"Doubt is an uncomfortable condition, but certainty is a ridiculous one. Voltaire
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"Doubt is an uncomfortable condition, but certainty is a ridiculous one. Voltaire Posted: October 24, 2013
George asked me to talk with you from my perspective on what the electric utility industry might look like as we progress through the 21st century.
Let me begin my rank speculation on the topic with full disclosure. The environmental movement if you will, is not a monolith, but is instead a range of interests, individuals, and organizations that are in some respects as similar and as different as are electric cooperatives and investor-owned electric utilities. The perspective of the Kentucky Resources Council, a membership organization providing technical and legal assistance to individuals, communities, and local governments on a wide range of environmental, energy, and utility issues, differs from that of some of the national environmental groups and their state affiliates, although we share many concerns and viewpoints. Because much of KRCs work occurs at the intersection of poverty and environmental damage and injustice, we tend to be a bit more attuned to the economic implications of policy choices and regulatory decisions on residential and other ratepayers.
After a century of relative stability in the electric utility industry, where the utility business model was that of producing, transmitting, and distributing electrons in a safe, cost-efficient and reliable manner, under rate and service regulation, to a captive population of customers whose demand increased exponentially and who relied entirely on the provision of electrons by the utility for meeting electricity demand, both industry executives and the investment community increasingly view the electric utility industry as one in significant upheaval or as the January 2013 Edison Electric Institute report termed it, facing disruptive challenges.
There is general agreement on the drivers that create these challenges, and while predictions run the risk of becoming wildly inaccurate as the planning horizon grows, (a good example being the recent study predicting that coal use would increase by 20% or decrease by 50% by 2030!), it is important to understand these change drivers and how they interact to alter and reshape the framework within in the utility industry will operate.
What considerations will affect the future of the industry?
A major factor that has already begun to change the generation portfolios of many utilities has been the development of shale gas from the Marcellus, Utica, Bakken, and other formations, made economical and possible by advances in horizontal drilling and hydraulic fracturing. The change has resulted in dramatic shift from coal to natural gas as the fuel of choice for new electric generation facilities, and has in turn resulted in additional uncertainties for utilities and customers in a state like Kentucky, which has been historically been over 90% reliant on coal to fuel electric generation, which has a significant industrial sector that is extremely sensitive to changes in electricity costs, and which has relied on coal production for employment and tax revenue.
The increased availability of inexpensive natural gas-fired electricity in the wholesale market, coupled with the increase in coal-fired electricity due to a combination of production costs and cost increases drive by the internalization through regulation of historically off-budget costs related to coal combustion and waste management, invite increased tension between major industrials seeking cheaper power, the utilities who invested in generation capacity to serve those customers, and other ratepayers, who face the prospect of paying the stranded costs of those investments if other industrials are allowed to exit the system. The fight between the smelters and Big Rivers during the last session could be a harbinger of other legislative battles, as the General Assembly is asked to balance economic development and maintenance of electricity-intensive industries with fairness to other utility customers and investors.
There are few within the industry who believe that carbon controls will not be required within the lifecycle of new generation units now under consideration, as well as some existing units. EPA has indicated that it will, within the next year, propose and finalize standards for both, and the recent acceptance by the United States Supreme Court of several petitions seeking review of the EPAs actions to date, will increase the certainty and set targets for carbon management that will affect new capacity, and could result in retirement of existing units or retrofitting units. KRC has encouraged EPA to craft an approach that provides maximum flexibility within and among the generating units, as well as among different sectors, so that the most efficient reductions can be achieved as rapidly as possible, while capture and management technology matures.
Because the electric power sector is the largest single source of U.S. and global carbon dioxide emissions, responsible for approximately 40 percent of total emissions, controls on carbon dioxide are inevitable, and as the cost of addressing emissions are factored in, the economics of producing electricity with large, centralized fossil-fueled generation will change considerably. While historically the Kentucky Public Service Commission has resisted inclusion of carbon costs into a determination of what is lowest cost power, the recent approval of a power purchase contract from a biomass facility by the Public Service Commission, based on part on the announced policy of the Commonwealth of encouraging renewable biomass energy, could signal a new receptivity to incorporating public policy considerations such as addressing climate change and diversifying utility portfolios to include more renewable energy, when considering purchase power contracts, certificates of need, and other proceedings, that have historically not been included in determining what is least cost.
The effect of changes in energy consumption will also have an effect on the electric utility industry, as will the small growth in demand that is projected over the next two decades (less than ½ of 1% according to the International Energy Agency). While demand grew significantly between 1950 and 2010, with the average American using roughly seven times as much electricity in 2010 than it did in 1950, the paradigm of the electric utility remaining profitable and sound by producing and selling more electrons is changing, and the demand is slowing in developed countries like the United States.
There are several drivers one is the increase in energy efficiency, both in the replacement of major appliances and in space heating and lighting, and other actions by consumers in response to increases in unit costs of power. Another currently small but rapidly growing driver, is the increase in distributed energy from solar PV, fuel cells, and other distributed electricity resources. Industry experts expect these distributed energy sources to deliver 5 percent to 20 percent of U.S. power supply by 2020.
With utility customers using less electricity and the possibility of customers generating power on their own (and in some cases, off-grid), electric utility companies will need to adapt to changing customer needs and expectations, while remaining financially viable and continuing to attract investment in an increasingly complex and uncertain environment.
In the near term, as distributed energy resources increase, there will be some pushback from the utility industry, which views the trend as one of a number of disruptive challenges rather than an opportunity. Demand Side Management programs have cost recovery mechanisms to assure that utility revenue associated with the embedded costs in volumetric rates are recovered, and that efforts to make end-users more efficient and to better manage their energy demands are compensated. The customer uses less electricity, new capacity investment can be delayed or deferred entirely, and both parties benefit.
There are questions regarding the extent to which tariff structures allocate costs related to serving customers that utilize grid-connected distributed energy resources, and whether those costs are being recovered from other customers due to the design of the rates. Some question whether distributed energy resources, the deployment of which remains a small overall percentage of electric load but which is increasing at a significant rate due to technological advances, lower costs of distributed generation, governmental subsidies, and increasing demand for greener power, are being subsidized by non-participating customers in the same class. With lower usage by a customer with distributed electricity production, some of the costs necessitated by the customers participation (such as interconnection, metering, balancing, providing back-up power) may (depending on the rate structure) be paid by non-participating customers.
Isolating the costs to the utility of providing these services to distributed energy participants that are grid-connected, and determining how these costs are recovered, will be a significant economic and policy issue, affecting the speed of deployment of these resources, the earnings potential of the utility, and the rates of both participating and non-participating ratepayers. Increasing the fixed charges as a way of assuring recovery of the costs from the party incurring them, presents a policy challenge, since shifting more costs away from volumetric charges to fixed, can weaken the incentive for energy efficiency and distributed energy that embedding some of those costs in the usage charges creates. And as technologies increasingly allow for customers to completely sever their ties to the grid, numerous questions will arise regarding the recovery of investments made to serve customers that have exited the system from a dwindling ratepayer base, and of increased costs of system maintenance being spread among fewer users.
Historically self-viewed as a provider of electrons, the 21st century electric utility that thrives will be one that views their role as providing an array of energy services and partner in meeting energy demand in a sustainable and efficient manner. As one observer noted, If the first 100 years of the electricity industry has been about improving peoples lives by delivering power, the next 100 years will be about giving them the power to use less.
What might a repurposed utility look like?
Combining electricity usage data and smart meter technology, the utility could work with each customer to help trim energy bills and meet energy needs while lessening the costs of accommodating peak power needs.
Recognizing that energy efficiency can cost as little as 3 cents per kilowatt hour saved, while electricity costs 6 to 12 cents per kilowatt hour, the smart utility will invest in energy efficiency measures that avoid unnecessary energy supply investments, moderate increases in customer bills and create jobs for electricians, plumbers, laborers, and engineers, while reducing carbon emissions.
A smarter electric grid could allow the utility to offer many more products and services to help customers manage their energy demand.
Rather than viewing distributed energy as a threat, utilities might become providers of such systems, installing and maintaining systems for their customers and integrating those units into the larger grid in a more predictable and efficient manner, with the panels feeding power into the grid and the company paying rental fees to those living or working under those roofs. The utilities might also develop, market, and service an array of non-grid systems for customers, encouraging the deployment of distributed electricity, heating, cooling, and other utility systems, under a leasing system or a lease-purchase system that spreads the capital costs that are an impediment for many residential customers.
Looking out the 12th floor window here at the LG&E Headquarters, one can imagine installation of solar arrays on the roofs of the various buildings, the arena, and other places where harvesting of solar energy could both help power the needs of the buildings, and provide a significant return of clean electricity at a comparatively modest and low-risk cost when compared to new fossil-fueled generating capacity. The community hosts numerous areas where such arrays would make sense from warehouses to landfills, from the airport to office complexes to home roofs, and there is no reason why the electric utilities should not be the entities to lease the space, install and maintain the arrays, and help customers overcome capital barriers to more robust investment and deployment of distributed electricity generation.
Thank you for letting me share some observations from an outsider on the electric utility industry of the 21st century.
George asked me to talk with you from my perspective on what the electric utility industry might look like as we progress through the 21st century.
Let me begin my rank speculation on the topic with full disclosure. The environmental movement if you will, is not a monolith, but is instead a range of interests, individuals, and organizations that are in some respects as similar and as different as are electric cooperatives and investor-owned electric utilities. The perspective of the Kentucky Resources Council, a membership organization providing technical and legal assistance to individuals, communities, and local governments on a wide range of environmental, energy, and utility issues, differs from that of some of the national environmental groups and their state affiliates, although we share many concerns and viewpoints. Because much of KRCs work occurs at the intersection of poverty and environmental damage and injustice, we tend to be a bit more attuned to the economic implications of policy choices and regulatory decisions on residential and other ratepayers.
After a century of relative stability in the electric utility industry, where the utility business model was that of producing, transmitting, and distributing electrons in a safe, cost-efficient and reliable manner, under rate and service regulation, to a captive population of customers whose demand increased exponentially and who relied entirely on the provision of electrons by the utility for meeting electricity demand, both industry executives and the investment community increasingly view the electric utility industry as one in significant upheaval or as the January 2013 Edison Electric Institute report termed it, facing disruptive challenges.
There is general agreement on the drivers that create these challenges, and while predictions run the risk of becoming wildly inaccurate as the planning horizon grows, (a good example being the recent study predicting that coal use would increase by 20% or decrease by 50% by 2030!), it is important to understand these change drivers and how they interact to alter and reshape the framework within in the utility industry will operate.
What considerations will affect the future of the industry?
A major factor that has already begun to change the generation portfolios of many utilities has been the development of shale gas from the Marcellus, Utica, Bakken, and other formations, made economical and possible by advances in horizontal drilling and hydraulic fracturing. The change has resulted in dramatic shift from coal to natural gas as the fuel of choice for new electric generation facilities, and has in turn resulted in additional uncertainties for utilities and customers in a state like Kentucky, which has been historically been over 90% reliant on coal to fuel electric generation, which has a significant industrial sector that is extremely sensitive to changes in electricity costs, and which has relied on coal production for employment and tax revenue.
The increased availability of inexpensive natural gas-fired electricity in the wholesale market, coupled with the increase in coal-fired electricity due to a combination of production costs and cost increases drive by the internalization through regulation of historically off-budget costs related to coal combustion and waste management, invite increased tension between major industrials seeking cheaper power, the utilities who invested in generation capacity to serve those customers, and other ratepayers, who face the prospect of paying the stranded costs of those investments if other industrials are allowed to exit the system. The fight between the smelters and Big Rivers during the last session could be a harbinger of other legislative battles, as the General Assembly is asked to balance economic development and maintenance of electricity-intensive industries with fairness to other utility customers and investors.
There are few within the industry who believe that carbon controls will not be required within the lifecycle of new generation units now under consideration, as well as some existing units. EPA has indicated that it will, within the next year, propose and finalize standards for both, and the recent acceptance by the United States Supreme Court of several petitions seeking review of the EPAs actions to date, will increase the certainty and set targets for carbon management that will affect new capacity, and could result in retirement of existing units or retrofitting units. KRC has encouraged EPA to craft an approach that provides maximum flexibility within and among the generating units, as well as among different sectors, so that the most efficient reductions can be achieved as rapidly as possible, while capture and management technology matures.
Because the electric power sector is the largest single source of U.S. and global carbon dioxide emissions, responsible for approximately 40 percent of total emissions, controls on carbon dioxide are inevitable, and as the cost of addressing emissions are factored in, the economics of producing electricity with large, centralized fossil-fueled generation will change considerably. While historically the Kentucky Public Service Commission has resisted inclusion of carbon costs into a determination of what is lowest cost power, the recent approval of a power purchase contract from a biomass facility by the Public Service Commission, based on part on the announced policy of the Commonwealth of encouraging renewable biomass energy, could signal a new receptivity to incorporating public policy considerations such as addressing climate change and diversifying utility portfolios to include more renewable energy, when considering purchase power contracts, certificates of need, and other proceedings, that have historically not been included in determining what is least cost.
The effect of changes in energy consumption will also have an effect on the electric utility industry, as will the small growth in demand that is projected over the next two decades (less than ½ of 1% according to the International Energy Agency). While demand grew significantly between 1950 and 2010, with the average American using roughly seven times as much electricity in 2010 than it did in 1950, the paradigm of the electric utility remaining profitable and sound by producing and selling more electrons is changing, and the demand is slowing in developed countries like the United States.
There are several drivers one is the increase in energy efficiency, both in the replacement of major appliances and in space heating and lighting, and other actions by consumers in response to increases in unit costs of power. Another currently small but rapidly growing driver, is the increase in distributed energy from solar PV, fuel cells, and other distributed electricity resources. Industry experts expect these distributed energy sources to deliver 5 percent to 20 percent of U.S. power supply by 2020.
With utility customers using less electricity and the possibility of customers generating power on their own (and in some cases, off-grid), electric utility companies will need to adapt to changing customer needs and expectations, while remaining financially viable and continuing to attract investment in an increasingly complex and uncertain environment.
In the near term, as distributed energy resources increase, there will be some pushback from the utility industry, which views the trend as one of a number of disruptive challenges rather than an opportunity. Demand Side Management programs have cost recovery mechanisms to assure that utility revenue associated with the embedded costs in volumetric rates are recovered, and that efforts to make end-users more efficient and to better manage their energy demands are compensated. The customer uses less electricity, new capacity investment can be delayed or deferred entirely, and both parties benefit.
There are questions regarding the extent to which tariff structures allocate costs related to serving customers that utilize grid-connected distributed energy resources, and whether those costs are being recovered from other customers due to the design of the rates. Some question whether distributed energy resources, the deployment of which remains a small overall percentage of electric load but which is increasing at a significant rate due to technological advances, lower costs of distributed generation, governmental subsidies, and increasing demand for greener power, are being subsidized by non-participating customers in the same class. With lower usage by a customer with distributed electricity production, some of the costs necessitated by the customers participation (such as interconnection, metering, balancing, providing back-up power) may (depending on the rate structure) be paid by non-participating customers.
Isolating the costs to the utility of providing these services to distributed energy participants that are grid-connected, and determining how these costs are recovered, will be a significant economic and policy issue, affecting the speed of deployment of these resources, the earnings potential of the utility, and the rates of both participating and non-participating ratepayers. Increasing the fixed charges as a way of assuring recovery of the costs from the party incurring them, presents a policy challenge, since shifting more costs away from volumetric charges to fixed, can weaken the incentive for energy efficiency and distributed energy that embedding some of those costs in the usage charges creates. And as technologies increasingly allow for customers to completely sever their ties to the grid, numerous questions will arise regarding the recovery of investments made to serve customers that have exited the system from a dwindling ratepayer base, and of increased costs of system maintenance being spread among fewer users.
Historically self-viewed as a provider of electrons, the 21st century electric utility that thrives will be one that views their role as providing an array of energy services and partner in meeting energy demand in a sustainable and efficient manner. As one observer noted, If the first 100 years of the electricity industry has been about improving peoples lives by delivering power, the next 100 years will be about giving them the power to use less.
What might a repurposed utility look like?
Combining electricity usage data and smart meter technology, the utility could work with each customer to help trim energy bills and meet energy needs while lessening the costs of accommodating peak power needs.
Recognizing that energy efficiency can cost as little as 3 cents per kilowatt hour saved, while electricity costs 6 to 12 cents per kilowatt hour, the smart utility will invest in energy efficiency measures that avoid unnecessary energy supply investments, moderate increases in customer bills and create jobs for electricians, plumbers, laborers, and engineers, while reducing carbon emissions.
A smarter electric grid could allow the utility to offer many more products and services to help customers manage their energy demand.
Rather than viewing distributed energy as a threat, utilities might become providers of such systems, installing and maintaining systems for their customers and integrating those units into the larger grid in a more predictable and efficient manner, with the panels feeding power into the grid and the company paying rental fees to those living or working under those roofs. The utilities might also develop, market, and service an array of non-grid systems for customers, encouraging the deployment of distributed electricity, heating, cooling, and other utility systems, under a leasing system or a lease-purchase system that spreads the capital costs that are an impediment for many residential customers.
Looking out the 12th floor window here at the LG&E Headquarters, one can imagine installation of solar arrays on the roofs of the various buildings, the arena, and other places where harvesting of solar energy could both help power the needs of the buildings, and provide a significant return of clean electricity at a comparatively modest and low-risk cost when compared to new fossil-fueled generating capacity. The community hosts numerous areas where such arrays would make sense from warehouses to landfills, from the airport to office complexes to home roofs, and there is no reason why the electric utilities should not be the entities to lease the space, install and maintain the arrays, and help customers overcome capital barriers to more robust investment and deployment of distributed electricity generation.
Thank you for letting me share some observations from an outsider on the electric utility industry of the 21st century.
By Kentucky Resources Council
on 10/24/2013 5:32 PM
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The Kentucky Resources Council is a non-profit, 501(c)(3) organization dedicated to the conservation and prudent use of Kentucky’s natural resources. Since 1984, we have dedicated ourselves to protecting Kentucky’s land, air, water, and communities.