Thursday, September 29, 2016

OPEC Agrees to Agree


  • Yesterday's reported OPEC deal left many details unresolved, so oil prices remain under $50, at least for now.
  • Time has given OPEC greater leverage to make effective production cuts, and ample incentive to do so. Will that be enough to close the deal come November?

Yesterday's news that OPEC's members have agreed on the outlines of a deal to reduce output is a fine reason to end my long, unplanned hiatus between blog posts. This morning's news commentary seems focused mainly on the difficulties OPEC faces in sorting out the details by its next official meeting at the end of November. Fair enough, but we shouldn't miss the fact that what came out of the informal meeting in Algiers is qualitatively different from anything OPEC has announced since their meeting in October 2014, which pushed the oil price collapse into high gear.

It's worth taking a moment to review how we got to this point. After oil prices recovered from their last big dive during the financial crisis of 2008-9, the global oil market--best represented during this period by the price of UK Brent crude--settled into a range of roughly $70-90 per barrel. The events of the "Arab Spring" in 2011, including the revolution in Libya, pushed prices well over $100, where they remained until fall 2014.

By early 2010 US shale, or more accurately "tight oil", production was beginning to ramp up. Total US crude oil output (excluding gas liquids) had fallen steadily from 9 million barrels per day (MBD) in 1985 to a plateau around 5 MBD in the mid-to-late 2000s. Most experts thought we would be lucky if it stayed that high in the long term. So the 4 MBD of production from tight oil that came onstream by late 2014, pushing total US production back to 9 MBD, was largely unexpected.

The market impact of the first couple of million barrels per day from US shale was muted by events in the Middle East. In addition to the ongoing instability from the Arab Spring, tighter sanctions on Iran had taken another million-plus barrels per day out of exports. Prices remained high, providing a strong incentive for more tight oil drilling, which yielded the biggest increase in US oil production history from 2013 to 2015.

In thinking about what OPEC might achieve with the modest cuts they are apparently discussing, it's crucial to understand that while US tight oil at its peak in 2015 was no more than 5% of the global oil market, it had a massive effect on prices, because the price of oil is set by the last barrels in or out of the market. Inventories matter, too, but less from the standpoint of their absolute levels, than how fast they are growing or shrinking.

Simply put, the unanticipated growth of US shale swamped the market but is now an established part of supply. In late 2014 OPEC's members likely concluded that, given the upward path shale was then on, they couldn't cut their output by enough to keep prices high without simply making more room for shale, so they were better off keeping things uncomfortable for the competition by standing pat. In fact, they doubled down on that by increasing output after October 2014, mainly from Saudi Arabia and other Persian Gulf producers.

Two years of low oil prices have changed the landscape in ways that I doubt OPEC's members expected. US shale contracted but didn't die. If anything, the efficiencies that shale producers found have made many of them competitive at current prices and big beneficiaries of any future price increase. The latest rig counts from Baker Hughes show a small but steady increase in drilling activity over the last several months. However, what has collapsed with little indication of revival is investment in large-scale, non-shale oil projects from non-OPEC countries.

According to analysis from Wood Mackenzie, global oil investment--actual and planned--is down by over $1 trillion for the period 2015-20. Because of the development time lag for big oil projects, that means that a potentially serious supply gap is being created a few years down the road. Remember that non-OPEC, non-shale production makes up over half of global oil output. French oil company Total has estimated the potential shortfall at 5-10 MBD by 2020, or 5-10% of global supply.

This outcome is a mixed bag for OPEC. To whatever extent its decision to increase, rather than cut output in late 2014 was a "war on shale", that has failed at the cost of many hundreds of billions of dollars of foregone revenue. The collateral damage to the global industry, particularly in places like the North Sea, has been dramatic, even if it won't become obvious until the pipeline of projects started in the $100 years dries up sometime soon. OPEC will surely be blamed for any future price spike, but the likelihood that any cut they make now would be back-filled by non-OPEC production is much less than it was in 2014 or '15.

OPEC faces a conundrum. The market remains over-supplied in the near term, and inventories are at historic levels. Failing to reach agreement in November would not greatly hamper US shale. However, it would continue to enlarge the potential supply gap and price spike that is being stored up for an uncertain future that now also includes electric vehicles and possible carbon taxes, the incentive for both of which will expand significantly if oil prices spike again.

What's a cartel to do? We will see much speculation about that during the next two months. My guess is that the need to shore up the national budgets of OPEC's member countries, which are going deeper into debt by the day, along with a desire to avoid a price spike that would merely hasten the transition to non-hyrocarbon energy, will lead to an agreement in November to make at least cosmetic cuts in production. Stay tuned.


Thursday, July 28, 2016

Don't Book Your Solar-Powered Flight Yet

  • An around-the-world flight by a solar-powered airplane is a remarkable achievement, but it does not signal that solar passenger planes are the next big thing.
  • Compared to other options, solar's low energy density makes it an especially challenging pathway for pursuing large cuts in the emissions from aircraft.
Earlier this week the pioneering solar-powered airplane, Solar Impulse 2, completed its record-setting circumnavigation of the Earth, returning to Abu Dhabi. Just a few hours earlier, the US Environmental Protection Agency announced its intention to regulate greenhouse gas emissions from aircraft engines under the Clean Air Act. Over the last dozen years I have written numerous posts linking stories like these together, but this is one case in which I sincerely hope these events were entirely unrelated. That requires a bit of explanation.

Let's start by acknowledging the engineering talent and sheer courage involved in the flight of the Solar Impulse 2 (Si2). The aircrew and designers deserve all the kudos they will receive; they have earned a place in aviation history. However, notwithstanding the prediction of pilot Bertrand Piccard that, "within 10 years, electric aircraft could be carrying up to 50 passengers on short to medium-haul flights," I am skeptical that this project will be the forerunner of solar-powered commercial flight in the way that Charles Lindbergh's transatlantic flight in 1927 led to the first non-stop commercial flight across the Atlantic in 1938.

There's no anti-solar bias involved in that statement, just an appreciation of the constraints that physics and geometry (e.g., the "square-cube law") impose on the amount of solar energy an aircraft can harvest during flight with anything like current technology. Energy density is an essential factor in the economics of commercial air travel.

According to the website for the Si2, the aircraft is approximately "the size of a 747 with the weight of a car." That should be our first hint that scaling up to the performance and capacity of today's jets would be an even bigger challenge than the one these folks have just completed. During the course of its journey, which entailed over 500 hours of flight spread across 17 months, the Si2 collected and consumed electrical energy equivalent to a little over 300 gallons of kerosene-based jet fuel. By comparison, a Boeing 777, which is capable of carrying up to 400 people, burns an average of around 2,000 gallons of jet fuel per hour.

If you covered a 777's wings with the same 22%-efficient SunPower solar cells used by the Si2, they would generate the fuel-equivalent of less than 3 gallons per hour at noon on a cloudless day. Even allowing for the higher efficiency of electric motors compared to gas turbines, that is still orders of magnitude less than the energy necessary to push a fully-loaded jetliner through the sky at 550 miles per hour. (The Si2 averaged 47 mph.)

As the Financial Times reported, the near-term applications of solar-powered flight are likely limited to surveillance drones and other specialized platforms for which long-range fuel-free flight confers a big advantage. I could also envision lightweight, high-efficiency solar cells being used on next-generation commercial aircraft to provide auxiliary (non-motive) power, saving both fuel and emissions.

That brings me back to the EPA. The agency's stated rationale for targeting aircraft engines now is that they expect these emissions to increase in the future, and that reductions would lead to climate and health benefits. There's no mention of solar-powered aircraft, and I must trust that had nothing to do with their announcement.

The EPA's latest greenhouse gas inventory reported that in 2014 commercial and other aircraft accounted for 8% of US transportation-related emissions, and about 2% of all US emissions of CO2 and other greenhouse gases. It also showed that aviation emissions have fallen 22% since 2005.

Perhaps the growth they are worried about is proportional, rather than absolute, as emissions from electricity generation and other sources decline faster. However, compared to cars and light trucks that account for over 60% of emissions from transportation, and for which many emission-reduction options are available, aviation is a small and rather challenging focus for further reductions.  Those will likely rely on advanced biofuels, along with additional gains in turbine efficiency and airframe weight reduction. 

The website for Solar Impulse 2 acknowledges that its flight was intended to highlight the earth-bound applications of renewable energy: "Behind Solar Impulse’s achievements, there is always the same goal: show that if an airplane can fly several days and nights in a row with no fuel, then clean technologies can be used on the ground to reduce our energy consumption, and create profit and jobs." Solar-powered air travel for the masses seems pretty far off, and certainly not something we can count on for cutting our emissions

Friday, July 01, 2016

EVs and The Service Station of the Future

Tesla Motors is apparently in talks with Sheetz, Inc. to install electric vehicle (EV) Superchargers in the latter's chain of gas stations. This caught my eye, because I was involved in a much earlier effort to install EV recharging facilities in service stations in the late 1990s. It wasn't just ahead of its time; it was stymied by some of the same economic challenges noted in the Washington Post article, as well as physical and regulatory issues that weren't mentioned.

The logic of an alliance between Tesla and gasoline retailers like Sheetz seems sound. Tesla embarked on its strategy to build a network of quick-rechargers in order to sell more cars. Its Superchargers are likely to be more effective in that role if they're installed in places that are both convenient to highways and offer a variety of other amenities for drivers, while they wait 15 minutes or more to top up their car's range. High-volume fuel retailers like Sheetz have already optimized their sites for convenience of location, and they have a wider range of food and beverage choices than the average gas station.

They also provide another essential feature: space. When Texaco was evaluating adding rechargers for GM's ground-breaking EV1 electric car to its Southern California retail network nearly 20 years ago, the fire marshals with whom we met insisted that high-voltage electricity and pumps dispensing volatile fuels like gasoline could not share the same pump island. They had to be widely separated for safety, and few of our L.A. locations had large enough footprints for that. Sheetz, by contrast, typically has large stations--many in rural or suburban locations--that could accommodate EV charging without endangering customers filling up with gas or diesel.

Another obstacle I encountered at Texaco was that EV rechargers are expensive, while electricity is cheap. Even if you're allowed to charge customers for it--we weren't, for regulatory reasons--it takes a lot of usage to pay back the substantial investment in equipment and installation. With EV sales still occupying a small niche in the market, that calculation hasn't changed much in the intervening decades. However, Tesla's primary motivation isn't to make money selling electricity, but to generate profits and support its stock price by selling more premium EVs. I would hate to see the standalone P&L for Tesla's growing Supercharger network, but that's beside the point.

This resolves a major hurdle for Sheetz and other fuel retailers that might want to add EV recharging to expand their customer base, or "green up" their image to enhance the loyalty of current customers, especially among Millennials. The profitability of such an investment would still be questionable, even if they sold EV owners lots of premium coffee and snacks while they wait. But if someone else is footing most of the bill for the added hardware, the extra revenue in the convenience store is all upside.

The service station of the future has been slower arriving than my colleagues and I envisioned when we developed Texaco's first global scenarios for the future of energy nearly twenty years ago. Sales of EVs and cars running on hydrogen have not grown as fast as we expected, while the improving performance of gasoline cars has raised the bar for alternative vehicles. However, current trends suggest that our vision of facilities offering a diverse mix of transportation energy was more premature than wrong. I will be very interested to see how Tesla and Sheetz or others move ahead with this idea.

Tuesday, June 21, 2016

Another Step Backward for Nuclear and the Environment

I don't normally do breaking news, but today's announcement by PG&E and a coalition of environmental groups on retiring the Diablo Canyon nuclear power plant in California within 8-9 years merits immediate comment.

Given the enormous social and political challenges PG&E faced in undertaking the re-licensing of the facility when its current operating licenses expire in 2024 and 2025, this action is understandable, though regrettable. I lived in California when Diablo Canyon was planned and built. It was sufficiently controversial in the 1970s, and the environment has only become more contentious. Extending the operating licenses of nuclear power plants to 60 years has become typical elsewhere, but the utility's board must have concluded that it was a non-starter in today's California.

However, we should not be misled by press-release language about replacing "power produced by two nuclear reactors...with a cost-effective, greenhouse gas free portfolio of energy efficiency, renewables and energy storage." Under California's extremely aggressive renewable energy and storage targets, the alternative energy mentioned here was coming, anyway, but it was intended to replace higher-emitting sources like out-of-state coal and in-state natural gas generation. Until there is an overall surplus of zero-emission energy--when?--the energy mix is a zero sum game.

This agreement--perhaps the best deal possible under the circumstances--thus represents the net loss of 18 billion kilowatt-hours (kWh) per year of zero-emission electricity. That's equivalent to 9% of all utility-scale electricity generated in California last year. The state went through a similar event in 2013 with the permanent shutdown of the San Onofre Nuclear Generation Station between L.A. and San Diego. As I noted at the time:

How much emissions will increase following the shutdown depends on the type of generation that replaces these units. If it all came from renewable sources like wind and solar, emissions wouldn’t go up at all, but that’s impractical for several reasons. Start with the inherent intermittency of these renewables, and then compound the challenge by its scale. Even in sunny California, replacing the annual energy contribution of the SONGS units would require around 7,200 MW of solar generating capacity, equivalent to nearly 2 million 4-kilowatt rooftop photovoltaic (PV) arrays. That’s over and above the state’s ambitious “Million Solar Roofs” target, which was already factored into the state’s emission-reduction plans.

Grid managers from the state’s Independent System Operator indicated that in the near term much of the replacement power for SONGS will be generated from natural gas. Even if it matched the mix of 71% gas and 29% renewables added from June 2012 to April 2013, based on “net qualifying capacity”, each megawatt-hour (MWh) of replacement power would emit at least 560 lb. more CO2 than from SONGS. That’s an extra 4 million metric tons of CO2 per year, or 8% of California’s 2010 emissions from its electric power sector and almost 1% of total state emissions. If gas filled the entire gap, or if the natural gas capacity used was not all high-efficiency combined cycle plants, the figure would be closer to 6 million metric tons, equivalent to the annual emissions from about 1.5 million cars.


So far, the state's environmental data supports this conclusion. Although offset by larger imports of low-emission power from out-of-state, there was a noticeable uptick in greenhouse gas emissions from in-state generation from 2013 to 2014. (See Figure 8 in the 2016 California GHG Inventory.) 

California will get more renewables either way, but shutting down Diablo Canyon when it still has decades of useful life left represents a net loss to California consumers, PG&E shareholders, and to the global environment. 


Thursday, June 16, 2016

Could the Hydrogen Economy Run on Ethanol?

  • Plans for a fuel cell car running on ethanol look like a clever way to circumvent the obstacles faced by other fuel cell vehicles.
  • However, it is not clear that ethanol's perceived logistical benefits or emissions profile would give Nissan an edge in the competitive market for green cars.

Japan's Nissan Motor Co., Ltd. made headlines this week when it announced plans to produce a fuel-cell car that would run on ethanol, instead of hard-to-find hydrogen. As reported by Scientific American, the company expects to commercialize this approach by 2020, even though competitors like Toyota already have fuel cell cars in their showrooms. It's an interesting choice. Ethanol seems to offer logistical advantages over hydrogen, but the technical challenges involved aren't trivial, nor is ethanol without drawbacks from an energy or environmental perspective.

Fuel cells have long promised a different and potentially superior path to electrifying automobiles, compared to battery-electric vehicles (EVs) with their limited range and relatively long recharging times. One of the biggest obstacles has always been the lack of infrastructure and supply--hydrogen must first be liberated from water, methane or other compounds--and the problems of storing sufficient quantities of it on board. I've driven prototype fuel-cell vehicles (FCVs) and found the experience pretty similar to driving a regular car, as long as you have a hydrogen filling station handy.

Nissan makes the case that ethanol (chemical formula C2H6O) is much easier to source and distribute than gaseous hydrogen, and the process for making it give up its hydrogen is routine, at least under laboratory conditions. However, as the alternative energy research subsidiary of my former employer, Texaco Inc., found in pursuing a similar concept with gasoline, it's one thing to do this in a bench-scale device and quite another to do it in a size and shape that will fit easily and safely in a car and run as reliably as an internal combustion engine. I suspect Nissan's engineers have their work cut out for them for the next four years.

The bigger questions about this approach are more basic: Does it make sense from an economic, energy and environmental perspective, and can it find a large enough market? Consumers already have a wide range of green alternatives from which to choose, ranging from Prius-type hybrids (gasoline only), plug-in hybrids (gasoline + electricity) and battery EVs, not to mention the continuous improvement of non-electric cars. 

Nissan didn't include many numbers in the documents accompanying its press release, but the chemistry and math involved are pretty simple. At 100% efficiency, a gallon of ethanol could produce just under 0.8 kilograms (Kg) of hydrogen (H2) using the standard steam-reforming process. The best efficiency I could find for this ethanol-to-hydrogen conversion  was around 90%, so in the real world that gallon of ethanol would yield around 0.7 Kg of H2--enough to take Toyota's Mirai FCV about 46 miles. That's pretty good, considering that same gallon in a Chrysler 200 equipped as a flexible fuel vehicle (FFV) would drive an average of just 21 miles. Fuel cells are much more efficient than internal combustion engines.

The economics of operation don't look bad, either. If we use today's average US price for E85 (85% ethanol + 15% gasoline) of $1.87/gal. as a proxy for an ethanol retail price, that equates to around 4 ¢/mile, using the Mirai's published fuel economy data. That's about 15% cheaper than a Prius on regular gasoline at this week's US average of $2.40/gal., but it's also around 10% more expensive than a Nissan Leaf using off-peak electricity in northern California.

Emissions are trickier to assess. There's a lively and growing controversy about whether biofuels produced from crops can truly be considered carbon-neutral, even in places like Brazil where the yields from sugar cane are so high. There's much less controversy that the production of most US ethanol from corn is anything but a net-zero-emission endeavor. Corn requires fertilizer sourced from natural gas, and ethanol refineries consume gas (or coal) and electricity in their production process. In any case, when Nissan characterizes their planned ethanol FCV as having "nearly no CO2 increase whatsoever", they are either oversimplifying a very complex discussion or taking a large leap of faith. 

We can count the CO2 coming out of the tailpipe of such a car, and it would need a tailpipe because the onboard ethanol converter would emit about 12.5 lb. of CO2 for every gallon of ethanol converted to pure H2, plus some CO2 from the ethanol burned to heat the unit. My back-of-the envelope calculation gives a figure of 135 grams of COper mile, or 20% lower than a Toyota Prius on gasoline. It would not be a Zero Emission Vehicle (ZEV), though of course an EV running on average grid electricity isn't really a ZEV, either, except in isolated regions or at specific times of day.

Even if there aren't any deal-killers here, I'm skeptical about Nissan's fundamental assumption that the ethanol infrastructure for their FCV would be that much easier to develop than the H2 infrastructure other FCVs require. That's because of the cost and ownership structure of the retail fuels business, which as I've argued previously helps explain why your corner gas station is unlikely to sell E15 (85% gasoline, 15% ethanol) any time soon, despite the EPA having approved it for newer cars

At least in the US, most gas stations are owned by small businesses, not by the oil companies whose brands they display. Margins are slim, and these folks don't have deep pockets, so adding a new fuel like pure ethanol or the ethanol-water mix that Nissan suggests, poses a difficult business decision: Do you take over an existing tank and stop selling diesel fuel, or premium gasoline with its high margins? Or do you rip up the forecourt to add a new tank, which entails being out of business for months--or even longer if you discover that one of your existing tanks is leaking? Either way, the investment costs and disruption to current customers are significant, in exchange for selling what at first would certainly be a low-volume product. When I was in the fuels supply & distribution business, we would have called that kind of decision a "no-brainer."

If Nissan can't encourage enough service stations to add ethanol or an ethanol/water blend--E85 would not work--to their product mix, do they start their own service station network? That seems unlikely. And if you buy one of these cars in a few years, should you carry a case of vodka in the trunk as an emergency range-extender? That's only half-facetious.  

I give Nissan credit for pursuing a novel option for making fuel cell cars more viable, as an alternative to today's range-limited EVs. Ethanol looks like a cost-competitive source of hydrogen, and it is at least easier to store than H2 gas or liquid H2. However, they face practical and marketing challenges that might well offset most of the advantages the company claims to see. The ethanol FCV could encounter the same chicken-and-egg dynamic as FCVs running on hydrogen, or indeed any new model requiring a fuel that is not distributed at scale today. It will be interesting to watch their progress.



Thursday, May 26, 2016

On Track for a Golden Age of Gas?

  • The global energy industry must overcome significant new challenges if natural gas development is to achieve the vision of a Golden Age of Gas.
  • Low energy prices and reduced investment are only half the battle as regulations complexify and organized opposition grows. 

Five years ago the International Energy Agency (IEA) issued a report entitled, "Are We Entering a Golden Age of Gas?" Gas development was booming, from both conventional resources and US shale deposits, and gas was widely seen as a vital tool for reducing greenhouse gas emissions. Much has happened since then, including a collapse in global oil prices, the signing of a new climate agreement in Paris, and a broadening of the anti-fossil-fuel focus of climate activists. If we're still on the path to a golden age of gas, the ride will be bumpy.

This is probably most evident across the pond, where Nick Butler, the Financial Times' respected energy analyst, observed this week, "Unless something changes radically, Europe has passed the point of peak gas consumption." He cited Germany's ongoing "Energiewende" (energy transition) which in order to maximize wind and solar and minimize nuclear power, ends up squeezing gas out between renewables and much higher-emitting coal.

Earlier this month France's Energy Minister announced she was pursuing a ban on imports of US shale gas--effectively any gas from the US--since France already bans domestic fracking. That strikes me as a textbook example of having to keep making bad decisions to be consistent with the first one, but it's their sovereign choice.

As the IEA defined it at the time, this Golden Age would entail faster growth in gas demand in every major sector, compared to the agency's main "New Policies" scenario in its then-current annual World Energy Outlook (WEO). They anticipated compound average growth of 1.8% per year, much faster than oil or coal, with gas consumption ending up 13% higher than the WEO's projection for 2035. That's like adding an extra Russia or Middle East to world gas demand within 20 years.

One gauge of whether that still seems realistic can be found in the US Energy Information Administration's (EIA) just-released 2016 International Energy Outlook. The EIA's long-term forecast actually has gas consumption growing slightly faster than IEA's Golden Age track in the developed countries of the OECD between now and 2035, but with a slower ramp-up to essentially the same end-point in the non-OECD countries.

Of course one forecast can't really validate another, so let's consider how some of the big uncertainties that the IEA identified in the 2011 report have shifted, starting with energy pricing. After oil's recent rebound, oil and gas have fallen by around half their 2011 US prices. That makes investments in oil and gas exploration and production considerably less attractive. Nearly $400 billion of projects have been canceled or deferred, globally, setting up slower growth in production from both gas fields and oil fields with associated gas in the near-to-medium term. This deceleration is evident in EIA's latest monthly Drilling Productivity Report for US shale.

With the contract price of liquefied natural gas (LNG) often tied to oil prices or competing with pipeline gas that has also fallen in price, large gas infrastructure projects like LNG plants look less attractive, too. We've already seen cancellations of new facilities in Australia and Canada. Fewer LNG export facilities are likely to be built in the US than previously planned. All this means less new gas reaching markets where it can be used.

Cheaper oil also reduces the attractiveness of gas as a transportation fuel. Although increasingly popular as a cleaner fuel for buses, natural gas hasn't made much headway in US passenger cars. However, this application has been growing in places like Italy and Iran, for different reasons.

Viewed in isolation, these price-related responses seem likelier to delay, rather than derail the expectations the IEA set out in 2011. The bigger challenges come from a set of issues the IEA identified a year later, in a follow-up report called "Golden Rules for a Golden Age of Gas." As Dr. Birol, now the Executive Director of IEA, indicated then, these boil down to the industry's "social license to operate."

Transparency, water consumption, emissions including methane leaks--all on IEA's list--are some of the key issues over which companies, regulators, NGOs and activists are sparring today. The UK is a prime example. Conventional energy production is declining rapidly and a large shale gas potential has been identified by the British Geological Survey, but every attempt to drill exploratory wells has encountered strong opposition.

A new factor the IEA did not anticipate is the emergence of political movements focused on fossil fuel divestiture and a "keep it in the ground" mantra. These may be based on unrealistic expectations of how quickly the world can transition to a zero-emission economy, but they illustrate the scale of a stakeholder engagement challenge the global oil and gas industry has so far failed to meet adequately. 

Just as social media are transforming politics, they are also altering the balance of power between organizations and their critics. The gaps that must be bridged if new gas development is to remain broadly acceptable to the public are growing in ways that will demand new approaches and new strategies to address. 

Considering the shifts in the global energy mix that will be necessary to reduce global emissions in line with the goals of last year's Paris Agreement, gas ought to have a future every bit as bright as the Golden Age the IEA described five years ago. Achieving that now likely depends less on the price of energy and the scale of available resource than on convincing regulators and the public that the trade-offs involved in obtaining its benefits are still reasonable.


Tuesday, May 10, 2016

A New Angle on Carbon Capture

In my last couple of posts I looked at the difficulty of meeting ambitious targets for cutting greenhouse gas emissions (GHG) without help from the lower-emitting portions of our current energy mix. Last week ExxonMobil announced that it is pursuing a new pathway for capturing carbon from power plant exhaust. That could help revive another important strategy for large-scale emissions reduction from our existing energy sources.

Carbon capture and sequestration (CCS) has fallen out of favor, lately, mainly due to the high cost and technical challenges of the early prototypes for large-scale implementation of the technology. Not only are the initial investment costs of today's CCS hardware still very high, but it is also inherently expensive to operate. That's because of the high energy consumption of the process, resulting in a "parasitic" load on the host power plant that reduces its net output by up to 20%, making the remaining output much more expensive. That creates a large deterrent in any market that doesn't provide either direct subsidies for carbon removal, or a high carbon tax or price for traded emissions offsets.

Another reason that CCS has received less attention recently is that the costs of renewable energy technologies like wind and solar power have kept falling. To some they now look cheap enough, especially with further cost improvements extrapolated, to enable us to reach our emissions goals mainly through wider deployment of solar modules and wind turbines.

Even if that were technically feasible, like most other energy industry experts I have met I am convinced that the deep emissions cuts desired for mid-century will require implementing or retro-fitting CCS onto the fleet of coal and gas-fired power plants that will likely still be in service decades from now. CCS underpins several of the emissions stabilization wedges pioneered by Princeton engineering professor Rob Socolow and his colleagues ten years ago.

What makes the approach that ExxonMobil and FuelCell Energy, Inc. have described so attractive is that, instead of being a drain on power generation, capturing CO2 via fuel cells would actually add significantly to a facility's reliable power output. It would increase revenue, rather than curtailing it.

The clever bit, and its potential advantage over current carbon-capture technology, is that CO2 capture in a carbonate fuel cell occurs as a byproduct of the power generation step. That means that it doesn't require a big, expensive, power-hungry process unit, the only function of which is to strip CO2 from flue gas and concentrate it for subsequent shipment and storage.

These fuel cells would still require natural gas for fuel, and they would produce CO2 emissions in the process of generating electricity, though at a lower rate than the coal or gas-fired plant with which they would be partnered. However, both their direct emissions and the CO2 extracted from the power plant exhaust would come out in a highly purified form suitable for geological sequestration and stay out of the atmosphere.

That brings up an important advantage of this approach over various schemes to capture CO2 directly from the atmosphere. Although the article on the Exxon/Fuel Cell Energy development in MIT Technology Review  described the CO2 concentration in power plant flue gas (5%-15%) as "low", that is still hundreds of times higher than its concentration in air.

400 parts per million of CO2 in the atmosphere may be worrying from a climate perspective, but it is still just 0.04% of air that remains mostly nitrogen and oxygen. And the lower the concentration, the harder--and normally more expensive--it is to extract. (Green plants can do this trick cheaply thanks to billions of years of evolution combined with cost-free sunlight.)

The press release makes it very clear that this new carbon-capture technology has so far only been demonstrated in the lab. Scaling it up will require additional work, and success is uncertain. Many other promising innovations, including a host of cellulosic biofuel technologies, have failed to scale. However, its potential applications are compelling enough to justify a lot of patience and persistence. I wish them luck.