Canadian CEOs want governments to invest in clean-tech innovation

[chuckChuck]

Canadian CEOs want governments to invest in clean-tech innovation

RICHARD BLACKWELL

The Globe and Mail

Published Sunday, Mar. 27, 2016 4:44PM EDT

Last updated Sunday, Mar. 27, 2016 7:03PM EDT

A majority of Canada’s business leaders believe governments need to invest in clean-technology research to spur breakthroughs that could result in the elimination of fossil-fuel use over the coming decades.

The latest quarterly C-Suite survey of corporate executives shows that almost three-quarters of respondents support government backing for research and development that leads to a reduced reliance on fossil fuels. The support for public involvement is weakest in Alberta, but, even there, 55 per cent agreed this is an important role for government.

How fast Canada can move away from fossil fuels, though, is a question that divides executives. Only 14 per cent said the country could completely eliminate the use of fossil fuels by 2050, while 38 per cent said that point will come in the 2051-2100 time frame. Thirty-one per cent said Canada will never completely eliminate the use of fossil fuels.

The survey was conducted before last week’s federal budget, which contained a wide range of measures for environmental protection and clean-tech innovation.

Not surprisingly, it is the executives in the clean-tech sector who see the feasibility of a complete shift to renewables by 2050.

“I firmly believe it is possible, and I don’t think I am a lunatic-fringe kind of person,” said John Simmons, chief executive officer of Victoria, B.C.-based solar lighting firm Carmanah Technologies Corp. “I can’t imagine why other clear-thinkers can’t see it as being possible.”

Mr. Simmons noted that the cost of solar panels is dropping just as the efficiency of sunlight-to-electricity conversion technology is improving. “The technology works, it is getting better, and all the cost curves are heading in the right direction,” he said.

At the same time, he noted, executives are being pushed by the millennial generation to take into account environmental and social issues while striving to be profitable – thus increasing the momentum toward a clean-tech revolution.

The view from the oil patch, on the other hand, is more cautious. “The world demand for energy is growing at an incredible pace.” said Kevin Stashin, CEO of Calgary-based NAL Resources Ltd., a private oil-and-gas company with production in Alberta and Saskatchewan. “What you are going to need in the future is a myriad of different energy sources, from fossil fuels to renewables. It is not a question of either-or; it is a question of needing it all.”

Many renewable sources of power are still intermittent, so in the foreseeable future they will not be able to replace all the energy needed in Canada, even in the electrical sector, said Mr. Stashin, who added that the Canadian economy continues to be driven by fossil fuels.

But the government does need to support research into renewables, he said, even if the transition to them takes a long time. “Fossil fuel is a finite resource, and as it becomes more scarce in the future, the costs to explore for it and develop it will go up. You are going to need an alternative source of energy … so why not be on the forefront of it?”

A significant number of executives – 43 per cent – said it would be worthwhile to at least set a goal of eliminating fossil fuel use by 2050. However, only 22 per cent think this target is realistic.

Harry Taylor, chief financial officer at Westjet Airlines Ltd., said he thinks fossil fuels can be completely eliminated – even for aircraft – some time before 2100, but “2050 feels a little tight, given the amount of research that needs to be done and proven.”

“But if we haven’t figured this out by 2100, then we just haven’t invested enough intellectual capital and financial capital,” he said. “There has got to be something that we can develop. It is going to be hard work, and I’m sure [there will be] a lot of false starts, but I have faith that we will find something.”

In the airline industry, it is really up to engine-makers and airframe manufacturers to solve the problem, Mr. Taylor said, but research is already under way. In the meantime, airlines such as Westjet “are always looking for opportunities to reduce our fuel consumption and our carbon footprint.” This is “enlightened self-interest,” he said, because cutting fuel use saves money at the same time that it trims carbon dioxide emissions.

Mr. Taylor said he believes governments do have roles in supporting clean-technology research, even though they “have a propensity to be wasteful, and chase after things.” They should help create the conditions for the success of new industries “rather than propping up old-technology industries,” he said. Partnerships are a good means of doing this, he added: “Co-investing rather than just giving money away seems to make sense to me.”

Bill Murphy, national leader for sustainable services at KPMG Canada, said Canadian executives have shifted their thinking about clean technology. This is partly driven by a change in the political environment – both internationally and in Canada – and by technological advances, which show a low-carbon economy is now “in the realm of the possible.”

Still, he said he doesn’t see the end of fossil fuels in the medium term: “Some of the cleaner-burning fossil fuels are still going to be with us for some time.”

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[bucket]

Instead if asking the government...actually taxpayers... to cover the costs of R&D why don't the guys that profit the most pay for it.

I am really getting sick of someone telling me to become more efficient or this will be better for me and yet it's my taxes that pay for their eventual profits.

Examples....

1. Let's get rid of branchlines and the system will be more efficient. It's not and it created a trucking industry. Maybe the trucking industry is part of our environmental problems. Super Bs lined up terminal look the same as 3 tons at wooden elevators.

2. The triffid flax adventure where farmers picked up the tab. Not the R&D guys.

3. Let's have the grain commission introduce another class of grain that the elevators don't have the infrastructure to segregate.

I could go on but it's all ****ing bullshit. The reduction in hours on an average farm compared to 25 years ago has been an unpaid contribution to the green ****heads.

Except for the extra diesel burned to get to the elevator.

If people want a society without fossil fuels they can pay for the nonsense instead of taxing the shit out of fossil fuels to pay for it.

86 cents for gas and 37 oil of which cdn oil producers might start with 20 bucks a barrel.

No tin foil but can't these guys just **** off.

[wakopa]

i live in my own little world,making a good living and surrounding myself with good poeple, i dont have the problems most of u agri have .

[wilagro]

I agree with you "bucket"...let these clean-tech nitwits pay for the research. Why tax the users OR the producers of conventional energy for the NEW technology MOST OF WHICH IS TOO EXPENSIVE TO USE AT PRESENT and in reality will NEVER work on any large scale.
====

[oneoff]

I hate to piss on the parade...just kidding; BUT


Has absolutely anyone got the first clue about active power (metered by utility); reactive power (necessary for producing magnetic fields in motors and transformers...but actually detrimental to power transmission and the electrical grid as it is correlated to power factor); and causes transmission losses in electrical grid and increased current flow...but does no usable work.


Now when the electrical system was made up of handfuls of power plants and union trained staff running them; its a whole different game than when you have thousands or tens of thousands of little independent power producers who know nothing about what "dirty power" and harmonics and their cumulative effects on an electrical grids.

And those nasty switching power supplies (even your computer power supplies and probably solar panel inverters just might need to have capacitative or reactive elements to get the minimum power factor of 0.9 that Sask Power would tell you must be met before even being allowed to connect to a grid.

Oh how easy it is when you just copy some promoter/who doesn't consider themselves an environmental lunatic. Don't let laws of physics get in the way of repeating only that which confirms what you already know.

[chuckChuck]

Most of you must hate green technology and don't believe it works. But the evidence is right before your eyes. You really must have a very negative attitude not to even believe that smaller scale renewables can exist with lager scale production when it is already happening in many parts of the world including Canada.

Germany's renewable energy sector is among the most innovative and successful worldwide. Net-generation from renewable energy sources in the German electricity sector has increased from 6.3% in 2000 to about 30% in 2014.[1][2] For the first time ever, wind, biogas, and solar combined accounted for a larger portion of net electricity production than brown coal.[3] While peak-generation from combined wind and solar reached a new all-time high of 74% in April 2014,[4] wind power saw its best day ever on December 12, 2014, generating 562 GWh.[5] Germany has been called "the world's first major renewable energy economy".[6][7]

More than 23,000 wind turbines and 1.4 million solar PV systems are distributed all over the country's area of 357,000 square kilometers.[8][9] As of 2011, Germany's federal government is working on a new plan for increasing renewable energy commercialization,[10] with a particular focus on offshore wind farms.[11] A major challenge is the development of sufficient network capacities for transmitting the power generated in the North Sea to the large industrial consumers in southern parts of the country.[12]

According to official figures, some 370,000 people were employed in the renewable energy sector in 2010, especially in small and medium-sized companies. This is an increase of around 8% compared to 2009 (around 339,500 jobs), and well over twice the number of jobs in 2004 (160,500). About two-thirds of these jobs are attributed to the Renewable Energy Sources Act[13][14]

Germany's energy transition, the Energiewende, designates a significant change in energy policy from 2011. The term encompasses a reorientation of policy from demand to supply and a shift from centralized to distributed generation (for example, producing heat and power in very small cogeneration units), which should replace overproduction and avoidable energy consumption with energy-saving measures and increased efficiency.

[chuckChuck]

Germany recharged: EU powerhouse goes all in on alternative energy

JOANNA SLATER

POTSDAM, GERMANY — The Globe and Mail

Published Friday, Apr. 10, 2015 6:59PM EDT

Last updated Friday, Apr. 10, 2015 7:14PM EDT

On a recent Saturday afternoon, a couple of engineers working the weekend shift were monitoring the regional electricity grid in the heart of Potsdam, a city south of Berlin. The control room was largely quiet as the technicians bent over their workstations, scrutinizing the flow of power through the system.
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Ralf Doering, a network manager for E.dis AG, the grid operator, pointed to a screen, where an innocuous-looking red line on a chart had just dropped to zero. The line measured how much electricity the grid drew from conventional sources of energy.

As of a few minutes earlier, a swath of northeastern Germany from the Baltic Sea to the Polish border, an area roughly the size of Switzerland, was being powered entirely by energy from the wind and the sun. A group of visitors looked around the room – at the lights, the computers, the equipment – and mentally multiplied the scene across the entire region. “Solar and wind are now enough,” Mr. Doering said matter-of-factly.

If Germany continues on its current course, such moments will become commonplace. The country has embarked on the most ambitious energy revolution anywhere in the industrialized world. Last year, 26 per cent of Germany’s power supply came from renewable sources. By 2050, the figure is targeted to rise to 80 per cent. The shift, Foreign Minister Frank-Walter Steinmeier said last month, is Germany’s “man on the moon” project.

As Germany has discovered, however, a project with sky-high aims can carry a huge price tag. The initiative, which began in 2000 and is a top priority for Chancellor Angela Merkel, has pushed electricity prices for German consumers to the second-highest level in the European Union, behind Denmark. German businesses also pay some of the highest prices for power in the region, with exceptions for certain energy-intensive industries.

German business groups complain that the country’s energy policy hurts their ability to compete and plan long-term investments. They’re especially galled by Ms. Merkel’s decision, in the wake of the Fukushima disaster in 2011, to commit to closing of all of Germany’s nuclear power plants by 2022.

More recently, the energy policy – which is aimed squarely at reducing Germany’s contribution to climate change – witnessed a disturbing paradox. Between 2009 and 2013, carbon dioxide emissions from Germany’s power sector actually rose, despite the growing share of electricity produced by wind, solar, hydro and biomass. That’s because power companies were increasing their use of cheap but carbon-laden energy sources like lignite and hard coal compared to previous years. Those sources became more attractive for two reasons, experts say: the higher price of natural gas and the low cost of carbon-emissions permits in the European trading system.

Alarmed by that development and by the upward march of electricity prices, Ms. Merkel’s government introduced revised energy legislation last year that moved to rein in the surcharges for renewable energy. The government is also looking at placing new restrictions on coal producers to bring down emissions. Experts estimate that emissions in 2014 from Germany’s power sector fell to their lowest point since 2009.

Despite the hurdles, Germany is plunging full-speed ahead in what is known here as the “Energiewende,” or energy transition. But its leaders acknowledge that unless Germany can prove that the policy works for businesses too, it risks being deemed a failure.

“We need to show that in a country like Germany and a continent like Europe, it is possible to have a high level of industrialization” in combination with policies to mitigate climate change, Sigmar Gabriel, the Economy and Energy Minister, said last month. Only then, he said, “will we find that other countries follow us. Only then will we persuade people.”

Unintended consequences

In late March, policy makers from more than 50 countries gathered in Berlin for a conference to discuss the challenges of transforming a country’s energy supply. Some were from oil-rich nations such as Kuwait and Algeria; others were from smaller European nations that already generate much of their electricity from renewable sources. In Portugal, for instance, the figure is more than 60 per cent.

What Germany is attempting, however, is far more complicated. It is the world’s fourth-biggest economy, with a large industrial sector. Other major economies such as France and the United Kingdom have less lofty targets for renewable energy and aren’t phasing out nuclear power.

At the conference, Jan Mladek, the Czech Minister of Trade and Iindustry, told a story that pointed to some of the difficulties Germany faces. On a visit last year to Berlin, Mr. Mladek said, he met with federal officials who urged him to speed up the Czech Republic’s adoption of renewable energy. Then, later that same day, he met with the Premier of the state of Saxony, which borders the Czech Republic. The Premier urged Mr. Mladek not to build wind farms near the border, fearing it would destroy Saxony’s tourism industry.

The story epitomizes how each step Germany has taken toward greater use of renewables has created new and sometimes unforeseen challenges – in electricity prices, in carbon emissions and in power distribution.

In Germany, consumers paid an average of nearly 30 euro cents (41 cents) per kilowatt-hour for electricity last year. In Ontario, by contrast, the peak price is currently 14 cents; the average price for consumers in the United States is similar.

Here’s what happened to prices. To hasten the adoption of renewable energy, Germany guaranteed long-term price contracts to such producers – a technique also common elsewhere in the world. The difference between those guaranteed prices and the price of power sold on the wholesale market gets passed on to consumers.

In Germany, that difference is known as the renewable energy surcharge. The surcharge has jumped from 1 euro cent per kilowatt-hour in 2009 to more than 6 euro cents currently. The increase is due to a rapid growth in the installation of green power, which has also helped to drive the market price down.

So consumers have paid more, even as the market price for German electricity has fallen considerably, because the surcharge must fill the gap. In its reforms last year, the government moved to curb further increases in the surcharge.

Despite the rising prices, support for the government’s energy policy remains strong, said Claudia Kempfert, an energy expert at the German Institute for Economic Research in Berlin. Electricity accounts for just 3 per cent of the average household’s budget, she noted, compared to heating and transportation, which takes up 30 per cent. A poll conducted last year found that 92 per cent of Germans favoured expanding renewable energy.

Businesses are far less sanguine than consumers about shouldering the costs of the transition. Electricity prices for industrial customers have risen more than 40 per cent since 2008 and companies say the policy has begun to affect their investment decisions.

The “huge costs for promoting renewable forms of energy restrict the competitiveness of our companies,” a spokesman for the German Association of the Automotive Industry said in a statement. “In the long run, that will damage employment at home.”

BASF, a chemicals giant, has said it will focus its new investments outside Germany as a result of energy costs. Last year, SGL Carbon SE and BMW Group said they would invest an additional $200-million (U.S.) in a carbon-fibre manufacturing facility in Washington state. A driving force behind the decision: the availability of cheap power.

BASF and SGL Carbon are among the roughly 2,300 large, energy-intensive German companies that are exempted from paying the renewable energy surcharge through at least 2017. But even some of these firms assert that the energy policy isn’t working.

Heribert Hauck, director of energy affairs at Trimet Aluminium SE, a large consumer of electricity, said the shifting policy terrain is making long-term investments impossible for his firm.

What’s more, he added, the volatility of renewable energy – the sun doesn’t always shine and the wind doesn’t always blow – makes it unsuitable to meet the burden of constant industrial demand.

Germany, like other countries, has not yet solved the dilemma of how to store the electricity produced by solar power and wind energy. And it has only begun to tackle the transportation of such energy, which is primarily produced in the north of the country, to the industrial heartland in the south. One major planned transmission route from north to south – the “Stromautobahn,” or electricity highway – has faced intense protest from those living in its path.

“We can implement the Energiewende up to a certain degree,” said Mr. Hauck of Trimet. But the government must leave a “supply of conventional, reliable, competitive power plants in the system. That’s what industry needs.”

Smaller companies have complaints too. Horst Linn runs a maker of industrial furnaces in Bavaria, typical of the thousands of so-called “Mittlestand” firms that form the backbone of the German manufacturing sector.

The government’s focus on renewables is wrong-headed, Mr. Linn said. Instead, it should have focused on energy-saving technology, he asserted.

Mr. Linn estimates that his company’s electricity costs have jumped 30 per cent in the past five years and fears that more increases lie ahead as the country phases out nuclear power. Yet he’s never seriously considered operating anywhere else because of the skilled labour and quality control required in his business.

“You have no chance with the product we make to go to Bulgaria,” he said.

Fingers crossed

In the middle of March, Germany’s solar industry faced a critical test. A partial eclipse for several hours on the morning of March 20 threatened to wreak havoc on the system: Grid operators faced an unprecedented fluctuation in electricity supply as sunlight disappeared with unusual speed, only to reappear with the same unusual alacrity. (Prior to the eclipse, representatives of the solar industry had asserted everything would be fine. But “really, we were like this,” said a spokesman for the industry, holding up crossed fingers on both hands).

The industry passed the test and hailed it as proof that renewable energies were now a mature and successful part of Germany’s electricity system. As the shift to renewable energy deepens, some power producers see the writing on the wall. E.on SE, a major German utility, announced in December that it would split its businesses into two.

The first will be composed of its conventional energy assets and the second will consist of its ventures in alternative energy and distribution. Some commentators likened the move to the manoeuvre deployed by some financial institutions in the wake of the 2008 crisis: dividing healthy and troubled assets into a “good” bank and a “bad” bank.

Germany’s Greens, the political party that helped kick off the energy revolution, tend to dismiss business concerns as so much bellyaching. In recent years, Germany has notched the strongest economic performance of any major European country at the same time as it has implemented the energy transition, proponents of the policy say. Norsk Hydro ASA, a Swedish company, is increasing its aluminum production in Germany, Baerbel Hoehn, a Greens member of the Bundestag, said in a recent statement.

For the Greens, the future looks a little like Feldheim, a small village of neat brick-and-stucco houses south of Berlin. On a ridge near the village, 47 wind turbines generate enough electricity to power the community’s needs 100 times over; the rest is sold to the regional grid.

The village also generates its own heat from a heavily subsidized biogas plant. Next up: a test project to create a lithium-ion battery storage facility for the renewable energy the village produces, the largest such installation in Europe.

Of course, there’s no industry whatsoever in Feldheim. Back in the grid control room in Potsdam, the electrical engineers note that the region they oversee has very few industrial concerns, which makes it easier to incorporate alternative energies.

Meanwhile, they’re plowing ahead with the many different facets of the Energiewende. “For us as engineers, it’s really challenging and exciting,” said Bernd Westphal, a regional manager at E.dis. “We’re not getting bored here.”

[bucket]

What I get out of those articles is that it is an expensive option for canada as a low contributor on a percentage of total world emissions.

In other words we could go back to an unpopulated 1800 in canada and we still wouldn't make a difference in the world.

It makes it very expensive and those that want to explore it should pay and work to reducing the cost of this nonsense.

I have a tractor that is supposed to be environmentally friendly but never had so much trouble with a 4wd in my life.

Alarms and air filters cost would run past my lease cost if I replaced them as often as it said. It becomes a non productive piece of shit. And yeah its a deere.

[tweety]

[URL="http://news.mit.edu/2016/heat-loss-fusion-reactors-0121"]http://news.mit.edu/2016/heat-loss-fusion-reactors-0121[/URL]

[Hamloc]

My take is that average price of power is 30 cents a kwh in Germany and 14 cents a kwh in Ontario may have read that wrong. You can get 6 cents a kwh contracts in Alberta now but that might not last long. Also noted that big companies are investing outside Germany where power is cheaper. Chuck2 did you read this article not your usual bullshit propaganda lol!!!

[oneoff]

The article stated "In Germany, consumers paid an average of nearly 30 euro cents (41 cents) per kilowatt-hour for electricity last year"...not 30 cents.

And it talks glowingly of residential demand; which is differentiated quite differently from manufacturing usage of electrical energy.

Do people know what 41 cents per Kwh would mean for consumers in Western Canada. It would mean you couldn't afford to aerate grain. Electric heat for a house would be exhorbitent. Some people would freeze to death. Rinks couldn't afford the lighting bills and artificial ice would break the budget of local rinks. Anyone should be ashamed of themselves for actively promoting such economic hardships on their supposed communities.


This is absurd. And the intent is to make heating energy of any sort cost in the same realm as electrical energy.

[Hamloc]

Thanks for the correction Oneoff, when I am reading an article like this my blood pressure is so high it affect my eyesight lol.

[oneoff]

How could anyone even be sure that any correction was required. We're both relying on someone else's report; figures that may or may not be accurate; deliberately misleading; and maybe not even applicable to a "problem" that may capable of being solved by following the path that some chunks of the world have swallowed hook line and sinker.

Still its necessary to first decide how may human beings the world can sustain now and into the future. No one wants to touch that subject.

[chuckChuck]

So how come Germany has the strongest economy in Europe? And still has alot of support for renewables?

So I guess you both must know what Sask Powers cost projections are for all the renewables they are going to put on line?

What is the cost of renewables vs coal ,nuclear, and oil in 20, 40, 60, 80 100 years? Hydro is considered renewable and low cost.

Guess what happens when prices for energy go up? Consumers and industry use less and become more efficient and less wastefull.

The sky is falling chicken little, better run an hide from renewables.

[chuckChuck]

https://www.eia.gov/forecasts/aeo/electricity_generation.cfm

Levelized Cost and Levelized Avoided Cost of New Generation Resources in the Annual Energy Outlook 2015

Release date: June 3, 2015

This paper presents average values of levelized costs for generating technologies that are brought online in 20201 as represented in the National Energy Modeling System (NEMS) for the Annual Energy Outlook 2015 (AEO2015) Reference case.2 Both national values and the minimum and maximum values across the 22 U.S. regions of the NEMS electricity market module are presented.

Levelized cost of electricity (LCOE) is often cited as a convenient summary measure of the overall competiveness of different generating technologies. It represents the per-kilowatthour cost (in real dollars) of building and operating a generating plant over an assumed financial life and duty cycle. Key inputs to calculating LCOE include capital costs, fuel costs, fixed and variable operations and maintenance (O&M) costs, financing costs, and an assumed utilization rate for each plant type.3 The importance of the factors varies among the technologies. For technologies such as solar and wind generation that have no fuel costs and relatively small variable O&M costs, LCOE changes in rough proportion to the estimated capital cost of generation capacity. For technologies with significant fuel cost, both fuel cost and overnight cost estimates significantly affect LCOE. The availability of various incentives, including state or federal tax credits, can also impact the calculation of LCOE. As with any projection, there is uncertainty about all of these factors and their values can vary regionally and across time as technologies evolve and fuel prices change.

It is important to note that, while LCOE is a convenient summary measure of the overall competiveness of different generating technologies, actual plant investment decisions are affected by the specific technological and regional characteristics of a project, which involve numerous other factors. The projected utilization rate, which depends on the load shape and the existing resource mix in an area where additional capacity is needed, is one such factor. The existing resource mix in a region can directly impact the economic viability of a new investment through its effect on the economics surrounding the displacement of existing resources. For example, a wind resource that would primarily displace existing natural gas generation will usually have a different economic value than one that would displace existing coal generation.

A related factor is the capacity value, which depends on both the existing capacity mix and load characteristics in a region. Since load must be balanced on a continuous basis, units whose output can be varied to follow demand (dispatchable technologies) generally have more value to a system than less flexible units (non-dispatchable technologies), or those whose operation is tied to the availability of an intermittent resource. The LCOE values for dispatchable and nondispatchable technologies are listed separately in the tables, because caution should be used when comparing them to one another.

Since projected utilization rates, the existing resource mix, and capacity values can all vary dramatically across regions where new generation capacity may be needed, the direct comparison of LCOE across technologies is often problematic and can be misleading as a method to assess the economic competitiveness of various generation alternatives. Conceptually, a better assessment of economic competitiveness can be gained through consideration of avoided cost, a measure of what it would cost the grid to generate the electricity that is otherwise displaced by a new generation project, as well as its levelized cost. Avoided cost, which provides a proxy measure for the annual economic value of a candidate project, may be summed over its financial life and converted to a stream of equal annual payments. The avoided cost is divided by average annual output of the project to develop the "levelized" avoided cost of electricity (LACE) for the project.4 The LACE value may then be compared with the LCOE value for the candidate project to provide an indication of whether or not the project's value exceeds its cost. If multiple technologies are available to meet load, comparisons of each project's LACE to its LCOE may be used to determine which project provides the best net economic value. Estimating avoided costs is more complex than estimating levelized costs because it requires information about how the system would have operated without the option under evaluation. In this discussion, the calculation of avoided costs is based on the marginal value of energy and capacity that would result from adding a unit of a given technology and represents the potential revenue available to the project owner from the sale of energy and generating capacity. While the economic decisions for capacity additions in EIA's long-term projections use neither LACE nor LCOE concepts, the LACE and net value estimates presented in this report are generally more representative of the factors contributing to the projections than looking at LCOE alone. However, both the LACE and LCOE estimates are simplifications of modeled decisions, and may not fully capture all decision factors or match modeled results.

Policy-related factors, such as environmental regulations and investment or production tax credits for specified generation sources, can also impact investment decisions. Finally, although levelized cost calculations are generally made using an assumed set of capital and operating costs, the inherent uncertainty about future fuel prices and future policies may cause plant owners or investors who finance plants to place a value on portfolio diversification. While EIA considers many of these factors in its analysis of technology choice in the electricity sector, these concepts are not included in LCOE or LACE calculations.

The LCOE values shown for each utility-scale generation technology in Table 1 and Table 2 in this discussion are calculated based on a 30-year cost recovery period, using a real after tax weighted average cost of capital (WACC) of 6.1%5. In reality, the cost recovery period and cost of capital can vary by technology and project type. In the AEO2015 reference case, 3 percentage points are added to the cost of capital when evaluating investments in greenhouse gas (GHG) intensive technologies like coal-fired power and coal-to-liquids (CTL) plants without carbon control and sequestration (CCS). In LCOE terms, the impact of the cost of capital adder is similar to that of an emissions fee of $15 per metric ton of carbon dioxide (CO2) when investing in a new coal plant without CCS, which is representative of the costs used by utilities and regulators in their resource planning.6 The adjustment should not be seen as an increase in the actual cost of financing, but rather as representing the implicit hurdle being added to GHG-intensive projects to account for the possibility that they may eventually have to purchase allowances or invest in other GHG-emission-reducing projects to offset their emissions. As a result, the LCOE values for coal-fired plants without CCS are higher than would otherwise be expected.

The levelized capital component reflects costs calculated using tax depreciation schedules consistent with permanent tax law, which vary by technology. Although the capital and operating components do not incorporate the production or investment tax credits available to some technologies, a subsidy column is included in Table 1 to reflect the estimated value of these tax credits, where available, in 2020. In the reference case, tax credits are assumed to expire based on current laws and regulations.

Some technologies, notably solar photovoltaic (PV), are used in both utility-scale generating plants and distributed end-use residential and commercial applications. As noted above, the LCOE (and also subsequent LACE) calculations presented in the tables apply only to the utility-scale use of those technologies.

In Table 1 and Table 2, the LCOE for each technology is evaluated based on the capacity factor indicated, which generally corresponds to the high end of its likely utilization range. Simple combustion turbines (conventional or advanced technology) that are typically used for peak load duty cycles are evaluated at a 30% capacity factor. The duty cycle for intermittent renewable resources, wind and solar, is not operator controlled, but dependent on the weather or solar cycle (that is, sunrise/sunset) and so will not necessarily correspond to operator dispatched duty cycles. As a result, their LCOE values are not directly comparable to those for other technologies (even where the average annual capacity factor may be similar) and therefore are shown in separate sections within each of the tables. The capacity factors shown for solar, wind, and hydroelectric resources in Table 1 are simple averages of the capacity factor for the marginal site in each region. These capacity factors can vary significantly by region and can represent resources that may or may not get built in EIA capacity projections. Projected capacity factors for these resources in the AEO 2015 or other EIA analyses will not necessarily correspond to these levels.
Table 1. Estimated levelized cost of electricity (LCOE) for new generation resources, 2020 U.S. average levelized costs (2013 $/MWh) for plants entering service in 20201
Plant type Capacity factor (%) Levelized capital cost Fixed O&M Variable O&M (including fuel) Transmission investment Total system LCOE Subsidy2 Total LCOE including Subsidy
Dispatchable Technologies
Conventional Coal 85 60.4 4.2 29.4 1.2 95.1
Advanced Coal 85 76.9 6.9 30.7 1.2 115.7
Advanced Coal with CCS 85 97.3 9.8 36.1 1.2 144.4
Natural Gas-fired
ConventionalCombined Cycle 87 14.4 1.7 57.8 1.2 75.2
Advanced Combined Cycle 87 15.9 2.0 53.6 1.2 72.6
Advanced CC with CCS 87 30.1 4.2 64.7 1.2 100.2
Conventional Combustion Turbine 30 40.7 2.8 94.6 3.5 141.5
Advanced Combustion Turbine 30 27.8 2.7 79.6 3.5 113.5
Advanced Nuclear 90 70.1 11.8 12.2 1.1 95.2
Geothermal 92 34.1 12.3 0.0 1.4 47.8 -3.4 44.4
Biomass 83 47.1 14.5 37.6 1.2 100.5
Non-Dispatchable Technologies
Wind 36 57.7 12.8 0.0 3.1 73.6
Wind – Offshore 38 168.6 22.5 0.0 5.8 196.9
Solar PV3 25 109.8 11.4 0.0 4.1 125.3 -11.0 114.3
Solar Thermal 20 191.6 42.1 0.0 6.0 239.7 -19.2 220.6
Hydroelectric4 54 70.7 3.9 7.0 2.0 83.5

1Costs for the advanced nuclear technology reflect an online date of 2022.
2The subsidy component is based on targeted tax credits such as the production or investment tax credit available for some technologies. It only reflects subsidies available in 2020, which include a permanent 10% investment tax credit for geothermal and solar technologies. EIA models tax credit expiration as follows: new solar thermal and PV plants are eligible to receive a 30% investment tax credit on capital expenditures if placed in service before the end of 2016, and 10% thereafter. New wind, geothermal, biomass, hydroelectric, and landfill gas plants are eligible to receive either: (1) a $23.0/MWh ($11.0/MWh for technologies other than wind, geothermal and closed-loop biomass) inflation-adjusted production tax credit over the plant's first ten years of service or (2) a 30% investment tax credit, if they are under construction before the end of 2013. Up to 6 GW of new nuclear plants are eligible to receive an $18/MWh production tax credit if in service by 2020; nuclear plants shown in this table have an in-service date of 2022.
3Costs are expressed in terms of net AC power available to the grid for the installed capacity.
4As modeled, hydroelectric is assumed to have seasonal storage so that it can be dispatched within a season, but overall operation is limited by resources available by site and season.
Source: U.S. Energy Information Administration, Annual Energy Outlook 2015, April 2015, DOE/EIA-0383(2015).

As mentioned above, the LCOE values shown in Table 1 are national averages. However, as shown in Table 2, there is significant regional variation in LCOE values based on local labor markets and the cost and availability of fuel or energy resources such as windy sites. For example, LCOE for incremental wind capacity coming online in 2020 ranges from $65.6/MWh in the region with the best available resources in 2020 to $81.6/MWh in regions where LCOE values are highest due to lower quality wind resources and/or higher capital costs for the best sites that can accommodate additional wind capacity. Costs shown for wind may include additional costs associated with transmission upgrades needed to access remote resources, as well as other factors that markets may or may not internalize into the market price for wind power.

As previously indicated, LACE provides an estimate of the cost of generation and capacity resources displaced by a marginal unit of new capacity of a particular type, thus providing an estimate of the value of building such new capacity. This is especially important to consider for intermittent resources, such as wind or solar, that have substantially different duty cycles than the baseload, intermediate and peaking duty cycles of conventional generators. Table 3 provides the range of LACE estimates for different capacity types. The LACE estimates in this table have been calculated assuming the same maximum capacity factor as in the LCOE. A subset of the full list of technologies in Table 1 is shown because the LACE value for similar technologies with the same capacity factor would have the same value (for example, conventional and advanced combined cycle plants will have the same avoided cost of electricity). Values are not shown for combustion turbines, because turbines are more often built for their capacity value to meet a reserve margin rather than to meet generation requirements and avoid energy costs.
Table 2. Regional variation in levelized cost of electricity (LCOE) for new generation resources, 20201 Range for total system LCOE
(2013 $/MWh) Range for total LCOE with subsidies2
(2013 $/MWh)
Plant type Minimum Average Maximum Minimum Average Maximum
Dispatchable Technologies
Conventional Coal 87.1 95.1 119.0
Advanced Coal 106.1 115.7 136.1
Advanced Coal with CCS 132.9 144.4 160.4
Natural Gas-fired
Conventional Combined Cycle 70.4 75.2 85.5
Advanced Combined Cycle 68.6 72.6 81.7
Advanced CC with CCS 93.3 100.2 110.8
Conventional Combustion Turbine 107.3 141.5 156.4
Advanced Combustion Turbine 94.6 113.5 126.8
Advanced Nuclear 91.8 95.2 101
Geothermal 43.8 47.8 52.1 41.0 44.4 48.0
Biomass 90.0 100.5 117.4
Non-Dispatchable Technologies
Wind 65.6 73.6 81.6
Wind – Offshore 169.5 196.9 269.8
Solar PV3 97.8 125.3 193.3 89.3 114.3 175.8
Solar Thermal 174.4 239.7 382.5 160.4 220.6 351.7
Hydroelectric4 69.3 83.5 107.2

1Costs for the advanced nuclear technology reflect an online date of 2022.
2Levelized cost with subsidies reflects subsidies available in 2020, which include a permanent 10% investment tax credit for geothermal and solar technologies.
3Costs are expressed in terms of net AC power available to the grid for the installed capacity.
4As modeled, hydroelectric is assumed to have seasonal storage so that it can be dispatched within a season, but overall operation is limited by resources available by site and season.
Note: The levelized costs for non-dispatchable technologies are calculated based on the capacity factor for the marginal site modeled in each region, which can vary significantly by region. The capacity factor ranges for these technologies are as follows: Wind – 31% to 40%, Wind Offshore – 33% to 42%, Solar PV – 22% to 32%, Solar Thermal – 11% to 26%, and Hydroelectric – 35% to 65%. The levelized costs are also affected by regional variations in construction labor rates and capital costs as well as resource availability.
Source: U.S. Energy Information Administration, Annual Energy Outlook 2015, April 2015, DOE/EIA-0383(2015).

When the LACE of a particular technology exceeds its LCOE at a given time and place, that technology would generally be economically attractive to build. While the build decisions in the real world, and as modeled in the AEO, are somewhat more complex than a simple LACE to LCOE comparison, including such factors as policy and non-economic drivers, the net economic value (LACE minus LCOE, including subsidy, for a given technology, region and year) shown in Table 4 provides a reasonable point of comparison of first-order economic competitiveness among a wider variety of technologies than is possible using either the LCOE or LACE tables individually. In Table 4, a negative difference indicates that the cost of the marginal new unit of capacity exceeds its value to the system, as measured by LACE; a positive difference indicates that the marginal new unit brings in value in excess of its cost by displacing more expensive generation and capacity options. The range of differences columns represent the variation in the calculation of the difference for each region. For example, in the region where the advanced combined cycle appears most economic in 2020, the LCOE is $74.6/MWh and the LACE is $75.8/MWh, resulting in a net difference of $1.2/MWh. This range of differences is not based on the difference between the minimum values shown in Table 2 and Table 3, but represents the lower and upper bound resulting from the LACE minus LCOE calculations for each of the 22 regions.
Table 3. Regional variation in levelized avoided costs of electricity (LACE) for new generation resources, 20201 Range for LACE (2013 $/MWh)
Plant type Minimum Average Maximum
Dispatchable Technologies
Coal without CCS 65.9 70.9 80.8
IGCC with CCS2 65.9 71.0 80.8
Natural Gas-fired Combined Cycle 65.8 71.4 80.7
Advanced Nuclear 68.4 72.1 82.0
Geothermal 70.7 70.9 71.0
Biomass 66.0 71.7 80.9
Non-Dispatchable Technologies
Wind 60.6 64.6 69.0
Wind – Offshore 64.6 71.5 78.1
Solar PV 61.6 80.4 92.3
Solar Thermal 59.4 83.0 89.4
Hydroelectric 64.8 69.5 80.0

1Costs for the advanced nuclear technology reflect an online date of 2022.
2Coal without CCS cannot be built in California, therefore the average LACE for coal technologies without CCS is computed over fewer regions than the LACE for IGCC with CCS.
Otherwise, the LACE for any given region is the same across coal technologies, with or without CCS.

The average net differences shown in Table 4 are for plants coming online in 2020, consistent with Tables 1-3, as well as for plants that could come online in 2040, to show how the relative competitiveness changes over the projection period. Additional tables showing the LCOE cost components and regional variation in LCOE and LACE for 2040 can be found in the Appendix. In 2020, the average net differences are negative for all technologies except geothermal, reflecting the fact that on average, new capacity is not needed in 2020. However, the upper value for the advanced combined cycle technology is above zero, indicating competiveness in a particular region. Geothermal cost data is site-specific, and the relatively large positive value for that technology results because there may be individual sites that are very cost competitive, leading to new builds, but there is a limited amount of capacity available at that cost. By 2040, the LCOE values for most technologies are lower, typically reflecting declining capital costs over time. All technologies receive cost reductions from learning over time, with newer, advanced technologies receiving larger cost reductions, while conventional technologies will see smaller learning effects. Capital costs are also adjusted over time based on commodity prices, through a factor based on the metals and metal products index, which declines in real terms over the projection. However, the LCOE for natural gas-fired technologies rises over time, because rising fuel costs more than offset any decline in capital costs. The LACE values for all technologies increase by 2040 relative to 2020, reflecting higher energy costs and a greater value for new capacity. As a result, the difference between LACE and LCOE for almost all technologies gets closer to a net positive value in 2040, and there are several technologies (advanced combined cycle, wind, solar PV, and geothermal) that have regions with positive net differences.
Table 4. Difference between levelized avoided costs of electricity (LACE) and levelized costs of electricity (LCOE), 20201 and 2040 Comparison of LACE - LCOE (2013 /$MWh)
Range of Differences
Plant type Average LCOE Average LACE Average Difference Minimum of Range Maximum of range
2020
Dispatchable Technologies
Conventional Coal 95.1 70.9 -24.1 -43.0 -15.5
Advanced Coal 115.7 70.9 -44.7 -60.0 -34.6
Advanced Coal with CCS 144.4 71.0 -73.4 -88.9 -61.4
Natural Gas-fired
Conventional Combined Cycle 75.2 71.4 -3.8 -10.8 -1.8
Advanced Combined Cycle 72.6 71.4 -1.2 -7.6 1.2
Advanced CC with CCS 100.2 71.4 -28.8 -35.9 -22.5
Advanced Nuclear 95.2 72.1 -23.2 -31.4 -10.6
Geothermal 44.4 70.9 26.5 22.7 30.0
Biomass 100.5 71.7 -28.8 -44.4 -16.9
Non-Dispatchable Technologies
Wind 73.6 64.6 -9.0 -19.6 0.1
Wind – Offshore 196.9 71.5 -125.5 -191.6 -98.3
Solar PV 114.3 80.4 -33.9 -83.5 -10.5
Solar Thermal 220.6 83.0 -137.5 -266 -74.3
Hydroelectric 83.5 69.5 -14 -33.9 -1.4
2040
Dispatchable Technologies
Conventional Coal 91.7 78.9 -12.8 -34.6 -3.5
Advanced Coal 105.5 78.9 -26.6 -43.3 -17.1
Advanced Coal with CCS 127.6 79.2 -48.4 -58.9 -38.7
Natural Gas-fired
Conventional Combined Cycle 82.6 79.3 -3.3 -9.9 -1.2
Advanced Combined Cycle 79.3 79.3 -0.1 -5.6 2.1
Advanced CC with CCS 106.3 79.3 -27.0 -32.8 -21.9
Advanced Nuclear 88.9 78.7 -10.3 -19.3 -0.2
Geothermal 56.9 80.6 23.7 -2.8 50.2
Biomass 93.5 79.6 -13.9 -34.0 -1.6
Non-Dispatchable Technologies
Wind 75.1 71.7 -3.4 -47.9 8.6
Wind – Offshore 175.6 79.3 -96.3 -155.6 -69.9
Solar PV 107.1 91 -16.1 -70.1 3
Solar Thermal 197.1 95.6 -101.5 -210.9 -49.1
Hydroelectric 89.9 77.7 -12.2 -30.4 -0.5
1Costs for the advanced nuclear technology reflect an online date of 2022.
Footnotes

1 2020 is shown for all technologies except for the advanced nuclear plant type. Because of additional licensing requirements for new, unplanned nuclear units, the AEO2015 assumes 2022 is the first year a new nuclear plant, not already under construction, could come online and the LCOE/LACE in tables 1-4 represent data consistent with the 2022 online date.

2 The full report is available at http://www.eia.gov/forecasts/aeo/index.cfm.

3 The specific assumptions for each of these factors are given in the Assumptions to the Annual Energy Outlook, available at http://www.eia.gov/forecasts/aeo/assumptions/.

4 Further discussion of the levelized avoided cost concept and its use in assessing economic competitiveness can be found in this article: http://www.eia.gov/renewable/workshop/gencosts/.

5 The real WACC for plants entering service in 2020 is 6.1%; nuclear plants are assumed to enter service in 2022 and have a real WACC of 6.2%. The real WACC corresponds to a nominal after tax rate of 8.1% for both plants entering service in 2020 and 2022. An overview of the WACC assumptions and methodology can be found in the Electricity Market Module of the National Energy Modeling System: Model Documentation. This report can be found at http://www.eia.gov/forecasts/aeo/nems/documentation/electricity/pdf/m068(2014).pdf.

6 Morgan Stanley, "Leading Wall Street Banks Establish The Carbon Principles" (Press Release, February 4, 2008), www.morganstanley.com/about/press/articles/6017.html.
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