Tag Archives: utilities

EU winter package brings renewables in from the cold

December 1, 2016 |

 

Joint press conference by Maroš Šefčovič and Miguel Arias Cañete on the adoption of a Framework Strategy for a Resilient Energy Union with a Forward-Looking Climate Change Policy

Christmas came early yesterday in Brussels, with the release of some heavy reading for the EU’s parliamentarians to digest over the festive season. Or at least that was the more jovial take on the launch of the EU winter package from Maroš Šefčovič, the EU vice-president in charge of the Energy Union (pictured).

Targets to cut energy use 30% by 2030, the phasing out of coal subsidies and regional cooperation on energy trading are central to the proposals, which updates the regulations and directives that support targets set out in 2014 as part of the Energy Package 2030.

Whether this gift is not just for Christmas will be down to the EU parliamentarians who have two years to debate these proposals and implement them.

So where does it leave us with the growth of renewables, the underpinning for a decarbonised power sector? If the EU meets its 2030 target, 50% of electricity should be renewable compared with an EU average of 29% today. That target remains unchanged, so those engaged in producing clean energy for Europe’s electricity grid should be reassured – up to a point.

A great deal was made of scrapping priority dispatch for renewables after that proposed change was ‘leaked’. In the end, the Commission merely soften its language but the outcome remains the same on priority dispatch, implying that policymakers think that renewable generation should be more responsive to the market.

Yesterday, Šefčovič and the Commissioner for Climate Action and Energy Miguel Arias Cañete both acknowledged that renewables need to be more integrated into wholesale markets, and those markets need to be more coordinated with each-other. Specifically, the package encourages member states to:

  • ensure that renewables participate in wholesale and balancing markets on a “level playing field” with other technologies. In particular, the new package removes the requirement for renewables to be given priority dispatch over other generation types (which most, but not all, member states currently abide by). It instead requires dispatch which is “non-discriminatory and market based”, with a few exceptions such as small-scale renewables (<500kW). In addition, renewables should face balancing risk and participate in wholesale and balancing markets.
  • increase integration between national electricity markets across the EU. Requirements include opening national capacity auctions to cross-border participation and an interconnection target of 15% by 2030 (ie, connecting 15% of installed electricity production capacity with neighbouring regions and countries). Earlier this year, the Commission established an expert group to guide member states and regions through this process.

What does this all mean for investors? The obvious concern is that removal of priority dispatch and exposure to balancing markets will increase revenue risk for renewables generators.

So, why is the EU removing these rules on priority dispatch once the mainstay of the Commission’s wholesale market rules? The main argument is to help reduce the costs of balancing supply and demand, and managing network constraints. Generally, it is most economic to dispatch renewables first because their running costs are close to zero regardless of whether they have priority dispatch.

But, when there is surplus generation, the most economic option is sometimes to curtail renewables ahead of other plant. For example, turning down an inflexible gas plant only to restart and ramp it up a few hours later can be expensive and inefficient. By contrast, wind generators can be turned down relatively easily.

Therefore, giving renewables priority dispatch can sometimes increase the overall costs of managing the system. When renewables were a small part of the market, any inefficiencies caused by priority dispatch were small and easy to ignore, while it helped reduce risks around renewables investment. But now renewables are set to become the dominant part of electricity markets it is harder to ignore.

Nevertheless, risks around balancing for wind can cause real headaches for investors. In our report from earlier this year, Policy and investment in German renewable energy we found that economic curtailment could increase significantly, potentially adding 17% to onshore wind costs by 2020.

The amount a generator is curtailed depends on a wide range of uncertain factors which wind investors have little or no control over (eg, electricity demand, international energy planning, network developments and future curtailment rules).

What could happen next?

So to maintain investor confidence (and avoid costly lawsuits) existing renewables investments need to be financially protected as rules are changed. There are many ways to do this. For example, priority dispatch status could be grandfathered for existing generators (as the winter package suggests) or, as set out in our recent report of Germany, generators could be fully compensated for curtailment through “take-or-pay” arrangements.

More generally, very clear rules around plant dispatch and curtailment are needed to avoid deterring investment. Ideally, dispatch will be determined by competitive, well-functioning balancing markets, where renewables are paid to be turned down based on what they offer, rather than by a central system operator curtailing without compensation.

The move to integrate renewables into balancing markets means they will compete with other options to balance the system such as storage and demand-side measures. These flexibility options should benefit from the sharper price signals and greater interconnection implied by winter package. But there is no clear consensus yet on the right business and regulatory models to support investment in flexibility. However, CPI is currently working on a programme as part of the Energy Transitions Commission to explore the role of flexibility in a modern, decarbonised grid and will be publishing our findings soon.

Ultimately, there is an unavoidable trade-off in designing electricity markets: it is very difficult to provide incentives for generators, storage and the demand-side to dispatch efficiently through market mechanisms without also exposing them to some risk. Yesterday’s announcement in the winter package means more countries will have to face this dilemma.

Disclaimer: Unless otherwise stated, the information in this blog is not supported by CPI evidence-based content. Views expressed are those of the author.

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EU Curtailment Rules Could Increase German Wind Costs by 17% by 2020

April 14, 2016 |

 

This week, members of CPI’s Energy Finance team traveled to Brussels to present and discuss findings from our analysis of financing for European low-carbon energy transitions to a panel of EU policymakers and regulators including representatives from DG Energy and DG Competition and investors. This followed a meeting in February to present findings on the German low-carbon energy transition to the Federal Ministry of Economic Affairs and Energy (BMWi) and the Federal Ministry of Finance (BMF). The discussions focused in particular on the subject of economic curtailment an issue that is not yet fully appreciated by most investors but has the potential to reduce the availability and increase the cost investment. BMWi are in the process of designing policy to help mitigate this risk.

Analysis from our latest report suggests that without appropriate policies to lessen curtailment risk the cost of onshore wind in Germany could increase by over 17% by 2020 and by even more in future years. German policymakers are in the process of designing policy to help mitigate this risk.

So what is economic curtailment? Under European Commission state aid guidelines, renewable energy generators should have no incentive to generate electricity at times of negative prices. In other words, revenue support should be suspended during these times so that suppliers of renewable power will stop generating electricity because they will be out of pocket if they continue to do so. We have defined this issue as ‘economic curtailment’ (as distinct from ‘grid curtailment’ which occurs when the grid has no more capacity to take on power) and, as renewable energy deployment increases, it is an issue that is likely to become more relevant until such time as effective energy flexibility solutions (e.g. storage and demand response) are found.

Germany has an agreement with the European Commission that this rule does not need to be applied until prices are negative for six consecutive hours or more. This reduces the potential impact on the levelised cost of electricity somewhat. Curtailing support on an hourly basis could increase the cost of electricity by over 30% in 2020. Applying a six hour rule almost halves the cost increase requirement to 17% by significantly reducing the number of negative price hours affected and therefore lowering the cost of investment by increasing the amount that debt investors would lend.

We identified and tested additional approaches that could further address the needs of policymakers and investors. The solutions we evaluated were:

Take-or-pay: One option would be to curtail production from renewable energy but continue to pay generators for the lost output. This option provides the lowest cost and risk while still offering flexibility, but under current interpretations would fall foul of EU state aid regulations by incentivising production when it was not needed.
Proportional curtailment: Negative prices generally occur when wind or solar generation is high. Our analysis shows that on average a reduction of only 15% of wind output during negative price hours would move prices into positive territory. Thus, a system that could curtail only the excess generation and allocate the cost of this curtailment amongst all fixed tariff generators would better reflect system economics. This option would only be 5% more expensive than the cost of electricity under the take or pay option.
Add to the end: Under this option any hours that are curtailed during the 20-year support period – after incorporating the 6 hour rule – can be accrued and power generation beyond this support period can claim additional support until such time as the accrued hours are used up. However, high discounting of cash flows 20 years from now, as well as the fact that such a policy does not extend the operating life of the generation assets (and therefore would add no value if future energy prices are at or higher than the fixed tariff prices), means that this policy would add almost no additional value to investors.
Cap: under this option we assume that in addition to the 6 hour cut-off there is a limit to the number of hours that can be economically curtailed each year. The impact varies depending on the cap level.

Figure 37 - Impact on bid prices of hourly, 6 hour rule and proportional

The appeal of these additional approaches depends on policymakers’ priorities and investors’ needs but our analysis suggests that if take-or-pay was not available as an option to remove economic curtailment risk then a low level cap or proportional curtailment would be the next best approaches for attracting levels of investment consistent with meeting renewable energy deployment targets and doing so at low cost.

The analysis presented in Brussels was financed by the European Climate Foundation and the Global Commission on the Economy and Climate to examine how policy impacts the availability and cost of investment for low-carbon energy transitions. It aims to inform thinking on how renewable energy deployment targets can be achieved whilst minimising the cost to consumers.

For more information, please see our paper ‘Policy and investment in German renewable energy’.

And keep a look out for a forthcoming paper that will also examine finance for renewable energy in other European countries, namely the UK, Nordic countries, Spain and Portugal.

A version of this blog appeared on EurActiv. Click here to read it.

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Could New Investment Structures in the German Renewable Energy Market Make the Market More Cost-Competitive?

June 2, 2015 |

 

Germany is in the midst of a major energy transition, one that could serve as a model for the rest of the world. At the core of the challenge is the need to continue to grow renewable energy (and drastically reduce dependence on coal) while containing the cost of renewable energy to government and ratepayers.

German policymakers are looking to control costs by replacing the feed-in tariffs that have driven renewable energy deployment and cost reduction with new competitive mechanisms. However, if these policy changes are made without considering their impact on how projects are financed, they could inadvertently increase costs. Any changes to policy should be made with a comprehensive understanding of the current and potential investors in renewable energy and the impact that different policy mechanisms and financing structures could have on their costs and ability to invest.

CPI, with the support of the European Climate Foundation, is examining this important aspect of the transition to inform policy and financing activities that could allow Germany to advance its energy transition at lower cost. In this project, we will:

  1. Size the investment potential for different types of renewable energy across potential German investor groups in the sector – utilities, developers, financial investors, large energy users, small energy users, and municipal and other governments.
  2. Assess the market opportunity for new financing instruments, including new financing structures such as YieldCos, crowdsourcing, and municipal funding, which we identified as potential opportunities in previous work.
  3. Identify policy options that seem to have the most favorable impact or provide the biggest barriers to investment. Starting with opinions expressed by investor groups and their analysts and advisors, as well as a review of investment cases and our financial modelling, we will analyze the impact of policy changes to financing costs for different market segments.

 
Alongside this project, CPI is also working with the Stockholm Environment Institute (SEI) on a New Climate Economy project, to identify and analyze the barriers faced by investor groups across five European countries/regions (Germany, UK, Nordic countries, Iberia, Italy).

The lessons from these projects will be relevant for Europe and beyond. With Europe’s new, more ambitious renewable energy and carbon emissions reduction targets for 2030, changes to European policies and regulations will be necessary, as well as policy and regulation in EU member states.

Ultimately, the transition to a low-carbon electricity system will require wholesale changes to policy, technology, market design, consumer behavior, industry structure, and finance. Addressing the finance portion of the equation is critical to develop a true picture of the priorities for policy development in Germany and beyond.

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Video: New business models for a low-carbon electricity system in the U.S. and Europe can save billions

November 10, 2014 |

 

New finance and business models for a low-carbon electricity system in the U.S. and Europe can save consumers, investors, and taxpayers billions. Watch the video or read the analysis to learn more.

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With new market structures and business models, consumers can help states reduce carbon emissions

July 8, 2014 |

 

On June 2, in a historic move towards addressing CO2’s climate impacts, the Environmental Protection Agency (EPA) released its Clean Power Plan proposed rule for regulating carbon emissions from existing power plants. The regulations encourage states to take advantage of a range of CO2-reducing methods, like energy efficiency and renewable energy, rather than requiring all emissions reductions to occur at the power plants themselves. Electricity consumers can play an important role in states’ plans to meet the regulations, if regulators can take advantage of all the resources they can provide. Fully utilizing consumers’ electrical resources may require the help of new market structures and business models.

The value that individuals, households, and businesses can provide to the electric grid could be quite significant. Technologies such as rooftop solar panels, “smart” thermostats, more efficient appliances, and electric vehicles, especially when combined with smart meters and other smart grid technologies, could enable consumers to reduce the demands on the grid at peak times and help absorb excess generation from renewable generation when demand is low. As CPI discusses in our Roadmap to a Low Carbon Electricity System, many factors are already conspiring to make these consumer-level resources more valuable and accessible.

Wise use of these so-called distributed energy resources could replace some of the fossil-fuel power plants that would otherwise be needed to balance a renewable-generation-heavy grid, creating cost-effective emissions reductions. They could even make the grid more resilient to future severe weather.

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The Clean Power Plan means changes for coal, but not the ones you might expect

June 18, 2014 |

 

Under President Obama’s recently announced Clean Power Plan, the Environmental Protection Agency (EPA) proposed that states cut greenhouse gas emissions from existing power plants by 30 percent from 2005 levels.

Commenters on both sides of the aisle say this rule means big changes for the coal industry.

But before we get fired up about the changes, it’s important to take a look at the facts: While states will need to retire coal plants at the end of their useful lives to meet the proposed limits, EPA’s rule would give states a great amount of flexibility to avoid coal asset stranding and still meet emissions reduction targets. In fact, valuing the right services from coal plants will prove the more important question for a low-cost, low-carbon electricity system.

Let’s look at why.

First, we need to understand what the rule really means for coal asset stranding. An asset is “stranded” if a reduction in its value (that is, value to investors) is clearly attributable to a policy change that was not foreseeable by investors at the time of investment.

In our upcoming analysis of stranded assets, Climate Policy Initiative finds that if no new investments are made in coal power plants and existing plants retire as planned (typically, 60 years for plants with pollution control technology investments and 40 years for plants without), the U.S. coal power sector stands to experience approximately $28 billion of value stranding from plants that are shut down. While that’s a big sounding number at first glance, it’s very small relative to the size of coal power sector. As the figure shows, that retirement schedule puts the U.S. coal power sector on track to come close to the coal power capacity reductions called for in the IEA 450 PPM scenario to limit global temperature increase to 2°C.

U.S. Coal Power w emissions (2)

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California’s Climate Credit is Worth Watching

April 17, 2014 |

 

This month, many Californians will see something new on their electricity bills: The first bi-annual Climate Credit, a payout to customers of investor-owned utilities like PG&E and SCE through California’s Cap and Trade program. The Climate Credit is worth around $30-$40 and will recur every April and October for most customers. However, for customers of some small utilities it will reach nearly $200, while certain small businesses, schools, and hospitals will receive their credit every month.

National and international climate communities are already keeping a close eye on California’s AB32 Global Warming Solutions Act, which includes the Cap and Trade Program as part of a package of policies aimed at cost-effectively reducing California’s emissions. The impact of the Climate Credit — the first of its kind — is worth watching to determine if similar mechanisms could be used successfully elsewhere. In particular, the Credit’s impact on both energy efficiency and public support for the Cap and Trade program will be especially interesting to follow.

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The promise and pitfalls of shareholder incentives: Lessons from California’s high-stakes test

February 19, 2014 |

 

This post originally appeared on Intelligent Utility.

How many millions of dollars does it take to change a state’s light bulbs?

This sounds like the start of a joke, but for the last seven years, it’s been anything but to California utilities and regulators. The crux of the dispute, which has had stakes in the hundreds of millions of dollars, has been an ambitious—but controversial—shareholder incentive designed to motivate California utilities toward greater energy efficiency.

The policy, called the Risk/Reward Incentive Mechanism, or RRIM, targeted California utilities. However, the concept of a shareholder incentive is one that 20 other states have adopted in recent years. It’s also under discussion at the federal level as part of President Obama’s proposed Race to the Top Energy Efficiency Initiative.

So what can utilities in other states learn from California’s experience? Climate Policy Initiative’s recent analysis, “Raising the Stakes for Energy Efficiency: California’s Risk/Reward Incentive Mechanism,” draws a few lessons that stand out.

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Will California’s AB327 help or hinder renewable energy? The devil is in the details

November 18, 2013 |

 

California Assembly Bill 327 (AB327), signed into law October 7th, 2013, drew fire from solar and energy efficiency proponents, The Sierra Club, and other environmental groups over the rate-setting powers it would give the California Public Utilities Commission (CPUC). These opponents worry that the bill allows changes in rate and regulatory structure that could discourage renewable energy investment in California. However, local governments, industry groups, utilities and some consumer groups argue these same powers could, used wisely, make electricity rates more equitable, protect consumers and help utilities adapt to an increasingly renewable and distributed grid. Climate Policy Initiative’s analysis suggests they could also create a very fertile and cost-effective environment for renewable energy for years to come.

AB327 allows the extension of the Renewable Portfolio Standard (RPS) and requires the extension of the Net Energy Metering program, both of which Climate Policy Initiative analysis has shown to be significant drivers of renewable energy growth in California. Many of the details of their implementation are left to the CPUC, though, and these details will decide the ultimate impact of AB327 on renewable energy in California.

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Renewable portfolio standards – the high cost of insuring against high costs

December 17, 2012 |

 

State-level renewable portfolio standards (RPS) are a critical part of the U.S. renewable energy policy landscape. 29 states and Washington DC have enacted mandatory RPS policies. Taken together, they require that nearly 10% of U.S. electricity comes from RPS-eligible renewable energy sources by 2020.

But state policy makers have expressed concern about the potential cost of these policies. Over 20 states have included some form of cost limit in their policy. These cost limits are intended to protect electricity consumers from unacceptably high costs, and mitigating this risk can help increase political and public support for the policy. But depending on how they are designed and implemented, these cost limits can have unintended effects: They can increase the cost of deploying renewable energy, make RPS policies more complicated and less certain, and sometimes do not even limit costs as intended.

States have taken a wide range of approaches to limiting costs. Common approaches include:

  • Alternative compliance payments – ACPs let electricity suppliers meet their renewable energy requirements by making a payments rather than purchasing renewable energy credits or contracting with renewable energy projects. These payments are often used to fund complementary clean energy or energy efficiency programs. The ACP level is usually set by a regulator, and in practice, creates a maximum price for renewable energy credits.
  • Rate impact caps – Some states put a limit on how much renewable energy policy can increase electricity rates. These mechanisms vary significantly from state to state in terms of which renewable energy costs are included, how they are calculated, and the time period that they apply to.
  • Per-customer cost caps – A handful of states place a limit on the dollar amount any particular customer’s bill can increase because of the RPS.
  • Contract price caps – A couple of states have applied limits on the price that a renewable energy generator can contract to sell power to a utility.
  • Funding limits – Several states have created limits to the amount of funding that can be used to cover the costs of renewable energy.

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