Here is my quick summary of the Mon Power, ApCo, and Wheeling Power IRPs
Top Ten Talking Points on Mon Power & Potomac Edison's IRP
1. MP/PE ignores the CPP. No specific plans until DEP imposes requirements.
2. Since Mon Power provides all generation for PE, these are combined under Mon Power.
3. MP projects a capacity shortfall by 2016, with the shortfall growing to 850 MW by 2027.
4. Propose two options: A) Purchase 850 MW of new capacity in 2017, or B) Retrofit existing plants (Harrison and Fort Martin) to co-fire with up to 30 % gas. Cost of conversion would be $55-80 million at each plant.. (What happened? I though the purchase of Harrison was supposed to provide excess capacity for decades!)
5. Current Capacity is 1984 MW from Harrison, 1098 MW from Fort Martin, 488 MW from Bath County pump-storage ; 50 MW from MEA, 80 MW from Grant Town, and 31 MW from New Martinsville Hannibal Hydro Project.
6. Actual peak growth 2010-2014 was 3.1 %, mostly from growth in the natural gas drilling and processing sector. Projected peak load forecast is 2.2 % per year for 2015-2020.
7. Mon Power apparently did not consider ANY new EE or DR options for meeting new capacity needs. Existing Phase I and Phase II EE Plans will reduce energy use by cumulative 1 % by 2018.
8. Claims the Mercury rule was a key factor in closing Albright, Rivesville and Willow Island Sept. 1, 2012.
9. Concludes that solar, geothermal, and new hydro are not cost-effective, but wind or biomass co-firing are most viable options for renewable generation.
10. New generation could be acquired by building or buying an additional power plant. Co-firing would add "fuel diversity" at existing plants. (It is not clear to me how co-firing helps resolve the capacity shortfall?)
Top Ten Talking Points on ApCo's IRP (Based on a review of the Executive Summary)
1. ApCo Ignores the CPP. No specific plans until DEP imposes requirements. Models assume a "cost of carbon dioxide" of $15-20/ton over a 30-year period.
2. FERC Capacity requirements (Peak Demand & Reliability assurance) differ from expected generation (actual energy requirements of customers), both will be important. Intermittent sources such as wind and solar will have limited "capacity" potential, driving ApCo to retain more base load and peaking facilities. ApCo expects a slight capacity shortfall between available generation versus expected demand by 2021, based on PJM's Capacity Performance rule (reserve margin requirements).
3. ApCo assumes average growth in demand of 0.3%, with peak demand increasing 0.2 % annually.
4. ApCo continues operation of Amos and Mountaineer plants.
5. Convert Clinch River Units 1 & 2 from coal to gas, but retires them in 2026.
6. Additional Demand side resources in the form of EE and Volt-Var Optimization = 3.1 % of energy needs, reducing capacity requirements by 118 MW by 2025.
7. Add 10 MW of large-scale solar by 2018.
8. Add 150 MW in 2018, 2020, 2021, 2022 & 2025 (750 MW total).
9. Assumes customers add distributed solar increasing by 5 % annually, totaling 14 MW by 2025. (The analysis assumed the ITC expired in 2016, so I think we can expect faster growth. For example, the average growth rate in residential solar for the last 10 years has been around 40 % per year, so continuing that rate should get us over 200 MW).
10. Adds 10 MW of battery storage by 2025.
Four Talking Points on Wheeling Power's IRP Based on a review of the Executive Summary)
1. Ignores CPP
2. Assumes growth in demand of 0.4 % and in peak Demand of 0.5 % per year.
3. All of WPCo's capacity comes from 50 % ownership in Mitchell plant.
4. No new resources are proposed, but some demand-side management options may be proposed in the future.
Thanks for this, Jim. EEWV is not going to be intervening, but I appreciate being kept in the loop.
We will probably be issuing comments in the coming weeks, though. My associate, Levi (copied), will be working with me on those. We're actually thinking about doing comments on all of the IRPs, even the small ones.
What's interesting is that Black Diamond, which is a small utility with about 2600 customers in the Beckley area, has said that it will not be filing an IRP. It is saying that, because it purchases all of their power from APCo, it doesn't need to issue an IRP. It also says that APCo would "include Black Diamond in its Integrated Resource Plan filing," but I couldn't see anything in the APCo filing that mentioned Black Diamond. Furthermore, I know that Black Diamond customers are not permitted to access most of the energy efficiency programs offered by APCo. While Black Diamond is a very small utility in the grand scale of things, I think that EEWV may issue a letter of protest that it is not complying with the statute.
Is Sierra Club going to file in all three of the main utilities' IRPs, or just stick to APCo and MP/PE?
-Emmett
P.S. - Here's the letter filed by Black Diamond that I am referring to: http://www.psc.state.wv.us/scripts/WebDocket/ViewDocument.cfm?CaseActivityID...
-- Emmett Pepper Executive Director Energy Efficient WV 304-346-5891 emmett@eewv.org www.eewv.org @eewv
On Wed, Jan 6, 2016 at 9:31 PM, James Kotcon jkotcon@wvu.edu wrote:
Here is my quick summary of the Mon Power, ApCo, and Wheeling Power IRPs
*Top Ten Talking Points on Mon Power & Potomac Edison’s IRP*
MP/PE ignores the CPP. No specific plans until DEP imposes requirements. 2.
Since Mon Power provides all generation for PE, these are combined under Mon Power. 3.
MP projects a capacity shortfall by 2016, with the shortfall growing to 850 MW by 2027. 4.
Propose two options: A) Purchase 850 MW of new capacity in 2017, or B) Retrofit existing plants (Harrison and Fort Martin) to co-fire with up to 30 % gas. Cost of conversion would be $55-80 million at each plant.. (What happened? I though the purchase of Harrison was supposed to provide excess capacity for decades!) 5.
Current Capacity is 1984 MW from Harrison, 1098 MW from Fort Martin, 488 MW from Bath County pump-storage ; 50 MW from MEA, 80 MW from Grant Town, and 31 MW from New Martinsville Hannibal Hydro Project. 6.
Actual peak growth 2010-2014 was 3.1 %, mostly from growth in the natural gas drilling and processing sector. Projected peak load forecast is 2.2 % per year for 2015-2020. 7.
*Mon Power apparently did not consider ANY new EE or DR options for meeting new capacity needs.* Existing Phase I and Phase II EE Plans will reduce energy use by cumulative 1 % by 2018. 8.
Claims the Mercury rule was a key factor in closing Albright, Rivesville and Willow Island Sept. 1, 2012. 9.
Concludes that solar, geothermal, and new hydro are not cost-effective, but wind or biomass co-firing are most viable options for renewable generation. 10.
New generation could be acquired by building or buying an additionalpower plant. Co-firing would add “fuel diversity” at existing plants. (It is not clear to me how co-firing helps resolve the capacity shortfall?)
*Top Ten Talking Points on ApCo’s IRP* (Based on a review of the Executive Summary)
ApCo Ignores the CPP. No specific plans until DEP imposes requirements. Models assume a “cost of carbon dioxide” of $15-20/ton over a 30-year period. 2.
FERC Capacity requirements (Peak Demand & Reliability assurance) differ from expected generation (actual energy requirements of customers), both will be important. Intermittent sources such as wind and solar will have limited “capacity” potential, driving ApCo to retain more base load and peaking facilities. ApCo expects a slight capacity shortfall between available generation versus expected demand by 2021, based on PJM’s Capacity Performance rule (reserve margin requirements). 3.
ApCo assumes average growth in *demand* of 0.3%, with peak demand increasing 0.2 % annually. 4.
ApCo continues operation of Amos and Mountaineer plants. 5.
Convert Clinch River Units 1 & 2 from coal to gas, but retires them in 2026. 6.
Additional Demand side resources in the form of EE and Volt-Var Optimization = 3.1 % of energy needs, reducing capacity requirements by 118 MW by 2025. 7.
Add 10 MW of large-scale solar by 2018. 8.
Add 150 MW in 2018, 2020, 2021, 2022 & 2025 (750 MW total). 9.
Assumes customers add distributed solar increasing by 5 % annually, totaling 14 MW by 2025. (The analysis assumed the ITC expired in 2016, so I think we can expect faster growth. For example, the average growth rate in residential solar for the last 10 years has been around 40 % per year, so continuing that rate should get us over 200 MW). 10.
Adds 10 MW of battery storage by 2025.*Four Talking Points on Wheeling Power’s IRP* Based on a review of the Executive Summary)
Ignores CPP 2.
Assumes growth in *demand* of 0.4 % and in peak Demand of 0.5 % per year. 3.
All of WPCo’s capacity comes from 50 % ownership in Mitchell plant. 4.
No new resources are proposed, but some demand-side management options may be proposed in the future.
Here is a story on today's Charleston Gazette that provides a better narrative on the IRPs filed.
JBK
Full story (and picture) is at: http://www.wvgazettemail.com/business/20160109/appalachian-power-moves-towar...
West Virginia’s four largest electric utilities have revealed plans for what the state’s power production might look like over the next 10 years.
First Energy’s and American Electric Power’s West Virginia subsidiaries filed their integrated resource plans, a type of roadmap used by power companies, with the state Public Service Commission on Dec. 30.
While the companies have conducted integrated resource planning in the past, this is the first time the utilities have been required to make the plans public in West Virginia, after a bill passedhttp://www.legis.state.wv.us/Bill_Text_HTML/2014_SESSIONS/RS/bills/HB2803%20SUB.pdf by the West Virginia Legislature in 2014 and the PSC issued an orderhttp://www.psc.state.wv.us/scripts/WebDocket/ViewDocument.cfm?CaseActivityID=420248 last year.
The planning documents, which rely on cost calculations, electric demand data and energy forecasts, highlight where the electricity for homes and businesses in West Virginia may come from in the coming decade and give a vague understanding of what investments might be made by the companies in order to supply that power.
For Appalachian Powerhttps://www.documentcloud.org/documents/2671906-Appalachian-Power-IRP.html and Wheeling Powerhttps://www.documentcloud.org/documents/2672088-Wheeling-Power-IRP.html, the plans show that both American Electric Power subsidiaries will continue to rely on the John Amos, Mitchell and Mountaineer coal-fired plants to supply a majority of the energy needed for their 475,000 customers in West Virginia. But the documents also highlight Appalachian Power’s attempt to diversify its energy portfolio, adding more solar and wind energy, as the company moves closer to 2025.
It’s a different story for the Mon Power and Potomac Edison. The First Energy subsidiarieshttps://www.documentcloud.org/documents/2671612-First-Energy-IRP-2016.html will continue to provide roughly 389,000 customers with electricity largely from the Harrison and Fort Martin coal-fired power plants. But where Appalachian Power expects to move toward alternative energy sources, the First Energy companies are considering additional investments in coal power.
The First Energy resource plan considers purchasing another existing coal-fired power plant in order to meet an expected 700-megawatt deficit by 2020, and it suggests retrofitting the Harrison and Fort Martin plants to let them co-fire with natural gas.
“At a high level, we have identified existing coal plants as the option that appears to be the lowest-cost solution to meet our capacity shortfall,” said Todd Meyers, a spokesman for Mon Power and Potomac Edison. “This option would require an agreement between Mon Power and any seller at a price that allows this to remain the lowest cost solution.”
James Van Nostrand, a West Virginia University law professor and the director of the Center for Energy and Sustainable Development, said co-firing the Harrison and Fort Martin plants is a good course of action, but he can’t understand how buying another coal plant is the best choice for the companies’ ratepayers.
“It’s shocking if they get away with buying more coal,” Van Nostrand said. “It’s a tale of two utilities, in terms of one that gets it and another that is sticking its head in the sand.”
Renewable energy sources like wind and solar are becoming cheaper, as they continue to benefit from reapproved tax incentives. Natural gas has started to outcompete coal as the dominant source of power. Residential and commercial customers have continued to install rooftop solarhttp://www.wvgazettemail.com/article/20151114/GZ03/151119721/1101. The U.S. Supreme Court is set to rulehttp://www.wvgazettemail.com/article/20151010/GZ03/151019994 on the Federal Energy Regulatory Commission’s jurisdiction to regulate aspects of electricity demand. And the Obama administration’s highly-contested Clean Power Plan continues to work its way through the federal court system, even as it begins to affect price outlooks for coal and other carbon-based power after 2022.
- See more at: http://www.wvgazettemail.com/business/20160109/appalachian-power-moves-towar...
________________________________ From: James Kotcon Sent: Wednesday, January 6, 2016 9:31 PM To: ec@osenergy.org; Mark Kresowik; Bridget Lee Cc: Emmett Pepper Subject: IRP Review
Here is my quick summary of the Mon Power, ApCo, and Wheeling Power IRPs
Top Ten Talking Points on Mon Power & Potomac Edison’s IRP
1. MP/PE ignores the CPP. No specific plans until DEP imposes requirements.
2. Since Mon Power provides all generation for PE, these are combined under Mon Power.
3. MP projects a capacity shortfall by 2016, with the shortfall growing to 850 MW by 2027.
4. Propose two options: A) Purchase 850 MW of new capacity in 2017, or B) Retrofit existing plants (Harrison and Fort Martin) to co-fire with up to 30 % gas. Cost of conversion would be $55-80 million at each plant.. (What happened? I though the purchase of Harrison was supposed to provide excess capacity for decades!)
5. Current Capacity is 1984 MW from Harrison, 1098 MW from Fort Martin, 488 MW from Bath County pump-storage ; 50 MW from MEA, 80 MW from Grant Town, and 31 MW from New Martinsville Hannibal Hydro Project.
6. Actual peak growth 2010-2014 was 3.1 %, mostly from growth in the natural gas drilling and processing sector. Projected peak load forecast is 2.2 % per year for 2015-2020.
7. Mon Power apparently did not consider ANY new EE or DR options for meeting new capacity needs. Existing Phase I and Phase II EE Plans will reduce energy use by cumulative 1 % by 2018.
8. Claims the Mercury rule was a key factor in closing Albright, Rivesville and Willow Island Sept. 1, 2012.
9. Concludes that solar, geothermal, and new hydro are not cost-effective, but wind or biomass co-firing are most viable options for renewable generation.
10. New generation could be acquired by building or buying an additional power plant. Co-firing would add “fuel diversity” at existing plants. (It is not clear to me how co-firing helps resolve the capacity shortfall?)
Top Ten Talking Points on ApCo’s IRP (Based on a review of the Executive Summary)
1. ApCo Ignores the CPP. No specific plans until DEP imposes requirements. Models assume a “cost of carbon dioxide” of $15-20/ton over a 30-year period.
2. FERC Capacity requirements (Peak Demand & Reliability assurance) differ from expected generation (actual energy requirements of customers), both will be important. Intermittent sources such as wind and solar will have limited “capacity” potential, driving ApCo to retain more base load and peaking facilities. ApCo expects a slight capacity shortfall between available generation versus expected demand by 2021, based on PJM’s Capacity Performance rule (reserve margin requirements).
3. ApCo assumes average growth in demand of 0.3%, with peak demand increasing 0.2 % annually.
4. ApCo continues operation of Amos and Mountaineer plants.
5. Convert Clinch River Units 1 & 2 from coal to gas, but retires them in 2026.
6. Additional Demand side resources in the form of EE and Volt-Var Optimization = 3.1 % of energy needs, reducing capacity requirements by 118 MW by 2025.
7. Add 10 MW of large-scale solar by 2018.
8. Add 150 MW in 2018, 2020, 2021, 2022 & 2025 (750 MW total).
9. Assumes customers add distributed solar increasing by 5 % annually, totaling 14 MW by 2025. (The analysis assumed the ITC expired in 2016, so I think we can expect faster growth. For example, the average growth rate in residential solar for the last 10 years has been around 40 % per year, so continuing that rate should get us over 200 MW).
10. Adds 10 MW of battery storage by 2025.
Four Talking Points on Wheeling Power’s IRP Based on a review of the Executive Summary)
1. Ignores CPP
2. Assumes growth in demand of 0.4 % and in peak Demand of 0.5 % per year.
3. All of WPCo’s capacity comes from 50 % ownership in Mitchell plant.
4. No new resources are proposed, but some demand-side management options may be proposed in the future.
I loved Van Nostrand's comment. He called First Energy a "Neanerthal utility."
On Sun, Jan 10, 2016 at 9:32 AM, James Kotcon jkotcon@wvu.edu wrote:
Here is a story on today's Charleston Gazette that provides a better narrative on the IRPs filed.
JBK
Full story (and picture) is at:
http://www.wvgazettemail.com/business/20160109/appalachian-power-moves-towar...
West Virginia’s four largest electric utilities have revealed plans for what the state’s power production might look like over the next 10 years.
First Energy’s and American Electric Power’s West Virginia subsidiaries filed their integrated resource plans, a type of roadmap used by power companies, with the state Public Service Commission on Dec. 30.
While the companies have conducted integrated resource planning in the past, this is the first time the utilities have been required to make the plans public in West Virginia, after a bill passed http://www.legis.state.wv.us/Bill_Text_HTML/2014_SESSIONS/RS/bills/HB2803%20SUB.pdf by the West Virginia Legislature in 2014 and the PSC issued an order http://www.psc.state.wv.us/scripts/WebDocket/ViewDocument.cfm?CaseActivityID=420248 last year.
The planning documents, which rely on cost calculations, electric demand data and energy forecasts, highlight where the electricity for homes and businesses in West Virginia may come from in the coming decade and give a vague understanding of what investments might be made by the companies in order to supply that power.
For Appalachian Power https://www.documentcloud.org/documents/2671906-Appalachian-Power-IRP.html and Wheeling Power https://www.documentcloud.org/documents/2672088-Wheeling-Power-IRP.html, the plans show that both American Electric Power subsidiaries will continue to rely on the John Amos, Mitchell and Mountaineer coal-fired plants to supply a majority of the energy needed for their 475,000 customers in West Virginia. But the documents also highlight Appalachian Power’s attempt to diversify its energy portfolio, adding more solar and wind energy, as the company moves closer to 2025.
It’s a different story for the Mon Power and Potomac Edison. The First Energy subsidiaries https://www.documentcloud.org/documents/2671612-First-Energy-IRP-2016.html will continue to provide roughly 389,000 customers with electricity largely from the Harrison and Fort Martin coal-fired power plants. But where Appalachian Power expects to move toward alternative energy sources, the First Energy companies are considering additional investments in coal power.
The First Energy resource plan considers purchasing another existing coal-fired power plant in order to meet an expected 700-megawatt deficit by 2020, and it suggests retrofitting the Harrison and Fort Martin plants to let them co-fire with natural gas.
“At a high level, we have identified existing coal plants as the option that appears to be the lowest-cost solution to meet our capacity shortfall,” said Todd Meyers, a spokesman for Mon Power and Potomac Edison. “This option would require an agreement between Mon Power and any seller at a price that allows this to remain the lowest cost solution.”
James Van Nostrand, a West Virginia University law professor and the director of the Center for Energy and Sustainable Development, said co-firing the Harrison and Fort Martin plants is a good course of action, but he can’t understand how buying another coal plant is the best choice for the companies’ ratepayers.
“It’s shocking if they get away with buying more coal,” Van Nostrand said. “It’s a tale of two utilities, in terms of one that gets it and another that is sticking its head in the sand.”
Renewable energy sources like wind and solar are becoming cheaper, as they continue to benefit from reapproved tax incentives. Natural gas has started to outcompete coal as the dominant source of power. Residential and commercial customers have continued to install rooftop solar http://www.wvgazettemail.com/article/20151114/GZ03/151119721/1101. The U.S. Supreme Court is set to rule http://www.wvgazettemail.com/article/20151010/GZ03/151019994 on the Federal Energy Regulatory Commission’s jurisdiction to regulate aspects of electricity demand. And the Obama administration’s highly-contested Clean Power Plan continues to work its way through the federal court system, even as it begins to affect price outlooks for coal and other carbon-based power after 2022.
- See more at:
http://www.wvgazettemail.com/business/20160109/appalachian-power-moves-towar...
*From:* James Kotcon *Sent:* Wednesday, January 6, 2016 9:31 PM *To:* ec@osenergy.org; Mark Kresowik; Bridget Lee *Cc:* Emmett Pepper *Subject:* IRP Review
Here is my quick summary of the Mon Power, ApCo, and Wheeling Power IRPs
*Top Ten Talking Points on Mon Power & Potomac Edison’s IRP*
MP/PE ignores the CPP. No specific plans until DEP imposes requirements. 2.
Since Mon Power provides all generation for PE, these are combined under Mon Power. 3.
MP projects a capacity shortfall by 2016, with the shortfall growing to 850 MW by 2027. 4.
Propose two options: A) Purchase 850 MW of new capacity in 2017, or B) Retrofit existing plants (Harrison and Fort Martin) to co-fire with up to 30 % gas. Cost of conversion would be $55-80 million at each plant.. (What happened? I though the purchase of Harrison was supposed to provide excess capacity for decades!) 5.
Current Capacity is 1984 MW from Harrison, 1098 MW from Fort Martin, 488 MW from Bath County pump-storage ; 50 MW from MEA, 80 MW from Grant Town, and 31 MW from New Martinsville Hannibal Hydro Project. 6.
Actual peak growth 2010-2014 was 3.1 %, mostly from growth in the natural gas drilling and processing sector. Projected peak load forecast is 2.2 % per year for 2015-2020. 7.
*Mon Power apparently did not consider ANY new EE or DR options for meeting new capacity needs.* Existing Phase I and Phase II EE Plans will reduce energy use by cumulative 1 % by 2018. 8.
Claims the Mercury rule was a key factor in closing Albright, Rivesville and Willow Island Sept. 1, 2012. 9.
Concludes that solar, geothermal, and new hydro are not cost-effective, but wind or biomass co-firing are most viable options for renewable generation. 10.
New generation could be acquired by building or buying an additionalpower plant. Co-firing would add “fuel diversity” at existing plants. (It is not clear to me how co-firing helps resolve the capacity shortfall?)
*Top Ten Talking Points on ApCo’s IRP* (Based on a review of the Executive Summary)
ApCo Ignores the CPP. No specific plans until DEP imposes requirements. Models assume a “cost of carbon dioxide” of $15-20/ton over a 30-year period. 2.
FERC Capacity requirements (Peak Demand & Reliability assurance) differ from expected generation (actual energy requirements of customers), both will be important. Intermittent sources such as wind and solar will have limited “capacity” potential, driving ApCo to retain more base load and peaking facilities. ApCo expects a slight capacity shortfall between available generation versus expected demand by 2021, based on PJM’s Capacity Performance rule (reserve margin requirements). 3.
ApCo assumes average growth in *demand* of 0.3%, with peak demand increasing 0.2 % annually. 4.
ApCo continues operation of Amos and Mountaineer plants. 5.
Convert Clinch River Units 1 & 2 from coal to gas, but retires them in 2026. 6.
Additional Demand side resources in the form of EE and Volt-Var Optimization = 3.1 % of energy needs, reducing capacity requirements by 118 MW by 2025. 7.
Add 10 MW of large-scale solar by 2018. 8.
Add 150 MW in 2018, 2020, 2021, 2022 & 2025 (750 MW total). 9.
Assumes customers add distributed solar increasing by 5 % annually, totaling 14 MW by 2025. (The analysis assumed the ITC expired in 2016, so I think we can expect faster growth. For example, the average growth rate in residential solar for the last 10 years has been around 40 % per year, so continuing that rate should get us over 200 MW). 10.
Adds 10 MW of battery storage by 2025.*Four Talking Points on Wheeling Power’s IRP* Based on a review of the Executive Summary)
Ignores CPP 2.
Assumes growth in *demand* of 0.4 % and in peak Demand of 0.5 % per year. 3.
All of WPCo’s capacity comes from 50 % ownership in Mitchell plant. 4.
No new resources are proposed, but some demand-side management options may be proposed in the future.
EC mailing list EC@osenergy.org http://osenergy.org/mailman/listinfo/ec
I did not really need to include the name-calling, but if the shoe fits....
JBK
________________________________ From: Jim Sconyers jimscon@gmail.com Sent: Sunday, January 10, 2016 9:53 AM To: James Kotcon Cc: ec@osenergy.org; Mark Kresowik; Bridget Lee; Nachy Kanfer; Emmett Pepper Subject: Re: [EC] IRP Review
I loved Van Nostrand's comment. He called First Energy a "Neanerthal utility."
On Sun, Jan 10, 2016 at 9:32 AM, James Kotcon <jkotcon@wvu.edumailto:jkotcon@wvu.edu> wrote:
Here is a story on today's Charleston Gazette that provides a better narrative on the IRPs filed.
JBK
Full story (and picture) is at: http://www.wvgazettemail.com/business/20160109/appalachian-power-moves-towar...
West Virginia’s four largest electric utilities have revealed plans for what the state’s power production might look like over the next 10 years.
First Energy’s and American Electric Power’s West Virginia subsidiaries filed their integrated resource plans, a type of roadmap used by power companies, with the state Public Service Commission on Dec. 30.
While the companies have conducted integrated resource planning in the past, this is the first time the utilities have been required to make the plans public in West Virginia, after a bill passedhttp://www.legis.state.wv.us/Bill_Text_HTML/2014_SESSIONS/RS/bills/HB2803%20SUB.pdf by the West Virginia Legislature in 2014 and the PSC issued an orderhttp://www.psc.state.wv.us/scripts/WebDocket/ViewDocument.cfm?CaseActivityID=420248 last year.
The planning documents, which rely on cost calculations, electric demand data and energy forecasts, highlight where the electricity for homes and businesses in West Virginia may come from in the coming decade and give a vague understanding of what investments might be made by the companies in order to supply that power.
For Appalachian Powerhttps://www.documentcloud.org/documents/2671906-Appalachian-Power-IRP.html and Wheeling Powerhttps://www.documentcloud.org/documents/2672088-Wheeling-Power-IRP.html, the plans show that both American Electric Power subsidiaries will continue to rely on the John Amos, Mitchell and Mountaineer coal-fired plants to supply a majority of the energy needed for their 475,000 customers in West Virginia. But the documents also highlight Appalachian Power’s attempt to diversify its energy portfolio, adding more solar and wind energy, as the company moves closer to 2025.
It’s a different story for the Mon Power and Potomac Edison. The First Energy subsidiarieshttps://www.documentcloud.org/documents/2671612-First-Energy-IRP-2016.html will continue to provide roughly 389,000 customers with electricity largely from the Harrison and Fort Martin coal-fired power plants. But where Appalachian Power expects to move toward alternative energy sources, the First Energy companies are considering additional investments in coal power.
The First Energy resource plan considers purchasing another existing coal-fired power plant in order to meet an expected 700-megawatt deficit by 2020, and it suggests retrofitting the Harrison and Fort Martin plants to let them co-fire with natural gas.
“At a high level, we have identified existing coal plants as the option that appears to be the lowest-cost solution to meet our capacity shortfall,” said Todd Meyers, a spokesman for Mon Power and Potomac Edison. “This option would require an agreement between Mon Power and any seller at a price that allows this to remain the lowest cost solution.”
James Van Nostrand, a West Virginia University law professor and the director of the Center for Energy and Sustainable Development, said co-firing the Harrison and Fort Martin plants is a good course of action, but he can’t understand how buying another coal plant is the best choice for the companies’ ratepayers.
“It’s shocking if they get away with buying more coal,” Van Nostrand said. “It’s a tale of two utilities, in terms of one that gets it and another that is sticking its head in the sand.”
Renewable energy sources like wind and solar are becoming cheaper, as they continue to benefit from reapproved tax incentives. Natural gas has started to outcompete coal as the dominant source of power. Residential and commercial customers have continued to install rooftop solarhttp://www.wvgazettemail.com/article/20151114/GZ03/151119721/1101. The U.S. Supreme Court is set to rulehttp://www.wvgazettemail.com/article/20151010/GZ03/151019994 on the Federal Energy Regulatory Commission’s jurisdiction to regulate aspects of electricity demand. And the Obama administration’s highly-contested Clean Power Plan continues to work its way through the federal court system, even as it begins to affect price outlooks for coal and other carbon-based power after 2022.
- See more at: http://www.wvgazettemail.com/business/20160109/appalachian-power-moves-towar...
________________________________ From: James Kotcon Sent: Wednesday, January 6, 2016 9:31 PM To: ec@osenergy.orgmailto:ec@osenergy.org; Mark Kresowik; Bridget Lee Cc: Emmett Pepper Subject: IRP Review
Here is my quick summary of the Mon Power, ApCo, and Wheeling Power IRPs
Top Ten Talking Points on Mon Power & Potomac Edison’s IRP
1. MP/PE ignores the CPP. No specific plans until DEP imposes requirements.
2. Since Mon Power provides all generation for PE, these are combined under Mon Power.
3. MP projects a capacity shortfall by 2016, with the shortfall growing to 850 MW by 2027.
4. Propose two options: A) Purchase 850 MW of new capacity in 2017, or B) Retrofit existing plants (Harrison and Fort Martin) to co-fire with up to 30 % gas. Cost of conversion would be $55-80 million at each plant.. (What happened? I though the purchase of Harrison was supposed to provide excess capacity for decades!)
5. Current Capacity is 1984 MW from Harrison, 1098 MW from Fort Martin, 488 MW from Bath County pump-storage ; 50 MW from MEA, 80 MW from Grant Town, and 31 MW from New Martinsville Hannibal Hydro Project.
6. Actual peak growth 2010-2014 was 3.1 %, mostly from growth in the natural gas drilling and processing sector. Projected peak load forecast is 2.2 % per year for 2015-2020.
7. Mon Power apparently did not consider ANY new EE or DR options for meeting new capacity needs. Existing Phase I and Phase II EE Plans will reduce energy use by cumulative 1 % by 2018.
8. Claims the Mercury rule was a key factor in closing Albright, Rivesville and Willow Island Sept. 1, 2012.
9. Concludes that solar, geothermal, and new hydro are not cost-effective, but wind or biomass co-firing are most viable options for renewable generation.
10. New generation could be acquired by building or buying an additional power plant. Co-firing would add “fuel diversity” at existing plants. (It is not clear to me how co-firing helps resolve the capacity shortfall?)
Top Ten Talking Points on ApCo’s IRP (Based on a review of the Executive Summary)
1. ApCo Ignores the CPP. No specific plans until DEP imposes requirements. Models assume a “cost of carbon dioxide” of $15-20/ton over a 30-year period.
2. FERC Capacity requirements (Peak Demand & Reliability assurance) differ from expected generation (actual energy requirements of customers), both will be important. Intermittent sources such as wind and solar will have limited “capacity” potential, driving ApCo to retain more base load and peaking facilities. ApCo expects a slight capacity shortfall between available generation versus expected demand by 2021, based on PJM’s Capacity Performance rule (reserve margin requirements).
3. ApCo assumes average growth in demand of 0.3%, with peak demand increasing 0.2 % annually.
4. ApCo continues operation of Amos and Mountaineer plants.
5. Convert Clinch River Units 1 & 2 from coal to gas, but retires them in 2026.
6. Additional Demand side resources in the form of EE and Volt-Var Optimization = 3.1 % of energy needs, reducing capacity requirements by 118 MW by 2025.
7. Add 10 MW of large-scale solar by 2018.
8. Add 150 MW in 2018, 2020, 2021, 2022 & 2025 (750 MW total).
9. Assumes customers add distributed solar increasing by 5 % annually, totaling 14 MW by 2025. (The analysis assumed the ITC expired in 2016, so I think we can expect faster growth. For example, the average growth rate in residential solar for the last 10 years has been around 40 % per year, so continuing that rate should get us over 200 MW).
10. Adds 10 MW of battery storage by 2025.
Four Talking Points on Wheeling Power’s IRP Based on a review of the Executive Summary)
1. Ignores CPP
2. Assumes growth in demand of 0.4 % and in peak Demand of 0.5 % per year.
3. All of WPCo’s capacity comes from 50 % ownership in Mitchell plant.
4. No new resources are proposed, but some demand-side management options may be proposed in the future.
_______________________________________________ EC mailing list EC@osenergy.orgmailto:EC@osenergy.org http://osenergy.org/mailman/listinfo/ec
-- Jim Sconyers jimscon@gmail.commailto:jimscon@gmail.com 304.698.9628
Remember, Mother Nature bats last.
I just want to make it clear that I know neanderthals, neanderthals are friends of mine, and my friends are insulted by the equation of them with FE. FirstEnergy is NO NEANDERTHAL!!!!
William V. DePaulo, Esq. 122 N Court Street, Suite 300 Lewisburg, WV 24901 Tel 304-342-5588 Fax 866-850-1501 william.depaulo@gmail.com www.passeggiata.com www.casasanta.org
On Sun, Jan 10, 2016 at 1:23 PM, James Kotcon jkotcon@wvu.edu wrote:
I did not really need to include the name-calling, but if the shoe fits....
JBK
*From:* Jim Sconyers jimscon@gmail.com *Sent:* Sunday, January 10, 2016 9:53 AM *To:* James Kotcon *Cc:* ec@osenergy.org; Mark Kresowik; Bridget Lee; Nachy Kanfer; Emmett Pepper *Subject:* Re: [EC] IRP Review
I loved Van Nostrand's comment. He called First Energy a "Neanerthal utility."
On Sun, Jan 10, 2016 at 9:32 AM, James Kotcon jkotcon@wvu.edu wrote:
Here is a story on today's Charleston Gazette that provides a better narrative on the IRPs filed.
JBK
Full story (and picture) is at:
http://www.wvgazettemail.com/business/20160109/appalachian-power-moves-towar...
West Virginia’s four largest electric utilities have revealed plans for what the state’s power production might look like over the next 10 years.
First Energy’s and American Electric Power’s West Virginia subsidiaries filed their integrated resource plans, a type of roadmap used by power companies, with the state Public Service Commission on Dec. 30.
While the companies have conducted integrated resource planning in the past, this is the first time the utilities have been required to make the plans public in West Virginia, after a bill passed http://www.legis.state.wv.us/Bill_Text_HTML/2014_SESSIONS/RS/bills/HB2803%20SUB.pdf by the West Virginia Legislature in 2014 and the PSC issued an order http://www.psc.state.wv.us/scripts/WebDocket/ViewDocument.cfm?CaseActivityID=420248 last year.
The planning documents, which rely on cost calculations, electric demand data and energy forecasts, highlight where the electricity for homes and businesses in West Virginia may come from in the coming decade and give a vague understanding of what investments might be made by the companies in order to supply that power.
For Appalachian Power https://www.documentcloud.org/documents/2671906-Appalachian-Power-IRP.html and Wheeling Power https://www.documentcloud.org/documents/2672088-Wheeling-Power-IRP.html, the plans show that both American Electric Power subsidiaries will continue to rely on the John Amos, Mitchell and Mountaineer coal-fired plants to supply a majority of the energy needed for their 475,000 customers in West Virginia. But the documents also highlight Appalachian Power’s attempt to diversify its energy portfolio, adding more solar and wind energy, as the company moves closer to 2025.
It’s a different story for the Mon Power and Potomac Edison. The First Energy subsidiaries https://www.documentcloud.org/documents/2671612-First-Energy-IRP-2016.html will continue to provide roughly 389,000 customers with electricity largely from the Harrison and Fort Martin coal-fired power plants. But where Appalachian Power expects to move toward alternative energy sources, the First Energy companies are considering additional investments in coal power.
The First Energy resource plan considers purchasing another existing coal-fired power plant in order to meet an expected 700-megawatt deficit by 2020, and it suggests retrofitting the Harrison and Fort Martin plants to let them co-fire with natural gas.
“At a high level, we have identified existing coal plants as the option that appears to be the lowest-cost solution to meet our capacity shortfall,” said Todd Meyers, a spokesman for Mon Power and Potomac Edison. “This option would require an agreement between Mon Power and any seller at a price that allows this to remain the lowest cost solution.”
James Van Nostrand, a West Virginia University law professor and the director of the Center for Energy and Sustainable Development, said co-firing the Harrison and Fort Martin plants is a good course of action, but he can’t understand how buying another coal plant is the best choice for the companies’ ratepayers.
“It’s shocking if they get away with buying more coal,” Van Nostrand said. “It’s a tale of two utilities, in terms of one that gets it and another that is sticking its head in the sand.”
Renewable energy sources like wind and solar are becoming cheaper, as they continue to benefit from reapproved tax incentives. Natural gas has started to outcompete coal as the dominant source of power. Residential and commercial customers have continued to install rooftop solar http://www.wvgazettemail.com/article/20151114/GZ03/151119721/1101. The U.S. Supreme Court is set to rule http://www.wvgazettemail.com/article/20151010/GZ03/151019994 on the Federal Energy Regulatory Commission’s jurisdiction to regulate aspects of electricity demand. And the Obama administration’s highly-contested Clean Power Plan continues to work its way through the federal court system, even as it begins to affect price outlooks for coal and other carbon-based power after 2022.
- See more at:
http://www.wvgazettemail.com/business/20160109/appalachian-power-moves-towar...
*From:* James Kotcon *Sent:* Wednesday, January 6, 2016 9:31 PM *To:* ec@osenergy.org; Mark Kresowik; Bridget Lee *Cc:* Emmett Pepper *Subject:* IRP Review
Here is my quick summary of the Mon Power, ApCo, and Wheeling Power IRPs
*Top Ten Talking Points on Mon Power & Potomac Edison’s IRP*
MP/PE ignores the CPP. No specific plans until DEP imposes requirements. 2.
Since Mon Power provides all generation for PE, these are combined under Mon Power. 3.
MP projects a capacity shortfall by 2016, with the shortfall growing to 850 MW by 2027. 4.
Propose two options: A) Purchase 850 MW of new capacity in 2017, or B) Retrofit existing plants (Harrison and Fort Martin) to co-fire with up to 30 % gas. Cost of conversion would be $55-80 million at each plant.. (What happened? I though the purchase of Harrison was supposed to provide excess capacity for decades!) 5.
Current Capacity is 1984 MW from Harrison, 1098 MW from Fort Martin, 488 MW from Bath County pump-storage ; 50 MW from MEA, 80 MW from Grant Town, and 31 MW from New Martinsville Hannibal Hydro Project. 6.
Actual peak growth 2010-2014 was 3.1 %, mostly from growth in the natural gas drilling and processing sector. Projected peak load forecast is 2.2 % per year for 2015-2020. 7.
*Mon Power apparently did not consider ANY new EE or DR options for meeting new capacity needs.* Existing Phase I and Phase II EE Plans will reduce energy use by cumulative 1 % by 2018. 8.
Claims the Mercury rule was a key factor in closing Albright, Rivesville and Willow Island Sept. 1, 2012. 9.
Concludes that solar, geothermal, and new hydro are not cost-effective, but wind or biomass co-firing are most viable options for renewable generation. 10.
New generation could be acquired by building or buying anadditional power plant. Co-firing would add “fuel diversity” at existing plants. (It is not clear to me how co-firing helps resolve the capacity shortfall?)
*Top Ten Talking Points on ApCo’s IRP* (Based on a review of the Executive Summary)
ApCo Ignores the CPP. No specific plans until DEP imposes requirements. Models assume a “cost of carbon dioxide” of $15-20/ton over a 30-year period. 2.
FERC Capacity requirements (Peak Demand & Reliability assurance) differ from expected generation (actual energy requirements of customers), both will be important. Intermittent sources such as wind and solar will have limited “capacity” potential, driving ApCo to retain more base load and peaking facilities. ApCo expects a slight capacity shortfall between available generation versus expected demand by 2021, based on PJM’s Capacity Performance rule (reserve margin requirements). 3.
ApCo assumes average growth in *demand* of 0.3%, with peak demand increasing 0.2 % annually. 4.
ApCo continues operation of Amos and Mountaineer plants. 5.
Convert Clinch River Units 1 & 2 from coal to gas, but retires them in 2026. 6.
Additional Demand side resources in the form of EE and Volt-Var Optimization = 3.1 % of energy needs, reducing capacity requirements by 118 MW by 2025. 7.
Add 10 MW of large-scale solar by 2018. 8.
Add 150 MW in 2018, 2020, 2021, 2022 & 2025 (750 MW total). 9.
Assumes customers add distributed solar increasing by 5 % annually, totaling 14 MW by 2025. (The analysis assumed the ITC expired in 2016, so I think we can expect faster growth. For example, the average growth rate in residential solar for the last 10 years has been around 40 % per year, so continuing that rate should get us over 200 MW). 10.
Adds 10 MW of battery storage by 2025.*Four Talking Points on Wheeling Power’s IRP* Based on a review of the Executive Summary)
Ignores CPP 2.
Assumes growth in *demand* of 0.4 % and in peak Demand of 0.5 % per year. 3.
All of WPCo’s capacity comes from 50 % ownership in Mitchell plant. 4.
No new resources are proposed, but some demand-side management options may be proposed in the future.
EC mailing list EC@osenergy.org http://osenergy.org/mailman/listinfo/ec
-- Jim Sconyers jimscon@gmail.com 304.698.9628
Remember, Mother Nature bats last.
EC mailing list EC@osenergy.org http://osenergy.org/mailman/listinfo/ec
Hear hear!! On Jan 10, 2016 1:34 PM, "William V. DePaulo, Esq." < william.depaulo@gmail.com> wrote:
I just want to make it clear that I know neanderthals, neanderthals are friends of mine, and my friends are insulted by the equation of them with FE. FirstEnergy is NO NEANDERTHAL!!!!
William V. DePaulo, Esq. 122 N Court Street, Suite 300 Lewisburg, WV 24901 Tel 304-342-5588 Fax 866-850-1501 william.depaulo@gmail.com www.passeggiata.com www.casasanta.org
On Sun, Jan 10, 2016 at 1:23 PM, James Kotcon jkotcon@wvu.edu wrote:
I did not really need to include the name-calling, but if the shoe fits....
JBK
*From:* Jim Sconyers jimscon@gmail.com *Sent:* Sunday, January 10, 2016 9:53 AM *To:* James Kotcon *Cc:* ec@osenergy.org; Mark Kresowik; Bridget Lee; Nachy Kanfer; Emmett Pepper *Subject:* Re: [EC] IRP Review
I loved Van Nostrand's comment. He called First Energy a "Neanerthal utility."
On Sun, Jan 10, 2016 at 9:32 AM, James Kotcon jkotcon@wvu.edu wrote:
Here is a story on today's Charleston Gazette that provides a better narrative on the IRPs filed.
JBK
Full story (and picture) is at:
http://www.wvgazettemail.com/business/20160109/appalachian-power-moves-towar...
West Virginia’s four largest electric utilities have revealed plans for what the state’s power production might look like over the next 10 years.
First Energy’s and American Electric Power’s West Virginia subsidiaries filed their integrated resource plans, a type of roadmap used by power companies, with the state Public Service Commission on Dec. 30.
While the companies have conducted integrated resource planning in the past, this is the first time the utilities have been required to make the plans public in West Virginia, after a bill passed http://www.legis.state.wv.us/Bill_Text_HTML/2014_SESSIONS/RS/bills/HB2803%20SUB.pdf by the West Virginia Legislature in 2014 and the PSC issued an order http://www.psc.state.wv.us/scripts/WebDocket/ViewDocument.cfm?CaseActivityID=420248 last year.
The planning documents, which rely on cost calculations, electric demand data and energy forecasts, highlight where the electricity for homes and businesses in West Virginia may come from in the coming decade and give a vague understanding of what investments might be made by the companies in order to supply that power.
For Appalachian Power https://www.documentcloud.org/documents/2671906-Appalachian-Power-IRP.html and Wheeling Power https://www.documentcloud.org/documents/2672088-Wheeling-Power-IRP.html, the plans show that both American Electric Power subsidiaries will continue to rely on the John Amos, Mitchell and Mountaineer coal-fired plants to supply a majority of the energy needed for their 475,000 customers in West Virginia. But the documents also highlight Appalachian Power’s attempt to diversify its energy portfolio, adding more solar and wind energy, as the company moves closer to 2025.
It’s a different story for the Mon Power and Potomac Edison. The First Energy subsidiaries https://www.documentcloud.org/documents/2671612-First-Energy-IRP-2016.html will continue to provide roughly 389,000 customers with electricity largely from the Harrison and Fort Martin coal-fired power plants. But where Appalachian Power expects to move toward alternative energy sources, the First Energy companies are considering additional investments in coal power.
The First Energy resource plan considers purchasing another existing coal-fired power plant in order to meet an expected 700-megawatt deficit by 2020, and it suggests retrofitting the Harrison and Fort Martin plants to let them co-fire with natural gas.
“At a high level, we have identified existing coal plants as the option that appears to be the lowest-cost solution to meet our capacity shortfall,” said Todd Meyers, a spokesman for Mon Power and Potomac Edison. “This option would require an agreement between Mon Power and any seller at a price that allows this to remain the lowest cost solution.”
James Van Nostrand, a West Virginia University law professor and the director of the Center for Energy and Sustainable Development, said co-firing the Harrison and Fort Martin plants is a good course of action, but he can’t understand how buying another coal plant is the best choice for the companies’ ratepayers.
“It’s shocking if they get away with buying more coal,” Van Nostrand said. “It’s a tale of two utilities, in terms of one that gets it and another that is sticking its head in the sand.”
Renewable energy sources like wind and solar are becoming cheaper, as they continue to benefit from reapproved tax incentives. Natural gas has started to outcompete coal as the dominant source of power. Residential and commercial customers have continued to install rooftop solar http://www.wvgazettemail.com/article/20151114/GZ03/151119721/1101. The U.S. Supreme Court is set to rule http://www.wvgazettemail.com/article/20151010/GZ03/151019994 on the Federal Energy Regulatory Commission’s jurisdiction to regulate aspects of electricity demand. And the Obama administration’s highly-contested Clean Power Plan continues to work its way through the federal court system, even as it begins to affect price outlooks for coal and other carbon-based power after 2022.
- See more at:
http://www.wvgazettemail.com/business/20160109/appalachian-power-moves-towar...
*From:* James Kotcon *Sent:* Wednesday, January 6, 2016 9:31 PM *To:* ec@osenergy.org; Mark Kresowik; Bridget Lee *Cc:* Emmett Pepper *Subject:* IRP Review
Here is my quick summary of the Mon Power, ApCo, and Wheeling Power IRPs
*Top Ten Talking Points on Mon Power & Potomac Edison’s IRP*
MP/PE ignores the CPP. No specific plans until DEP imposes requirements. 2.
Since Mon Power provides all generation for PE, these are combined under Mon Power. 3.
MP projects a capacity shortfall by 2016, with the shortfall growing to 850 MW by 2027. 4.
Propose two options: A) Purchase 850 MW of new capacity in 2017, or B) Retrofit existing plants (Harrison and Fort Martin) to co-fire with up to 30 % gas. Cost of conversion would be $55-80 million at each plant.. (What happened? I though the purchase of Harrison was supposed to provide excess capacity for decades!) 5.
Current Capacity is 1984 MW from Harrison, 1098 MW from Fort Martin, 488 MW from Bath County pump-storage ; 50 MW from MEA, 80 MW from Grant Town, and 31 MW from New Martinsville Hannibal Hydro Project. 6.
Actual peak growth 2010-2014 was 3.1 %, mostly from growth in the natural gas drilling and processing sector. Projected peak load forecast is 2.2 % per year for 2015-2020. 7.
*Mon Power apparently did not consider ANY new EE or DR options for meeting new capacity needs.* Existing Phase I and Phase II EE Plans will reduce energy use by cumulative 1 % by 2018. 8.
Claims the Mercury rule was a key factor in closing Albright, Rivesville and Willow Island Sept. 1, 2012. 9.
Concludes that solar, geothermal, and new hydro are not cost-effective, but wind or biomass co-firing are most viable options for renewable generation. 10.
New generation could be acquired by building or buying anadditional power plant. Co-firing would add “fuel diversity” at existing plants. (It is not clear to me how co-firing helps resolve the capacity shortfall?)
*Top Ten Talking Points on ApCo’s IRP* (Based on a review of the Executive Summary)
ApCo Ignores the CPP. No specific plans until DEP imposes requirements. Models assume a “cost of carbon dioxide” of $15-20/ton over a 30-year period. 2.
FERC Capacity requirements (Peak Demand & Reliability assurance) differ from expected generation (actual energy requirements of customers), both will be important. Intermittent sources such as wind and solar will have limited “capacity” potential, driving ApCo to retain more base load and peaking facilities. ApCo expects a slight capacity shortfall between available generation versus expected demand by 2021, based on PJM’s Capacity Performance rule (reserve margin requirements). 3.
ApCo assumes average growth in *demand* of 0.3%, with peak demand increasing 0.2 % annually. 4.
ApCo continues operation of Amos and Mountaineer plants. 5.
Convert Clinch River Units 1 & 2 from coal to gas, but retires them in 2026. 6.
Additional Demand side resources in the form of EE and Volt-Var Optimization = 3.1 % of energy needs, reducing capacity requirements by 118 MW by 2025. 7.
Add 10 MW of large-scale solar by 2018. 8.
Add 150 MW in 2018, 2020, 2021, 2022 & 2025 (750 MW total). 9.
Assumes customers add distributed solar increasing by 5 % annually, totaling 14 MW by 2025. (The analysis assumed the ITC expired in 2016, so I think we can expect faster growth. For example, the average growth rate in residential solar for the last 10 years has been around 40 % per year, so continuing that rate should get us over 200 MW). 10.
Adds 10 MW of battery storage by 2025.*Four Talking Points on Wheeling Power’s IRP* Based on a review of the Executive Summary)
Ignores CPP 2.
Assumes growth in *demand* of 0.4 % and in peak Demand of 0.5 % per year. 3.
All of WPCo’s capacity comes from 50 % ownership in Mitchell plant. 4.
No new resources are proposed, but some demand-side management options may be proposed in the future.
EC mailing list EC@osenergy.org http://osenergy.org/mailman/listinfo/ec
-- Jim Sconyers jimscon@gmail.com 304.698.9628
Remember, Mother Nature bats last.
EC mailing list EC@osenergy.org http://osenergy.org/mailman/listinfo/ec
Jamie found some really great stuff in there. I hope that Sierra Club is able to push back and have the PSC reject the FirstEnergy IRP. I don't know his availability, but Jamie would be a good expert witness, if you ask me.
EEWV is considering issuing comments on some of the smaller utilities' IRPs, since we aren't able to intervene.
Emmett Pepper Energy Efficient West Virginia o: 304-346-5891 c: 917-617-8208 On Jan 10, 2016 3:10 PM, "Jim Sconyers" jimscon@gmail.com wrote:
Hear hear!! On Jan 10, 2016 1:34 PM, "William V. DePaulo, Esq." < william.depaulo@gmail.com> wrote:
I just want to make it clear that I know neanderthals, neanderthals are friends of mine, and my friends are insulted by the equation of them with FE. FirstEnergy is NO NEANDERTHAL!!!!
William V. DePaulo, Esq. 122 N Court Street, Suite 300 Lewisburg, WV 24901 Tel 304-342-5588 Fax 866-850-1501 william.depaulo@gmail.com www.passeggiata.com www.casasanta.org
On Sun, Jan 10, 2016 at 1:23 PM, James Kotcon jkotcon@wvu.edu wrote:
I did not really need to include the name-calling, but if the shoe fits....
JBK
*From:* Jim Sconyers jimscon@gmail.com *Sent:* Sunday, January 10, 2016 9:53 AM *To:* James Kotcon *Cc:* ec@osenergy.org; Mark Kresowik; Bridget Lee; Nachy Kanfer; Emmett Pepper *Subject:* Re: [EC] IRP Review
I loved Van Nostrand's comment. He called First Energy a "Neanerthal utility."
On Sun, Jan 10, 2016 at 9:32 AM, James Kotcon jkotcon@wvu.edu wrote:
Here is a story on today's Charleston Gazette that provides a better narrative on the IRPs filed.
JBK
Full story (and picture) is at:
http://www.wvgazettemail.com/business/20160109/appalachian-power-moves-towar...
West Virginia’s four largest electric utilities have revealed plans for what the state’s power production might look like over the next 10 years.
First Energy’s and American Electric Power’s West Virginia subsidiaries filed their integrated resource plans, a type of roadmap used by power companies, with the state Public Service Commission on Dec. 30.
While the companies have conducted integrated resource planning in the past, this is the first time the utilities have been required to make the plans public in West Virginia, after a bill passed http://www.legis.state.wv.us/Bill_Text_HTML/2014_SESSIONS/RS/bills/HB2803%20SUB.pdf by the West Virginia Legislature in 2014 and the PSC issued an order http://www.psc.state.wv.us/scripts/WebDocket/ViewDocument.cfm?CaseActivityID=420248 last year.
The planning documents, which rely on cost calculations, electric demand data and energy forecasts, highlight where the electricity for homes and businesses in West Virginia may come from in the coming decade and give a vague understanding of what investments might be made by the companies in order to supply that power.
For Appalachian Power https://www.documentcloud.org/documents/2671906-Appalachian-Power-IRP.html and Wheeling Power https://www.documentcloud.org/documents/2672088-Wheeling-Power-IRP.html, the plans show that both American Electric Power subsidiaries will continue to rely on the John Amos, Mitchell and Mountaineer coal-fired plants to supply a majority of the energy needed for their 475,000 customers in West Virginia. But the documents also highlight Appalachian Power’s attempt to diversify its energy portfolio, adding more solar and wind energy, as the company moves closer to 2025.
It’s a different story for the Mon Power and Potomac Edison. The First Energy subsidiaries https://www.documentcloud.org/documents/2671612-First-Energy-IRP-2016.html will continue to provide roughly 389,000 customers with electricity largely from the Harrison and Fort Martin coal-fired power plants. But where Appalachian Power expects to move toward alternative energy sources, the First Energy companies are considering additional investments in coal power.
The First Energy resource plan considers purchasing another existing coal-fired power plant in order to meet an expected 700-megawatt deficit by 2020, and it suggests retrofitting the Harrison and Fort Martin plants to let them co-fire with natural gas.
“At a high level, we have identified existing coal plants as the option that appears to be the lowest-cost solution to meet our capacity shortfall,” said Todd Meyers, a spokesman for Mon Power and Potomac Edison. “This option would require an agreement between Mon Power and any seller at a price that allows this to remain the lowest cost solution.”
James Van Nostrand, a West Virginia University law professor and the director of the Center for Energy and Sustainable Development, said co-firing the Harrison and Fort Martin plants is a good course of action, but he can’t understand how buying another coal plant is the best choice for the companies’ ratepayers.
“It’s shocking if they get away with buying more coal,” Van Nostrand said. “It’s a tale of two utilities, in terms of one that gets it and another that is sticking its head in the sand.”
Renewable energy sources like wind and solar are becoming cheaper, as they continue to benefit from reapproved tax incentives. Natural gas has started to outcompete coal as the dominant source of power. Residential and commercial customers have continued to install rooftop solar http://www.wvgazettemail.com/article/20151114/GZ03/151119721/1101. The U.S. Supreme Court is set to rule http://www.wvgazettemail.com/article/20151010/GZ03/151019994 on the Federal Energy Regulatory Commission’s jurisdiction to regulate aspects of electricity demand. And the Obama administration’s highly-contested Clean Power Plan continues to work its way through the federal court system, even as it begins to affect price outlooks for coal and other carbon-based power after 2022.
- See more at:
http://www.wvgazettemail.com/business/20160109/appalachian-power-moves-towar...
*From:* James Kotcon *Sent:* Wednesday, January 6, 2016 9:31 PM *To:* ec@osenergy.org; Mark Kresowik; Bridget Lee *Cc:* Emmett Pepper *Subject:* IRP Review
Here is my quick summary of the Mon Power, ApCo, and Wheeling Power IRPs
*Top Ten Talking Points on Mon Power & Potomac Edison’s IRP*
MP/PE ignores the CPP. No specific plans until DEP imposes requirements. 2.
Since Mon Power provides all generation for PE, these are combined under Mon Power. 3.
MP projects a capacity shortfall by 2016, with the shortfall growing to 850 MW by 2027. 4.
Propose two options: A) Purchase 850 MW of new capacity in 2017, or B) Retrofit existing plants (Harrison and Fort Martin) to co-fire with up to 30 % gas. Cost of conversion would be $55-80 million at each plant.. (What happened? I though the purchase of Harrison was supposed to provide excess capacity for decades!) 5.
Current Capacity is 1984 MW from Harrison, 1098 MW from Fort Martin, 488 MW from Bath County pump-storage ; 50 MW from MEA, 80 MW from Grant Town, and 31 MW from New Martinsville Hannibal Hydro Project. 6.
Actual peak growth 2010-2014 was 3.1 %, mostly from growth in the natural gas drilling and processing sector. Projected peak load forecast is 2.2 % per year for 2015-2020. 7.
*Mon Power apparently did not consider ANY new EE or DR options for meeting new capacity needs.* Existing Phase I and Phase II EE Plans will reduce energy use by cumulative 1 % by 2018. 8.
Claims the Mercury rule was a key factor in closing Albright, Rivesville and Willow Island Sept. 1, 2012. 9.
Concludes that solar, geothermal, and new hydro are not cost-effective, but wind or biomass co-firing are most viable options for renewable generation. 10.
New generation could be acquired by building or buying anadditional power plant. Co-firing would add “fuel diversity” at existing plants. (It is not clear to me how co-firing helps resolve the capacity shortfall?)
*Top Ten Talking Points on ApCo’s IRP* (Based on a review of the Executive Summary)
ApCo Ignores the CPP. No specific plans until DEP imposes requirements. Models assume a “cost of carbon dioxide” of $15-20/ton over a 30-year period. 2.
FERC Capacity requirements (Peak Demand & Reliability assurance) differ from expected generation (actual energy requirements of customers), both will be important. Intermittent sources such as wind and solar will have limited “capacity” potential, driving ApCo to retain more base load and peaking facilities. ApCo expects a slight capacity shortfall between available generation versus expected demand by 2021, based on PJM’s Capacity Performance rule (reserve margin requirements). 3.
ApCo assumes average growth in *demand* of 0.3%, with peak demand increasing 0.2 % annually. 4.
ApCo continues operation of Amos and Mountaineer plants. 5.
Convert Clinch River Units 1 & 2 from coal to gas, but retires them in 2026. 6.
Additional Demand side resources in the form of EE and Volt-Var Optimization = 3.1 % of energy needs, reducing capacity requirements by 118 MW by 2025. 7.
Add 10 MW of large-scale solar by 2018. 8.
Add 150 MW in 2018, 2020, 2021, 2022 & 2025 (750 MW total). 9.
Assumes customers add distributed solar increasing by 5 % annually, totaling 14 MW by 2025. (The analysis assumed the ITC expired in 2016, so I think we can expect faster growth. For example, the average growth rate in residential solar for the last 10 years has been around 40 % per year, so continuing that rate should get us over 200 MW). 10.
Adds 10 MW of battery storage by 2025.*Four Talking Points on Wheeling Power’s IRP* Based on a review of the Executive Summary)
Ignores CPP 2.
Assumes growth in *demand* of 0.4 % and in peak Demand of 0.5 % per year. 3.
All of WPCo’s capacity comes from 50 % ownership in Mitchell plant. 4.
No new resources are proposed, but some demand-side management options may be proposed in the future.
EC mailing list EC@osenergy.org http://osenergy.org/mailman/listinfo/ec
-- Jim Sconyers jimscon@gmail.com 304.698.9628
Remember, Mother Nature bats last.
EC mailing list EC@osenergy.org http://osenergy.org/mailman/listinfo/ec
-
Emmett Pepper -
James Kotcon -
Jim Sconyers -
William V. DePaulo, Esq.