conference that he would scrap President Obama's Clean Power Plan, which aims to curb greenhouse gas emissions 32% by 2030 from the power sector.
On the other hand, Clinton's energy proposals include a focus on renewable energy, efficiency, natural gas as a bridge fuel, and lowering oil consumption.
"Were they enacting policy in a vacuum, they would take very different paths," said Konschnik. But "market trends are really important, and they can't be wished away. Their decisions are confined in some ways by the realities they will face the first day in office."
That said, the next administration will make decisions on energy issues from electric vehicles to nuclear plants, including the technology and market sides. And there are a half dozen general areas where influence will be greatest.
The Federal Energy Regulatory Commission is charged with overseeing wholesale power markets, and the White House appoints the five-member commission. But right now, FERC has two seats vacant — and three Democrats currently serving.
"It's unusual, but not quite as unprecedented as the Supreme Court having just eight justices," said Ari Peskoe, the senior fellow in electricity law at the Harvard Law School Environmental Law Program Policy Initiative. The longest stretch of a three-member commission was about a year, in 2005 and 2006. By law, FERC cannot have more than three members from the same political party, so a Republican will likely be nominated next.
"The line between federal and state jurisdiction over the electricity sector is shifting," according to the report. "FERC once played a limited role in sector oversight, but regionalization of the electric grid and development of interstate markets for electricity, electric capacity, and transmission development have expanded its responsibilities."
There has been a series of Supreme Court decisions addressing state and federal power markets, demand response, and states' ability to encourage new generation. But the report said "tensions between state and federal policies are likely to continue." In particular, environmentalists have targeted FERC for protests in recent years, pushing the commission to take ecological considerations more into account when evaluating energy infrastructure proposals, particularly pipeline construction.
Peskoe said other issues FERC will face include how to incorporate state renewable policies into wholesale markets, and whether to address renewables issues and the Public Utilities Regulatory Policies Act comprehensively, or to continue with case-by-case determinations.
Climate policy
The next President will hold enormous sway over the nation's climate policy, but they will also face commitments the United States has already made.
The most immediate decisions are likely to be questions of appointments — who will lead the U.S. Environmental Protection Agency, Department of Energy and White House Office of Budget and Management. Those agencies will make the decisions over how to address the Clean Power Plan, and whether to challenge the D.C. Circuit Court decision when it is issued.
CPP compliance is a large chunk of the federal government's plan to abide by the Paris climate treaty, but Christina Reichert, policy counsel for the Climate and Energy Program at Duke University's Nicholas Institute for Environmental Policy Solutions, said "existing regulations may not be sufficient to meet the full commiment."
The administration will also need to determine how to incorporate the social cost of carbon into its federal rulemakings and policy decisions, following a court decision in 2008 by the 9th Circuit Court of Appeals. The Department of Energy's use of that metric for commercial refrigeration standards was upheld this year.
"Agencies that do not include a social cost of carbon in their policies risk litigation," Reichert said.
Nuclear policy
The nation's aging nuclear fleet, whether to support the plants economically and keep them running long past their initial licenses, will also be an issue the next president will face.
The two major policy points the next administration will focus on are licensing and financial support: how to approach operating extensions out to 60 and 80 years, and subsidies needed in some markets to keep them online, thanks to low gas prices. Nuclear waste storage and the development of smaller, modular facilities will also be up for debate.
The next president will have the opportunity to appoint at least three members to the U.S. Nuclear Regulatory Commission. The NRC is in the process of developing a framework to review 80-year license extensions, and "the next administration will inherit that unfinished guidance," said Sarah Adair, a senior policy associate at Duke's Nicholas Institute.
But even if safety concerns about keeping nuclear power plants operating are assuaged, market forces are endangering many. Several nuclear plants have retired in recent years, five will retire by 2019, and more are at risk, according to the report.
"We see a potential role for FERC here, which may be asked to weigh in on policies," said Adair.
While FERC has traditionally not favored specific fuels, the changing utility landscape could mean a broader review of RTO and ISO market issues where nuclear plants are involved, and the possibility that regulators could "break with tradition," said Adair.
Natural gas
Shale gas was 5% of the nation's production in 2004, and by last year it was more than half. "This is the forseeable future of natural gas in the United States," said Konschnik.
The rapid rise of production, enabled by hydraulic fracturing, has created several policy questions regarding production and whether to continue to rely on gas as a bridge away from coal. Whether the next administration presses for renewable tax credits could also impact natural gas demand. And in addition to appointing a new EPA head, the next president will also appoint someone to direct the Bureau of Land Management, which sets policies for energy production on federal lands.
The exclusion of fracking from some Safe Drinking Water Act (SDWA) requirements has rankled environmentalists for years, and last year the EPA issued a draft assessment of the rule. "Depending on the timing and substance of the final report, the next administration may face pressure to move quickly on certain types of regulation or to defer to states," the report said.
And "environmental groups are pressing the EPA to regulate other aspects of shale gas production." In March, the Natural Resources Defense Council petitioned the EPA to revisit aquifer exemptions under the SDWA.
While Trump has sworn to revitalize coal production, that ship may have sailed. But issues surrounding use of liquefied natural gas could raise prices and demand, and the president has influence there through FERC, which licenses export terminals.
Any significant changes to natural gas production or transport regulations could reverberate throughout the power sector. Natural gas sets the marginal price of electricity in most U.S. wholesale markets today and is expected to generate more electricity than any other fuel in 2016, edging out coal for the first time.
Economic development
The next president will also face employment issues related to the changing energy landscape, particularly surrounding coal.
According to the Bureau of Labor Statistics, 14,700 coal mining jobs were lost between 2009 and 2015, but the impacts of declining use and tighter regulations go beyond that. During the same period, 4,450 jobs were lost in petroleum and coal products manufacturing; more than 10,000 jobs were lost in electric power generation, transmission, and distribution; and more than 11,000 jobs were lost in rail transportation.
"Federal agencies will decide how to implement programs, where to focus their efforts, and what types of activities to support," according to the report. The next President will also make decisions on how to implement workforce development provisions of the broad energy bill Congress has been working on, should that legislation ultimately pass.
The last area where the government can exert influence is "not as a regulator, but as a market participant," said Peskoe, "and it's a big one." The federal government is responsible for more than 1% of the nation's electric bill and it operates the largest vehicle fleet, "so procurement decisions can really have an effect."
The next president will appoint the head of the General Services Administration and OMB, and will be tasked with determining how to implementing rules that establish greenhouse gas reduction goals for federal agencies. The choice there will be between Obama's Executive Order 13693, which established more aggressive goals, or targets set by Congress a decade ago.
"Achieving the goals established by Executive Order 13693 will require a sustained commitment by the executive branch," the report said. Much of that work is already underway, however. Federal data centers, for instance, are installing advanced energy meters and aiming to achieve specific power-use effectiveness targets.
And the Obama administration may finalize a procurement rule, but would rely on the next administration for its implementation. GSA and the National Aeronautics and Space Administration have proposed a rule that considers contractors’ GHG emissions.
"If finalized and implemented, the rule would establish a contractor reporting system. The next administration would use the information to identify opportunities to reduce supply chain emissions and implement procurements that incorporate consideration of those emissions," the report said.
