What about greenhouse gases?

As many readers of this blog would have noticed, I have been in favor of developing all different energy sources—nuclear, coal, oil, wind, solar. I advocate that position because more than three billion people still do not have adequate electricity and are mostly eking out subsistence. The society has an obligation to lift them out of poverty, and provide them with ample, affordable, and clean energy so they can live healthy productive lives. 

So what happens to greenhouse gases? Aren’t we then inexorably marching towards a calamity? Not if we recognize the need for a differentiated response. For starters, societies that have high per capita energy consumption can look for opportunities to conserve and and/or adopt more efficient technologies. As we do this, our focus should be on actions that can have a significant impact on greenhouse gas emissions, preferably on the short order.

Specific actions would differ for different societies. For people currently relying on foraging wood and burning it for fuel providing natural gas or electricity to would be highly beneficial. It would improve their health by limiting the exposure to sooty open flames, reduce deforestation, and reduce the warming due to soot. Since many of them are not currently supported by grid electricity, we should consider distributed power from appropriately sized wind or PV systems. 

Reining in fugitive natural gas during oil and gas production and from landfills is another important factor. Earlier this year, Shindell et al. published an article in Science pointing out the need to look at methane and black carbon sources. The paper showed that strategies to reduce methane and black carbon emissions would reduce the projected global warming by about 0.5°C. The paper emphasized the need for a differentiated response, as regional differences are important. For example in the US, natural gas emissions are mostly associated with municipal waste (ca. 50%), and less so with oil and gas operations (ca. 12%; additional 12% from coal mining). Methane from O&G operations contributed much more in Russia, Middle East, and Central Africa. While the new EPA regulations on methane emissions from shale gas are important to ensure that this energy source does not become a major culprit, we should not lose sight of methane emissions from landfills. Innovations to economically use landfills as a resource for electric power production would have a larger impact on reducing greenhouse gases. 

Another leverage point for reducing greenhouse gases is agriculture. As we discuss in our book, reducing beef consumption in our diet can make a very large difference by impacting at multiple levels. Fewer cattle would burp out less methane and require less feed—feed that is in turn produced by using energy intensive fertilizers, etc. By using controlled-release fertilizers or by using biochar as soil amendment, we can further reduce both the amount of fertilizer used and the efficiency of its uptake by the plants.  These measures are not as exciting or trendy but they can have a substantial impact on GHG emissions and are deserving of our attention.

In an Op-Ed in the NY Times (May 9, 2012), James Hansen declared that if Canada develops its tar sands resources it is “Game Over” for climate change. His point is that developing tar sands and other unconventional sources such as shale oil would detract from efforts to “phase out our addiction to fossil sources.” I see the recent rise in the production of unconventional resources as a welcome relief from the energy crunch that we were facing. It takes decades to develop alternate energy sources like solar, wind, and geothermal, and with the recent closure of nuclear plants in Japan and Germany, there is increasing pressure to find CO₂-free sources of energy. At present they are significantly more expensive, and it would take further innovations to bring their costs down and get them ready for widespread commercialization. Shale gas, shale oil and other unconventional resources are helping us buy time to develop CO₂-free sources of energy. It would be criminal to waste this precious gift of time.

You can't have your gas and burn it too!

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Lately there is much talk of the surge in natural gas supplies, their falling prices, and predictions of greatly expanded use. Two key technologies, hydraulic fracturing (fracking) and horizontal drilling, have made accessible enormous quantities of an unconventional resource shale gas. The Energy Information Administration of the Department of Energy estimates technically recoverable shale gas resource at 827 trillion cubic feet (tcf), almost four times the proved reserves of natural gas of 245 tcf. There are also an estimated 1500 tcf of unproved conventional resources, and a good fraction of these may also become available at some pint in the future.

When expressed in CMO units (cubic mile of oil equivalents) the proved reserves, shale resource, and unproved resources are only 1.6, 5.4, and 9.8 CMO respectively, and it is clear that they can only make a modest contribution to the overall global energy scene.

The unleashing of natural gas from shale is good news. About a third of the natural gas is used for producing hydrogen, which in turn is used industrially to refine fuels or produce fertilizers. The large availability of natural gas at relatively low cost has allowed US refineries to increase their output. Monthly exports of finished petroleum products hovered around 25 millions barrels per month for 20 years between 1985 and 2005. Since 2005, the monthly exports of finished products from the US have grown to about 80 million barrels per month, which has also helped with the balance of payments.

The shale gas provides the US with an energy resource that is much cleaner than coal and has about one-half its carbon footprint. Natural gas-fired power plants operating in combined cycle mode (NGCC) emit less than 400 g CO₂/Kwh, whereas a typical coal-fired plant emits 850 g for the same kWh. Natural gas power plants also have low capital expense: about $700/Kw capacity compared to $1400-$2000 per kW for a coal-fired plant. In the past, the gas price was high, and so the natural gas was generally used for providing power during periods of peak demand, while the coal-fired or nuclear plants were used for base power. However, if the gas price is low (<$2.00/MMBtu), there is no reason why NGCC plants could not be used to provide base power.

A few years ago the US was slated on becoming a major gas importer, in anticipation of which facilities from handling liquefied natural gas (LNG) were being built. Now it appears that US could make use of those facilities for exporting LNG.  Since shutting down most of their nuclear plants, Japan and Germany have increased import of natural gas. LNG export represents a likely expansion market for US natural gas.

Apart from its use in electric power production, natural gas can also be used to fuel transportation. Although its lower volumetric energy density than gasoline or diesel may pose challenges to its use in certain types of vehicles, there exist ample opportunities for its use in delivery vans, buses, and even long-haul trucks where its operating cost advantage could outweigh the initial outlay for conversion and installing a larger tank or the inconvenience of more-frequent fueling.

The current annual consumption of natural gas in the US is around 22 tcf, and the added shale gas is a very welcome relief as is portends a supply of about 38 years—but that is at the current rate of consumption. If the consumption continues to increases at its historical average of 2.0%/yr this amount would be exhausted in 29 years, and even sooner at a higher growth rate as is expected from the opening of newer markets. The best part of it is that it buys us time to develop alternatives that can make a lasting impact.

How Germany and Japan dealt with reduced nuclear power

Writing for the American Solar Energy Society Paul Gipe wrote in Sep. 2011 that despite shutting down its nuclear plants Germany is managing without increasing use of coal and other fossil sources.  On this blog (Oct. 14,2011), I commented that it was perhaps premature to make that judgment since the electricity production data covered only the first half of the year during most of which period the nuclear plants were fully operational.

I have been waiting for the 2011 numbers to be reported by various sources (BP, IEA etc.).  The latest numbers I have from IEA's Monthly Electricity Statistics, but they cover through Nov. 2011.  In Nov. 2011 there was 77% less nuclear power produced in Japan compared to Nov. 2010.  In Germany, the decline was not as steep, only 31%.  What surprised me was that in contrast to the impression given in media articles, in neither country is the contribution from nuclear power zero.  

To enable comparison with total electricity productions in 2010, I estimated the 2011 numbers by adding the Nov. 2011 production figures to the year-to-date figures (essentially asserting that production in Dec. 2011 will be close to that in Nov. 2011).  With this assumption nuclear plants in Japan and Germany would generate 274 and 133 TWh respectively out of an estimated total power consumption of 1000 and 548 TWh.  In 2010 the two countries produced 1038 and 566 TWh of electricity.  Somehow, despite nuclear power shutdowns in 2011, both countries have managed to generate over 96% of the power they generated in 2010.

	Japan		Germany
	2010	2011 (est)	2010	2011 (est)
Total Electricity	1038	1000	566	548
Nuclear	274	154	133	102
Combustion sources	673	747	374	359
Hydro	82	75	25	28
Wind, Solar, Geo	9	23	49	62
Net export	0	0	15	2

To deal with the shortfall from nuclear power, Germany drastically reduced its power exports and increased imports of electricity. Germany's net exports in 2010 amounted to 15 TWh, but in 2011 that number is likely to be 2 about TWh.  Couple this change with an increased production from wind, solar, and geothermal sources of 13 TWh and about 2 TWh additional from hydropower, and you have made up 28 of the 31 TWh lost from nuclear power.  Germany also reduced combustion-based electricity by about 15 TWh, such that in 2011, it is estimated to consume about 18 TWh less in 2011.

Japan does not export or import electric power.  The estimated loss of 120 TWh from nuclear has been made up in part by increased generation from combustion sources (74 TWh), and in part from increased wind, solar and geothermal resources (14 TWh).  Hydropower production has gone down in Japan in 2011 by about 7 TWh (I am not sure why), and so the total shortfall for the year could be as much as 39 TWh (ca. 4%). 

Further nuclear plant closures are scheduled in both countries, and in 2012 the contribution from nuclear power will be substantially less.  How they manage these deeper cuts, remains to be seen. 


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The IEA published the final numbers for the year, and so although it does not make any substantive difference, here are the electricity production numbers.  One reader pointed out to me that by focusing on net exports I am missing the marked changes in the imports.  With that in mind, here is the updated breakdown in TWh:

	Japan		Germany
	2010	2011	2010	2011
Total Electricity	1038	1010	566	548
Nuclear	274	153	133	102
Combustion sources	673	747	374	354
Hydro	82	75	25	28
Wind, Solar, Geo	9	22	49	67
Exports	-	-	58	55
Imports	-	-	43	51
Net export	0	0	15	4

Green Jobs in Energy

Perusing through an announcement from ARPA-e, I ran across this statistic: the US ethanol industry employed 400,000 people in 2010 and produced 13 billion gallons of ethanol (9 billion gallons of gasoline equivalent).  Wow, that is a lot of jobs! Consider the fact that the oil and gas industry employs a comparable number of people, 415,000 (Bureau of Labor Statistics data) for extraction and refining.  The output of the O&G industry was roughly an equivalent of 130 billion GGE of liquid fuels and about 24 trillion cubic feet of natural gas (ca. 200 billion GGE).  Likewise, in 2010 the US electric power generation sector employed about 390,000 people and to produce 4,325 TWh of electricity. Contrast that with the nearly 100,000 employed in the wind industry that generated only 170 TWh.

As we pointed out in the CMO book, “The primary purpose of the energy industry is not to provide employment within the industry, but to make a commodity that allows many industries to flourish and employ people.”  If as a nation we are really seeking to find employment for people, we have to produce more energy.  Developing energy sources like ethanol or wind may be great at employing many more people, but it only means that when you have to pay living wages to all those employed; the product is naturally more expensive. 

Economics of residential PV Systems

My previous post on this blog focused on utility-scale installations of PV systems, and I pointed out that for those systems achieving a parity of the levelized cost of electricity (LCOE) with the price paid by consumers is not the most appropriate comparison. The LCOE of PV should be compared with the LCOE of competing power generation systems. Since one of the big advantages of PV is that it can be deployed in a distributed manner, it behooves us to examine the economics of those systems too. For the customers the operative comparison is indeed based on the price they pay.

Residential users pay different rates for electricity from a low of around 7 cents/kWh to as much as 36 cents/kWh. The variation depends on the operative schedules as agreed upon between the local utilities and the governing commissions. The large variation in price also means that the outcome of economic analysis could differ substantially depending on an individual’s circumstance. Also, let us bear in mind that economic considerations are not necessarily the primary drivers for individual actions.

Installation costs for rooftop PV systems are somewhat higher than those for utility scale systems. According to a recent report from the Lawrence Berkeley Laboratory, Tracking the Sun IV, the average cost of installing a 1-2 kW system in 2010 was $9.80/W, and it decreased in increasing size. The cost for a 9-10 kW system in 2010 was $6.60/W. The capacity-weighted average of residential systems, most of which were in the 2-5 kW range, was $7.3/W.  At this rate the cost of a 3-kW system would be $21,900. To soften the rather steep up-front cost, the federal government offers investment tax credits, and there are also rebates available from the utilities. Together, these can bring down the cost of the 3-kW systems to about $10,800.

At a capacity factor of 25%, such a system would produce 6,570 kWh of electricity over the course of a year. My utility, Pacific Gas and Electric, charges users based on a tiered system. The base usage is billed at 12 cents/kWh; the rate goes up to 14 cents/kWh for usage between 100 and 130% of the base, and above 130% electricity costs 34 cents/kWh. My electricity rarely exceeds 130% of my base allocation; the economic value of PV electricity for me is at best 14 cents/kWh. Thus, it would take me about 12 years to recoup the cost of the PV system. My neighbor’s electricity usage is substantially higher, and his marginal rate for electricity is 34 cents/kWh. The period to recoup his outlay would be only about 5 years. To recover the total installed cost—because the tax credits and rebates are ultimately paid by the society as a whole—the time for recoup the cost of installations would be 24 and 10 years respectively in the two cases.

The foregoing analysis is grossly simplified. I have not considered any escalation of the cost of grid electricity, nor have I included any financing charges for installing the PV system. For a rigorous analysis and policy implications I refer you to the work of Prof. Severin Borenstein. 

To go a bit deeper, we should also examine why the pricing is the way it is, and what choices have we made that led to that structure. The tiered structure was designed to promote efficiency, and encourage homeowners to reduce energy usage by upgrading the insulation and installing more energy-efficient appliances. Since the economics on a personal level are rather favorable for my neighbor, he is also considering purchasing an electric car, for which he would also receive a significant tax credit. I sincerely hope that he has also made significant investments in reducing his electricity consumption too. If not, our policy for supporting the growth of PV would be in a perverse way encouraging profligate use of energy.
 

Grid Parity for Solar PV: Important Milestone but not a Tipping Point

A recent study shows that solar electricity from photovoltaic systems has reached grid parity. The final peer-reviewed paper from this study has not yet been published, but a prepublication draft may be accessed here.  The study has already generated discussion on several websites (e.g., see here and here).

Achieving grid parity marks a significant milestone in the development. Although the authors of the study do not call it so, grid parity has been claimed to be the tipping point. Is it the tipping point—the point which marks an inexorable trend towards installation of PV systems over other technologies such as coal, natural gas, or nuclear? I think it would be premature to call it a tipping point, as doing so unnecessarily raises false hopes and undercuts credibility when reality does not live up to the expectations. Let us review what is really meant by grid parity and then we can decide whether or not to call it a tipping point.

A technology is said to have reached grid parity when the levelized cost of electricity, LCOE, produced by it is equal to the price of electricity that customers pay to the utility. Note that already there is an apples-to-oranges comparison. On the one hand we are talking about the cost of producing electricity, on the other it is the price that we pay for it.

There are many technologies for producing electricity each with its own set of capital and operating expenses, risks—which impact interest rates—and expected useful lifetime. Some require fuel use others do not. LCOE is a way of capturing these disparate factors and estimating the cost of producing a unit of electricity from a new facility. It is a tool to help power producers decide which technology to deploy to expand capacity. Conceptually the process is straightforward and entails estimating all the expenses for the lifetime of the plant and the total dividing it by the total amount of electricity expected from this plant. In practice though, details get in the way and muddy the waters. I found this discussion of LCOE to be particularly lucid.

Plants are rarely built with all installation costs paid upfront by cash. They generally require some type of financing, and these charges (principal and interest) as well as operational and maintenance expenses are incurred over time. Likewise, the income from the sale of the power is accrued over time. Net present value of these future expenses and revenues are calculated using a discount rate, which is generally slightly more than the projected inflation rate. For technologies requiring fuel inputs, projections must be made about the likely the future price of the fuel. The expected power output also requires assumptions about terms such as plant’s availability, useful lifetime and performance degradation over time. One of the key messages of the study cited above is that it is very important to use consistent and realistic values for these parameters when comparing LCOEs. The other point of the study was that if one uses realistic estimates for financing terms, useful lifetime, and performance of PV panels, the LCOE of solar electricity is significantly lower than many previous estimates.  It can range between 12 and 25 cents/kWh and thus reach grid parity in many locations.

The grid price for electricity for many US customers is between 9 and 12 cents/kWh, although the cost of producing electricity is substantially lower. Depending on their usage, the marginal cost of electricity for residential users can be as high as 35 cents/kWh. The cost of producing 1 kWh of electricity from coal power plants is often quoted as between 2 and 2.5 cents. This cost is not the LCOE from coal plants as it refers to only additional cost incurred by plants that have already been paid for. LCOE from coal plants is estimated at between 6 and 8 cents/kWh without carbon capture and sequestration. The economics of installing a PV system depend on whether one is speaking of residential systems or a utility scale system.

While it may now make economic sense for certain users to install PV at their homes, the LCOE from PV systems have to ultimately compete with LCOE from competing technologies. With relatively stable natural gas prices for the foreseeable future (ca. $4.00/MBtu), the LCOE from gas-fired plants is currently estimated at about 7 cents/kWh. Add to that their reliability, rapid ramp up, and relatively low system cost PV still has ways to go before it becomes the technology of choice for large scale installations. 

Misleading Headline

The headline of an article in LA Times declares, “Renewable power trumps fossil fuels for first time.”  No, it is not that more electric power is being generated from renewable sources than from fossil energy.  The article is talking about investments in power systems, and according to a recent analysis by Bloomberg New Energy Finance, in 2010 more dollars were invested renewable electric power systems than in coal-, gas-, and oil-fired plants; $187 billion versus $157 billion. 

The accelerated pace of investing in renewable power is good news, particularly when we realize how far we have to go. However, it is also worth asking what did we buy with those investments.  This article does not answer that except mentioning towards the end that 36 GW of wind capacity was added 2010. It turns out that globally about 92 GW of renewable energy capacity was installed renewables; 30 GW of large hydro, 17 GW of PV, a smaller amounts of solar thermal and geothermal systems.  The world also added a comparable capacity of coal- and gas-fired plants in 2010.  China alone added 80 GW of coal and India added about 20 GW.  Because of their higher availability factor, they are expected to provide two to three times more electrical energy for the comparably sized fleet of renewables.