Friday, June 23, 2017

Everything You Need to Know About US Electric Vehicle Policies [GTM Squared]

from GTM Solar

3 Takeaways from the Renewable Energy Finance Forum: Taxes, Merchant Solar and Customer Choice

It’s tough to get large-scale solar deals done in 2017, but there was no palpable haze over the crowd of financiers at Renewable Energy Finance Forum this year.

Sure, volatility still defines many sectors of the solar market, the U.S. pulled out the Paris climate agreement and the federal government is skeptical of intermittent renewable energy resources. But the speakers and audience at REFF-Wall St. were focused on the opportunities in front of them, and those are plentiful.

Corporations in the drivers seat

“You can get a great price if you can get something done,” Ray Henger, SVP of M&A and structured finance for sPower, said of the falling rates in solar. He also noted that non-traditional drivers, including the C&I sector and even community choice aggregators are starting to drive new deals.

“At some point it needs to be the customer demanding solar -- like MGM,” said Yuri Horwitz, CEO of Sol Systems. “It’s munis, corporations and other large entitles that are making the decision to go solar or wind,” he said. “If your are involved in finance and want volume, you have to look at [contract for differences], synthetic PPA swaps and remote PPAs. You need to get comfortable with these.”

Michael Silvestrini, president of Greenskies Renewable Energy, told financiers that are interested in getting deeper into C&I, there is a need to find efficiencies when putting together the complex transactions that can involve multiple off-takers and locations. “To limit structural complexity, we’re asked to bring fully executed contract to financiers,” he noted. “So it’s a little clunky. We’d like to wash, rinse and repeat.”

Valuing the merchant tail of renewable energy

“Financial innovation is happening in equity,” said Henger. “The piece people argue about is what’s the value of the asset at the end of its hedge?”

That is an open argument, one that makes Dan Benoit, chief investment officer for North America at Brookfield Asset Management queasy. “We struggle with this question,” he said. “I don’t think we’ve found the magic bullet.”

Margins are already thin in the rest of the merchant generation business, and with falling prices, a good answer on how to make money on projects once they get to the merchant tail after their initial contract is hard to find. “It’s a tough business and it’s getting tougher,” Tom O’Flynn, EVP and CFO of AES Corporation, said of the merchant business.

Beyond merchant solar, repowering contracts are a topic that’s warming up in the wind industry, although not many are happening just yet. Earlier this year, GE announced it repowered 300 turbines in a deal with NextEra Energy. Once people work through technical and tax issues, “I think they’ll come fast,” Kevin Walsh, managing director of renewable energy for GE Energy Financial Service, said of future repowering deals. Brookfield Asset Management and AES said they have not executed repowering contracts in the U.S. yet, but are keeping an eye on opportunities.

The tax conundrum

The issue of PTC and ITC reform was mostly a non-starter. “There is little appetite with the House and Senate to revisit wind and solar phase down schedules,” Greg Wetstone, CEO of the American Council on Renewable Energy, said about potential for the ITC and PTC to be revisited, after speaking with members of Congress and White House staffers.

Even so, there are still questions that need to be answered. There is not yet clear guidance for solar in terms of which projects will be granted safe harbor under the ITC and PTC. For wind that uses the PTC, the IRS says as long as a developer has excavated a foundation at the site, that’s enough, said Katherine Breaks, managing tax director within tax credit and energy advisory services at KPMG. As for solar-plus-storage guidance from the IRS, “[it] would be helpful,” said Walsh, “but I’m not hopeful.”

Another potential tax issue is any change to the corporate tax rate. “In the upside down world we live in, corporate tax rate reductions are a bit of a mixed bag for renewable energy,” said Breaks. She noted that because wind and solar can get a five-year tax write off, “a major component of tax equity return is the write off of these losses.” Therefore, any reduction in the corporate tax rate would be a reduction in those returns. “Developers will have to grapple with, ‘where do we find the cash to fill that hole?’" she said.

If the renewable financiers in a New York midtown ballroom are any gauge, however, developers will not have to grapple with that question any time soon, if at all. When one moderator asked the room how many saw tax reform coming this year, not a single hand went up. When the question was pushed out to 2018, only a few raised hands could be counted amongst a few hundred conference attendees.

from GTM Solar

The Most Important Solar Charts of 2017: The H1 Edition [GTM Squared]

from GTM Solar

Thursday, June 22, 2017

How Calculating FERC’s One-Mile Rule Could Affect Renewable Energy Projects

As the vigorous pace of wind and solar energy development continues, the ability of renewable projects to obtain Qualifying Facility status under the Public Utility Regulatory Policies Act of 1978 can be critical to a renewable project’s financing options -- and thus its viability. It can also have important implications for the interconnected utility purchasing the project’s output and the rates of that utility’s customers.  

A pending application before the Federal Energy Regulatory Commission (FERC) sets the stage for the regulatory body to clarify aspects of its so-called “one-mile rule” that may influence the way certain renewable projects are developed.

With certain exceptions, the Public Utility Regulatory Policies Act (PURPA) generally imposes a mandatory obligation on an interconnected “electric utility” to purchase the energy and capacity delivered -- or "put" -- to it from a Qualifying Facility (QF) developed on its system (see 18 C.F.R. 292.303 a). A renewable small power production facility must be 80 megawatts or less to be a QF (see 16 U.S.C. 796 17 A). Developers who intend to rely on a project’s QF status and the mandatory purchase provisions of PURPA to sell the output of a project have an incentive to configure each project as a “facility” that does not to exceed the 80 megawatt threshold.

FERC’s one-mile rule (not mandated by the statute, but developed as a mechanism to implement it) provides that, for purposes of determining whether small power production facilities seeking QF status are considered to be located “at the same site,” FERC will aggregate the capacity of generating facilities that: (1) are located within one mile of each other, (2) use the same energy resource (e.g. solar or wind) and (3) are owned by the same persons or their affiliates (see 18 C.F.R. 292.204 a). FERC’s regulations require the distance between generating facilities for the one-mile rule to be measured “from the electrical generating equipment of each facility."

FERC’s regulations do allow waiver of the one-mile rule “for good cause.” In past orders, FERC has described the one-mile rule as “essentially arbitrary [in] nature” and “inappropriate as applied to certain situations … [w]here it appears that rigid application of the [one-mile] rule would classify a number of facilities as being on the same site, when a common sense conclusion would reach the opposite result” (Windfarms, Ltd., 13 FERC). However, FERC has also emphasized that it “is constrained to implement Congress’ decision … to limit to 80 megawatts the power production capacity of small power production facilities located at the same site,” and considers strict application of the one-mile rule to be part of that effort (Pinellas County, 50 FERC).

As a practical matter, FERC’s one-mile rule may be most relevant for larger-sized small power production QFs, or projects at the upper limits of the 80 megawatt threshold, outside of centralized markets. For example, in the bilateral markets of the West and South.

In other areas, QF status may not mean as much economically because FERC has provided the opportunity for utilities in markets operated by Regional Transmission Organizations (RTOs) or Independent System Operators (ISOs) to be relieved of their PURPA purchase obligation and some interconnected transmission and distribution utilities have obtained that relief. FERC has established the rebuttable presumption that QFs above 20 megawatts located in RTO/ISO markets have nondiscriminatory access to wholesale markets without the need for PURPA’s must purchase obligation, but that QFs 20 megawatts and below are presumed to lack such access and benefit from the must purchase obligation. In either case, in order to be relieved of the obligation, the utility must make a filing with FERC.  

For developers, the ability to meet the QF standards and be entitled to the PURPA “put” to the interconnected utility can be an important backstop to obtain financing for a renewable project. From another perspective, some utilities simply believe that they have too much QF output within their footprint and are concerned about passing costs related to QF purchases along to their retail customers, so QF determinations may be a concern. 

Beaver Creek Wind Applications

On February 9, 2017, two entities Beaver Creek Wind II and Beaver Creek Wind III, separately filed applications with FERC seeking an order to certify their respective wind projects in Stillwater County, Montana as QFs (see FERC dockets QF17-673-000 and QF17-674-000). On the same day, two other entities -- Beaver Creek Wind I and Beaver Creek Wind IV) filed self-certifications as QFs. Each of the four projects (collectively, “Beaver Creek Projects”) would provide capacity of approximately 80 megawatts, and each project shares a boundary with at least one of the other projects. Caithness Beaver Creek will operate each of the Beaver Creek Projects.  

“Weighted Geographic Center” Approach

Central to the Beaver Creek QF applications is the proposal that FERC calculate the distance between generating facilities for its one-mile rule using a “weighted geographic center” approach, which identifies a single geographic location at the project “center,” averaging the locations of the various wind turbines. The Beaver Creek applicants explain that projects composed of dispersed generating equipment, such as wind projects with an array of various turbines, create a challenge for applying FERC’s one-mile rule, and the Beaver Creek applicants argue that the proposed weighted geographic center approach is a reasonable proxy to calculate the distance between the facilities for purposes of applying FERC’s one-mile rule. 

Using a proposed formula to calculate the weighted geographic center of each project, the Beaver Creek applicants argue that the geographically averaged “center” of each of the four Beaver Creek Projects (each consisting of multiple separate wind turbines) is located more than a mile from the center of any other Beaver Creek Project, and thereby arguably separately qualifying as a QF under the proposed approach. The Beaver Creek QF applicants make this argument even though they expressly inform FERC that several individual wind turbines near the different Beaver Creek Project boundaries are within one mile of each other. 

To the extent that FERC concludes that the one-mile rule would bar these projects from being certified as separate QFs, the Beaver Creek QF applications alternatively request that FERC simply waive the one-mile rule under its regulations and consider the Beaver Creek Projects as separate sites for purposes of certifying the Beaver Creek QF applications, emphasizing that the distance between the facilities of the Beaver Creek Projects is determined by the nature of the wind resource and the equipment required to optimize energy production.

Challenge to the QF Applications

NorthWestern Energy is identified as the interconnected utility that would be obligated to purchase the output of any of the Beaver Creek Projects should they obtain QF status.  NorthWestern intervened in the proceeding and protested the Beaver Creek QF applications. Northwestern made certain arguments related to the upstream ownership of the Beaver Creek Projects and protested Beaver Creek’s proposed weighted geographic center approach to the one-mile rule. 

NorthWestern argued that the various sites of the electrical generating equipment (i.e. the individual wind turbines) cannot be averaged to create a single, artificial project “location” because doing so would ignore the reality that the turbines are dispersed geographically across vast areas. NorthWestern points out that the proposed weighted center approach in the Beaver Creek QF applications would make it likely that the boundaries of an expansive wind farm with arrays of neighboring wind turbines could be configured into separate projects that would be considered more than one-mile from each other. 

For example, NorthWestern’s protest highlights the fact that the proposed weighted center approach would allow a project consisting of various turbines to be configured to include a distant (even non-contiguous) minor portion of the generating equipment in order to shift the weighted center location of one project away from another, so that each project can be a QF that is not located at “the same site” under the one-mile rule. 

FERC Deficiency Letters, Response and Action on the Beaver Creek QF Applications

Due to a follow-up request from FERC, the deadline for FERC to act on the Beaver Creek QF applications has been reset to September and it is conceivable that the deadline for FERC action could be further extended. 

FERC may choose this case as an opportunity to comment on the one-mile rule. Because the requirement is a regulation, FERC would not be able to eliminate the requirement without further process. Significantly, however, the statutory language does not require the one mile rule. The weighted geographic center concept, if adopted, could minimize the rule’s effect on wind, hydroelectric and solar projects.

In the context of such multiple turbine facilities, the proposed weighted center concept could allow line-drawing in order to achieve a particular outcome (i.e. the PURPA QF status for multi-turbine projects). FERC could rely on this case as an opportunity to update and explain its current policy views on this issue. PURPA, an almost 40 year old statute, has been increasingly debated in legislative circles because its original purposes (energy independence, increased fossil fuel efficiency and non-utility investment) have been either largely achieved or are no longer priorities. PURPA came up in the Senate confirmation hearings for FERC commissioners, and both nominees Neil Chatterjee and Robert Powelson stated that revision of the statute was a task for Congress.

Whether that debate will translate into revision of the statute remains to be seen, but in any event that would not likely occur before FERC’s action with respect to these Beaver Creek QF applications.

It's worth noting that FERC currently lacks the required number of commissioners for the quorum necessary to decide contested proceedings such as this one, although confirmation of two new FERC commissioners that would restore a quorum appears imminent. Regardless of when the new FERC commissioners are seated, the existing backlog of competing cases and policy issues will likely require the newly-constituted FERC to prioritize and the timing of a decision on the Beaver Creek QF applications may shift as a result. Notwithstanding the timing uncertainties, the Beaver Creek QF applications provide FERC with an opportunity to clarify a rule that, going forward, may affect the development of various renewable projects with dispersed generation equipment seeking QF status.  


Seth Lucia is counsel and David Poe is a partner in Bracewell LLP’s energy practice in Washington, D.C. Mr. Lucia advises clients on a wide range of energy regulation and policy matters before the Federal Energy Regulatory Commission (FERC). Mr. Poe represents and provides advice to clients who own infrastructure assets subject to governmental regulation in their ownership and/or operation.

from GTM Solar

Your Guide to the Bitter Debate Over 100% Renewable Energy

A bitter dispute. A clash. A battle royale.

Those are just a few descriptions of a new study countering Mark Jacobson's 2015 report showing that we can source 100 percent of America's energy from wind, solar and water.

Jacobson's study is controversial. Celebrities like Mark Ruffalo and Bernie Sanders have lauded his work. Jacobson himself has called it the "only moral choice."

Other experts have long questioned his assumptions. This week, Twitter erupted with debate over Jacobson's modeling -- resulting in personal attacks, a litany of tweet storms and wide press coverage.

In this episode, we're going to dig into the dispute over 100 percent renewables that has spilled out of academia and into the mosh pit of Twitter and politics.

This podcast is sponsored by KACO New Energy, a leading solar inverter company with superior engineering and unmatched customer service.

Here are some top tweet storms about the debate over Jacobson's work from experts around Twitter:

In the second half of the show, we'll focus on reliability and renewables. Does Europe’s better outage record tell us anything about variable wind and solar and the health of the grid?

Finally, America just got 10 percent of its electricity from non-hydro renewables. What does that tell us about where we are headed?

from GTM Solar

PJM’s Market Changes: The Good, the Bad and the Ugly for Green Energy and Demand Response

PJM, the grid operator responsible for delivering electricity to about 65 million customers from the mid-Atlantic coast to the Great Lakes, is working on ways to price carbon into its energy markets, and incorporate subsidized wind and solar power into its mix. It’s also projecting a future grid that’s stable despite a rise in wind, solar and demand-side energy flexibility -- contrary to concerns expressed by Energy Secretary Rick Perry.

But for green energy advocates, none of that makes up for the negative effects of PJM’s Capacity Performance rules -- and as of this week, those rules are sticking around for awhile. 

On Tuesday, a three-judge panel of the D.C. Court of Appeals rejected challenges to the Federal Energy Regulatory Commission’s approval of new electricity market rules for PJM’s 13-state region. Known as capacity performance, these rules introduced year-round requirements, broken into winter and summer seasonal markets, to replace the summer-peaking-only market that’s been in place for decades. 

PJM’s new year-round requirement was partly a response to the 2014 polar vortex, when record-cold temperatures simultaneously spiked demand for heating energy and froze up about 22 percent of the generators available, leading to emergency conditions. They’re also an attempt to deliver more efficient allocation of resources, potentially adding up to billions of dollars, according to PJM’s analysis. 

But environmental and clean energy groups have argued from the start that PJM’s new market structure will make it harder for demand response, wind and solar resources to recognize their value against always-on resources like natural-gas-fired power plants. 

That’s mainly because capacity performance doesn’t actually split the market into winter and summer blocks, in a way that would allow programs and technologies that do best in hot weather, such as air conditioning cycling or rooftop solar PV, to bid separately from winter resources, when cold temperatures and heating needs drive peak loads. 

Instead, it requires participants to virtually aggregate summer resources with corresponding amounts of winter-focused resources, through a complicated process that we’ve covered in some detail at GTM Squared. The problem is, there aren’t enough remote-control water heaters, thermal energy storage systems, or other forms of winter-focused capacity to match up with the well-established summer-peaking capacity resources. 

The results from PJM’s Base Residual Auction last month appear to have borne out the green energy and demand response industries’ concerns. Capacity for the 2020-2021 period cleared a price of $76.53 per megawatt-day, well below the prices of $80 to $100 from last year’s auction. This fact could be taken as a sign that PJM’s new rules are working, by delivering cheaper capacity for its utilities and consumers. 

But the auction also revealed a big drop in demand response, down 24 percent compared to last year, and in solar, down more than 60 percent from the year before, Jennifer Chen, attorney for the Natural Resources Defense Council (NRDC), noted in a Tuesday blog post. “As predicted, many summer resources seeking complementary winter resources did not find any to pair with,” she wrote. 

PJM did loosen its rules on aggregation for the auction, which helped somewhat. Still, the number of seasonal resources that could combine into annual capacity added up to less than 400 megawatts, or two-tenths of a percent of total procurement, Chen wrote. 

PJM’s final implementation of its capacity performance rules has upset more than environmentalists. The groups challenging FERC’s decision in court include NRDC, the Sierra Club, the Union of Concerned Scientists, and the Advanced Energy Management Alliance representing the demand response industry. But it also includes separate complaints from the American Public Power Association and National Rural Electric Cooperative Association, both representing utilities, which argue that the year-round requirements will increase capacity costs, with unclear future benefits. 

Even so, the three judges ruled unanimously to uphold FERC’s decision to allow PJM to move ahead with the particulars of its implementation of capacity performance, including the year-round requirement. Chen wrote that NRDC was “reviewing the decision and our options for undoing these costly market rules,” including new complaints filed with FERC, seeking a re-examination of the seasonal capacity issue -- an issue that’s unlikely to rise to attention anytime soon, given FERC’s current lack of a quorum

Measured against these kinds of figures, PJM’s recent work on integrating state carbon policies into its markets may not offer much of an upside to clean energy advocates. Last week, PJM published three white papers laying out its approach to the process, part of a broader effort being driven by FERC to examine the way state renewable and carbon policies affect the operation of interstate energy markets, as we've covered at GTM Squared

The first white paper looks at how PJM could establish a regional or sub-regional carbon price to reflect state renewable and climate change mitigation policies in wholesale market prices. The second looks at a new approach to how subsidized resources like wind and solar power are treated as capacity, by expanding the minimum offer price rule, or MOPR, to these resources. 

Finally, the third white paper “does not respond per se to state subsidy programs,” but instead “examines whether the aforementioned profound changes to the industry require re-examination of PJM rules that define when and under what circumstances a generator is eligible to set marginal prices.” There’s a lot more to unpack on the concept in the white paper, but its underlying goal is to deal with “an unintended bias in the energy markets favoring lower-capital-cost resources." That means things that are cheaper than big power plants, but that may fail to “signal the true, full cost incurred to meet the marginal increment of load.” 

Greentech Media will be covering the intersection of demand response, building energy management, distributed energy and the pull and push of market and policy forces at its Grid Edge World Forum 2017 conference this July 27-29 in San Jose, Calif.

The three-day conference will feature a who’s-who of utility, grid and distributed energy executives, entrepreneurs and insiders, GTM Research’s latest market and policy updates, and a natural point of contact for people working on ways to bring a greener grid to life from the customer on up. Click here to learn more.

from GTM Solar

Mind the Storage Gap: How Much Flexibility Do We Need for a High Renewables Grid?

Imagine for a moment that we have built enough wind and solar power plants to supply 100 percent of the electricity a region like California or Germany consumes in a year. Sure, the wind and sun aren’t always available, so this system would need flexible resources to fill in the gaps. But with continuing rapid cost declines of wind, solar and batteries, it’s possible that very ambitious renewable energy targets can be met at costs competitive with fossil fuels.

Every region has a different climate and demand profile, but with the right mix of wind and solar, up to 80 percent of the variable renewable power produced could be used in the same hour, without accounting for transmission interconnections. Still, a reliable grid needs fast-responding flexible resources to satisfy the remaining 20 percent of demand. But what will that flexibility cost?

The answer is surprising -- by 2030 an 80 percent renewable energy system including needed flexibility could cost roughly the same as one relying solely on natural gas. As Climate Policy Initiative (CPI) demonstrated in our recent report Flexibility: the path to low-carbon, low cost electricity grids, if renewable generation and battery storage prices continue to fall in line with forecasts, meeting demand in each hour of a year with 80 percent of electricity coming from wind and solar could cost as little as $70 per megawatt-hour -- even when accounting for required short-term reserves, flexibility and backup generation. Finding cheap, reliable and carbon-free ways to shift energy for long periods emerges as the key decarbonization challenge.

Of course, this analysis makes some simplifying assumptions; it represents the new-build cost of generation and flexibility to meet demand in every hour using historical weather profiles from Germany, without factoring in transmission connectivity or existing baseload power plant constraints. But it also leaves out the significant potential for cheaper flexibility from regional interconnections, existing hydroelectricity and the demand side.

CPI’s analysis helps us understand what kinds of flexibility we will need and what it will cost. The promise of a low-cost grid based on wind and solar is so compelling, it’s worth digging into what we’d need to do to realize this vision.

What is flexibility, anyway?

A power system has a wide variety of flexibility needs with time scales ranging from seconds to seasons, and a range of different technology options can be used to meet those needs, depending on the time scale.

Fast-responding resources are needed to keep the grid in balance and compensate for uncertain renewables and demand forecasts on very short time frames from seconds to minutes. These needs should grow only modestly as shares of renewables climb to high levels, and they could be accommodated cheaply using existing hydro generation (where it exists), fast-responding demand response, cheap batteries or even smart solar and wind power plants.

Solar and wind output can also change rapidly on a predictable, hourly basis, requiring flexible resources that can quickly pick up the slack. One feature of California’s now-infamous “duck curve” is the need for fast-ramping resources to meet the evening decline in solar production. California has devised innovative market mechanisms to ensure flexible gas and hydro generators are available to meet these ramping needs.

On a daily basis, the profile of renewables production doesn’t neatly match demand, requiring resources that can store or shift energy, or otherwise fill in the gaps across the day. Today, daily imbalances are met primarily by dispatching fossil fuel fired power plants. But a number of solutions are gaining momentum, such as automatically shifting when consumers use energy and building large batteries.

At even longer time frames, multi-day and seasonal mismatches can exist between when renewable energy is produced and consumed. But the promising solutions for daily storage may not solve seasonal storage needs. In fact, using lithium ion batteries for seasonal storage, cycling once per year, would cost tens of thousands of dollars for each megawatt-hour shifted.

The challenge of power grid decarbonization hinges on this ability to store or shift energy. But how much energy would the power grid really need to shift, and over how long? 

Solar drives daily storage needs, wind drives storage needs of up to a week

A power system that relies primarily on solar would have abundant power in the middle of each day, and scarcity during the night. Trying to exclusively power the grid with solar, with no ability to store or shift energy, would mean more than half of demand would go unmet. But with enough daily storage to shift solar energy to any time in each day, solar could meet nearly 90 percent of California’s electricity demand (but only 70 percent in Germany, because of different seasonal patterns).

Wind, on the other hand, is a better match with demand hour-by-hour. But daily storage has little value for wind, improving this match only by a few percentage points. For wind, the biggest gains come from shifting energy by up to a week. In both California and Germany, the ability to shift energy by up to a week could allow nearly 90 percent of energy demand to be met with wind.

Beyond a week, seasonal storage needs depend on regional demand and renewable resource profiles, and, critically, what mix of renewable resources the region has installed. For instance, a mix of 70 percent wind and 30 percent solar in Germany could meet 90 percent of demand on a daily basis, reducing the need for longer-term storage.

Many technologies are well-suited to shifting energy within a day. Today, hydro and thermal power plants are used to meet changing demand. Advanced batteries promise multiple hours of storage and shifting capability. Thermal energy can be stored in buildings, shifting when electricity is used for heating or cooling. And as electric vehicles become more widespread, ubiquitous charging infrastructure, electricity pricing and automated charging could shift when drivers charge their vehicles.

But far fewer technology options allow for long-term energy shifting. Consumers can’t go for a week without heat, cooling, or charging vehicles and long-term storage technologies like hydrogen need cost and efficiency improvements. The default option for long-term storage is a familiar one -- fuel-burning power plants that provide flexibility to today’s power systems. Finding cheap, reliable and carbon-free ways to shift energy seasonally may be the final piece to the deep decarbonization puzzle.

Storage gap for 100 percent wind or 100 percent solar in California and Germany

Storage gap for a wind and solar mix that minimizes long-term storage needs in California and Germany

So how should we approach the seasonal storage gap?

Policymakers and planners have several strategies they can use to bridge the storage gap:

  1. Target a mix of renewable resources that minimizes long-term storage needs. Procuring the right mix of resources can be the easiest way to reduce the seasonal storage gap.
  2. Connect neighboring regions to trade surpluses and shortfalls of energy. Northern Europe and the Western U.S. are taking steps to better integrate regional grids, although getting neighboring states and countries to cooperate can be challenging.
  3. Make use of existing hydropower. Regions with abundant hydroelectricity may already have enough existing flexibility to completely satisfy seasonal storage needs. But electricity and ecological needs don’t always align, and drought years could spell trouble for grid reliability.
  4. Make industrial demand seasonal. Paying the fixed capital and labor costs of an electric arc furnace for several months of the year while a steel foundry lays idle may be cheaper than building the storage or generation needed to meet that demand carbon-free year-round. But this solution would require a careful balancing act between industrial competitiveness, trade, and ensuring job stability for workers.
  5. Develop storage technologies that shift energy across weeks and months. Converting renewable electricity into hydrogen could enable longer-term and larger-scale storage if cost and efficiency improve, and hydrogen could be used directly for transportation, heating and industry.
  6. Develop flexible, dispatchable carbon-free power plants to cover shortfall periods. A recent survey of decarbonized grid models suggested that nuclear and carbon capture and storage may be needed to completely decarbonize the grid. But market models and technologies will need to evolve for these resources to operate flexibly and profitably.

Transitioning to a low-carbon grid

A low carbon grid is the lynchpin of any serious plan to avoid the dangerous impacts of climate change. And with solar, wind, and energy storage costs dropping year over year, the vision of a low-cost, flexible grid driven by renewable energy seems tantalizingly within reach. But to fully decarbonize the grid, the long-term storage gap is one of the biggest challenges that lies ahead.

We have many of the technologies and tools we need for this shift, but our electricity policies and markets need to evolve for a new generation of technologies with different cost and risk profiles. If we start laying the groundwork today, we’ll be ready to keep pace with the rapid transition ahead.


Brendan Pierpont is a consultant with the energy finance team at Climate Policy Initiative.

from GTM Solar