Why We Need CCS, Part 4: Carbon Negative Solutions

Highlights

• The economic growth ambitions of the developing world combined with the very tight carbon budget prescribed for the 2 áµ'C scenario could potentially demand a very large deployment of carbon negative solutions from the middle of the 21st century.
• CCS is the best candidate for achieving negative CO2 emissions - both in the form of bio-energy with CCS and direct air capture. 
• Extensive modelling studies performed by the IPCC show that removal of this option makes the achievement of the 450 ppm scenario much more expensive or even impossible. 

Introduction

As discussed in a previous post, CCS is likely to play a very important role if climate science is eventually proven correct and long-term atmospheric CO2 concentration levels of ~450 ppm are confirmed as a top global priority. The possible role of CCS retrofits to the very young fleet of fossil-fueled industry currently being built in the developing world was discussed as a medium-term possibility in the case where CO2 prices rise very rapidly in the next decade. Given the massive coal-fired push towards economic growth in the developing world and the very tight CO2 budget related to the 450 ppm scenario, however, this is unlikely to be sufficient.

Indeed, with every passing year of much climate talk and little climate action, various agencies around the world adjust their 2 áµ'C scenarios towards something that looks even more unrealistic than the previous iteration. The most recent of these scenario analyses comes from the IPCC where it was flatly stated that many models could not achieve the 450 ppm scenario if CCS is eliminated as an option. And a substantial portion of the projected CCS impact comes in the form of carbon negative solutions resulting in net-negative emissions from the electricity sector starting mid-century (see below).

Carbon negative solutions

Taking CO2 from the air is quite a lot more difficult than putting it there, but, as shown in the figure above, almost all 450 ppm scenarios require large net-negative emissions from the electricity sector towards the end of the century. The IPCC assigns this responsibility to bio-energy with CCS (BECCS), but also mentions direct air capture as an option.

Naturally, there is great uncertainty tied to BECCS, primarily related to the feasibility and impact of building out bio-energy on such an enormous scale. However, if it eventually turns out that the 450 ppm scenario is indeed a vitally important target for the future of the planet, we will have little choice other than making this work.

CCS rollout

The amount of emissions mitigated by CCS in various scenarios producing long-term CO2 concentrations in the range of 430-530 ppm is shown below. A rapid upscaling is clearly visible with the storage rate in the year 2100 being close to the entire energy-related emission rate of today - a rather incredible expectation.

The ~3 GtCO2/yr storage rate in 2030 might not look very impressive in comparison, but the enormity of this upscaling effort becomes evident when compared to the large subsidy-driven renewable energy rollout in recent years. For example, wind energy has expanded at a very impressive 30% CAGR over the past 15 years, but, as shown below, currently avoids only about 0.235 GtCO2/yr - more than an order of magnitude less than is expected from CCS within a similar timeframe under the 430-530 ppm scenario. (CO2 mitigation from wind is calculated under the assumption that wind displaces natural gas at 0.45 tCO2/MWh and that additional emissions associated with embodied energy, fossil fuel balancing and the rebound effect are negligible.)

Cost implications

The IPCC details several mitigation scenarios which deviate from the "all of the above" baseline case. The difference in total mitigation costs relative to the baseline scenario for these different scenarios is given on the left in the figure below.

It is clear that the "No CCS" scenario results in the biggest cost increase among 450 ppm scenarios, followed by the "Limited Bioenergy" scenario. It should also be noted that many of the "No CCS" model runs could not achieve the 450 ppm scenario.

One of the reasons given for the substantial cost increase caused by these two mitigation scenarios is the absence of BECCS (negative emissions) in the second half of the century. In comparison, the "Nuclear Phase Out" and "Limited Solar/Wind" scenarios show very small cost increases relative to the baseline because they are limited to the electricity sector and cannot achieve negative emissions.

It should also be noted that the above left figure is generated under highly idealistic assumptions of a global least-cost climate change mitigation effort starting immediately. Under more realistic assumptions regarding delays in climate action and regional differences in ambition, mitigation costs increase further (as shown on the right in the figure above) and model predictions become increasingly dependent on large negative emissions from CCS in the second half of the century.

Conclusion

The role of CCS is increasingly becoming more clearly defined as an insurance policy against the scenario where climate science actually turns out to be correct. This climate insurance can potentially be claimed through retrofits to the enormous new fleet of fossil-fueled infrastructure still being rapidly deployed in the developing world and through the carbon negative solutions of bio-energy with CCS and direct air capture.

Even though the existence of this insurance policy can make the potentially catastrophic longer-term effects of climate change appear less daunting, it should not be relied upon too heavily. An enormous push towards carbon negative solutions towards the middle of the century is likely to be unnecessarily expensive and potentially environmentally destructive due to the enormous amounts of bio-energy that will be required. We can make things a lot easier for ourselves by establishing a true technology-neutral CO2 mitigation policy framework sooner rather than later.

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Schalk Cloete

I am a research scientist searching for the objective reality about the longer-term sustainability of industrialized human civilization on planet Earth. Issues surrounding energy and climate are of central importance in this sustainability picture and I therefore seek to learn more from the Energy Collective community. My current research focus is on second generation CO2 capture processes ...

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YieldCos Could Cut Renewables Costs by 20%, Study Finds

Financial innovation has unlocked distributed solar and helped to drive down costs in recent years, but there is also ample room for new investment vehicles for large-scale wind and solar, according to a new study.

Widespread use of YieldCos should allow for wind and solar costs to drop by more than 20 percent compared to current project finance models, according to the Climate Policy Initiative’s paper, Roadmap to a Low Carbon Electricity System.

YieldCos earn cash flows based on real assets and then issue the earnings in dividends, offering a high yield to investors and lower-cost capital for renewable energy projects. There have been various YieldCos launched recently, including offerings from NRG Yield, Greencoat Energy, Pattern Energy and Nextera YieldCo.

The limitations of utility financing

Funding renewable energy projects is just one issue that utilities face, and potentially not even the most pressing one. From transmission and distribution investment to system balancing and market operations, nearly every area of the utility business model is ripe for transformation.

The research from Climate Policy Initiative found various reasons why utility financing is not well suited to renewable energy projects. “The current model is adapted from financing fossil fuel assets,” said Uday Varadarajan, senior analyst with Climate Policy Initiative. “Those assets have a very different profile of risk and reward.”

Solar and wind projects do not have the same operational risks, nor do they have the fuel risk of fossil fuel plants. “We should not be paying industries a high premium for operating a lower-risk asset,” said Varadarajan.

Most utility-scale renewable energy projects are funded either through project finance, when a developer sets up a project company that can borrow money against the cash flows from the project, or through an investor-owned utility or independent power producer using its own equity and borrowing power to finance the project.

In 2013, $279 billion out of the total $359 billion for all low-carbon investments, including renewable energy, energy efficiency, electric vehicles and other projects, came from balance sheet financing or project-level financing, according to CPI. 

Growing pains for YieldCos

The paper was bullish on the ability of YieldCos to drive down the cost of large-scale renewables, but it also outlines various challenges that persist for YieldCos in the renewable market. “Are there going to be enough PPAs to really support continued growth of the YieldCo market?” asked Varadarajan. “Are we going to get the institutional investors biting on these?”

Many of the limitations could be growing pains, since YieldCos for renewable energy are relatively novel. Although some issues could work themselves out in coming years, CPI outlined four features that a YieldCo must have:

1. Provide highly predictable, long-term cash flows. That includes paying out nearly all of the free cash generated from underlying projects to YieldCo owners, rather than retaining a substantial portion to invest in new projects, owning a diversified set of projects and investing in operational assets.
2. Provide liquidity in the investment. The YieldCo should be exchange-traded and have a large set of investors that attracts financial sector analysis.
3. Provide investment at low fees. CPI notes that one of the drawbacks seen by institutional investors with many current YieldCos is their high costs and fees.  
4. Become established as part of the portfolio of options for institutional investors. In many ways, this is a growing pain, but YieldCos need to work with investors, as well as financial regulators, to develop the YieldCo as an asset class.

“Maturity could deal with most of these issues,” said Varadarajan, adding that ideally, YieldCos could spin off closed funds. To help YieldCos mature more rapidly, there could be a role for green banks, such as those in Connecticut or New York, added Varadarajan.

Another question for YieldCos is whether they could be one of the vehicles to unlock the mid-tier market of renewables that are smaller than utility scale but larger than residential. “The thing about YieldCos is they have to be very large,” Izzet Bensusan, founder and CEO of Karbone Group said at the Renewable Energy Finance Forum Wall Street on Wednesday. “That means you have to go really broad [in project selection] to live up to your investors' expectations.” 

A role for municipalities?

YieldCos could play an interesting role in utility-scale renewable projects in coming years, but there is also a potential role for municipalities, CPI found.

“Wind and solar are really bond-like investments,” said Varadarajan. “You could certainly see municipal bond financing” for renewable projects.

He pointed to Los Angeles Department of Water and Power’s prepaid power-purchase agreement for wind power from the Milford Wind Farm in Utah that used Southern California Public Power Authority and municipal tax-exempt bonds.

The approach could be more attractive in Europe, he noted, but it is certainly possible in the U.S. “Unlike institutional investors, municipalities could invest directly in renewable energy projects without the liquidity concerns, much as they invest in infrastructure,” the study authors wrote.

Municipal financing could also be supported by infrastructure or green banks, where smaller municipalities would be able to access capital.

The report focuses on large-scale renewable projects, but there are other areas where market and financial innovation are needed. Although YieldCos may not directly finance other assets, such as grid-balancing technologies or energy efficiency, “YieldCos could be a Trojan horse for the rest of this,” said Varadarajan. “YieldCos and a demand-side shift are coming. The rest will follow because it’s a rational investor response.”

Greentech Media (GTM) produces industry-leading news, research, and conferences in the business-to-business greentech market. Our coverage areas include solar, smart grid, energy efficiency, wind, and other non-incumbent energy markets. For more information, visit: greentechmedia.com , follow us on twitter: @greentechmedia, or like us on Facebook: facebook.com/greentechmedia.

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Our Comment in Nature Calling for Oil Sands Moratorium

Here is the press release for our Nature paper, released June 25, calling for a moratorium on oil sands expansion. This means no loss of current jobs in the oil sands. But it does mean a return to sanity from this selfish rush to accelerate global warming, ocean acidification and ecological destruction - events that will lead to huge economic and social costs according to a just-released study by the World Bank. It does mean that we should not build new pipelines like Keystone XL, Northern Gateway and others.

Press release:

Scientists call for a Halt to Oil Sands Expansion Until Policies Address True Costs and Global Impact.

A Comment published today in the journal Nature calls for a moratorium on new oil sands projects in Alberta, Canada due to flaws in how oil sands decisions are made. The authors are a multidisciplinary group of economists, policy researchers, ecologists, and decision scientists. They argue that the controversy around individual pipelines like Keystone XL in the US or Northern Gateway in Canada overshadows deeper policy flaws, including a failure to adequately address carbon emissions or the cumulative effect of multiple projects. The authors point to the contradiction between the doubling of the rate of oil sands production over the past decade and international commitments made by Canada and the US to reduce carbon emissions. “The expansion of oil sands development sends a troubling message to other nations that sit atop large unconventional oil reserves,” said lead author Wendy Palen, Assistant Professor at Canada’s Simon Fraser University. “If Canada and the United States continue to move forward with rapid development of these reserves, both countries send a signal to other nations that they should disregard the looming climate crisis in favor of developing the most carbon-intensive fuels in the world.” The authors point out that oil sands development decisions (e.g. pipelines, railways, mines, refineries, ports) made in isolation artificially restrict public discussions. Debate in the news media and during hearings for individual projects are limited to evaluating the short-term costs and benefits to the local economy, jobs, environment and health, and do not account for the long-term and cumulative consequences of multiple projects or of global carbon pollution. Co-author Joseph Arvai, Professor and Research Chair in decision science at the University of Calgary, explained the problem. “Individual projects â€" a particular refinery or pipeline â€" may seem reasonable when evaluated in isolation, but the cumulative impacts of multiple projects create conflicts with our commitments to biodiversity, aboriginal rights, and controlling greenhouse gas emissions. Though we have the knowledge and the tools to do better â€" to more carefully analyze these tradeoffs and make smarter long-term choices â€" so far governments have not used them.” A moratorium would create the opportunity for Canada and the United States to develop a join North American road map for energy development that recognizes the true social and environmental costs of infrastructure projects as well as account for national and international commitments to reduce carbon emissions. Anything less “demonstrates flawed policies and failed leadership”, the authors state.

Contact:

Wendy J. Palen

Department of Biological Sciences

Simon Fraser University

Burnaby, BC, Canada

Thomas D. Sisk

Landscape Conservation Initiative

School of Earth Sciences and Environmental Sustainability
Northern Arizona University

Maureen Ryan

School of Resource and Environmental Management

Simon Fraser University

Joseph L. Árvai

Department of Geography

University of Calgary

Calgary, AB, Canada

Mark Jaccard 

School of Resource and Environmental Management

Simon Fraser University

Burnaby, BC, Canada 

Anne Salomon

School of Resource and Environmental Management

Simon Fraser University

Burnaby, BC, Canada

Thomas Homer-Dixon

Balsillie School of International Affairs

University of Waterloo

Waterloo, ON, Canada

Ken Lertzman

School of Resource and Environmental Management

Simon Fraser University

Burnaby, BC, Canada

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Mark Jaccard

Mark has been professor in the School of Resource and Environmental Management at Simon Fraser University, Vancouver, since 1986, which was only interrupted from 1992-97 while he served as Chair and CEO of the British Columbia Utilities Commission. His PhD is from the Energy Economics and Policy Institute at the University of Grenoble. Mark contributed to the Intergovernmental Panel on ...

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Some Energy System Home Truths

One point of note on the annual calendar of energy events is the release by BP of their Statistical Review of World Energy. The data, all available to download in Excel format, covers the period up to the end of the previous year (i.e. the current data is to the end of 2013) and as such is about 18 months ahead of the equivalent data from the IEA (which is currently up to 2011 but will be updated later this year). Just about anything you might want to know on energy supply, energy consumption, CO2 emissions, fossil fuel reserves etc, is there for the interested user. In recent years BP have updated the tables to include a more comprehensive look at renewable energy as well.

The most recent release by BP was just a couple of weeks ago, so here are a few key energy/climate home truths within it;

Global CO2 emissions just keep on rising: This is hardly a surprise, but given the recent burst of capacity from the renewable energy sector there might be some sign of some levelling off at least. OECD emissions are at least flat now, but non-OECD emissions continue to rise sharply as coal use increases in particular (chart below in millions tonnes CO2 per annum).

The global CO2 intensity of energy isn’t budging: This is a bit more surprising given the influx of natural gas into the global economy and the build rate of renewables. But coal continues to surge and quite some nuclear has been shut down in Japan. The chart below shows the OECD intensity falling as renewables take off in Europe and natural gas increases in the USA, but non-OECD intensity offsets this to give a flat picture overall (chart below is in tonnes of CO2 per barrel of oil equivalent).

The annual increase in fossil fuel use far exceeds the increase in renewable energy production: While many will readily quote the annual increase in renewable energy investment or annual increase in renewable energy capacity as evidence of turning the corner, the reality in terms of renewable energy produced is somewhat different. The chart below compares the annual coal increase with global solar and wind increases. For reference, the total fossil fuel increase from 2012-2013 was 183 Mtoe (million tonnes oil equivalent). The whole picture is rather distorted by the global financial crisis, but coal alone is increasing by something like 100-150 Mtoe per annum. At least for the last couple of years solar has been flat at about 7 Mtoe annual increase.

Solar and wind are growing rapidly, but the fossil fuel share of global primary energy is high and steady: Both solar and wind are in their early rapid growth phase where double digit annual increases are expected, but as they become material in the energy system at around 1% of global energy production, don’t be surprised to see this start to level off. The chart below has a log scale (otherwise solar and wind are barely discernible) and shows fossil fuel up in the mid 80′s as a percent of the global energy mix.

Even in Germany it is taking a while for solar to make a showing: While solar PV in Germany is having a profound impact on electricity generation on long sunny days in June, the annual story when looking at total energy use is different. Solar has reached about 2% of the mix (i.e. reached materiality) and might even be showing some signs of slowing up and growing at a more linear rate (but a few more years data are needed to see the real trend). Again, this is a log chart.

Thanks to BP for the time and effort they put into this work every year.

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Energy Quote of the Day: 'Utilities are Most Valuable When they Stay Invisible'

On the last day of this year’s 37th IAEE International Conference in New York a distinguished panel of experts, among them Ralph Izzo (Chairman and CEO of Public Service Enterprise Group Incorporated (PSEG)), Jigar Shah (Founder of SunEdison) and David Newbery (Director of Energy Policy Research Group (EPRG), University of Cambridge) discussed the profound challenges the traditional utility business model is facing from different vantage points with their own distinct points of departure. This session again encapsulated in miniature what made the entire IAEE conference on “Energy & The Economy” so invaluable; namely, it provided fertile grounds for the exchange of ideas between practitioners across the entire energy spectrum and academia in order to drive necessary future energy discussions further into the 21^st century.

Mr. Izzo of PSEG set the stage by identifying the three transformative forces to have a substantial impact on the traditional utility business model: changes in individual behavior, environmental protection, and technology. Obviously, all those perceived factors imply major investment needs without necessarily leading to increases in sales of electricity. The latter is a major headache for the industry given that utilities are traditionally paid on a kWh basis. In this context, Mr. Izzo pointed to the relative underinvestment in energy efficiency innovations/improvements, for example, in buildings compared to investments in solar in the last couple of years. “Germany has the lowest electricity bills because of energy efficiency improvements,” he added.

Picking up on utilities’ profitability concerns due to changing revenue streams Mr. Shah of SunEdison, a solar power and renewable energy solutions company, tried to draw a parallel to the cell phone evolution. Over time and due to technology advances as well as the right marketing strategy, customers started to get the perception that they receive embedded in their cell phones more value for their money. Consequently, they are now willing to pay much higher prices for their cell phone service than in the past if for nothing else than just the perception of some ‘value-added’. According to Mr. Shah, it is crucial for utilities to understand that power customers “value what comes from electricity, not electricity itself.” This is not different from what Mr. Izzo referred to as electricity having just an “implicit value/price” in the eyes of the public.

So, how do utilities secure enough revenue streams to attract low cost capital in order to make necessary infrastructure investments? Mr. Shah advocates for allowing as much innovation as possible on the customer side. He also inserted another interesting thought into the discussion; namely, that in the future the “vast majority of revenue [for utilities] will come from the unregulated area” comparing it to Verizon’s revenue composition. While in 1996 about 90 per cent of Verizon’s revenues, according to Mr. Shah, originated in the regulated area, its revenues now come predominantly from the unregulated area.

Meanwhile, Professor David Newbery of the University of Cambridge stressed from an energy security perspective the benefits as well as the need of energy market coupling in order to spur investment into the energy sector following the straightforward logic that de-risking will lower the cost of capital. “Interconnections in capacity markets increase the security of supply, provided they are free to respond to scarcity. If this is so, this should displace domestic reserve capacity,” he noted.

In sum, one thing is clear whether customers pay in the future performance-based rates â€" i.e. utilities satisfying certain reliability metrics and thus de-linking it from investment â€" or for some kind of ‘value-added’ in utilities, they will have to pay more for electricity due to externalities in energy markets. At this point, Mr. Izzo’s previous comment on energy efficiency becomes even more important. Most customers of utilities would love to not think about their utility bills and would generally agree with Mr. Izzo’s view that “utilities are most valuable when they stay invisible.” Note, however, that Mr. Izzo’s point of departure here is the constant attempt by utilities to strike a balance between the optimization for their customers and their shareholders. As he acknowledged himself, today a shift in the direction of the latter is visible.

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Authored by:

Jared Anderson

Jared Anderson, Managing Editor at Breaking Energy, covered international oil and natural gas market fundamentals as an Analyst then Senior Analyst in the Research & Advisory division at Energy Intelligence Group. Earlier in his career, Jared spent several years working in the environmental consulting industry. He holds a Master's degree in international relations with a focus on energy from ...

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Energy Efficiency Prospects Surge for Minnesota Utilities

Samantha Williams, Staff Attorney, Chicago

The Minnesota Public Utilities Commission has rejected a nearly two-fold increase in fixed charges for CenterPoint Energy Resource’s residential customers, and ordered a mechanism â€" decoupling â€" for the gas utility that’s aimed at encouraging more energy savings for the state’s homes, businesses and industry.

Last week’s ruling sets an important precedent for states striving to achieve robust energy-saving goals and move toward a low-carbon future. As NRDC has written extensively about in the last few weeks, using these mechanisms to increase energy efficiency also can help move states closer to the proposed U.S. Environmental Protection Agency standards to reduce the power plant carbon emissions that contribute to climate change.  

But first things first - what is decoupling and how does it accomplish these benefits?

Traditionally, a utility’s ability to recover its “fixed costs” (i.e. the cost of meters, service lines, meter reading, and billing) is linked to how much energy it sells. As a result, it has an incentive to focus on sales volume rather than helping customers save energy. Decoupling breaks that link, freeing the utility to promote conservation.

And decoupling is very simple in practice: each year CenterPoint will adjust its rates up or down to cover its fixed costs - no more and no less - of serving homes, businesses and industry in Minnesota. These adjustments are small, but the impacts are huge, driving deeper energy savings and thus saving customers money on their bills. 

Decoupling furthers Minnesota’s goals

NRDC, along with Minnesota-based advocates Fresh Energy and the Izaak Walton League, sheparded CenterPoint’s decoupling proposal through this case, by:

• Supporting the decoupling request as an essential tool to move CenterPoint away from its current business model and create a more favorable regulatory environment for vigorous energy efficiency investment in the future.
• Strenuously opposing the request to nearly double fixed charges for residential customers (from $8 to $15/month). These increases inhibit conservation by sending an “all you can eat” price signal to customers, while reducing rewards for those who act to reap the benefits of efficiency.

Rather than increasing fixed charges, decoupling is the solution â€" an approach that both utilities and consumers can get behind.

The commission concurred, in a 3-2 decision, and found that decoupling is exactly the kind of policy that Minnesota law envisions to drive utility investment in efficiency. One commissioner even commented that the commission would be “failing to satisfy its statutory directive” if it did not implement decoupling. They concluded that “decoupling has substantial potential to align the [utility's] interests with the public’s interest in energy efficiency.”

This mechanism also satisfies a number of other important state goals. It is the only approach presented in the CenterPoint case that balances competing principles of rate design, including avoiding consumer rate shock, conserving energy, protecting consumers from rate volatility, and providing a utility with a reasonable opportunity to recover its costs of service. 

But with decoupling in place, it also means that a utility will not need to increase its fixed customer charge - an increase that can destroy customer energy efficiency efforts. Rate design is often referred to as a “zero sum game;” when a utility increases it fixed customer charge, it simultaneously decreases the variable charge that goes up and down as customers change how much energy they use.  This variable charge is the only portion of the bill that customers have the ability to control through energy efficiency.

A fixed charge increase reduces customers’ propensity to invest in efficiency. It sends them a counterintuitive message: “We’ll reward you for using more energy, and penalize you for using less.”

Again, the Minnesota commission concurred, finding that decoupling achieves the same goal as increasing the fixed charge â€" making the utility whole and stabilizing rates for customers â€" but without destroying conservation. As the commission stated, “given the protection provided by revenue decoupling, [we] will not approve the Company’s proposed increase.”

Decoupling is becoming the norm â€" not the exception â€" nationwide

Decoupling precedent in other states also came to bear on the CenterPoint case. Recent studies make clear that decoupling is commonplace across the nation, with half the states having adopted such mechanisms for at least one electric and/or gas utility, and, in total, 28 natural gas utilities and 51 electric currently implementing decoupling.

In fact, it is becoming the industry standard, and has helped spur some of the best-performing energy efficiency programs in the country. For example, seven of the ten states that lead the nation in per-capita investment in residential natural gas efficiency programs - Massachusetts, New Jersey, Utah, Minnesota, Michigan, Oregon, and Rhode Island - have decoupling for at least one natural gas utility.

What comes next?

In the last decade, Minnesota has made significant strides toward a clean energy future, including a commitment to reduce power sector carbon emissions 25 percent below 2005 levels by 2025.

One key to that success is the state’s requirement that utilities reduce energy sales by 1.5% annually through energy efficiency programs. As noted above, this commitment to conservation will be a key tool for further reducing emissions and achieving EPA’s proposed carbon pollution rules for power plants. 

Importantly, the CenterPoint decision shows once again that decoupling is a great incentive that will help Minnesota’s utilities â€" and many states â€" cross that finish line.

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Has Consumer Electronics Energy Use Finally Peaked?

Noah Horowitz, Senior Scientist and Director of the Center for Energy Efficiency, San Francisco, CA

The Consumer Electronics Association (CEA) just issued its latest report on the amount of electricity used by consumer electronics (CE) and the good news is that it’s finally begun to come down. However, the total is still enormous -- equal to the output of more than 50 large polluting power plants and costing consumers about $20 billion annually.

The CEA analysis entitled “Energy Consumption of Consumer Electronics in U.S. Homes in 2013” found their electricity use had declined to 12 percent of total residential consumption last year. This drop from 13.2 percent in 2010 comes after years of rapid growth due to the increasing number of gadgets in our homes and the huge amounts of energy required to operate the first generation of digital TVs and high-definition set top boxes.

While this is a great development and hopefully a trend that continues, we can’t claim victory over wasted energy in CE products yet. Here are some initial thoughts and observations about the report:

12 percent of a really big number is still a really big number. The report included an inventory of consumer electronics (CE) products in the home and publicly available data on the energy use of each product category. When you add it all up, CEA estimates consumer electronics products now use 169 terawatt hours of electricity per year (TWh/yr., which is a billion kWh/yr.) and highlighted that this is only 12 percent of total residential electricity use. While that may seem small when presented as a percentage, it’s still a really big deal. In fact, CE products:

• Use the equivalent of more than 50 large (500 megawatt) coal power plants’ worth of electricity and cause millions of tons of carbon dioxide emissions per year; and
• Cost their users around $20 billion per year to operate.
• Consume as much electricity each year as 15 million US homes do.

TVs and the stuff attached to them represent more than half of the total CE energy use. The big screen TVs and the devices connected to them -- which include set top boxes, video game consoles, DVD players, etc. -- consumed more than 90 TWh/yr., or over 50 percent of the total. The great story here is that new flat screen TVs now consume less than half the energy needed just eight years ago. In addition to these efficiency gains that save consumers money on their electric bills, new TVs also cost a fraction of what they once did.

These gains were due to a range of policies and manufacturer innovation, which included minimum energy-saving standards set by the California Energy Commission (CEC), ENERGY STARâ„¢ labels that helped consumers identify the more efficient models, and rebates provided by utilities for models that met or exceeded ENERGY STAR levels of energy savings.

(Note: The California standards that required 50 percent reductions of TV energy use by 2013 from 2006 levels have been met by all the manufacturers despite the CEA’s dire predictions that these standards would result in empty store shelves and thousands of lost jobs in California, alone. They didn’t. As California’s population represents such a large share of the market, manufacturers changed over their entire supply chains to meet the California standards and the national market has been transformed. Now consumers in others parts of the country can buy these energy-saving TVs too.)

According to the CEA study, set top boxes are the No. 2 energy-using CE product in the home at 18 percent. Due to renewed commitment by the set top box makers and the companies that buy the boxes such as Comcast, DirecTV, and AT&T, many of the boxes being purchased in 2014 use about 20 to 25 percent less energy than the ones in place in 2012. In time, the fleet of installed boxes will change over to the more efficient ones and consumers will realize significant savings.

Shifting to portable/battery-operated products cuts energy waste. CE products that are battery-operated tend to be optimized for energy efficiency and product designers work hard to cut energy waste in order to maximize battery life. That’s why portable devices such as tablets, laptop computers, and smart phones are very energy efficient and contain cutting-edge technology. Unfortunately, devices like desktop computers and game consoles, which are plugged into the wall and have unlimited power availability, have not been fully optimized and consume a lot more energy than necessary.

Game console energy use is growing and we might see increased CE energy use elsewhere too. It also should be noted that the CEA analysis did NOT include the new game consoles introduced in late 2013 by Microsoft and Sony, the Xbox One and PlayStation 4, respectively. Due to their new features and increased performance, these consoles use TWO TIMES more energy annually than the latest models of their predecessors. (For more information, go to NRDC’s game console report.) This growth is largely due to these new consoles drawing relatively high power levels even when consumers think they turned off their consoles, due to always-on features such as network connection, voice command and USB charging that were poorly designed. If other devices adopt these features, will the downward trend in CE energy consumption continue? Another future energy impact is the shift to super high resolution content called 4K or ultra-high definition (UHD), which could significantly increase the energy consumption of TVs and associated equipment--including set-top boxes and home networking equipment.

What happens to the 3.8 billion CE devices when they are no longer used? When you run the math, each household now has around 32 consumer electronics devices, ranging from smart phones, tablets, TVs, to the modems and routers that receive and push this content around our homes. While it wasn’t part of the scope of this report, the consumer electronics industry needs to continue to expand its efforts to make sure this ever-increasing number of gadgets are collected and properly recycled at the end of their useful life.

So while the CEA’s analysis does show a positive trend in our electronic gadgets using less energy over the course of a year, we still have a way to go before anyone should declare victory.

Photo Credit: Home Electronic Energy Efficiency/shutterstock

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HTR-PM: Nuclear-Heated Gas Producing Superheated Steam

The first HTR-PM (High Temperature Reactor â€" Pebble Module), one of the more intriguing nuclear plant designs, is currently under construction on the coast of the Shidao Bay near Weihai, China.

This system uses evolutionary engineering design principles that give it a high probability of success, assuming that the developers and financial supporters maintain their steady progress. Considering the fact that the plant is a logical follow-on to a successful prototype that has been operating since 2000 and that it is being developed by long-term thinking Chinese engineering and constructors there does not appear to be much development risk. Since the project appears to have the solid backing of the Chinese government, there does not appear to be much risk of sudden funding removal.

Here is a link to an April 2014 update presentation given to the IAEA â€" HTR Progress in China.

It does a good job of describing the technical foundations of the plant design and the reasons why the system is considered to have a high degree of inherent safety.

In basic layout, the power plant will share a number of features with the second stage of a modern combined cycle power plant. In a combined cycle power plant, the exhaust gases from combustion turbines are directed to a heat recovery steam generator (HRSG).

Those combustion product gases enter the HRSG at a temperature somewhere close to 750 C and leave that HRSG at a temperature of about 250 C. On the other side of the HRSG heat transfer tubes, feed water enters and boils, leaving the HRSG as superheated steam with a temperature somewhere close to 565 C and a pressure of 13-15 MPa. In most cases, the steam output of two or more gas turbine/HRSG modules is combined to drive a single steam turbine train, which might include both a high pressure and a low pressure turbine.

Interestingly enough, those are the same conditions produced in the HTR-PM.

For the demonstration plant, two reactor modules, each producing 250 MWth in a large, low power-density pebble bed reactor produce high temperature gas that enters the reactor at 250 C and leaves the reactor at 750 C. That hot gas (helium in the case of the HTR-PM) is moved by a circulator (the gas equivalent of a pump) into a steam generator that has feed water coming in and steam going out. The steam conditions are 565 C and 13.2 MPa. The output of the two steam generators is combined to drive a single 210 MWe steam turbine.

As described in the literature, this demonstration configuration was chosen to gain experience with multiple modules with the full intention of eventually producing larger output power plants by using more reactor/steam generator modules connected to larger steam turbines.

There are conceptual designs for 4, 6, 8 and even 10 reactor modules all connected to a single steam turbine. The designers are sticking with smaller power output reactors. Calculations tell them that if they keep total output power less than 300 MWth they can make a testable claim of inherent safety. No conceivable event can lead to a situation where the temperature in any part of the core exceeds the 1600 C design temperature for the TRISO particle fuel.

If no accident leads to temperatures that can cause fuel damage, there is no need to devise additional safety systems or features to remove heat.

HTR-PM Reactor Vessel and Steam Generator
(via Next Big Future)

There are several evolutionary paths available based on this design advancement. One path would be to implement a phased replacement of coal fired boilers with HTR-PM reactor/steam generator modules. China has a large and rapidly growing inventory of modern steam plants that currently require burning about 3.5 billion tons of coal per year, resulting in places where the air is almost too foul to breathe.

Moving all of that coal from the source to the power plant is also a major burden on the country’s straining rail and barge transportation network. Replacing coal boilers with nuclear heat sources would eliminate the main drawbacks of the power plants while fully using the rest of the installed infrastructure of cooling water, steam plant, transmission lines, and trained operators/maintenance staffs.

Another direction available is to gradually increase the temperature capability of the pebble bed to the point where the gas is hot enough to drive a direct cycle gas turbine whose exhaust can then be directed to the steam generator for a higher efficiency, higher power output combined cycle system.

The Chinese purchased their initial TRISO fuel manufacturing capability from the Germans and their designs have a great deal in common with the HTR program being pursued in Germany up until the end of the 1980s. In that program, demonstrated gas temperatures reached 950 C with future plans of hitting 1100 or 1200 C as the manufacturing techniques improved.

As demonstrated in the German program, TRISO fuel particles do not have to be UO2, a wide variety of actinide compounds including UC, PuO2, and ThO2 have been tested and are available for future use.

One of the things that I find incredibly invigorating about nuclear technology is the almost endless horizons and options for creatively using energy dense, ultra-low emission fuel sources to create useful heat that does not require wholesale reengineering of our basic infrastructure. We can reuse a large portion of what we have already built and already learned how to effectively operate and maintain.

If you are as interested in high temperature reactors as I am, you might want to learn more about HTR-2014, The 7th International Topical Meeting on High Temperature Reactor Technology. It is being held in China in Weihai, close to the HTR-PM construction site, from October 27-31. Tours of the site will be offered as part of the conference program.

Additional reading

Next Big Future (April 2013) HTR-PM High Temperature Pebble-Bed Modular Status in China March 2013

The post HTR-PM â€" Nuclear-heated gas producing superheated steam appeared first on Atomic Insights.

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Authored by:

Rod Adams

Rod Adams gained his nuclear knowledge as a submarine engineer officer and as the founder of a company that tried to develop a market for small, modular reactors from 1993-1999. He began publishing Atomic Insights in 1995 and began producing The Atomic Show Podcast in March 2006. Following his Navy career and a three year stint with a commerical nuclear power plant design firm, he began ...

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Randall Abramson: Juniors Clean Up Behind the Elephant Hunters

Randall Abramson, CFA, is CEO and Portfolio Manager of Trapeze Asset Management Inc., a firm he cofounded in 1999 shortly after founding its affiliate broker dealer, Trapeze Capital Corp. Abramson was named one of Canada's 'Stock Market Superstars' in Bob Thompson's Stock Market Superstars: Secrets of Canada's Top Stock Pickers (Insomniac Press, 2008). Trapeze's separately managed accounts are long/short or long only, and have either an all-cap orientation or large cap-only mandate via the company's Global Insight model. Abramson graduated with a bachelor's degree in commerce from the University of Toronto in 1989, and his career has spanned investment banking, investment analysis and portfolio management.

The Energy Report: With all the excitement over unconventional oil and gas resources these days, why are you focused on conventional exploration and production companies?

Randall Abramson: Being contrarian, when everybody's focused on one area, we tend to focus on the other. Our largest weighting at the moment in our All-Cap portfolios is Manitok Energy Inc. (MEI:TSX). I picked up the phone one day and somebody recommended that we look at it. The majors in Alberta were all leaving for unconventional plays, and they left behind a perfectly good conventional play for a junior to come in and pick up!

What happened was a bunch of Talisman Energy Inc. (TLM:TSX) employees had been drilling for deep gas wells in the Alberta foothills, and were bypassing perfectly good oil zones when they were looking for deep gas. That was what they were charged with in their Talisman days. Then, when gas prices declined materially in the debacle of '08â€"'09, and the majors left, suddenly land prices dropped back to 1998 levels. That created an opportunity for this team of former Talisman employees to swoop in, gather up a bunch of cheap land and go after the oil they knew was there, because they saw it when they were drilling for gas in the good old days. That's what created this conventional opportunity.

TER: How does a junior company like Manitok Energy compete in an industry dominated by oil and gas majors?

RA: Competition is somewhat irrelevant. Once you have land to exploit, it's under a lease for a certain amount of time, and as long as you're producing, that land is typically yours to keep until you sell it or move on. From that perspective, I'm not sure competition is relevant. In fact, big competition, as in the case of Talisman, was actually the source of Manitok's opportunity.

Manitok has a second big opportunity for growth in an area called Entice, with a lease it acquired from Encana Corp. (ECA:TSX; ECA:NYSE). Encana has been mostly a gas company since it spun off Cenovus Energy Inc. (CVE:TSX; CVE:NYSE). It isn't really interested in oil wells that can produce between 100 and 300 barrels a day (100â€"300 bbl/d). The Entice area was a case where the major had this asset for the longest timeâ€"since the 1800sâ€"and wasn't interested in it because it was smaller. Encana did little drilling for oil in this vast area over the years, though the adjacent areas have produced more than 200 million (200M) cumulative barrels of oil. Again, the competition is creating an opportunity for Manitok.

On the other hand, another company that we own, Corridor Resources Inc. (CDH:TSX), needs majors to participate, because it's a junior that has stumbled into significant assets and it can't pull them off on its own. Sometimes you're at the whim of the majors, and sometimes you're lucky because you get the smaller items they overlook when they're out elephant hunting.

TER: Why is the market responding strangely to developments at Manitok?

RA: Oil and gas companies quite often are viewed as homogeneous. Investors think, "If I'm not investing in Manitok, I can invest in 'Shmanitok.'" I think today's analyst community is used to the unconventional play, and they like it because it's cookie-cutter. They can see the rate of return more easily; it's easier to quantify, to spreadsheet. Also, when something goes slightly awry or there's a bit of noise, that tends to depress some oil and gas companies, because investors, seeing them as homogeneous, think, "I may as well go play the next one."

Manitok had a few things go against them, which weakened sentiment toward the company. First, it had a pretty significant equity financing in the fall that satisfied a lot of demand for the shares. Then it had some disappointing well results in a noncore area. On top of that, the COO left the company and he was reasonably highly regarded as a geologist and driller. I think that created a lot of questions in people's minds about why he left. It also created a couple of camps, because some people were behind him as well. The new COO is an operator with much more experience in bringing production on stream, having grown his previous company from 3,000 bbl/d to 30,000 bbl/d. We believe management is much stronger now.

"Manitok Energy Inc., in our view, is a rare opportunity."

The acquisition of the Entice area from Encana also created some uncertainty about the direction of the company, because before that Manitok was focused solely on its Stolberg area. All of a sudden, this new area was introduced that people didn't know much about. There was also some downward guidance in Q3/13 because the company wasn't pulling fast enough on production. Even though Manitok announced it was back on track in Q3/13, sometimes the market shoots first and asks questions later, and selling begets further selling.

A number of things have temporarily kept a lid on the stock. As positive results keep coming out, both from Stolberg and the Entice area, Manitok should look very different as people get more comfortable. Recent positive indications from the initial five wells at Entice give us even more confidence in this area, where there's potential for more than 50 new pools of oil. Between Stolberg and Entice, the company should have a sizable drilling inventory for years to come.

TER: What is your recommendation and your target for Manitok?

RA: Our target today is $4.50. Our target valuation by year-end is $6. We would look for something closer to an $8 mark over the next three years. The stock is around the $2.20 mark today. The reserve-based NAV, including land, was around $3.80 at the end of March. That $3.80 would include zero value beyond land value for the new Entice area, and understates the value of Stolberg.

The going rate on the market today for Manitok's peers is about $68,000 per flowing barrel ($68,000/bbl), and somewhat higher if you look at what private market transactions have brought. You can use those metrics quite easily on the barrels Manitok is producing today. Manitok's exit guidance for 2014 is more than 7,000 bbl (7 Mbbl). You can easily see value of more than $6/share. Manitok, in our view, is a rare opportunity. The company has a rapid growth rate, industry-leading well results, high internal rates of return (IRRs), high netbacks, only a modicum of debt and plenty of room for further growth, yet it trades at a large discount to its fair valueâ€"in fact, bizarrely, it's the cheapest of its peers.

TER: Northern Tier Energy LP (NTI:NYSE) is an independent, downstream, energy master limited partnership (MLP) with refining, retail and pipeline operations that serve the Petroleum Administrative for Defense District (PADD) 2 region of the United States. What's your recommendation for Northern Tier?

RA: I think Northern Tier is getting closer to fair value. There is still probably 10% or 15% upside there, particularly if its large owner, Western Refining Inc. (WNR:NYSE), which owns close to 39% of the company, decides it wants to have the rest of the company for itself, to unlock significant value. This transaction could diversify Western Refining by geography, end-markets and feedstock, and allow a cash-flow boost in Western Refining's own MLP by adding Northern Tier's significant assets in retail, pipeline and storage facilities.

TER: How does the cyclical nature of the refining industry affect Northern Tier's earnings?

RA: I think Northern Tier is a bit of a standout. There is a shortage of refinery capacity within the U.S., which makes the refining industry less cyclical than it used to be. And Northern Tier should be even less cyclical than the group because there's a more pronounced supply/demand issue in its region. The company should also have better margins: It gets a Bakken feed of light oil, and at the same time there's a significant shortage in its Minnesota backyard, which allows it to get a better margin when it sells the refined product. Northern Tier also has some vertical integration because of its ownership of the retail downstream.

TER: Corridor Resources Inc.'s share price is up more than 300% over the last year. What's driving that?

RA: One of the key ingredients is that natural gas prices themselves have been rocketing up to where they sit today, just shy of the $5 per thousand cubic feet ($5/Mcf) range from as low as $2-and-change a year ago. That's attributable to storage inventory dropping as the number of gas rigs has plummeted, and to the fact that we had a disgusting winter. Demand has also been up because there has been switching from coal to gas for economic reasons, although, bizarrely, it's been going slightly back in the other direction recently because of the change in prices. But the carbon footprint issues have put upward pressure on the natural gas price.

At the same time, what's really helped Corridor, specifically on the gas price front, is the higher gas price in its specific market, which is the U.S. Northeast, as it sells into the New England area. There's been a tremendous shortage there. Gas refineries and natural gas plants were lying idle on the coldest days of the year simply because they couldn't get enough product.

There isn't enough pipeline capacity coming into New England right now. Corridor ships its gas through the Maritime Northeast Pipeline into New England. It has already locked in US$11/Mcf for a good part of next winter. That's been a huge change for Corridor, to be able to lock in those prices and to start capital spending again in a significant way both at its McCully Field, which is its main field, and its Frederick Brook shale field.

"Orca Exploration Group Inc.'s Tanzania pipeline is now more than 70% complete."

Corridor also took on partners for exploration and production on Anticosti Island in the Gulf of St. Lawrence: the Québec government and Maurel & Prom (MAU:EPA), out of France. Corridor has about 22% of the Anticosti play. The partners will put in the money to drill on that property over the next couple of years. We think anticipation of that event and the event itself have helped propel the share price. Anticosti Island is a shale oil project similar to what we've seen in the Utica Shale. It still requires some work to assess the viability of the project, but on the holes that the company has looked into thus far, the core samples look exactly the same as what we've seen in the Utica. Corridor should be drilling and doing more work through the rest of 2014 and 2015 to determine flow rates.

Corridor has two other properties, one called Old Harry, offshore Newfoundland and Québec, and Frederick Brook, the shale property. Those two fields need partners because they require tens, if not hundreds, of millions of spending to bring them to fruition. But they are massive projects.

What's amazing about Corridor is that it's still trading, in our opinion, below the breakup liquidation value of the company. If you took the land value, the value of existing production and the value of its compression gas plant, and sold those off, you'd probably get more than the share price today. Because that's not going to happen, we still believe that we're getting those megaprojects for free. The company has no debt and about $35 million ($35M) in cash on hand.

TER: Corridor has one producing property in New Brunswick. Is that shale gas or conventional gas?

RA: Most of it is conventional, but there is a little shale gas on the Hiram Brook zone, which is on the company's McCully property. Underneath the Hiram Brook zone, Corridor has discovered a zone called the Frederick Brook, and it's one of the most prolific shales in North America. It's more than 1,000 meters thick.

The problem for Corridor has been that it requires $100Mâ€"150M to begin developing it, and the company needs a partner to pull that off properly. Repsol-YPF S.A. (REPYY:OTCPK) has an LNG import facility nearby that it has been talking about converting into an import/export facility. That would create instant demand for Corridor and others' gas in the region, not just to sell into the Maritimes and into the Northeast of the U.S., but also to Europe and elsewhere. That can be done at a much lower cost than what we're seeing with export facilities in Louisiana or on the coast of British Columbia.

TER: Are the protests against fracking in New Brunswick threatening Corridor's operation?

RA: I don't think they've had an impact on Corridor because Corridor operates away from metropolitan areas. The protesting has led to more stringent regulations. That's a positive. To think that we're not going to have fracking at all is somewhat ridiculous because, again, circling back to conventional versus unconventional, this isn't the Beverly Hillbillies anymore, where the oil gurgles up to the surface. (Although, with Manitok, that's exactly what's been happening with its conventional rarity.) With Corridor, its rock has to get fracked. That's the case with most unconventional formations, which means most of the formations and reservoirs that exist today. Fracking is just reality.

TER: What's happening with Orca Exploration Group Inc. (ORC-A:TSX.V; ORC-B:TSX.V)?

RA: Orca is extremely neglected. I think there might be two analysts who follow the company. The company is domiciled in Tanzania. That puts it out of sight, out of mind. And the company has struggled with a number of issues.

Orca was supposed to have a pipeline built in the country to allow higher deliverability of its own gas, as its gas fires more than 50% of the power in the whole country of Tanzania. That pipeline was delayed and delayed, and finally broke ground in fall of last year. The pipeline is now more than 70% complete, and is scheduled to be commissioned this time next year. But the government of Tanzania has been in shambles. It has not been paying its own bills, which means TANESCO, which is the national utility of the country, has been behind in paying Orca and others who supply it. But Orca has received some money back.

The World Bank has now entered to help the country. Tanzania got a second tranche recently of about $100M, so Orca should see its share of that over the next month or so. There should be further dollars to come. As we see it, everything's actually improving now. The government has established a very capitalistic national energy policy. It's talking about having completely liberalized markets by the end of this year. There is an election at the end of next year. If this power situation isn't sorted outâ€"because Tanzania has been dealing with significant brownouts for years nowâ€"I think the government is going to struggle to get reelected.

I think a lot of market participants want to see everything looking rosy before they participate. Meanwhile, the company has more than $1 per share of cash on hand at the moment and another $1 per share of working capital above that. You're essentially getting the rest of the business for free. The rest of the business has approximately $12 net present value using a 10% discount rate from the third-party engineer reserve value. There's arguably $14 of value and a $2.30 share price. There's no debt.

TER: What are some other companies you're excited about?

RA: We like Legacy Oil + Gas Inc. (LEG:TSX). It's a mid-cap company with just over a billion dollars ($1B) of market value in the Saskatchewan/Dakota area. It's an unconventional play and has essentially batted 1.000 on its drilling. I think last year it went 99% because it missed one, but in the most recent quarter it hit them all.

What we like about Legacy is its high netbacks. It's virtually all light oil, with a high IRR. It trades at about a 20% discount to its asset value. We see that changing over the next 6â€"12 months as the company makes accretive acquisitions or gets the balance sheet more in line with what the market would like to see. In the meantime, Legacy is growing its fair value. This is not a small company. This is a company that has forecast an exit rate of about 24 Mbbl/d production for this year.

TER: Any parting thoughts for the investor with money to spend?

RA: Oil prices obviously go up and down because oil is a commodity. But oil is not iron ore, it's not copper and it's not nickel. Those other commodities are much more cyclical in nature. Demand for oil rarely goes negative, like copper or nickel or iron ore would. I think that allows oil and gas companies to look more like any other company.

I think we're in a sweet spot right now. We've got ever-rising demand. If you look at the non-OECD nations, there's substantial growth in demand. And demand is greater than supply. Storage inventories are dropping way below the five-year average, which means that consumption is rising faster than production. That means the prices for products that the Orcas and the Corridors and the Manitoks of the world sell are likely going higher over time. If you've got a company with terrific production growth, a decent balance sheet and a high IRRâ€"and the price of what it's selling is going up at the same timeâ€"that's a pretty good recipe for success, especially if it's already undervalued even at $85/bbl oil, like a Manitok and a Legacy.

TER: Thank you very much for your thoughts.

RA: My pleasure.

Want to read more Energy Report interviews like this? Sign up for our free e-newsletter, and you'll learn when new articles have been published. To see recent interviews with industry analysts and commentators, visit our Streetwise Interviews page.

DISCLOSURE:
1) Tom Armistead conducted this interview for Streetwise Reports LLC, publisher of The Gold Report, The Energy Report, The Life Sciences Report and The Mining Report, and provides services to Streetwise Reports as an independent contractor. He owns, or his family owns, shares of the following companies mentioned in this interview: None.
2) The following companies mentioned in the interview are sponsors of Streetwise Reports: Manitok Energy Inc., Orca Exploration Group Inc. Streetwise Reports does not accept stock in exchange for its services.
3) Randall Abramson: I own, or my family owns, shares of the following companies mentioned in this interview: Manitok Energy Inc., Corridor Resources Inc., Orca Exploration Group Inc., Northern Tier Energy Inc. I personally am, or my family is, paid by the following companies mentioned in this interview: None. My company has a financial relationship with the following companies mentioned in this interview: None. I was not paid by Streetwise Reports for participating in this interview. Comments and opinions expressed are my own comments and opinions. I had the opportunity to review the interview for accuracy as of the date of the interview and am responsible for the content of the interview.
4) Interviews are edited for clarity. Streetwise Reports does not make editorial comments or change experts' statements without their consent.
5) The interview does not constitute investment advice. Each reader is encouraged to consult with his or her individual financial professional and any action a reader takes as a result of information presented here is his or her own responsibility. By opening this page, each reader accepts and agrees to Streetwise Reports' terms of use and full legal disclaimer.
6) From time to time, Streetwise Reports LLC and its directors, officers, employees or members of their families, as well as persons interviewed for articles and interviews on the site, may have a long or short position in securities mentioned. Directors, officers, employees or members of their families are prohibited from making purchases and/or sales of those securities in the open market or otherwise during the up-to-four-week interval from the time of the interview until after it publishes.

( Companies Mentioned: CDH:TSX, LEG:TSX, MEI:TSX, NTI:NYSE, ORC-A:TSX.V; ORC-B:TSX.V, WNR:NYSE, )

Photo Credit: Unconventional Fuel Sources/shutterstock

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How Solar Finance is Driving Solar Businesses to Change

At the risk of sounding like an old man with graying whiskers, I can remember giving a presentation more than a decade ago about how we needed to stop thinking in terms of capital cost and think about price per kilowatt hour when it comes to selling solar.

I could see that in other parts of the world, solar systems were becoming financial instruments, despite the fact that Australia was in the midst of the triple bottom line boom driving consumers and business to think green. It was therefore entirely logical to predict that successfully selling solar power would come down to its root’s; a financial competitor in lifetime, all-in energy terms not just an environmental nicety.

Environmental concerns waned and are only now starting to re-emerge as deep rooted concerns around carbon pollution surface again. However, the driving force behind solar today is its competitiveness; it’s ability to save you financially and environmentally. Ironically, as costs plummeted and the industry grew many solar businesses fell under its spell. Lowest price became the dominant factor; quality was assumed to be implicit and liability was assumed to be with the manufacturers who could not fail.

Whilst cost reductions resulted in growth, we are now faced with an emerging price to pay and an adjustment period is upon us.
Unfortunately, the quality of some products has been appalling and I am starting to have more regular conversations about how to handle growing warranty liabilities with solar retailers. At the extreme, we have seen fraudulently labelled fake products and safety switches that can cause roof fires.

The poor quality control and lack of diligence by manufacturers is clearly the root cause; but to be fair, buyers who demanded ever lower prices and failed to pay sufficient attention to details should consider how they influenced their own predicament too. As time passed cracks started to appear and the all-powerful Tier ranking got talked about a lot to the point it became a throw-away line used by all and sundry. Australia’s market, unlike others featuring larger projects which were financed, didn’t understand or value yield or quality and government drove politically motivated schemes aimed at buying as many votes as possible.

But now, we are in a rapidly festering pickle and paradoxically, one of our most iconic finance icons famous lines might be more profound than he realised. Aussie John’s catch phrase was “We’ll save you” and I’m starting to see signs that he could well be right in more ways than he could imagine.

Where finance really helped other countries was by enforcing due diligence on supply chain partners and monetarily valuing carefully analysed yield. Quality became valuable and attention to detail lowered risk and cost. There is a very good reason why solar costs are higher in almost every other country in the world.

This trend is now well and truly emerging in Australia in our rapidly growing solar finance market. I work with a number of finance companies today, assisting them to test the veracity of claims, conducting due diligence work and protecting them from future failures and let me tell you, the better ones take this stuff very seriously.

One of my clients often bring new brands and partners to me, looking for guidance and increasingly I am finding myself saying “not with a 100 pole mate; walk away”. Although this can be frustrating for everyone, so often I am faced with a simple reality that with the price gap being so small between Tier 1 and others, I wonder why anyone would bother taking the risk for a few cents of gain.

In fact I had this very conversation with a retailer recently and suggested that if they felt the price pressure was so extreme that they needed to go below Tier 1, they should simply stop offering those products with finance and purely do them as cash sales because there was no way I was going to support them being approved. Equally, there is a very strong focus on the vendors; (that’s you the solar retailer). Finance companies are increasingly looking for sophistication, understanding of the market, marketing panache and comprehensive business and safety compliance. My client reckons he knocks back more solar retailers than he accepts to control his finance risk and I fully support him in that.

Another important element of this equation is the warranty and more importantly the support behind it. Google “solar warranty and insurance” and hey presto, you can find a template for a solar panel warranty and global insurance, I’m sad to say. One supplier I checked on recently couldn’t even be bothered trying to keep the validity dates right on their insurance certificates on the International web site, despite assuring their solar retailer customer that the panels were covered. Fail.

In other cases, we have found utterly fraudulent insurance documents and in eight out of ten cases the warranty documents aren’t even compliant with Australian law, let alone decent. The ramifications of these things can be profound as one solar retailer described to me recently. His wholesaler supplier had gone bust and the solar manufacturer supplying them had also vanished â€" and now failures were starting to emerge. His entire livelihood is now at stake and although he realised he was liable, I have met solar retailers who had no idea that the buck stopped with them.

He asked me what he could do and I explained how more than a decade ago I used to explain to solar retailers that whilst solar manufacturers had an obligation to support potential warranty claims, so did they as solar retailers. I used to argue that like the manufacturer I worked for, they should be retaining a warranty support accrual and before my beard turned grey, that is what many did. Today however, the competitive pressure has forced many to wrongly assume that they could get away without accruals and it is causing companies into bankruptcy, as we speak. I suspect it could force some very, very large solar companies to the brink as well.

Now clearly finance has a cost and it doesn’t suit every customer or application. It’s also become categorically clear that crude financial products which apply zero due diligence and are extortionately expensive and which have dominated the market are finally starting to lose market share.

We are now seeing far smarter products, carefully tailored to our product and market which are delivering lower cost finance and better solutions. In fact, smart finance changes the whole sale proposition from selling a product, to selling a solution; it’s a different technique and requires a different sales strategy.

The reality is that finance is driving structural change in solar businesses.

Those who are adapting successfully are changing to selling long term value, not just pushing a quick sale based on the fear of rebates or FIT’s evaporating. They are no longer focused on pushing the technological features as a sales differentiator â€" quality products become implicit, embedded because the financier won’t accept anything less. Instead the focus switches to creating a better long term financial position for the customer â€" which is what drives many to look at solar in the first place.

The technological and quality focus becomes a back office function and there-in lie’s a big challenge because the majority of solar companies are from trade backgrounds and are very product-centric in their sales approach. Selling finance shouldn’t scare these types of operators, they just need to understand that the technology focus doesn’t have to be front-end focused and arguably, finance companies actually make them work harder to find better products.

One of my finance clients said to me recently “Nige; one of my vendors sells great volume at $2/Watt which has improved the profitability no end. They no longer try or need to compete at $1/Watt because they are selling a completely different value proposition. It’s completely changed their business, they are now growing again and their chance of surviving the ups and downs on the solar market have dramatically improved”

It has to be said of course that the cost of money and the drive towards quality is increasing the cost of solar, compared to cash purchases of less heavily scrutinized product.

I’m actually really happy about that.

Finance companies are having a more material impact on the quality of products and service than I have seen in decades and that is a bloody good thing. They are driving the focus onto lifetime energy cost and away from capital costs and that where we need to be.
They are creating new sales techniques demanding new business models and are setting a high bar for suppliers and consumers.

The evolution of intelligent finance is not easy money, its clever money.

This story is Part 1 of a 2 Part series on finance in the solar sector, stay tuned for Part 2!

Photo Credit: Solar Finance Changing Solar Business/shutterstock

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Energy Storage Opportunities are Everywhere

Hi everybody,

Thank you for your interest and all your comments on my previous articles.

So here is part 4 of my insights into the Future of Energy from an interview for TheEnergyBlog.

I’m looking forward to your comments and ideas.

All the best,

Michael

“I like to think of storage in the widest sense,” says Dr. Weinhold. “It’s not only about storing electricity for later use. It’s also about crossing over into other infrastructures like mobility. For example, we see it now in electic and hybrid cars that carry batteries. (As an aside, at Dr. Weinholds university institute they converted a Trabant into an E-Trabi as far back as the 1980’s. “We called it our ‘E-Trabant.’ It went very fast but it did not go very far,” recalled Dr. Weinhold, with a laugh.)

He continued: “We also see interesting storage possibilities in the heating sector via heat pumps. Consider that, in Germany, a third of the end-usage application of all energy consumed is for room heating. And the total amount of energy used for heating across homes and industry combined is probably around 50%. Imagine the potential of buffering the surplus of just a small proportion of that… and then redistributing it in the most effective manner possible via grids. The efficiencies would be considerable.

Then there is the field of hydrogen, via electrolyzers. Once you’ve created hydrogen you can easily store it and then use it as and when required. Hydrogen is the bridge to a huge amount of applications, for example there are car manufacturers who have announced the launch of Hydrogen fuel cell cars next year. And Hydrogen has many other impressive applications too. Next year, for example, we will install a 6 Megawatt, electrolyzer in the city of Mainz, which will provide control energy for the electricity market.

“In terms of what is state of the art, there are now large new battery storage systems based on Lithium Ion batteries that can be used to buffer power supply. And storage technologies can only continue to develop and improve in ways that we have not yet imagined,” said Dr. Weinhold.

Photo Credit: Energy Storage Future/shutterstock

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Michael Weinhold

Born in Rüsselsheim, Germany, Mr. Weinhold completed his studies at the Ruhr-University Bochum in 1993 with a Dr. Ing. degree in Electrical Engineering. He began his professional career that same year at Siemens PowerTransmission and Distribution (PTD). After holding several management-level positions in the Network Planning Department, he joined the High Voltage Division as technical ...

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Hollande's Proposed "Cap" on Nuclear Electricity Capacity

France’s President Francois Hollande and his Socialist Party ran on a platform that included scaling back France’s dependence on nuclear energy. It was not a very popular part of his campaign pitch, but Sarkozy was such a flawed candidate that Hollande won anyway.

Hollande is trying to follow through on his promise, but there are large numbers of well-connected and resourced people who oppose the idea. A few days ago, French Energy Minister Segolene Royal introduced a proposed piece of energy legislation that would, among other things, attempt to cap the total capacity of nuclear power plants in France at 63.2 GWe, which is the current level.

Though I believe that the proposal has little chance of being passed in anything resembling its current form, it is something that needs to be watched. My hope is that there will be strong and well organized resistance to the idea from a wide swath of French industry and consumers who will be harmed by artificially restricting the country’s ability to improve on its current nuclear generating fleet and its proven ability to find substantial export markets for the clean, ultra-low emission, reliable electricity that its nuclear plants can produce.

Electricity is a wonderful export product; most customers are repeat customers whose purchases will naturally increase over time if they are happy with the pricing and service, there is no inventory to maintain and there is no burden placed on roads, ports, or airports. Nuclear technology and operational expertise is also a valuable export product; France is one of the few Western nations that has maintained its skills and capabilities in this area â€" though there is plenty of room for improvement as it gains experience in the newest generation of nuclear power plants.

In 2012, Gail Luft, writing for the Journal of Energy Security, published an article titled France: Can the ‘Lumiere de Monde’ Risk a Brown-Out? that points out some of the considerations that the French people should keep in mind as they discuss and resist Hollande’s ill-considered attempt to hamstring such an important part of his country’s economic base. Here is an example quote, but there are many additional items in the original article.

One option for Hollande is to use his anti-nuclear stance as a way to endear himself to Berlin. After the disaster in Japan, Germany was the first European country to announce its plan to bid farewell to nuclear power and move aggressively towards green power. Adopting a similar stance would be music to German Chancellor Angela Merkel’s ears particularly as the two leaders will be looking for issues on which they can agree. But one hopes that Hollande knows that even the winds of Normandy and the sun of Provence will not come close to replacing nuclear power. France’s installed capacity for photovoltaic power is about 100 times less than Germany’s, and the French economy is not sufficiently prosperous to embark on massive subsidization of renewable energy, as its northern and southern neighbors, Germany and Spain have done in recent years. Furthermore, by now Europeans like Americans have come to realize the false promise of green jobs as a major driver of economic growth. With unemployment above 10% France does not have the luxury of dismantling the 30,000-job nuclear industry without replacing it with an equally labor intensive one.

It is probably possible to trace some of the Socialist Party funding to Russian natural gas interests. Russia loves its own nukes, but spends quite a bit of time and money spreading propaganda (FUD) about the nuclear programs in its customer and competitor nations. France’s domestic nuclear plants help to keep it independent of Russian gas, and France’s nuclear electricity exports help its neighbors reduce their purchases of Russian gas.

The unreliables industry is also well known for its complaints that nuclear “crowds” them out of the market. They are working hard to force middle-aged nuclear plants to shut down merely because they were initially licensed for 40 years. That period has nothing to do with the design life or the ability of well-maintained nuclear heated steam plants to last at least as long as coal, oil or gas-fired steam plants.

It is interesting to note that many information sources that target the unreliables industry (which prefers to brand itself as the “renewables industry”) have covered the proposed legislation as a done deal, with phrasing like the following:

France will cap nuclear power and aim for renewable energy to make up 40 percent of its electricity production by 2030 (less than 20 percent now), 38 percent of heat consumption and 15 percent in the transport sector, according to a new energy bill, writes Reuters. France will also boost energy savings. For example, a tax credit will be introduced for renovation work carried out.

(Emphasis added.)

None of those proposed actions will be implemented when the bill is soundly defeated.

The fight will be messy because there are massive financial stakes associated with the decision. My hope, however, is that the full strength of the established and entrepreneurial nuclear industry and all associated interested parties will be brought to the battle for hearts, minds and wallets.

The post Hollande’s proposed “cap” on nuclear electricity capacity appeared first on Atomic Insights.

Photo Credit: Hollande, France, and Nuclear/shutterstock

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Rod Adams

Rod Adams gained his nuclear knowledge as a submarine engineer officer and as the founder of a company that tried to develop a market for small, modular reactors from 1993-1999. He began publishing Atomic Insights in 1995 and began producing The Atomic Show Podcast in March 2006. Following his Navy career and a three year stint with a commerical nuclear power plant design firm, he began ...

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