Global Energy Blog 

Recently I attended the 3rd Annual Global Arbitration Review (GAR) Live Energy Disputes conference in London.  A stimulating day of discussion about developments in the international energy business closed with a vigorous debate on the following motion: “This house believes that there’s no law in gas pricing arbitration”.

Those supporting the motion focused on the complex commercial and economic exercise arbitrators in a gas pricing dispute must tackle.  In essence, they contended the arbitrators, by reference to current market conditions, try to update the parties’ commercial deal by copying the economic exercise those parties undertook when they agreed their long-term SPA.  In short, arbitrators decide what the parties should have agreed given the current facts.

Those arguing against the motion forcefully reminded the conference that gas and LNG price reviews take place within the legal structure set out in the SPA.  So, interpretation of the scope of the relevant price review clause remains at the heart of the dispute.  Further, any award the arbitrators make in the first price review under the SPA will inevitably impact later reviews under that contract, i.e. applying the law of issue estoppel is often central to pricing disputes.  So, a price review is not just a commercial and economic exercise.

I have some sympathy for both sides’ opinions.  However, while respecting the central role economic arguments play, it is going too far to say there is no law in gas pricing arbitration.

My experience of gas pricing disputes is that most of both sides’ cases focuses on the economic evidence with the independent experts take opposing views on several topics. For example, the state of the relevant market(s) at particular times, what are the competing fuels and, critically, the most apt data and methods for calculating a new price.  As a result the economic issues can dominate the arbitration.  One point of view is that price reviews are intended simply to re-run the economics underlying the parties’ original deal to update the price to reflect current market conditions.

However, most of the audience at the GAR conference did not accept this limited view of gas pricing arbitrations.  Although economic arguments may dictate the arbitration and final hearing, the parties must always present those arguments through the prism of the law.  All the price review arbitrations I have worked on raised difficult questions about interpreting the price review clause.  In my most recent price review, submissions expressly dealt with applying the English Supreme Court’s recent decision in Arnold v Britton to the clause.  I accept the economic evidence may colour how a party chooses to advance its case on the meaning of the price review clause.  Nonetheless, the experts must present their evidence given the instructions they receive upon the exercise the price review clause requires.  Further, ultimately, the tribunal must apply their understanding of the expert evidence to the objective criteria in the clause to decide whether (and, if so, how) the price should change.  Deciding how the price clause is to be interpreted and whether, in the light of two different experts’ opinions, the test it sets is met, are inherently legal exercises.  That is why parties send price reviews to arbitration, not expert determination.  It is also why parties choose lawyers as arbitrators rather than economists, although hopefully lawyers who can understand complex economic evidence.

Finally, it was notable that the moot arbitrators at the GAR conference mentioned issue estoppel as a key reason they could not accept the motion.  Those of us who have worked on second (and later) price reviews will know how important this area of law can be.  The award on a first price review will reverberate through the remaining term of the SPA.  In particular, the tribunal’s interpretation of the price review clause will often bind future tribunals considering price reviews under that SPA.  The second edition of GAR’s Guide to Energy Arbitrations recognises the central role issue estoppel plays in price reviews.  It includes a new chapter that Liz Tout and I have written tackling this subject.  So, perhaps next year, the motion considered at the GAR conference should be: “This house believes contractual interpretation and issue estoppel lie at the heart of disputes under long-term energy contracts”.

Following recent discoveries of significant oil and gas reserves in regions with no or limited existing upstream oil and gas activities, many countries have reorganised, or are in the process of reorganising, their oil and gas regulatory regime in preparation for a ramp up in activity – from Cyprus in the East Mediterranean to Kenya, Tanzania and Mozambique in East Africa.

Part of this process of regulatory reform is likely to include a ‘new’ national oil company (“NOC” –  an oil company fully, or majority, owned by a national government) – either a newly established NOC or an existing NOC with greatly expanded roles and responsibilities. In light of this, here are 5 key things for governments and new NOCs to think about.

State participation

Before considering the role of the NOC, the objectives of state participation in oil and gas assets must be clearly identified. These fall under two broad headings:

• commercial and fiscal objectives, where the aim of the state is to maximise the Government ‘take’, i.e. revenues (almost always either through a production sharing regime or a tax and royalty regime); and
• other predominantly non-commercial objectives, which can be both symbolic, i.e. the exercise of state control over the disposal of the hydrocarbon resource, and more practical, e.g. the development of local skills and expertise and the promotion of local content in upstream operations.

The approach taken in relation to state participation will significantly influence the roles and responsibilities given to the NOC.

Role of the NOC

The government will need to determine the role it expects the NOC to play in the upstream sector. For example:

• will the NOC take an interest in all upstream licences / production sharing contracts (“PSCs”)? If so, on what basis (as operator, or as a minority equity investor)?
• will the NOC be responsible for managing interactions with international oil companies (“IOCs”) on behalf of the government (e.g. evaluating applications for licences / PSCs)?
• will the NOC act as regulator in respect of the upstream oil and gas sector, or will there be a separate, arm’s length regulator?
• will the NOC own any infrastructure (e.g. offshore and onshore pipelines that fall outside the licence / PSC area)?
• what reporting obligations will the NOC have to the government?
• will the NOC be responsible for marketing the government’s share of production?
• will the NOC be able to pursue investment opportunities overseas?

In particular, whether the NOC has a minority investor role or an operator role will have a significant impact on the requirements of the NOC in relation to staffing and financing. As a minority investor the NOC’s interests tend to converge with those of the state (i.e. to encourage its partner to actively explore, while ensuring costs are controlled and a high standard of operations is maintained), whereas as an operator, the NOC will be required to have the capability to propose a development plan, raise money and manage a large project.

In addition, political and legal clarity regarding the NOC’s mandate, its source of financing, the activities it can undertake and the revenues it can generate is essential. In many cases it may be advisable for these to be set out in primary legislation, to promote certainty for investors.

Financing

Governments need to ensure that their strategy for state participation in the upstream sector is affordable. This is a particular consideration with new or young NOCs – sources of finance will be limited at the outset because there are little, or no, upstream revenues from production until commercial discoveries are made and developed. The NOC will therefore rely on government funding, including emergency borrowing in times of trouble (e.g. low oil price scenarios).

NOCs need clear revenue streams to meet day-to-day running costs and investment requirements as well as the ability to raise finance, with access to the capital and debt markets. Revenue streams for the NOC are often varied and unreliable. In addition, securing finance at the pre-discovery stage can be difficult. Even if the NOC is carried for its costs by IOCs pre-production, it will still need funding for staffing etc.

Governance

Good governance, transparency and accountability are extremely important. The government must ensure that the NOC has accountability to the state for its performance and its funding by monitoring the NOC’s costs, processes and performances through accounting and financial disclosure and risk management.

Staffing and training

NOCs need the appropriate level of staffing. As well as technical employees, secondary commercial roles as a minority investor may include managing service providers. If the NOC is operator it will also need accountants, marketers, economists and other administrative staff.

Staff will need appropriate skills and training. If, for example, the NOC is required to take on a greater role in the upstream sector, the NOC may not currently have the appropriate level of staff, in terms of numbers and capability. Training and capacity-building is very expensive, especially without proven reserves, so if this is necessary it needs to be taken into account at an early stage.

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 Barn^TM. 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.

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

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

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

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

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

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

Results skew significantly to the lower bands

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

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

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

Gap between policies and performance

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

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

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

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

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

Conclusion

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

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

1. Summary

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

2. Auction support scheme

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

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

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

Source: data from President of the ERO. The data concerning the capacity from the auction in 2017 presents only the estimation of the Ministry of Energy.

3. Split of auctions and auction baskets in the auctions system

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

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

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

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

4. Budget allocations for 2017

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

Table no. 1 Budgets of auctions in 2017

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

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

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

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

5. Reference prices

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

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

Table no. 2 Reference price for certain installations in 2017

6. Possible auction dates

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

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

7. The effect of winning an auction and support period

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

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

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

8. Auctions in particular baskets

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

a. Basket of high-efficiency installations

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

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

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

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

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

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

b. Basket of WTE installations

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

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

c. Basket of low-emission installations

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

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

d. Basket of biogas installations

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

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

e. Basket of other installations

In this basket two auctions for new installations are provided.

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

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

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

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

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

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

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

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

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

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

1. There are RES installations which started production of renewable energy before 1 July 2016 (existing installations) and after 1 July 2016 (new installations);

2. There are installations with capacity of up to 1 MW (small installations) and those with capacity of more than 1 MW (large installations).

3. From 1 January 2018, only RES installations with a capacity less than 500 kW and agricultural biogas installations will be able to benefit from mandatory purchase of electricity.

4. Taking into account that currently known connection conditions for off-shore installations book capacity around the 1000 MW threshold, exceeding many times the assumed budget of auctions, we treat participation of investors based on this technology as purely hypothetical.

Oil Sands / Unconventional

• March 29, 2017 – Cenovus Energy Inc. (“Cenovus”) agreed to acquire ConocoPhillips’s 50% interest in the FCCL Partnership, which is the companies’ jointly owned oilsands venture operated by Cenovus. Cenovus is also purchasing the majority of ConocoPhillips’s Deep Basin conventional assets in Alberta and British Columbia. These assets have a combined 2017 forecast production of approximately 298,000 boe per day. Total consideration for the purchase is $17.7 billion, including $14.1 billion in cash and 208 million Cenovus common shares.
• March 9, 2017 – Canadian Natural Resources Limited (“CNRL”) announced an agreement, subject to regulatory approvals, to acquire 70% of the Athabasca Oil Sands Project including 70% of the Scotford upgrader, as well as additional working interests in other producing and non-producing oilsands leases. CNRL has agreed with Shell Canada Limited and certain subsidiaries to acquire its 60% working interest in the Athabasca Oil Sands Project. CNRL and Shell have also agreed with Marathon Oil Corporation to jointly acquire its 20% share in Athabasca Oil Sands Project and related oilsands investments.

Conventional

• March 24, 2017 – Total Energy Services Inc. (“Total Energy”) acquired a majority of the outstanding common shares of Savanna Energy Services Corp. (“Savanna”). Western Energy Services Corp. stated that Total Energy has taken up 51.6 % of the shares of Savanna under its hostile take-over bid.
• March 24, 2017 – Pengrowth Energy Corporation entered into an agreement for the sale of its non-producing Montney lands at Bernadet in northeast British Columbia for cash consideration of $92 million. The Bernadet asset encompasses 36.6 sections (100% working interest) of land with no associated production.
• March 22, 2017 – Trican Well Service Ltd. (“Trican”) and Canyon Services Group Inc. (“Canyon”) have entered into an arrangement agreement pursuant to which Trican has agreed to acquire all of the issued and outstanding common shares of Canyon on the basis of 1.70 common shares of Trican for each outstanding Canyon share. The consideration to be received by Canyon shareholders reflects a value of $6.63 per Canyon share based on the closing price of Trican shares on the Toronto Stock Exchange on March 21, 2017. The aggregate transaction value is approximately $637 million, including the assumption of approximately $40 million in Canyon debt. Upon completion of the transaction, existing holders of Trican shares and Canyon shares will collectively own approximately 56 % and 44 % of the combined company, respectively.
• March 21, 2017 – Journey Energy Inc. (“Journey”) has entered into a purchase and sale agreement with an undisclosed private company to acquire interests in Central Alberta for an aggregate purchase price of approximately $35.6 million, comprised of $29.6 million of cash and 2.1 million common shares of Journey. The acquisition consists of approximately 2,000 boe per day of high working interest liquids-rich gas production.
• March 20, 2017 – Pengrowth Energy Corporation announced it has entered into an agreement for the sale of a portion of its Swan Hills assets in north-central Alberta for total cash consideration of $180 million, subject to customary adjustments.
• March 17, 2017 – Blackbird Energy Inc. (“Blackbird”) entered into a binding agreement with Knowledge Energy Inc. for the acquisition of two gross sections (two net) of Montney rights for total consideration of 1.92 million Blackbird common shares.
• March 16, 2017 – Total Energy Services Inc. purchased, through the facilities of the Toronto Stock Exchange, 35,000 Savanna Energy Services Corp. shares.
• March 16, 2017 – Painted Pony Petroleum Ltd. (“Painted Pony”) entered into a share purchase agreement to acquire all of the issued and outstanding shares of UGR Blair Creek Ltd., a privately held 100% controlled subsidiary of Unconventional Resources Canada LP (“URC”), a portfolio investment held in certain private equity funds advised by ARC Financial Corp. and EnCap Investments LP. Pursuant to the agreement, total consideration of 41 million common shares of Painted Pony will be issued to URC. Based on the price per Painted Pony share in respect of the offering of $5.60, total share consideration is $229.6 million.
• March 9, 2017 – Enerplus Corporation announced agreements to sell Canadian properties located in Alberta and southwest Saskatchewan for aggregate proceeds of $67.3 million, before closing adjustments. The properties to be divested include the majority of Enerplus’s shallow gas assets, as well as its Brooks waterflood property.
• March 9, 2017 – Northern Petroleum PLC signed an agreement to acquire production wells and facilities located in Alberta in the same area as the company’s existing Rainbow assets. The company will acquire 75% of the assets with its joint venture partner, High Power Petroleum LLC acquiring the remaining 25%.

Midstream

• March 13, 2017 – The federal government approved NOVA Gas Transmission Ltd.’s Towerbirch Expansion Project subject to 24 binding conditions. The $439-million project will involve the construction of two new pipeline sections totalling approximately 87 kilometres along with associated facilities in northwest Alberta and northeast British Columbia.

Conventional

• February 13, 2017 – Alberta celebrated the 70^th anniversary of the discovery of oil at Leduc #1, which is considered by many to be the start of the modern oil and gas industry in the province. The Government of Alberta marked the anniversary with a special presentation at the Leduc #1 Energy Discovery Centre. Attendees included Marg McCuaig-Boyd, Alberta’s Minister of Energy, Mark Scholz, President of the Canadian Association of Oilwell Drilling Contractors (CADOC), and Tim Hawkins, President of the Leduc/Devon Oilfield Historical Society. The discovery followed years of failures exploratory throughout the province, with Imperial Oil, the well’s proponent, having drilled 133 dry holes previously.
• February 9, 2017 – Clearview Resources Ltd. closed an acquisition of assets in the Wilson Creek area of Alberta for $11.36, effective Dec. 1, 2016. Following the acquisition, Clearview’s production will be approximately 900 boe per day (roughly 50 percent oil and liquids and 50 percent gas).
• February 1, 2017 – Alberta Investment Management Corporation (AIMCo) entered into a financing arrangement with Razor Energy Corp. AIMCo has committed a non-revolving term loan facility for a principal amount of $30 million on a four-year term, with an interest rate of 10 per cent payable semi-annually. A portion of the proceeds of the facility were used by Razor to fund the purchase price of the acquisition of certain producing oil and gas interests in the Swan Hills area of Alberta, with the remainder to be used to fund its development program and for general corporate purposes. In consideration of AIMCo providing the facility, Razor issued approximately 10.05 per cent of its outstanding common shares to AIMCO.

Oil Sands / Unconventional

• February 13, 2017 – Malaysia’s state-owned oil company Petroliam Nasional Bhd (PETRONAS) may consider relocating its Canadian LNG export terminal project if required by Canadian government authorities, according to media reports quoting chairman Mohamad Sidek Hassan. The reports also indicated that PETRONAS has identified a potential new location for the plant to reduce costs and address environmental concerns.

Midstream / Downstream

• February 23, 2017 – Enbridge Inc. and Spectra Energy Corp. announced that the previously announced merger of the two companies has received all required regulatory clearances under the merger agreement, including from the Canadian Competition Bureau. The transaction closed on February 27, 2017. The merged company will have an enterprise value of approximately CDN$166 billion, with an extensive, North America-wide portfolio of crude oil, liquids and natural gas pipelines, a large portfolio of strong, regulated gas distribution utilities and a growing renewable power generation position.
• February 16, 2017 – Pembina Pipeline Corporation announced that it had entered into a 20-year infrastructure development and service agreement with Chevron Canada Limited. The agreement includes an area of dedication by Chevron, in excess of 10 gross operated townships (over 230,000 acres), located in Kaybob region of the Duvernay resource play near Fox Creek, Alberta. Under the agreement and subject to Chevron sanctioning development in the region, Chevron has the right to require Pembina to construct, own and operate gas gathering pipelines and processing facilities, liquids stabilization facilities and other supporting infrastructure for the area of dedication, together with Pembina providing long-term service for Chevron on its pipelines and fractionation facilities.
• February 15, 2017 – Keyera Corp. announced plans for two new projects. First, a new NGL gathering pipeline system (Keylink) that will provide producers in west-central Alberta with a pipeline alternative for transporting NGLs from a number of Keyera gas plants. The estimated cost will be $147-million with an in-service date of mid-2018. Second, Keyera announced a project to expand the liquids handling capacity at the Simonette gas plant to meet customers’ growing needs. The project is expercted to cost $100 million with an in-service date of mid-2018.
• February 13, 2017 – Gibson Energy Inc. entered into an agreement to sell its industrial propane business for cash consideration of $412 million to Superior Plus LP, which is to be completed through a series of transactions. Pursuant to an option purchase agreement and subject to the fulfilment of customary conditions, Gibson and Superior are obligated to complete the initial transaction pursuant to which Superior will pay non-refundable cash consideration of $412 million and Gibsons will grant an irrevocable option to Superior to acquire 100 per cent of the partnership units and shares of its Canwest and Stittco businesses.
• February 2, 2017 – Suncor Energy Inc. closed the previously announced sale of its Petro-Canada Lubricants Inc. (PCLI) business to a subsidiary of HollyFrontier Corporation for gross proceeds of $1.125 billion, subject to customary closing adjustments.

Lenders and capacity providers in the UK’s Capacity Market will want to take note of new procedures introduced by National Grid in its role as the Capacity Market’s Delivery Body.

The Capacity Market aims to incentivise investment in new electricity generating capacity and ensure reliable electricity supplies for end users. Where a Capacity Provider has third party debt financing, the lender will want to take security over the capacity payments it is entitled to receive by registering a Security Interest in respect of the relevant Capacity Agreement on the Capacity Market Register.

Recently National Grid, as Delivery Body, has changed the way such Security Interests are to be registered.

Previously lawyers acting for lenders (the beneficiaries of the Security Interests) have undertaken registration on behalf of their clients, in line with the other common security registrations at Companies House and where applicable, the Land Registry. All that was required was to submit by email a notice of the Security Interest in a form agreed by the Delivery Body (the Security Interest Notice).  The Delivery Body now requires that Security Interest Notices are registered by the relevant Capacity Provider itself, via the online portal registration system known as the EMR Delivery Body Portal (the Portal).

This means that beneficiaries of the Security Interests, or lawyers acting on their behalf, are no longer able to manage this process, so the Security Interest Notice will need to be submitted to the Capacity Market Register via the Portal by the Capacity Provider or their lawyers (if they are appointed as an agent to act on behalf of the relevant Capacity Provider).

Once a Security Interest Notice has been uploaded to the Portal the Delivery Body will receive notification and following this the Delivery Body will be required to approve (or return) an application to register that Security Interest and update the Capacity Market Register accordingly.

Going forward, it is likely that this process will be reflected in any relevant loan or security document to ensure that, where applicable, borrowers and developers are required to submit a Security Interest Notice to the Delivery Body (or provide evidence of this to the beneficiaries of the Security Interest) as a condition to the terms of the financing.

If you are a Capacity Provider and you have not already signed up to the Portal, information on how to register via the company registration form can be found here. The Delivery Body has also published guidance on how to upload a Security Interest which you can access by clicking here.

If you are experiencing any issues with the Portal, the Delivery Body can be contacted via email at EMR@nationalgrid.com or via telephone on 01926 655300.

Defined terms used in this blog post are taken from the consolidated version of The Capacity Market Rules 2014 published on 14 July 2016, or as introduced by the author.

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

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

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

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

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

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

Conventional

• December 15, 2016 – Athabasca Oil Corporation entered into agreements with Statoil ASA and its wholly owned subsidiary Statoil Canada Ltd. to acquire their Canadian thermal oil assets for consideration of $435 million cash, 100 million common shares and contingent value payments triggered at oil prices above US$65 per bbl WTI.
• December 14, 2016 – Toro Oil & Gas Ltd. entered into a definitive agreement with Steelhead Petroleum Ltd., pursuant to which Steelhead will acquire all of the outstanding common shares and common share purchase warrants of Toro Oil & Gas Ltd. for approximately $44.1 million in cash.
• December 12, 2016 – Delphi Energy Corp. announced that it closed its strategic agreement with its existing working interest industry partner to accelerate the development of Delphi’s liquids-rich Deep Basin natural gas play at Bigstone in northwest Alberta. Delphi Energy Corp. received approximately $31.3 million in cash for the partner’s equalization of certain working interests and the partner also paid $10.9 million to Delphi for the partner’s carried obligation of the joint drilling program.
•  December 9, 2016 – The Court of Queen’s Bench of Alberta granted an approval and vesting order for the previously announced purchase and sale of substantially all of the assets and business of Lightstream Resources Ltd. by Ridgeback Resources Inc. for the full amount of the claims outstanding in respect of the company’s 9.875% second lien secured notes due 2019 and debt in priority to the secured notes.
• December 9, 2016 – ARC Resources Ltd. closed the previously-announced sale of its Saskatchewan assets and operations to Spartan Energy Corp. for total cash consideration of $700 million, subject to customary post-closing adjustments. The effective date of the transaction is October 1, 2016.
• December 8, 2016 – Spartan Energy Corp. closed its previously announced bought deal public offering, including the exercise in full of the over-allotment option, for aggregate gross proceeds of approximately $287.6 million. Prior to the completion of the prospectus offering, Spartan closed a non-brokered private placement offering for aggregate gross proceeds of $255 million. The aggregate gross proceeds from the prospectus offering and the private placement are approximately $542.6 million.
• December 6, 2016 – Marquee Energy Ltd. announced the completion of the previously announced acquisition of Marquee Energy Ltd. by Alberta Oilsands Inc. by way of a plan of arrangement and the subsequent completion of the short-form vertical amalgamation to form the “new” Marquee Energy Ltd.
• December 6, 2016 – Pine Cliff Energy Ltd. closed its previously announced disposition of non-core oil assets for $31.4 million, prior to any closing adjustments, consisting of $26.6 million in cash and $4.8 million in TSX-listed common shares of the purchaser. The disposed assets include approximately 500 boe per day of production weighted 94% to oil located in the Viking area of central Alberta.
• December 5, 2016 – TransGlobe Energy Corporation entered into a definitive agreement to acquire Cardium light oil and Mannville liquid-rich gas assets in the Harmattan area of west-central Alberta for total consideration of $80 million.
• December 5, 2016 – Bellatrix Exploration Ltd. entered into an agreement with a TSX-listed issuer to sell certain non-core assets in the Harmattan area of Alberta for $80 million, subject to customary closing adjustments. The transaction is expected to close prior to December 31, 2016, with an effective date of December 1, 2016. The $80 million purchase price will be payable $65 million in cash and $15 million in a vendor take back loan bearing interest at 10% per annum and secured by a first lien charge against the assets being sold.
• December 2, 2016 – PrairieSky Royalty Ltd. completed four separate acquisition transactions for aggregate consideration of $117.3 million, representing approximately 460 boe per day of royalty production and over 100,000 acres of mineral title and royalty lands.
• December 2, 2016 – BlackPearl Resources Inc. completed the sale of a gross overriding royalty interest on its Onion Lake property for $55 million. Under the terms of the agreement BlackPearl sold an approximate 1.75% royalty on production from substantially all of its Onion Lake lands.

Unconventional

• December 15, 2016 – PrairieSky Royalty Ltd. entered into a definitive agreement with Pengrowth Energy Corporation to acquire a 4% gross overriding royalty on current and future phases of its Lindbergh SAGD thermal oil project, as well as seismic over certain lands in British Columbia and Alberta, for total cash consideration of $250 million.

Midstream

• December 21, 2016 – Alberta Investment Management Corporation on behalf of certain of its clients, agreed to acquire an ownership stake in Howard Energy Partners from EnLink Midstream Partners, LP. The investment, representing an ownership stake of approximately 28% of Howard Energy Partners, makes the Alberta Investment Management Corporation the second largest unitholder in the company. The transaction is expected to close during the first quarter of 2017, subject to customary closing conditions.
• December 20, 2016 – Tidewater Midstream and Infrastructure Ltd. acquired from a vendor the remaining approximate 37% working interest in the Brazeau River Complex gas plant and the remaining approximate 60% working interest in 105 kilometres of gas gathering pipelines directly connected to the BRC in addition to the remaining working interests for 100% ownership in the previously announced three proven natural gas storage reservoirs that are also directly connected to the BRC for a purchase price of $30 million in cash.
• December 16, 2016 – Spectra Energy Corp. announced that during a special stockholder meeting, Spectra Energy stockholders voted to approve the previously announced combination of Spectra Energy with Enbridge Inc. in a stock-for-stock merger transaction. Enbridge shareholders also approved the required resolutions in connection with the merger transaction between Enbridge and Spectra at its special meeting of shareholders.
• December 2, 2016 – Enbridge Inc. together with Enbridge Income Fund Holdings Inc. announced that it closed the previously announced sale of its South Prairie Region assets to Tundra Energy Marketing Limited for $1.075 billion in cash.