Stabilizing the Renewable Grid

New wind farms are signing PPAs for energy at $50/MWh, where will you get energy for $10/MWh?
There are numerous points throughout the WindFuels site where we note an expected price for off-peak carbon neutral energy. In the economics discussion, we mention an “ideal” price for carbon-neutral energy of only $5/MWh ($0.005/kWh). The worst-case energy prices that we project in the near term are $25/MWh, and the average case is $10/MWh. This price expectation is our most often misunderstood claim – and therefore the claim that is most often challenged.

Understanding the affect that deep wind power penetration has on the electricity market is crucial to understanding one of the most exciting advantages of the WindFuels system – its ability to use intermittent renewable energy whenever it is available at a low price.

Wind Curtailment.
An oft-heard criticism of wind farms is that people “drive by them every day while the wind is blowing and the turbines aren’t spinning”. This is true, and it’s deliberate. The turbine blades are often pitched so that they recover less energy or no energy from the wind, a process commonly referred to as “wind curtailment”.

Wind curtailment happens whenever electricity providers must reduce the net energy on the grid, but do not expect to require the energy levels to be reduced for long. Baseload power is slow to ramp up, and sees a highly reduced efficiency if it is quickly ramped down. So if the amount of energy coming online is greater than the energy demand, the power provider must determine whether to pitch the wind turbines out of the wind, or ramp down baseload power (the response “peaker” power plants will have all been tamped back to minimum at this point). If the power company guesses wrong, and backs off too far on a coal plant only to see the wind suddenly drop, the power company will lose money buying emergency excess power from neighboring markets and inefficiently re-firing their coal plants and pushing their peaking plants to max. The money lost could exceed what it would cost the power company to just keep the baseload plants burning and curtail some of the wind. So the power companies use the best weather predictions available (which are very accurate for a time horizon of a few hours,) and make the best choices they can for maximizing profit. The result is the wind turbines are pitched out of the wind far more often then renewable energy advocates would prefer.

In 2010, it is likely that U.S. wind curtailment totaled ~20 TWh. Put another way, it is likely that more than 17% of the wind energy that could have been produced from installed capacity was curtailed instead. MISO is the only source that has released a detailed report on curtailment for 2010. They show a year-over-year increase in curtailment going from only a few GWh in 2008 to 292 GWh in 2009 and 832 GWh curtailed in 2010 (this doesn’t include XCEL Energy’s curtailment of ~5% of their wind generation, nor does it include other power providers that have different reporting practices). ERCOT doesn’t have recent information available, nor does it report curtailments in terms of energy. However, in early 2009 they were reporting between 500 and 3300 MW of curtailed power, with curtailment shutting in as much as 55% of the wind power within the ERCOT region. There has since been almost 2 GW of new wind capacity installed.

WindFuels would end wind curtailments.
We expect that a major power provider could contract with a WindFuels plant. In cases where excess wind production begins to threaten grid stability, rather than curtailing the wind they could merely direct excess energy to the electrolyzers at a nearby WindFuels facility. This energy would be contracted for a very low price, as the alternative would be curtailment – zero value energy. In return, the power company would see less O&M costs associated with maintaining their wind farms, they could get SOME return on those hours of wind power rather than none, and they would also be eligible to receive credit for renewable energy generation being delivered to the grid – whether that would serve to satisfy mandates or simply offer subsidies or tax credits.

The other advantage is that there is now a more stable grid at large, with the power company having the ability to adjust the demand from electrolyzers from 2% (which could be provided from heat recovery at the WindFuels plant itself) to 100% or anywhere in between with <100 ms warning, it would enable them to smoothly and efficiently plan for operations and run all of their base load thermal systems at maximum efficiency and effectiveness, while smoothing the way for much greater wind penetration at maintained stability.

There is clearly a great gain for power providers to offer very low energy pricing for WindFuels, and there is enough curtailed wind energy NOW to provide for the needs of scores of WindFuels plants throughout the Midwest.

One can now understand the principal defense of our statement that the energy used to power the WindFuels system will be carbon neutral. If a new WindFuels plant is brought online within a region and consumes 175 GWh from the grid with specific timing so that there is 175 GWh less wind curtailment, then no additional fossil energy was used to power the WindFuels plant. In truth, the actual impact will be greater than this, as a much more stable grid requiring less curtailment would encourage more development of wind within a grid – allowing more fossil energy to be abated than could ever have occurred without WindFuels plants being present.

The ISO/RTO markets.
Most states within the U.S. have their electrical energy traded through virtual markets within an Independent System Operator (ISO) or Regional Transmission Operator (RTO). The energy is openly bought and sold within these virtual markets in short blocks, and the pricing is recorded as Local Marginal Price (LMP), where the value is determined by the amount that would be willing to be paid for one additional MWh of energy traded within that time frame.

ISO/RTO systems are far more favorable than other structures to wind projects at large, as the larger region of established trade allows for more transmission of energy, “smoothing” local variability. The limit to the expansion of wind is based on its profitability, so in systems where less wind is curtailed, wind will continue to penetrate until something limits its continued development. In ISO/RTO markets, the limiter is often the final price of energy – which causes power companies to hesitate to sign more PPA’s for delivered energy.
When we first began investigating the economics of the WindFuels system, we looked at the Minnesota hub in MISO (an RTO that includes much of the industrial Northern Midwest). At the time, Minnesota was the state that had the greatest penetration of wind, followed by Iowa and North Dakota. The Minnesota hub sees trades that cover all of MN, Northern IA, and most of ND. This then was considered an ideal predictor of what an electric market with reasonably high penetration of wind might look like if grid transmission was adequate. We’ve continued tracking this hub. For the rest of this discussion, we will be including data from MISO’s RT trades (wind is typically traded in the real time – RT market) over the Minnesota hub. More dramatic information could be shown from ERCOT data, but most people believe that transmission improvements will fix many of the local problems in Texas. There are no transmission problems for the Minnesota hub, just a large multi-state region that has ~10% wind penetration.

Figure 1 depicts the average peak energy price, off-peak energy price, and the average price of the cheapest 6 hours of the day traded over the last four years througout the Minnesota hub.

End-use consumers see little price difference between peak and off-peak energy, or hour-by hour. End-use customers contract for a given rate, and they use energy as dictated by need. A WindFuels system would differ because it would be available to take its contracted energy needs at times that are solely within the discretion of the energy provider – who is trading over MISO. So most of the Windfuels plant’s energy needs could be satisfied exclusively during the cheapest hours of energy on any given day.

This would be a huge benefit for the power company, as it would help draw some of the excess energy off of the grid, forcing the prices higher for the rest of the trades. If the presence of an extra few percent energy beyond demand is forcing all of the RT energy trades to be negatively priced for 7-40 hours/week, then a power company could simply contract with a WindFuels plant for 1% of the RT energy at a very low price. On some days they'd lose money on that 1%, but more often they'd get far more for that energy sold to Windfuels then they would have gotten had they traded it over the ISO (note the “cheapest 6 hours/day” trace in the above graph – its average price is lower than the $10/MWh target set in our economics discussion). However, there would now be a market every day with 1% less energy traded RT, which would likely lead to much stronger RT prices. Thus they would generate more revenue on the improved pricing for the other 99% than they could ever lose for that 1%.

There is no other way in an ISO system for a power provider to manipulate supply at that level without substantial losses – in true real time with absolute fluctuation of how much demand there is. If a single power provider tried to manipulate the energy balance through curtailing much more of their wind electricity, that provider would lose 100% of the revenue of their curtailed wind, and the curtailment of other wind farms would instantly be reduced until the RT price was back down to the same level that it had been (price is causing these providers to determine when they curtail their wind) which means that any provider trying to be more aggressive about wind curtailment simply loses more money and advantages their competitors without getting anything back in return. If instead the excess were simply drawn off the grid by a completely variable load, the wind turbines would see less curtailment and the net prices for the rest of the energy traded would either be the same or higher. So the power provider would gain both in decreased curtailment and in increased nighttime prices.

Negative priced energy?
You may (or may not) have heard of the concept of negative priced energy. But there are times when power companies must literally PAY others to take their energy to avoid damage to their assets and those of their customers on the grid. During the off-peak hours, power companies are continually making decisions based on economic models on the extent to which their fossil power generation is tamped down versus selling excess energy to their neighbors at prices that may not be profitable. As more and more wind energy is brought online in any region, preferential treatment of local wind power will ensure that local markets would use some of their locally produced wind energy rather than fully curtailing it, which means that more energy is now supplied in a market that hasn’t seen any change in demand. Most grids have less than 10 minutes worth of storage capacity, so supply and demand fundamentals don’t stop affecting prices at production costs, nor do they stop influencing prices at $0/MWh.

Figure 2 shows a scatter plot of the trade LMP over the Minnesota hub in the real time market of February 2011. While the average price of energy traded was $26.38/MWh, it is clear that many hours that were negatively priced which created such an artificially low average price.

While negative pricing is not new, the rapidly increasing supply of intermittent wind energy is causing the instance of negative energy to increase rapidly. Figure 2 shows the price of energy at every hour during the month of February 2011. While the resolution is difficult to discern, different colors were used for days of the week, and different shapes were used for different weeks of the month. The average hourly price for the month can be discerned.

To get a sense of how frequently this occurs, look again at the “lowest cost six hours/day” trace in Figure 1. In three separate months, the average of the cheapest 6 hours/day was negative for the entire month.

Negative pricing occurs even in regions that are seeing large curtailment rates. In fact, throughout ERCOT, it is virtually impossible to see a day go by without several hours of negative pricing, even though ERCOT mandates curtailing and the ISO at large saw curtailment of well over 5.5 TWh/yr in 2010.

As expected, most of the periods of lowest-priced energy fall within periods of higher wind power generation, and these periods are more and more prevalent. Figure 3 illustrates the number of hours per quarter that energy has been traded at very low prices (<$10/MWh) and the number of hours per quarter that energy has been traded at negative pricing. The reduction in low and negatively priced energy seen between 2009 and 2010 was a direct result of the fact that the amount of energy curtailed in this region nearly tripled in that time frame.

Figure 3: The red columns show the number of hours energy prices averaged below $0/MWh throughout the Minnesota hub, the blue columns show the number of hours energy traded below $10/MWh.

As more wind power is installed, additional energy is produced without regard to the local demand, which means that more locales will have excess energy more often that they have to sell, increasing the supply in the open market. This will serve to increase both the instance of negative energy prices and the amount of wind curtailment.

Wasted Electrical Energy.
Keep in mind that during these off-peak times of high winds, power companies are losing money hand over fist. Baseload power costs money, and power companies have to pay the ISOs in order to trade energy, which they are trading at negative value.

When energy is traded over the ISOs at such times, it is often “purchased” by neighboring municipalities, who now have excess power that they must “sell” at a slightly higher price to THEIR neighbors… in effect a series of fees paid to the ISO to “push” the energy to outlying regions that are not suffering from an energy glut. The transmission may be through lines and transformers that are near capacity, thereby imposing limits on the trading.

But other means of dealing with excess energy abound. It’s fairly easy to imagine that every light in every facility owned by a power company will be shining brightly before excess power gets “sold” for negative price. The same is undoubtedly true with excess AC/climate control, water heating, and whatever else can be done with the energy, including simply running large amounts of energy through resistor banks.

If the energy is being “sold” at negative pricing, it’s equally easy to imagine the co-ops who “purchase” this energy would also be motivated to use this energy rather than “sell” it, and they too would use lighting, heating, air conditioning, and any other power draw that they could find to utilize or waste this electricity in the middle of the night.

This is why it is not uncommon to see areas that boast of “green” initiatives end up having tremendous amounts of lights burning in every city building through the night, or large outdoor heating vents operating at odd times throughout the night.

There is no way to determine exactly how much electricity is wasted, but there is a certain financial motivation, and compelling anecdotal evidence throughout the wind corridor.

As wind power continues to build out and develop a deeper penetration into regional grid portfolios, all three of these issues that are currently costing power companies – curtailment, negative energy pricing, and electricity wasting – will continue to increase. A very low-cost contract for variable power demand during excess generation periods would be FAR more profitable for the power companies in all cases. We expect there will be no difficulty getting favorable contracts for at least the next several decades.

Won’t they simply stop building wind farms?
The immediate reaction from most investors after they learn about some of the difficulties facing high wind penetration into the grid is: clearly this cannot last! They’ll stop building wind power until some “fix” is found. The DOE apparently agrees with this assessment. However, the DOE’s record of projecting renewable energy installations may be even worse than their record on projecting oil prices, and they have had a history of being irrationally bearish on wind in particular, as we’ll show...

To illustrate, the DOE’s “Annual Energy Outlook” from the year 2000 (AEO 2000) called for 5 GW of wind capacity installed throughout America by 2010, and then called for that to increase by an additional 12.5 GW of wind by 2020 under the “high renewables scenario”. The AEO 2005 reference case projected that a nationwide total of 11.6 GW of wind capacity would be installed by 2025, and by 2025 a total of 35 TWh/year would be generated. Even as recently as early 2008, the DOE’s “high economic growth case” in the AEO 2008 was projecting a total wind capacity of 27.3 GW by 2010 and 34.6 GW by 2020. According to AEO 2008 we would see 94 TWh generated in 2019.

The projections for wind energy generation according to the AEO 2011 are shown in Table 1. The boldfaced years represent actual data, the remaining are projections calculated from the 4th quarter of 2010.

The actual data from 2010 shows that the year ended with wind generation totaling 94.6 TWh. At the end of the first quarter of 2011, the total installed capacity across America was already equal to the given projection of the year’s average, and there is currently >5 GW of new capacity under construction that will be completed before the end of the year.

While the prediction of a complete cessation of any new installations in wind power may seem shocking, the DOE has been predicting just such an event for years. Each year with the new release of the AEO, they merely advance the year in which all wind growth stops.

It seems obvious that this kind of projection is more a reflection of bias at the DOE rather than an honest attempt to project the growth of wind. Perhaps this is because coal continues to maintain significant influence over the DOE.

This may seem to be picking on the DOE excessively, but it is important to realize that there are absolutely no grounds for DOE projections, and they have historically been further afield in their projections for renewable energy than any other analysts, including coal and natural gas lobbies. They have certainly had a far worse track record than the carefully researched work done by the team at Doty Energy.

Year	Average Installed Capacity	Total Generation
2008	24.89	55.42
2009	31.45	70.82
2010	37.49	91.25
2011	41.62	109.31
2012	48.9	141.78
2013	48.9	141.77
2014	48.9	141.77
2015	48.9	141.77
2016	48.9	141.77
2017	48.9	141.78
2018	48.9	141.78
2019	48.9	141.78
2020	49.01	142.16
2021	49.01	142.16
2022	49.64	144.32
2023	50.3	146.6
2024	50.78	148.46
2025	51.56	150.73

Table 1: Unreasonably pessimistic projections from the DOE AEO 2011 for wind development in the U.S.

You still haven’t explained why they won’t just stop building wind farms.
It boils down to government intervention. Thirty-eight states have renewable portfolio standards (RPSs, sometimes called RESs, renewable electricity standards). For these states, the power companies are mandated to utilize more renewable energy, whether there is a cost justification in doing so or not. This has been the dominant driving force behind both the wind and solar industries for the past decade, and more states are either adopting or expanding RPSs every year. Table 2 was compiled to help give a better appreciation for how much renewable energy must be brought online in the coming years – in order to comply with government mandates. Some RPSs specify installed capacity rather than percentage of energy produced. Many specify minimum portions for certain industries, and in some cases a date is specified so that only newer installations can count towards this mandate.

State	2010 Energy Demand	State RPS Mandate/Goal	Unspecified renewable energy needed to fulfill RPS assuming 0.8% annual growth (GWh)
TX	356,500	10,000 MW	Satisfied
CA	250,400	33%	29,900
OH	154,400	12.5%	18,900
PA	149,400	18%	7,200
NY	144,700	30%	13,000
IL	144,400	25%	31,300
NC	136,600	12.5%	11,600
VA	115,900	15%	14,800
IN	105,782	10%	6,532
MI	103,900	10%	7,100
WA	91,200	15%	8,300
MO	85,900	15%	11,200
LA	85,500	350 MW	335 MW
NJ	79,000	20.38%	16,000
AZ	72,800	15%	5,300
MN	68,100	25%	10,300
MD	65,500	22.5%	11,900
MA	56,300	22.1%	9,100
CO	52,100	30%	11,600
OR	46,300	25%	7,600
WV	32,000	25%	5,900
CT	30,400	27%	4,700
Other states w/RPS	405,600	10% - 40%	30,900 + 9700 MW
Total			273,100 GWh + 10,000 MW

Because of this, a state like Washington – which derives over 60% of its energy from renewable sources – still is not achieving its 15% RPS mandate. In all cases, while compiling Table 2, we were careful to only factor in the portion of RPS mandates that could be fulfilled by wind energy. For instance, in Nevada, we did not include a consideration for the additional solar energy that must be installed – as that was a separate line item. We only factored in the 23.5% of the energy mandate that could be filled by any energy source. Between 2000 and 2010, America saw a total electricity demand increase of 8.4%, and that time frame oversaw a very sluggish economic growth that both began and ended with recessions. The fourth column shows what must be implemented if demand growth in the next decade merely equals that of the previous one.

Even based on this conservative growth assumption, just to satisfy current RES mandates 273.1 TWh of additional renewable energy will have to be generated from new sources – not counting the solar, hydro, distributed generation, farm waste, and other itemized sources within these state mandates.

A quick look at the previous two decades should help us understand the potential growth of many of these renewable options. Table 3 was compiled to demonstrate the growth and/or contraction of the most popular renewable energy technologies.

Table 3: Electrical energy (TWh/yr) generated from renewable resources in the U.S.
Year	Hydropower	Wind	Total Biomass	Geothermal	Solar
1993	280.5	3.0	56.0	16.8	0.5
1997	356.5	3.3	58.7	14.7	0.5
2000	275.6	5.6	60.7	14.1	0.5
2002	264.3	10.4	53.7	14.5	0.6
2004	268.4	14.1	53.5	14.8	0.6
2006	289.2	26.6	54.9	14.6	0.5
2007	247.5	34.4	55.5	14.6	0.6
2008	254.8	55.4	55.0	14.8	0.9
2009	273.4	73.9	54.5	15.0	0.9
2010	257.1	94.6	56.5	15.7	1.3
Change since 2000	-18.5 (-6.7%)	+89 (+1590%)	-4.2 (-6.9%)	+1.6 (11.3%)	+0.8 (+160%)

Hydropower in America peaked in 1997 at 356.5 TWh. Weather variation shows as much as a 60 TWh variation in yield for any given year, but the average yield over the last decade has been 261.8 TWh – nearly 100 TWh below the 1997 peak. Water demand for irrigation and consumption have decreased the volume of water passing through the dams, and more dams have been decommissioned and destroyed than built in the last decade. These trends are likely to continue in the U.S., and 2020 seems likely to see less energy from hydropower than what was produced in 2010.

Solar power has only recently seen build rates that outpaced the degradation of earlier panels, and it is still completely insignificant. If solar power were to achieve the same generation growth over the next decade that wind power saw over the last decade, then 2020 might see ~18 TWh of solar energy produced. As much as 8 TWh of that solar energy generation might be concentrated in California alone, with another 2-4 TWh produced between AZ and NM. Essentially all other solar development in the U.S. over the next decade will be built to comply with technology-specific line items within state’s RES mandates, and this additional generation will be counted towards those mandates, not the generation requirements calculated here.

Geothermal power peaked in 1993. A period of very slow growth led to a rapid drop-off in energy production for the next two years before development resumed and kept pace with the energy loss from the cooling of the wells. Growth over the last three years has accelerated to a rate of 2-3% annual growth. If this accelerated rate continues, then a total of 4 to 5 additional TWh compared to that seen in 2010 can be expected by 2020.

Biomass-sourced electricity peaked in 2000 at 60.7 TWhs. Though wood co-firing has remained consistent, other sources of biomass have receded due to competition from biofuels. Biomass has averaged 54 TWh/year over the past decade.

It should be noted that factoring only these most often discussed sources of renewable energy – hydropower, solar, wind, geothermal, and biomass – more renewable electricity was generated in 1997 than in 2010. The only renewable energy technology that has seen significant growth within the last decade is wind power – growing at an average of 32%/yr in the U.S for the past 13 years. Wind will certainly comprise a super-majority of the renewable energy that is brought online to meet the additional 273+ TWh currently mandated for the coming decade.

Therefore, if we were to assume that wind comprised all but ~12 TWh of the mandated energy generation, there would still need to be ~98 GW installed across America in order to achieve compliance. Of the 10+ GW of capacity that is mandated in addition to the generation requirements, 8 GW of that capacity is specified as wind, and nearly 2 GW is mandated to be installed in KS – the state with the second best wind resources in the country. So the total amount of wind required simply to comply with RES mandates that have already passed should be expected to be ~108 GW, thus requiring that the next decade average an install rate similar to that seen in 2009.

The wind farms are coming, whether the power companies have any viable integration solutions or not.

The high cost of “peaker” energy.

NERC Region	Discount rate for wind
MRO	8.0%
SPP	8.2%
ERCOT	8.7%
SERC	9.9%
NPCC	13.2%
RFC	16.6%
WECC	18.5%

Table 4: the discount rate applied to wind capacity for minimum reserve capacity compliance.

"Peak energy” is so costly because power companies are often forced to build “peaker” natural gas power plants to service only a few hours of the day. This means that these new plants will only operate between 4-25% capacity factor. Rules from the North American Electric Reliability Corporation (NERC) require that a minimum capacity of reserve be built out to insure that summer peak demands can be reliably met. This is important, as it reduces the likelihood of roaming blackouts in the summer, but it is also costly. Invariably, the power companies will make these plants as cheaply as possible and they (1) consistently have worse NOX emissions than any other power plant, (2) often exceed SO2 and other harmful emissions of baseload plants even though they typically are gas-burning, and (3) have notoriously low efficiencies. This is because power companies cannot justify putting significant capital into a plant that may only run 4-5% of the time. In some cases, there are still diesel generators to serve as peakers.

Increased wind penetration is changing the game here as well. Power companies “discount” the capacity of wind when it comes to calculations for minimum compliance levels. The extent to which wind is discounted varies per NERC region, but they all fall between 8 and 18.5%, and they typically drop as wind energy penetrates more deeply within the region. What this means, is that if a 100 MW wind farm is brought online in Nebraska (part of the MRO region), then power companies only get credit for 8 MW of new capacity in the region, and they must keep their fossil plants on standby to comply with minimum reserve capacity requirements. The typical capacity factor for new wind farms (before curtailment) is 32-35%, so clearly having only an 8% credit will result in having too much capacity most of the time.

This is eliminating the need for new peaker plants in any region that has deep wind penetration, and as shown in Figure 4, the effect on peak energy prices is little short of shocking. As is the case with most of the rest of the price data, the impact on prices was tempered by increased curtailment.

Within MISO, nearly half of the curtailments occur during peak hours. Using wind curtailment has supplanted using rapidly ramping/tamping peaker plants to balance hour-by-hour supply and demand loads. In some cases it is less expensive to over-build wind and curtail it than it is to build a natural gas plant and constantly ramp it up and down.

Figure 4: Peak electricity prices (6am - 10pm)

The Un-viability of Conventional Energy Storage.
What increasing wind penetration has done is render traditional energy storage completely unviable in those regions. Referring to Figure 4 tells part of the story; in 2007-2008, power companies and co-ops bought and sold energy to one another at peak prices ranging between $60-$80/MWh, on average. After the market became saturated with wind in late 2008-early 2009, these prices averaged only $30-$40/MWh. That’s a $40/MWh average loss in potential revenue if the technology’s business model is to sell energy back to the grid during the “high priced” peak hours. Figure 5 brings this point home even more bluntly by displaying the average of the highest and lowest hours of each day and then tracing the average marginal profit (EBITDA, not including O&M costs) of a hypothetical energy storage system which bought energy at $10/MWh and managed with perfect timing to sell that energy back to the grid at precisely the highest possible rate (which could not happen).

Figure 5: The marginal gain possible assuming $10/MWh purchased by grid-to-grid energy storage. The traces shown are cumulatively calculated, so if you were to have a storage solution that was 80% efficient and you purchased energy at $10/MWh and sold it back at the highest price possible for 4 hours a day, the overall average gain for all four hours would be ~$30/MWh. That number represents the best possible yield assuming flawless timing, and ignores the potential impact that the introduction of additional energy might have on prices within the traded hub.

As seen from this data, purchasing curtailed off-peak energy at $10/MWh and then selling it back during peak hours does not allow much profit potential. This information should be especially troubling for those hoping that conventional energy storage will play a major role in integration and stability for increased wind penetration. We have investigated the cost of grid-level energy storage (our energy storage paper is available here). The findings of our work disagree with much of the traditional rhetoric that is found elsewhere, but this is due to a less biased approach to looking at the pricing trends in energy. Reviewing the LMP pricing data, a clear pattern emerges that holds even as the overall price shifts radically from year to year. During the warmer periods (second and third quarters), there is a single trough in pricing, and the price gradually increases to a single peak and then gradually descends. During the cold periods (the first and fourth quarters of each year), there are two peaks and two troughs. Hence, an energy storage option that would take electrical energy from the grid during low-price hours and sell that energy back during high-priced hours would only cycle once/day during warm months and twice/day during colder months. This changes the levelized cost of energy storage considerably.

Tables 5 and 6. Economics of grid stability for 2015 Technology.

Assumptions: 7% discount rate. Facilities would purchase 8 hours/day of off-peak power at the 150 MW level. Other than WindFuels, all plants would then sell power back to the grid at ~100 MW with optimal timing.

The WindFuels plant cost includes 150 MW of electrolyzers, allowing it to generate its daily hydrogen needs in 8 hours. The H2 fuel-cell option requires the same (expensive, 150 MW) electrolyzers as the WindFuels plant, but the energy sold is far less valuable, as it must be sold back into the same saturated grid as the energy had been removed from earlier that day.
UPHS: Underground Pumped Hydrostorage. AA-CAES: Advanced Adiabatic Compressed Air Energy Storage.
SMES: Superconducting Magnetic Energy Storage.
The last six options listed operate at more cycles per year than the first six.

*All options are assumed to purchase energy at $10/MWhr, but the cost in this column is divided by the cycle efficiency.

Our calculations involving the economics of storing energy are summarized in Tables 5 and 6 above. The cost of the storage facility is divided into two components – cost per energy stored and cost per power capacity. Here, we have assumed the facilities will be able to charge at the rate of 150 MW and discharge at the rate of 100 MW, as the duration of the low-priced period is generally less than the duration of the high-priced period. More details and support for the numbers are available elsewhere.

The column labeled “Incremental Cost of Delivered Energy” is based on the system cost, lifetime, number of cycles per year, energy per cycle, discount rate, and O&M. The system costs here are somewhat different here than we reported elsewhere primarily because of differences in assumed peak charge and discharge rates and in scale.
For WindFuels, the cost of delivered energy is similar to that for pumped hydrostorage or fuel cells, but unlike all of the other options, the stored energy will not be sold back into the local grid. The storage for gasoline, diesel, jet fuel, and other liquid fuels is inexpensive enough that the products can be stored (perhaps 5-8 months) until the front-month contract is ideal to sell. (Here, we have assumed several months of on-site fuel storage in the system cost.) Conventional energy storage, on the other hand, must sell the energy back into the grid, and the storage cost is far too high to hold it for more than half a day.

Gasoline sold for ~3.50/gallon during the first 4 months of 2011, which works out to ~$100/MWh. While we fully expect the price of oil and petro-products to increase steadily over the next 5 years, this is sufficiently high to illustrate the advantage of liquid fuels energy storage. (We expect that by 2015 the market price for transportation fuels will be at least $150/MWh.)

The value of the energy sold in Table 3 is based on market data from 2010 assuming optimum timing. For instance, a 150 MW lithium ion battery system, with 80% efficiency could draw 150 MW from the grid during the cheapest 8 hours and sell back 960 MWhs during peak hours with optimal timing – at maximum rate during the most expensive hours. Though unlikely, this is what is assumed in the table above.

Some of the storage systems could sell waste heat, and the possible value of this is included. The WindFuels and fuel-cell facilities will also sell co-produced O2. This has not normally been considered in prior analysis of H2 storage, but it is not difficult to liquefy the pressurized high-purity oxygen gas coming from the electrolyzers. (The energy requirements for this are actually negative.)

Conclusions.
We have shown that mandated RES policies will lead to increased curtailment, increased availability of negative-priced electricity, and reduced opportunities for conventional energy-storage technologies to operate profitably. These trends are expected to continue for at least several decades, and these trends, along with the steadily increasing price of liquid transportation fuels, establish an undeniably strong economic and climate-benefit argument for synthesizing standard fuels from clean, off-peak wind energy and CO2.