DOCUMENTING THE COST OF REGULATORY DELAYS, RE-DELAYS, March 2016
Final report DOCUMENTING THE COST OF REGULATORY DELAYS (RE-DELAYS) March 2016
DOCUMENTING THE COST OF REGULATORY DELAYS, RE-DELAYS, March 2016
AB OUT IEA -RETD
The International Energy Agency’s Implementing Agreement for Renewable Energy Technology Deployment (IEA-RETD) provides a platform for enhancing international cooperation on policies, measures and market instruments to accelerate the global deployment of renewable energy technologies.
IEA-RETD aims to empower policy makers and energy market actors to make informed decisions by: (1) providing innovative policy options; (2) disseminating best practices related to policy measures and market instruments to increase deployment of renewable energy, and (3) increasing awareness of the short-, medium- and long-term impacts of renewable energy action and inaction.
For further information please visit: http://iea-retd.org or contact [email protected]. Twitter: @IEA_RETD
IEA-RETD is part of the IEA Energy Technology Network.
DISCLAIMER
The IEA-RETD, formally known as the Implementing Agreement for Renewable Energy Technology Deployment, functions within a Framework created by the International Energy Agency (IEA). Views, findings and publications of IEA-RETD do not necessarily represent the views or policies of the IEA Secretariat or of its individual Member Countries.
COPYRIGHT
This publication should be cited as:
IEA-RETD (2016), COUNTRY CASE STUDIES: DOCUMENTING THE COST OF REGULATORY DELAYS (RE- DELAYS), IEA Implementing Agreement for Renewable Energy Technology Deployment (IEA-RETD), Utrecht, 2016.
Copyright © IEA-RETD 2016
(Stichting Foundation Renewable Energy Technology Deployment)
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ACKNOWLEDGEMENTS
The Authors would like to thank the IEA-RETD RE-DELAYS Project Steering Group (PSG) members for their guidance and support throughout the project, as well as the interview partners and supporting colleagues:
Project Steering Group
Michael Paunescu Senior Policy Advisor, Natural Resources Canada
Georgina Grenon Chargée de Mission, Ministry for Ecology, Sustainable Development, Transport and Housing, France
Heymi Bahar Renewable Energy Markets Analyst, International Energy Agency
Warren Neill Policy Analyst / Economist, Natural Resources Canada
Jennifer Johnson Senior Policy Advisor, Natural Resources Canada
Jon Graham Senior Policy Analyst, Natural Resources Canada
Sascha Van Rooijen Operating Agent, IEA-RETD
Coraline Bucquet Operating Agent, IEA-RETD
Supporting Colleagues Antoon Soete (3E N.V.), Régis Decoret (3E N.V.), Jérôme Crotteux (3E N.V.), Timothée Risson (3E N.V.)
Reviewing partners
RenewableUK (United Kingdom), The French Wind Energy Association (France), The Norwegian Wind Energy Association (Norway), CanSIA (Canada) AUTHORS
Ruben Verhaegen (3E N.V.), Pieter Joseph (3E N.V.), Amit Pinjani (LEI LLC), Lance Brooks (LEI LLC), Bat- Erdene Baatar (LEI LLC), Aurore Flament (3E N.V.)
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TABLE OF CONTENTS
Executive summary ...... 4 Glossary ...... 8 1 Introduction ...... 9 1.1 Context of the study ...... 9 1.2 Country selection ...... 10 1.3 Methodology and approach for analysis ...... 12 2 Qualitative assessment of the impact of regulatory delays on the development of renewable energy projects ...... 14 2.1 Markets overview ...... 14 2.2 Support mechanisms and options for finance ...... 17 2.3 Regulatory, permitting and grid access barriers ...... 21 3 Quantitative assessment of the impact of regulatory delays on the development of new renewable enegry projects ...... 25 3.1 Overview of the model and data gathering ...... 25 3.2 Estimation of regulatory costs and delays ...... 26 3.3 Indicative Estimation of NPV/Cost impact of delays and sensitivity analysis ...... 28 4 Key observations and conclusions ...... 37 5 Annex A: Country case studies...... 42 5.1 Introduction ...... 42 5.2 Country Selection ...... 43 5.3 France ...... 45 5.4 Australia ...... 56 5.5 Ontario (Canada) ...... 68 5.6 Norway ...... 79 5.7 United Kingdom ...... 90 5.8 United States Of America ...... 105 6 Annex B: Example survey for France ...... 119
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EXECUTIVE SUMMARY
Regulatory delays, whether they are related to differing countries promoting the development policy or project development undermine the of new renewable generation, as well as growth and economic potential of the qualitative insights into the market and renewable energy industry. In particular, such regulatory frameworks, and quantitative delays impede entry of nascent energy results from our economic model. These technologies. The development of renewable observations may foster and support new energy thus must be governed by a stable, regulatory reform initiatives for more efficient transparent and efficient regulatory framework renewable energy deployment. in order to compete effectively with conventional generation. Qualitative insights
The International Energy Agency – Renewable Barriers for permitting are a primary source of Energy Technology Development (IEA-RETD) delay for new generation development and commissioned 3E N.V. (3E) together with result in significant costs for developers. Our London Economics International LLC (LEI), research demonstrates the fact that herein referred to as 3E-LEI, to undertake a redundancies in the approval processes and research project to investigate the cost of disclosure requirements are frequently regulatory delays in the development of new experienced by developers. Various developers renewable energy projects worldwide. noted that across countries the permitting processes are not streamlined. This situation Approach has resulted in significant duplication of information requirements and, therefore, The project includes country case studies for unanticipated costs. The experiences of long France, Ontario (Canada), Australia, Norway, and expensive permitting and appeals the United Kingdom (UK) and the United States processes have been shared by interviewees of America (USA). To complement general across most jurisdictions. This is particularly a economic and policy observations from problem when no clear timelines are set. publicly available research and reports, Further, the appeal process can be expensive interviews with 37 project developers and (where legal assistance is required). several industry associations across the countries have been conducted. 3E-LEI started Lack of clarity and transparency in existing interviewing developers in August 2015, and regulation or development of new policies continued to receive input from developers continues to result in significant costs and until January 2016. delays to entry for (new) renewable technologies. Developers revealed that This report is accompanied by an economic uncertainty surrounding implementation of cost model and user guide, allowing for users governments’ commitments towards support to perform their own project-specific for RE, competing government objectives at assessments with individual times, as well as costly and lengthy parameters/assumptions. consultation processes in the development of policy/regulation are the key sources of delays 3E-LEI provide observations on the various and costs. regulatory frameworks implemented by
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Grid connection costs and grid access The grid connection process can also result in uncertainty are also cited as key issues. significant costs ranging up to $300,000 USD Developers are often required to pay for onshore wind and up to $100,000 USD for significant fees to access and stay on grid solar PV. Related to this is the access cost which connection queues, sometimes years before can range up $100,000 USD for both onshore construction can start, as observed in the UK wind and solar PV. This is however less and USA. Greater transparency regarding the significant for offshore wind and hydro. application and current standings of the queue, as well as increased communication between Modelling of the case studies developers and network operators will likely reduce developer uncertainty and costs. The model has been developed to be flexible and allows the user to review the impact for Quantitative insights different assumptions. Specific technology cost ranges have been estimated for each country. Through interviews and desktop research, the Furthermore, broader macroeconomic impacts different categories of regulatory delays, as associated with delays in direct job creation, illustrated above, were quantified. In order to investments and avoided greenhouse gas provide indicative cost estimates, 3E-LEI emissions are accounted for in the model. assessed the impact for these delays on both the project developer level and the economy in For illustration purposes, the impact (on general. project developers and the economy) of regulatory delays were modelled for delay Conclusions from this analysis illustrate that terms of one year and five years respectively. delays and costs associated with the As such, regulatory delays were found to have permitting process result in the largest impact the highest impact on project NPV in the UK for to project development across all technologies onshore wind, in the US for hydro and offshore and countries. Under certain scenarios, these wind and in Ontario for solar PV. The results can costs can range between $100,000-$200,000 vary significantly when different country- USD for solar PV, $300,000-$400,000 USD for specific assumptions are used. onshore wind and up to several million USD for offshore wind. For onshore wind, a generation technology covered in all six countries, Regulatory delays and costs are often project- permitting was found to be the most important specific, which makes it challenging to regulatory cost and is primarily driven by generalize modelling results across any environmental assessments. Grid connection technology or jurisdiction. Project developers costs also have a significant, albeit less, impact in different (or even the same) jurisdictions on the development of a project. Regulatory may face very different delay terms and costs costs are highest in the UK and grid connection in their specific experience. A striking costs appear to be higher in the UK, Australia observation is that 100% of the onshore wind and the USA than in France, Ontario and projects in France are facing regulatory delays Norway. Scenario comparison also reveals the as a result of challenges made by the public largest NPV impact in the UK, due to a and/or authorities. combination of a large investment multiplier (0.62), high capital costs (1,910 USD/kW) and
local content (69%), whereas France (capital
Page 5 of 124 DOCUMENTING THE COST OF REGULATORY DELAYS, RE-DELAYS, March 2016 costs 1,590 USD/kW with local content 52%) Policy Recommendations and Norway (capital cost 1275 USD/kW with local content 25%) are the least affected. From our discussions with developers and through independent desktop research, With respect to hydro development, a several measures were identified that may be generation technology covered in the applied to better encourage renewable project development, and reduce future delays and US and Norway, the important regulatory cost costs. Some of these measures have already driver is permitting and specifically, the been highlighted in the past but have not environmental impact assessments. The always led to significant reduction in delays. impact on NPV of different types of delay is Therefore a more provocative approach to this similar for Norway and the USA, however the might have an impact, and as such reduce the impact of delayed avoided emissions is more costs both on micro- as on macro-economic important in the USA than in Norway. This can level. be explained by the higher carbon intensity of the USA electricity sector (approximately 0.55 Streamline the regulatory processes. This CO2 tons/MWh compared to 0.002 CO2/MWh can be achieved by creating a one stop in Norway). shop with simplified rules for applications. Responsibilities should be defined upfront Permitting is equally the most including responsible actors paying important regulatory cost for solar PV compensations if applicable. There is a particular need for clear grid development developers in Ontario, France and Australia. In plans and compensation if infrastructure is Ontario costs are higher because site access not ready on time. Clear time lines for costs can be high. Grid connection costs are decisions regarding permitting and grid more important in Ontario relative to other access approvals will support this. jurisdictions. Scenario comparison confirms Regulation should be as independent as that Ontario is the most affected, whereas possible and this can be realized by France is the least affected. This can be investing in cross-national regimes. explained by the fact that Ontario is Increase accountability for decision making characterized by the highest assumed local processes at the regulatory/governmental content (approximately 80%), France (50%), level. Currently, in many cases, if a Australia (30%), and Ontario has a higher government or regulatory agency does not carbon intensity (0.18 CO2 tons/MWh) than make a decision after a pre-determined France (0.07 CO2 tons/MWh). period on a project, it is likely assessed unfavourably. It will be prudent for Finally, permitting costs for offshore decision making authorities to be held wind in both the UK and USA are accountable for delays in decisions within similar whereas grid connection costs their control. The accountability can come are more significant in the USA. Although the in the form of pre-determined fines impact of delays is similar in both countries, it associated with not achieving set is slightly higher in the USA due to milestones. approximated higher local content of capital goods (assumed 100% compared to 50% in the Link the level of incentive such as FIT to UK) and a higher carbon intensity (0.55 CO2 delay. More delays could potentially lead tons/MWh compared to 0.51 tons/MWh in the to a higher incentive provided to the UK).
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project developer making the government mechanisms to share concerns. Public more accountable acceptance towards these projects, often a key bottleneck, can be improved by Define clear procedures and cost impact informing the public about the benefits assessment of appeal processes. When the and risks of renewable energy projects. losing party in an appeal procedure is Acceptance will also be higher if locals can forced to indemnify the other party, there share concerns in a cooperative and is an incentive to avoid long appeal consultative environment. processes, and delays accordingly.
Inform the public about benefits and risks of RE and encourage consultative
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GLOSSARY
AREA Australian Renewable Energy Agency CanSIA Canadian Solar Industries Association CCA Capital Cost Allowance CEFC Clean Energy Finance Corporation EIA US Energy Information Agency EnergiNorge (electricity industry association) for Norway ERT Environmental Review Tribunal FEE French Wind Energy Association FIT Feed-In-Tariff GHG Greenhouse Gas IA Impact Assessment IESO Independent Electricity System Operator ITC Business Energy Investment Tax Credit LRP Large Renewable Procurement Program NORWEA Norwegian Wind Energy Association NREL National Renewable Energy laboratory NVE Norwegian Energy Regulator PTC Renewable Energy Production Tax Credit REA Renewable Energy Approval Process RenewableUK Renewable Energy Trade Association RGGI US Climate Action Plan and Regional Greenhouse Gas Initiative RPS Renewable Portfolio Standards SEIA US Solar Energy Industries Association UK United Kingdom USA United States of America
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1 INTRODUCTION
Regulatory delays and costs in renewable energy project development occur in many jurisdictions in the world. 3E-LEI have studied the impacts of these delays and costs in six countries and four RE technologies. By conducting desktop research and interviews with 37 developers, we performed both a qualitative analysis including case studies and quantitative analysis including the development of a financial model.
1 . 1 CONTEXT OF THE STUDY Regulatory delays, whether they are related to policy or project development, can undermine the growth and economic potential of the renewable energy industry and also in particular impede entry of nascent energy technologies. The development of renewable energy must thus be governed by a stable, transparent and efficient regulatory framework to compete effectively with conventional generation.
Understanding these issues 3E N.V. (3E) and London Economics International LLC (LEI), herein referred to as 3E-LEI, were commissioned to undertake a research project for the International Energy Agency – Renewable Energy Technology Development (IEA-RETD) to investigate the cost of regulatory delays in the development of new renewable energy projects worldwide. The overall objective of the research is to better understand and quantify the impact of regulatory delays and uncertainties to inform regulatory reform initiatives and promote greater efficiency in the global market for renewable energy deployment.
Two categories of regulatory delays and uncertainties are covered in the study:
Delays related to renewable energy policy decisions at the national, regional or local level. These delays create an uncertain climate for investors who may, as a result, hesitate to move forward with project investments. The target audience for these delays are local, regional and national governments. Delays related to administration and regulation. These include delays in disclosing or implementing regulation related to the renewable energy project development life cycle, such as building consents, environmental assessments and grid connection. The most affected by these delays are project developers and local industry players in the renewable energy chain; at the same time, delays may be caused by lengthy and in some cases, non-transparent administrative processes at various government/regulatory levels, in addition to appeal processes initiated by developers and/or other stakeholders involved (e.g. local citizens, governments).
The project involves quantifying the economic and financial costs (net of positive externalities) of regulatory delays to renewable energy developers and to the broader economy in a number of different jurisdictions throughout North America, Europe and Asia. Specifically, in order to quantify the impact of these delays, 3E-LEI has carried out country case studies and developed a financial model for six different jurisdictions. Data was sourced primarily from renewable energy developers and industry associations operating across these jurisdictions via interviews and survey questionnaires. In
Page 9 of 124 DOCUMENTING THE COST OF REGULATORY DELAYS, RE-DELAYS, March 2016 total 37 developers and associations were interviewed, providing valuable market insight into known and unknown regulatory delays.
1 . 2 COUNTRY SELECTION The jurisdictions covered as part of the study were discussed and agreed upon jointly between the IEA-RETD and 3E-LEI. Six countries have been selected for this study: France, Canada (Ontario), Australia, Norway, the United Kingdom (UK) and the United States of America (USA), on the basis of geographic representation and country interest with respect to the project objectives. Furthermore these countries provide a cross-section of approaches to the regulation and development of renewable energy supply (including policy and market objectives) and the energy market more broadly.
In addition to identifying specific countries to be covered, 3E-LEI has focused its studies on selecting generation technologies widely adopted in each of the countries, specifically onshore and offshore wind, conventional hydro and solar PV. Figure 1 highlights the selected countries and the respective generation technologies investigated.
Figure 1: Country and technology selection
1.2.1 Geographic Representation Four out of the six countries selected are IEA-RETD member countries. Out of the six selected countries, three continents, North America, Europe and Asia-Pacific are represented, reflecting the continental spread of the IEA-RETD member countries. In Europe, a diversity of regions, the British, Isles, Central Western Europe and Scandinavia, are also represented.
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1.2.2 Country Interest Market size, market maturity and resource diversity were key factors considered in the selection of countries relevant and interesting for the study. For instance, according to REN21’s latest Renewable Energy Global Status report, the USA and Canada are among the world’s top five countries for installed renewable power (including hydro).1 Furthermore, 3E-LEI’s collective knowledge of known examples of regulatory/policy delays or regulatory reforms was another consideration. For example, the UK and France have recently implemented measures to reduce regulatory delays for renewable energy development to varying degrees of success, while in Ontario a review of the feed-in-tariff program in 2011-2012 initially led to significant changes and delays in the developer application process. Finally, as four technologies are to be analysed in this project, it was important to select a group of countries with a high resource share or interesting project examples of onshore wind, offshore wind, hydro and solar PV development.
1.2.3 Practical considerations One of the main advantages of a study of this nature is gaining direct access to primary data sources through interviews with project developers and respective associations. These primary sources provide insight into the development process allowing 3E-LEI to gain a better understanding of both the cause of a regulatory delay and its associated cost.
The consortium’s ability to deliver in-depth and reliable information within the project schedule and budget is hinged on the countries selected for study. Pragmatic considerations that influenced our selection included 3E-LEI’s past project experience, existing local networks, office locations, language proficiency, access to secondary sources of data, and consortium and Project Steering Group (PSG) country expertise.
1 REN21, Renewables 2015 Global Status Report, 2015, Available at: http://www.ren21.net/Portals/0/documents/e- paper/GSR2015/index.html
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1 . 3 METHODOLOGY AND APPROACH FOR AN ALYSIS The overall objective of our research is to better understand and quantify the impact of regulatory delays to renewable energy developers and to the broader economy.
1.3.1 Process in several steps For this purpose, 3E-LEI followed a 5-step approach, as further explained and illustrated in
Figure 2:
Figure 2: Methodology followed
Step 1: gathering information with respect to general economic conditions, energy market and regulatory frameworks and project developments in the agreed upon countries through secondary source. Step 2: carrying out interviews with 37 project developers in 6 countries to gain insights in project development (primary sources). Step 3: development of case studies, including insights from developers (qualitative analysis). Step 4: developing a financial model with the purpose to quantify the impact of political and regulatory delays on project development and job creation (quantitative analysis). Step 5: developing policy recommendations and conclusions.
The focus in Step 1 is on costs of technology, job creation, support mechanisms, administrative processes, grid systems and sources of data (including previous research, reports and statistical information) for input into the economic model. With respect to Step 2, in-depth interviews were used to identify specific details regarding project developments, including steps and costs of development and technology. The first developers were contacted in August 2015. In addition to meetings with
Page 12 of 124 DOCUMENTING THE COST OF REGULATORY DELAYS, RE-DELAYS, March 2016 project developers, 3E-LEI also conducted interviews with various industry associations (and subsequently their member organisations) to provide additional valuable feedback and insight.
Both primary and secondary sources have allowed 3E-LEI to carry out a qualitative and quantitative analysis of the impacts of regulatory delays on the development process. We will elaborate on the results of qualitative analysis (Step 3) in Chapter 3. While 3E-LEI were able to gain interesting insights from developers and industry associations, it is important to emphasize that these insights are useful as a primary information source but are not the only starting point of the analysis. For the quantitative analysis (Step 4), where we calculate the impact of delays on the Net Present Value (NPV) of a project, we have equally challenged the feedback from the developers with 3E-LEI and third party resources/reports and databases as much as possible. Both types of analysis allowed us to come up with key observations (Step 5) presented in Chapter 5.
1.3.2 Data validation While 3E-LEI were able to gather significant data principally from developers, we recognise data validation is crucial to come up with sound results. Therefore, 3E-LEI’s wind, solar and hydro experts have been reviewing figures for the different countries. Also, as much data as possible was reviewed by the French Wind Energy Association (FEE) for France, by the Renewable Energy Trade Association (RenewableUK) for the United Kingdom (UK) and by the Norwegian Wind Energy Association (NORWEA) for Norway. In addition, the Canadian Solar Industries Association (CanSIA) assisted in gathering data from its members, the Canadian Wind Energy Association (CanWEA) provided some interesting insights on delays related to Renewable Energy Approval (REA) processes, and 3E-LEI also interviewed the USA Solar Energy Industries Association (SEIA). Data was further validated by secondary sources such as publications from the USA Energy Information Agency (EIA), National Renewable Energy laboratory (NREL) and third party databases (SNL, ABB Velocity Suite) among others.
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2 QUALITATIVE ASSESSME NT OF THE IMPACT OF REGULATORY DELAYS ON THE DEVELOPMENT OF RENEWABLE ENERGY PROJECTS
Market size, together with mandated RE targets, are each an important factor supporting the development of new renewable generation. Similarly the availability of support mechanisms and options for financing present key concerns for developers and have historically played a pivotal role in the development of new generation. Finally delays associated with prescriptive regulatory frameworks, and barriers associated with permitting and grid access remain the key sources of delays in the current market environment.
2 . 1 MARKETS OVERVIEW Figure 3 illustrates that, while the USA (with a population of 321 million people) have the highest volumes in terms of installed capacity of wind, hydro and solar PV (totalling 162 GW all together), the country has the lowest rate of production (13%) in 2014. Canada (Ontario), with a population of 13.7 million people, has the smallest market in terms of installed capacity (10.6 GW) but has a relatively high share of renewable energy production (32%). Finally, Norway is the smallest country in terms of population (5.1 million people) but the third country in terms of installed capacity driven by hydropower production (30.3 GW). Figure 3 illustrates the installed capacity of renewable energy technologies in the different countries. It is important to recognise the natural endowment of renewable energy resources in each of the countries covered as part of the study will have had a direct impact on the volume of renewable energy supply.
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Figure 3: Market size of renewable energy technologies 2
While the USA have the highest volumes of installed hydro and onshore wind generation capacity in 2014, reflective of the size of the market and its endowment of hydro and onshore wind resources, Norway (30.3 GW) and France (25.4 GW) also have considerable hydro capacity. The UK (13.5 GW in 2014) and France (9.3 GW in 2014) have heavily invested in onshore wind over the last few years. In the USA (18.3 GW in 2014), France (5.6 GW in 2014) and the UK (5.1 GW in 2014), PV solar energy has also been growing significantly over the last few years.3
2.1.1 RE targets In order to further develop renewable energy technologies in the years to come, the presence of a RE target (as a percentage of domestic final demand) across each jurisdiction provides for a positive response from markets in terms of new power station developments. Individually these targets provide a level of investment certainty to their respective markets facilitating the development of new renewable energy projects, for example through establishing a liability on behalf of retailers or a capacity procurement target in the case of Ontario.
2 PV Tech, Obama sets 20% renewables target for US government by 2020, 6 December 2013, Available at: http://www.pv- tech.org/news/obama_sets_20_renewables_target_for_us_government_by_2020 Country case studies RTE, France Electricity Report for 2014, Available at: http://www.rte- france.com/sites/default/files/2015_01_27_pk_rte_2014_french_electricity_report.pdf#9 3 Solar Energy Industries Association, 10 March 2015, Available at: http://www.seia.org/news/us-installs-62-gw-solar-pv-2014-30-over- 2013 Country case studies
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All jurisdictions covered have such a target ranging from 20% to 100% of total production as displayed in Figure 3. Norway already produces 100% of its electricity from renewable energy sources, but is seeking to increase hydro and onshore wind generation in order to export additional energy to neighbouring countries. The government of Ontario outlined its plans to have renewable sources account for 46% of installed capacity or approximately 20 GW by 2025.4 The remaining four countries have renewable energy targets between 20% and 30%. The USA is different such that renewable targets for separate states are mainly governed by Renewable Portfolio Standards (RPS). Since October 2015, 29 states, the District of Columbia, and two territories implemented enforceable RPS policies, while an additional eight states and two territories have set renewable energy goals.5
Unexpected reviews of, or changes made to, these targets can create investor uncertainty or lead to additional regulatory delays (timing and costs) for project developers. The Australian government, for example, recently announced changes to its renewable energy target for large scale renewable generation, reducing the target from 41,000 GWh to 33,000 GWh of total demand by 2020. Through discussions with Australian renewable energy developers 3E-LEI understand this led to the postponement of a number of new developments while uncertainty remained in the market regarding details of the new target (and in the case of retailers, until an understanding of their overall liability was determined). Another example is the significantly less ambitious targets for wind energy developments recently communicated by the new elected government in the UK.
2.1.2 Market activity The current market activity can equally be seen as an important indicator for developments in the near to medium term. With respect to wind development, new capacity additions in the USA totalled more than 4.8 GW while the UK and France developed respectively around 1.7 GW and 1 GW in 2014. The development of renewable wind capacity in the USA is expected to rebound and grow in the next few years due to improvements in cost and performance. In the UK perspectives for wind developments are less bright since the newly elected government argues that there is enough onshore wind in the pipeline to reach the 2020 targets. As far as offshore wind is concerned, the UK is expected to deliver another 5 GW by 2020. France has put in place different initiatives to simplify existing regulation relating to onshore wind in order to increase development in the sector.
In contrast, wind development in Norway has plunged between 2012 (0.2 GW of new installed capacity) and 2014 (0.045 GW of new installed capacity) mostly due to the low electricity price and the low green certificate market price in the country, though it has very good wind conditions (average capacity factor of 31%) and a high potential for wind development.6 Large hydro projects on the other
4 Ontario Ministry of Energy, Achieving Balance: Ontario’s Long-Term Energy Plan, December 2013, Available: http://www.energy.gov.on.ca/en/ltep/ 5 RPS in this case study refers to all renewable energy target policies such as the Renewable Energy Standard (“RES”), Renewable Energy Portfolio Standard (“REPS”), Clean Energy Portfolio Goal (“CEPG”), Alternative Energy Portfolio Standard (“AEPS”) and others NCSL, State Renewable Portfolio Standards and Goals, October 2015, Available at: http://www.ncsl.org/research/energy/renewable- portfolio-standards.aspx 6 European Wind Energy Association, Wind in Power, 2014 European statistics, February 2015, Available at: http://www.ewea.org/fileadmin/files/library/publications/statistics/EWEA-Annual-Statistics-2014.pdf Cleantechnica , Solar & Wind = 53% Of New US Electricity Capacity In 2014, 3 February 2015, Available at: http://cleantechnica.com/2015/02/03/solar-wind-53-new-us-electricity-capacity-2014
Page 16 of 124 DOCUMENTING THE COST OF REGULATORY DELAYS, RE-DELAYS, March 2016 hand are expected to continue to be developed, with forecasts taking into account an additional 2.8 GW of new hydro power coming online in the next 16 years.
In the USA (5.2 GW), UK (more than 2.3 GW) and France (more than 0.9 GW), there have also been large capacity additions for solar PV (more than 0.9 GW) in 2014.7
In Ontario, the Independent Electricity System operator (IESO) is responsible for procurement of all new generation in the province. The Ontario government’s announcement of a renewable energy target of 10.7 GW for wind, solar, and bioenergy to 2021, and hydro target of 9.3 GW by 2025 as part of the 2013 Long Term Energy Plan was designed to provide the renewables sector with a predictable procurement schedule going forward. In March 2015 the IESO released a request for proposals as part of the Large Renewable Procurement (LRP) program. The IESO targets for the first procurement (targeted for completion on March 2016) under the LRP program include up to 0.3 GW of wind, 0.14 GW of solar, 0.05 GW of bioenergy and 0.075 GW of hydro. Where these targets are met, this would be in addition to the 0.505 GW of hydro, 0.7861 GW of solar, 1.448 GW of wind and 0.3747 GW of bioenergy capacity added over 2014 and 2015.
Unlike Ontario, investment in new generation in Australia is not underwritten by contracting directly with the system operator. Instead investors/developers typically seek power purchase agreements with retailers (or other large customers), thereby guaranteeing a certain level of revenue, in order to finance a new development.8 Furthermore, and as noted previously, a key factor underpinning investment in renewable generation is the provision of generation certificates under the renewable energy target scheme. The Australian Energy Market Operator’s August 2015 Electricity Statement of Opportunities for the National Electricity Market reports 1.0684 GW of new wind and solar generation capacity commenced operation in the financial year 2014-2015. With recent changes to the large scale renewable energy target having been made by the Australian Government the market witnessed an initial slowdown in the level of development activity while the review was conducted. Although speaking with developers, market activity is expected to increase over the short- to medium-term with the announcement of a new target and abolishment of defined review periods every two years.
2 . 2 SUPPORT MECHANISMS A ND OPTIONS FOR FINAN CE Available support mechanisms and financing options are important levers in the development of renewable energy projects. As our analysis revealed, different support mechanisms are available depending on the technology and the country, and financing options ensure the maturity and liquidity of the market.
PV magazine, UK almost doubles PV capacity in 12 months, January 2015, Available at: http://www.pv- magazine.com/news/details/beitrag/uk-almost-doubles-pv-capacity-in-12-months_100017981/#ixzz3t65un6BM RTE, France Electricity Report for 2014, January 2015, Available at: http://www.rte- france.com/sites/default/files/2015_01_27_pk_rte_2014_french_electricity_report.pdf#9 Country case studies 7 RTE, France Electricity Report for 2014, Available at: http://www.rte- france.com/sites/default/files/2015_01_27_pk_rte_2014_french_electricity_report.pdf#9 8 Alternatively (and similarly to Ontario) investors/developers may rely solely on the prevailing energy market prices, where deemed favourable
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2.2.1 Contract support Our case studies illustrate four different schemes have been implemented to support investment in renewable energy technologies, tenders (or procurement of new generation capacity), Feed-in-Tariffs (FIT) programs, tax breaks and tradable certificate schemes. Whereas Australia and Norway have set up a system of tradable generation certificates, Canada (Ontario) organises various tenders/programs for the procurement of generation supply. The USA, Canada and Australia also use variations of a FIT programme and or tax breaks. France and the UK have implemented combinations of different systems. France uses FITs for onshore wind, and a tender system for ground mounted solar PV projects larger than 250 kW. The UK uses a Renewable Obligations Certificates support scheme, moving towards a CFD auctions system. Table 1 shows the different support schemes in places and related parameters.
Support system in Length (years) Most recent tariffs Framework support place (USD/Kwh)* scheme France onshore wind FIT 15 9.21 USD cents first 10 Stable support years, between 3.15 and 9.21 USD cents last 5 years France solar PV Tenders 20 Similar tariffs as for wind Support for PV solar was increased in August 2015 Australia onshore wind Generation 15 LGC –53.12 USD cents* Uncertain regulatory certificates SGC –28.95 USD cents* framework
Australia solar PV Generation 15 LGC – 53.12 USD cents* Uncertain regulatory certificates / FIT SGC – 28.95 USD cents* framework FIT (State prices) 3.7 – 8.7 USD cents Canada (Ontario) Tenders/ FIT 20 First phase currently Support is increasing onshore wind underway but results not known 9.64 USD cents yet Canada solar PV Tenders / FIT 20 First phase currently Support is increasing underway but results not known 20.7 – 28.91 USD cents yet Norway onshore wind Generation 15 1.5-2 USD cents System is politically certificates driven Norway hydro Generation 15 1.5-2 USD cents Closure in 2020 certificates United Kingdom Support only Uncertain regulatory (England and Scotland) projects 20 5.8 USD cents framework onshore wind operational in the short-term United Kingdom Tenders 15 17.4- 18.4 USD cents Support postponed for (England and Scotland) new projects – offshore wind Auctions end of 2016 United States of PTC/ITC Inflation-adjusted per kWh Support subject to America tax credit; credit based on a potential renewal percent of expenditures * Spot price as of November 27, 2015 (minimum parcel size 5,000 certificates)
** Exchange rate EUR/USD= 0.89, Exchange rate GBP/USD= 0.654, Exchange rate NOK/USD=8.238, Exchange rate CAD/USD= 1.238, Exchange rate AUD/USD= 1.378
Table 1: Support schemes per technology in the different countries for new projects
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The table demonstrates that the length of support varies between 10 and 20 years across the various jurisdictions. In France, support levels are stable and it was recently announced that more support for ground-mounted solar projects will be available. Ground mounted solar PV projects larger than 250 kW receive support through tenders for 20 years. Wind is supported by a strong FIT scheme that has been in place since 2008 and was re-instated in 2014.
The UK government, on the other hand, decided that all onshore wind projects that don’t have a planning consent, a grid connection offer and acceptance and evidence of the land rights before 18 June 2015 or become operational before April 2016, will not be eligible for Renewables Obligation (RO) support anymore, arguing that there is already enough onshore wind in the pipeline to reach the 2020 targets. Support for offshore wind however is high though uncertain in the future.
In Norway, the certificate scheme was only launched in 2012 (and will close in 2020), but prices have been significantly decreasing and it is very difficult to develop projects because electricity market prices are decreasing as well.9
In Ontario, the IESO facilitate the procurement of new generation capacity via several programs including FIT, microFIT and Large Renewable Procurement (LRP). Ontario’s FIT programs have undergone several iterations since their implementation in 2009 under the Green Energy and Green Economy Act (2009). The current version, Version 4, was released in September 2015.
As noted previously, interviews with Australian developers highlight the importance of a stable RE target scheme to the development of new large scale generation developments. In addition to the RE target scheme, individual states have voluntarily established FIT programs promoting investment in smaller scale renewable energy technologies. These programs have resulted in a significant increase in the level of rooftop solar generation operating across the country.
In the US, the Renewable Energy Production Tax Credit (“PTC”) and Business Energy Investment Tax Credit (“ITC”) are federally administered corporate tax credits for the development of renewable energy. The PTC was enacted in 1992, and modified in 2009, 2013, and 2014. It provides an inflation- adjusted per kWh tax credit for electricity generated and sold from qualifying resources. The ITC was enacted in 2008, and expanded in 2009. It provides a credit based on a percent of expenditures dependent on the technology or resources used.10
9 Country case studies Bloomberg, Nordic green energy boom may exceed target as power prices slump, 3 June 2015, Available at: : http://www.bloomberg.com/news/articles/2015-06-03/nordic-green-energy-boom-may-exceed-target-as-power-prices-slump 10 U.S. Government of Energy, Business Energy Investment Tax Credit (ITC), Available at: http://energy.gov/savings/business-energy- investment-tax-credit-itc
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2.2.2 Options for financing While support from governments can be seen as one way to finance projects, project developers have access to finance through many other ways. We identified the options for finance in Table 2.
National and/or supra-national Financial/institutions and Grants, tax credits and low Access to finance banks investors interest loans
Grants, tax credits and low France Yes Yes (Public and Private) interest loans Grants, tax credits and low Australia Yes Yes (Public and Private) interest loans Yes (Mainly Government Grants, Accelerated capital cost Canada (Ontario) Yes funds) allowance Yes but very domestic and Norway Yes hesitating because of low Tax credits prices Yes but don't want to finance CPF was frozen in march 2014 and United Kingdom (England Yes projects without permit before tax exemptions disappeared in and Scotland) April 2016 July 2015 United States of America Yes Yes PTCs/ITCs Table 2: Financing options in the different countries
In both France and the UK, there is an important presence of banks and financial institutions. However, in the UK, there is uncertainty with respect to the availability of support for onshore and offshore wind. As a result, investors hesitate to finance projects that might not have the building permit by the end of March 2016 as mentioned before. There are also more instruments such as grants, tax credits and low interest loans available in France than in the UK.
In Norway, mostly Norwegian project financers are present. However, discussions with developers indicate they are waiting for electricity market and certificate prices to go up. A driver for these price increases could be the increasing volumes of export to other countries and the recently decided RE targets that are more ambitious. Some international players are looking to invest in the Norwegian electricity market due to the possibility of higher returns, access to inter-jurisdictional markets, and perceived lower risks.
Investment in renewable energy projects in the USA amounted to USD 29.3 billion in 2014. Corporations such as Google, Amazon, Apple, Facebook, and IKEA are also investing in renewables. As indicated earlier, the US Government supports renewable development through tax credits such as the PTC and ITC, and through accelerated depreciation benefits. These tax benefits represent approximately 50-55% of a renewable project’s installed costs.11
In Australia the Australian Renewable Energy Agency (ARENA) has access to approximately AUD 2.5 billion of funding which is legislated and extends until 2022. This funding is to be used to advance RE technologies towards commercial readiness, improve business mores and/or reduce overall industry
11 NREL, Financing U.S. Renewable Energy Projects Through Public Capital Vehicles: Qualitative and Quantitative Benefits, April 2013, Available at: http://www.nrel.gov/docs/fy13osti/58315.pdf
Page 20 of 124 DOCUMENTING THE COST OF REGULATORY DELAYS, RE-DELAYS, March 2016 costs. ARENA has completed 49 projects to date and has an additional 200 projects currently under management. Further to ARENA, the Clean Energy Finance Corporation (CEFC), established under the Clean Energy Finance Corporation Act 2012, seeks to mobilise investment in renewable energy, energy efficiency and low emission technologies. The CEFC has invested over AUD 1.4 billion in finance, through 55 direct investments and 34 co-financed projects.
The Canadian Government allows for businesses investing in renewable energy to be eligible for the accelerated capital cost allowance (“CCA”) rate. This would allow the cost of eligible assets procured before 2020 to be depreciated at a rate of 50% per year on a declining balance basis. Other federal programs aimed at renewable energy include the ecoENERGY for Renewable Power program, a CAD 1.4 billion initiative, which run from April 2007 through March 2011 to promote wind, low-impact hydro, solar photovoltaic and biomass electricity generation.1213
2 . 3 REGULATORY, PERMITTI NG AND GRID ACCESS B ARRIERS As briefly mentioned earlier in this section, the general regulatory framework will be crucial for any new project development. Significant delays occur in many countries because of permitting and grid access barriers. Table 3 provides an overview of these different barriers.
General and administrative Barriers for permitting Barriers for grid access barriers
France * Government strongly supports RE * Permi tting: lengthy * Grid costs: difficult to estimate * Developments steps cannot be * Consultations and appealing: * Grid availability: sometimes issue done in parallel lengthy and costly. Almost all wind projects are challenged by opponents Australia * Government strongly supports RE * Permitting: lengthy with * Grid costs: often an issue - cost, *Prohibitive variations in state potential for duplication complexity and time delays based regulations (between state and federal experienced in some instances for new * Lack of market-exit incentives requirements) in some instances connections * Consultations and appealing: * Grid availability: network access lengthy and costly generally not an issue Canada * Government strongly supports RE * Permitting: can be lengthy and * Grid access: lengthy and uncertain (Ontario) * Investment subject to IESO non-transparent subject to individual LDC processes procurement and government Consultations and appealing: directive non-transparent
Norway * Support: politically driven and * Permitting: lengthy and no * Grid costs and availability: grid is closure 2020 clear decision timelines weak sometimes so high costs of * Recent joint target increases by * Consultations and appealing: reinforcements, often to be paid by Swedish and Norwegian lengthy (various consultations, project developers. If grid available, government appealing used a lot) these costs do not have to be paid United Kingdom * Government not pro-renewables * Permitti ng: wind * Grid costs: very high, unpredictable * Secretary of State can call in on projects<50MW: lengthy and and to be paid years upfront any project processes are very unclear * Grid availability: big issue * Consultations and appealing: lengthy
12 KPMG, Taxes and incentives for renewable energy, September 2013, Available at: https://www.kpmg.com/Global/en/IssuesAndInsights/ArticlesPublications/taxes-and-incentives-for-renewable- energy/Documents/taxes-and-incentives-for-renewable-energy-2013.pdf 13 Natural Resources Canada, EcoEnergy for Renewable Power, 2015, Available at: https://www.nrcan.gc.ca/ecoaction/14145
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United States of * Government supports RE * Permitting processes can be * Grid costs: Cost impact of another America * Uncertainty over PTC/ITC lengthy and cumbersome and project (in queue) withdrawing can be regulations can sometimes be unclear and unknown need to be streamlined * Grid availability: In some regions, grid Consultations and appealing: connections are relatively easy to lengthy apply for, but can clog up the system
Table 3: Regulatory, permitting and grid access barriers to the development of renewable energy projects
2.3.1 General and administrative barriers In France, the government strongly supports renewables and we can observe a relatively stable regulatory framework (though changes have taken place these last few years). Applications for permits and the grid connection however have to be carried out sequentially, which slows the process.
In Norway, support was only introduced in 2012, and will be abolished by 2020 for new projects. The green certificate prices are however variable and the commitment of the government towards RE is unclear. The different processes are very lengthy and costly.
The UK abolished the existing support for new onshore wind projects and future support for onshore and offshore wind is uncertain. Moreover, the planning appeals recovery criteria allow the Secretary of State to take the final decision on onshore wind appeals.
In the USA, interconnection process is typically governed by federal policy for transmission-level interconnections and state-level policy for distribution-level interconnections. Streamlining processes and regulatory certainty can assist.
While in Ontario, the renewable energy assessment (REA) process provides for prescriptive steps to be completed prior to the construction and operation of a new RE facility and in some cases may provide developer rewards for achieving greater community buy-in, this significant consultation can result in lengthy delays, costs and litigation measures for developers
In Australia a lack of market-exit incentives and regulations is seen by some developers as an obstacle for renewable project development, especially when electricity demand is falling. With decreasing demand, installing new renewable generators means replacing high order emitting end-of-life assets, the operators of which have been reluctant to decommission plants, instead preferring to continue operations.. Policy makers in Australia also face competing objectives, whereby fossil fuels such as coal make up a significant percentage of Australia’s export revenues and (low cost) fossil fuel (coal) technologies have historically dominated generation supply in the country. As a result policy makers are required to balance any unnecessary stranding of Australian energy exports or assets while attempting to promote investment in renewable energy technologies.
2.3.2 Barriers for permitting There are issues with respect to permitting in all jurisdictions covered in the study. In all countries, permitting (including the impact assessment (IA) study, other studies and the decision-making process by local or national authorities) can be very lengthy. Consultations with concerned stakeholders are also increasingly important and can result in an appeals process without clear time lines.
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In France, almost all wind projects are challenged by opponents leading to delays of several years and appeals are generally expensive because the developer has to make use of the expensive services of lawyers. In Norway, the timing of licence decisions is highly unpredictable and the appeals process is carried out between the energy regulator and the Ministry of Petroleum and Energy. This makes it less expensive than in France but often very time consuming. In the UK appeals processes are executed between a local appeal body and the national government but these processes often go together with strong involvement of staff members from project developers. Furthermore, projects are often delayed because of contradicting licence decisions on different government levels and deadlines for licence decisions that are not respected.
Receiving permitting approvals (particularly related to environmental permitting) can, similarly, be lengthy and cumbersome in the USA and Canada. For example, in the US, several developers have expressed frustration at the lack of clarity in the process, and have suggested that the USA Fish and Wildlife Service processes should be streamlined. In Canada these processes are subject to significant community consultation which may in turn lead to significant delays and challenges where various permit applications/decisions are challenged by interveners. Where, for example a challenge is made to the environmental assessment process as part of the REA, the process may be referred to the Environmental Review Tribunal (ERT) for review. This could lead to a delay of up to 6 months and potentially additional legal costs not anticipated as part of the review. Furthermore Canadian developers note that the studies submitted as part of the REA are often not deemed to be complete and guidance as to how to address deficiencies may sometimes be lacking or inconsistent from one project to the next.
In Australia, the permitting process for the development of a new generating station has historically been a source of delay and additional costs for developers. In particular, where a developer is required to gain approval from both Federal and State based governments, this process may lead to duplication of information submitted as part of the permit approval process. Recognising these issues the Australian Government looked to reduce the regulatory costs on businesses (and individuals) in its report Regulatory Cost Savings Under the One-Stop Shop for Environmental Approvals (September 2014). In the report the Australian Government recognise the duplications between state, territory and federal environmental assessment and approval processes have amounted to:
Administrative costs for example completing two separate application forms. Administrative cost savings for business under the One-Stop Shop are estimated at AUD 9 million.
Delay costs for example waiting for an Australian Government project approval after a state or territory project approval. Delay cost savings for business under the One-Stop Shop are estimated at AUD 417 million.14 In releasing the report the Australian Government notes the One-Stop Shop will result in streamlined decisions on projects, lower costs for business and high environmental standards being maintained.15
14 Australian Government – Department of Environment, Regulatory Cost Savings Under the One-Stop Shop for Environmental Approvals, September 2014 15 Ibid
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2.3.3 Barriers for grid access The interviews undertaken also reveal significantly more issues with respect to grid access in the UK (Scotland) and the USA than in the other countries.
In Scotland, delays of up to 7-8 years can occur if no grid capacity is available (significant unavailability of grid capacity before 2020 or 2025 in some cases). Not only availability but also costs are a bottleneck because developers often have to pay high costs many years upfront to secure the connection. In France, high costs and a low availability can also occur in some regions but the transmission grid is generally strong so it is less of a problem. The Ministry of Ecology, Sustainable Development and Energy plays an important role in the organisation and development of the electric system in France, and it defines long term system planning in terms of investment in production capacity.
In Norway, the grid is equally weak in many (more remote) regions, but the transmission operator, Statnett, has been investing a lot in recent years and many infrastructure investments are planned for the coming years. The fee that project owners will have to pay highly varies from one project to another. Since the grid operators in Norway are obliged to connect power generating plants to their grid, they have to invest in grid infrastructure or reinforcements, and will often ask for an important contribution from the plant operator.
In certain USA states/regions, grid connections are relatively easy to apply for, but fall into a queue in the system. When a developer withdraws a grid connection application, the cost impact to remaining developers in the queue can be unknown beforehand. Developers often pay a significant amount of money to stay in queue for grid connection.
In Ontario developers note the connection assessments process can be long if the local distribution companies (LDC) are small or new to the process, and need to hire consultants to assess connection requests. The delay may also become acute if the LDC needs to engage Hydro One (due to its transmission ownership).
Finally, in Australia, the regulatory framework governing the electricity network provides for non-firm access to be granted to all generators on a non-discriminatory basis.16 Developers therefore take on the investment and operational risks in deciding where to connect to the network, subject to among other factors, access to fuel supplies, and location of load centres and configuration of the transmission and distribution networks. While developers are generally free to connect to the network, there are known timing, complexity and costs issues with gaining access to the network. The Australian Energy Market Commission recognised these issues in release of the Transmission Framework Review – Final Report April 2013.
16 Optional firm access may be granted in some instances.
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3 QUANTITATIVE ASSESSM ENT OF THE IMPACT OF REGULATORY DELAYS ON THE DEVELOPMENT OF NEW R ENEWABLE ENEGRY PROJECTS
3E-LEI quantified the impact associated with regulatory delays/costs related to site access, permitting and grid connections. Of these impacts permitting and securing grid connection for a new development results in the greatest change in a projects costs and timing across all countries assessed. The largest NPV impact associated with delays occurs in the UK for onshore wind, in the USA for hydro and offshore wind and in Ontario for solar PV.
3 . 1 OVERVIEW OF THE MODE L AND DATA GATHERIN G 3E-LEI identified the following four delays that can be traced back to policies, regulations and processes originating from government and regulatory entities or part of the regulatory review processes:
- Political/regulatory delays: these are related to changes in policy and regulation that lead to delays and lost opportunities, including the cost of missed support scheme opportunities due to delays. - Site access delays: these are related to procedures to obtain approvals from local communities, businesses and landowners (i.e. not directly related to environmental approvals). - Environmental delays: these are related to procedures to obtain environmental permits (the impact assessment of air, land, water resources and ecosystems). - Grid connection delays: these are related to procedures to obtain approvals for grid connection (non-technical delays related to the lack of coordination between system planners, transmission system operators and/or distribution system operators, regulators).
In order to estimate a project NPV value, the model uses six different data sets (one for each country covered in the study) with a focus on the cost of technology, regulatory costs and the economic impact of investments, manufacturing, construction and permanent jobs and avoided CO2 emissions. The sources of data inputs include a variety of primary and secondary sources, such as previous research studies and reports, industry surveys, statistical information collected by government agencies, and direct interviews with project developers in the jurisdictions covered by the model. The model subsequently calculates the change in the value of projects resulting from timing delays and additional costs associated with delay events. Furthermore, the model accounts for broader economic benefits and changes in emissions resulting from a regulatory delay. This allows the calculation of the total impact of regulatory delays. More details on each aspect of the model are presented in the user guide included in Appendix 1.
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3 . 2 ESTIMATION OF REGULATORY COSTS AND DELAYS Based on interviews with project developers and industry associations and desk research, we have observed a broad range of delays and costs across generation technologies and these delays and costs are usually project specific. Project developers in the same jurisdictions can thus face very different delay terms and costs in their specific experience. Also, project sizes for a specific technology can vary significantly from one country to another and this can partly explain regulatory cost differences.
3.2.1 Regulatory costs and delays for onshore wind With respect to onshore wind, interviews reveal that regulatory costs are different across each country. In France, the permitting cost is mainly driven by the environmental impact assessment (EIA), other technical studies, internal staff costs and lawyer costs because of appeal processes. In Norway, the impact assessment, often including external services of consultants, is by far the highest regulatory cost. In the UK, permitting costs are driven by impact studies and appeal processes and costs to prepare grid connections (fees that have to be paid upfront years before) are a lot higher than in other jurisdictions. According to the interviewed developers, these grid costs can run from ten thousands United Kingdom Pound Sterling (GBP) up to several millions GBP.
All European countries have been confronted with political delays. While the UK is currently confronted with uncertainty with respect to onshore wind developments, projects seeking support in France can wait up to 1 year to go through the FIT process. In Norway, delays occur because of low and fluctuating certificate prices. The support scheme in this country is also subject to political intervention. For example between 2009 and 2012, no support for wind was available. Permitting delays happen in all three European countries mainly because of slow decision making (up to 3-4 years in France and the UK, up to 5-6 years in Norway) and appeals processes (up to 3 years in Norway, up to 4-5 years in the UK, up to 7-8 years in France). Grid connection delay costs are very high, predominantly because of the lack of grid availability and the need for reinforcements.
Ontario’s FIT program had provided onshore wind developers with an attractive support scheme when launched but political delays increased uncertainty and risks when the FIT program was put on hold for nearly 2 years. Property owners (especially in more rural parts of Ontario) have voiced their concerns with health impacts of wind turbines, leading to more difficult site access processes. USA onshore wind development has been buoyed by tax incentives, renewable targets (where available), high energy market prices and lowering of capital costs over the past decade so much so that in many states wind became substantial merchant revenue-based source of energy. Currently the developers of new projects face a more challenging environment (e.g. lower energy prices due to lower price of natural gas) and uncertainty surrounding the extension of the investment tax credit. Australia’s wind developers have been particularly concerned with the unclear status of the renewable attainment targets in recent years which have limited their ability to find off-takers.
3.2.2 Regulatory costs and delays for hydro We have identified that hydro project developers are confronted with important regulatory costs when applying for permits. In Norway, similar to wind development, the environmental impact assessment as a part of the permitting is the most important cost. It is also during the permitting process that developers experience the longest delays whereby decision-making can take up to 5-6 years. According
Page 26 of 124 DOCUMENTING THE COST OF REGULATORY DELAYS, RE-DELAYS, March 2016 to the information from our interviews, appeals are less of an issue for hydro. As for onshore wind, low and fluctuating prices are equally a problem for hydro projects and can be considered as a political delay.
The major challenges for development of hydroelectric power in the USA are centred on the site access. Over a century of development means that in many cases easy access sites are already developed. Regulatory delays related to permitting are often caused by federal agencies tasked with enforcement of the Endangered Species Act and similar legislation. Many of the available resources are located in relatively remote areas causing challenges in getting a cost-effective grid connection.
3.2.3 Regulatory costs and delays for solar PV With respect to solar PV, in France, the permitting cost is mainly driven by the EIA, other technical studies and internal staff costs. Appeals processes are less expensive and less common (rare cases for large-scale projects) so this might be one of the explanations why regulatory costs are lower. Furthermore, the development process is faster for solar PV than for onshore wind. Delays of up to 4 years with respect to grid connection access can occur but are also less common than for onshore wind, partly because installed capacities are smaller.
Challenges for development of solar PV projects in Ontario and Australia mirror those in Europe. Additionally, similar to onshore wind challenges in Ontario, solar PV projects have encountered a freeze in FIT processes (1-2 years) and downward revision of FIT prices. Australia’s solar PV project developers have also found it challenging to secure contracts due to uncertainty surrounding renewable targets.
3.2.4 Regulatory costs and delays for offshore wind In the UK, impact assessments and consultation processes for offshore wind projects as a part of permitting dominate the development process so issues and ambiguities with respect to these will cause the most significant delays and costs. According to developers, permitting costs can range from several millions up to several tens of millions of GBP. Other delays are less common as decisions on permits tend to be made within 18 months of submission of an application. Appeals processes do not occur and offshore developers have a lot more control on grid issues.
While the USA has more abundant resources for development of offshore wind power, it lags behind the European counterparts. Cape Wind, slated to be the first offshore wind project in the US, has been through 15 years of planning and litigation, mainly due to local opposition to consenting the project. Another project by Deepwater Wind has been able to achieve more progress after acquiring lease rights to offshore territory controlled by the federal government (foundation for the first installation was laid earlier this year). Among the major challenges to the development of offshore wind power are uncertainty around the ITC and discontinuation of the federal loan guarantee program as well as a 5-7 year permitting process.
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3.2.5 Summary of different regulatory costs according to the interviews Our analysis illustrates that, for wind, permitting costs range between USD 300,000-400,000, grid connection costs go up to USD 300,000 and site access costs can range up to USD 100K. For solar PV, permitting costs range between USD 100,000-200,000, grid connection costs range up to USD 100,000 and site access costs can be of the same order of magnitude than for onshore wind. For offshore wind and hydro, permitting costs are respectively around up to several million USD and USD 300,000- 400,000 whereas other regulatory costs are less important.
3 . 3 INDICATIVE ESTIMATIO N O F NPV/COST I M PA C T O F DELAYS AND SENSITIVITY ANA LYSIS As described in the previous section, according to our interviews, project delays will vary between projects and countries. To present a comparable analysis across countries/technologies, 3E-LEI estimated the change in NPV with two scenarios, including one-year or five-year delay for political, site access, environmental or grid connection reasons. These are analysed for the four technologies (i.e. hydro, solar, offshore wind and onshore wind). In these scenarios, we are using the following assumptions:
A one-year delay results in 50% of additional regulatory costs and 0.25% increase in cost of debt. A five-year delay results in 20% of additional annual regulatory costs and 1.00% increase in cost of debt.
While the project sizes can vary across projects and countries, to make results comparable, we assume standard project sizes of 100 MW for onshore wind, 70 MW for hydro, 25 MW for solar PV and 200 MW for offshore wind.
3.3.1 Onshore wind Onshore wind projects have different impacts for the four types of delays across different countries. The UK is the most impacted, whereas France and Norway are the least affected. Figure 4 demonstrates that NPV decreases are primarily explained by delayed economic benefits in all 3 countries whereas delayed avoided emissions are also essential in the UK and to a lesser extent in France. In Norway, these avoided emissions are almost of no importance. With the above mentioned assumptions, there is a higher impact on the NPV due to timing delays and additional regulatory costs in the UK than in Norway and France.
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Figure 4: NPV (USD) decreases for onshore wind because of permitting delays – UK, France and Norway
- Cost of Debt - 0.25% Cost of Debt - 1.00% Cost of Debt - 0.25% Cost of Debt - 1.00% Cost of Debt - 0.25% Cost of Debt - 1.00% (10,000,000) higher higher higher higher higher higher 50% reg costs 20% reg costs 50% reg costs 20% reg costs 50% reg costs 20% reg costs (20,000,000) 1 year 5 years 1 year 5 years 1 year 5 years (30,000,000) UK Norway France
(40,000,000)
(50,000,000)
(60,000,000)
Change in NPV due to delayed economic benefits Change in NPV due to delayed avoided emissions
The primary driver that differentiates France and Norway versus UK, USA and Australia is the carbon intensity of these countries. Additionally, the UK has greater capital cost (USD 1,910/kW) and greater impact on economy due to larger multiplier for investment (1.21) and approximated higher local content (69%), while Norway has lower approximated local content (25%) and lower capital costs ( USD 1,275/kW). Ontario’s carbon intensity is estimated at levels below those of UK, USA and Australia (primarily driven by high proportion of coal-fired capacity), but higher than in France (substantial nuclear capacity) and Norway (almost entirely hydroelectric capacity). The impact of delays on the NPV in all countries is estimated in Figure 5.
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Figure 5: Impact of different delays on the NPV (USD) of onshore wind projects
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3.3.2 Hydro The hydro projects analysed in this study are in Norway and the United States. As Figure 6 displays for permitting delays, NPV decreases are primarily explained by delayed economic benefits and delayed avoided emissions in the USA. In Norway, delayed economics benefits are the only dominant factor.
Figure 6: NPV (USD) decreases for hydro because of permitting delays - USA and Norway
- Cost of Debt - 0.25% higher Cost of Debt - 1.00% higher Cost of Debt - 0.25% higher Cost of Debt - 1.00% higher (200,000) 50% reg costs 20% reg costs 50% reg costs 20% reg costs (400,000) (600,000) 1 year 5 years 1 year 5 years (800,000) US Norway (1,000,000) (1,200,000) (1,400,000) (1,600,000)
Change in NPV due to timing delay Change in NPV due to additional regulatory costs
- (5,000,000) Cost of Debt - 0.25% higher Cost of Debt - 1.00% higher Cost of Debt - 0.25% higher Cost of Debt - 1.00% higher (10,000,000) 50% reg costs 20% reg costs 50% reg costs 20% reg costs (15,000,000) 1 year 5 years 1 year 5 years (20,000,000) US Norway (25,000,000) (30,000,000) (35,000,000) (40,000,000) (45,000,000)
Change in NPV due to delayed economic benefits Change in NPV due to delayed avoided emissions
This can be partly explained by the fact that Norway has lower carbon intensity (0.002 tons/MWh as opposed to 0.55 tons/MWh), thus less economic benefit is lost from avoided emissions. Additionally, according to our interviews, Norway has shorter capital recovery period compared to the USA (Norway - 15 years for debt, 10 years for equity; USA - 40 years for both debt and equity). This means that there is less capital to be recovered in later years, which translates into a smaller effect on project NPV. Finally, the assumed local content value for USA is 100% (wider and deeper manufacturing base, allowing for complete domestic sourcing of capital goods) and 80% for Norway. The economic impact of the investment is therefore less pronounced in the case of Norway. Figure 7 provides an overview of the impact on the NPV for an individual project across all four types of regulatory delays.
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Figure 7: Impact of different delays on the NPV (USD) of hydro projects
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3.3.3 Solar When analysing the impact of political, site access, environmental and grid connection delays on solar projects in France, Ontario and Australia, it can be noticed in Figure 8 that France is least affected (its NPV is only slightly impacted), whereas Ontario is the most affected. Looking to permitting delays, changes due to delayed economic benefits are equally more critical in Ontario than in the other two countries where these changes are similar. Finally a change in NPV resulting from delays in avoiding
CO2 emissions have significantly greater consequences in Australia than in France and Ontario while changes in NPV due to timing delay in Ontario are 2 to 3 times those in France and Australia.
Figure 8: NPV (USD) decreases for solar because of permitting delays - USA and Norway
This is explained by the fact that Ontario has larger local content (estimated at 80% due to diverse manufacturing base, including PV panel manufacturing) compared to France (50%), which means that solar projects in Ontario have bigger impacts on the economic benefits. Moreover, France has a smaller carbon intensity (0.07 tons/MWh) compared with Ontario (0.18 tons/MWh). The emissions impact in France as a result is smaller than in Ontario. Finally, Australia has the smallest local content (30%), but it is also the country with the highest carbon intensity (0.99 tons/MWh). Figure 9 highlights the impact on NPV due to all four types of regulatory delays assessed.
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Figure 9: Impact of different delays on the NPV (US$D) of solar projects
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3.3.4 Offshore wind Offshore wind projects are impacted similarly in the USA and the UK when faced with political, site access, environmental and grid connection delays as shown in figure 10 (at least for a one year delay period). Both NPV changes due to delayed economic benefits and delayed avoided emissions are comparable when we analyze permitting delays. Estimates indicate that the impact due to additional regulatory costs will be of the same order of magnitude (Figure 10).
Figure 10: NPV (USD) decreases for offshore wind because of permitting delays - USA and UK
The slightly greater impact for the USA, especially with a five-year delay is primarily driven by the higher local content of its capital goods (assumed at 100% due to wide and deep manufacturing base). Moreover, the carbon intensity of the USA is also slightly higher relative to the UK's. Overall the difference is less pronounced due to a higher impact of permanent jobs on the economy for UK.
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Figure 11: Impact of different delays on the NPV (USD) of offshore wind projects
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4 KEY OBSERVATIONS AND CONCLUSIONS
Table 4 summarizes the key regulatory costs and delays identified in each country:
France According to the interviews, permitting is the most important regulatory cost for both technologies. This cost is mainly driven by environmental assessments and other studies. With respect to regulatory delays, the cost model illustrates that:
o For onshore wind, there is limited impact of regulatory delays on NPV compared to the UK, US, Australia and Ontario and a similar impact compared to Norway. o For solar PV, there is less impact of regulatory delays on NPV compared to Australia and Ontario. o The impact for both technologies is limited because of: low carbon intensity electricity (0.07 CO2 tons/MWh), relatively low investment multiplier (0.71) and moderate local content (around 50%). Important insights from the interviews and desk research are that: o Permitting is costly and lengthy. o All wind projects are challenged by opponents leading to delays of several years and high costs because lawyers are involved. o Development steps cannot be carried out in parallel.
According to the interviews: o Permitting is the most important regulatory cost for onshore wind but grid connection costs are also important. o Permitting is the most important regulatory cost for offshore wind. With respect to regulatory delays, the cost model illustrates that: o For onshore wind, the highest impact of regulatory delays on NPV is in the UK from the 6 covered countries. o For offshore wind, there is a comparable impact of regulatory delays on NPV to the USA. o The impact for both technologies is high because of: high carbon intensity electricity (0.51 CO2 tons/MWh), high capital cost (onshore 1,910 USD/kW, offshore 3,261 USD/kW), high investment multiplier (onshore 1.21, offshore 0.96) and high local content (onshore 69%, offshore 50%). Important insights from the interviews and desk research are that: o Permitting and consultation processes are lengthy and costly. o For onshore wind, appealing is lengthy and costly. Projects are often delayed because of contradicting license decisions on different government levels and deadlines for license decisions that are not respected. There is also a significant unavailability of grid capacity (weak transmission grid) before 2020 or even 2025 in some cases.
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Norway According to the interviews, permitting is the most important regulatory cost for both technologies. This cost is mainly driven by environmental assessments. With respect to regulatory delays, the cost model illustrates that: o For onshore wind, there is a limited impact of regulatory delays on NPV in Norway compared to the UK, USA, Australia and Ontario and a similar impact compared to France.
o For hydro, the impact of regulatory delays on NPV is similar to the USA. o The impact for both technologies is rather low because of low carbon intensity electricity (0.002 CO2 tons/MWh). Important insights from the interviews and desk research are that: o Permitting, consultations and appealing are lengthy and costly. o The commitment of the government towards RE is unclear. o The timing of license decisions is highly unpredictable.
United States According to the interviews: o Permitting and grid connection costs/delays are of most importance across technologies. o Regulatory uncertainty can increase costs and add to delays. With respect to regulatory delays, the cost model illustrates that: o For onshore wind, the impact of regulatory delays is on par with Australia and UK, and lower than in France, Norway and Ontario. o For offshore wind, the impact of regulatory delays is somewhat lower than in UK. o For Hydro, the impact of regulatory delays is substantially higher than in Norway. o The impact of regulatory delays is relatively high compared to other countries because of: high carbon content of the electricity sector (0.55 CO2 tons/MWh) and high local content potential. Important insights from the interviews and desk research are that: o Attention is required to streamline permitting processes. o Developers sometimes have to pay a significant amount in fees to stay in queue for grid connection. o Developers may have to pay higher costs if other developers withdraw grid applications.
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Australia According to the interviews: o Policy uncertainty (changes in RE technology, removal of carbon price etc.) has been a significant source of delay in recent years. With respect to regulatory delays, the cost model illustrates that: o For onshore wind, the impact of regulatory delays is on par with USA and UK and higher than in France, Norway and Ontario. o For Solar PV, the impact of regulatory delays is less than in Ontario, but higher than in France. o Both technologies have relatively high impact because of: high carbon intensity (0.99 CO2 ton/MWh). Important insights from the interviews and desk research are that: o Differing state based regulatory requirements can lead to additional costs – promotion of standard or national requirements may assist. o Difficulties associated with key exports, i.e. coal (and therefore access to cheaper fossil fuels) will continue.
Canada According to the interviews: (Ontario) o Permitting is one of the most important regulatory costs/delays across both technologies. o Grid connection delays and regulatory uncertainty can also be additional sources for delay. With respect to regulatory delays, the cost model illustrates that: o For solar PV, the impact of regulatory delays is highest when compared with Australia and France. o For onshore wind, the impact of regulatory delays is higher than in France and Norway, but slightly lower than in USA and Australia. Important insights from the interviews and desk research are that: o Delays in permitting and connection process key cause of concern for developers. o Provincial targets for procurement of new renewable generation key to all new developments in the province. Regulatory uncertainty, and changes in key programs such as FIT have resulted in regulatory delays and costs in previous years. Table 4: expected evolutions in different jurisdictions, points of attention and potential for economic benefits
Our analysis of the different countries illustrates that regulatory barriers are very different between countries and technologies and the costs and timing for developments are highly project-specific.
However, in the interviews we observed that regulatory costs and delays with respect to permitting, primarily driven by the environmental impact assessment, result in a greater impact on the costs of projects relative to other forms of delays. Delays can result in costs ranging from USD 100,000-200,000
Page 39 of 124 DOCUMENTING THE COST OF REGULATORY DELAYS, RE-DELAYS, March 2016 for solar PV, USD 300,000-400,000 for onshore wind and hydro, and up to several million USD for offshore wind. There are several critical factors which can explain the impact of permitting delays on the timing of a project and its costs. Firstly, developers note duplication or redundancies in the approval processes and disclosure requirements with several processes yet to be streamlined. Also, sometimes there are conflicting decisions at various government levels or departments. Thirdly, projects are delayed as a result of no clear timeframes for completion of key permitting process, as well as extensive, and costly, appeals processes. This can result in project being delayed for several years.
The interviews furthermore demonstrated that uncertainty surrounding grid access, as well as grid connection costs, can result in lengthy delays and costs, in particular for solar PV and onshore wind developments. Regulatory costs can range up to USD 100,000 for solar PV and up to USD 300,000 for onshore wind. They sometimes have to be paid upfront years before a project is to be developed and additional costs can arise when the queue changes due to withdrawals and cancellations by other projects, necessitating reliability and stability reinforcements.
In addition to issues regarding permitting and grid connection, we noted the impact associated with a lack of transparency and clarity within existing regulations, or in the development of new policy/regulation. Common issues discussed include a lack of commitment to RE (for example in setting or changing RE targets), competing government objectives, and lengthy consultation processes.
Furthermore, cost ranges are more significant for large-scale projects, such as offshore wind and hydro projects. Interviewees highlighted specific development costs can potentially vary in a significant range of between ten thousands USD and millions of USD, attributable to project-specific concerns. This is one key reason for developing a model that is flexible in nature, allowing users to assess impacts with different project-specific assumptions. Also, delay ranges are not necessarily smaller for smaller-sized projects. For example, although permitting usually takes more time for offshore wind projects, these projects usually (but not always) do not go through long appeals processes and total delays can potentially be lower than those for onshore wind projects.
Another interesting observation is that the macroeconomic impacts associated with delays in investment are often more significant than the developer costs of regulatory delays, primarily due to the significant impact of greenhouse gases on the economy. In this framework, the macroeconomic impact is dependent on local contents of capital goods, level of capital costs, economic multipliers applicable to investment, carbon intensity of electric sectors, level of pay and applicable multipliers for income. A combination of these factors explains why, according to the interviews, the largest NPV impact of delays will be in the UK for onshore wind (combination of high carbon intensity, high CAPEX and high local content), in the USA for hydro (carbon intensity of the electricity sector in USA is almost 300 times carbon intensity in Norway) and offshore wind (local content offshore wind is higher in the USA than in the UK) and in Ontario for solar PV (combination of higher local content and carbon intensity than the other countries).
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Finally, in the interview process, we observed that while it is easier to gain insights into project development in some renewable energy sectors (such as solar PV and onshore wind), it can be significantly more challenging to gain similar level of insights for offshore wind projects.
Below we identified 7 measures that can be considered by policy-makers to better encourage renewable project development, and reduce delays. Some of these measures have already been highlighted in the past but have not always led to significant reduction in delays. Therefore a more provocative approach to this may have an impact, and as such reduce the costs both on micro- as on macro-economic level:
Set clear time lines for decisions regarding permitting and grid access approvals. Regulation should be as independent as possible and this can be realized by investing in cross-national regimes (for example, integrated EU-wide regimes). This would be particularly beneficial in Norway since the country already has a joint subsidy scheme with Sweden. Increased accountability for decision making process at the regulatory/governmental level. Currently, in many cases, if a government or regulatory agency does not make a decision after a pre-determined period on a project, it is likely assessed unfavorably. It will be prudent for decision making authorities to be held accountable for delays in decisions within their control. The accountability can come in the form of pre-determined fines associated with not achieving set milestones. Provide clarity with respect to application requirements upfront and avoid confusing legislation surrounding permitting processes. Regulators should focus on the harmonization of local (and national) procedures, create simpler rules for smaller-scale projects and pre- define geographical areas for new projects. Streamline the regulatory processes. This can be achieved by creating a one stop shop with simplified rules for applications. Responsibilities should be defined upfront including responsible actors paying compensations if applicable. There is a particular need for clear grid development plans and compensation if infrastructure is not ready on time. Link the incentive such as FIT to delay. More delays could potentially lead to a higher incentive provided to the project developer making the government more accountable. Define clear procedures and cost impact assessment of appeal processes. Provision of support for specific renewable energy technologies or projects which create potential positive externalities in the form of indirect investments, indirect jobs and value chain effects. In this framework, governments should focus on available competences and try to develop economies of scale with other regions, countries and industries. Inform the public about benefits and risks of RE and encourage consultative mechanisms to share concerns. Public acceptance towards these projects, often a key bottleneck, can be improved by informing the public about the benefits and risks of renewable energy projects. Acceptance will also be higher if locals can share concerns in a cooperative and consultative environment.
These measures are required for evolving towards a more mature and stable renewable industry.
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5 ANNEX A: COUNTRY CAS E STUDIES
5 . 1 INTRODUCTION In August 2015, 3E N.V. (3E) and London Economics International LLC (LEI) were commissioned to undertake a research project for the IEA Renewable Energy Technology Development (IEA-RETD) to investigate the cost of regulatory delays for renewable energy projects. The overall objective of the research is to better understand and quantify the impact of regulatory delays and uncertainty to ultimately inform regulatory reform initiatives and promote greater efficiency in the global market for renewable energy deployment.
The project involves quantifying the economic and financial costs (net positive externalities) of regulatory delays to renewable energy players and to the broader economy in a number of different jurisdictions throughout North America, Europe and Asia. We are emphasizing primary sources through 37 interviews with developers because this allows us to gain new market insights.
Two categories of regulatory delays and uncertainties are covered in the study:
Delays related to renewable energy policy decisions at the national, regional or local level. These delays create an uncertain climate for investors who may, as a result, hesitate to move forward with project investments. The target audience for these delays are local, regional and national governments. Delays related to administration and regulation. These include delays in disclosing or implementing regulations related to the renewable energy project development life cycle, such as building consents, environmental assessments and grid connection. The most affected by these delays are project developers and local industry players in the renewable energy chain; at the same time, delays may be caused by lengthy and in some cases, non-transparent administrative processes at various government/regulatory levels, in addition to appeals processes initiated by developers.
This report provides background information on six countries selected for study: France, Canada (Ontario), Australia, Norway, the United Kingdom (UK) and the United States of America (USA). Section 2 details our rationale for the selection of the countries covered in the study. Each of the case studies will be structured under the following topics:
State of the economy. Labour market. Capital markets and access to project financing. Preparedness of the regulatory environment for renewable energy projects. Renewable energy technology development and insights from developers related to market and regulatory issues.
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This information will be used to provide valuable context on the selected countries to better determine the strengths and weaknesses of their regulatory frameworks. Regulations and policies can be improved in the future on the basis of the results achieved in this study.
5 . 2 COUNTRY SELECTION The jurisdictions for this study have been discussed jointly between the IEA-RETD and 3E-LEI during the project kick-off meeting and in subsequent email correspondence. They have been selected to give a broad cross-section of jurisdictions which provide for different contextual characteristics including levels of renewable energy penetration and adoption of differing policies and regulations related to renewable development.
Six countries have been selected for this study, France, Canada (Ontario), Australia, Norway, the United Kingdom (UK) and the United States of America (USA), on the basis of geographic representation, country interest with respect to the project objectives and practical considerations. In addition to identifying specific countries to be covered, 3E-LEI has focused its studies on selecting generation technologies widely adopted in each of the countries including onshore and offshore wind, conventional hydro and solar PV.
Figure 12: Country and technology selection
5.2.1 Geographic Representation Four out of the six countries selected are IEA-RETD member countries. Out of the six selected countries, three continents, North America, Europe and Asia-Pacific are represented to reflect the
Page 43 of 124 DOCUMENTING THE COST OF REGULATORY DELAYS, RE-DELAYS, March 2016 continental spread of the IEA-RETD member countries. In Europe, a diversity of regions, the British, Isles, Central Western Europe and Scandinavia, are represented.
5.2.2 Country Interest Market size, market maturity and resource diversity were key factors considered in the selection of countries relevant and interesting for study. For example, according to REN21’s latest Renewable Energy Global Status report, USA and Canada are among the world’s top five countries for installed renewable power (including hydro).17 Further, 3E-LEI’s collective knowledge of known examples of regulatory/policy delays or regulatory reforms was another consideration. For example, UK and France have recently implemented measures to reduce regulatory delay for renewable energy development, to varying degrees of success. Finally, as four technologies are to be analysed in this project, it was important to select a group of countries with high resource share or interesting project examples of onshore wind, offshore wind, hydro and solar PV development.
5.2.3 New insights through interviews and Practical Considerations One of the main advantages of this study is that we are emphasising primary sources through interviews with project developers instead of secondary sources. This allows us to gain new insights from different project developers. An example of these surveys for France can be found in annex 1. However, the consortium’s ability to deliver in-depth and reliable information within the project schedule and budget is hinged on the countries selected for study. Pragmatic considerations that influenced our selection included 3E-LEI’s past project experience, existing local networks, office locations, language proficiency, access to secondary sources of data, and consortium and PSG country expertise. Furthermore, insights from developers are similar for different technologies in some countries whereas regulatory delays and costs appear to be technology-specific in other countries. Therefore, we include a general section on insights from developers for some countries and subsections for different technologies for other countries.
5.2.4 Data validation While 3E-LEI were able to gather significant data principally from developers, we recognise data validation is crucial to come up with sound results. Therefore, 3E-LEI’s experts have reviewed figures for the different countries. Also, as much data as possible was reviewed by the French Wind Energy Association (FEE) for France, by the UK’s leading Renewable Energy Trade Association (RenewableUK) for the United Kingdom (UK) and by the Norwegian Wind Energy Association (NORWEA) for Norway. In addition, the Canadian Solar Industries Association (CanSIA) assisted in gathering data from its members, the Canadian Wind Energy Association (CanWEA) provided some interesting insights on delays related to Renewable Energy Approval (REA) processes, and 3E-LEI also interviewed the USA Solar Energy Industries Association (SEIA). Data was further validated by secondary sources such as publications from the USA Energy Information Agency (EIA), National Renewable Energy laboratory (NREL) and third party databases (SNL, ABB Velocity Suite) among others.
17 REN21, Renewables 2015 Global Status Report, 2015, Available at: http://www.ren21.net/Portals/0/documents/e- paper/GSR2015/index.html
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5 . 3 FRANCE
5.3.1 State of the Economy After three years of stagnant activity, the European Commission predicts a modest economic recovery for France in 2015, gaining traction in 2016 on the backs of private consumption.18 This view is supported by the OECD. Lower energy prices, improving financial conditions, slowing fiscal consolidation and a pro-competitive reform agenda should support an increase in consumption.19
However, after a strong showing in the first quarter of 2015, the economy stagnated in the second quarter. As a result, the Economist Intelligence Unit is looking to revise their 2015 real GDP forecast of 1.1% to around 0.9%.20
Source: The Economist Intelligence Unit
Overall debt levels in France continue to be high and rising. In 2014, the general government deficit and debt reached 4.3% and 95.2% of GDP respectively.21 High debt coupled with low growth and low inflation increases the country’s vulnerability to external economic events. To address the public deficit, the government is pursuing structural reforms to restrain spending over 2015-16.22
Investments contracted in 2014, notably in the manufacturing and equipment sector.23 The low pace of investment erodes France’s competitive position. However, a moderate expansion of capital formation in 2015-16 is expected, boosted by ongoing structural reforms by the government that are focused on growth.24
Export market shares are expected to decline in the long run. Over the past five years, France has lost 13% of its export market shares. The manufacturing industry has suffered export losses across all
18 European Commission, European Economy: Macroeconomic Imbalances Country Report – France 2015, 2015, Available at: http://ec.europa.eu/economy_finance/publications/occasional_paper/2015/pdf/ocp217_en.pdf
19 OECD, France – Economic Forecast Summary – June 2015, 2015, Available at: http://www.oecd.org/economy/france-economic-forecast- summary.htm
20 The Economist Intelligence Unit, France, 2015, Available at: http://country.eiu.com/france
21 European Commission, European Economy: Macroeconomic Imbalances Country Report – France 2015, 2015, Available: http://ec.europa.eu/economy_finance/publications/occasional_paper/2015/pdf/ocp217_en.pdf
22 OECD, France – Economic Forecast Summary – June 2015, 2015, Available at: http://www.oecd.org/economy/france-economic-forecast- summary.htm
23 Ibid
24 Ibid
Page 45 of 124 DOCUMENTING THE COST OF REGULATORY DELAYS, RE-DELAYS, March 2016 sectors, except for the high-tech sector. One reason behind this decline is that French export levels appear to be sensitive to cost competition.25 In the renewable energy sector for example, manufacturing and equipment jobs are steadily shifting to more cost competitive Asian markets. Labour costs are high in France which impedes the country’s businesses from competing effectively with international alternatives.
Depreciation of the euro and other government reforms will not be sufficient to reverse export losses, as volumes are mainly affected by weak aggregate demand not the price development of the euro. France has strong financial and trade linkages with other Member States. Negative economic developments in France could adversely affect other European trading partners.
Economic Indices Figure (Year)
Population 66.25 million (2014)
GDP USD 2,829.19 billion (2014)
GDP per Capita USD 35,669.59 (2014)
Key industries Telecommunications, aerospace and defense, ship building, pharmaceuticals, construction and civil engineering, chemicals, textiles, automobile production
Table 4: Key economic facts on France
Source: European Commission
5.3.2 Labour Market The active population of France aged fifteen or over is estimated at 28.6 million. By 2025, it could grow to reach 30 million. In the European Union, the rate of employment for persons aged 15 to 64 years was 64.1% in 2012. France is on a par with the European employment average, behind the Netherlands, Sweden, Germany, Denmark and Austria, which have rates of over 70%.26
25 OECD, France: restoring competitiveness, November 2013, Available at: http://www.oecd-ilibrary.org/economics/france-restoring- competitiveness_9789264207967-en
26 European Commission, Labour Market Information – France at the National Level, 2015, Available at: https://ec.europa.eu/eures/main.jsp?countryId=FR&acro=lmi&showRegion=true&lang=en&mode=text®ionId=FR8&nuts2Code=FR23& nuts3Code=null&catId=2647
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Design engineers, executives and IT R&D staff are occupations in high demand and are among the country’s top ten most difficult roles to fill.27 Employers consider recruitment in the manufacturing industries and the trade and construction sector to be particularly difficult, due to the shortage of applicants or unsuitable profiles. Employers describe training for employees rather than external recruitment as the best way to remedy labour shortage in these highly skilled roles.
Renewable energy jobs are starting to shift away from Europe and North America to Asia.28 The latest 2014 employment figures from the International Renewable Energy Agency (IRENA) highlight slight contractions in established markets across the European Union, including France.29 Renewable energy employment in France fell by 4% from 184,000 in 2012 to 176,200 in 2013 but France still leads Europe in biomass/biofuels and geothermal employment. Globally, France continues to be one of the top ten countries in the world in terms of overall renewable energy employment.
The French national government is trying to fuel a rebound in the renewable energy industry by facilitating the framework conditions for the development and realisation of new projects. French Energy and Environment Minister, Ségolène Royal, has recently defined renewable energy as one of six government priorities, which includes the planned creation of one hundred thousand jobs in the green growth sector over the next three years from 2015 to 2018. During that time, an estimated 10 billion EUR of state aid will be invested in the green growth sector, in the form of tax credits, zero- interest loans or household/electric vehicle bonuses.30
5.3.3 Capital Markets and Access to Project Financing Current state of project financing
From late 2010 to early 2014, project financing for renewables in France slowed down due to uncertainty with the feed-in tariff (FIT) program.31 This uncertainty was lifted at the beginning of July 2014 with the signing of a new by-law by the Minister of Sustainable Development and Energy.32
27 European Commission, EURES: Short overview of the French labour market, 2014, Available at: https://ec.europa.eu/eures/printLMIText.jsp?lmiLang=en®ionId=FR0&catId=2647
28 European Renewable Energies Federation, Overview concerning the contribution of renewable energies towards employment and growth within the EU, 2014, Available at: http://www.eref-europe.org/wp-content/uploads/EREF-overview-RES-jobs-20142.pdf
29 IRENA, Renewable Energy and Jobs – Annual Review 2015, 2015, Available at: http://www.irena.org/DocumentDownloads/Publications/IRENA_RE_Jobs_Annual_Review_2015.pdf
30 Bloomberg New Energy Finance, Country Profile – France, 2015
31 Norton Rose Fulbright, European renewable energy incentive guide – France, 2013, Available at: http://www.nortonrosefulbright.com/knowledge/publications/66831/european-renewable-energy-incentive-guide-france
32 EurObserv’ER, Country Policy Profile – France, 2014, Available at: http://www.eurobserv-er.org/pdf/res-policy/EurObservER-RES-Policy- Report-Country-Profile-2014-France.pdf
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The Minister also recently announced the signing of two hundred “Positive Energy Territory” agreements with local governments. These local governments will be granted between 0.5 and 2 million EUR to support their clean energy and sustainability initiatives.33
According to Bloomberg New Energy Finance, France ranked number eight in the world in 2014 for volumes of renewable energy transactions totalling USD 8,236 million.34 The top ten renewable energy lenders investing in France were HSH Finanzfonds AoeR, Société Générale, BNP Paribas Fortis, Crédit Agricole Groupe, Natixis, Dexia, Norddeutsche Landesbank Girozentrale, Deutsche Bank, European Investment Bank and UniCredit SpA.
In 2014, it was announced that Eiffage will build Europe’s largest solar complex in France for developer Neon SAS at a cost of more than EUR 360 million.35 According to Bloomberg, the solar complex at Cestas near Bordeaux is double the size of Europe’s largest photovoltaic plant in operation.36 It will generate more than 350 GWh of electricity annually. Neoen has secured almost EUR 310 million in project finance from banks led by Société Générale SA, now syndicating the debt with other lenders. The term of the loan is 18 years. This is unusually long and reflects a recent trend of banks moving away from short term loans.
Supra-national and national banks
Europe is home to a number of supra-national financial institutions such as the European Investment Bank and the European Bank for Reconstruction and Development.37 Supporting European-wide energy policy objectives, these financial institutions help enable substantial capital to support large renewable energy projects. These banks may also provide loan guarantees and channel on-lending funds from other organisations to support the renewable energy sector. 38
Commercial banks and investors
French commercial banks have a long history of providing dedicated capital support for renewable energy projects, serving as a model for other international jurisdictions.39 Some French banks have
33 Ministère de l'Écologie du Développement Durable et de l'Énergie, Un territoire à énergie positive, qu’est ce que c’est?, 2015, Available: http://www.developpement-durable.gouv.fr/Un-territoire-a-energie-positive.html
34 Bloomberg New Energy Finance, Country Profile – France, 2015
35 NEOEN, NEOEN Announces the Construction of Europe’s Largest Photovoltaic Solar Park”, 2014, Available at: http://www.neoen.fr/wp- content/uploads/2014/11/Neoen-Cestas-solar-park-1106.pdf
36 Bloomberg New Energy Finance, Country Profile – France, 2015
37 AFME Finance for Europe, Supranational Institutions, 2015, Available at: http://www.investinginbondseurope.org/Pages/LearnAboutBonds.aspx?id=6292
38 Deutsche Bank, Green infrastructure and business financing and advising, 2015, Available at: https://www.db.com/cr/en/concrete- sustainable-large-scale-projects.htm
39 E3G, European Perspectives on the Challenges of Financing Low Carbon Investment: France, 2011, Available at: http://www.e3g.org/docs/E3G_European_Perspectives_on_the_Challenges_of_Financing_Low_Carbon_Investment_France.pdf
Page 48 of 124 DOCUMENTING THE COST OF REGULATORY DELAYS, RE-DELAYS, March 2016 dedicated green investment divisions that support internal corporate social responsibility agendas. Many French banks also offer assessment services, technical expertise, industry connections and other supporting services to assist their renewable sector clients.
Tax exemptions, tax credits and low interest loans
France recently implemented a “Sustainable Development Tax Credit” similar to the system in place in the Netherlands, where individuals can reduce their tax liability by claiming part of the cost of renewable energy production equipment. For corporations though, there is no specific favourable tax treatment. On the contrary, the fixed tax IFER (Imposition Forfaitaire sur les Entreprises de Réseaux) was doubled for solar and wind, whereas it stayed the same for the other sources of energy such as hydro, gas and nuclear. This had a negative impact on several stand-alone IPPs. France however provides low interest loans to support the purchase of renewable energy infrastructure.40
5.3.4 Preparedness of the Regulatory Environment for Renewable Energy Projects Electricity Supply Mix and Renewable Targets
France is the European Union’s second largest producer and consumer of renewable energy.41 In 2013, power generation from renewable sources represented 17.6% of France’s electricity production. The share of renewables is expected to grow significantly in the following years under François Hollande’s socialist government. Under the provisions of Directive 2009/28/EU of 23 April 2009 (the Renewable Energy Directive), 23% of France’s final energy consumption must be generated from renewables by 2020.42 The current government has also committed to reducing the nuclear share in the electricity mix from 75% to 50% by 2025, on the basis that consumption will increase.
40 European Commission, Energy efficiency action plan for France – 2014, 2014, Available at: https://ec.europa.eu/energy/sites/ener/files/documents/2014_neeap_en_france.pdf
41 European Commission, Renewable Energy Statistics, 2015, Available at: http://ec.europa.eu/eurostat/statistics- explained/index.php/Renewable_energy_statistics
42 Norton Rose Fulbright, European renewable energy incentive guide – France, 2013, Available at: http://www.nortonrosefulbright.com/knowledge/publications/66831/european-renewable-energy-incentive-guide-france
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Figure 13: Supply mix in France (2014)
Source: Bloomberg New Energy Finance
The reduced share of nuclear power will open opportunities for other generation sources. The introduction of a capacity market, expected sometime in 2016/17, will support the development of more flexible resources; this would complement plans for increase renewable generation.
Renewable Support Schemes for onshore wind and ground-mounted solar PV
We are considering both onshore wind and ground-mounted solar PV projects. Electricity from renewable energy sources is promoted through a feed-in tariff (FIT) system (only surviving for onshore wind as to date) whereas tax benefits and a tendering system are available for large renewable energy projects.43
Wind is supported by a strong FIT scheme that has been in place since 2008 and was re-instated in 2014. The 2008 tariff was challenged by opponents, which forced the government to cancel and resubmit the tariff proposal to the European Union for approval. 44
Under the 2014 re-instated FIT program, onshore wind PPA (Power Purchase Agreement) contracts are entered for fifteen years with Électricité de France (EDF), at a base rate of 8.2 c EUR/kWh for the first ten years, then between 2.8 and 8.2 c EUR/kWh for the remaining five years depending on actual production level. Production level is calculated by averaging the full load hours of the previous five years of the plant’s operation.45 The 8.2 c EUR/kWh tariff is associated to the year 2008. Every year, on the first of January and regardless of the PPA application date, the reference tariff is updated according to a 2% decrease and a K coefficient that takes into account economic indices.
43 Norton Rose Fulbright, European renewable energy incentive guide – France, 2013, Available at: http://www.nortonrosefulbright.com/knowledge/publications/66831/european-renewable-energy-incentive-guide-france
44 HSH Nord Bank, Sector Study – Wind Energy, 2014
45 Ibid
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With respect to solar PV, ground-mounted solar PV projects larger than 250 kW receive support through tenders for 20 years while feed-in tariffs are paid to other ground mounted installations in France for 15 years. The first category is the focus of this study.46
According to announcements made by public authorities, a new support mechanism is expected to come into force by the end of 2016 or beginning of 2017, in order to bring the French subsidy scheme in alignment with recent EU guidelines on state aid for energy.47 The main objective of the new support system is to prevent the over- and underproduction of capacity in France, and to better reflect cost evolutions and market price convergence for mature technologies, such as onshore wind and solar PV. Three market-based financing models have been suggested, and are under discussion today:
Ex-post premium. Renewable energy producers must sell their energy on the wholesale market and balance their production. A premium is calculated retrospectively to compensate for the difference between the target price (strike price) and a market reference price. Ex-ante premium. In this financing mechanism, a bonus (in EUR/MWh) is fixed ex-ante. The renewable energy producer sells the generated electricity on the market. The premium is added on top of the market revenue. Quotas (Green Certificates). The producer sells both its electricity on the electricity market as any other producer and on the green certificates market. The market for green certificates is "created" by quotas of green certificates bought by electricity suppliers. The green certificate price is limited upwards by the penalty of non-compliance with quotas. A move away from a FIT support scheme will expose project developer to price risks in the wholesale electricity markets.
Consultations took place over the year between government and professionals. A draft decree has been in consultation and auditions were held at the Higher Energy Council (Le Conseil Supérieur de l'Energie (CSE) on 4 November 2015. The model retained is an ex-post subsidy in the form of a CfD (Contract for Difference) with a formula integrating capacity certificates and no guarantee of origin valued at zero. The formula is complex and relies on one-month to one-year market reference price. FEE (France Energie Eolienne) supported a daily price to avoid large spread deviations between target price and actual market price. Wind will nevertheless retain the FIT at least until 12 August 2018 according to the minister who indicated that changes will start being discussed then.
Administrative Processes
Administrative processes are long in France. Project developers face a large number of technical, administrative and environmental requirements. Due to several regimes co-existing, such as the requirement for a building permit, the authorisation for an installation classified for environmental
46 Bloomberg New Energy Finance, Country Profile – France, 2015
France PV Tenders – Installations>250 kW, Bloomberg New Energy Finance
Bloomberg New Energy Finance, Country Profile – France, 2015
47 European Commission, State aid for environmental protection and energy, 2014, Available at: http://ec.europa.eu/competition/sectors/energy/legislation_en.html
Page 51 of 124 DOCUMENTING THE COST OF REGULATORY DELAYS, RE-DELAYS, March 2016 protection (installation classée pour la protection de l'environnement (ICPE)) and now the newly introduced regime enabling developers to apply only for a unique authorisation as further explained hereunder, developers often face confusion. Local authorities are however accustomed to processing applications for renewable projects.48 As part of the process, a large number of approvals are required before submitting the building permit.49 Building permits are signed off by the Prefect, but are often subject to political games. In France, permits are frequently challenged by opponents who are well- organised and experienced. For wind projects, we know from our interviews with developers that the appeal process can add another two to eight years to the usual time required to prepare and process the project application. In addition, each administrative decision (initial approval, any future change, for example) is subject to court challenge multiplying delay.
Some changes to the administrative processes have been implemented in recent years, including the cancellation of the Zone de Développement de l'éolien (ZDE).50 This has reduced redundancies in the permitting process and has narrowed opportunities for renewable opponents to appeal development. The French government is also investigating opportunities to simplify administrative processes through the introduction of a single permit, which groups environmental, social and site access permission into a single building permit (“Autorisation unique”). This process is being applied in the whole country since the Energy Transition Law was voted on 17 August 2015.
Notable clauses in the draft included facilitating financing of energy cooperatives and making grid access compulsory within eighteen months of filing an application.51 One of the main issues was the introduction of the European guidelines into the French legislation.
Grid Access and Systems
The Ministry of Ecology, Sustainable Development and Energy plays an important role in the organisation and development of the electric system in France. It defines long term system planning in terms of investment in production capacity. The Direction Générale de l’Energie et du Climat (DGEC) within the Ministry is responsible for approving the development and expansion of the public transmission network.52 The entity decides how to distribute production capacity according to the
48 CDC Climate Research, The Role of Sub-National Authorities in Public Support for Renewable Energies – Examples in Europe and France, Available at: http://www.cdcclimat.com/IMG/pdf/11-11-02_climate_report_30_- _the_role_of_regional_authorities_in_public_support_for_re.pdf
49 Thomas Reuters, Environmental law and practice in France: Overview, 2015, Available at: http://uk.practicallaw.com/7-503- 4572#a932178
50 Norton Rose Fulbright, European renewable energy incentive guide – France, 2013, Available at: http://www.nortonrosefulbright.com/knowledge/publications/66831/european-renewable-energy-incentive-guide-france
51 Ministère de l'Écologie du Développement Durable et de l'Énergie, The Energy Transition: A Users Guide., 2014, Available at: http://www.developpement-durable.gouv.fr/IMG/pdf/14123-2_plaq-NMTE-parlementaires_GB_DEF_Light-2.pdf
52 Ministère de l'Écologie du Développement Durable et de l'Énergie, Directorate General for Energy and Climate, Available at: http://www.developpement-durable.gouv.fr/IMG/pdf/Plaquette_DGEC_GB.pdf
Page 52 of 124 DOCUMENTING THE COST OF REGULATORY DELAYS, RE-DELAYS, March 2016 following criteria: primary energy, technical development and physical area. Energy production is controlled and must correspond to development plans imposed by the Ministry.
The Energy Regulatory Commission (CRE), established in 2000, is the independent administrative authority responsible for ensuring the proper functioning of the electricity and gas markets in France. According to a law established in 7 December 2006, the CRE is also responsible for ensuring that grid access conditions do not hinder market competition. With respect to renewable project connection, the CRE sets the grid access fees and regulates system operator activities.53
The French electricity network is well developed and divided into two networks. Réseau de Transport d'Électricité (RTE) manages the transmission network (HTB network), rated between 63,000 to 400,000 volts for connection of projects 12 MW or greater. Électricité Réseau Distribution France (ERDF) manages the distribution network (HTA network) rated at 63,000 Volts or under for projects less than 12 MW in size.54
The grid connection cost is generally more expensive in regions with high connection demand (i.e., areas with high resource potential). For wind projects, this would be in the northern, Picardy, Brittany and southern regions of France. If grid reinforcement is needed to connect a project, developers are required to bear the additional costs. In other regions such as Aquitaine and Burgundy, grid connection costs are lower. In this context, the regional schemes for the grid connection of renewable energy (schémas régionaux de raccordement aux réseaux des énergies renouvelables (SRRREnR)) – 5 year connection plans – are being implemented in each region, some without renewables. These plans were envisaged as planning tools for ERDF to schedule grid reinforcement and incorporate a quote part by which reinforcement costs, as calculated by ERDF, are charged to developers on a per MW basis.
5.3.5 Large-scale Onshore Wind Development France has one of the highest potentials for generating electricity from wind in the EU, with a coastline of 5,500 km. If the objectives set forth by the French government (19 to 25 GW of onshore wind, 6 GW of offshore wind) are met by 2020, wind power will represent 10% of the national electric production.55 After a quiet year in 2013, wind installation is picking up, potentially rising to 2011 levels on the backs of a reinstated FIT program and ahead of program changes expected in 2016/17. France will not comply with its own 2020 objectives unless +/- 2,000MW are to be put online each year until 2020.
Different initiatives to simplify existing regulation relating to onshore wind were implemented in 2013. Proponents now undergo one instead of two approval procedures. Another step towards simplification is the replacement of local plans with national plans. The government has also abolished the rule that wind farms must constitute at least five turbines to be eligible for subsidies.
53 Commission de régulation de l'énergie, Les missions de la CRE, 2015, Available at: http://www.cre.fr/presentation/missions
54 EDF, Transmission and Distribution in France, 2015, Available at: https://www.edf.fr/en/the-edf-group/world-s-largest-power- company/activities/transmission-and-distribution
55 Prime Capital, European Framework for Investments in Renewable Energy, 2015
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5.3.6 Large-scale Solar PV Development (Ground mounted installations) At the end of 2014, France represented the fourth largest solar PV market in Europe after Germany, Italy and Spain, achieving over 5.6 GW of installed capacity.56 Earlier in the year, the French energy minister announced that France would be doubling its target for annual photovoltaic energy growth from 500 MW to 1 GW and implementing reforms to its existing FIT scheme. The FIT scheme was simplified to cover three categories instead of five and reduced price digression for rooftop installations from 10% to 5%.57
In 2013, a new tender process for 400 MW of large 250 kW solar installations was initiated. In August 2015, the French energy ministry announced that it would authorise a further 400 MW, based on high demand and competitive prices emerging from the recent June bid offers. Almost 2,000 MW of ground capacity was offered at prices competitive with onshore wind for the first time ever. 58
5.3.7 Insights from developers An important insight is that both solar PV and onshore wind development are often slowed down because the application for permits, participation in tenders and the application for the grid connection have to be carried out sequentially and cannot be done in parallel. Another insight is that it can be difficult to estimate the cost of the grid connection at the start of the project because developers have to pay for grid reinforcements if these are necessary. Furthermore, in France, political changes and regulatory issues can significantly modify project development schedules. For example, the probability that a project will be carried out can significantly decrease when the municipal council is replaced.
Insights for large Onshore Wind Development
A first important insight is that opponents of onshore wind projects are extremely well organised in France. Nowadays, a large proportion of the projects are challenged which leads to project delays between 2 and 8 years. During an appeal process, investors and lenders are not willing to invest in a project (they normally invest when the developer acquires the grid connection agreement) and conditions for financing, if the project is not cancelled, can be very different at the end of this period. Also, sometimes the type of turbines that was used to apply for the initial permit does not exist anymore at the end of an appeal process. In these cases, developers will have to apply for a modified permit, which can re-open the court challenge for the modified permit. An interesting evolution in this context is that the French government recently introduced one single permit to replace several permits. Some developers expect this to lead to shorter delays because opponents can only challenge one application while others argue that this will not change anything since the same documents will be required and opponents can challenge several documents within the single application. This
56 EurObserv’ER, Country Policy Profile – France, 2014, Available at: http://www.eurobserv-er.org/pdf/res-policy/EurObservER-RES-Policy- Report-Country-Profile-2014-France.pdf
57 Prime Capital, European Framework for Investments in Renewable Energy, 2015
58 Reuters, France doubles size of solar tender after strong bidding, 2015, Available at: http://uk.reuters.com/article/2015/08/20/france- solar-idUKL5N10V3V720150820
Page 54 of 124 DOCUMENTING THE COST OF REGULATORY DELAYS, RE-DELAYS, March 2016 potential advantage is largely counterbalanced by the fact that radar operators (military, meteorological and civil aviation) must give a positive response to project requests. Military aviation froze a large portion of the French territory and tends not to answer to requests for advice or to give negative advice.
As already mentioned, the grid connection request can only be requested once the permits have been granted. Once the connection has been completed the wind farm must be operational within 2 years. Once the tariff to be used in the PPA is requested, which can be done at any time, the developer only has three years to be in line. If connection occurs after the three-year period, the 15-year term of the PPA is reduced proportionately to the delay. This is an issue in the case of an appeal process of several years.
Furthermore, the regulatory framework with regards to onshore wind has changed several times since 2007. Before 2007, developers could only apply for the FIT if the installed capacity was smaller than 12 MW. Between 2007 and 2013, the government identified specific development areas for onshore wind. Since 2013, there is no threshold anymore to apply for the FIT nor specific development areas (ZDE). All these changes have an important impact on the rate of development and the size of the projects and can notably delay commissioning of the project. Several developers mentioned development cycles of about 10 to 12 years. In such a case, it can for example be very difficult to renew lease agreements with land owners.
Insights for Large-Scale Solar PV Development (Ground-mounted installations)
In contrast with onshore wind energy, solar developers state that appeals with respect to solar PV do not occur very often (one developer mentioned in 10% of the cases while others mentioned that it never happens) and that the appeal process will be notably shorter than for onshore wind projects.
Also, negotiating lease agreements for very large solar PV projects is increasingly difficult. Sometimes, they have to be negotiated with a high number of land owners and this can take up to several years.
Political changes have also modified project development schedules and cancelled solar PV projects in recent years. One of the main drivers to stop projects has been the strong decreases in FITs. However, this is becoming less relevant since developers of large-scale projects are now participating in tenders for large-scale solar PV projects.
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5 . 4 AUSTRALIA
5.4.1 State of the Economy The Australian economy grew at a moderate pace in the past year. Following strong growth in the 1st quarter of 2015 (0.9%), growth slowed in the 2nd quarter (0.2%) due to some reversal of the substantial rise in exports in early 2015. According to the Reserve Bank of Australia, overall growth for the Australian economy is expected to reach over 3% by 2017. In the past five years, GDP growth accelerated from 1.96% in 2010 to 3.73% in 2012, but remained at 2.5% in 2013 and 2014.59
Low interest rates have fuelled growth in household consumption, the housing market, and non- mining investment in Australia. Despite the slow recovery from advanced economies such as the Europe and the USA, commodity prices are expected to remain low for the near term due to slowdown in global growth. Mining investment is therefore expected to experience further declines in the near future, while resource exports will enjoy a continuous strong growth in response to the depreciating Australian dollar (AUD).60
Economic Indices Figure (Year)
Population 23 million (2014)
GDP AUD 1,600 billion (2014)
GDP per Capita AUD 69,565 (2014)
Key industries Mining, industrial and transportation equipment, food processing, chemicals, steel
Table 5: Key economic facts on Australia
Source: Reserve Bank of Australia
Last year the AUD depreciated by approximately 15% on a trade-weighted basis in line with the currencies of other commodity-exporting countries. Set for more than a decade of deficits between 2008 and 2019, the Australian Commonwealth’s net debt is projected to peak at 18% of GDP in 2017, resulting in fiscal consolidation over the coming years.61
59 The World Bank, Data on annual percentage GDP growth, Available at: http://data.worldbank.org/indicator/NY.GDP.MKTP.KD.ZG
60 Research Bank of Australia, Statement on Monetary Policy, August 2015, Available at: http://www.rba.gov.au/publications/smp/2015/aug/html/
61 Grattan Institute, Fiscal challenges for Australia, 2015, Available at: http://grattan.edu.au/report/fiscal-challenges-for-australia
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Major trading partners of Australia are expected to have stable, but slower, growth rates, mostly reflecting a weaker growth in Asia overall. Specifically, China, as one of the country’s most important trading partners, now carries a more subdued demand for iron ore as well as other resource commodities.
5.4.2 Labour Market Between 1994 and 2014, the proportion of Australia’s population aged 15-64 years remained stable at just over 65% of the total population. However, the proportion under the age of 15 decreased from 21.6% to 18.8% during the past decade, indicative of a progressively aging population.
Australia’s unemployment rate has been increasing since 2011 from around 5% to more than 6% in 2014 and is expected to remain at the current level in the near future.62 Employment is projected to increase in most industries over the next five years with the exception of Mining and Manufacturing.63 For utility sectors including electricity, natural gas, water and waste services, employment is projected to grow in total of 3.8% over the next five years.
In the utilities sector, Australia has been shifting away from coal powered energy to more expensive sources and technologies. According to Hays’ 2015 survey,64 oil and gas workers in Australia were the highest paid in the world, earning an average of USD 130,000 per year compared to a global average of USD 83,300. In the Hays’ article released in March 2014, 40% of Australian resource-sector employers reported that skilled labour shortages were their biggest concern.65
The number of employees in the renewable energy industry has grown significantly in the past decade. Entities such as First Solar, AGL Energy Limited (AGL), the Australian Renewable Energy Agency (ARENA), and the New South Wales (NSW) Government are supporting the delivery of Australia’s largest utility-scale solar farms, which are expected to provide significant value to the region with up to 450 direct construction jobs by the end of 2015.66
However, more than 2,000 clean energy jobs have been lost over the past two years as the renewable sector faces political uncertainty over the Renewable Energy Target (RET). Over 20,000 people were employed in the industry in 2014, about 900 fewer than in 2013.67 Statutory reviews of the bipartisan
62 Australian Bureau of Statistics, Available at: www.abs.gov.au
63 Australian Government Department of Employment, Available at: lmip.gov.au
64 Hays Recruiting experts in Oil & Gas, Oil and Gas Global Salary Guide 2015, Available at: https://www.hays.com/cs/groups/hays_common/@og/@content/documents/promotionalcontent/hays_1429953.pdf
65 Hays Recruiting experts in Oil & Gas, Skills shortages are the primary challenge for oil and gas employers in Australia, 2014, Available at: http://www.hays.com.au/press-releases/skills-shortages-are-the-primary-challenge-for-oil-and-gas-employers-in-australia-145255
66 First Solar & ARENA, Industry Development and Job Creation in Australia, 2014, Available at: http://arena.gov.au/files/2014/08/20140613-AGL-Solar-Project-Knowledge-Sharing-Report-No-3a-Attachment-B.pdf
67 Clean Energy Council, Clean Energy Australia 2012 Report, 2012, Available at: https://www.cleanenergycouncil.org.au/dam/cec/policy- and-advocacy/reports/2013/Clean-Energy-Australia-Report-2012/Clean%20Energy%20Australia%20Report%202012.pdf
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RET of 41,000 GWh of annual renewable energy production by 2020 commenced in 2013. In May 2015, following agreement between political parties, the RET was revised to 33,000 GWh. This ended the two-year review of the scheme which was the major source of uncertainty for renewable energy investment. Details about RET are discussed later in Section 5.4.4.
5.4.3 Capital Market and Access to Project Finance Current state of project financing
According to Bloomberg New Energy Finance, Australia’s large-scale renewable energy industry has significantly slowed down in recent years with only one investment in Q1 2015 worth USD 5.1 million following no investments in Q4 2014.68 For the year to March, investment totalled USD 192 million, which was 90% lower than the previous 12 months. This was primarily due to the ongoing uncertainty caused by the RET review.
Figure 14: TotalTotal new new large large--scalescale renewable renewable energy energy investment investment in in Australia (USD million) Australia (USDm) 841.8 788.5 752.2
437.1 324.5 238.3 214.9 174.4 41.6 18.0 0.0 8.9 10.2 0.0 12.5 0.0 5.1
Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 2011 2012 2013 2014 2015
Source: Bloomberg New Energy Finance
The reasons underlying the reduction in the RET were both economic and political. According to Michael Fraser, the head of AGL, one of Australia’s three large “gentailers”, in August 2013 there was about 9,000 megawatts of oversupply in the national electricity generation sector. The company had to seek funding from the ARENA to make up for equivalent wholesale electricity prices dragged down by the extra capacity. To achieve the targeted 33,000 GWh, approximately 6,000 MW of new renewable energy capacity is to be built by 2020. This will likely make the existing investments less profitable, especially for big generators burning coal and gas.69
68 Hannam Peter, Australia’s renewable energy investment grinds to a halt, 2015, Available at: http://www.smh.com.au/environment/climate-change/australias-renewable-energy-investment-grinds-to-a-halt-20150414-1mkn70.html
69 Courtice Ben, Why Abbott wants to scrap the renewable energy target, February 2014, Available at: https://www.greenleft.org.au/node/55919
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To avoid further uncertainty, the government also removed a previously legislated requirement for RET reviews which were to occur every two years.70 It is expected that the frozen status of project finance in Australia’s renewable sectors will return to vitality in the coming months.
Despite the settlement of RET reviews, investors still have concerns regarding the availability of power purchase agreements as the RET legislation relies on retailers to manage the liability of their customers by procuring sufficient renewable generation. In the first decade of the RET renewable procurement in Australia was done primarily through the negotiation of long-term power purchase agreements. Retailers today are reluctant to commit to long term off-take contracts from new renewable projects, instead accessing renewable energy certificates (and generation) via the spot market or short-term forward contracts. Partly in response to these issues, AGL recently announced the creation of the Powering Australian Renewables Fund (PARF). The PARF provides the opportunity to invest in a portfolio of assets, diversifying risk and reducing overall costs. The fund provides for various 5 or 10 year off take arrangements for the procurement of energy and renewable energy certificates.
Supra-national and national banks
The Clean Energy Finance Corporation (CEFC) is a government-owned organization that was established to facilitate increasing flows of finance into the clean energy sector. It invests using a commercial approach to overcome market barriers and mobilizes investment in renewable energy, energy efficiency and low-emission technologies. Since it started to operate under the Clean Energy Finance Corporation Act 2012, the CEFC has committed over AUD 1.4 billion in finance for investments in clean energy projects valued at over AUD 3.5 billion.71
With a total funding allocation of AUD 3.2 billion out to 2020, the Australian Renewable Energy Agency (ARENA) is an independent agency of the Australian federal government, established in 2012 to manage the government's renewable energy programs, with the objective of increasing supply and the competitiveness of Australian renewable energy sources.72 In the 2013 budget, the Labor Government deferred AUD 370 million of ARENA's funding, extending the timeline to 2022. The subsequent Abbott Government proposed to cut $435 million from ARENA's budget, followed by an additional AUD 40 million, but has affirmed its support for the agency.73 ARENA has consolidated various earlier renewable programs and research and development projects from the Australian Centre for Renewable Energy, the Australian Solar Institute, and the former Department of Resources, Energy and Tourism.74 For example, the Renewable Energy Venture Capital Fund (REVCF) was initiated by ARENA to provide venture capital and active investment management to encourage the development of Australian companies that are commercializing renewable energy technologies.
70 Clean Energy Council, Available at: https://www.cleanenergycouncil.org.au/policy-advocacy/renewable-energy-target.html
71 Clean Energy Finance Corporation, Available at: http://www.cleanenergyfinancecorp.com.au/about.aspx
72 ARENA, Available at: http://arena.gov.au/about-arena/corporate-publications/annual-report-2012-13/
73 ARENA, Available at: http://arena.gov.au/news/update-on-arena-funding-and-board-appointments/
74 ARENA, Annual Report 2013-14, Available at: http://arena.gov.au/about-arena/corporate-publications/annual-report-2013-14/
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Commercial banks
Many commercial banks (such as ANZ, Commonwealth Bank of Australia, National Australia Bank and Westpac) have signed principle agreements to support renewable energy sectors, including for example Carbon Disclosure Project, Extractive Industries Transparency Initiative, Equator Principles, Global Reporting Initiative, UNEP Finance Initiative, UN Global Compact, UNEP Finance Initiative, and UNEP Principles for Responsible Investments. Practices conducted include bond issuance and discounted loans. For example, in December 2014, National Australia Bank (NAB) raised AUD 300 million in Australia’s first ever bank-issued climate bond. In 2015, NAB has partnered with CEFC on an AUD 120 million funding program that provides Australian businesses with access to discounted funding for energy efficiency and renewable energy upgrades.75 At present loans and investments from commercial banks in Australia are relatively limited compared to their holding in conventional energy sectors such as coal mining.76 However as part of its stated mission “to accelerate Australia's transformation towards a more competitive economy in a carbon constrained world, by acting as a catalyst to increase investment in emissions reduction”, through direct investment in sector the CEFC aims to attract private sector finance, as well as strategic co-financing arrangements.
Total Coal (%) Renewables (%) ANZ 85.9% 14.1% Commonwealth Bank of Australia 95.4% 4.6% National Australia Bank 87.9% 12.1% Westpac 77.9% 22.1% Total 87.1% 12.9% Table 6: Investments in coal and renewables in 2010 (%)
Note: "Total coal" includes Coal mining, coal-fired power stations and coal export port expansions Source: Greenpeace Australia Pacific.77
Tax exemptions, tax credits and low interest loans
Renewables are also eligible for the R&D Tax Incentive scheme, the mechanism accessible to all industry sectors to provide targeted, generous, and easy-to-access incentives to help businesses offset some of the costs of doing R&D. Currently the program offers two tiers of incentives: a 43.5% refundable tax offset (equivalent to a 150% deduction) for eligible entities with a grouped turnover of
75 FINSIA, NAB commits to renewable energy finance, 2015, Available at: https://www.finsia.com/news/news-article/2015/07/21/nab- commits-to-renewable-energy-finance
76 Profundo economic research, Available at: https://www.google.com/url?sa=t&rct=j&q=&esrc=s&source=web&cd=1&cad=rja&uact=8&ved=0CB0QFjAAahUKEwjm6MT6kI7JAhXMdj4 KHaBDBZc&url=http%3A%2F%2Fwww.profundo.nl%2Ffiles%2Fdownload%2FGpA1010c.pdf&usg=AFQjCNG57PDE9or2SQjYcKuc0YTIeslzGQ &sig2=HbvAK1kLgFQfTEyp40Ea3g
77 Ibid. This was the most recent source of similar data at the time this study was conducted.
Page 60 of 124 DOCUMENTING THE COST OF REGULATORY DELAYS, RE-DELAYS, March 2016 less than AUD 20 million per annum, or a non-refundable 38.5% tax offset (equivalent to 133% deduction) for all other eligible entities (unused non-refundable offset amounts may be able to be carried forward to future income years).78
The carbon pricing mechanism (CPM) administered by the Clean Energy Regulator from 2012 to 2015 was an emissions trading scheme that put a price on Australia's carbon pollution. It was introduced by the Clean Energy Act 2011 and captured approximately 500 of Australia's largest carbon emitters. CPM was applied to electricity generation and industrial facilities emitting in excess of 25,000 metric tons 79 of CO2-equivalent and landfill facilities emitting more than 10,000 tons of CO2-equivalent a year. Approximately 60% of Australia's carbon emissions, including from electricity generation, stationary energy, landfills, wastewater, industrial processes, and fugitive emission were priced during the 2012- 2014 period. However, the CPM was repealed in June 2014.80 Since then, the Emissions Reduction Fund (ERF) has been established as the centrepiece in the Australian Government’s Direct Action Plan to achieve a reduction in carbon emissions to 5% below 2000 levels by 2020. The Direct Action Plan was introduced in 2013 (initially developed for the 2010 Federal election) and incorporates among other initiatives an auction process to allocate $2.5 billion for emission reduction projects and a yet to be developed baseline setting process for major emitting facilities.81
5.4.4 Preparedness of the Regulatory Environment for Renewable Energy Projects Electricity supply mix and renewables targets
Over 50% of Australia’s total generation capacity comes from coal. Gas-fired generation accounts for 22% of total capacity while renewables makes up the rest, with hydro and wind dominating (17% and 8% respectively). Only about 0.6% comes from large scale solar and biomass.82
The 2020 target for large-scale renewable energy of 33,000 GWh implies doubling the current renewable generation and targeting 23.5% of total electricity generation from renewable sources. Under the ambitious plan, AUD40.4 billion worth of investment and more than 15,200 jobs are to be created, 30-50 major projects are to be delivered, and at least 5 million average homes are to be powered by the electricity generated.
78 KPMG, Taxes and incentives for renewable energy, 2014, Available at: https://www.kpmg.com/Global/en/IssuesAndInsights/ArticlesPublications/Documents/taxes-incentives-renewable-energy-v1.pdf
79 Center for Climate Change and Energy Solutions, Australia’s Carbon Pricing Mechanism, Available at: http://www.c2es.org/docUploads/Australia_Pricing_Mechanism.pdf
80 Australian Government Clean Energy Regulator, About the mechanism, 2015, Available at: http://www.cleanenergyregulator.gov.au/Infohub/CPM/About-the-mechanism
81 Tim Nelson, Cameron Reid and Judith McNeill, Energy-only markets and renewable energy targets: complementary policy or policy collision?, 2014, Available at: http://aglblog.com.au/wp-content/uploads/2014/08/No-43-energy-only-and-renewable-targets-FINAL.pdf
82 In addition to the large scale solar installations, Australia currently has over 4,000 MW of installed PV capacity as a result of the Small- Scale Renewable Energy target scheme. Australian PV Institute Available at: http://pv-map.apvi.org.au/historical#4/-26.67/134.12
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Figure 15: Supply mix in Australia (2015)
Generation Capacity (MW, %) Total Generation (GWh, %) Water, Wind, 10,252, Biomass, 3,511, 7,297, 12% 4% 1% Other, 1, 0%
Other, 2,817, Solar, 4,858, Water, 18,421, 5% 2% 8% Oil, 5,012, 2% Wind, 3,797, 6%
Oil, 1,490, Coal, 29,061, 2% 46% Gas, 54,394, 22% Coal, 151,849, 61% Gas, 18,523, 29%
Source: Australian Government Department of Industry, Innovation and Science83,84
Renewable Support: SRES, LRET, FIT
The RET scheme is the most crucial scheme initiated by Australia government supporting renewable energy for electricity generation. It is composed of two parts: the Small-scale Renewable Energy Scheme (SRES) and the Large-scale Renewable Energy Target (LRET). The LRET creates a financial incentive for the establishment or expansion of renewable energy power stations, such as wind and solar farms or hydro-electric power stations, while SRES lowers the costs of renewable energy system installation for households, small businesses and community groups.85 The 33,000 GWh target by 2020 of renewable generation applies to large-scale generation only.
The LRET provides a financial incentive for renewable power station projects by requiring energy users to procure a growing portion (reaching approximately 20% by 2020) of their electricity load from renewable sources. One large-scale generation certificates (LGC) is created for each MWh of eligible renewable electricity produced by an accredited renewable power station, and can be sold or traded to Renewable Energy Target liable entities in addition to their sale of electricity to the grid.86
The SRES, on the other hand, legislates demand for Small-scale Technology Certificates (STCs) to create financial incentives for the installation of small systems. For example, the SRES allows eligible solar PV
83 Australian Government Department of Industry, Innovation and Science, Energy in Australia, 2015, Available at: http://industry.gov.au/Office-of-the-Chief-Economist/Publications/Documents/energy-in-aust/Energy-in-Australia-2015.pdf
84 Australian Government Department of Industry, Innovation and Science, Australian Energy Update, 2015, Available at: http://www.industry.gov.au/Office-of-the-Chief-Economist/Publications/Documents/aes/2015-australian-energy-statistics.pdf
85 Australian Government Department of the Environment, Available at: https://www.environment.gov.au/climate-change/renewable- energy-target-scheme
86 Australian Government Clean Energy Regulator, Large scale renewable energy target, 2015, Available at: http://www.cleanenergyregulator.gov.au/RET/About-the-Renewable-Energy-Target/How-the-scheme-works/Large-scale-Renewable- Energy-Target
Page 62 of 124 DOCUMENTING THE COST OF REGULATORY DELAYS, RE-DELAYS, March 2016 systems to create STCs equivalent to 15 years of expected system output. RET-liable entities have a legal requirement to buy STCs and surrender them to the Clean Energy Regulator on a quarterly basis. In practice, installers usually offer a cash payment or a discount on the price of an installation in return for the right to create the STCs.87
Feed-in-tariffs are mostly state-based initiatives and are applicable to only small-scale generation except in the Australian Capital Territory (ACT) which has previously run a Large Scale Feed-n-Tariff Scheme which provides the ACT government with power to grant feed-in tariff entitlements up to 210 MW of generation capacity.88
Administrative Processes
The administrative process for renewable energy power generation projects varies depending on the source of energy, technology applied, and location. For example, the process of developing a wind farm requires consideration of the quality of the wind resource, negotiations with landowners, the cost of connecting to the electricity network, the impact of a proposed wind farm on local amenity, environment and heritage, and the benefits of the wind farm to a region.89
Figure 16: Wind farm development process
Year 1: Site Year 2: Project Year 3-4: Year 5-6: Year 7-20: Year 21: Selection Feasibility Planning & Construction Commissioning Decommissioning (1 to 6 (1 to 2 years Approvals (1 to 2 years) & Operations (1 to 6 months) months) with ongoing (1 to 2 years) (20 years) wind monitoring)
Source: Australian Government Department of the Environment
Grid access and systems
In Australia, there are transmission networks in each state and territory, with cross-border interconnectors that link some networks. The National Electricity Market (NEM) in eastern and southern Australia provides a fully interconnected transmission network from Queensland through to New South Wales, the Australian Capital Territory (ACT), Victoria, South Australia and Tasmania. The
87 Australian Government Department of the Environment, Available at: https://www.environment.gov.au/climate-change/renewable- energy-target-scheme
88 KPMG, Available at: https://home.kpmg.com/xx/en/home/insights/2013/10/australia-taxes-and-incentives.html
89 Clean Energy Council, Wind Farms, a guide for communities, Available at: https://www.cleanenergycouncil.org.au/technologies/wind- energy/guide-for-communities.html
Page 63 of 124 DOCUMENTING THE COST OF REGULATORY DELAYS, RE-DELAYS, March 2016 transmission networks in Western Australia and the Northern Territory do not interconnect with the NEM or each other.90
The wholesale electricity exchange is operated and administered by the Australian Energy Market Operator (AEMO). AEMO operates the energy markets and systems and also delivers planning advice in eastern and south-eastern Australia.
Two additional regulatory bodies have responsibilities under the NEM legislative scheme:91
The Australian Energy Market Commission is the body responsible for making and amending the National Electricity Rules and for market development and market review at the national level, and for providing strategic and operational advice to the Council of Australian Governments (COAG) Energy Council.
The Australian Energy Regulator performs economic regulation of the wholesale electricity market and electricity networks in the NEM, and is responsible for consumer protection and performance monitoring of retail energy markets in those jurisdictions that have adopted the National Energy Customer Framework (NECF). It is also responsible for the enforcement of the National Electricity Law and the National Electricity Rules. Regulated electricity network businesses must periodically apply to the AER to assess their revenue requirements (typically, every five years).
Access to the NEM is regulated by national rules – National Electricity Rules (NER). Access to the grid depends on the applicant’s compliance with technical requirements as well as ability to bear the cost of connection. Under the NER, the enquiring generator usually bears the standalone transmission costs specified in the connection offer, although the costs could be shared among parties (including the transmission network service provider and generator) by negotiation. The NEM interconnects five regional market jurisdictions (Queensland, New South Wales, Victoria, South Australia and Tasmania).92 Energy flows between these states are subject to network capacity and constraints. Potential new renewable energy must consider these constraints and therefore access to markets as part of their planning decisions.93
5.4.5 Large-scale Onshore Wind Development Wind farms produced more than 4.2% of Australia’s overall electricity in 2014. By the end of 2014, Australia established 1,866 wind turbines in 71 wind farms, reaching a total installed capacity of 3,807
90 Australian Energy Market Operation, Available at: http://www.aemo.com.au/About-AEMO
91 Essential Services Commission of South Australia, Available at: http://www.escosa.sa.gov.au/electricity-overview/reporting-and- compliance.aspx
92 Australian Energy Market Operator, Available at: http://www.aemo.com.au/About-the-Industry/Energy-Markets/National-Electricity- Market 93 In certain circumstances investment in the transmission network, allowing for increased (renewable) energy flows from one region to another may be more appropriate.
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MW. South Australia has the most wind farms with about 40% of its electricity coming from wind power in 2014.
Due to the low cost and large scale, wind power is most likely to be supported by the RET through LRET. The Clean Energy Council has also developed best practices for Community Engagement Guidelines and Communities Expectation Guidelines in support of wind power projects. Since the new RET was passed, the AUD 450 million Ararat Wind Farm signed to be the first major contract in Western Victoria94; Goldwind’s White Rock Wind Farm has negotiated the connection of 70 wind turbines to the state’s transmission system;95 and Windlab has announced commencement of the AUD 50 million construction of Coonooer Bridge Wind Farm in western Victoria.96
Location Owner State Installed Status capacity (MW) Snowtown 2 Trustpower SA 270 Completed (Nov-14) Gullen Range Goldwind NSW 166 Completed (Jan-15) Mt Mercer Meridian VIC 131 Completed (Nov-13) Boco Rock EGCO NSW 113 Completed (Mar-15) Taralga Banco Santander NSW 107 Completed (May-15) and CBD Energy Bald Hills Mitsui&Co Ltd VIC 107 Completed (Aug-15) Portland Wind Pacific Hydro VIC 47 Completed (Feb-15) Energy Project IV Chepstowe Future Energy VIC 6 Completed (Apr-14) Table 7: Large-scale wind projects completed since 2014
Source: Clean Energy Council.97
5.4.6 Large-scale Solar PV Development (Ground-mounted Installations) The large-scale solar industry is still in the early stages of development in Australia due to the relatively high cost of the technology. The largest operating large-scale solar PV plant is the 20 MW Royalla facility, which officially opened in September 2014 with support from the ACT Government’s reverse auction for large-scale solar power. Once completed, AGL and First Solar’s 102 MW Nyngan Solar Plant in New South Wales will hold the mantle as Australia’s largest solar plant. Other large-scale solar
94 Hannam Peter, Renewable Energy Target deal clears way for $450 million wind farm investment, 2015, Available at: http://www.smh.com.au/environment/climate-change/renewable-energy-target-ret-deal-clears-way-for-450-million-wind-farm- investment-20150624-ghx4jw
95 Goldwind Australia Pty Ltd. Media Release, Transgrid Agrees to Connect White Rock Wind Farm, 2015, Available at: http://www.whiterockwindfarm.com/wp-content/uploads/2015/07/Transgrid-Agrees-to-Connect-White-Rock-Wind-Farm-2-July-2015.pdf
96 Milman Oliver, Work begins on $50m Coonooer Bridge windfarm to supply ACT clean energy, 2015, Available at: http://www.theguardian.com/environment/2015/jul/03/work-begins-on-50m-coonooer-bridge-windfarm-to-supply-act-clean-energy
97 Clean Energy Council, Clean Energy Australia Report 2014, AEMO, 2015, Available at: Electricity Statement of Opportunities
Page 65 of 124 DOCUMENTING THE COST OF REGULATORY DELAYS, RE-DELAYS, March 2016 projects include the 56 MW Moree Solar Farm in northern New South Wales developed by FRV, the ground-breaking 44 MW Kogan Creek solar thermal-coal hybrid project developed by CS Energy, and the University of Queensland’s 3.275 MW project. Since the new RET was passed, power producer Ratch Australia Corp has carried out an AUD 100 million solar power plant project with a capacity of 20 to 30 MW in Collinsville.98 The construction is planned to start in 2016.99
Location Owner State Installed Status capacity (MW) Royalla Fotowatio ACT 20 Completed (Sep-14) Renewable Ventures Mildura Belectric VIC 4 Completed (Apr-14) Nyngan AGL NSW 102 Completed (June-15) Moree Fotowatio NSW 56 Expected Completed Early Renewable 2016 Ventures University of First Solar/UQ QLD 3 Completed (Mar-15) Queensland Broken Hill AGL NSW 44 Completed (Nov-15) Table 8: Large-scale solar projects
Source: Clean Energy Council100
5.4.7 Insights from developers For Australian renewable developers, the main source of delay in the development of renewable generation is financing, despite various funding channels offered by the government and private sectors. In fact, as of early 2015, there were several projects that currently hold planning approvals, but are at a standstill due to the lack of investment.101 Although the political uncertainty has been removed, several other concerns on the market continue to cast doubt for financial investors. First, it is very difficult for companies to accept all market and policy risks without an underlying contract from retailers (on behalf of energy users). The greater the term a retailer (end user) may commit to procuring renewables the greater the ability of the proposed project to attract financing. Second, the transformation of the Australian economy from a resource-based to a more service-based economy, in addition to increased energy efficiency measures and rooftop PV installations, has led to reductions in electricity demand. Historically the AEMO has overestimated demand projections which may result in unclear investment signals to the market. Finally, current policy provides RET revenue for projects
98 Hair Jonathan, Collinsville solar power plant to go ahead thanks to Renewable Energy Target decision says Ratch, 2015, Available at: http://www.abc.net.au/news/2015-07-06/collinsville-solar-power-plant-a-goer/6597400
99 Ibid
100 Clean Energy Council, Clean Energy Australia Report 2014
101 Financial Review, Available at: http://www.afr.com/business/energy/desperately-seeking-certainty-renewables-sector-still-in-limbo- over-green-energy-target-20150515-gh2jai
Page 66 of 124 DOCUMENTING THE COST OF REGULATORY DELAYS, RE-DELAYS, March 2016 up until 2030, therefore it is extremely crucial for the projects to start in the next 12 to 24 months just to get enough revenues from RET as the value of cash flow afterwards is hard to estimate and can vary significantly.
Another source of delay faced by large-scale renewable generation developers is associated with complying with changing planning regulations.102 For example, at the state-level, the Victorian Government passed legislation prohibiting the construction of wind turbines within 2 kilometres of a residence area. Although this rule was removed by the new government a few years later, it draws attention to the fact that rules regarding wind farm development are not steady and are not consistent across Australia. Developers suggested that the establishment of a set of standardized planning guidelines for wind farms across the country may be one approach to inspiring more confidence in the upcoming projects.
Developers provided further thoughts on Australia’s endogenous barriers to the renewable industry. First, about 30% of Australia’s export revenues from goods are sourced from the sale of coal and other mineral fuel, which means policy makers have to prevent any unnecessary stranding of Australian energy exports when considering a progressive rate to meet the country’s emission reduction obligations. On the other hand, they need to keep a balance between minimizing emission at the lowest cost and accelerating the country’s structural transformation from a currently coal-heavy economy.
Second, lack of market-exit incentives and regulations is another obstacle for renewable project development, especially when electricity demand is falling. With decreasing demand, installing new renewable generators means replacing high order emitting end-of-life assets, the operators of which have been reluctant to decommission plants, instead preferring to continue operations or mothball generators. One developer noted a regulatory standard and policy incentives may be called for to address this issue. 103 Other developers shared their concern regarding the potential of having a precedent set allowing for payments for closure of certain facilities.
102 Byrnes, Liam; Brown, Colin; Foster, John; Wagner, Liam, Australian renewable energy policy: Barriers and challenges, Available at: https://www.researchgate.net/publication/248707121_Australian_renewable_energy_policy_Barriers_and_challenges
103 Tim Nelson, Cameron Reid and Judith McNeill, Energy-only markets and renewable energy targets: complementary policy or policy collision?, 2014, Available at: http://aglblog.com.au/wp-content/uploads/2014/08/No-43-energy-only-and-renewable-targets-FINAL.pdf
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5 . 5 ONTARIO (CANADA)
5.5.1 State of the Economy Home to approximately 38% of all Canadians, making it the largest province by population, Ontario is a major contributor to Canada’s GDP and host to Canada’s financial capital, Toronto.104 In 2014 alone, Ontario contributed nominally 36.5% or CAD 721 billion to the national GDP. The 2014 fiscal year was dominated by twin issues of declining oil prices and the weakening of the exchange rate against the USA dollar.105 Both of these events have played a significant role in shaping Ontario’s – and, more broadly, the nation’s – economic outlook.
In 2014 Canada’s national GDP grew by 2.53%.106 The Bank of Canada recently revised their forecast for 2015 GDP growth from 1.9% to just above 1% owing to downgrades in business investment plans in the energy sector, and contraction in non-commodity exports such as intermediate metal products and industrial machinery equipment.107 In a bid to spur further investment, the Bank of Canada also lowered the overnight rate in July 2015 from 0.75% to 0.5%.108 Despite this revision to the 2015 forecast, growth is expected to rebound in 2016 and 2017 to approximately 2.6%.109
As an oil-importing province, Ontario is braced for mixed results following the dramatic decline in the price of crude oil. While lower pump prices and input costs will result in increased consumer expenditure and possible business expansion, decreased capital expenditure by companies operating in Canada’s western provinces will mean less demand for machinery, equipment, professional- technical services, and financing from Ontario-based firms. This potential reduction is to be partially offset by global demand moderately boosting the province’s exporting manufacturers given a weaker Canadian dollar.
Relative to national forecasts, Ontario continues to grow at a moderate pace, with GDP growth of 1.9% in 2014 and forecast growth of 2.6% in 2015 spurred by stronger growth in the province’s two top export destinations, the United Stated and the United Kingdom.110 Inflation in the province remains low at 1.5%, consistent with the national rate of 1.3%. However, Ontario’s government is currently
104 Statistics Canada, Quarterly Demographic Estimates, 2015, Available at: http://www.statcan.gc.ca/pub/91-002-x/2015001/tablesectlist- listetableauxsect-eng.htm
105 Ontario Ministry of Finance, Ontario Fact Sheet August 2015, 2015, Available at: http://www.fin.gov.on.ca/en/economy/ecupdates/factsheet.html
106 World Bank, Country Data: Canada, 2015, Available at: http://data.worldbank.org/country/canada
107 Bank of Canada, Monetary Policy Report, 2015, Available at: http://www.bankofcanada.ca/wp-content/uploads/2015/07/mpr-2015-07 15.pdf
108 Bank of Canada, Bank of Canada lowers overnight rate target to 1/2 percent, Press Release, 2015, Available at: http://www.bankofcanada.ca/wp-content/uploads/2015/07/fad-press-release-2015-07-15.pdf
109 Ibid
110 Ontario Ministry of Finance, Ontario Fact Sheet August 2015, 2015, Available at: http://www.fin.gov.on.ca/en/economy/ecupdates/factsheet.html
Page 68 of 124 DOCUMENTING THE COST OF REGULATORY DELAYS, RE-DELAYS, March 2016 running the second largest deficit in the country, with net debt-to-GDP of 38% in 2013-14, owing to significant infrastructure spending in the province.111
Finally, household spending remains strong with existing house sales projected to maintain their current growth trajectory, in turn fuelling spending on furniture, appliances and building materials.112
Economic Indices Figure (Year)
Population 13.68 million (2014)
GDP CAD 721 billion (2014)
GDP per Capita CAD 56,862 (2014)
Key industries Automotive manufacturing, aerospace industry, financial services, food & beverage manufacturing, information technology, mining, life sciences, water technology
Table 9: Key Economics Facts on Ontario
Source: Statistics Canada, Ontario Chamber of Commerce, Ontario Ministry of Finance
5.5.2 Labour Market Ontario’s unemployment rate of 6.4% in July 2015 remains below the national average of 6.8%. The 0.4% difference in rates is the largest since October 2004.113 Ontario’s 2015 labour participation rate and employment rates remain in line with the national average at 65.2% and 61.2% respectively. Ontario’s services sector (in particular trade and professional, scientific, and technical services) showed strong employment growth over 2014 and is forecast to grow further in 2015 providing support for Ontario’s labour market.114
The elimination of coal-powered energy in Ontario has sustained a decline in employment in the utilities sector. Specifically, employment in the utilities sector has fallen in five of the past six years,
111 RBC Economics, Canadian Federal and Provincial Fiscal Tables, 2015, Available at: http://www.rbc.com/economics/economic- reports/pdf/provincial-forecasts/prov_fiscal.pdf
112 RBC Economics, Provincial Outlook: June 2015, 2015, Available at: http://www.rbc.com/economics/economic-reports/pdf/provincial- forecasts/ont.pdf
113 Ontario Ministry of Training, Colleges and Universities, Ontario Labour Market Statistics for July 2015, July 2015, Available at: http://www.tcu.gov.on.ca/eng/labourmarket/currenttrends/docs/monthly/201507.pdf
114 Employment and Social Development Canada, Environment Scan, Ontario, Spring 2015, March 2015. Available at: http://www.esdc.gc.ca/eng/jobs/lmi/publications/e-scan/on/on-escan-spring2015.pdf
Page 69 of 124 DOCUMENTING THE COST OF REGULATORY DELAYS, RE-DELAYS, March 2016 marking an overall 18.6% decline since 2008.115 This overall decline is partially offset by construction jobs associated with the development of wind and solar farms across the province. For example, construction of new wind farms in the Stratford-Bruce Peninsula area is expected to create 2,300 jobs over the next two years with the two new projects, the Armow Wind Project (92 turbines) and K2 Wind Power Project (140 turbines), to be developed by 2016.116 Recently, at the Goshen Wind Energy Centre in Huron County, 250 jobs in construction and 10 jobs in operations have been created.117
New job growth in the renewables sector has been spurred by the introduction of the Ontario Green Energy Act (2009), GEA, and the creation of subsequent programs including the Feed-in-Tariff (FIT) program. At its launch in 2009, the Ontario government estimated the Green Energy Act would create 50,000 jobs by the end of 2012.118 Approximately 30,000 of the 50,000 jobs were expected to be construction-related owing to new developments across the province. However by the end of 2013, only 31,000 renewable energy jobs were created.119 The majority of these jobs are temporary, relating to the construction of new renewable energy projects developed across the province.
More recently, procurement processes such as the Large Renewable Procurement (LRP) program administered by the Independent Electricity System operator (IESO), in which up to 300 MW of wind, 140 MW of solar, 50 MW of bioenergy and 75 MW of hydro capacity is expected to be procured, have driven new developments and therefore new job opportunities in the sector.120
5.5.3 Capital Markets and Access to Project Financing Current state of project financing
Canadian capital provision for renewable energy is shaped largely by three major categories of financiers: financial investors, strategic investors, and international owners / operators. Financial investors consist of infrastructure funds that own a mix of Greenfield investments and operating assets, seeking consistent returns for developments. Some funds in this category include Northleaf Capital Partners, Solar Income Fund, and Ontario Teachers’ Private Capital. Large utilities and independent power producers are considered strategic investors who are listed and predominately attracted to high-yield Greenfield investments. These include Northland Power, Innergex, Enbridge,
115 Ibid Page 8
116 Ontario Chamber of Commerce, 2015 Regional Economic outlook Stratford-Bruce Peninsula, 2015, Available at: http://www.occ.ca/Publications/2015-Regional-Economic-Outlook/Stratford-Bruce-Peninsula.pdf
117 Employment and Social Development Canada, Labour Market Bulletin – Ontario: April 2015, 2015, Available at: http://www.esdc.gc.ca/eng/jobs/lmi/publications/bulletins/on/apr2015.shtml?pedisable=false
118 Pembina Institute, Ontario Feed-in Tariff: 2011 Review, Page 10, 2011, Available at: http://www.pembina.org/reports/on-feed-in-tarif- 2011-review.pdf
119 Ontario Ministry of Energy, Achieving Balance: Ontario’s Long-Term Energy Plan, December 2013, Available at: http://www.energy.gov.on.ca/docs/LTEP_2013_English_WEB.pdf
120 IESO, Large Renewable Procurement, 2015, Available at: http://www.ieso.ca/Pages/Participate/Generation-Procurement/Large- Renewable-Procurement/default.aspx
Page 70 of 124 DOCUMENTING THE COST OF REGULATORY DELAYS, RE-DELAYS, March 2016 and TransCanada. The third type, described as international owners / operators, are established international players with large and diverse portfolios, including NextEra and GDF Suez. They tend to seek higher rates of return in global markets.121
The majority of the capacity in the province is developed under long-term power purchase agreements with the IESO, effectively underwriting the investment and therefore the financing required for new developments. Recent examples of deals completed in the bond market for renewable energy developments include Brookfield Renewable Energy Partners’ issuance of 17.7-year BBB bonds valued at CAD 450 million (at a yield of 5.13%) in February 2013 as part of its refinance of the 166-MW Comber Wind Farm.122 This followed NextEra Energy’s CAD 175 million 19-year BBB bonds at a yield of 4.8% to refinance two solar projects in Sarnia, Ontario.123 Both issuances were the first investment-grade bonds issued of their kind for wind and solar PV projects in Canada.
Commercial banks
Many of the major commercial banks in Canada assist with financing options for renewable energy projects including small business lending and large business lending. These include Toronto-Dominion Bank (TD), Scotiabank, Canadian Imperial Bank of Commerce (CIBC), Bank of Montreal (BMO), and Royal Bank of Canada (RBC). In 2014, CIBC lent $490 million towards $4.6 billion in total financing for renewable projects in wind, solar, and biomass.124 Scotiabank and RBC were the sole lead and book runners in bond issuances for Brookfield Renewable Energy Partners and NextEra Energy, respectively (see section 4.3.1 Current state of project financing).
Tax exemptions, tax credits and low interest loans
The Canadian Government allows for businesses investing in renewable energy to be eligible for the accelerated capital cost allowance (CCA) rate. This would allow the cost of eligible assets, procured before 2020, to be depreciated at a rate of 50% per year on a declining balance basis. Other federal programs aimed at renewable energy include the ecoENERGY for Renewable Power, a CAD 1.4 billion program, from April 2007 through March 2011, although payments for existing agreements will
121 Canadian Solar Industries Association, KPMG, Solar PV Industry Roadmap 2020: White Paper, April 2014, Available at: http://cansia.ca/sites/default/files/20140403_cansia_white_paper_final_0.pdf
122 Brookfield Renewable Energy Partners, Brookfield Renewable Completes CND $450 Million Financing for Comber Wind Facility, February 2013, Available at: https://www.brookfieldrenewable.com/content/2013/brookfield_renewable_completes_cnd_450_million_fi- 36747.html
123 Climate Bonds Initiative, RBC issues Canada’s first solar bond - $175m, 19yr BBB, 2012, Available at: https://www.climatebonds.net/2014/05/rbc-issues-canada’s-first-solar-bond-175m-19yr-bbb
124 CIBC, Responsible Financing, 2015, Available at: https://www.cibc.com/ca/inside-cibc/environment/green-products-services.html
Page 71 of 124 DOCUMENTING THE COST OF REGULATORY DELAYS, RE-DELAYS, March 2016 continue to March 2021, to promote wind, low-impact hydro, photovoltaic and bioenergy electricity generation.125,126
5.5.4 Preparedness of the Regulatory Environment for Renewable Energy Projects Electricity Supply Mix and Renewable Targets
Ontario is the largest producer of nuclear energy in Canada with over 60% or 93.7 TWh of all power production in Ontario sourced from nuclear facilitates in 2014 alone. Just over 32% of Ontario’s installed capacity is made up of renewable sources, dominated by an abundance of hydro generation (24% of total capacity) and wind (7% of total capacity).
Figure 17: Supply mix in Ontario (2014)
Intalled Capacity (MW, %) Generation (GWh, %) Biomass, Wind, 317, 0% 6,759, 4% Biomass, Other, 98, Wind, 0% 302, Gas / Oil, 2,483, 1% 7% 14,806, 10%
Nuclear, 12,947, Gas / Oil, Hydro, Nuclear, 38% 9,920, 37,059, 24% 94,860, 62% 30%
Hydro, 8,119, 24%
Source: IESO data127 Ontario’s Green Energy Act and Green Economy Act, both of 2009, marked the Province’s commitment to significantly increase the share of renewables in its supply mix. As part of the Province’s then Climate Change Strategy, the Green Energy Act supported the Province’s objectives to eliminate coal-fired generation by 2014 and achieve a 30% reduction in natural gas consumption by 2017. Furthermore the Green Energy Act looked to spark growth in renewable sources of energy such as solar, wind, hydro, biomass, and biogas in the province.
Ontario’s triennial Long Term Energy Plan (LTEP), outlines the energy policy direction for the province for the next two decades. The current LTEP was released in December 2013; with its release, the
125 KPMG, Taxes and incentives for renewable energy, September 2013, Available at: https://www.kpmg.com/Global/en/IssuesAndInsights/ArticlesPublications/taxes-and-incentives-for-renewable-energy/Documents/taxes- and-incentives-for-renewable-energy-2013.pdf
126 Natural Resources Canada, EcoEnergy for Renewable Power, 2015, Available at: https://www.nrcan.gc.ca/ecoaction/14145
127 The above figures do not account for generation connected directly to the distribution network, such as rooftop solar. CanSIA recognise more than 2 GW of solar generation is in commercial operation in Ontario (with another 400 MW) contracted and under development.
Page 72 of 124 DOCUMENTING THE COST OF REGULATORY DELAYS, RE-DELAYS, March 2016
Ontario government outlined its plans to have renewable sources account for about half of installed capacity or approximately 20 GW by 2025.128 In reaching this target, 10.7 GW of wind, solar, and bioenergy is to be phased in by 2021, and 9.3 GW of hydro to be online by 2025. In August 2015, the IESO released an update to the 2013 LTEP. While providing for continuation of key targets, the IESO noted the projected need for additional supply in the short to medium term would be deferred given recent contracting efforts (including entering into agreements providing for the refurbishment of Bruce and Darlington nuclear facilities, and retirement of Pickering nuclear facility) and new project developments.
Finally, in April 2015, Ontario announced its intention to join the California and Quebec cap-and-trade program under the Western Climate Initiative (WCI). This program places a price on carbon emissions, and will give businesses a quota on greenhouse gas emissions, allowing for the sale of surplus quota to other businesses.129
Renewable Support: FIT, MicroFIT and LRP
At the time of its enactment in 2009, the Feed-In Tariff (FIT) program remained North America’s first comprehensive guaranteed pricing structure for renewable energy sources. The FIT program is administered by the IESO. The program’s objectives are to “facilitate the increased development of renewable generating facilities of varying sizes, technologies and configurations via a standardized, open and fair process”.130 The FIT program motivates renewables by streamlining project development and by offering long-term contracts to developers.
In Ontario the program is delivered through two separate streams, the FIT program and the microFIT program, the latter utilized for projects of 10 kW or less. Eligible technologies include: solar PV, wind, biomass, biogas, hydro power, and landfill gas. The IESO pays a fixed contract price, and with the exception of solar contracts, indexed to the Consumer Price Index (CPI) over the term of the contract. The length of the FIT or microFIT contracts is typically 20 years for all technologies, except hydro power, which usually involves a 40-year contract.131
The program is not without controversy, with the government having previously made significant changes to the program following its first review in 2011, effectively forcing developers who had not yet received contracts to restart the costly application process. The Province also revised downwards FIT prices, damaging the feasibility of some developments. To avoid further significant issues with
128 Ontario Ministry of Energy, Achieving Balance: Ontario’s Long-Term Energy Plan, December 2013, Available: http://www.energy.gov.on.ca/en/ltep
129 Office of the Premier, Cap and Trade System to Limit Greenhouse Gas Pollution in Ontario, April 2015, Available at: http://news.ontario.ca/opo/en/2015/04/cap-and-trade-system-to-limit-greenhouse-gas-pollution-in-ontario.html
130 Ontario Ministry of Energy, Glossary, Available at: http://www.energy.gov.on.ca/en/renewable-energy-development-in-ontario-a-guide- for-municipalities/8-glossary/
131 IESO, FIT Program, 2015, Available at: http://fit.powerauthority.on.ca/fit-program
Page 73 of 124 DOCUMENTING THE COST OF REGULATORY DELAYS, RE-DELAYS, March 2016 administering the program, the Province has now committed to a more regular biennial program review period.
The current version of the FIT program (version 4) is open only to projects less than 500 kW, and the microFIT program remains open to small projects of less than 10 kW. Table 10 below highlights the current FIT price schedule as of September 9, 2015.132
Project Size 2015 Price 2016 Price Renewable Fuel Tranche (¢/kWh) (¢/kWh) ≤ 10 kW 38.4 29.4 Solar (PV) >10 ≤ 100 kW 34.3 24.2 (Rooftop) > 100 kW ≤ 500 kW 31.6 22.5 Solar (PV) ≤ 10 kW 28.9 21.4 (Non-rooftop) > 10 kW ≤ 500 kW 27.5 20.9 On-Shore Wind ≤ 500 kW 12.8 12.8 Waterpower ≤ 500 kW 24.6 24.6 Renewable Biomass ≤ 500 kW 17.5 17.5 ≤ 100 kW 26.3 26.3 On-Farm Biogas > 100 kW ≤ 250 kW 20.4 20.4 Biogas ≤ 500 kW 16.8 16.8 Landfill Gas ≤ 500 kW 17.1 17.1 Table 10: FIT and MicroFIT prices in Ontario
Source: IESO data133
In addition to the FIT and microFIT programs, the IESO also administers the LRP program. The LRP program has been designed as “a competitive process for procuring large renewable energy projects, generally larger than 500 kilowatts”.134 Through municipal, community and aboriginal stakeholder engagement, as well as research and analysis conducted across 2013 and early 2014, a path was established by the IESO for the procurement of new renewable energy supply, including capacity targets and proposed timing for procurement process. The first phase of the LRP program, LRP I, is currently underway, with a target of 300 MW for wind, 140 MW for solar, 75 MW for hydro power, and 50 MW for bioenergy. As part of the LRP process 42 unique developers were pre-qualified, altogether proposing 119 different projects.135
132 IESO, FIT prices given in Canadian dollars/cents as of 2015, 2015, Available at: http://fit.powerauthority.on.ca/fit-program/fit-program- pricing/fit-price-schedule
133 Available at: http://fit.powerauthority.on.ca/fit-program/fit-program-pricing/fit-price-schedule
134 IESO, Website – Large Renewable Procurement, September 2015, Available at: http://www.ieso.ca/Pages/Participate/Generation- Procurement/Large-Renewable-Procurement/default.aspx
135 Ibid
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Administrative Processes and Policy Change
After preliminary discussions with industry professionals, we understand the administrative process can be lengthy at times, hindering new project developments in the province. For example every project attempting to qualify for a FIT or LRP contract is subject to, as a minimum, the Renewable Energy Approval (REA) as shown in Figure 18, from the Ministry of Environment and Climate Change (MoECC), which is prescribed as a 6-month process but has been cited as common source of administrative delays by developers.
Figure 18: Renewable Energy Approval
Application for Environmental Community Feasibility Analysis electricity and regulatory Construction Operation engagement contract approvals
With the introduction of greater scope for In 2015, the Ontario Superior Court of Justice participation by municipalities and First Nation found that the City of Kawartha Lakes had communities, as stakeholders in the REA process, acted outside its jurisdiction in denying use of developers have an opportunity to be rewarded for a roadway by Wpd Sumac Ridge Wind Inc. The achieving greater buy-in from the community of wind turbine developer had already received 136 their project. However, unfavourable approval for the construction of five industrial municipality and First Nations community wind turbines and related infrastructure in interactions have also been cited as roadblocks to the city. During the approval process, the city 137,138 timely approvals. An objection by aggrieved knew of the project’s reliance on the roadway communities to the award of an REA subjects a but did not raise any issues until after developer to the Environmental Review Tribunal approval. Consequently, the project was (ERT) process, a litigation measure that could set a delayed, and the City of Kawartha was developer back by a further 6 months. ordered to pay CAD 55,000 and act in good faith. In addition to the REA, the LRP program requires potential developers to participate in both a Request for Qualification (RFQ) and Request for Proposals (RFP) process. Newly-proposed LRPs must demonstrate site and resource due diligence as well as engagement with the communities in which they are proposing to locate.139 The requirement for new developers to participate in this process is a
136 Renewable Energy Facilitation Office, Renewable Energy Development: A Guide for Municipalities, December 2012, Available at: http://www.energy.gov.on.ca/en/renewable-energy-development-in-ontario-a-guide-for-municipalities/
137 Energyinsider.ca, Municipalities May Not Exercise Their Powers to Frustrate Projects Granted Renewable Energy Approvals, August 2015, Available at: http://energyinsider.ca/index.php/municipalities-may-not-exercise-their-powers-to-frustrate-projects-granted-renewable- energy-approvals/
138 myKawartha, Court rules City acted in bad faith in denying wind energy company access to road, August 2015, Available at: http://www.mykawartha.com/news-story/5808259-court-rules-city-acted-in-bad-faith-in-denying-wind-energy-company-access-to-road/
139 IESO – Website, Large Renewable Procurement, September 2015, Available at: http://www.ieso.ca/Pages/Participate/Generation- Procurement/Large-Renewable-Procurement/default.aspx
Page 75 of 124 DOCUMENTING THE COST OF REGULATORY DELAYS, RE-DELAYS, March 2016 direct reflection of the market design in Ontario and the role performed by the IESO in procuring new generation capacity to come online in the province.
A key component for new developments looking to secure grid access in Ontario is the completion of a series of impact assessments including the IESO administered Connection Assessment and Approval (CAA) process. This process includes a System Impact Assessment (SIA) which assesses, among other issues, a new connections impact on system reliability. In addition to the CAA, new connections to the transmission or distribution network must complete a Customer Impact Assessment done as part of the Customer Connection Application process administered by the transmission system owner/operator, Hydro One. Discussions with developers in the province have highlighted a lack of transparency and general accountability in the completion of this process.
5.5.5 Large-scale Onshore Wind Development While Ontario remains heavily dependent on nuclear and hydro generation for baseload power, rapid development of onshore wind power has resulted in a total of 2.5 GW of wind capacity or 7% of total installed capacity now being connected to the grid.140 Ontario is a national leader in wind farm development, with approximately 2,000 MW of new developments in the pipeline or in various stages of the development lifecycle.141 In 2014, 39% of total wind energy installed in Canada was located in Ontario.142 The current LRP I procurement process has set out a procurement target of 300 MW for wind energy for 2015 and 2016, ensuring a strong pipeline of wind projects coming online.
A key change benefiting developers under the Green Energy and Green Economy Act (2009) ultimately resulted in a curtailment of municipal powers under Ontario’s Planning Act in regards to new renewable energy developments. Specifically, new renewable energy facilities were exempt from key components of the Planning Act including restrictions around official plans, zoning bylaws, demolition control areas, and development permit systems. Municipalities across the province have generally had mixed responses to the changes with some embracing the (broader) changes and encouraging new renewable investment in their regions while others have openly criticised and campaigned against the changes and new investment.
140 Ontario placed a moratorium on offshore wind development in February 2011, at the time noting further scientific studies were required.
141 CanWEA, Ontario Wind Energy Market Profile, June 2014, Available at: http://canwea.ca/wp-content/uploads/2014/06/Ontario-Market- Profile.pdf
142 CanWEA, Installed Capacity, June 2015, Available at: http://canwea.ca/wind-energy/installed-capacity/
Page 76 of 124 DOCUMENTING THE COST OF REGULATORY DELAYS, RE-DELAYS, March 2016
Figure 19: Wind Energy Installed Capacity (2015)
Installed Capacity (MW)
Nova Scotia 4% British Other Columbia 10% 5% Ontario 39% Alberta 14%
Quebec 28%
Source: CanWEA, 2015
5.5.6 Large-scale Solar PV Development (Ground-mounted Installations) Ontario remains Canada’s largest solar market, with 1,642 MW of utility-interconnected solar PV systems installed across the province in September 2014. The provincial government has committed to a further 150 MW of solar PV below 500 kW under the FIT program, 50 MW under the microFIT program, and a further 140 MW of new solar generation under the LRP 1. The total amount of installed and under development PV capacity in Ontario is approximately 2,438MW.143
Large solar farms face a similar regulatory development cycle as wind. However, solar PV enjoys a more favourable public perception, with results from a CanSIA-administered survey indicating 98% approval for solar PV as a renewable energy source.144
5.5.7 Insights from developers We undertook several interviews with wind and solar project developers and solar/wind energy associations in Ontario. Key insights are discussed in this section.
The REA permitting process in Ontario was identified as one of the regulatory steps that could cause potential delays of several months. Developers noted that the studies are often not deemed to be complete and guidance as to how to address deficiencies may sometimes be lacking or inconsistent. The delays could require scheduling additional seasonal investigations. A related delay is with regards to the Environmental Review Tribunal (ERT) process — this is a legal tribunal whereby any challenges or reviews to the REA are heard. This process could take up to 6 months. REA approvals after the initial submission of an application can sometimes range from one to three years. Another source of delays identified was the connection assessment and approval process. Connection assessments can be long if the LDCs are small or new to the process, and need to hire consultants to assess connection requests.
143 IESO, A progress report on contracted electricity supply – Third Quarter 2015, December 2015, Available at: http://www.ieso.ca/Documents/Supply/Progress-Report-Contracted-Supply-Q32015.pdf
144 Ibid page 25
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The delay may also become acute if the LDC needs to engage Hydro One (due to its transmission ownership).
Policy uncertainty, like in other jurisdictions, was identified as another source of major delays, or even a source for several projects being abandoned all together. For instance, the FIT program was launched in 2009 and after 2 years of operation, the program went into review. In 2011, the government stopped accepting applications and those that had not been awarded were placed into hiatus for several months as the government carried out a review of the program. Once the review was completed, the province announced new rules which eliminated some pending applications. Some new requirements meant that the old applicants had to redo their applications. The industry was not pleased — for example, one of the larger solar firms (with 118 applications pending) served a legal notice to the provincial government seeking damages in excess of CAD 100 million.145
145 National Post, Solar firm seeks $100M over McGuinty’s green energy rejig, Available at: http://news.nationalpost.com/news/canada/solar-firm-seeks-100m-over-mcguintys-green-energy-rejig
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5 . 6 NORWAY
5.6.1 State of the Economy Although oil is crucial for the Norwegian economy and oil prices sharply fell in 2014- 2015, mainland economy grew at 2.2 percent in 2014. Decreasing prices were mainly offset by stronger public spending and continued growth in private consumption. Furthermore, although unemployment was rising, it stayed at relatively low levels.
The near term outlook of the IMF (May 2015) for 2015 is that mainland GDP growth will slow down to 1.4 percent because of weaker private investments, a lower consumption and a declining demand for mainland inputs to the offshore sector. Both the IMF and the OECD subsequently predict a rebound in 2016 and Source: The Economist Intelligence Unit 2017, driven by increasing oil prices and private consumption, non-oil investments and increasing export.146
Government debt levels in Norway are relatively low (32.4% of GDP) but there are increasing worries about the level of household debt. Ever-rising housing prices have forced buyers to take on bigger mortgages than ever before and the household debt-to-disposable income ratio is now one of the highest among the OECD countries (about 220% of disposable income in the first quarter of 2015). 147
Furthermore, investments into the oil, gas and mining sector sharply declined in 2014 and 2015 while high investments within electricity supply are expected at least until the end of 2016. There is also a strong growth in export-related industries such as refined petroleum, chemicals, pharmaceuticals and basic metals, and export is expected to be sustained because of recent capacity upgrades and modernisation. Whereas Norway had a trade surplus of around 20.6 billion Norwegian Krone (NOK)
146 International Monetary Fund, Norway, Concluding Statement of the 2015 Article IV Mission, 28 May 2015, Available at: https://www.imf.org/external/np/ms/2015/052815.htm
OECD, Selected indicators for Norway, 2015, Available at: https://data.oecd.org/norway.htm
147 International Monetary Fund, Norway, Concluding Statement of the 2015 Article IV Mission, 28 May 2015, Available at: http://ec.europa.eu/eurostat/statistics- explained/index.php/File:Unemployment_rates,_seasonally_adjusted,_September_2015.pnghttps://www.imf.org/external/np/ms/2015/0 52815.htm
Page 79 of 124 DOCUMENTING THE COST OF REGULATORY DELAYS, RE-DELAYS, March 2016 in October 2015, this surplus has decreased by 38.5% compared to the same month last year. This decreasing trade surplus is both because of decreasing exports and increasing imports.148
In the coming years, a transition away from Norway’s oil-dependent growth model will be the main challenge. The country is at the beginning of a period of restructuring and its economy will have to be brought more in line with those of other countries in the longer run.149
Economic Figure (Year) Indices
Population 5.1 million (2015)
GDP USD 500.1 billion (2014)
GDP per Capita UAD 64,837 (2015)
Key industries Oil, gas, maritime, seafood, pharmaceuticals, chemicals
Table 11: Key economic facts on Norway150
Source: OECD and World Bank
5.6.2 Labour Market Norway has an active population aged fifteen and over of approximately 3.3 million. With an employment rate of over 75% of people aged 15 to 64 (77% of men and 74% of women), the country is performing better than almost all other OECD countries. Nevertheless, there is increasing global competition to attract the best workers, and various industries in Norway are confronted with labour shortages. A study from 2013 indicates that there is a particular shortage of engineers and IT specialists.151
148 Statistics Norway SBB, Investments in oil and gas, manufacturing, mining and electricity supply, Q4 2015, 24 November 2015, Available at: Investments in oil and gas, manufacturing, mining and electricity supply, Q4 2015
149 International Monetary Fund, Norway, Concluding Statement of the 2015 Article IV Mission, 28 May 2015, Available at: https://www.imf.org/external/np/ms/2015/052815.htm
Norges Bank, Oil and the Norwegian economy – the challenges ahead, 2015, Available at: http://www.norges- bank.no/en/Published/Speeches/2015/27032015-Olsen-New-York/
150 OECD, Selected indicators for Norway, 2015, Available at: https://data.oecd.org/norway.htm
The World Bank, Norway, Available at: http://data.worldbank.org/country/norway 151 The World Bank, Labor force participation rate, total (% of total population ages 15+) (modeled ILO estimate), Available at: http://data.worldbank.org/indicator/SL.TLF.CACT.ZS
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Hydropower counts for 97% of total electricity production in Norway and the country wants to invest more and more in other renewable energy technologies. In 2008, 725 companies were active in hydropower, employing almost 10,000 people. Only around 1,000 people were working in the wind sector but this number has probably increased since the green certificates scheme was launched in 2012 and several developments have taken place, certainly in the year 2012 (below).152
5.6.3 Capital Markets and Access to Project Financing Current state of project financing
Electricity market prices in Norway and Sweden are the lowest in Europe and it is thus challenging to develop profitable projects in the Nordic market. A lot of projects, particularly onshore wind projects, have been cancelled in recent years because of low prices (as for example Statkraft who was considering the rejection of a 1 GW Norway onshore wind development in June 2015). In September 2015, market prices were at their lowest in 12 years and investments in utility-scale wind assets fell 76% in the three years through 2014. Problems related to uncertainty in the green certificates have to be seen as a part of this issue (below).153
If companies are still investing, because low returns go together with very low risks, they generally focus on projects related to grids (as mentioned before), wind power (single projects and portfolios), district heating and distribution assets, small scale hydro and large scale hydro coming up for sale. New large hydropower developments are less common. Statkraft and Statnett are by far the largest investors in the renewable energy market, but there has also been interest from European and international companies over the last few years, including the “green” investment departments of large oil & gas producers, In 2015, it was announced that two Scandinavian wind-power developers will merge their 3.2 billion-euro investment pipeline across Finland, Norway and Sweden. The main objective of this merger is the establishment of one of the lowest cost and highest return wind developers in the Nordic region. The new company, Havgul Nordic AS, plans five projects of 865 megawatts in Norway.154
Fafo Østforum, International talent recruitment to Norway, 2013, Available at: http://www.fafo.no/~fafo/images/pub/2013/20334.pdf
OECD Better Life Index, Norway, Available at: http://www.oecdbetterlifeindex.org/countries/norway/
152 European Employment Observatory, EEO Review: Promoting green jobs throughout the crisis, Norway, 2013
153 Bloomberg, Wind Farm Investment Plunges With Power Prices in Nordic Region, 4 September 2015, Available at: http://www.bloomberg.com/news/articles/2015-09-04/wind-farm-investment-plunges-with-power-prices-in-nordic-region
Bloomberg New Energy Finance, Wind Farm Developers to Merge $3.5 Billion Pipeline of Projects, March 2015
WindPowerMonthly, Statkraft ends 1GW Norway development, 4 June 2015, Available at: http://www.windpowermonthly.com/article/1350073/statkraft-ends-1gw-norway-development
The Norwegian Wind Industry Association (NORWEA)
154 Bloomberg New Energy Finance, Wind Farm Developers to Merge $3.5 Billion Pipeline of Projects, March 2015
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Supra-national and national banks
The state-owned company Enova is a driving force for energy conversion in Norway. It offers financial support for various renewable energy and environmentally friendly projects. The Nordic Investment Bank (NIB) also finances many hydro projects through other financial intermediaries, such as the Norwegian Sparebanken Vest (SPV). Note that in March 2014 the major Norwegian sovereign wealth fund decided to invest a lot more in renewable energy. 155
Commercial banks and investors
The Norwegian Sparebanken Vest (SPV), the third largest savings bank in Norway, started to finance hydropower projects in 1998 and has so far lent to more than 70 hydropower projects in the Western Norway region. Furthermore, Norway’s Statkraft announced at the end of 2014 that it was going to invest over USD 8 billion in renewable energy projects in Norway and abroad. Examples of other major domestic and foreign investors and banks putting money in renewable energy projects in recent months and years are Norwegian’s Hafslund Produksjon AS, Japan’s Eurus Energy holding, Zurich Municipal Electric Utility and ING Groep NV. EON is equally examining the possibility of establishing several onshore wind farms in Norway. 156
Tax exemptions, tax credits and low interest loans
Sweden and Norway share a joint green certificates scheme to support hydro and onshore wind projects. In this framework, Sweden ended on 13 March 2015 its tax exemption for Swedish companies that install new capacity in order to level out the playing field for building new capacities between the two countries.157
Schjodt, Renewable energy in Norway, 2015, Available at: http://www.schjodt.no/kompetanse/kina-ekspertise/publications-and- seminars/renewable-energy-in-norway/
155 Nordic Investment Bank, Hydropower in Norway:a smile is his umbrella, Available at: http://www.nib.int/news_publications/cases_and_feature_stories/1169/hydropower_in_norway_a_smile_is_his_umbrella
KPMG International, Taxes and incentive for renewable energy, 2014, Available at: https://www.kpmg.com/Global/en/IssuesAndInsights/ArticlesPublications/Documents/taxes-incentives-renewable-energy-v1.pdf
Bllueandgreentomorrow, Norway’s oil fund ploughs forward in renewable energy investment, March 2014, Available at: http://blueandgreentomorrow.com/2014/03/14/norways-oil-fund-ploughs-forward-in-renewable-energy-investment/
156 Bloomberg New Energy Finance, Hog Jaeren Wind Farm Phase II, Available at: https://www.bnef.com/AssetFinancing/19624?fromGlobalSearch=3191675017
Cleantechnica, Norway’s Statkraft To Invest $8 Billion In Renewables, December 2014, Available at: http://cleantechnica.com/2014/12/29/norways-statkraft-invest-8-billion-renewables/
Bloomberg New Energy Finance, Hafslund Plans 128 Megawatt Upgrade for Hydro Plant in Norway, 9 September 2015
157 WindPowerMonthly, Norway and Sweden adjust balance for renewable energy pact, 13 March 2015, Available at: http://www.windpowermonthly.com/article/1338120/norway-sweden-adjust-balance-renewable-energy-pact
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5.6.4 Preparedness of the Regulatory Environment for Renewable Energy Projects Electricity Supply Mix and Renewable Targets
In 2013, Norway was the 5th largest producer of renewable energy in Europe. With 97% of hydro production and 3% of wind energy production in 2014 (Figure 20) the country had a larger share of renewables in gross inland (and final) energy consumption (37.4%) than any European country.
Figure 20: Supply mix in Norway (2014)
Source: Bloomberg New Energy Finance
Norway and Sweden furthermore recently agreed to increase their common renewable energy target from 26.4 TWh to 28.4 TWh by 2020. The joint electricity market and electricity Certificate Scheme to support electricity from renewable sources, which was implemented in 2012, should help to achieve this objective. However, the Swedish plan originating from their national political discussions was not matched by Norwegian obligations, so the additional production will be entirely under the responsibility of Sweden. As the targets are financing targets, no consideration to location is made. Sweden is to finance 15.2 TWh and Norway 13.2 TWh regardless if this is installed in Sweden or Norway.158
Norway is a large exporter of electricity and is expected to export 32 TWh of electricity by 2030. In 2014, the country had an installed interconnection capacity of more than 6,000 MW with Sweden, Denmark, the Netherlands, Finland and Russia. Since Norway and Sweden have a common electricity
Svenk Windenergi, What does the parliament decision October 21st mean?, November 2015, Available at: http://www.vindkraftsbranschen.se/wp-content/uploads/2015/11/Important-parliament-decision-on-the-TGC-system-20151110.pdf
Renewableenergyworld, Norway May Miss Out on $6 Billion Wind Power Boom, September 2014, Available at http://www.renewableenergyworld.com/news/2014/09/norway-may-miss-out-on-6-billion-wind-power-boom.html
158 European Commission, Renewable Energy Statistics, 2015, Available at: http://ec.europa.eu/eurostat/statistics- explained/index.php/Renewable_energy_statistics
Bloomberg New Energy Finance, Sweden/Norway Electricity Certificate Scheme, 21 October 2015
Svenk Windenergi, What does the parliament decision October 21st mean?, November 2015, Available at: http://www.vindkraftsbranschen.se/wp-content/uploads/2015/11/Important-parliament-decision-on-the-TGC-system-20151110.pdf
Page 83 of 124 DOCUMENTING THE COST OF REGULATORY DELAYS, RE-DELAYS, March 2016 market, the largest interconnector capacity is with Sweden with an estimated 3,640 MW. Two 1,400 MW interconnector points will become operational between Norway and Germany in 2018 and Norway and the United Kingdom in 2020. By 2020, the country is expected to have a total interconnection capacity of 9,040 MW.159
Renewable Support Schemes for onshore wind and hydro
As already mentioned, Norway and Sweden have a joint electricity certificate scheme to support renewable generation. Generators of renewable energy receive certificates for their production. One MWh of electricity from renewable energy sources corresponds to one certificate for any technology considered. Both onshore wind and hydro are included in this scheme. Electricity suppliers, registered energy intensive companies, as well as users who produce, import or purchase electricity subsequently have to hold certificates corresponding to their sale and use of electricity during the previous calendar year. As the support mechanism will run until 31 December 2035 and an installation's eligibility cannot exceed 15 years, few new installations are expected for both technologies after 2020. However, the deadline for getting certificates is theoretically set at the end of 2021. Since the mechanism closes in 2035, new installations in 2021 will thus only receive 15 years minus the days in 2021. 160
In 2014 and 2015, the Norwegian and Swedish quota stood at respectively 14.2% and 14.3%. However, the increase to 28.4 TWh of joint production by 2020 (decision of the Swedish government on the 21 October 2015 to increase its target from 13.2 TWh to 15.2 TWh) will cause quota adjustments in 2016 and the following years. Moreover, existing targets were set 5 years ago and important differences have been noticed between the observed and forecasted figures. More specifically, electricity production has been higher than expected and the electricity consumption has been significantly lower (as noticed in many other European countries too). Therefore, there has been an oversupply of green certificates leading to decreasing prices and a problematic market situation since electricity market prices are decreasing as well. Figure 21 illustrates planned future quota increases. We know
159 Datamonitor Energy. Norway will export 32TWh of electricity by 2030, 1 August 2014, Available at: http://www.datamonitorenergy.com/2014/08/01/norway-will-export-32twh-of-electricity-by-2030/
OffshoreWIND.Biz, Norway-Denmark Interconnector Inaugurated, 22 March 2015, Available at: http://www.offshorewind.biz/2015/03/12/norway-denmark-interconnector-inaugurated/
National Grid. Interconnectors – Norway, Available at: http://www2.nationalgrid.com/About-us/European-business- development/Interconnectors/norway/
Government of Norway, License granted for electricity interconnectors to Germany and the UK, 13 October 2014, Available at: https://www.regjeringen.no/en/aktuelt/License-granted-for-electricity-interconnectors-to-Germany-and-the-UK/id2008232/
160 Bloomberg New Energy Finance, Sweden/Norway Electricity Certificate Scheme, 21 October 2015
The Norwegian Wind Energy Association (NORWEA)
Page 84 of 124 DOCUMENTING THE COST OF REGULATORY DELAYS, RE-DELAYS, March 2016 from the interviews that developers are hoping that these quota increases will increase the price of green certificates in the very near future.161
Figure 21: Quota increase on the green certificates market in Norway and Sweden
Adjustments –raised Adjustments -forecastingtarget Existing quota
Source: Svensk Vindenergi and Bloomberg New Energy Finance All quotas are regardless if capacity is installed in Sweden or Norway. Sweden can as such account for new installations in Norway, and the other way around.162
Administrative Processes
In Norway, the development process for large-scale hydro and onshore wind (larger than 10 MW) is similar. For both types of technologies, the licensing process is, according to NVE (the Norwegian energy regulator), supposed to take between 2 and 6 years.
In a first step, the developer has to work out a notification including a description of projects plans and conclusions about environmental reports related to the project. He also has to propose an Impact assessment (IA). All concerned parties are then allowed to make comments on the project and the
161 Norwegian Water Resources and Energy Directorate, Electricity Certificates, Available at: http://www.nve.no/en/Electricity- market/Electricity-certificates/
Energy and Water Resources in Norway, Norwegian Ministry of Petroleum and Energy Facts 2015, 2015, Available at: https://www.regjeringen.no/contentassets/fd89d9e2c39a4ac2b9c9a95bf156089a/facts_2015_energy_and_water_web.pdf
Bloomberg New Energy Finance, Sweden/Norway Electricity Certificate Scheme, 21 October 2015
Svenk Windenergi, What does the parliament decision October 21st mean?, November 2015, Available at: http://www.vindkraftsbranschen.se/wp-content/uploads/2015/11/Important-parliament-decision-on-the-TGC-system-20151110.pdf
Interviews with project developers
162 Svenk Windenergi, What does the parliament decision October 21st mean?, November 2015, Available at: http://www.vindkraftsbranschen.se/wp-content/uploads/2015/11/Important-parliament-decision-on-the-TGC-system-20151110.pdf
Page 85 of 124 DOCUMENTING THE COST OF REGULATORY DELAYS, RE-DELAYS, March 2016 proposed programme. In a next step, authorities and local people will study the plans and NVE will plan one or several meetings to provide all concerned parties with the necessary information.
There will subsequently be a 6-week hearing period (first consultation) and NVE will propose a final IA for the project itself and the associated grid connection, access roads, etc. The project developer has to hire external experts to carry out the IA. In a next step, the IA-reports are opened for a second consultation by NVE. At the end of this consultation, NVE will go on site to meet the local people, politicians and NGOs and evaluate the application.
Whereas NVE will subsequently take a license decision for onshore wind projects, NVE will only recommend a decision to the Ministry of Petroleum and Energy (OED), who will in the end take a decision for (large) hydro projects. The Ministry will involve ministries and municipalities and organise a last consultation (third consultation). It is crucial to highlight that environmental aspects have been dominating these applications in recent years.
All decisions by NVE with respect to the license for onshore wind can also be appealed to OED but the complainer must be affected by the project in some way or represent common interests. In such case, NVE will study complaints and send another recommendation to the OED who will take the final decision. The whole appeal process is, according to NVE, likely to take as long as 2 years. In this context, opponents to wind development are gaining strength in Norway and, in the NVE’s experience, almost all wind power licences are appealed today. However, many local authorities and communities embrace wind development for its promise of job creation and potential revenue. The northern areas are also sparsely populated and therefore less likely to encounter planning issues.163
In order to have access to the electricity certificates, the power station needs to be built before the end of 2021 and must be compliant with the relevant licensing terms. Also, the station needs to be registered in NVE and Statnett (TO) or the local/regional operator to get the certificates.164
Grid Access and Systems
In Norway, renewable energy sources do not have priority connection to the grid and the grid operator cannot discriminate against parties on the market. The grid operator is obliged to connect power generating plants to the grid. The electricity grid is divided into three levels: the distribution grid (≤
163 Norwegian Water Resources and Energy Directorate (NVE), Handling procedures, Available at: http://www.nve.no/en/Licensing/Handling-prosedures/
The Norwegian Wind Energy Association (NORWEA), Licensing for onshore wind projects, 2015
Nordvind. Wind Power in the Nordic Region, Conditions for the expansion of wind power in the Nordic countries, October 2011, Available at: http://www.nordvind.org/files/otherfiles/0000/0088/Vilk_rsnotat_ENG.pdf
164 Norwegian Water Resources and Energy Directorate (NVE), Electricity certificates, Available at: http://www.nve.no/en/Electricity- market/Electricity-certificates/
Statnett, Velkommen til NECS – Statnetts register for elsertifikater og opprinnelsesgarantier, 2015, Available at: http://necs.statnett.no/(S(zqkyuj45rm4x1j45rrut0j55))/default.aspx
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22kV), the regional grid (between 33kV and 132kV) and the central transmission grid (>132kV). New generators are required to liaise with Statnett (TO) or the relevant network company to secure a grid connection. There are 158 network companies; several have both distribution and regional grids. According to the Energy Act, generators must possess three licenses (construction, area and trading license), in order to connect and exchange electricity on the grid.165
The fee that project owners will have to pay highly varies from one project to another. Grid operators will have to invest in grid infrastructure or reinforcements so they will ask for an important contribution from the plant operator. In many regions in Norway, the transmission grid is poor, so reinforcements will often go together with important costs. Competition is also tough when grid capacity is available. Therefore, NVE is processing reinforcements and grid expansion plans for both regional and national networks. These expansions will help to significantly increase electricity export by 2030.166
5.6.5 Large-scale Onshore Wind Development According to Bloomberg New Energy Finance (2015), the installed onshore wind capacity in Norway was 847 MW at the end of 2014. The country has very good wind conditions (average capacity factor of 31%) and a high potential for wind development. In February 2015, the Norwegian Energy Association (NORWEA) declared that 6 to 8 TWh in new wind power can be added by 2020 thanks to tax amendments in 2015. However, the new installed capacity per year has been going down year by year between 2012 (almost 200 MW of new installed onshore wind) and 2014 (only 45 MW of new installed capacity). An important explanation for this low market activity is the low electricity price and the low green certificate market price.167
5.6.6 Large-scale Hydro Development In 2014, Norway, the leading hydro power generator in Europe, produced approximately 130 TWh of hydroelectricity, nearly 97% of the country’s total net electricity production. The energy source is anticipated to remain the primary source for the country’s electricity generation. By 2030, hydro power
165 Thomson Reuters Practical Law, Electricity regulation in Norway: overview, 2014
Nordvind, Wind Power in the Nordic Region. Conditions for the expansion of wind power in the Nordic countries, October 2011, Available at: http://www.nordvind.org/files/otherfiles/0000/0088/Vilk_rsnotat_ENG.pdf
Bloomberg New Energy Finance, Sweden/Norway Electricity Certificate Scheme, 21 October 2015
166 Thomson Reuters Practical Law, Electricity regulation in Norway: overview, 2014
Nordvind, Wind Power in the Nordic Region. Conditions for the expansion of wind power in the Nordic countries, October 2011, Available at: http://www.nordvind.org/files/otherfiles/0000/0088/Vilk_rsnotat_ENG.pdf
Bloomberg New Energy Finance, Sweden/Norway Electricity Certificate Scheme, 21 October 2015
167 Bloomberg New Energy Finance, Overall Supply Mix Norway, 2014.
IEA Wind, 2014 Annual Report, August 2015, Available at: https://www.ieawind.org/annual_reports_PDF/2014/2014%20AR_smallfile.pdf
Reuters, Sweden dwarfs Norway in new wind power, but not for long, 18 February 2015, Available at: http://www.reuters.com/article/2015/02/18/norway-windpower-idUSL5N0VR2Q520150218
Page 87 of 124 DOCUMENTING THE COST OF REGULATORY DELAYS, RE-DELAYS, March 2016 generation, partly driven by export objectives, will reach 160 TWh and forecasts take into account an additional 2.8 GW of new hydro power coming online in the next 16 years. Nevertheless, low and continuously decreasing prices are equally an important threat for hydro developments. 168
5.6.7 Insights from developers All developers confirmed that low prices and related market uncertainties are the most important bottlenecks with respect to onshore wind and hydro development. The Green Certificate Scheme is highly political and it is thus difficult to know what to expect from it. Another major issue is that there are no clear timelines for license decisions.
Since developers often have to pay for grid infrastructure and reinforcements, grid costs will also be significant for some projects. Some developers have been selecting sites without paying enough attention to grid availability over the last few years. Most of the issues are related to the transmission grid and not to the distribution grid. Also, development has been further slowed down because of appeal processes with respect to infrastructure projects carried out by grid operators. However, other project developers argued that grid-related issues are not very common since they know about the investment plans of grid operators who are obliged to accept developers if there is grid availability. In theory you cannot contract an agreement with the grid operator if you don’t have the license, but it is very unlikely that the grid operator would give permission to another development starting later in time. Strong contacts with grid operators will thus be important and it is important for developers to know what is happening around them.
Insights for large onshore wind developments
With respect to support for onshore wind, the government abolished investment subsidies in 2009 and only introduced the electricity certificates in 2012. This led to project delays of up to 2 years for some developments.
Another crucial insight is that there are no clear timelines for license decisions by NVE. In some cases, it is very difficult to plan projects and the focus of NVE is very unpredictable. One developer mentioned a permit application that was sent in 2007 for which the decision was taken 6.5 years later, while other developers mentioned maximum timelines of around 5 years. Since the scheme will close in 2021, many project developers want to apply for permits as soon as possible, which slows down the process even more. Nevertheless, it was also mentioned that NVE recently has been speeding up the decision process and one developer declared that a clear and continuous communication with NVE and all other concerned parties can significantly decrease the response time. Furthermore, response time will
168 Bloomberg New Energy Finance, Overall Supply Mix Norway, 2014.
Datamonitor, Norway will export 32TWh of electricity by 2030, 1 August 201, Available at: http://www.datamonitorenergy.com/2014/08/01/norway-will-export-32twh-of-electricity-by-2030/
Norwegian Ministry of petroleum and Energy (NCE), 2015, Energy and water resources in Norway, December 2014, Available at: https://www.regjeringen.no/contentassets/fd89d9e2c39a4ac2b9c9a95bf156089a/facts_2015_energy_and_water_web.pdf
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Project decisions are furthermore regularly appealed. All interviewed developers mentioned that appeals occur for all projects on the Norwegian onshore wind market. This is not an expensive process because NVE has to take this up with OED, so lawyers are not involved, but it is another time- consuming process. It was mentioned several times that, while delays were mainly because of license decisions before, these delays are more and more because of appeal decisions by OED.
Another insight is that, according to some developers, minimum 3,200 full load hours are necessary to make a project profitable. Competition amongst turbine manufacturers is increased since few new projects are being built in recent months, which pushes them to decrease their prices to sell more volumes. Besides, Chinese manufacturers, who have a big domestic market, want to come to Europe and compete with European players such as Siemens and Vestas.
Finally, the interviews identified that project developers active in Norway collaborate a lot with external consultants and do less work internally. External professionals often have very good contacts with grid operators and better understand the requirements of the grid application.
Insights for large hydro developments
From developers of both onshore wind and hydro, we know that large-scale hydro is given priority over small-scale hydro and onshore wind. The reason for this is that large-scale hydro plants are sometimes very economical and can be operational between 50 and 100 years. As for onshore wind, it is very unpredictable when the OED, who will mostly follow NVE’s recommendation, will take a decision and it could take up to several years. Project appeals do not occur for large-scale hydro because license decisions are taken from the beginning at a higher political level.
We also identified that large-scale hydro projects in Norway are both new projects and project extensions. This is partly because most of the hydro potential has already been exploited and there are few new locations for large-scale development available.
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5 . 7 UNITED KINGDOM
5.7.1 State of the economy Having shown strong economic figures in 2014, UK growth is expected to be sustained at a similar pace in 2015 and 2016. For the year 2015, these expectations are likely to be maintained because GDP rose by 0.7% in Q2/2015 to bring Britain back to the economic peak it last saw in 2008 before the crash. The main drivers are oil and gas extraction, domestic demand, increasing house prices and a relatively low unemployment rate of around 5.5%.
However, the UK economy slightly slowed down in Q3/2015 because of weak construction and manufacturing, but economists remain confident that the country will sustain growth in the latter part of the year. 169
Source: The Economist Intelligence Unit The UK government has been focusing on expenditure cuts since 2010, resulting in a falling budget deficit of 5.3% of GDP (10.8% in 2009-2010) in 2014-2015 and this deficit is expected to continue to fall in 2016-2017. However, gross government debt continues to increase (89% of GDP in 2014-2015) and is expected to reach 90.5% of GDP in 2016-2017.
Investments into the country were at their lowest point in 2009 and have been steadily increasing over the period 2009-2014. Nevertheless, business investments dropped by 1.4% in Q4-2014, mainly driven by falling gas and oil prices. This reflects the cancellation of plans in the oil sector. In this context, the government argues that, in order to secure a secure a sustainable future, the government should rely less on debt-fuelled consumer spending and a move towards more manufacturing and exports.
169 European Commission, European Economy: Macroeconomic Imbalances Country Report – United Kingdom 2015, 2015, Available at: http://ec.europa.eu/economy_finance/publications/occasional_paper/2015/pdf/ocp227_en.pdf
OECD, United Kingdom – Economic Forecast Summary – June 2015, 2015, Available at: http://www.oecd.org/economy/united-kingdom- economic-forecast-summary.htm,
UK business insider, YES! Britain's economy is officially back at the peak it last saw in 2008, 2 July 2015, Available at: http://uk.businessinsider.com/uk-gdp-growth-q2-2015-2015-7July
The Economist Intelligence Unit, United Kingdom, 2015, Available at: http://country.eiu.com/United Kingdom http://www.ft.com/intl/cms/s/0/9430244e-7c8d-11e5-98fb-5a6d4728f74e.html#axzz3qKhcfSeN
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Another interesting insight is that the trade balance has been more or less stable in recent years but the total trade deficit widened to GBP (British Pound) 34.8 billion in 2014, the largest yearly deficit since 2010 when the deficit stood at GBP 37.1 billion. Both exports and imports fell but the deficit can mainly be attributed to a decreased export of goods. In August 2015, export reached the lowest level since September 2010 and the trade deficit of July 2015 and August 2015 together was already double the deficit for the whole quarter Q2/2015. Export prospects in the near future are expected to be hurt by the appreciation of the GBP. 170
Economic Indices Figure (Year)
Population 64.51 million (2014)
GDP USD 2,942 billion (2014)
GDP per Capita USD 45,604 (2014)
Key industries Chemicals and pharma, transport, electronics and electrical, machinery, food, drinks and tobacco, rubber, plastics and non-metallics, metals, wood, paper and printing, textiles
Table 12: Key economic facts on the United Kingdom171
Source: World Trade Organization (WTO) and The Manufacturers’ organisation (EEF)
170 Office for National Statistics, UK Trade, December 2014, Available at: http://www.ons.gov.uk/ons/dcp171778_391926.pdf
Office for National Statistics, Summary: UK Trade, August 2015, 9 October 2015, Available at: http://www.ons.gov.uk/ons/dcp171780_419373.pdf
Government of the United Kingdom, Growth Dashboard, 22 January 2014, Available at: https://www.gov.uk/government/uploads/system/uploads/attachment_data/file/396740/bis-15-4-growth-dashboard.pdf
European Central Bank, Exchange rate UK pound sterling/EUR, Available at: http://sdw.ecb.europa.eu/quickview.do?SERIES_KEY=120.EXR.D.GBP.EUR.SP00.A
Euler Hermes, UK Export prospects hurt by sterling appreciation, 9 September 2015, Available at: http://www.eulerhermes.co.uk/euler- hermes-UK-and Ireland/mediacenter/news/Lists/NewsDocuments/UK%20export%20prospects%20hurt%20by%20sterling%20appreciation.pdf
The manufacturers’ organisation, UK manufacturers provide a strong foundation for growth in the UK, Available at: http://www.eef.org.uk/campaigning/campaigns-and-issues/manufacturing-facts-and-figures
171 World Trade Organization, United Kingdom, Available at: http://stat.wto.org/CountryProfile/WSDBCountryPFView.aspx?Country=GB&Language=S
The manufacturers’ organisation, UK manufacturers provide a strong foundation for growth in the UK, Available at: http://www.eef.org.uk/campaigning/campaigns-and-issues/manufacturing-facts-and-figures
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5.7.2 Labour Market The UK has approximately 41 million people aged between 16 and 64 and the population older than 16 is expected to increase from 51.7 million in 2012 to 55.4 million in 2022. With an employment rate of 71.9% in the age group 15-64, that has been growing since 2011, the country had among the highest employment rates in the European Union in 2014. Only Denmark, Germany, The Netherlands and Sweden did better.172
However, a recent study from CV-Library, the UK’s largest job site, has revealed that the majority of recruitment professionals are still struggling to find the right candidates and that engineering jobs and jobs in the commodities and energy sector are the most difficult to fill. Another survey carried out by Hays and CIPD amongst 520 UK-based HR professionals reveals that managers, specialist and technical staff are the most difficult to find mainly because of a lack of specialist skills and industry and general experience.173
According to Energy for Sustainable Development (ESD) and Greenpeace UK, the United Kingdom is after Germany one of the most important markets for offshore wind and has the potential to employ between 25,000 and 75,000 people in the sector by 2020. The majority of the workforce would be employed in manufacturing and installation while another smaller part would work on operations and maintenance. With respect to onshore wind, the new UK government, elected in May 2015, is cutting a lot of support for onshore wind and a lot of jobs are thus threatened in this market segment.174
172 Nomis- Official labour market statistics, Labour Market Profile – Great Britain, Available at: https://www.nomisweb.co.uk/reports/lmp/gor/2092957698/report.aspx
UK Commission for employment and skills, Government of the United Kingdom, Working futures 2012-2022, Evidence Report 83, March 2014, Available at: https://www.gov.uk/government/uploads/system/uploads/attachment_data/file/298510/working-futures-2012-2022- main-report.pdf
Eurostat, Available at: http://ec.europa.eu/eurostat/statistics- explained/images/6/66/Employment_rate%2C_age_group_15%E2%80%9364%2C_2004%E2%80%9314_%28%25%29_YB16.png
173 HR Grapevine, UK recruiters reveal the most challenging roles to fill, 29 October 2015, Available at: http://www.hrgrapevine.com/markets/hr/article/2015-10-29-uk-recruiters-reveal-the-most-challenging-roles-to-fill
CIPD in partnership with Hays, Resourcing and Talent Planning 2015, survey report, June 2015, Available at: http://www.cipd.co.uk/binaries/resourcing-talent-planning_2015.pdf
174 Energy for Sustainable Development (ESD) Ltd for Greenpeace UK, Offshore wind onshore jobs – A New Industry for Britain, October 2014, Available at: http://www.greenpeace.org.uk/MultimediaFiles/Live/FullReport/6702.pdf
IRENA, Renewable Energy and Jobs. Annual review 2015, 2015, Available at: http://www.irena.org/DocumentDownloads/Publications/IRENA_RE_Jobs_Annual_Review_2015.pdf
The Economist Intelligence Unit, United Kingdom, 2015, Available at: http://country.eiu.com/United Kingdom
The Guardia, The nine green policies killed off by the Tory government, July 24, Available at: http://www.theguardian.com/environment/2015/jul/24/the-9-green-policies-killed-off-by-tory-government
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5.7.3 Capital Markets and Access to Project Financing Current state of project financing
According to Bloomberg New Energy Finance, the United Kingdom ranked number four in the world in 2014 for volumes of renewable energy transactions, totalling USD 30.5 billion. The top ten renewable energy lenders investing in the United Kingdom are the European Investment Bank, Mitsubishi UFJ Financial Group Inc., Royal Bank of Scotland Group PLC, Lloyds Banking Group PLC, Norddeutsche Landesbank Girozentrale, HSBC Holdings PLC, BNP Paribas SA, Mizuho Financial Group Inc., Green Investment Bank Ltd, and Barclays PLC. For this case study of the United Kingdom, we are considering both onshore and offshore wind project development. 175
However, the new Tory government, elected in 2015, took the decision to close the Renewable Obligation (RO) subsidy scheme for onshore wind one year earlier than expected in March 2016 instead of March 2017. This will prevent hundreds of turbines being built under the scheme and many projects will be cancelled. The Department of Energy and Climate Change (DECC) stated in May 2015 that there is enough onshore wind capacity already to contribute what’s needed to reach the UK’s ambitions for 2020. However, it remains to be seen whether a sufficient proportion of this capacity will be built out in the next few years to meet the Government’s target of 12-13 GW of onshore wind capacity by 2020. It is also uncertain as to whether onshore wind will be included in future auction rounds of the Contract-for-Difference (CFD). These policy changes have negatively impacted the UK investment climate and we know from our interviews with project developers that some financial institutions are postponing investment in future onshore wind projects. Developers are thus cancelling or delaying projects or financing project development from their own balance sheets. The uncertainty is also illustrated by the recent news that the company Drax has quit a large-scale carbon-capture project, citing government reversals of green policies and future policy risk as reasons for their decision. Further proof that the UK is losing its reputation for a strong and stable policy environment is the fact that the country recently lost its triple-A rating from the World Energy Council. 176
With respect to offshore wind, the United Kingdom still has ambitious targets as illustrated by the recently announced developments by Dong Energy and RWE. The UK is expected to deliver a further
175 Bloomberg New Energy Finance, Country Profile – United Kingdom, 2015
176 Department of Energy & Climate Change (DECC), Statement on ending subsidies for onshore wind, 22 June 2015, Available at: https://www.gov.uk/government/speeches/statement-on-ending-subsidies-for-onshore-wind Department of Energy & Climate Change (DECC), Controlling the cost of renewable energy, 22 July 2015, Available at: https://www.gov.uk/government/news/controlling-the-cost-of-renewable-energy Telegraph, Wind farm subsidies faxing the axe, 31 May 2015, Available at: http://www.telegraph.co.uk/news/earth/energy/renewableenergy/11641088/Wind-farm-subsidies-facing-the-axe.html The Financial Times, UK energy policy under fire as Drax quits carbon-capture project, 24 September 2015 Government of the United Kingdom, New direction for UK energy policy, 18 November 2015, Available at: https://www.gov.uk/government/news/new-direction-for-uk-energy-policy Business green, Government confirms it will halt onshore wind subsidy scheme a year early, 18 June 2015, Available at: http://www.businessgreen.com/bg/news/2413731/government-confirms-it-will-halt-onshore-wind-subsidy-scheme-a-year-early BBC news, UK energy policy ‘deters investors’, 11 November 201,. Available at: http://www.bbc.com/news/business-34786128 World Energy Council, Energy Trilemma Index,d Available at: https://www.worldenergy.org/data/trilemma-index/
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5 GW by 2020 and has the potential to deliver a lot more additional capacity. Dong Energy secured financing to build the world’s biggest offshore wind farm in UK waters on 28 October 2015. This 660 MW project in the Irish Sea has an estimated cost of around USD 3.1 billion and will generate energy for around 460,000 UK homes. RWE secured financing for a USD 2.3 billion project of 336 MW. The project, announced on 30 October 2015, will be financed by a group of 12 commercial banks and the European Investment Bank. However, while the RO will remain open as planned until March 2017 for offshore wind, policy and investment uncertainty is also increasing since it was not clear at all when the next results of the CFD auction will be published. On 18 November 2015, Energy and Climate Change Secretary Amber Rudd announced that the government plans to make funding available for three offshore wind auctions and to hold the first of these auctions by the end of 2016. It is important to emphasize that the government will only be committed to offshore wind support on the condition that it comes down in cost.177
Supra-national and national banks
As in France, supra-national financial institutions including the European Investment Bank and the European Bank for Reconstruction and Development are active in the UK. In 2012 the British Government also created the Green Investment Bank, a bank that was initially established with the UK government as its sole shareholder. It was capitalised with an initial GBP 3.8 billion of public funds to back green projects on commercial terms and mobilise other private sector capital into the UK’s green economy. The business model of the bank initially only allowed it to invest in UK-based green infrastructure projects and focuses primarily on energy efficiency, waste and bioenergy and offshore wind. However, following announcements by the Business Secretary in June, the Green Investment Bank is now due to be part-privatised and this focus may change.178
Commercial banks and investors
Although the European Investment Bank invests significantly more in renewable energy projects than all other actors (period 2005-2015), a lot of commercial banks from various countries were also
177 RenewableUK and GROW: Offshore wind, Offshore Wind Project Intelligence, October 2015
Department of Energy & Climate Change (DECC), Controlling the cost of renewable energy, 22 July 2015, Available at: https://www.gov.uk/government/news/controlling-the-cost-of-renewable-energy
Bloomberg New Energy Finance, Dong Build World’s Biggest Offshore Wind Farm in U.K. Waters, October 2015
Bloomberg New Energy Finance, RWE Finds New Partners for $2.3 Billion U.K. Offshore Wind Farm, October 2015
Government of the United Kingdom, New direction for UK energy policy, 18 November 2015, Available at: https://www.gov.uk/government/news/new-direction-for-uk-energy-policy
178 Deutsche Bank, Green infrastructure and business financing and advising, 2015, Available at: https://www.db.com/cr/en/concrete- sustainable-large-scale-projects.htm http://www.greeninvestmentbank.com/about-us/
Page 94 of 124 DOCUMENTING THE COST OF REGULATORY DELAYS, RE-DELAYS, March 2016 financing. The most important companies providing financial resources for the period 2005-2013 came from the United Kingdom, Japan, France and Germany.179
Tax exemptions, tax credits and low interest loans
The United Kingdom adopted a Climate Change Levy (CCL), a tax on energy delivered to non-domestic users, in 2001. The tax was not to be paid on renewable electricity supplied to businesses and the public sector under renewable source contracts to support renewables and reduce greenhouse gas emissions. However, since July 2015, the CCL exemption has been removed for electricity generated from renewable sources. Given that one of the primary objectives of the UK government is to meet climate change objectives in a cost effective way, this move has resulted in much criticism both within and outside the renewables industry. As reason for its decision, the Government cited the fact that some of those receiving CCL exemption were located in other countries receiving domestic support and were therefore not contributing to the UK’s renewable energy targets. 180
While the UK government announced a Carbon Price Floor (CPF) in April 2013, which was designed to provide an additional incentive (above the ETS) to invest in low-carbon power generation by providing greater support and certainty to the carbon price in the UK’s electricity generation sector 181, this policy too has changed. In March 2014 the carbon floor price was subsequently frozen at 2015 levels (GBP 18.08 per tonne) by Chancellor George Osbourne, with a view to maintaining the floor price at this level until the end of the decade. Environmental groups argue that this decision to freeze the carbon floor price indicates that the UK government is no longer committed to tackling climate change.182
5.7.4 Preparedness of the Regulatory Environment for Renewable Energy Projects Electricity Supply Mix and Renewable Targets
The United Kingdom is the European Union’s ninth largest producer of renewable energy (2013). In 2013, power generation from renewable sources represented 13.9% of the United Kingdom’s electricity production. Under the provisions of Directive 2009/28/EU of 23 April 2009 (the Renewable
179 Bloomberg New Energy Finance, Country Profile – United Kingdom, 2015
180 Government of the United Kingdom, HM Revenue & Customs. Climate Change Levy: removal of exemption for electricity from renewable sources, 8 July 2015, Available at: https://www.gov.uk/government/publications/climate-change-levy-removal-of-exemption- for-electricity-from-renewable-sources/climate-change-levy-removal-of-exemption-for-electricity-from-renewable-sources
Government of the United Kingdom, Environmental taxes, reliefs and schemes for businesses, 2 October 2015, Available at: https://www.gov.uk/green-taxes-and-reliefs/climate-change-levy
RenewableUK
181 Government of the United Kingdom, HM Revenue & Customs. Carbon price floor, Available at: https://www.gov.uk/government/uploads/system/uploads/attachment_data/file/179259/carbon_price_floor.pdf.pdf The Scottish Government. UK Carbon Price Floor and Carbon Price Support Mechanism, Available at: http://www.gov.scot/Topics/Environment/climatechange/ukandeuclimatechange/Carbon-Price-Floor 182 Available at: http://uk.reuters.com/article/2014/03/19/uk-britain-budget-carbon-idUKLNEA2I02620140319
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Energy Directive), 15% of the United Kingdom’s final energy consumption and 30% of the electricity must be generated from renewables by 2020.183
Figure 22: Supply mix in the United Kingdom (2014)
Source: Bloomberg New Energy Finance
Although the UK government is planning to build a nuclear plant with a capacity of 3,260 MW to power 6 million households in Somerset (Hinkley Point C), it is likely that there will remain significant potential for renewable energy sources because one fifth of existing UK generation capacity is set to close in the next decade. In this framework, it is very likely that support will mainly be focused on offshore wind as mentioned previously.184
Renewable Support Schemes for onshore and offshore wind
Since Q4/2014, Contracts-for-Difference (CFD) replaced the Renewables Obligation (RO) as the UK’s main support scheme. However, generators can still choose between CFD and RO until 1 April 2017.
Renewable Obligations Certificates (ROCs) within the RO system are issued to renewable energy projects for each MWh of electricity generated over a 20 year period.
183 European Commission, Renewable Energy Statistics, 2015, Available at: http://ec.europa.eu/eurostat/statistics- explained/index.php/Renewable_energy_statistics
Eurostat Newsrelease, Share of renewables in energy consumption up to 15% in the EU in 2013, 10 March 2015, Available at: http://ec.europa.eu/eurostat/documents/2995521/6734513/8-10032015-AP-EN.pdf/3a8c018d-3d9f-4f1d-95ad-832ed3a20a6b
Ofgem, Offshore Transmission, Available at: https://www.ofgem.gov.uk/electricity/transmission-networks/offshore-transmission
184 EDF, Hinkley Point C: facts and figures, Available at: http://press.edf.com/fichiers/fckeditor/Commun/Presse/Communiques/EDF/2013/EDF_HinkleyPointC_va.pdf EDF, Hinkley Point C, Securing the UK’s energy future, Available at: http://www.edfenergy.com/energy/nuclear-new-build-projects/hinkley- point-c
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Figure 23 illustrates how many certificates renewable energy generators currently receive for each MWh of electricity produced. The price of a green certificate is around GBP 42/ROC but prices might further decrease because of oversupply in the market. Electricity suppliers are subsequently obliged to submit a certain number of these certificates for each MWh of electricity they supply to customers. For the 2014-2015 CP13 compliance year, the obligation level was 0.244 ROCs/MWh supplied. If suppliers don’t present enough ROCs, they must pay an equivalent amount into a buyout fund at a buyout price. On 1 April 2017, the RO will be grandfathered for existing accredited projects until it ceases to operate in 2037 (the last projects that come in in 2017 will receive support for 20 years).185
Figure 23: ROC/MWH for different technologies under the RO 186
With CFDs, the existing main support scheme, eligible generators receive a top-up payment, lasting 15 years, when the wholesale electricity price (WEP) falls below a defined strike price. When the wholesale price goes above the strike price, generators pay money back. These strike prices are determined through auctions. One of the main advantages of this mechanism is that it ensures stability of prices for eligible generators. The first CFD allocation round results for 2015 were published on 26 February 2015. Strike prices for onshore wind were between GBP 80/MWh and GBP 82.5/MWh while strike prices for offshore wind were between GBP 114/MWh and GBP 120/MWh.187
While the RO will close to all new projects in March 2017, the Energy Bill 2015-2016 (9 July 2015) will end ROC support for onshore wind one year earlier. Only projects that had a planning consent, an
185 Government of the United Kingdom, RO banding levels, 2013, Available at: https://www.gov.uk/government/uploads/system/uploads/attachment_data/file/211292/ro_banding_levels_2013_17.pdf
Department of Energy & Climate Change, Policy paper, 2010 to 2015 government policy: low carbon technologies, 8 May 2015, Available at: https://www.gov.uk/government/publications/2010-to-2015-government-policy-low-carbon-technologies/2010-to-2015-government- policy-low-carbon-technologies
Bloomberg New Energy Finance, UK Renewables Obligation.
Platts, UK Green certificate monthly auction price dips to GBP 42.45/ROC: NFPA, 24 April 2015, Available at: http://www.platts.com/latest- news/electric-power/london/uk-green-certificate-monthly-auction-price-dips-26073065
186 Government of the United Kingdom, RO banding levels, 2013, Available at: https://www.gov.uk/government/uploads/system/uploads/attachment_data/file/211292/ro_banding_levels_2013_17.pdf
187 Bloomberg New Energy Finance (BNEF), UK EMR – Contract For Difference (CFD)
Page 97 of 124 DOCUMENTING THE COST OF REGULATORY DELAYS, RE-DELAYS, March 2016 accepted grid connection offer and evidence of land rights on or before 18 June 2015 will be eligible for the grace period provisions which are being finalised through the Energy Bill. Projects that do not qualify for grace period provisions will need to become operational before April 2016, in order to receive RO support. As mentioned above, the UK government is arguing that there is already enough onshore wind in the pipeline to reach the 2020 targets and there is current uncertainty as to whether the onshore wind sector will be able to participate in future CFD auctions.188
For offshore wind projects, the RO support scheme will only close as planned at the end of March 2017 when the recently introduced CFD will permanently replace it. As figure 12 illustrates, support for offshore wind under the RO is double the support of onshore wind. Nevertheless, uncertainty regarding future auction rounds remained until 18 November 2015, when the next results of the CFD auction were going to be published (these results were initially going to be published in October 2015). On this day, Energy and Climate Change Secretary Amber Rudd announced that the government plans to make funding available for three future offshore auctions and to hold the first of these auctions by the end of 2016. It is nonetheless important to emphasize that the government will only be committed to offshore wind support on the condition that it comes down in cost. 189
188 Department of Energy & Climate Change (DECC), Statement on ending subsidies for onshore wind, 22 June 2015, Available at: https://www.gov.uk/government/speeches/statement-on-ending-subsidies-for-onshore-wind
Department of Energy & Climate Change (DECC), Controlling the cost of renewable energy, 22 July 2015, Available at: https://www.gov.uk/government/news/controlling-the-cost-of-renewable-energy
Government of the United Kingdom, New direction for UK energy policy, 18 November 2015, Available at: https://www.gov.uk/government/news/new-direction-for-uk-energy-policy
LCP and Frontier Economics, What next for UK auctions of renewable Contracts for Difference?, March 2015, Available at: http://www.frontier-economics.com/documents/2015/03/lcp-frontier-economics-next-uk-auctions-renewable-contracts-difference.pdf
Parliament of the United Kingdom, Onshore wind subsidies, 18 June 2015, Available at: http://www.publications.parliament.uk/pa/cm201516/cmhansrd/cm150618/wmstext/150618m0001.htm
189 UK Trade & Investment, UK Offshore Wind: Opportunities for trade and investment, December 2014, Available at: http://www.greeninvestmentbank.com/media/44638/osw-pitchbook_dec-2014.pdf
Government of the United Kingdom, Contracts for Difference (CFD) Allocation Round One Outcome, 26 February 2015, Available at: https://www.gov.uk/government/uploads/system/uploads/attachment_data/file/407059/Contracts_for_Difference_-_Auction_Results_- _Official_Statistics.pdf
LCP and Frontier Economics, What next for UK auctions of renewable Contracts for Difference?, March 2015, Available at: http://www.frontier-economics.com/documents/2015/03/lcp-frontier-economics-next-uk-auctions-renewable-contracts-difference.pdf
Edp Renovaveis, Offshore Wind in the UK. January 2010
Government of the United Kingdom, New direction for UK energy policy, 18 November 2015, Available at: https://www.gov.uk/government/news/new-direction-for-uk-energy-policy
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Finally, it is important to emphasize that, when spread over a 20 year period, the auction results of the CFD are about 10% lower than today’s ROC.190
Administrative Processes
In this section we will mainly be focusing on England and Scotland since these are by far the most important markets in the United Kingdom with respect to wind energy.
A first important point is that the planning and administrative processes in England and Scotland differ, depending on the size and location of the proposed development. Onshore wind farms in England that have an installed capacity of over 50MW and all offshore wind farms off the coast of England and Wales are determined by the Department of Energy and Climate Change (DECC), under the Planning Act 2008. In Scotland, onshore projects above 50MW and offshore wind projects less than 12 nautical miles off the Scottish coast are decided by the Scottish Government, under the 1989 Electricity Act.191
Across England and Scotland, onshore wind farms under 50MW are determined by the relevant local planning authority, which is expected to decide applications within 12-16 weeks, under the Town and Country Planning Acts. In England, the Government changed planning requirements for such projects in June 2015, placing greater emphasis on the importance of local support for projects and their location. When determining planning applications, local authorities should now only consent a project if it is proven that the planning impacts on local communities have been fully addressed and that the application is thus supported by local communities. In addition, the location has to be identified in a Local or Neighbourhood Plan as suitable for wind energy development.192
Further changes to the planning system are also in train as the Government proposes to place decision- making for all onshore wind projects in England (including those above 50MW in capacity) under the
190 NDA information
191 House of Commons, Planning for onshore wind. Number 04370, 29 June 2015, Available at: http://researchbriefings.files.parliament.uk/documents/SN04370/SN04370.pdf
RWE, Onshore Wind Development Process, Available at: http://www.rwe.com/web/cms/en/1117192/rwe-innogy/about-rwe-innogy/rwe- innogy-uk/useful-information/development-process/
RenewableUK
192 House of Commons, Planning for onshore wind. Number 04370, 29 June 2015, Available at: http://researchbriefings.files.parliament.uk/documents/SN04370/SN04370.pdf
Government of the United Kingdom, Offshore wind: part of the UK’s energy mix, 1 August 2013, Available at: https://www.gov.uk/guidance/offshore-wind-part-of-the-uks-energy-mix
The Guardian, Government will step in if councils don't fast-track fracking applications, 13 August 2015, Available at: http://www.theguardian.com/environment/2015/aug/13/government-will-step-in-if-councils-dont-fast-track-fracking-applications
RWE, Onshore Wind Development Process, Available at: http://www.rwe.com/web/cms/en/1117192/rwe-innogy/about-rwe-innogy/rwe- innogy-uk/useful-information/development-process/
RenewableUK
Page 99 of 124 DOCUMENTING THE COST OF REGULATORY DELAYS, RE-DELAYS, March 2016 remit of local planning authorities. This proposal, contained within the current Energy Bill, is intended to give local communities greater say over development that takes place in their area.193
Across the UK, an Environmental Impact Assessment (EIA) will be required prior to the determination of a planning application (or prior to submitting a Development Consent Order in the case of Planning Act 2008 projects) for the majority of onshore wind power projects and all offshore wind farms. An EIA will be used to identify the relevant environmental, social and economic effects of the project and assess their significance (e.g. construction, landscape and visual impacts, noise, etc.).194
In all cases, a developer is allowed to appeal a decision. This is getting more important because six in ten UK onshore wind farms were rejected in 2014. The appeal bodies, reporting directly to national governments in England and Scotland, may request written or informal representation, or it may decide to open a public inquiry. The latter option is often taken for more controversial or complicated wind farm proposals. Furthermore, the Secretary of State in England, and the Scottish Government in Scotland have the power to call in planning applications for their own determination. This is happening more and more as illustrated by the fact that Erick Pickles, Secretary of State for Communities and Local Government in England between 2010 and 2015, intervened in at least 50 onshore wind projects between spring 2013 and in autumn 2014, only approving two of the 19 on which he made a decision. One of the important issues, also mentioned several times by developers and industry association, is that the Secretary of State for Communities does not have to take a decision within a specified time frame when he calls in projects.195
Finally, as mentioned earlier, in order to be eligible for the RO, all projects need a planning permission or development consent, an accepted grid connection offer and evidence of land rights for the site on which projects will be built (in case of an onshore wind project). For the CFD, developers need a planning permission or development consent and a grid connection offer accepted. The evidence of
193 RenewableUK
194 Environmental Impact Assessment for Wind farms, Available at: http://gse.cat.org.uk/downloads/Environmental_Impact_Assessment_Consenting_Process_Windfarms.pdf
Interviews with developers
195 Telegraph, Wind farm subsidy ban may not apply in Scotland, 27 May 2015, Available at: http://www.telegraph.co.uk/news/politics/queens-speech/11633005/Wind-farm-subsidy-ban-may-not-apply-in-Scotland.html
The Guardian, Six in 10 UK onshore windfarms rejected, January 2015, Available at: http://www.theguardian.com/environment/2015/jan/21/six-in-10-uk-onshore-wind-farms-rejected-report
Planning resource United Kingdom, DCLG clarifies position on onshore wind appeals, 24 June 2015, Available at: http://www.planningresource.co.uk/article/1353228/dclg-clarifies-position-onshore-wind-appeals
House of Commons, Planning for onshore wind. Number 04370, 29 June 2015, Available at: http://researchbriefings.files.parliament.uk/documents/SN04370/SN04370.pdf
RWE, Onshore Wind Development Process, Available at: http://www.rwe.com/web/cms/en/1117192/rwe-innogy/about-rwe-innogy/rwe- innogy-uk/useful-information/development-process/
Page 100 of 124 DOCUMENTING THE COST OF REGULATORY DELAYS, RE-DELAYS, March 2016 land rights can sometimes be complicated, especially in cases when a number of parties and complicated legal processes related to land agreements are involved.196
Grid Access and Systems
In this section we will mainly be focusing on England and Scotland since these are by far the most important markets in the United Kingdom with respect to wind energy.
In the United Kingdom, renewable energy sources have no priority on the grid. Grid operators are obliged to connect entities which are located in areas of planned grid development so they cannot discriminate against certain plant operators. All projects have to secure a grid connection through the relevant Transmission Operator (TO) or the regional Distribution Network Operator (DNO). While National Grid Electricity Transmission plc (NGET) owns the transmission grid in England, Scottish Power Transmission Limited and Scottish Hydro Electric Transmission plc are operating the TO in respectively Southern Scotland and Northern Scotland. The applicant should receive and/or accept a formal offer of grid connection from the relevant network operator at the time of application. Otherwise, the developers will face a risk since it is not certain that there will be availability on the grid by the time they commission the project.197
Connection costs are charged by the grid operator to the wind plant operator and charges are calculated and applied as set out in the relevant bilateral connection agreement. These network costs mainly consist of the costs for work and equipment used to make the connection and the cost of reinforcement and O&M. In 2010, the European Wind Energy Association (EWEA) published that the average grid access lead time in the United Kingdom (8.26 months) was significantly lower than in the EU 27 (25.83 months for onshore wind and 14.06 months for offshore wind). Also, grid connection costs were found to be around 5% of total project costs in line with the European average.198
196 Government of the United Kingdom, Statement on ending subsidies for onshore wind, 22 June 2015, Available at: https://www.gov.uk/government/speeches/statement-on-ending-subsidies-for-onshore-wind
RenewableUK
Pinsent Masons, Consenting with Contracts For Difference – A Guide for Developer, Investors and Funders, March 2015, Available at: http://www.pinsentmasons.com/PDF/Consenting-with-Contracts-for-Difference.pdf
Interviews with RenewableUK
197 IRENA, United Kingdom (including Scotland), Available at: https://www.irena.org/DocumentDownloads/Publications/GWEC_UK.pdf
Ofgem, The GB electricity transmission network, Available at: https://www.ofgem.gov.uk/electricity/transmission-networks/gb-electricity- transmission-network
198 Cornwall Energy, Overcoming grid connection issues for community energy projects for Co-operatives UK and The Co-operative Group, 3 October 2013, Available at: http://www.localenergyscotland.org/media/33075/Cornwall-Energy-report_Overcoming-grid-connection- issues-for-community-energy.pdf
Wind Barriers, Administrative and grid access barriers to wind power, July 2010, Available at: http://www.windbarriers.eu/fileadmin/WB_docs/documents/WindBarriers_report.pdf
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However, grid costs for onshore wind projects highly depend on the availability of capacity and, according to developers, this capacity has been significantly decreasing in recent years and delays are thus increasing. Cornwall Energy demonstrates how grid costs can substantially vary between different projects. The company published cost ranges going from a total of GBP 150,000/MW to almost GBP 7.4 million/MW.199
With respect to offshore projects, grid infrastructure will logically play an even bigger role. In order to further boost investments in infrastructure projects, the government has established the competitive offshore transmission regulatory regime, a competitive tender process through which offshore transmission licences are granted to the most competitive player – the Offshore Transmission Owner (OFTO). Under the existing regime, developers can choose between the generator build option and the OFTO build option. Under the OFTO build option, the developer undertakes high level design and preliminary works before transferring the rest of the work to the OFTO, who will construct and operate the assets. Under the generator build option, the developer will design and construct the transmission assets and the OFTO will only operate, maintain and decommission assets. Since offshore wind project developers are in charge of building the transmission lines themselves, delays are less common. However, in some situations, grid reinforcements on the land might be necessary.200
5.7.5 Large-scale Onshore Wind Development At the end of 2013, the United Kingdom had the third largest installed capacity of wind power in Europe after Germany and Spain. According to the UK Wind Energy Database from RenewableUK, the currently installed onshore capacity is 8,357 MW and at the end of 2014, industry projections forecasted a total of 12-14GW installed by 2020. 201
However, as stated previously, these industry projections are somewhat less certain at the time of writing this report because of the government’s decision to close the RO to onshore wind a year earlier than planned. As a result of these changes to support for onshore wind, 4.1 GW of additional capacity (through the RO and the CfD) is expected to be built by 2020 while around a further 7.1 GW is unlikely to go ahead. It can thus be expected that only projects viable without support will move forward in the future years. In this context, Scotland has better wind conditions than in England and it is therefore unsurprising that Scotland has seen, and continues to see, the majority of the UK’s onshore wind
199 Cornwall Energy, Overcoming grid connection issues for community energy projects for Co-operatives UK and The Co-operative Group, 3 October 2013, Available at: http://www.localenergyscotland.org/media/33075/Cornwall-Energy-report_Overcoming-grid-connection- issues-for-community-energy.pdf
200 Ofgem, Offshore transmission, Available at: https://www.ofgem.gov.uk/electricity/transmission-networks/offshore-transmission
Ofgem, The Electricity (Competitive Tenders for Offshore Transmission Licences) Regulations 201, 27 July 2015, Available at: The Electricity (Competitive Tenders for Offshore Transmission Licences) Regulations 2015
201 EurObserver, The State of Renewable Energies in Europe, Edition 2014
RenewableUK, Onshore Wind Energy, Available at: http://www.renewableuk.com/en/renewable-energy/wind-energy/onshore-wind/
Page 102 of 124 DOCUMENTING THE COST OF REGULATORY DELAYS, RE-DELAYS, March 2016 energy development with half of all construction projects and 70% of all UK consents located in Scotland over July 2014 – June 2015.202
5.7.6 Large-scale Offshore Wind Development Since 2008, the United Kingdom has been the world leader in offshore wind development with as much capacity installed as the rest of the world combined. The first offshore wind farm started operating in 2000 and, over the last 15 years, the sector has developed with a series of licensing rounds coordinated by the Crown Estate. Round 1 (2001) involved 18 now completed projects in England and Wales with a total installed capacity of 1.5 GW. Round 2, launched in 2003, will add another 7 GW of capacity and round 3, issued in 2010, will add more than 24 GW of capacity if fully constructed. At this moment, there is 5.05 GW of offshore wind operational across 25 offshore wind sites and the UK is expected to deliver another 5 GW by 2020.203
Nevertheless, since a second CfD auction round has not been published as expected, and future auctions will not be published before the end of 2016, there is increasing uncertainty with respect to market development and future support for offshore wind.
5.7.7 Insights from developers We identified that early consultation with stakeholders is becoming more and more important for project developers of both onshore and offshore wind projects. Nevertheless, bottlenecks for both technologies are very different as the following sections illustrate.
Insights for large onshore wind development
According to several developers, one of the biggest problems is that financial institutions do not want to finance projects anymore because of the uncertainty related to the regulatory framework. Developers thus have to finance these projects from their own balance sheets if they want to proceed. They revealed that they expect to develop most of their projects in Scotland because of more
202 Department of Energy & Climate Change (DECC), Statement on ending subsidies for onshore wind, 22 June 2015, Available at: https://www.gov.uk/government/speeches/statement-on-ending-subsidies-for-onshore-wind
UK onshore wind capacity factor 1998-2004, Available at: http://www.uea.ac.uk/~e680/energy/energy_links/renewables_Obligation/wind_capacity_factors_file43950.pdf
RenewableUK, Scotland reaps economic benefits of UK onshore wind, as England forges ahead offshore, 6 October 2015, Available at: http://www.renewableuk.com/en/news/press-releases.cfm/scotland-reaps-economic-benefits-of-uk-onshore-wind-as-england-forges- ahead-offshore#sthash.LinCWpDk.dpuf
RenewableUK
203 European Wind Energy Association (EWEA)., The European offshore wind industry – key trends and statistics 2014, January 2015, Available at: http://www.ewea.org/fileadmin/files/library/publications/statistics/EWEA-European-Offshore-Statistics-2014.pdf RenewableUK, Offshore Wind Project Timelines, June 2015, Available at: http://www.renewableuk.com/en/publications/index.cfm/Offshore-Wind-Project-Timelines RenewableUK, Offshore Wind, Available at: http://www.renewableuk.com/en/renewable-energy/wind-energy/offshore-wind/
Page 103 of 124 DOCUMENTING THE COST OF REGULATORY DELAYS, RE-DELAYS, March 2016 favourable wind conditions and less restrictive planning requirements. According to the industry association RenewableUK, the cost of capital in the UK is also a lot higher than in other European countries because of ongoing uncertainty.
Another insight is that local authorities are not always respecting deadlines for the determination of planning applications (currently projects <50MW). While decisions should be taken within 16 weeks, we learned that, in reality, it can easily take up to several years. For larger projects determined under the Planning Act 2008, deadlines are respected a lot more.
We also identified that a lot of projects are rejected by national and local governments for reasons such as interference with military radars, other aviation issues and issues related to public consultation (technical and environmental reasons). A lot of projects in England have also been held up for many months due to call-ins by the Secretary of State for Communities. The majority of these projects have since been refused, even in cases where a Planning Inspector has advised that the projects should be approved. This process has resulted in significant further uncertainty for developers who lack any visibility as to when they will receive a positive or negative planning decision. All these delays and an increasing rate of planning refusals at the local level have led to a situation where many projects that were hoping to be completed under the RO may now be unable to access future financial support.
For those developers that have achieved planning consent on their projects, many will be hoping to build out these projects under the RO (including those who can fully construct their projects before April 2016 and those who are likely to be eligible for future grace period provisions). As a result, a significant backlog of projects awaiting construction is observed.
When many parties are involved, it becomes increasingly complicated to acquire land rights. We previously mentioned that the government is placing an increased emphasis on the need for local consent and is currently pursuing proposals for local authorities to take decisions on onshore wind projects at all scales in England. According to some developers, this will increasingly harm the market because it will become impossible to develop larger-scale projects. We also understand that developers would be open to accept lower support if the planning process would be more clear.
A last but important insight is that securing grid capacity is becoming more and more challenging. The biggest issue is that, on some locations, no grid capacity is available before 2020 or even 2025 and projects are thus significantly delayed. Furthermore, because the grid availability is so low, onshore wind developers have to book grid capacity years before the commissioning date, and have to start paying a fee a number of years ahead of connection. These payments range from a few tens of thousands GBP up to several million GBP, with some grid costs risking the viability of the project overall. The industry association RenewableUK mentioned that there is also a lack of transparency as to what the transmission operator/distribution operator will charge and when there will be availability. One project developer even mentioned that they were considering investing in grid infrastructure themselves if the company managed to get consent for a large-scale project (more than 100 MW). Finally, we also identified that developers have to continue paying grid fees even when a project is abandoned because the grid operator will already have made investments in planned grid works.
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Insights for large offshore wind development
While, according to our interviews, securing grid access is by far the slowest and most expensive step for onshore wind development, the EIA as a part of the consent application is by far the most expensive step for offshore wind. The different studies usually take several years and it is very difficult to know what the government requires for the EIA. Some of the interviewed companies active in the offshore sector are international companies with a good knowledge of the European market so they can easily compare various markets. In this context, they declared that the EIA is significantly more demanding in the United Kingdom than in countries such as the Netherlands and Denmark. There are also differences within the UK regarding the time taken to reach decisions on consents for offshore wind. These are generally taken within one year in England, under the Planning Act 2008, while it can take up to several years in Scotland, under the Electricity Act 1989.
Another important insight is that early consultation with stakeholders plays an essential role in offshore wind project development, where developers are expected to have conducted extensive public consultation prior to submitting a Development Consent Order for determination. As with the EIA, this can easily take up to several years. The appeal process, by contrast, has not yet been tested for offshore projects as almost all offshore projects have received a positive decision.
Grid connection and financial issues also appear less problematic for offshore wind developers. Most of the companies active in the offshore market segment are big players with much more financial stability and the developer itself is the one taking decisions with respect to grid infrastructure and thus not dependant on the Transmission Operator (TO). The whole grid connection process will normally run in parallel with the consenting and will not usually delay project development.
A final important insight is that offshore wind developers are much less willing to share information related to project development than onshore wind developers. This is maybe because the uncertain future of the sector and the criticism on the cost of offshore wind in recent years.
5 . 8 UNITED STATES O F A M E R I C A
5.8.1 State of the Economy The United States (USA) is the world’s largest country by GDP and fourth largest country by population. GDP in 2014 was USD 17 trillion, and estimated population in 2015 is 321 million.204,205 Earlier in the year 2015, the Federal Reserve gave indications of increasing interest rates above the current near- zero level due to improving employment. In December 2015, the US Federal Reserve, in light of continued, albeit moderate, expansion of the economy, together with improved labour market conditions and renewed confidence, noted that inflation will rise over the medium term to meet its 2 percent objective. As such, the USA Federal Reserve increased the target range for the federal funds
204 World Bank, Gross domestic product 2014, Available at: http://databank.worldbank.org/data/download/GDP.pdf
205 CIA, The World Factbook: Country Comparison Population, Available at: https://www.cia.gov/library/publications/the-world- factbook/rankorder/2119rank.html
Page 105 of 124 DOCUMENTING THE COST OF REGULATORY DELAYS, RE-DELAYS, March 2016 rate to ¼ to ½ percent.206 Meanwhile, oil prices fell from around USD 100 per barrel in 2014 to less than USD 40 per barrel currently (February 2016). As a result, the USA energy sector saw reduced income with production facilities reducing output. However, consumers are expected to see annual net gain of around USD 920 per household from lower energy consumption.207
In the third quarter of 2015, real GDP was estimated to increase at an annual rate of 2.1% compared to second quarter increase of 3.9%. Growth is expected to come from positive contributions in personal consumption expenditures, state and local government spending, fixed investment, and exports.208 Improving labour market conditions, low energy prices, and the stronger dollar will likely continue to drive domestic demand. This may be dampened by weaker export growth, especially with slower external demand and strengthening of the dollar.209
Economic Indices Figure (Year)
Population 321 million (2015)
GDP USD 17,419 million (2014)
GDP per Capita USD 54,630 (2014)
Key industries Oil & gas, mining, agribusiness, renewable energy, medical equipment & services, construction equipment and services, aircraft, and power generation and related services
Table 13: Key Economics Facts on the United States
Source: The World Bank, Ex-Im Bank
206 US Federal Reserve, Press Release, December 16, 201,. Available at: http://www.federalreserve.gov/newsevents/press/monetary/20151216a.htm; http://www.bbc.com/news/business-34863241
207 Resources for the Future, Falling Oil Prices and US Economic Activity: Implications for the Future, Available at: http://www.rff.org/files/sharepoint/WorkImages/Download/RFF-IB-14-06.pdf
US Energy Information Administration, Petroleum & other liquids: Spot prices, Available at: https://www.eia.gov/dnav/pet/pet_pri_spt_s1_d.htm
208 Bureau of Economic Analysis, National Income Product Accounts Gross Domestic Product: Third Quarter 2015 (Advance Estimate), 2015. Available at: http://www.bea.gov/newsreleases/national/gdp/gdpnewsrelease.htm
209 OECD, United States – Economic forecast summary (November 2015), November 2015, Available at: http://www.oecd.org/unitedstates/united-states-economic-forecast-summary.htm
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5.8.2 Labour Market Over the past year, the labour market in the USA has continued to improve. Nonfarm payroll employment increased by 271,000 in October 2015 while the unemployment rate and labour force participation rate remain unchanged at 5.0% and 62.4%, respectively. The monthly job gain of 271,000 for October was higher than both the preceding three month average of 187,000 and the twelve month average of 230,000.210
Jobs in the renewable sector across the USA have improved since 2013. Total solar employment rose 22% to 173,800 jobs in 2014 from 142,700 jobs in 2013. Driving this growth is installations of solar PV (adding 97,000 jobs) and manufacturing (adding 2,600 jobs). Meanwhile, wind employment rose 43% to 73,000 jobs in 2014 from 50,500 jobs in 2013.211 For example, in Maine, wind power projects are estimated to create an average of 1,560 jobs a year. Over the past eight years, wind power companies have spent $532 million on projects in Maine. They expect to spend an additional $745 million over the next four years.212
5.8.3 Capital Markets and Access to Project Financing Current state of project financing
Investment in renewable energy projects in the USA decreased slightly from USD 30.5 billion in 2013 to USD 29.3 billion in 2014. Wind project financing increased from USD 3.9 billion in the first half of 2014 to USD 7.1 billion in the second half from clarifications in eligibility around the production tax credit (PTC). Corporations such as Google, Amazon, Apple, Facebook, and IKEA are also investing in renewables. IKEA plans to invest USD 1.7 billion in renewable projects in 2015. In 2014, IKEA acquired the 98 MW Hoopeston wind farm in Illinois and 165 MW Cameron wind farm in Texas in 2014.213
The US Government supports renewable development through tax credits such as the PTC and the Investment Tax Credit (ITC), and through accelerated depreciation benefits. These tax benefits represent approximately 50-55% of a renewable project’s installed costs.214 As tax credits are useful only when developers reach profitability and have taxable income, developers have partnered with tax equity investors who can profit from government tax policies.
210 US Bureau of Labor Statistics, Commissioner’s Statement on The Employment Situation, November 2015, Available at: http://www.bls.gov/news.release/jec.nr0.htm
211 IRENA, Renewable Energy and Jobs Annual Review 2015, 2015, Available at: http://www.irena.org/publications/rejobs-annual-review- 2015.pdf
212 Portland Press Herald, Maine wind industry boasts 1,560 jobs, $532 million in spending, January 2015, Available at: http://www.pressherald.com/2015/01/06/wind-industry-boasts-of-1560-jobs-and-532-million-investment-in-annual-report/
213 Orrick, U.S. Renewable Energy Financing and Regulatory Outlook 2015, March 2015, Available at: https://www.orrick.com/Events-and- Publications/Documents/US-Renewable-Energy-Financing-and-Regulatory-Outlook.pdf
214 NREL, Financing U.S. Renewable Energy Projects Through Public Capital Vehicles: Qualitative and Quantitative Benefits, April 2013, Available at: http://www.nrel.gov/docs/fy13osti/58315.pdf
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Commercial banks
Goldman Sachs is one of many banks investing in renewable projects. In November 2015, it announced plans to invest USD 150 billion in clean energy financing and investments by 2025 compared to USD 40 billion promised in 2012.215 Meanwhile, the USA Bank National Association has, to date, invested USD 3.4 billion in renewable energy tax equity to finance USD 7 billion in renewable energy.216 In May 2015, Bank of America issued their second green bond at USD 600 million principal to fund renewable energy projects.217 The first green bond of USD 500 million in principal was issued in 2013 at a three- year fixed-rate.218 In January 2010, Bank of New York Mellon announced it will purchase 1,125 GWh of Renewable Energy Credits (RECs) from NextEra Energy Resources over five years and has been ranked as a top purchaser of green power.219 Other major banks such as JP Morgan, Citigroup, and Wells Fargo have also supported the development of renewables.
Tax exemptions, tax credits and low interest loans
The Renewable Energy PTC and Business Energy ITC are federally administered corporate tax credits for the development of renewable energy. The PTC was enacted in 1992, and modified in 2009, 2013, and 2014. It provides an inflation-adjusted per kWh tax credit for electricity generated and sold from qualifying resources. Duration of the PTC is generally ten years after the facility has been built.220 Figure 24 provides a summary of resource types and respective credit amounts.
Figure 24: PTC Tax Credit Amount
Resource Type Credit Amount ($ / kWh) Wind 0.023 Closed-Loop Biomass 0.023 Open-Loop Biomass 0.011 Geothermal Energy 0.023 Landfill Gas 0.011 Municipal Solid Waste 0.011 Qualified Hydroelectric 0.011 Marine and Hydrokinetic 0.011
215 SNL, Goldman to invest $150B in renewable energy by 2025, November 2015.
216 US Bank, Our Team: Renewable Energy Tax Credits, Available at: https://www.usbank.com/commercial-business/tax-credit- financing/renewable-energy-tax-credits-team.html [accessed on November 16, 2015]
217 Bank of America, Bank of America Issues Second Green Bond, May 2015, Available at: http://newsroom.bankofamerica.com/press- releases/corporate-and-investment-banking-sales-and-trading-treasury-services/bank-america-iss
218 Bank of America, Bank of America Issues $500 Million Green Bond, November 2013, Available at: http://newsroom.bankofamerica.com/press-releases/corporate-and-financial-news/bank-america-issues-500-million-green-bond
219 U.S. Department of Energy, Large Purchasers of Green Power, January 2010, Available at: http://apps3.eere.energy.gov/greenpower/resources/tables/customers.shtml?page=1&companyid=774
220 U.S. Government of Energy, Renewable Electricity Production Tax Credit (PTC), Available at: http://energy.gov/savings/renewable- electricity-production-tax-credit-ptc [accessed on November 11, 2015]
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Source: U.S. Department of Energy
The ITC was enacted in 2008, and expanded in 2009. It provides a credit based on a percent of expenditures dependent on the technology or resources used.221 Figure 25 provides a summary of resource types and respective rebate amounts.
Figure 25: ITC Tax Rebate Amount
Resource Type Rebate Amount (% of expenditures) Solar 30% Fuel Cells 30% Small Wind Turbines 30% Geothermal Systems 10% Microturbines 10% Combined Heat and Power 10% Source: U.S. Department of Energy
5.8.4 Preparedness of the Regulatory Environment for Renewable Energy Projects Electricity Supply Mix and Renewable Targets
Total nameplate capacity in the USA was 1,173 GW in 2014, while net generation was 4,093 TWh.222
221 U.S. Government of Energy, Business Energy Investment Tax Credit (ITC), Available at: http://energy.gov/savings/business-energy- investment-tax-credit-itc
222 Excluding hydro pumped storage nameplate capacity of 21.6015 GW
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Figure 26 provides a distribution of installed capacity and net generation by fuel type. In 2014, gas, oil, coal, and nuclear account for 85 percent of installed capacity. Hydro and wind dominate renewable energy development, while biomass, geothermal, and solar account for 25 GW or around two percent of total installed capacity. In terms of net generation, production was dominated by coal, gas and oil, and nuclear. Hydro and wind account for 10 percent of generation, while biomass, geothermal, and solar account for 56 TWh or around 1.4 percent of total net generation in 2014.
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Figure 26: Supply mix in the United States (2014)
Generation (GWh, %)
Wind, Other, Hydro, 181,791, 111,845, 258,749, 4% 3% 6%
Coal, 1,585,697, Nuclear, 39% 797,067, 20%
Gas & Oil, 1,163,995, 28%
Source: EIA Electric Power Annual
Renewable targets across the USA are mainly governed by the state-level Renewable Portfolio Standards (RPS).223 These are flexible market-based policies that ensure competitive retail electric suppliers obtain a minimum percentage of their power from renewables by a certain date. Although RPS was first established in 1983, most states did not join until after 2000, and have established state- level renewable energy targets since.224 As of October 2015, around 29 states, the District of Columbia, and two territories have enforceable RPS policies, while an additional eight states and two territories have set renewable energy goals.225 Figure 27 provides a summary of states that have implemented RPS standards, voluntary standards, or have not implemented any standard.
223 RPS in this case study refers to all renewable energy target policies such as the Renewable Energy Standard (RES), Renewable Energy Portfolio Standard (REPS), Clean Energy Portfolio Goal (CEPG), Alternative Energy Portfolio Standard (AEPS) and others.
224 IRENA, State-level Renewable Portfolio Standards (RPS), August 2012, Available at: http://www.iea.org/policiesandmeasures/renewableenergy/index.php?country=United%20States
225 NCSL, State Renewable Portfolio Standards and Goals, October 2015, Available at: http://www.ncsl.org/research/energy/renewable- portfolio-standards.aspx [accessed on November 19, 2015]
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Figure 27: State Renewable Portfolio Standards
Source: NCSL
Many state policies also include a system of tradable RECs. Similar to a cap-and-trade system, electricity suppliers that generate more than the RPS-mandated renewable electricity capacity can trade or sell RECs to other electricity suppliers. For every megawatt-hour placed on the grid by renewable generators, one REC is created.226 Deficiencies in meeting RPS targets may be met through Alternative Compliance Payment (ACP). The ACP is subsequently used to fund new renewable energy projects, and also set a price cap on RECs.
Figure 28 provides a summary of RPS policies across the top ten states ranked by GDP that have implemented required renewable energy targets.227 Many states have noncompliance penalties through regulatory reinforcement or ACPs and participate in regional credit trading systems.
Furthermore, the USAClimate Action Plan and Regional Greenhouse Gas Initiative (RGGI) set greenhouse gas (GHG) emission reduction targets that will directly and indirectly stimulate the growth of renewables. The USA Climate Action Plan was introduced on June 25, 2013 to cut carbon pollution in the USA and address climate change impacts. This includes installing 100 MW of renewables in
226 EPA, Renewable Energy Certificates (RECs), August 2015, Available at: http://www3.epa.gov/greenpower/gpmarket/rec.htm
227 Ranking of states is taken from the 2014 estimates: http://www.bea.gov/newsreleases/regional/gdp_state/gsp_newsrelease.htm
Page 112 of 124 DOCUMENTING THE COST OF REGULATORY DELAYS, RE-DELAYS, March 2016 federally assisted housing by 2020, and 3,000 MW of renewables in military installations.228 RGGI is a cap-and-trade program established in 2005 by a few North-Eastern and Mid-Atlantic states. By 2007, all states in New England were part of the program. Partial funding from the trading of allowances in auctions is used to stimulate investments in renewable energy.229
Figure 28: State-level RPS Summary of Top 10 States by GDP
State Date Enacted Standard Noncompliance Penalties Credit Trading 33% by 2020 40% vy 2024 California 2002 Penalty: $50 / MWh WREGIS 45% by 2027 50% by 2030 5,880 MW by 2015 Texas 1999 ACP: $50 / MWh ERCOT 10,000 MW by 2025 Under New York 2004 29% by 2015 None Development ACP calculated by average REC prices in M-RETS and Illinois 2008 25% by 2025-2026 most recent IPA REC procurement PJM-GATS ACP: Pennsylvania 2004 18% by 2020-2021 Tier 1 and II: $45 / MWh PJM-GATS Separate calculation for Solar ACP: Initially $45 / MWh, but adjusted M-RETS and Ohio 2008 25% by 2024 annually with price floor $45 / MWh PJM-GATS Class I and II: 20.38% by 2020-2021 New Jersey 1999 ACP: $50 / MWh PJM-GATS +4.1% solar-electricity by 2027-2028 IOUs: 12.5% by 2021 North Carolina 2007 Regulatory Enforcement NC-RETS Municipality & Cooperatives: 10% by 2018
ACP: Class I: $66.16 / MWh Class I (New Resources): 15% by 2020 Class II: $27.16 / MWh Massachusetts 1997 NEPOOL-GIS Class II (Existing Resources): 5.5% in 2015 Class II Waste Energy: $10.86 / MWh Solar Carve-Out: $523 / MWh Solar Carve-Out II: $375 / MWh Michigan 2008 10% by 2015 Regulatory Enforcement MIRECS Washington 2006 15% by 2020 Penalty: $50 / MWh WREGIS Source: DSIRE, NCSL
228 IRENA, US Climate Action Plan, August 2012, Available at: http://www.iea.org/policiesandmeasures/renewableenergy/index.php?country=United%20States
229 Ibid
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Renewable Support: PTC, ITC
According to the National Renewable Energy Laboratory (NREL), the PTC has been the primary federal incentive that On February 17, 2014, Duke Energy is driving growth in wind power development. As a result, announced plans to sell 13 power wind power capacity has grown at an annual rate of 30% from plants in Midwestern US that totalled 2006 to 2012.230 Since its inception in 1992, the PTC has been 6.6 GW of electricity. The exit came extended in one- or two-year intervals, and sometimes after Ohio regulators rejected a USD allowed to expire. In 2012, uncertainty over whether the PTC 729 million rate increase proposed by would expire at the end of the year contributed to a Duke Energy. In a press release, Duke significant fall in annual wind additions in 2013. More Energy blamed volatile returns and a recently, the PTC was retroactively instated for 2014 and 2015 challenging competitive market as both within a few weeks prior to year-end, and currently has reasons leading to the exit. In 2012, been extended until 2019.231 In a scenario where the PTC is uncertainties surrounding the not extended and other policies remain in place, wind extension of the PTC significantly capacity additions fall between 3 GW and 5 GW a year impacted wind development. compared to 8.7 GW a year from 2008 to 2012.232
Developers have echoed similar sentiments where changing PTC and ITC legislation is leading to delays. Frequent changes in PTC and ITC have increased the risk of projects, making it significantly more difficult to obtain Power Purchase Agreements.
Administrative Processes and Policy Change
The interconnection process is typically governed by federal policy for transmission-level interconnections and state-level policy for distribution-level interconnections. The federal interconnection policy is overseen by the Federal Energy Regulatory Committee (FERC) and administered by the Regional Transmission Organizations (RTOs). FERC will step in when no RTO exists for a particular region. FERC interconnection procedures and agreements are governed by the Large Generator Interconnection Procedures (LGIP) and Large Generator Interconnection Agreement (LGIA) for large merchant generators greater than 20 MW in capacity, and the Small Generator Interconnection Procedures (SGIP) and Small Generator Interconnection Agreement (SGIA). For small generators below 2 MW, there is a fast-track review process.233
230 U.S. Department of Energy, The Production Tax Credit is Key to a Strong U.S. Wind Industry, April 2014, Available at: http://energy.gov/articles/production-tax-credit-key-strong-us-wind-industry
231 US Department of Energy. Renewable Electricity Production Tax Credit (PTC), Available at: http://energy.gov/savings/renewable- electricity-production-tax-credit-ptc [accessed on February 16, 2016]
232 U.S. Department of Energy, The Production Tax Credit is Key to a Strong U.S. Wind Industry, April 2014, Available at: http://energy.gov/articles/production-tax-credit-key-strong-us-wind-industry
233 NARUC, An Introduction to Interconnection Policy in the United States, August 8. 2014, Available at: http://www.naruc.org/international/Documents/BiH%20Interconnection%20Policy.pdf
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For example, for those entities looking to connect to the PJM Interconnection (PJM) the process starts with the submittal of an interconnection request to PJM.234 Projects are placed in an interconnection queue. There is an optional scoping meeting right after the interconnection request between the applicants, PJM staff, and transmission owners. Afterwards, the feasibility study, system impact study, and facilities study are completed. The Interconnection Service Agreement (ISA) is filed with FERC, and the Construction Service Agreement (CSA) is finalized with the transmission operator, developer, and PJM. Construction and billing is completed under the ISA and CSA, and the generating resource is subsequently placed under commercial operation. Figure 29 provides a summary of the interconnection process in PJM.
Figure 29: PJM Interconnection Process
Source: NARUC
Sometimes the interpretation of legislation changes over time, while the actual policy remains unchanged. The textbox below explores the troubles one developer had over land permits.
A developer in Vermont purchased wetlands with the understanding that the rules at the time allowed the development of wind farms. However, after the Vermont Agency of Natural Resources checked the area, the developer was informed it was not suitable. Although legislation had not changed, the interpretation of the legislation had evolved. The developer was forced to move to a forested area and clear three acres of trees before proceeding. There was approximately five months of delay in the project and an estimate of around USD 60,000 to obtain environmental approval. On the other hand, some developers have faced obstacles with changing legislation. Expiration of the PTC and ITC is one common area that has led to uncertainty every year. This is explored further in
234 PJM is a regional transmission organisation responsible for the coordination of wholesale energy markets across all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia, and the District of Columbia
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In 2012, Pattern Energy Group LP faced delays in the construction of the Ocotillo Express Wind Energy Facility after the Quechan Tribe expressed concerns that the facility would violate their sacred sites near Southern California’s Imperial Country. According to the tribe, their efforts to participate in the permitting process were impaired, and the Bureau of Land Management (BLM) did not seriously address their concerns.
Renewable Support: PTC, ITC. More recently, lawmakers in Massachusetts failed to expand the net metering cap. Analysts expect that 100 MW of solar power will be forgone in 2016 as a result.235
In addition, the USA Fish and Wildlife Services require an incidental take permit for the protection of endangered and threatened species.236 A few developers have expressed frustration at the lack of clarity in the process, and have suggested that the USA Fish and Wildlife Service processes should be streamlined.
5.8.5 Large-scale Wind Development The development of renewable wind capacity in the USA is expected to rebound and grow in the next few years from improvements in cost and performance. Long-term growth of renewables hinges on the PTC as it is the primary federal incentive for wind development. In December 2015, the expiration date for the PTC was extended to December 31, 2019 quelling industry uncertainty. This extension applies retroactively to January 1, 2015 for wind renewable projects that began construction throughout 2015 and includes a phase-down beginning for wind projects commencing construction after December 31, 2016.237
Overall, the USA has demonstrated considerable growth in the development of wind renewables over the past few years. The USA was ranked third worldwide by wind capacity additions for 2014, and second in terms of cumulative capacity at the end of 2014. New capacity additions totalled 4,854 MW and attracted USD 8.3 billion in new investments while total installed capacity grew by eight percent to 67.7 GW. Wind renewables accounted for 24% of electricity generating capacity additions in 2014.238 Across the USA states, Texas has the largest installed capacity at 15,635 MW. Figure 30 provides a distribution of installed wind capacity.
235 Utility Dive, 100 MW of Mass. commercial solar at risk from failure to reach net metering compromise, November 23 2015, Available at: http://www.utilitydive.com/news/100-mw-of-mass-commerical-solar-at-risk-from-failure-to-reach-net-meterin/409680/
236 U.S. Fish and Wildlife Services, Permits, Available at: http://www.fws.gov/ENDANGERED/permits/index.html [accessed on November 23, 2015]
237 US Department of Energy. Renewable Electricity Production Tax Credit (PTC), Available at: http://energy.gov/savings/renewable- electricity-production-tax-credit-ptc [accessed on February 16, 2016]
238 Ibid
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Figure 30: Supply mix for wind renewables in the US for 2014
Installed Wind Capacity (MW, %) Net Wind Generation (TWh, %)
Texas, 40.01, Texas, 22% 15,635, 23% Rest of US, Rest of US, 29,631, 44% 82.78, 46% California, California, 12.99, 7% 6,018, 9% Iowa, 16.31, Iowa, 9% 5,708 , 8%
Oklahoma, Oklahoma, Oregon, Illinois, 11.94, 7% Oregon, Illinois, 3,932, 6% 7.56, 4% 10.08, 5% 3,153, 5% 3,667, 5%
Source: WINDExchange, EIA
5.8.6 Large-scale Hydro Development In the USA, hydropower has total capacity of 79.91 GW accounting for 7% of installed generating capacity. Between 2005 and 2013, capacity increased by 2.05 GW. At the end of 2014, just over 330 projects were under the development pipeline, accounting for 4.37 GW in capacity. Out of these, 407 MW are under construction and 263 MW have received proper authorization.239 Figure 31 provides a distribution of installed hydro capacity using the latest available EIA data.240
Figure 31: Supply mix for hydro renewables in the USA for 2014
Source: U.S. Department of Energy, EIA
239 U.S. Department of Energy, 2014 Hydropower Market Report, April 2015, Available at: http://www.energy.gov/sites/prod/files/2015/04/f22/2014%20Hydropower%20Market%20Report_20150424.pdf
240 Finalized EIA hydroelectric capacity data was only available until 2013. Proposed additions were added to provide an estimate for 2014.
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5.8.7 Insights from Developers We gained several insights from speaking with developers. First, developers noted that changing legislation around PTC and ITC by the Government creates uncertainty for developers. The PTC is renewed every few years, and often left to expire. For example, the PTC was retroactively instated for 2014 and 2015 both within weeks prior to year end. This creates uncertainty and costs for developers, and it becomes difficult to sign PPAs or offtake agreements in an uncertain environment. Developers have recommended that regulators extend the window for PTC and ITCs. Ideally, developers should be notified 24 months in advance of expiry on whether the tax credit will be extended.
Second, when a developer withdraws a grid connection application, the cost impact to remaining developers in the queue is unknown beforehand. Developers often pay a significant amount of money to stay in queue for grid connections. In some regions, grid connections are relatively easy to apply for, but can clog up the system. Developers believe the process should be streamlined and transparent.
Third, the process to apply for a ‘take permit’ — related to environmental approvals — is largely unknown. The US Fish and Wildlife Services issues a number of take permits each year as a method to protect endangered species. It is a criminal offence to exceed the take permit. The unclear process can lead to abandonment of projects, and developers have recommended that the USA Fish and Wildlife Services processes be streamlined.
Lastly, legislation around permitting can sometimes be interpreted in different ways, despite remaining unchanged. For example, a developer that purchased wetlands in hopes of constructing a wind farm found that it was deemed to be unsuitable some period later. Clarity of regulations and their interpretation is important for most developers in order to avoid unnecessary delays.
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6 ANNEX B: EXAMPLE SURVEY FOR FR ANCE
Background on developer 1. How many wind projects have you developed approximately in the last 10 years?
2. Where have you developed these projects?
3. What has been the average size of your projects?
B) Development timeline in France 4. Can you provide us with a brief overview of the different steps from siting to commercial operation for onshore wind project in France?
5. In your experience, which step is most likely to experience most delays? Any indicative ranges of delays (in months/years) associated with such delays will be appreciated.
D) Cost of permitting 6. What is the most costly regulatory step?
7. Are there other costs not captured by the regulatory fees?
8. What is the time given to authorities to issue an answer/permit?
9. What is the cost of each permit? How much effort (what activities are required) to prepare these permit applications?
10. After submission of the application, how often are additional permits required (that are not anticipated upfront)?
11. In your experience, typically how long does it take to obtain additional permits? What kind of costs are involved – indicative ranges will be great.
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E) Actual delays 12. In your experience, where have you experienced the longest delays: (4 options: political, consenting, environmental, grid connection) ?
13. What is the underlying cause of the delay – paperwork/numerous requirements, number of parties, lack of transparency/confusion about process, process redundancies, long response times from regulators/government, lack of grid capacity, project backlog?
14. Did the specific delay have a snowball effect and delayed other steps of the development?
15. Can you quantify these delays in terms of indicative months/years?
16. Can you quantify these delays in terms of costs incurred in the development cycle – indicative ranges?
G) Capital and Operating Costs - Wind 17. Our research indicates that the capital cost of wind turbines ranges from 1300 to 1700 €/kW. Do you think this is a reasonable estimate?
18. What type of wind turbines are you considering for your next project? Can you shed some light on its cost ranges?
19. We estimate that the length of useful life of wind turbines is about 20 years. Do you agree? If not, what is more realistic?
20. We estimate the target period for equity recovery from the project at 10 years. Is this reasonable? If not, what is more realistic?
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21. We estimate the typical length of long-term debt at 15 years. Is this reasonable? If not, what is more realistic?
22. We estimate the typical maintenance cost at around 20€/kW of capacity per year. Is this reasonable? If not, what is more realistic?
23. What is the range of load factors that you have observed for your projects in France?
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MEMBER COUNTRIES OF IEA -RETD
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The International Energy Agency’s Implementing Agreement for Renewable Energy Technology Deployment (IEA-RETD) provides a platform for enhancing international cooperation on policies, measures and market instruments to accelerate the global deployment of renewable energy technologies.
IEA-RETD aims to empower policy makers and energy market actors to make informed decisions by: (1) providing innovative policy options; (2) disseminating best practices related to policy measures and market instruments to increase deployment of renewable energy, and (3) increasing awareness of the short-, medium- and long-term impacts of renewable energy action and inaction.
Current member countries of the IEA-RETD Implementing Agreement are Canada, Denmark, France, Germany, Ireland, Japan, Norway, and United Kingdom.
More information on the IEA-RETD can be found at
www.iea-retd.org
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