A Practical, Affordable (and Least Business Risk) Plan to Achieve “80% Clean Electricity” by 2035

A Practical, Affordable (and Least Business Risk) Plan to Achieve ‘‘80% Clean Electricity’’ by 2035 As the world’s largest free economies move towards a dramatically new future for their power industries, what challenges face electric utilities? Will it be feasible to achieve President Barack Obama’s goal of 80% Clean Electricity by 2035? How might electric utilities proceed with the least business risk? Craig A. Severance

Craig A. Severance, CPA, is an energy economics author and consultant. He is co-author of The Economics of Nuclear and Coal Power (Praeger, 1976) and author of Business Risks to Utilities as New Nuclear Power Costs Escalate (Electricity Journal, May 2009). He has served as Assistant to the Chairman and to Chief Commerce Counsel, Iowa State Commerce Commission. His articles on energy options are regularly published on several energy Web sites.

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I. Introduction I’ve always said that a utility manager’s job should not be too interesting. he utility industry is expected to be prudent, staid, and predictable. The public expects the lights to come on. Investors expect a steady stream of dividends and growth in value. That’s how it’s supposed to be, but certain choices can place a utility and its managers under

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enormous stress. Rising costs can lead to ratepayer revolts and increasing numbers of customers unable to pay their bills. Utilities can commit to enormously expensive projects, only to have recessions shred revenue projections. Imprudent projects can lead a utility to bankruptcy court, or to a default on its bonds. The stresses on this ‘‘staid and predictable’’ industry are now extreme. A runaway accident landed TEPCO’s manager in the hospital as his power plants

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caused a national health safety and power shortage crisis.1 In India, demonstrations against proposed new nuclear plants resulted in the shooting death of a protestor and injuries to dozens.2 Adding to long-term stress, the United Nations’ Intergovernmental Panel on Climate Change (IPCC) and national governments are embroiling utilities in contentious debates over efforts to slash greenhouse gas emissions.3 he Fukushima disaster was triggered by a massive earthquake, but the ground is shifting under electric utilities in more ways than this.

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II. No ‘‘Easy Button’’ The core technologies that powered the electricity industry throughout the 20th Century – coal, oil, and nuclear power – are now being rejected as too dirty, too insecure, or too costly and unsafe. Even natural gas must phase out over this new century, as supplies of this finite resource diminish. Distressing to some has been the collapse of the so-called ‘‘Nuclear Renaissance.’’ With the familiar workhorse coal plants phasing out, nuclear power was often perceived by politicians and some utility managers as the ‘‘easy button’’ – because it seemed not to require a change in thinking. Nuclear power seemed to fill the same role as utilities’ old baseload coal plants – with the July 2011, Vol. 24, Issue 6

vital financial distinction, however, that baseload power must be cheap power if it is to cover its full costs selling kWh’s at times of low demand. Upon closer examination, the business risks4 associated with slow and costly new nuclear expansion countered any illusion nuclear power could provide an easy button solution. The Renaissance was already faltering even before Fukushima.

a future that requires innovative new solutions for their power sectors. In this rapidly changing environment, utilities need a sure rudder. Utility managers must see clear goals, understand the challenges, and follow the core principle of prudent investment to develop practical and affordable plans that minimize business risks.

III. A Clear Goal

In this rapidly changing environment, utilities need a sure rudder.

Now, in the wake of Fukushima, the world’s thirdlargest economy (Japan)5 and fourth-largest (Germany)6 have explicitly halted new nuclear expansion. In the world’s largest economy, the U.S., it was already clear new nuclear’s staggeringly high costs meant only a handful of new nuclear plants would be built.7 Even China’s nuclear expansion plans are now under review, as the world’s secondlargest economy considers scaling back nuclear expansion and putting more emphasis on renewable power.8 ll four leading economies are therefore now pursuing

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The President of the United States has chosen to make the goal of 80 percent clean electricity generation by 2035 the first priority in his move to make America more competitive. In his recent State of the Union Address, Barack Obama compared this goal to the 1960s’ moon shot program, noting America is at another ‘‘Sputnik moment’’ where the U.S. must innovate or be left behind. While many applauded Mr. Obama’s call for innovation and investment, eyes were rolling among many fiscal conservatives. The President’s call for investment was immediately labeled as simply a call for increased government spending. This is a critical concern when the U.S. is already running a $1.6 trillion budget deficit. This controversy illustrates the debate paralyzing U.S. political life, as Americans are worried about both high unemployment and record deficits. For some time, it has been discussed the solution to this

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conundrum is investment – ‘‘to invest money now, into projects that when completed will help us individually and as a nation to save more.’’9 he difference between investment and runaway spending is that investment pays for itself. One way it can pay for itself is to help consumers to spend less. Another way it can pay for itself is to bring in more revenues – more sales to other countries, and more job creation. Utilities can play a key role investing in the domestic economy. After the credit explosion and collapse of the past decade, most households and small businesses are now ‘‘maxed out.’’ Utilities, however, can still obtain financing for projects which carry reasonable business risks, and thus can help counter economic deflationary forces.10 Mr. Obama is undoubtedly right that utility investments can create jobs – but what should be the focus of new utility investment?

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IV. Standards Not Subsidies As climate and energy author Dr. Joseph Romm of the Center for American Progress has said on many occasions, the key now to reduce carbon emissions is ‘‘deployment, deployment, R&D, deployment, deployment.’’11 If utility deployment is to proceed rapidly at scale, rather 10

than only a few token ‘‘demonstration projects,’’ the investments must be prudent and cost-effective. A profligate ‘‘Clean Energy Plan’’ that invests in outlandishly expensive technologies will fail. Customers won’t save, but instead will be forced to pay more. Also, other countries won’t be attracted to costly boondoggles – you need something to sell that makes sense.

The difference between investment and runaway spending is that investment pays for itself.

Past forays of the government into subsidizing specific energy technologies – such as corn ethanol – give pause that government can prop up exactly the wrong ‘‘solutions.’’ Those with the best lobbyists and the most campaign contributions get the government gravy. Rather than a subsidy program, therefore, the ‘‘80% Clean Energy’’ goal is in the mode of the renewable portfolio standards or goals that have already been adopted by 36 states and the District of Columbia and Puerto Rico.12 These are simply standards

adopted as part of the regulatory framework that must be followed for the privilege of operating as utilities. When utilities select prudent projects, the costs can then be recovered through electricity rates.13 If a Clean Energy Standard establishes a guaranteed new market for deployment of clean energy, why would any taxpayer subsidy be required? While the government should continue to promote basic research for innovation, little else is needed from taxpayers.

V. What Electric Customers Need If electricity is to continue to serve us well as a foundation of modern life, it must meet three basic needs. A. First customer need: Affordability If electricity becomes too expensive it will place a significant burden on family budgets. U.S. home electric bills already average over $106 per month, as electric rates increased 29 percent from 2004 to 200914 – over twice the 14 percent increase in CPI. If these increases continue, over the next 10 years average home electric bills will rise to about $180 per month.15 It’s not as though consumers have more money. With the ongoing destruction of the middle class, American workers are

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a core solution to ending our addiction to oil. Our electric grid must prepare to meet this national security challenge.

experiencing declining real wages.16 A huge generation of retiring baby boomers will be living on fixed incomes. Will households be able to pay skyrocketing electric bills, and still buy prescriptions and groceries? onsumers have supported clean energy standards that have price controls, such as Colorado’s 2 percent per year limit for renewable power rate increases above the comparable cost of fossil fuel power. If utilities ignore affordability, however, build-out plans can come to an inglorious end. Utilities can learn a lesson from the Florida ratepayer revolt that effectively halted Florida P&L’s new nuclear plans after it proposed drastic rate increases to fund the new nukes.17

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C. Third customer need: Clean power

B. Second customer need: Always there

Utilities have long operated without paying the cost of ‘‘externalities’’ – in a word, damages – inflicted upon society by their pollution. Now, however, the public is insisting the harm be stopped. Both liberal and conservative voters support a legitimate role for government in preventing harm to innocent victims. Polls thus show overwhelming support for EPA efforts to cut harmful utility pollutants.19 According to a recently released report from the American Lung Association,20 coal-fired power plants produce more hazardous air pollutants (including mercury, arsenic, lead, acidic gases, and dioxins) than any other industrial polluters in the U.S.

Americans expect their electric utility will always ‘‘keep the lights on.’’ This will be increasingly important as other energy sources such as oil begin to decline. Our entire economy and indeed way of life is threatened by Peak Oil coming much sooner than expected.18 The economic disruptions from high priced oil may destroy millions of jobs if we have not prepared alternative ways to fuel our society. An increased use of electricity for transportation – with electric cars, electrified freight and passenger trains, and increased use of electric transit – is

Electric utilities also currently emit 39 percent of total U.S. carbon dioxide emissions.21 With a string of extremely destructive weather events now garnering public attention, there is strong public support for regulatory actions to limit GHG emissions.22 Climate impact studies have indicated severe droughts, floods, sea level rise, and other impacts of climate change could cause hundreds of billions or even trillions of dollars of economic losses.23 ecause electricity can be generated from a myriad of clean sources, utilities have been asked to lead the way, to achieve over 80 percent of total U.S. energy-related carbon dioxide emission reductions by 2030.24

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VI. Size of the Challenge Figure 1 presents the most recent annual data from the Energy Information Administration (EIA)25 on the

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Figure 1: Percentage of U.S. MWh Generation 2010 by Source Source: EIA Electric Power Monthly, March 2011

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sources of electricity generation in the U.S. in 2010. f one accepts Mr. Obama’s definition of ‘‘clean energy’’ (though many do not, especially in the wake of the Japanese nuclear accidents), the nation is already generating almost 54 percent of its electricity from sources Mr. Obama designates as ‘‘clean energy’’ – renewable energy, natural gas, and nuclear. To meet an 80% by 2035 standard, therefore, would require a conversion of another 26 percent of generated MWh over the 25 years from the end of 2010 to the end of 2035 – an average shift of 1.04 percent per year of existing total MWh generated. EIA reports that in 2010, total U.S. net generation was 4,120,028 thousands of MWh.26 Shifting 1.04 percent of this total would therefore require generating approximately 42,850 thousand MWh more each year from qualifying Clean Energy sources, if no growth occurred in total MWh generation. How big is this conversion? This would require the equivalent generation of installing about 13,500 MW of new wind farms each year in the U.S. (after accounting for wind’s MWh output per MW, and transmission losses).27 This is achievable – in 2009 the U.S. installed 10,010 MW of new wind capacity,28 and DOE has projected U.S. new wind construction capacity of 16,000 MW/yr is feasible by 2018.29 Clean Energy will

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also include far more than just new wind. Of course, if demand for electricity grows, even more new generation will be needed. If kWh use grows by 1 percent per year, by 2035 we will use about 28 percent more electricity than today. Lest one think a growth rate of ‘‘only’’ 1 percent is optimistically low, the Electric Power Research Institute has projected a growth rate of 0.83 percent per year is achievable through 2030 with voluntary measures, and greater savings if mandatory controls such as new building codes were adopted.30 Nonetheless, compared to a simple shift of 26 percent of existing generation if consumption stayed flat, a 1 percent per year growth in kWh usage would almost double the investment required. The result is ‘‘almost double’’ rather than more than double, because under a proportional 80% Clean Energy standard, growth in kWh use has the effect of allowing older generators to run longer. If all new additions are Clean Energy generators, a smaller percent of

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existing capacity would need to be converted and some ‘‘dirty’’ generators may be allowed to operate longer. Mr. Obama’s proportional Clean Energy standard is thus similar to China’s proposed ‘‘carbon intensity per unit of GDP’’ goal, as it allows greater emissions if kWh use grows.31

VII. Major Business Risks Now Facing Electric Utilities While consumers and politicians want utilities to supply affordable and clean power that is always available, there are major challenges facing electric utilities. A. First business risk: Soft and unpredictable sales Utilities are in the business of selling electricity, and must build new power plants to provide it. However, customers can cut their kWh purchases and leave the utility with no ability to pay for these expensive investments (Figure 2).

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Figure 2: Total U.S. Retail Sales of Electricity32

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lectricity sales in the U.S. declined from 2007 to 2008, and even more in 2009. While 2010 numbers show a rebound, total kWh sales for 2010 were still lower than the peak of U.S. kWh sales, which occurred in 2007. The Great Recession is a major cause, and thus overall macroeconomic risks from Peak Oil, fiscal shocks, and other expected stresses to the economy must weigh heavily on utility planning. Electricity is only a service to the general economy. Will general economic growth collapse again? When considering projections of unending growth, it is best to remember customer demand is not what people want to use, but rather what they can afford to pay.33 Customers under economic stress often run up bills they cannot pay, ending in disconnects and lost revenue. Many utilities have implemented ‘‘prepaid’’ electric meters that automatically shut off when the prepaid amount has been used. Until households and businesses see real increases in their income, growth in sales may be tenuous at best. B. Second business risk: Electricity customers can now walk away In most parts of America, customers have still not implemented even the most basic of energy efficiency measures. The ‘‘low-hanging fruit’’ of energy efficiency has yet to be harvested. When power bills get too high, even simple measures

like a clothesline can drastically cut electricity use. Electric customers can now ‘‘walk away’’ from their central utility not only through efficiency, but also by generating their own power. Combined heat and power has long offered large customers a cost-effective distributed power solution whose use is growing rapidly,34 and now

on-site power is entering a new era. General Electric’s global research director, Mark M. Little, recently noted on-site electricity generation with solar panels may be cheaper than electricity generated with fossil fuels and nuclear power within three to five years because of innovations. GE is a leading manufacturer of fossil fuel and nuclear power plants, whose generators supply roughly one-quarter of the world’s electricity. Yet GE has long pursued aggressive development of renewable energy with its line of wind turbines. Wind energy was still focused on the central utility market, but GE will now open a thin-film solar PV

manufacturing plant by 2013.35 Lowe’s and Home Depot are now offering solar PV leases.36 With major players now pushing distributed power generation, the days of a captive customer base for central electric utilities are over. he unspoken fear of all utility managers is the ‘‘Death Spiral Scenario.’’ In this nightmare, a utility commits to build a very expensive new power plant. However, when electric rates are raised to pay for the new plant, the rate shock moves customers to cut their kWh use. The utility then has no way to pay for the new power plant unless it raises rates even higher – causing a further spiral as customers cut their use even more or walk away. In the final stages of that death spiral, the utility’s more affluent customers have drastically cut purchases by implementing efficiency and on-site power, but the poorest customers have been unable to finance such measures. The utility is then left attempting to collect higher and higher rates from poorer and poorer customers.

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C. Third business risk (or opportunity): Unused capacity U.S. utilities currently have a large, relatively young, and highly efficient fleet of natural gas combined-cycle gas turbines – that have an average capacity factor of only about 42 percent.37 Their power simply isn’t needed for large portions of each day.

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tilities also have impressive fields of zero-fuel-cost wind turbines – that generate a lot of inexpensive electricity in the middle of the night when it is not needed. However, many wind farms don’t run much when their power is most needed, on hot summer days. On those summer days, even solar produces the most power at Solar Noon, rather than late afternoon when air conditioners are running full tilt. When those peak power times come, utilities must pull out all the stops. Utilities use cheap-to-build but highly inefficient single-cycle gas peaker units, which provide some of the most expensive kWh on the grid. Even baseload power plants that run 24 hours per day are affected greatly by fluctuations in consumer demand. An expensive baseload plant such as a new nuclear plant may run most of the time, but it might need to charge about 25 cents for every kWh. Yet, it can’t get paid that much for offpeak power so its economics don’t work.38 In the days when power plants and fuel costs were both relatively cheap, the enormous inefficiencies caused by this mismatch of power capacity versus customer demand were cumbersome, but tolerable. While no other business would choose to run this way, it has been business as usual for utilities for so long, it now seems almost normal. If it remains the ‘‘normal’’ mode of operation into the future, 14

however, these inefficiencies will place utilities and their customers at economic risk as costs skyrocket. The flip side of unused capacity is that it is an opportunity. If consumers can switch demand to times when low-cost power is in surplus, both utilities and customers save. If utilities can store surplus low-cost power for

later use, they may avoid the high cost of capacity additions and the expense of operating inefficient generators. D. Fourth business risk: Need to replace aging power plants The President’s challenge to the utility industry to move away from dirty power and toward clean power is actually a challenge the industry is already facing, due to the age of existing plants. Mr. Obama may very well have set a goal for utilities that is going to happen anyway. The dirtiest parts of our power plant fleet are already quite old. The capacity-weighted age of power plants in the U.S. is now 38

years old for coal, and 30 years for nuclear plants. The oldest coal plants will likely be retired by 2035. In contrast, natural gas plants have a capacity weighted age of only 19 years, and wind plants only six years.39 1. Retiring old coal To meet an 80% Clean Energy goal, the 45 percent of our MWh now supplied by ‘‘dirty’’ (noncarbon-capture-and-storage) coal must be drastically reduced. As noted above, with flat growth, an average 1.04 percent of total current electric generation needs to shift to ‘‘clean energy’’ sources each year – but this translates to an average 2.3 percent per year reduction of current coal MWh’s. This may seem a tall order. Over a 25-year period, we would need to see a retirement or conversion of almost 60 percent of existing coal generation. However, by 2035 the capacity weighted average age of the existing coal fleet would be 62 years old. This is beyond the traditional retirement age for coal plants, so it is likely at least this proportion of today’s old coal plant generation will be phased out by then. It is not a question of whether coal plants will be retired – but how best to replace today’s dirty and old power plants. 2. Retiring old nuclear? The U.S. nuclear power plant fleet is also quite old, and if it also has to be replaced before 2035, the challenge will be much greater. Because of this, it seems likely (however one might feel about it)

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the Nuclear Regulatory Commission will extend the licenses of most existing U.S. nukes somewhat beyond the 2035 time line. By then, the utility industry must already be well along a path toward cleaner power, and can then take on that next wave of replacements. hile the NRC seems committed to extending nuclear power plant licenses, this will be a massive experiment and reality will likely intrude. Aging plants tend to require everincreasing capital expenditures to keep in operation, as happened recently with the Oyster Creek power plant in New Jersey, which will close 10 years earlier than its current license allows.40 Public outcry over radiation leaks, such as at the Vermont Yankee plant,41 and the Japanese nuclear debacle may also force earlier-thanexpected phase-outs of existing nuclear plants.

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E. Fifth business risk: New power plants are much more expensive We are now obtaining over two-thirds of our MWh from coal and nuclear plants built more than three decades ago. It should come as no surprise that as the utility industry replaces these very old plants, newer power plants are going to cost more – a lot more – than old power plants built decades ago. We’ve gotten used to driving the old paid-off clunker. Now, when the old beater finally has to

be retired, the shock to the pocketbook will come. hereas long-term trends in utility construction costs for decades showed reasonable escalation in power plant costs, the cost of building new power plants has taken a sharp turn upward since 2000. The Power Capital Cost Index from Cambridge Energy Research

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Associates, which has the year 2000 as a base of 100, was at 215 as of the Dec. 21, 2010, release, ‘‘indicating that a portfolio of power plants that cost $100 billion in 2000 would, on average, cost $215 billion today.’’42 In a 2007 report for The Edison Foundation, The Brattle Group attributed the recent sharp escalation to several factors: rapid increases in prices for material input costs, changes in dollar exchange rates, increased labor costs, tight fabrication and shop capacity, and an overheated demand for engineering and procurement contract services worldwide.43 The rapid run-up in prices for resources such as steel, copper,

and energy is a symptom of ‘‘an unprecedented shift in the price structure of resources’’ recently noted by Jeremy Grantham, principal of GMO, a leading asset management group. In its report Time to Wake Up: Days of Abundant Resources and Falling Prices Are Over Forever, GMO plotted resource prices since the year 1900, which showed a steady decline of about 1.2 percent per year in real prices. For a century there was a long-term trend of abundance, which fueled great advances in our standard of living with falling resource prices. Now, however, with massive increases in the demand for natural resources from emerging economies, Grantham notes, ‘‘they are now rising, and in the last eight years have undone, remarkably, the effects of the last 100-year decline!’’ With statistical analysis indicating the trend of abundance has now reversed to scarcity, Grantham calls this ‘‘one of the giant inflection points in economic history.’’44 F. Sixth business risk: Escalating fuel prices World supplies of oil have already reached a tipping point where the easiest reserves have been tapped and are rapidly depleting. As oil production moves to more difficult to reach and unconventional supplies, oil prices are increasing and it is becoming difficult to maintain production levels. ‘‘Peak Oil’’ will occur – if it has not already – when exhaustion rates of old fields

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[(Figure_3)TD$IG] exceed increased production from new sources, after which total world production of oil will fall into irreversible decline.45 ortunately, most electric utilities have moved away from a significant dependence on oil. However, this familiar pattern of initial abundance as cheap resources are tapped, followed by increasing costs and eventual decline, is certain to apply to the utility industry’s other fuel sources.

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Figure 3: Example of Total vs. Economically Recoverable Coal

1. Cheap coal limited? Coal mine development has followed the traditional extraction pattern, with initial development of the easiest to reach coal seams. However, as these seams are exhausted, expansion into further coal reserve areas will involve significantly higher costs. For instance, in the U.S. ‘‘Saudi Arabia of Coal’’ area in the Powder River Basin, coal companies began in the eastern areas with the shallowest seams. As they move westward the depths of overburden are much higher and costs of extraction increase. While enormous amounts of coal exist, the amounts economically recoverable are dramatically less than total resources often touted implying the U.S. has over 200 years of coal. For instance, a detailed U.S. Geological Survey 2008 study of the Gillette coal field in the Powder River Basin – an area that in 2006 accounted for 37 percent of U.S. coal tonnage production – showed only 6 percent may be 16

economically recoverable. This 6 percent is equivalent to only 24 years of production at 2006 Gillette production levels of 413 million short tons, as indicated in Figure 3.46 In August 2010, the journal Energy published a multi-Hubbert cycle analysis of total world coal production by Tadeusz W. Patzek and Gregory D. Croft. The study estimated the peak of world coal production, by energy content, is imminent and may occur as early as this year (2011). Their results indicate total world coal production will likely decline to 1990 levels by 2037, reaching only 50 percent of peak by 2047. Given the importance of coal, the authors note, ‘‘If we are right, major restructuring and shrinking of the global economy will follow.’’47 2. Natural gas prices The natural gas industry is also experiencing the decline of its cheapest reserves – traditional natural gas wells – and is already

moving strongly to develop moreexpensive and harder-to-extract gas reserves. The EIA projects that by 2035, 46.5 percent of total U.S. natural gas supply will come from shale gas, obtained through expensive ‘‘fracking’’ techniques that inject chemicals deep underground to fracture shale gas formations.48 With increased reliance on shale gas to develop natural gas supply, a price increase will be needed. Current prices in the $4–5 million/Btu range are widely acknowledged to be insufficient to support fracking. EIA projects an increase of 30 to 40 percent in natural gas prices, into the $6.50– $7.00 range.49 Yet, the pace of this price increase will likely need to be much sooner than EIA projects, if shale gas is to come on line on the time line projected. After compensatory pricing is reached, however, the shale gas resource is very large,50 so natural gas prices may prove much less volatile for at least several decades.

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G. Seventh business risk: Climate change While Mr. Obama’s stated goal for electric utilities is to reach 80% Clean Energy by 2035, the ways in which Mr. Obama has defined clean energy mean his new goal is still a far cry from the GHG emissions cuts proposed just two years ago for the utility industry. As noted above, during debate of the U.S. House energy and climate bill in 2009, EIA studies projected electric utilities would do the heavy lifting. Reductions in electricity sector CO2 emissions by 2030 were expected to be from 29 percent (requiring payment for international offsets) up to 88 percent reductions (if utility emissions reductions occurred domestically).51 Mr. Obama’s 80% Clean Energy standard, however, would require far less drastic cuts in GHG emissions – particularly if utilities choose natural gas fired power plants to meet a significant share of that goal. Though natural gas plants fall within Mr. Obama’s definition, they still emit significant GHG emissions. he prospect for natural gas to achieve major reductions in GHG reductions could be even worse. A recent study by Howeth et al. of Cornell University has called into question whether fugitive methane emissions, most prominent in shale gas production, could negate the power plant efficiency advantage of natural gas plants compared to coal. Methane is a far more potent

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GHG than CO2, so even small percentage leaks in natural gas production wells greatly skew ‘‘full-cycle’’ GHG emissions.52 hough the Cornell study raises serious concerns about shale gas, the bulk of natural gas production will still be from traditional wells, so a weighted analysis of expected sources may show natural gas still

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they fade away of their own accord. If the scientific warnings are valid, however, the issue will keep coming back until effective actions are taken. As the public becomes increasingly concerned over deaths and damages from extreme weather events and other impacts of climate change, political tides may shift once again to favor strict controls on utility GHG emissions. If a utility implements only minimal GHG reduction efforts, it may later need to play catch-up and do far more.

VIII. What Will the Conversion to 80% Clean Energy Cost?

has substantial GHG advantages over coal. Cornell also notes many things can be done by the natural gas industry to reduce the methane gas leaks. A new combined-cycle gas turbine that achieves 61 percent baseload efficiency and ramps far more efficiently to mesh with renewables will also reduce natural gas emissions calculations.53 Nevertheless, the substantial business risk to the utility industry is that achieving ‘‘so-so’’ reductions in GHG emissions will ultimately prove woefully inadequate. Scientific issues such as climate change cannot be killed. If scientific theories are not valid,

In the context of business risks from limits on what customers can afford to pay, and the increasing ability of customers to walk away if central power costs rise too sharply, it will matter a great deal which types of power plants utilities choose for the conversion away from old coal. Converting 26 percent of the MWh generated in 2010 in the U.S. (i.e., generating increased ‘‘clean energy’’ of about 1,071,250 thousand MWh per year) by the year 2035 will require hundreds of billions of dollars of new power plant investments. It is useful to compare capital costs of various options. The sampling of costs below is only for the cost of converting this 26 percent of existing generation. Growth in demand adds more costs – a 1 percent per year kWh growth

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through 2035 would almost double the investment requirements noted below. A. Small hydro, CHP, and gas-fired power plants Replacing 26 percent of existing MWh generated is likely to cost about $246 billion in upfront capital costs (in today’s dollars) if we replace the old coal plants with about 136,000 MW of the cheapest mix of new power plants – traditional natural gas plants, together with a combination of RPS-qualifying small hydro power, biogas, landfill gas, heat-recovery generation, and combined-heatand-power.54 n addition to being the cheapest to build, these types of power plants can typically be built quickly with only two- to three-year lead times. Utilities thus avoid the major business risks that come with long construction periods: the need to bet on consumer demand many years in advance, and unpredictable escalations of costs during construction. While cheap to build, the total price per kWh will also include fuel costs. Small hydro, renewable gas, heat-recovery, and CHP plants have zero or low fuel costs, but traditional natural gas plants may require paying significant life cycle fuel costs. Utilities with natural gas plants can cut their business risk exposure to high fuel costs by continuing to bring more renewable power onto the grid,

and cycling off their gas plants to save fuel. Unlike coal or nuclear plants, natural gas plants are compatible with intermittent wind and solar energy as they ramp up and down far more efficiently. B. Wind and geothermal Wind and geothermal power require a significant step up in

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capital costs per annual MWh, but they have zero fuel costs and are therefore roughly comparable to natural gas in life cycle costs per kWh. Building enough wind turbines or geothermal plants (and transmission lines for these) to generate the 26 percent of existing MWh needing conversion would cost about $626–670 billion under current policies, or up to $816 billion if tax credits are allowed to permanently expire.55 This is a significantly higher up front capital cost than natural gas, but utilities which own these generators will never need to worry about their fuel costs or GHG emissions.

C. Concentrating solar power Another step up in capital costs per annual kWh are the concentrating solar power plants – thermal CSP, concentrating photovoltaic, and Stirling Engine – now being built in the desert Southwest. The base design (with no thermal storage) has similar capital costs/kW as geothermal,56 but higher capital costs per annual kWh produced because they typically do not operate at night. However, thermal CSP plants have natural gas boilers to keep the plant at operating temperatures during intended operating hours, so they can provide dispatchable daytime power. Concentrating solar plants cost roughly twice the capital cost per annual kWh as geothermal – but the kWh’s they produce are the most valuable, daytime kWh’s. They will not be installed nationwide, so a comparative cost to replace all retiring coal plants is not appropriate. D. Untested options Large numbers of natural gas, hydro, wind and geothermal plants, and some CSP plants, have recently been built – so we know what they cost. Build-out of these generators is already proceeding at scale. Two new technologies discussed below, however, require much more expensive power plants, and none have yet been built in the U.S.

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1. ‘‘Clean coal’’ If utilities instead try to build new coal-fired plants with carbon capture and storage (CCS) to replace the retiring ‘‘dirty’’ coalfired plants, the tally would likely be at least $900 billion.57 This is much higher than natural gas and most renewables. nlike renewables, however, coal requires paying fuel costs that would grow over time, and CCS systems impose an efficiency penalty requiring approximately one-third more coal consumption. ‘‘Clean coal’’ is thus a more expensive option – and we don’t really know how expensive, because CCS is still an unproven technology.

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2. New nuclear On the highest end of the scale, another unproven cost is new nuclear power. If we tried to build all new nuclear plants to fill this same generation need, the total bill to replace just those retiring coal plants would likely be about $1.5 trillion dollars,58 not including the cost of nuclear waste dumps. E. No Moon Shot – much more costly Mr. Obama used the example of the Apollo Moon Shot program as an inspiration for what utilities need to do today. However, perhaps a more fitting comparison may be the Marshall Plan, or the mobilization effort for World War II. The cost for the entire NASA Apollo moon program was

approximately $160 billion in today’s dollars, ‘‘with only the building of the Panama Canal rivaling the Apollo program’s size as the largest non-military endeavor ever undertaken by the United States.’’59 Replacing dirty coal plants with ‘‘clean energy’’ will likely cost about $250–$816 billion if we build gas and renewable

If we don’t control kWh growth, and we also let lobbyists push to build the most expensive power plants – this will be no Moon Shot – it will be more like 20 Moon Shot programs.60

IX. Innovative Strategies to Make Clean Energy Goal Affordable The practical strategies discussed below can keep the cost of meeting the Clean Energy Standard affordable to utilities and their ratepayers. These innovations address the electricity system as a whole. A country that adopts these strategies can take a leadership position to show the rest of the world how ‘‘clean energy’’ can be done economically.

plants, but could cost up to $1.5 trillion if lobbyists get their way and convince Congress the most expensive power plants – CCS and nuclear – should be built. Another cost multiplier is growth. If in addition to ‘‘cleaning up’’ 26 percent of existing generation, utilities also need to handle 1 percent per year growth, the investment needed will roughly double, to handle another 28 percent more MWh’s. However if growth instead averages 2.5 percent per year, the extra MWh’s needed would be 85 percent more – more than tripling the investment needed.

A. First innovative strategy: Do customer-level projects first If the computer age had proceeded with the same mindset as the U.S. utility industry, IBM would have just continued building bigger and more expensive central computers. There would have been no PCs, and no Internet. remember in the early days everyone was asking, ‘‘Why would I ever want a computer at home?’’ Today that question seems ludicrous – but only because the power of innovation was unleashed across hundreds of millions of distributed computers. Before electric rates are raised to fund hundreds of billions or even trillions of dollars in new

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centralized power plants, utilities must first ‘‘firm up’’ the demand for centrally generated power so it is reliably known. It would be a business disaster of monumental proportions to spend all this money on central power plants and then have consumers ‘‘walk away.’’ onsumers must first be given every chance to reduce their use, and to generate their own power, to reduce demands on the central power grid. This strategy recognizes the low-hanging fruits of energy efficiency and distributed power have not yet been harvested. One low-hanging fruit is the ability of utilities to tell electricity customers their current usage and offer them signals of what times of day electric costs are high or low. If electric rates are set high during peak periods and low during offpeak, customers can switch the times they do things like run their dishwasher or charge their car. The Smart Grid can even directly control smart appliances such as water heaters to save everyone money. The reason customer level projects such as insulation and PV power have still not been done is that most utility customers have no access to the capital to finance these energy-saving and distributed power projects. Utilities, however, can make money by providing 100 percent up-front financing through on-bill financing, folding these projects into the monthly bills of whoever lives in the property at any time.61 Customer-level actions can have dramatic results. A study by

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the American Council for an Energy Efficient Economy (ACEEE) showed that simply implementing existing costeffective strategies would flatten and actually reduce Texas electricity peak demand curve for at least 15 years.62 Utilities have for years been trying to control demand growth with demand response programs.

Implementing both on-bill financing and the Smart Grid will be like demand response on steroids. If customers are given financing, and real-time feedback, opportunities will blossom for thousands of new vendors. ‘‘We’ve got an app for that’’ will become the new motto for the electric power sector. B. Second innovative strategy: Storage to allow full use of excess capacity, and efficient use of wind and solar This strategy is a major money saver because it allows better use of existing highly efficient combined-cycle natural gas

power plants that are now underutilized. Wind farms and baseload plants that must now dump power for low revenue at times of low consumer demand would also benefit. This strategy begins with the realization that most utilities already possess enough energy generation capability to generate far more MWh than they currently provide – it is just poorly matched to demand. If new energy production generation must now be added, it must often be renewable MWh’s to meet RPS and carbon targets. In addition to shifting generation from one time period to another, energy storage generators also provide valuable services to provide power quality and reliability. They thus bring far more value to the electric grid than single-purpose (generationonly) power plants. This innovative strategy would therefore install ‘‘energy storage generators’’ as a first priority for new generation in every electric grid. This strategy can provide major fuel cost savings, GHG reductions, and avoidance of high-cost new power plant construction. If already-built efficientburning power plants, plus renewable power sources, can be better utilized, the high fuel costs and GHG emissions of expensive peaker plants can be avoided. Fuel savings may be over 25 percent even after storage losses.63 Also, by better utilizing available energy generation capabilities, expensive new

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(single-purpose, non-storage) power plants can be deferred. Storage allows utilities to serve customer needs at high-value times of day when consumers want to use electricity, with power generated at other times from cheap sources. The arbitrage of transferring cheap power to highvalue times can bring significant profits. tilities might get automobile owners to buy these energy storage generators for them. Electricity-using vehicles have large batteries and electronic control systems which can be designed for two-way charging and feedback to the grid. They can be timed to charge during off-peak times, or even to know when extra windgenerated power is being produced. If utilities or car makers warrant batteries for the extra battery cycling, and utilities offer tie-in incentives, many electric car owners may even feed power back to the grid during peak power periods. Other economical examples of energy storage generators include compressed air energy storage turbines, and pumpedhydro turbines. Pumped hydro storage has been used for decades with lakes and dams, pumping water uphill and then letting it fall back through turbines. Now, there are also pumped-hydro generators that do not require above-ground landscapes, allowing siting virtually anywhere. These new

designs use man-made drilled shafts to pump water up and down beneath the earth’s surface.64 Energy storage generators provide dispatchable generating capacity. Many cost little more to install than traditional gas generators,65 so they provide a new power generation option in the low to middle range of costs,

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or 90 years of natural gas.67 That’s no time at all. Are we going to do the same thing with coal, natural gas, and uranium that we have done with oil – do nothing until fuel supply shortages and drastic price increases hit? By 2035, it will be starkly evident that coal, natural gas, and uranium are non-renewable fuels with impending finite limits. Before any new power plants are built in that decade, business risk assessments will call into question whether any power plant that uses these non-renewable fuels will be able to operate economically for its full design life. Also by 2035 – or perhaps much sooner – climate change impacts will be obvious. y 2035 it will clearly be time to move to a clean, safe and 100 percent renewableenergy-based power generation system. If we have followed Strategies #1 (efficiency and distributed power) and #2 (energy storage generators), we will already know how to do this, and do it affordably. We can continue to add more wind, hydro, geothermal, solar thermal, photovoltaic, biomass, and other renewable power generation without confusion about how to mesh these together in an electric grid. If, however, we choose to do politically motivated boondoggles, by definition these will fail. We will have learned what doesn’t work – but not what does.

B far less costly than coal/CCS or new nuclear. Most importantly, they provide the foundation for a legacy system to continue our civilization long after finite fossil fuels and uranium run out – a 100 percent renewable electricity system. C. Third innovative strategy: Create a ‘‘legacy’’ electricity system We know that economical supplies of coal, natural gas, and uranium are going to run out, and actually quite soon. If you really think much about it – it provides little comfort to believe we have perhaps 80 years left of uranium66

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country thrives by tapping abundant and affordable natural resources. If we go the right path the resources we can tap are enormous. According to the USGS, geothermal resources alone can supply roughly 550,000 MW (mean value of estimated resources) in the U.S.68 A study by Navigant Consulting found over 400,000 MW of water power resources.69 Solar and wind resources are even greater. This is personal. My two-yearold grandson Ashton will only be 26 years old in 2035. His generation will see the end of affordable natural gas, coal, and uranium. What are we leaving them? We can (and ultimately, we must) build a practical legacy system. The time to lay the groundwork is now.&

Endnotes: 1. Norihiko Shirouzu, Mariko Sanchanta and Kana Inagaki, At Utility, a Leadership Vacuum: Hospitalization Furthers Anxiety and Leaves a Leadership Vacuum, WALL ST. J., Mar. 31, 2011, at http://online.wsj. com/article/SB10001424052748704559 904576231742989493576.html. 2. One Killed in Clash at Planned India Nuclear Plant Site, BBC News, April 18, 2011, at http://www.bbc.co.uk/ news/world-south-asia-13124773. 3. See, e.g., Labour Turn Up Heat on Huhne over Carbon Emissions Row, BBC News, May 10, 2011, at http://www. bbc.co.uk/news/uk-politics13343055. 4. See, Craig A. Severance, Business Risks to Utilities as New Nuclear Power Costs Escalate, ELEC. J., May 2009, or Business Risks and Costs of New 22

Nuclear Power, Jan. 2009, at http:// energyeconomyonline.com/uploads/ Business_Risks_and_Costs_of_New_ Nuclear_Power_Reprint_-_Jan_2__ 2009_Craig_A._Severance.pdf. 5. See, e.g., Gus Lubin, Japan Officially Cancels its Plan to Become 50% Nuclear Powered by 2030, BUSINESS INSIDER, May 11, 2011, at http://www. businessinsider.com/japan-nuclearpower-2011-5. 6. See, e.g., Nuclear Commission Pinpoints 2021 for German Atomic

gr&articleId=467 (registration may be required). This briefing notes ‘‘Although record amounts of cash have been pumped into the economy by the world’s main central banks, much of the liquidity has been hoarded by the banks as a buffer against a further deterioration of their loan books. As a result, this liquidity has not found its way into the economy . . .’’ Utility investment on the other hand could flow into the domestic economy and help counter deflationary job losses. 11. See, e.g., Joseph Romm, Breaking: Socolow Reaffirms 2004 ‘Wedges’ Paper, Urges Aggressive LowCarbon Deployment ASAP, CLIMATE PROGRESS, May 18, 2011, at http:// climateprogress.org/2011/05/18/ socolow-wedges-deployment/. 12. See DSIRE Web site resource, Summary Maps – RPS Policies May 2011, at http://www.dsireusa.org/ summarymaps/index.cfm?ee=1& RE=1.

Shutdown, D.W. - WORLD, May 11, 2011, at http://www.dw-world.de/dw/ article/0,,15066387,00.html. 7. See, e.g., Exelon’s Rowe: Low Gas Prices and No Carbon Price Push Back Nuclear Renaissance ‘A Decade, Maybe Two,’ CLIMATE PROGRESS, Oct. 12, 2010, at http://climateprogress.org/2010/ 10/12/exelon-john-rowe-nuclearrenaissance-constellation-energy/. 8. See, e.g., China Renewable Sector Eyes Govt Support Amid Nuke Safety Fears, Reuters, Mar. 30, 2011, at http:// www.reuters.com/article/2011/03/ 30/china-renewables-nuclearidUSL3E7EU15C20110330. 9. Craig A. Severance, Job Losses Push Need for Energy Bill, ENERGY BULLETIN, Feb. 10, 2010, at http://www. energybulletin.net/51504. 10. See, e.g., Developed Economies Fall into a Deflationary Spiral, Global Risk Alert, Economist Intelligence Unit, Mar. 16, 2011, at http://gfs. eiu.com/Article.aspx?articleType=

13. If a mandatory national Clean Energy Standard proves impossible, its adoption by the Executive Branch could still be an argument to approach state regulators for inclusion of projects in rate base. The industry can choose to make progress toward this goal, even if not required. 14. Energy Information Administration, Average Retail Price of Electricity to Ultimate Customers, at http://www.eia.doe.gov/cneaf/ electricity/epm/table5_3.html. Average residential bills of ‘‘over $106 per month’’ using 2010 average rates from that table of $0.1158/kWh, and EIA data of average (2008) residential consumption of 920 kWh/month, from: http://www.eia.doe.gov/tools/ faqs/faq.cfm?id=97&t=3. 15. Electricity rate inflation could become far worse. A recent study projected electricity prices in Australia may ‘‘nearly double’’ from FY08 to FY15 because of four forces now also affecting U.S. utilities: (1) increasing fuel costs; (2) higher costs to build new power plants; (3) advanced grid buildout costs; and (4) new environmental standards. See: Paul Simshauser, Tim

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Nelson, Tim and Thao Doan, The Boomerang Paradox, Part I: How a Nation’s Wealth Is Creating Fuel Poverty, ELEC. J., Jan./Feb. 2011, and ‘‘Part II’’ in the Mar. 2011 edition.

Executive Summary, see Table ES-2 on p. ES-4, at http://www.epa.gov/ climatechange/emissions/ downloads11/US-GHG-Inventory2011-Executive-Summary.pdf.

16. See, U.S. Bureau of Labor Statistics series on real wages, April 2011 release at http://www.bls.gov/news.release/ pdf/realer.pdf BLS notes ‘‘since reaching a recent peak in Oct. 2010, real average weekly earnings have fallen by 1.7 percent.’’

22. See, e.g., Benenson Strategy Group poll results, Aug. 25, 2010, at http:// climateprogress.org/wp-content/ uploads/2010/08/Benenson-epapoll-8-30-10-2.pdf.

17. See, e.g., Julie Patel, Regulators Slash FPL’s Rate-Hike Request, S. FLORIDA SUN SENTINEL, Jan. 13, 2010, at http://www. sun-sentinel.com/business/fl-pscincrease-vote-20100113,0,5320042, full.story. The rate increases garnered so much public opposition Gov. Crist ‘‘had opposed the rate hike and reshaped the commission by appointing two outsiders to replace two outgoing commissioners.’’ Even in non-democratic societies such as China, officials hold down rate increases, starving utilities of revenues needed to pay for increased costs, see, e.g., Keith Bradsher, China’s Utilities Cut Energy Production, Defying Beijing, N.Y. TIMES, May 24, 2011, at http:// www.nytimes.com/2011/05/25/ business/energy-environment/ 25coal.html?_r=2&pagewanted=1. 18. See, e.g., The Peak of the Oil Age: Analyzing the World Oil Production Reference Scenario in World Energy Outlook 2008, Global Energy Systems Group, ENERGY POLICY, Mar. 2010, at http://www.tsl.uu.se/uhdsg/ Publications/PeakOilAge.pdf. 19. See, e.g., ORC International, Survey Highlights: Americans Want EPA to Do More, Not Less, Feb. 2, 2011, at http://switchboard.nrdc.org/ blogs/paltman/2-2%20ORC%20 International%20EPA%20Survey%20 Report.pdf. 20. American Lung Association, Toxic Air: The Case for Cleaning Up CoalFired Power Plants, Mar. 2011, at http://www.lungusa.org/assets/ documents/healthy-air/toxic-airreport.pdf. 21. U.S. Environmental Protection Agency, U.S. Greenhouse Gas Emissions Inventory 1990–2009:

23. International Institute for Environment and Development, Costs of Adapting to Climate Change

Significantly Under-Estimated, Aug. 27, 2009, at http://www.iied.org/ climate-change/key-issues/ economics-and-equity-adaptation/ costs-adapting-climate-changesignificantly-under-estimated. 24. Energy Information Administration, Energy Market and Economic Impacts of H.R. 2454, The American Clean Energy and Security Act of 2009. EIA’s analysis of the House climate and energy bill projected (see p. ix (p. 10 of PDF) ‘‘the electricity sector accounts for between 80 and 88 percent of the total reduction in energy-related CO2 emissions relative to the Reference Case in 2030,’’ at http://www.eia. doe.gov/oiaf/servicerpt/hr2454/pdf/ sroiaf(2009)05.pdf. 25. Data for chart drawn from Energy Information Administration, Total Electric Power Industry Summary Statistics, Year-to-Date 2010 and 2009, January through December, Net Generation and Consumption of Fuels, from EIA’s Electric Power

Monthly published in Mar. 2011 with data through Dec. 2010, see Chart ES.1.B at http://www.eia.doe.gov/ ftproot/electricity/epm/02261103. pdf. The chart lists net generation before losses from transmission & distribution, which typically average about 6.5% for the U.S. 26. Id. 27. See, e.g., U.S. Department of Energy, 20% Wind Energy by 2030, at http://www.nrel.gov/docs/fy08osti/ 41869.pdf. In this comprehensive evaluation of the potential for substantial wind energy build-out in the U.S., DOE assumed by 2030 the U.S. could obtain 20 percent of 5.8 billion MWh/year from wind (p. 21), i.e., 1.16 billion MWh per year, with wind capacity of 305,000 MW (p. 26). DOE assumed average wind-associated additional transmission loss of 4.72 percent (p. 207, loss assumptions 0.236 kW/MW/mile and avg. 200-mile transmission). This seems to imply an average capacity factor of 45.5 percent at the wind farm. DOE assumes significant improvement in wind capacity factors, due both to technology improvements and about 18 percent of the total 305 GW as offshore wind. This may be a best case scenario, however. A 1.04 percent shift of 2010 total generation would require new generation of 42,850 thousands of MWh. Using more pessimistic assumptions, this could be generated by approximately 13,500 MW of wind with an average ‘‘wind transmission penalty’’ of 10 percent and a less optimistic average capacity factor at the wind farm of approximately 40 percent. 28. American Wind Energy Association, AWEA U.S. Wind Industry Annual Market Report Year Ending 2009, at 4, at http://www.awea.org/ learnabout/publications/loader.cfm? csModule=security/getfile&PageID= 5089. 29. U.S. Department of Energy, supra note 27, footnote 27, at 13 (PDF p. 32). 30. Electric Power Research Institute (EPRI), Assessment of Achievable Savings Potential From Energy Efficiency and Demand Response in the U.S., Jan. 2009, at http://www.edisonfoundation.

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net/iee/reports/EPRI_Assessment AchievableEEPotential0109.pdf. Of particular note is this study evaluated voluntary measures, and did not include the imposition of any new mandatory measures such as improved building codes, beyond those already adopted. EPRI noted (p. 185): ‘‘As such, any new codes and standards or other externalities would contribute to greater levels of overall efficiency.’’ 31. A proportional standard allows existing ‘‘dirty’’ power to operate longer if there is growth in electricity use. If electricity use increases 1 percent per year from 2010 to 2035, i.e., by 28 percent, and all new generation added to meet growth in use is supplied by ‘‘clean energy’’ generators, then the full growth wedge (28 of a 128 Index, or 22 percent of the new total) would be ‘‘clean energy.’’ Since 54 percent of the existing 2010 generation mix, or 54/128 = 42% of the new total 128 Index, is already ‘‘clean,’’ then ‘‘clean energy’’ would be 22% + 42% = 64% of the new 128 total. To meet an 80% Clean Energy standard a total of 16 percent of the new 128 Index (20 percent of the existing 2010 mix) would need to be retired and converted, rather than 26 percent of the existing 2010 mix needing retirement and conversion if there is no growth in MWh usage. A greater percentage of ‘‘dirty’’ power plants could operate longer. This is a major difference between a proportional 80% Clean Energy standard, and a ‘‘shrinking carbon cap’’ with absolute carbon reductions. 32. Energy Information Administration, data for 1997–2009 from Electricity Overview: Selected Years, 1949–2009, at http://www. eia.gov/emeu/aer/pdf/pages/ sec8_5.pdf, data for 2010 from ELECTRIC POWER MONTHLY, Mar. 2011, at http:// www.eia.doe.gov/ftproot/ electricity/epm/02261103.pdf. 33. Credit goes to financial writer Nicole Foss of The Automatic Earth, http://theautomaticearth.blogspot. com/ for repeatedly reminding us of this basic concept. 24

34. See, e.g., U.S. Environmental Protection Agency, Combined Heat and Power Partnership, an in-depth EPA program to promote increased use of CHP, at http://www.epa.gov/ chp/. 35. Bryan Wingfield, GE Sees Solar Cheaper Than Fossil Power in Five Years, Bloomberg News, May 26, 2011, at http://www.bloomberg.com/news/ 2011-05-26/solar-may-be-cheaperthan-fossil-power-in-five-years-gesays.html.

40. See, e.g., Matthew L. Wald, Oyster Creek Reactor to Close by 2019, N.Y. TIMES, Dec. 8, 2010, at http://www. nytimes.com/2010/12/09/nyregion/ 09nuke.html. 41. See, e.g., Mark Clayton, State Senate Pulls the Plug on Vermont Yankee Nuclear Power Plant, CHRISTIAN SCI. MONITOR, Feb. 24, 2010, at http:// www.csmonitor.com/USA/2010/ 0224/State-Senate-pulls-the-plug-onVermont-Yankee-nuclear-plant. 42. IHS Global Insight, Press Release, Power Capital Costs Index, Dec. 21, 2010, at http://press.ihs.com/pressrelease/energy-power/power-plantconstruction-costs-recovery-pausedcosts-go-flat-once-more. Note the price trend was steeply upward until the Great Recession. 43. Marc Chupka and Gregory Basheda, Rising Utility Construction Costs: Sources and Impacts, a Brattle Group report for The Edison Foundation, Sept. 2007, at http://www.edisonfoundation.net/ Rising_Utility_Construction_Costs. pdf.

36. Ehren Goosens, Lowes Buys Sungevity Stake to Offer In-Store Solar Lease, Bloomberg News, May 16, 2011, at http://www.bloomberg.com/ news/2011-05-16/lowe-s-buys-stakein-sungevity-to-offer-in-store-solarlease-program.html.

44. Jeremy Grantham, Time to Wake Up: Days of Abundant Resources and Falling Prices are Over Forever, GMO, at http://www.gmo.com/ websitecontent/JGLetterALL_1Q11. pdf. 45. Global Energy Systems Group, supra note 18.

38. This point was highlighted by the Citi Nov. 2009 financial analysis New Nuclear: The Economics Say No, at https://www.citigroupgeo.com/ pdf/SEU27102.pdf.

46. Data for chart from Fig. 68 (PDF p. 115) U.S. Geological Survey, Assessment of Coal Geology, Resources, and Reserves in the Gillette Coal Field, Powder River Basis, Wyoming, Open File Report 2008-1202. Chart 67 notes this 6 percent is 10 billion short tons. PDF p.12 notes total Gillette field coal production in 2006 was 413 million short tons, equivalent to 37 percent of total U.S. coal production. Report at http://pubs.usgs.gov/of/2008/1202/ pdf/ofr2008-1202.pdf.

39. Energy Information Administration, How Old Are U.S. Power Plants? (2010 ages are listed, and this article adds one year for estimated average age as of 2011); EIA table at http://www.eia.gov/tools/faqs/faq. cfm?id=110&t=3.

47. Tadeusz Patzek and Gregory Croft, A Global Coal Production Forecast with Multi-Hubbert Cycle Analysis, ENERGY, Aug. 2010, at http:// xa.yimg.com/kq/groups/20593576/ 885722944/name/Patzek+and+ Croft+2010+-+Peak+Coal+2011.pdf.

37. Energy Information Administration, Average Capacity Factors by Energy Source, 1998 through 2009, at http://www.eia. gov/cneaf/electricity/epa/ epaxlfile5_2.pdf.

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48. Energy Information Administration, Annual Energy Outlook 2011 Early Release Overview, Table 14: Oil and Gas Supply, at http://www.eia.doe.gov/forecasts/ aeo/excel/aeotab_14.xls. 49. Id. 50. Potential Gas Committee, Potential Gas Committee Reports Substantial Increase in Magnitude of U.S. Natural Gas Resource Base, April 27, 2011, at http://www.potentialgas. org/.

other than natural gas power plants. For instance, EIA expects 20.2 GW by 2035 of biomass cogeneration facilities related to mandated biofuels production (EIA, Annual Energy Outlook 2011, at 77 at http://www. eia.gov/forecasts/aeo/pdf/ 0383(2011).pdf). Small hydro, combined heat and power, landfill gas, and biogas plants are more expensive per kW than natural gas CCGTs (see, e.g., EPA CHP resources, supra note 34). If average all-in cost is $3,000/kW for these other types of

51. EIA, supra note 24, at PDF p. 35, at http://www.eia.gov/oiaf/servicerpt/ hr2454/pdf/sroiaf(2009)05.pdf. 52. Robert W. Howarth, Renee Santoro, and Anthony Ingraffea, Methane and the Greenhouse Gas Footprint of Natural Gas from Shale Formations, CLIMATIC CHANGE LETTERS, DOI: 10.1007/s10584-011-0061-5, at http://graphics8.nytimes.com/ images/blogs/greeninc/Howarth 2011.pdf. 53. General Electric Press Release, GE Launches Power Plant with Breakthrough Flexibility and Efficiency to Enable Greater Use of Wind, Solar and Natural Gas on Power Grid, May 25, 2011, at http:// www.genewscenter.com/content/ detail.aspx?ReleaseID=12510&News AreaID=2&PrintPreview=True. 54. Increasing ‘‘Clean Energy’’ generation an average of 42,850 thousand MWh/yr each year, for a 25year period results in total generation converted of about 1,071,250 thousand MWh/yr by the end of 2035. If supplied by generators operating in base load mode at 90 percent capacity factor, this requires approximately 136,000 MW (136 GW) of new capacity to replace supplanted ‘‘dirty’’ generation. If all were combined-cycle gas turbines with an installed total allin cost of about $1,300/kW (including ‘‘overnight’’ costs without escalation of $1,050/kW, modest real dollar cost escalations of 3%/yr during construction period, and avg. weighted cost of capital of 10.5% during construction), this 136 GW would cost roughly $176 billion. Yet, because of RPS requirements it is reasonable 30 percent may come from

power plants, and they comprise 40.8 GW (30 percent) of the total 136 GW, then total all-in costs of construction for the 26 percent conversion would be approximately $246 billion. 55. As noted in note 27, if the 26 percent converted was all generated from wind, approximately 13,500 MW/year of wind farms would need to be brought on line. EIA’s current ‘‘overnight’’ cost estimate for on-shore wind is $2,438/ kW. This jumped 21 percent from the prior-year estimate. Assuming no further real price escalation (because of technology improvements and Chinese competition), average wind all-in costs are estimated at $2,645/ kW. The DOE 20 percent wind study (supra note 27) estimated transmission costs attributable to wind of $120/wind kW (p. 95, PDF p. 114), bringing total wind costs to $2,765/kW. If 340 GW of wind is added over the 25 years, total wind costs may equal $939 billion if there

are no tax credits. If the 30 percent tax credit is extended then net costs to utilities are $670 billion. Geothermal is more cost-effective. If total ‘‘all-in costs’’ for geothermal average $4,600/kW (starting with EIA’s current ‘‘overnight’’ cost estimate of $4,141/kW) this same generation with geothermal may cost roughly $693 billion assuming no tax credits available, average 7.5 percent transmission losses due to remote locations, and transmission capital costs of $18 billion. If the 10 percent tax credit for geothermal is extended, utility costs would instead be $626 billion. If a mixture of 50 percent geothermal and 50 percent wind is used with no tax credits, total costs would be $816 billion. See Energy Information Administration, Updated Capital Cost Estimates for Electricity Generation Plants, Nov. 2010, Table 2 at 8, at http://www.eia.gov/oiaf/ beck_plantcosts/pdf/updated plantcosts.pdf. 56. Id. EIA Capital Cost Estimates, at 172. EIA’s current cost estimate for solar thermal is $4,692/kW for a plant that includes a natural gas boiler to warm up the plant during early morning hours, and keep the plant at operating temperatures during daylight operational hours. 57. Id., Table 1 at 7 and Table 2 at 8 and individual sections on coal with CCS. The lowest ‘‘clean coal’’ estimate is pulverized coal with CCS, estimated at overnight cost of $4,579/kW before cost escalations during construction, and before cost of capital during construction. Adding modest real dollar cost escalations during construction plus the cost of capital during construction, brings all-in costs to roughly $6,625/kW. Using the same 136,000 MW baseload needed to replace the 26 percent of generation converted means ‘‘clean coal’’ may cost approximately $900 billion. 58. Id., Table 1 at 7 and Table 2 at 8. EIA’s updated ‘‘overnight’’ cost per kW for new nuclear is $5,339/kW, in an estimate prepared well before the Fukushima debacle. In 2008, industry

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cost estimates for new nuclear (in $2007) were in the $4,000/kW ‘‘overnight’’ cost range. (See Webposted report at note 4.) This new EIA estimate is now 33 percent higher. With much more modest (5%/yr) further real dollar cost escalations during construction, and including cost of capital during construction, indicates total all-in costs for new nuclear of $10,970/kW. Using an optimistic 90 percent capacity factor and thus the same 136 GW, total all-in capital costs would be $1.492 trillion for new nuclear to replace the retired ‘‘dirty’’ power MWh generated.

money’’ by recovering their weighted cost of capital in the rate base for all funds committed to on-bill financing programs. 62. American Council for an Energy Efficient Economy, Potential for Energy Efficiency, Demand Response, and Onsite Renewable Energy to Meet Texas’ Growing Electricity Needs, Mar. 1, 2007, at http://www.aceee. org/research-report/e073. 63. Generation of power at off-peak by an otherwise idle advanced

59. National Aeronautics and Space Administration, Project Apollo: A Retrospective Analysis, at http:// history.nasa.gov/Apollomon/ Apollo.html. NASA quotes the cost of the entire Apollo program as ‘‘about $95 billion in 1990 dollars.’’ which converted with a CPI calculator is approximately $160 billion in 2010 dollars. 60. If we express existing MWh as 100 index ‘‘units,’’ then 2.5 percent growth through 2035 results in new MWh demand of 185 ‘‘units’’ by 2035. All existing ‘‘clean energy’’ generators are 54 units. To meet 80% Clean requires 148/185. Thus, a total of 148 54 = 94 new ‘‘units’’ need built. 94/26 = 3.6 times the investment required in new plant compared to simple conversion of 26 percent of existing generation. If the most expensive option (new nuclear) were chosen at $1.5 trillion for a 26unit block, total investment needed might be $5.4 trillion. If instead CCS at $900 billion  3.6 were built, $3.24 trillion might be spent. This is about 20 Apollo programs. 61. On-bill financing that stays with the utility bill for that address as part of the fixed-charge cost of local service – rather than requiring payment in full when the customer moves – is the ‘‘barrier-breaker’’ similar to PACE (Property Assessed Clean Energy) loans, but should not carry the ‘‘property taxes take priority over lenders’’ objection to PACE from mortgage lenders that has crippled PACE. It may also be the only way to help renters. Utilities can ‘‘make 26

combined-cycle gas turbine (CCGT) of approximately 6,333 Btu/kWh Heat Rate, cycling this off-peak output through pumped hydro energy storage with 80 percent efficiency (i.e., 20 percent lost) would provide an effective heat rate of about 7,920 Btu/kWh. Compared to a conventional natural gas combustion turbine with a heat rate of 10,842 Btu/ kWh, fuel savings could be approximately 27 percent. If the power stored came instead from a wind farm, fuel savings might be 100 percent. Heat rates from National Petroleum Council, Electric Generation Efficiency, Topic Paper No. 4, July 18, 2007, at http://www. npc.org/ Study_Topic_Papers/4-DTGElectricEfficiency.pdf. 64. See, e.g., Tom Scheueneman, Gravity Power Module Revolutionizes Pumped Hydro Energy Storage, TRIPLE PUNDIT, Mar. 11, 2011, at http:// www.triplepundit.com/2011/03/ gravity-power-module-aims-

revolutionize-pumped-hydro-energystorage/, and Water Battery: Riverbank Power Brings New Twist to Pumped Storage, ECO FRIENDLY MAG, Mar. 24, 2009, at http://www.ecofriendlymag. com/sustainable-transporation-andalternative-fuel/water-batteryriverbank-power-brings-new-twist-topumped-storage/. 65. Electric Power Research Institute, Electricity Energy Storage Technology Options, Dec. 2010, Energy Storage System Costs on p. xxiii (PDF p. 25). Compressed Air Energy Storage Systems estimated at $1,150–$1,250/ kW and Pumped Hydro from $1,500– $4,300/kW. This entire White Paper on energy storage is well worth reading, at http://www.electricitystorage.org/ images/uploads/docs/EPRI_Storage Report_5_11.pdf. 66. World Nuclear Association, Supply of Uranium, at http:// webcache.googleusercontent.com/ search?q=cache:56xsARvWWaEJ: www.world-nuclear.org/info/ inf75.html+80+years+uranium+world +nuclear&cd=1&hl=en&ct=clnk&gl= us&source=www.google.com WNA’s estimate of 80 years left of economic resources is at current usage rates, therefore increases in usage from new reactors would likely shorten this time frame. 67. The Potential Gas Committee’s latest assessment of total ‘‘U.S. Future Gas Supply’’ is 2,170 Tcf. (Supra footnote 50.) Divided by current U.S. consumption of approx. 24 Tcf/yr the math (90 years) leads to statements of ‘‘100 years of natural gas supply.’’ However, as usage increases the time line shrinks. 68. U.S. Geological Survey, Substantial Power Generation from Domestic Geothermal Resources, Sept. 29, 2008, at http://www.usgs.gov/ newsroom/article.asp?ID=2027& from=rss_home. 69. Navigant Consulting, Job Creation Opportunities in Hydropower, Sept. 20, 2009, at http://www.hydroworld. com/etc/medialib/new-lib/ hydroreview/online-articles/2010/ 09.Par.30736.File.dat/NHA_Jobs Study.pdf.

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