Rep29 From: Rep29 Sent: Thursday, March 02, 2017 2:34 PM To: 'Representative Bill Blessing Subject: FW: Electric Issue Perspective Sent: Thursday, March 02, 2017 11:43 AM To: Pine, Ty Subject: Electric Issue Perspective Dear Representative: Below is an interesting article on electric energy issues. ask that you take the opportunity to read Mr. Myers? perspective as i believe it will prove instructive for our energy policy discussions in the coming months. Thanks. Ty Pine Director, State Affairs FirstEnergy 614457?8926 Richard Myers Free?[ancejournalist Former head of policy and planning for a major energy trade association. Before that, a reporter and editor at "The Energy Daily.? Feb 20 America?s Hidden Energy Crisis if Competitive Electricity is Such A Good Business, Why Are Companies Closing Power Plants, Taking Write-Downs, Seeking Bankruptcy Protection and Scrambling for the Exits? casual observer scanning the headlines might conclude that America?s biggest energy challenge involves the Trump Administration?s position on climate change, whatever that turns out to be. But the country faces an equally difficult and?because it is mostly hidden to all but industry insiders?"more insidious challenge. The competitive business model worked reasonably well until a few years ago, when the entire electric power industry sailed into a hundred?year storm, a period of unprecedented stress that continues unabated to this day. Left untreated, this festering problem will lead to loss of valuable energy infrastructure that has decades of useful life left, more costly electricity, more volatility in electricity prices, higher emissions of carbon and other pollutants, and possibly even less reliable electricity supply. The problem is the business of generating electricity in those parts of the country that deregulated the power industry in the late 19905 and early 20005. Since then, electricity has evolved into two very different businesses. States in the south and southeast resisted the temptation to deregulate. In those states, companies own power plants, transmission lines and the local distribution networks. They operate under a regulatory bargain struck many decades ago. In return for an exclusive franchise, the companies accept an "obligation to serve" any and all who need electricity. They are guaranteed a reasonable opportunity to recover all their costs, plus a reasonable return on their investment. States in the northeast, mid?Atlantic, midwest and Texas?representing roughly two? thirds of the electricity consumed in the United States?forced their companies to restructure. They separated transmission and distribution (the "wires? business) from the business of generating the electricity. The wires continued as regulated enterprises, but generating electricity became an unregulated, competitive undertaking, with the grid manage-d by independent regional organizations. There?s no compelling evidence that the competitive business model is any better. Retail electricity 33% in the south and southeast (regulated states) average 9 ?10 cents per kilowatt?hour. Some states with competitive markets (Ohio, Texas, for example) are also in that range. But electric rates in many other competitive states? notably on the East and West Coasts?are at least 50% higher. Connecticut holds the dubious distinction of having the highest rates in the lower~48, at 17.7 cents per kilowatt? houn A Hundred- Year Storm The competitive business model worked reasonably well until a few years ago, when the entire electric power industry sailed into a hundred?year storm, a period of unprecedented stress that continues unabated to this day. The stress is caused partly by disruptive advances in technology. For example, horizontal drilling and hydraulic fracturing unlocked vast reserves of natural gas in so?called ?tight" formations. This produced a gusher of natural gas at extremely lowmand probably unsustainably low??prices. Since natural gas is a dominant fuel for producing electricity, wholesale electricity prices have collapsed along with natural gas prices. But the stress also comes from other sources. Demand for electricity is growing slowly, if at all, thanks to relatively anemic, halting economic growth since the 2008 recession, and greater efficiency in electricity use. Nationwide, electricity consumption in 2016 was below 2010. Even companies in regions with relatively robust economies are feeling the pinch. Atlanta? based Southern Co. (which operates in Georgia, Alabama and parts of Mississippi and Florida) expects annual electricity demand to grow only between 0% and 1% for the next four or five years. And companies in more economically?challenged regions, like Columbus, Ohio?based American Electric Power, saw quarterly growth in electricity demand in 2016 range from a low of in the third quarter to a high of 0.3% in the fourth. Inevitably, slow demand growth?or no demand growth?tends to depress prices even further. It?s notjust nuclear plants that are closing. Coal?fired power plants are closing down, too, and notjust due to tighter environmental controls. So are gas?fired power plants, including relatively new, high?efficiency facilities. In fact, without subsidies and mandates, wind and solar facilities would probably be tanking, too. Add to all this the impact of state and federal mandates and subsidies for renewable sources of electricity. The last 7?10 years have seen remarkable improvements in the cost and performance of wind and solar technologies. Still, 29 states and the District of Columbia continue to force renewable energy into the market, by requiring their utilities to buy a certain percentage of their electricity from renewable sources. On top of this, the federal government provides a production tax credit to wind generation and an investment tax credit to solar. Leaving aside personal opinion about the wisdom and 5 merits of mandates and subsidies, it is inarguable that these programs distort markets and, in the case of federal subsidies, suppress wholesale electricity prices even further. Then add serious problems with design and operation of the competitive markets. These markets typically don?t recognize or value the positive attributes of the resources in place. They?re not always operated so that all costs are reflected in prices. And they operate solely on the basis of lowest short-run marginal cost, when it?s clear that a robust and resilient market must also factor in other factors?long?run price stability, for example, or the value of fuel and technology diversity, or environmental factors, and others. In sum, it?s hard to imagine a more ?perfect storm? of negative factors all arriving at about the same time, all pushing wholesale electricity prices down, down, down. When Low Prices Aren?t Always Such a Good Thing To the average consumer, low electricity prices sound like a good thing. And so they are, unless they?re so low that the companies operating the power plants cannot generate sufficient revenue to stay in business. The competitive electricity markets in the United States have reached that point. Today?s situation is simply unsustainable. To be sustainable, a competitive market?for crude oil, gasoline, tires, orangejuice, electricity or any other commoditym?must satisfy the needs of consumers, suppliers, asset owners and investors, regulators, policy?makers and other stakeholders. ?We continuously expect our electric industry to solve a complex ?simultaneous equation? in whichthe countless decisions of myriad actors need to produce a reliable, efficient; and . increasingly clean supply of electricity,? Susan Tierney, one of the most respected observers of electricity issues and a principal with a consultancy called The Analysis Group, told federal energy regulators several years ago. In Tierney?s view, the markets today are not solving that ?simultaneous equation? correctly: ?Something has to change for the numbers to support a sustainable, healthy and vibrant electric industry capable of meeting system operators? technical necessities, consumers? implicit needs, policy?makers? explicit demands, and investors? inherent requirements. That entire equation must be satisfied,? she says, ?or the system isn?t sustainable.? The distress is most visible?or perhaps most talked about?in America?s nuclear energy industry, which produces about 20 percent of US. electricity supply, and about two?thirds 6 of the country?s carbon?free electricity. Since 2013, six nuclear reactors have shut down permanently. That leaves 99 operating reactors. Three more reactors are planned to be shut down before 2020, two more in 2020-2021, and two more in the mid-20205. And there are others at risk. The common wisdom holds that the nuclear plants can't compete in a world of low?cost natural gas, and isn?t thatjust too bad but markets are cruel places where only the strong (or the lowest?cost) survive. As is often the case, the common wisdom is wrong. It?s notjust nuclear plants that are closing. Coal?fired power plants are closing down, too, and notjust due to tighter environmental controls. So are gas~fired power plants, including relatively new, high?efficiency facilities. In fact, without subsidies and mandates, wind and solar facilities would probably be tanking, too. The entire competitive generation segment of the electric power industry is struggling. Across the board, companies are dumping the power plants that, as recently as 10 years ago, were their crown jewels. In its annual assessment of the competitive electricity business late last year, Moody?s Investors Service, the credit rating agency, maintained its negative outlook on the entire sector: ?Against persistent headwinds, [the] fundamentals remain negative," Moody?s said. In a separate analysis, the rating agency noted the economic stress facing some nuclear plants, but found that over 66,000 megawatts (MW) of coal?fired generating capacity in 16 states is also at risk (out of roughly 100,000 coal?fired megawatts operating in those states). And despite the Trump Administration?s rhetoric, this coal?fired capacity is not at risk because of environmental requirements or the Obama Administration's Clean Power Plan. Moody?s criterion was simple economics: ?at?risk? is when fuel, variable operating and maintenance costs and fixed exceed $30 per megawatt?hour. Running for the Exits So the electric power companies operating in competitive (or ?merchant") markets are in full flight from the business of generating electricity, and they have been for several years. Between 2003 and 2015, electric industry revenues moved from 64?percent regulated to 78?percent regulated. Across the board, companies are dumping the power plants that, as recently as 10 years ago, were their crown jewels. Instead, they?re putting their capital into upgrading and strengthening the "wires? business (transmission and distribution), because it?s regulated and safe. They're assured of capital recovery and steady, predictable earnings. Power plants are out. The "wires" business (transmission and distribution) is in. Transmission and distribution are regulated, and provide stable cash flows and predictable earnings. Chicago?based Exelon is a poster child for this strategy. Exelon is one of the largest merchant generating companies in the United States, with roughly 33,000 MW of capacity, much of it nuclear. But it?s not a happy business. Only heroic state government intervention in 2016 in New York and Illinois saved seven Exelon reactors that were slated for premature shutdown over the next several years. The states provided "zero?emission credits??-??basically a way to compensate the nuclear plants for producing carbon?free electricity, in much the same way that ?renewable energy credits" value the contribution 8 from wind and solar. It will take similar state government action to save other nuclear plants at risk in Ohio, Connecticut, and Texas. Last year?s reprieve didn?t really solve Exelon?s bigger problem, however. In a recent assessment, UBS equity analyst Julien Dumoulin?Smith sees the earnings-per?share contribution from Exelon?s generation subsidiary collapsing?~from $1.40 per share in 2014 to an estimated 25?cents per share in 2020. Why would any company want to stake its future on a business with such unappetizing earnings potential? Exelon?s leadership has reinvented and repositioned the company over the last several years to deal with this. From a base that included two big distribution companies?? Commonwealth Edison in Chicago and PECO- in Philadelphia-?the company acquired Baltimore Gas and EIeCtric in 2011 and POtomac Electric in 2016. By so doing, the company ensured that it would always be able to cover its dividend to shareholders, and provide earnings growth, through the regulated side of the business?making it relatively indifferent to continuing economic pressure on its generating business. Exelon is investing its growth capital?$20?billion?or?so over the next four years?in its regulated businesses, where it can earn predictable returns. And it's harvesting free cash flow from its generating subsidiary to pay down debt and invest in its regulated utilities. Of $6.8 billion in free cash flow expected from Exelon Generation over the next four years, more than 75% will go to debt reduction and its regulated business. Misery loves company, and Exelon has lots of it. American Electric Power (AEP) has sold, or is in the process of selling, most of its generating assets in Competitive markets. At the end of January, AEP closed on the sale of four large power plants?~three gas?fired and one coal?fired, totaling 5,200 megawatts (MW) of capacity?to a private equity group. During the third quarter of 2016, the company took a $2.3?billion impairment charge to write down the value of its remaining merchant generating assets (about 2,700 MW, mostly in Ohio). In all its presentations to investors, AEP emphasizes its large capital investment in transmission and distribution, and brands itself prominently as "The PremierRegulated Energy Company." New Orleans?based Entergy is winding down its merchant generation business. It closed (or will close) two nuclear plants and a gas-fired combined cycle plant in New England and a nuclear plant in Michigan. It sold another nuclear plant in upstate New York to Exelon. 9 Entergy is so anxious to exit merchant generation that it finally agreed in January to do what New York Governor Andrew Cuomo has been trying to accomplish for years-?close down the two Indian Point reactors on the Hudson River, about 35 miles north of New York city. Akron?based FirstEnergy intends to exit the competitive electricity generating business no later than mid?2018, and will either sell or shut down its power plants operating in competitive markets?"including several coal-fired plants and three nuclear power stations. (The company is urging Ohio legislators to follow the lead of New York and Illinois, and provide zero?emission credits to save the Davis?Besse and Perry nuclear plants.) In January, the company found a buyer for several power plants?including gas?fired plants in and its share of a hydroelectric plant inVirginia. One of the gas?fired facilities is a relatively modern (commissioned in 2003) high?efficiency combined?cycle plant. During the fourth quarter of 2016, the company wrote down the value of its competitive generating assets by $9.2?billion billion after tax). FirstEnergy continues to warn investors that its competitive generating subsidiary may be forced to seek bankruptcy protection. And like AEP, FirstEnergy takes great pains to remind investors in its presentations that it is putting capital to work in its regulated businesses and ?Transforming into a Regulated Energy Company." When There Is No Exit These companies, at least, have large regulated transmission and distribution subsidiaries to fall back on. The "pure play? independent power producers?names like NRG, Calpine and Dynegy? are not so fortunate. NRG closed on February 17 at a little over $17 a share?~better than the $10.54?a?share in January 2016, but down more than 50% from its 10?year high. Dynegy reached $36 a share in mid?2014. It?s now hovering just above $9 a share, and U85 moved the company several weeks ago to ?sell". Calpine hit $22.87 in June 2008, slipped to $4.95 in March 2009, recovered to $23.76 by June 2014, and is back down to $11.47 a share. Not surprisingly, these independent power producers (IPPs) are also closing power plants. . 10 Dynegy announced last May that it planned to close 2,800 MW of coal?fired generating capacity in southern Illinois. In December, it requested court approval of a prepackaged bankruptcy plan for its Illinois Power Generating subsidiary to restructure $825 million in unsecured debt. To call these electricity markets ?competitive markets" or ?free markets? is to flirt with fantasy. They are seriously compromised by a patchwork of state programs that remove large portions of the market from the competitive supply?demand bidding process. In California, Calpine has shut down its Sutter Energy Center, a gas-fired combined cycle plant that started up in 2001. Dynegy has closed 1,500 MW of gas?fired capacity at its Moss Landing plant on the California coast. And last December, the private? equity owner of the La Paloma plant, a gas?fired combined cycle facility that was commissioned in 2003, filed for bankruptcy protection, crippled by a $524?million debt load. In California?s case, the culprit is high penetration of renewables, more than low gas prices. The Golden State is a major success story for renewable energy. During 2016, electricity produced from renewable sources in California was almost 20% higher than the year before, and nearly 50% above the previous five~year average. But there's a dark side to this story. Increasing production of renewable electricity?which floods the market forjust a few hours at the same time every daywpushes so?called "thermal" power plants gas? fired, coal?fired and nuclear) out of the market during those hours. The thermal plants run less and less, generating less and less revenue, spiraling down toward insolvency. This wouldn?t matter, except renewables produce only 30?50% of the time?solar typically around the midday hours, wind at night. So the thermal plants are still needed,'when the sun isn?t shining and the wind isn?t blowing, to meet demand for electricity and to maintain reliability. Seriously Compromised Markets This is a difficult situation?difficult to explain, difficult to fix. Although much of the attention has focused on nuclear plants shutting down prematurely, the loss of valuable and productive power plants clearly extends well beyond nuclear. 11 The competitive markets are either poorly designed or crudely designed. They do not fairly compensate resources in place for the value they bring to the grid. Some zero-carbon resources are compensated for providing clean electricity, for example; some are not. And the markets are distorted by state and federal mandates and subsidies, to the advantage of some sources of electricity and to the disadvantage of others. The core problem is that many nuclear, coal-fired and gas-fired power plants cannot cover their costs with revenues from the market. Wind and solar facilities do not cover their costs out of the market either, but they have the advantage of other sources of so-called ?out of market? revenue, which insulates them from the carnage around them. In the northeast, wind and solar facilities generate most of their revenue from federal tax credits and state mandates. This insulates them from the market stress experienced by other electricity generators. In New England, for example, over 70 percent of the revenues for both wind and solar units in 2015?16 were from federal and state programs, such as federal investment or production tax credits or the renewable energy credits (RECs) created by state portfolio mandates. Similarly in New York: a new solar project would have earned 58?69 percent of its 2015 revenues from renewable energy credits and tax credits. Onshore wind units in New York would have received 5166 percent of their 2015 net revenues from state and federal programs. 12 In fact, to call these electricity markets "competitive markets? or ?free markets? is to flirt with fantasy. They are seriously compromised by a patchwork of state programs that remove large portions of the market from the competitive supply?demand bidding process. In Connecticut, for example, the state purchases renewable energy for the grid outside the market under several programs authorized by legislation enacted in 2013 and 2015. New York announced last month a $360?million grant to 11 renewable energy projects,just the latest in a series of interventions. Massachusetts enacted legislation last summer requiring the state to execute 15~20 year contracts for 1,600 megawatts of offshore wind and another 1,200 megawatts of hydropower, which will likely come from Canada. To no avail,the power plant owners in New England complained that the Massachusetts legislation places about 60% of the state?s market off?limits?"the single biggest step away from a competitive electricity market ever taken in New England," said Dan Dolan, president of the New England Power Generators Association. If current trends continue, Exelon estimates approximately 60% of the New England market in 2030 will be reserved for state?supported or state?mandated programs; only about 40% will operate as a competitive market. Leaving aside these structural issues, there is also an element of anti?consumer economic lunacy on display here. At the same time New England is closing down reliable, zero? emission, relatively low?cost nuclear power plants, states are mandating construction of power plants that will produce much more costly electricity. 13 Economic lunacy: New England is closing down nuclear power plants, which produce electricity for $45?$50 per megawatt?hour Instead, the region is building new gas~ fired combined cycle plants for up to $78 per or new offshore wind facilities (for $118?$214 per or importing Canadian hydro (at $97 per The Vermont Yankee nuclear plant (which shut down at the end of 2014) and the Pilgrim nuclear plant in Massachusetts (which will close in mid-2019) both operate (or operated) for $45?50 per megawatt?hour (In the nuclear world, these are relatively small plants and thus the highest?cost. The average US. nuclear plant in 2015 produced electricity at an all?in cost of $35.50 per and the large multi?unit sites for less than that). In place of Vermont Yankee and Pilgrim, Massachusetts will substitute Canadian hydroelectricity that, by one independent estimate, will cost roughly twice as much ($97 per Or offshore wind at somewhere between $118 per (according to Lazard) and per (according to the US. Energy Information Administration). 14 Even if those $50?per?MWh nuclear plants were replaced with the most modern, most efficient gas?fired power plants, the gas?fired electricity would cost $48 ?$78 per (Lazard) or (EIA). None of this makes economic sense. Draining the Swamp To their credit, the regional transmission organizations (RTOs), which operate the grid and manage the markets, and the states and the Federal Energy Regulatory Commission (FERC), which oversees the RTOs, all recognize there?s a problem. For a federal government agency, the classic first response to an. incipient crisis is to commission reports from its staff and convene workshops and conferences on the issue. The FERC did that in 2013 and, three?plus years later, there?s not much to show for it. The agency has taken a few small, necessary and appropriate steps?"to ensure that market prices actually reflect real-?time supply?demand conditions, for examplem?but nothing that could be characterized as particularly bold or innovative. PJM has changed its market practices to provide additional compensation to some power plants~?like nuclear power plants or gas?fired power plants with firm gas delivery contracts?capable of sustained, predictable operation. These resources are expected to be available and capable of providing energy when needed, and face substantial penalties if they are not. That was an important, necessary and appropriate step that should be replicated nationwide. Several of the regional transmission organizations?including England and PJM?recognize the distortions occurring in the energy markets due to federal and state subsidies and mandates. Both are considering various options to address this market defect, but they're compelled to use a cumbersome stakeholder consultation process that is virtually guaranteed to arrive at stalemate. Time to Reboot: Back to First Principles The preponderance of the evidence suggests that the merchant power generation business is flat on its back. That's certainly not healthy and probably not sustainable. 15 Does all this mean that competitive electricity markets are fatally compromised? Not necessarily. But it's unlikely that band?aids applied here and there will fix systemic maladies. Step one is to admit there?s a problem and, sadly, there?s still a lot of denial out there. In a whopping unintended irony, PJM published a white paper last year that declared: ?No evidence suggests the PJM markets inadequately compensate legacy units and thus are forcing a premature retirement of economically viable generators." Exactly one day later, Exelon announced that it would be forced to close its Clinton and Quad Cities nuclear stations??two reliable, low?cost generating stations in western PJM?because the markets did not recognize their value. Step two is to return to basics and first principles,_rediSCover the attributes necessary for a robust, reliable, sustainable market, then design a market structure that provides and preserves those attributes. Absent major reform, this story ends with the United States shackled to an electric supply system that's subject to chronic, punishing volatility in prices. New England is already there. Lowest possible short?run cost is an important attribute, to be sure, but it is not the only important metric. (In fact, in an industry that builds and operates infrastructure with 40?to? 60wyear lifespans, lowest?possible short?run cost may not even be the most important characteristic of a successful market.) What are the other necessary attributes of a sustainable power supply system? Long?term price stability is important. So are environmental factors. So is the ability to operate when needed, regardless of weather, whether or not the wind is blowing or the sun shining, whether or not natural gas arrivesjust in time via pipeline. Portfolio value is particularly critical. A diverse portfolio of fuels and technologies is a prudent necessity in power as a diverse portfolio of debt and equity, short? term instruments and longer?dated ones, is a prudent necessity in a financial portfolio. Fuel and technology diversity is a hedge against supply disruptions or price volatility in any part of the portfolio. 16 So there we have five attributes of a successful market. As currently designed, America?s competitive electricity markets have one attribute out of the five. Defenders of the status quo insist that the competitive markets arejust doing what they?re designed to do?deliver power at the lowest possible short?run cost. They insist that these markets were not designed to provide long?term price stability, or a diverse portfolio of fuels and technologies. Yes that?s precisely the point. Comments like that are an excuse, not a solution. Will the Lights Go Out? Will the lights go out if the status quo prevails? Of course not. In what appears to be a triumph of hope over experience, there?s apparently an endless supply of companies willing to build even more gas?fired power plants. And, as in any industry, there are always bottom?feeders willing to snatch up distressed assets for pennies on the dollar. Absent major reform, however, this story ends with the United States shackled to an electric supply system that?s subject to chronic, punishing volatility in prices. New England is already there. In its 2016 Regional Electricity Outlook, published in January 2016, the New England grid operator notes: ?[WJintertime access to natural gas has grown tight over recent years because the regional fuel transportation network has not kept up with demand from both generation and heating sectors. These natural gas constraints have led to grid reliability challenges, emission increases during winter, and spikes in wholesale electricity prices. The situation is exacerbated by other market dynamics: low gas prices during most of the year except winter are putting economic pressure on coal, oil, and nuclear resources. By 2020, resources representing about 30% of regional capacity have committed to cease operation or are at risk of retirement. Taking their place are even more natural?gas~fired units?currently, more than 60% of new generation being proposed by private investors across the six states will be primarily or exclusively fueled by natural gas 17 The region?s growing dependence on natural gas for power generation exposes consumers of electricity to increasing price volatility: "Because so much of the region ?5 generating capacity runs on natural gas, the price of this single fuel source sets the price for wholesale electricity about 70% of the time. Both electricity and gas prices have seen dramatic swings in recent years. Between February and June 2015, for example, the region ?5 average wholesale electricity price plummeted from the third?highest price to the lowest price since 2003, the year that competitive markets in their current form were introduced in New England. (Emphasis added.) One ?nal thought: it?s true that electricity represents only 2-3% of America?s GDP. Not such a big deal perhaps. But that 2?3% drives the other 97?98%. So this is serious stuff. Best we get it right. Richard Myers is a free?lance journalist based in Washington, D. C. He worked almost 30 years at the Nuclear Energy Institute, the U. 5. nuclear industry?s D. Cubased policy organization, the last 10 years as vice president for policy and planning. Before that, he spent almost 15 years as a reporter and editor with The Energy Daily, now published by IHS Markit. The information contained in this message is intended only for the personal and con?dential use of the recipient(s) named above. If the reader of this message is not the intended recipient or an agent responsible for delivering it to the intended recipient, you are hereby notified that you have received this document in error and that any review, dissemination, distribution, or copying of this message is strictly prohibited. If you have received this communication in error, please notify us immediately, and delete the original message. 18 Rep29 From: Pine, Ty Sent: Thursday, March 02, 2017 11:43 AM To: Pine, Ty Subject: Electric Issue Perspective Dear Representative: Below is an interesting article on electric energy issues. ask that you take the opportunity to read Mr. Myers? perspective as I believe it will prove instructive for our energy policy discussions in the coming months. Thanks. Ty Pine Director, State Affairs FirstEnergy 614-257-8926 .com/sea Richard Myers Free~lance journalist. Former head of policy and planning for a major energy trade association. Before that, 'a reporter and editor at "The Energy Daily." Feb 20 America's Hidden Energy Crisis If Competitive Electricity is Such A Good Business, Why Are Companies Closing Power Plants, Taking Write-Downs, Seeking Bankruptcy Protection and Scrambling for the Exits? casual observer scanning the headlines might conclude that America?s biggest energy challenge involves the Trump Administration?s position on climate change, whatever that turns out to be. But the country faces an equally difficult and?~because it is mostly hidden to all but industry insiders?more insidious challenge. The competitive business model worked reasonably well until a few years ago, when the entire electric power industry sailed into a hundred-?year storm, a period of unprecedented stress that continues unabated to this day. Left untreated, this festering problem will lead to loss of valuable energy infrastructure that has decades of useful life left, more costly electricity, more volatility in electricity prices, higher emissions of carbon and other pollutants, and possibly even less reliable electricity supply. The problem is the business of generating electricity in those parts of the country that deregulated the power industry in the late 19905 and early 20005. Since then, electricity has evolved into two very different businesses. States in the south and southeast resisted the temptation to deregulate. In those states, companies own power plants, transmission lines and the local distribution networks. They operate under a regulatory bargain struck many decades ago. In return for an exclusive franchise, the companies accept an ?obligation to serve" any and all who need electricity. They are guaranteed a reasonable opportunity to recover all their costs, plus a reasonable return on their investment. States in the northeast, mid?Atlantic, midwest and Texaswrepresenting roughly two?- thirds of the electricity consumed in the United their companies to restructure. They separated transmission and distribution (the "wires? business) from the business of generating the electricity. The wires continued as regulated enterprises, but generating electricity became an unregulated, competitive undertaking, with the grid managed by independent regional organizations. There?s no compelling evidence that the competitive business model is any better. Retail electricity LELQS. in the south and southeast (regulated states) average 9 ?10 cents per kilowatt?hour. Some states with competitive markets (Ohio, Texas, for example) are also in that range. But electric rates in many other competitive states? notably on the East and West Coasts?are at least 50% higher. Connecticut holds the dubious distinction of having the highest rates in the" lower?48, at 17.7 cents per kilowatt? houn A Hundred- Year Storm The competitive business model worked reasonably well until a few years ago, when the entire electric power industry sailed into a hundred?year storm, a period of unprecedented stress that continues unabated to this day. The stress is caused partly by disruptive advances in technology. For example, horizontal drilling and hydraulic fracturing unlocked vast reserves of natural gas in so-called "tight" formations. This produced a gusher of natural gas at extremely low?wand probably Since natural gas is a dominant fuel for producing electricity, wholesale electricity prices have collapsed along with natural gas prices. But the stress also comes from other sources. Demand for electricity is growing slowly, if at all, thanks to relatively anemic, halting economic growth since the 2008 recession, and greater efficiency in electricity use. Nationwide, electricity consumption in 2016 was below 2010. Even companies in regions with relatively robust economies are feeling the pinch. Atlanta? based Southern Co. (which operates in Georgia, Alabama and parts of Mississippi and Florida) expects annual electricity demand to grow only between 0% and 1% for the next four or five years. And companies in more economically?challenged regions, like Columbus, Ohio-?based American Electric Power, saw quarterly growth in electricity demand in 2016 range from a low of 0.5% in the third quarter to a high of 0.3% in the fourth. Inevitably, slow demand growth~?or no demand growth?tends to depress prices even further. It?s notjust nuclear plants that are closing. Coal?fired power plants are closing down, too, and notjust due to tighter environmental controls. So are gas?fired power plants, including relatively new, high?efficiency facilities. In fact, without subsidies and mandates, wind and solar facilities would probably be tanking, too. Add to all this the impact of state and federal mandates and subsidies for renewable sources of electricity. The last 7?10 years have seen remarkable improvements in the cost and performance of wind and solar technologies. Still, 29 states and the District of Columbia continue to force renewable energy into the market, by requiring their utilities to buy a certain percentage of their electricity from renewable sources. On top of this, the federal government provides a production tax credit to wind generation and an investment tax credit to solar. Leaving aside personal opinion about the wisdom and 5 merits of mandates and subsidies, it is inarguable that these programs distort markets and, in the case of federal subsidies, suppress wholesale electricity prices even further. Then add serious problems with design and operation of the competitive markets. These markets typically don?t recognize or value the positive attributes of the resources in place. They?re not always operated so that all costs are reflected in prices. And they operate solely on the basis of lowest short?run marginal cost, when it?s clear that a robust and resilient market must also factor in other factors?long?run price stability, for example, or the value of fuel and technology diversity, or environmental factors, and others. In sum, it?s hard to imagine a more ?perfect storm" of negative factors all arriving at about the same time, all pushing wholesale electricity prices down, down, down. When Low Prices Aren?t Always Such a Good Thing To the average consumer, low electricity prices sound like a good thing. And so they are, unless they?re so low that the companies operating the power plants cannot generate sufficient revenue to stay in business. The competitive electricity markets in the United States have reached that point. Today?s situation is simply unsustainable. To be sustainable, a competitive market?for crude oil, gasoline, tires, orangejuice, electricity or any other commodity?must satisfy the needs of consumers, suppliers, asset owners and investors, regulators, policy?makers and other stakeholders. ?We continuously expect our electric industry to solve a complex ?simultaneous equation? in which the countless decisions of myriad actors need to produce a reliable, efficient and increasingly clean supply of electricity,? Susan Tierney, one of the most respected observers of electricity issues and a principal with a consultancy called The Analysis Group, told federal energy regulators several years ago. In Tierney?s view, the markets today are not solving that ?simultaneous equation? correctly: ?Something has to change for the numbers to support a sustainable, healthy and vibrant electric industry capable of meeting system operators? technical necessities, consumers? implicit needs, policy?makers? explicit demands, and investors? inherent requirements. That entire equation must be satisfied,? she says, ?or the system isn?t sustainable.? The distress is most visible?nor perhaps most talked about?in America?s nuclear energy industry, which produces about 20 percent of US. electricity supply, and about two?thirds 6 of the country?s carbonwfree electricity. Since 2013, six nuclear reactors have shut down permanently. That leaves 99 operating reactors. Three more reactors are planned to be shut down before 2020, two more in 2020?2021, and two more in the mid?20205. And there are others at risk. The common wisdom holds that the nuclear plants can?t compete in a world of low?cost natural gas, and isn?t thatjust too bad but markets are cruel places where only the strong (or the lowest?cost) survive. As is often the case, the common wisdom is wrong. It?s notjust nuclear plants that are closing. Coal~fired power plants are closing down, too, and notjustdue to tighter environmental controls. So are gas?fired power plants, including relatively new, high?efficiency facilities. In fact, without subsidies and mandates, wind and solar facilities would probably be tanking, too. The entire competitive generation segment of the electric power industry isstruggling. Across the board, companies are dumping the power plants that, as recently as 10 years ago, were their crown jewels. In its annual assessment of the competitive electricity business late last year, Moody?s Investors Service, the credit rating agency, maintained its negative outlook on the entire sector: ?Against persistent headwinds, [the] fundamentals remain negative,? Moody?s said. In a separate analysis, the rating agency noted the economic stress facing some nuclear plants, but found that over 66,000 megawatts (MW) of coal?fired generating capacity in 16 states is also at risk (out of roughly 100,000 coal?fired megaWatts operating in those states). And despite the Trump Administration?s rhetoric, this coal?fired capacity is not at risk because of environmental requirements or the Obama Administration?s Clean Power Plan. Moody?s criterion was simple economics: ?at?risk? is when fuel, variable operating and maintenance (O8LM) costs and fixed 081M exceed $30 per megawatt?hour. Running for the Exits So the electric power companies operating in competitive (or ?merchant") markets are in full flight from the business of generating electricity, and they have been for several years. Between 2003 and 2015, electric industry revenues moved from 64?percent regulated to 78-percent regulated. Across the board, companies are dumping the power plants that, as recently as 10 years ago, were their crown jewels. Instead, they're putting their capital into upgrading and strengthening the "wires" business (transmission and distribution), because it?s regulated and safe. They?re assured of capital recovery and steady, predictable earnings. Power plants are out. The "wires" business (transmission and distribution) is in. Transmission and distribution are regulated, and provide stable cash flows and predictable earnings. Chicago-based Exelon is a poster child for this strategy. Exelon is one of the largest merchant generating companies in the United States, with roughly 33,000 MW of capacity, much of it nuclear. But it?s not a happy business. Only heroic state government intervention in 2016 in New York and Illinois saved seven Exelon reactors that were slated for premature shutdown over the next several years. The states provided "zero?emission a way to compensate the nuclear plants for producing carbon?free electricity, in much the same way that "renewable energy credits? value the contribution 8 from wind and solar. It will take similar state government action to save other nuclear plants at risk in Ohio, Connecticut, and Texas. Last year?s reprieve didn?t really solve Exelon?s bigger problem, however. In a recent assessment, UBS equity analyst Julien Dumoulin?Smith sees the earnings?per?share contribution from Exelon?s generation subsidiary $1.40 per share in 2014 to an estimated 25ucents per share in 2020. Why would any company want to stake its future on a business with such unappetizing earnings potential? Exelon?s-leadership has reinvented and repositioned the company over the last several years to deal with this. From a base that included two big distribution companies? Commonwealth Edison in Chicago and PECO in. Philadelphia?the company acquired Baltimore Gas and Electric in 2011 and Potomac Electric in 2016. By so doing, the company ensured that it would always be able to cover its dividend to shareholders, and provide earnings growth, through the regulated side of the business?making it relatively indifferent to continuing economic pressure on its generating business. Exelon is investing its growth over the next four yearsmin its regulated businesses, where it can earn predictable returns. And it?s harvesting free cash flow from its generating subsidiary to pay down debt and invest in its regulated utilities. Of $6.8 billion in free cash flow expected from Exelon Generation over the next four years, more than 75% will go to debt reduction and its regulated business. Misery loves company, and Exelon has lots of it. American Electric Power (AEP) has sold, or is in the process of selling, most of its generating assets in competitive markets. At the end of January, AEP closed on the sale of four large power gas-fired and one coal?fired, totaling 5,200 megawatts (MW) of capacity?to a private equity group. During the third quarter of 2016, the company took a $2.3-billion impairment charge to write down the value of its remaining merchant generating assets (about 2,700 MW, mostly in Ohio). In all its presentations to investors, AEP emphasizes its large capital investment in transmission and distribution, and brands itself prominently as ?The Premier Regulated Energy Company." New Orleans?based Entergy is winding down its merchant generation business. It closed (or will close) two nuclear plants and a gas-fired combined cycle plant in New England and a nuclear plant in Michigan. It sold another nuclear plant in upstate New York to Exelon. 9 Entergy is so anxious to exit merchant generation that it finally agreed in January to do what New York Governor Andrew Cuomo has been trying to accomplish for yearsm?close down the two Indian Point reactors on the Hudson River, about 35 miles north of New York city. Akron?based FirstEnergy intends to exit the competitive electricity generating business no later than mid?2018, and will either sell or shut down its power plants operating in competitive marketswincluding several coal?fired plants and three nuclear power stations. (The company is urging Ohio legislators to follow the lead of New York and Illinois, and provide zero~emission credits to save the Davis?Besse and Perry nuclear plants.) In January, the company found a buyer for several power plants?including gas?fired plants in and its share of a hydroelectric plant in Virginia. One of the gas~fired facilities is a relatively modern (commissioned in 2003) high?efficiency combined?cycle plant. During the fourth quarter of 2016, the company Wrote down the value of its competitive generating assets by $9.2-billion billion after tax). FirstEnergy continues to warn investors that its competitive generating subsidiary may be forced to seek bankruptcy protection. And like AEP, FirstEnergy takes great pains to remind investors in its presentations that it is putting capital to work in its regulated businesses and ?Transforming into a Regulated Energy Company." When There Is No Exit These companies, at least, have large regulated transmission and distribution subsidiaries to fall back on. The ?pure play" independent power producers?names like NRG, Calpine and Dynegy?~ are not so fortunate. NRG closed on? February 17 at a little over $17 a sharembetter than the $10.54?a?share in January 2016, but down more than 50% from its 10-year high. Dynegy reached $36 a share in now hoveringjust above $9 a share, and U88 moved the company several weeks ago to ?sell". Calpine hit $22.87 in June 2008, slipped to $4.95 in March 2009, recovered to $23.76 by June 2014, and is back down to $11.47 a share. Not surprisingly, these independent power producers (IPPs) are also closing power plants. 10 Dynegy announced last May that it planned to close 2,800 MW of coal~fired generating capacity in southern Illinois. In December, it requested court approval of a prepackaged bankruptcy plan for its Illinois Power Generating subsidiary to restructure $825 million in unsecured debt. To call these electricity markets ?competitive markets" or ?free markets? is to flirt with fantasy. They are seriously compromised by a patchwork of state programs that remove large portions of the market from the competitive supply?demand bidding process. In California, Calpine has shut down its Sutter Energy Center, a gas?fired combined cycle plant that started up in 2001. Dynegy has closed 1,500 MW of gas?fired capacity at its Moss Landing plant on the California coast. And last December, the private? equity owner of the La Paloma plant, a gas?fired combined cycle facility that was commissioned in 2003, filed for bankruptcy protection, crippled by a $524~million debt load. In California?s case, the culprit is high penetration of renewables, more than low gas prices. The Golden State is a major success story for renewable energy. During 2016, electricity produced from renewable sources in California was almost 20% higher than the year . before, and nearly 50% above the previous five?year average. But there?s a dark side to this story. Increasing production of renewable electricity?which floods the market forjust a few hours at the same time every day?pushes so?called ?thermal" power plants gas? fired, coa ~fired and nuclear) out of the market during those hours. The thermal plants run less and less, generating less and less revenue, spiraling down toward insolvency. This wouldn?t matter, except renewables produce only 30?50% of the time?solar typically around the midday hours, wind at night. So the thermal plants are still needed, when the sun isn?t shining and the wind isn't blowing, to meet demand for electricity and to maintain reliability. Seriously Compromised Markets This is a difficult situation?difficult to explain, difficult to fix. Although much of the attention has focused on nuclear plants shutting down prematurely, the loss of valuable and productive power plants clearly extends well beyond nuclear. 11 The competitive markets are either poorly designed or crudely designed. They do not fairly compensate resources in place for the value they bring to the grid. Some zero?carbon resources are compensated for providing clean electricity, for example; some are not. And the markets are distorted by state and federal mandates and subsidies, to the advantage of some sources of electricity and to the disadvantage of others. The core problem is that many nuclear, coal?fired and gas-fired power plants cannot cover their costs with revenues from the market. Wind and solar facilities do not cover their costs out of the market either, but they have the advantage of other sources of so?called ?out of market" revenue, which insulates them from the carnage around them. In the northeast, wind and solar facilities generate most of their revenue from federal tax credits and state mandates. This insulates them from the market stress experienced by other electricity generators. In New England, for example, over 70 percent of the revenues for both wind and solar units in 2015u16 were from federal and state programs, such as federal investment or production tax credits or the renewable energy credits (RECs) created by state portfolio mandates. Similarly in New York: a new solar project would have earned 58?69 percent of its 2015 revenues from renewable energy credits and tax credits. Onshore wind units in New York would have received 51-66 percent of their 2015 net revenues from state and federal programs. 12 In fact, to call these electricity markets ?competitive markets? or ?free markets" is to flirt with fantasy. They are seriously compromised by a patchwork of state programs that remove large portions of the market from the competitive supply?demand bidding process. In Connecticut, for example, the state purchases renewable energy for the grid outside the market under several programs authorized by legislation enacted in 2013 and 2015. New York announced last month a $360?million grant to 11 renewable energy projects,just the latest in a series of interventions. Massachusetts enacted legislation last summer requiring the state to execute 15?20 year contracts for 1,600 megawatts of offshore wind and another 1,200 megawatts of hydropower, which will likely come from Canada.- To no avail, .the power plant owners in New England complained that the Massachusetts legislation places about 60% of the state?s market off?limitsw?"the single biggest step away from a competitive electricity market ever taken in New England,? said Dan Dolan, president of the New England Power Generators Association. If current trends continue, Exelon estimates approximately 60% of the New England market in 2030 will be reserved for state~supported or state-mandated programs; only about 40% will operate as a competitive market. Leaving aside these structural issues, there is also an element of anti?consumer economic lunacy on display here. At the same time New England is closing down reliable, zero- emission, relatively low?cost nuclear power plants, states are mandating construction of power plants that will produce much more costly electricity. 13 Economic lunacy: New England is closing down nuclear power plants, which produce electricity for $45?$50 per megawatt?hour Instead, the region is building new gas? fired combined cycle plants for up to $78 per or new offshore wind facilities (for $118?$214 per importing Canadian hydro (at $97 per The Vermont Yankee nuclear plant (which shut down at the end of 2014) and the Pilgrim nuclear plant in Massachusetts (which will close in mid?2019) both operate (or operated) for $45?50 per megawatt?hour (In the nuclear world, these are relatively small plants and thus the highest?cost. The average US nuclear plant in 2015 produced electricity at an all?in cost of $35.50 per and the large multi-unit sites for less than that). In place of Vermont Yankee and Pilgrim, Massachusetts will substitute Canadian hydroelectricity that, by one independent estimate, will cost roughly twice as much ($97 per. Or offshore wind at somewhere between $118 per (according to Lazard) and per (according to the US. Energy Information Administration). 14 Even if those $50~per?MWh nuclear plants were replaced with the most modern, most efficient gas?fired power plants, the gas?fired electricity would cost $48 ?$78 per (Lazard) or $53.40m$67.40 (EIA). None of this makes economic sense. Draining the Swamp To their credit, the regional transmission organizations (RTOs), which operate the grid and manage the markets, and the states and the Federal Energy Regulatory Commission (FERC), which oversees the RTOs, all recognize there?s a problem. For a federal government agency, the classic first response to an incipient crisis is to commission reports from its staff and convene workshops and conferences on the issue. The FERC did that in 2013 and, three?plus years later, there's not much to show for it. The agency has taken a few small, necessary and appropriate steps?to ensure that market . prices actually reflect real?time supply?demand conditions, for examplembut nothing that could be characterized as particularly bold or innovative. PJM has changed its market practices to provide additional compensation to some power plants?like nuclear power plants or gas-fired power plants with firm gas delivery contracts?capable of sustained, predictable operation. These resources are expected to be available and capable of providing energy when needed, and face substantial penalties if they are not. That was an important, necessary and appropriate step that should be replicated nationwide. Several of the regional transmission organizations?including England and PJM?recognize the distortions occurring in the energy markets due to federal and state subsidies and mandates. Both are considering various options to address this market defect, but they?re compelled to use a cumbersome stakeholder consultation process that is virtually guaranteed to arrive at stalemate. Time to Reboot: Back to First Principles The preponderance of the evidence suggests that the merchant power generation business is flat on its back. That?s certainly not healthy and probably not sustainable. 15 Does all this mean that competitive electricity markets are fatally compromised? Not necessarily. But it?s unlikely that band?aids applied here and there will fix systemic maladies. Step one is to admit there?s a problem and, sadly, there?s still a lot of denial out there. In a whopping unintended irony, PJM published a white paper last year that declared: ?No evidence suggests the PJM markets inadequately compensate legacy units and thus are forcing a premature retirement of economically viable generators.? Exactly one day later, Exelon announced that it would be forced to close its Clinton and Quad Cities nuclear stations?two reliable, low?cost generating stations in western PJM?because the markets did not recognize their value. Step two is to return to basics and first principles, rediscover the attributes necessary for a robust, reliable, sustainable market, then design a market structure that provides and preserves those attributes. Absent major reform, this story ends with the United States shackled to an electric supply system that?s subject to chronic, punishing volatility in prices. New England is already there. Lowest possible short?run cost is an important attribute, to be sure, but it is not the only . important metric. (In fact, in an industry that builds and operates infrastructure with 40?to? 60?year lifespans, lowest?possible short?run cost may not even be the most important characteristic of a successful market.) What are the other necessary attributes of a sustainable power supply system? Long?term price stability is important. So are environmental factors. So is the ability to operate when needed, regardless of weather, whether or not the wind is blowing or the sun shining, whether or not natural gas arrivesjust in time via pipeline. Portfolio value is particularly critical. A diverse portfolio of fuels and technologies is a prudent necessity in power supply?-?just as a diverse portfolio of debt and equity, short- term instruments and longer?dated ones, is a prudent necessity in a financial portfolio. Fuel and technology diversity is a hedge against supply disruptions or price volatility in any part of the portfolio. 16 So there we have five attributes of a successful market. As currently designed, America's competitive electricity markets have one attribute out of the five. Defenders of the status quo insist that the competitive markets arejust doing what they?re designed to do?deliver power at the lowest possible short?run cost. They insist that these markets were not designed to provide long?term price stability, or a diverse portfolio of fuels and technologies. Yes that?s precisely the point. Comments like that are an excuse, not a solution. Will the Lights Go Out? Will the lights go out if the status quo prevails? Of course not. In what appears to be a triumph of hope over experience, there?s apparently an endless supply of companies willing to build even more gas?fired power plants. And, as in any industry, there are always bottom?feeders willing to snatch up distressed assets for pennies on the dollar. Absent major reform, however, this story ends with the United States shackled to an electric supply system that's subject to chronic, punishing volatility in prices. New England is already there. In its 2016 Regional Electricity Outlook, published in January 2016, the New England grid operator notes: ?[Wjintertime access to natural gas has grown tight over recent years because the regional fuel transportation network has not kept up with demand from both generation and heating sectors. These natural gas constraints have led to grid reliability challenges, emission increases during winter, and spikes in Wholesale electricity prices. The situation is exacerbated by other market dynamics: low gas prices during most of the year except winter are putting economic pressure on coal, oil, and nuclear resources. By 2020, resources representing about 30% of regional capacity have committed to cease operation or are at risk of retirement. Taking their place are even- more natural?gas-fired units?currently, more than 60% of new generation being proposed by private investors across the six states will be primarily or exclusively fueled by natural gas 17 The region's growing dependence on natural gas for power generation exposes consumers of electricity to increasing price volatility: ?Because so much of the region ?5 generating capacity runs on natural gas, the price of this single fuel source sets the price for wholesale electricity about 70% of the time. Both electricity and gas prices have seen dramatic swings in recent years. Between February and June 2015, for example, the region ?5 average wholesale electricity price plummeted from the third-highest price to the lowest price since 2003,. the year that competitive markets in their current form were introduced in New England. (Emphasis added.) One final thought: it?s true that electricity represents only 2?3% of America?s GDP. Not such a big deal perhaps. But that 28% drives the other 97m98%. So this is serious stuff. Best we get it right. Richard Myers is a free?lance journalist based in Washington, D. C.. He worked almost 30 years at the Nuclear Energy Institute, the US. nuclear industry?s D. C.?based policy organization, the last 10 years as vice president for policy and planning. Before that, he spent almost 15 years as a reporter and editor with The Energy Daily, now published by Markit. The information contained in this message is intended only for the personal and con?dential use of the recipient(s) named above. If the reader of this message is not the intended recipient or an agent responsible for delivering it to the intended recipient, you are hereby noti?ed that you have received this document in error and that any review, dissemination, distribution, or copying of this message is strictly prohibited. If you have received this communication in error, please notify us immediately, and delete the original message. 18 Rep29 From: Lehman, Ryan Sent: Tuesday, February 28, 2017 4:45 PM To: Rep30; Kasych, Shawn; Rep29 Cc: ?Wolf, Jimmy'; Romanchik, Kelsey Subject: FW: Delivery from LSC Attachments: R01 94?24 32. Alf, Attached is the brand new analysis from LSC on the most current -3 version of the mandate bill. Ryan J. Lehman Majorizj? Policy Adviser Of?ce of Speaker Clifford A. Rosenberger Ohio House of Representatives ryan.lehman@ohiohouse.gov (614) 466-65 05 From: Sent: Tuesday, February 28, 2017 3:43 PM Subject: Delivery from LSC - Please see the attached document(s), with respect to the research, requested from LSC. If you have any questions about this assignment or want any changes made to it, please contact Maura McClelland, who worked on the assignment, or Ralph Clark, rclark@lsc.ohio.gov, who reviewed it. OHIO LEGISLATIVE SERVICE COMMISSION Bi" Analysis Maura McClelland L-132-0522-3 132nd General Assembly BILL SUMMARY Energy efficiency and peak demand reduction 0 Effectively makes the energy efficiency requirements for 2017, 2018, 2020, 2021, 2023, 2024, and 2026 no longer true requirements. I Decreases the energy efficiency benchmarks, resulting In a decrease to the current cumulative requirement from 22. 2% to 17. a Seeks to clarify that the energy efficiency requirements terminate at the end of 2027. - Effectively makes the peak demand reduction requirements for 2017 and 2018 no longer true requirements, but keeps the benchmarks for those years (and the two years that follow) at the levels in current law. - Requires that electric distribution utilities (EDUS) be deemed in compliance with the energy efficiency and peak demand reduction requirements and eligible for incentives approved by the Public Utilities. Commission (PUCO) in any year in which their "actual cumulative energy ef?ciency and peak demand reduction savings? meet or exceed the "cumulative mandates." - Requires the following to be counted toward the energy ef?ciency and peak demand reduction requirements: 0 Energy intensity reductions resulting from heat rate improvements at electric generating plants (also prohibited from qualifying for Shared savings); 0 Energy efficiency savings and peak demand reductions that occur as a consequence of consumer reductions in water usage or reductions and improvements in wastewater treatment; Nonelectric energy efficiency savings and nonelectric peak demand reductions that occur as a consequence of an EDU's energy efficiency and peak demand reduction portfolio plan; 0 The savings and reduction associated with heat rate improvements, other efficiency improvements, or other energy intensity improvements, if proposed by an EDU and achieved since 2006 from an electric generating plant that is either owned by the EDU or, in some cases, owned and operated by an EDU affiliate (also prohibited from qualifying for shared savings). Requires the following to be counted toward the energy efficiency requirements only: any plan, policy, behavior, or practice that reduces the energy intensity of a facility, pipeline, building, plant, or equipment; or any water supply function or water treatment function. Adds mercantile customers to those customers that may, subject to a number of requirements, including requirements for customer reporting, opt out of an energy efficiency and peak demand reduction portfolio plan, effective January 1, 2019. Modifies the current definition of energy intensity and broadens the definition's applicability. Renewable energy Permits, rather than requires, EDUs and electric services companies (ESCs) to provide portions of their electricity supplies from renewable energy resources, as long as their costs of providing those portions do not exceed a 3% cost cap. Permits, beginning January 1, 2019, and subject to rules that the bill requires the PUCO to adopt, all customers to opt out of paying anyrider, charge, or other cost recovery mechanism designed to recover an EDU's or ESC's cost of providing electricity from renewable energy resources. Requires continued recovery from customers of ongoing costs associated with contracts to procure resources to comply with the current renewable energy requirements, if those contracts were entered into before the bill's effective date. Requires, by January 1, 2018, the PUCO to ad0pt rules governing disclosure to customers of the costs of electricity provided after the bill's effective date from renewable energy resources. Legislative Service Commission Permits EDUs and ESCs to request a force majeure determination with the PUCO for the reduction of a benchmark for the permissible provision of renewable energy rather than the reduction of a benchmark for the renewable energy requirements, though due to the bill's construction, this provision will likely be moot. Reports, reviews, and testimony Beginning in 2018, requires every EDU to report to the PUCO, by July 1 of each year, its status of compliance for the prior calendar year with the energy efficiency and peak demand reduction provisions. Beginning in 2018, requires every EDU and BBC to report to the PUCO, by July 1 of each year, the amount of electricity that the EDU or ESC provided from renewable energy resources during the prior calendar year. Makes the following changes regarding the annual report that the PUCO is currently required to make to the General Assembly on renewable "energy: 0 Requires a report to be made by August 1 of each year, but does not require a report in 2017. Requires the report to include the amount of electricity that EDUs and ESCs provided from renewable energy resources during the prior calendar year, and requires this portion of the report to be based on the and reports to the PUCO. Repeals a provision requiring the PUCO to allow and consider public comments on the report prior to its submission to the General Assembly. 0 Repeals a provision specifying that nothing in the report is binding on any person. 0 Requires the report to include EDU compliance with the energy ef?ciency and peak demand reduction provisions, and requires that portion of the report to be based on the reports to the PUCO. Requires that the currently required annual report of EDU compliance with the energy efficiency and peak demand reduction provisions must be based on the reports to the PUCO, as well as any other information that is public. Requires the PUCO Chairperson to provide testimony, by September 1 of each year, on the August 1 report, to the standing committees of both houses of the General Assembly that deal with public utility matters. Legisiative Service Commission -3- Bypassability of generation costs - Expressly states that an costs for providing generation service, including all costs of providing electricity from renewable energy resources, are bypassable by any consumer that shops for an electric supplier. Funding for home energy assistance - Changes funding allocations for federal funds from the Home Energy Assistance Block Grant; however, due to the effective date of the changes, they will likely have no effect. TABLE OF CONTENTS Energy efficiency requirements 4 Peak demand reduction requirements 5 Compliance with and incentives for energy ef?ciency and peak demand 6 improvements counted as energy efficiency and peak demand reduction 6 Mercantile customer opt out for energy ef?ciency and peak demand 7 Mercantile opt out beginning in 2019 7 Baseline exclusion 8 Renewable energy 9 Requirements changed to permissive provisions 9 3% cost cap 10 Force majeure provision 11 Customer opt out 11 Recovery for long-term contracts . 11 Renewable energy credits 12 Disclosure of customer costs on bills 12 Reports and testimony 13 Utility and company reporting requirement 13 PUCO reports 13 Renewable energy 13 Energy efficiency and peak demand reduction 13 PUCO testimony 14 of generation costs 14 Funding for home Weatherization services 15 Repeal of uncodified law enacted by 8.8. 310 15 CONTENT AND OPERATION Energy efficiency requirements The bill makes two changes to the energy ef?ciency requirements on electric distribution utilities (EDUs): (1) it effectively makes the energy efficiency requirements for 2017, 2018, 2020, 2021, 2023, 2024, and 2026 no longer true requirements and (2) it decreases the energy efficiency benchmarks. .. Legislative Service Commission 4- The bill effects the first change by doing the following: - Specifying that noncompliance With the energy ef?ciency provisions is subject to forfeitures only for the requirements for years 2016, 2019, 2022, 2025, and 2027;. 0 Limiting the Public Utilities Commission's (PUCO's) requirement to assess forfeitures to only those years; and - Specifying that the assessment of forfeitures is the sole penalty for noncompliance with the energy ef?ciency provisions. The bill decreases the energy efficiency benchmarks as follows, resulting in a decrease to the current cumulative requirement from 22.2% to 17.2%: 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 *not true requirements Finally, the bill seeks to clarify that the energy ef?ciency requirements terminate at the end of 2027 by repealing the language requiring savings of 2% ?each year thereafter." Under current law this language might be interpreted to imply that the 2% requirement extends beyond 2027.1 Peak demand reduction requirements The bill effectively makes the peak demand reduction requirements on EDUs for 2017 and 2018 no longer true requirements. But it keeps the benchmarks for those years (and the two years that follow) at the levels in current law. The bill accomplishes this change by doing the following: 1 RC. and (C). Legislative Service Commission -5- - Specifying that noncompliance with the peak demand reduction provisions is subject to forfeitures only for the requirements for years 2016, 2019, and 2020; 0 Limiting the requirement to assess forfeitures to only those years; and I Specifying that the assessment of forfeitures is the sole penalty for noncompliance with the peak demand reduction provisions.2 Compliance with and incentives for energy efficiency and peak demand The bill requires an EDU to be deemed in compliance with the energy ef?ciency and "peak demand reduction savings" requirements and to be eligible for approved incentives in any year in which the "actual cumulative energy ef?ciency and peak demand reduction savings" meet or exceed the "cumulative mandates? under provisions governing energy ef?ciency and peak demand reduction.3 (See COMMENT 1.) Improvements counted as energy efficiency and peak demand reduction The bill requires the following to be counted toward the energy efficiency and peak demand reduction requirements: 0 Energy intensity reductions resulting from heat rate improvements at electric generating plants (also prohibited from qualifying for shared savings); I Energy ef?ciency savings and peak demand reductions that occur as a consequence of consumer reductions in water usage or reductions and improvements in wastewater treatment; - Nonelectric energy efficiency savings and nonelectric peak demand reductions, required to be counted on a basis, that occur as a consequence of an EDU's energy efficiency and peak demand reduction portfolio plan; 0 The savings and reduction associated with heat rate improvements, other ef?ciency improvements, or other energy intensity improvements, if those savings and reduction are proposed by an EDU in its sole discretion and 2 RC. and (C). 3 RC. if; Legisiative Service Commission R??i32~0194?2 achieved since 2006 from an electric generating plant that is either owned by the EDU or owned and Operated by an EDU affiliate, provided that the plant was previously owned, in whole or in part, by an Ohio EDU (also prohibited from qualifying for shared savings). The bill requires the following to be counted toward the energy ef?ciency requirements only: any plan, policy, behavior, or practice that reduces either of the following: I The total energy intensity of a facility, pipeline, building, plant, or equipment, regardless of the type of energy intensity reduction; 0 The energy intensity of any water supply function or water treatment function. - The bill changes the current definition of energy intensity, and applies the bill's de?nition to the provisions discussed above. The bill defines energy intensity as the amount of energy used to produce a certain level of output or activity, measured by the quantity of energy needed to perform a particular activity, expressed as energy per unit of output, energy per unit of gross total ?oor space, or an activity measure of service. The current definition, which applies only to the customer~opt?out provisions, defines the term as the amount of energy, from electricity, used or consumed per unit of production. The bill also defines water supply function to mean functions associated with raw water collection, purification, treatment, and storage; establishing or maintaining pressure to balance water supply and demand; and water delivery and transfer. Water treatment function is de?ned as any of the preliminary, secondary, tertiary, and advanced activities, whether physical, biological, or chemical, associated with removing contaminants from, or conditioning of, wastewater before recycling it or returning it to the environment.i Mercantile customer opt out for energy efficiency and peak demand Mercantile opt out beginning in 2019 Effective January 1, 2019, the bill adds mercantile customers to those customers that may opt out of an EDU's energy efficiency and peak demand reduction portfolio plan. Such an opt out would make them exempt from associated cost recovery and unable to participate in or directly benefit from the plan and associated programs.5 4 RC. and 4928.662, and 4928661003). 5 RC. and 4928,6611 and Section 6; RC. 49286613, not in the bill. j' Legislative Service Commission Current law already permits certain large-usage customers to Opt out of the portfolio plans. In general terms, the customers who may already opt out must either receive service above the EDU's "primary voltage level," or they must be commercial or industrial consumers of more than 45 million kilowatt hours (kWh) of electricity per year who has made a written request to self?assess under the tax.6 A mercantile customer is defined under continuing law as a commercial or industrial consumer of more than 700,000 per year, or a commercial or industrial customer that is part of a national accormt involving multiple facilities in one or more states.7 Average annual consumption for a residential utility customer is approximately 11,000 kWh.8 The bill subjects mercantile customers who opt out to the same requirements and restrictions as the large?usage customers who can already opt out. These requirements and restrictions include (1) providing the EDU a detailed notification of the intent to opt out, (2) submitting periodic reports 'to the PUCO on the projects, actions, policies, or practices that the customer implements to reduce energy intensity, and (3) time limitations on when the customer can opt back in.9 Baseline exclusion The bill modifies the law so that all customers who opt out of an EDU's energy efficiency and peak demand reduction portfolio plan are to be excluded from the baselines used for determining the actual amounts for the energy ef?ciency and peak demand reduction requirements. Customers who can already opt out are already required to be excluded from the baseline. The bill adds the mercantile customers who may opt out beginning in 2019. The effect of these baseline exclusions is that the requirements for energy ef?ciency savings and peak demand reduction would be reduced proportionately to the baseline exclusions. Without exclusions, the baselines would be the average of the total sold by the EDU in the preceding three calendar . years.10 Using a 1% energy savings requirement as an example, if the three-year average (without exclusions) is 100 million kWh, but customers who opt out account for sales of 6 RC. RC. not in the bill. 7 RC. not in the bill. 8 US Energy Information Administration, "How much electricity does an American home use?" available at: eia.gov/tools/faqs/faq. 9 RC. 49286612, 49286614, and 49286616, not in the bill. 10 RC. and Legislative Service Commission R-132-0194-2 20 million kWh, then the savings requirement becomes of 80 million kWh, or 800,000 kWh, rather than 1% of 100 million kWh, or 1 million kWh. Renewable energy Requirements changed to permissive provisions The bill permits, rather than requires, EDUs and electric services companies (ESCs) to provide certain portions of their electricity supplies from renewable energy resources, subject to a 3% cost cap (see COMMENT 2). Specifically, the bill states that an EDU may, subject to the cost cap, provide from renewable energy resources a portion of the electric supply required for its standard service offer. And it states that an ESC may, subject to the cost cap, provide a portion of its electricity supply for Ohio retail consumers from renewable energy resources. These resources are defined as "qualifying renewable energy resources.? The term encompasses a long list of resources in continuing law unchanged by the bill solar, wind, hydroelectric facilities, geothermal, biomass, and many others). But to be "qualifying renewable energy resources,? some of the resources must meet certain date restrictions on when the resources were placed in service, modified, or retrofitted.11 The bill further states that, subject to the cost cap, the portion may equal 12.5% of a baseline and may be generated in accordance with the following benchmarks: 2017 3.5% 0.15% 2018 4.5% 0.18% 2019 5.5% 0.22% 2020 0.5% 0.26% 2021 7.5% . 0.3% 2022 8.5% 0.34% 2023 9.5% 0.38% 2024 10.5% 0.42% 2025 11.5% 0.46% 2026 12.5% 0.5% These benchmarks and the 12.5% portion amount are currently required of EDUs and ESCs. Current law also requires that the 12.5% benchmark be maintained 11 RC. 4928.142, and 4928.20; R.C. not in the bill. Legisiative Service Commission 9- R'l 32411942 indefinitely by EDUs and ESCs on an annual basis after 2026. The bill neither expressly permits nor requires any benchmark to be achieved after 2026.12 There is currently an annual compliance review by the PUCO and forfeitures that are imposed if the annual benchmarks are not met. Because the bill makes these benchmarks permissive, it removes the provisions governing the compliance review and forfeitures.13 But the bill retains, for the 2016 compliance year only, the current authority to conduct a compliance review and impose forfeitures.1ch Under current law, forfeitures from noncompliance with the current renewable energy requirements (that the bill removes) contribute to funding for the Advanced Energy Program administered by the Department of Development Services.15 The bill permits the qualifying renewable energy resources to be either facilities located in Ohio or resources that can be shown to be deliverable into Ohio (see COMMENT 2). This is a requirement in current law.16 3% cost cap While the bill permits EDUs and ESCs to provide certain portions of their electricity supplies from renewable energy resources, as explained above, it does so subject to a 3% cost cap. Specifically, the bill prohibits an EDU and BBC from providing a portion of its electricity from qualifying renewable energy resources if the or ESC's cost of providing that portion from those resources exceeds the EDU's or ESC's reasonably expected cost of otherwise producing or acquiring the same amount of electricity by 3% or more. The cost of providing the portion from qualifying resources must be calculated as though certain tax and assessment exemptions had not been granted. As long as the cost of providing the portion from qualifying renewable energy resources does not exceed the cost cap, the bill expressly permits EDUs and ESCs to exceed the benchmarks outlined above (see COMMENT 2). 12 RC. and (2). 13 RC. 14 Section 5. 1'5 R.C. 4928.61 and 4928.62. 16 RC. Legislative Service Commission -10? The same 3% cost cap limits and obligations to comply with the renewable energy benchmarks under current law.17 Force majeure provision The bill retains a provision of current law that allows an EDU or BBC to request a force majeure determination with the PUCO for the reduction of a renewable energy benchmark when there are insufficient resources available for the EDU or ESC to comply with the benchmark. But since the bill makes the benchmarks permissive rather than mandatory, the force majeure provision will likely be moot.18 Customer opt out The bill permits, beginning January 1, 2019, any customer paying any rider, charge, or other cost recovery mechanism designed to recover the or cost of providing electricity from qualifying renewable energy resources (see COMMENT 3). The bill requires the PUCO to adOpt rules by January 1, 2019, governing the customer opt out. But the bill does not provide any parameters for what the rules should include.19 The bill de?nes the baseline for the 12.5% portion and the benchmarks to exclude customers who opt out of paying the rider, charge, or other cost recovery mechanism (see COMMENT 4). The baseline is currently the average of total sold by the EDU or ESC in the preceding three calendar years.20 Recovery for long-term contracts The bill requires continued recovery from customers of ongoing costs associated with contracts to procure resources to comply with the current renewable energy requirements, if those contracts were entered into before the bill's effective date. Currently, the same continued recovery is permitted for contracts entered into before April 1, 2014. The bill merely extends this date to cover contracts entered into between April 1, 2014, and the bill?s effective date. Under continuing law, recovery is limited to costs associated with the original term of the contract. Recovery is not permitted for 17 RC. 18 RC. 19 RC. and (C). 20 RC. 4928.643. ij Legislative Service Commission -11- R?i32?0194?2 contract extensions, or for contract amendments if those amendments were made after the bill's effective date.21 The bill specifies that customers cannot opt out of cost recovery for these contracts.22 Renewable energy credits The bill permits EDUs and ESCs to use renewable energy credits to provide electricity from qualifying renewable energy resources. Under current law, EDUs and ESCs are permitted to use these credits for the purpose of complying with the renewable energy requirements. The bill does not alter current restrictions on when credits may be used or how credits are calculated and registered.23 Disclosure of customer costs on bills The bill requires, by January 1, 2018, the PUCO to adopt rules governing disclosure to customers of the costs of electricity provided after the bill's effective date from qualifying renewable energy resources. The rules must require that every EDU and ESC list, as a distinct line item on the customer's bill, the customer's individual cost for the applicable billing period. The bill also requires, by January 1, 2018, the PUCO to adopt rules governing disclosure to customers of any costs still paid by customers for the current renewable energy requirements, including costs associated with long?term contracts entered into before the bill's effective date (see "Recovery for long-term contracts," above). The rules must also require that EDUs and ESCs list this cost as a distinct line item for the individual customer and applicable billing period. Current law required, by January 1, 2015, the PUCO to adopt rules governing the disclosure to customers of and costs of compliance with the current renewable energy requirements, as well as costs of compliance with the current energy efficiency and peak demand reduction requirements. As of the date this analysis was written, those rules have not been adopted. The bill changes this date to January 1, 2018, which effectively gives the PUCO a new deadline for adopting the rules regarding customer cost disclosure for energy efficiency and peak demand reduction.24 21 RC. 4.928.641. 22 no 492864703). 23 RC. 4928.645. 24 RC. 4928.65. Legislative Service Commission 42- Reports and testimony Utility and company reporting requirement The bill requires every EDU and ESC to submit an annual report for the prior calendar year to the PUCO not later than July 1 of each year. For an EDU, the report must detail the EDU's status of compliance with the energy ef?ciency and peak demand reduction provisions. For EDUs and ESCS, the report must detail the amount of electricity that the EDU or ESC provided from qualifying renewable energy resources during the calendar year covered by the report. The report is required for every year beginning with the July 1, 2018 report, even if the energy efficiency and peak demand reduction requirements for the year covered by the report are not true requirements. The bill also requires the PUCO to modify its rules in accordance with the reporting requirement, including the filing date.25 PUCO reports Renewable energy The bill makes changes regarding the amual report that the PUCO is currently required to make to the General Assembly on renewable energy. First, the bill requires a report to be made by August 1 of each year (beginning in 2018). Current law requires an annual report but does not specify a date. Second, the bill requires the report to detail the amount of electricity provided by EDUs and ESCs from qualifying renewable energy resources during the year covered by the report, based on the information provided in the and reports to the PUCO. (The bill repeals a provision requiring the report to detail EDU and ESC compliance with the current renewable energy requirements.) Third, the bill repeals a provision requiring the PUCO to allow and consider public comments on the report prior to its submission to the General Assembly. Fourth and ?nally, the bill repeals a provision specifying that nothing in the report is binding on any person.25 Energy efficiency and peak demand reduction The bill requires that the PUCO's annual report of EDU compliance with the energy efficiency and peak demand reduction provisions must be based on the reports to the PUCO, as well as any other information that is public. Continuing law requires this report to be produced and docketed at the PUCO, with a copy provided current law) and Legislative Service Commission ?13? R-132-0194-2 the Ohio Consumers? Counsel.27 Current law does not specify a date by which this report must be produced. The bill also requires the August 1 report on renewable energy, discussed above, to include EDU compliance with the energy efficiency and peak demand reduction provisions. It is unclear whether this is the same report as the compliance report that is currently required. (See COMMENT 5.) The bill requires the portion of the August 1 report that details EDU compliance With the energy efficiency and peak demand reduction provisions to be based on the reports to the PUCO (but it does not specify ?any other information that is PUCO testimony . . . The bill requires the PUCO Chairperson to provide testimony on the August 1 report to the standing committees of both houses of the General Assembly that deal with public utility matters. The testimony must be provided by September 1 of the same year.29 Bypassability of generation costs The bill expressly states that an EDU's costs for providing generation service, including all costs of providing electricity from renewable energy resources, are bypassable by any consumer that shops for an electric supplier. The bill also clarifies that an EDU's electric security plan must be consistent with this bypassability requirement.30 The bill repeals a similar provision that makes an costs incurred in complying with the current renewable energy requirements bypassable by customers . that shop.31 27 R.C. 4928,6603). 28 RC. 4928662003). 29 RC. 3? R.C. 4928.031 and 31 RC. 49286403) (as in current law). Legislative Service Commission ?14? Funding for home weatherization services The bill changes allocations for federal funds from the Home Energy Assistance Block Grant. However, due to the effective date of the changes, they will likely have no effect. These funding allocations are governed by appropriation language in the budget bill, which is in effect only for the current ?scal biennium, ending June 30, 2017. The effective date of the bill's changes is June 30, 2017. The funding allocations could be revised differently in the next budget bill, expected to take effect July 1, 2017.32 I Under the current budget, about 15% of the federal block grant funds are set aside for weatherization projects for individuals eligible for the Home Energy Assistance Program (HEAP) below 175% of the poverty line. HEAP is administered by the Development Services Agency (DSA). The rest of the funds are used for home heating assistance??3 This 15% allocation for weatherization is allowed under federal HEAP guidelines. However, the federal guidelines allow states to apply for a waiver to raise the set?aside for weatherization to a maximum of 25%.34 The bill requires DSA to allocate the full 25% for weatherization and apply for the federal waiver.35 Repeal of uncodi?ed law enacted by 8.8. 310 The bill repeals uncodified sections that were enacted by Sub. SB. 310 of the 130th General Assembly. These sections governed customer?opt?out provisions and energy efficiency and peak demand reduction portfolio plans, but the applicability of the sections ended in 2016.36 COMMENT 1. The bill requires an EDU to be deemed in compliance with the energy efficiency and peak demand reduction savings requirements and to be eligible for PUCO?approved incentives in any year in which the ?actual cumulative energy efficiency and peak demand reduction savings" meet or exceed the "cumulative 32 Sections 7, 8, and 9; Section 257.80 of Am. Sub. H.B. 64 of the 1313t General Assembly. 33 Section 257.10 of Am. Sub. H.B. 64 of the 1315t General Assembly, not in the bill; Home Energy Assistance Programs, available at: heaphtm. 34 Catalog of Federal Domestic Assistance, Program Information, available at: Office of Community Services, (it As for Professionals, available at: 35 Sections 7, 8, and 9; Section 257.80 of Am. Sub. H.B. 64 of the 1315t General Assembly. 36 Sections 3 and 4; Section 6 of Sub. SB. 310 of the 130th General Assembly. Legislative Service Commission -15- R-132-0194-2 mandates" under provisions governing energy efficiency and peak demand reduction.37 The bill is unclear as to whether PUCO-approved incentives are the same as shared savings. 2. Under current law, EDUs and ESCs are required to provide power from qualifying renewable energy resources at certain percentages. The bill, on the other hand, permits them to provide power from these resources at the same percentages (ending with 12.5% by the end of 2026). The bill also permits the qualifying renewable energy resources to be either facilities located in Ohio or resources that can be shown to be deliverable into Ohio. The EDUs and ESCs arguably do not need legal permission to provide power currently from renewable energy resources. Giving them permission to do what they already can do, but at specific levels and with specific renewable energy resources raises questions about the full implications of these changes. For instance, it is unclear whether EDUs and ESCs would still have the authority to: Provide power from renewable resources that do not meet the definition of a "qualifying renewable energy resource"; 0 Provide power from renewable energy resources that are neither located in Ohio nor deliverable into Ohio; 0 Recover the cost of providing power from qualifying renewable energy resources at percentages that are lower than the benchmarks; and Recover the cost of providing power from qualifying renewable energy resources beyond 2026, since the benchmarks end with that year?"8 3. The bill permits all customers to ?opt out of paying any rider, charge, or other cost recovery mechanism designed to recover the costs of [an EDU's or provision of electricity from qualifying renewable energy resources.?39 It is unclear what, exactly, customers who opt out would avoid paying for under this provision. The broad terminology could be interpreted to allow customers who opt out to avoid paying for any portion of an EDU's or ESC's electricity supply that is provided from qualifying renewable energy resources, even if that customer is still receiving electricity generated from those resources. 37 RC. 4928.6621 (B). 38 RC. and (2), (C), and (D), 4928.142, and 4928.20. 39 RC. Legislative Service Commission -16? R-?i32?0194?2 4. The bill permits EDUs and ESCs to use a baseline for the renewable energy percentages even though that baseline is a requirement under current law. The bill states that an EDU or BBC "may provide from qualifying renewable energy resources. . . a portion of its electricity supply," and ?[t]hat portion may equal of the baseline."40 The effect of not requiring EDUs and ESCs to use this baseline is that any adjustments that are supposed to be made to the baseline may not actually have any effect. And the bill attempts to exclude from the baseline customers who opt out of paying any rider, charge, or other cost recovery mechanism for qualifying renewable energy resources.41 Therefore, this attempt at excluding the opt?out customers from the baseline may not actually have the effect of changing actual amounts achieved by EDUs and ESCs. 5. The bill is unclear as to how many reports the PUCO must make regarding EDU compliance with the energy efficiency and peak demand reduction provisions. Continuing law, largely unchanged by the bill, requires the PUCO to produce and docket an annual report containing verification of the annual levels of energy efficiency - and peak demand reductions achieved by each EDU. A copy of this report must be provided to the Ohio Consumers Counsel. But the bill, in a separate provision, requires the PUCO to submit a report to the General Assembly by August 1 of each year detailing EDU compliance with the energy efficiency and peak demand reduction provisions. If it is determined that only one report is required, it would be unclear whether the report must be based in part on public information. This is because the bill requires that the currently required report must be based in part on public information. But the bill does not require this for the August 1 reportst2 RUIQ?l?Z-lBZdomdks 40 RC. 4'1 RC. (emphasis supplied). 42 RC. and 4928662003). Legislative Service Commission ?17? Rep29 From: Sent: Wednesday, February 22, 2017 5:08 PM To: Rep82 Cc: Romanchik, Kelsey; Rep29; Benjamin, Abigail Subject: Attachments for Your Review Attachments: Green Link Report Reaponsedocx; RE: Oct. 12 Email; EMSC Report. Craig, Please review the enclosed attachments as a preview of our meeting. My staff will contact yours to get this set up. would also like you to watch my two floor speeches on HB 554 from last year. Just follow the link below and then click on my name that appears in the HB 554 category and it will take right to the second i start. :39&end:51:54 Thanks, Bill Committees William I. Seitz Public Utilities, Chair State Senator State Government Oversight and Reform, 8?1 District Vice Chair Civil Justice Ohio Senate Criminal justice Columbus, Ohio 4-32 1 5 Energy and Natural Resources 614-466-830 68 State and Local Government Finance Correnctions Subcommittee MEMORANDUM To: Iosh Knights Leo Almeida From: Senator Bill Seitz Date: November 8, 2016 Re: Green Link Report Thank you for sharing the Green Link report, which i have now reviewed in detail. I appreciate that those who commissioned this report are willing to engage in a revisitation of the arbitrary numbers that were included in the original SB 221. l. Assessment of the three scenarios While I do not agree with any of the three scenarios outlined in the report, of the three that are presented, 1 would prefer the Accelerated Efficiency-scenario mainly for three reasons. First, the report consistently understates the cost of renewables, as to get a real feel for their costs, one would have to add back in the 30% per kilowatt hour tax credit with which renewabies are favored for at least the next five years. While these tax credits do not have a bill impact, the fact of the matter is that the cost of these credits is footed by the American taxpayer (or by their children and grandchildren who inherit the national debt that grows by reason of the tax credits). Therefore, any scenario that deemphasizes renewable mandates, at least as long as renewables are supported by a lavish tax credit, makes more sense to me. Second, the report assumes in all its discussion of renewables that the current wind farm siting rules are ?modified? and in our meeting you indicated the assumed modification is a complete revision to pre- 2014 rules. That is simply not going to happen and I would refer you to my comments on the Ohio Environmental Council?s comments on the current Ohio Power Siting Board proposed rule docket for an explanation of why Ohio?s setback rules are not out of the mainstream. Third, energy that is not used at all (energy efficiency) is the ultimate best choice because it avoids the production of the energy in the first place. All forms of electricity fuel have their drawbacks and risks to human and to animal and plant health, so rather than pick winners and losers in terms of one?s favorite electricity fuel du jour, policies that cost effectively improve energy efficiency are preferred. II. Methodological flaws in the models in all three scenarios 1 will focus on the data regarding the Accelerated Efficiency scenario to demonstrate the methodological flaws in all three scenarios. The only difference in the scenarios is the relative weight placed on renewables and ef?ciency, but the models are the same. Close analysis of the charts on pages 20-21 reveals the report projects a net benefit over cost by 2030' of $5.1 billion under the accelerated efficiency scenario. However, given that the public health savings component is $607 million in 2020 and $1530 million in 2030 it is quite evident that the entirety of the net benefit is in impudent ?public health savings.? This much is also clear from figures 3.8 and the discussion at pages 1617 of the report. This is not to discount the importance of public health savings. It is, however, to point out that because the report nowhere focuses on using natural gas in lieu of renewables or efficiency, and because natural gas offers the same or similar emission reductions, we simply do not know from this report the extent to which reliance on Ohio?s copious quantities of natural gas would achieve similar public health benefits at far less cost. We do know that natural gas costs less, and figure 3.7 on page 16 clearly discloses that there is no positive bill impact posited by the report until after 2025. indeed, table 3.4 on page 21 clearly discloses a net gigs; of $2.73 billion in 2020 were the accelerated efficiency scenario to be adopted. Nor does the report appear to explain the basis for its generous iteration of public health benefits beyond saying it relies on ?an advanced public health econometrics database? (p.16) that calculates and prices ?pollutant damages that are height and locationally dependent? The report also discloses (p.52?53) that the source of the public health savings in all three scenarios ?a re predominately derived from reductions in generation at the largest coal plants in the state.? Again, the report?s failure to model any of its scenarios against a natural gas based plan is a serious flaw?especially given that numerous combined cycle gas plants aggregating billions of dollars of investment are already under construction in Ohio. Even assuming that the public health benefits have been correctly calculated, it is methodological error to include them. This is because?these benefits presumptively accrue to a population encompassing all of Ohio (and perhaps even beyond Ohio), whereas the cost is imposed only on Ohio retail customers of investor owned electric distribution companies. Remember, neither Ohio municipal electric companies nor Ohio rural electric cooperatives are subject to the mandates. It is therefore unfound to compare costs imposed on a smaller population with benefits enjoyed by a much larger population that is essentially getting a free ride. Much of the report addresses how each scenario would put Ohio on a path toward achieving Clean Power Plan (CPP) compliance by 2030. While this is certainly a relevant consideration, it is also an exercise in conjecture. We do not know whether and to what extent CPP survivesjudiciai scrutiny, nor what the state of Ohio may submit by the way of a state plan. For that matter, significant questions remain as to the final contours of a Federal implementation plan (FIP) and as to definitive guidance (which necessarily awaits the outcome of the court cases) as to when the CPP rule becomes effective, when states must submit a plan, what may ?count? for ?extra credit? ?and when?under the clean energy incentive program part of the CPP, and other such unknowns. Therefore, choosing any of the three scenarios at this time is terribly premature and a highly speculative effort to predict currently unknown factors. Finally, while the report claims to model ?the baseline case? entailing ?an extended freeze? of the standards, that baseline case is never clearly described or modeled. Assuming the ?extended freeze? runs through 2030 (and it is-not clear that is what is meant), then it is a rather meaningless comparison because neither SB 320 (as introduced) nor the substitute bill (with which you are familiar) does that. What would?ve been more instructive was a comparison of the three scenarios against a ?baseline case? as presented by SB 320 or its substitute version. For that matter, the report also is deficient in failing to model of a resumption of the SB 221 mandates (as modified by SB 310) against the three scenarios that were presented. My guess is that any of those comparisons would show that the SB 320 model produces even more ?benefits? of the kind counted in the report?s three scenarios than does any of the three scenarios against a ?baseline case? that does not exist. Ill. Comments on the Recommended "Market Based Reforms? The report also makes five recommendations for ?market?focused reforms.? 1. Ensure all electricity generator incumbents do not receive unfair advantages over new competitors While I agree with this, the fact is that all electric generating technologies are now wholesale market competitors. The fact is that the newer competitors (wind and solar) are receiving subsidy and tax credit advantages that their older competitors do not receive, and to an extent greater than those older competitors historically received. 2. Modify the wind farm siting rules that block development By way of response, enclose the comments i submitted to the Ohio Power Siting Boa rd (OPSB) regarding the Ohio Environmental Council?s comments on the proposed OPSB rules on wind turbine siting and an email I recently sent outlining some areas where the wind farm siting rules and statutes might warrant modifications. However, to the extent Green Link is assuming that we will revert to the previous 2014 setback rules, which were insufficiently protective of the property rights of nonparticipating adjacent land owners, I doubt that that is going to happen. 3. Allow on~bill repayment to spur investments in energy efficiency proiects To the extent you advocate for more financing options, I agree with you. The one that favor, i however, is property assessed clean energy (PACE), additional steps towards which are taken in my Senate Bill 185 which has passed committee and awaits a floor vote. The problem with on? bill repayment is it forces unwilling regulated electric distribution companies to bill and collect for third-party suppliers of energy efficiency projects, which then raises a host of problems as to what level of compensation these are to receive for acting as the billing agent of unaffiliated suppliers. 4. Adopt a market for energy efficiency credits Philosophically, I agree with this recommendation and have a fair volume of correspondence trying to iron out the details. My information is that in the few states where this concept has been implemented, it was both expensive to create and resulted in low participation. Moreover, there are a host of definitional and technical questions that crop up, such as defining what counts as energy efficiency for purposes of an energy efficiency credit and whether the regulated EDUs would receive lost distribution revenues. While a renewable energy credit is easily defined, energy efficiency comes about through a diverse menu of technologies that do not lend themselves to a standard credit definition. 5. Maintain and promote volumetric electric rate structures that incorporate price signals While I do not know enough about this to have a firm opinion, lam told that such structures inadequately account for the fixed costs involved in producing and distributing electricity. That is why current rate structures contain a customer charge, a demand component, and an energy component. Finally, I endorse the commentary at page 56 of the report that applauds market based policies for all the reasons there stated. However, for these very reasons, the report is at odds with itself. You cannot square a full?throated endorsement of market-based policies with an equally full-throated endorsement of maintaining a robust renewable portfolio standard or a robust energy efficiency standard. These statutory and regulatory mandates are the very antithesis of market?based policies, as they allocate market share to particular favored supply or demand side winners and losers. traitnr munn . 31% . . .. .u tail . . .L . dinr??lfu In; 2% 5mg} . i. ?hu? an .E. riS?Tu . . a Wn??m??n e: 5 f??rrz. $33.9; {a The purpose of this report is to compare the cost of electricity from existing generation resources with the cost from new generation resources that might be constructed to replace them. To date, the tevelized Cost of Electricity from New generation resources has been the primary focus of "cost of electricity" comparison studies and debates. Our new calculation of levelized cost from existing resources offers policymakers a more accurate depiction of the tradeoffs involved in industry. is based on data from two government sources Federal Energy Regulatory Commission Form and Energy information Administration 860. Decision makers often compare levelized cost of electricity from various types ofnew power plants that might be built to Serve society in the future. One such comparison, a part ol? the Annual Energy Outlook (AEO) 20M 20l5), includes a projection for the LCOE from new generation facilities that could be brought online in 2019. BA de?nes LCOE as ?the per-megawatt?hour cost (in real dollars) of building and operating a generating plant over an assumed ?nancial life and duty cycle.?1 ElA?s estimates of LCOE are the most widely accepted and commonly used version of the methodology. comparisons can be quite useful ifthey encompass a wide range oF likely alternatives. However, one otthe clear de?ciencies of most reports has been the absence ofany information about cost of electricity from existing generation resources, even though those resources supply all of ourelectrigity todayand most of them could continue to supply reliable electricity at the lowest-cost for decades to come. On the other hand, if regulators or lawmakers induce power. plants to retire earlier than they would have otherwise, the price otelectricity must increase to pay forthe incremental cost of replacement capacity, Because electricity is an essential input to nearly all goods and services, replacement of operationally sound, least cost: electricity producing power plants with new ones that produce electricity at a- higher levelized cost comes at a cost which must be borne and allocated across the domestic economy. This report on the cost of electricity from existing generation resources provides a baseline from which policymakers can assess the cost of replacing existing plants with new ones. . Our analysis is based on data reported to federal government agencies, EIA and FERC. The data suggest that almost all existing power plants have lower ?xed costs than and similar variable costs to their most likely replacements. The primary reason new power plants have higher LCOE is because they begin their operational lives with a full burden ofconstruction debt and equity investment to repay. Since existing power plants have already repaid some or all of those obligations, th eir ?xed costs going forward are lower. To the extent power plants of the same type outlive their "mortgages," they enioy far lower ?xed costs of operation and thus are likely to be capable of supplying electricity at a lower cost overall. Data sources mined for this report indicate that for all major generation resources, the fleet-average cost of electricity from existing power plants is less than the ?eet-average cost ofe?l?ctn?city from new p;ower plants of the same type. We also examine a best-case magenta forlnew plants u?singa hypothetically achievable capacity factor that is higher than observed data. Table i summarizes these ?ndings. At 20M fuel prices, the iowest cost new resource is combin ed cycle natural gas (CC gas). Because the replacement of existing coal with new CC gas capacity is the most common real world scenario today, GENERATOR TYPE the fleet average costs of electricity from these two resources are highlighted yellow in Table i. All ?gures are shoWn in 203 2 DISPATCHABLE RESOURCES Conventional Coat}. 3 i?tuciear3 ro (seasonal) Conventions! Combined Cycle Gas (CC gas}3 ?3 DISPATCHABLE PERKINS RESOURCES Cooventionat Combustion Turbine Gas (CT gas} RESOURCES AS USED iN PRACTICE Wind inctuding cost imposed on CC gas Existing LCOE New (on) New (to) as found in as adjusted -.- as adiosted FERC Form} by the Report i by the Report fleet avg best case (51A ?eet avg 2012 2032 2012 38.4 . 30.0 97.? 48.9 65.3 73.4 29.5 92.? 34.2 34.5 no142.8 128.4 i 352.} 96.2 112.3 i +other costs? +other costs? . 5 .. "Other costs? could odd $25 - $50 per i?itiWh and include transmission costs and subsidies not considered by in their calculation of Furthermore, opporentty mode no distinction between the 20 25 year expected lifespons of wind and solar facilities vs. the 50+ year lifespons of most other technologies. See the following publications: docs/5r? iosti/47078pdf, i734. Tablet shows ieveiized cost oteiectricity from existing resources (LCOE-E) in column 3, as derived using the FERC Form 3 database. EiA?s estimate of the leveiized cost of electricity from new generation resources for units becoming operational in 2019 is shown in Columns 2' and 3 and broken down in two ways. Coiumn 2 re?ects ?xed costs per as calculates them (using "best case single plant" and "simple average of marginal units? capacity factors for dispatchable and non-dispatchable resources, respectively) and Column 3 uses actual (observed) ?eet average capacity factors substituted for best case capacity factors:i Capacity I factor is the average output of a plant or ?eet over time divided ,..:bythe theoretical maximum output of that plant or fieet, and is listed as ai?percenta gait-?or exarn pie, the {neasured ?eet average capacity factor for existing conventio nai coat plants in 2014 was 60.9 percent? As Tabie 1 makes clear, the cost advantage of existing resources over new sources is pronounced. These?cost advantages are most evident when comparing existing sources against: i) new sources with high capitai costs, such as coal, nuciear, wind, and hydro; or 2) new sources with low capacity factors, such as simple-cycle Combustion Turbine natural gas "peaker? piants (CT gas} and wind. Environmental Regulations Subsidies and Mandates for Renewabies are Driving Most New Generating Capacity Construction, Not . New Electricity Demand The reason the cost of generation from existing sources is - sojmfaoftant is that government i'handates, regulations and subsidies (not additionai demandiare driving the construction of new generation resources. LEVELIZED COST OF GENERATOR TYPE cowennowm com in u-unul CYCLE GAS (cc ens} NUCLEAR convannonm comaus?nonwm GAS {cr ens} WIND COST IMPOSED ON CC GAS FERC Form 1 and 860 show that: in the absence of mandates, subsidies and regulatory compliance costs, the cost of electricity from almost all existing generation resources wilt remain less than the cost of electricity from their likely repiacements for at least the next 10 to 20 years. In fact, in their 20M State of the Market report to FERC, grid operator PJM's independent Market Monitor stated that: ubsidies in the form of additional out of market revenue is not consistent with the PJM market design, The result would be to arti?cially depress prices in the capacity market. This would negatively affect the incentives to build new generation and would likely result in a situation where onty subsidized units would ever be bunt.? From 2004 through 20M, electricity demand in the United States increased by an average of0.3% percent per year? Absent mandates for new generation and the onset of new federal environmental regulations forcing some coal ?red :generating capacity as retireaimost'no new'gije?neration capacity wouid have been necessary over that ten year period. FLE E'i' AVG. L?u?iO RANGE OF (NEW) AT BEST CASE FACTOR AT REAL WORLD FACTOR MEN COST PREMEUM T0 REPLACE COAI. NEW CC GAS $l00 $200 COST Longevity ofthe Existing Fleet Forms 1 and 860 data indicate that most existing power plants could remain economicaiiy viable for years or decades beyond their current age. While existing resources remain our lowest cost option, regulatory compliance costs and arti?cial "wholesale price suppression" brought about by subsidizing and mandating higher cost and lower vatue technologies causes low-cost existing dispatchable resources to operate at a ?nancial loss. These external in?uences are not consistent with market design. The result is that some existing resources may be operating at a net ?nancial loss even while their likely replacements would produce electricity at a substantially higher cost. 3 The lowest possible electricity rates wit! only be achieved by keeping existing generating resources in operation until their product becomes uneconomic relative to the levelized cost of electricity from new sources that wouid re place them. LLoviqzost natural gasjsanother factor influencing the - I retirement of coal (and even some nuclear) capacity. Competitive marginal prices for CC gas energy place downward pressure on clearing prices, which in turn reduee the revenues accruing to all technologies, A properly valued and functioning capacity market should result in capacity marl-let clearing prices suf?cient to carry existing capacity contributors (in this case coal and nuclear) through any short? term reduction in gross margin and/or capacity facton To date, however, even our most sophisticated grid operators such as PM are struggling to arrive at appropriate capacity market rules. Conclusion Most existing coal, natural gas, nuclear, and hydroelectric generation resources could continue producing eleCtricity for decades at a far lower cost than could any potential new generation resources. At a coal~?red power plant, for example, when a component wears out, only the component must be replaced, not the entire plant The same is true for nuclear plants, until they reach their regulatory and of life, which is currently defined to be 60 years but could be extended to 80.9 Under current laws, rules, and regulations, large amounts of generating capacity is slated to retire and will be replaced with new generating capacity which will produce electricity at a far higher average levelizecl cost. The institute for Energy Research recently identi?ed more than ii 0 SW of coal and nuclear generation capacity set to close as a direct result of federal regulations. 1'9 Of course, substitutions of natural gas for coal could work for only some fraction of existing coal electricity before substantial and expensive increases in natural gas infrastructure would be required. Even then, the system would be more vulnerable to natural gas supply shortages and price increases. When electricity from an existing electric generating plant costs less to produce than the electricity from the new plant technology expected to be constructed to replace it~and yet we retire and replace the existing plant despite the higher costs?ratepayers must expect the cost of future electricity to rise faster than it would have if we had instead kept existing power plants in service. An unprecedented amount of generating capacity is set to close due to ongoing renewables policies, undervalued capacity markets, currently low natural gas prices, and additional environmental regulations. in the absence of even some of these factors, most existing power plants would remain operational, helping keep electricity costs low for many years or decades into the future. The Ohio House . The Ohio Senate of Representatives The Energy Mandates Study Committee Co?Chairs? Report State Representative Kristina Roegner, Co-Chair State Senator Troy Balderson, Co-Chair September 30, 2015 II. TABLE OF CONTENTS INTRODUCTION 1 FINDINGS OF THE STUDY COMMITTEE 3 RECOMMENDATIONS 11 Recommendation #1 11 Recommendation #2 13 Recommendation #3 13 Recommendation #4 15 Recommendation #5 16 I. INTRODUCTION The Energy Mandates Study Committee (the ?Study Committee?) was created by Substitute Senate Bill No. 310 of the 130th General Assembly (?813310?). The Study Committee consisted of a bipartisan panel of members of both the Ohio House and Senate and the chairperson of the Public Utilities Commission of Ohio SB310 tasked the Study Committee with studying Ohio?s renewable energy, energy efficiency, and peak demand reduction mandates (collectively, the ?Mandates?) enacted into law by Amended. Substitute Senate Bill No. 221 of the 127th General Assembly By September 30, 2015, SB3 10 requires the Study Committee to submit a report of its ?ndings to the House and Senate that includes, at a minimum, the following: 1. A cost-bene?t analysis of the renewable energy, energy efficienCy, I and peak demand reduction mandates, including the projected costs on electric customers if the mandates were to remain at the percentage levels required under sections 4928.64 and 4928.66 of the Revised Code, as amended by this act; 2. A recommendation of the best, evidence-based standard for reviewing the mandates in the future, including an examination of readily available technology to attain such a standard; 3. The potential bene?ts of an opt-in system for the mandates, in contrast to an opt-out system for the mandates, and a recommendation as to Whether an opt-in system should apply to all electric customers, whether an opt?out system should apply to only certain customers, or whether a hybrid of these two systems is recommended; 4. A recommendation on whether costs incurred by an electric distribution utility or an electric services company pursuant to any contract, which may be entered into by the utility or company on' or after the effective date of SB310 for the purpose of procuring renewable energy resources or renewable energy credits and complying with the requirements of section 4928.64 of the Revised Code, may be passed through to any consumer, if such costs could have been avoided with the inclusion of a change of law provision in the contract; 5. A review of the risk of increased grid congestion due to the anticipated retirement of coal?fired generation capacity and other factors; the ability of distributed generation, including combined heat and power and waste energy recovery, to reduce electric grid congestion; and the potential bene?t to all energy consumers resulting from reduced grid congestion; 6. An analysis of whether there are alternatives for the development of advanced energy resources as that term is de?ned in section 4928.01 of the Revised Code; 7. An assessment of the environmental impact of the renewable energy, energy ef?ciency, and peak demand reduction mandates on reductions of greenhouse gas and fossil fuel emissions; and 8. A review of payments made by electric distribution utilities to third-party administrators to promote energy ef?ciency and peak demand reduction programs under the terms of the utilities? portfolio plans. The review shall include, but shall not be limited to, a complete analysis of all ?xed and variable payments made to those administrator's since the effective date of SB221, jobs created, retained, and impacted, whether those payments outweigh the bene?ts to ratepayers, and whether those payments should no longer be recovered from ratepayers. The review also shall include a recommendation regarding whether the administrators should submit periodic reports to the Commission documenting the payments received from utilities. The Senate President and the Speaker of the House appointed the following members to the Study Committee: Senator Troy Balderson, co-chaz?r Representative Kristina Roegner, co?chairl Senator Cliff Hite Representative Ron Amstutz Senator Bob Peterson Representative Louis W. Blessing, HI Senator Bill. Seitz Representative Christina Hagan Senator Capri Cafaro Representative Jack Cera 2 Senator Sandra Williams Representative Mike Stinziano Andre T. Porter, in his capacity as the chairman of the PUCO, also served as an ex of?cio, nonvoting member of the Study Committee.3 From November 2014 through July 2015, the Study Committee conducted eight public hearings. All testimony from those hearings, and testimony separately submitted to the Study Committee, can be found on the Study Committee?s webpage at: 1 Replaced former co-chair, Representative Peter Stautberg, after his term of of?ce ended on December 31, 2014. 2 Replaced former Senator Shirley Smith after her term of of?ce ended on December 31, 2014. 3 Replaced former Chairman of the PUCO, Thomas W. Johnson, who served on the Study Committee from November 2014 through April 2015. II. FINDINGS OF THE STUDY COMMITTEE Historical Costs of Mandates Renewables Ohio?s electric distribution utilities and competitive retail electric suppliers providers?) are required to comply with Ohio?s renewable mandateiIL by purchasing renewable energy credits Ohio?s renewable mandate is bypassable, which means customers pay for the mandate by paying their electric provider. 6 While EDUS speci?cally bill customers the exact cost of the mandate, CRES providers simply account for all of their costs (including the mandate) in their price offerings? This is because CRES providers? rates are not set or approved by the PUCO. 8 The. most recent data the PUCO provided to the Study Committee on the cost of RECS in Ohio is from 2012,9 which illustrates that in-state RECS were more expensive than out?of?state RECs. 2012 Average Cost of RECSIO Ohio Electric Ohio Competitive Retail Distribution Utilities Electric Service Providers Category Avg. Avg. Ohio Solar $212.23 $195.93 Other Solar $53.75 $104.99 Ohio Non-Solar $3 3 .51 $13 .08 Other Non?Solar $24.93 $2.04 As of December 2014, the PUCO determined the average charge for the renewables mandate as $0.001142 per kilowatt hour,11 which averaged out to the following costs for each customer class:12 4 By 2026 and each year thereafter, EDUs and CRES providers must obtain at least 12.5% of its energy supply from renewables. 5 Thomas W. Johnson, PUCO Chairman, p. 3, Dec. 8, 2014. 5 Thomas W. Johnson, PUCO Chairman, p. 3, Dec. 8, 2014. Thomas W. Johnson, PUCO Chairman, p. 3-4, Dec. 8,2014. 3 Thomas W. Johnson, PUCO Chairman, p. 3?4, Dec. 8, 2014. 9 See DRAFT Alternative Energy Portfolio Standard Report by the Staff of the Public Utilities PUCO of Ohio for the 2012 Compliance Year, Iss'ued January 14, 2014 pursuant to R.C. (PUCO Case No. ACP). Pursuant to RC. the PUCO is required to submit an annual report to the General Assembly that sets forth whether EDUS complied with the renewables mandate, in addition to the average cost of RECS for the reporting year. The PUCO has not ?nalized the 2012 report that was due to the General Assembly in 2013. (see PUCO Case No. The PUCO has not drafted the 2013 report that was due to the General Assembly in 2014, but a case has been opened (see PUCO Case No. The PUCO has not drafted the 2014 report that was due to the General Assembly in 2015, nor has a case number been opened for that report. 1? Thomas w. Johnson, PUCO Chairman, Exhibit A, Dec. 8, 2014. Typical Bill Cost for Alternative Energy Rider (as of December 4, 2014) Dayton AEP Power Duke Energy FirstEnergy Light Columbus Cleveland Customer Southern Ohio Electric Ohio Toledo Class Power Power DPL Duke?Ohio Illuminating Edison Edison Mirage. $1.31 $0.77 $0.62 $0.27 $1.30 $1.01 $0.77 Resuiential Average 9 Commerci a1 $5 06.52 $98.65 $248.04 $109.20 $501.60 $388.20 $297.30 Average I Industrial $9,928.80 $5,854.20 $4,960.80 $2,184.00 $9,738.00 $7,5 36.00 $5,778.00 Note: Average Residential typical usage 750 Average Commercial typical usage 300,000 Average Industrial typical usage 6,000,000 The table above shows that in 2014 the average residential customer incurred a charge between $0.27 and $1.31 for the renewables mandate. Multiplying these numbers by 12 months in a year, the average residential customer would have paid between $3.24 and $15.72 for the renewables mandate in 2014. The actual costs paid by a customer for the renewables mandate in any given month is required to be placed on each customer?s bill.13 Energy Ef?ciency/Peak Demand Reduction Unlike the renewables mandate, Ohio?s energy ef?ciency and peak demand reduction mandates apply only to The costs associated with complying with the energy ef?ciency and peak demand reduction mandates are recovered by an EDU through a non?bypassable rider.15 That rider is recovered from all customers of an EDU regardlessof Whether they shop for electric .. .- generation with the exception of those mercantile customers that obtained a rider exemption from the PUCO pursuant to SB221.16 As of December 2014, the PUCO determined the average charge for the energy ef?ciency and peak demand reduction mandates as $0.007225 per kilowatt hour.? The PUCO only provided the range of the costs of the energy ef?ciency and peak demand reduction 11 Thomas W. Johnson, PUCO Chairman, p. 3, Dec. 8, .2014. 12 Thomas w. Johnson, PUCO Chairman, Exhibit B, Dec. 8, 2014. 13 SB310 required the PUCO to adopt rules that require the costs of each mandate to be placed on each customer?s bill. As of the date of publication of this Report, that rule has not yet been implemented. 1? Thomas w. Johnson, PUCO Chairman, 1). 4, Dec. 8, 2014. 15 Thomas w. Johnson, PUCO Chairman, p. 4, Dec. 8, 2014. 16 Thomas W. Johnson, PUCO Chairman, p. 4, Dec. 8, 2014. 17 Thomas W. Johnson, PUCO Chairman, p. 3, Dec. 8, 2014. mandates for residential customers, which ranged from 00189 to 004566 per kilowatt hour.18 The PUCO determined the average costs of the energy ef?ciency and peak demand reduction mandates for the following customer classes to be:19 Typical Bill Cost for Energy Ef?ciency and Peak Demand Rider (as of December 4, 2014) Dayton AEP Power FirstEnergy Light gy Columbus Cleveland Customer Southern Ohio Electric Ohio Toledo Class Power Power DPL Duke-Ohio Illuminating Edison Edison Average Residential $3.42 $3.42 $3.43 $2.58 $3.31 $2.37 $1.42 Average. $1,001.70 $1,001.70 $762.27 $501.00 $512.40 $582.30. $948.90 Commerclal Average . $5,719.80 $5,719.80 $13,050.60 $10,020.00 $5,076.00 $14,496.00 $15,606.00 Industrial Note: Average Residential typical usage 750 Average Commercial typical usage 300,000 Average Industrial typical usage 6,000,000 The table above shows that in 2014, the average residential customer incurred a charge between $1.42 and $3.43 for the energy ef?ciency and peak demand reduction mandates. Multiplying these numbers by 12 months in a year, the average residential customer would have paid between $17.04 and $41.16 for the energy efficiency and peak demand reduction mandates in 2014. As of December 2014, the PUCO found that the total amount of the Mandates averaged out to be the following percentages of customers total bills:20 Alternative Energy and Energy Ef?ciency/Peak Demand Rider as a Percentage of Estimated Total Bill (as of December 4, 2014) Dayton AEP Power FirstEnergy Light g" Columbus Cleveland Customer Southern Ohio Electric Ohio Toledo Class Power Power DPL Duke?Ohio Illuminating Edison Edison AYeragf' 3.61% 3.20% 3.64% 3.07% 4.75% 3.54% 2.25% Resrdential Average. 3.59% 3.09% 3.05% 1.96% 2.80% 3.04% 3.54% Commermal Average 2.47% 1.82% 2.96% 2.39% 2.63% 4.11% 3.89% Industrial 18 Thomas W. Johnson, PUCO Chairman, p. 4, Dec. 8, 2014 19 Thomas w. Johnson, PUCO Chairman, Exhibit C, Dec. 8, 2014. 2" Thomas w. Johnson, PUCO Chairman, Exhibit D, Dec. 8, 2014. Note: Average Residential typical usage 750 Average Commercial typical usage 300,000 Average Industrial typical usage 6,000,000 Future Costs of Mandates The Study Committee heard testimony from Ryan M. Yonk, of Utah State University. Dr. Yonk, along with ?ve individuals from Utah State University, published a comprehensive report in April 2015 entitled ?Renewable Portfolio Standards: Ohio.? That report concluded that Ohio renewables mandate Will lead to the following:21 Signi?cant increases in ?scal and economic costs between now and 2026 A 920, 000, 000 burden on Ohio ratepayers A $52, 000, 000 decrease 1n investment A decrease 1n personal disposable income of $258 million in 2026 An increase in the unemployment rate by 10%, which equates to 29,366 jobs The Study Committee did not receive any de?nitive data from the PUCO on the projected future costs of the energy ef?ciency and peak demand reduction mandates. In a letter from the PUCO to the Study Committee dated September 14, 2015, the PUCO stated that they do not currently have the capability to independently forecast the costs of implementing the energy ef?ciency mandates in future years with a high level of signi?cance. .21 Ryan Yonk, Utah State University, p. 8, July 20, 2015. Grid Congestion PJM Interconnection testi?ed at a Study Committee hearing about grid reliability and congestion. PM is the Regional Transmission Organization operating in Ohio. PJM testi?ed that there are adequate resources to meet the forecasted demand of customers plus a reserve margin.22 PJ also ensured the power grid will remain reliable with the retirement of generating plants because the PM forward capacity market is attracting new resources. As shown on page 4 of slide attachment,23 the PM capacity market has successfully attracted over 35,000 MW of new generation or upgrades throughout the PJM region, compared to the 26,000 MW in retirement notices to date. 22 Andrew Ott, PIM Interconnection Executive Vice President of Markets, p. 3, Mar. 18, 2015. 23 Andrew Ott, PM Interconnection Executive Vice President of Markets, slide 4, Mar. 18, 2015. 7 he Clean Power Plan On August 3, 2015, the United States Environmental Protection Agency released a ?nal version of its proposed Clean Power Plan a rule that sets performance rates and individual state targets for carbon dioxide emissions from existing power plants. Issued under the apparent authority of Section 111(d) of the Clean Air Act, the CPP seeks to reduce emissions by 32% nationwide by 2030, relative to 2005 levels.24 Each state is given speci?c targets under the final version of the CPP. Under a rate?based carbon reduction plan, Ohio would be required to reduce its carbon dioxide emissions by 37% between 2012 and ?nal implementation of the CPP.25 That mandated target was increased by roughly 11% from the US original proposed rule.26 As illustrated in the US chart below, under a mass-based carbon reduction plan, in which reductions are measured in short tons, Ohio would be required to reduce its carbon emissions by approximately 27%. Interim (2022-2029) and Final Goals (2030)? Rate C02 Emissions (lbs/Net (short tons) 2012 Historic" 1,900 102,23 9,220 2020 Projections (wi thou CPP) 1,742 103,946,835 Mass-based Goal Mass Goal (Existing) Rate-based Goal (annual average New Source Com Iement emissions in short tons) Inter? Pemd 2022' 1,3 33 82,526,513 83,476,510 2029 Interim Step 1 Period 20224024? 1,501 88,512,513 88,902,150 Interim Step 2 Period 20254027? 1353 80,704,944 82,020,069 Interim Step 3 Period 20282029? 1,252 76,280,168 77,522,714 G0312030 and Beyond 1,190 73,769,806 74,607,975 EPA made some targeted baseline adjustments at the state level to address commenter concerns about the representativeness of baseline-year data. These are highlighted in the C02 Emission Performance Rate and Goal Computation TSD. ?Note that states may elect to set their own milestones for Interim Step Periods 1, 2, and 3 as long as they meet the interim and ?nal goals articulated in the emission guidelines. In its state plan, the state must de?ne its interim step milestones and demonstrate how it will achieve these milestones, as well as the interim goal and ?nal goal. See section of the ?nal rule preamble for more information. 24 Craig Butler, Ohio EPA Director, Testimony Before the US. House of Representatives, p. 1?2, Sept. 11, 2015. 25 Craig Butler, Ohio EPA Director, Testimony Before the US. House of Representatives, p. 2 Sept. 11, 2015. 26 Craig Butler, Ohio EPA Director, Testimony Before the U.S. House of Representatives, p. 2, Sept. 11, 2015,. 27 A summary of Ohio?s targets and requirements can be found at: The ?nal version of the gproposed CPP also made energy ef?ciency optional, rather than a core requirement of the rule.2 The US EPA estimates that its proposed CPP will cost between $5,100,000,000 and $8,400,000,000 in 2030.29 28 Craig Butler, Ohio EPA Director, Testimony Before the US. House of Representatives, p. 4, Sept. 11, 2015. 29 US. EPA, Regulatory Impact Analysis for the Clean Power Plan Final Rule, August 2015, page ES-9. Third Partv Administrators Third party administrators are ?organizations that partner with utilities to ?nd potential qualifying energy ef?ciency work or projects that will assist a utility in meeting its statutory obligations. Such administrators are often trade associations who are able to help facilitate ?nding energy ef?ciency savings through their unique relationships with, and knowledge of, their members? operations.?30 In most cases, third party administrators are afforded lump sum, periodic, or performance?based payments in exchange for their services}1 Instances vary case- by?case, but are often tied to performance.32 Performance is measured as a nominal amount for every kilowatt hour of realized energy savings.33 Performance payments to third party administrators are paid by the EDU, but those expenses are recovered directly from ratepayers.34 The PUCO submitted to the Study Committee the following list of third party administrators who have been previously paid by an FirstEnergy Ohio Council of Small Enterprises (COSE) County Commissioners Association Industrial Energy Users-Ohio (IEU) Ohio Hospital Association (OHA) Ohio Manufacturers? Association (OMA) Ohio Schools Council Roth Brothers The Group Association of Independent Colleges and Universities (AICUO) Ohio Hospital Association (OHA) Ohio Manufacturers? Association (OMA) Dayton Power and Light Company Ohio Hospital Association (OHA) Ohio Manufacturers? Association (OMA) Duke Not applicable 3? Thomas w. Johnson, PUCO Chairman, p. 2, Nov. 24, 2014. 31 Thomas w. Johnson, PUCO Chairman, p. 3, Nov. 24, 2014. 32 Thomas w. Johnson, PUCO Chairman, p. 3, Nov. 24, 2014. 33 Thomas W. Johnson, PUCO Chairman, p. 3, Nov. 24, 2014. 34 Thomas w. Johnson, PUCO Chairman, 13. 3, Nov. 24, 2014. 35 Thomas w. Johnson, PUCO Chairman, Exhibit E, Dec. 3, 2014. 10 IV. RECOMMENDATIONS After an extensive and comprehensive review of the Mandates, including eight public Study Committee hearings, seventeen witnesses, additional written testimony separately submitted, and two onsite visits, the following recommendations are submitted to the General Assembly: Recommendation #1 Extend the S3310 Freeze Inde?nitely The US EPA, by promulgation of the proposed CPP, seeks to change the energy landscape signi?cantly across the United States. Each state, including Ohio, will be handed interim and ?nal targets that dictate carbon dioxide emission levels. However, there are a number of outstanding questions about the CPP that the US EPA has yet to answer, in addition to federal court lawsuits that challenge the very foundation of the rule. Until the US EPA provides greater clarity on the operation of the CPP, and until litigation is resolved, the General Assembly should freeze the Mandates at their current levels. First, there are signi?cant legal questions as to whether the federal government has the right to govern state electricity policy. For this reason, in addition to a number of others, Ohio has joined in a lawsuit with 14 other states to argue that Congress did not intend to grant the US EPA authority under section directly or indirectly, to remake the national power system.3'5 Governor Kasich also recently submitted a letter to President Barack Obama asking him to stay implementation of the rule until legal matters have been resolved. 37 Ohio Environmental Protection Agency (OEPA) Director Craig Butler also testi?ed to Congress that ?we are marching down the road toward implementing a rule with far-reaching economic consequences without any assurance that the rule is even a legal exercise of US. authority.?38 Consequently, as long as legal questions remain pending, the General Assembly should refrain from allowing escalating costs to be paid by Ohio ratepayers in the form of increased Mandates or making any signi?cant changes to the State of Ohio?s energy policies without knowing whether'the CPP will ever apply. Second, freezing the Mandates inde?nitely should provide the OEPA maximum to recommend a State Impiementation Program, at the appropriate time, as well as corresponding legislation targeted to meet the goals of that program. Resumption of SB221 or any revised Mandates before resolution of the CPP could impede ?exibility. The PUCO estimated the proposed CPP would have cost (the PUCO has yet to conclude a cost analysis of the ?nal CPP). Given the magnitude of the cost impacts to Ohio ratepayers, the General Assembly should not impede ?exibility at this time by either allowing the Mandates to resume or imposing any additional mandates. Once there is 100% certainty the CPP 35 Craig Butler, Ohio EPA Director, Testimony Before the U.S. House of Representatives, p. 3, Sept. 11, 2015. 37 Craig Butler, Ohio EPA Director, Testimony Before the US. House of Representatives, 1). 3, Sept. 11, 2015. 38 Craig Butler, Ohio EPA Director, Testimony Before the US. House of Representatives, p. 3, Sept. 11, 2015. 39 Craig Butler, Ohio EPA Director, Testimony Before the US. House of Representatives, 2, Sept. 11, 2015. ll becomes effective, any ef?ciency or renewable mandates should be imposed in a way to minimize the overall cost impact to Ohio ratepayers. Finally, many questions remain unresolved, including, but not limited to, the following questions posed by the OEPA Director: I How will advanced energy and qualifying technologies be determined? 0 How will renewable energy credit be recognized from out-of-state sources? 0 How will the demonstrated economic hardship aspects of Ohio?s law be recognized by the US I Will the US EPA allow credit for improvements already in place? 0 Will Ohio?s ?nal targets be adjusted? If so, how?40 The Director also testified that: ?The most common question we are asked is whether the targets in SB 221 or 310 are enough for Ohio to meet the Clean Power Plan carbon dioxide reduction targets. I wish I could provide a clear answer to this Subcommittee. Unfortunately, that is not possible. Throughout our comment process US. EPA has provided little guidance or clarity. Rather, they have repeatedly asked for advice and a thorough critique of their proposal.?41 ?Ohio power plants have signi?cantly reduced carbon dioxide emissions from electricity generation below 2005 emissions levels. in fact, carbon dioxide emissions have dropped from 138 million tons in 2013 to 107 million tons in 2015 and we expect an additional 33.8 million tons by While the stated target of the CPP is to reduce CO2 emissions by 32% below 2005 levels by 2030, the USEPA is using 2012 as a baseline for CO2 emissions. Nothing done to meet the energy mandates outlined in SB221 prior to 2012 will count towards C02 emission reduction.?43 Based on all of these facts, it is evident that an inde?nite freeze of the Mandates is the best path forward for Ohio. Prematurely enacting legislation to comply with a federal rule that may never go into effect seems irrational and could saddle Ohio ratepayers with extraordinary and unnecessary costs. At this point, there is also insuf?cient guidance from the US EPA to rely upon in determining whether any of the energy ef?ciency achieved in Ohio under Ohio law prior to 2012 will count towards the emissions reductions of the CPP. While the General Assembly should extend the freeze of the Mandates, the State of Ohio should simultaneously prepare for the possibility that the CPP may take effect in some form or fashion. 4" Craig Butler, Ohio EPA Director, 13. 9, Feb. 5, 2015. 41 Craig Butler, Ohio EPA Director, p. 9, Feb. 5, 2015. 42 Director Butler mentioned while testifying that he had reversed the numbers. The numbers here re?ect that correction while the online written testimony still contains the error. A fact sheet with the updated numbers can be found at: It is unclear how signi?cantly the Mandates affected these reductions, as SB221 was enacted during the period in question. 43 Craig Butler, Ohio EPA Director, 13. 6, Feb. 5, 201.5. 12 Thus, the director of the OEPA must work closely with the General Assembly in addressing the uncertainty surrounding the CPP. Recommendation #2 Provide an Expedited Process at the PU 0 for the Review of New Utility Plans for Energy Ef?ciency Whether the General Assembly allows the Mandates to resume at their current law rates or if an inde?nite freeze is enacted, the General Assembly will need to address the issue of how to deal with the four existing 3-year energy ef?ciency portfolio plans,44 all of which are set to expire on December 2016. While interested parties should no doubt have the opportunity to be heard on any future portfolio plan applied for by an EDU, the General Assembly should consult with the PUCO on- how to develop an expedited review process that will enable portfolio plans to be effective by January 1, 2017. Separately, beginning on January 1, 2017, all large industrial users are permitted to opt?out of the portfolio plan that is applicable to them by way of an expedited process at the PUCO.45 Undoubtedly, the General Assembly should maintain the current law opt?out mechanism. Many, if not all, of the large industrial users invest millions of dollars in energy ef?ciency projects at their facilities because those projects provide an individual company with a competitive advantage. Such investments should be encouraged, and maintaining the opportunity for these large users to opt out of a portfolio plan will help accomplish that. Similarly, the General Assembly should extend to all mercantile customers, as de?ned in R.C. 4928.01, the same opportunity to opt-out if they choose to do so beginning on January 1, 2019. Recommendation #3 Investigate and Ensure Maximum Credit for All of Ohio ?3 Energy Initiatives Ohio has a robust and diverse set of energy assets. As policymakers, the General Assembly should remain diligent in ensuring that the State of Ohio counts all forms of emerging renewable resources, advanced energy, and energy ef?ciency initiatives that have been implemented to date across the state. To do this, the General Assembly should do all of the following: 0 Count ?advanced energy projects? and ?advanced energy resources,? as those terms are respectively de?ned in RC. 4928.01, towards the 12.5% benchmark that EDUs and CRES suppliers currently must Obtain by 2027. Because wind and solar are intermittent renewable resources, values their capacity contribution at 13% and 38%, respectively, of their nameplate capacity.?SIMS This means that of the 8,800 MW of wind 44 Pursuant to RC. a portfolio plan is a ?comprehensive energy efficiency and peak-demand reduction program portfolio plan required under rules adopted by the public utilities commission and codi?ed in Chapter 490111?39 of the Administrative Code or hereafter recodified or amended?. $66 no. 4928,6610 through 49.28.6616 46 Andrew Ott, PJM Interconnection, p. 4, March 5, 2015. 13 resources that are expected to be in operation by 2017, these resources contribute only about 1,150 MW of capacity or reliability value. 7 As such, the State of Ohio should not rely exclusively on highly variable resources, but instead look to any and all sources of alternative energy so that the state can count as many of those sources as possible. 0 Determine the most effective way to further incentivize the deployment and counting of combined heat and power A CHP system produces electricity and usable thermal energy using the same input fuel source.48 At the beginning of September, the Study Committee visited Kent State University to visit a CHP facility. The CHP Panel that testi?ed before the Study Committee identi?ed 147 potential CHP sites in Ohio, each about 5 MW, for a total potential of 5,95l MW.49 Bene?ts that this technology offers include: ef?ciency, reliability (and back-up capabilities), limiting grid congestion, reducing peak demand, and cost effectiveness.50 Facilities that utilize CHP for their own power use can save significant amounts on electric bills.51 Current Ohio law allows CHP to be counted as energy ef?ciency, but it is treated as a renewable on a very limited basis.52 If CHP is energy ef?cient, it should be counted towards the energy ef?ciency mandate. Simultaneously, if some portion of CHP is a renewable resource, that portion should also be counted towards the renewables mandate. I Count all energy ef?ciency projects that have been implemented in the State of Ohio to date since 2008. This will require substantially broadening the types of energy efficiency savings that count towards compliance with the energy ef?ciency and peak demand reduction mandates, as compared to how the current PUCO rules and practices, which need correction, currently operate. In order to count as many energy ef?ciency projects as possible, the General Assembly should work in coordination with the Ohio EPA and the PUCO to come up with a method for counting projects that have not historically been counted. It is likely that the most effective way to do this is for the General Assembly to work with the EDUs to develop a method for them to capture energy ef?ciency projects that they previously could not, in order for those projects to be accounted for with the PUCO moving forward in the future. 0 Investigate and maximize extra credit for low-income and multi?family housing. The CPP grants states ?extra credit? for low-income and multi-family housing ef?ciency programs. If the recently passed measure in the budget bill (Amended Substitute House Bill No. 64 of the 131St General Assembly) that requires the Development Services Agency to separately bid out the PIPP load is successful, then the savings could be devoted to funding such a program. 47 Andrew Ott, PJ Interconnection, p. 4, March 5, 2015. 48 CHP Coalition Presentation to the Energy Mandates Study Committee, slide 19 April 16, 2015. 49 CHP Coalition Presentation to the Energy Mandates Study Committee, slide 12, April 16, 2015. 5? Patrick Smith Testimony, IGS Generation, p. 1, April 16, 2015. 51 Greg Collins Testimony, Energy Systems Group, p. 2, April 16, 2015. Greg Collins cites in his testimony at 30 MW project that ESG is working to secure. The project would generate approximately $10 million in annual bene?ts to the company. 52 CHP Coalition Letter, p. 1, Sept. 9, 2015. 14 Recommendation #4 Switch from Energy Mandates to Energy Incentives SB221 required EDUs to meet speci?c energy ef?ciency benchmarks that total over 22% of energy savings by 2025 and peak demand reduction benchmarks that result in a 7. 75% reductiosn in demand by 2018. SB310 effectively extended the deadlines to 2027 and 2020, respectively.53 If the PUCO determines that an EDU has failed to comply with the Mandates, the PUCO must assess a forfeiture on the EDU. SB221 also included renewable benchmarks that require EDUs and CRES providers to provide, by 2025, 25% of their electricity supply from alternative energy. A speci?c portion of that amount would need to be from solar energy. SB310 placed a temporary two year freeze on the above dates, and reduced the 25% benchmark to 12.5% by repealing the advanced energy component. The continuation of the Mandates will be costly for Ohioans, and the penalties for not attaining the Mandates are overly punitive. At the same time, energy ef?ciency can provide great value if it is structured properly so that Ohio ratepayers pay less for electricity and the state uses less electricity overall. Therefore, during the inde?nite freeze of the Mandates recommended above, the General Assembly should consider enacting legislation that would expressly allow EDUs to offer voluntary energy ef?ciency programs that operate to reduce Ohio ratepayers? electricity bills and overall electricity consumption in the State of Ohio. EDUs should continue to be able to provide cost~effective programs to customers, with possible opportunities to share resulting savings. Voluntary programs of this nature have worked successfully in other states. The following are additional suggestions on how to switch from a mandate driven state to an incentive-based, energy efficiency driven state: 0 Allow EDUS and CRES providers who provide material ?nancial assistance to persons wishing to build projects that can be net metered to negotiate a lower price at which to buy the net metered electricity product. (Current law requires payment at the higher standard service offer (SSO) prices.) 0 Consider other constructs for EDUS to fairly participate in distributed generation opportunities. 0 Expand the Property Assessed Clean Energy program whereby the capital costs of energy ef?ciency or renewable improvements can be ?nanced through property tax assessments paid over a period of years. There is current legislation pending in both chambers on this topic (SB185 and HB72 address this issue). 53 SB310 gave utility companies the opportunity to choose to continue or modify their existing portfolio plans. If continued, the Mandates and deadlines from SB221 remained effective; however, if modi?ed, the Mandates and deadlines from SB221 were extended two years. FirstEnergy chose to modify its portfolio plan, so the 2-year extension applies to it. AEP Ohio, Duke Ohio and Dayton Power Light chose to continue their plans, so the 2?year extension did not apply to any of them. 15 I Incentivize the use of smart thermostats in residential homes so that consumers can remotely control energy usage While they are away. 0 Investigate a market-based certi?cation instrument for energy ef?ciency. Recommendation #5 Declare that the General Assembly Retains Statutory Auth orig; with Respect to Energy Policy and Dispatch Protocols As stated previously, the General Assembly should have the freedom to independently make and determine the energy policy of this state. As such, the General Assembly must do the following: - Clarify that, regardless of the fate of the CPP, OEPA has no new state statutory authority, absent action by the General Assembly, to: 0 require utilities to acquire renewable energy 0 require the achievement of speci?c energy ef?ciency goals 0 promulgate a state or regional cap and trade system 0 Ensure that all state agencies will work in concert with the General Assembly before submitting a State Implementation Plan under the CPP Finally, the General Assembly should continuously review the energy landscape in Ohio and once the ?nal determinations have been made as to the applicability of the CPP, stand ready to restructure the Mandates as necessary. 16 Rep29 From: State Senator Bill Seitz Sent: Monday, October 17, 2016 10:27 AM To: 'Dayna@governmentedgecom' Cc: 'Fraizer, Michael'; Subject: RE: Oct. 12 Email Attachments: Manhattan Institute List of Projects Rejectedpdf Dayna, thanks for sharing the articles you sent on October 12. I offer a few observations below: Ill. Wind setbacks saw nothing in the articles that makes a case for addressing the wind setback issue. Neither Ohio utilities nor their customers are constrained to buy in?state wind. The setbacks are quite mainstream compared to many other domestic and foreign jurisdictions, particularly given the pepulatio'n density of Ohio as compared to many other states. As the Manhattan Institute hasjust demonstrated (see enclosed article), the trend is towards greater setbacks, or even bans, and not the other way around. Moreover, given this trend (particularly at the local level), you should be grateful to me for having set up a state wide system 8 years ago instead of leaving it up to every small jurisdiction to set their own restrictions. That said, i have consistently told you and Terrence that there may be issues to address in the setbacks as applied to interpreting them in a checker board square configured wind farm, or in one where the neighboring parcels are totally uninhabited for human or farming purposes, or where the township trustees or city and village council members vote to establish less rigorous setbacks (provided they are not themselves being paid as wind farm lessors, which in my view is a conflict of interest). There are also reasonable debates over how to interpret the number of setback waivers that must be secured from among property owners adjacent to the wind farm and over what sort of amendments to previously-issued certi?cates trigger the new setbacks. But on these and most of the other renewable mandate issues, most of those to whom to you sent your email have failed to engage in any meaningful dialogue. Not for my lack of trying, I might add. Supplying renewable energy to those who want it Because Ohio is a deregulated generation state, customers are not locked in to electric supply only from the investor owned utility. There are no constraints to customers seeking with whomever they wish to. Moreover, and i believe Sam Randazzo can confirm this, all of Ohio?s investor owned utilities in fact are willing to supply ?100% renewable? just as First Energy Solutions did for the entire city of Cincinnati at its request. We are structured to accommodate these demands from existing and new customers who want renewable power, provided those who want it are willing to pay for it. The issue instead is with mandates that force all of the investor owned utility?s ratepayers to pay for what only some of them insist on. The very fact, if true, that an increasing number of corporations and institutions want renewable energy is proof that envirosocialist mandates on everyone are not necessary. Cost comparisons The Bloomberg article correctly points out that wind and solar are getting cheaper and ?more competitive? with fossil fuels. That is a welcomed development (of course, what is left unsaid is how much of this is due to exorbitant federal tax payer subsidies that are not counted as ?cost?), but ?more competitive? is not the same 1 thing as ?competitive?. Notable by its omission is any comparison of wind and solar to natural gas, which remains the cheapest electricity fuel today?and one with which Ohio is blessed. Indeed, the Bloomberg article showing wind costs in north Europe is declining is not entirely a complete picture. Left unsaid is how much of this decline is due to well documented evidence that Europe is running away from new renewable projects, repealing or downwardly adjusting its grossly expensive mandates, and encountering excess capacity as its economy is crippled in no small part due to high electricity prices. 2. 3% ?this Lens} Wes ?k?our Legit? i A {tweet Look at 83 by it} i326.- EAL Clebume County EClebur'ne County Commission passed regulations on setbacks and noise. intending 2,500 feet from adjacent property and a 40~decibel ttmit. Reguiations were passed after sustained oppos: -tion to a proposed wind project on Turkey Heaven Moontaie. Project is for to) to St) _Ituroines therefore egtirneted oapaclt; ts 6t} meoawetts 60 lA EE 2 Buchaoeh 2 County biesIEI'I 3 turbine wEnd project 22 eIack Hawk 2 3 County 230413113! oEfE Artiustmont voted 5 to. tAieot. a sEEpeotatE- permit and EuAriaoceEE - Eitor _a 3 turbine wind protest. The oroteot he?d previousty been turned down in Fayette and . _Buohaoen counties mist 5 A EtEEeyette pounty EECountv sooervt EsEors Imposed a ESE- n?onth moratorium Eon sew wEiAdE prEEoteAtEsE 27/17/15 . . I2 Livingston Gounte Boar?EernEostnvenergy?s eEAptioatton to: AEpEArrEott for pt?jee?t" Athens . Boone County 2County 2 Boone Board voted 9- 3 to require Eel: med turbines be a mioimEuEm At 2 .ESEAOE Eteet from 2 a property line - WellsiECountyE WelEAECEountyE EE Area Plan f_ Commisswn _Count?y?E Eooed negotteoons Ewtth wind devetoper "jot-22112 i: we 2Countiy. 130 5I?EotEIotyE oommISSIoners extend Ea moratorium on Astrid projAoEts for an addItIonai BEEourne stop a tour-turbine Ewind project In South Ptymouth tA concerns shoot Adverse health effects, - mates 'Atiegany? County gitti??etiiaro'cssz?Eh?gj Assetsteed-us?sesoszysees . project on A Mountain 3' exams MD Kent County EEGounty oommIssIoners a Htoroioe Eorojeot Apex Clear: Energy mm MF- "Freedom .. ETAWII A -paEge ordinaooe- EAAacts ooroeroos regata?aons EME Dix?etd Town 5 Towo voters agoro?A EA oErritanEner onE torolees that sets :mats EonE noise setback (4. 308 test from so}! occupier} and. filoker ms- 201? inland . Fisheries aInd: EEDepattrreot At Efnlaed- ?sheries witdti '22 announced Ewoelo oppose the Ipr?ojeo.- based on its Ipotonttat impact on birds IeIIt-it bets Two tater Son Edisoo. the 22the Maine EDopartmentoEf Environmemetg EPEroteotiEoEnE 2 Court State . EEttEto coon: toleAE envi oannEental epEpeAiEs boa acted Ewlthin its powAErE to EoenyiogE SunEoison? peoposed S?tuzbine Bowers Mountain wind term. The court agrees that the protest would have "an unreasonable adverse effect on the scenic character" of several 8/15 lakes that have deemed Arsenic of IIthIe state iceuno Cases .. w??k EpEaEsEsect by Etowosttio was ohaiteooed ErestEdEeEnts ?en?dE toEE A Ereferenttom roots to M1 For so 3? the project so stalled. Moore ts one of towosmos that Witt turbines._ 2 2263192215" MI Passed restrictive Ei'onihg' EuoEd?rE' poses powers authority The courts initiatly- overniled the. dmanoe ITh?e township t; stt? seeming its. Ioext. . 64 33/19/15 Passed rest ?ctive zoning under police powers ity The Escorts tAiEtEiAEly dioenco saying that only the pianning boaro' could peso tews governing tone use. The . _oioancewas revised to focus on notes. ME Dailas 5012512231155 2555' $5552} The .1ewnshie 1155 since TpTeesedT -iTr1Tzerim 25:51.5 C251 eesiricis tower 21151th 122. 380 feet. 5/5215 - T555555 Referendum 251s 20121213 51 :ziTTecisiceT 51:" 1:15 12222221 ?C?ai'd- :0 create Twind- everiay dietrTiTITiiTT 3/25/25 . 555522 2/17/15 51120 5 County 2:661:22in 2152:2223; ?5:552:55 TarTIiTi Commieemn 5521152; Ta reTqQTeeTTtT by 5152211315 Tie up _meieeroieqmel ieeti 22g towers' :21 the Nevins-err 5322 sf the 220225132 5525 Head island Head 25522; 51251225112325 1252115 22255152222522: cemmuriityi natuTrQ-i arid T1;i_sr_e__ric 21513; 5255521 25005222110 '5 yiew 0T1 2522512522.521221151555555 5555551251255 W?TLild represeni :er usjfihe 2 32363022253? 5223 C231 5.351552525251522 damage 111522515251 environment and resources 1ThTai we '2 'cherieh and met tiri2e ear 555552222; 25.25215 NC .. .. 19515222222555 -: 80.5522 50512225 commissioners ?225552525 21 "funk-221021121 mereterium Ten aT 55.255252551252152 a' surge TT incai 5255215. 712211552225 County J'b'?unty 5152:5155 225252155c5'22555552555'222 15 551155 2252251221225 5255522222: wind prefect 55/15 8522212 801211532 555225 County County 1211525 211511er 15 122155552 2255 TTyTeTer 2252525225222 appdeaiwrm 105 new wind pre?ecils "1:55 9222225 ME 1.2522555 55522232115 TT 8551215225 voted 525525512155eg25222525225552" 5:15 reeincieeg high Voltage 51512555121153 52215225151215 property as weii as neise iimiis er; 212211: nee and minimum seihecks 511640 2351120211 22222225252: made and priveie 2552:9123.r net 355211151521 1.2121111154212123 5103551 . '5 525225 . Q1255 'fFraninn TTewn siri? 925/25 . 2355522555 . TT residerts 252552522532515555 12125-52525552255512551. I g.52212252552;.Qf TTewnship $315551; vete? aQeinsi ailewi 22152:; 951252532 aeveicpmeni.T TT TT "9215225 Oak Creek Township Township veted egams? eilcwi r15 25212142223532.2551deveiepmee; . "9.25225 5 15215225252 "1:52:1129 Wind preJeTct 74 [51.15225 ggAiexentina 2375:5111. TQM ?25255 595152 the 523222135 82de Wind T525155 TGrTefie?T 85121225, Passed various T121551 2512:2512: 255155; wind energy projects? 3 5215225 ester TgTownT T222222 voted 5952211151 the Swiss 222555 Wind Eire; 25:1 222 5252255 Passed 53210125 TieTcTaiTT laws to restrici windehergy projeegs 2212215 35251152 'TgTewn #555 1201521 ageir? the S?prLre ?222555? W155 TPrTeTie'ci'T 222 Cra?ton County P555522 1222155115 1555 53.153 ie _r_esi?ci 21212225511 ergy proiec?s 3215215 TT: 52555515221555 law. This erdience pessed overwheimmeiy Tefier town 525T ThTerT to 11551 with . _the tgrbines 5' 35.5215: 13.70.25? Passed vari bus i?ws ?22) 2552521 wind- -erTITergy_ projects. 3/1335 9.5522922 5'3in T"t"lCiWiFid energy 2210152225 TT 12:22:51 1221225222 "2.2232125,? 51255552551255 Committee TT Cemrmtiee passed 211152221255 5'5 prejecis 5 Include 5522;121:155 er: wind energy projects Judiciary '22: District Gout . ST 2323512231 11512511 en 37 turbine 5121552525525225} determining 2112225 T552525 212? 5 Management (31.2.2) environmental eiudy ef the project 10 be built in the Mojave Desert had ;j i - . gags The project aims is insieii 87 turbines er: 13,949 acres of BLM land. Total capacity: TT 200 MW e7?: . E22 2221' 5 S?arci?ziight TT j=Disirici Court . i 5125555 vacTe?Tz?QT C15 255525: peymiis 252T cansiucizee 21:5 Searci?ilght Wmdi?re- ject In Seuihem Nevada Jucige Du ?25252: 12151 55512522525515: ebezyisee prepared ?by the BLM .- and U. Fish 82 Service ieadequa?reiy evaluated the siengers 212511125 in'dusiriai eceie 22212522391562 wee id 5:255 to 1255521 wiidiife a T. 25215 T555.) Ceard 591322555 3 202:5: iew on 55135123125 5112111 T225222 turbi nee 2113225 TT NY Tovan 2'55 sunk ?1.11 T?1isLa11d WEE 1111.11 1.31112 1 .1 11k 1115 11.1 11,1. 30 ?19 0111521 11111113: $911113 85 11111.15? 5131133 111E 1111. 113.111.1115 1111111183 11122 ..- . ?111113111111 8: ELL-11111111115 11111115 111 VT 3/30/15 NY 1111552115. 1311111119 "511's 5.135115121111113 119111161119 the Lighthouse 11111111 pram. .. County . 10.11.11.551 11111111- of. Heaith . . -. .. .L 7/5 5.. NY 3511131391" T011111 1.111111st11 11 511113 11111 LidhthoLse 1.1111111 ?11111601 200 7/28/15 LNY "1781311813011 T131511 11115-61315 111E111 11E rvcsii'i'?'s' 659115.119 111155111 515111 51119115311 EraiEEt 1:11 102@3109 12118115" 5 Orleans (311113119 C?un'f'y ng1siatars 111' 1111115311. 11111 Light'?ouse'. 3111111114.. 1.191951111111114. proposed 11%? 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LinCE'l'h' "60511131 L'1'1'1Eolr1 {151111131 CEmmissianerE denied appEEl company 05151.11 Power Cur-111111115 {301111151 131 11111111. 11.11111111111as seeking permission 11.11 111.3181: Elogmai 111116113111 51111111 1.1111111 energy "111:: 911111111 for the 11111.1 towers had previausiy been denied by the 61111115? 3 211111119 111.511.1111.. papuia?on 111 51111111 Lincoln Csur?y 111193 11111 supgort wind 1111111911113; a majority 11141111? 53151511111111. 131113151111, chair 111 11116-52113 81111111 Dakata. .. . 3326/15 VT ".'i'Norfheaste'r'h 'L'E'Ss'e'x' {33:8ch '1"A?er (1131253311111. 1119' 81111111 9 "11131111131111 'nia and Orleans scaie wind 1181113111me111 E11111E [11111111111131 55 Kingdom."The association covers 21 01111111110111? 1111111 area and represents .. ?11550013 10.11.2101an . . 6,1511% "Entiand 27 {0151133111 "1111111111811 LEE 151111381111 P111111 1.511511 11211119111113 1.1111. GEE evE'yt111'1a 111151 1111111111111; 111' . . _5 Regionai 'Rutiand County wind energy Wind turbines 1111151 have 5911311513 of 1 mile per megawatt 111? capaciw from EagL '2 . 1 11111111311113 structare. . Planning: VT 81111311113111 Town :111111.111 110135.731 150 against the Becky Ridge . .. . . .. . . 73.0"" "high 11111111135111 "he -. . 53115915 :.T1:1wn T511111 51118011111311} 1.1111511 11'} 013511813 Rocky Ridge 11111111 P1011161 . 111 Govemor 3_ I Peter Shumlin 1'11 11211111111 position be k110111_._nL - .. 91?102?1 5 VII For'esf 'i'Towa . T111111: cnROJ'Tced 11191 113 16921} 1'1: E11115. 51115511111111.1115 1.11111 13111111111111. aning 102;_ - 111111-1111 Si. (11111-11 Circuit 12111111 orde'r'ed 111E Public 89.111191: Commission '05. Wissongin. ?to: hold 111111111. hearincs' before 31.111111111531116 cons?uation 111.1113 The 1111 1111? prLEss ralease said??1'h11 Town has 11111910119513.1111 1.1.1111 2111111111113 111 11133115311111 Highiand 1.1111111 rarm project 11.111105111111511} _pLiLa Govemmeoi Entities That Moved to Rejeoi or iiesiriet Wind Projects id 2316 . iTwioii Democratic senators a did that wooid erohibii wind projects the state; if i Town oi'Booriie fildd Iawwi?t eoetns?tfwre Gerereiloowimi owned by ConEdioon BAAFHO sine the omiect . :f gig/15 2 . SD fEDevison i County Commoswe voted to ddoy A permit for Adi ior?oioe proieotiodsiiog 34d 20 - . . . CAWTAATAA - A421 6. my? ii Town Edam? Bda'rd 3098 on 166016 off: osai?Addsihg Liohibause Wied wad?: a ddeoimooe voie seeing lire pro; wouid he aesthetically negative eodihaitiie noise could harm the of locai . .. ii ?2 [27716 i NY i i 'iNiag?ra Gaunt}; i The Niagara Coord; eororo BoArd Approved {we amendments for iheiown of i .5 iiCounty Somerset the: set eiriot standards for varied e?ergy development Tire roles are aimed at the _5 . lighthouse Wino ozojeoi. :Pianning {Board 1 21241185 NY i dei?riidf 31'0"de Boafdi i i :The Town Board approved a law loading eerie wmdiorbine i 203 i so 1121 n2": wind tubine can 'oe' oldoed withing i 500 _ieei oi Airy. reeideetial' ii houddary ?ne it eiso restricts. noise ie?eeio to: no more than 35 Ari; A from 8 o, io Ta. . A wind energy ordidoier said the new iew was A ban on ividd projects The ?rules .- . .. .. .. .. . ..i'AIiegeoy County 5 The oouriiy ?led a petition wiih the state Pebiio Servide Commisson to siop widd project dnii 3 - County Deo?e Mountain The move was made adenine devolooer Dan' A Mountain Wit: 0 Force LLB A: fried to oimemveni a December move by ihe Aiiegeoy County Board of Zoning which denied 1 - project 5- 33 i Sing/TE i MI _?Eim?iood Town T'Tdd owoehio iodeied in Tuecoi. A (foamy eneo Wear moraioraorn on w: od iurdiod ?Township to better protect?die heeiih safety: and weifere" of residents" 3/316 i in 'i i Town ii aoprovede rooreidr lie any new widd projects mg monies i - Township The: iownehio is among sites Exeion i3 cone dering for a wind proieet 3/3f1 i: Mi Argyie ETUWQ - Town heid A referendum do its ordi: renoe whi oh was Add ddwii idi~13d Ai issue Is 2&9} . Tgwniship- i wind prejeoi ,1 invenergy. which wants to boiid wind on 25 ,008 dates is"! 5" - L. . __ieiddre, Argyie Laidoii_e.__and T?WFahipS . 31816 ii Town held a referendum on i tswii?i ordinendd WAS voted demo 105- 65 Aiissde is ii i i ii i TOWITSTIED proposed wind project by imrenergy, which wants to build wind torbioes on 25,008 acres in ?__idoore,_A_igyie, Lemaitre. and Wheatlaod iomehioe. . 332155335 NH iCaneAn Towii genera Appioded e' edmant'ertioie bye of AT 3922-53911 idarddi Ei. .. ?60 - -. The vote is aimed at stoopieg the Spruce Wind project being pushed by EDA. iive NH towns that iieve'been targeieo for the Spruce Wind projeoi?uAiexendrie, Canaan, Dorchesiea Lg; geidion Add voted io rejeoi ire pxoieoti i-i 5 NH i "Ogahg?m 'ithijiih" i 3' in January, ire Grange Piannii?zg Eo'erd undid: gimme- a reeir oiive wind ordinance. ii 5 - was added To the March warrant for the Marsh 8 meeting The ordinance restricts noise to 3218116 . . . Mi . Lioodin .. .. . 12.5 Township jgeeying it was offi ooeesed ?roi a proposed DTE wind The ietter,g e: goed by ail - Efdo'aid members, has two sentenoee?? We} feei that Home. County. has done our dart es mfer Admin . . 3129/1 5 . NY i Fiendoiph iThe Randolph Zoning Board of oirienimouslyiireiedtied 'e?iinii iepoiloeilon for a i meteroiogioei tower Thai was; being sooght by iberdroie Heneweblee. i NE i Gage County ii Cgunty ii i i iGage Couniy Board of s?rengi?e'ied vorimieroiei wrnd?energy regulations by - lowering :=i1oi so limits night Sedeacks were aiso . . .. . . . .. .. 432/1 6 Ml Huimn County 5 Cg?nty i i i The board voted 4- 3 in favor of a zoning ordindooe iliai; haiid dii wirid-energy development i- Board of for 90 days or until a new ordinance can be passed - Commissiooers . i AMA-A55 i. Mi 5 'i ?5Toiriiosillp ii 100; Mi Ten 1&5; a This Land Wes Too? Lemi i A Cioser Look at 80 by 30 54;? 411 6 iiewfieid Town Towii goerd'e'p'soroied moreiorEEi urriE on new Ewinci . . 15 {34735 MA Z??i?g'ggam The {open sEEZEoEnirigE Board oermptiorone oiE-E of Appeals owned wind torhiipes? The major ity of ips memb'ers' found 'feuii _wiih the town 3 on more than one point, including a zoning requirement ihatihe turbine Known esWiz?ro i" :35 not have ?adverse on either the or the town. Noise from the turbines .5 . has been .a 'sopir so of controversy in the town for years and neighbor of the turbines. have gjre'peaie'diy oompielnegi about the. noise. In May. the town announced it iewsui3393*?? .20?ng 593m The 330%? .. . .. pep/15,115 NY Orleans 13555? Town Eboerd voted to approve month moratorium on wirid progeete efEiEriErEE Iberdroie propo? 280 s?eo period project In the town .:ri726fiE_6 NY Bard Flamlog ii'oiepi' Eio' peoommeori .hai Toiihi Boerri eiriend its proposed- .. County "Imoreioriurn on wiped. proieo :sfroni six. months. to one year . NY Ci??dn EE Tow? Cgu'ngp} eix- -Emenih moratorium Looei Law No 2 on powers well are for wied? energy ties . 55 (jg-peang ?aming BoardE The Opieano Cooeipi ?Piennieg Board expressed o?ic: oi month moratormm . County on wiod~energy projecie requested by Town. Eof?i?aie?e. 55/5f16 ME Land Use The comrpiiseion Eiri E13 iownsoipis andE plantairooe ironi experiiteri Pianni?g permit me . . . .. .. 35:51 1 . ?35" 53553053 The idea eeam denied To wipifii vi? real. nae" beenEEreouesieo by :p'exzea p03 1 if it _eiso piriepii 'mooeiy _ooproved. a resolution declaring itwee "not a willi' pig host" for 3 EighiPointWin'o iipop'eoi?or'ah'y otherwihpi energy feellriy??haidoeen?ioomeijwih . .. . - - - .. E5f12j15 EE i NY Yaie?EE EE'EonwEn Boappi The Town Board ?oheeimcmeipp moppih moratorium on u. erop o'r'oontEs, I The move is the iaiest efiopt by the town in its fight against Apex Ciean Energy and the . .. .. . -- WW 93313?? - .. . . $3151.15 Councip The rm EECEoonoii- Eoeseeti an dineriee EthEeiE ihoreior T5 ismiihiieid- . . 5f24f16 EE EE AE oomwpodge wiEtEii The Brrdoei?amppori Pianeing oommiesion emit: a a 153E I County pubiio hearing on Exeioe' epoiicetion for a lane use permiifor its planned .. . . . . . .. . Wind 3 milieu: - isigma i? 55353me 505.15" j'se'e'ciai Ruoh Superiorwurtdupige Matriiewo Bepieyroieo? eagempemeieo 26o? EE 339E- 3' 3 . Superior Court decision by the Rush Cooniy' Board of Zoning to approve 'excepiion pen-hi 5 'for the construction of 'ho turbines for the proposed Fiat Rook Wind pp ojeoi stand despite claims from APEX- Clean __Eoergye-jihe comeany behind the proieotm?Eihet the BZA ovepsteppeo its authority in stipulating that the distance for Those-f orbiries wood .. haveio 1:32 Boopeetfrom noe- -p_e_r_i_ici_ paiing Eof'i oo?iee?z E5f31 f1 5 .EAppegany Couriip' The commissionere ii moiion the Maryiand ECommie'Ee'iE'oe to dismiee' 47 i Count}! Commission Dan 3 mountain Wino Force roouesi for a required certificate for i?I-iorbine wind Term - propeot on Den 3 Mountain '2 ifs/1151's 2505 EFeEderEai'E EE Ninth The com ioled moi tEhEoE of Land EixE?r anagemeot ErioEEt address EE 104 JiEiEdiciary Ei' Circuit to the sage grooee from a proposedwind project@5315 EVA E??ckb?dge 30351 of board in "e Benito regulators concerns an iteEeys 3'5 .3 5. i County Supervisors wouio sit just beyond its oontroi Ewhiie eifeoiing' Its peeio'eotS. eniuironment and economy Land The oompnreeior? voted remoeig} pie Tom the area where EE - PianninEEg roomoniai. reviews of. wind pro; acts are fasimiraokeo to encourage -- . . {tether-0e, Concord Edmoo'depioog Peed Meson. Misery Gore Molunkus Seiem. -Sepi_i__ng . omm'SS?On and Sapiihg Administrative Kreai townehi pie; Dennision Ridge 'arr'd Reneeiy plow 5f potions; one ET'eonion Reynhera Grant '?Commi?ee members say wind develop)w 5 men: in ?those areas would o'etreoi from hand velee spoii viewehede end. demo: the rooriem 5 . . New amp-Ind to we" .. . 55,9315 JTN 3'53 (jig; pjp?EE City The City Eiroioeti opposlrion aE farm or: iistone Mountain inE 71 5' 3 5 Curr-Eioerland Coun?p oeer ?Cr-3b Cir-chard being propel-soon by IAoex EEnergy. .. proseiie . .. 519513. Township 11315118: . . Supervisors Board 1:1. 11:11:11: I :Seiectboard :The 1:111:31? 36:11.3 131111: asking 11:11:: deveioper iberdrois stop: 2: Q6- ?mega1::att 1:11:16 proieci "11111111111? .. i~ffrustees 1:111:31: 1rustass 3111151311 1: ?13011111131111 opposmoo 11:11:11 EverPows: piar: 111:1: 1: 1311:1351 1r: iogan Count: 5:15:11 Logan Count: County Commission I 61:11:11}: commissioners 11:11:: unan: 1110:1313: 1:51:11 Evewower {squest for a payment In :11: for taxes 13:11:11 :8 wind 11:: 1:11:89 northern Logan 8111:1113: The praise? :5 11311311 53101:: Farm 5 311611113 oouo1y's mowe? EverPower said 11:33: will 111:1 locate any turbines in Logan (1:111:13: watersutsomy 135-1111111130 nearby - "5:191:18" {Planning {Ovmmisiao 171:1: commission denied two requests from :1st Clean Energy to buii111awers ir: the 8:11:1th __parL of the 3013:1310 gather wind ?sts . . '5'6/2'1716 I NC. Sena1e I I Lawmakers 1:35.131: 3 1:11 1131111011111 1111:1111 1111116111111112 1mm beiog 1::1111ir: most 111 03:11:11: - and eastern 11:11:11 Cars: 11:11 5:21:11: :11" I Wobdstock? I saws Seiectmen . T111: board voted to sign 1' 1:11:51 support asking: 111' Mame 13:13 1:31: Pisnning Commssior: Ir: Bangor 10 remove 1113:: Townshig: from 11:3 stats' 3 821191111511 perml?irsg 11133191111111: 3::sz 7:20:16 . LNE . 3:111: 3 ?aunt: Pla?hi?g I I .1111: resommended against approwsn a cooda?rmnai 1:11 1:313:11 1orampoten1isim 111111113111: 1r: 11:6 enmity 3' 8/21: 3 1:11:11: . Referendum 831111191111: 3:011:10 510:: 1113 demopmen?: 1:11: 24 16mins project 1:311:11 Mic?igan 3 i1:111:1311133:?13:11:11?: 8:22:16 e1ec1men 23.18- Resuits: 47 Entities i1: 18 31:135. (11:11: 11:11:; {31:33:11 11:11 45 smitiss in M31113 that haw: requested to 1:3 1x91111131: from 11:11 51111935 assessed siting program.) Tots} wind at issue: 25 gigaws?s. ?Exoei 113 11111: iinks sources at