Archive for electric grid

New York’s Energy Highway: Public Comment until July 31

In his 2012 State of the State address, Governor Andrew M. Cuomo put forward an initiative to upgrade and modernize New York State’s electric power system.  The goal is to systematically plan new electricity generation and transmission in the state with all the relevant government agencies and private developers at the table.

The first stage of the proposal was a request for information about proposed generation and transmission from developers, utilities, and interest groups.  These responses are in, and are shown on these maps:

NY Energy Highway Transmission

Ny Energy Highway Generation Map

The Energy Highway taskforce will be taking comments from the public on these proposals until July 31, and issue an action plan based on all the information received sometime this fall.

More information is available at the NY Energy Highway website.

You can submit comments here.

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Colorado House Bill 10-1001 Passes Senate: Will Raise Renewable Energy Standard to 30% by 2020

This article was written before the HB10-1001 passed the Senate on March 5, and so focuses on the arguments for and against. Read on, and you’ll see why I think the passage was a good idea. I’m publishing now without updating what follows because it looks like I’ll be the first to break the news. Please bear with any typos, my proofreader has not had a chance to see this yet. The full text of the bill is here. All that is needed to pass this bill into law is for the House to approve minor amendments made in the Senate, and Governor Ritter’s signature. Neither is expected to be a barrier to adoption.

Tom Kornad, Ph.D.

Colorado has a good chance of increasing the requirement for electricity from renewable sources for the second time since I’ve been blogging here. When I moved to Colorado in 2005, the state had recently passed the first renewable energy standard (Amendment 37 or A37) to be directly approved by voters in the United States. A37 required that the state’s investor owned utilities (Currently Xcel Energy (XEL) and Black Hills (BKH) to produce 15% of their electricity from renewable sources, with a small set-aside for solar and residential solar by 2020, 15 years in the future at that time.

The reason A37 was voter-approved was not because the state was trying to capture some "first" but because of steadfast opposition in the Colorado Legislature from many of the state’s leading politicians. As of April 2009, Xcel was getting, 10% of its electricity from non-hydro renewable generation (mostly wind), and the cost of that achievement has been a surcharge (called the RESA or Renewable Electricity Standard Adjustment) on our electric bills of 0.6% until after the first doubling of the RPS, and stayed at 1.4% for at least a year after the first doubling. The the current House Bill 10-1001 (HB1001) raises the standard to 30% without raising the statutory cap on the RESA, although the full 2% will most likely to be needed. Yes, our transition to clean energy costs money, but it is altogether lower than the costs caused by constant fluctuations in natural gas and coal prices.

Andrew Winston, in the Plenary address at this year’s Sustainable Opportunities Summit the next day described the debate currently going on on in Washington DC as surreal. He likened Climate Change to a bunch of people in a house where one room is on fire. The current discussion at the international level he thought was analogous to debating about who started the fire and who should put it out. The debate in Washington, DC, he likened to debating if the room is actually on fire.

The debate in Colorado is often similarly surreal. The opposition to the bill, which came more from committee member Lundberg rather than the people who testified, centered on cost. Keep in mind that the cost is capped at 2% of electric bills… if the target cannot be met within this cost, the target will not be met. More intelligent (if not completely accurate) opposition came from the Oil and Gas industry. Officially, they were neutral on the bill, but opposed it on the ground that wind in Colorado has not reduced pollution in Colorado, because wind variability has forced existing coal plants to ramp up and down faster than they were designed to do. This makes them run less efficiently, and emit just as many pollutants such as SOx, NOx, and particulates, even though they are producing less power. Further, there are plans to close most of these coal plants by 2017.

The oil and gas argument about a lack of reduction in pollution from coal plants is more serious than the cost argument, but still does not stand up to scrutiny. First of all, they are focusing on conventional pollutants, not Greenhouse Gasses, which are what we are most concerned about. More importantly, there are already a couple of factors in place which will help to mitigate the problems which cause the quick ramping to diminish. I just recently wrote about better predictive software which allows utilities to predict wind production much more effectively. What forces Xcel to ramp their coal plants quickly is not that wind power is variable so much as the fact that the utility gets surprised by quick changes in wind output. When a utility knows that wind ouput is going to rise by 100MW an hour ahead, they can start lowering the output from their coal plants slowly in the time, and replacing that power with power from natural gas, which can ramp up and down much more quickly.

Second, as we get more renewable electrity on the system, we will also have more diverse electrity sources on the system. Right now, most of the wind farms in Colorado are located in the Northeast of the state. This clustering is because that corner of Colorado not only has a good wind resource, and also has available existing transmission lines to bring the wind power to the load centers in Denver and the Front Range. That means that wind power production in Colorado is mostly a function of the wind in Northeast Colorado. The lesson here is not that we should not add more renewable electricity to the grid, but that as we add non-wind renewables, and wind in other parts of the state. Adding large wind farms in other parts of the state requires new transmission. The main barrier against new transmission is not cost, but the difficulty of permitting and the time it takes to build. But Colorado is working to overcome this barrier by looking ahead and and planning the transmission we need for wind and other renewable resources ahead of time. I wrote about a report that came out of this process and the cost of transmission a couple months ago, and some new projects are alredy well into the planning stages.

Other renewables are not at all correlated to the existing wind power in the Northeast of the state. Solar power is also variable, but it forms a natural complement to wind, because wind in Colorado tends to peak at night in the winter, while sun is most abundant during the day in the summer. Other renewables such as cofiring biomass, such as a recent project from Colorado Springs Utilities, are baseload power, and small hydropower has some variablity depending on stream flows, but it is completely uncorrelated with wind.

Just like in a stock market portfolio, a diversified portfolio of energy sources leads to a less variable and more stable grid. Diversified energy sources not only means power from a variety of sources, but also geographic divesity. HB1001 has a 1.5% set aside for Distributed Generation (DG), which means (in the context of this bill) renewable generation that does not require new electricity distribution facilities. By definition, DG will not be big wind in the Northeast corner of the state. Much of it will be solar, bit it also opens the field to small scale biomass, hydropower in water municipal water and sewage systems, and biogas electricity from anaerobic digestion. There was some opposition to this set-aside from interests that worry that building any renewable generation other than big wind would cost too much, but this set aside is an investment in diversification. Yes, many of these diverse resources cost more now than large wind turbines, but they are an investment today in establishing new industries and technologies which can then get to a scale where they can contribute to a diverse and more robust electric grid.

If the financial crisis taught us anything, it should have taught us that a single-minded focus on short term return and projections from complex models, leads to fragile financial systems. A single-minded focus on electricity generation that has the lowest cost similarly leads to a fragile electric grid. Utility least cost planning is driven by cost models for the price of each form of generation, and models for the prices of the fuels which go into them. We need to acknowledge that our models have been flawed in the past, and will continue to be flawed in the future. Predictions of fossil fuel prices are more often wrong than right, and even the projections of the cost to build generation are often wrong as well.

Since we know that the cost models are wrong, but we don’t know how they are wrong, it makes sense to make sure that we invest in electric resources that may not appear to be lowest cost when we run them through those models, but which add diversification and resilience to our electric grid in preparation for the day when the models fail. That day does not have to be a catastrophe like the financial crisis, but a crisis is more likely if we put all our faith in least cost modeling and don’t want to pay an extra 2% for renewable energy insurance.

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Better Software Enables Better Wind Integration

A year ago, I wrote an article about the Dumb Grid, complaining that the reason that many utilities find wind power so hard to integrate is because they aren’t using any brains. I used the infamous Feb 2008 incident when wind power in Texas dropped right as demand picked up because of a cold front to make my case: Both the rise in demand and the drop in wind power were predictable consequences of the cold front, but the ERCOT controllers were not using that weather information in their dispatch planning. Hence, the problem was not wind power or even the cold front: it was failure to use the available information.

Fortunately, things are much better today. There’s an excellent article on Power-Gen Worldwide about the Texas electric grid’s control center two years later. Here’s an excerpt about how they deal with wind variability today:

    The wind resource is more manageable now that ERCOT has wind resource forecasting software at its disposal. […]

    ERCOT has begun using forecasting tools from AWS Truewind to help it manage wind energy resources. In the coming days ERCOT will begin using a ramping tool, from the same vendor, to improve its forecasting of wind resource ramping events. Just a week before our visit, the AWS Truewind software–operating in a test mode–predicted a 2,000 MW drop in wind resource followed 15 minutes later by a 2,000MW recovery. The predicted ramp event matched the actual event almost perfectly.

    Joel Mickey told me that ERCOT is happy to dispatch as much wind energy as is available.

Thanks to Micheal Giberson over at Knowledge Problem for bringing this article to my attention.

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The Cost of Transmission

Tom Konrad, Ph.D.

I’ve been reading a report out of the Colorado Governor’s Energy Office called The REDI Report: Connecting Colorado’s Renewable Resources to the Markets in a Carbon-Constrained Electricity Sector.  I summarized the REDI report’s main conclusions and drew some conclusions for stock market investors here.

I found the report’s discussion of transmission costs particularly interesting, because I’ve had trouble finding numbers for the cost of transmission in the past.  I once resorted to Wikipedia in order to find costs for transmission when comparing them to the costs of large scale electricity storage.  If you don’t think that the two are comparable, consider that long distance transmission can reduce the net variability of wind and solar, making it possible to integrate these renewable forms of generation without the cost of expensive storage.  That’s why even net-zero electricity homes are connected to the grid: it’s prohibitively expensive to buy enough batteries to keep the lights on 24/7.

Here are a couple cost charts from the report:

I took the data from the above table, and plugged it into my spreadsheet comparing the costs of electricity storage.  Below are the updated graphs (click for enlarged versions.)  The notation "2-500 kV AC" means a Double-circuit 500 kV AC line.  As in the storage comparison, I computed the costs and round-trip electricity losses for a 1000 mile line, since that was the example I used in my original Transmission/Storage comparison.

 

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Is There a Tradeoff Between Economics and the Environment?

Tom Konrad Ph.D.

California’s RETI process lends insight into the near-term prospects of Solar, Wind, Geothermal, and Biomass.  

In September, California’s Renewable Energy Transmission Initiative (RETI) released their Phase 2A report, which outlined potential transmission corridors to collect renewable energy from Competitive Renewable Energy Zones (CREZ) that had been identified in previous phases.  As part of Phase 2A, they also screened each CREZ for environmental impact, and the potential difficulty of obtaining land for renewable energy development.  

I previously looked at the results from Phase 1A and gained some insight into the cost of renewable energy technologies.  However, what renewable energy projects actually get built has to do with a lot more than just economics.  If it raises too many environmental concerns, such as infringing on endangered Mojave Ground Squirrel habitat, it isn’t going to get built.

Drawing on the spreadsheet "Supplemental Materials, CREZ Data" I put together the following charts, graphing the economics of each type of renewable energy in each CREZ against the expected environmental impact of that CREZ.  

Each circle represents one type of renewable energy at one of 35 CREZs.  Concentric circles in different colors appear where a single CREZ offers multiple types of renewable energy development.  The only difference between the two graphs is the size of the circles.  In the first graph, circle sizes represent the potential annual energy production (GWh/yr) of a CREZ, while circle sizes in the second shows power rating (MW.)  Geothermal and Biomass resources are relatively larger in the first graph because these are typically baseload technologies generating electricity near peak capacity all the time, while solar and wind are variable.

The cluster of circles in the middle right represent resources outside California: they were not rated for environmental concerns, so I assigned them an arbitrary value in the middle of the range in order to display them on the charts.

Economic/Environmental Tradeoff?

I found it surprising that there is little evidence of a tradeoff between economic viability of CREZ’s and environmental impact.  In fact, the circles in the graphs above are generally clustered along a line from the lower left (high environmental impact, bad economics) to the upper right (little environmental impact, good economics).  A tradeoff between economic viability and environmental concerns would manifest itself in a clustering along a line from the upper left (bad economics, little environmental impact) to the lower right (good economics, large environmental impact.)

Considering these four major renewable energy technologies, as they might be deployed in California, there is no real tradeoff between economics and the environment.  The best economics coincide with the least environmental impact.  If we were to include energy efficiency in the analysis, the trend would be even more pronounced: energy efficiency has the best economic profile of all, yet avoids the use of energy and hence does less harm to the environment.

The exception here is biomass.  The small green dots don’t show a pronounced trend in any direction, meaning that there may be some tradeoff for biomass.  Such a tradeoff would not be surprising, because harvesting plant matter on a large scale is bound to have significant ecosystem impacts.  Note that Biomass here does not include such technologies as waste to energy, which can be environmentally benign, or even an improvement compared to land filling.  In this study, the biomass in remote regions that do not yet have transmission, since lack of sufficient transmission was one of the requirements to be a CREZ.

With clean energy, it may actually be possible to do well while doing good.

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“Heretic” Battles Straw Man

Energy Self-Reliant States [pdf], a flawed study on local Renewable Energy availability from the Institute for Local Self-Reliance (ISLR) found that 18 of the 50 states could not meet their electricity needs with local renewables.   In fact, no state can meet its electricity demand through local renewables without expensive electricity storage.  On a national basis, such storage would cost an estimated $13 Trillion, or over 65 times the cost of the transmission investments they oppose.

by Tom Konrad, Ph.D.

Straw Man: "Transmission is Only for Utility Scale Renewables"

Image: GE Smart Grid Scarecrow (video)

One of the study authors, John Farrell, has been promoting the study as a "Heresy on Transmission."  Rather than a heretic attacking misguided establishment shibboleths, this flawed study attacks a simplistic misunderstanding of why we need transmission.  Farrell and his co-author David Morris are either intentionally promoting this misunderstanding as a straw man, or if they simply fail to grasp the reasons behind long distance transmission’s necessity.

Their straw man is the false choice between states relying on local renewables such as PV on rooftops which supposedly would require only "minimal transmission upgrades" and far-off wind farms requiring expensive long distance transmission.  They say, for example,

[I]f Ohio’s electricity came from North Dakota wind farms — 1,000 miles away — the cost of constructing new transmission lines to carry all that power and the electricity losses during transmission could result in an electricity cost to the consumer that is about the same, or higher, than local generation with minimal transmission upgrades.

This ignores most of the benefits which would flow from new transmission lines connecting North Dakota and Ohio.  A 1,150 mile transmission line from Bismark to Cincinnati would also connect Fargo, Minneapolis, Eau Claire, Madison, Chicago, and Indianapolis running along Interstate Highway corridors (Google maps.)  It also ignores the study’s own finding that Ohio would only be able to generate 29% of the electricity it needs with local renewables. 

Incidentally, their national map shows Ohio being able to generate 33% of its electricity from local renewables, but adding up their own numbers for the renewables they identify gives 29%.  I looked closely at their numbers for only six states, so there may be other arithmetic errors as well.

The states along this hypothetical route are North Dakota, Minnesota, Wisconsin, Illinois, Indiana, and Ohio.  The study found that these states can generate the following percentages of local demand with in-state renewables:

State %Wind % Solar % Small hydro % CHP Total
North Dakota 14,000% 19% 1% 4% 14,024%
Minnesota 1,311% 24% 1% 4% 1,340%
Wisconsin 120% 22% 1% 5% 150%
Illinois 57% 17% 2% 4% 80%
Indiana 83% 18% 1% 3.6% 106%
Ohio 3% 20% 1% 5% 29%

If each of these states attempted to meet their local electricity needs with the renewables in the study, Ohio and Indiana would still need to import some electricity from other states.  Although Ohio would not need to import power from as far away as North Dakota, they would have to tap into Minnesota’s wind resources if demand were to be satisfied along this corridor.  An attempt to meet that demand with the nearest resources might look like this:

State %Wind % Solar % Small hydro % CHP Total
North Dakota 300% 2% - 2% 304%
Minnesota 150% 10% 1% 2%   163%
Wisconsin 120% 22% 1% 5%   148%
Illinois 57% 17% 2% 4%  80%
Indiana 83% 18% 1% 3%   105%
Ohio 3% 20% 1% 5%  29%

You’ll note that the total above exceeds 600% because the states with renewable energy surpluses have much lower local demand.  The magnitudes of this demand are my best guess.  Keep in mind that I did not choose this corridor to make my example work; the suggestion came directly from the transmission example in the study.

The Consequences of Timing

By the study’s own methodology, both Ohio and Illinois need interstate transmission, because they cannot generate all their renewable electricity locally.  Yet, as I will demonstrate, even though North Dakota and Minnesota would be generating electricity for export, they will often need to import renewable electricity as well.  

Using the Correlation Maximization tool on Energy Timing (note: Energy Timing has been taken down, see comment here.), I generated the best portfolio of North Dakota wind and solar farms to meet the needs of Square Butte Electric Coop, an electric utility in Grand Forks, ND.  The results are shown below:

Composition of Optimal Portfolio of North Dakota Renewable Energy:  ND Optimal Portfolio

  Site Name Type Optimal Weight Capacity Factor
1) Olga 5, ND Wind 63% 21%
2) Pickert, ND Wind 19% 38%
3) Valley City, ND Wind 18% 22%

 

Normalized Diurnal ND wind and demand.png

This combination of three wind farms represents the best fit between electric output from existing wind farms and solar sites in Energy Timing’s database, and local demand.  Even though this is the best fit, the correlation between supply and demand is only 13.2%.  Solar sites do not appear in the optimal portfolio because they do not lead to a better fit.

As you can see from the bottom graph, wind output is strongest in the morning, when demand is relatively low, and falls off in the afternoon, as demand rises.  Hence, unless North Dakota builds far more wind farms than it needs to supply local demand (an expensive proposition which could only be justified by electricity exports), they would not have enough electrify in the afternoon and early evening, when the wind typically dies down.  This would be the situation on a typical day.  On any given day, wind power is even more variable than it is on average, leading to large and frequent swings from oversupply to undersupply.

Composition of Optimal Portfolio of Minnesota Renewable Energy:  MN Optimal Portfolio

  Site Name Type Optimal Weight Capacity Factor
1) International Falls, MN Solar 37% 17%
2) Minneapolis, MN Solar 34% 20%
3) Rochester, MN Solar 23% 19%
4) Duluth, MN Solar 6% 18%

 

Normalized Diurnal MN Solar and demand

In the case of Minnesota electrical demand, solar sites turn out to be a better fit than wind sites.  In reality, if Minnesota were to attempt to meet local demand with renewable energy, a mix of wind and solar sites would be used, since wind is so much less expensive than solar.  But since solar sites are the best fit for local demand, a mix of wind and solar would produce a worse match than the 24.5% correlation we see in the scenario above.

Benefits of Transmission

We can now see how both Minnesota and North Dakota would benefit with a high capacity transmission connection between the states.  In the early morning, before the sun rises, Minnesota will not be producing any domestic renewables, so it makes sense to import electricity from North Dakota, where production is far in excess of demand all morning.  Minnesota will in turn be able to supply excess solar power to North Dakota in the afternoon before the sun gets low and cuts solar output.  

In short, even though both Minnesota and North Dakota can easily produce enough local renewable electricity for their needs, the timing of that electricity causes problems of both oversupply and unmet demand.  If we build transmission connecting states regions, these problems are reduced, and less storage is needed to make up the difference.

As we increase the interregional connections, we will be able to bring in power from farther afield that better meets demand.  For instance, both these states don’t have enough local renewables in the evening, even when combined.  The worst period is just around dusk, from about 5pm to 8pm Central time, before the wind begins to pick up at night in North Dakota.  But in the sunny Mojave Desert of southern California, the sun is still up (it’s two hours earlier, Pacific Time), and large Concentrating Solar Power (CSP) plants can use relatively cheap thermal storage to continue producing power for hours after sunset.

We can also see that both North Dakota and Minnesota typically have spare production capacity in the summer months, so they could export electricity back to the Southwest during these months, when Southwest electricity demand peaks due to air conditioning loads.

As we increase the length of regional transmission networks, each state along the path gains, both as an electricity exporter and as an importer depending on the season and weather conditions.  Ohio does not need to pay for giant transmission lines from North Dakota to import which "could result in an electricity cost to the consumer that is about the same, or higher, than local generation."  North Dakota, Minnesota, Wisconsin, Illinois, and Indiana would also benefit from such a line, and all could be asked to contribute.

Costing Storage vs. Transmission

The study’s authors also invoke electricity storage to "solve" the problem of timing, saying

Some renewable fuels, like sunlight and wind, are variable.  Thus, the estimates, especially for wind, assume a significant level of storage or on-demand distributed generation.

Unfortunately, they make no attempt to account for the price tag of such storage.  They state only, 

This report does not examine storage and its implications, but in our analysis of variable renewable energy potential, we assume that sufficient storage is available.

"On-demand distributed generation" could come from natural gas or biomass.  Renewable generation relies on the availability of the natural resource, few of which can be stored.  Even incremental hydropower is typically not on-demand, because it is usually the result of adding generation to existing dams and comes with obligations to maintain flow rates.

Biomass based power is typically baseload, not on-demand.  Furthermore, the study authors explicitly rule out the large scale use of biomass for electricity because they expect the amount of biomass-based electricity to be "modest."  Even if large scale, on-demand distributed biomass based generation were available, it would only be available in those states with a large biomass resources.  See the map below.

Natural gas is an incomplete response to climate change in that it is a fossil fuel, may not even be available in the necessary quantities, and must be imported by the vast majority of states.  What is the point in pushing for reliance on locally generated renewable electricity if it only increases our dependence on imported natural gas which may not be available and produces greenhouse gas emissions? 

Given the not only daily, but seasonal mismatches between local electricity production and demand, states which are locally self-sufficient in electricity would have to invest in a month or more worth of storage.  While electric vehicles may be able to provide some daily or hourly storage, they will not be available for seasonal electricity storage, since the vehicle owners will need to drive them, and so cannot keep them fully charged for months or even days on end.

The cheapest large scale electricity storage solutions, (Pumped Hydropower, Compressed Air Energy Storage, and Molten Salt Thermal Storage) typically cost $10 to $50 per kWh of storage.  Unfortunately, all three of these options are limited in where they can be located, so restricting transmission will also restrict the use of these cheaper forms of storage.  The cheapest battery and flow battery storage technologies cost about $100 to $150 per kWh.  To be generous, I will assume that all states can build as much electricity storage as they want at $50 per kWh, or $50,000 per MWh.  I will also assume that geothermal, hydropower, combined heat and power, and efficiency gains will mean that solar and wind will need to supply only 50% of our current electricity usage. 

According to the Energy Information Administration, total electricity production in 2007 was 4,156,745 thousand MWh.  An average monthly production was thus 346,395,000 MWh, and the cost of a month’s worth of national electricity storage to meet half of a month’s demand would be $8,665 Billion under the assumptions above.  In contrast, the ILSR study states that "FERC, Congress, and environmental groups… rush to accelerate the construction of a new $100-$200 Billion interregional transmission network."  

If such a network cost $200 Billion, and reduced the need for storage by only 10%, then it would have paid for itself more than eight times.  Given less conservative (and I think more realistic) assumptions of reducing the need for storage by 50%, and a per MWh cost of storage of $75,000, a regional transmission network would pay for itself in reduced storage needs by 65 to 1.

Conclusion

To me, 65-to-one, or a savings of approximately $13 Trillion, seems worth the price of stringing wires.  For comparison, $700 Billion has been spent on the war in Iraq since 2001.  In other words, the ILSR study is suggesting that we pay for eighteen wars in Iraq in order to avoid building an interregional transmission network, costing about as much as we spent in Iraq in 2008. 

In fact, the price for local self-reliance on renewable energy would likely be higher.  Thirteen trillion dollars does not include the cost savings that the report’s authors tried to address: Transmission allows us to exploit less expensive renewable generation.    Furthermore, the variability of both wind and solar generation can be vastly reduced by combining the output of dispersed wind and solar farms.  Less variability reduced the need for costly spinning reserves to stabilize the grid if wind power suddenly drops or a cloud passes above a solar farm.

Not all self-styled heretics are fighting a just cause against an oppressive consensus.  To the extent that a consensus exists in favor of an improved national transmission grid, it is based on sound science and economics.  It is unfortunate that so many environmentalists are seduced by the mirage of renewable energy self-reliance.

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Market Predictions

Predicting market moves is notoriouslly difficult, but I’m feeling pretty good about my recent efforts.
On October 11, 2008, I stoped being a permabear and said, “the market as a whole now seems to me to be fairly valued.” The S&P 500 closed the previous Friday just below 900; today it closed at 919.32. In the fear that abounded last October, it was a hard call to be even that bullish, bit it seems to have worked out.

On June 2, I said we were near a market peak/ The S&P 500 closed that day at 944.74, and is currently down 3% almost a month later, having only bearly exceeded that number by a fraction of a percent.

Since I’m currently short-term bearish, I’ve started a series of articles not to by now, but to buy when a market decline puts them back on sale. Here are may clean enrgy shopping list articles so far:

  • Transmission stocks
  • Energy Efficiency Stocks
  • Clean Transport Stocks
  • Why market timing makes sense
  • Two Landfill Gas and Three Geothermal Stocks
  • Five Solar Stocks
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