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Voltscast: Jesse Jenkins on energy modeling Mar 05, 2021

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Hello, People of Volts!

Today I’ve got a special treat for you: a podcast with Jesse Jenkins, energy modeler and assistant professor at Princeton.

Those of you on #EnergyTwitter already know Jesse. He’s been doing this as long as I have, working his way up from take-haver to think tanker to graduate researcher at MIT to Princeton prof. Along the way he’s developed a reputation not only as one of the sharpest, most empirically informed energy analysts in the country, but as a scrupulously nice guy, always willing to share what he knows and engage in good faith with questions and arguments. As a journalist, I’ve found him indispensable.

So it was a real treat to sit with Jesse for an in-depth conversation on energy system modeling. What exactly is it? How does it work? What does it tell us about the kinds of energy technologies we will need to decarbonize, and their relative scale? How do politicians use — and misuse — models?

We get into all of it (as you will hear, I kept Jesse talking so long that I started worrying I might be violating the Geneva Conventions). I hope you enjoy it as much as I did.

Here are a few links either mentioned in, or relevant to, the discussion:

* A three-part series on the “rebound effect,” whereby energy efficiency reduces the price of a service, which then increases demand for the service, which then wipes out some of the energy and environmental gains of the efficiency. I wrote it in 2012 for Grist.

* Jesse’s old blog Watthead, with posts going all the way back to 2005.

* A 2015 post of mine about how the International Energy Agency (IEA) consistently overestimates the cost of renewable energy.

* The Princeton University Net-Zero America project, an effort to model a variety of pathways to deep decarbonization in the US.

* A presentation on the Net-Zero project with Jesse and Princeton’s Eric Larson.

Question for the type of folks who read to the bottom: would you be interested in a written transcription of this episode? It would be some work, but if enough people want it I’d be up for doing it, perhaps as a bonus for community members. Let me know in comments or at david@volts.wtf.

Thanks for reading. If you value work like this, please consider becoming a paid subscriber.

This is a public episode. If you'd like to discuss this with other subscribers or get access to bonus episodes, visit www.volts.wtf/subscribe

Lessons from the Texas mess Feb 24, 2021

Show notes

Hello there, Voltron! It’s been an interesting week, hasn’t it? A guy writes a tediously long and wonky series on energy transmission and, next thing you know, transmission grids are dominating the news. By now, the story of what happened in Texas last week is familiar: an extraordinary cold snap simultaneously a) raised demand on the grid to well higher than the grid operator’s worst-case winter projections, and b) knocked out more than 30 gigawatts worth of energy generators. Supply and demand must be kept in perfect balance on a self-contained grid like Texas’, so when demand spiked and supply plunged, something had to give — thus the not-so-rolling blackouts.Most of that lost generation was natural gas and coal. Freezing afflicted not only the water used in power plants but the mining, distribution, and storage of fossil fuels. And, yes, some wind turbines froze, though wind actually performed better than the modest expectations set by ERCOT, Texas’ grid operator.I’m not going to go through the story in detail. I just want to talk a bit about what it means and what we can learn from it. To learn more about what happened, those affected, and the role Texas’s grid and regulations played in events, I recommend reading the following:* The Houston Chronicle had a great story on the events as they unfolded and is, in general, all over it. * In The New Republic, Kate Aronoff has a great overview, with crucial historical context for why the Texas grid is isolated and why it has an energy-only power market.* In the Atlantic, Rob Meyer has great coverage of the Texas planning failures. * The team at ProPublica has a piece on how Texas regulators “have repeatedly ignored, dismissed or watered down efforts to address weaknesses in the state’s sprawling electric grid.”* In the Los Angeles Times, Sammy Roth has another great wrap-up, with a focus on grid vulnerability.* In the New York Times, a team of journalists pulls together a great backgrounder on Texas’s unique power market structure and grid independence. * In the New York Times, Princeton energy analyst Jesse Jenkins has a piece on the crucial failure of Texas utilities to future-proof their assets. * In the Wall Street Journal, Katherine Blunt and Russell Gold have a story on the implications of the disaster for the energy-only market.* In Utility Dive, Alex Gilbert and Morgan Bazilian write on what happened and what it means for Texas grid regulation.* The New York Times’ Brad Plumer explains what climate impacts will mean for the nation’s power grids.* At Gizmodo, Molly Taft reports on how much the oil and gas industry is paying Republicans to lie about what happened.* And here’s the Wall Street Journal editorial board lying about what happened.Any handful of those stories (save the last) will fill you in on what happened and why. Now let’s talk about what we can learn from it.It was going to be bad in Texas regardlessOne thing worth emphasizing up front is that Texas just faced an extremely unusual event. It got much colder, much faster, and dumped more snow and ice, for longer, and took out more energy infrastructure than even the grimmest forecasts predicted. Yes, the state has had cold snaps before — including in 2011 and 2014, producing a set of recommendations and guidelines that state regulators made voluntary and state utilities largely ignored — but this was extreme even in context. We’re going to touch on better planning, helpful technologies, and reformed regulatory structures, but the grim truth is that there is probably no alternative set of planners or regulations that would have adequately prepared for what took place last week. They certainly could have done better, but this event was fated to be rough.If we’re going to start seriously preparing the electricity system for long-tail, low-probability events — the kind climate change is making more likely — it will be a new thing, not something that’s been mastered by any current entity or regulatory body.Small picture: Texas electricity and natural gas systems need to be weatherized The Texas mess is being characterized as a grid crisis, but it was actually a generation crisis. Two-thirds of the state’s power comes from natural gas, and a) natural gas wells and pipelines froze (cutting normal production by about 20 percent), b) commercial and residential heating got priority access to natural gas, per state policy, and c) natural gas power plants froze. [Clarification: national natural gas production fell by 20 percent; Texas production fell by 50 percent.]Some coal plants and wind turbines also froze up, and one of the state’s nuclear plants went offline for unrelated reasons, but the bulk of the 30+ gigawatts of energy generation that went offline was natural gas power plants (many were also down for scheduled winter maintenance).Natural gas production and distribution falls under the purview of the Railroad Commission of Texas, so it is the RRC that will need to update regulations to make sure this doesn’t happen again on the production side. Given the RRC, that seems … unlikely.As for power plants, after the 2011 rolling blackouts, Texas should have required all generators to weatherize. It’s perfectly possible for natural gas plants and wind turbines to operate in the cold — there are wind farms in the Arctic. But the weatherization recommendations released in the wake of the blackouts were made voluntary and very few generators followed them.Some have argued that this failure to prepare can be laid at the feet of Texas’ energy-only market — the only such market in the US.In other restructured areas (like PJM in the Mid-Atlantic), alongside energy markets there are capacity markets, through which generators can get paid to maintain generation capacity in reserve, in the name of reliability. Texas has no capacity market. The incentive to maintain reserve capacity is supposed to come from the fact that the price of energy is allowed to swing with supply and demand. In times of high demand and/or constrained supply, prices rise, sometimes to many multiples of their normal level. Generating energy during those times can be incredibly lucrative. That’s supposed to induce generators to set aside (and weatherize) some capacity, to take advantage of those rare moments. It’s not a “free” market — no electricity market is — but it is more lightly regulated than its regional neighbors.For the past 10 years, the Texas grid has generally maintained lower reserves than, say, PJM, but it has performed quite well, despite persistent predictions to the contrary. During that time, Texas ratepayers saved quite a bit of money with their lean system. It’s not clear that if Texas had a capacity market, it would have avoided what happened last week. If a generator is set aside as reserve but it freezes, it doesn’t help. Capacity markets could impose regulations or mandates requiring generators to weatherize, but then again, so could regulators in an energy-only market. It is perfectly within the power of the Texas Public Utility Commission (PUC) to require weatherization. It just didn’t.Any regulatory system is going to need conscientious regulators and good planning. The larger lesson of the cold snap is that Texas, like the rest of the country, needs to plan its grid around resilience and redundancy rather than optimization, market or otherwise.Big picture: the Texas grid needs resilience in three directionsThe basic climate forecast for Texas is that it’s going to get warmer on average, but there’s a decent chance these freak cold snaps will get more frequent and nastier. (Like all climate science trying to pin down temporally and geographically narrow effects, this is provisional and there is disagreement within the science community.)That is a brutally wide range of conditions for which to plan and prepare. And the same basic problem will face grids in every region of the country. Climate change means a less predictable, less stable set of futures. Texas needs to work toward resilience at three levels.Improving the existing energy systemEven assuming it eventually wants to, or is forced to, it will take Texas a while to decarbonize its grid, working its way free of natural gas. In the meantime, it needs to take steps to ensure the security of supply, including weatherproofing major wells and pipelines and bulking up reserves.Clearly all power plants need to be weatherproofed, something that falls entirely within the jurisdiction of the Texas PUC. The Texas grid needs to be better and more finely segmented, so power outages can be more targeted, rather than akin to a lottery (homeowners who happened to be on a circuit with a hospital retained power). And ERCOT, like all transmission grid operators, could investigate the many ways of increasing the capacity and performance of existing transmission lines (see: transmission month). Improving local resilienceOne thing this crisis highlighted is the desperate need for demand-side resources on the Texas grid (measures the PUC and utilities have traditionally resisted). The state is way behind on “demand response,” whereby large groups of customers can be coordinated to reduce demand at times of grid stress. (FERC recently gave demand response access to capacity markets in areas under its jurisdiction, a decision the Supreme Court backed.)Perhaps the most basic step would be to better weatherize and insulate Texas’ homes and buildings, so they don’t require as much energy to heat and cool and they don’t lose heat as fast if the power goes out. Solar panels wouldn’t do much good in a snowstorm, but other distributed energy resources like batteries and electric vehicles can provide emergency power. At the community level, larger battery or other storage installations (perhaps fuel cells or flow batteries) located within distribution systems could help run community resilience centers, where at least people could congregate to stay warm.And microgrids that could island off from the larger grid and run on stored emergency power in the event of a blackout would have helped many Texans through the worst of the cold. I recommended the same set of local resilience and distributed energy solutions for California — which has had its own grid woes, despite not having an energy-only market — in a much more detailed piece, if you want to dig in.Improving interconnectionTexas, notoriously, runs its own grid, an island between the Western and Eastern Interconnections.There’s a long history behind why this is so (read Aronoff’s piece, and also this), but the gist is that, by not transporting electricity across state lines, the Texas electricity system escapes federal jurisdiction, in the form of the Federal Energy Regulatory Commission (FERC). Texas has long been, and remains, ornery about federal authority. Because its grid is an island, Texas could not import power from, say, nearby Southeast states, where conditions were somewhat better. It could only cut power to customers.(Notably, El Paso — which for quirky historical reasons isn’t on the ERCOT grid, but rather on the larger Western Interconnection — survived the storm just fine, because it could import power from neighboring states.)It’s difficult to envision Texas allowing this arrangement to change. A transmission developer would have to propose an interstate line and ERCOT would have to approve it, at which point FERC could reasonably assert authority. But Texas has fought off such attempts in the past and shows little appetite, even in the face of this crisis, for submitting to the feds. It might bring the dread Green New Deal to the state!A few years back, a project called Tres Amigas proposed to connect the three US interconnections with HVDC lines. Even though it argued that it wouldn’t trigger federal jurisdiction over Texas, the project ended up dying.Nonetheless, it’s at least worth noting that it would be to Texas’ benefit to build HVDC lines to the other interconnections. Among other things, it could import power when 30 GW of generation goes offline. Building a few HVDC connections would probably be cheaper in the long run than trying to up-armor the state’s entire natural gas infrastructure and all its wind turbines against once-a-decade cold conditions. That’s the beauty of a national transmission grid: no region has to prepare for every conceivable weather pattern. When extreme or unusual conditions strike, any region can draw power from elsewhere in the country. All things being equal, interconnection boosts resilience and reduces prices. Perhaps ERCOT and FERC could work out some sort of deal, whereby the feds promise not to impose a capacity market or other dramatic market changes on the state as long as it meets basic North American Electric Reliability Organization (NERC) reliability standards and takes steps to interconnect with the rest of the country. Everybody wins. Resilience costs moneyAll the recommendations for Texas above apply equally to every state and regional grid. They all need to quit planning based on past conditions and instead plan for a future of wider variation, less predictability, and more frequent extremes. That calls for resilience: improving the performance of existing infrastructure, improving local resilience through efficiency, weatherization, and distributed energy resources, and improving interconnection with neighbors through HVDC lines. All of that costs money. Texas has been demonstrating for a decade that it’s possible to operate with slimmer reserves, closer to a just-in-time delivery model, and save quite a bit of money for ratepayers. It works pretty well most of the time, except for once a decade or so, when it catastrophically fails.In the wake of such failures, with the human costs evident, it’s easy to blame regulators and demand more resilience. But imagine if, five years ago, Texas legislators and regulators had approached the Texas public and proposed to substantially raise its electricity rates in order to weatherproof its electricity system against once-a-decade (or in this case, maybe once-a-century) conditions. It would not have been popular.It’s just difficult to spend money wisely, with an eye on long-term resilience. The short-term incentives align against it — not just the market incentives, but the political incentives. It’s difficult for Texas, it’s difficult for California, it’s difficult everywhere.And it’s especially difficult in the US thanks to the fundamental misalignment between our current social and environmental goals — lower carbon, better performance and efficiency, increased resilience and security — and the regulatory incentive structure within which US power utilities operate. They make money by investing in capital projects. They don’t want to do more with less; they make money by doing more with more.The US utility regime is designed for expansion, for building out electricity infrastructure to a country without it. Now that the electricity system is built out, now that it needs to be ruggedized and fine-tuned, now that local distribution systems need more autonomy and intelligence, that regime is no longer serving us. We end up, again and again, working against utilities, trying to kludge together artificial incentive structures to persuade them to do stuff they simply aren’t designed to do.Getting to resilience and national interconnection by fighting through 50 public utility commissions is going to take forever. What’s needed are some federal performance standards and a large-scale program of public investment into electricity infrastructure. Congress needs to step up and act like climate change is a national emergency.Texas may lose some of its treasured autonomy in the process, but it will gain a more effective and resilient electricity system. This is a public episode. If you'd like to discuss this with other subscribers or get access to bonus episodes, visit www.volts.wtf/subscribe

Full show notes at the publisher

Transmission month: everything in one place Feb 19, 2021

Show notes

Greetings, People of Volts! We have come at last to the end of Transmission Month, née Week. It’s been quite a journey.

Below are links to and summaries of all the transmission posts. Above is a mega-podcast — all the posts, read by me, strung together, for when you have a couple of hours free.

* The subscriber-only discussion post that started everything. Thanks for all the ideas!

* Why we need more big power linesAn explanation for why the US needs more big, long-distance power lines to decarbonize, relieve grid congestion, and reduce the cost of power.

* How to start building more big power linesBuilding new power lines in the US is absurdly difficult, a kaleidoscope of dysfunction from planning to financing to permitting to siting. Local resistance ends up killing anything ambitious. The federal government needs to step in.

* Burying power lines next to rail & roads to make a national transmission gridOne way to avoid siting hassles and local battles is to bury new transmission lines alongside existing rail and road infrastructure. One big line doing this, connecting Iowa wind to the Chicago area, is underway now.

* How to make the existing grid work betterA set of “grid-enhancing technologies” stand ready to increase the capacity and improve the performance of the existing transmission grid, from “dynamic line ratings” to “topology optimization.” Utilities just need incentives to install them.

* Two more ideas to quickly boost the transmission gridA couple of final proposals to improve existing transmission. One is using energy storage to supplement transmission; the other is replacing existing AC lines with HVDC lines.

* Volts podcast: the challenges of building transmission in the US, and how to overcome them, with Liza ReedA discussion with clean-energy researcher about the obstacles facing long-distances transmission lines and some policies that might help clear them away.

If you value this kind of deep-dive explanatory journalism, please consider becoming a paid Volts subscriber. I don’t have any advertisers or sponsors; the only way I can do this is with your support.

Thanks for reading and listening.

This is a public episode. If you'd like to discuss this with other subscribers or get access to bonus episodes, visit www.volts.wtf/subscribe

Transmission month: two more ideas to quickly boost the transmission grid Feb 17, 2021

Show notes

Greetings, faithful Volts readers! Welcome back to the Transmission Week that never ends.

The news these last few days has been filled with talk about electricity grids. Texas is suffering from an unprecedented cold snap that has left more than four million people without power for days. It’s a terrible situation. There’s a lot to say about it, what can and can’t be learned, and perhaps I’ll get to it next week.

But you didn’t sign up for a breaking-news email, you signed up for Volts! So today brings what I believe what I believe will be my last big transmission post, though I may do a wrap-up after this. Thank you for traveling with me on this longer-than-expected journey.

Today, we’re going to look at a couple of final ideas to make the transmission grid work better, short of building new lines — a remainder bin of grid-enhancing technologies, if you will.

Idea #1: Using energy storage as a transmission asset

At least since the Energy Policy Act of 2005, the US government has acknowledged that energy storage technologies can be used to ease grid congestion and increase the reliability and flexibility of energy transmission. In recent years, there has been increasing interest in “storage as a transmission asset” (SATA), which refers to energy storage installations that are treated as transmission assets — meaning utilities can “rate base” them and receive a guaranteed rate of return plus any tariffs or incentives for transmission assets.

Basically, it means allowing some storage to be treated — legally, financially, and operationally — like a piece of the transmission system.

SATA projects — sometimes known as “virtual power lines” — offer a range of benefits to regional energy grids.

When a line is congested, it can offload some power to storage. At times of lower congestion, stored power can be injected to maintain high line utilization. Storage can thus relieve congestion and make the grid more reliable. It is much cheaper and quicker to deploy than new transmission, its footprint is much smaller, and it faces a much less onerous regulatory process. It is extremely modular and scalable, which means it can start small and be scaled up precisely to need, and even relocated as grid needs change.

Congestion on a power line often causes “inefficient dispatch,” meaning grid operators must ask generators on one side of the line to curtail their output and generators on the other side of the line to ramp theirs up, even if that isn’t the most cost-effective option. Storage on either side of the line can help reduce inefficient dispatch.

Another key service storage can provide is to free up unused line capacity. A grid capacity standard called “N-1” holds that the grid must maintain safe operation if a “contingency event” takes out one of the lines. This means all lines must maintain some reserve capacity to absorb energy in the event of an N-1 situation.

But storage can serve that purpose — rapidly injecting energy into, or absorbing energy from, the grid in the case of a contingency event — even better than power lines. Adding SATA projects can free up some of that reserve line capacity to carry more power.

As with most things transmission, Europe is way ahead of the US on this. Most notably, Germany is developing 1,300 MW worth of SATA in a project known as Netzbooster (grid booster) to free up line capacity otherwise reserved for an N-1 contingency. (Germany has notorious congestion between the wind-heavy north and load centers in the south.)

The US has nothing at the GW scale like that, but a few RTOs are moving forward. In August 2020, FERC approved MISO’s proposal for the rules and processes by which it would integrate storage into its planning and project selection.

One twist: FERC has indicated that it is “permissible as a matter of policy” in the US for a storage project to be “dual use,” to serve as a transmission asset and receive fixed returns and simultaneously to participate in wholesale energy markets and receive market returns.

This move has drawn some criticism, since it seems to blur the canonical separation between energy market participants and the “wires companies” that are supposed to offer them non-discriminatory access to the grid. If a wires company owns a storage asset that is drawing market returns, it has every reason to give that asset privileged grid access.

FERC has said dual use is subject to the following four principles:

* must be cost-competitive with transmission,

* must avoid double recovery for providing the same service,

* cannot suppress market bids, and

* cannot jeopardize ISO/RTO independence.

It’s not entirely clear how dual use storage could, in practice, avoid bumping up against those principles. So far as I know, none of the big RTOs/ISOs has yet hashed out exactly how to make the dual-use thing work. (Here’s an issue paper in which California ISO wrestles with the problem.)

There are reasons to remain skeptical of SATA projects. Batteries are still relatively expensive compared to other types of assets. “Many areas of congestion are better served by a new power plant, fuel cell, or demand response asset than a big single-purpose battery,” says Cody Hill, who analyzes and deploys storage projects for LS Power.

The California ISO has been skeptical too. It reported in 2018: “Over the past several years, the ISO has studied 27 battery storage proposals and one pumped hydro storage proposal as potential transmission assets. To date only two proposals have resulted in storage projects moving forward, both in the most recent 2017-2018 Transmission Plan.”

But utilities are allowed to rate-base SATA projects — receive a guaranteed rate of return on them — and they love rate-basing stuff, whether it’s cost-effective or not. They make money by spending money. (See: Texas utility Oncor’s $5.2 billion SATA proposal, which was never approved. I wonder if grid regulators regret that in light of current news!)

“A company that gets a SATA project approved gets a guaranteed profit on every dollar spent,” says Hill, “so utilities have an obvious incentive to get lots of these projects approved and put into the rate base, and not much of an incentive to keep the costs down.”

Hill warns that utilities are working in regulatory proceedings “to guarantee that they will have a monopoly on new SATA projects going forward” — sheltering them from competition under FERC Order 1000, the same way they’ve been sheltering transmission lines from competition (see this post for more on that). “Now that storage is getting cheap enough to pencil in more locations,” Hill says, “this would be a terrible outcome for storage developers and utility customers alike.”

Hopefully FERC will take steps to implement performance-based incentives for utilities and force true competitive bidding in both transmission and SATA, allowing merchant projects to compete on a level playing field. Here’s what the International Renewable Energy Agency (IRENA) says is needed (quoting its report):

* Clear rules on the ownership and operation of the Virtual Power Line (VPL).

* Compensation structures that reflect the costs of the VPL.

* Regulations enabling a multi-service business case, so that the social welfare benefits provided by the ESS is maximised.

* Regulations that enable network operators to consider battery storage systems in network planning, together with conventional investments in network infrastructure.

The Energy Storage Association has laid out a set of positions and policy recommendations that get into more policy weeds, explaining how FERC could meet those conditions.

In the meantime, a 2020 study found that, in a system with high renewable energy penetration, “storage value originates primarily from deferring investments in generation capacity (VRE, natural gas) and transmission.” SATA can do that — make the existing transmission system work better, thus cutting down the need for new lines.

Anyway: storage as transmission! It’s all part of the process of making transmission grids more networked, dispatchable, and intelligent.

Idea #2: Converting AC lines to HVDC lines

Finally, here at the very end, let’s quickly look at a proposal that I probably should have put very first, since it may be the quickest and easiest way to boost transmission grid performance.

Here’s the idea: existing AC (alternating current) lines have already fought all the siting battles. The land has already been claimed. In some cases, it is possible to convert AC lines to HVDC (high-voltage direct currect) lines.

It turns out the actual wire used is the same — it just needs to be reconfigured. “If you are using an existing corridor, you can use the existing lines and just change the bundles,” says Dr. Liza Reed, research manager for low carbon technology policy at the Niskanen Center. “So if you have three phases of four lines each, you've got 12 lines, and you can turn that into six lines on either side of the DC bipole.”

In some cases that will mean slightly extending the height of the tower.

But the costliest part is replacing AC substations with converters to shift the AC power to DC and vice versa (and in some cases, boosting the capacity of nearby substations to handle the additional power). Ideally, the new converters will be Voltage Source Converters (VSCs) using solid-state electronics. (This this post for more on VSCs, which Reed thinks are close to being the default choice for HVDC developers.)

Even with that cost, converting lines “is surprisingly cost-effective, even over relatively short distances, and, in some cases, may be the only way to achieve dramatic increases in the capacity of existing corridors.” That’s the conclusion of a 2019 study on which Reed — who did her PhD dissertation on converting lines at Carnegie Mellon — was the lead author.

In another study, Reed and colleagues looked at five options for expanding transmission capacity: reconductoring (replacing conductors) to increase current, increasing voltage, installing a FACTS (see previous post), converting to HVDC, and building a new line.

“In the normal course of operations, utilities have to replace lines as they age anyway,” Reed told me. “Replacing lines with high-temperature low-sag options can increase capacity quickly and at low cost compared to other solutions. The capacity increase is limited, but often still has substantial benefits to power flow.”

Converting lines has been a subject of discussion among power engineers and scholars for decades (see this 1997 paper), but as with previous technologies we’ve discussed, things are finally now beginning to come together: costs are falling even as grid congestion and the need for relief rise.

Reed says it’s difficult to pin down the total national potential of replacing lines, since projects are so dependent on specific line conditions, which in many cases have not been analyzed.

The most promising lines for conversion are double-circuit 345kV lines. The map below shows the roughly 25 percent of US transmission circuit-miles that are over 300kV. About two-thirds of those, something like 16 percent of total US transmission, is suitable, at least in theory, for conversion.

That’s not going to solve US grid woes, but it does represent a crucial opportunity to quickly expand the existing grid and relieve congestion while other solutions are being developed.

And that’s it, folks! Transmission! I can’t guarantee I won’t return to the subject in the future, but I think I pretty much covered the waterfront. I hope it was helpful.

Later this week, I’ll send a transmission wrap-up post, linking to all the previous posts in one place and summarizing what we’ve learned.

As a reward for sticking with me this far, here’s Mabel with a bloop of snow on her nose:

This is a public episode. If you'd like to discuss this with other subscribers or get access to bonus episodes, visit www.volts.wtf/subscribe

Transmission month: how to make the existing grid work better Feb 12, 2021

Show notes

(If you’d rather listen to this post than read it, just click play above.)Welcome back to Volts, where every week is Transmission Week!In my three transmission posts so far, I have focused mostly on the challenges of building new long-distance energy transmission lines in the US — the poor planning, the inefficient financing, the permitting and siting hassles. Today I’m going to turn to a different subject: the various ways that the performance of the existing transmission system could be upgraded and improved through so-called “grid-enhancing technologies” (GETs).To be honest, I probably should have tackled this subject first. Though new lines are going to be needed regardless, it is faster and cheaper to upgrade the existing system, with fewer regulatory barriers. GETs can achieve short-term relief from grid congestion while new lines are being developed.There are three techs that are typically classified as grid-enhancing technologies, and I will focus on them in this post. In my next post, I’ll cover a couple of extra options that I haven’t found any other way to fit in. Let’s jump in. (I should note here up top that I will be drawing heavily from a 2019 report on GETs from the Brattle Group and Grid Strategies.)Closer monitoring to improve line performanceWhen electricity passes through transmission lines, they heat up. As they heat up, they sag. If too much electricity is run through a line, it can exceed its maximum operating temperature or sag to the point that it brushes up against trees or other structures, potentially sparking fires.Grid operators want to avoid that, so they do not load lines to their full rated capacity. They set an operational limit well below theoretical capacity, to create a safety margin. But how far below capacity should the limit be set? That is the question.The heat and sag of a given line are changing in subtle ways all the time. They vary with the ambient temperature, humidity, barometric pressure, and wind speed. If it’s warmer, the line will heat up faster; if there’s a breeze, it will heat more slowly. Because the heat and sag are in constant flux, so too is the maximum safe capacity of the line.“The number we love to quote is, an increase in wind blowing across a power line of three feet per second results in a 44 percent increase in the capacity of that power line,” says Jonathan Marmillo, co-founder of LineVision, a company that makes equipment for monitoring lines. “That's the equivalent of a light breeze.” (Note: this means that the capacity of transmission lines increases as the production of wind energy increases. Handy!)But transmission system operators do not generally have that kind of real-time information about the heat and sag of their lines. They are forced to estimate, to use an average. In some cases, they assign a line a single “static rating,” well below full capacity. In some cases, they assign the lines seasonal ratings, adjusting for seasonal conditions. These estimates are, necessarily, conservative.As a result, “most transmission lines are loaded at 40 or even 30 percent of their rated capacity,” says Marmillo. That’s an enormous amount of usable capacity going unused, to hedge against the lack of information.That has changed with the development of “dynamic line ratings” (DLRs), whereby lines are continuously monitored and their capacity continuously updated.DLRs have been around for a couple of decades, but the first generations of devices were cumbersome. They were installed directly on the power lines (which involved taking the lines out of commission) and proved unreliable in operation.Technology marches on, though, and the latest generation of DLRs is vastly improved. LineVision’s DLR devices, for instance, have “no-contact” installation, which means no messing with the lines; they attach to the transmission tower. They are topped with LIDAR — the same technology used by autonomous vehicles — which gathers fine-grained data that is then crunched to determine the “net effective perpendicular windspeed,” the most important variable for determining line temperature. “We essentially use the conductor as a giant hot wire anemometer,” says Marmillo.Of course, if you abandon averages in favor of real-time measurement, sometimes capacity will be below what the static average would have indicated. But “we see capacity above static [ratings] about 97 percent of the time,” says Marmillo. It turns out those static ratings are extremely conservative. Allowing more power to travel through lines relieves grid congestion, which is valuable to grid operators. Marmillo says a recent installation of LineVision’s device on a PJM line paid itself back in three months.DLRs are particularly cheap if you compare them to more dramatic solutions to grid congestion. “The cost of deploying a DLR system on a transmission line,” says Marmillo, “is less than 5 percent the unit cost of reconstructing or rebuilding the line.”(Note: there’s an open FERC proposal on the subject of line ratings, in which the commission plans to require seasonal line ratings within two years, and for RTOs and ISOs to put in place systems that are prepared for DLRs within a year.)So that’s technology one: DLRs to better understand and exploit the real-time capacity of existing lines.Controlling the flow of electricity to ease congestionThe Brattle report says: “Power flow through an AC line is proportional to the sine of the difference in the phase angle of the voltage between the transmitting end and the receiving end of the line,” and I’ll just go ahead and trust them on that.Left uncontrolled, power will simply cascade through the system according to Kirchhoff's laws. But it is useful for grid operators to be able to route power away from congested areas and toward less congested areas. To do that, they need flow control devices.The first kind are special transformers called “Phase Angle Regulators” (PARs) that directly manipulate the phase angle to control the flow of power. They are well-known and accepted in the industry, but they are expensive, to the tune of millions of dollars a year, which has limited their deployment to a select few high-traffic lines. Plus, the accelerating pace of change in the electricity system has made their size and inflexibility more problematic. “These are 40-plus-year fixed assets,” says Jenny Erwin, marketing director for Smart Wires Inc., a company that makes flow control devices, and these days, “it's just much harder to plan out what you need 40 years from now.”The other family of flow control devices are Flexible Alternating Current Transmission Systems (FACTS), which are generally power-electronics devices that control the flow of power through a line or voltage on a system by, for example, increasing or decreasing reactance on a line. Older versions of FACTS were also quite large and expensive, but due to advances in electronics and control software, they have been made much smaller and more modular. “What used to be done with copper and steel,” Erwin says, “we are able to do with silicon and software.”Now, reports Brattle, FACTS “typically cost significantly less than PARs, can be manufactured and installed in a shorter time, are scalable, and in many cases, are available in mobile form that can be easily redeployed.” (Smart Wires, a California company that’s been around since 2010, is currently the only company making these modular FACTS.)Several studies have found that FACTS create value by easing grid congestion and deferring transmission system investments. For example, Brattle summarizes the results of a 2018 study from the Electric Power Research Institute (EPRI): “simulating the 2016 PJM system with 13 power flow control devices placed in optimal locations to reduce thermal overloads indicated annual production cost savings of $67 million. Considering the initial investment cost of $137 million, the payback period is roughly 2 years.”The possibilities opened up by modular FACTS have only just begun being explored. Most deployments and studies have focused on individual lines, but as more and more lines become dispatchable, it stands to reason that there will be emergent system effects. It’s one thing to have a dispatchable line; it’s another to have a dispatchable grid.Erwin acknowledges that this is, in fact, Smart Wires’ long-term vision. “We like to think about it as crawl, walk, and run,” she says, and implementing a fully dispatchable grid “would be running.” The company is taking small steps in that direction in the UK, installing FACTS on several lines across a wide swath of territory and linking them up so that they communicate with one another.But she stresses that the comprehensive vision “is not required to unlock value. You can extract meaningful value today, because every new FACTS adds a degree of control and efficiency.” For much more on this, see this technical report from EPRI and many other reports compiled by Smart Wires. So that’s technology two: power electronics to control the flow of power across the grid.Reconfiguring the grid to route around congestionThe flow of energy through an electricity system is determined by the level of output of the generators, the level of consumption of the loads, and the “topology” (physical configuration) of the transmission lines connecting them. There is already hardware deployed across the grid, in the form of circuit breakers and communications systems, that can, by switching open or closed, change that topology. Grid operators have long had switching procedures in place to reconfigure the grid as necessary to maintain reliability. But “finding good reconfigurations is computationally challenging,” says electrical engineer Pablo Ruiz, a consultant at Brattle, associate research professor at Boston University, and co-founder of NewGrid, Inc., a grid software company spun off from an ARPA-E project. Traditionally, reconfigurations have been implemented on a limited, ad hoc basis, guided by operator experience.Recently, however, engineers have learned to calculate reconfigurations more quickly using software. Thus the budding field of “topology optimization.” Ruiz draws an analogy with transportation. The old way of handling congestion was to raise tolls on the main roads, convincing drivers to stay home (or in the case of power, generators to curtail their output). Topology control software, Ruiz says, is like the navigation app Waze, showing drivers how they can route around congestion. That will mean less curtailment and less congestion.The software doesn’t do the reconfiguring itself — that’s still for the grid operator. “The analogy with Waze is actually pretty accurate,” Ruiz says. “It's a decision-support tool. This is not about self-driving cars; the operator is still the driver.”Naturally, though, it makes me wonder about the possibility of self-driving grids — grids that route power optimally and automatically. Ruiz thinks something like that will eventually happen, but expects a long road of incremental advances in automation before then.Anyway, in the meantime, recent deployments of topology control software in the UK have shown that “just by optimizing the configuration of the grid, you can increase grid capacity by, depending on system conditions, between 4 and 12 percent,” Ruiz says. “These are very large transfers, so if you can get 10 percent more with existing infrastructure, without any new capital investment, that's a big deal.”Studies by Brattle in the US and National Grid in the UK have confirmed that topology optimization can relieve transmission constraints and save power consumers tens of millions of dollars annually. “Broad application of the technology for real-time and day-ahead congestion management support would reduce the cost of congestion by about 50 percent,” he says.Even with the misaligned incentives of today’s utilities (software investments, unlike infrastructure investments, do not receive a guaranteed rate of return), Ruiz thinks topology control will pencil out for them. It might reduce the need for some smaller transmission-expansion projects, but it will relieve congestion on lower capacity lines by routing power to (currently underutilized) high-capacity lines — thus improving the economics of those larger, more expensive projects.Topology control will also improve the business case for a national macrogrid, since it can help ensure that every high-voltage trunk line is fully utilized.So that’s technology three: software to map out the best and most efficient configuration of the grid, from day to day and hour to hour.The extensive benefits of GETs The Brattle report I mentioned at the top of the post recounts several examples of successful deployments of GETs. It estimates that wide deployment would produce benefits that rival the value of creating regional transmission organizations (RTOs) and competitive power markets. The benefits of GETs include not only relieving grid congestion, deferring new capital investments, and saving ratepayers money, but also boosting reliability and resilience and generally improving system performance.The most interesting attempt to assess the full benefits of GETs comes in a forthcoming report prepared by Brattle for the WATT (Working for Advanced Transmission Technologies) Coalition, a group of companies developing GETs. The study won’t be released until February 24, and unfortunately, the folks at the WATT Coalition are too short-sighted to allow me to share the results in advance (grumble). I can say, though, that it is a detailed engineering analysis focused on a single (wind-rich, increasingly congested) transmission region. It examines the effects of a full deployment of GETs across the region.Long story short, GETs double the amount of new renewables the regional grid is able to accommodate through 2025. Building enough new power lines to do that would be wildly expensive and take decades; GETs do it almost immediately, with an investment that pays itself back in about six months. It also creates jobs, reduces carbon emissions, and saves the region money.In terms of the clean-energy transition, GETs are an easy win, a quick way to bring more renewables online and reduce emissions while also, helpfully, saving money. Utilities just need to do it.Making utilities want to get GETsThe core problem for GETs is the same problem I have been identifying for years: the incentive system in which US energy utilities operate. They do not make money by selling electricity or by providing superior service. They make money by receiving a guaranteed rate of return on capital investments. Naturally, they want to make more capital investments. If a technology comes along — energy efficiency, distributed energy resources (DERs), or GETs — that promises to defer or even head off the need to make new capital investments, the utility’s profits are directly threatened. All those technologies may serve the public’s social, economic, and environmental goals, but they do not serve the utilities’ financial interests. Even when utilities do not face a disincentive to improve their operational performance, they have no positive incentive, no reason to set aside money and resources. The costs of congestion and interconnection backups are simply passed along to ratepayers. Everyone in clean energy is aware of this basic incentives mismatch. “It's really an incentives issue,” says Erwin. “Clearly there is a misalignment in incentives,” says Ruiz. “There's no question about it.” Consequently, deployment of GETs remains confined to a few demonstration projects. Brattle summarizes:The slow pace of adoption of these new technology options may largely be driven by two factors. First, the technology options by themselves are not being recognized enough for their capabilities. … Second, there is insufficient incentive for either the transmission operators or owners—the two market players w…

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Transmission fortnight: burying power lines next to rail & roads to make a national transmission grid Feb 01, 2021

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Happy Monday! Welcome back to Transmission Fortnight here at Volts. Today’s a fun one.In my previous post, I described the many difficulties facing new high-voltage, long-distance transmission projects, from planning to financing to permitting and siting. It’s a bureaucratic slog.Today we’re going to look at a clever idea for bypassing many of those problems, namely, stitching together a national power grid by burying power lines along existing rail and road infrastructure, where rights-of-way are already established, thus eliminating the endless haggling with local governments and landowners. The idea has been gaining steam in the policy community for the last few years. FERC issued a report in June on challenges to transmission; siting along existing infrastructure was cited as a promising solution. In his Build Back Better plan, Biden promised to “take advantage of existing rights-of-way — along roads and railways — and cut red-tape to promote faster and easier [transmission] permitting.” This op-ed in The Hill sums up the benefits quite nicely, both of a national grid and of building it without siting battles. The vision is taking hold. And at least one small piece of that vision has gone beyond speculation into an actual permitting process. The SOO Green line will carry Iowa wind power to ChicagoA company called Direct Connect is currently in the development and permitting phase of a privately financed, $2.5 billion project called the SOO Green HVDC Link, a proposed 349-mile, 2.1-gigawatt (!), 525-kilovolt transmission line to run underground along existing railroad from Mason City, Iowa, to the Chicago, Illinois, area. It aims to go into operation in 2024.Going underground will allow the line to minimize environmental and visual impact. It will be much more resilient than an overhead line against weather, temperature shifts, sabotage, or squirrels. Two side-by-side cables will run through tubes of Cross-Linked Polyethylene (XLPE) and will be self-contained, lightweight, and easy to handle. They won’t get hot, interfere with signaling equipment (unlike AC lines), or affect rail operations. There are fiber-optic sensors along the lines to monitor sound and heat for any problems. (Nemo Link, the world’s first 400 kilovolt line using XLPE, runs undersea between the UK and Belgium; it began operation in January 2019.)Running alongside the railroad means SOO Green will have no need to claim land via eminent domain. Almost all of that railroad is owned by Canadian Pacific (one of seven large “class one” railroads in the US), so there are a tractable number of parties to deal with. A deal like this offers railroads a new passive revenue stream; royalty fees well exceed what they get from similarly buried fiber-optic lines, of which there are more than 100,000 miles along US railroads. And it’s also a chance for railroads to be part of a positive sustainability story. The project is privately funded, so there will be no need for any complicated cost-allocation formulas. The financiers (including Siemens, which very rarely puts direct capital in transmission projects) will make their money back from those who use the line — the suppliers that put power on it, the shippers that sell power across it, and the buyers that consume the power — through competitive bidding for capacity. SOO Green is holding an open solicitation right now to allocate its 2,100 megawatts among them. The aim is to create a more robust energy market by, for the first time, connecting the MISO and PJM territories. (MISO and PJM are regional transmission organizations; see previous post for details.) Wind power projects are backed up in MISO, waiting to connect, stymied by grid congestion. Meanwhile, nextdoor neighbor PJM is the largest liquid energy market in the world. The idea is that SOO Green will unlock renewable energy development in MISO; Direct Connect projects four to six new gigawatts. That energy will be transported to population centers in PJM, easing grid congestion, reducing the carbon intensity of the East Coast energy mix, and lowering power prices. The connection will also allow MISO and PJM to share reserves for the first time, which could reduce the need for reserve capacity, increase reliability, and save consumers money. Because the MISO side will be drawing from such a geographically broad region, it is likely to be in use almost continuously. “When the wind isn't blowing in North Dakota, it likely is in Minnesota,” Trey Ward, the CEO of Direct Connect, told me. “We anticipate upwards of 90 percent line utilization.”“It's as if we teleported a 2,100-megawatt wind turbine with a 90 percent capacity factor from Iowa into suburban Chicago,” he says. In fact, the converter station in PJM has applied to be treated as a capacity source in that market. (That will require some updating of regulations, just as power market regulations had to be updated to accommodate batteries.) The converter stations at each end of the line are worth looking at more closely. They will use the latest generation of Voltage Source Converters (VSCs) to exchange power between the HVDC line and the regional high-voltage alternating current (HVAC) systems already in place. VSC technology has been around since the late 1990s, but it has only recently gotten efficient, compact, and cheap enough to compete against the thyristors (solid-state valves) in common use today on HVDC lines. VSCs boast several important advantages. Thyristors need strong AC systems on both sides of the line, they require power filtering, and they have limited control over reactive power. (Do not ask me, or anyone else, what “reactive power” is. That way lies madness.)VSCs, on the other hand, are “self-commutated converters,” which means they can generate AC voltages (using IGBT capacitors) without relying on an AC system. They can control power independently, even with a weak AC system or no AC current at all; they can “black start” a grid from a blackout automatically, without any workers out throwing switches.VSCs allow precise and instantaneous, bi-directional control of both active and reactive power. They can provide services to the grid other than just energy — things like voltage and frequency regulation or “synthetic inertia” to support grid stability.“You can go from zero to 2,100 megawatts in 1/100 of a second, and back down again just as fast,” says Ward. “It will be the fastest, most dynamic resource on the North American grid.”Power electronics experts have been claiming for years that VSCs would eventually replace thyristors in HVDC projects. (“We’re in a race with Germany,” Ward says.) If built, SOO Green would be a big step toward making it finally happen — the first deployment of VSCs at this scale in the world. The main thing these VSC stations will do is serve as regional energy hubs, accepting gigawatts of energy from, or dispensing it to, existing HVAC grids.Energy users that require a large, reliable supply of high-quality electricity, like data centers or technology parks (perhaps ensconced in microgrids), can co-locate with the hubs to take advantage of their high-quality power control, thus spurring economic development. Direct Connect estimates that the SOO Green project will create 2,000 temporary construction jobs, unlock more than 4,000 jobs in renewable energy development, generate more than $2.7 billion in economic development in the two states, and yield more than $3.75 billion in ratepayer savings over 20 years. We shouldn’t exaggerate how easy things will be for SOO Green. It won’t be completely free of siting hassles, and there are costs outside its control. (The X factor is the cost of copper for the lines themselves — if it spikes for some reason, SOO Green will be in trouble.) But its costs will be much more predictable than a typical overhead line’s. It knows its exact route from the beginning and, because digging ditches is a pretty cheap and well-established technology, 80 percent of its construction costs will be for equipment. Things might be trickier for the next rail-transmission project. SOO Green is exploiting ideal conditions: a low-use railroad with well-characterized geology, connecting an energy-producing region with an energy-consuming one. Future projects could face more physical and economic challenges. At some point, there will be projects that don’t pencil out for private capital, but are needed to link the lines together into a national grid; then public money will have to step in.But private capital can do a lot. Ward mentions two federal policies that could help. One is a federal investment tax credit (ITC) like the one renewable energy receives, to defray the cost of investment, especially for early and pioneering projects. (More details on that in the previous post.)The other is some kind of manufacturing tax credit to spur more US companies to manufacture the XLPE line that Direct Connect is currently buying overseas. Even without those policies, though, things are more or less on track (har har) for SOO Green. If things go well for the project — no sure thing, given America’s history with transmission — it could serve as a template for new HVDC backbones along other sections of the elaborate US rail network. Ward estimates that as few as a half-dozen such lines would completely transform the US electricity system and spark billions of dollars of renewable energy development. (Direct Connect is in talks with all the class one railroads.) An aside: as long as we’re talking about electricity and railroads, you should check out Solutionary Rail, a plan to run (overhead catenary) electricity lines along the nation’s rail lines and electrify rail freight in the process.Anyway, to date there are no HVDC lines being planned along roads or highways, in part because state Departments of Transportation are always thinking about adding lanes, in which case the lines would have to be moved. But it’s also because developers still have an inflated sense of the cost of undergrounding lines. The news hasn’t widely spread that modern lines require less conducting metal, horizontal drilling has been perfected by natural gas frackers, and inverter stations are as little as 25 percent the size they used to be.Here’s what Dr. Christopher Clack, an energy modeler at Vibrant Clean Energy (VCE), told me:Data that I was provided from Tier 1 transmission vendors shows that the cost of underground HVDC transmission has a similar price point to the same overhead capacity of HVAC when the transmission line is over approximately 250 miles. This includes the cost to build inverter and rectifier stations at each end. And of course the sticker price of building overhead lines does not include the unpredictable expenses of regulatory hassles and intransigent landowners. A line can not be cheap if it never gets built. In terms of long-distance transmission, underground HVDC is now the smart choice. But there’s one other step planners and developers can take to bypass conventional transmission hassles.A national grid made of two-state piecesVCE is currently working on a detailed modeling exercise showing how the US can decarbonize by 2050. (You can see a preview here.)The modeling (like much other modeling before it) shows that a national HVDC network is desperately needed for decarbonization. But VCE is aware of the difficulty of siting lines that cross multiple states. So it came up with a way to create a national network that is comprised entirely of lines that only bridge two states — each one originates in one state and terminates in a neighboring state. And every one of the major HVDC trunk lines is underground, running along rail or road infrastructure.Here it is (a fancier map with more precise routes will be coming with the final release): The two-state pieces are like Legos from which a national grid can be built. “You can get [energy] from Colorado to Chicago,” Clack told me, “but you have to go through five rectifier stations. It is the same as having one line.”Building the system this way does come at some additional cost, since the VSC stations at the terminus of each line are expensive, and this would involve building more of them. And since each conversion of energy loses a little bit, all the additional conversions would add up to about 0.5 percent more “line loss.” But the advantage of this approach is that “each line is just a contract between two states,” Clack says. “You would never have a flyover state and you would never have a state that wouldn't get access to the market.” Each participating state would have one or more energy hubs and all the advantages — economic development, less grid congestion, lower power prices — they bring. The end result would be a functioning national energy grid. Clever! (When VCE’s modeling is officially released I’ll take a closer look at how the national grid operates and what it accomplishes.)Let’s do thisA national energy grid composed of underground HVDC lines running along existing rail and road infrastructure, with VSC stations in every state, is an absolute home run of an idea. It ticks every conceivable box: it’s economic development, jobs, clean energy, lower prices, and most of all, an ambitious national project that we can accomplish, red and blue states together, to regain some of America’s lost mojo.What’s more, transmission hasn’t yet fallen under the shadow of partisanship, unlike … everything else. There is bipartisan appetite for infrastructure spending and for unlocking the domestic renewable energy that is often concentrated in red states and needed in blue ones. An underground national HVDC network would create thousands of jobs and bring hundreds of millions or even billions of dollars of new economic development to every single US state. It would save every American money on their power bills. It would bring national decarbonization within reach. It would literally do what Biden promised: bring people together. We should build it! This is a public episode. 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Transmission week: how to start building more big power lines Jan 27, 2021

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Welcome back to Transmission Week here at Volts!In my previous post, I explained why the US needs lots of new high-voltage power lines. They will help stitch together America’s balkanized grids, connect remote renewable energy to urban load centers, prepare the country for the coming wave of electrification, and relieve grid congestion. And oh yeah — we won’t be able to decarbonize the country without them. Nonetheless, they are not getting built! It’s a problem.Today, we’re going to walk step by step through the process and show why they’re not getting built. At each stage, we’ll look at what Congress can do — and what Biden can do without Congress’ help — to get the process moving. This is some wonky stuff, but I’ve tried to keep it as simple as possible.Before we start …Transmission-related acronymsThis post will involve numerous acronyms, so to make things easier, I’ve put together a little acronym guide here at the beginning for you to check as needed. If you’re already an electricity system wonk, you can skip this.* DOE: The Department of Energy. The federal agency responsible for, among many other things, energy research.* FERC: The Federal Energy Regulatory Commission. The federal agency that regulates interstate transmission of, and bulk sale of, electricity and natural gas. * IOU: Investor-owned utility. Privately owned companies acting as public utilities. Excepting some federally owned and municipal utilities, most utilities in the US are IOUs. * ISO: Independent System Operator. For our purposes here, you can think of these as the same as RTOs (see below). This is why you constantly hear people in this field using the unwieldy phrase “RTOs and ISOs.” * NIETC: A National Interest Electric Transmission Corridor, designated by DOE as an area in particular need of new transmission to ease costs or congestion. * NREL: The National Renewable Energy Laboratory, a DOE-run research lab.* PMA: Power Marketing Administration. Federal agencies that operate electric systems and sell the electrical output of federally owned hydroelectric dams in 33 states. They are: Bonneville Power Administration (BPA), Western Area Power Administration (WAPA), Southeastern Power Administration (SEPA), and Southwestern Power Administration (SWPA).* RTO: Regional Transmission Organization. Non-governmental organizations (which nonetheless have government-like powers) that oversee transmission planning and wholesale energy markets in areas of the country that have been “restructured,” i.e., where generation, transmission, and distribution are owned by separate utilities. RTO membership is composed of the utilities in a particular region. Here are the US RTOs and ISOs: CAISO, ERCOT, SPP, MISO, PJM, NYISO, and ISO-NE.All right, let’s get to it! There’s still not much inter-regional (much less national) transmission planningFor most of the history of the US electricity system, up to the 1990s, almost all utilities were “vertically integrated,” meaning they owned the whole electricity value chain in a given territory, from generators to transmission and distribution. They built large central-station power plants close by to population centers and then ran transmission lines out to them. There was neither much need nor much appetite for building longer regional or inter-regional lines. Over all that time, states developed a persistently parochial lens and tight control over transmission planning. Two things have changed in recent decades. One, renewable energy expanded rapidly and got really cheap, which is why solar and wind are the fastest growing sources of new electricity capacity. However, as we saw in the previous post, the most intense sun and wind in the US are distant from population centers. This suggests the need for a wider scope of planning.Two, a wave of reforms in the 1990s and 2000s led to “restructuring” in regions containing around half the nation’s electricity ratepayers. Vertically integrated utilities were broken up: generation owners were separated from transmission owners and both were separated from distribution-system operators (i.e., the local utility that sends you a power bill). Transmission planning in these restructured regions was given over to RTOs and ISOs. This suggests there ought to be capacity for a wider scope of planning.Indeed, FERC has acknowledged the need for larger-scale, regional and inter-regional transmission planning for decades, and attempted to make it happen through orders 888 (1996), 2000 (1999), 890 (2007), and 1000 (2011). I won’t get into all those orders other than to note that order 2000 created RTOs (membership in which was voluntary for utilities) and was explicitly meant to encourage (though not mandate) broader regional transmission planning. Part of the idea was to create competitive regional markets for transmission, similar to wholesale markets for generation, in which merchant (non-utility) projects would compete on a level playing field with IOU projects. As Ari Peskoe of the Harvard Electricity Law Initiative writes in a recent paper, “FERC was optimistic that [the IOUs’] central-planning development model would be replaced by ‘well-defined transmission rights and efficient price signals’ that would facilitate market-driven expansion.” When it didn’t quite work out that way, once again, in order 1000, “FERC employed several mechanisms to pry control over regional transmission development from IOUs and break the IOU-by-IOU planning model,” Peskoe writes.The general consensus is that, despite its best efforts, FERC has failed to bring IOUs to heel and produce truly regional transmission planning and markets. Local IOU transmission plans still serve as the foundation of regional planning. There is still virtually no transmission built through competitive bidding. In practice, IOUs still build virtually all the lines in and between their territories and have deliberately made it difficult for merchant projects to get sited and financed. IOUs have engaged in a “shift away from regional projects, which must be developed competitively, to smaller or supposedly time-sensitive projects that IOUs build with little oversight and without competitive pressures,” Peskoe writes, and RTOs have implicitly or explicitly supported them in this shift.These local IOU processes are often opaque, closed to journalists and public interest groups, but the broad shift is clear. Utilities in PJM, for instance, tripled spending on local transmission projects since order 1000 was issued. In MISO, spending on regional projects shrank from nearly $6 billion to just $300 million from 2014 to 2019. Not a single transmission project in NYISO has been built on the basis of regional benefits since FERC established the process in 2008. A Brattle Group analysis found that between 2013 and 2017, 97 percent of the transmission approved by RTOs was not subject to a competitive process. Local transmission and reconstruction of aging facilities still receive the bulk of investment. One problem is, IOUs are not mandated to be part of RTOs, so they can threaten to withdraw their assets from RTOs at any point. That gives them undue leverage; RTOs are loathe to cross them.And so most transmission planning remains largely parochial. RTOs remain dominated by their members and predisposed to accept plans driven by local benefits. There are virtually no planning processes that take into account the changing energy mix or public purposes like integrating renewables and reducing greenhouse gases, and virtually no lines are being planned between regions.What Biden can doBiden’s FERC will start off with a 3-2 Republican majority. Current Democratic commissioner Richard Glick, a solid supporter of decarbonization, has been made head of the commission, and Democrat Allison Clements (who is also extraordinary) was sworn in in December. In June, an additional vacancy will open up, which Biden will be able to fill, giving Democrats a majority, which will be significant on a commission increasingly issuing partisan split rulings on things like oil and gas pipelines and, er, the MOPR (don’t ask). With a climate hawk majority, FERC could issue a stronger order mandating membership in RTOs and participation in regional planning. It could instruct RTOs and states to take into account the changing resource mix, the need for decarbonization, rising (and shifting) demand from electrification, and the benefits of inter-regional transmission. (MISO’s “multi-value project” process is often cited as a model here.)FERC could also mandate that transmission planning take a broader view of reliability, resilience, and cost-effectiveness, to replace the siloed way they are assessed today. It could also work with DOE and other agencies to develop a true national transmission plan, with an eye toward national policy goals, from which regional organizations could take their cue. And, as Peskoe advocates, FERC could more closely scrutinize the local transmission planning processes now run — parochially and with very little supervision — by IOUs. Specifically, it could “reverse its longstanding policy of presuming that all transmission expenses are prudent, and replace it with a presumption that only capital expenditures committed pursuant to an independently administered planning process are presumed prudent.” In other words, shift the burden of proof to IOUs. Doing so would push IOUs to put more transmission planning in independent hands. And FERC could take additional steps to force IOUs to regularly divulge key information necessary for independent planning. “In transmission operations, separating ownership from operational control allowed the industry to capture benefits of both coordination and competition,” Peskoe writes. “Separating ownership from control over planning could have similarly significant benefits by untethering planning from maintaining any IOU’s state-granted advantages.”One way or another, FERC has to wrestle control over transmission planning from IOUs and give it to independent organizations that can assess the full range of benefits.What Congress can doCongress could pass legislation clarifying that it intends for FERC to fully regionalize (and to some extent nationalize) transmission planning by taking the steps above. The Democrats’ Climate Leadership and Environmental Action for our Nation’s (CLEAN) Future Act, passed through the House last summer, contained language that would instruct FERC to issue a rulemaking to that effect. Congress could also allocate funding to DOE to ramp up its research on a macrogrid, including resuming NREL’s Interconnections Seam Study. It could also fund DOE to assist state and regional organizations in studying and implementing inter-regional planning, and work out a transmission plan for offshore wind in the Northeast (which is currently beset by NIMBYs). Basically, the federal government needs to study and develop best practices for inter-regional planning and then require that IOUs, RTOs, and states actually use them. Much of that legislative legwork has already been done in the Interregional Transmission Planning Improvement Act of 2019, introduced by Sen. Martin Heinrich (D-N.M.); it was included in the House-passed infrastructure bill, HR-2, but not in the year-end package that passed both houses.All right, that’s planning! Up next is financing, but first, we need a cuteness break. Here’s my cute niece:Financing transmission is unnecessarily difficultThe interconnection process — the process of connecting a new generator to the transmission network — is currently run by RTOs on a “participant funding” model, which means the project developer must pay for any grid upgrades or new lines required. This despite the fact that new lines create benefits (in reliability, efficiency, and regulatory compliance) that are spread state-wide, even regionally. A recent report from Americans for a Clean Energy Grid (ACEG) compared participant funding to “charging the next car to enter a congested highway for the cost of building a new lane.”The process is currently a disaster. First, there’s the free-rider problem: no developer particularly wants to shoulder the costs for broadly distributed benefits. Second, no renewable energy project developer knows in advance whether their interconnection will require grid upgrades; when it does, they often drop out, which means the whole interconnection study and approval process starts all over again for the next project in the queue. Third, it’s impossible to predict the location and size of power demand in five years, which is how long it takes to build transmission. And fourth, the one-at-a-time process foregoes opportunities to plan larger scale, multi-line regional projects. The financing barriers, coupled with the risk and uncertainty of a long, multi-stage regulatory process, serve to deter investment and keep costs unnecessarily high. What Biden can doWhat’s needed is for the costs of new transmission to be spread out more evenly among the beneficiaries, beyond the members of the particular RTO in which the line is proposed. That’s a highly technical undertaking in practice, so FERC could begin by soliciting solutions to this problem from RTOs and ISOs. But the process should result in a rule that forces cost-allocation reforms.To speed things up, a FERC rule could also permit portfolio-based cost allocation, which allows RTOs to group projects together instead of running individual cost-allocation studies for each.FERC could also apply more scrutiny and higher standards to local transmission investments, weighing them relative to regional projects that could provide the same benefits and more.What Congress can doCongress could pass legislation instructing FERC to prohibit the participant-funding model and spread costs out more equitably. It could also implement tax incentives for transmission investment, along the lines of the tax credits for solar and wind. They could be tailored to encourage long-distance, inter-regional lines. (There are Democratic bills in both the House and Senate that contain provisions to this effect; ACEG has its own proposal. There’s a whole wonky post to be written about how best to design these credits, but I will spare you.)And there are other ways Congress could pump money into transmission: investment grants, direct funding for inter-regional projects, support for states involved in regional and inter-regional planning, and money to compensate communities affected by new transmission projects.The Department of Transportation issues what are called Transportation Infrastructure Finance and Innovation Act (TIFIA) loans, targeted at surface transportation infrastructure projects that are of regional or national significance. A similar loan program could be set up for transmission projects.Finally, Congress could reinvigorate America’s Power Marketing Administrations (PMAs), which operate in 33 states (primarily to market and sell power from government-owned hydroelectric dams). As part of their operations, PMAs build and operate transmission. Congress could give them some money and a kick in the ass to get moving on more regional transmission. OK, that’s financing. Onward to permitting and siting!Permitting and siting are valleys of death for transmissionThe Center on Global Energy Policy (CGEP) at Columbia University and the Institute for Policy Integrity (IPI) recently put out a report (forthwith, the “CGEP report”) on what Biden can do to boost transmission without help from Congress. It serves as a good backgrounder on the barriers to siting transmission projects.The key background condition is that the 1935 Federal Power Act gave FERC authority over transmission rates and facilities, but not over transmission siting. That authority remained, and remains, with states. Consequently, a power line that runs through more than one state must be approved by each state’s public utility commission to act as…

Full show notes at the publisher

Transmission week: why we need more big power lines Jan 25, 2021

Show notes

[If you would rather listen to the post than read it, click play above.]

Hello, Volties, and welcome to Transmission Week here at Volts! It’s been delayed almost as many times as Infrastructure Week, but it’s finally here. All week, we’re going to be digging into the US energy transmission system.

For those of you new to the subject, “transmission system” refers to the big, high-voltage power lines that carry electricity over long distances, usually perched along tall metal towers. To use a road analogy, transmission lines are like the interstate system, whereas lower-voltage “distribution systems” are like the nests of highways and streets that serve local populations.

I’ve always been fascinated by distribution systems, but I’ve never really taken a deep dive into the transmission side of things. Until now!

And now that I have, I understand better than ever why I put it off for so long.

It’s complicated, y’all. There are lots and lots of acronyms, agencies, and obscure policies involved. It’s not the sexiest stuff.

But it’s important. Transmission is one of the key tools to help decarbonize the country and also one of the biggest, most dangerous bottlenecks standing in the way. We (probably) can’t decarbonize at the scale and speed we need without more of it, but laws, rules, and systems designed for a different century and a different electricity system are slowing it to a snail’s pace.

The entire transmission process badly needs attention and reform. And there are signs it may finally be getting some. There’s bipartisan political support for it, along with support from big unions like the International Brotherhood of Electrical Workers.

“I'm excited about transmission,” says Fatima Ahmad, senior counsel for the House Select Committee on the Climate Crisis. “I see jobs benefits, I see bipartisan interest, I see more and more climate policy advocates taking the time to get educated about these issues — all those things make me excited. This is just such a clear next step.”

So here’s what we’re going to do. Today, I’m going to try to convince you that transmission matters: we need more of it, we’re not building it, our decarbonization goals are at risk, but we’re at a moment when real reform is possible.

In the next post, we’ll get into the weeds. Getting a transmission line built requires planning, financing, permitting, and siting, and right now every single step of that process is dysfunctional and constipated. In each case, we’ll look at what Biden can do (through the agencies) and what Congress can do to expedite the process. Expect acronyms.

In the post after that, we’ll look at a related issue: not how to build new transmission lines, but how to improve the existing transmission system with “grid-enhancing technologies.” (Get excited about topology optimization algorithms!)

And finally, we’ll review what we’ve learned and contemplate the political landscape ahead.

It’s gonna be so much fun!

Why we need more transmission

I wrote about the need for more transmission here and here for Vox, if you want to really dig in, but here’s a quick review of the top reasons.

We need more transmission to decarbonize

A group of researchers at Princeton recently did some comprehensive modeling of US decarbonization scenarios. Of the scenarios that achieved net-zero, the one with the least new transmission — the RE- scenario, which includes lots of nuclear power and natural gas with carbon capture and sequestration — doubles US transmission capacity by 2050. In the more renewables-heavy scenario, E+, transmission triples.

Modeling from Dr. Christopher Clack at Vibrant Clean Energy has produced similar results, as have many other studies.

If the US wants to decarbonize at all, it’s going to have to build the sh*t out of some new transmission.

We need a national energy grid anyway

Despite my road analogy above, the US transmission system is different from its interstate system in one important way: we have a true national interstate network. No matter where you are in the system, you can drive to anywhere else in the system.

The US does not have a true national energy network. Instead, functionally speaking, it has three transmission grids: the Eastern Interconnection, the Western Interconnection, and ERCOT (a Texas grid, basically). Though there are a few small ties between them, very little energy is exchanged. They mostly operate in isolation.

(As you can see from all the labels below, the Eastern Interconnection is divided up among several functional transmission regions, but they are all connected to a common physical grid.)

This is goofy. Linking them together with high-voltage direct current (HVDC) lines — i.e., creating a true national energy network — would allow them to share, exporting energy when they have oversupply or importing it when supply is stretched. Early morning solar in Arizona could go to New York at the peak of its afternoon demand. Evening wind power in North Dakota could go to California when everyone is turning on their big screen TVs.

Generally, with grids, the bigger and more interconnected they are, the more efficient, reliable, and cost-effective they are. To wit: a 2016 study by scientists at NOAA found that a national HVDC network would save US consumers $47 billion annually. The Interconnections Seam Study by the National Renewable Energy Laboratory (NREL) — a study the Trump administration tried to squash — found that every $1 invested in a national HVDC grid would return $2.50 in economic, environmental, and social benefits.

A national grid (with the appropriate cybersecurity and resilience measures) would allow the US to make the best possible use of its domestic clean-energy resources. It’s a no-brainer.

(By the by, China is in the midst of plowing $26 billion into a national network of ultra-high voltage lines — UHVDC — to carry renewable energy across the country.)

We need to connect remote renewables to population centers

The areas in the US where sunlight and wind are most intense (the desert Southwest and the Midwest corridor, respectively) are distant from the metropolitan areas (mostly along the coasts) where there is most demand.

To make use of that remote renewable energy, we need transmission lines much longer than most that were built in the age of fossil fuel electricity, when plants could be built close by. Those long HVDC lines will require sophisticated new technologies and unfamiliar planning processes. Right now, we’re stuck in a chicken-and-egg problem: renewable energy developers are hesitant to build, not knowing whether they’ll be forced to pay for expensive new lines; transmission developers are hesitant to build, not knowing whether there will be generators to fill their lines.

Someone (spoiler: the federal government) needs to come in and break up the logjam to get things moving. There’s a huge pool of clean, domestic American energy waiting to be tapped.

We need to prepare for clean electrification

Among today’s US energy wonks, it is now fairly widely agreed that the fastest, cheapest, and possibly only route to large-scale, near-term decarbonization is through clean electrification. That means, first and foremost, transitioning to a net-zero-carbon electricity grid. But it also means shifting most transportation and heating/cooling off of liquid fossil fuels and onto electricity.

Large-scale electrification will dramatically increase demand for electricity — close to 40% by 2050, by some estimates.

It will also change the location and timing of energy demand, in ways that will change where and when the grid is stressed.

A plan to decarbonize the US must involve looking forward, anticipating those changes, and planning the transmission system around them.

We need to relieve grid congestion

Even transmission wires of modest length can help relieve congestion in regional grids and make them more efficient and cost-effective.

Currently, congestion is a major problem, and it’s creating a nightmare for new renewable energy projects in some regions. A recent report from Americans for a Clean Energy Grid (ACEG) found that, “at the end of 2019, 734 gigawatts of proposed generation — 90 percent of which are new wind, solar, and storage projects — were waiting in interconnection queues nationwide.” Not all that proposed generation would be built, even in the best of circumstances, but it’s still an enormous backlog of projects waiting to connect.

Here’s a map of grid congestion in the territory covered by the Midcontinent Independent System Operator (MISO). The areas in orange and red are already overloaded (as of 2018).

A recent analysis by the Natural Resources Defense Council’s Sustainable FERC Project — well-covered by Kari Lydersen for Midwest Energy News — found that “245 clean energy projects that had reached advanced stages of development were withdrawn between January 2016 and July 2020,” mainly due to grid congestion and the resulting high costs of grid upgrades. That’s an enormous amount of clean energy — and work on the part of renewable energy developers — down the drain.

The graph below shows the amount of different kinds of energy waiting in interconnection queues from 2014 to 2019 — as you can see, both solar and wind are spiking. We’ve got more and more clean energy just waiting around to start sending electrons.

Unclogging those queues requires, among other things, building more transmission.

Remember that study by the NOAA scientists? It also found that a national energy grid would allow the integration of 523 gigawatts of new wind and 371 gigawatts of new solar. (US total electrical capacity is around 1,200 gigawatts, so those are not small amounts.)

So: new transmission would help integrate renewable energy, reduce greenhouse gas emissions, reduce electricity costs, and relieve congestion. It’s national infrastructure that creates jobs and repays upfront investment many times over. We can’t hit our national decarbonization goals without it.

It is good. We should build more of it.

State and local resistance is constipating the national energy grid

I’ll go into this in more detail in the next post, but the root of the problem for transmission in the US is local resistance.

For natural gas, the federal government can step in, permit a pipeline, and seize land via eminent domain. It does not have that authority when it comes to transmission lines (except in some special cases). In the US, transmission siting is controlled by states. The process is a bureaucratic marathon subject to parochial objections and ridden with veto points at every stage.

That’s why, even as the consensus around the need for new national transmission has been strengthening for decades, the US has continued … not building much. We have been under-investing in transmission for decades. Check out how electricity demand outran transmission expansion from 1988 to 2009:

Texas broke the mold by building a bunch of transmission to connect renewables through its Competitive Renewable Energy Zones (CREZ) program in the 2010s, but the rest of the country hasn’t followed suit. Some shorter local lines are getting built, some lines that are underwater (and thus free of local landowners), but in terms of long-distance, high-voltage lines, there’s been basically bupkis.

(In his book Superpower, journalist Russell Gold tells the story of Houston entrepreneur Michael Skelly and his company Clean Line Energy Partners, which had grand plans to build a national network of HVDC transmission lines — plans that were largely frustrated.)

And so, overall, the US transmission system is as janky and outdated as the rest of its infrastructure.

There are some positive signs, though. Biden is choosing smart people to lead the agencies that will have a hand in transmission, there’s broad public and political appetite for Green New Deal-style infrastructure spending, and advocates have begun a coordinated push to get the issue some attention — see, for example, the Macro Grid Initiative, a co-production of the American Council on Renewable Energy (ACORE) and ACEG. In its recent comprehensive report, the House Select Committee on the Climate Crisis included a whole detailed section on “moving toward a national Supergrid.”

The top recommendation in all the reports I’ve read is simply that transmission be made a national priority. The president needs to affirm via executive order — and preferably Congress by legislation — that federal agencies will cooperate to develop and implement a comprehensive plan for a national transmission grid.

That’s the big picture. On our next episode of Volts, we’ll dig into the specifics of what Congress can do, and what Biden can do without Congress, to get the process of building a national energy grid unconstipated.

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A few interesting bits of news Jan 20, 2021

Show notes

[If you don’t feel like reading this post, just click Play above and I’ll read it to you.]

Happy Inauguration Day, Voltsians!

I know it’s getting somewhat tedious to keep saying this, but yes, I’m still working on that transmission post. I swore when I started my own publication that I was not going to rush anymore — that I would research and work on stuff until I was happy with it. But I never swore not to be neurotic and apologetic about it!

Anyway, it’s in the works. Until then, let’s look at a few interesting news developments from this eventful past week.

Biden administration pledges to come out of the gate swinging

A few weeks ago, I shared some simple advice with the Biden administration: blitz. Do everything within your power, as fast as possible, and don’t get tripped up trying to finesse the media narrative or secure chimerical congressional cooperation.

In what is clearly a direct response to my piece (I mean probably), the administration recently leaked plans for its first term, to be kicked off with a 10-day spree of executive actions — roughly a dozen on Day One alone. CTV News got the scoop from a memo by incoming Biden Chief of Staff Ron Klain, which Politico subsequently confirmed.

I really encourage you to click over and read the list — it’s the best I’ve felt in ages. So many lives will be immediately improved through health, immigration, and Covid relief measures. Elections really do matter.

But we’re here to talk about climate and energy, so I went through and picked out the relevant stuff:

Wednesday, after inauguration

Declaration that the U.S. is rejoining Paris climate accord.

Start of a process to restore 100 public health and environmental rules that the Obama administration created and President Donald Trump eliminated or weakened.

Not included in the memo but confirmed by CNN reporting: rescind the permit for the Keystone XL pipeline.

By February 1

Executive actions to address climate change.

Beyond

Win passage of a $2 trillion climate package to get the U.S. to net-zero carbon emissions by 2050.

Win passage of a plan to spend $700 billion boosting manufacturing and research and development.

The list suggests that the administration is going to move aggressively on multiple fronts, but it doesn’t reveal much about what direction it will go on climate.

The last two items are going to be pure messaging efforts — as long as the filibuster remains in place, neither has a chance of passage in Congress.

The first item, getting back in the Paris agreement, is low-hanging fruit, more symbolic than impactful. Ultimately, a Paris pledge is simply a pledge to pass domestic carbon policy, so it’s the domestic carbon policy that really matters.

The second item, cleaning up Trump’s regulatory mess, is extremely important, but it’s a matter of restoration, not building. The third item, Keystone XL, is a genuinely nice-to-see nod to climate activists, but not that big a deal in carbon terms.

So everything rides on that vague fourth item: “Executive actions to address climate change.” Will Biden’s EPA launch work on new rules to tackle fuel economy? A new plan to decarbonize the electricity sector? More stringent rules on air pollution? Rules that encourage building electrification?

My fear is that the administration will put off that work, thinking that being gentle will make legislation easier. It won’t. Just do the rules!

Court strikes down Trump’s plan to (not) regulate power plants

Tuesday brought a bit of good fortune that will make Biden’s work easier: a federal court struck down one of Trump’s most important climate rollbacks, and not only that, repudiated the legal argument it was based on.

Some background:

The Obama administration’s plan to reduce greenhouse gas emissions from power plants — the Clean Power Plan — was stuck in legal limbo, waiting on a federal court ruling, when Trump came into power and squashed it for good. It never got the ruling or went into effect.

The argument before the court was over whether the Clean Air Act grants EPA the authority to regulate air pollutants “beyond the fenceline.” The Clean Power Plan was extremely flexible, allowing states to meet their reduction targets through a portfolio of compliance strategies, many of which (like building new renewables or increasing energy efficiency) took place outside of the regulated power plants themselves — beyond the fenceline.

Republican lawyers argued that EPA regulations can only mandate changes “within the fenceline,” which, when it comes to something like a coal plant, amounts to some modest efficiency improvements.

When the rule and the lawsuit were scrapped, Trump’s EPA developed a replacement plan based on that legal interpretation: the Affordable Clean Energy (ACE) rule.

Now, pretty much all the rules that came out of the Trump administration were shoddy and ridiculous, but ACE was something special. Studies found that the rule would lead to an increase in carbon emissions, because it would enable some coal plants to run more often. EPA’s own regulatory impact analysis found the rule would lead to as many as 1,400 additional deaths per year by 2030.

Yes, you read that right: it was a pollution rule that would have led to more pollution and more deaths than passing no rule at all.

It was super-dumb. Happily, a key federal court agrees: the DC Circuit Court of Appeals just struck ACE down. The ruling said that the administration “fundamentally has misconceived the law” in restricting changes to within the fenceline, effectively endorsing the Obama administration’s much more expansive interpretation.

That means Biden’s EPA will not have to go through the laborious process of rolling back the ACE rule. Instead it can begin with a blank slate — “consider the question afresh,” as the court put it — and come up with a plan as flexible as Obama’s, but much more ambitious. It’s a fortuitous bit of news, fortuitously timed.

And we begin our course in advanced Manchin studies

West Virginia Sen. Joe Manchin (D-ish) — who incoming Senate Majority Leader Chuck Schumer has inexplicably made the chair of the Senate Energy and Natural Resources Committee — recently gave an interview to the conservative Washington Examiner in which he said a bunch of ridiculous stuff like, “you cannot eliminate your way to a cleaner environment. You can innovate your way.”

Sigh. I was disheartened, and said so on Twitter.

I was subsequently assured by several people I trust that this is just Manchin being Manchin, saying the kinds of things that will appeal to whatever audience he happens to be speaking to.

In fact, I’m told, while Manchin is obliged by the Republican lean in his state to voice opposition to heavy-handed (read: any) regulation, he is in fact open to the kind of historic investments that would transform the energy landscape. He hasn’t ruled out DC statehood. He’s softer on the filibuster than it seems. He’ll be willing to bargain when it comes time for budget reconciliation.

Congressional insiders seem weirdly optimistic about the possibilities under Manchin. So maybe I’m wrong! Maybe he is more flexible than he’s making out and will come through when circumstances demand it. I hope so.

Either way, we’re all going to be studying this guy’s every word and expression for clues, for four years, so get used to it.

Feline representation matters

My dogs Forest and Mabel get most of the glory here at Volts, but I also have two cats, Anakin and Obi-Wan. They are old — my family got them when I was away attending Obama’s 2008 inauguration, ironically enough — and not particularly fond of sitting for pictures.

They do like a good cuddle, though, and are willing to look at you exactly like this until you comply.

Thanks for reading, everyone.

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Voltscast: How to decarbonize the electricity sector through budget reconciliation Jan 13, 2021

Show notes

Greetings, peoples of the Volts! I’ve got a special treat for you today. It’s not my first podcast, exactly, but it’s my first Official Podcast, with music and fancy-pants guests and everything.

My guests are:

* Dr. Leah Stokes, an assistant professor of political science at the University of California, Santa Barbara, and author of the excellent recent book Short Circuiting Policy: Interest Groups and the Battle Over Clean Energy and Climate Policy in the American States; and

* Sam Ricketts, former climate director for the Jay Inslee presidential campaign, cofounder of Evergreen Action, senior fellow at the Center for American Progress, and general climate-political man about town.

Our subject? How to pass a national clean energy standard through budget reconciliation.

If those words mean nothing to you, I recommend reading my previous post, about the Georgia Senate wins and what they mean for clean-energy policy. But I’ll run through some quick background.

Biden may need to squeeze his signature climate plan through a budget bill

One of the most important elements of Joe Biden’s climate plan — arguably the centerpiece — is a national clean energy standard (CES) that would require the electricity sector to steadily decarbonize until it reaches net-zero greenhouse gas emissions by 2035.

This is important not just because the electricity sector is responsible for about a third of emissions, but because a lot of other emitting sectors like transportation and heating are going to shift to electricity in coming years, driving up demand. It’s important to have clean electricity for them to use.

While Biden does have a Democratic Congress, his majority in the Senate remains slim and the filibuster is likely to remain in place, which means a big climate bill is unlikely. Any big bill at all is unlikely.

Probably the only thing that will pass Congress is what’s called a budget reconciliation bill, which can not be filibustered and thus can get by with a simple majority.

The only things allowed in a reconciliation bill are budget-relevant items, i.e., measures that raise or lower government revenue. Biden’s CES is a purely regulatory measure — it just changes the rules. It probably couldn’t get through reconciliation.

However! Could a CES be tweaked or modified or redesigned in some way so that it is budget relevant and could pass through reconciliation? Could Biden pass his top climate priority after all?

That is precisely what Leah and Sam have been working on, and that’s what we discuss, at some length, in today’s podcast.

It’s way more interesting than it sounds! (That may be my new tag line.)

Bonus Mabel

Life is a donut, y’all. Grab onto it with all your fearsome teeth.

This is a public episode. If you'd like to discuss this with other subscribers or get access to bonus episodes, visit www.volts.wtf/subscribe