NewEnergyNews: 05/01/2013 - 06/01/2013/


Gleanings from the web and the world, condensed for convenience, illustrated for enlightenment, arranged for impact...

The challenge now: To make every day Earth Day.



  • TTTA Wednesday-ORIGINAL REPORTING: The IRA And The New Energy Boom
  • TTTA Wednesday-ORIGINAL REPORTING: The IRA And the EV Revolution

  • Weekend Video: Coming Ocean Current Collapse Could Up Climate Crisis
  • Weekend Video: Impacts Of The Atlantic Meridional Overturning Current Collapse
  • Weekend Video: More Facts On The AMOC

    WEEKEND VIDEOS, July 15-16:

  • Weekend Video: The Truth About China And The Climate Crisis
  • Weekend Video: Florida Insurance At The Climate Crisis Storm’s Eye
  • Weekend Video: The 9-1-1 On Rooftop Solar

    WEEKEND VIDEOS, July 8-9:

  • Weekend Video: Bill Nye Science Guy On The Climate Crisis
  • Weekend Video: The Changes Causing The Crisis
  • Weekend Video: A “Massive Global Solar Boom” Now

    WEEKEND VIDEOS, July 1-2:

  • The Global New Energy Boom Accelerates
  • Ukraine Faces The Climate Crisis While Fighting To Survive
  • Texas Heat And Politics Of Denial
  • --------------------------


    Founding Editor Herman K. Trabish



    WEEKEND VIDEOS, June 17-18

  • Fixing The Power System
  • The Energy Storage Solution
  • New Energy Equity With Community Solar
  • Weekend Video: The Way Wind Can Help Win Wars
  • Weekend Video: New Support For Hydropower
  • Some details about NewEnergyNews and the man behind the curtain: Herman K. Trabish, Agua Dulce, CA., Doctor with my hands, Writer with my head, Student of New Energy and Human Experience with my heart




      A tip of the NewEnergyNews cap to Phillip Garcia for crucial assistance in the design implementation of this site. Thanks, Phillip.


    Pay a visit to the HARRY BOYKOFF page at Basketball Reference, sponsored by NewEnergyNews and Oil In Their Blood.

  • ---------------
  • WEEKEND VIDEOS, August 24-26:
  • Happy One-Year Birthday, Inflation Reduction Act
  • The Virtual Power Plant Boom, Part 1
  • The Virtual Power Plant Boom, Part 2

    Friday, May 31, 2013


    The climate change sceptics are winning

    Liam Dennis, May 29, 2013 (UK Independent via Times of Oman)

    “For the first time in five million years the proportion of carbon dioxide molecules in the Earth's atmosphere has reached 400 parts per million (ppm)…Yet for all the Nobel prizes and predictions of global apocalypse and destruction, climate change is still a niche issue. The environmental movement has failed to capture the public's imagination…[P]ublic opinion of the issue is ambivalent…[T]he scientific, civil and environmental lobbies are left preaching to the converted…[Tabloid newspaper] daily onslaught against the science of climate…is influential and damaging…

    “…Changing the orthodoxy of the government, against a hostile media is no easy feat. Lobbyists for big business have louder voices…The green movement must re-evaluate what is working, and what needs to be done to get the public back on side…Energy bills are a major concern for the public. Decoupling the preconception that energy bills are rising due to green policies is imperative (Green policies account for 6 per cent of the average gas bill and 11 per cent of electricity bill)…”

    “…[Besides] debunking myths and celebrating positives, it's necessary to re-energise the public with the importance of action. There is a need to simplify the science and speak with a more united voice, to convey better what a 2C degree rise in temperature really means, and the dire consequences of a rise higher than this. It is important to engage with the public better and more inclusively, including via less traditionally friendly media…to justify tough choices and convince the public that inaction will be much costlier.

    “For many in the know, 400ppm is another sleepwalking step towards catastrophe…The major concern is without a catastrophic wakeup call the issue could disappear from the political mainstream altogether and 400ppm will soon become 450, 500….The action needed to [reverse that] demands a societal transformation. This cannot be made by stealth and requires the mass mobilisation and support of the public. Navel gazing and arrogance will not do.”


    Global Solar PV Market Poised To 'Rise From The Ashes' Of 2011

    21 May 2013 (Solar Industry)

    “The solar photovoltaic market is poised to rise from the ashes of its 2011 crisis to grow to $155 billion in 2018, as market forces engineer a turnaround to a healthy 10.5% compound annual growth rate (CAGR), according to a new report from Lux Research…In the most likely scenario…the PV market will grow at a modest clip to 35 GW this year before ramping up to 61.7 GW in 2018…

    “…[A]nalysts used a detailed levelized cost of energy (LCOE) analysis in 156 separate geographies, accounting for 82% of the world’s population, to determine the viability and competitiveness of solar in each market…[and concluded that the] U.S., China, Japan and India will take over where Germany and Italy left off. With an 18% CAGR to 10.8 GW of installations in 2018, the U.S. will emerge the world’s second-largest market. But China will leapfrog it, growing over 15% annually to 12.4 GW in 2018.”

    “Utility-scale solar, the smallest segment in 2012 at 8.6 GW, will grow the fastest to 19.9 GW in 2018 as developing markets turn to PV. Globally…commercial applications reign supreme as markets like the U.S. and Japan move to large rooftop installations.

    “Struggling start-ups present opportunities to acquire intellectual property at low prices. For example…Hanergy acquired Miasolé - which in 2012 announced the leading CIGS module efficiency at 15.5% - for only $30 million after investors had pumped $500 million into the firm.”


    Electric Vehicles in India

    2Q 2013 (Navigant Research)

    “Sales of plug-in electric vehicles (PEVs) in India have been minimal due to a myriad of factors: little domestic production, the high cost of vehicles, a lack of government commitment, an often unstable power grid, and almost no formal charging infrastructure.

    “Making the environment more conducive to electric vehicle (EV) sales will take years of investment from the public and private sector, limiting the growth of the market in the short term. The government’s on-and-off support for EVs has caused many companies that began to produce EVs to halt production, and in some cases cease operations.”

    “Nevertheless, trends in the country’s demographics, traffic patterns, and natural resources suggest enormous potential. Estimates by the Indian government and industry foresee India becoming the third-largest market for cars in the world by 2020. The country’s dense urban centers and short yet congested commutes make it a natural fit with the relatively low power density of electric drivetrains…[The 2013] government incentive for EV purchases…will spur Indian automakers…

    “Navigant Research forecasts that sales of PEVs in India will reach 17,000 by 2018. Combined with sales of hybrid electric vehicles (HEVs), that number will reach more than 22,000 in the same year. Two-wheeled electric vehicles will grow to more than 1.1 million units annually by 2018, with electric scooters the preferred vehicle type…”


    An Incredibly Detailed Map Shows The Potential Of Global Water Risks; …a new tool…lets you see all the bad things that might stem from water, from droughts to floods and beyond.

    May 2013 (World Resources Institute)

    “…[T]he drought that hit the U.S. in 2012…was a big deal…53% of the country was dealing with…moderate to extreme drought…by July. Over 1,000 counties were declared federal disaster areas…Aqueduct, a new map from the World Resources Institute (WRI), throws the world’s growing water woes into stark relief…[The water issue] is emerging as one of the defining challenges of the 21st century…

    “The project, created with an alliance of companies including GE, Goldman Sachs, Shell, and Procter & Gamble, is the highest high-resolution map of global water stress available today. It’s also the first water-risk mapping tool to include a layer for groundwater data…”

    “WRI’s free map uses 2010 data (the most current data available) to measure a number of categories of water risk around the world: physical risk; variability in available water from year to year, which looks at flood occurrences (how often and how intense); severity of droughts (how long and how severe), groundwater stress, pollution pressure, demand for water treatment, media coverage about water issues (meaning how much attention is given to water in a given area), and more…

    “…Places that haven’t traditionally had high water risks--the East Coast of the United States, the upper Midwest, Europe--now have medium to high water risk…because of changes in water demand, withdrawal patterns, weather, and water-supply patterns…[P]laces where there’s already high competition for water (i.e. India) are at serious risk when combined with annual variability in water…”

    Thursday, May 30, 2013


    Obama Campaign Group Targets Climate Change

    Coral Davenport, May 28, 2013 (National Journal via Yahoo News)

    “While President Obama's reelection campaign was almost completely silent on the issue of global warming, Organizing for Action, the advocacy group tooled from his 2012 campaign machine, has launched a campaign designed to build support for the president's climate-change agenda…The multipronged, multiyear effort aims to inject climate change into the heart of national politics—and make it an election issue as well…[F]ormer campaign operatives who scrupulously avoided talking about climate change last year are now writing press releases slamming Republican lawmakers for denying the science behind it…[and] fanning out around the country—to more than 20 states, so far—holding meetings and press conferences aimed at spurring voters to bring up the issue with elected officials…

    “…Last month, in its first foray into changing the national conversation, Organizing for Action sent out an e-mail blast and Web video directly attacking Republicans as climate-change deniers…[H]ighlighting those views could make some moderates uncomfortable…One Republican strategist dismissed that effort…But Republican denials of climate science could be a Democratic issue that resonates with young voters…Events and outreach will be tailored to the profile of each congressional district...[OFA events will be] aimed at linking [local impacts] to the broad global problem of climate change…”

    “Meanwhile, Organizing for Action intends to push back against an ongoing campaign…[by] the conservative American Legislative Exchange Council, which has taken funding from Koch Industries, the oil conglomerate that helped fund the tea-party group Americans for Prosperity…to bring up bills that would roll back state laws mandating production of electricity from wind and solar sources. OFA will campaign against those bills…send workers to go door-to-door in those communities to talk about the virtues of renewable energy…[and] spur clean-energy projects such as adding solar panels to churches…to link clean energy and community-building in voters' minds…

    “…While prospects for congressional action on climate change are grim, Obama is expected—nobody knows when— to use his executive authority to roll out two massive, controversial climate-change regulations reining in pollution from coal-fired power plants…If those rules stand, they'll likely be the cornerstone of Obama's climate legacy…[I]t's expected that Senate Republicans will use a procedure called the Congressional Review Act, which allows Congress to repeal an executive regulation within 60 days of its issuance…For OFA, the endgame will be to ensure that the Congressional Review Act votes fail by building up enough voter support in the home states of key lawmakers, particularly Democratic senators facing close elections in 2014. That will be a tough assignment…”


    Study: How Northwest Wind Can Play With Energy Storage And Provide Operational Flexibility

    Frances White and Joel Scruggs, 23 May 2013 (North American Windpower)

    “Enough Northwest wind energy to power about 85,000 homes each month could be stored in porous rocks deep underground for later use [using two unique methods], according to a new, comprehensive study..[by researchers] at the Department of Energy's Pacific Northwest National Laboratory (PNNL) and Bonneville Power Administration (BPA)…[About 13%, or nearly 8.6 GW, of the Northwest's power supply comes from wind]…

    “Compressed air energy storage plants could help save the region's abundant wind power - which is often produced at night when winds are strong and energy demand is low - for later, when demand is high and power supplies are more strained. These plants can also switch between energy storage and power generation within minutes, providing flexibility to balance the region's highly variable wind energy generation throughout the day…”

    “All compressed-air energy-storage plants work under the same basic premise. When power is abundant, it is drawn from the electric grid and used to power a large air compressor, which pushes pressurized air into an underground geologic storage structure. Later, when power demand is high, the stored air is released back up to the surface, where it is heated and rushed through turbines to generate electricity. Compressed-air energy-storage plants can regenerate as much as 80% of the electricity they take in…

    “The world's two existing compressed-air energy-storage plants…use man-made salt caverns to store excess electricity. The PNNL-BPA study examined…using natural, porous rock reservoirs that are deep underground to store renewable energy…Analysis identified two particularly promising locations in eastern Washington…The Columbia Hills Site could access a nearby natural gas pipeline, making it a good fit for a conventional compressed-air energy-storage facility…The Yakima Minerals Site, however, does not have easy access to natural gas. So…[it] would extract geothermal heat from deep underground…”


    Mid-Size Solar PV Installations Accounting for over 60% of US Project Pipeline

    Christine Beadle, May 24, 2013 (SolarBuzz)

    “The trend for U.S. solar PV projects in the mid-size range (100 kW to 2 MW) has been changing considerably, from individual installations (on municipal or school buildings, for example) to multi-site projects…[P]roject master plans now embrace the bigger picture, outlining the needs of an entire town, county, or school district. Typically, contracts cover everything from development to operations and maintenance of the system for up to 25 years, often with no cost to the host for installation.

    “…[C]ontingency plans to extend projects in later years…[are]rarely discussed…Once an installer is on-site, the aim is to get as much power as possible, to complete the project quickly, and to reap the benefits with a steady return on investment…Because many cities, government entities, and schools are unable to take advantage of tax breaks, developers have been quick to step in with third-party ownership in states where such ownership models are allowed…[T]he host leases space to the developer and pays no upfront cost for the solar installation. Electricity is received through a power purchase order at a fixed or fluctuating rate as determined by the contract. The developer then owns and maintains the system, and claims the tax incentives.”

    “…[R]ather than a city/municipality looking at each site as an individual project…projects are being looked at as one master project, meaning bigger overall projects/contracts, even though each PV array is similarly sized and located at different sites…[M]ultiple arrays can be bid out as one project and installers can capitalize somewhat on economies of scale when purchasing components.

    “These models are also leading to the emergence of community-based solar…[C]ommunity members can purchase ‘shares’ of a PV project to offset their own electricity use even though they are not able to act as hosts. As more areas begin to allow this type of ownership there is a significant potential for further growth in the mid-size project pipeline…[T]his is a brand new growth opportunity for the downstream PV market as customers that might be interested in solar, but unable to install it due to living style (e.g. apartment buildings), will be able to invest…”


    Smart Parking Systems; Sensor, Communications, and Software Technologies, Smart City Applications, City and Supplier Profiles, Market Analysis, and Forecasts

    2Q 2013 (Navigant Research)

    “…[P]oorly managed parking supply [is 30% of cities traffic congestion,] frustrates drivers, wastes fuel, creates air and noise pollution, and stifles economic activity. Today, the parking industry is going through its biggest transformation since the introduction of the first parking meters in Oklahoma City in 1935. It is being transformed by new technologies that are having an impact on operational efficiency and customer expectation…

    “…[Navigant Research expects to see a major breakthrough over the next 12 to 18 months as smart parking projects transition from trials and small deployments to large-scale rollouts, a broader range of pilots, and expansion into new countries and regions…The global market for smart parking systems in 2013 is expected to be worth $60.0 million…”

    “Navigant Research projects annual revenue will grow to $356.5 million by 2020, representing a compound annual growth rate (CAGR) of 29.0%. On a cumulative basis, the market will reach $1.6 billion between 2013 and 2020. During this period, the smart parking systems market will rapidly transition from the pilot stage to being an accepted technology for city management.]

    “Faced with growing environmental and economic pressures on city transportation, cities are reexamining how and where parking is provided…Enabled by new technologies, innovative approaches to parking are becoming one of the cornerstones of cities’ mobility strategies. Navigant Research forecasts that the installed base of on-street smart parking spaces will surpass 950,000 worldwide by 2020…”

    Wednesday, May 29, 2013


    Enlisting the Sun: Powering the U.S. Military with Solar Energy

    May 17, 2013 (Solar Energy Industries Association)


    • Solar plays a critical role in making the military’s energy supply more secure, distributed, affordable and independent. The DoD has committed to meet 25% of its energy needs with renewable energy by 2025.

    • The Navy, Army and Air Force have each implemented aggressive plans that are increasing the U.S. investment in solar and encouraging innovation in the industry.

    • As of early 2013, there are more than 130 megawatts (MW) of solar photovoltaic (PV) energy systems powering Navy, Army and Air Force bases in at least 31 states and the District of Columbia. Combined, these installations provide enough clean energy to power 22,000 American homes.

    • Investment in solar energy technologies to power the armed forces will lower electricity bills, reduce carbon emissions and promote energy security at military installations across the country.

    • The U.S. Dept. of Defense (DoD) is the largest energy consumer in the world, with a $20 billion annual energy bill. Each year, the military uses as much energy as the entire state of Oregon.

    • As DoD budgets decline following federal sequestration, solar installations can help to rein in the military’s vast energy bill ($20 billion). Solar Boosts National Security

    • Today, from security and battlefield readiness to cost savings and efficiency, America’s military is turning increasingly to solar energy as a way to become an even more effective fighting force.

    • In Afghanistan, our troops on the front lines are using everything from portable solar panels to solar tent shields to solar-powered security systems to help them successfully carry out critical missions.

    • According to the New York Times, much of the solar technology being used by the military today is commercially available or has been adapted for the battlefield from readily available consumer products.

    • In recent years, the Pentagon has become increasingly concerned about on overdependence on fossil fuels. The military buys gas for just over $1 a gallon, but getting that gasoline to forward bases in Afghanistan costs $400 per gallon.

    • By utilizing more solar, U.S. Marines say they are not only saving money – but potentially lives, as well. Solar is helping to reduce the number of truck convoys needed to transport fuel, which are often the targets of attacks by insurgents or victims of IEDs. Our military has suffered more than 3,300 casualties over the past decade from attacks on fuel convoys.

    Current actions + goals

    • In recent years, the Navy, Army and Air Force have each implemented aggressive plans that have put the U.S. military on a path to significantly expand its use of clean, renewable solar energy. Each branch has outlined ambitious renewable energy targets that will drive 3 gigawatts (GW) of renewable energy installations by 2025.

    • All of these targets have been designed to help meet a wider DoD mandate, title 10 USC 2911, that requires 25 percent of total facility energy consumption to come from renewable energy sources by 2025.

    • The military has increasingly turned to solar energy to address DoD objectives and meet its renewables targets.

    • Solar has proven an effective alternative to traditional energy sources in a variety of roles for the DoD: large, centralized utility-scale solar projects to power bases; smaller, distributed-generation (DG) systems to supply buildings and homes; and portable solar systems to provide crucial energy on the battlefield.

    • As of early 2013, there are more than 130 megawatts (MW) of solar photovoltaic (PV) energy systems powering Navy, Army and Air Force bases in at least 31 states and the District of Columbia. Combined, these installations provide enough clean energy to power 22,000 American homes.


    • To date, the Navy has installed more solar than either the Army or Air Force, with more than 58 MW at or near bases in 12 states and DC.

    • The Navy plans to obtain 50% of its energy from renewable sources by 2025.

    • Solar is expected to be instrumental in the Navy’s efforts to meet these goals in the upcoming years. PV comprises 57 percent of all DON planned renewable energy capacity additions from 2012 to 2017 and provides the Navy with a more secure and independent generation mix.

    Air Force

    • The Air Force currently has 38 MW of solar capacity operating in 24 states, enough to power more than 5,600 American homes.

    • As the largest consumer of energy in the DoD, the Air Force has taken proactive and accelerated measures to diversify its generation mix and reduce energy costs. In the spring of 2012, the Air Force announced it would procure 1 GW of renewable power by 2016, exceeding all DoD mandates.

    • PV is planned to account for over 70 percent of all new Air Force renewable energy capacity added from 2012 to 2017.


    • The Army currently has more than 36 MW of solar installed at different bases in at least 16 states, enough to power well over 5,000 American homes.

    • The Army has also implemented plans to procure 1 GW of renewable energy capacity in an effort to satisfy the DoD’s 25 percent renewables by 2025 mandate.

    • Solar comprises a third of the Army’s planned renewable generating capacity additions from 2012 to 2017.


    WIND WORKS FOR BIRDS Terra-Gen gets OK on wind farm in wake of condor decision; U.S. officials approve project, which is taking advanced measures to keep turbines from harming condors. Earlier, Terra-Gen was told it would not be prosecuted if a condor is accidentally killed.

    Louis Shahagun, May 24, 2013 (LA Times)

    “…[The Tehachapi Mountains] will soon bristle with antennas and listening devices designed to protect endangered California condors…[at] the future home of Terra-Gen Power's 2,300-acre Alta Windpower Development…[T]hat project will include equipment to detect incoming condors soon enough to switch off the company's massive wind turbines before they slice into one of the birds. [It is a new standard for wind energy facilities]…

    “…The high-tech equipment and other steps Terra-Gen will take to avoid killing the endangered condors is the chief reason that the U.S. Fish and Wildlife Service has granted [the company’s 153-megawatt project, about 100 miles north of Los Angeles] a unique exception to the Endangered Species Act. For the first time, a company will not be prosecuted if it accidentally kills a condor. [Penalties for killing a condor can be up to $100,000 in fines and one year imprisonment for an individual, and up to $200,000 in fines for an organization. To date, there is no record of a condor fatality linked to a wind energy facility]…”

    “Fish and Wildlife officials say they believe the likelihood of killing a condor is low at Alta because it is outside the bird's historic range and it will be situated on the leeward slopes, where thermal updrafts are rare. Condors use updrafts to gain altitude and soar on 10-foot wingspans…To reduce possible harm to wildlife, including golden eagles, Terra-Gen voluntarily reduced the size of the project from 106 turbines to 51. The 450-foot-tall structures will be spread across four square miles, most of which is publicly owned…

    “…The system will include a telemetry system to track signals from radio transmitters already attached to tagged condors, radar to detect untagged birds and on-site biologists to report condor sightings. If a condor ventures within two miles, the speed of rotating turbine blades will be reduced within 2 minutes to about 3 mph. [The company plans to share its detection data with neighboring wind farms, an alternative energy hot spot in eastern Kern County with thousands of turbines that have been in operation for decades. The company also will provide $100,000 per year to condor recovery activities]…”

    SOLAR POWER TOWER NEARING COMPLETION Power in the Desert: Ivanpah on the Verge; Awesome or a blight on the desert? See Ivanpah, near completion in the Mojave, in all its glory.

    Pete Danko, May 23, 2013 (Greentech Media)

    “The giant Ivanpah solar thermal project in the Mojave Desert is now 92 percent complete…The 377-megawatt project consists of three 459-foot-tall towers encircled by arrays of garage-door-sized mirror sets. Those computer-controlled heliostats -- 153,990 out of 173,500 of which are now in place -- will reflect the sun onto the receiving towers, heating water to create steam that will drive turbines that produce electricity.”

    “The government-backed project has drawn criticism from some environmentalists, most notably for its impact on a fragile endangered desert tortoise habitat and, more recently, for dust problems linked to the development. But others view it as a remarkable step forward in the search for clean, sustainable energy…”

    UK NEW ENERGY WOULD SAVE RATEPAYERS BILLIONS Switch to low-carbon future would save households £1,600; A saving of £45bn should be good news, but the study’s conclusions clash with the pursuit of gas

    Tom Bawden, 23 May 2013 (UK Independent)

    “…Overturning the general consensus that green electricity is more expensive than gas-generated power, a parliamentary advisory committee finds that while ‘decarbonising’ the energy supply will cost more in the next few years, the expense will quickly become negligible and will save British households £45bn, or £1,600 apiece, after 2030…[And even if] Britain is sitting on vast amounts of accessible shale gas… – which won’t be clear for at least a few years - the case for a low-carbon energy revolution in the UK is still ‘robust’, adds the Climate Change Committee (CCC) report…

    “The report…provides by far the most [long term] comprehensive analysis of the relative cost of gas and low-carbon energy sources…It concedes that subsidies already in place to green Britain’s energy supply will add £100 to the average annual household energy bill between 2010 and 2020…[and that] a predominantly green energy supply - in which 90 per cent of electricity is generated from low-carbon sources by 2030 - would add a further £20 by the end of the next decade.”

    “But after that, the upfront costs of renewable energy plants such as wind and solar, will have been largely paid for, while developments in fledgling low-carbon technologies will dramatically reduce its cost – meaning that by 2050, consumers will be much better off than if the energy generators focused that investment on gas power plants…

    “…Britain is legally bound to generate 15 per cent of its energy – or about a third of its electricity – from renewable sources by 2020. But unless MPs vote through the 2030 decarbonisation amendment, there will be no low-carbon electricity target beyond 2020…The CCC’s £45bn [savings] estimate…could potentially rise as high £100bn – or more than £3,000 per household…”

    Tuesday, May 28, 2013


    The Net Benefits of Increased Wind Power in PJM Final Report

    May 9, 2013 (Synapse Energy Economics)


    By the end of 2012, wind power accounted for roughly 3.4% of PJM’s installed capacity supply (6,300 MW of approximately 185,000 MW total, excluding demand side resources). It provided 12,634 GWh of annual energy, about 1.5%% of PJM’s total. Over the next 13 years, the presence of renewable portfolio standards (RPS) in the PJM states will result in significant increases in supplied renewable energy, with most of the increase coming from wind power. PJM States have RPS goals for renewable resources totaling roughly 14% of all energy consumed by 2026. PJM estimates that about 11 of the 14%, or 108,539 GWh total, will be from wind in 2026.4 In this analysis, we examine the effects of roughly doubling the level of currently projected wind power in PJM by 2026, with much of the increase in wind installations beyond that of the “RPS case” or base case coming in the last five years of the 2013-2026 horizon analyzed.

    Increased transmission required to enable the base case will likely be in place by the turn of the decade or in the early part of the following decade, and additional transmission infrastructure coupled with the RPS case transmission overlays will allow for continuing integration of an increased amount of wind. Improved overall “flexibility”5 of the PJM system – arising from coal-fired power plant retirement and increasing installations of newer, flexible gas-fired combined cycle and combustion turbine resources coupled with key transmission improvements - will balance energy needs and allow the system to operate reliably even with a relatively high level of variable energy output from wind resources. Continuing declining costs and improving performance of wind power will lead to beneficial economic and emission results for consumers in PJM.

    These findings, based on the modeled year 2026, validate an economic preference for an energy future with greater levels of wind power than current renewable portfolio standards suggest. It is a future where wind-powered resources displace a significant portion of energy that would otherwise be obtained from traditional fossil fuels, all the while retaining sufficient resource adequacy to ensure reliable grid operation.

    Increased wind power displaces fossil-fueled generation, primarily gas and coal-fired production.

    It lowers emissions and exerts downward price pressure on wholesale energy markets. While not analyzed in this report, it creates jobs in installation and manufacturing across both the PJM region and other parts of the country, and its lowering of emissions reduces health costs. Even adding in the cost of wind-enabling transmission and recognizing that ongoing installations of gasfired resources will be required to offset the retirement of coal plants and add balancing capacity to the system, a doubling of wind power by 2026 relative to what would otherwise be in place with current RPS standards will allow consumers to reap economic and emission benefits.

    Purpose of Study

    Synapse conducted this analysis to assess the overall economic and emissions effect on PJM ratepayers of alternative electricity futures that include higher levels of wind than will be seen under current renewable standards. By testing the effects of different combinations of increased renewable energy supply, increased transmission infrastructure, reductions in the use of fossilfueled resources, and increases in the overall flexibility of the thermal resource base in PJM, we are able to draw broad conclusions about the relative benefits and costs to consumers of pursuing a clean energy future in the PJM region that roughly doubles the amount of wind power that would otherwise be in place by 2026 under current standards.

    Methodology and Key Assumptions

    Synapse modeled the economic and emissions effects of a PJM electricity future in 2026 that includes significantly higher levels of renewable energy (primarily wind) than a reference case tied to current state renewable portfolio standards (RPS). The reference case achieves an aggregate 14% RPS by 2026 across the PJM States, with most of that (11%) sourced from wind. The two wind cases developed for this analysis roughly double that level of supplied renewable energy, with increased wind power. One wind case distributes the wind around the PJM region; a second wind case allows for a portion of the total wind to be sourced from higher-performing wind regions (the Midwest) and then imported into PJM via high voltage DC lines.7

    The reference case includes transmission increases projected from PJM information on a planned RPS Overlay8, and the wind cases include incremental transmission beyond the planned RPS overlays to allow even higher levels of wind power to be integrated onto the grid. All cases include coal plant retirement and gas plant additions to ensure resource adequacy, and all cases presume that at least part of the cost of carbon emissions will be internalized; we use a $30/ton emissions adder for CO2 in 2026 to estimate this internalization. We ran one sensitivity without this adder for base and wind cases.

    Synapse used the ProSym production cost modeling tool9 to gauge energy impacts in year 2026 for each case. ProSym is an hourly dispatch and unit commitment production cost model that provides a detailed picture of the operation of the electric power sector over the course of a year. It uses a 10-zone configuration for the PJM system, and it performs a unit commitment and economic dispatch for 168-hour “typical weeks” over the course of the year, respecting variations in wind output and outages of conventional generation. It is based on an extensive assumption set, including load, resource mix, transmission system configuration, fuel prices, and operational constraints. The model output includes generation by resource type, marginal prices, and transmission flows for hourly periods of the year 2026.

    Synapse used a capital investment spreadsheet tool to track projected overall costs associated with generation, transmission, and demand response (DR) in each of the cases. It also tracked additional offshore wind capital costs for a sensitivity case. The tool tracked the year-by-year capital investment requirements, and used benchmark financial assumptions including a proxy for weighted average cost of capital, and depreciation periods to estimate annual revenue requirements associated with all new capital investment for each of the base and wind cases. Using the production cost modeling and capital investment accounting tool, Synapse computed production cost and energy market impacts from the wind cases, relative to the base case; and determined the incremental revenue requirements needed to pay for the increased capital investment of the wind cases. We then estimated the net impacts in 2026 of the alternative wind cases, relative to a base case using less wind (and more natural gas).

    An additional production cost simulation run was executed to test the sensitivity of the results to increased levels of offshore wind. Additional model runs were also conducted to help determine how the power system responds to different sets of resource addition or transmission addition assumptions. The results of those model runs provided important insights into the economics of power system operation under different resource assumptions, and helped to shape the final sets of resource assumptions used in the wind scenarios.

    The study did not build up overall rate impact effects on PJM consumers, but rather focused on the difference in aggregate impacts that would be seen from a base case when greater levels of wind are integrated onto the system. We note that net benefits accrue beyond the PJM region in this study, as the sizable increases in wind additions effect transfers at the PJM borders and the economic dispatch in adjacent Eastern Interconnection regions. The study added resource capacity to maintain planning reserve margins, with slightly higher margins for the wind cases in the out years (2020-2026) to address the increased operating reserve requirement that may be needed to integrate large levels of wind power. The study did not attempt to model any effects of the PJM RPM capacity market, which is a near-term, three-year forward construct. Our interest was long-term outcomes under clean energy scenarios; the annual revenue requirement construct was used to estimate the relative long-term investment outcomes.

    Synapse presumes that at least a portion of the societal costs of carbon emissions will be internalized across the PJM system by 2026, and to support a consistent comparative framework, we assumed the same carbon emission cost in all three scenarios. To test the broad cost/benefit outcomes in the absence of a carbon emission cost, we ran the production cost model without the carbon cost adder for the base and PJM wind case, but leaving coal retirement assumptions unchanged. In those model runs, we found the broad results still show net benefit: the production cost savings exceeded the capital investment for a net benefit of roughly $2.6 billion/year in 2026.

    Our key resource assumptions, listed in detail in Chapter 2, include the following:

    Key Findings

    Based on our findings, we conclude the following:

    1. The cost to increase wind installations and wind output across the PJM region up to 2 times beyond what current renewable portfolio standards call for by 2026 (including the costs associated with increased transmission, and gas generation investment needed to maintain resource adequacy margins) is more than offset by production efficiency gains seen across the broader PJM and interconnected regions. Wind output displaces coal, gas and oil-fired generation; this displacement is the source of the production cost (and corresponding reduced emissions) benefits we observe in the modeling results.

    2. We draw this conclusion based on the results of year 2026 ProSym production cost model runs, and our capacity/investment cost accounting model that includes the costs of all wind, transmission and gas resource supply requirements associated with the base and high wind scenarios. It estimates the annual investment cost requirements associated with each of the base and high wind cases, accounting for the timing of resource need and projections of investment or capital costs for the supply resources. The incremental investment costs for the high wind scenarios (compared to the base case) can be compared to the decreased production costs (compared to the base case) seen in the high wind cases.

    3. By 2026, our modeled wind scenarios (total PJM wind = 65.4 GW) lead to a production cost savings on the order of $14.5 to $14.9 billion dollars per year ($2026) compared to the base scenario (total PJM wind = 32.1 GW) that includes roughly half that level of installed wind.

    4. We computed annual revenue requirements for the incremental investment associated with the base and wind cases. The annual revenue requirement increase above the base case for the wind case ranges from $7.6 to $8.0 billion per year ($2026). Thus, net production cost efficiency gains from the increased wind scenarios are on the order of $6.9 billion per year by 2026, when the higher levels of wind are in place.

    5. Production cost efficiency gains from improved average wind resource performance (from a portion of wind resources sourced from the higher-performing MISO region) are roughly offset by the increased transmission costs to deliver those resources to PJM.

    6. PJM carbon emissions in the wind scenarios are 14% lower than base case emissions. SO2 emissions are 6% lower and NOx emissions are 10% lower than base case levels. Base case levels include the effect associated with retiring roughly 58 GW of coal-fired plants in PJM.

    7. Load-weighted average annual energy market prices in the PJM zones are lower under the wind cases. Average annual energy prices differences for the PJM zones in aggregate are roughly $1.74/MWh lower for the wind cases, relative to base case prices. This is generally expected given that wind output reduces, or displaces, the use of fossilfueled resources that set the market clearing price in PJM. The price differences are greatest in the non-summer months, when wind output is highest, load is lowest and supply margins are greatest.

    Notably for this study, peak load summer months see market prices higher in the wind cases relative to the base cases, reflecting the more difficult balancing act required in the high wind cases, the greater variation in wind output during those times, and the presence of a steep marginal cost of supply during those periods that renders clearing prices more sensitive to these factors than during less resource-tight months. In simpler terms: the wind cases see more summer peak period energy from “peaking” fossil resources, and less summer peak period energy from base-loaded and intermediate-loaded fossil resources, relative to the base case. This is a consequence of using economically optimal unit commitment and dispatch while respecting fossil-fuel plant operating constraints and the time profiles of wind output. It is also arises from increased exports from or reduced imports to the PJM zone, relative to the base case.

    Prices in regions adjacent to PJM are also lower, as the interconnected nature of the grid results in greater flows from PJM to those neighboring regions than is seen in the base case. This illustrates that some of the production cost efficiency benefits seen in the study could flow outside the PJM region, depending on how individual resource and load contractual arrangements are structured throughout the areas.

    8. If all production cost efficiency gains flow to consumers based on consumers paying the annual revenue requirements for incremental wind installed in the PJM region, then consumers are clearly much better off economically with increased wind resources, relative to a base case with less wind and more gas. In a market environment however, consumers would not pay the “annual revenue requirements” associated with the increases in wind power. Instead, they pay spot prices for power, and merchant investment would cover the costs of incremental wind – and receive spot market revenue streams. In this analysis, we assume that consumers both pay for the increased wind plant, and retain the production cost efficiencies that result.

    9. Increasing the amount of “PJM wind” that is sourced from further west regions, in this analysis modeled as MISO-sourced wind, leads to incrementally greater wind performance and higher production cost efficiencies. These savings are roughly offset by increased transmission costs associated with delivering more of this wind to PJM via HVDC lines, the proxy delivery method used in this analysis.

    Observations, Conclusions, and Next Steps

    Observations and Conclusions

    While analyzing the PJM system under different wind and gas resource addition assumptions, the modeling results clearly indicated that large, annual, net benefits from production cost efficiency gains exist for high wind scenarios. Displacing fossil-generated electricity with wind power leads to lower overall production costs. In most months, our modeling also indicates that PJM market prices are also lower in the wind cases. Tellingly, summer month periods with low levels of wind power output can still lead to higher market prices (compared to the base case) for those months in the high wind scenarios. This occurs because of the different mix of generation used, arising from the more complex operational solutions required (in the wind cases) when responding to large variations in wind energy output during those months. It is also influenced by the pattern of PJM to neighboring region imports and exports under the different scenarios. We summarize our observations and conclusions below.

    1. Increased installation of wind power resources in the PJM region at roughly double the levels specified by existing RPS statutes lead to annual production cost reductions that range from $14.5 to $14.9 billion per year. This result, arising from the use of the ProSym production cost modeling tool, is based on a set of reasonable assumptions concerning future carbon costs in the electric sector, load, coal retirement levels, natural gas resource additions, improved transmission system infrastructure, and natural gas prices.

    2. Consumers see significantly improved emission profiles in the wind scenarios. Carbon, SO2 and NOx emissions are all reduced.

    3. The incremental costs to achieve these production cost gains ranges from $7.6 to $8.0 billion per year by 2026. This indicates that in general a planned expansion of wind power in the region will lead to net benefits for consumers.

    4. The energy market price impact of a high wind case is seen to be relative high in nonsummer months, and market prices in the summer period are high in the wind cases. PJM consumers could be exposed to these market prices, but to the extent that PJM consumers pay for the incremental wind power assumed for the wind scenarios, consumers are hedged against those market prices. We assume that all production cost efficiency gains seen in this analysis flow to consumers, and all required investments are borne by consumers. We also note that the Eastern interconnection-wide nature of the energy modeling leads to a relative increase in exports from PJM in the wind cases, compared to the base case (with PJM net imports).

    Next Steps

    Additional analysis is required to determine the relative effects of varying any number of critical assumptions. To further test the robustness of the results seen in this analysis, Synapse recommends the following additional scenarios, or sensitivities, be analyzed using the production cost modeling and capital investment recovery model:

    1. Assume large scale retirements of coal plant resources throughout the Eastern Interconnection, not just in the PJM region. A rebalancing of capacity requirements in each major area would be necessary to ensure resource adequacy.

    2. Conduct iterative runs of the production cost modeling by incrementally stepping up transmission system transfer capacities, and simultaneously reducing the overall planning reserve margin, to optimize the tradeoffs between building more transmission and building sufficient balancing capacity with new gas-fired resources.

    3. Continue to test production cost effects on different combinations of increased demandside resources, including energy efficiency and demand response. Given the relatively high summer period prices and transmission congestion during those periods, it appears that non-wind related constraints can lead to increasing production costs, since summer wind output is relatively low in the model.

    4. Test the effects of multiple combinations of increasing wind, solar and energy efficiency resources.

    5. Test varying potential cost profiles for offshore wind and solar resources.

    6. Examine PJM boundary interactions, and assess the extent to which different import/export flow patterns are influenced by resource decisions within and outside of PJM.


    LOOKING AHEAD AT U.S. WIND AND SUN Short-Term Energy Outlook (STEO); U.S. Electricity and Heat Generation from Renewables

    May 2013 (EIA)

    “… EIA projects renewable energy consumption for power and heat generation to increase by 3.3 percent in 2013. While hydropower declines by 2.2 percent, non-hydropower renewables grow by an average of 7.1 percent in 2013. In 2014, the growth in renewables consumption for power and heat generation is projected to continue at a rate of 4.4 percent, as a 1.8‐percent increase in hydropower is combined with a 6.0‐percent increase in non-hydropower renewables.

    “EIA currently estimates that wind capacity will increase by 7 percent this year to nearly 63,000 megawatts, and reach almost 73,000 megawatts in 2014. However, electricity generation from wind is projected to increase by 19 percent in 2013, as capacity that came on line at the end of 2012 is available for the entire year in 2013. Wind‐powered generation is projected to grow by 8 percent in 2014.”

    “EIA expects continued robust growth in the generation of solar energy, both from central‐station and distributed capacity, although the total amount remains a small share of total U.S. generation. Central‐station capacity, which until recently experienced little growth compared with distributed capacity, is projected to more than double between 2012 and 2014…

    “Photovoltaics (PV) accounted for all central‐station solar growth in 2012, but EIA expects that several large solar thermal generation projects will enter service in 2013 and 2014. However, PV is still expected to account for the majority of central station and distributed capacity additions in 2013 and 2014…”

    GOOGLE BUYS FLYING WIND Google X Acquires Makani Power And Its Airborne Wind Turbines

    Frederic Lardinois, May 22, 2013 (AOL Tech)

    “After previously investing in the company, Google has now acquired Makani Power, a green energy startup that is currently building airborne wind turbines…Google invested $10 million…in 2006 and another $5 million in 2008…[This seems to mark] the first time Google has acquired a company specifically for its Google X skunkworks.

    “…Google CEO Larry Page [reportedly] approved the acquisition…[and said X has] the budget and the people to go do this…lMakani] was founded by Saul Griffith and Don Montague, a former World Cup windsurfer. The price of the acquisition was not disclosed…Google has confirmed this acquisition…[Makani hopes that the acquisition will provide resources to accelerate wind energy becoming cost competitive with fossil fuels. It comes just a week after the company completed the first autonomous flight of its Wing 7 prototype…”

    “Creating clean energy is one of the most pressing issues facing the world, [a Google statement said,]…Makani Power’s technology has opened the door to a radical new approach to wind energy. They’ve turned a technology that today involves hundreds of tons of steel and precious open space into a problem that can be solved with really intelligent software. We’re looking forward to bringing them into Google[X].

    “…The Makani Airborne Wind Turbines, which resemble mini airplanes, are launched when wind speeds reach 3.5 meters per second. Rotors on each blade help propel it into orbit, and double as turbines once airborne. The blades are tethered to the ground with a cord that delivers power to throw them into the sky and receives energy generated by the turbines to be sent to the grid-connected ground station.”

    TESLA PAYS BACK DOE LOAN WITH INTEREST Tesla Motors pays off Department of Energy advanced technology loan

    Jerry Hirsch, May 22, 2013 (LA Times)

    “Upstart electric car maker Tesla Motors…paid off a Department Energy loan that had become a political hot potato…Tesla owed the federal government $451.8 million on a loan that was part of a special program to develop alternative fuel vehicles and renewable energy sources…

    “Tesla has raised about $900 million this month in stock and debt offering deals and is expected to raise another $100 million in the coming days…Its shares have more than doubled in the last year, helped by the automaker’s first-ever quarterly profit earlier this month and its success selling the Model S electric sports sedan…The Energy Department’s loan program, which includes major automakers such as Nissan’s U.S. division, gained notoriety after the 2011 bankruptcy of Solyndra…cost taxpayers more than $400 million…”

    “Last month, Fisker Automotive of Anaheim defaulted on a similar loan, which could cost taxpayers $171 million…[Tesla will also use the money to expand sales abroad, develop its Model X, a sport utility vehicle, and start work on a less expensive vehicle that would extend its customer base and manufacturing volumes]… The [stylish, fast] Model S starts at about $62,000 and can top $100,000, depending on trim level and options…”

    [Ernest Moniz, Secretary, Department of Energy:] “When you’re talking about cutting-edge clean energy technologies, not every investment will succeed…but today’s repayment is the latest indication that the Energy Department’s portfolio of more than 30 loans is delivering big results for the American economy while costing far less than anticipated.”

    Monday, May 27, 2013


    The Benefits and Costs of Solar Distributed Generation for Arizona Public Service

    R. Thomas Beach and Patrick G. McGuire, May 8, 2013 (Crossborder Energy)

    This report provides a new cost-benefit analysis of the impacts of solar distributed generation (DG) on ratepayers in the service territory of Arizona Public Service (APS). On January 23, 2013, the Arizona Corporation Commission ordered APS to conduct a multi-session technical conference to evaluate the costs and benefits of renewable DG and net energy metering (NEM), as part of the ACC’s consideration of the APS Renewable Energy Standard (RES) 2013 Implementation Plan. This report is intended to contribute to the technical conferences and the ACC’s future deliberations on the APS 2013 RES Plan, and to provide a different perspective than the studies on the value of solar DG that APS commissioned in 2009 from R.W. Beck (the “Beck Study”) and in 2013 from SAIC (the “SAIC Study”), which recently acquired R.W. Beck.

    The scope of this report is limited to assessing how demand-side solar will impact APS’s ratepayers. In the context of the cost / benefit evaluations of demand-side programs, this analysis is a ratepayer impact measure (RIM) test. It is not a total resource cost (TRC) test that would look more broadly at whether distributed solar resources provide net benefits to Arizona. Generally, policymakers should look at a variety of cost-benefit tests, including the broad TRC test, in evaluating whether to initiate, continue, or expand a demand-side program.

    In assessing the benefits and costs of solar DG from a ratepayer perspective, it is important to use a time frame that corresponds to the useful life of a solar DG system, which is 20 to 30 years. This treats solar DG on the same basis as other utility resources, both demand- and supply-side.

    When a utility assesses the merits of adding a new power plant, or a new energy efficiency (EE) program, the company will look at the costs to build and operate the plant or the program over their useful lives, compared to the costs avoided by not operating or building other resource options. A central problem with the Beck and SAIC Studies is that they assess the benefits of solar DG only in a single-year “snapshot,” without considering the long-term benefits of the solar resource over its full expected life.

    In addition, solar DG provides significant benefits as a resource that can be scaled easily, from a system serving a single home to utility-scale plants, and that can be installed with shorter lead times and on a wider variety of sites compared to large-scale fossil generation resources. As APS itself recognizes in its 2012 IRP, DG combines with other small-scale, short-lead-time, demand-side resources such as EE and demand response (DR) programs to reduce APS’s need for supply-side generation, both in the near- and long-terms. The Beck and SAIC Studies do not recognize these benefits of solar DG resources; instead, they first construct "blocks" of solar DG of different sizes, corresponding to different scenarios for solar DG penetration, and then analyze each block as though it were a conventional large-scale power plant. As a result, these studies calculate few capacity-related benefits from solar DG except in the higher penetration scenarios that are years in the future. In reality, solar DG and APS’s other demand-side programs combine to continuously avoid the need for supply-side resources, and all of these resources should be assigned capacity value commensurate with this role and on a comparable basis.

    This report relies on data from APS’s 2012 Integrated Resource Plan (2012 IRP), supplemented with data from the Beck Study and with data presented in the series of technical workshops that APS held in March and April 2013. Our intent in using this data is to minimize debates over the input assumptions. We also have used a limited amount of current data from the regional gas and electric markets in which APS operates. Our approach to valuing solar DG makes two key changes to the Beck and SAIC studies: first, our analysis is performed over 20 years, instead of just for single years; and, second, we evaluate the benefits of solar DG based on the change in APS’s costs per unit of solar DG installed, without requiring solar DG to be installed in the same “lumpy” increments as large-scale conventional generation. We also draw upon relevant analyses that are standard practice in other states, including the avoided cost “calculator” for demand-side programs adopted by the California Public Utilities Commission (CPUC), as well as new studies such as the value-of-solar analysis that Clean Power Research (CPR) used in developing the solar tariff for Austin Energy.

    The costs of solar DG for APS ratepayers are principally the lost revenues from solar DG customers who use their on-site solar generation to serve their own loads and who export excess output back into the grid, thus running the meter backward using net energy metering (NEM). For the costs of solar DG, we rely on data that APS reports on the 20-year levelized rate credits that both residential and business customers who install solar DG will realize from the output of their net-metered systems. Finally, on the cost side we also include APS’s remaining DG incentives and the utility’s calculated costs to integrate intermittent solar generation into the grid.

    Our work concludes that the benefits of DG on the APS system exceed the cost, such that new DG resources will not impose a burden on APS’s ratepayers. The following table summarizes our results. The benefits exceed the costs by more than 50%, with a benefit / cost ratio of 1.54. The benefits also exceed the costs in both the residential and commercial markets considered individually. Based on SAIC’s projection of 431,000 MWh of incremental solar DG in 2015, these benefits amount to $34 million per year for APS’s ratepayers…

    Benefits of Solar DG

    a. Energy

    APS’s 2012 resource plan makes very clear that the utility’s marginal sources of generation are principally natural gas-fired resources. In addition, APS expects renewable generation to compete with, and potentially to displace, a portion of these future gas-fired resources:

    APS foresees the ability to treat natural gas and renewable energy resources as competing levers during this time period, and resource decisions can be modified from the current plan based on the relative tradeoffs between those fuel sources throughout the intermediate-term stage. For example, APS plans to add over 3,700 MW of natural gas generation capacity and 749 MW of renewable coincident-peak capacity during this stage. In the event that solar, wind, geothermal, or other renewable resources change in value and become a more viable and cost-effective option than natural gas, future resource plans may reflect a balance more commensurate to the Enhanced Renewable Portfolio.5

    In the future, to the extent that APS’s customers invest in demand-side resources, including on-site solar DG, the resources displaced will be new gas-fired generation.

    Accordingly, APS’s future avoided energy costs are the energy costs of APS’s long-term gas-fired generation resources. To estimate these avoided costs, we first develop a long-term forecast of APS’s burnertip cost of gas at its power plants. This forecast uses current (April 1, 2013) forward gas price data from the NYMEX Henry Hub market, the basis differential from the Henry Hub to the Permian basin, plus variable delivery costs over the El Paso Natural Gas (EPNG) system to APS’s plants in Arizona. Figure 1 compares this projection to APS’s 2012 IRP cost of gas forecast6 and to the APS gas cost forecast for 2015, 2020, and 2025 (based on the December 31, 2012 forward market) which SAIC has used. Our gas cost forecast is very similar to the SAIC forecast.

    Because our forecast is based on forward market natural gas prices, it represents a cost of gas that APS could fix for the next 20 years. This captures the fuel price hedging benefit of renewable DG, which has no fuel costs and thus avoids the volatility associated with generation sources whose cost depends principally on fossil fuel prices.

    Figures 5-3 and 5-5 of the Beck Study show that solar DG systems on the APS system typically displace combustion turbine (CT) generation during the four peak summer months (June-September) and combined-cycle (CCGT) generation in other months. We assume that solar DG avoids generation from new, efficient, state-of-the-art gas plans, with heat rates of 9,400 Btu/kWh for CTs and 7,300 Btu/kWh for CCGTs, plus the corresponding variable O&M costs for such generation.8 We use our gas price forecast as the fuel costs for these avoided resources. We note that the resulting avoided energy costs in the near term (2014-2015) are close to current forward market prices for the Palo Verde trading hub, as shown in Figures 2 and 3. We also include APS’s 2012 IRP forecast of greenhouse gas (GHG) allowance costs ($15 per metric ton, starting in 2019) as an adder to the gas price forecast,9 using the standard natural gas CO2 emission rate (117 lbs/MMBtu). Finally, we assume that APS will avoid marginal line losses of 12.1%, based on the detailed analysis of the loss impacts of solar DG that is in the Beck Study.10 W ith these inputs, our Base Case forecast of APS’s avoided energy costs for solar DG is a 20-year levelized value of 7.1 cents per kWh, in 2014 dollars.

    In addition, we have modeled two sensitivity scenarios for APS’s avoided energy costs for 2019 and subsequent years. The first is a High Case which assumes APS’s High projection of GHG costs from the 2012 IRP. The second sensitivity is a Low Case with zero GHG costs for the next twenty years, which is the Low GHG scenario from the 2012 IRP.

    Figure 2 shows our Low, Base, and High avoided energy cost forecasts for the peak months of June – September; Figure 3 presents the results for the off-peak months of October through March. Table 2 summarizes the resulting 20-year levelized avoided energy costs for solar DG in APS’s service territory, including avoided line losses.

    SAIC used the results of APS’s confidential production cost modeling to estimate avoided energy costs; the SAIC results are shown in the second column of Table 3, below. These modeling results are too low to be credible as long-run avoided energy costs for the resources displaced by solar DG. The final column of Table 3 shows the marginal heat rates that are implicit in these results, based on the SAIC/APS natural gas and GHG cost forecasts. These heat rates are far lower than the heat rates of even the most efficient new gas-fired resources, indicating that APS’s modeling either (1) assumes that solar DG often displaces APS’s existing coal-fired generation or (2) reflects only the low, short-run incremental costs of moving already-operating gas plants in the western U.S. from one loading point to another. Moreover, even if this modeling is realistic, it understates APS’s avoided opportunity costs of selling its excess generation into the regional energy market at Palo Verde and other trading hubs, as shown in Figures 2 and 3. In sum, these results significantly understate the long-run energy costs avoided by solar DG resources which will completely displace the need for and the full costs of future gas-fired units.

    b. Generation Capacity

    The 2012 IRP finds that APS does not need new large-scale, fossil resources until 2017.11 However, the 2012 IRP shows continued growth in energy efficiency and demand response programs and in distributed solar resources between 2012 and 2017 (see Table 2), such that the new demand-side resources will contribute 1,150 MW to meeting APS’s peak demands in 2017. Solar DG, along with energy efficiency and demand response, thus contributes to deferring any resource need until 2017. As a result, solar DG installed before 2017 has greater value than just avoiding short-term energy costs. DG also hedges against events that could accelerate the 2017 need, such as unexpected increases in demand (from an accelerating economic recovery) or the loss of existing resources (for example, nuclear plant shutdowns such as the recent problems at the San Onofre plant in southern California).

    Combustion turbines are the least-cost source of new utility-scale capacity. CTs are the long-term peaking resource typically displaced by solar DG, and are the resource that APS expects to add in 2017. The Beck and SAIC Studies use the fixed costs of a new CT to calculate solar DG’s generation capacity value. The CT fixed costs in the Beck Study were based on a CT capital cost of $1,088 per kW in 2008, times a fixed charge rate of 11.79% to convert to an annual levelized value.12 The 2012 IRP cites CT capital costs in a range of $600 to $1,400 per kW, with heat rates from 8,900 to 11,900 Btu/kWh for a variety of brownfield and greenfield projects.13 SAIC is using a CT capital cost of $1,136 per kW, plus $206 per kW in gen-tie transmission.14 Following the Beck and SAIC Studies, we also have included (and updated) the fixed O&M costs and the El Paso Natural Gas pipeline reservation costs for a new CT built in APS’s service territory. As shown in Table 4, we calculate that APS’s levelized avoided capacity costs are $190.10 per kW-year in 2014 dollars.

    The CT fixed costs are multiplied by the effective load-carrying capacity (ELCC) of PV generation. At the present level of solar PV penetration, this adjustment is 50% for a fixed array and 70% for an array with single-axis tracking. APS used these adjustments in the 2012 IRP to determine the firm capacity of solar resources, including resources that will be developed in the 2013-2015 time frame.15 The resulting avoided generation capacity costs are shown in Table 4.

    This analysis focuses on the value of solar to be developed in the next several years (2013-2015). The Beck and SAIC Studies indicate that, if solar penetration increases significantly, the capacity value of solar that is installed in 2020 and 2025 may be lower than today, as the increased amounts of installed solar resources shift APS’s afternoon peak to later in the day. This possibility does not diminish the capacity value of solar installed today; indeed, the decline in capacity value in 2020 and 2025 will not occur unless substantial amounts of solar are installed over the next twelve years. Finally, the Beck / SAIC result that the capacity value of solar will decline over time assumes that the future will look like today, only with more solar. This is unlikely to be true. For example, other trends, such as hotter summers resulting from climate change, could increase future peak demands by more than expected, and offset the impact of solar additions. Customers also can respond to the changing mix of resources. If additional solar reduces the price for grid power in the afternoon, if those prices are conveyed in accurate price signals, and if customers have greater choice and control over when and from where they consume electricity, consumers will respond by shifting consumption from the evening to the afternoon – i.e. the opposite of what DR tries to achieve today – pre-cooling homes, running appliances remotely, and filling batteries in the afternoon instead of the evening.

    c. Ancillary Services and Capacity Reserves

    The Beck Study found that the intermittency of solar DG is unlikely to increase the ancillary services or operating reserves that APS must supply to ensure reliable service, given the geographically dispersed nature of DG systems.16 The study did not consider, however, the fact that DG will result in a reduction in the loads that APS will serve, because the majority of DG output will serve the on-site load of the DG host customer or will run the customer’s meter backward if power is exported. WECC reliability standards require control area operators to maintain operating reserves (spinning and non‐spinning) equal to 7% of the load served by thermal generation. As a result, load reductions from DG will reduce APS’s requirements to procure operating reserves. In addition, APS must maintain a capacity reserve margin of 15%. Thus, each kW reduction in APS’s peak demand from DG will reduce the utility’s capacity requirements by 1.15 kW. We model these avoided ancillary service and capacity reserve requirements as 7% of Base Case avoided energy costs from Table 217 and 15% of the south-facing avoided generation capacity costs from Table 4. These avoided ancillary service and capacity reserve costs are summarized in Table 5.

    d. Transmission

    The Beck Study reported that APS incurs $125 million in high-voltage transmission costs for every 400 MW increase in peak demand, and $7 million in lower-voltage subtransmission costs per 30 MW of load growth.18 The SAIC April 11 presentation, at slide 63, shows $29.5 million in deferrable subtransmission costs for a 130 MW decrease in peak demand. In the long-run, solar DG combines with EE and DR resources to defer such costs even if, over a short-term period such as a three-year transmission planning cycle, none of these small-scale resources individually amounts to 400 MW or to the smaller amounts in specific areas that is required to defer subtransmission projects. Given that EE, DR, and DG resources will combine to reduce APS’s peak demands by 1,150 MW in 2017, it seems clear that, in aggregate, these resources will avoid significant transmission costs on the APS system. Escalating these avoided transmission and sub-transmission costs to 2014 and using the current APS carrying charge of 11.05% for transmission yields a levelized avoided transmission cost of $65.14 per kW-year, as shown in Table 6. As with avoided generation capacity costs, we apply the solar ELCC values to the avoided transmission costs, in recognition that peak solar output does not necessarily coincide with system peak demands.

    e. Distribution

    The Beck Study examined a range of possible DG impacts on distribution system costs. These impacts are more location-specific than the effects of DG on the generation or transmission systems. The Beck Study concluded that distribution capacity cost savings are possible if demand reductions from DG exceed load growth on distribution feeders or substations, and if solar DG can be targeted to specific locations where circuits would otherwise need an upgrade.19 The study valued these reductions using a distribution avoided cost of $115,000 per MW of DG ($115 per kW).20 SAIC has now backed away from these results, arguing that it could identify only 5-9 circuits on which installed PV capacity reduced the circuit peak to below the 90% of capacity threshold at which the utility begins to plan an upgrade.21 Yet this appears to be an appreciable fraction of the 30-40 circuits that APS upgrades each year.22 Moreover, even on a circuit whose loading is below the 90% threshold today, PV can reduce the peak loading and defer the future date when that circuit’s loads exceed the 90% threshold, a date that may be beyond the current distribution planning period but well within the lives of the installed PV systems. The Beck Study reported that 50% of the feeders modeled show potential for reducing peak demand and deferring capital improvement projects.23 Avoided distribution capacity costs can be valued using the same approach applied to transmission costs in Table 5, with the additional assumption that PV can avoid distribution costs on 50% of circuits. Table 7 presents these results.

    f. Environmental

    With the exception of greenhouse gas emissions, the Beck and SAIC studies have not quantified any of the environmental benefits of renewable generation, such as reductions in criteria air pollutants (SO2, NOx, and PM 10) and decreased water use for electric generation. APS did quantify these benefits in the 2012 IRP, however. The utility calculated both the reduced emissions of these pollutants and the lower water use, per MWh of renewable generation,24 and included estimates of the dollar value of such reductions.25 Table 8 summarizes these environmental benefits.

    g. Avoided Renewables Costs

    Solar DG helps APS to meet Arizona’s Renewable Energy Standard (RES) requirements. The Arizona RES regulations include a requirement that APS must procure renewable generation equal to a certain percentage of its sales, with the percentage increasing from 4.0% in 2013 to 10% in 2020 and 15% by 2027. The RES requirement also provides that, after 2011, 30% of the new renewable generation meeting the RES standard must be DG resources. Pursuant to Arizona Corporation Commission (ACC) Decision No. 71448. APS also must procure an additional 1,700,000 MWh of incremental renewable generation by December 31, 2015.26 The Beck Study did not attribute any value to DG’s contribution to meeting APS’s RES requirements. However, because it is customers who make investments in DG resources, not APS, such customer-owned resources allow the utility to avoid the higher capacity-related costs of renewable power.

    APS has also argued that solar DG does not avoid the costs of other renewable resources because APS already has procured adequate renewables to meet its RES requirement. However, all of these resources are not yet on-line, so solar DG may hedge against the failure of some of the utility-scale renewables with which APS has contracted. Moreover, APS itself recognizes that, in the long-run, it may have to procure renewables beyond today’s RES requirements. The 2012 IRP includes an Enhanced Renewable Portfolio which assumes that APS increases the contribution of renewable energy to 30% of retail sales by 2025 and meets 90% of load growth with emissions-free resources. In addition to further reductions in emissions of greenhouse gases and criteria air pollutants, there are economic reasons to procure additional renewables. For example, the 2012 IRP notes that, in both the intermediate- and long-terms, “renewable resources have the ability to diversify the overall portfolio of resources and provide mitigation against the inherent price volatility risks associated with a natural gas-dominated energy mix.”27

    Renewable generation also results in a number of difficult-to-quantify benefits, including:

    • Price mitigation benefits. Lower demand for electricity (and for the gas used to produce the marginal kWh of power) has the broad benefit of lowering prices across the gas and electric markets in which APS operates.28

    • Grid security. Renewable DG resources are installed as many small, distributed systems and thus are highly unlikely to fail at the same time. They are also located at the point of end use, and thus reduce the risk of outages due to transmission or distribution system failures. This reduces the economic impacts of power outages.

    • Economic development. Renewable DG produces more local job creation than fossil generation, enhancing tax revenues.

    We assume that the additional cost of renewable generation provides a proxy for these benefits. These benefits have been calculated separately in at least one study, which estimated these benefits collectively to be from $100 to $140 per MWh in several eastern U.S. markets.29

    For the APS system, the 2012 IRP includes APS’s estimates of the incremental cost of renewables. The Enhanced Renewable scenario in the 2012 IRP features additional purchases of renewables in the 2017-2026 time frame, totalling 4,532 GWh of additional renewable generation by 2026 compared to the Base case (about 500 GWh per year in additional renewable generation).30 The 2012 IRP includes annual revenue requirements for both the Base and Enhanced Renewable scenarios; the difference between these revenue requirements allows one to calculate the annual cost premium for the incremental renewables in the latter scenario.31 The cost premium for these purchases averages $46.55 per MWh from 2017-2026 ($45.27 per MWh on a 10-year levelized basis).32 We use this premium as the measure of the costs which APS will avoid if APS’s customers invest in solar DG, reduce the future need for APS to purchase additional wholesale renewable generation, and provide the benefits listed above. This appears to us to be a conservative estimate of the value of additional customer-driven renewable generation on the APS system over the next 20 years.

    3. Costs of Solar DG

    The primary costs of solar DG are the retail rate credits provided to solar customers through net metering, i.e. the revenues that the utility loses as a result of DG customers serving their own load. Data responses from APS to the ACC staff in the 2013 RES case33 include calculations of the 20-year levelized retail rate credits (i.e. the lost revenues for APS) resulting from DG, as well as the costs of the current incentives paid to customers who install DG. In the technical workshops, APS also has provided Vote Solar with its estimates of residential and commercial lost revenues. For residential customers, the retail rate credits amount to 15.5 cents per kWh; for business customers, the credits are 7.1 cents per kWh.34 APS has assumed a retail rate escalation of 2.5% per year and an 8% discount rate.35 These assumptions produce 20-year levelized retail rate credits of 19.7 cents per kWh for residential and 9.0 cents per kWh for commercial (2014 $). Assuming the current mix of residential and commercial systems, the average rate credit is 13.7 cents per kWh.

    With respect to incentive costs, the 20-year levelized cost of the current 10 cents per watt residential upfront incentive is 0.6 cents per kWh. We understand that APS has proposed to eliminate these residential incentives, so they may be zero in the future. APS also has eliminated business incentives, except for school and government projects.

    Finally, we add an estimate of solar integration costs using a recent study which APS commissioned which estimated integration costs of $2 per MWh in 2020 and $3 per MWh in 2030.36 We assume that these costs scale to other years as a function of gas costs. Table 1 and Table 9 summarize all of these costs of DG for APS’s ratepayers.

    4. The Context for this Cost / Benefit Analysis

    The Beck and SAIC Studies calculate the benefits of DG – i.e. the “value of solar.” These benefits could be used in a cost-benefit evaluation of solar DG, such as is presented in the report. The Beck and SAIC Studies do not discuss the cost side of the equation, or attempt to apply any of the standard cost-effectiveness tests to DG. We assume that APS will use a new calculation of the benefits of DG in a ratepayer impact test, such as the one presented in this report.37 The conclusion of this report is that solar DG with net metering is cost-effective for non-participating ratepayers in APS’s service territory.

    We emphasize that the ratepayer impact perspective should not be the only one which policymakers examine in deciding on future policies affecting solar DG in Arizona. The RIM test often is considered the most rigorous of the cost-effectiveness tests for demand-side resources; passing the RIM test with a benefit / cost ratio greater than 1.0 means that there are “no losers” from a demand-side resource. Nonetheless, a full analysis of solar DG as a resource also should consider additional cost-effectiveness perspectives, such as societal, total resource, participant, and program administrator tests.38 Other demand-side programs typically are evaluated from these multiple perspectives, and policymakers should take a similarly broad view in assessing distributed generation programs.