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Strong and stable, or storing up trouble? The outlook for energy storage projects in the UK

While strength and stability have taken rhetorical centre stage in the run-up to the UK’s snap General Election on 8 June, the GB energy system faces radical uncertainty on a number of fronts at a time when its stakeholders need it least. So far, the main election focus on energy has inevitably been price caps for household gas and electricity bills. But once the excitements of the campaign and polling day are over, the new government will need to make up for lost time on some less potentially vote-grabbing issues that are central to the continued health of the GB energy sector. None of these is more pressing than how to respond to the possibilities opened up by energy storage technology.

This post will summarise the benefits of energy storage as an enabler of system flexibility, look at the technology options and market factors in play and consider both some of the practical issues faced by developers and the regulatory challenges that – General Election and Brexit notwithstanding – urgently need to be addressed by the government and/or the sector regulator Ofgem.

Benefits of energy storage

The most widely cited benefit of energy storage is the ability to address the intermittency challenge of renewable sources. For more than 100 years, the general lack of bulk power storage in the GB electricity system (other than a small amount of pumped hydro capacity) did not matter. Fluctuations in demand could easily be met by adjusting the amount of power produced by centralised fossil fuel plant that generally had fairly high utilisation rates. But in a power industry transformed by the rise of wind and solar technology, things are different. As a greater proportion of the generating mix is made up of technologies that cannot be turned on and off at will, often in areas where grid capacity is limited, storage offers the possibility that large amounts of power could be consumed hours or days after it is generated, reducing the otherwise inevitable mismatch between consumers’ demands for electricity and the times when the sun is out, the wind is blowing or the waves are in motion.

In a world that increasingly wants to use low carbon sources of electricity which are inherently less easy to match to fluctuations in demand than fossil fuelled generation, storage reintroduces an important element of flexibility. More specific advantages of energy storage range across value chain.

  • For generators, power generated at times of low demand (or when system congestion makes export impossible) can be stored and sold (more) profitably when demand is high, exploiting opportunities for arbitrage in the wholesale market and potentially also earning higher revenues in balancing markets. But storage does not just help wind and solar power. It can also help plants using thermal technologies that work most efficiently operating as baseload (such as combined cycle gas turbines or nuclear plants), but which may not find it economic to sell all their power at the time it is generated. Even peaking plants can use storage to their advantage by avoiding the need to waste fuel in standby mode (using e.g. battery power to cover the period in which they start up in response to demand).
  • For transmission system operators and distribution network operators, energy storage can mitigate congestion, defer the need for investment in network reinforcement and help to maintain the system in balance and operating within its designated frequency parameters by providing a range of ancillary or balancing services such as frequency response.
  • For end users, particularly those with some capacity to generate their own power, and providers of demand-side response services who aggregate end users into “virtual power plants”, energy storage can increase household or business self-consumption rates. And in a world of tariffs differentiated by time of use (enabled by smart metering), storage opens up the possibility of retail-level arbitrage or peak shaving: buying power when it is cheaper (because not many people want it) and storing it for use it at times when it would be more expensive to get it from the grid (because everybody wants to use it).

What could all that mean in practice? Estimates in National Grid’s Future Energy Scenarios 2016 suggest that over the next 25 years, deployment of storage in the UK could grow at least as rapidly as deployment of renewables has grown over the last 20 years. Also in 2016 the Carbon Trust and Imperial College London published a study that modelled the implementation of storage and other flexible technologies across the electricity system, and showed projected savings of between £17 billion and £40 billion between now and 2050. In a consultation published in May 2017, distribution network operator Western Power Distribution (WPD) invited comment on its proposed planning assumptions for the growth of storage in GB from its current capacity of 2.7 GW (all pumped hydro plants): these are a “low growth” scenario that anticipates 4-5 GW (6-15 GWh) by 2030 and a “high growth” scenario of 10-12 GW (24-44 GWh) by that date. Growth of storage at that higher rate would see it outstripping or close to matching current government estimates for the development of new gas-fired or nuclear generation, or new interconnection capacity over the same period. (Although it should be noted that the government’s own projections for the growth of storage are more in line with WPD’s low growth scenario: see this helpful analysis by Carbon Brief.)

Technology options

As is the case in Europe and the rest of the world, energy storage in the UK is currently mostly supplied by pumped hydropower plants, which account for almost all storage capacity and are connected to the transmission system. Until very recently, the much less frequently deployed technique of compressed air energy storage (CAES) was the only other commercially available technology for large-scale electricity storage. The two technologies are similar in that both use cheap electricity to put a readily available fluid (water or air) into a state (up a mountain or under pressure) from which it can be released so as to flow through a turbine and generate power. They differ in that pumped hydro requires a specific mountainous topography, whereas CAES can use a variety of geologies (including salt caverns, depleted oil and gas fields and underground aquifers).

But it is batteries that are currently attracting the keenest investor interest in storage. There are many different battery technologies competing for investment and market penetration. Those based on sodium nickel chloride or sodium sulphur have made advances, but most storage attention surrounds batteries based on lithium-ion structures, also the battery of choice for the electric car industry, where competition has driven down costs. Just before the General Election got under way, the Department of Business, Energy and Industrial Strategy (BEIS) announced £246 million of funding for the development and manufacture of batteries for electric vehicles. Electric car batteries need to be able to deliver a surge of power far more rapidly than those deployed in the wider power sector: in Germany, car manufacturers are already exploring the use of electric car batteries that no longer up to automotive specifications in grid-based applications. In the North East of England, distribution network company Northern Powergrid is collaborating with Nissan to look at how integration of electric vehicles can improve network capacity, rather than just placing increased demands on the grid.

The cost of batteries has come down because of improvements in both battery chemistry and manufacturing processes, as well as the economies of scale associated with higher manufacturing volumes such as with Tesla and Panasonic’s new battery Gigafactory in Nevada. Underlining rising global expectations about low cost and set-up time for battery production, in March 2017 Tesla’s Elon Musk offered to build a 100 MWh battery plant in Australia within 100 days, or to give the system away for free if delivery took any longer.

Batteries are ideally suited to many applications, but they also have some drawbacks. They are less good at providing sustained levels of power over long periods of discharge, and on a really large scale, than CAES or pumped hydro. The non-battery technologies also have other selling points. For example, CAES also has a unique ability, when combined with a combined cycle gas turbine, to reduce the amount of fuel it uses by at least a third. Given the likelihood that the UK power system will continue to need a significant amount of new large-scale gas fired plant, even as it decarbonises, and given the current slow development of carbon capture and storage technology, the potential reduction in both the costs and the carbon footprint of new gas-fired power that CAES offers is well worth consideration by both developers and government. Finally, as regards future alternative technology options, hydrogen storage and fuel cells are the subject of significant research efforts and funding. Most enticing from a decarbonisation perspective, is the prospect of electrolysing water with electricity generated from renewables to produce “green hydrogen”, which can then be used to generate clean power with the same level of flexibility as methane is at present.

Models and market factors

In the abstract, it might be thought that energy storage projects could be categorised into five basic business models:

  • integrated generator services: storage as a dedicated means of time-shifting the export of power generated from specific generating plants (renewable, nuclear or conventional), with which the storage facility may or may not be co-located, and so optimising the marketing of their power (and in some cases, where there are grid constraints, enabling more power to be generated, and ultimately exported, than would otherwise be the case);
  • system operator services: providing frequency response and other ancillary or balancing services to National Grid in its role as System Operator (and potentially, in the future, to a distribution system operator that is required to maintain balance at distribution level): a distinction can be made between “reserve” and “response” services, the latter involving very quick reaction to instructions designed to ensure frequency or voltage control;
  • network investment: enabling distribution networks to operate more efficiently and economically, for example by avoiding the need for conventional network reinforcement. This was notably successfully demonstrated by the 6 MW battery at Leighton Buzzard built by UK Power Networks (UKPN). The results of WPD’s Project FALCON were a little more equivocal, but it is trying again, using Tesla batteries to test a range of applications at sites in the South West, South Wales and the East Midlands);
  • merchant model: a standalone storage facility making the most of opportunities to buy power at low prices and sell it at high prices, with no tie to particular generators, and perhaps underpinned by Capacity Market payments (see further below);
  • “behind the meter”: enabling consumers to reduce their energy costs (retail level arbitrage or peak shaving, as noted above, as well as maximising use of on-site generation where this is cheaper than electricity from the grid).

These models are far from being mutually exclusive. Indeed, at present, they are best thought of as simply representing different categories of potential revenue streams: the majority of storage projects will need to access more than one of these streams in order to be viable. Some will opt to do so through contracts with an aggregator, for whom a relationship with generation or consumption sites with storage, particularly if they have a degree of operational control over the storage facility, offers an additional dimension of flexibility.

In the short term, the largest revenue opportunity may be the provision of grid services. The need for a fast response to control frequency variations is likely to increase in the future as a result of the loss of coal-fired plant from the system.

Growing interest in energy storage also owes much to the decline in the UK greenfield renewables market, with the push factor of the removal or drastic reduction of subsidies previously available for new renewable energy projects and the pull factor of the battery revolution. According to a report published in May 2017 by SmartestEnergy, an average of 275 solar, wind and other renewable projects were completed in each quarter between 2013 and the last quarter of 2016, when the figure plummeted to 38. Only 21 renewable projects were completed in the first quarter of 2017.

So why, when UKPN, for example, report that between September 2015 and December 2016 they processed connection applications from 600 prospective storage providers for 12 GW of capacity, is the amount of battery capacity so far connected only in the tens of MW?

Tenders and auctions

It may help to begin by looking at another very specific factor that drove this extraordinary level of interest in a technology that had been so little deployed to date. This was National Grid’s first Enhanced Frequency Response (EFR) tender, which took place in August 2016. A survey by SmartestEnergy, carried out just before the results of the tender were announced, found that 70 percent of respondents intending to develop battery projects in the near future were anticipating that ancillary services would be their main source of revenue.

National Grid were aiming to procure 200 MW of very fast response services. Although “technology neutral”, the tender was presented as an opportunity for battery storage providers and as expected, storage, and specifically batteries, dominated. All but three of the 64 assets underlying the 223 bids from 37 providers were battery units. Perhaps less expected were the prices of the winning bids: some as low as £7/MWh and averaging £9.44/MWh. The weighted price of all bids was £20.20/MWh.

This highly competitive tender gave the UK energy storage market a £65 million boost. The pattern of bids suggested that alongside renewables developers and aggregators, some existing utilities are keen to establish themselves in the storage market, and are prepared to leverage their lower cost of capital and accept a low price in order to establish a first mover advantage.

Independent developers who regard storage as a key future market might also have been bullish in their calculations of long-term income while accepting lower revenues in the near term to compete in a crowded arena. For all bidders, one of the key attractions was the EFR contract’s four-year term, which makes a better fit with their expectations of how long it will take to recoup their initial investment than the shorter duration of most of National Grid’s other contracts for balancing / ancillary services.

Aspiring battery storage providers also responded enthusiastically to the regular four year ahead (T-4) Capacity Market (CM) auction when it took place for the third time in December 2016. To judge from the Register for the T-4 2016 auction, some 120 battery projects, with over 2 GW of capacity between them, were put forward for prequalification in this auction. (This assumes that all the new build capacity market units (CMUs) described as made up of “storage units” and not obviously forming part of pumped hydro facilities were battery-based.) Although almost two-thirds of these proposed CMUs are described on the relevant CM register as either “not prequalified” or “rejected”, of the remaining 33 battery projects, no fewer than 31 projects, representing over 500 MW of capacity between them, went on to win capacity agreements in the auction.

There are a number of points to be made in connection with these results.

  • Taking the CM and EFR together, the range of parties interested in batteries is noteworthy, as is the diversity of motivations they may have for their interest.  It includes grid system operators (UKPN), utilities (EDF Energy, Engie, E.ON, Centrica), renewables developers (RES, Element Power, Push Energy, Belectric), storage operators, aggregators / demand side response providers (KiWi Power, Limejump, Open Energi) and end-users, as well as new players who seem to be particularly focused on storage (Camborne Energy Storage, Statera Energy, Grid Battery Storage).
  • Developers of battery projects are evidently confident that the periods during which they may be called on to meet their obligations to provide capacity by National Grid will not exceed the length of time during which they can continuously discharge their batteries – in other words, that the technical parameters of their equipment do not put them at an unacceptable risk of incurring penalties for non-delivery under the CM Rules: a point that some had questioned.
  • The CM Rules are stricter than those of the EFR tender as regards requiring projects to have planning permission, grid connection and land rights in place as a condition of participating in the auction process. This is presumably one reason why fewer battery projects ended up qualifying to compete in the T-4 auction as compared with the EFR tender.
  • For batteries linked to renewable electricity generation schemes that benefit from renewables subsidy schemes such as the Renewables Obligation (RO), the EFR tender was an option, but the CM was not, since CM Rules prohibit the doubling up of CM and renewables support. So, for example, the 22 MW of batteries to be installed at Vattenfall’s 221 MW RO-accredited Pen-y-Cymoedd wind farm was successful in the EFR tender but would presumably not have been eligible to compete in the CM.
  • Accordingly, CM projects tend to be designed to operate quite independently of any renewable generating capacity with which they happen to share a grid connection. But some of these projects are located on farms that might have hosted large solar arrays when subsidies were readily available for them. Green Hedge, four of whose projects were successful in the T-4 2016 CM auction, has even developed a battery-based storage package called The Energy BarnTM. Others CM storage projects are located on the kind of industrial site that might otherwise be hosting a small gas-fired peaking plant. UK Power Reserve (as UK Energy Reserve), which has been very successful with such plants in all the T-4 auctions to date, won CM support for batteries at 12 such locations.
  • The Capacity Market may be less lucrative than EFR, measured on a per MW basis, but it offers the prospect of even longer contracts: up to 15 years for new build projects.
  • Batteries are still a fairly new technology. The clearing price of Capacity Market auctions has so far been set by small-scale gas- or diesel-fired generating units using well established technology. In a T-4 auction, the CMUs, by definition, do not have to be delivering capacity until four years later – although the Capacity Market Rules oblige successful bidders to enter into contracts for their equipment, and reach financial close, within 16 months of the auction results being announced. Other things being equal (which they may not be: see next bullet), it will clearly be advantageous to developers if they can arrange that the prices they pay for their batteries are closer to those prevailing in 2020 than in 2016. It has been pointed out that although internationally, battery prices may have fallen by up to 24 percent in 2016, the depreciation of Sterling over the same period means that the full benefit of these cost reductions may not yet be accessible to UK developers.
  • The proportion of prequalified battery-based CMUs that were successful in the T-4 2016 CM auction was remarkably high. But may not have been basing their financial models solely or even primarily on CM revenues. In addition to EFR and other National Grid ancillary services, such as Short Term Operating Reserve or Fast Reserve, and possible arbitrage revenues, it is likely that at least some projects were anticipating earning money by exporting power onto the distribution network during “Triad” periods. This “embedded benefit” would enable them to earn or share in the payments under the transmission charging regime that have been the main source of revenue for small-scale distributed generators bidding in the CM, enabling them to set the auction clearing price at a low level and prompting a re-evaluation of this aspect of transmission charges by Ofgem. From Ofgem’s March 2017 consultation on the subject, it looks as if these payments will be drastically scaled down over the period 2018 to 2020. This may give some developers a powerful incentive to deploy their batteries early (notwithstanding the potential cost savings of waiting until 2020 to do so) so as to benefit from this source of revenue while it lasts. Those who compete in subsequent CM auctions may find that the removal of this additional revenue leads to the CM auctions clearing at a higher price.
  • As with EFR, some developers may be out to buy first mover advantage, and most already have a portfolio of other assets and/or sources of revenue outside the CM. But what they are doing is not without risk, since the penalties for not delivering a CMU (£10,000, £15,000 or £35,000 / MW, depending on the circumstances) are substantial.
  • Meanwhile, a sure sign of the potential for batteries to disrupt the status quo can be seen in the fact that Scottish Power has proposed a change to the CM Rules that would apply a lower de-rating factor to batteries for CM purposes than to its own pumped hydro plant.

Finally, one other tender process, that took place for the first time in 2016, could point the way to another income stream for future projects. National Grid and distribution network operator Western Power Distribution co-operated to procure a new ancillary service of Demand Turn Up (DTU).

The idea is to increase demand for power, or reduce generation, at times when there is excess generation – typically overnight (in relation to wind) and on Summer weekends (in relation to solar). DTU is one of the services National Grid use to ensure that at such times there is sufficient “footroom” or “negative reserve”, defined as the “continuous requirement to have resources available on the system which can reduce their power output or increase their demand from the grid at short notice”.

National Grid reports that over the summer of 2016, the service was used 323 times, with “10,800 MWh called with an average utilisation price of £61.41/MWh”. The procurement process can take account of factors other than the utilisation and availability fees bid, notably location. Successful tenders in the 2017 procurement had utilisation fees as high as £75/MWh.

At present, the procurement process for DTU does not appear to allow for new storage projects to compete in DTU tenders, but once they have become established, they should be well placed to do so, given their ability to provide demand as well as generation. They could be paid by National Grid to soak up cheap renewable power when there is little other demand for it. If National Grid felt able to procure DTU or similar services further in advance of when they were to be delivered, the tenders could have the potential to provide a more direct stimulus to new storage projects.

Battery bonanza?

Those who have been successful in the EFR or CM processes can begin to “stack” revenues from a number of income streams. And the more revenues you already have, the more aggressively you can bid in future tenders (for example for other ancillary services) to supplement them.

But even if all the projects that were successful in the EFR and CM processes go ahead, they will still represent only a small fraction of those that have been given connection offers. Moreover, it looks as if the merchant and ancillary services models are the only ones making significant headway at present.  Why are we not seeing more storage projects integrated with renewables coming forward, for example? Why, to quote Tim Barrs, head of energy storage sales for British Gas, has battery storage “yet to achieve the widespread ‘bankable status’ that we saw with large-scale solar PV”?

Technology tends to become bankable when it has been deployed more often than batteries coupled with renewables have so far in GB. But even to make a business case to an equity investor, a renewables project with storage needs to show that over a reasonable timeframe the additional revenues that the storage enables the project to capture exceed the additional costs of installing the storage. What are these costs, over and above the costs of the batteries and associated equipment?  What does it take to add storage to an existing renewable generating project, or one for which development rights have already been acquired and other contractual arrangements entered into?

  • The configuration and behaviour of any storage facility co-located with subsidised renewable generation must not put the generator’s accreditation for renewable subsidies at risk because of e.g. a battery’s ability to absorb and re-export power from the grid that has not been generated by its associated renewable generating station. The location of meters is crucial here. According to the Solar Trade Association, only recently has Ofgem for the first time re-accredited a project under the RO after storage was added to it. While an application for re-accreditation is being considered, the issue of ROCs is suspended. Guidance has been promised which may facilitate re-accreditation for other sites. Presumably in this as in other matters, the approach for Feed-in Tariff (FIT) sites would follow the pattern set by the RO. For projects with existing Contracts for Difference (CfDs), there is no provision on energy storage. For those hoping to win a CfD in the 2017 allocation round, the government has made some changes to the contractual provisions following a consultation, but, as the government response to consultation makes clear, a number of issues still remain to be resolved.
  • An existing renewables project is also likely to have to obtain additional planning permission. There may be resistance to battery projects in some quarters. RES recently had to go to appeal to get permission for a 20 MW storage facility by an existing substation at Lookabootye after its application was refused by West Lothian Council. It will also be necessary to re-negotiate existing lease arrangements (or at least the rent payable under them), and additional cable easements may be required.
  • Unless it is proposed that the battery will take all its power from the renewable generating station (which is unlikely), it will be necessary to seek an increase in the import capacity of the project’s grid connection from the distribution network operators. Even if the developer does not require to be able to export any more power at any one time from the development as a whole, in order to charge the battery at a reasonable speed from the grid it will need a much larger import capacity than is normal for an ordinary renewable generating facility. The ease and costs of achieving this will vary depending on the position of the project relative to the transmission network. There may be grid reinforcement costs to pay for: UKPN has noted that there are few places on the network with the capacity to connect a typical storage unit without some reinforcement. They will also treat the addition of storage as a material change to an existing connection request for a project that has not yet been built, prompting the need for redesign and resulting in the project losing its place in the queue of connection applications.
  • A power purchase agreement (PPA) for a project with storage will need to address metering. For the purposes of the offtaker, output will either need to be measured on the grid side of the storage facility (the same may not be true of metering for renewable subsidy purposes), or an agreed factor will need to be applied to reflect power lost in the storage process. Secondly, in order to maximise the opportunities for arbitrage by time-shifting the export of its power, a project with storage may want more exposure to fluctuations in the wholesale market price, and even to imbalance price risk, than a traditional intermittent renewables project. The detail of how embedded benefits revenues are to be shared between generator and offtaker may also require to be adjusted if the addition of storage makes it more likely they will be captured.

For the moment, most renewables projects probably fall into one of two categories with regard to integrated storage.

  • On the one hand, there are those that are already established and receiving renewable generation subsidies, or which have been planned without storage and now simply need to commission as quickly as possible in order to secure a subsidy (for example, under RO grace period rules for onshore wind projects). For them, introducing storage into an existing project may be more trouble than it is worth for some or all of the reasons noted above. They have little incentive to deploy storage unless it is an economic way of reducing their exposure to loss of revenue as a result of grid constraints or to imbalance costs: these have been increasing following the reforms introduced by Ofgem in 2015 and will increase further as the second stage of those reforms is implemented in 2018, but for many renewable generators are a risk that is assumed by their offtakers.
  • On the other hand, for projects with no prospect of receiving renewable subsidies, it would appear that the cost of storage is not yet low enough, or the pattern of wholesale market prices sufficiently favourable to a business model built on  time-shifting and arbitrage to encourage extensive development of renewables + storage merchant model projects. If it was generally possible easily to earn back the costs of installing storage through the higher wholesale market revenues captured by – for example – time-shifting the export of power from a solar farm to periods when wholesale prices are higher than they are during peak solar generating hours, the volume and profile of successful storage + renewable projects in the CM and elsewhere would be different from what it now is.

However, battery costs will continue to fall, and wholesale prices are becoming “spikier”. It may only be a matter of time before GB’s utility-scale renewables sector, whose successful players have so far built their businesses on the predictable streams produced by RO and FIT subsidies, can get comfortable with business cases that depend more fundamentally on the accuracy of predictions about how the market, rather than the weather, will behave. Moreover, there is nothing to stop a storage facility co-located with a renewables project that has no renewable subsidy from earning a steady additional stream of income in the form of CM payments.

Arguably, the UK has missed a trick in not having adopted pump-priming incentives for combining storage with renewables, such as setting aside a part of the CfD budget for projects with integrated storage. But with the door apparently generally closed for the time being on any form of subsidy for large-scale onshore wind or solar schemes in most of GB, it is probably unrealistic to hope for any such approach to be taken in the near future.

Regulatory challenges

There are undoubtedly already significant commercial opportunities for some GB storage projects, but it does not feel as if the full power of storage to revolutionise the electricity market is about to be unleashed quite yet. This is perhaps not surprising.

Almost as eagerly awaited among those interested in storage as the results of the EFR tender was a long-promised BEIS / Ofgem Call for Evidence on how to enable a “smart, flexible energy system”, which was eventually published in November 2016. This Call for Evidence, the first of its kind, represented a significant step forward for the regulation of storage in the UK, but although it pays particular attention to storage and the barriers that storage operators may face it is not just “about” storage. It ultimately opens up questions about how well the current regulatory architecture, designed for a world of centralised and despatchable / baseload power generation, can serve an increasingly “decarbonised, distributed, digital” power sector without major reform. (At an EU level, the European Commission’s Clean Energy Package of November 2016 tries to answer some of these questions, and there is generally no shortage of thoughtful suggestions for reforming power markets, such as the recent Power 2.0 paper from UK think tank Policy Exchange, or the “Six Design Principles for the Power Markets of the Future” published by Michael Liebreich of Bloomberg New Energy Finance.)

However, whilst it is important to take a “whole system” approach, it would be unfortunate if the breadth of the issues raised by the Call for Evidence were to mean that there was any unnecessary delay in addressing the regulatory issues of most immediate concern to storage operators. Government and regulators have to start somewhere, and it is not unreasonable to start by trying to facilitate the deployment of storage since it could facilitate so many other potentially positive developments in the industry.

On 25 April Ofgem revealed that it had received 240 responses to the Call for Evidence, with around 150 responses commenting on energy storage. Barriers to the development of storage identified by respondents include the need for a definition of energy storage, clarity on the regulatory treatment of storage, and options for licensing. The response from the Energy Storage Network (ESN) offers a good insight into many of the issues of most direct concern to storage operators. Some of the other respondents who commented on storage also demonstrated an appetite for fundamental reform of network charging (described by one as “probably not fit for purpose in its current form”) and for significant shifts in the role of distribution network operators.

Interest in a definition of energy storage is unsurprising. It is arguably hard to make any regulatory provision about something if you have not defined it. But at the same time, the Institution of Engineering and Technology may well be correct when it says in its response to the Call for Evidence: “lack of a definition is not a barrier in itself…as the measures are developed to address the barriers to storage, it will become clear whether a formal definition is required and at what level…agreeing a definition should be an output of regulatory reform, not an input.”. In other words, how you define something for regulatory purposes – particularly if that thing can take a number of different forms and operate in a number of different ways – will depend in part on what rules you want to make about it.

Under current rules, energy storage facilities end up being classified, somewhat by default, as a generation activity – even though their characteristic activity does not add to the total amount of power on the system. But because storage units also draw power from the grid, they find themselves having to pay two sets of network charges – on both the import and the export – even though they are only “warehousing” the power rather than using it. Both these features of the current regulatory framework are strongly argued against by a variety of respondents to the Call for Evidence.

Treating storage as generation complicates the position for distribution network operators wishing to own storage assets. Under the current unbundling rules (which are EU-law based, but fully reflect GB policy as well), generation and network activities must be kept in separate corporate compartments. These rules are designed to prevent network operators from favouring their own sources of generation (or retail activities). The issue is potentially more acute when you have a storage asset forming part of the network company’s infrastructure and regulated asset base, but having the ability to trade on the wholesale power and ancillary services markets in its own right as well as to affect the position of other network users (by mitigating or aggravating constraints). UKPN considers that the approach it has adopted with its large battery project could provide a way around this problem for others as well – essentially distinguishing the entity that owns the asset from the entity responsible for its trading activity on the market. However, such an arrangement is not without costs and complexity, both for those involved to set up and for the regulator to monitor. The ESN has also made proposals in its response to the Call for Evidence about the conditions under which distribution network operators should be permitted to operate storage facilities.

It may be that the most useful contribution that transmission and distribution network operators could make to the development of storage would be to determine as part of their multi-year rolling network planning processes where it would be most beneficial in system terms for new storage capacity of one kind or another to be located. But the underlying question is whether at least some storage projects should be treated more as network schemes with fixed OFTO or CATO-like rates of return rather than being regarded as part of the competitive sector of the market along with generation and supply. (Similar concerns about the status of US network-based storage projects, admittedly in a slightly different regulatory environment, have been addressed by the Federal Energy Regulatory Commission in a recent policy statement and notice of proposed rulemaking.)

If storage is not to be treated as generation or necessarily part of a network (and required to hold a generation licence where no relevant exemption applies), what is it? Should it be recognised as a new kind of function within the electricity market? In which case, the natural approach under the GB regulatory regime would be to require storage operators to be licensed as such (again, subject to any statutory exemptions). That would require primary legislation (i.e. an Act of Parliament) to achieve, at a time when Parliamentary time may be at a premium because of Brexit – and then there would need to be drafting of and consultation on licence conditions and no doubt also numerous consequential changes to the various industry-wide codes and agreements.

The ESN’s Call for Evidence response has some helpful suggestions as to what a licensing regime for storage might look like. But is the licensing model is a red herring in this context? After all, the parallel GB regulatory regime for downstream gas includes no requirement for those wishing to operate an onshore gas storage facility to hold a licence to do so under the Gas Act 1986. And it is entirely possible to trade electricity on the GB wholesale markets (a key activity for storage facilities), without holding a licence under the Electricity Act 1989 (or even engaging in an activity requiring such a licence but benefiting from an exemption from the requirement to hold a licence).

As for some of the current financial disadvantages facing storage, it is encouraging that in consulting on its Targeted Charging Review of various aspects of network charging in March 2017, Ofgem provisionally announced its view that some double charging of storage should be ended. It consulted on a number of changes that, taken together, should have the effect of ensuring that “storage is not an undue disadvantage relative to others providing the same or similar services”. However, although welcome, these Ofgem proposals so far only cover the treatment of the “residual” (larger) element of transmission network charges for demand (applicable to distribution-connected projects), in respect of storage units co-located with generation. It remains to be seen whether – and if so, what – action will be taken to deal with other problems in this area, such the payment of the “final consumption” levies that recover the costs of e.g. the RO and FIT schemes by both the storage provider and the consumer on the same electricity when a storage operator buys that electricity from a licensed supplier. Storage operators can at present only avoid this cost disadvantage if they acquire a generation licence, which does not seem a particularly rational basis for discriminating between them in this context.

Speaking in March, the head of smart energy policy at BEIS, Beth Chaudhary, said that ending the double counting of storage “might require primary legislation”, adding that Brexit has made the progress of such legislation “difficult at the moment”. The General Election has only added to concerns of momentum loss, a sense of “circling the landing strip” in the words of the Renewable Energy Association’s chief executive, Dr Nina Skorupska.

“The revolution will not be televised”…but it probably needs to be regulated

What is the storage revolution? Storage will not turn the electricity industry into a normal commodity market, like oil, overnight – or indeed ever. We will still have to balance the grid. As before, what is being exported onto the grid will need to match what is being imported from it at any given moment. It’s just that storage will provide an additional source of power to be exported onto the grid (which was generated at an earlier time) and it will also facilitate more balancing actions by those on the demand side where they have access to it. It is also likely that increased use of micro grids, with the ability to operate in “island mode” as well as interconnected with the public grid, will result in the public grid handling a smaller proportion of the power being generated and consumed at any given time.

Of course, one could look at this and say: “Fine, but what’s the hurry?”. The UK developed a renewables industry when it was still a relatively new and expensive thing to do. Thanks to the efforts made by the UK and others, renewables are now both “mainstream” and relatively cheap. Those countries that are only starting to develop sizeable renewable projects now are reaping the benefit of the cost reductions achieved by the early adopters. Would it be such a bad thing if a GB storage revolution was delayed for a year or two while other markets experiment with the technology and help it to scale up, reducing the costs that UK businesses and consumers will pay for its ultimate adoption in the UK?

After all, we have to be realistic about the number of large and difficult issues the UK government and regulators can be expected to focus on and take forward at once. Is it not more important, for example, to reach agreement with the rest of the EU on a satisfactory set of substitute arrangements for the legal mechanisms that currently govern the UK’s trade in electricity and gas with Continental Europe (and the Republic of Ireland)? In addition, the General Election manifestos of each party prioritise other contentious areas of energy policy for action, such as facilitating fracking and reducing the level of household energy bills.

We do not deny the importance of these other issues, and BEIS and Ofgem resources are, of course, finite, but we would argue that storage and the complex of “flexibility” issues to which it is central should be high on the policy agenda after 8 June in any event.

  • GB distribution network operators have already done lot of valuable work on storage, much of it funded by various Ofgem initiatives (notably the Innovation Funding Incentive, Network Innovation Allowance and Low Carbon Networks funding). This has generated a body of published learning on the subject which continues to be added to and which it would be a pity not to capitalise on as quickly as possible.
  • Depending (at least in part) on the outcome of Brexit, we may find ourselves either benefiting from significantly more interconnection with Continental European power markets, or becoming more of a “power island” compared with the rest of Europe. In either case, a strong storage sector will be an advantage. Storage can magnify the benefits of interconnection but it would also help us to optimise the use of our own generating resources if our ability to supplement them (or export their output) through physical links to other markets was limited.
  • The UK has in some respects led the world on power market reform.  We have complex, competitive markets and clever companies that have learnt how to operate in them. Looking at storage from an industrial strategy point of view, the UK is may not make its fortune after by the mass manufacture of batteries for the rest of the world, but the potential for export earnings from some of the higher value components of storage facilities, and the expertise to deploy them to maximum effect, should not be neglected.
  • On the other hand, if the UK wants to maintain its position as an attractive destination for investment in electricity projects, it needs to show that it has a coherent regulatory approach to storage, both because storage will increasingly become an asset class in its own right and because sophisticated investors in UK generation, networks or demand side assets will increasingly want to know that this is the case before committing to finance them.
  • As the Call for Evidence and the other attempts to address the challenges of future power markets referred to above make clear, everything is connected. There is, arguably, not very far that you can or should move forward on any aspect of generation or other electricity sector policy without forming a view on storage and how to facilitate it further.
  • Finally, because some of the policy and regulatory issues are hard and resources to address them are finite, this will all take time, so that with luck, the regulatory framework will have been optimised by about the same time as the price reductions stimulated by demand from the US and other forward-thinking jurisdictions have started to kick in.

Almost whatever problem you are looking at, whether as a regulator or a commercial operator in the GB power sector, it is worth considering carefully whether and how storage could help to solve it. Storage has the potential, as noted above, to change the ways that those at each level in the electricity value chain operate, and with the shift to more renewables and decentralised generation, it has a significant part to play in making future electricity markets “strong and stable”. The “trouble” alluded to in the title of this post is change either happening faster than politicians and regulators can keep pace with, or innovation being stifled by the lack of regulatory adaptation as they find it too difficult to address the challenges it poses when faced with other and apparently more urgent priorities. Because the ways in which generators, transmission and distribution network operators, retailers and end users interact with each other is so much a function of existing regulation of one kind or another, it is very hard to imagine storage reaching its full potential without significant regulatory change. These changes will take time to get right, but since ultimately an electricity sector that makes full use of the potential of storage should be cheaper, more secure and more environmentally sustainable than one that does not, there should be no delay in identifying and pursuing them.

 

 

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Strong and stable, or storing up trouble? The outlook for energy storage projects in the UK

Extractives companies’ human rights records ranked in Benchmark study

Developments continue apace in human rights responsibilities for businesses. We are seeing persistent implementation of new reporting requirements across EU jurisdictions and beyond, judgments of national courts and international tribunals holding corporations to ever stricter account for their responsibilities in this area and UN negotiations continuing for a global treaty imposing binding international law obligations on businesses.  Staying ahead of the field in this area is crucial.

While the responsibilities imposed by the UN Guiding Principles on Business and Human Rights (the UNGPs) are not in themselves legally binding, governments’ expectations that companies will step up in this area have been made clear through National Action Plans, parliamentary enquiries and the introduction of “hard” legal requirements, such as under the Modern Slavery Act in the UK.

Now, the Corporate Human Rights Benchmark (CHRB) has ranked 98 of the largest publicly traded companies globally on 100 human rights indicators, focusing on the Extractives, Agricultural and Apparel industries.  These areas were specifically selected because of the high human rights risks they carry, the extent of previous work on the issue, and global economic significance.  41 Extractives companies featured.

The CHRB is a collaboration between investors and a number of business and human rights NGOs. It has emphasised this is a pilot assessment and welcomes input on the methodology used.  The study was compiled from publicly available information, with the selected companies also having the opportunity to submit information to the CHRB.  Companies were given scores for the measures they are taking across six themes, grounded in the framework of the UNGPs:

  • Governance and policy commitments.
  • Embedding respect and human rights due diligence.
  • Remedies and grievance mechanisms.
  • Performance: Company human rights practices.
  • Performance: Responses to serious allegations.
  • Transparency.

The selected companies were then banded according to their overall percentage score.  The performance-related criteria carried greater weight than the policy-based heads, with “Embedding respect and human rights due diligence” and “Company human rights practices” counting for 25% and 20% respectively.

Results skew significantly to the lower bands

There was a wide spread in the participants’ performance, with a small number of clear leaders emerging. No company scored above the 60-69% band, with only three companies falling within that band.  A further three scored 50-59% and 12 scored 40-49%.  48 companies fell within the 20-29% band.

Of the companies in the top band, two were in the Extractives sector; a further six Extractives companies fell within the 40-49% band; 19 scored 20-29% and five were found to trail at less than 19%.

The generally low scores across the three industries may be explained by the fact that the impact of some businesses’ human rights processes may still be filtering through. We should expect that in future years the authors of the survey will adopt a more stringent approach and subject low-scoring businesses to greater criticism.

Gap between policies and performance

On the whole, companies tended to perform more strongly on policy commitments, high-level governance arrangements and the early stages of due diligence. They performed less well on actions such as tracking responses to risks, assessing the effectiveness of their actions, remedying harms and undertaking specific practices linked to key industry risks.  There is often a mismatch between board level measures and their granular implementation, as well as between public responses to serious allegations and taking appropriate action.

Of the Extractives companies surveyed, only six companies scored were given a zero score for their policy commitments, whereas this was the case for 17 companies for “Embedding respect and human rights due diligence” and nine for “Company human rights practices”.

On the policy side, some Extractives companies scored points for emerging practices such as regular discussion at board level of the company’s human rights commitments, linking at least one board member’s incentives to aspects of the human rights policy, and committing not to interfere with activities of human rights defenders, even where their campaigns target the company.

In terms of implementation, some participants explained how human rights risks are integrated into their broader risk management systems, how they monitored their commitments across their global operations and business relationships, and how they had systems in place for identifying and engaging with those potentially affected by their operations.

Companies were also scored for their practices in relation to selected human rights specific to each industry. Those in which the Extractives participants featured included freedom of association and collective bargaining, health and safety, land acquisition, water and sanitation and the rights of indigenous people.

Conclusion

The significant interest in the CHRB since it began its work is unsurprising given it provides an opportunity to demonstrate commitment and progress in this area vis-à-vis competitors. The pilot methodology will be refined and ultimately the CHRB will be produced on an annual basis for the top 500 companies globally.  We expect it to contribute to the continued drive of companies across all sectors to proactively manage human rights risks in their own operations and through their expectations of their business partners.

Extractives companies’ human rights records ranked in Benchmark study

Financial parameters of auctions for renewable energy sources

On 3 April 2017, two regulations were published in the Journal of Laws which set out the financial parameters of auctions for renewable energy sources (RES) that will be held in 2017. The government is planning to spend more than PLN 27 billion (approximately €6.5 billion) on support for producers in auctions, which will generate more than 55 TWh of electricity during 15 years. The parameters of the auctions are set out below.

  1. Summary
  • In 2017, fourteen auctions will be organized, each of them dedicated to different groups of installations. Nearly 75 percent of the funds (PLN 20 billion) will be allocated to new installations. Nearly 63 percent of all funds (PLN 17 billion) will be allocated to large installations.
  • So-called stable installations will be the most favored group of installations. The largest part of the funds is allocated to a basket of high-efficiency installations (37 percent of funds in 4 auctions). Biomass installations are expected to be a dominant group in this basket. Significant funds (35 percent in 4 auctions) will be allocated to agricultural biogas installations.
  • It is planned to allocate funds to Waste-to-Energy projects, which should assure the construction of installations with nearly 150 MW of total capacity (one auction dedicated for new, large installations). Part of the funds will be allocated to a basket dedicated to hydro-electric plants, both existing and new (three auctions).
  • Another part of the budget is allocated to a basket for new installations covering “other installations” (15 percent of funds in two auctions). In this basket, two auctions are planned: the first for small installations that, according to the government’s intention, will result in the construction of 300 MW new photovoltaic projects, and the second for large installations, where support could be obtained by nearly 150 MW new wind projects. Significant competition is expected in these two auctions.
  • Installations participating in an auction cannot apply for higher support than the “reference price,” which is determined for each year. The reference price is set separately for 21 categories of installations. In 2017 for example, this price will be PLN 350 per MWh for large installations using wind and PLN 450 per MWh for small installations using solar energy.
  • Auctions will be announced by the President of ERO and cannot be organized earlier than 30 days after its announcement. In light of the RES Act, an auction could be organized at the earliest on 24 May 2017, but no announcements regarding auctions have been made to date.
  1. Auction support scheme

Under the Act of 20 February 2015 on renewable energy sources (RES Act), there are two support schemes for RES installations in Poland. Existing installations can obtain support in the form of certificates of origin (green certificates) and can sell electricity to designated entities at the officially determined price (system of certificates). New installations will compete for support allocated in auctions (auction system) organized by the President of the Energy Regulatory Office (ERO).

The auction system is dedicated mainly to new installations, but existing installations can also transfer to this system (in such case they lose a right to participate in the system of certificates). This system is intended to assure the future development of RES but in a controlled and predictable manner—this may be pursued through the allocation of budgets to auctions where installations favored by the government start and through the reduction of budgets for auctions for unwanted installations. The increase in RES in Poland, and the contemplated impact of auctions in 2017 on the installed capacity of RES, is presented in Figure no 1.

Figure no. 1     Increase in renewables capacity (MW) in Poland

Source: data from President of the ERO. The data concerning the capacity from the auction in 2017 presents only the estimation of the Ministry of Energy.
  1. Split of auctions and auction baskets in the auctions system

Auctions are conducted separately for installations qualified for particular “baskets” (or bands). There are five baskets (two additional baskets will be added from 1 July 2017, but no funds are allocated to them in 2017). The following existing baskets are dedicated to particular RES installations:

  • With a degree of utilization of the installed electricity generation capacity, irrespective of the level of CO2 emission, of more than 3504 MWh/MW/year (basket of high-efficiency installations)
  • Using, for the generation of electricity, biodegradable industrial waste and municipal solid waste of plant or animal origin, including waste from waste treatment systems and waste from water treatment and waste treatment, including in particular sludge, in accordance with the provisions on waste concerning classification of energy recovered from thermal waste treatment (basket of WTE installations)
  • In which emission of carbon dioxide does not exceed 100 kg/MWh, with utilization of total installed capacity of more than 3504 MWh/MW/year (basket of low-emission installations)
  • Using only agricultural biogas to generate energy (basket of biogas installations)
  • Other than those already specified (basket of other installations)

In each of those baskets, separate auctions are organized for existing installations and new installations. Moreover, separate auctions are organized for small installations and large installations. Separate auctions will be organized for so-called upgraded installations, but no budget has been provided in 2017. (as it was in 2016).

Therefore, in each year and in each basket, up to four auctions are possible and in total up to 20 auctions may be organized, each of them dedicated to different groups of installations (40 auctions including upgraded installations).

  1. Budget allocations for 2017

In 2017, the auction budget is PLN 27,177,622,626; support will be provided for the production of 55 562 607 MWh during the coming years. The individual budgets are presented in Table no 1 below:

Table no. 1 Budgets of auctions in 2017

Conclusions from the above data: In 2017, the auctions will be dedicated mainly to new installations—75 percent of funds are allocated to these installations. The most supported technologies are stable installations, i.e. with predictable generation, mainly from the basket for high-efficiency installations (37 percent of all funds) and from the basket for biogas installations (35 percent of all funds). Large installations will be dominant, as 63 percent of all funds have been allocated to these installations. A breakdown of funds between large vs. small and existing vs. new installations is presented in Figure no 2.

Figure no. 2 Breakdown of auction funds in 2017: large v. small and existing v. new installations

Source: Regulation of the Council of Ministers regarding the maximum volume and value of electric energy generated in renewable energy source installations which may be sold by auction in 2016.

A more detailed description of each of the auctions is provided in point 8 below.

  1. Reference prices

An RES installation producer cannot submit at auction a bid that is higher than the maximum ‘reference price’ per MWh. The reference price is determined for each year, separately for each of the 21 categories (42 if we take into account the additional 21 categories for upgraded installations). This division does not coincide with the division into technological baskets. The reference price is uniform for existing and new installations. Parts of the reference prices are determined separately for small and large installations, while others are the same for both categories.

Below, we present the reference prices for the installations that are intended to be supported by the government in 2017. A summary of all reference prices is set out in Appendix 1 below.

Table no. 2 Reference price for certain installations in 2017

  1. Possible auction dates

Under the RES Act, auctions are announced and organized by the President of the ERO. The announcement should be published in the Public Information Bulletin of ERO at least 30 days before the day of the auction starting. The auction cannot be conducted earlier than 60 days after publication of the reference prices.

The regulation determining reference prices in 2017 entered into force on 25 March 2017, therefore this year’s auction can be conducted at the earliest on 24 May 2017 (if the President of the ERO publishes the announcement on 24 April 2017 at the latest). Nevertheless, some media say that the main auctions will be organized in the second half of the year.

  1. The effect of winning an auction and support period

The producer that won the auction will receive support dependent on the capacity of the installation. Producers that have an installation with installed capacity of <500 kW will be entitled to sell their total electricity offered in the auction at the price established at auction to the designated entity (pay-as-bid mechanism). Producers that have an installation with installed capacity of >500 kW will have the right to cover the difference between the market price and the price established at auction in the scope of the volume offered in the auction (termed “return of negative balance”) with the obligation to return the surplus if the market price exceeds the auction price (contract-of-difference mechanism). The support is also not allocated, when the power exchange prices of electricity are lower than zero PLN (with some additional conditions).

The support period for new installations is determined annually together with reference prices. In 2017 it is 15 years. The support period for existing installations is also 15 years, but it is calculated from the date the first electricity is generated and fed to the grid, as confirmed by the issued green certificate.

If, after winning the auction, at least 85 percent of the quantity of electricity declared in the bid is not generated, a fine will be imposed calculated on the basis of the not delivered volume of electricity and a half of the auctioned bid price. In the case of installations with an assumed efficiency of 3504 MWh/ MW/year, a failure to reach declared capacity utilization leads to the obligation to return all public aid obtained through auctions.

  1. Auctions in particular baskets

Below, we present a short description of each basket, stating the types of installation supported in accordance with the government’s intention. Whenever the amount is given together with the name of a specific installation, it means the reference price for this installation. The grading of individual installations into baskets is given for illustration purposes only; we cannot guarantee that in fact the indicated types of installation will start in any given auction.

a. Basket of high-efficiency installations

Four auctions will be organized in this basket, but the funds for small installations (both existing and new) constitute only 9 percent; the funds for large installations dominate.
Auctions for large installations in this basket are dedicated mainly to plants combusting biomass. It is predicted that the following installations can participate in these auctions:

  • Dedicated co-firing combustion installations (DCCI) using biomass, biofuels, biogas or agriculture biogas (325 PLN)
  • Hybrid RES installation with aggregated installed capacity >1 MW (405 PLN)
  • Dedicated biomass combustion installations (DBCI) or biomass hybrid systems (HS) with aggregated installed capacity of up to 50 MW (both 415 PLN)
  • DBCI or HS in CHP with aggregated installed capacity >50 MW and up to 150 MWt of CHP (435 PLN)
  • DBCI or HS in CHP with aggregated installed capacity of up to 50 MW (450 PLN)

Potentially this basket may be joined by investors who plan to develop on-shore wind farms (350 PLN) installing new generation turbines. Some claim that in certain technical configurations it would be possible to achieve efficiency at the level required for this basket.

The government’s intention is a transfer of nearly 50 percent of existing installations combusting biomass (probably the DBCI, although this intention is not clearly stated), but taking into account the reference price it may turn out that the auction winner will be an installation co-firing biomass with coal (DCCI). Competition in this basket is expected, as due to the declining prices of green certificates, a transfer to the auction system may be financially profitable for existing installations.

In the scope of large, new installations, the government is planning to award funds that will result in the construction of approximately 100 MW of DBCI.

Funds for small installations are allocated to installations using biogas other than agricultural, hence for installations using biogas extracted from a landfill site (405 PLN) and biogas extracted from a sewage treatment plant (365 PLN). In the scope of new installations, it is planned to construct approximately 5 MW of capacity for each type of these installations.

b. Basket of WTE installations

In this basket only one auction for large, new installations will be organized. Funds from this basket are intended to provide support for waste incineration plants that produce energy (385 PLN). It is planned that results from the auction support will be given to installations with total capacity of 150 MW.

According to publicly available information, there are five waste incineration plants in Poland which produce nearly 334,000 MWh/year. (This data is an unconfirmed estimation due to the lack of official information in this respect.) Assuming that the winning installation will produce the same amount of MWh every year (which gives production of 309,600 MWh annually), contracting the total volume in this basket will result in an increase in the energy generation of those installations of 92 percent.

c. Basket of low-emission installations

In this basket three auctions will be organized, all addressed to hydro-electric installations (480 PLN) able to achieve at least 3504 MWh/MW/year. Hydro-electric installations below this threshold will need to participate in auctions in the basket of other installations. In addition, large offshore wind energy installations (470 PLN) may potentially take part in auctions in this basket—if such installations will be able to produce more than 3504 MWh/MW/year. Similarly, as in the case of the basket of high-efficiency installations, this basket may be joined by investors planning to install on-shore wind turbines (350 PLN) of a new generation, only if the information on sufficiently efficient technical setups is confirmed.

In the scope of existing installations, it is intended that as a result of the auctions from 2017 and 2016 approximately 80 percent of existing, small hydro plants will be transferred to the auction system. The budget for new installations will enable the construction of 10 MW of small installations and 10 MW of large installations (this indicates that offshore wind plants can take part in the auction only hypothetically).

d. Basket of biogas installations

In this basket four auctions will be organized, each solely for agriculture biogas installations (PLN 550).

The government in its rationale of regulations did not indicate the percent of existing installations that will be transferred to the auction system in this basket. In the scope of auctions dedicated to new installations, it is planned to allocate support to small installations with total aggregated capacity of 70 MW and to large installations with total aggregated capacity of 30 MW.

e. Basket of other installations

In this basket two auctions for new installations are provided.

The auction for small installations is addressed to solar energy installations, but other installations can also take part in this auction:

  • Small onshore wind energy Installations (320 PLN)
  • Small installations using solar energy (450 PLN)
  • Hydro-electric small installations (480 PLN)—installations with efficiency <3504 MWh/MW/year

The last auction in this basket, in December 2016, was the only auction where the bids outstripped available volume (from 152 bids only 84 were chosen). Keen interest is also expected this year, although funds allocated to the auction are nearly three times larger. It is planned that support will be obtained by installations with total capacity of approximately 300 MW in this auction. If solar plants obtain the said support, it will mark a significant increase in the capacity of these installations. The installed capacity of solar energy installations in Poland and the contemplated impact of the auction in 2017 on this capacity is presented in Figure no 3.

Figure no. 3 Installed capacity in PV plants in Poland (in MW)

Source: Data disclosed by President of the ERO. The data concerning the capacity from the auction presents only the estimation of the Ministry of Energy. In 2016 it was intended to support approx. 100 MW of new power, but only 84 offers were chosen in the auction. The aggregated capacity of these offers is unknown, but as the auction was addressed to small installations their aggregated capacity may not exceed 84 MW.

Keen competition is expected in the auction for large installations, which is addressed to wind energy plants. The following installations can take part in this auction:

  • Large onshore wind energy installations (350 PLN)
  • Large installations using solar energy (425 PLN)
  • Large offshore wind energy installations (470 PLN)—installations with efficiency <3504 MWh/MW/year

Keen competition is expected in this basket, which is dominated by onshore wind energy installations. There are two main reasons for this. First, the planned budget provides support for approx. 150 MW, which might be significantly lower capacity than available for existing projects that can submit bids in this auction. In practice, if bids are submitted in the auction for the new installations with higher effectiveness than the level used for the calculation by the government, the volume of offered electricity from these installations will be proportionally higher. In this case, support will be allocated to installations within limits closer to 100 MW of new generation capacity. Second, the negative approach of the current government to wind farms is not a secret. Therefore it is conceivable that the auction in 2017 will be the last one in a few years with funds allocated to this basket. Moreover, the entry into force of the Act of 20 May 2016 on investments concerning wind turbines stipulates that a building permit for wind turbines issued on the basis of zoning decisions will expire if the occupancy permit is not obtained for the wind turbine by 1 July 2019. Based on our own knowledge, quite a large number of wind turbines were developed on the basis of zoning decisions (not on the basis of local zoning plans, as required by the abovementioned Act). Therefore, in light of the time required to build wind turbines, this auction may be the last chance some wind farms have of obtaining the state aid they need to ensure financial profitability of the project, in light of the occupancy permit issue. Building permits for many projects face expiry, and it may prove impossible to obtain new building permits under the new Act.

Appendix no 1
Reference Prices obliging in 2017 (in PLN/MWh)

Appendix no 2
Summary of auctions in 2017 in the order set by the Minister of Energy

 


  1. There are RES installations which started production of renewable energy before 1 July 2016 (existing installations) and after 1 July 2016 (new installations);
  2. There are installations with capacity of up to 1 MW (small installations) and those with capacity of more than 1 MW (large installations).
  3. From 1 January 2018, only RES installations with a capacity less than 500 kW and agricultural biogas installations will be able to benefit from mandatory purchase of electricity.
  4. Taking into account that currently known connection conditions for off-shore installations book capacity around the 1000 MW threshold, exceeding many times the assumed budget of auctions, we treat participation of investors based on this technology as purely hypothetical.
Financial parameters of auctions for renewable energy sources

UK “early” Capacity Market auction produces cheapest prices yet

The provisional results of the “early” Capacity Market auction held last week have now been published.

This was an auction exclusively of 1-year capacity agreements, primarily to cover Winter 2017/18, after the UK Government decided that it did not want National Grid to carry on ensuring security of supply during Winter periods by means of a Contingency Balancing Reserve (CBR).  The CBR involved auctions open to generators who would not otherwise be operating in a given Winter period and to demand side response providers.  A Government consultation in March 2016 noted that the prices National Grid were paying under the CBR were increasing and that it introduced distortions into the market.

From Winter 2018/19, of course, the Capacity Market itself will ensure security of supply.  Those with capacity agreements beginning in 2018 will be the capacity providers who bid successfully in a four year ahead auction held in 2014, supplemented by those who win capacity agreements in any subsequent one year ahead auction for delivery in 2018.  Last week’s “early” auction was a one-off bridge between the CBR (now operating for the last time to cover Winter 2016/17) and the fully-fledged Capacity Market regime.  The key difference between the CBR and the Capacity Market is that the CBR (or at least the major part of it) focuses on securing capacity that would otherwise not be in the market, to fill the potential gap between existing generation and projected peak demand, whereas the Capacity Market provides a reliability incentive to all eligible generators and demand side response providers on the market.

Commentary on previous Capacity Market auctions (such as this post from December 2016) has tended to focus on the failure of the four year ahead auctions to result in the award of 15 year agreements to meaningful amounts of large-scale new gas-fired generation projects.  With new projects competing against almost all existing thermal generation, and new reciprocating engine projects able to bear much lower Capacity Market clearing prices than a CCGT project, the auctions have produced low clearing prices, but no obvious successors to the existing big coal-fired plants that the Government wants to close by 2025.

How to evaluate the results of the “early” auction, then?  The provisional results indicate capacity agreements going to 54.43 GW of capacity, at £6.95 kW / year, suggesting total costs to bill payers of around £378 million.  This might look like spectacularly good value compared with the results of the last four year ahead auction (for delivery starting in 2020), where the clearing price was £22.50 kW / year for 52.43 GW of capacity.  But that isn’t really a fair comparison, since about a quarter of the capacity that was awarded agreements for 2020 was new build, whereas less than 4 percent of the capacity awarded agreements in the “early” auction falls into this category.  All the rest will be paid £6.95 for just continuing to operate – which presumably most of them would have done anyway. 

An alternative point of comparison might be with the costs of the CBR.  The most recent Winter for which these are available is 2015/16, when National Grid spent just over £31 million on procuring, testing and utilising less than 3 GW of CBR capacity.  Obviously a much inferior system. 

 

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UK “early” Capacity Market auction produces cheapest prices yet

Close but no cigar? What’s different about the T-4 Capacity Market auction results of 2016?

They say a picture is worth a thousand words, so rather than writing a lengthy post on the provisional results of the four-year ahead GB Capacity Market Auction, published on 9 December 2016 by National Grid, we are focusing on two pictures and inviting you to spot the difference between them.

The first, immediately below, shows the progress of bidding in the 2016 auction.  In simple terms:

  • the process starts with all prequalified potential providers of capacity “in” at the cap price of £75/kw/year and the price then goes down by £5 with each round;
  • the auction clears when the purple line, whose progress from right to left shows how many bidders are left in after each round, converges with the red line “demand curve” drawn on the graph by the Government as part of the auction parameters;
  • all bidders still in at that point get a capacity agreement at the clearing price.

The big right to left moves occurred when the price moved between £35 and £30 and below £25.  In particular, each of these moves saw 6GW of capacity drop out.

2016 progress of bidding chart

Now look at the equivalent presentation of results from last year’s auction.  The purple line slopes more gradually, and the biggest right to left moves happen much earlier on in the bidding, between £60 and £50.  (The picture from 2014 is very similar to the 2015 one.)

2015 progress of bidding chart

It’s only an educated guess, of course, but it seems likely that much of the big leftward shifts in both auctions represented the exiting of bidders with plans to build large-scale proposed combined cycle gas turbine (CCGT) plants.  As a group, they are almost certain to have higher per MW development costs than other categories of new build projects competing for capacity agreements (small gas or diesel projects based on reciprocating engines, open-cycle gas projects, or battery based storage).  And the amount of capacity involved corresponds roughly with the big CCGT projects in the auction.

If the above is correct, why were proposed new big CCGT plants apparently prepared to tolerate prices almost 50% lower this year?  Perhaps they were hoping that a price between £30 and £35 would be where the auction cleared this time, on the basis that:

  • the clearing price is effectively set by the bidding behaviour of a sub-set of the smaller-scale, distribution-connected, fossil fuel generators;
  • on top of their power sales revenue, these smaller-scale generators have two main projected sources of income: capacity agreements and so-called residual demand TNUoS benefits;
  • Ofgem has issued what amounted to a warning that residual demand TNUoS benefits could be very sharply reduced by the time plants bidding in this year’s auction are commissioned;
  • the anticipated loss in residual demand TNUoS benefit revenue would be enough to push the smaller-scale generators to want a significantly higher capacity market price than the clearing prices seen in 2014 and 2015, both of which were below £20;
  • lower gas prices and slightly higher projected wholesale power prices may make a low capacity market price more bearable for CCGT plant, and there may other ways to mitigate merchant risk through innovative trading arrangements.

Maybe Ofgem’s warning wasn’t strong enough.  Maybe the smaller-scale generators reckon that Ofgem’s bark will turn out to have been worse than its bite on this.  In any event, the outcome has shown that for now, simply expanding the amount of capacity to be procured under an auction, as the Government appeared to be hoping when it adopted a limited change of approach to the 2016 auction, isn’t enough to ensure that some new GB CCGT plant is financeable and gets built.  Instead, a somewhat higher price will be paid to all successful bidders, including existing plant, for a larger amount of capacity than the Government thought we really needed.

As usual on these occasions, the Government has professed itself happy with the result of the auction, and it is fair to note that of the two new gas-fired plants with a capacity of around 300 MW that have been successful in the auction, one is described in the Capacity Market register as being CCGT.  But if a new generation of big CCGT plants is an important part of our new lower carbon power mix, there is some way to go.  A possibly more promising approach to using a capacity market to stimulate new CCGT build is suggested by the European Commission’s recent Winter Package of Energy Union proposals: set a date beyond which existing coal-fired plant will be ineligible for capacity market payments.  This is not among the options canvassed in the Government’s recent consultation on achieving the closure of coal-fired plant by 2025.  There would of course be an element of risk in adopting such an approach (coal plant might stay open because it can still make money without a subsidy, resulting in overcapacity, or alternatively coal plant might close immediately, before the new CCGT plant is built, leaving a generation gap), but it might be worth considering.

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Close but no cigar? What’s different about the T-4 Capacity Market auction results of 2016?

Something for everyone? The European Commission’s Winter “Clean Energy” Package on Energy Union (November 2016)

On 30 November 2016, the European Commission officially unveiled the latest instalment of its ongoing Energy Union initiative, which will reform some of the central pieces of EU energy legislation.  Referred to in advance as the “Winter Package” (not to be confused with the rather more limited package released in February 2016), it has been published as the “Clean Energy for all Europeans” proposals and is the most significant series of proposals yet to emerge under the Commission’s “Energy Union” brand.  It will have far-reaching implications within and potentially beyond the existing EU single energy market.

There is a lot to consider in these proposals, and we will return to some of the issues they raise in more depth and from other perspectives in future posts. What follows is an overview and some initial thoughts from a predominantly UK-based viewpoint.

Important though it is, many of the Winter Package’s proposed reforms are evolutionary rather than revolutionary.  Some could even be criticised for lacking ambition.  The Commission’s proposals certainly provide opportunities for newer technologies such as storage and demand side response and for those seeking to make use of newer commercial models such as aggregation or community energy schemes, but all these groups are still likely to need to work hard in many cases to exploit the leverage that the new rules would give them.  It is interesting that what has been picked up most in early news reports of the Winter Package is the Commission’s move to end subsidies for coal-fired plant.  This is a significant step, but it is only one part of a complex and multi-layered set of draft legislative measures, and is one of the few instances in those measures of a provision that overtly tilts the playing field in favour of or against a particular technology in a new way.

The story so far

Let’s begin by reminding ourselves what Energy Union is about. The project is said to have five “dimensions”.  These are:

  • Security, solidarity & trust: the buzz-words are “diversification of supply” and “co-operation between Member States” – all informed by anxieties about over-dependence on Russian gas.
  • A fully-integrated internal energy market: going beyond the 2009 “Third Package” of gas and electricity market liberalisation measures (and their ongoing implementation through the promulgation of network codes) to achieve genuine EU-wide single gas and power markets.
  • Energy efficiency: using less energy can be hard, but it is the best way to meet environmental objectives and it can also be a significant source of new jobs and economic growth.
  • Climate action – decarbonising the economy: signing and ratifying the Paris CoP21 Agreement was the easy bit.  How is the EU going to achieve deep decarbonisation of not only its power but also its heat and transport sectors so as to meet its UNFCCC obligations?
  • Research, innovation & competitiveness: can European businesses still take the lead in developing technologies that will save the planet, and also make money out of commercialising them?

In other words, Energy Union is about everything that matters in EU energy policy.  To date, at least in relation to electricity markets, the initiative has involved a lot of consultation but not many concrete legislation proposals.  The new Winter Package goes a long way towards redressing this balance, but it shows there is still a lot of work to do.

What is in the Winter Package?

The documents published by the Commission (all available from this link) include legislative proposals and a range of explanatory and background policy documents.  The legislative proposals are for:

We comment below on what seem to us at this stage to be the most interesting points in these, and also on the Communication on Accelerating Clean Energy Innovation (the Innovation Communication).

The Revised IMED

Overall impressions

The legislative elements of the Winter Package are all inter-related, but the Revised IMED is as good a place to start as any.  Its early articles include two programmatic statements:

  • National legislation must “not unduly hamper cross-border flows of electricity, consumer participation including through demand-side response, investments into flexible energy generation, energy storage, the deployment of electro-mobility or new interconnectors”.
  • Electricity suppliers must be free to determine their own prices.  Non-cost reflective power prices should only apply for a transitional period to vulnerable customers, and should be phased out in favour of other means of support except in unforeseeable emergencies.

In some ways, this sets the tone for the more specific provisions that follow.  It often seems that the Commission never loses an opportunity to put forward legislation in the form of a directly applicable Regulation rather than in the form of a Directive that by definition requires Member States to take implementing measures in order fully to embed its effect within national regulation.  However, the revised IMED, like its predecessor, stands out as a classic old-school Directive, in which EU legislators tell Member States lots of results to be achieved, but do not prescribe many of the means by which this is to happen.  Moreover, even the expression of those objectives is (inevitably) qualified: in other words, get rid of the barriers to the Commission’s vision of Energy Union, except the ones you can justify.  Of course, that is slightly unfair: as noted below, there are at least one or two eye-catching points in the revised IMED, and there are significant changes proposed in other parts of the Winter Package that should further the objectives of the revised IMED, but it arguably demonstrates less willingness to get to grips with some of the most difficult of the longer-term and more fundamental changes in the market than the call for evidence on moving towards a smart, flexible energy system that was published on 10 November by the UK government and GB energy regulator Ofgem (although admittedly the UK authorities are only asking questions, not proposing solutions at this stage).

A market for consumers (and prosumers)

The revised IMED would enhance the rights of consumers generally in a variety of ways.  For example:

  • Price increases are to be notified and explained in advance, giving them the opportunity to switch before an increase takes effect.  Switching must take no longer than three weeks.
  • Termination fees may only be charged where a fixed term contract is terminated prematurely, and must not exceed the direct economic loss to the supplier.
  • All consumers are to be entitled, on request, to a “dynamic electricity price contract” which reflects spot market price fluctuations at least as frequently as market settlement occurs.  They will of course need smart meters to make this work (see further below).
  • All consumers are to be entitled to contract with aggregators, without the consent of their supplier, and to end such contracts within three weeks.

In addition, special consideration is given to two newly defined categories of persons.

  • “Active consumers” are defined as individuals or groups “who consume, store or sell electricity generated on their premises, including through aggregators, or participate in demand response or energy efficiency schemes”, but who do not do so commercially / professionally.
  • “Local energy communities” are defined as organisations “effectively controlled by local shareholders or members, generally non-profit driven or generally value rather than profit-driven…engaged in local energy generation, distribution, aggregation storage, supply or energy efficiency services, including across borders”.

Active consumers are to be:

  • entitled to undertake their chosen activities “in all organised markets” without facing disproportionately burdensome procedures or charges; and
  • encouraged to participate alongside generators in all organised markets.  Obviously in most cases they will do this through aggregators, who are to be treated “in a non-discriminatory manner, on the basis of their technical capabilities”.  For example, they are not to be required to pay compensation to suppliers or generators (contrary to some of the suggestions in the UK call for evidence referred to above).

Local energy communities:

  • are similarly not to be discriminated against;
  • may “establish community networks and autonomously manage them” and “purchase and sell electricity in all organised markets”;
  • must not make participation in a local energy community compulsory, or limit it to those who are shareholders in or members of the community; and
  • will be subject to the unbundling rules for distribution system operators if they are DSOs.

As in the original Directive 2009/72/EC, there are provisions requiring improvements to customer billing and encouraging the rollout of smart meters.

  • Customers should receive bills once a month where remote reading of the meter is possible.
  • Where a Member State has decided not to mandate smart meters for cost-benefit reasons, they are to revisit their assessment “periodically” and report the results to the Commission.
  • The draft Directive sets out functionalities that smart meters must include where a Member State mandates their rollout.  In such cases, the costs of smart metering deployment are to be shared between all consumers.  In other cases, every customer is entitled, on request, to receive a smart meter that complies with a slightly reduced set of functionalities.
  • The implementation of smart metering must encourage active participation of consumers in the electricity supply market (although this may be qualified by a cost-benefit analysis).
  • There are a number of provisions reflecting both concerns about cybersecurity and the importance of making useful data securely available to legitimate market participants.

DSOs (and EVs)

There has been no shortage of recent commentary on how the shift towards decentralised generation of electricity, combined with the potential for storage and more active consumer behavior, may require changes in the role of the 2,400 market participants that the IMED has always called distribution system operators, but which in many jurisdictions have historically not had, even within their own networks, the kind of “system operator” responsibilities of a transmission system operator.  The recent UK call for evidence on flexibility appears at least prepared to contemplate some significant realignment of the respective functions of DSOs and TSOs.  There is nothing so fundamental in the revised IMED, but there are a number of new provisions about DSOs.

  • DSOs are to be allowed, and incentivised, to procure services such as distributed generation, demand response and storage in order to make their networks operate more efficiently.  DSOs will be paid for this, and must specify standardised market products for these services.
  • Every two years, DSOs must update five to ten year network development plans for new investments, “with particular emphasis on the main distribution infrastructure which is required…to connect new generation capacity and new loads including re-charging points for electric vehicles”, as well as demand response, storage, energy efficiency etc.
  • DSOs serving isolated systems or fewer than 100,000 consumers can be excused from this requirement, but note that in general, those operating “closed distribution systems” are to be subject to the same rules as other DSOs under the revised IMED.

However, although DSOs are to facilitate the adoption of new technologies, such as storage and EVs, they are not encouraged to diversify into actually providing them to end users themselves.

  • Member States are to facilitate EV charging infrastructure from a regulatory point of view, but DSOs may only “own, develop, manage or operate” EV charging points if the regulator allows them to after an open tender process in which nobody else expresses an interest in doing so.  And even then, the service taken on by the DSO must be re-tendered every five years.
  • Similar rules would apply to the development, operation and management of storage facilities by either DSOs or TSOs.  For TSOs, there would be an additional requirement that the storage services or facilities concerned are “necessary” to ensure efficient and secure operation of the transmission system, and are not used to sell electricity to the market.

What makes these provisions significant is that until now, with the IMED in its original form silent on the subject of storage, the operation of storage facilities had been seen as potentially falling within the categories of generation or supply.  This appeared to make the involvement of DSOs or TSOs in storage projects (at least as investors) subject to the general unbundling restrictions, and so has tended to inhibit the progress of energy storage initiatives in a number of cases.  The proposed new rules are restrictive in some respects, but bring a degree of clarity and at least recognise storage as a distinct category.

The Revised Market Regulation

General organisation of the electricity market

Like the revised IMED, the Revised Market Regulation begins with firm statements of purpose: enabling market access for all resource providers and electricity customers, enabling demand response, aggregation and so on.  It goes on to list 14 “principles” with which “the operation of electricity markets shall comply” – starting with “prices are formed based on demand and supply” and finishing with “long-term hedging opportunities allow to hedge parties against price volatility risks”.

Entirely in keeping with these principles, the first specific provision is that all market participants are to be responsible for (or to delegate to a responsible third party) the consequences of any imbalance they create in the electricity system as a result of importing or exporting to or from the grid at a given time more or less than they had said would be the case at that time in previous notifications to the system operator.  This much-trailed provision may be a significant change for renewable generators in some jurisdictions (though not in GB, where imbalance charging reforms are already being implemented).  In an earlier draft, the Revised Market Regulation only permitted sub-500kW renewables or high-efficiency CHP to be exempted from this requirement.  In the published version, this exemption has been broadened to include RES projects that have received state aid that has been cleared by the commission and that have been commissioned before the Revised Market Regulation enters into force.  It also requires that “all market participants” are to have access to the balancing market on non-discriminatory terms, either directly or through aggregators.

There are a number of quite detailed provisions on the overall organisation of electricity markets. We pick out a few of the more notable ones below.

  • There is a shift from a national to a regional approach.  As the explanatory memorandum to the draft Directive puts it: “In certain areas, e.g. for the EU-wide ‘market coupling’ mechanism, TSO cooperation has already become mandatory, and the system of majority voting on some issues has proven to be successful…Following this successful example, mandatory cooperation should be expanded to other areas in the regulatory framework.  To this end, TSOs could decide within ‘Regional Operational Centres’…on those issues where fragmented and uncoordinated national actions could negatively affect the market and consumers (e.g. in the fields of system operation, capacity calculation for interconnectors, security of supply and risk preparedness).”.  Functions to be carried out at a regional level include “the dimensioning of reserve capacity” and “the procurement of balancing capacity”.
  • As far as possible, the organisation of markets is to avoid any rules that could restrict cross-border trading or the participation of smaller players.  So, for example, trades are to be anonymous and in a form that does not distinguish between bidders within and outside a bidding zone.  The minimum bid size is not to exceed 1 MW.
  • Market participants are to be able to trade energy as close to real time as possible, with imbalance settlement periods being set to 15 minutes by 1 January 2025.
  • Long-term (firm, and transferable) transmission rights or equivalent measures are to be put in place to enable e.g. renewable generators to hedge price risks across bidding zone borders.  Such rights are to be allocated in a market-based manner through a single allocation platform.
  • As a general rule, there must be no direct or indirect caps or floors on wholesale power prices, other than a cap at the value of lost load and a floor of minus €2000, or during a 2-year transitional period when a transitional maximum and minimum clearing price may be allowed.  Defined as “an estimation in €/MWh of the maximum electricity price that consumers are willing to pay to avoid an outage”, the value of lost load is to be defined nationally and updated at least every five years.  This concept will evidently need refinement, as there is a difference between what individual consumers may be prepared to pay and the kind of price spikes that it is reasonable for wholesale markets to bear for short periods of time.
  • Dispatching of generation and demand response is to be market-based.  Priority dispatch for renewables is to be brought to an end subject to certain exceptions (these are summarised in the section on the revised RED below).  On the other hand, where redispatch (changing generator output levels) or curtailment is imposed by the system operator other than on market-based criteria, the draft Regulation imposes restrictions on when RES, high-efficiency CHP and self-generated power can be redispatched or curtailed.
  • There is to be a review of the bidding zones within the single electricity market, so as to maximise economic efficiency and cross-border trading opportunities while maintaining security of supply.  In other words, the market coupling process should allow customers to benefit from the availability of lower-priced wholesale power in adjacent markets, but the bidding zone boundaries need to take account of “long-term structural congestion” in the network infrastructure for this to be workable and without adverse side-effects.  TSOs are to participate in the review, but the final decisions are to be taken by the Commission.
  • A significant piece of work is to be undertaken by ACER on “the progressive convergence of transmission and distribution tariff methodologies”.  This is to include, but not be limited to, some issues that have recently proved contentious in the GB context, including the respective shares of tariffs to be paid by those who generate and those who consume power; locational signals (how much more should generators pay if they are located a long way from where the power they generate used); and which network users should be subject to tariffs (would this, for example, open up the question of whether generators connected to the distribution network should pay a share of transmission network charges?).
  • Separately, the draft Regulation sets out some general principles about network charges and restricts both the circumstances in which revenue can be generated from congestion management and the uses to which such revenue can be put.

Resource adequacy (a.k.a. Capacity Markets)

The growth in the share of installed generating capacity in many Member States represented by intermittent renewable generators and the unattractive economics of new large-scale combined cycle gas-fired plant has left many governments in the EU concerned about security of power supply and turning to various forms of capacity market subsidy in order to ensure that the lights stay on.  The Commission has been concerned that capacity markets dampen the price signals that should drive new investment and potentially introduce new barriers to cross-border power flows.  A number of national capacity market regimes have been investigated by the Commission’s DG Competition; both the UK and French approaches to the problem have received state aid clearance.

The starting point of the draft Regulation in this area is an annual assessment of “the overall adequacy of the electricity system to supply current and projected demands for electricity ten years ahead”.  This European-level assessment will form the yardstick against which national proposals to introduce a capacity mechanism are to be judged.  If it has “not identified a resource adequacy concern, Member States shall not introduce capacity mechanisms” and no new contracts shall be concluded under existing capacity mechanisms.  Where capacity mechanisms are introduced, they must not distort the market unnecessarily; interconnected Member States should be consulted; and other approaches, such as interconnection and storage, should be considered first.

The draft Regulation prescribes common elements which capacity mechanisms must contain, including that they must be open to providers in interconnected Member States (unless they take the form of strategic reserves) and that the authorities of one country must not prevent capacity located in their territory from participating in other countries’ capacity mechanisms.  Those participating simultaneously in more than one capacity mechanism “shall be subject to two or more penalties if there is concurrent scarcity in two or more bidding zones that the capacity provider is contracted in”.  Maybe that will help to dampen industry’s appetite for capacity markets.

Finally, the draft Regulation sets an emission limit of 550 gCO2/kWh for plant on which a final investment decision is made after the Regulation enters into force.  Such plant must have emissions below this limit if it is to be eligible for capacity mechanism support.  The draft Regulation goes on to state that generation capacity emitting at this level or higher is “not to be committed in capacity mechanisms 5 years after the entry into force of this Regulation”.  These provisions may be motivated by laudable decarbonisation objectives, but they must at the very least risk precipitating a rush to take final investment decisions in new coal-fired generating capacity over the next two years.  It is possible, but unlikely, that they might stimulate further investment in carbon capture and storage (to bring the emissions of coal-fired plants below the threshold).  Previous experience with emissions limit rules also suggests that much will depend on how emissions are measured – the usual trick of polluting plant being to argue that they should be counted not per hour of generation, but averaged out over time so as to allow for plant to run above the limit for short periods.  This is bound to be an area for lively negotiations between Member States and in the European Parliament.

The Commission’s proposals in relation to capacity markets need to be read alongside DG Competition’s final report on its investigation and the accompanying Staff Working Paper.  We will look in more detail at this aspect of the proposals and how it might affect existing Member State initiatives in a future post.  For now, it is sufficient to note that although this part of the Winter Package is entirely consistent with the logic of the evolving single electricity market, for some, it may simply appear to be an unacceptable blow to the principle of Member States’ self-determination of their own generating mix.

Institutions

In addition to its existing roles, the TSO umbrella body, ENTSO-E, will acquire new responsibilities for the European resource adequacy assessment and in relation to the Regional Operational Centres, including adopting a proposal for defining the regions which each will cover, and generally monitoring and reporting on their performance.  A parallel umbrella body for DSOs, with consultative functions, is also to be set up.

The draft Regulation devotes a number of articles to the Regional Operational Centres. They will be limited liability companies established by TSOs (with adequate cover for potential liabilities incurred by the impact of their decisions).  Their role is to complement TSO functions by ensuring the smooth operation of the interconnected transmission system, but apparently from the perspective of planning and analysis rather than real-time  operational control.  Specific areas of their work (listed under 17 headings) include outage planning coordination, calculating the minimum entry capacity available for participation of foreign capacity in capacity mechanisms, and much else besides.

This area of the draft Regulation will need careful development and implementation if the proliferation of new bodies and functions is not to result in confusion and a lack of accountability.  However, the question of whether to grant Regional Operational Centres binding decision-making powers in relation to some of their potential functions is left to be decided by the national regulatory authorities of a system operating region.

The Revised RED

Target for 2030

The existing Renewable Energy Directive (2009/28/EC) sets out the binding national targets for each Member State to achieve a specified proportion of its energy consumption to be obtained from renewable energy sources (RES) by 2020, contributing to an EU-wide goal of 20% of final energy from RES.  The revised RED starts from a slightly different point, since EU leaders decided in 2014 to move away from legally binding national RES targets imposed at EU level but to set a goal of achieving at least 27% of energy from RES across the EU by 2030.  The starting point of the revised RED, therefore, is that “Member States shall collectively ensure” that the 27% target is achieved by 2030, whilst, individually, ensuring that they continue to obtain at least as high a proportion of final energy from RES as they were obliged to achieve by 2020.

At this point, you may ask what the enforcement mechanism is for meeting the new EU-wide target.  An answer (of sorts) is to be found in the Governance Regulation – see below.

Power (plus)

With reference to subsidies for RES, the revised RED builds on the principles set out in the Commission’s 2014 guidelines on state aid in the energy and environmental sectors: competitive auctions in which all technologies can compete on a level playing field are to be the norm, with traditional feed-in tariffs limited to small projects.

The revised RED also makes provision on two points that have led to disputes in connection with RES subsidies.  First, picking up on a point that has in the past given rise to litigation under general EU Treaty principles, it would set quotas for the proportion of capacity tendered in RES subsidy auctions that each Member State must throw open to projects from other Member States.  Second, with an eye to the numerous cases brought against Member States either under domestic constitutional / administrative law or under the Energy Charter Treaty, the revised RED attempts to outlaw retrospective reductions in support for RES once that support has been awarded, unless these are required because a state aid investigation by the Commission has found the subsidy received by a project is unduly generous.  Note that while the first of these rules appears to relate only to RES electricity subsidies, the second is expressed in a way that suggests that it relates to all RES projects.   An additional measure of reassurance for investors is a requirement to consult on and publish “a long-term schedule in relation to expected allocation for [RES] support” looking at least three years ahead.

Other points of interest in the draft Directive in connection with RES power include:

  • In a magnificently brief reference to one of the most important market trends in the renewable power sector, the revised RED would require Member States to “remove administrative barriers to corporate long-term power purchase agreements to finance renewables and facilitate their uptake”.
  • The process of applying for permits to build and operate new RES projects is to be streamlined, with a single point of contact co-ordinating the permitting process (including for associated network infrastructure) and ensuring that it does not last longer than three years.  This provision would confers on all RES projects (again, the current language of the draft Directive does not limit this to power sector projects) a benefit currently only conferred at EU level under the Infrastructure Regulation on those projects singled out as Projects of Common Interest – although in its current form it is questionable if it would give a developer thwarted by slow decision-making in a given case a useful remedy.
  • The permitting procedures for repowering of existing projects are to be “simplified and swift” (i.e. not to last more than 1 year), although this may not apply if there are “major environmental or social” impacts.  If you were hoping to be able to demand fast-track treatment for applications to repower existing wind farms with fewer, taller turbines generating more power, don’t hold your breath.
  • The existing RED rules on priority dispatch for RES generators are to be abolished.  This point is reiterated in the Revised Market Regulation.  However, that draft Regulation provides for “grandfathering” of priority dispatch rights for existing RES (and high efficiency CHP) generators until such time as they undergo “significant modifications”.  Exceptions are also permitted for innovative technologies and sub-500kW installations (from 2026, sub-250kW), if no more than 15% of total installed generating capacity in a given Member State benefits from priority dispatch (beyond that level, the threshold is 250kW or 125kW from 2026).
  • The revised RED likes prosumers, or as it calls them, “renewable self-consumers”.  They are to be entitled to sell their surplus power “without being subject to disproportionate procedures and charges that are not cost reflective”, to receive a market price for what they feed into the grid, and not to be regulated as electricity suppliers if they do not feed in more than 10MWh (as a household) or 500MWh (as a business) annually (Member States may set higher limits).
  • The revised RED also likes “renewable energy communities”.  The draft definition of these is a little complicated, but essentially they are locally based entities that are either SMEs or not for profit organisations, which are to be allowed to generate, consume, store and sell renewable electricity, including through PPAs.

Heat, cooling and transport

The revised RED seeks to “mainstream” RES in heating and cooling installations, and in the transport sector.  The means by which it seeks to achieve this are not, at first sight particularly dramatic, given the acknowledged scale and difficulty of the challenge of decarbonising these sectors.

In relation to heat and cooling, Member States are to identify “obligated parties amongst wholesale or retail energy and energy fuel suppliers” and require them to increase the share of RES in their heating and cooling sales by at least 1 percentage point a year.  The obligation should be capable of being discharged either directly or indirectly (including by installing or funding the installation of highly efficient RES heating and cooling systems in buildings).  This does not seem hugely ambitious.  Mention is made of “tradable certificates” – it feels a bit like a combination of the Renewables Obligation, but applied to heat and cooling, and the Clean Development Mechanism under the Kyoto Protocol.  It is also relevant in this context that the revised RED envisages that renewable guarantees of origin (REGOs or GoOs) will in future be available for the production and injection into the grid of renewable gases such as biomethane.

The rules aimed at the transport sector are also based on mandatory requirements on fuel suppliers – in this case to incorporate both a minimum (annually increasing) percentage of certain kinds of RES fuel, waste-based fossil fuel and RES electricity into the transport fuel they supply and to ensure that the parts of that supply that take the form of advanced biofuels and biogas from specified sources (which must constitute a certain part of the overall RES percentage) contribute to an increasing reduction in greenhouse gas emissions.  The provisions for calculating the various percentages are quite complex, involving as they do an element of lifecycle emissions calculation (e.g. considering the emissions from the generation of electricity used to produce advanced biofuels).

On district heating and cooling, the revised RED takes a three-pronged approach.

  • Member States are to ensure that authorities at local, national and regional level “include provisions for the integration and deployment of renewable energy and the utilisation of unavoidable waste heat or cold when planning, designing, building and renovating urban infrastructure, industrial or residential areas and energy infrastructure, including electricity, district heating, and cooling, natural gas and alternative fuel networks”.
  • The efficiency of district heating systems is to be certified.  Providers of such systems must grant access to new customers where they have the capacity to do so (unless they are new and meet exemption criteria based on efficiency and use of renewables).  Customers of systems that are not efficient may disconnect from them in favour of their own RES heat and cooling, but Member States may restrict this right to those who can demonstrate that the customer’s own heating or cooling solution is more efficient.
  • There is to be regular consultation between operators of district heating and gas / electricity networks about the potential to exploit synergies between investments in their respective networks.  Electricity network operators must also assess the potential for using district heating and cooling networks for balancing and energy storage purposes.

This is all unobjectionable.  It is not clear that in itself it will be enough to cause a major expansion of district heating and cooling where it does not already exist, or to significantly increase the take-up of RES heat and cooling options, but perhaps this is the kind of area where an effective policy push can only be delivered at national, or indeed municipal level.

Biomass

Following a trend that has been evident for some time in UK subsidies for RES electricity, the revised RED would appear to prohibit “public support for installations converting biomass into electricity” unless they apply high efficiency CHP, if they have a fuel capacity of 20 MW or more.  However, the precise words setting this out have been moved from the operative provisions of the draft Directive into a recital, which also clarifies that this would not require the termination of support that has already been granted to specific projects, but that new biomass projects will only be able to be counted towards renewables targets if they apply high efficiency CHP.

What is clear is that the revised RED would tighten the sustainability criteria applicable to biofuels and bioliquids at various points in the energy supply chain, with greenhouse gas emissions – for example those arising from land use to grow the raw materials that become biofuels – being designated as a distinct impact to be measured.  If you dig up soil with a high carbon content to grow something that will become biofuel, you may end up increasing rather than reducing overall GHG emissions, so this is obviously to be avoided.

The Governance Regulation

The Governance Regulation is meant to hold everything together.  In particular, it aims to give credible underpinning to the commitments on climate change that the EU as a whole has made under the Paris Agreement (but which must ultimately be delivered by Member State action) and to bridge the gap left by having an EU level 2030 renewables target but no correspondingly increased Member State level targets.  It also gives legislative expression to the EU’s Union-level energy and climate targets to be achieved by 2030, which are:

  • a binding target of at least 40% domestic reduction in economy-wide greenhouse gas emissions as compared with 1990;
  • a binding target of at least 27% for the share of renewable energy consumed in the EU;
  • a target of at least 27% for improving energy efficiency in 2030, to be revised by 2020, having in mind an EU level of 30%;
  • a 15% electricity interconnection target for 2030.

In outline, the Regulation works as follows.

  • Every 10 years, starting in 2019, each Member State is to produce an integrated national energy and climate plan covering a period of ten years, two years ahead (so e.g. the 2019 plan covers 2021 to 2030, and so on).  The plan is to set out, in relation to each of the five dimensions of the Energy Union, the current state of play in the relevant Member State; the national objectives and targets, policies and measures they have adopted; and their projections (including in relation to emissions) going forward to 2040.  The draft Regulation sets out in considerable detail the information which is required to be included.
  • In relation to RES and energy efficiency, Member States are expressly required to take into account the need to contribute towards achieving the relevant EU level targets, and to ensure, collectively, that they are met.  In relation to RES policies, they are also to take into account “equitable distribution of deployment” across the EU, economic potential, geographic constraints and interconnection levels.
  • The draft Regulation states that Member States must consult widely on the plans and suggests that there may also be a need for the preparation of and consultation on a strategic environmental assessment of the draft plans in some cases.
  • Every two years (starting in the first year to which the plans apply), Member States are to report to the Commission on the status of implementation of their plans; on GHG policies, measures and projections; on climate change adaptation and support to developing countries; on progress in relation to renewable energy, energy efficiency and energy security; on internal market benchmarks such as levels of interconnectivity; and on public spending on relevant research and innovation projects.  In addition, the draft Regulation specifies how Member States are to report annually on GHG inventories for UNFCCC purposes.
  • The plans and drafts are to be updated if necessary after five years (with the first draft update in 2023 and the first update in 2024), using the same procedures.  Updates cannot result in Member States setting themselves lower targets.
  • The plans are first to be submitted to the Commission for comment one year in advance, in draft (i.e. first draft by 1 January 2018).  Either at this point or in its annual State of the Energy Union reports, the Commission may make recommendations to individual Member States, for example about “the level of ambition of objectives and targets” in its draft plan, and Member States “shall take utmost account” of these when finalising the plan.  Member States are obliged to issue annual progress reports on their plans and these must include an explanation of how they have taken utmost account of any Commission recommendations and how it has implemented or intends to implement them.  Any failure to implement the Commission’s recommendations must be justified.
  • Member States whose share of RES falls below their 2020 baseline must cover the gap by contributing to an EU-level fund for renewable projects.  If it becomes clear by 2023 that the 2030 RES target is not going to be met, Member States must cover the gap in the same way, or by increasing the percentage of RES fuel to be provided by heat and transport fuel suppliers under the revised RED, or by other means.  Action may also be taken by the Commission at EU level.

The answer to the question of how the 2030 targets are enforced is therefore – and perhaps inevitably – somewhat incomplete.  Whilst one may doubt the usefulness, under the current RED, of the prospect of the Commission taking infraction proceedings against a Member State that fails to reach the required percentage of RES energy by 2020, there is arguably nothing in the Governance Regulation that has even this degree of legal bite when it comes to pushing recalcitrant Member States into action from the centre.  However, ultimately the whole edifice of the Paris Agreement, of which this is effectively a supporting structure, will only work on the basis of a combination of the economic attractions of better energy efficiency, cheaper renewables and other technological advances, and stakeholder pressure, including through democratic and judicial processes.  The Governance Regulation, like the UK’s Climate Change Act 2008 with its system of carbon budgets, certainly provides some scope for interested parties to challenge national authorities who are, for example, failing unjustifiably to implement Commission recommendations.

The Risk Regulation

The Risk Regulation exists to provide “a common framework of rules on how to prevent, prepare for and manage electricity crisis situations, bringing more transparency to the preparation phase and…ensuring that electricity is delivered where it is needed most”.  A common approach to identifying and quantifying risks is seen as essential to building the necessary “trust” and “spirit of solidarity” between Member States.  The draft Regulation would replace the rather less ambitious existing Directive 2005/89/EC.

ENTSO-E is tasked with developing a common risk assessment methodology, on the basis of which it is to draw up and update regional crisis scenarios such as extreme weather conditions, natural disasters, fuel shortages or malicious attacks.  Provision is made for emergency planning at both national and regional levels, with the Regional Operational Centres playing a significant role at various points.  As throughout the Winter Package, emphasis is laid on using market measures wherever possible, so that forced disconnections, for example, should be response of last resort, and Member States facing a crisis should not automatically seek to curtail outbound cross-border power flows.

The ACER Regulation

It comes as no surprise that the Winter Package proposes conferring more powers on ACER.  So, for example, the methodologies and calculations underlying the European resource adequacy assessment will require the approval of, and may be amended by, ACER – since, as one of the recitals to the draft Regulation notes, “fragmented national state interventions in energy markets constitute an increasing risk to the proper functioning of cross-border electricity markets”.  But the draft Regulation is far from representing a major transformation of ACER into an EU energy super-regulator.

The Innovation Communication

The Innovation Communication picks up on a number of the themes emphasised in the various legislative proposals.  It builds on existing initiatives, for example within the framework of the EU’s Horizon 2020 funding programme, for which it includes some new money.  The need to leverage more private sector investment in innovative energy-related technologies is noted, with some examples of where this has already been achieved.  The Communication also states that the Commission, with Member States, will take a leading role in two of the workstreams identified by the international Mission Innovation Initiative.

Four particular priorities are singled out as technology focus areas for EU innovation funding:

  • Energy storage solutions, including the (perhaps not unambitious) objective of “re-launching the production of battery cells in Europe”.
  • Electro-mobility and a more integrated urban transport system, which amongst other things will include tackling “fragmentation in the developing market of low-emission transport”.
  • Decarbonising the EU building stock by 2050: going beyond “today’s nearly zero-energy designs” to include e.g. the application of circular economy principles.
  • Integration of renewables: reducing the costs of existing established technologies; promoting new technologies like building-integrated photovoltaics; and intensifying efforts to integrate renewables through storage and the transport sector.

Energy Efficiency

Last but not least, energy efficiency. The two draft Directives on this make less wide-ranging changes to the existing legislation.

Under the revised Energy Efficiency Directive, Member States will be obliged to deliver the equivalent of 1.5% of annual energy sales (by volume) to final consumers over the period 2021-2030 – but with scope to determine how those savings are phased.

As regards the Energy Performance of Buildings Directives, there is an emphasis on encouraging the use of smart technologies.  There is also a requirement, when building or carrying out major renovations of buildings with more than 10 car parking spaces, to install one alternative fuel re-charging point for every 10 spaces in a non-residential context and to put in pre-cabling for re-charging points for EVs in all spaces in a residential context.  In the non-residential context at least, the re-charging point must be “capable of starting and spotting charging in relation to price signals”.  There are also some new requirements to monitor the energy efficiency of non-residential buildings, presumably in the hope that if their owners become aware of how much inefficiencies of design or operation are costing them, they will invest in improvements.

At the same time, the Commission has issued an ecodesign working plan for 2016-2019, reminding us as it does so that EU ecodesign and energy labelling deliver “energy savings equivalent to the annual consumption of Italy” and “save almost €500 per year” on household energy bills, as well as delivering approximately €55 billion extra revenue for industry.

Brexit

One of the many energy-sector questions raised by the UK’s decision to leave the EU is on what terms participants in the electricity markets in GB and Northern Ireland (and indeed the Republic of Ireland, until such time as it has a direct interconnection with Continental Europe) may be able to continue to participate in the EU’s single electricity market in a post-Brexit world.  Possible models for this include membership of the European Economic Area (as an EFTA, rather than an EU state) or joining the Energy Community (many of whose members are candidates for EU membership, but disputes within which are resolved by a political Association Council without reference to the Court of Justice of the EU).

The Winter Package in its published form casts no direct light on this subject.  However, in a version of the main legislative proposals that was leaked only a couple of weeks before they were published, a number of the draft measures (such as the draft revised IMED) included a couple of articles that appeared to offer some grounds for hope – if continued UK membership of the single EU electricity market is the sort of prospect that makes you hopeful.

  • Like the EU itself, the Energy Community is currently operating on (or is working towards) the version of the single electricity and gas markets set out in the Third Package of EU liberalisation measures adopted in 2009.  The leaked draft revised IMED set out a process for the Energy Community and the Commission to incorporate the revised Directive into the Energy Community’s legislative framework.  So if the UK was happy with the final form of the Winter Package legislation, the option of continuing to be subject to and getting the benefit of it as a member of the Energy Community would be a possible option.
  • On the other hand, once the UK ceases to be an EU Member State, and assuming it does not opt for EEA membership, it will simply become a “third country” (with or without the benefit of a bespoke EU / UK free trade agreement).  The leaked draft revised IMED suggested that third countries may participate in the single electricity market provided that they agree to adopt, and apply, “the main provisions” of the Winter Package legislation; EU state aid rules; the REMIT rules on wholesale energy market integrity; “environmental rules with relevant for the power sector”; and rules on enforcement and judicial oversight that require it to submit either to the authority of the Commission and the CJEU or “to a specific non-domestic enforcement body and a neutral non-domestic Court or arbitration body which is independent from the respective third country”.

Reading these provisions in the UK, it was hard not to see them as drafted with Brexit in mind.  Of course, the EU is, or aspires to be, physically connected to power systems in other non-EU countries as well (such as the potential solar energy exporters of North Africa), so it would be wrong to see them entirely in that light.

How the absence of such provisions, or the prospect of their potential reinsertion, will affect the dynamics of the UK’s participation in negotiations on the Winter Package (which is likely to take place while the UK is still a Member State) is another question.  In our view, the UK and its electricity industry stakeholders should in any event try to play a leading and constructive role in the whole of the negotiations on the Winter Package, as they have in negotiation on past internal energy market measures.

Maybe, in one sense, it is better that the draft provisions on third country participation have not been included at this stage.  Similar provisions could be negotiated on a standalone basis later, and include the gas as well as electricity single markets, for example.  By leaving them out of the Winter Package (for whatever reason), the Commission may have prevented the UK team from being unduly distracted from the main subject of the legislative proposals, or expending its negotiating capital on their Brexit dimension.

Provisional conclusions

The Winter Package covers a lot of ground, but then it needs to do so, since the next ten years are acknowledged to be crucial to the success of global efforts to avoid dangerous climate change.  It may not be as radical as some would like, but then whilst some of its requirements are already more or less met by a number of Member States, for others they may represent a considerable challenge.  In one sense it is a timely reminder of both the scope and the limitations of the European project.

There are a lot of links between the individual pieces of draft legislation.  There are also a number of areas where the drafting suggests that some key concepts have not yet been absolutely fully thought out.  Steering negotiations so as to result in a clear and coherent legal framework will be difficult.  The risks of (calculated or inadvertent) lack of clarity in the final texts may be higher than is usual with EU legislation, leading to wrangles with regulators and before the courts down the line – or simply having a chilling effect on what could be useful activity.  However, since the need for action is urgent, waiting for perfect legislation is not a luxury the EU can afford.  So it is vital that those with an interest in making Energy Union work scrutinise the parts of the Winter Package that matter to them carefully, and tell their national governments or MEPs where they find it wanting.

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Something for everyone? The European Commission’s Winter “Clean Energy” Package on Energy Union (November 2016)

Sanctions in Energy: Russia and Iran

US and EU sanctions related to Russia and Iran have a direct and targeted impact on the energy sector. The sanctions regimes against Russia and Iran differ substantially and seem to be moving in different directions. In this article, we explore the challenges facing US and EU energy companies seeking to operate in Russia and Iran.

Brief overview of energy related sanctions against Russia

US Sanctions

Since March 2014, the US has imposed an increasingly strict set of sanctions against Russian and Ukrainian individuals and companies. These sanctions generally fall into four categories: a list of blocked persons and entities, identified as Specially Designated Nationals, or SDNs; much more limited restrictions for specified Russian banks, oil companies and technology companies, identified as a Sectoral Sanctions Identification List or SSI List; export controls; and a full commercial embargo of Crimea. These sanctions are imposed pursuant to several Executive Orders promulgated by President Obama and the Ukraine-Related Sanctions Regulations[1]. US Persons—defined as US citizens and permanent residents, entities organized under US jurisdictions, and persons physically in the United States—must comply.

The US has designated as SDNs a number of key government and military officials (both Russian and from the former Ukrainian Government), individuals with close ties to the Russian Government, and Russian and Crimean entities[2]. US Persons are generally prohibited from transacting with any of these blocked persons, and must freeze such blocked persons’ property in their possession, custody, or control. These SDNs are also banned from traveling to the US. In comparison with the SSI List, SDNs targeted inter alia leaders of the Russian oil companies.

According to SSI List and its related OFAC’s Directives, the following activities by a US Person or within the United States related to oil companies are prohibited, except to the extent provided by law or unless licensed or otherwise authorized by the Office of Foreign Assets Control: the provision, exportation, or re-exportation, directly or indirectly, of goods, services (except for financial services), or technology in support of exploration or production for deep-water, Arctic offshore, or shale projects that have the potential to produce oil in the Russian Federation, or in a maritime area claimed by the Russian Federation and extending from its territory, and that involve any person determined to be subject to this Directive, its property, or its interests in property. The prohibition on the exportation of services includes, for example, drilling services, geophysical services, geological services, logistical services, management services, modeling capabilities, and mapping technologies[3]. The SSI List includes, among others, Russia’s largest energy companies.

EU sanctions

The US and EU sanctions are largely aligned. Like the US, the EU has also adopted sanctions that block persons, restrict financing, limit certain exports, and broadly prohibit trade with Crimea. EU persons—EU citizens and permanent residents, entities organized in EU member states and persons physically in the European Union—must comply.

While there are differences between the US and EU sanctions, these are more of a degree than of a kind. For example, the EU and US do not block an identical set of individuals and entities, but the implications for those blocked persons are the same: a visa ban (for individuals) and a freezing of all assets[4]. Notably for EU companies in the energy sector, EU sanctions prohibit the provision of loans or investment services to Crimean companies, ban exports of goods and technology and prohibit the provision of technical assistance, brokering, construction, or engineering services, in the energy sector and in the prospecting for, and exploration and production of oil, gas, and mineral resources, to any Crimean entity, or for use in Crimea. Contracts signed prior to 20 September 2014 are exempted[5].

Brief overview of energy related sanctions against Iran

On 14 July 2015, the “P5+1” working group (China, France, Germany, Russia, the UK and the US) reached a landmark agreement with the Government of Iran to adopt the Joint Comprehensive Plan of Action (the JCPOA). Under the JCPOA, the P5+1 agreed to implement broad UN, US and EU sanctions relief in exchange for Iran’s ongoing compliance with a number of nuclear-related measures. This sanctions relief will occur in two phases: (1) when the International Atomic Energy Agency (the IAEA) verifies Iran’s compliance with nuclear-related measures, which occurred on 16 January 2016; and (2) when the IAEA, together with the UN Security Council, confirms that Iran’s nuclear materials are being used for peaceful activities, or 18 October 2023, whichever is sooner[6].

US Sanctions

Most of the US sanctions that are suspended—both in the first and second phases—are extraterritorial, i.e., they apply to non-US Persons who do business with Iran. US companies seeking to engage the Iranian market, therefore, need to be aware of the limits of US sanctions relief under the JCPOA, namely:

1. US Persons generally remain prohibited from doing business with Iran. The JCPOA will not lift the general commercial embargo which prohibits US Persons from doing business with Iran, except for certain sales of civilian commercial aircraft to Iran, imports of Iranian-origin carpets and foodstuffs.
2. US companies’ overseas subsidiaries will be licensed to transact with Iran under OFAC’s General License H. The JCPOA will license overseas subsidiaries of US entities for activities consistent with the agreement. However, the licensing methodology and the definition of “overseas subsidiaries” are not described and remain to be clarified.
3. Other US sanctions including those related to counter-terrorism or human rights-related sanctions asserting extraterritorial application[7] will remain in place.
4. On 7 October 2016, OFAC issued updated guidance on several issues. The issues addressed include banking transactions with Iranian banks; dollar-denominated transactions; acceptable due diligence standards; and part-ownership of Iranian companies by entities who remain on the SDN list[8].

With regard to Iran’s vast oil and gas reserves, the first phase of relief will mean the US will no longer sanction non-US Persons who engage in transactions with Iran’s energy, shipping and shipbuilding sectors, or port operations[9]. Nor will the US any longer sanction non-US persons who invest in Iran’s oil, gas and petrochemical sectors; purchase, sell, transport, or market oil, gas and petrochemicals from Iran; export, sell or provide refined petroleum products and petrochemical products to Iran; or otherwise transact with Iran’s energy sector including Naftiran Intertrade Company, National Iranian Oil Company and National Iranian Tanker Company, and associated services[10]. Non-nuclear-related sanctions still remain in place on all companies and persons, regardless of nationality, who seek to do business with any Iranian people or entities which remain on the SDN List.

EU sanctions

EU sanctions relief is far more expansive. Unlike the US, the EU will allow its companies to invest directly in Iran and transact with Iranian persons. EU member states have agreed to terminate or suspend all “economic and financial sanctions” against Iran[11]. As a result of the first phase of sanctions relief under the JCPOA, EU persons are permitted to trade in Iranian crude oil and petroleum products, natural gas and petrochemical products, as well as related financing. Similarly, the sale, supply or transfer of equipment and technology, as well as the provision of technical assistance and training in this sector are permitted. In addition, EU Persons are free to grant financial loans or credit and to participate in joint ventures with any Iranian persons engaged in the oil, gas and petrochemical sectors in Iran or elsewhere.

Implications for energy companies

While the US and EU have both imposed a number of sanctions on Russia that aim directly to constrain investment in Russia’s energy sector—and in particular its future oil development—there are a number of reasons why Russia’s energy sector may possibly continue to attract US and European investment.

To begin with, US and EU sanctions are (thus far) narrowly targeted. Unless specifically prohibited, Russia’s economy, including its energy sector, is fully open to investment. Second, the sanctions against Russia could be lifted, if the situation in Eastern Ukraine and Crimea develops in certain directions. Finally, US and EU companies are more familiar with Russia and Russian business practices in comparison to Iran, a country where numerous other compliance and other business risks are encountered.

During the first phase of sanctions relief under the JCPOA, which began on 16 January 2016, EU energy companies and the overseas subsidiaries (again yet to be defined) of US energy companies will now have the opportunity to engage Iran’s vastly underdeveloped energy sector. It is estimated that the country will need hundreds of billions of dollars of investment to restore its petroleum fields and then further develop them. EU and the overseas subsidiaries of US companies seeking to engage Iran should therefore be prepared to understand and implement an updated sanctions compliance program that ensures they do not inadvertently risk breach of the ongoing EU and US sanctions. These companies will need to also actively monitor Iran’s compliance as determined by the IAEA and the JCPOA Committee, as a breach may trigger a mandatory wind-down and withdrawal.

The same is not true with regard to the remaining US sanctions against Iran, for example, which would require approval by the US Congress. Moreover, critically, the JCPOA provides for UN, US and EU sanctions to “snapback.” This means that while many companies may now be allowed to invest in Iran, they will face the prospect of having to wind down their operations in the event that Iran is found to have breached the JCPOA[12].

“We note that other countries, including Canada, also continue to maintain sanctions against Iran that go beyond the limited sanctions imposed by the UN. To the extent there is any connection to such other countries in particular transactions, country-specific sanctions compliance advice should also be sought.”


[1]31 CFR Part 589.
[2]Executive Orders of the President of the US on “Blocking Property of Certain Persons Contributing to the Situation in Ukraine,” No 13660 dated 6 March, 2014 and No 13661 as of 19 March 2014 “Blocking Property of Additional Persons Contributing to the Situation in Ukraine,” Section 1, 19 December 2014. As a result of blocking sanctions, all property and interests of designated persons which are within (or may come into) the possession and control of any US individual or entity (which extends to a foreign branch of a US entity) are blocked, and an entry into the US of designated persons is suspended.
[3]Directive 4 under Executive Order 13662 of the Office of Foreign Assets Control as of 12 September 2014.
[4]The Council of the European Union, giving force to its Decision 2014/145/CFSP authorizing travel restrictions and the freezing of funds and economic resources of certain individuals believed to have been responsible for actions “which undermine or threaten the territorial integrity, sovereignty and independence of Ukraine“ (“designated individuals”), adopted Council Regulation (EU) No. 269/2014 of 17 March 2014.
[5]US and EU embargo Crimea, and US adopts new Ukraine sanctions law, 29 December 2014.
[6]The second phase of sanctions relief is eight years after “Adoption Day,” defined as 18 October 2015. See http://www.state.gov/secretary/remarks/2015/10/248311.htm
[7]Executive Order of the President of the US on “Blocking the Property and Suspending Entry Into the United States of Certain Persons With Respect to Grave Human Rights Abuses by the Governments of Iran and Syria via Information Technology” No. 13606 dated 22 April 2012.
[8]https://www.treasury.gov/resource-center/sanctions/OFAC-Enforcement/Pages/20161007_33.aspx
[9]Iran Freedom and Counter-Proliferation Act as of 2012, Section 1244(c)(1),(d).
[10]President Obama directs key US agencies to prepare for sanctions waivers under the JCPOA, 21 October 2015 and The Joint Comprehensive Plan of Action: A First Look, 17 July 2015.
[11]In the second step, on Transition Day, the EU will seek to terminate the sanctions suspended in the first step and terminate EU proliferation-related sanctions. As such, EU proliferation-related sanctions, among some other measures, will remain in place for eight years after Implementation Day.
[12]Special thanks to former Managing Associate of Dentons US LLP, Mr. Kenyon Weaver, for his contribution to this article.
Sanctions in Energy: Russia and Iran

First flesh on the bones of the new UK government’s energy policy?

The UK Department of Business, Energy & Industrial Strategy (BEIS) chose 9 November 2016 to release a series of long-awaited energy policy documents.  The substance of some of the announcements, which primarily cover subsidies for renewable electricity generation and the closure of the remaining coal-fired generating plants in England and Wales, was first outlined almost a year ago when Amber Rudd, the last Secretary of State for Energy and Climate Change, “re-set” energy policy in outline in a speech of 18 November 2016.  Broadly speaking, the documents indicate that little has changed in the UK government’s thinking on energy policy following the EU referendum and the formation of what is in many respects a new government under Theresa May.

Contracts for Difference

BEIS has confirmed that the next allocation process for contracts for difference (CfDs) for renewable generators will begin in April 2017, aiming to provide support for projects that will be delivered between 2021 and 2023. There will be no allocation of CfD budget for onshore wind or solar, consistent with the Government’s view that these are mature and/or politically undesirable technologies which should no longer receive subsidies.  The only technologies supported will be offshore wind, certain forms of biomass or waste-fuelled plant (advanced conversion technologies, anaerobic digestion, biomass with CHP) wave, tidal stream and geothermal.

The budget allocation is a total of £290 million for projects delivered in each of the delivery years covered: 2021/22 and 2022/23. Details are set out in a draft budget notice and accompanying note.  CfDs are awarded in a competitive auction process, the details of which are set out in an “Allocation Framework” (the one used for the last auction, in 2014/2015, can be found here).  It is likely that most, if not all, of the budget will be taken up by a small number of offshore wind projects, as the size of the projects which could be eligible to bid in the auction is large in comparison with the available budget.

Competition for CfDs will be fierce and Government should be able to show progress towards achieving its target of reducing support to £85/MWh for new offshore wind projects by 2026. For the 2017 auction, “administrative strike prices” have been set at levels designed to ensure that “the cheapest 19% of projects within each technology” can potentially compete successfully.  Behind this terse statement and the methodology it summarises lies an extensive BEIS analysis of Electricity Generation Costs, underpinned or verified by studies or peer reviews by Arup, Imperial College, NERA, Prof Anna Zalewska, Prof Derek Bunn, Leigh Fisher and Jacobs and EPRI.

The heat is on

Alongside the draft budget notice, BEIS has published two documents about CfD support for particular technologies.

One of these is a consultation that returns to the long-unanswered question of what to do about onshore wind on Scottish islands: should it be regarded as just another species of onshore wind (and therefore not to receive subsidy, in line with post-2015 Government policy), or does it face higher costs to a degree that merits a special place in the CfD scheme, as was suggested by the 2010-2015 Government?  It comes as no surprise that the Government favours the former view: another item to add to the list of points on which the UK and Scottish Governments do not see eye to eye.

The second document is a call for evidence on the currently CfD-eligible thermal renewable technologies of biomass or waste-fuelled technologies (including biomass conversions), and geothermal.  These raise a number of issues, on which the call for evidence takes no clear stance.

  • Is continued support for the fuelled technologies in particular consistent with getting “value for money” by focusing subsidies on the cheapest ways of decarbonising the power supply (except onshore wind and solar), given that (with the exception of biomass conversions), they have a relatively high levelised cost of electricity generation?
  • Can they be justified on the grounds that they are “despatchable” (and so do not impose the same burdens on the system as “variable” renewable generation like wind and solar)?  Or on the grounds that (where they incorporate combined heat and power), they contribute to the decarbonisation of heat, as well as of power generation – an area in which more progress needs to be made soon in order to meet our overall target for reducing greenhouse gas emissions under the Climate Change Act 2008 (and the Paris CoP 21 Agreement)?
  • Is the current relationship between the CfD and Renewable Heat Incentive support schemes the right one in this context?  Is a CfD for a CHP plant unbankable because of the risk of losing the heat offtaker?
  • Are all these technologies about to be overtaken as potential ways of decarbonising the heat sector on a large scale by other contenders such as hydrogen or heat pumps (and if so, is that a reason to abandon them as targets for CfD or other subsidy)?
  • Should more existing coal-fired power stations be subsidised to convert to burning huge quantities of wood pellets (is that really “sustainable” – and would such subsidies comply with current EU state aid rules, for as long as they or something like them apply in the UK)?

Against this background, the draft budget notice proposes to limit advanced conversion technologies, anaerobic digestion and biomass with CHP to 150MW of support in the next CfD auction.

Kicking the coal habit

Finally, BEIS is consulting on the best way to “regulate the closure of unabated coal to provide greater market certainty for investors in the generation capacity that is to replace coal stations as they close, such as new gas stations”.  The consultation needs to be read alongside BEIS’s latest Fossil Fuel Price Projections (with supporting analysis by Wood Mackenzie).  These set out low, central and high case estimates of coal, oil and gas prices going forward to 2040.  BEIS has significantly reduced its estimates for all three fuels under all three cases as compared with those in its 2015 Projections.

We are talking here about eight generating stations, which between them can produce 13.9GW. Their share of GB electricity supply tends to fluctuate with the relative prices of coal and gas.  Most are over 40 years old.  All can only survive by taking steps to comply with the limits on SOx, NOx and dust prescribed by the EU Industrial Emissions Directive – at least for as long as the UK is within the EU.

The Government’s difficulty is how to ensure that these plants close (for decarbonisation purposes), but on a timescale and in circumstances that ensure that the contribution that they make to security of electricity supply is replaced without a gap by e.g. new gas-fired plant, of which so little has recently been built. BEIS evidently hopes that by the time this consultation finishes on 1 February 2017, the results of next month’s four-year ahead Capacity Market auction will have seen a significant amount of new large-scale gas fired power projects being awarded capacity agreements at prices that make them viable (when taken together with expectations of lower-for-longer gas prices).

Although BEIS professes confidence in the changes that it has made to the rules and market parameters for the next Capacity Market auctions, one cannot help but wonder how convinced Ministers are that the 2016 auctions will succeed in this respect where those of 2014 and 2015 failed.  Because from one point of view, if the Capacity Market does result in new large gas-fired projects with capacity agreements, and gas prices remain low, the market should simply replace the existing coal-fired plants – which, as the consultation points out, aren’t even as flexible as modern gas-fired plant.  Maybe if a newly inaugurated President Trump pushes ahead with his plans to revive the use of coal in the US, higher coal prices will help accelerate the closure of some of our remaining coal-fired plants: BEIS calculates that with relatively low coal prices and no Government intervention, they could run until 2030 or beyond.

So how will Government make the plants close? Two options are proposed.  One would be to require them to retrofit carbon capture and storage (CCS), the other would be to require them to comply with the emissions performance standard (EPS) that was set in the Energy Act 2013 for new fossil-fuelled plant with a view to ensuring that no new coal plant was commissioned.  Neither path is entirely straightforward.  As it seems unlikely that operators would invest the kinds of sums associated with CCS on such old plant, there must be a risk that in trying to make CCS a genuine alternative to complete closure, regulations could end up allowing operators to run a significant amount of capacity without CCS whilst taking only limited action to develop CCS capacity.  With the EPS approach, there would be some tricky questions to resolve around biomass co-firing, as well as biomass conversion, if that were to remain an eligible CfD technology and budget were to be allocated to it.

When it comes to consider how to ensure that coal closure does not involve a “cliff-edge” effect, the consultation seems to run out of steam a bit: having mentioned the possibility of limiting running hours or emissions, either on a per plant basis or across the whole sector, BEIS says simply that it would “welcome any views on whether a constraint [on coal generation prior to closure] would be beneficial and, if so, any ideas on the possible profile and design”.

What next?

Nothing stands still.  The period of these consultations / calls for evidence, and the next Capacity Market auctions, overlaps with other processes.  Over the next few months, the Government is scheduled to produce over-arching plans or strategies in a number of areas that overlap with some of the questions posed in these documents.  It will also continue to develop its strategy for Brexit negotiations with the EU; and the European Commission will publish more of its proposals on Energy Union (including new rules on renewables, market operation and national climate and energy plans).

The documents state more than once that while the UK is an EU Member State, it will “continue to negotiate, implement and apply” EU legislation. But – at least in relation to coal closure – the Government is trying to make policy here for the 2020s.  By that time, it presumably hopes, it will no longer be constrained by EU law.  It remains to be seen how Brexit will affect the participation of our remaining coal-fired plants in the EU Emissions Trading System, which is at present a significant feature of the economics of such plant.  In the short term, the coal consultation points to an announcement in the Chancellor’s 2016 Autumn Statement (23 November) of the “future trajectory beyond 2021” of the UK’s own “carbon tax”, the carbon price support rate of the climate change levy.

After a period in which we have been relatively starved of substantive energy policy announcements, things are starting to move quite fast, and decisions taken by Government over the next few months could have significant medium-to-long-term consequences for UK energy and climate change policy.

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First flesh on the bones of the new UK government’s energy policy?

Alberta unveils Renewable Electricity Program: The beginning of the end for the energy-only market?

On November 3, 2016, the Alberta government released the details of its long-awaited plan to accelerate the development of renewable power generation in the province through an auction-based procurement process—a key plank of the Climate Leadership Plan it announced in 2015.

The Renewable Electricity Program (REP) will be launched in early 2017 with an initial, three-stage procurement process for up to 400 MW in new or expanded renewable generation.  Winning bidders will be awarded payments under a “Renewable Electricity Support Agreement” (RESA) that would grant fixed, market-insulated prices for a 20-year term, similar to Ontario and other jurisdictions.

The REP represents a clear, if incremental, change of course for Alberta’s “energy-only” electricity market model—one that will offer significant opportunity to prospective renewable developers if the 2017 auction succeeds.

Background:  The Climate Plan and the AESO’s role

In late 2015, the Alberta government, acting on the recommendations of a Climate Change Advisory Panel (Climate Panel), released its Climate Leadership Plan, a four-pronged “policy architecture” to address climate change in the province.

Beyond its plans for an economy-wide carbon tax, a 100 Mt oil sands emissions cap and a methane reduction plan, the Climate Plan includes a commitment to “30 by ’30”:  to increase the generation share of renewables in Alberta to 30 percent by 2030. To that end, the Climate Panel recommended setting up an open, competitive request for proposals process and incentive payments bounded by a “price collar” (or limit to government support) of CA$35/MWh.  The Panel otherwise saw no need for a change in Alberta’s “energy-only” electricity market.

The “30 by ’30” goal coincides with the Climate Plan’s announcement of a planned phase-out of all of Alberta’s coal-fired generation by 2030. This will be a significant undertaking: based on Alberta Energy 2015 statistics, coal supplies fully half of Alberta’s power requirements.

In January 2016, the Alberta government assigned the Alberta Electric System Operator (AESO) the task of developing specific recommendations on the REP, noting that the government “has not chosen to fundamentally alter the current wholesale electricity market structure.” In the first half of 2016, the AESO launched a stakeholder engagement process and retained economic and financial consultants to study options.

The AESO’s report and the Renewable Electricity Program

On November 3, 2016, the Alberta government publicly released the AESO’s May 2016 Renewable Electricity Program Recommendations report (AESO Report) and adopted its recommendations as the REP.

Speaking at the Canadian Wind Energy Association’s annual conference, Minister Shannon Phillips claimed that the REP would inject some CA$10.5 billion into the Alberta economy by 2030 and create 7,200 jobs. The policy is to be implemented through enacting a Renewable Electricity Act in late 2016.

(a)  The REP payment mechanism: Loosening the “collar”

The REP aims to incent the addition of 5,000 MW in installed renewable generation by 2030 through a series of AESO-administered auctions. As described by the AESO, the “[w]inning bidder bids a price that is, in essence, its lowest acceptable cost for the renewable project the bidder plans to advance.” Successful bidders are awarded the right to guaranteed per-MWh prices for 20-year terms via “top-up” support payments enshrined in a RESA.

The RESA payment mechanism, financed by carbon revenues from large industrial emitters, operates as a so-called “Contract for Differences.” To compensate for low Alberta power market prices relative to renewable costs, RESA payments add to the generator’s market revenues and recede as the market price rises toward the generator’s bid price. If the market price exceeds the generator’s bid price, the generator pays its above-bid revenues to the government.

Interestingly, this “indexed” approach was criticized in the November 2015 Climate Panel report on the basis that it would remove market price–based incentives for higher-value (rather than simply higher-capacity) power projects and “likely trigger a land rush for the best wind resources in the province.”

The AESO Report, on the other hand, indicates the opposite concern with the Climate Panel’s CA$35/MWh support “collar”—noting that consulted lenders were of the view that it left power projects unfinanceable. The AESO expects the RESA’s “uncollared,” indexed approach to attract more extensive bidder interest by offering greater revenue certainty to developers (and by placing price risk with Alberta). The likely result, in the AESO’s estimation, is a more competitive auction featuring lower bid prices.

(b)  The 2017 REP bid process

Alberta has indicated its intention to stage and complete its first REP procurement in 2017. For the AESO’s first round, qualifying projects must:

  • be based in Alberta;
  • be new or expanded (existing projects are not eligible);
  • be 5 MW or greater in size;
  • meet Natural Resources Canada’s definition of a “renewable” source;
  • connect to existing transmission or distribution infrastructure; and
  • be operational by the end of 2019.

The requirements of an existing grid connection and a 2019 in-service date may constrict the 2017 bidder pool. In particular, the AESO Report itself acknowledges the challenges developers may face in obtaining the requisite regulatory approvals in time to energize in 2019.

The auction process is to follow three stages, each monitored by an appointed “Fairness Advisor”:

  • Request for Expressions of Interest (REOI): in which the AESO has the opportunity to attract and gauge interest in the auction and receive feedback (4-6 weeks);
  • Request for Qualifications (RFQ): in which eligibility requirements are released and bidders submit their qualifications (including in respect of project eligibility, financial strength and capacity, and construction and operations capability), and a non-refundable “Pay-to-Play” fee is paid by participants (4-6 months); and
  • Request for Proposals (RFP): in which qualified bidders provide security for their bids, make final, binding offers and a winning bidder is selected (2-3 months).

The auction process will be “fuel-neutral”; the AESO is not setting quotas for, or otherwise favouring particular sources. Notably, for the first auction, there is also no provision for crediting Aboriginal or community aspects of a project, as in Ontario’s FIT programs, and as was contemplated by the Climate Panel. The AESO Report instead insists that qualified bidders strictly “be selected on based on lowest price (subject to any affordability ceiling).”

The government has indicated that stakeholder engagement on the 2017 auction’s draft commercial terms will begin on November 10, 2016.

Does the energy-only market have a future?

Since Ontario’s foray into procuring contracted, renewable forms of generation began in 2004, the share of the province’s generation under contract—without exposure to the market price—has risen to 65 percent, according to data from a 2015 Independent Electricity System Operator (IESO) report. Many commentators have described Ontario’s market as a “hybrid” system, characterized by high levels of policy intervention, steeper costs and the effective abandonment of market price as a generation investment signal.

The introduction of market price–insulated generation envisioned by the REP promises, at least at this juncture, to be more incremental than Ontario’s sweeping example. The Climate Plan and AESO Report both contemplate the maintenance of Alberta’s wholesale market system and prioritize, in express terms, cost containment. The increasing price-competitiveness of renewable sources, too, may cushion the cost increases seen in early-adopting jurisdictions. Finally, as noted by the Climate Panel, Alberta continues to reap the benefit of an abundant, low-priced gas supply in transitioning away from coal.

Notwithstanding this, the eligibility of generators for RESA payments—especially given the low market prices and rising costs of the current environment—may itself “result in other generators demanding the same treatment (i.e. some kind of guaranteed revenue stream),” as the AESO acknowledges in its report. Elsewhere, the AESO Report presents a grim diagnosis for non-renewable investment, noting that “there has been a significant erosion of the support for investing in the energy-only markets in Alberta (and elsewhere) given [that] market and policy is undermining confidence.” It remains to be seen whether the REP’s policies, as in other places, signal a broader trend away from energy-only markets; are themselves overtaken by political opposition in a contested election; or find their place in a market framework that has, to date, proven adaptable to Alberta’s ever-changing climate.

This post was co-authored by Joseph Palin and Bernard Roth, Partners in Dentons’ Calgary office.

Alberta unveils Renewable Electricity Program: The beginning of the end for the energy-only market?

Ukraine’s Energy Efficiency Fund

Efficiency dilemma

In common with other post Soviet countries, Ukraine suffers from very low energy efficiency and a high level of energy consumption in its economy. Key primary sources of energy are coal and natural gas (about 36 percent of the energy mix each), with nuclear power accounting for roughly 18 percent.[1]

The Ukrainian government has been aware of the efficiency issue for decades but has failed to make substantial progress. State officials felt no great incentive to take any meaningful active measures, as Russia always sold natural gas to Ukraine at low prices.

The mood changed dramatically in 2014 when the need for a long-term energy efficiency drive was made painfully obvious by the flare up of tensions between Ukraine and the Russian Federation. In particular, Ukraine’s northern neighbor tried to pressurize the new administration and the state-owned company PJSC “Naftogaz of Ukraine” into buying natural gas at much higher prices than previously. This kick-started the Ukrainian government into taking a number of sporadic energy efficiency initiatives, such as partial reimbursement of loans to households to replace gas boilers, special ESCO legislation in the public sector, and special tariffs for producers of heat from alternative fuel.

While these measures had some effect, they were soon deemed insufficient, and both public officials and civil society realized that a more systematic approach was required, in particular in terms of providing financing for energy efficiency measures in the district heating sector.

This culminated in late 2015 / early 2016 with the government proposing that an Energy Efficiency Fund be set up to create sustainable financing for energy efficiency activities in district heating and related areas. Discussions ensued, resulting in the Cabinet of Ministers of Ukraine adopting a formal ‘Concept for the Implementation of Mechanisms for Sustainable Financing of Energy Efficient Measures’ by Resolution No. 489-p of 13 July 2016. The Resolution paves the way for the regulatory framework needed to establish the Energy Efficiency Fund, as discussed below.

Savings opportunity

The Concept estimates that the country loses out to the tune of US$3 billion annually through the inefficient use of fuel and energy in district heating costs, meaning that some 60 percent of energy resources are wasted. Household energy consumption is running at 20,384 Mtoe, which is almost 33 percent of total consumption in Ukraine ‒ 58 percent of which is natural gas.

Ukraine burns on average 18.6 bcm of gas per annum to meet its district heating requirements. If Ukraine enjoyed EU levels of gas consumption efficiency, it would save up to 11.4 bcm annually (equivalent to 60 percent of Ukrainian imports). This could be achieved through the following measures: (i) thermal upgrade of buildings (up to 7.3 bcm); (ii) replacement of residential boilers (up to 1.7 bcm); (iii) boiler upgrades (up to 1.1 bcm); and (iv) pipeline upgrades (up to 1.3 bcm).

The intensity of individual energy consumption in Ukraine is two to three times higher than in western EU member states. To achieve a comparable level of energy efficiency, an estimated UAH 830 billion (approx. US$32 billion) would need to be invested in thermal upgrades of buildings. Disappointingly, only UAH 893 million (approx. US$34 million) was allocated for these purposes in the state budget for 2016–2017. Given scant resources in state and local budgets, sustainable financing of energy efficiency projects in residential buildings is possible only with additional funding from international financial and donor organizations.

Creating the Energy Efficiency Fund

The Ukrainian government believes the Energy Efficiency Fund will successfully attract external financial resources. It will be based on the principles of transparent and efficient use of available resources and on the model European approach towards cooperation between state and international financial organizations.

The Fund should start operations in 2017 (most likely full scope operation will start in April 2017, according to recent statements by government officials) and optimal results are expected to be achieved in a 15 year horizon. Key goals include: (i) a reduction in the consumption of natural gas forecast at 1.5 bcm annually, saving UAH 9.1 billion (US$350 million) annually and improving stability of the local currency and energy efficiency; (ii) reduction in direct subsidies (UAH 5 billion annually) and other breaks for consumers with respect to utilities payments; (iii) creation of a new market for energy efficiency measures; (iv) creation of up to 75,000 new jobs; (v) increased tax payments of up to UAH 10 billion; and (vi) a reduction in household bills, and increased investment by households in their own energy efficiency.

The government plans that, initially, the Fund will use existing mechanisms of support available under state and local budgets. According to official statements, UAH 800 million (US$31 million) has been allocated for the Fund, and up to US$110 million is expected from international partners for 2016-2017.

The Cabinet of Ministers of Ukraine expects to create the Fund directly as a state establishment, as proposed under the Bill: Law on Energy Efficiency of Buildings No. 4941 of 11 July 2016, planned to be voted on in November 2016. The Fund will act on the basis of a charter approved by the government.

It is expected that the Fund will, in particular: (i) reimburse part of the interest payable on loans (or part of loans) obtained by individuals, associations of co-owners of condominiums and ESCO companies for energy efficient measures related to residential households, public establishments and organizations; (ii) provide technical support (energy audit, technical and economic feasibility, etc.) for projects aimed at enhancing energy efficient measures of residential households, public establishments and organizations and heating supply buildings; (iii) provide proposals for state policy in the sphere of energy efficiency and related instruments; and (iv) perform other functions in accordance with its charter.

The Ministry of Regional Development and Municipal Economies of Ukraine is currently working on the structure of the Fund, and the government is expected to approve its internal structure (financing, staff, etc.) after consultations with all interested parties in October–November 2016.

[1] https://www.eia.gov/beta/international/analysis.cfm?iso=UKR

Ukraine’s Energy Efficiency Fund