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Abundant Smart Meters, Not Many Smart Tariffs, FERC Survey Finds
Electricity Currents A survey of current industry news and developments
Obama to Congress: Act on Climate, or I Will Having barely averted the so-called fiscal cliff, President Obama’s second term is facing another stress – balancing the federal budget – followed by a number of other challenges that may deprive him of the political capital needed to achieve his energy and environmental agenda. Yet in his inaugural address on Jan. 21 and then again in his State of the Union address on Feb. 12, he mentioned climate change among his second-term priorities. It remains to be seen how much can be achieved. That topic is further addressed in several articles in this issue of The Electricity Journal. The President was unequivocal when he said, ‘‘I urge this Congress to pursue a bipartisan, market-based solution to climate change,’’ warning, ‘‘But if Congress won’t act soon to protect future generations, I will.’’ Obama reminded the lawmakers that 12 of the world’s hottest years on record were in the past 15 years, adding, ‘‘We can choose to believe that superstorm Sandy, and the most severe drought in decades, and the worst wildfires some states have ever seen, were all just a freak coincidence. Or we can choose to believe in the overwhelming judgment of science - and act before it’s too late.’’ One bit of good news is that domestic oil and gas production are up with prospects for North America becoming a net energy exporter in 2020s – the exact date varies by who is doing the projections. By contrast, America’s major trading partners, among them the European Union, Japan, China, and India, will become more energy-import-dependent. Needless to say, this is a rather rosy outcome for the U.S. not only on energy security grounds but also in terms of the trade balance, foreign policy, and defense spending. North America’s unconventional oil and gas bonanza will be accompanied by feeble demand growth resulting
Continued on page 6 March 2013, Vol. 26, Issue 2
In Electricity Currents This Month: Obama to Congress: Act on Climate, or I Will . 1 Abundant Smart Meters, Not Many Smart Tariffs, FERC Survey Finds . . . . . . . . . 1 Much Is at Stake in Southern Co.’s New Nuclear Plants . . . . . . . . . . . . . . . . . . . . . . . 4 US Retail Competition Is Alive, and Seemingly Managing Well. . . . . . . . . . . . . . . 5 Electricity Currents is compiled from the monthly newsletter EEnergy Informer published by Fereidoon P. Sioshansi, President of Menlo Energy Economics, a consultancy based in San Francisco. He can be reached at [email protected].
Abundant Smart Meters, Not Many Smart Tariffs, FERC Survey Finds The Energy Policy Act of 2005 (EPAct 2005) requires FERC to publish an annual account of advancements in smart metering and demand response (DR) programs in the U.S. The latest, published in December 2012, offers a comprehensive survey of 3,349 ‘‘entities,’’ all but a handful considered 1040-6190/$–see front matter
1
‘‘utilities’’ of one form, shape, or size. Over 1,900, roughly 60 percent, responded – not bad as survey participation rates go. The sheer number of active entities in this space is simply mind-boggling and may explain why it is difficult to get things done, whether it is DR or anything else. There are over 1,800 municipally owned utilities (munis), over 800 cooperatively owned utilities (coops), nearly 200 investor-owned utilities (IOUs), plus a sizable number of federal and state power agencies, over 100 retail power marketers operating in jurisdictions where there is competitive retail such as in Texas, 11 curtailment service providers (CSPs) – entities that deliver negawatt savings during peak demand periods to whoever is willing to pay the going price – plus 7 organized wholesale market operators (ISOs and RTOs) spread across 50 states and the District of Columbia (DC). Each ‘‘entity’’ has its own motives and agenda and operates under different regulations, in some cases virtually no regulations, with vastly different priorities. In the report, the survey results are summarized by region, utility type and customer class. In the case of DR, results are further broken down by type of program implemented. It is a useful and timely survey. Already, all but one of the top 10 states are above 50 percent in terms of penetration of smart meters by mid-2012, when the survey was conducted, 87 percent in the case of District of Columbia, followed by California at 70 percent – where virtual total penetration is mandated for the three large IOUs in the coming year or so (there has been some deadline slippage). While smart meters are far from universal across all states and various types of ‘‘utilities’’ in the U.S., recent trends suggest reaching the 50 percent milestone by 2015–16 and much higher rates in many jurisdictions by the end of the decade. Considerable scope is devoted in the latest FERC report to how much DR potential there is in the U.S. and how it may be tapped. After all, the business case for investing big money in AMR is usually not compelling without the ability to manage, modify, shift, or clip peak demand. The starting point in FERC’s survey is a definition for DR, which the 2
1040-6190/$–see front matter
agency defines as ‘‘changes in electric use by demandside resources from their normal consumption patterns in response to (a) changes in the price of electricity, or (b) to incentive payments designed to induce lower electricity use at times of high wholesale market prices or when system reliability is jeopardized’’ (‘‘a’’ and ‘‘b’’ added for emphasis). Following the above definition, FERC classifies DR programs into two broad categories, incentivebased and time-based, each with many subcategories, even though the distinction may be artificial – after all, all DR programs are incentivebased, since customers respond to incentives one way or another, though the incentives may be in the form of variable prices. The big surprise, to the extent that there are any, is that FERC’s latest survey puts total reported DR potential at 72 GW, a 25 percent rise from the 2010 survey – that is more than 9 percent of U.S. peak demand – an astonishing figure. The number, of course, is a fictitious one, since demand peaks in different parts of the network at different times. No matter, it is a big number and it suggests that DR resource can save the day and keep the network from collapsing if you can indeed get it and count on it when you actually need it. Actual DR – what utilities or organized market operators have actually been able to deliver when needed – typically falls far short of such targets. Among the U.S. organized wholesale market operators, PJM and Midwest ISO (MISO) appear to be more bullish in estimating how much DR potential there is, while other markets, notably California Independent System Operator (CAISO), put the figures at negligible levels. It is a puzzle, which FERC report does not adequately cover. Some of these discrepancies may be definitional while some may be explained by lack of operating DR auctions within the existing wholesale markets. As is always the case, one has to read the fine print, and even that is not always enough. In case of PJM and MISO, for example, a big potential for DR is identified under ‘‘load as a capacity resource’’ and ‘‘demand bidding & buyback’’ – in other words negawatts that can be shed by or bought from participating customers in response to The Electricity Journal
given price signals and other schemes that have been incorporated into wholesale auctions managed by these market operators. Clearly, organized wholesale markets in the US operate differently, some have incorporated functional DR auctions with significant volume of DR bidding while others have not or are in the process of establishing such markets. A chapter of the report is focused on what FERC has attempted to do since the passage of EPAct 2005 to foster the development of DR, most notably Order 719 in October 2008 and Order 745 in March 2011. While progress has been made following these and other FERC directives, much more can and needs to be done. According to the 2012 FERC survey, the following four programs account for 80 percent of the total reported potential peak reductions in the U.S.: Load as capacity resource; Interruptible load; Direct load control (DLC); and Time of use (TOU). Clearly, if you want to start a serious DR program, these would be obvious places to explore. As for what has actually been achieved to date, FERC reports a little over 20 GW of peak demand reductions from ‘‘demand response resources’’ in 2012, ‘‘representing use of 31 percent of the total reported peak load potential.’’ As for the future, FERC survey identifies key DR programs planned for the period to 2017, mostly focused on the same areas that appear to have been successful in the past, such as DLC and TOU. When it comes to time variable pricing, the FERC survey exposes the near total lack of progress to date. Residential time-of-use (TOU) programs, for example, were offered by 151 among the roughly 1,900 ‘‘entities’’ who responded to the survey. Only 28 entities reported offering real-time pricing (RTP) in 2012, suggesting substantial room for improvement. Implementation of TOU and RTP schemes for residential customers is limited to a handful of active utilities in jurisdictions with favorable regulatory support. The two large utilities in Arizona, Arizona Public Service (APS) and Salt River March 2013, Vol. 26, Issue 2
Project (SRP), for example, report that one-third of their residential consumers ‘‘have voluntarily chosen to participate in’’ TOU programs. California may become the proving ground for testing the popularity of dynamic tariffs with offerings by the three large investor-owned utilities by the end of 2012. Critical peak pricing (CPP) has been the default option for large commercial and industrial (C&I) customers in California for some time. The debate has shifted to applying the CPP default tariff to all residential consumers – pending the resolution of a number of remaining regulatory and legal challenges currently before the California Public Utilities Commission. Regulators in California, as many other jurisdictions, are weary of consumer backlash that may follow after switching large numbers of residential consumers to dynamic pricing because the volatility of these rates may prove unpopular. In addition to California, FERC lists Maryland, Arkansas, Oklahoma, Illinois, Idaho, Colorado, and Connecticut as potential candidates for widespread use of RTP, CPP, or similar time-variable rates. Despite the progress achieved since 2005, FERC identifies several key barriers to future implementation of DR including: The limited number of retail customers on timebased rates; Measurement and cost-effectiveness of (load) reductions; Lack of uniform standards for communicating DR price signals and usage information; Lack of customer engagement; and Lack of DR forecasting and estimating tools. In short, despite its great potential, DR remains broadly underrated, and not just in America. The power industry is still dominated by those who view load as a ‘‘given’’ and generation as what has to be adjusted to meet the variable load. These same people are greatly troubled by intermittent generation from renewable resources. Ironically, no one seems bothered by intermittent load, variable or unpredictable demand, or spikes in peak demand due to weather or cyclic customer behavior. The chairman of FERC, Jon Wellinghoff, is among a handful of people who have discovered the 1040-6190/$–see front matter
3
absurdity of the outdated perspective of treating demand to be whatever it wants to be and ramping generation up and down to match it, no matter the costs. Why shouldn’t we adjust demand when and if it is cheaper to do rather than generation? Time-variable pricing is one way to go, as are multiple other ways of managing load. It may be easier, more environmentally benign, and potentially a lot cheaper. & http://dx.doi.org/10.1016/j.tej.2013.02.009
Much Is at Stake In Southern Co.’s New Nuclear Plants The U.S. nuclear renaissance, to the extent that there is one, boils down to a handful of new reactors in various stages of construction/ completion. Among the companies that have defied the prevailing odds – unusually low natural gas prices, depressed wholesale prices in organized markets, and low demand growth due to economic recession and energy efficiency gains – Atlanta-based Southern Company stands out as the most determined and outspoken fan of nuclear power in America. Its CEO, Tom Fanning, goes to great lengths to explain why his company, as conservative as utilities come, has decided to put so many eggs in two new AP1000 Westinghouse-designed nuclear reactors under construction at the Vogtle site in Georgia. On the surface, the two reactors, with an estimated cost of $14 billion, represent a major liability even for a giant company such as Southern. But the company has secured significant loan guarantees from the federal government – which gives shareholders some assurance that their investment is safe even if there are glitches along the way – plus generous treatment by regulators in Georgia that allows the company to recover some of the costs during the construction period, rather than accumulating capital investment and interest until the plants go into service some years in the future, which is the customary method. 4
1040-6190/$–see front matter
Finally, Southern is essentially shielded from external competition from lower-cost generators since it operates in states where there are no organized wholesale markets. This allows the company to recover the plants’ investment and operating costs in regulated tariffs from captive customers without the risk of being undercut by lower-cost generators. These are among the reasons Mr. Fanning is undeterred by the prevailing low cost of natural gas, uncertainties about future demand growth, or the ultimate cost of the new reactors – reasons he omits to mention in frequent interviews with the press. Nevertheless, the ultimate fate of any future U.S. nuclear renaissance to a great extent depends on the success or failure of The Southern Company at its Vogtle site. If the plants can be completed on time, originally scheduled for 2016 and 2017, and more or less on budget, other utilities may find the courage to follow. If the plants suffer substantial delays and/or go significantly over budget, that would be a major blow to any future nuclear prospects. For his part, Fanning is doing all he can to make Vogtle a shining example of what future nuclear plants can be. He has reportedly installed a flat screen TV in his office monitoring the progress of work at the construction site 24/7. It is a reminder to every construction worker, superintendent, and manager that the boss is watching your every move. Whether the TV is on or he is actually watching is immaterial. Having a lot at stake, the Georgia Public Service Commission (GPSC) is taking no chances either. Instead of relying exclusively on progress reports from Southern, the Commission has hired Bill Jacob as its independent monitor to provide regular updates on the progress of the work, costs, and the project’s likely completion date. His latest report, released towards the end of December 2012, was not a happy read. Jacob advised the regulators to brace for potential costly delays of two to four years. Referring to ‘‘numerous examples of poor performance’’ by the contractors, he said he is not optimistic that the project will be able to meet major milestones on schedule. The Electricity Journal
Obama to Congress: Act on Climate, or I Will Having barely averted the so-called fiscal cliff, President Obama’s second term is facing another stress – balancing the federal budget – followed by a number of other challenges that may deprive him of the political capital needed to achieve his energy and environmental agenda. Yet in his inaugural address on Jan. 21 and then again in his State of the Union address on Feb. 12, he mentioned climate change among his second-term priorities. It remains to be seen how much can be achieved. That topic is further addressed in several articles in this issue of The Electricity Journal. The President was unequivocal when he said, ‘‘I urge this Congress to pursue a bipartisan, market-based solution to climate change,’’ warning, ‘‘But if Congress won’t act soon to protect future generations, I will.’’ Obama reminded the lawmakers that 12 of the world’s hottest years on record were in the past 15 years, adding, ‘‘We can choose to believe that superstorm Sandy, and the most severe drought in decades, and the worst wildfires some states have ever seen, were all just a freak coincidence. Or we can choose to believe in the overwhelming judgment of science - and act before it’s too late.’’ One bit of good news is that domestic oil and gas production are up with prospects for North America becoming a net energy exporter in 2020s – the exact date varies by who is doing the projections. By contrast, America’s major trading partners, among them the European Union, Japan, China, and India, will become more energy-import-dependent. Needless to say, this is a rather rosy outcome for the U.S. not only on energy security grounds but also in terms of the trade balance, foreign policy, and defense spending. North America’s unconventional oil and gas bonanza will be accompanied by feeble demand growth resulting
Continued on page 6 March 2013, Vol. 26, Issue 2
In Electricity Currents This Month: Obama to Congress: Act on Climate, or I Will . 1 Abundant Smart Meters, Not Many Smart Tariffs, FERC Survey Finds . . . . . . . . . 1 Much Is at Stake in Southern Co.’s New Nuclear Plants . . . . . . . . . . . . . . . . . . . . . . . 4 US Retail Competition Is Alive, and Seemingly Managing Well. . . . . . . . . . . . . . . 5 Electricity Currents is compiled from the monthly newsletter EEnergy Informer published by Fereidoon P. Sioshansi, President of Menlo Energy Economics, a consultancy based in San Francisco. He can be reached at [email protected].
Abundant Smart Meters, Not Many Smart Tariffs, FERC Survey Finds The Energy Policy Act of 2005 (EPAct 2005) requires FERC to publish an annual account of advancements in smart metering and demand response (DR) programs in the U.S. The latest, published in December 2012, offers a comprehensive survey of 3,349 ‘‘entities,’’ all but a handful considered 1040-6190/$–see front matter
1
‘‘utilities’’ of one form, shape, or size. Over 1,900, roughly 60 percent, responded – not bad as survey participation rates go. The sheer number of active entities in this space is simply mind-boggling and may explain why it is difficult to get things done, whether it is DR or anything else. There are over 1,800 municipally owned utilities (munis), over 800 cooperatively owned utilities (coops), nearly 200 investor-owned utilities (IOUs), plus a sizable number of federal and state power agencies, over 100 retail power marketers operating in jurisdictions where there is competitive retail such as in Texas, 11 curtailment service providers (CSPs) – entities that deliver negawatt savings during peak demand periods to whoever is willing to pay the going price – plus 7 organized wholesale market operators (ISOs and RTOs) spread across 50 states and the District of Columbia (DC). Each ‘‘entity’’ has its own motives and agenda and operates under different regulations, in some cases virtually no regulations, with vastly different priorities. In the report, the survey results are summarized by region, utility type and customer class. In the case of DR, results are further broken down by type of program implemented. It is a useful and timely survey. Already, all but one of the top 10 states are above 50 percent in terms of penetration of smart meters by mid-2012, when the survey was conducted, 87 percent in the case of District of Columbia, followed by California at 70 percent – where virtual total penetration is mandated for the three large IOUs in the coming year or so (there has been some deadline slippage). While smart meters are far from universal across all states and various types of ‘‘utilities’’ in the U.S., recent trends suggest reaching the 50 percent milestone by 2015–16 and much higher rates in many jurisdictions by the end of the decade. Considerable scope is devoted in the latest FERC report to how much DR potential there is in the U.S. and how it may be tapped. After all, the business case for investing big money in AMR is usually not compelling without the ability to manage, modify, shift, or clip peak demand. The starting point in FERC’s survey is a definition for DR, which the 2
1040-6190/$–see front matter
agency defines as ‘‘changes in electric use by demandside resources from their normal consumption patterns in response to (a) changes in the price of electricity, or (b) to incentive payments designed to induce lower electricity use at times of high wholesale market prices or when system reliability is jeopardized’’ (‘‘a’’ and ‘‘b’’ added for emphasis). Following the above definition, FERC classifies DR programs into two broad categories, incentivebased and time-based, each with many subcategories, even though the distinction may be artificial – after all, all DR programs are incentivebased, since customers respond to incentives one way or another, though the incentives may be in the form of variable prices. The big surprise, to the extent that there are any, is that FERC’s latest survey puts total reported DR potential at 72 GW, a 25 percent rise from the 2010 survey – that is more than 9 percent of U.S. peak demand – an astonishing figure. The number, of course, is a fictitious one, since demand peaks in different parts of the network at different times. No matter, it is a big number and it suggests that DR resource can save the day and keep the network from collapsing if you can indeed get it and count on it when you actually need it. Actual DR – what utilities or organized market operators have actually been able to deliver when needed – typically falls far short of such targets. Among the U.S. organized wholesale market operators, PJM and Midwest ISO (MISO) appear to be more bullish in estimating how much DR potential there is, while other markets, notably California Independent System Operator (CAISO), put the figures at negligible levels. It is a puzzle, which FERC report does not adequately cover. Some of these discrepancies may be definitional while some may be explained by lack of operating DR auctions within the existing wholesale markets. As is always the case, one has to read the fine print, and even that is not always enough. In case of PJM and MISO, for example, a big potential for DR is identified under ‘‘load as a capacity resource’’ and ‘‘demand bidding & buyback’’ – in other words negawatts that can be shed by or bought from participating customers in response to The Electricity Journal
given price signals and other schemes that have been incorporated into wholesale auctions managed by these market operators. Clearly, organized wholesale markets in the US operate differently, some have incorporated functional DR auctions with significant volume of DR bidding while others have not or are in the process of establishing such markets. A chapter of the report is focused on what FERC has attempted to do since the passage of EPAct 2005 to foster the development of DR, most notably Order 719 in October 2008 and Order 745 in March 2011. While progress has been made following these and other FERC directives, much more can and needs to be done. According to the 2012 FERC survey, the following four programs account for 80 percent of the total reported potential peak reductions in the U.S.: Load as capacity resource; Interruptible load; Direct load control (DLC); and Time of use (TOU). Clearly, if you want to start a serious DR program, these would be obvious places to explore. As for what has actually been achieved to date, FERC reports a little over 20 GW of peak demand reductions from ‘‘demand response resources’’ in 2012, ‘‘representing use of 31 percent of the total reported peak load potential.’’ As for the future, FERC survey identifies key DR programs planned for the period to 2017, mostly focused on the same areas that appear to have been successful in the past, such as DLC and TOU. When it comes to time variable pricing, the FERC survey exposes the near total lack of progress to date. Residential time-of-use (TOU) programs, for example, were offered by 151 among the roughly 1,900 ‘‘entities’’ who responded to the survey. Only 28 entities reported offering real-time pricing (RTP) in 2012, suggesting substantial room for improvement. Implementation of TOU and RTP schemes for residential customers is limited to a handful of active utilities in jurisdictions with favorable regulatory support. The two large utilities in Arizona, Arizona Public Service (APS) and Salt River March 2013, Vol. 26, Issue 2
Project (SRP), for example, report that one-third of their residential consumers ‘‘have voluntarily chosen to participate in’’ TOU programs. California may become the proving ground for testing the popularity of dynamic tariffs with offerings by the three large investor-owned utilities by the end of 2012. Critical peak pricing (CPP) has been the default option for large commercial and industrial (C&I) customers in California for some time. The debate has shifted to applying the CPP default tariff to all residential consumers – pending the resolution of a number of remaining regulatory and legal challenges currently before the California Public Utilities Commission. Regulators in California, as many other jurisdictions, are weary of consumer backlash that may follow after switching large numbers of residential consumers to dynamic pricing because the volatility of these rates may prove unpopular. In addition to California, FERC lists Maryland, Arkansas, Oklahoma, Illinois, Idaho, Colorado, and Connecticut as potential candidates for widespread use of RTP, CPP, or similar time-variable rates. Despite the progress achieved since 2005, FERC identifies several key barriers to future implementation of DR including: The limited number of retail customers on timebased rates; Measurement and cost-effectiveness of (load) reductions; Lack of uniform standards for communicating DR price signals and usage information; Lack of customer engagement; and Lack of DR forecasting and estimating tools. In short, despite its great potential, DR remains broadly underrated, and not just in America. The power industry is still dominated by those who view load as a ‘‘given’’ and generation as what has to be adjusted to meet the variable load. These same people are greatly troubled by intermittent generation from renewable resources. Ironically, no one seems bothered by intermittent load, variable or unpredictable demand, or spikes in peak demand due to weather or cyclic customer behavior. The chairman of FERC, Jon Wellinghoff, is among a handful of people who have discovered the 1040-6190/$–see front matter
3
absurdity of the outdated perspective of treating demand to be whatever it wants to be and ramping generation up and down to match it, no matter the costs. Why shouldn’t we adjust demand when and if it is cheaper to do rather than generation? Time-variable pricing is one way to go, as are multiple other ways of managing load. It may be easier, more environmentally benign, and potentially a lot cheaper. & http://dx.doi.org/10.1016/j.tej.2013.02.009
Much Is at Stake In Southern Co.’s New Nuclear Plants The U.S. nuclear renaissance, to the extent that there is one, boils down to a handful of new reactors in various stages of construction/ completion. Among the companies that have defied the prevailing odds – unusually low natural gas prices, depressed wholesale prices in organized markets, and low demand growth due to economic recession and energy efficiency gains – Atlanta-based Southern Company stands out as the most determined and outspoken fan of nuclear power in America. Its CEO, Tom Fanning, goes to great lengths to explain why his company, as conservative as utilities come, has decided to put so many eggs in two new AP1000 Westinghouse-designed nuclear reactors under construction at the Vogtle site in Georgia. On the surface, the two reactors, with an estimated cost of $14 billion, represent a major liability even for a giant company such as Southern. But the company has secured significant loan guarantees from the federal government – which gives shareholders some assurance that their investment is safe even if there are glitches along the way – plus generous treatment by regulators in Georgia that allows the company to recover some of the costs during the construction period, rather than accumulating capital investment and interest until the plants go into service some years in the future, which is the customary method. 4
1040-6190/$–see front matter
Finally, Southern is essentially shielded from external competition from lower-cost generators since it operates in states where there are no organized wholesale markets. This allows the company to recover the plants’ investment and operating costs in regulated tariffs from captive customers without the risk of being undercut by lower-cost generators. These are among the reasons Mr. Fanning is undeterred by the prevailing low cost of natural gas, uncertainties about future demand growth, or the ultimate cost of the new reactors – reasons he omits to mention in frequent interviews with the press. Nevertheless, the ultimate fate of any future U.S. nuclear renaissance to a great extent depends on the success or failure of The Southern Company at its Vogtle site. If the plants can be completed on time, originally scheduled for 2016 and 2017, and more or less on budget, other utilities may find the courage to follow. If the plants suffer substantial delays and/or go significantly over budget, that would be a major blow to any future nuclear prospects. For his part, Fanning is doing all he can to make Vogtle a shining example of what future nuclear plants can be. He has reportedly installed a flat screen TV in his office monitoring the progress of work at the construction site 24/7. It is a reminder to every construction worker, superintendent, and manager that the boss is watching your every move. Whether the TV is on or he is actually watching is immaterial. Having a lot at stake, the Georgia Public Service Commission (GPSC) is taking no chances either. Instead of relying exclusively on progress reports from Southern, the Commission has hired Bill Jacob as its independent monitor to provide regular updates on the progress of the work, costs, and the project’s likely completion date. His latest report, released towards the end of December 2012, was not a happy read. Jacob advised the regulators to brace for potential costly delays of two to four years. Referring to ‘‘numerous examples of poor performance’’ by the contractors, he said he is not optimistic that the project will be able to meet major milestones on schedule. The Electricity Journal