NewEnergyNews: 02/01/2013 - 03/01/2013/


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

    Thursday, February 28, 2013


    The Surprising Way Obama Is Trying to Tackle Climate Change

    Azmat Khan, February 27, 2013 (PBS Frontline)

    [Coral Davenport, energy and environment correspondent, National Journal:] “There are two ways to tackle climate change: One is mitigation, [such as] policies that stop emissions, stop carbon. The other is adaptation…The White House has tasked all of the federal agencies with coming up with adaptation plans…ways for farmers to adapt to the drought…[ways for] transportation and housing and urban development departments[to] help cities and towns adapt to the storms…[ways to] build [safer] roads and bridges [and infrastructure]…[for] higher sea levels…[and] flooding…”

    [Coral Davenport, energy and environment correspondent, National Journal:] “The issue of climate change remains surprisingly inflammatory. There is a significant [part] of the Republican Party and of the Tea Party that questions the science of climate change… [T]he president just doesn’t want to take the conversation that direction…[O]utreach by federal agencies…[does not get] a high-profile fight…about the politics of climate change…[but gets a] conversation on climate change…into town halls and city halls and planning boards and zoning boards where it’s not partisan…It becomes treated as a matter-of-fact set of issues…baked into how communities are planning…”

    [Coral Davenport, energy and environment correspondent, National Journal:] “…[I]t seems very clear that Congress is going to fail to act, in which case the Environmental Protection Agency (EPA) does have, under the Clean Air Act…That is a top-down, very aggressive move. It’s sort of a last resort [because] it’s very politically unpopular…EPA is expected to put out final rules essentially saying that companies building new electric utilities will have to limit the emissions…[and saying] existing coal plants will have to cut their emissions…It’s probably going to cause some coal plants to shut down…cost them jobs…have a big environmental impact…[and] cut U.S. carbon pollution. But it will have huge political pushback…”

    [Coral Davenport, energy and environment correspondent, National Journal:] “…Shortly after the president’s State of the Union speech in which he called on Congress to act, [Senators Barbara Boxer (D-Calif.) and Bernie Saunders (I-Vt.)], …two of the most liberal members of the Senate, …[introduced] a sweeping and aggressive climate change bill…that would tax carbon emissions. Environmentalists love it, and it’s very clear that it has no chance legislatively at all…The idea is to publicly make an effort in Congress to have a clash, and send the message to the American public [that Congress failed]…[I]t gives the EPA time to gather and write these very difficult and complicated rules…”


    Is China Now the ‘New’ Germany of PV Demand?

    Michael Barker, February 20, 2013 (SolarBuzz)

    “The second half of 2012…cemented the rise of China as a major force in global PV demand, complementing its place as a leader in the upstream supply side…for several years…aided in no small part by government assistance at the provincial (driven by local job creation goals) and national (supporting a key industry sector) levels.

    “Germany…has seen its production base dwindling over the past few years, while remaining the largest single-country end-market in the world. But this changed at the end of 2012 when China passed it…[T]his trend is now set to continue for many years…[overlapping with industry uncertainty] caused by European trade investigations.”

    “…[I]f this trade dispute is to restrict the European market from Chinese-produced PV products, it may cause a severe bifurcation within the industry into China and non-China based supply/demand environment. Chinese manufacturers that lack the ability to pursue partnerships/acquisitions in Europe may [have to]…put all their efforts into securing projects in their own end-market.

    “…Already, some Chinese manufacturers have exploited local end-market growth to boost Y/Y shipments and increase their market-share globally. If this trend continues in 2013, it is possible that China will become the largest – and for many the only – market for domestic supply…[But] over-dependence on any one market comes with considerable risks to PV manufacturers…A major development to watch…will be how China manages domestic supply to meet its own PV demand climate over the next 12-18 months. The related issue is how Tier 1 Chinese manufacturers adapt to the situation outside of China to keep a strong pipeline of global opportunities going forward.”


    As economics shift, wind developers see the light on solar power

    Dan Haugen, February 25, 2013 (Midwest Energy News)

    “…An ongoing lull in wind projects and falling solar panel prices has wind companies looking to add solar projects to their portfolios…In the U.S., 2013 is projected to be a lost year for the wind industry, which added more than 13 gigawatts of capacity in 2012 but could do as little as 3 gigawatts this year in the aftermath [of the PTC controversy and delay]…

    “…[S]olar is surging…[and] could surpass new wind additions this year for the first time ever…[I]nstead of sitting on their turbines, wind developers are diversifying, hiring solar experts and broadening their portfolios to include photovoltaics…The trend extends throughout the supply chain, from consultants to construction and engineering firms. Some companies are even dropping the word “wind” from their names.”

    “EDF Renewable Energy…is developing one of the country’s largest solar-wind hybrid projects in California’s Mojave Desert, pairing a 140-megawatt wind farm with a 143-megawatt solar farm…Solar is still a relatively small part of EDF’s portfolio — it’s developed less than 300 megawatts of solar compared to more than 3,500 megawatts of wind. But its solar business been growing in recent years with an eye towards the current wind slowdown…

    “…[D]isruptions have been an unavoidable part of doing business in the renewable energy world, idling industries every few years as incentives come up for renewal…As much as uncertainty over incentives pushed wind companies to think about other opportunities, the pull of solar power’s rapidly improving economics has been a more important factor...[Much] existing expertise easily transfers from wind to solar..[like] GIS mapping, real estate contracts, and transmission issues…And the customers are often the same, too…”


    2013 Hurricane Sandy Responsiveness Study…State Governments and Electric Utilities Provided More Effective Emergency Responsiveness During Hurricane Sandy than Did Local and Federal Governments

    21 February 2013 (J.D. Power & Associates)

    “Overall, state governments and electric utilities provided more effective responsiveness and handling of the 2012 Hurricane Sandy emergency than did local and federal governments, according to the J.D. Power and Associates 2013 Hurricane Sandy Responsiveness Study…The emergency responsiveness of state governments and electric utilities (611 and 610, respectively, on a 1,000-point scale) surpass local governments (598) and the federal government (539) in overall responsiveness to the emergency [based on preparedness for the hurricane; efforts to support hurricane recovery; and effectiveness of communications.]…

    “Hurricane Sandy's damage is estimated at $50 billion and is considered the second-costliest hurricane in U.S. history. During the October 2012 hurricane event, approximately 8.5 million customers lost power, and 65,000 utility workers responded from 80 utilities from nearly every state and Canada, dispatching crews and equipment to impacted areas.3 During the hurricane, 43 percent of all customers surveyed experienced a power outage lasting 24 hours or longer. The average outage duration among all customers surveyed was 48 hours…”

    “The Connecticut, Delaware and New Jersey state governments perform highest in the study…Ohio, Pennsylvania and West Virginia perform lowest…Customers in New Jersey, New York and West Virginia rate the federal government lowest…Maine and Maryland rate the federal government highest in responsiveness…Among customers with extensive outages (average length of 24 hours or longer)…Atlantic City Electric, Central Hudson Gas & Electric and PPL Electric Utilities…[and local governments] within the counties of Bronx New York, Burlington New Jersey and New Haven Connecticut [peformed well].

    “…Customers received most of their information regarding the outage by calling their utility directly (37%); listening to radio or watching TV (29%); and going directly to their utility's website (17%). Nearly three-fourths (71%) of customers who made contact with their utility during the outage used their mobile cellphone or smartphone. Satisfaction is highest among customers who say they received proactive outbound communications, in which their utility sent emails, text messages or outbound phone calls…”

    Wednesday, February 27, 2013


    2013 Annual US Geothermal Power Production and Development Report

    February 2013 (Geothermal Energy Association)

    Key Statistics from 2013

    US Industry Statistics

    • Installed geothermal power capacity grew by 5% or 147.05MW in the United States since GEA’s last survey in March 2012.

    • Seven geothermal projects became operational in 2012, including the first coproduction plant. Additionally, the first hybrid solar-geothermal plant went online this year, although no new geothermal capacity was added at this plant.

    • There are currently 175 geothermal projects under development in the U.S.

    • About 5,150-5,523 MW of known geothermal resources are under development in the U.S., of which geothermal developers are developing 2,511-2,606 MW in potential capacity additions over the next decade.

    • GEA revised its last year’s estimate of total installed capacity to increase its estimate by 128 MW. Currently 3,386 MW of geothermal power are installed in the United States.

    Geothermal Resource Types and Their Definitions

    In reporting a project in development to the GEA, the developer of a geothermal resource is asked to indicate which of the following definitions the project falls under:

    Conventional Hydrothermal (Unproduced Resource): the development of a geothermal resource where levels of geothermal reservoir temperature and reservoir flow capacity are naturally sufficient to produce electricity and where development of the geothermal reservoir has not previously occurred to the extent that it supported the operation of geothermal power plant(s). Such a project will be labeled as “CH Unproduced” in this report.

    Conventional Hydrothermal (Produced Resource): the development of a geothermal resource where levels of geothermal reservoir temperature and reservoir flow capacity are naturally sufficient to produce electricity and where development of the geothermal reservoir has previously occurred to the extent that it currently supports or has supported the operation of geothermal power plant(s). Such a project will be labeled as “CH Produced” in this report.

    Conventional Hydrothermal Expansion: the expansion of an existing geothermal power plant and its associated drilled area so as to increase the level of power that the power plant produces. Such a project will be labeled as “CH Expansion” in this report.

    Geothermal Energy and Hydrocarbon Co-production: the utilization of produced fluids resulting from oil and/or gas-field development for the production of geothermal power. Such a project will be labeled as “Co-production” in this report.

    Geopressured Systems: the utilization of kinetic energy, hydrothermal energy, and energy produced from the associated gas resulting from geopressured gas development to produce geothermal electricity. Such projects will be labeled as “Geopressure” in this report.

    Enhanced Geothermal Systems: is the development of a geothermal system where the natural flow capacity of the system is not sufficient to support adequate power production but where hydraulic fracturing of the system can allow production at a commercial level. Such a project will be labeled as “EGS” in this report.

    Tracking Projects through the Development Timeline

    In addition to defining their projects according the above list of definitions, developers also indicate to GEA their projects’ current status in the project development timeline using a fourphase system. This system captures how much, and what type of, work has been performed on that particular geothermal resource up until the present time. These four phases of project development are:

    Phase I: Resource Procurement and Identification

    Phase II: Resource Exploration and Confirmation

    Phase III: Permitting and Initial Development

    Phase IV: Resource Production and Power Plant Construction

    Each of the four phases of project development is comprised of three separate sections, each of which contains phase sub-criteria. The three separate sections of sub criteria are resource development, transmission development, and external development (acquiring access to land, permitting, signing PPA’s and EPC contracts, securing a portion of project financing, etc.). For a project to be considered as being in any particular phase of development a combination of subcriteria, specific to each individual project phase, must be met.

    Planned Capacity Addition (PCA) and Resource Capacity

    Finally, at each phase of a project’s development a geothermal developer has the opportunity to report two project capacity estimates: a Resource Capacity estimate and a Planned Capacity Addition (PCA) estimate. At each project phase the geothermal resource capacity estimate may be thought of as the megawatt (MW) value of the total recoverable energy of the subsurface geothermal resource. It should not be confused with the PCA estimate, which is defined as the portion of a geothermal resource that “if the developer were to utilize the geothermal resource under its control to produce electricity via a geothermal power plant . . . would be the power plants estimated installed capacity.” In other words, the PCA estimate is usually the expected power plant’s estimated installed capacity. In the case of an expansion to a conventional hydrothermal geothermal plant, the PCA estimate would be the estimated capacity to be added to the plant’s current installed capacity. In each phase of development the resource and installed capacity estimates are given different titles that reflect the level of certainty of successful project completion. The different titles as they correspond to the separate phases are as follows:

    Phase I: “Possible Resource Estimate” and “Possible PCA Estimate”

    Phase II: “Possible Resource Estimate” and “Possible PCA Estimate”

    Phase III: “Delineated Resource Estimate” and “Delineated PCA Estimate”

    Phase IV: “Confirmed Resource Estimate” and “Confirmed PCA Estimate”

    This section outlines how the Geothermal Reporting Terms and Definitions influence the reporting and presentation of project in development information in this report…

    The US Geothermal Industry

    The development of geothermal energy resources for utility-scale electricity production in the United States began in the 1960’s. Since that time, the continual development of geothermal resources and technology has positioned the US as a leader in the global geothermal industry. The US currently has approximately 3,386 MW of installed geothermal capacity, more than any other country in the world.

    Installed Capacity

    Geothermal companies continue to increase the development of geothermal resources in the US. At the end 2012, geothermal energy accounted for roughly a third of a percent of total installed operating capacity in the United States. Additionally, Geothermal was about 1% of new renewable energy projects brought online in 2012.2 While this number may seem small on a national scale, geothermal is a significant portion of renewable electricity generation in the states of CA and NV. While the majority of geothermal installed capacity in the US is concentrated in California and Nevada, geothermal power plants are also operating or under construction in Alaska, Hawaii, Idaho, Oregon, Utah, Washington and Wyoming. A significant amount of additional geothermal capacity -- 574 - 620 MW -- could become operational by January 2016 if companies who participated in GEA’s survey bring their plants online on time.

    Due to the varying resource characteristics of different geothermal reservoirs and the lack of a standardized plant design, three generalized plant categories are used to define geothermal generators in the US: dry-steam, flash, and binary. Currently, dry-steam power plants account for approximately 1585 MW (47%) of installed geothermal capacity in the US, and are all located in California. Next, flash plants count for approximately 997 MW (29%), the majority of which are also located in California. With a few exceptions, though, most of the industry growth comes from binary plants, which utilize lower temperature resources. Binary capacity reached roughly 803.57 MW, or 24% of the geothermal installed capacity. Also notably the first co-production facility in the US came online in Nevada at Florida Canyon Mine and Enel Green Power North America brought the first hybrid solar geothermal plant online at their Stillwater facility.

    The US geothermal industry’s trend of sustained steady growth continued in 2012. In that year five geothermal power plants and two expansion projects to existing power plants were completed for a total of approximately 147.05 MW of newly installed capacity.

    Additionally, GEA conducted a statistical revision of its information on existing plants and found that many power plants had slightly increased their installed capacity since GEA had last contacted those geothermal plant operators. Therefore, of the total 275 MW of growth since GEA’s last survey, 147 MW came from plants installed in 2012, while 128 MW is a result of revision to GEA statistics. So the true increase in geothermal capacity this year was only ≈5%. The new geothermal capacity installed in 2012 came from five different geothermal companies. EnergySource completed their John L. Featherstone Plant with a capacity of 49.9 MW, ElectraTherm brought one of the first co-production plants in the US online at Florida Canyon Mines, and Terra-Gen’s Dixie Valley expansion became operational. Additionally, Ormat Technologies brought its 18 MW Tuscarora geothermal power plant online in Elko County, Nevada and a second 30 MW plant online called McGinness Hills. U.S. Geothermal expanded electricity generation at its San Emidio resource by replaced old generating equipment at the site with a new 12.75 MW power plant and completed a 30 MW plant in Oregon. As a result, geothermal installed capacity increased in the US by approximately 147.05 MW to an overall total of 3,386 MW.

    Capacity in Development

    Installed geothermal capacity increased from 3,187 MW in early 2012 to 3,386 MW in February of 2013. As the economy recovers and the recent language alteration of the PTC tax credit effects the geothermal industry, significant growth is expected in 2013 and subsequent years. From the information GEA gathered from reporting companies, up to 14 plants could become operational in 2013 and 9 new plants in 2014 and 10 more plants in 2015, by over 20 different companies and organizations making 2013, 2014, and 2015 three of the most significant boom years for geothermal in decades.

    As advanced geothermal projects enter or near the construction phase of development, geothermal companies in the US are also acquiring and developing early stage geothermal resources. In 2013, the geothermal industry is developing 175 geothermal projects (including prospects). The geographic spread of geothermal projects alone is significant, with projects in various phases of project development located in 13 different states.

    Of the 175 projects 15 are “unconfirmed” by their respective developer. By unconfirmed” GEA means the project developer failed to respond to GEA’s requests for information during the Jan.- Feb. data collection period. Thus, the information presented is based on public sources or the developer’s 2012 response.

    The number of developing geothermal projects reported to GEA in 2013, excluding unconfirmed projects and prospects is 125. This result represents a slight decrease from 2012 at 130 projects. This decrease is partly due to companies failing to report to GEA, not necessarily because fewer projects are under development.

    Beginning with the 2012 US Geothermal Power Production and Development Report, GEA allowed for the reporting of geothermal “prospects” by developers. The reporting of a prospect may occur when a geothermal developer has acquired access to a geothermal resource which has the potential for electricity production, but which has not yet met enough project criteria for the geothermal resource to be considered a Phase I project under the Geothermal Reporting Terms and Definitions (see Section 1). While not currently considered a geothermal “project,” a geothermal prospect has the potential to become so. When including confirmed prospects, the total number increases to 160 confirmed projects and prospects.

    The number of confirmed geothermal projects recorded in this report account for approximately 5,150-5,523 MW of geothermal resources in development and 2,511-2,606 MW planned capacity additions spread among 13 states in the Western US. However, these numbers exclude projects where the total resource capacity or the potential capacity additions (PCA) are unknown and are therefore lower than ‘real’ estimates. Some developers may only report the PCA or resource numbers to GEA. Additionally, projects in early stages of development do not always have estimates for PCA or resource available.

    Note that while a project’s resource capacity value provides an estimate of the amount of recoverable electricity (MW) from an underground reservoir, a project’s potential capacity additions (PCA) estimate is the portion of that geothermal resource which a developer plans to develop for electricity production via a geothermal power plant (see Section 1 explaining the Geothermal Reporting Terms and Definitions used in this report). Currently, geothermal companies are developing 2,511-2,606 MW of potential capacity additions in the US. Of this total, 774 – 799 MW are advanced-stage (Phase 3 – 4) geothermal projects. These numbers in the Table 2 include all 15 unconfirmed projects.

    While the majority of advanced-stage projects are currently located in Nevada and California, utility-scale projects are also nearing completion and production in Oregon, Utah, Idaho, and Alaska…

    As the geographical reach of the geothermal industry expands, developers are increasingly exploring for and developing conventional hydrothermal geothermal resources in areas where little or no previous development has taken place. Of the 175 projects surveyed (including unconfirmed), 148 (approximately 84%) are developing conventional hydrothermal resources in “unproduced” areas (CH Unproduced) where the geothermal resource has not been developed to support electricity generation via a power plant. Additionally, 17 or 10% are developing conventional hydrothermal projects in “produced” (CH Produced) areas, and four or 2% of projects are expansions to existing conventional hydrothermal power plants (CH Expansion). The remaining projects are three geothermal and hydrocarbon coproduction (Co-production) and three enhanced geothermal systems (EGS) projects.

    The exploration for and development of new resources, as well as the application of new technologies, has the potential to expand the geographic extent of the industry. Projects featuring the development of conventional hydrothermal resources as well as EGS pilot projects are increasing in the Western US. At the same time, the potential to generate geothermal electricity from low-temperature fluids co-produced with from oil and gas production is being explored through demonstration scale projects in states along the Gulf of Mexico and in North Dakota. A number of successful co-production test projects concluded this year...

    Emerging Technology

    Significant Developments in EGS and Co-Production

    In 2006, MIT published a study that found that EGS technology could create 100 gigawatts (GW) of electricity by 2050.13 One example of a developing EGS project is Davenport Newberry Holdings LLC’s Newberry Geothermal Project in Bend, Oregon. This past year they have significantly progressed on their EGS demonstration funded by $26 million from Google, Kleiner Perkins, Khosla Ventures and Vulcan Capital, as well as funds from the US Department of Energy (DOE). If successful, EGS technology development could make significant progress toward cutting geothermal costs and eliminate significant risks in geothermal development. For example, EGS will allow developers to create multiple stimulated geothermal areas from a single well.

    The Newberry project is still in the testing and research phase. However, Altarock has stimulated multiple geothermal zones at the site, it still needs to run injection tests and test the heat exchange areas in addition to drilling a production well in the stimulated zones. After this testing phase, AltaRock Energy intends to build a demonstration power plant, and eventually a utility-scale power plant on-site.

    Other groundbreaking milestones in co-production were reached this year as the first coproduction generator became operational at ElectraTherm’s Florida Canyon Mine and other important research projects at University of North Dakota (UND) progressed.

    ElectraTherm’s project at Florida Canyon Mine turns waste heat to power by using co-produced fluids. Low temperature geothermal brine produced in the mining, oil and gas industries is considered a nuisance. However, ElectraTherm’s technology, known as the ‘Green Machine’, uses a cleanable heat exchanger to generate a power output of 75kW. This standardized unit is easy to transport, install, and can produce fuel-free, emission-free power.

    UND is in the early stages of research demonstrating the technical and economic feasibility of generating electricity from non-conventional low temperature (150° to 300°F) geothermal resources using binary ORC technology. This research will demonstrate that the technology can be replicated within a wider range of physical parameters including geothermal fluid temperatures, flow rates, and the price of electricity sales. The success of this research will be a significant milestone for co-production and could further prove the technologies economic feasibility and expand the utilization of co-production across the US.

    Department of Energy Grant Recipients

    The DOE Geothermal Technologies Office (GTO) works to advance the broader deployment of geothermal energy in the United States. The DOE reports in their 2012 Annual Update that through research, development and portfolio of over 200 projects under development in the fiscal year 2012, DOE investments yielded approximately 25 MW of additional nameplate capacity and identified an additional 57 MW of new resources…


    WHAT U.S. OFFSHORE WIND NEEDS Fulfilling the Promise of U.S. Offshore Wind; Targeted State Investment Policies to Put an Abundant Renewable Resource within Reach

    February 22, 2013 (National Resources Defense Council)

    “Offshore wind is an inexhaustible resource that lies just off our shores…[According to the Department of Energy,] the United States could obtain 20 percent of its electricity from wind by 2030, and more than 15 percent of that wind power could come from offshore projects, totaling 54,000 megawatts (MW) of generating capacity…

    “…[Yet] zero MW of offshore wind capacity are installed or even under construction…[and] only three projects [are] in advanced stages of development…The underlying limiting factor for offshore wind development in the United States, a factor not found in places where the sector has advanced, is that the basic economic and financial conditions for offshore wind success are not in place…"

    “The way forward…[is to] put in place targeted investment polices that provide the revenue certainty and debt capacity necessary to make projects viable and attractive to the equity and debt investors [and make investors comfortable providing capital]…

    [Fulfilling the Promise of U.S. Offshore Wind] focuses on the German policy successes and the lessons they present for the United States and also briefly examines the very unsuccessful German approach to transmission as a cautionary tale that should not be replicated in the United States.”

    MASSACHUSETTS PLANNING FOR MORE SUN After The First 400 MW: Massachusetts Makes Plans For More Solar

    Jessica Lillian, 26 February 2013 (Solar Industry)

    “…Massachusetts is now seeking to avoid the dreaded drop-off point with its popular solar carve-out program, which began in 2009 and currently has a 400 MW cap in place. The administration of Gov. Deval Patrick, D-Mass., recently announced that it had begun work on a new policy to sustain solar development past 400 MW [and overcome an oversupply of solar renewable energy credits (SRECs) and a draining of incentive funds]. The [Massachusetts Department of Energy Resources (DOER)] also plans to tweak carve-out compliance requirements and the queuing process for projects now in the market…

    “The DOER action comes as a relief to developers building in Massachusetts. With 150 MW installed last year alone, the industry can expect to hit the 400 MW cap soon…Industry stakeholders and the DOER itself are generally pleased with the results and mechanisms of the current program…PV system costs have dropped, fostering increased competition among integrators and their partners.”

    “Although the next version of the program may feature a few changes in order to tackle any vulnerabilities, the Massachusetts SREC market as a whole has managed to avoid much of the SREC pricing volatility seen in other states - most notably in New Jersey...First, the reactive design formula takes into account supply…[A] solar credit clearinghouse auction allows for [absorption of] any unsold credits…[and a mechanism preventing] SRECs exceeding the cap from entering the market…

    “By the time Massachusetts reaches that 401st megawatt, the DOER expects to have its new cap and associated plans in place…[A]t least one major stakeholder has already weighed in: The Solar Energy Industries Association (SEIA) called on the commonwealth to triple or quadruple the 400 MW cap…citing New Jersey's 4 GW solar goal and Maryland's 1.3 GW solar goal…”

    2,500MW WYOMING WIND MOVES AHEAD Massive Wyoming wind farm developer to seek state permit

    Adam Voge, February 19, 2013 (Casper Star-Tribune)

    “…Power Company of Wyoming, developer of the [$5 billion] 1,000-turbine Chokecherry and Sierra Madre wind project…was set to file an application with the Wyoming Industrial Siting Council…[but delayed because of] now-dead legislation which…would have required companies…to spend at least 25 percent of the anticipated cost in the first two years after approval…

    “Now that the measure appears to be dead, the company plans to meet with the council…[The application is] among the last in a series of approvals needed for the project, which could generate between 2,000 and 3,000 megawatts of wind power…[Power Company of Wyoming remains determined to begin construction on the massive wind farm, targeting a possible 2014 groundbreaking. It has has spent about $25 million on project development so far]…”

    “If the project receives the permits and approvals to go forward, it would quickly become the backbone of Wyoming's emerging but sputtering wind energy industry. Developers statewide have lately faced issues both political and logistical in their efforts to farm and export Wyoming wind, a top-notch resource.

    “Chief among the hurdles facing Wyoming wind developers is a lack of transmission lines to carry the state's abundant resource to markets hungry for renewable energy. At least three major transmission line projects which could address the issue remain up in the air…TransWest Express-- owned by Power Company of Wyoming's parent company, Denver-based Anschutz Corp…would carry about 3,000 megawatts of power…to just south of Las Vegas…[A] draft of the federal Bureau of Land Management's environmental impact statement is expected this spring…”

    Tuesday, February 26, 2013


    Boulder’s Energy Future Municipalization Exploration

    February 26, 2013 (Boulder City Council)

    Executive Summary

    The City of Boulder has embarked on a significant undertaking that could change the future of electric service and energy management for its residents and businesses. As directed by council, city staff has been analyzing the viability of various options to help the community achieve its Energy Future goals. The process is grounded in commitments to be objective, to include as many alternate viewpoints as possible, and to project out not only the results on the first day of potential service from a municipal utility, but for 20 years into the future.

    The analysis presented in this memo was designed to answer a critical first-level question:

    • Can the city municipalize? In other words, is there at least one form of municipalization that meets the prerequisites that voters approved as part of the City Charter?

    If council decides that the answer to that question is yes, staff will continue its work with the community over the next few months to answer equally important second-level questions:

    • How can the city best achieve its Energy Future goals? Is a city-owned utility the best path to accomplish the broad set of goals the community set for its Energy Future? Would a city-owned electric utility provide value sufficient to offset potential risk and distinguish its services from those that Xcel Energy currently offers or could offer in the future through a new partnership? A question the city has posed in the past is, should we form a municipal utility? Staff believes the answer to this question will become more clear as the analysis continues and as part of a series of future decisions. The previous questions, however, are the ones the community and city officials should be starting to assess now.

    Based on the current analyses, the answer to whether it is possible to municipalize is yes, and the findings to date are promising in terms of the potential value a local electric utility could bring when compared to other alternatives. The results detailed in this memo indicate that a local utility could operate effectively with cost savings and flexibility, creating significant advantages. Certain options for the local electric utility would meet the Charter metrics and with a very high likelihood be able to:

    • Offer all three major customer classes (residential, commercial and industrial) lower rates than what they would pay Xcel, not just on day one, but on average over 20 years;

    • Maintain or exceed current levels of system reliability and emergency response, and, if the community chose to, use future investments to enhance dependability;

    • Reduce harmful greenhouse gas emissions by more than 50 percent from current levels and exceed the Kyoto Protocol target in year one;

    • Obtain 54 percent or more of its electricity from renewable resources; and

    • Create a model public electric utility with leading-edge innovations in reliability, energy efficiency, renewable energy, related economic development and customer service.

    The Electric Utility of the Future

    At the core of these analyses is a vision of “the electric utility of the future” that is bold and exciting. No matter which energy path the city chooses to take, it strives to be a leader in reducing the impact its electric use has on climate change and in providing local energy services that meet the unique needs and community values of Boulder. For traditional electric utilities, “managing energy” is their core competence. Xcel has repeatedly said it is limited in its ability to shift from its current trajectory. The question Boulder faces is whether it wishes to be beholden to this antiquated business model for the next 20 years, while also recognizing community concerns that change represents risk.

    Public utilities are not regulated at the state level in the same way as investor-owned utilities, but they are subject to local oversight that in many ways ensures the utility is held to a higher standard of service. Locally controlled public utilities, because they are not regulated by a state Public Utilities Commission, have the freedom to design programs and services that directly match the needs of the geographic and demographic area served. A regulated utility must provide more generalized services that are designed from a top down view of its entire service area. Typically, what the investor-owned utility offers to one set of customers it must offer to all, making customization difficult.

    Boulder’s vision for the future requires a utility willing to phase out the old business model and aggressively pursue a new way of operating. The community’s Energy Future goals prioritize a cleaner energy supply; the ability to develop innovative energy efficiency and demand-side management programs that enhance customers’ control; a structure that supports economic vitality through low costs and high reliability, as well as the creation of a high-tech test bed; and the opportunity to work with energy consumers to meet their diverse needs. Boulder’s vision, either in partnership with Xcel Energy or through a municipal utility, is to transform from a utility model centered on selling more electrons to a new business model in which the mission is to collaborate with customers to provide options to use fewer electrons.

    The opportunity exists for Boulder to transition to a new sustainable, low-carbon emission society, and it is coming much faster than anyone had anticipated just a few years ago. The growing differential between the rising costs of fossil fuels and the declining costs of renewable energy technologies is setting the stage for the emergence of a new economic paradigm for the next century. Boulder is poised to drive this process to tackle climate change, secure energy independence, and grow a sustainable 21st century economy all at the same time.

    Public Outreach and Working Groups

    Given the potential impact of a decision to create an electric utility on residents and businesses, more than 50 individuals, many of whom offered significant industry expertise, participated in developing the options, vetting assumptions and providing specific data inputs. Five working groups were formed, representing the major areas of finance, reliability, resources, decision analysis and public outreach (see Attachment A). The city staff extends a huge thank you to the community members who gave significant amounts of time to help ensure the integrity of this process. Draft recommendations included in this memo have been vetted with these work teams. Additionally, extensive community outreach will take place between the Feb. 26 study session and April 16 council meeting.

    The Modeling Process

    The analysis incorporated five major areas of focus: financial, reliability, resource mix, asset acquisition and legal issues. Models were designed to span 20 years, from 2017 to 2037. An extensive list of inputs, which were vetted by community working groups and consultants, drew upon current market pricing, analyses by federal laboratories, benchmarking from American Public Power Association and regional utilities, and a diversity of other sources to ensure that data was accurate, realistic, conservative, and locally relevant. A smaller number of high-impact variables were modeled with wide cost ranges to show the risks associated with future uncertainty. These variables included gas prices, wind prices, interest rates, operations and maintenance costs, stranded and acquisition costs, and the ability of the utility to generate sufficient debt service coverage. Although the models are robust, they have limitations—for example, they do not allow for the types of course changes that might happen in reality. The significance of this is that a city-owned utility could start on a path of least-cost power and move to more renewable energy based on changing market conditions, just as Xcel could.

    The structure of the modeling for this phase was driven by the first-level question of whether municipalization is feasible under the conditions set by the City Charter. Staff modeled an Xcel Energy Baseline, based on publicly available documents and Xcel’s own projections, for comparison to five municipalization-driven options that combine different resource packages and energy efficiency investments. The Xcel Baseline was modeled as conservatively as possible, giving Xcel a notable benefit of the doubt; significant cost increases, such as a planned $3.5 billion capital plan, may not have not been fully incorporated as not all of Xcel’s forecasting information is available or accessible. The utility’s latest rate increase was not included in this phase of modeling.

    No alternative partnerships with Xcel Energy have been modeled at this time because the city does not have sufficient information from Xcel about the type of agreement—from among those proposed by the city in December 2012 or new ideas the company might have— Xcel would be interested in pursuing. It is possible that Xcel, working with the city, could become the utility of the future. In fact, it is possible that some of the municipalization options presented in this memo could be implemented in partnership with Xcel, if the company is willing and able to make some necessary changes. Staff is hopeful that Xcel will come to the table to develop these ideas more concretely in the upcoming months.


    Reliability was raised as a key concern by both the business community and by residents. Given its importance, a separate analysis and working group was formed to address this issue. Engineers were hired to evaluate the system and its current condition, provide recommendations about needed improvements, identify regulatory reliability requirements and recommend best practices to ensure the acquired system would be just as reliable, if not better, than it currently is. The city recognizes that it is fortunate to have major employers who are industrial customers, and these customers have processes that require high-quality power and a reliable supply. Power failures can have significant financial impacts to these customers. Therefore, it was critical to not only talk to these companies about their needs and concerns, but to have equipment, systems, and processes in place to meet those specific needs. All models assume that reliability is a requirement and are based on separation and service area recommendations that participating engineers have indicated will achieve this goal.


    Results presented later in this memo show that three of the five options for forming a local electric utility could achieve all of the Charter metrics with medium to high likelihood. In all cases, except the Xcel Baseline, a significant reduction in greenhouse gas emissions and increased renewable resources could be achieved. Two options that were modeled to prioritize greenhouse gas emissions reductions did not meet the Charter requirement of rate parity at the time of acquisition, while a least-cost power option was able to bear even the highest cost stranded and acquisition rulings under certain conditions.


    ASIA-PACIFIC SOLAR BOOM GOES ON PV Demand in the Asia Pacific Region to Reach 13.5 GW in 2013…Leading PV Countries in Asia Pacific Starting to Exhibit Diverse Market-Entry Conditions

    February 13, 2013 (SolarBuzz)

    “Solar photovoltaic (PV) demand from the Asia Pacific (APAC) region is forecast to grow to 13.5 GW in 2013, growing 50% Y/Y…China, Japan, India, and Australia…will account for 90% of APAC demand in 2013. However, discrete end-market demand environments are now evolving in each of these countries. As a result, PV suppliers and technologies are being selected in each territory based upon factors such as domestic manufacturing, policies, import duties, and customer preferences…

    “…[A] single go-to-market strategy…is no longer viable…In Australia, the elimination of the Solar Credit Multiplier, along with incentive reductions in Victoria and Queensland, will slow PV growth during 2013. In Japan, demand will peak during Q1’13, ahead of scheduled tariff reductions in April…The Chinese government will likely re-adjust the goals of its 12th Five-Year Solar Development Plan, and the country will see over 75% of its 7 GW demand in 2013 occur in 2H’13…In India, the final version of Phase II of the National Solar Mission program is still pending…[It could drive] a capacity increase from 3.7 to 9 GW, with an increased focus on the off-grid and rooftop sectors.”

    “The threat of further trade wars involving APAC countries, along with other import restrictions, is segmenting the APAC region into country and application-specific markets. Domestic content restrictions on imported modules into India may strongly affect c-Si supply from China or any thin-film imports to India.

    “The APAC region is becoming more selective about technologies. In Japan, high-efficiency modules have become the preferred technology for locations with constrained space. In China, domestically manufactured multi c-Si modules are satisfying ground-mounted requirements. And in India, 1 GW of new demand will come from rooftop projects under Phase II of the National Solar Mission, which could further shrink this key market for thin-film suppliers…”

    SO DAKOTA WANTS WIND SD Senate panel endorses incentives for wind power

    Chet Brokaw, February 14, 2013 (Bloomberg BusinessWeek)

    “…[The] South Dakota Senate Commerce and Energy Committee voted 6-1 to pass a measure…that would provide financial incentives to encourage the stalled construction of wind power projects in the state…[The] construction of wind farms has drawn to a standstill in South Dakota because the state imposes much higher taxes during construction than neighboring states do.

    “…South Dakota currently would charge $7 million to $11 million in sales taxes and contractor's excise taxes during the construction phase of a typical wind farm. North Dakota, Minnesota and Iowa would charge only $1 million to $2 million…[T]he committee approved a…[measure that] would give a wind project an incentive payment roughly equal to 2 percent of its final cost. For example, a $5 million project would get a $100,000 incentive payment. One costing $100 million would get a $2 million incentive payment…”

    “Rob Rebenitsch, director of the South Dakota Wind Energy Association, said South Dakota has 784 megawatts of installed wind power, while North Dakota has twice as much. Iowa has 4,536 megawatts of wind power installed…Rebenitsch said more than 13,000 megawatts of wind generation was installed across the nation last year in 192 projects costing $25 billion…[but] none of that generation was installed in South Dakota…

    “Wind energy officials said the bill is a good start, but they believe larger incentives are needed…Sen. Mark Johnston, R-Sioux Falls, said he objected to the bill because it deals with only one industry…[S]tate officials and legislators are making progress in devising an overall incentive program that would cover agricultural processing and all other kinds of large construction projects.”

    STILL BIG MONEY IN LITHIUM ION BATTERIES … Global Lithium-ion Market to Double Despite Recent Issues; The market was valued at $11.7 billion at the end of 2012 - Fastest growth can be witnessed in the industrial and automotive segments

    21 February 2013 (Frost and Sullivan)

    “The global lithium-ion battery market was worth $11.7 billion in 2012 and is expected to double by 2016, according to Frost & Sullivan. This will happen despite the recent issues experienced by Boeing, and despite Airbus decision to abandon these batteries…

    “North America holds the highest share of revenues for consumer and industrial applications while Europe boasts the highest revenues for industrial lithium-ion batteries (LiBs). The highest growth in industrial battery demand is expected to come from APAC. China, Japan and South Korea account for close to 85-90% of the global LiB production.”

    “China…has the highest concentration of LiB manufacturers: over 200 players…[in] the consumer segment and around 30-40 companies for automotive…[and many] US companies…have been acquired by Chinese firms…[The] Obama administration’s ARRA funding…[started many LiB companies but many have gone] bankrupt with the funding drying up…[the] economic slowdown…[and the] high cost of EVs…[ Germany and Switzerland are strong contributors to R&D] among European countries and the demand for batteries comes from all the three segments: consumer, industrial and automotive...

    “The global LiB market holds immense opportunities for growth and expansion. Although the consumer segment is mature in developed economies, this still is a growing application in Latin America, China, [and] India…The highest potential for growth however is exhibited by the industrial applications. Manufacturers that were previously involved only on producing and selling batteries for the automotive segment…have started to sell LiBs for cordless power tools, forklifts, and garden equipment…”

    Monday, February 25, 2013


    Why Are Residential PV Prices in Germany So Much Lower Than in the United States? A Scoping Analysis (with Updated Data on Installation Labor Requirements)

    Joachim Seel, Galen Barbose, and Ryan Wiser, February 2013 Revision (Lawrence Berkeley National Laboratory)

    Note for the February 2013 Revision

  • The original September 2012 briefing included the results of a survey of 24 German PV installers conducted in early 2012
  • One of the more surprising results was the extraordinarily low number of installation labor hours reported by survey respondents
  • LBNL conducted a follow-up survey of 41 German installers in October 2012, focused solely on installation labor requirements
  • The results of the follow-up survey are more in line with expectations (a mean response of 39 man-hours per system for on-site installation labor, compared to 7.5 hours per system in the original survey)
  • This revised briefing includes the results of this follow-up survey, as well as a limited number of other updates (including Q3 2012 data on system pricing and market size)

    Motivation, Scope, and Limitations

  • The installed price of residential PV is significantly lower in Germany than in the U.S., due primarily to differences in “soft” costs – But relatively little is known about how/why soft cost components differ
  • In order to better characterize the nature of these differences, LBNL: – Fielded two surveys of German PV installers, adapted from NREL’s survey of U.S. installers, to collect data on residential PV soft costs – Comprehensively reviewed public and private consultant data relevant to the cost structure of residential PV in Germany
  • Focus is the pre-incentive price paid for customer-owned systems – Residential PV in Germany is almost entirely customer-owned; substantial third-party ownership in U.S. but pricing sometimes impacted by appraised values
  • Analysis here is intended to be a “first cut” and serves to highlight specific areas where further research could reveal additional insights – Survey focus was on quantifying differences in specific business process costs – Additional research needed to confirm and characterize differences in more detail, as well as to link observed differences to underlying market drivers

  • Germany’s 2011 Additions ~4x Greater, and Cumulative Additions More than 5x Greater, than United States

    *Annual Residential Installations in Germany 2.5x Greater (9.4x Greater on per Capita Basis) than in the United States

    * Cumulative Residential Installations in Germany 3.6x Greater (14x on per Capita Basis) than in United States

    Varied Data Sources Are Available for U.S. and German PV System Pricing

  • LBNL Tracking the Sun (TTS): Installed prices for ~70% of PV capacity installed in the U.S. from 1998-2011
  • NREL Cost Modeling Team: Quarterly bottom-up installed price benchmarks based on interviews with installers and modeling
  • EuPD: Project-level price quotes collected through quarterly survey of German installers (since 2008); used for BSW price reports
  • Photon, other consultants: Installed price benchmarks based on interviews with installers or other market research
  • Miscellaneous: Schaeffer et al., 2004, “Learning from the Sun”; Haas, 2004, “Progress in Markets for Grid-Connected PV Systems in the Built Environment”; Credit Agency for Reconstruction (KfW); IEA National PVPS reports; Langen 2010

    * Residential PV System Prices Have Often Been Higher in the U.S. Than in Germany

    * Installed Price Gap Was $2.8/W in Q4 2011 and Differential Continued Through 2012

    * Installed Prices in the U.S. Are Also Much More Varied Than in Germany

    Learning Curve Analyses of BoS Costs

    Question: To what extent are lower BoS costs in Germany potentially due to larger overall market scale and associated learning-induced cost reductions?

  • Traditional PV learning curve analyses often focus on PV modules and relate global module production to module prices
  • Some business process costs (e.g., installation labor, customer acquisition) may also be subject to local learning effects
  • We compare the relative impact of local BoS learning in the U.S. and Germany based on implied non-module costs for less than 10 kW PV systems and cumulative national PV capacity installed
  • BoS progress ratios may help predict future U.S. price reductions that accompany larger market scale

    Differences in Market Size Alone May Explain Roughly Half of the Price Gap

  • Total non-module costs in 2011 were ~$2.8/W higher in the U.S. than in Germany
  • But, at the same cumulative capacity that the U.S. had installed at the end of 2011 (4 GW), non-module costs for residential PV in Germany were only $1.3/W less than in the U.S.
  • One might (crudely) infer that the remaining $1.5/W of the total gap in 2011 non-module costs may be due simply to the larger base of German experience

    Soft-Cost Learning for less than 10 kW Systems Occurs More Slowly in the U.S. and Is Less Effective

  • The development of non-module costs is less correlated with market growth in the US than in Germany (52% vs. 9% explained by other factors)
  • The learning rate for non-module costs (proxy for soft costs) is lower in the US than in Germany (7% vs. 15%)

    Regular FiT Adjustments Pressure German Installers to Reduce Prices

  • BNEF (2012) indicates the presence of value-based pricing in both the US and Germany
  • Following this hypothesis, the iterative reduction of the FiT presses German installers to lower system prices to maintain attractive investments for their customers
  • Similar forces may operate less efficiently in the U.S., yielding higher “valuebased” prices, even for customer-owned systems

    Hypotheses Explored for Why German and U.S. Residential PV Prices Differ

  • General: – Residential systems are larger in Germanyà yes – US installers develop projects more slowly à yes (semi-addressed) – US installers have higher profit margins, after recovering all overhead expenses à uncertain (semi-addressed)
  • Component costs: – Hardware component costs are lower in Germany à possibly true for inverters, but uncertain (semi-addressed) – US has a lower share of cheaper Chinese modules à no
  • Customer acquisition: – US installers have higher customer acquisition costs à yes – US installers have lower customer success rates à yes – US installers have higher marketing and advertising costs à yes
  • Installation labor: – US installers need longer for the installation process à yes – US installers have higher wages à yes for installation labor, no for other labor (semiaddressed)
  • Permitting, Interconnection and Inspection Costs – US installers have higher labor hour requirements for PII à yes – US has higher permitting and interconnection fees à yes
  • Taxes – The US charges higher sales taxes on PV systems than Germany à yes

    Additional Hypotheses Not Explored Here

  • Overhead costs – US has higher business overhead costs (e.g. insurance costs, material storage costs) – German installers have higher sales volume per year, spreading fixed costs over larger denominator and profiting from economies of scale, allowing for volume discounts – US installers have higher cost of capital for their own business operations – US installers face higher transaction costs associated with arranging financing for customers – US has a longer supply chain for PV modules and other hardware
  • Profit margins – US has a lower degree of competition among installers, maintaining higher profit margins – Value based pricing allows for higher prices in the US, given better irradiation, high retail rates in some regions, and more generous subsidies
  • Regulatory issues – US requires each panel and rack component to be grounded to the DC switchbox leading to higher material costs and installation labor hours – Germany has less onerous requirements for roof mounting structures
  • Installation timing – US systems are installed more steadily throughout the year, whereas German installations were traditionally concentrated at the end of the year when prices are lower, leading to lower annual average prices
  • Exchange rate dynamics are more beneficial for German system costs

    A Small Body of Literature Explores the German-U.S. PV Price Gap

  • Few have sought to explain the underlying reasons behind the German-U.S. PV price gap or to quantify differences in specific soft costs – Photon 2011a, Photon 2011b, BNEF 2012, Langen 2010, Podlowski 2008, Goodrich et al. 2012
  • Possible reasons for the price gap that have been postulated: – “Value-based pricing” in the U.S. (e.g., associated with more generous subsidies and/or less competition among installers) – Preference for premium products in the U.S. – Lower customer-acquisition costs in Germany due to simpler/more certain value proposition (FiT), critical mass of demand, and economies of scale – Lower installation labor costs in Germany due to greater experience and economies of scale – Lower permitting costs in Germany due to fewer requirements and greater standardization – Less onerous electrical requirements and interconnection processes in Germany
  • Our analysis complements that literature by: – Deriving estimates for specific business process costs via two surveys of German residential installers – Using large samples of system prices to compare price developments and distributions – Estimating the impact of differences in project development times on reported prices – Analyzing residential module market composition
  • Complements NREL cost modeling team’s in-depth interviews with installers

    Overview of Initial Survey Approach

  • German survey focuses on standard DOE soft cost categories:
  • Customer acquisition
  • Permitting, interconnection, inspection
  • Installation labor
  • Adapted from NREL survey of U.S. installers to allow comparisons
  • Average labor hours per system for PII and installation
  • Total annual expenditures on customer acquisition…

    Follow-Up Survey on German Installation Labor Hours

  • LBNL conducted a second survey of German installers in October 2012, focused solely on installation labor requirements
  • The survey asked 7 questions about German residential PV installations completed during the preceding 12 months.
  • Survey was fielded online (between October 9th and November 5th 2012) in German in collaboration with

    Raw Sample Characterization

  • Most respondents in both surveys are small volume installers – Most installed <50 systems per 12-month period – Median installations/yr = 25 for 2011, 26 for 2012
  • Average system sizes are a bit smaller in 2012 German survey – Average of 6 kW per system (compared to 8 kW in German 2011 survey) – Less variation in average system size

    * Total Soft BoS Costs + Profit Represent Roughly $0.62/W or 20% of System Price

    * Survey Responses Are Generally Consistent with Estimates Reported Elsewhere

    * Soft Costs for Residential PV in Germany Are ~$2.7/W Lower Than in the U.S. -- Total soft costs for residential PV in Germany, including margin, are just 19% of the implied soft costs for U.S. residential PV ($0.62/W vs. $3.34/W)

    * Labor Rates Are Higher in Germany Than in the U.S. for Some Functions, but Lower for Others

    Residential Customer Acquisition Costs Average $0.07/W in Germany

  • Most respondents reported customer acquisition costs <$0.15/W; several small volume installers reported somewhat higher costs
  • On average, customer acquisition labor includes 3 hrs/system for sales representative and 2 hrs/system for design engineer

    Customer Acquisition Costs in Germany Are $0.6/W Less Than in the U.S.

  • Mean bid success rate is slightly lower in the US (30% in US vs. 40% in Germany)
  • German installers leverage partnerships with equipment manufacturers
  • Langen (2010) points to simpler and more certain value proposition in Germany (i.e., FiT), installer learning, and critical mass for word of mouth

    PII Costs Are Negligible for Residential PV in Germany

  • Total PII costs of $0.03/W on average
  • Fewer than 10 hours of labor required for all PII activities, and no fee – Average labor requirement of 5 hrs (confirmed by PV legal survey, lowest for all European countries) – Permit requests and incentive application are done online; usually no permit inspection required
  • Grid upgrade costs for German residential PV systems are paid by Grid Operator (SEPA 2012)

    PII Costs Account for Roughly $0.2/W of the German-U.S. PV Price Gap Differences due to both PII labor costs and permit fee

  • PII labor costs are $0.12/W lower in Germany
  • Remainder of gap ($0.09/W) is associated with permit fee (assuming an average of $430 per system in the U.S.)
  • Langen (2010) estimates PII costs for the US at $.80/W, and Germany at $.10/W
  • PV Grid (2012) reports 2.5h for interconnection, 1.5h for interconnection permits and .7h for other legal-administrative processes in Germany
  • SunRun (2011) estimate of $.50/W in the U.S. includes sales & marketing costs & variations in building requirements

    Installation Labor Costs in Germany Average $0.23/W

  • German follow-up survey shows higher labor hours than original survey, more in line with expectations: – Mean installation labor = 39 man-hours/system (vs. 7.5 hours in original survey) – Responses generally ranged from 25-50 hours/system – Respondents to original survey likely misinterpreted the question (i.e., confusion between hours-on-site vs. man-hours)
  • No obvious economies of scale with respect to installer annual sales volume

    German Installations Are Faster and Cheaper than in the United States

  • Updated survey results show a sizable gap between the United States and Germany in installation times (36h)
  • Installers in Germany rely even more on (cheaper) nonelectrician installation labor than in the US (77% vs. 65%)

    Differences in Installation Labor Partly Stem from Different Mounting Practices

  • Large majority of German installers either never or rarely install systems requiring roof-penetration
  • Roof penetration is much more common in the United States, due to differences in roofing materials and higher wind speeds in some regions
  • Follow-up survey also asked about the usage of roof-to-inverter conduits for wiring and about the location of grounding for German residential PV – But no clear trend that might explain differences in labor requirements compared to U.S. systems

    Nationwide Sales Tax Exemptions in Germany Further Reduce Soft Costs

  • Survey respondents confirmed that German residential PV systems are effectively exempt from revenue taxes/ sales taxes/ value added taxes – Regular tax rate of 19% can be exempted either via “Kleinunternehmer” or “Vorsteuererstattungs” clause 35
  • In the United States, 23 states assess sales tax on residential PV systems, usually 4-8% of system prices, as do many local governments
  • Given the spatial distribution of PV systems, and accounting for sales tax exemptions in some states, state and local sales taxes added $0.21/W to the median price of US residential PV in 2011

    * PII, Customer Acquisition, and Installation Labor Total Just $0.33/W for Residential PV in Germany - For residential PV in Germany, PII, customer acquisition, and installation labor are estimated to represent 53% of all non-hardware costs and 11% of the total system price.

    * Summary of Soft Cost Differences for Residential PV in the U.S. and Germany

    * Summary of Soft Cost Differences for Residential PV in the U.S. and Germany

    Secondary Analyses… Longer U.S. Project Development Time Contributes to Apparent Price Gap… German Residential Systems Are Generally Larger Than U.S. Systems… If the Size Distribution of U.S. Residential Systems Were the Same as in Germany, Median Prices Would Be $0.15/W Lower… Installer Purchase Prices for Chinese Modules Are Lower than for Non-Chinese Modules in Germany… The Price Gap Is Not Due to Differences in Chinese Module Market Share…

    Summary of Findings from Survey of German Installers

  • Total non-hardware costs for residential PV in Germany are ~$2.70/W lower than in the U.S.
  • Customer acquisition costs average just $0.07/W in Germany, or roughly $0.62/W lower than in the U.S.
  • Installation labor requirements reportedly average 39 hours for German systems, leading to $0.36/W lower costs than in the U.S.
  • PII processes require 5 hours of labor, on average, in Germany, with no permitting fee, resulting in PII costs roughly $0.21/W lower than in the U.S.
  • German residential systems are exempt from sales/value-added tax, while U.S. systems are subject to an average sales tax of roughly $0.21/W (accounting for sales tax exemptions in many U.S. states)
  • The remaining gap in soft costs between Germany in the U.S. (~$1.32/W) is associated with overhead, profit, and other residual soft costs not captured in the categories above

    Summary of Findings from Secondary Analysis

  • Shorter project development times in Germany contribute to apparent price gap (e.g., ~$0.2/W effect for Q4 2011 installations)
  • Residential PV systems are larger in Germany (partly due to differences in policy design), benefitting from economies of scale ($0.15/W effect)
  • Not additive to the differences in soft costs presented previously, but rather helps to explain those differences (e.g. larger system sizes in Germany are partly why marketing costs, on a per Watt basis, are lower)
  • Market share of Chinese modules is similar for customer-owned residential systems in Germany and U.S., and thus does not contribute to price gap

    Possible Market Drivers for Soft Cost Differential between Germany and U.S.

  • Greater market-wide deployment and longevity in Germany allow for cost reductions based on installer experience
  • Lower market fragmentation (one contiguous market and regulatory framework) and higher population density in Germany allow for lower overhead, transport, and supply chain costs. – In the US, at least 50 markets exist – many more when considering local permitting-inspection-interconnection rules.
  • Larger and more concentrated markets in Germany (as well as cultural differences with the US) facilitate bandwagon effects and customer acquisition by word of mouth, leading to lower customer acquisition costs
  • Less onerous permitting-inspection-interconnection processes (e.g. online registration, no permitting fee or inspection by county officials) and installation practices (e.g. easier grounding, roof penetration) in Germany
  • Simpler, more certain and more lasting value proposition in Germany allow for both lower customer acquisition + overhead costs, and larger average system sizes – FiT guaranteed for 20 years in Germany vs. varying value of net metering + state incentives + federal tax incentives in the US
  • Regular declining FiT and high competition among installers yield pressure for price reductions and lower margins in Germany, while larger incentives, opportunities for higher value-based pricing, and less installer competition allow for higher prices and margins in US

    Policy Implications

    Reducing residential PV prices in the United States may require policies that enable:

  • A large and durable market size
  • A concentrated market->minimize fragmentation
  • A simple, transparent, certain incentive structure/value proposition
  • Simple interconnection, permitting, and inspection requirements
  • Regular incentive declines to drive & follow cost reduction…