The government has done something right! In contrast to the Obamacare website debacle, the DOE has provided a website that provides extensive and useful information on large scale electric storage projects.
The recent press release states,
" The Energy Storage Database lists 420 energy storage projects from 34 countries with a combined 123GW of installed capacity. More than 50 energy storage technologies are represented worldwide, including multiple battery technologies, compressed air energy storage, flywheels, gravel energy storage, hydrogen energy storage, pumped hydroelectric, superconducting magnetic energy storage, and thermal energy storage. The policy section of the database shows 18 federal and state policies addressing grid connected energy storage, from rules and regulations to tariffs and other financial incentives."
I've referred to in the past and used it to track storage projects. It's been useful to weed out the "vaporware" projects, like the Obama Stimulus Ashlawn project (not in the database) from the real projects. You can find our vanadium flow battery project at Gills Onions here.
It's a good resource - use it!
Thursday, October 31, 2013
Wednesday, May 22, 2013
Utility Approach to Energy Storage
Energy storage is a strange duck for utilities. Is it load or generation? What box should it be in and what should be required from an end customer that wants to install energy storage on-site?
The California Public Utilities Commission is trying to shed some light on the problem for utilities in the current Order Instituting Rulemaking (OIR) to implement Assembly Bill 2514, setting procurement targets for storage, R1012007. However, there are no current guidelines for interconnection. As a result, the utility engineers are struggling to understand how to incorporate storage systems on the local distribution line.
AES has highlighted this issue with their argument that storage is both load and generation. John Zahurancik, VP at AES Energy Storage, recently presented a webinar with Navigant Research and made the point that a 2 MW storage system is actually a 4 MW resource because it can cycle over 2 MW "down" from a set point (charging) and 2 MW "up" (discharging). The comparison is against a typical generator that would need to be sized at 4 MW to move 2 MW up and down.
US&R is currently working to install a 2 MW, 2 hour (4 MWH) system in Southern California Edison territory and we are working through these real-world issues. The system is being installed under the Self Generation Incentive Rebate program and the rebate requirements rule out the export of power. However, the utility engineers reviewing the interconnection believe they must account for the possibility of 2 MW of generator export. In addition they want to classify it as "intermittent" generation, like solar PV or wind. Of course, this approach is completely opposite to the often discussed "smoothing" benefits of storage. I feel for the engineers that must evaluate such a new technology under the existing "old" criteria, but storage is a disruptive technology and implementation requires new methods of evaluation. After several years of planning, PG&E recently announced a 4 MW system has been installed at HGST, Inc., in San Jose. Although not behind the meter, we hope that installations like this will lead to a more informed and facilitative approach by the utilities.
AES has highlighted this issue with their argument that storage is both load and generation. John Zahurancik, VP at AES Energy Storage, recently presented a webinar with Navigant Research and made the point that a 2 MW storage system is actually a 4 MW resource because it can cycle over 2 MW "down" from a set point (charging) and 2 MW "up" (discharging). The comparison is against a typical generator that would need to be sized at 4 MW to move 2 MW up and down.
US&R is currently working to install a 2 MW, 2 hour (4 MWH) system in Southern California Edison territory and we are working through these real-world issues. The system is being installed under the Self Generation Incentive Rebate program and the rebate requirements rule out the export of power. However, the utility engineers reviewing the interconnection believe they must account for the possibility of 2 MW of generator export. In addition they want to classify it as "intermittent" generation, like solar PV or wind. Of course, this approach is completely opposite to the often discussed "smoothing" benefits of storage. I feel for the engineers that must evaluate such a new technology under the existing "old" criteria, but storage is a disruptive technology and implementation requires new methods of evaluation. After several years of planning, PG&E recently announced a 4 MW system has been installed at HGST, Inc., in San Jose. Although not behind the meter, we hope that installations like this will lead to a more informed and facilitative approach by the utilities.
Tuesday, November 29, 2011
California Energy Incentives - Shot-in-the-Foot
When is a rebate not a rebate? When the California Public Utilities Commission (CPUC) offers a rebate, then takes it back if the California Energy Commission offers a grant.
Some people think there are too many energy agencies in California. This may be an example of how the mission of one agency can be derailed by another.
Our firm recently considered applying for a grant through the California Energy Commission PIER (Public Interest Energy Research) program. PIER offered a grant under their Emerging Technology Demonstration Grant Program (ETDG), which specifically targets Industrial, Agriculture & Water Energy Efficiency RD&D. Without going into great detail, the grant would fund, among other things, customer side energy storage applications up to $2 million with applicant match funding of at least 25% of the project cost.
The CPUC offers a rebate of $2 Watt for customer side energy storage. The CEC published a Q&A on the PIER grant advising that SGIP funds could be used for matching funds. Fantastic! This meant we could install a 1 MW energy storage system, which are expensive due to a lack of scale, and report on the multiple applications and monetary benefits, like power quality improvement, demand response, peak shaving, integration and shaping of the intermittent on-site solar PV, and CAISO ancillary services. Southern California Edison issued a white paper on the applications of energy storage on their system, and we wanted to demonstrate several of their applications, such as:
• On-peak intermittent energy smoothing & shaping
• Ancillary service provision
• End user time-of-use rate optimization
• Peak load shifting downstream of distribution system
• Variable distributed generation integration
Our work would help inform the CPUC for their current proceeding to, "...set policy for California utilities to consider the procurement of viable and cost-effective energy storage systems".
However, just as it looked like the energy policy and incentives in California were going to allow for a significant project with wide-ranging benefits - the CPUC informed us that they would reduce the SGIP rebate for the installation on a dollar for dollar basis if we received CEC grant money for R&D and reporting!
So California energy policy shoots itself in the foot. We cannot do the PIER research and reporting if we want to accept the SGIP for installation. Who is in charge? A program designed to help the CPUC form policy has been foiled by the CPUC. Can anyone explain this?
Some people think there are too many energy agencies in California. This may be an example of how the mission of one agency can be derailed by another.
Our firm recently considered applying for a grant through the California Energy Commission PIER (Public Interest Energy Research) program. PIER offered a grant under their Emerging Technology Demonstration Grant Program (ETDG), which specifically targets Industrial, Agriculture & Water Energy Efficiency RD&D. Without going into great detail, the grant would fund, among other things, customer side energy storage applications up to $2 million with applicant match funding of at least 25% of the project cost.
The CPUC offers a rebate of $2 Watt for customer side energy storage. The CEC published a Q&A on the PIER grant advising that SGIP funds could be used for matching funds. Fantastic! This meant we could install a 1 MW energy storage system, which are expensive due to a lack of scale, and report on the multiple applications and monetary benefits, like power quality improvement, demand response, peak shaving, integration and shaping of the intermittent on-site solar PV, and CAISO ancillary services. Southern California Edison issued a white paper on the applications of energy storage on their system, and we wanted to demonstrate several of their applications, such as:
• On-peak intermittent energy smoothing & shaping
• Ancillary service provision
• End user time-of-use rate optimization
• Peak load shifting downstream of distribution system
• Variable distributed generation integration
Our work would help inform the CPUC for their current proceeding to, "...set policy for California utilities to consider the procurement of viable and cost-effective energy storage systems".
However, just as it looked like the energy policy and incentives in California were going to allow for a significant project with wide-ranging benefits - the CPUC informed us that they would reduce the SGIP rebate for the installation on a dollar for dollar basis if we received CEC grant money for R&D and reporting!
So California energy policy shoots itself in the foot. We cannot do the PIER research and reporting if we want to accept the SGIP for installation. Who is in charge? A program designed to help the CPUC form policy has been foiled by the CPUC. Can anyone explain this?
Thursday, September 22, 2011
Rebates Extended for Energy Storage in California
Today, Jerry Brown, Governor of California, will sign AB 1150 into law. This bill increases the funds available for the Self Generation Incentive Program (SGIP) rebates. These rebates have helped fund distributed storage projects in California and have been extended to include Energy Storage. After many delays and changes in the SGIP program, these additional funds, plus the recent final ruling by the CPUC, will allow for substantial installations of energy storage.US&R has participated directly and indirectly in all of the 8 MW's of energy storage projects that have applied for funding under the SGIP. None have yet come to fruition, although some are still in process. The main stumbling block to progress on these projects has been the constantly changing rules applied to the program. US&R worked with VRB Power and Strategen to open the SGIP to energy storage. This was a process that took several years and occurred against a backdrop of changing legislation affecting the SGIP. In late 2008, the CPUC finally agreed that energy storage could claim the SGIP, but only if "associated" with a fuel cell or wind turbine installation.
However, shortly after several projects began to come together, Strategen, on behalf of the newly formed California Energy Storage Alliance, filed an action with the California Public Utilities Commission (CPUC) to loosen the definition and technical requirements for energy storage. That dragged on for months. All projects were put on hold until developers, vendors and customers could be sure that their installation would qualify. A decision was finally rendered that did little to make the rebate available to a wider range of technologies, but it did impose metering and verification requirements that were not required of any other technology. Projects began to move forward again - but then the CPUC called a halt to any and all applications for the SGIP in December 2011.
It seemed that certain manufacturers (Bloom Energy) were reserving funds at an alarming rate. The concern was that the funds would be depleted before the CPUC could agree on another revision to the eligibility requirements required by legislation in SB 412.
However, the final ruling by the CPUC has expanded the options for energy storage, reflecting the intent of prior legislation and AB 1150,
"It is the intent of the Legislature that the self-generation incentive program increase deployment of distributed generation and energy storage system..."
US&R is actively developing energy storage projects for on-site applications at industrial and commercial end-users. Please contact us if you are interested in on-site energy storage for your facility, solar PV, fuel cell or wind project.
Thursday, August 18, 2011
CPUC Revamp Trying to Kill Advanced Energy Storage?
The California Public Utility Commission (CPUC) is revamping the rules for the Self Generation Incentive Program (SGIP) with a major, and completely inappropriate, performance requirement for Advanced Energy Storage.
The SGIP provides rebates for various on-site distributed energy resources (DER). Energy Storage was added to the list of DER's several years ago after much work by VRB Energy (the former manufacturer of the VRB-ESS® now made by Prudent Energy) Strategen and Utility Savings & Refund, LLC (US&R). One requirement of a qualifying Advanced Energy Storage system (AES) was the ability to provide at least 4 hours of energy and be capable of hundreds of daily charge and discharge cycles. Strategen, representing the California Energy Storage Alliance (CESA), later tried to ease these performance requirements to a single charge-discharge cycle once every three days. The CPUC relaxed the cycling requirement for fuel cell applications but retained the 100's of cycles performance for wind applications. In addition, the CPUC required metering for energy storage to record performance - which was not required for other technologies.
However, the CPUC never required the AES to cycle every day or otherwise "perform" to certain criteria, simply to be able to perform. This was important for the application of AES to the specific on-site load profile of an end-user and the applicable utility tariffs. For example, if the facility was closed on the weekend, then it would be pointless to charge and discharge the AES during the weekend. However, if the electric load was widely variable during the day, then the ability to partially charge and discharge repeatedly would help the facility smooth out its load profile and avoid increasing it's demand on the utility system.
The CPUC has been criticized for funding many projects under the SGIP that produced little electric generation, some being abandoned shortly after installation, so they've decided to condition part of the funding on performance (see pg 32 and 68 of the draft). That may make sense for a traditional generator, like cogen or solar, but is completely inappropriate for storage. Energy storage "stores" energy, it does not "generate". Some energy is lost in the charge - discharge process, which is not important if electricity is being shifted from a lower value time period to a higher value period - like a summer night to a summer hot day.
The CPUC is now requiring a 20% capacity factor for storage, which essentially means it must average a discharge of 4.8 hours per day (24 hours per day * 20% = 4.8 hours).This is a major performance change for storage and may further discourage AES installations. Not only has the performance standard been increased 20% from 4 hours to 4.8 hours of electricity, but cycling every day would cause the installation to lose money. For example, the E-20 industrial tariff for PG&E has a kWhr charge of $.078 at night and $.087 during the day. Assuming 70% efficiency for the charge cycle, comparable to pumped hydro, The AES would need 10 kWhrs of electricity at night ($.78) to deliver 7 kWhrs during the day ($.609). This results in a loss of -$.017 per kWhr delivered!
An arbitray performance standard like this disincentivizes AES installations. Without the imposed standard, the end user will optimize the AES to reduce utility bill demand charges, summer on-peak kWhr costs, improve power quality and reliability, and make the AES available for other grid support services. Requiring daily cycles, in excess of current capacity requirements, will impose additional costs on the installation and require the AES to be operated nearly half the 24 hour cycle (charge and discharge), thus reducing its availability for other valuable grid services such as demand response or emergency power.
The CPUC haslong recognized AES as a valuable DER that needs to be encouraged, but imposing new and costly additional requirements will not encourage new installations and may kill-off the necessary demonstration and pilot projects the SGIP is meant to encourage.
The SGIP provides rebates for various on-site distributed energy resources (DER). Energy Storage was added to the list of DER's several years ago after much work by VRB Energy (the former manufacturer of the VRB-ESS® now made by Prudent Energy) Strategen and Utility Savings & Refund, LLC (US&R). One requirement of a qualifying Advanced Energy Storage system (AES) was the ability to provide at least 4 hours of energy and be capable of hundreds of daily charge and discharge cycles. Strategen, representing the California Energy Storage Alliance (CESA), later tried to ease these performance requirements to a single charge-discharge cycle once every three days. The CPUC relaxed the cycling requirement for fuel cell applications but retained the 100's of cycles performance for wind applications. In addition, the CPUC required metering for energy storage to record performance - which was not required for other technologies.
However, the CPUC never required the AES to cycle every day or otherwise "perform" to certain criteria, simply to be able to perform. This was important for the application of AES to the specific on-site load profile of an end-user and the applicable utility tariffs. For example, if the facility was closed on the weekend, then it would be pointless to charge and discharge the AES during the weekend. However, if the electric load was widely variable during the day, then the ability to partially charge and discharge repeatedly would help the facility smooth out its load profile and avoid increasing it's demand on the utility system.
The CPUC has been criticized for funding many projects under the SGIP that produced little electric generation, some being abandoned shortly after installation, so they've decided to condition part of the funding on performance (see pg 32 and 68 of the draft). That may make sense for a traditional generator, like cogen or solar, but is completely inappropriate for storage. Energy storage "stores" energy, it does not "generate". Some energy is lost in the charge - discharge process, which is not important if electricity is being shifted from a lower value time period to a higher value period - like a summer night to a summer hot day.
The CPUC is now requiring a 20% capacity factor for storage, which essentially means it must average a discharge of 4.8 hours per day (24 hours per day * 20% = 4.8 hours).This is a major performance change for storage and may further discourage AES installations. Not only has the performance standard been increased 20% from 4 hours to 4.8 hours of electricity, but cycling every day would cause the installation to lose money. For example, the E-20 industrial tariff for PG&E has a kWhr charge of $.078 at night and $.087 during the day. Assuming 70% efficiency for the charge cycle, comparable to pumped hydro, The AES would need 10 kWhrs of electricity at night ($.78) to deliver 7 kWhrs during the day ($.609). This results in a loss of -$.017 per kWhr delivered!
An arbitray performance standard like this disincentivizes AES installations. Without the imposed standard, the end user will optimize the AES to reduce utility bill demand charges, summer on-peak kWhr costs, improve power quality and reliability, and make the AES available for other grid support services. Requiring daily cycles, in excess of current capacity requirements, will impose additional costs on the installation and require the AES to be operated nearly half the 24 hour cycle (charge and discharge), thus reducing its availability for other valuable grid services such as demand response or emergency power.
The CPUC haslong recognized AES as a valuable DER that needs to be encouraged, but imposing new and costly additional requirements will not encourage new installations and may kill-off the necessary demonstration and pilot projects the SGIP is meant to encourage.
Wednesday, July 20, 2011
CPUC Issues Rebate Revamp for Storage
Well, they've done it. After much delay, the California Public Utilities Commission (CPUC) has finally issued their draft decision in Rulemaking 10-05-004 to modify the Self Generation Incentive Program (SGIP) and the rebates available for Advanced Energy Storage (AES).
The California SGIP program was originally based on state legislation designed to reduce peak energy demand. SGIP rebates were made available to many variations of on-site generation, including solar and natural gas co-generation. Subsequent legislation significantly altered the program, limiting rebates to wind and fuel cell projects. US&R successfully worked with VRB Power, Inc. and Strategen to include rebates for AES. US&R helped develop over 32 MWH of SGIP eligible projects in 2010.
However, recent legislation, SB 412 (2009), required a makeover of the program, basing incentives on green house gas (GHG) reductions instead of reducing peak demand. In addition, certain fuel cell developers, utilizing off-site bio-gas, began to monopolize the program. This resulted in a complete suspension of the program December 2010 until the new rules could be implemented.
The recent decision will be subject to further comments and workshops before it becomes final. We cannot know when new applications will be accepted, but we hope it will be soon. Here are the key points affecting AES:
- Energy storage will still be an eligible technology in spite of some efforts to disqualify it based on no GHG reductions.
- In addition, the draft decision will incentivize stand alone installations. The original program required AES to be associated with fuel cells or wind. This will remove that restriction.
- The incentive will remain at $2 per Watt = $2,000 kW. Other technologies have had their incentives reduced, but storage will retain their previous incentive level.
- Measurement and verification will increased, but the extent and cost will be determined in subsequent workshops.
- Size limit restrictions have been lifted. Incentives are based on the first 3 MW of capacity, but installations over 5 MW had been disqualified entirely. That will no longer apply.
- Generation will be allowed to be exported, with up to 25% not used on-site.
- Substantial application fees will be required.
- The SGIP incentive cannot pay for more than 30% of project cost - unless the project is ineligible for a tax credit.
- Energy efficiency audits will be required - although the project will not be required to implement any recommendations.
- Payment of the SGIP will no longer be 100% upon completion of the project. Instead, only 50% will be paid up front, with the remainder paid over 5 years based on kWh production. A capacity factor of 20% will be used for AES.
These are substantial changes for the SGIP program. We will be tracking and reporting on the final revisions.
Friday, May 13, 2011
CESA v. Itron, How Hard is it to Put Energy Storage in a Box?
The California Public Utilities Commission hired Itron, Inc. to prepare a report on the “Cost-Effectiveness of Distributed Generation Technologies” as part of their on-going project to revise the Self Generation Incentive Program, which has provided rebates for energy storage installations. According to the California Energy Storage Alliance (CESA), they got it completely wrong when it comes to energy storage.
Legislation funding and defining the SGIP was changed by California Senate Bill 412 (SB412), and that has thrown a monkey-wrench into the program. (History of the SGIP program here...) US&R worked with VRB Power Systems, Inc. to open the SGIP for energy storage in 2008. Challenges to the energy storage provisions, the demise of VRB Power and subsequent purchase by Prudent Energy, and the ARRA stimulus program confused implementation, but things finally started to role in 2010 as the Gills Onions project was announced, and at least 5 energy storage projects were approved for the SGIP. However, the new legislation required the CPUC to revise and open the program to additional technologies, and all new applications were suspended to prevent the existing funds from being depleted before the CPUC finished their work.
The Itron report was supposed to provide a basis for evaluation. However, an analysis is only as good as it's assumptions, and Itron created a false energy storage straw man for evaluation, leading to cost effectiveness conclusions that severely reduced the apparent value of energy storage for SGIP incentives.
Some of the points made by CESA in their filing to the CPUC:
The SGIP revision process, which began in January 2010, now appears to be stuck in a quagmire of expensive consultant reports that are trying to compare apples to bananas, and not just energy storage bananas. In the meantime, projects that could be addressing the peak load management objectives of the program are stalled while the consultants fight over the GHG emission reduction benefits of various technologies.
CESA points out that energy storage has already been evaluated for the SGIP. Systems like the VRB® meet those requirements and have already been approved for funding. Unfortunately, until the current process is brought to a close, the opportunity to install and evaluate new storage technologies has been severely reduced.
Legislation funding and defining the SGIP was changed by California Senate Bill 412 (SB412), and that has thrown a monkey-wrench into the program. (History of the SGIP program here...) US&R worked with VRB Power Systems, Inc. to open the SGIP for energy storage in 2008. Challenges to the energy storage provisions, the demise of VRB Power and subsequent purchase by Prudent Energy, and the ARRA stimulus program confused implementation, but things finally started to role in 2010 as the Gills Onions project was announced, and at least 5 energy storage projects were approved for the SGIP. However, the new legislation required the CPUC to revise and open the program to additional technologies, and all new applications were suspended to prevent the existing funds from being depleted before the CPUC finished their work.
The Itron report was supposed to provide a basis for evaluation. However, an analysis is only as good as it's assumptions, and Itron created a false energy storage straw man for evaluation, leading to cost effectiveness conclusions that severely reduced the apparent value of energy storage for SGIP incentives.
Some of the points made by CESA in their filing to the CPUC:
- "...the Itron Report incorrectly assumes that Li-ion technology, one specific type of electrochemical battery storage technology, is representative of all energy storage technologies. This is done even though the Itron Report itself says that advanced lead acid, Zn/Br flow batteries and emerging Zn/air and Fe/Cr were generally found to have potential for low capital expenditure and the smallest gaps to support the energy storage business case. The Itron Report also arbitrarily and inexplicably assumes that Li-ion is a good match for an application that requires a four-hour duration for load shifting purposes."
- "Generally speaking, however, Li-ion is not the most cost-effective solution for long duration, multi-hour peak shifting, nor are Li-ion’s relatively minor volumetric advantages particularly needed for grid storage applications."
- Also, "The discussion of energy storage in the Itron Report makes it painfully clear that the report’s authors failed to understand the sources of value that would truly compensate system owners for their investment in grid connected energy storage. The Itron model does not simulate the way a storage system owner would operate the system in real-world scenarios. Such projects would rely entirely on electric bill savings results from shifting consumption of electricity from peak to off-peak periods, customer demand charge savings, and the SGIP incentive itself."
The SGIP revision process, which began in January 2010, now appears to be stuck in a quagmire of expensive consultant reports that are trying to compare apples to bananas, and not just energy storage bananas. In the meantime, projects that could be addressing the peak load management objectives of the program are stalled while the consultants fight over the GHG emission reduction benefits of various technologies.
CESA points out that energy storage has already been evaluated for the SGIP. Systems like the VRB® meet those requirements and have already been approved for funding. Unfortunately, until the current process is brought to a close, the opportunity to install and evaluate new storage technologies has been severely reduced.
Friday, March 18, 2011
Emission Off-Sets or Energy Storage?
The California Public Utilities Commission (CPUC) is currently dealing with the problem of disappearing electric generation in the Southern California area. Due to environmental concerns - emissions and water - many older fossil fueled plants are being retired,and it's not possible to permit new plants. 12,000 MW of capacity is at risk and system reliability is a great concern of the CAISO (California Independent System Operator). More information can be found here...
The only answer seems to be finding some exemption for new plants with emission off-sets.
However, the California Energy Storage Alliance (CESA) has suggested considering energy storage as a partial solution to the problem. "Grid storage displaces less efficient, dirtier peaker generation by time-shifting more efficient, cleaner base-load generation to peak periods. This results in substantial system-wide air quality benefits."
Janice Lin, co-founder and director of CESA, has prepared a white paper that details he benefits of grid connected energy storage. The CESA comments and the white paper can be found here...
The VRB-ESS(tm) would be an ideal asset to address the need for on-peak power in Southern California. Here's hoping that the staff at the various alphabet soup energy agencies include energy storage in their studies.
Note: The Vanadium Redox Flow Battery - VRB(R) - by Prudent Energy has a long life of 10 - 20 years and is not diminished by multiple charge - discharge cycles to 100% of its SOC (state of charge). The VRB flow battery can be distributed in MW size where needed, with minimal permitting and no air quality impacts. Hours of MW storage are available, with fast response, and the vanadium redox technology is not at risk for fire, explosion or damage from over or undercharging. More information is at our website - Utility-Savings.com.
The only answer seems to be finding some exemption for new plants with emission off-sets.
However, the California Energy Storage Alliance (CESA) has suggested considering energy storage as a partial solution to the problem. "Grid storage displaces less efficient, dirtier peaker generation by time-shifting more efficient, cleaner base-load generation to peak periods. This results in substantial system-wide air quality benefits."
Janice Lin, co-founder and director of CESA, has prepared a white paper that details he benefits of grid connected energy storage. The CESA comments and the white paper can be found here...
The VRB-ESS(tm) would be an ideal asset to address the need for on-peak power in Southern California. Here's hoping that the staff at the various alphabet soup energy agencies include energy storage in their studies.
Note: The Vanadium Redox Flow Battery - VRB(R) - by Prudent Energy has a long life of 10 - 20 years and is not diminished by multiple charge - discharge cycles to 100% of its SOC (state of charge). The VRB flow battery can be distributed in MW size where needed, with minimal permitting and no air quality impacts. Hours of MW storage are available, with fast response, and the vanadium redox technology is not at risk for fire, explosion or damage from over or undercharging. More information is at our website - Utility-Savings.com.
Friday, September 17, 2010
CAISO Report - Integration of Renewable Resources
CAISO - the California Independent System Operator - is constantly worrying about the impact of renewable wind and solar generation on the California grid. It's their job as the grid operator - gotta keep the grid stable and the lights on. The problem with intermittent - oops, sorry, variable generation - "variable" is the new PC term for intermittent - it just sounds so much better - the problem with variable generation is that it is "variable". The grid can't dispatch it when it is needed, like a natural gas peaker plant. It just happens when it wants to happen, whether it is convenient or useful or not.
As a result, CAISO is always studying the problem, and the latest report just came out. Here are some of the highlights:
- First, you'll be happy to know, is that the California grid can handle 20% penetration of renewable resources. Of course, there are some caveats. For example, the increased production of solar and wind energy will displace traditional thermal generators, so their revenue will decrease. In other words, we are likely to put the current generators out of business. Hope you are not invested in one!
- At the same time, we are going to need to keep those plants that are now uneconomic, because we need them to balance out the rapidly changing wind / solar PV generation.
"The integration of variable energy resources will require increased operational flexibility—notably capability to provide load-following and regulation in wider operating ranges and at ramp rates that are faster and of longer sustained duration than are currently experienced. Forecast uncertainty associated with wind and solar production will increase the need for reservation of resource capacity to ensure that these requirements are met in real-time operations...In providing these capabilities, the existing and planned generation fleet will likely need to operate longer at lower minimum operating levels and provide more frequent starts, stops and cycling over the operating day."
Exec. Sumary, pg. iii.
Again, the existing fleet of generators is going to loose money, "The lower capacity factors combined with the reduced energy prices under 20 percent RPS may result in a significant drop in energy market revenues for the gas fleet in all hours of the day and in all seasons." - pg xiv, but we need the entire fleet to keep renewables from crashing the grid, "The additional regulation requirements appear to be well within the capabilities of the existing generation fleet."
So, as long as we keep the current, money - loosing generators, and work them harder, for less money, we can add variable wind and solar without black-outs. Of course, ramping them up and down so much will increase their cost - for less revenue - and increase their emissions - adding pollution when the renewables are supposed to be reducing emissions.
The trade-off on emissions is supposed to come from lower over-all energy generation. Since they will produce less energy, the increased emissions from inefficient ramping will still be less than if they were at full production, although the impact from this type of operation was not calculated."The table also shows a reduction in CO2 emissions from combined cycle generators due to the reduction in operations, although this was calculated using a single emissions factor multiplied by energy output, and did not consider the potential for higher emissions at less efficient levels of operations." pg.86.
And the report made certain assumptions about the status of this generation fleet, that it will increase in capacity, not decrease:
- "Table 2.10 shows the new and planned thermal resources that were included in the analysis. These resources were included as they are currently under construction and have little or no risk of not being available in the 2012 timeframe. No resource retirements were modeled, nor were sensitivities conducted for the status of once-through cooling (OTC) plants. OTC plants are slated to be retrofitted or shut down after 2013 and are not expected to affect the 20 percent RPS integration. However, they could affect renewable integration after 2013, and hence are being examined in the ISO’s 33 percent RPS operational study."
We think increased penetration of energy storage is a better balancing strategy then building more natural gas peaker plants. Using energy storage, like the VRB-ESS™, allows variable resources to be fully integrated without increasing emissions. As we plan for 2020, we hope the regulatory agencies will continue to look toward clean technology resources to integrate renewables, and keep clean energy "clean".
Friday, June 18, 2010
Efficiency of Pumped Hydro Contest - Dud!
My contest to try and get some real figures on the round-trip efficiency of pumped hydro was a dud! No studies, no real world numbers. I heard from a few helpful readers that had projected efficiency numbers based on new turbines from Japan, but no information on existing projects. I find this highly interesting because new advanced energy storage systems, like the VRB-ESS(tm), are being compared, sometimes unfavorably, against pumped hydro. If PH is the gold standard for highly efficient time-shifting power generation, then one would think there would be substantial and easily accessed information on real-world experience.
I may try this again. In the meantime, if any reader has any resources on the subject, please leave a comment.
While we're on the subject, here are a couple of interesting points on the electricity in - electricity out efficiency of the VRB. The standard metric is 65% - 75%, AC-AC. However, the actual round-trip efficiency depends on the application.
For example, the lithium battery providers, like A123 and Altairnano, and flywheel providers, like Beacon Power, are advertising 90% efficiency. However, this is for a very limited pulse of power in the middle of their state of charge (SOS). The application is used for balancing the 60Hz frequency of the grid by pulsing to full capacity - in megawatt size - for only 15 minutes. Apparently, just about any battery system, including lead acid, could pulse like this, in the middle of their SOC, with high efficiency and many cycles.
This applies to the VRB-ESS as well. The greatest efficiency loss occurs at the end of the charge cycle, as it takes more work to find "uncharged" vanadium ions to "fill up the tank". In other words, if a facility had installed enough tanks of electrolyte to store 8 hours of energy, but only used the first 6 hours, then the round-trip efficiency would be closer to 80% than 70%, and if the VRB-ESS was used for the same application as the lithium systems, the efficiency would be the same - in the 90% range. However, one of the key distinctives of the VRB is the ability to fully cycle a nearly unlimited number of times without loss of capacity. Capacity is dependent on the amount of electrolyte. So, an application could chose 30 minutes of storage or 8 hours; it's simply a function of how much electrolyte is stored in the tank. After thousands of full cycles, whether on a 30 minute tank of electrolyte, or an 8 hour tank, the VRB is still able to provide full capacity and for the same amount of energy.
I may try this again. In the meantime, if any reader has any resources on the subject, please leave a comment.
While we're on the subject, here are a couple of interesting points on the electricity in - electricity out efficiency of the VRB. The standard metric is 65% - 75%, AC-AC. However, the actual round-trip efficiency depends on the application.
For example, the lithium battery providers, like A123 and Altairnano, and flywheel providers, like Beacon Power, are advertising 90% efficiency. However, this is for a very limited pulse of power in the middle of their state of charge (SOS). The application is used for balancing the 60Hz frequency of the grid by pulsing to full capacity - in megawatt size - for only 15 minutes. Apparently, just about any battery system, including lead acid, could pulse like this, in the middle of their SOC, with high efficiency and many cycles.
This applies to the VRB-ESS as well. The greatest efficiency loss occurs at the end of the charge cycle, as it takes more work to find "uncharged" vanadium ions to "fill up the tank". In other words, if a facility had installed enough tanks of electrolyte to store 8 hours of energy, but only used the first 6 hours, then the round-trip efficiency would be closer to 80% than 70%, and if the VRB-ESS was used for the same application as the lithium systems, the efficiency would be the same - in the 90% range. However, one of the key distinctives of the VRB is the ability to fully cycle a nearly unlimited number of times without loss of capacity. Capacity is dependent on the amount of electrolyte. So, an application could chose 30 minutes of storage or 8 hours; it's simply a function of how much electrolyte is stored in the tank. After thousands of full cycles, whether on a 30 minute tank of electrolyte, or an 8 hour tank, the VRB is still able to provide full capacity and for the same amount of energy.
Wednesday, March 31, 2010
Contest! Prizes! Discover Efficiency of Pumped Hydro!
Please help us ferret out (apologies to mink and weasel lovers!) information on what appears to be a great mystery - the round trip efficiency of Pumped Hydro Energy Storage. Prizes will be awarded!
The round trip efficiency of storage technologies are of great interest and discussion. Some are concerned about "wasting energy" when storing
electricity. "Losing" 30% of the electricity going into a storage facility is a "non-starter" for them. However, others counter by pointing out the greater value of electricity delivered on-peak, even if some energy is lost by storing off-peak power.
The number one storage technology in use today is pumped hydro. These are, usually, massive projects, where water is pumped up to a reservoir at night, when power is cheaper, and allowed to flow downhill during the day. The turbine used to pump the water uphill is then spun backwards by the water coming downhill, generating electricity. Whenever energy storage is discussed, pumped hydro is held up as the ideal answer due to it's large storage capacity, low emissions (although some have begun to be concerned about the amount of methane released from underwater biomass), fast response (although only when generating electricity) and high efficiency. However, your humble blogger has had a difficult time finding authoritative literature on pumped hydro efficiency, and I'm hoping to tap the resources of other, more knowledable members of the industry, by tempting them with fame and fortune.
As an example of what appears to be unsupported but accepted wisdom, NREL recently published their technical report on energy storage, and said this about pumped hydro:
"PHS plants can achieve round-trip efficiencies that exceed 75% and may have capacities that exceed 20 hours of discharge capacity. (pg 43)" However, even though this is supposed to be a technical report, no citation was offered.
Again, the Electricty Storage Association indicates efficiencies in the 70 - 85% range, but no authorities or links are provided.
I would tend to accept these statements as accurate, not knowing any better, but I have been at conferences where such claims have been hooted at by participants, with counter claims of less than 65%. This has piqued my interest in getting some authoritative answers, especially since the VRB-ESS achieves efficiencies in the 70 - 75% range when used for the same purposes as PHS. Obviously, if efficiencies of 70% or less are not a problem when applied to PHS, then higher efficiencies from a flow battery, like the VRB-ESS, would be even more desireable. If, however, PHS is much less than 70%, then alternative storage systems become even more attractive. But we need to know the facts before we can have an informed discussion.
Hence my contest. We will award prizes and fame to those that provide the most useful resources discussing PHS efficiency. Unless you wish to remain anonymous, we will announce the three commentators that provide the best citations or other authoritative resources. And, the winners will receive their choice of the Enerdynamics publications, "Understanding Today's Electricity Business" or "Understanding Today's Natural Gas Business". Both publications are valued over $60!
As a bonus, anyone that also provides authoritative analysis resources on the actual per kWhr cost of PHS will receive both books = $120!
I'm having a little bit of fun with this, but it looks like a good project given the dearth of information, or so it seems to me, on pumped hydro storage efficiency. Your comments will be posted below, therefore contributing to the general store of knowledge, unless you prefer to email your offerings to ctoca@utility-savings.com. I will be the sole judge of the winners - since it's my contest - and we will close the contest on Thursday, April 15th, so we won't continue to "tax" your patience!
Please click the "Post a Comment" link below or email your replies. Thanks for the help!
The round trip efficiency of storage technologies are of great interest and discussion. Some are concerned about "wasting energy" when storing
electricity. "Losing" 30% of the electricity going into a storage facility is a "non-starter" for them. However, others counter by pointing out the greater value of electricity delivered on-peak, even if some energy is lost by storing off-peak power.The number one storage technology in use today is pumped hydro. These are, usually, massive projects, where water is pumped up to a reservoir at night, when power is cheaper, and allowed to flow downhill during the day. The turbine used to pump the water uphill is then spun backwards by the water coming downhill, generating electricity. Whenever energy storage is discussed, pumped hydro is held up as the ideal answer due to it's large storage capacity, low emissions (although some have begun to be concerned about the amount of methane released from underwater biomass), fast response (although only when generating electricity) and high efficiency. However, your humble blogger has had a difficult time finding authoritative literature on pumped hydro efficiency, and I'm hoping to tap the resources of other, more knowledable members of the industry, by tempting them with fame and fortune.
As an example of what appears to be unsupported but accepted wisdom, NREL recently published their technical report on energy storage, and said this about pumped hydro:
"PHS plants can achieve round-trip efficiencies that exceed 75% and may have capacities that exceed 20 hours of discharge capacity. (pg 43)" However, even though this is supposed to be a technical report, no citation was offered.
Again, the Electricty Storage Association indicates efficiencies in the 70 - 85% range, but no authorities or links are provided.
I would tend to accept these statements as accurate, not knowing any better, but I have been at conferences where such claims have been hooted at by participants, with counter claims of less than 65%. This has piqued my interest in getting some authoritative answers, especially since the VRB-ESS achieves efficiencies in the 70 - 75% range when used for the same purposes as PHS. Obviously, if efficiencies of 70% or less are not a problem when applied to PHS, then higher efficiencies from a flow battery, like the VRB-ESS, would be even more desireable. If, however, PHS is much less than 70%, then alternative storage systems become even more attractive. But we need to know the facts before we can have an informed discussion.
Hence my contest. We will award prizes and fame to those that provide the most useful resources discussing PHS efficiency. Unless you wish to remain anonymous, we will announce the three commentators that provide the best citations or other authoritative resources. And, the winners will receive their choice of the Enerdynamics publications, "Understanding Today's Electricity Business" or "Understanding Today's Natural Gas Business". Both publications are valued over $60!
As a bonus, anyone that also provides authoritative analysis resources on the actual per kWhr cost of PHS will receive both books = $120!
I'm having a little bit of fun with this, but it looks like a good project given the dearth of information, or so it seems to me, on pumped hydro storage efficiency. Your comments will be posted below, therefore contributing to the general store of knowledge, unless you prefer to email your offerings to ctoca@utility-savings.com. I will be the sole judge of the winners - since it's my contest - and we will close the contest on Thursday, April 15th, so we won't continue to "tax" your patience!
Please click the "Post a Comment" link below or email your replies. Thanks for the help!
Monday, March 15, 2010
CAISO Postpones Entry of Energy Storage
The California Independent System Operator (CAISO), the state agency running the transmission system, has postponed the entry of limited energy storage resources (LESRs) into their ancillary services markets.
CAISO is bound by the Federal Energy Regulatory Commission (FERC) Order Nos. 719 and 890 to allow Non-Generator Resources to participate "on a comparable basis to services provided by generation resources in meeting mandatory reliability standards, providing ancillary services and planning the expansion fo the transmission grid".
To that end, CAISO began a stakeholder proceeding in September, 2009. LESR technology providers, like the Beacon flywheel, Altarinano and A123 lithium ion batteries, saw this as an opportunity to open these markets to their short term energy storage systems, as they have been able in other ISO markets. Many saw this as a continuation of the various energy storage proceedings that have started and stopped without resolution at CAISO since 2008.
However, the existing CAISO markets require greater energy resources than the above technologies can provide. Although CAISO reduced their requirements from up to 2 hours of energy, to as little as 30 minutes in the course of this proceeding, the LESR technologies are limited to 15 minutes of energy in one direction - charging or discharging. In fact, they want to be paid for providing service in both directions, requiring them to operate in the middle of their capacity, which only allows them to provide 7 minutes of energy - more or less.
The final decision of CAISO, after months of meetings and stakeholder comments, was the determination that new ancillary services markets would need to be created for these technologies because, "...energy storage and other resource have different operating characteristics and different implementation issues." (Draft Final Proposal, page 3)
CAISO proposes to take up the issue of LESR participation in future proceedings, although the timing is uncertain. This is understandably disappointing for the LESR companies, who have seen some success in other ISO territories, either with full participation or through pilot programs. However, for the foreseeable future, limited energy storage will not be able to participate in CAISO markets.
However, nothing in this decision or other proceedings prevents other energy storage technologies, with longer energy capability, from participating in CAISO markets. For example, the VRB flow battery, with the ability to store hours of energy, qulifies to provide spinning reserve, frequency regulation and other ancillary services. The VRB Energy Storage System (VRB-ESS), sited in conjuction with a solar PV, could shift generation, maintain peak output for the solar generator, and could then provide services to CAISO when not needed for solar energy.
CAISO is bound by the Federal Energy Regulatory Commission (FERC) Order Nos. 719 and 890 to allow Non-Generator Resources to participate "on a comparable basis to services provided by generation resources in meeting mandatory reliability standards, providing ancillary services and planning the expansion fo the transmission grid".
To that end, CAISO began a stakeholder proceeding in September, 2009. LESR technology providers, like the Beacon flywheel, Altarinano and A123 lithium ion batteries, saw this as an opportunity to open these markets to their short term energy storage systems, as they have been able in other ISO markets. Many saw this as a continuation of the various energy storage proceedings that have started and stopped without resolution at CAISO since 2008.
However, the existing CAISO markets require greater energy resources than the above technologies can provide. Although CAISO reduced their requirements from up to 2 hours of energy, to as little as 30 minutes in the course of this proceeding, the LESR technologies are limited to 15 minutes of energy in one direction - charging or discharging. In fact, they want to be paid for providing service in both directions, requiring them to operate in the middle of their capacity, which only allows them to provide 7 minutes of energy - more or less.
The final decision of CAISO, after months of meetings and stakeholder comments, was the determination that new ancillary services markets would need to be created for these technologies because, "...energy storage and other resource have different operating characteristics and different implementation issues." (Draft Final Proposal, page 3)
CAISO proposes to take up the issue of LESR participation in future proceedings, although the timing is uncertain. This is understandably disappointing for the LESR companies, who have seen some success in other ISO territories, either with full participation or through pilot programs. However, for the foreseeable future, limited energy storage will not be able to participate in CAISO markets.
However, nothing in this decision or other proceedings prevents other energy storage technologies, with longer energy capability, from participating in CAISO markets. For example, the VRB flow battery, with the ability to store hours of energy, qulifies to provide spinning reserve, frequency regulation and other ancillary services. The VRB Energy Storage System (VRB-ESS), sited in conjuction with a solar PV, could shift generation, maintain peak output for the solar generator, and could then provide services to CAISO when not needed for solar energy.
Thursday, December 31, 2009
I know this blog is about the VRB Energy Storage System, but...
I guess I'm one of those people who will step aside when the herd is all heading one way to look and make sure we're going the right way, and not off the cliff. Never been a lemming. I don't readily accept the "conventional wisdom". I've found out that usually, when some concept attains universal acceptance, it is probably due to some other reason than good logic, facts or common sense. So, I like to find the "other side of the story" - there is always one.
The VRB ESS fits in this concept. Popular sentiment is rushing toward renewable energy, like wind and solar, without truly considering the consequences. I believe we should develop distributed energy resources for many good reasons, including homeland security, energy independence, and local control v. centralized control. The VRB-ESS connected to solar PV or a wind turbine will provide all of that. And we'll need large energy storage facilities like the VRB to make large wind and solar PV installations useful and to prevent them from crashing the grid due to thier intermittant power output.
But I'm far from convinced that we need renewables to save our planet from global warming (opps! I mean climate change...) There, I've said it. But, even though I don't follow the climate change faith, I still have common ground for the reasons stated above.
All this so I could share these interesting bits:
ScienceDaily (2009-12-31) -- Most of the carbon dioxide emitted by human activity does not remain in the atmosphere, but is instead absorbed by the oceans and terrestrial ecosystems. However, some studies have suggested that the ability of oceans and plants to absorb carbon dioxide recently may have begun to decline and that the airborne fraction of anthropogenic carbon dioxide emissions is therefore beginning to increase. In contradiction to those studies, new research finds that the airborne fraction of carbon dioxide has not increased either during the past 150 years or during the most recent five decades.
And also:
ScienceDaily () -- A physicist from Colorado State University and his colleagues from the North American Carbon Program (NACP) have discerned and confirmed the unforeseen advantages of rising carbon dioxide levels. Through the processes of photosynthesis and respiration, scientists have been able to elucidate why plants are growing more rapidly than they are dying. The NACP is employing methods, such as the use of cell phone and aircraft towers to monitor and retrieve carbon data for their continuing study.
Tuesday, October 27, 2009
CAES - Lies and Damned Lies
With apologies to Mark Twain, I keep thinking of his categorization of whoppers when I hear the misleading, if not willfully false, claims made for Compressed Air Energy Storage - CAES.
The Wall Street Journal has a story on the DOE grants for CAES, due to be announced soon. $60 million is planned to "promote a patented technology that stores energy until it is needed".
First, referring to CAES as "energy storage", is a stretch, if not downright misleading. The WSJ doesn't mention that the compressed air is "stored" for the purpose of firing a natural gas generator! Yes, that's true - a natural gas, greenhouse gas emitting, fossil fueled generator.
Advocates of CAES are quick to point out that using compressed air increases the efficiency of natural gas generators, from about 33% to as much as 88%, so less GHG is emitted. That's great for fossil fueled generation, but don't call it energy storage. However, as discussed in an earlier blog, on an energy in - energy out basis, counting the energy used to compress the air, actual energy efficiency is about 54% or less. But I digress...
Second, how can anyone compare CAES to advanced batteries - like the VRB-ESS - and conclude that it's, "much cheaper than battery storage and far more durable"? The article quotes Robert Schainker of EPRI advising that batteries are too expensive. Elsewhere he is quoted as saying CAES costs about $700 per kWhr. If the PG&E project stays on budget - how likely is that? - then PG&E will get 10 hours at 300 MW, or 3,000 MWHrs for under $400 million, about $133 per kWhr? Wow, what a deal - if it happens. However, what about the cost of the natural gas? No information has been provided yet, but 8 million MMBtu per year seems in the ballpark. At $7 MMbtu, that's at least $560 million over 10 years. Twice that over 20 years. And what are the O&M costs? The generators are typically completely overhauled every 10,000 hours. We need more information...
By contrast, Prudent Energy is expecting the VRB-ESS to run about $500 per kWhr for 6 hours of storage within 2 years, and much cheaper for a 10 hour system. Refurbishment at 10 years, for about $60 kWhr for a 10 hour system, will allow the ESS to run another 10 years. And, wind power can be stored and delivered as needed, without emissions, with about 75% efficiency.
One final digression - if renewable energy, subsidized by taxpayers, is used to enhance a natural gas generator, is it still "renewable". Renewable wind power is consumed to run the air compressors. The compressed air is then released to enhance natural gas generation, turning "clean" energy into "dirty" energy. What does this do to the Renewable Portfolio Standards? Does wind energy, that is not delivered to consumers, but instead is consumed to produce natural gas fired electricity, count toward the 20% - 33% RPS?
There's no guarantee a 300 MW CAES will or can get built as expected, or that it will ultimately cost under $400 million. However, VRB systems can begin to be installed at wind farms and end-users now. It's more likely that 300 MW of VRB batteries can get installed in 5 years than CAES, and we won't have to substitute wind power for natural gas.
Tuesday, September 29, 2009
How Do You Value Grid Connected Energy Storage?
This is almost a part II to my earlier post, but I was reminded again of the problems we face when it comes to defining, and then valuing, Grid Connected Energy Storage (GCES).
The recent New York Times article, "Companies Race to Develop Utility-Scale Power Storage" pointed up the problems and potential for confusion. "Power storage" technologies listed included the Beacon flywheel, the NGK molton sodium-sulfur battery, the A123 lithim ion battery, and compressed air (again!). Quoting a report by GTM Research, this article made a very insightful distinction between "power oriented" technologies, used mainly to regulate short-term changes to grid frequency, and "energy oriented" storage -- in which energy use is shifted to other times of the day. However, the author could have done a better job applying this distinction and pointing out the difference in cost.
For example, the article discussed the $69 million Beacon project in New York, where they will install, "...hundreds of "flywheels" to store 20 megawatts of electricity, enough to power 200 homes for a day." In reality, the flywheel is designed to store only 15 minutes of power and falls into the "power oriented" category above. Its total energy storage will only be 5 MW hrs, about enough to power 40 homes for a day, although it will never be used for that purpose.
Also, the article reported on the $25 million requested by Southern California Edison for an A123 "32-megawatt-hour battery" - but is it really 32 MW hrs? I pose the question because the system will be designed as an 8 MW battery with 4 hours of storage (32 MW hr), but the application is at a wind farm, where multiple cycling is needed to firm wind - a "power oriented" application. Lithium ion batteries are good for about 500 - 600 complete charge and discharge cycles. If it is used in an "energy oriented" application, shifting wind power at night to the day, then it will only last about 2 years. However, in a "power" application, where the battery is barely discharged, it will last for many thousands of cycles. In fact, this is how it is currently applied. In this case it would be operated like an 8 MW flywheel, with usable energy storage of only about 2 MW hrs.
So how do you value these installations? If we value the flywheel and the li-ion systems by the MW hr, then their cost is $13.8 million and $12.5 million respectively. However, if all we care about is their power capacity, then the cost is $3.45 million and $3.125 per MW. (The NGK battery is the only energy oriented technology mentioned in the article, but no cost information was provided.)
By contrast, a VRB-ESS (vanadium redox flow battery - energy storage system) will provide both energy and power, with nearly unlimited cycles, full or partial, for about the same cost per MW of the flywheel or li-ion battery. However, the VRB-ESS will also include 4 - 8 hours of storage, dropping the cost per MW hr to a fraction of the cost for a "power oriented" system.
For example, a 5 MW system with 6 hours of storage would cost about $18 million, with all costs included - a complete turn-key system. That would provide 30 MW hrs of energy at a cost of about $600 thousand per MW hr. The cost of power is only $3.6 million per MW.
Although not directly relevant to the discussion, it's good to know that the VRB-ESS will last 10 years before needing refurbishment. This consists of replacing the PEM (proton exchange membrane) at a cost of about $3 million. The system is then good for another 10 years!
Bottom-line? - It's important to understand the application, whether energy, power or both, and then determine the cost per energy (MW) and/or the cost for power (MW hr), when evaluating the technology.
The recent New York Times article, "Companies Race to Develop Utility-Scale Power Storage" pointed up the problems and potential for confusion. "Power storage" technologies listed included the Beacon flywheel, the NGK molton sodium-sulfur battery, the A123 lithim ion battery, and compressed air (again!). Quoting a report by GTM Research, this article made a very insightful distinction between "power oriented" technologies, used mainly to regulate short-term changes to grid frequency, and "energy oriented" storage -- in which energy use is shifted to other times of the day. However, the author could have done a better job applying this distinction and pointing out the difference in cost.
For example, the article discussed the $69 million Beacon project in New York, where they will install, "...hundreds of "flywheels" to store 20 megawatts of electricity, enough to power 200 homes for a day." In reality, the flywheel is designed to store only 15 minutes of power and falls into the "power oriented" category above. Its total energy storage will only be 5 MW hrs, about enough to power 40 homes for a day, although it will never be used for that purpose.
Also, the article reported on the $25 million requested by Southern California Edison for an A123 "32-megawatt-hour battery" - but is it really 32 MW hrs? I pose the question because the system will be designed as an 8 MW battery with 4 hours of storage (32 MW hr), but the application is at a wind farm, where multiple cycling is needed to firm wind - a "power oriented" application. Lithium ion batteries are good for about 500 - 600 complete charge and discharge cycles. If it is used in an "energy oriented" application, shifting wind power at night to the day, then it will only last about 2 years. However, in a "power" application, where the battery is barely discharged, it will last for many thousands of cycles. In fact, this is how it is currently applied. In this case it would be operated like an 8 MW flywheel, with usable energy storage of only about 2 MW hrs.
So how do you value these installations? If we value the flywheel and the li-ion systems by the MW hr, then their cost is $13.8 million and $12.5 million respectively. However, if all we care about is their power capacity, then the cost is $3.45 million and $3.125 per MW. (The NGK battery is the only energy oriented technology mentioned in the article, but no cost information was provided.)
By contrast, a VRB-ESS (vanadium redox flow battery - energy storage system) will provide both energy and power, with nearly unlimited cycles, full or partial, for about the same cost per MW of the flywheel or li-ion battery. However, the VRB-ESS will also include 4 - 8 hours of storage, dropping the cost per MW hr to a fraction of the cost for a "power oriented" system.
For example, a 5 MW system with 6 hours of storage would cost about $18 million, with all costs included - a complete turn-key system. That would provide 30 MW hrs of energy at a cost of about $600 thousand per MW hr. The cost of power is only $3.6 million per MW.
Although not directly relevant to the discussion, it's good to know that the VRB-ESS will last 10 years before needing refurbishment. This consists of replacing the PEM (proton exchange membrane) at a cost of about $3 million. The system is then good for another 10 years!
Bottom-line? - It's important to understand the application, whether energy, power or both, and then determine the cost per energy (MW) and/or the cost for power (MW hr), when evaluating the technology.
Friday, September 18, 2009
What is Grid Connected Energy Storage?
The California Energy Commission recently requested input on what the definition should be for "utility connected energy storage". Here are some of my thoughts:
***************************
1. How do you define utility scale energy storage?
I would suggest looking at several common sense issues to get a handle on what is utility scale or grid connected energy storage (GCES).
First, we should define energy storage as "electrical" energy storage. That means electrical energy storage in and electrical storage out. For utility or grid applications, we need to store electrical energy for use when needed; meaning excess electrical energy is shifted to a time when electric energy is scarce. This excludes some types of valuable energy storage, like thermal energy storage, but it clarifies what we are doing.
Thermal storage is a good thing and useful, but it cannot be used to produce electrical power for the grid, so it should be excluded from our consideration. This is not to single out thermal energy, but to illustrate the need to focus on electric energy storage. The distinctive of utility or grid energy storage should be the storage of electricity. Storing electricity energy for use as some other type of useful energy does not provide the grid with the electric energy when needed. It is load only. Electric energy storage should be a two way street, not a one way street.
Logically, this also excludes electric energy generators. Again, this is an example of taking a different type of energy and converting it to electricity. Unless we define GCES as electricity in and electricity out, then a coal plant could be considered as GCES since it stores energy in the form of coal and provides energy as needed. If we do not specify electric in - electric out, then our discussion will be so broad as to be meaningless.
And, if we are careful to define GCES as electric in - electric out, then this will also exclude fuel driven compressed air energy storage systems. Such CAES systems are more clearly understood as highly efficient natural gas generators. Electric energy is used to run compressors. The compressed air is used to run natural gas generators more efficiently. Burning natural gas to produce electricity is not electric energy storage. It may be very desirable in some ways, but it should not be in the same box as other technologies that store electricity. If we include fuel driven technologies, then, again, our discussion becomes meaningless.
The second concept to address is the "storage" issue. The common sense expectation is that we are focused on storing and delivering useful amounts of electrical energy.
For example, there is a difference between delivering energy and providing power quality services. Various devices and technologies can store and deliver short bursts or pulses of power to balance short term variations in power quality. Utilities and energy users install various devices for this purpose. But their use is for power quality, not energy.
Similarly, the CAISO operates a market for frequency regulation that is considered a "capacity" market, as distinguished from their "energy" markets. Some ISO's are developing opportunities for Limited Energy Storage Resources (LESRs) to provide capacity - not energy - services, because they recognize the benefit from the quick response of such technologies. However, these systems are, by definition, limited in their energy and are not valued for their volume but for their capacity. Although valuable, they are not useful for energy delivery. At a minimum, a GCES facility should be able to store and deliver electric energy in hours, not minutes. We refer to the technical parameters used by the California Public Utilities Commission in their definition of advanced energy storage for the Self Generation Incentive Program. (Decision 08-11-044 November 21, 2008, page 12, “Ability to be discharged for at least four hours of its rated capacity to fully capture peak load reductions in most utility service territories (required AES duration of discharge will depend on each customer’s specific load shape, and the duration of its peak demand during peak utility periods).”)
LESRs should be in their own separate category for the valuable power quality benefits they provide to the grid, but they should be excluded from the GCES discussion because they cannot deliver energy in useful quantity.
***********************************
Any comments?
***************************
1. How do you define utility scale energy storage?
I would suggest looking at several common sense issues to get a handle on what is utility scale or grid connected energy storage (GCES).
First, we should define energy storage as "electrical" energy storage. That means electrical energy storage in and electrical storage out. For utility or grid applications, we need to store electrical energy for use when needed; meaning excess electrical energy is shifted to a time when electric energy is scarce. This excludes some types of valuable energy storage, like thermal energy storage, but it clarifies what we are doing.
Thermal storage is a good thing and useful, but it cannot be used to produce electrical power for the grid, so it should be excluded from our consideration. This is not to single out thermal energy, but to illustrate the need to focus on electric energy storage. The distinctive of utility or grid energy storage should be the storage of electricity. Storing electricity energy for use as some other type of useful energy does not provide the grid with the electric energy when needed. It is load only. Electric energy storage should be a two way street, not a one way street.
Logically, this also excludes electric energy generators. Again, this is an example of taking a different type of energy and converting it to electricity. Unless we define GCES as electricity in and electricity out, then a coal plant could be considered as GCES since it stores energy in the form of coal and provides energy as needed. If we do not specify electric in - electric out, then our discussion will be so broad as to be meaningless.
And, if we are careful to define GCES as electric in - electric out, then this will also exclude fuel driven compressed air energy storage systems. Such CAES systems are more clearly understood as highly efficient natural gas generators. Electric energy is used to run compressors. The compressed air is used to run natural gas generators more efficiently. Burning natural gas to produce electricity is not electric energy storage. It may be very desirable in some ways, but it should not be in the same box as other technologies that store electricity. If we include fuel driven technologies, then, again, our discussion becomes meaningless.
The second concept to address is the "storage" issue. The common sense expectation is that we are focused on storing and delivering useful amounts of electrical energy.
For example, there is a difference between delivering energy and providing power quality services. Various devices and technologies can store and deliver short bursts or pulses of power to balance short term variations in power quality. Utilities and energy users install various devices for this purpose. But their use is for power quality, not energy.
Similarly, the CAISO operates a market for frequency regulation that is considered a "capacity" market, as distinguished from their "energy" markets. Some ISO's are developing opportunities for Limited Energy Storage Resources (LESRs) to provide capacity - not energy - services, because they recognize the benefit from the quick response of such technologies. However, these systems are, by definition, limited in their energy and are not valued for their volume but for their capacity. Although valuable, they are not useful for energy delivery. At a minimum, a GCES facility should be able to store and deliver electric energy in hours, not minutes. We refer to the technical parameters used by the California Public Utilities Commission in their definition of advanced energy storage for the Self Generation Incentive Program. (Decision 08-11-044 November 21, 2008, page 12, “Ability to be discharged for at least four hours of its rated capacity to fully capture peak load reductions in most utility service territories (required AES duration of discharge will depend on each customer’s specific load shape, and the duration of its peak demand during peak utility periods).”)
LESRs should be in their own separate category for the valuable power quality benefits they provide to the grid, but they should be excluded from the GCES discussion because they cannot deliver energy in useful quantity.
***********************************
Any comments?
Friday, August 28, 2009
PG&E Compressed Air Project - Quick Thoughts
Now that the deadline has passed to file for grid storage projects under the ARRA , we're beginning to see some of the concepts and projects that have applied for funds - see post below - including the 300 MW compressed air project by PG&E I believe PG&E will have to deal with some of the following issues on this project.
- First, the $25 million requested is only for "initial analysis and design". The anticipated cost for the project will be $368 million. And that's before we see the cost over runs, delays and unexpected problems a huge project like this will invariably incur.
- Then the utility will have to explain why they want to take "clean" wind energy and make it "dirty". Because, you see, the compressed air will be used for natural gas turbines! The argument is that the compressed air will make the natural gas turbines run more efficiently, requiring less natural gas - which is great if you're trying to make your natural gas turbines more efficient. But we thought the point of wind energy was to produce clean and renewable power - not more fossil fueled power.
- And how much energy will we lose in this process? We create a certain amount of energy with wind and then burn it away by compressing it and burning natural gas. What is the net delivered energy when all of this is finished? I've seen reports of as little as 54%. So we take wind energy, throw away 40% or more, increase the price volatility through the natural gas market, and add emissions and GHGs. Why is this a good idea?
Thursday, August 27, 2009
Largest Grid Battery Ever? What's the Real Story?
Southern California Edison has announced, apparently, that they have applied to the DOE, under the smart grid stimulus program, for $25 million to build the largest grid battery ever. I have many questions about this story and I'm hoping we'll get more clarification in the near future.
We are well aware of the DOE grant program because we are involved in several applications for the VRB-ESS. We'll provide more information as we have developments we can share.
Here are the issues and questions I have with the story:
We are well aware of the DOE grant program because we are involved in several applications for the VRB-ESS. We'll provide more information as we have developments we can share.
Here are the issues and questions I have with the story:
- First, I cannot find a press release from SCE. The story appears to based on an interview with Paul De Martini, Southern California Edison's vice president of advanced technologies. This makes it a bit difficult to get more detail or clarification. We'll ask Mr. De Martini for clarification.
- Next, the story says the grant is for 32 megawatt hours of storage. Since the current A123 grid systems in place are for grid stabilization, with only about 15 minutes of storage, Edison would need to install 128 MW of capacity to get 32 hours of energy. That would make it a huge, unheard of capacity battery, but with very short term storage. So, I'm not sure what the application would be for wind energy. 4:1 capacity to energy storage is normally conceived for frequency regulation, which is the current application for A123. That type of application can be anywhere on the grid - there is no need to place it at a wind farm. We normally think of storage for wind for the purpose of shifting generation from night time production to the day - something you can't do with 15 min. of storage.
- If the project is 32 MWHrs of storage, then it isn't the biggest project by a long shot. The 238 MWHr system by NGK in Japan wins that contest with their 34 MW by 7 hours of storage system. Sure, they can only use half the capacity at a time to avoid overcharging, but the total is still greater than the Edison project - if the story is correct.
- The ARRA grant is a matching grant, so we assume Edison will need to seek approval from the California Public Utilities Commission for an additional $25 million, or more, for a total cost of $50 million. That's $1,500 per kilowatt hour! - pretty darn expensive. For comparison, the flow batteries and NGK are between $500 and $700. However, on a capacity basis, at 128 MW, it's only $390 per kW.
- If the story meant to state a 32 MW capacity, then the economics make no sense.
Wednesday, August 5, 2009
VRB-ESS Government Incentives
This is a big month for us and many other energy storage companies. The American Recovery and Reinvestment Act - ARRA - a.k.a the Obama Stimulus Legislation - contains many incentives for energy storage and the smart grid. We're currently submitting several projects under the Smart Grid Demonstration Grant, which targets energy storage demonstrations. The deadline for submission is August 26th, and the total package will probably run to over 100 pages. We don't know how many projects will be submitted for the VRB-ESS - several sites are under evaluation - but, due to the complexity of the grant application process, we'll probably have to shut the door to additional projects around the 15th.
The Smart Grid Demonstration Grant is looking for several different types of demonstrations. The VRB-ESS is a good candidate for each category except one that is specifically set aside for compressed air energy storage. Grants are running from a couple million dollars for 1-3 MW installations to $25 million for 8-15 MW.
Here is the current breakdown of incentives for the VRB-ESS. We believe that the VRB-ESS specifically qualifies for these incentives in California - other energy storage technologies may not qualify.
The Smart Grid Demonstration Grant is looking for several different types of demonstrations. The VRB-ESS is a good candidate for each category except one that is specifically set aside for compressed air energy storage. Grants are running from a couple million dollars for 1-3 MW installations to $25 million for 8-15 MW.
Here is the current breakdown of incentives for the VRB-ESS. We believe that the VRB-ESS specifically qualifies for these incentives in California - other energy storage technologies may not qualify.
- ARRA - Under the current grant opportunity, the Department of Energy will fund 50% of an eligible project.
- SGIP - the California Self Generation Incentive Program will provide a rebate of $2 Watt ($2 million per MW) for the VRB-ESS in association with on-site fuel cells or wind turbines. We believe the VRB-ESS will also qualify for an additional 20% ($2.40 per Watt) under a specific provision for California suppliers.
- ITC - The Investment Tax Credit cash grant is equal to 30% of a project cost when integrated with other renewable energy projects. There are many conditions to this grant, but it's actually very liberal for the VRB-ESS. It will apply to VRB-ESS retrofits to existing cogeneration, fuel cells, biomass, hydro, wind, solar, etc. installations.
Friday, July 17, 2009
ITC Cash Grant for Storage
While the new guidelines from Treasury for the ITC grant are garnering headlines, a slightly overlooked item is the extension of the grant to energy storage!
Developers and vendors have had mixed views over the potential application of the Investment Tax Credit to energy storage equipment at renewable energy facilities. Guidance was lacking and opinions were mixed, including those of government agencies. Storage would allow PV and other intermittent renewables to increase their revenue per kW by providing firm and dispatchable power, increased sales of energy during the highest paid peak period, and the ability to offer additional ancillary services of great value to the grid operator. But, without the assurance of a tax credit, developers were cautious about figuring storage into their calculations.
However, the Treasury has now issued guidance on the ITC cash grant in lieu of a credit, and storage facilities are included. (see page 11) Storage must be "integrated" into the project, but the guidance on that is not restrictive. Now, the additional revenue from using storage can be factored into a project, and the investors can benefit from the tax credit/grant.
Subscribe to:
Posts (Atom)
