Tag Archives: electricity

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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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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What’s working and what’s not in state renewable portfolio standards

July 11, 2013 |

 

Combined renewable portfolio standards in the United StatesRenewable portfolio standards (RPS) are an important part of the U.S. renewable energy policy landscape.Twenty-nine states, from California to North Carolina, have enacted these policies to require utilities to provide at least some of their power from renewable sources. This year, at least fourteen of these states considered bills that would have watered down or repealed these policies. But these rollbacks proved to be unpopular, and on balance state legislatures have made RPS policies more ambitious in 2013.

Taken together, RPS policies will require nearly 10% of electricity sold in the U.S. to come from renewable sources by 2020. And with the help of federal tax credits, grants and loan guarantees, most RPS policies appear to have had limited impacts on electricity rates so far. But every state’s RPS is different, and the diversity of policy designs is a great opportunity to learn what is working well and what can be improved in these policies.

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In India, Renewable Energy Certificates are missing the target

February 11, 2013 |

 

In 2008, India’s National Action Policy on Climate Change set a renewable portfolio standard, called the Renewable Purchase Obligation (RPO), to produce 15% of the country’s electricity with renewable energy sources by 2020. Further, under the Jawaharlal Nehru National Solar Mission, the Indian government aims to develop 20,000 MW of solar energy by 2022.

To help reach these ambitious targets in a cost-effective manner, India launched a market-based mechanism called Renewable Energy Certificates (RECs) in 2010.

However, in the one year of trading so far, participation in the REC markets has been low: RECs have failed to attract investment. Though the design of the REC mechanism appears adequate, the performance of the market has been far from satisfactory. This, along with other issues, such as the cost of debt, translates to real concerns over whether India is on track to meet its ambitious targets.

So why is this happening?

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