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Trump’s response to Harvey, Irma, Maria and Sandy: more subsidies for coal-fired power

Those who wondered how President Trump would make good on his promise to put coal miners back to work now have their answer. On September 28 2017, Secretary of Energy Rick Perry dusted off a rarely used power in the Department of Energy Organization Act 1977 (DOEOA) and sent the Federal Energy Regulatory Commission (FERC) a proposal that it make a rule to “establish just and reasonable rates for wholesale electricity sales”. By this he appears to mean allowing coal-fired (and nuclear) plants to charge higher prices based on their contribution to the resilience of electricity suppliers. (Click here for the text of the Notice of Proposed Rulemaking (NOPR)).

Background

For many, the salient feature of US energy markets over recent years has been the astonishing ability of the unconventional gas industry to produce cheap fuel for power generation that allows new gas-fired plants to out-compete existing coal-fired or nuclear power stations. This new abundance of cheap gas has transformed not just the US, but arguably world energy markets, and along the way it has produced dramatic reductions in US greenhouse gas emissions.

Conventional wisdom recognizes the importance of what are generally thought of as baseload generating plant in markets with increasingly high proportions of (often intermittent) renewable generation, and it has two answers to the question of how to make sure there is enough power when there is a risk that the lights may go out because there is not enough plant on the system that can run regardless of whether the wind is blowing, the sun is shining, or gas supplies have been disrupted as a result of extreme weather events. The first is to let the market function freely and hope that the ability of the most secure generators to supply power in extreme conditions will enable them to charge sufficiently high peak prices (albeit on a very infrequent basis) in the wholesale electricity market to allow them to remain in business. The second is to create a “capacity market” alongside the wholesale power market. The capacity market is then designed so as to ensure that resources that will ensure security of supply are maintained at times when it is threatened, by providing sufficient incentives to sufficiently reliable sources of capacity to remain available to keep the lights on. Rather than just waiting for a chance to charge extremely high prices at a few moments when other generators are unable to satisfy demand, they are paid a regular (but lower) premium for being available “just in case”.

Politicians and politically sensitive regulators, if not free-market purists, tend to prefer the capacity market route, because it helps prevent wholesale prices from rising to what might seem excessive levels, and carries less risk that you will have to wait until the lights have gone out a few times before sufficiently reliable generators will act on the electricity market’s signal that it is worthwhile remaining in the market. As a result, capacity markets have been a feature of the US power industry for a number of years. Although subject to frequent rule-changes, one of their guiding principles, in theory if not always in practice, is to try to maintain a level playing-field between the different potential sources of capacity – which can include not only all forms of generation, but also demand-side response. The NOPR is a radical departure from this technology-neutral approach.

Reliability and resilience

The NOPR follows on from the Department of Energy (DOE) Staff Report to the Secretary on Electricity Markets and Reliability commissioned by Perry earlier this year (downloadable here). One of the conclusions of that report was: “Markets recognize and compensate reliability, and must evolve to continue to compensate reliability, but more work is needed to address resilience.” It drew a distinction between reliability (“the ability of the electric system to supply the aggregate electric power and energy requirements of the electricity customers at all times, taking into account scheduled and reasonably expected unscheduled outages of system components”) and resilience (“the ability to reduce the magnitude and/or duration of disruptive events, [which] depends upon [the ability of infrastructure] to anticipate, absorb, adapt to, and/or rapidly recover from a potentially disruptive event”).

Reliability has sometimes been seen as synonymous with dispatchability – the ability of certain technologies to produce power on demand (as compared to “variable” renewables like wind and solar). Resilience on the other hand has often been seen more in terms of the power system as a whole, and the need to improve the resilience of power transmission and distribution networks in the face of increasingly frequent and more severe extreme weather events has been a major driver of increases in network spending. Whereas some would regard gas-fired, coal-fired and nuclear generation as equally reliable, the report, and the NOPR, shift the focus onto resilience and see that quality in terms of the security of a generator’s fuel supplies. In simple terms, coal-fired and nuclear plants are more likely to carry stocks of fuel than gas-fired plants, which tend not to store reserves of fuel, but rely on pipeline supplies. Interestingly, however, despite the NOPR’s focus on “fuel-secure” plants that can store a 90-day supply of power on-site, such as coal and nuclear, the DOE Staff Report noted that “[m]aintaining onsite fuel resources is one way to improve fuel assurance, but most generation technologies have experienced fuel deliverability challenges in the past.  While coal facilities typically store enough fuel onsite to last for 30 days or more, extreme cold can lead to frozen fuel stockpiles and disruption in train deliveries.”  There appears to be a disconnect between the DOE Staff Report’s conclusions regarding fuel supply challenges for all forms of generation and Secretary Perry’s proposal to promote coal and nuclear plants, specifically, which might lead one to draw the conclusion that the move is more motivated by politics and the negative economic consequences to communities resulting from the loss of the retiring coal and nuclear generators and less by the attributes those resources offer the electric grid.

The proposed rule

The DOE’s proposed rule would require all regional transmission organizations (RTOs) and independent system operators (ISOs) (like MISO) to adopt market rules that would establish a rate applicable to generators able to store a 90-day supply of fuel on-site (i.e. coal and nuclear generators) that ensures that those generators recover their costs and a fair return on equity (the traditional cost-of-service pricing standard in the U.S.).  In short, because coal and nuclear resources have not been able to compete in markets dominated by low-cost natural gas, the DOE is requesting/directing FERC to establish market rules that will pay them more in an attempt to stop the trend of the retirement of coal and nuclear plants.  It is a surprisingly blatant attempt to have FERC, which has traditionally favored technology-neutral market rules, set up rules that subsidize specific technologies in order to prop them up.

New York and Illinois have already started moving toward establishing a credit for nuclear generators as part of their programs to reduce greenhouse gas emissions in their states.  So there may be some support at the state level for nuclear as a cleaner form of power.  States have not been moving toward providing credits or subsidies for coal, however (except, perhaps, for those states whose economies are somewhat reliant on the coal industry), so we would expect to see some significant pushback from state governments as to the subsidy for coal.  Also, to the extent that state programs are creating incentives for renewables to enter the market and FERC is creating incentives for coal and nuclear to stay in the market, ratepayers ultimately end up paying for both, even if both are not needed from an energy standpoint.

If you accept the principle that coal and nuclear need “extra help” beyond what they can obtain from the current capacity market, to support their continued operation, there are of course many different ways that such help could be provided. There are also legitimate policy questions to be considered about the risks that in compensating such generators for the service they can provide in particular circumstances, you end up unnecessarily distorting competition in the wholesale power market as a whole. In short, an alternative approach to the resilience problem would be to continue with efforts to enhance co-ordination between wholesale gas and power markets and the development of gas storage capacity, and to improve interconnection between the US’s different regional power markets.

What next?

In response to the NOPR, FERC staff have put together a list of 30 questions (many of them in several parts) for interested parties to comment on, teasing out both the principles behind the proposal and the potentially tricky details of its implementation (click here for the list). But there is apparently little time for either stakeholders or FERC to ponder all these questions, since the DOE has set forth a very aggressive timeline for this matter.

  • It is directing FERC to take final action in the matter within 60 days, or in the alternative to adopt the DOE’s proposed rule as an Interim Final Rule subject to further change after opportunity for public comment.
  • It states that the comment period will be 45 days or whatever period FERC sets out, if FERC can issue a notice establishing a comment period within 2 business days.
  • The DOE also proposes that any final rule adopted by FERC become effective 30 days after it is issued and would require RTOs to submit a compliance filing proposing their tariff revisions to FERC within 15 days of that date.

This is an extraordinarily accelerated timeline, particularly given the issues at stake and that most RTOs have a lengthy stakeholder process for developing new tariff revisions.  Under the DOEOA, FERC is required to “consider and take final action on any proposal made” by the DOE expeditiously in accordance with reasonable time limits set by the Secretary of Energy.  However, while FERC must act upon the proposal, it has exclusive jurisdiction, and thus complete discretion to accept, reject, or modify the DOE’s proposal.  So FERC could issue an order rejecting the DOE’s proposal but initiating a similar rulemaking effort on a more realistic timeline. FERC issued a notice inviting interested parties to file comments on the DOE proposal by October 23, and reply comments by November 7.

Unsurprisingly, much of the industry is far from happy about all this.  The trade associations have by and large rolled out in opposition to the accelerated timeline.  Within a few days of the NOPR, a joint motion of industry associations was filed proposing a 90 day initial comment period and a 45 day reply comment period by the following industry associations:  The Advanced Energy Economy, American Biogas Council, American Council on Renewable Energy, American Petroleum Institute, American Public Power Association, American Wind Energy Association, Business Council for Sustainable Energy, Electric Power Supply Association, Electricity Consumers Resource Council, Energy Storage Association, Interstate Natural Gas Association of America, National Rural Electric Cooperative Association, Natural Gas Supply Association, and Solar Energy Industries Association. (here)

It is remarkable to see the oil and natural gas associations on the same pleading with the municipal utilities, coops, independent power producers, consumer groups, and renewable energy associations.  Their motion argues that the proposed reforms laid out in the notice of proposed rulemaking would result in one of the most significant changes in decades to the energy industry and would unquestionably have significant ramifications for wholesale markets under FERC’s jurisdiction, and that the time frame allowed is far too short to consider such a significant change.  Answers in support of their motion were also filed by the Transmission Access Policy Study Group, Industrial Energy Consumers of America, National Association of State Utility Consumer Advocates, Northwest & Intermountain Power Producers Coalition, and the American Forest and Paper Association. However, in spite of this unusual amount of industry consensus, FERC has denied the request for an extension of time and is holding fast to its October 23 and November 7 deadlines.

It seems unlikely that FERC will be able to take any substantive action within the time frame set forth by the DOE (unless it rejects the proposal outright).

  • Acting Chairman Chatterjee (Republican) issued a statement in response to the August DOE Staff Report on Electricity Markets and Reliability that FERC would remain focused on the wholesale electric capacity market price formation issues, so there may be some will at FERC to proceed with this rulemaking, but there is likely to be strong state resistance, and as the trade associations point out, it is not going to be an easy matter to figure out how to insert a cost-of-service pricing regime for coal and nuclear resources into otherwise competitive wholesale markets.
  • One of the other Commissioners, Republican Robert Powelson, addressed the issue in a speech he gave this week, reaffirming FERC’s independence from the DOE and promising not to “blow up the markets.” He is quoted as saying “We will not destroy the marketplace.  Markets have worked well and markets need to continue to work well.”
  • The third sitting Commissioner, Democrat Cheryl LaFleur, endorsed Powelson’s comments on Twitter.  FERC staff have indicated that the agency is moving forward with the proposal and will take “appropriate action” within the 60-day timeframe requested by DOE (as noted above “appropriate action” does not necessarily mean “substantive action”).

It remains to be seen whether FERC will seriously entertain the DOE’s proposal, it could very well reject it quickly and go about business as usual, or (more likely) it could open an alternative proceeding to see if capacity and resiliency issues can be addressed through a better vehicle. Secretary Perry has stated that his intent in filing the proposal was to “start a conversation.”  FERC is one of the federal agencies that is typically the least impacted by changing political tides, and we do not expect to see the type of radical change in direction that has been seen in other agencies, such as the DOE, EPA and Interior.  Further, as described above, the commissioners have been telegraphing that they support markets and are unlikely to “blow them up,” but they have generally acknowledged that there have been significant changes in the industry that have put new pressures on the markets that may warrant taking a new look at whether there are attributes that the market is not pricing now that should be priced.  Earlier this year FERC conducted a two-day technical conference on the topic of how FERC’s markets are impacted by state goals (such as increasing reliability and decreasing emissions) and whether FERC markets should remain completely independent of such goals, seek to accommodate them, or seek to accomplish them.  Making predictions in the volatile scene of U.S. politics has become an increasingly dangerous game in recent months, but it seems that the most likely course of action for FERC to take regarding the DOE’s filing will be to wrap it up into the ongoing considerations of the markets and establish a more robust rulemaking to consider whether any and all of the attributes that the DOE and states are seeking to promote should be priced in the markets, most likely through a technology-neutral mechanism.

 

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Trump’s response to Harvey, Irma, Maria and Sandy: more subsidies for coal-fired power

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

Successful procurement challenge against the Nuclear Decommissioning Authority

On 29 July the High Court handed down its judgment in the high-profile Energy Solutions (ES) v Nuclear Decommissioning Authority (NDA) case.  The case concerned the competition to become the “Parent Body Organisation” (PBO) for 12 sites operating “Magnox” nuclear power stations, together with two other sites.  The PBO would become the regulated site licence company responsible for the decontamination and decommissioning of the various sites.

As one would expect, the procurement process involved the evaluation of highly technical submissions and involved very substantial amounts of public money: the total budget for decommissioning work during the initial even years of the contract was £4.211 billion.

ES bid with Bechtel in a consortium named Reactor Site Solutions (RSS) and was unsuccessful.  The contract was awarded to Cavendish Fluor Partnership (CFP) following a bid evaluation which showed a narrow winning margin of 1.06 percentage points in favour of the CFP bid.  ES challenged the outcome of the evaluation, seeking damages from the NDA (Bechtel did not challenge the award process).

ES spent approximately £10 million preparing the tender for the competition and expected to receive approximately £100 million in fees for its role in managing the delivery of the decommissioning work. Although damages are not addressed in the judgment, these figures give a rough idea of the potential value of ES’s claim.

The judgment runs to over 300 pages. In this blog post we can only draw attention to a small number of the interesting points that the case raises.

Legal issues

The key issues the court had to decide can be summarised as being:

  1. If properly evaluated, should the RSS bid have received a different or higher mark than that awarded by the NDA evaluation?
  2. Should CFP have been excluded from the procurement on the grounds of being non-compliant?  If not, and if properly evaluated, should the CFP bid have received a different or lower mark than that awarded by the NDA evaluation?
  3. What was the impact of information that witnesses providing evidence in support of  ES’s claim were offered “win bonuses” to be paid if  the claim was successful?

Scoring of the RSS bid

In considering the first issue, the judge set out some very useful guidance on the standard expected of authorities carrying out evaluations, fleshing out the idea that the courts will intervene where there has been a “manifest error” in the assessment of the bid.

The judgment also gives useful clarification on the role of the debrief documentation in the context of providing reasons. The judgment sets out that the reasons provided in the debrief documentation will be the actual basis for assessment as to whether there has been a manifest error.  The defendant authority will not be able to argue that, for different reasons other than those given as part of the debrief (which may come to light later), the scores were in fact correct.  The test of manifest error will be applied to those reasons given in the debrief documentation.  However, the information which may come to light later may be used by the defendant authority to make arguments relating to “causation” – that is to say, such information may very well be relevant to what the score should have been.  For example if a manifest error is revealed in the debrief documentation, this would amount to a breach of the procurement rules.  However, the defendant authority may well be able to argue that, had the evaluation been carried out properly taking account of factors which weren’t revealed in the debrief document, the score would not be changed and the claimant would not have suffered a loss.

The court also looked at the elements of manifest error. In determining whether there was an error the judge ruled that regard should be had to three factors: (1) the criteria for the award of the score; (2) the reasons; and (3) the score itself.  To avoid being in error, all of the elements need to “agree”.  It is not sufficient that the score determined at the end of the process is correct: there could still be manifest error if the reasoning does not support the final score awarded.  It would then be a question of causation as to whether the breach actually impacted on the outcome of the competition.

The court went on to apply these tests in relation to a large number of ES’s disputed scored responses, and found that there had been manifest errors in the scoring.  In the absence of these errors, ES would have been awarded a higher score.

Scoring the CFP bid

The court then conducted a similar exercise in relation to the CFP bid, and found that it had been scored too generously.  Much of the detail in relation to this aspect of the judgment is set out in a confidential annex, as it concerns commercially sensitive information.

One interesting aspect of the judgment is the hard line the judge takes in relation to the application of the so-called “threshold issues”.  These concerned the scoring of a number of questions which required a bidder to receive a score above a certain level for specific requirements in order to be deemed to have “passed”.  Bids which failed to meet the threshold were required under to be excluded under the tender rules.

The judge considered in what circumstances it may be permissible for an authority to waive a requirement to disqualify a tender which did not reach a threshold.  The conclusion reached offers little scope for flexibility.  He found that the doctrine of “proportionality” would only rarely be of assistance, and (unsurprisingly) did not allow an authority to alter scores in a way which avoided the threshold being breached.  In circumstances where the requirement to act transparently (following the terms set out in the tender documentation) and the requirement to act in a proportional manner come into conflict, transparency has primacy.  The judgment also considers other factors which may be taken into account when determining whether the proper course of action is to exclude a bidder.  The clear guidance provided by the judgment in this area will be useful to awarding authorities, even if the relatively strict approach underlying it may not always be entirely welcomed by them.

Win bonuses for witnesses (!)

ES made a shock revelation just before the judgment was due to be heard.  It had come to light that a number of their witnesses were to be given a bonus in the event that the claim was successful.  In one case the bonus was £100,000 plus 0.5% of any damages awarded.

This payment for the provision of witness evidence contravenes long-standing rules that prohibit such practices.  (On the other hand, recompense for time spent by consultants is permitted “provided the rate is reasonable and represents the witness’s loss of earnings”.)

So how did the judge address this revelation at such a late stage in proceedings?  The answer is “pragmatically”.  Although the defence sought an order that the case be dismissed entirely or reheard, he refused those requests.  Instead he assessed the degree of dishonesty involved in the agreements (deciding that there was none) and determined that it would be wholly disproportionate to grant either of the remedies requested.  For good measure, he also stated that even if the evidence was to be disregarded entirely (which he did not think was necessary) the same outcome would have been reached on the basis of the documentary evidence and the evidence provided by the NDA witnesses.

Concluding comments

This is a highly significant judgment for those involved in public procurement and will be a timely reminder to awarding authorities about the need for providing well-founded reasons for scores in debrief documents.

The astounding detail in the judgment and quality of the reasoning means that the half-life of the precedents set by the judgment may be long (if it survives any possible appeal).  However, given the significance of the damages claimed, and the contentiousness of some of the issues, it is quite possible that the NDA will not let matters rest where they are.  Some indication of their fighting spirit is given by the fact that litigation on a preliminary issue (concerning to the lawfulness of seeking damages but not the prevention of the award of the contract) was, at the point at which the judgment was published, due to be heard in the Supreme Court.

 

 

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Successful procurement challenge against the Nuclear Decommissioning Authority

UK-Iran Trade – A New Chapter

The UK Foreign & Commonwealth Office recently hosted a panel discussion with UK business leaders to clarify UK trade policy on Iran following the lifting of sanctions. The principal points of note for those interested in investing in the country or doing business with Iranian counterparts are as follows:

  • HM Government supports the restoration of trade links with Iran and recognises the commitments already made by Iran to meet the requirements for JCPOA Implementation Day (reached on 16 January 2016).
  • The UK has appointed Norman Lamont as its trade envoy for Iran.
  • UK Trade & Investment now have a representative based in Tehran to support UK companies doing business in Iran and have recently updated their guidance.
  • UK Export Finance has reintroduced cover for UK companies exporting to Iran. Cover will be made available on a case-by-case basis and UKEF are liaising with the Export Guarantee Fund of Iran.
  • UK Export Control aims to issue clear and accurate advice to UK businesses seeking to invest in Iran, providing guidance as to activities that are permitted, prohibited or subject to licence.
  • The FCO continues to take steps to upgrade the services provided by the UK Embassy in Tehran and hopes reciprocal measures will be taken by the Foreign Ministry in Tehran.
  • HM Government recognises that the continuing US Primary Sanctions (prohibiting US persons/companies from engaging in business with Iran) are seen to be problematic for many UK entities, especially banks, who fear financial penalties. The Government is encouraging OFAC to be as clear as possible in their guidance on Iran. UK investors may seek to explore what financing channels may be available to ring-fenced UK entities, perhaps more readily available from Asian financial institutions.

Despite the generally positive tone, UK businesses must be wary of political involvement in key industrial sectors as well as in major projects. Any investors should be aware that the legal and administrative environment in Iran often lacks clarity. Due diligence must be conducted on counterparts in Iran (given that a number of individuals and companies remain designated (sanctioned) entities. HM Government believes this, and any reputational risk, is navigable in most sectors, and is available to give guidance.

If you would like to discuss any of the issues raised above, please do not hesitate to get in touch with the author or any of your other regular contacts in the Dentons oil and gas team.

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UK-Iran Trade – A New Chapter

State aid for Hinkley Point C (3): What hope for “no aid” arguments?

This post is the third in a series on the European Commission’s initial assessment of the package of measures by which the UK Government proposes to provide financial support for the proposed new nuclear generating station at Hinkley Point (HPC) by NNB Generation Company Limited (NNBG).  In this post we focus on the Commission’s analysis of the UK Government’s arguments that its support for HPC does not constitute state aid within the meaning of Article 107(1) of the Treaty on the Functioning of the European Union and that HPC would be performing a service of general economic interest (SGEI), effectively meaning that it fell outside the state aid rules (for a summary of the overall framework of the Commission’s appraisal, click here).

As noted in the previous post, any “no aid” decision, or categorisation of the HPC as an SGEI, effectively turns on the application of the so-called Altmark criteria.  The quality of the Commission’s arguments in this strategically important area is variable. 

The Commission begins by making the point that it sees a service of general economic interest (SGEI), such as the Government claims would be provided by NNBG, as a service which an undertaking would not supply if it were considering its own commercial interest, and which serves a general economic interest.  In the context of HPC, the Commission’s starting point is that NNBG’s service would be to supply (baseload) electricity; yet that, the Commission says, is “normally considered a commercial activity and a market in which competition takes place”.  It suggests that nuclear generation is no exception to this principle, noting the “nuclear plants which are operated commercially” in the UK by NNBG’s parent EDF, and the “UK’s own assessment” that “private investors [would]…invest in nuclear energy in the UK by 2030 at the latest.  Finally, if the service which would not be provided without aid is the construction of HPC by an earlier date than the private sector would otherwise build new nuclear capacity, the Commission suggests that the UK has not made a convincing case for such early construction being in the general economic interest on security of supply or decarbonisation grounds.  

Almost every assertion that the Commission makes in the two pages or so which it takes to reach these provisional conclusions on “the existence of a SGEI” is questionable in terms of its accuracy or its relevance.  Electricity generation is indeed a commercial activity.  That does not mean that the construction of a new nuclear reactor is a service that will be provided without state aid.  Nor does the existence of the UK’s legacy nuclear fleet help the Commission’s case, constructed as it was by the CEGB in the days of nationalisation.  The Commission’s dismissal of security of supply and decarbonisation as interests served by the putative service of constructing and operating HPC is similarly one-sided.  For example, it effectively denies that there is any benefit in securing decarbonisation sooner if you think the market will decarbonise a few years later, and it ignores the effects on both security of supply and decarbonisation in both the longer and the shorter term which assurance about the viability of HPC (in the form of state aid clearance) could have.

The first Altmark criterion (which is also key to any attempt to justify a measure under Article 106(2)) is that the beneficiary be entrusted with a public service obligation (PSO).   The Commission argues that provisions of the CfD which limit the return which NNBG can make on its investment in HPC or penalise it for late delivery of the project are not capable of being PSOs.  The best claim that the CfD has to being regarded as placing NNBG under an obligation is that if it does not build HPC (or delivers it late), it will receive no money (or less money) under the CfD.  The Commission appears to be suggesting that in order to be a PSO, an obligation (e.g. to commission HPC by a certain date) has to be “enforceable” by some means other than the payment or non-payment of aid.  If the Commission is right about this, it may have implications for the design of the CfD contract terms more generally.  However, the Commission only engages very briefly with the case of Fred Olsen, which appears to offer some support to the UK Government’s view.  In that case, which concerned ferry services, the Court of First Instance remarked that the fact that an operator “unilaterally abandoned or altered the conditions for the operation of some maritime routes indicates at most” that it “failed to honour some of the obligations imposed on it by the provisional arrangements”, and seems to have found that not even the fact that an operator was subsidised at its own request prevented it from satisfying the first criterion.   

Looking beyond the particular circumstances of HPC, what the Commission seems to be saying here could have implications for the financing of other CfD-subsidised schemes.  If the Altmark criteria do truly require the state to have the means of enforcing compliance with requirements, such as the construction of HPC, that go beyond the stimulus provided by the absence of CfD revenues if no electricity is generated, it may not be possible to construct bankable CfDs which satisfy those criteria.  Elsewhere, in the analysis of Article 106(2) arguments, the Commission suggests that the absence of a true PSO is what excuses the UK from having to comply with the public procurement rules in respect of letting a CfD in respect of HPC, and that, conversely, if the requirements imposed on NNBG could be shown to constitute a PSO, the UK Government would have failed in its alleged obligation to follow the public procurement rules.

The Commission broadly accepts that the second Altmark criterion is satisfied – i.e. that the parameters on the basis of which the compensation is calculated are established in advance in an objective and transparent manner.  However, when it comes to the third criterion, that the compensation cannot exceed what is necessary to cover the costs incurred in the discharge of the PSO, its assessment is much less favourable.  Moreover, some of the arguments which emerge here also read across into the Article 106(2) and Article 107(3) analysis.

The Commission is concerned, firstly, that the Government does not appear to have a firm view of what the costs of discharging the PSO are (making the level of compensation by definition hard to assess); secondly, that the level of profit that NNBG can expect to earn over the lifetime of the CfD was negotiated with NNBG rather than being “established by reference to the rate of return on capital that would be required by a typical undertaking considering whether or not to provide the alleged SGEI”; and thirdly, that because the 35 year lifetime of the CfD is shorter than the 60 year lifetime of HPC, NNBG could earn super-normal profits in years 36 to 60. 

It is hard to comment on the first two of these points as far as HPC is concerned without access to the UK’s submissions to the Commission, although in response to the second one might ask: what is a “typical undertaking” considering whether or not to build HPC, let alone (as the Commission goes on to elaborate) “the average cost structure of efficient and comparable undertakings in the sector under consideration” – none of which have been built under exactly the same regulatory regimes as HPC would be built and operate under?  Moreover, for much of the period during which the Government was negotiating with NNBG, it was simply the only undertaking willing to contemplate any form of investment in new nuclear build in the UK.  On the other hand, prospective recipients of aid under enduring CfD regime for renewables in mind regime may take some comfort in this context from the fact that their strike prices will not be the result of bilateral negotiations. 

But the Commission’s point about the duration of the comparative lifetimes of the CfD and the generating station is something on which we can comment in the HPC context.  The strike price, we are told, has been set at a level which is designed to ensure that NNBG covers the costs of construction and operation and makes a return of 9.87% on the project as a whole over its lifetime (in post-tax, nominal terms).  Yet, as the Commission points out, once the CfD expires, the profitability of the plant is uncertain because the level of revenue accruing to the operator from the sale of electricity is no longer controlled by the strike price mechanism.  This makes it harder for the Commission to rule out the possibility of overcompensation during the post-CfD period of the plant’s operation.  The Commission suggests two ways of dealing with this problem: making the CfD coterminous with the life of the plant, or providing some means for the state to recover any overcompensation within the CfD itself (effectively a gain-share provision for the period when the strike price mechanism no longer applies).  One problem with the first of these, if taken in isolation, is that it is not possible to predict the lifetime of a plant with certainty when the strike price is initially calculated.  

In principle, it would seem that this arguments is not unique to the case of HPC and could be applied to the wider CfD regime.  The differences are that the periods of time involved – both CfD durations and plant lifetimes – are shorter for non-nuclear projects, so that the calculations are less dependent on very long range predictions of electricity prices; and that there is more comparative data on which to assess technology costs.  Whether the Commission will consider these differences to be sufficient for it to take a more favourable view of this aspect of the wider CfD regime than it has so far in the case of the HPC package remains to be seen.  In this context it is curious that the Commission states that “nuclear production, which requires very high levels of capital for the investment in the construction and hence before revenues can be generated, while also being characterised by a relatively low level of operating costs once the plant has been built, has few, if any, equivalents in commercial activities”: the CfD regime as a whole is surely predicated on the assumption that all the technologies it covers (renewable, nuclear, CCS) have in this sense a similar cost profile.

The fourth Altmark criterion is that where the undertaking which is to discharge a PSO is not chosen through a public procurement process, the level of compensation must be determined on the basis of an analysis of the costs which a typical, well run, undertaking would have incurred.  Here again, the problem is in finding the appropriate comparator.  Unsurprisingly, the Government has commissioned a review of NNBG’s cost estimates to determine whether they are “reasonable”.  The Commission says that this is not what the Altmark criterion requires.

The final sections of the Commission’s analysis of the UK’s “no aid” arguments deal with the credit guarantee and the proposal to compensate NNBG in the event of a “political shutdown” of HPC.  On the credit guarantee, the Commission essentially reserves judgment owing to the lack of detail available.  However,  it does lay down a marker when it observes that the guarantee “seems to differ from ordinary debt guarantees in that it would be drawn before equity, apart from equity already spent…It would therefore appear that [it] might diminish the risks borne by equity holders”.  The Commission appears prepared at this stage to accept the UK’s argument that political shutdown proposals do not constitute state aid, subject to the provision of more information “on whether this compensation…would also be available to other market operators placed in a similar situation”.  This is intriguing.  It is presumably possible that the UK Government would be prepared to offer a similar deal on political shutdown to another nuclear operator, but such a deal is clearly not on the table for operators of renewable technologies, for example, and whilst a political shutdown of UK wind farms may be a more remote possibility than something like the German reaction to Fukushima, will that point be sufficient to satisfy the Commission that the enduring regime for renewables should not in this respect be “levelled up”, to confer on its beneficiaries the additional protection offered to NNBG?

It is clear that the Commission is highly reluctant to reach a finding that there is “no aid” in the HPC package, or to find that there is an SGEI within the meaning of Article 106(2).  It does not want to treat nuclear power as a special case.  Yet unless it is prepared to recognise that nuclear power is not just another source of baseload electricity, how could the Commission find that there is no aid (or that there is a SGEI) in a CfD negotiated directly between a Government and the beneficiary undertaking which includes a generous strike price, a 35 year term and investor protection in the event of political shutdown – and still realise its ambition of cutting back on subsidies for renewables? 

To go by the evidence of the Commission’s initial assessment, the Government would – rightly or wrongly – have to do a lot more work both in terms of scheme design (including changing some features of the currently proposed CfD arrangements) and in terms of arguing its corner with the Commission if it is to persuade the Commission that there is “no aid” to NNBG.  It is possible that the Court of Justice might be more sympathetic to the Government on some of these points, but EU litigation would not help the timeliness of the delivery of EMR objectives.

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State aid for Hinkley Point C (3): What hope for “no aid” arguments?

State aid for Hinkley Point C (2): Outline of the Commission’s analysis

This is the second in a series of posts on the European Commission’s initial assessment of the package of measures by which the UK Government proposes to provide financial support for the proposed new nuclear generating station at Hinkley Point (HPC): click here for the first in the series.  The text of Commission’s letter is now also available in the Official Journal of the European Union: interested parties have one month from the date of its publication (7 March 2014) to comment.   

In this post we summarise the Commission’s analysis of the HPC support package.  This consists chiefly of a proposed Contract for Difference (CfD) and a credit guarantee conferred by participation in HM Treasury’s UK Guarantees Scheme: both are conveniently summarised in the opening paragraphs of the Official Journal notice.

Introduction: the state aid rules

It is worth beginning by reminding ourselves of the key EU Treaty provisions on state aid.  Article 107 of the Treaty on the Functioning of the European Union (TFEU) states:

1. Save as otherwise provided in the Treaties, any aid granted by a Member State or through State resources in any form whatsoever which distorts or threatens to distort competition by favouring certain undertakings or the production of certain goods shall, in so far as it affects trade between Member States, be incompatible with the internal market.

Article 107(2) then lists certain types of aid which fall within Article 107(1) but which “shall” be considered compatible with the internal market.  These relate to aid having a social character or relating to natural disasters, economic crises or German unification and can therefore be disregarded for present purposes.  Article 107(3) contains a further list of types of aid which “may” be considered compatible with the internal market.  Article 108(2) and (3) TFEU state:

2. If, after giving notice to the parties concerned to submit their comments, the Commission finds that aid granted by a State or through State resources is not compatible with the internal market having regard to Article 107, or that such aid is being misused, it shall decide that the State concerned shall abolish or alter such aid within a period of time to be determined by the Commission.

If the State concerned does not comply with this decision within the prescribed time, the Commission or any other interested State may, in derogation from the provisions of Articles 258 and 259, refer the matter to the Court of Justice of the European Union direct…

3. The Commission shall be informed, in sufficient time to enable it to submit its comments, of any plans to grant or alter aid. If it considers that any such plan is not compatible with the internal market having regard to Article 107, it shall without delay initiate the procedure provided for in paragraph 2. The Member State concerned shall not put its proposed measures into effect until this procedure has resulted in a final decision.

Secondary legislation has established an administrative framework for dealing with state aid cases (for further detail, click here).  Measures that are put into effect without having been notified and approved under Article 108(3) are “unlawful aid”.  If the Commission finds unlawful aid is incompatible with the internal market, it may require Member States to recover it from the beneficiaries.

To gain the Commission’s approval for the HPC package, the UK Government must therefore persuade the Commission either that its support for HPC does not constitute state aid within the meaning of Article 107(1), or that such support is compatible with the internal market.  The Government has identified three possible ways to avoid a finding of incompatibility, as set out below.

The “no aid” arguments

Any claim that a measure does not constitute state aid depends on showing that one of the elements of aid set out in Article 107(1) – state origin of the aid, conferral of a “selective advantage”, impacts on intra-EU trade and competition – is not present.  We take each of these in turn below as they have been applied to the HPC support package.

  • Apparently, the UK authorities “do not contest” that the CfD is financed from resources under the control of the state.  The Commission points out that the CfD will be administered by a Counterparty body essentially controlled, and potentially underwritten, by the Secretary of State.
  • As regards distortion of competition and an effect on intra-EU trade, the Commission observes: “As in this case the notified measures will enable the development of a large level of capacity which might otherwise have been the object of private investment by other market operators using alternative technologies from either the UK or other Member States, the notified measures can affect trade between Member States and distort competition.”.
  • That leaves as the key battleground the question of whether the support package confers a “selective advantage” on HPC.  Would HPC be getting a deal that will give it an advantage in the market and that is not open to its competitors?  In order to show that this element of the definition of aid is made out, the Commission has to engage with the criteria laid down by the Court of Justice in the case of Altmark.  In that case, the Court found that in certain circumstances compensation provided to undertakings entrusted with a public service function would not constitute state aid.  The Commission considers the Altmark criteria (discussed in the Commission’s 2012 Communication on compensation for the provision of services of general economic interest (SGEI)) in some detail.  Overall, the Commission finds it hard to see that HPC would be entrusted with the kind of public service obligation (PSO) that the Altmark criteria envisage.  It also inclines to the view that the compensation which HPC stands to receive under the CfD would be more than the Altmark criteria permit. 

The “aid is compatible” arguments

The Government argues that if the HPC package is considered to be state aid, its contribution to the common EU objectives of decarbonisation, security of supply and diversity of electricity generation, and addressing related market failures, outweighs its negative impact on the internal market.  The Commission is not persuaded by these arguments in favour of a finding of compatibility under Article 107(3).  For example, it is sceptical of claims about decarbonisation on the basis that support for HPC could crowd out investment in other low carbon technologies; and it queries claims about security of supply on the grounds that the most immediate concerns about the adequacy of the UK’s electricity generation capacity relate to the current decade, not the 2020s when HPC would be commissioned.

But the Commission’s scepticism about the objectives of the HPC support package is only the beginning of its concerns from an Article 107(3) point of view.  Even if it were prepared to accept that the HPC package is aligned with one of the “common EU objectives”, the Commission queries whether state aid – in the combined form of the proposed CfD and credit guarantee – is needed to enable HPC to achieve these objectives.  Overall, the Commission suspects that the level of protection from ordinary market risks which the support package provides is excessive: more or less every aspect of the package, from the duration of the CfD to the way in which it has been negotiated, is viewed in sceptical terms, so that the Commission concludes by saying that it doubts “whether it effectively addresses a market failure”; questions “whether [it] can be deemed…to be proportionate”; and is “concerned about its distortive effects on competition”.

A “service of general economic interest”?

In between the “no aid” and “compatible aid” limbs of its case, the Government argues that the HPC package with the internal market, fulfils the conditions of the Framework which the Commission has put in place for determining whether larger SGEI schemes fall within Article 106(2) TFEU.   Article 106(2) states:

2. Undertakings entrusted with the operation of services of general economic interest or having the character of a revenue-producing monopoly shall be subject to the rules contained in the Treaties, in particular to the rules on competition, in so far as the application of such rules does not obstruct the performance, in law or in fact, of the particular tasks assigned to them. The development of trade must not be affected to such an extent as would be contrary to the interests of the Union.

Article 106(2) is in some ways the ultimate derogation provision.  It says, in effect, that certain undertakings will be exempt from the requirements of EU competition and state aid law if the application of that law would “obstruct the performance” of a service of general economic interest entrusted to a particular undertaking.  The meaning of Article 106(2) has therefore been the subject of many arguments between the Commission and Member States.

The Commission has, for example, argued that Article 106(2) “authorizes measures contrary to the Treaty only to the extent to which they are necessary to enable the undertaking concerned to perform its task of general economic interest under acceptable economic conditions and, therefore, only if they are necessary for the financial equilibrium of the undertaking itself”.  But the Court of Justice, whilst acknowledging that Article 106(2), like all derogations, must be interpreted strictly, has found that it “seeks to reconcile the Member States’ interest in using certain undertakings, in particular in the public sector, as an instrument of economic or fiscal policy with the Community’s interest in ensuring compliance with the rules on competition and the preservation of the unity of the common market”.  Moreover, Member States “cannot be precluded, when defining the services of general economic interest which they entrust to certain undertakings, from taking account of objectives pertaining to their national policy or from endeavouring to attain them by means of obligations and constraints which they impose on such undertakings”.  As a result, “for the Treaty rules not to be applicable to an undertaking entrusted with a service of general economic interest under Article 90(2) of the Treaty, it is sufficient that the application of those rules obstruct the performance, in law or in fact, of the special obligations incumbent upon that undertaking. It is not necessary that the survival of the undertaking itself be threatened”.  (See Case C-157/94, Commission v Netherlands.)

                                                   

                                                A service of general economic interest

The Commission’s analysis in response to the UK’s SGEI arguments overlaps to a large extent with what it says in relation to the Altmark criteria and/or the Government’s Article 107(3) arguments.  It concludes that the Commission doubts whether the HPC package qualifies as an SGEI within the meaning of Article 106(2) and the Framework, and that even if it did so qualify the Commission doubts that it would comply with the Framework.

Overall characteristics of the Commission’s analysis

In future posts we will examine some of the Commission’s arguments in more detail.  For now, it is worth noting some more general features of the Commission’s appraisal.

  • There is a degree of unevenness about the Commission’s analysis.  It makes some extremely good points and some decidedly weak ones. 
  • There are a number of points when the Commission appears to help the UK by indicating possible ways of correcting what it sees as deficiencies in the HPC package in state aid terms.  Whether these potential “escape routes” are in practice open to the UK Government is another matter.
  • The Commission – intentionally or otherwise – draws attention to a number of places where the HPC package is different from the rest of the CfD regime (or at least the enduring regime for renewables).  Sometimes this is to the latter’s advantage, but not always.  In an ideal world, the whole of the CfD regime would have been worked out in full before being notified together, but it so happens that the first part of the regime that the Commission examines in detail is not entirely typical or representative of the regime as a whole.
  • Inevitably, much of the analysis is somewhat tentative, because details of almost all parts of the package still remain to be fully worked out.

Behind everything lurks the question: how much (or how little) freedom do the EU state aid rules allow Member States to have as regards ensuring that a certain proportion of their electricity generating capacity belongs to a specified technology type? 

 

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State aid for Hinkley Point C (2): Outline of the Commission’s analysis

State aid for Hinkley Point C (1): the context of the Commission’s letter of 18 December 2013

On 18 December 2013, the European Commission announced that it was opening an in-depth state aid investigation into the Government’s package of financial support for the proposed Hinkley Point C (HPC) new nuclear generating station.  On 31 January 2014 the Commission published a version of the letter setting out its reasons for launching a detailed investigation and the points on which it requires to be persuaded of before giving state aid clearance to the package.

What does the letter tell us?  It is a fairly closely-argued 67 pages, so it will take more than one post to cover it.  Today, we begin by setting the scene. 

The potential of HPC – an image from gov.uk

The critical tone of parts of the Commission’s analysis has been noted in a number of reports, but this is perhaps not the most surprising feature of the letter if one considers its context.

  • The package of support for HPC inevitably treats new nuclear as to some extent a “special case”.  State aid policy is administered on the principle that free markets are best and that claims that a particular industry is somehow “special” are to be treated with scepticism – even if that industry is one in which there is already massive state intervention in various forms. 
  • The European Commission’s decision-making on state aid cases has sometimes been criticised for being too politically expedient.  Here we have a case where the UK Government has invested huge political capital and the aid is going to a subsidiary of a company 84% owned by the French state.  Even if the Commission is ultimately minded to approve the HPC support package it cannot afford to be seen to have given it anything less than an economically rigorous evaluation.
  • In 2007, the Commission ruled on alleged state aid for the Olkiluoto 3 nuclear plant, to be built in Finland with French technology.  The issue was whether a guarantee given by the French state gave Areva an unfair competitive advantage over other potential suppliers.  The guarantee was found to have been given on market terms, so that there was no aid under the state aid rules.  However, the proceedings still lasted three years and the Commission went through an in-depth investigation before reaching a final decision. 
  • In 2006, the Commission approved the arrangements for setting up the Nuclear Decommissioning Authority (NDA).  Although the Commission acknowledged that the purposes behind the creation of the NDA were fully in line with the objectives of the Euratom Treaty, it was also very concerned about potential distortions of competition arising from it.  For example, notably tight controls were set on the pricing of electricity sold by the UK’s Magnox nuclear plants, to be run by the NDA, for the few remaining years of their life.
  • Most recently, the Commission decided that aid granted by Slovakia in relation to nuclear decommissioning was compatible with the state aid rules.  In doing so, the Commission emphasised that the aid related to plants that had already been shut down; that it did not subsidize current electricity production; and that it was “strictly limited to what is necessary to cover the costs of decommissioning historic nuclear facilities, for which no adequate provisions were created in the times of a centrally-planned economy”.  Moreover, the Slovak scheme was unlike “the numerous schemes of compensation for stranded costs, public service obligations and support schemes for renewable electricity, where the Commission has found that the financing of the support scheme through a levy has a protective effect of national electricity production”.
  • The HPC support package is the kind of arrangement that is intrinsically harder for the Commission to get itself comfortable with than the Okiluoto or NDA measures.  It explicitly and intentionally provides, under the Contract for Difference (CfD) mechanism, a guaranteed level of price for electricity and therefore a degree of revenue security which the market would not provide.  It can therefore be characterised as “operating aid” (as opposed to “investment aid”), which the state aid regime regards as particularly problematic – since it shields operating businesses from normal market risks.
  • Although there is an entire EU Treaty devoted to the promotion of nuclear power, it is politically controversial within the EU, and there are those who will take any opportunity to put the case, whether in administrative or judicial proceedings, against the adoption or approval of any measure that brings a “nuclear renaissance” in the EU closer.
  • There are undoubtedly some features of the support package for HPC which, at least at first sight and taken in isolation, appear very generous.
  • The Commission is in the process of “modernising” the state aid framework and has just published draft Guidelines on environmental and energy aid.  The Guidelines do not cover nuclear projects, but take a notably tough line on e.g. support for renewables, even though the deployment of renewables is mandated by EU law in a way that nuclear power is not.  Anything other than a searching approach to scrutiny of the HPC package would be out of keeping with the general thrust of current Commission policy in this area.
  • Whatever the ultimate outcome of the Commission’s evaluation of the HPC support package, the final decision can only be robust against potential challenge if it has clearly stated the potential objections to what the UK Government is proposing.

The UK public may have been encouraged to think that the hard part of HPC was over once development consent, a nuclear site licence, marine licence and other environmental permits were granted, and agreement on the strike price had been reached.  But obtaining state aid clearance in this case was always going to be a challenge.  And for all sorts of reasons, it is not surprising if at this stage the Commission has stated the “case for the prosecution” in clear and strongly worded terms.  In future posts, we will examine some of the Commission’s arguments a little more closely, consider the possible outcomes of the Commission’s investigation into the HPC support package, and look at what the Commission’s letter indicates about the prospects for state aid clearance of the rest of the Electricity Market Reform (EMR) package.

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State aid for Hinkley Point C (1): the context of the Commission’s letter of 18 December 2013