A Steady Hand: Dispatchable Renewables

Ship's wheel


As stated previously, intermittent renewable power from wind and solar PVs, without balancing generation or storage, will not be able to support a modern electric system that requires electricity to be dispatched on demand.  Though a definitive number has not been established for the Texas ERCOT grid, in general terms, only about 25% of intermittent electricity can be integrated on a conventional electric system without technical and/or economic trade-offs.  Even if technical progress pushes this limitation upwards, the need for dispatchable power will not go away anytime in the near future (if at all).

Energy efficiency, Smart Grid technologies and strategies, and intermittent wind power and photovoltaics can possibly displace or produce 40 to 50% of Austin’s per-customer electricity consumption on a sustainable basis.  Some type of steady power will be necessary for the balance.

Some environmentalists have proposed building long-distance power lines from one region of the U.S. to another, with the goal of balancing load between regions.  If one region is low on intermittent wind and solar resources, another will take up slack.  This is certainly possible, but also expensive, and may still require some extra level of storage during rare but critical times.  There may also be resistance from state government, which intentionally set up the Texas ERCOT electric system independent of the national grid network to avoid federal regulation.

In looking at dispatchable clean energy alternatives for this article, both battery storage and nuclear power were not considered, and for good reasons.

There is considerable optimism…and hype…about the future of batteries for electric storage.  These are still expensive, and despite vague promises, there is no certainty that they will be cost effective to store large amounts of power in the short or mid-term future.  Consider that even if the cost of the battery itself goes down, there are other large costs for shipping, taxes, installation, inverters and wiring, housing, temperature conditioning, maintenance, depreciation, and electric losses.  Adding enough battery power to store solar power for nighttime use would be incredibly expensive for the average ratepayer. Adding enough battery power for a week would be unimaginably expensive.1

Nuclear power is not clean energy, and is not even carbon free as is often claimed.  Energy used to manufacture massive amounts of concrete and steel, in addition to energy used to mine and purify uranium, dispose of nuclear waste, and decommission retired plants, emit substantial amounts of greenhouse gases, though less than a gas or coal plant.

The 2011 meltdown at Japan’s Fukushima nuclear station was still not completely contained at the beginning of 2017.  A thousand square miles surrounding the 1986 Chernobyl meltdown were still contaminated and quarantined in 2017 as well.  These are not indicators of sustainability.  Even if you attempt to trade these environmental disasters for less carbon emissions, the high costs of new reactors are a major deterrent to expanding the fleet of domestic nuclear plants.

Texas has no substantial amount of hydroelectric potential, and it also lacks substantial resources for high-temperature geothermal energy that lie close to the earth’s surface (so that the wells do not require expensive drilling and pumping).

In this article, the Directory has examined 4 clean energy options as alternatives: 1) Biogas; 2) Biomass in the form of wood pellets; 3) Concentrating Solar Power; and 4) Compressed Air Energy Storage (CAES) coupled with intermittent renewable energy.  The good news is that they are all technically feasible now, and the prices for them can be lower than they are today due to the learning curve of technology and economies of scale.  The bad news is that even when they reach full commercialization, they may still come at a higher cost than some sources of conventional power…if you ignore the costs to the environment.

While these dispatchable renewables can compete or come close to competing with new coal and nuclear plants, the costs for these conventional sources are so high that few utilities in the country are even considering them, at least without subsidies.  Repowering (refurbishing) and relicensing existing power plants, and building new combined cycle natural gas plants, are preferred economic options.

This article will discuss dispatchable renewable technologies appropriate for Texas, their expected costs and barriers, and strategies that might keep costs down.


Biogas digester next to wind farm
Biogas anaerobic digestion tanks produce renewable fuel
to fill in the gaps of intermittent wind power


The decomposition of organic matter stemming from animal and plant life emits methane, the primary component of natural gas.  Capturing this can create useful fuel for electric production, home heating, and transportation fuel.

In many countries, including the U.S., it is common to capture the waste gas from landfills and sewage treatment to use for electric production, and occasionally, auto fleets.  Austin Energy buys biogas electricity from generators located in a Northeast Austin landfill.  The Austin Water Utility has a relatively small biogas generator at its Hornsby Bend Biosolids Management Plant in East Austin.

Biogas can also be produced via anaerobic bacteria (bacteria that do not thrive in oxygen) in digestion tanks from manure at animal feedlots and dairy farms, as well as food waste. Biogas conversion can also have a positive effect on the environment by creating an alternative to massive sewage treatment facilities while simultaneously providing agricultural fertilizer and animal bedding.

Texas is the largest cattle producing state in the country.  At 11.8 million head in 2015, there was no equal.  The state also raised 28.3 million dairy cows, hogs, sheep, goats, and chickens.2  Capturing the methane from Texas commercial animal production waste has the potential to create 50.7 million MCF (thousand cubic feet) per year at a cost of roughly $8.12/MCF (2016 dollars, including pipeline transportation).3

Capturing the methane from Texas landfills could produce another 22.7 million MCF of fuel at a cost of about $5.93/MCF (2016 dollars, transportation included).4  Some of this landfill gas has already been captured, though this has not been separated out in this estimate.

As a point of comparison, the average cost of gas for electric production over the 10 years between 2006 and 2015 was $5.49/MCF (2016 dollars).5  While the cost of biogas is higher, it is low compared to other dispatchable biomass electric generation options discussed later in this story.

This is a “drop-in” fuel replacement.  Biogas, when upgraded to natural gas pipeline standards, has a very similar heat value to the conventional fuel, but the supply is almost insignificant compared to Texas’ energy demand.

If the entire estimated supply of animal manure and landfill gas in Texas were processed for biogas production, it could supply slightly more than Austin’s total electricity consumption in 2016 if the fuel were consumed in the most efficient gas plants currently available.  However, since Austin is part of the ERCOT balancing grid, the biogas supply would amount to only about 4% of total grid consumption in 2015, and ERCOT consumption between 2006 and 2015 grew at an average of 1.5% a year.6

Another complication for biogas in the production of electricity is that due to federal tax credits, it can often get a better price in the auto-fuel market for natural gas vehicles than it can for electric production.

There are also environmental and health risks to the over-consumption of animal food.

• Feedlot animals are often grain fed, and it takes several times as much grain to produce the same amount of animal food.  Collateral damage from farming, including use of artificial pesticides and fertilizers, soil erosion, and fossil-fuel powered equipment and transportation, are magnified.

• Most modern animal farming is conducted in Confined Animal Feeding Operations (CAFOs), where often unsanitary conditions create more disease, motivating large use of antibiotics.

• In 2014, about 2.8% of U.S. greenhouse emissions came directly from livestock digestion.7  This does not take into account energy used in raising and transporting feed grain.

• Diets with a large percentage of animal food have been linked to heart disease, diabetes, and certain cancers.8

Despite these concerns, it is not likely that most Texans are going to become vegans any time in the near future.  Turning wasted biogas into a resource, to the extent available, becomes a starting point for replacing conventional fuels.

Growing Coal: Biomass Electric Power

Fossil fuel supporters have frequently defended the use of coal by sarcastically claiming that it is “green.”  Technically, they are correct.  Coal was created from undecayed trees millions of years old that have hardened under geologic pressure.  The comparison stops there though.  Extraction techniques, combustion characteristics, and the quantity of supplies are totally different.

Theoretically, given enough land, money, and political will, the state could run a noticeable percentage of its grid with biomass produced from wood and crop land.  The difficulties of this concept, however, are formidable.  Consider:

• The coal for Austin’s Fayette Power Plant comes from Wyoming.  A 100-foot thick coal seam there can produce about 180,000 tons per acre.9  Wood harvesting, under optimal conditions, produces about 8 tons per acre annually.10  Considering an 8-year harvest rotation (again, optimal conditions), that amounts to 64 tons per acre per harvest.

• Coal mines have conveyor belts and railways strategically located nearby.  Favorable economics for wood assumes a nearby road, which is often not the case; and wood is often hauled by truck, which is much more expensive than rail.

• Depending on the tree species, wood can be half water before it is dried.  Only about a quarter of coal is moisture.

• When completely dry, sub-bituminous coal has more than 4 times the mass per BTU as wood.  You can co-fire wood chips in coal power plants, but this will reduce (derate) plant capacity and energy production because not as much heat per unit of mass is generated.

• In 2014, the state of Texas produced about 20 million tons of greenwood (half water) from the lumber industry.  In the same year, it consumed about 102 million tons of coal.11

• Given the size of Texas, it would be possible to create a wood-fuel industry to sustainably replace some fraction of the state’s current coal use with wood.  Due to growing cycles, however, it would take about a decade to establish plantation forests.  And the amount of land required is vast.

Austin’s own coal use in 2014 amounted to about 2.2 million tons, providing 32% of its electric needs.12  Supplying wood to replace just Austin’s share of the Fayette coal plant would have required an area of almost 600 square miles, half the size of Travis County.13  Coal replacement for the entire state in 2014 would have required an area equal to the states of New Hampshire and Vermont combined.14


Austin’s Biomass Plant

An impediment to Austin’s involvement in wood pellet conversions is the stigma of the “Biomass Plant” in East Texas.  In 2008, Austin Energy committed to buy the electric production from a 100-MW power plant owned by Nacogdoches Power burning unpelletized lumber waste.  At the time, gas was at record high prices, and it appeared that the U.S. Congress might approve a carbon tax.  These factors would have made the very high price of this dispatchable power plant, 14.6¢ per kwh, seem more reasonable.15 

The Austin City Council approved the contract over the protests of environmentalists, fiscal conservatives, and even some East Texas residents who came all the way to Austin to protest.

Since the Biomass Plant was approved, natural gas prices have plummeted, no U.S. carbon tax has been enacted, and the contract has been widely decried as a boondoggle.  Austin Energy is obligated to pay a capacity cost of $54 million a year (about 4% of utility revenues in 2015) whether or not the plant operates; and it is so expensive to operate that it is idle most of the year.


Carbon-free Carbon

Burning wood is technically carbon neutral.  Burning it emits carbon, but this is reabsorbed through photosynthesis.  The only carbon emissions in excess of the carbon cycle are from harvesting and transportation of the fuel.  There are several strategies employed in displacing coal with wood.

White and black pellets
Black and white wood pellets


White Pellets – Wood is dried, ground into powder, pelletized, and shipped to a power plant, both to reduce shipping costs and to increase the heat per mass to resemble conventional coal. Derating of generation capacity is minimal or non-existent.  However, it costs considerable money to process wood chips into pellets.  It takes more money to modify the coal plant with pellet storage to keep them from absorbing moisture.  Given the expense of complete conversion, some plants co-fire pellets with coal to reduce costs.

Black (Torrefied) Pellets – Torrefaction is a type of wood processing where wood chips are roasted in a low-oxygen environment, similar to the way coffee beans are processed.  This renders the chips (and sometimes the pellets), hydrophobic, so they can be stored in the open like coal instead of in an expensive storage building.  Torrefied pellets also have a higher heat value per mass than conventional pellets, making them less expensive to ship and derating of power plants even less likely.  The process has an extra advantage of potentially being able to re-use volatile organic gases emitted during pellet production as fuel.  While torrefaction is probably the future of the pellet industry, most pellet manufacturing plants still do not use it.

Pellets are rarely used in North American power production.  However, they are used elsewhere to such a degree that some of America’s woodlands are becoming de facto provinces of other countries in Western Europe and Asia, which import pellets in large quantities.  Internationally, about 27.1 million metric tons of pellets were burned in 2014, with 14% of this produced in the U.S., the largest producer of wood pellets in the world.16

In 2014, European Union countries burned 18.8 million metric tons of wood pellets, with about 21% of this coming from the U.S.17  These are combusted for power plants as well as building heat.  But to give you a sense of proportion, if all EU wood pellets consumed in 2014 were used to create electricity, it would be enough to fuel 4,100 MW of coal power plants.18  (This compares to Austin’s share of the Fayette coal plant at 602 MW.)

With overseas shipping and plant conversion costs, the price is around $10 per million BTUs, compared to fuel burned at Austin’s coal plant at about $2.15 per million BTUs.19  European utilities tolerate this high cost due to subsidies afforded them by their governments that encourage low-carbon fuel.  While torrefaction could lower costs to a degree, it is important to realize that most of the price for pellet manufacturing is in producing and transporting the wood.

At least one utility in the U.S., Portland General Electric (PGE), is studying biomass conversion of its (Boardman) coal plant located in Oregon near the Washington border.

However, the plant runs head-on into the same economic conflict: how to justify the higher costs of wood when it is only paying $2.50 per million BTUs for the coal.  Strategies to justify or lower costs include: 1) only operating the plant for 6 months (during peak winter and summer seasons) to compete with higher priced power; 2) using waste wood and biomass sources from forest fires, land clearing, etc. (in some cases, the plant might even receive a tipping fee for taking the waste wood); 3) using the plant to meet a future state or federal mandate or tax for carbon reduction.


Concentrating Solar Power

Solar power tower "halo" with ground mirrors
Hundreds of thousands of mirrors focus on a solar tower to produce heat for electric generation
Photo: Greg Glatzmaier, National Renewable Energy Laboratory


Concentrating Solar Power (CSP) employs sophisticated tracking mirrors to focus direct sunlight, creating heat to boil a working fluid for turbine-power generation.  Relatively few people realize how advanced the technology has become.

Some configurations have separate mirrors focusing on a single point, often located on a “tower” several hundred feet above the ground.  Other technologies use parabolic “troughs” or concave dishes to focus sunlight on a heat pipe running a few feet above them at the focal point.

Coupled with thermal storage, CSP can be dispatched on demand well into night.  At least one CSP plant in South Africa has operated continuously for a 24-hour period.

To operate economically, CSP needs large amounts of direct sunlight found in the Western U.S., including parts of Arizona, Colorado, California, Hawaii, New Mexico, Nevada, Texas, and Utah.  In the Southwestern United States, there are 307,000 square miles of suitable area, enough area with intense direct sun and low slope to provide almost 20 times the country’s total electric use.20  (Theoretically this is enough to provide electricity to the entire world at 3 times its 2015 consumption.)21

In Texas, there are 91,000 square miles of potential site area, enough suitable land to provide 58 times the state’s electric consumption in 2014.22  Just 6/10ths of 1% of the state’s land area (1,562 square miles) could provide all the electricity the state consumed in 2014.

The first commercial CSP plants in the world were in the U.S.  Nine small plants totaling 354 MW have been operating in the Mojave Desert for almost 3 decades.23  The largest of these plants is 80 MW in size.  Built between 1985-1989, they have an impressive record: maintenance costs have come down while generation output has increased.  These plants generate about 90% of their power from solar energy while employing natural gas as backup.  As such, they can operate at over 100% of their designed capacity, and their output coincides with the utility’s peak demand.24

In 2015, there were about 4,650 MW of CSP in the world, with 38%of this in the U.S.  Spain is actually the leader, with 50% of the total.25  In 2014, CSP produced about 2% of Spain’s total electric consumption.26

Solar vs. Solar

There are, however, few if any new CSP plants planned for the U.S. at this time.   Ironically, this is due to the plummeting cost of solar energy.

A CSP plant built in 2016 would cost about 12¢/kwh in the U.S.27  This would fall to about 9-10¢/kwh with federal solar tax credits.28  This is profoundly lower than CSP prices were just a few years ago, 21¢/kwh, but profoundly higher than the plummeting cost of solar cells, which cost only 3 to 5¢/kwh for utility-scale projects in 2015-2016.29

U.S. electric utilities required to meet state renewable energy purchase requirements utilized solar cells and wind power because they were cheaper.  While CSP has the distinct advantage of being dispatchable through onsite thermal storage, utilities will not look favorably on CSP until the amount of less-expensive intermittent renewable energy exceeds what can be easily integrated into the grid.

To stay alive, companies that build CSP technology and projects have almost completely abandoned the U.S.  In the 2016 world market, there were about 1,400 MW under construction, and as much as 4,300 MW of new power being planned.30  China has set a goal of 10,000 MW by 2020, and Saudi Arabia has apparently embraced competition to its own fossil fuel by setting a goal of 25,000 MW by 2040.31

Motivations for building CSP include making use of sunny climates, reducing carbon, building dispatchable renewable power, and reducing the high cost of imported fuel.  Its use in some oil-rich countries such as Saudi Arabia is motivated by the opposite reason: consuming locally available renewable resources allows the country to redirect locally produced fossil fuels for export to earn more money.

A Plug-In Solution?

Of the four renewable baseload alternatives appropriate for the Texas ERCOT region, CSP is the one most likely to succeed in the mid-term.  Unlike wood pellets, it will not take a decade or more to establish plantation forests of unprecedented scale.  Unlike biogas, the resource is much more available.

The generation equipment can use natural gas as onsite back-up on days when direct sunlight is not available in sufficient quantity, raising the capacity and lowering the fixed cost of the plant on a kilowatt hour basis.  Such cogeneration strategies can even employ “Integrated Solar Combined Cycle” power plants, where the most modern and efficient combined cycle gas units use solar heat as a booster that allows the plant to use less fuel.

While it is unfortunate that the U.S. is not taking an active role investing in more domestic production, the economies of scale may happen anyway over the next 5 to 10 years because of growth in the world market – it will just take longer.

The larger problem with CSP is that even when its costs fall, it may still not be enough to compete with some forms of conventional power…unless environmental costs are taken into account.

If the current cost of CSP is 10¢/kwh, and it falls by half to the target goal of 5¢/kwh through better technology and economies of scale, it cannot compete with the Texas wholesale power price of about 4¢/kwh in 2014, let alone 2.8¢/kwh in 2015.32  To be competitive, gas costs will have to rise, or environmental costs will require compensation.

Compressed Air Energy Storage With Renewables

Another approach to creating dispatchable electrical power is to use Compressed Air Energy Storage (CAES) in conjunction with intermittent renewable energy.

Compressed Air Energy Storage Diagram
Compressed Air Energy Storage Diagram
© Ridge Energy Group


CAES uses a simple concept.  An air compressor is located next to a geologic formation like a salt dome, an aquifer, or abandoned mine or oil well.  Electricity from wind power, cheap night-time off-peak generation, or another desired source is used to drive compressed air into the formation at 100 times normal pressure.  Storing air is similar to storing natural gas, which is quite common in the U.S.  (The country has enough gas storage capacity to contain about 15% of total current domestic use on an annual basis, which is employed during seasonal peaks.)

Pressurized air is much more powerful when heated in a combustion turbine than air at standard pressure.  So when this plant is needed later to fill in the valleys and ramp down the peaks of intermittent power, the pressurized air is heated (the most economic fuel being natural gas), and run through this combustion turbine to create electricity.

The process is about 54% efficient in terms of storing energy, compared to some battery technologies that can exceed 90%.33  This lower efficiency, however, is offset because: 1) CAES is profoundly less expensive than any other electric storage option in the ERCOT region; 2) most of the electricity that is stored can be carbon free; 3) in balancing intermittent renewables, it only runs a small percentage of the time.

To the last point, if intermittent wind provided 80% of electric load, and the CAES plant provided 20%, then the entirety of the CAES/Renewable dispatchable “plant” would only require about 12% fossil fuel.

While all the technology is off the shelf, the proven components have only been combined twice in a commercial CAES operation: a 290-MW power plant in Germany commissioned in 1978; and a 110-MW plant in McIntosh, Alabama completed in 1991.

Graph showing how compressed air energy storage is dispatched as firm supply
Load profile of CAES/Wind plant providing electricity on demand


Since these plants have to be built to scale to be as cost effective as possible, and since the economic value of energy storage has not been widely acknowledged in the electric utility industry until recently, most companies have not been willing to build the first plant in a generation.  A 317-MW plant could cost about half a billion dollars.34 

A CAES/Renewables plant can compete with a new dispatchable gas power plant when fuel costs are only about 15% higher than the 10-year average cost of gas, but would still need a small percentage of its energy from fossil fuel.35  Biogas could also be used, albeit at higher prices, but there are (previously discussed) limitations to supply.

Another possibility is co-fueling the CAES plant with hydrogen. People have been fantasizing about the “hydrogen economy” since at least the 19th century (science fiction writer Jules Verne).  While hydrogen is the most plentiful element in the universe as we know it, it is extraordinarily expensive to produce with electricity.  Ironically, most hydrogen produced in the U.S. is used for oil refining.

Co-fueling CAES with hydrogen produced from renewable energy would make this proposal completely carbon free…but removing carbon is hardly free.   

Producing hydrogen electrolytically would lose 39% of wind or solar energy due to inefficiencies in the process.36  The hydrogen fuel would lose another 46% in the CAES process.37  You also have to consider the cost, which could easily be $28 per MMBTUs, about 5 times the average cost of natural gas used in Texas generation in recent years.38  However, since only a small fraction of this expensive energy would be used for the CAES/Wind process, electricity would generally be about 7¢ per kwh.39

A Cause for Speculation:

Estimating Future Power Costs40

Attempting estimates of the future costs and technological development of electric generation, both conventional and renewable, always have blatant elements of uncertainty.  Fuel costs often gyrate with volatile demand.  Construction projects have overruns.  New technologies have unforeseen breakthroughs.  Financial interest rates rise and fall.

Costs presented here are suggested with the sober realization that they are based on the most current information available.  Engineering studies of any future generation project are essential and could revise these estimates.  Also, these are generally “overnight costs” that do not take into account the inflation and interest accrued in building a plant.  While solar and gas plants are constructed relatively quickly, a nuclear plant can take over a decade to complete.

Combined Cycle Natural Gas Plant – These efficient plants recapture much of the waste heat that was produced in older simple cycle plants.  This is the benchmark for preferred new conventional power plants for Austin Energy and many other utilities today.  The cost estimate contains the cost of $5.49 per MCF in 2016 dollars, the average price between 2006 and 2015.

Gas is a volatile fuel (no pun intended).  To predict that the price will stay relatively low for the 30-year life of the power plant is not supported by history.  If the average price goes up 13%, CAES with wind and gas breaks even with a combined cycle plant.  Currently, CAES plants are being proposed for grid stabilization (“ancillary services”), which justifies this higher cost.

If gas goes up 47%, biogas fuel breaks even with conventional fuel.  (The last time that natural gas was this high was in 2008.)

CAES With Wind and Hydrogen Fuel – To most people in the utility industry, suggestion of using electrolytically produced hydrogen in place of natural gas is preposterous.

This estimate assumes the 2016 cost of hydrogen is 5 times higher than the assumed cost of natural gas in the chart above. This assumes the approximate current cost of electrolysis equipment.41  While the industry has not ramped up to mass production yet, most of the cost of hydrogen is in the cost of electricity needed to produce it.  (The cost is assumed here to be 3¢/kwh for wind power.)

It is important to remember that gas is only used for about 12% of the process, with direct or stored wind generated electricity being the majority of cost.  So the impact of high-cost hydrogen is greatly limited.

This estimate is in some sense conservative in that it assumes the CAES/Wind/Hydrogen plant is used to follow load.  Dispatching power at opportune times, using the plant for higher-valued grid stabilization, and selling oxygen produced as a by-product will earn extra revenue and lower the effective cost of hydrogen production.

Coal and Wood Power – Using white wood pellets in Austin’s existing power station would substantially increase costs.  The cost of torrefied pellets, while still a developing technology, can be reduced by funding the production plant with municipal bonds, reusing the waste gas from the production process, and buying low-cost wood supplies.

However, even using torrefied pellets in an existing plant could be higher than a new coal plant, though few new coal plants are being built in the U.S. due to the high first cost, competition with gas, and fears of carbon regulation.

Concentrating Solar Power – The current costs here assume municipal bond rates, a 30-year life, and 10 hours per day of storage.  It is anticipated that price will fall by about 50% by 2025.

Nuclear Power – This author believes the cost cited here is unrealistically low in a technology infamous for cost overruns and construction delays, but it is the best estimate available.  Low-interest municipal bonds were also assumed, though given the financial risk associated with nuclear power, investors may demand higher interest rates.  Average fuel, Operation & Maintenance costs, and Capacity Factors (percentage of operation per year) for the current fleet of U.S. nuclear plants were also used.

Mitigating Circumstances: Ways to Reduce Costs

The costs of dispatchable renewable electricity discussed in this article are not orders of magnitudes higher than the benchmark cost of a new gas plant.  However, there are many ratepayers who will not want to pay a penny more than they do now.  There are at least five strategies that can  mitigate price increases caused by these new power sources.

1. Phase-In of New Power Sources – The cost of a new power plant will typically be phased in and blended in to the overall generation fleet, so incremental price increases caused by new facilities are not that steep.

2. Blend-In of Cheaper Clean Energy Sources –About half of Austin Energy’s expenses in 2016 were for transmission, administration, and other non-generation purposes.  About 40-50% of electricity can probably be provided or deferred through affordably priced energy efficiency, smart grid techniques and technologies, and intermittent renewable power.  So even if dispatchable renewable electricity is more expensive, it may not raise the overall cost of electricity proportionally or outrageously.

Example: If 50% of retail electric price is not related to generation, and 20% can be displaced with intermittent renewable energy, cost-effective efficiency, and smart grid technologies, then even a 50% premium for dispatchable renewables would only result in a 15% increase in overall consumer costs (50% increase X 30% of remaining cost).  Note that not all energy-efficiency savings will be seen in lower rates, but they will be seen in lower bills.

3. Collaborative Investment in New Technologies – Some dispatchable technologies will need innovation and economies of scale to bring their price down.  A large-scale consortium is needed, made up of other utilities, institutions, and governments (federal, state, and local) to accelerate the commercialization of alternative energy development.

Part of the funding might come from a voluntary subscription on the electric bill, similar to Austin Energy’s popular GreenChoice rate for renewable energy.  A mandatory surcharge on the electric bill will also be necessary, but it would be partially compensated by revenues from the renewable power plants that are built with the funds.

For instance, if several billion dollars were collectively raised to commercialize Concentrating Solar Power, and the state of California paid CSP plants higher prices than the Texas market, then the plant would be built in California and the investment revenue made from Texas ratepayers’ money would be routed back to them.

4. Capacity Market – The ERCOT electric system is an “energy only” market that awards more expensive dispatchable electricity the same price as less expensive intermittent renewables.  Creating a “capacity” market that awards value to dispatchability would be a great equalizer.

5. Soliciting Grants for Pilot Projects – Reliance on grant money to completely subsidize a fleet of dispatchable renewable power plants is not likely to succeed.  However, asking funding from federal, state, and non-profit sources for prototypes is a strategy that might gain traction.  Such pilots might include CAES using hydrogen or waste heat from the air compression process instead of natural gas.

Continue to Clean Energy Alternatives, Part 3, The Smart Grid->


U.S. Energy Information Administration, Dept. of Energy, is hereafter referred to as EIA.

1 While “unimaginably expensive” is subjective, utility-scale batteries, which cost much less than commercial batteries, currently cost about 20¢ per kwh if used once a day.

Lithium battery cost and specs from Lazard’s Levelized Cost of Storage, Version 2.0, December 15, 2016, New York, NY, p. 31.  4% interest assumed.

2 U.S. Department of Agriculture, Agricultural Statistics 2015, Washington, DC: U.S. Government Printing Office, 2015, Chapters VII and VIII.

3 American Gas Foundation, The Potential for Renewable Gas, September 2011, Table 22. Adjusted for inflation and with 30¢ added per MMBTUs for transportation.

4 Ibid.

5 EIA, Texas Natural Gas Price Sold to Electric Power Consumers, Data, 2006-2015.  Adjusted for inflation to 2016 dollars.  Online at

6 73.4 Million MCF consumed in a GE Harriet Class combined cycle plant at 5,964 BTUs/Kwh will generate about 12.7 Twh/year, about 4% of 351 Twh consumed in ERCOT in 2016.

ERCOT, “Long-Term Load Forecasts,” Austin, TX: data from 2006 to 2015.  Online at

7 U.S. Environmental Protection Agency, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990– 2014, EPA 430-R-16-002, Washington, DC, April 15, 2016, Tables 2-1 and 5-1.

8 Tilman, David & Michael Clark, “Global diets link environmental sustainability and human health,” Nature, Volume 515, November 27, 2014, p. 520.

9 Wyoming Mining Association, “Coal,” Cheyenne, WY, accessed 2/1/17.  Online at

10 Perlack, R.D. and B.J. Stokes, U.S. Billion Ton Update, Oak Ridge, TN: U.S. Department of Energy, Oak Ridge National Laboratory, August 2011, p. 116.  (Assumes Southern Pine.)

11 Tons of lumber from Edgar, Chris, et al., Harvest Trends 2014, College Station, TX: Texas A&M Forest Service, September 2015, p. 19.

Tons of coal from EIA, Beta, “Coal Data Browser,” Data.  Online at

12 Percentage from Austin Energy, Annual Performance Report, Year Ended 2014, pp. 15,17.

Tonnage derived from heat rate of 17 MMBTUs/ton ÷ 10,400 BTUs per kwh divided, in turn divided into total kwh production from plant at 75% capacity.

13 Number of acres assumes 602,000 KW X 75% capacity X 8,766 hours ÷ (16 million BTUs per dry ton X 8 dry tons/acre X 87% torrefaction conversion efficiency ÷ 10.400 BTUs per Kwh).  This is then divided by 640 acres per square mile to get about 578 sm, about half of Travis County’s 1,023 sm.

BTUs/kwh for Fayette coal plant for 2014: 10,400 high heat value (Derived from U.S. Environmental Protection Agency, “Air Markets Program Data,” Washington, DC, accessed 12/12/15.  Online at

14 Total electricity production for coal in Texas from ERCOT Quick Facts, Austin, TX, December 2015..  Fayette coal plant made up only about 2.9% of the electricity generated from coal in Texas in 2014.

15 Mathis, Michael, “Largest U.S. Biomass Plant to Be Built Near Austin, Texas,” CBS News, September 19, 2008.  ($2.3 billion over 20 years; 100 MW; 90% Capacity Factor).

16 Dale, Arnold, “Production and Consumption of Wood Pellets in the European Union, Halifax,” Nova Scotia, Canada; WPAC Conference, November 2015, slide 3.

17 Ibid, slide 5.

18 Assumes 10,500 BTUs/kwh; 75% plant capacity; white pellets at 15 million BTUs/metric ton.

19 European Wood costs from Note 40, Argus Biomass Markets.

20 Lopez, Anthony, et al., U.S. Renewable Energy Technical Potentials: A GIS-Based Analysis, National Renewable Energy Laboratory, NREL/TP-6A20-51946, July 2012, Table 5.  U.S. electric consumption in 2015 assumed to be 4,100 Twh.

21 Worldwide electric production from BP Statistical Review of World Energy, June 2016.

22 Note 20, p. 13, and EIA.  Texas electricity was 390 Twh.  Texas land is about 269,000 s.m.

23 Presentation by Fred Morse, renewable energy consultant, in Austin on February 24, 2005.

24 Ibid.

25 Whiteman, Adrian, et al., Renewable Capacity Statistics 2016, International Renewable Energy Agency, p. 32.

26 SolarPaces, “Spain,” Tabernas, Almería: Spain, accessed 2/5/17.  Online at

27 Mehos, Mark, et al., On the Path to SunShot: Advancing Concentrating  Solar Power Technology, Performance, and  Dispatchability, NREL/TP-5500-65688. Golden, CO: National Renewable Energy Laboratory, Table 6, pp. 31-32.

28 Ibid.

29 Mahapatra, Saurabh, “New Low Solar Price Record Set In Chile — 2.91¢ Per kWh!,” Cleantechnica, August 18th, 2016.

Dipaola, Anthony , “Cheapest Solar on Record Offered as Abu Dhabi Expands Renewables,” Bloomberg News, September 19, 2016.

30 Op. cit., Mehos, Mark, et al., On the Path to SunShot, p. 3.

31 Ibid., pp. 4-5.

32 Solar costs from Note 40.

33 CAES efficiency from Jack Farley, President of APEX•CAES, on October 24, 2016.

Op. cit., Lazard’s Levelized Cost of Storage.

34 Capital costs from Jack Farley, President of APEX•CAES, on May 31, 2017.  $1,560,000 per MW X 317 MW.

35 Note 40.

36 Note 40, Electrolysis efficiency from Ainscough, Chris,  et al.

37 Note 33, Farley.

38 Cost of gas from Note 5.

39 Note 40.

40 Nuclear

Fuel and Operation & Maintenance cost (2015) from EIA, Electric Power Annual 2015, PDF p. 170, adjusted for inflation to 2016 dollars.

Capital Costs; EIA, “Updated Capital Cost Estimates for Utility Scale Electricity Generating Plants,” Washington, DC, November 22, 2016.

Assumed baseload capacity of 90%

Nuclear Capacity from Nuclear Energy Institute, “US Nuclear Capacity Factors,” Washington, DC, 5-year average.

Assumed municipal interest rate of 4% for 30 years.


Capital Cost from Navigant Consulting, Inc., Independent Review of Austin Energy Resource Plan, Prepared for City of Austin, Austin, TX, November 13, 2015, p. 4-19, adjusted for inflation to 2016 dollars.

Assumed baseload capacity of 75%.  Assumed municipal interest rate of 4% for 30 years.

Fuel cost is EIA, Texas average for Electric Power Consumers from 2006-2015 adjusted for inflation to 2016 dollars.  Online at

Heat rate of 5,964 BTUs/kwh calculated by adjusting lower heat value of GE Harriet turbine class (5,383 BTUs) by 1.108

Fixed and Variable O&M costs from Op. Cit., Navigant Consulting, p. 2-4, adjusted for inflation.


All costs but fuel are same as gas costs above.

Fuel from American Gas Foundation, The Potential for Renewable Gas, September 2011, Table 22, adjusted for inflation to 2016 dollars; 30¢/MCF added for transportation.


Capital, O&M Costs, and fuel efficiencies from Jack Farley, President of APEX•CAES, January 23, 2017 and May 31, 2017.  Assumed 4% interest for 30 years.

Gas fuel costs from Op. cit, EIA.  Wind cost estimated to be 3¢/kwh

80% of wind is estimated to be used directly, with CAES unit providing balance of 20%.

CAES/Wind/Hydrogen – Current

Capital, O&M Costs, fuel efficiencies, and wind costs from above.

Hydrolysis equipment cost and electrolytic efficiency from Ainscough, Chris,  et al., “Hydrogen Production Cost From PEM Electrolysis,” Washington, DC: U.S. Department of Energy, July 1, 2014, Table 4, p. 7; adjusted for inflation to 2016 dollars.

Low cost storage from Shawn Patterson, APEX•CAES, on January 30, 2017.

High cost storage from Federal Energy Regulatory Commission, Current State of and Issues Concerning Underground Natural Gas Storage, Docket No. AD04-11-000, Washington, DC, February 2004, p. 25.  Number adjusted for inflation to 2016 dollars.

Adjustment: 42% of hydrogen energy can be stored in same space as natural gas.  From Mignard, D., Wilkinson, M. & Amid, A., “Seasonal Storage of Hydrogen in a Depleted Natural Gas Reservoir” International journal of hydrogen energy, Volume 41, Issue 12, April 6, 2016, pp. 5549–5558.

Storage cushion gas assumed to be 50% of storage volume.

CAES/Wind/Hydrogen – Future

Capital, O&M Costs, fuel efficiencies, and wind costs from above.

Future hydrolysis equipment cost and electrolytic efficiency from Op. cit, Ainscough, Chris, et al.

New Coal

Capital Cost, O&M costs, and Heat Rate from Op. cit., EIA, “Updated Capital Cost Estimates for Utility Scale Electricity Generating Plants.”

Assumed baseload capacity of 75%.

Assumed municipal interest rate of 4% for 30 years.

Fuel cost average from Fayette coal plant EIA 923 for 2013-2015 ($2.15 per MMBTU in 2016 dollars) ÷ Heat Rate

White Wood Pellets in Existing Plant

Argus Biomass Markets, Issue 16-014, April 6, 2016. p. 2.  Cost for industrial wood pellets from U.S. Southeast, 2nd Q 2016, adjusted to dollars from Euros.  Ocean freight costs not included.

Includes 7.8¢/kwh for fuel and 1.9-2.3¢/kwh for existing Fayette plant capital, conversion cost, and O&M.  Assumed 4% interest for 30 years and $350 -700/KW conversion costs for the Atikokan coal plant conversion completed in 2014, adjusted for inflation.  (No overnight cost available.)

Torrefied Wood Pellets (Future) in Existing Plant

Based on Tiffany, Douglas G., “Economics of Torrefaction Plants and Businesses Buying their Products,” (presentation to Heating the Midwest conference), August 25, 2013, p. 11.  Adjusted to 2016 dollars.  Online at

Trucking costs from forest to chipper from Qian, Yifei and Will McDow, The Wood Pellet Value Chain, U.S. Endowment for Forestry and Communities, March 2013, p. 13.  Adjusted to 2016 dollars.

Trucking costs from chipper to plant from Gonzales, Daniela, et al., “Cost analysis for high-volume and long-haul transportation of densified biomass feedstock,” Transportation Research, Part A 49 (2013) 48-61.  Adjusted to 2016 dollars.

Assumes gas cost credit from volatile gases equal to natural gas fuel costs above.

Concentrating Solar Power – Now and in 2025

Capital Costs, Capacity Factors, and O&M Costs from Op. cit., Mehos, Mark, et al., On the Path to SunShot.  Assumed municipal interest rate of 4% for 30 years.

41 $1,000 per KW of capacity.