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Investors move to secure positions in light of Tanzania natural resources reforms

Investors move to secure positions in light of Tanzania natural resources reforms

Recent measures introduced in the Tanzanian natural resources and mining sectors could have far-reaching implications for the value of investments in the country. As a result of legislation, approved by the National Assembly in early July, companies face the prospect of having to grant a 16 per cent free carried interest to the government, acquisition of up to 50 per cent of the company, increased royalties and forced renegotiation of certain terms.

The reforms are the latest in a campaign to exercise greater control over the extractives sectors. This has already given rise to two new claims by foreign investors since the beginning of July. Those with interests in the country’s mining, oil and gas industries will be closely observing developments, reviewing their contractual investment treaty protections and taking steps to protect their assets and any future claims.

The key provisions of significance to foreign investors are as follows:

Natural Wealth and Resources Contracts (Review and Re-negotiation of Unconscionable Terms) Act 2017

This Act grants the government far-reaching powers to renegotiate contracts relating to any natural resources where they contain what are considered by the National Assembly to be “unconscionable terms”. This power of review extends to contracts predating the Act. Terms that are deemed to be unconscionable include those which:

  • are aimed at restricting the state’s right to exercise sovereignty over its wealth, natural resources and economic activity;
  • restrict the state’s right to exercise authority over foreign investment within the country;
  • are “inequitable and onerous to the State”;
  • grant “preferential treatment” designed to create a “separate legal regime to be applied discriminatorily for the benefit of a particular investor”;
  • deprive the Tanzanian people of the economic benefits derived from natural resources;
  • empower transnational corporations to intervene in Tanzania’s internal affairs;
  • subject the state to the jurisdiction of foreign tribunals or laws.

What might be an unconscionable term is extremely broad – indeed, most recent contracts in which foreign entities are (even indirectly) involved are likely to contain provisions that would be caught. This again evidences the progressive change in policy towards foreign investment, going directly against many of the protections in Tanzania’s 11 bilateral investment treaties (BITs) currently in force.

Changes to the Mining Act 2010

The Written Laws (Miscellaneous Amendments) Act 2017 introduced the requirement that, where a company is carrying out any mining operations under a mining licence or special mining licence, the government shall have a minimum 16 per cent free carried interest in its shares. In addition, it will be entitled to acquire up to 50 per cent of the shares of the company, “commensurate with the total tax expenditures incurred by the Government in favour of the mining company”.

It remains to be seen whether the government will take the 16 per cent free carried interest where operations occur under existing licences, or only where new licences are granted. How the government’s “entitlement” to acquire additional shares will work is equally uncertain. Investors are likely to face difficult strategic decisions over the coming months in light of the risk of seizure of their shares or other assets.

Additionally, this Act increases the royalty rate payable for uranium, gemstones and diamonds from 5 per cent to 6 per cent, and for other metals including gold from 4 per cent to 6 per cent. There is a new requirement that one third of royalties are to be paid by depositing minerals of the equivalent value with the government.

Natural Wealth and Resources (Permanent Sovereignty) Act 2017

This Act provides that the people of Tanzania have permanent sovereignty over all natural wealth and resources, ownership and control of which vests in the government on their behalf. The President is to hold the country’s natural wealth and resources on trust for the people. This in itself may not have an immediate impact upon investments, but again sends a fairly clear message as to the government’s intentions.

Finally, the Act provides that disputes “arising from extraction, exploitation or acquisition and use of natural wealth and resources shall be adjudicated by judicial bodies or other organs established in the United Republic and [in] accordance with laws of Tanzania”.

It is doubtful whether a foreign tribunal considering its jurisdiction under a pre-existing valid arbitration clause would pay regard to this provision. The Act also provides that the jurisdiction of the Tanzanian courts must be acknowledged and incorporated in any “arrangement or agreement” – which may have significant implications for agreeing a forum for disputes outside Tanzania under future agreements.

It is unclear whether the Act intends to attempt to exclude ICSID jurisdiction. However, it would be unlikely to be effective where consent to that jurisdiction has been expressed by Tanzania in BITs (which consent cannot unilaterally be revoked). It should therefore be open to investors still to initiate ICSID arbitration under such treaties.

Impact and potential claims against Tanzania

Against the backdrop of the tightening regime relating to the natural resources sector, two international companies are reported to have commenced arbitration proceedings in as many months.

Two subsidiaries of Acacia Mining started LCIA arbitrations based on their Mineral Development Agreements (MDAs) with Tanzania. The arbitrations followed a ban on mineral exports by the companies imposed following allegations by the state that Acacia had under-reported its exports, amounting to a multi-million-dollar tax evasion. Acacia’s parent company, Barrick Gold, is said to have intervened to attempt to resolve the dispute with the government, and it was reported on 20 October that a settlement deal has been proposed. This would involve Acacia forming a new joint venture with the Tanzanian government to operate three gold mines, with Tanzania receiving a 16% stake in the mines and a 50% share of the profits, as well as a one-off payment of $300million from Acacia.[1]

South African company AngloGold Ashanti also announced earlier this month that it had begun arbitration proceedings against Tanzania, in response to the ability to renegotiate contracts pursuant to the Unconscionable Terms Act. Reports state this was a precautionary step taken by the company to protect its indirect subsidiaries’ agreements with the government in relation to the development and operation of the Geita Gold Mine. This pre-emptive action demonstrates the serious threat the new governmental powers pose to foreign investments.

Whilst the three arbitrations already launched are based on the companies’ contracts, investors with the government should also consider the BIT protections available to them and what claims could be brought before ICSID (with the increased potential for publicity and direct enforcement this entails). Where an applicable BIT contains an umbrella clause (as many of Tanzania’s do), any breach of an Mineral Development Agreement or other contract will also constitute a breach of the BIT, opening the door to ICSID jurisdiction over the dispute.

Even where no contract is in place, the measures threatened may well breach BIT provisions and trigger further claims. Any demand for carried interest without compensation is likely, for instance, to constitute an unlawful expropriation. If this were the case, the investor would usually be entitled to recover the fair market value of the shareholding immediately prior to the expropriation. The same would be true of any additional shares compulsorily acquired for which adequate compensation was not given.

Many of the measures identified may also breach fair and equitable treatment provisions in BITs (which include protection of an investor’s legitimate expectations) and provisions promising treatment no less favourable than that afforded to a state’s own nationals.

Those with interests in Tanzania’s mining, oil and gas industries would be well advised to take all possible steps to protect their investments in light of this legislation and widely anticipated further measures to create yet more state control over the sectors.

[1] “Tanzania takes steps to settle mining dispute”, Global Arbitration Review, 20 October 2017.

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Investors move to secure positions in light of Tanzania natural resources reforms

Energy Market Mergers – quick guide to EU Competition Law assessment

This blog is a summary of an article that appeared in Competition Law Insight examining the key competition law principles in energy market mergers. The article can be found at: https://www.competitionlawinsight.com/competition-issues/energy-market-mergers–1.htm?origin=internalSearch.

Since the mid-1990s, the European Commission has pursued a policy of energy market liberalization. At first, the Commission did so as legislator with the adoption of three successive liberalization directives. Since the beginning of the century, the Commission has supplemented its role as policy-maker by making full use of its competition policy enforcement powers. This has particularly manifested itself in its assessment of gas and electricity mergers under the EU Merger Regulation. The Commission’s push towards increasingly competitive energy markets by way of this two-track approach was approved by the Court of Justice of the European Union in a 2010 judgment.

In its assessment of energy mergers, the Commission must first define the relevant product and geographical markets. Because energy mergers usually comprise both gas and electricity markets, this determination must be made for both markets separately. In terms of the relevant product market, the Commission distinguishes between upstream and downstream markets for electricity. The upstream electricity market comprises a single wholesale electricity market, which interestingly includes the financial trading of electricity, as well as the market for ancillary services and balancing power. In making these distinctions, the Commission bases itself mostly on the criteria of substitutability, including price elasticity.

At the downstream level of the electricity market, the Commission has identified three levels of supply, i.e. supply through the transmission network, and two types of supply through the distribution network, one to small industrial and commercial users and the other to eligible household customers. The Commission’s assessment practice has demonstrated a steady preference for market share calculation on the basis of supplied volume, despite the fact that publicly available data released by regulators is mostly provided on the basis of physical connection points. To date, it firmly refuses to differentiate between sources of electricity such as wind, solar or nuclear. In future, this practice could come under increasing pressure for change given the increased impact of these power sources on consumer preferences.

In defining the relevant product market for natural gas, the Commission has categorized five different supply markets—supply to dealers from the supply to electricity producers, supply to large industrial and commercial users, supply to small industrial and commercial users and supply to eligible household customers. Finally, markets having a physical trading hub, such as a dedicated LNG sea port terminal, also constitute a separate gas market segment. Despite this seemingly uniform approach in defining market segments, there exists a high degree of variation in the thresholds at which they have been categorized. For example, in France, the threshold between the categories for small and large industrial and commercial users was set at 5 Gigawatt hours, whereas the threshold between the same gas market segments was set at 12 Gigawatt hours for Belgium. The Commission breaks down gas market segments further between high-calorific and low-calorific gas (H- and L-gas) because of their non-substitutability. However, there have been recent cases where parties have not even disclosed such data because they were of the view that the market shares would not differ significantly, or would involve a minimum increment.

At the geographic market level, energy market definition is subject to a case-by-case approach, with some markets being national and others sub-national or regional. These ad hoc determinations are made mostly by looking at customer switch rates, local marketing strategies and pricing policies.

Finally, our article identifies five market factors that can be regarded as the most significant obstacles to further market liberalization. In particular, we have pointed to high concentration levels on energy markets, high levels of vertical integration, the remaining government regulatory influences on pricing as well as public ownership, differences in prices and the “incumbency effect”, referring to the structurally lower rate of customer switching, to the benefit of legacy suppliers.

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Energy Market Mergers – quick guide to EU Competition Law assessment

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

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

Background

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

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

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

Reliability and resilience

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

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

The proposed rule

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

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

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

What next?

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

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

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

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

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

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

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

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

 

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

Ofgem on storage as generation (On the way to a smart, flexible energy system? Part 2)

On 29 September 2017, Ofgem published two storage-related consultations on possible modifications to the standard licence conditions of electricity generation and distribution licences.

Ofgem and the Department for Business, Energy and Industrial Strategy (BEIS) are minded to classify storage as a sub-set of the regulatory category of generation.  Clarifying the regulatory framework for electricity storage: licensing elaborates on this proposition and comes with a full set of generation standard licence conditions marked up to show the resulting changes.

Consistent with this approach, Ofgem takes the view that distribution network operators (DNOs) should not operate storage facilities – just as (with only minor exceptions) they are not permitted to operate generating stations.  Enabling the competitive development of storage in a flexible energy system: changes to the electricity distribution licence provides some more detail in this area and includes a draft standard licence condition 43B to keep generation and storage generally separate.

Take generation first. To begin with, Ofgem gives us a definition of storage: “the conversion of electrical energy into a form of energy, which can be stored, the storing of that energy, and the subsequent reconversion of that energy back into electrical energy”.  This comes with a list of technologies that Ofgem thinks the definition covers, which seems fairly comprehensive.  The definitions of “generating station”, “generation business” and “generation set”, would all be revised to include reference to storage.

A huge number of generating stations that are connected to DNO networks in GB operate without holding a generation licence. Clearly it would not be practicable for every household with a few solar panels on its roof to be required to hold a generating licence, but plenty of commercial generation operators also benefit from the statutory licence exemption regime.  Exemption from the obligation to hold a generation licence is more or less automatic up to 50 MW and is frequently granted by BEIS up to 100 MW.  It is generally thought that a licence-exempt generator stands to gain more than it loses by not holding a licence.  Licensees must shoulder a greater regulatory burden, complying with a range of industry codes such as the Balancing and Settlement Code.  This potentially gives them a voice in industry self-governance, but few small generators have the resources to make much of that opportunity, and many prefer simply to avoid the associated costs of code compliance.  Among the other, relatively limited perks of licensed status is the ability to use compulsory purchase powers against recalcitrant landowners in order to develop infrastructure.

It is conceivable that some storage providers may find those compulsory purchase powers useful. Of perhaps more general interest is the prospect that as a licensed storage operator, you would not be subject to “final consumption levies” (FCLs) – the charges that are imposed on suppliers (and therefore in most cases passed through to their customers) to fund the Renewables Obligation, Feed-in Tariffs, Contracts for Difference and Capacity Market payments to generators / capacity providers.  That could persuade some who would not otherwise have to apply for a new storage-friendly generation licence to do so: the rationale is that those who are only operating an intermediate stage in the value chain between generation and final consumption should not be liable for FCLs just because their interaction with the wholesale electricity markets comes through a licensed supplier.

But this is where it starts to get tricky. Storage technology, particularly some kinds of batteries, are becoming significantly cheaper.  Ofgem does not want every large industrial user, for example, to go out and buy a battery as a way of avoiding FCLs.  So a new Condition E1 is proposed: “The licensee shall not have self-consumption as the primary function when operating its storage facility.”  But as Ofgem notes, the notion of a facility’s “primary function” could be defined in many ways.

More generally, it is unfortunate that BEIS and Parliament do not currently have time to regularise matters fully by incorporating the new generation and storage definitions into the relevant legislation, but on balance, Ofgem’s approach of starting with the licence provisions seems a legitimate and pragmatic first step given the importance of clarifying this area.

Turning to the DNOs. According to Ofgem, the existing rules “are clear that the DNOs cannot directly own or operate large-scale storage over 100MW. However, because generation below this threshold does not require a generation licence, there is a grey area where DNOs can own smaller scale storage”.  The underlying rationale of Ofgem’s approach is that since they “control the infrastructure needed to trade energy and flexibility services”, DNOs “have the ability to restrict the activities of market participants by denying (or otherwise impeding) their network access”.  DNOs should therefore not operate storage facilities, as they may be tempted to use their position to gain an unfair advantage over competing storage providers.

This extends the conventional thinking that DNOs should not operate generating stations, and the principle that the monopoly and competitive parts of the electricity supply chain should be kept in separate hands – embodied in the “unbundling rules” set out in EU and UK legislation. Exceptions to the general principle are made in the case of emergency equipment such as uninterruptible power supplies.  These would continue.  It would also be possible for a company that formed part of a DNO’s corporate group to operate a storage facility subject to suitable legal separation from the DNO business and compliance with the existing unbundling rules.

Ofgem does not close the door on a third category of exception to the general rule, which would have to be individually applied for where the market is not able to provide an efficient solution, storage is the most economic and efficient solution, and conflicts of interest are minimised. Guidance is proposed to flesh out these principles.  Meanwhile, a way will be found to deal with the existing DNO owned and operated storage facilities built under Low Carbon Network innovation funding.

DNOs are particularly well placed to know where storage would be most useful in their networks. It must make sense to regulate in a way that encourages competition in providing storage, even where its primary purpose is to improve the functioning of a DNO network.  But the intensity of that competition will be determined in part by other ongoing regulatory workstreams (for a list, see the previous post in this series).

Ofgem on storage as generation (On the way to a smart, flexible energy system? Part 2)

Significant Developments in Canadian Energy – for the Month of July 2017

Conventional

  • July 4, 2017 – Canbriam Energy Inc. has completed a US$74 million (approximately C$100 million) investment from its existing private equity sponsors, which include Warburg Pincus, ARC Financial, Ontario Teachers’ Pension Plan, BlackRock and State Street (formerly GE Capital).
  • July 5, 2017 – Halliburton Company has acquired Summit ESP for an undisclosed purchase price. Summit ESP is considered a leading provider of electric submersible pump (ESP) technology and services.  The company engineers, manufactures and services electric submersible and surface pumping systems. The acquisition of Summit ESP strengthens Halliburton’s artificial lift portfolio for its global customers.
  • July 6, 2017 – Xtreme Drilling Corp. has finalized 18-month term contracts for its two remaining 850XE drilling rigs. Both rigs will work in the Utica play of the Appalachian Basin for the same customer, and be operated by a Utica E&P company.
  • July 11, 2017 – Pengrowth Energy Corporation has entered into an agreement to sell its Olds/Garrington area assets for cash consideration of $300 million, before customary closing adjustments, to a private company which is owned by a large Canadian life insurance company. Included in the assets are facilities and fathering systems related to the oil and gas properties being sold and the Olds gas plant.
  • July 12, 2017 – A new partnership has been announced in Ireland’s Corrib natural gas field. Canada Pension Plan Investment Board (CPPIB) will acquire Shell Exploration Company B.V.’s 45% interest in the project, and Vermilion Energy Inc. will be responsible for operating the assets after the acquisition is completed. CPPIB has entered into a definitive purchase and sale agreement with Shell, through its wholly owned subsidiary, CPP Investment Board Europe S.a.r.l., to acquire 100 % of Shell E&P Ireland Limited (SEPIL), which holds Shell’s 45% interest in Corrib for total cash consideration of €830 million, subject to customary closing adjustments and future contingent value payments based on performance and realized pricing. The acquisition has an effective date of January 1, 2017, and still requires necessary government consents, with closing expected to occur sometime in the first half of 2018 and will see Vermillion assuming operatorship as well as receiving SEPIL from CPPIB and a 1.5 % working interest for €19.4 million (before closing adjustments).
  • July 12, 2017 – Saturn Oil + Gas Inc. (Saturn) and Westcore Energy Ltd. have entered into a joint operating agreement to develop two sections of land near Flaxcombe, Saskatchewan. The assets are located 30 kilometres west of Kindersley. Both companies will have a 50 % working interest in both sections.  Additionally, Saturn has entered into a farm-in agreement with Westcore on the recompletion of an existing well on Westcore’s land at Flaxcombe.
  • July 17, 2017 – Tervita Corporation has acquired its first metals recycling facility in BC. Columbia Recycle (2008) Ltd., a full-service scrap yard, is located in Kimberley and is the largest metal recycler in southeast BC.
  • July 19, 2017 – Ceiba Energy Services Inc. (Ceiba) has obtained approval from its security holders for Secure Energy Services Inc. to acquire all of the issued and outstanding common shares and debentures in the capital of Ceiba.
  • July 26, 2017 – Encana Corporation has sold its Piceance natural gas assets, located in northwestern Colorado, to Caerus Oil and Gas LLC.
  • July 31, 2017 – Devon Energy Corporation has entered into a definitive agreement to monetize its Lavaca County assets in the Eagle Ford play. The transaction is expected to close by the end of 2017 and is subject to customary terms and conditions. It is projected that the Field-level cash flow which accompanies these assets will be approximately $30 million a year, excluding overhead costs.
Significant Developments in Canadian Energy – for the Month of July 2017

On the way to a smart, flexible GB energy system? Part 1 (overview and storage)

Things may be starting to move a bit faster in the world of GB energy policy after what you could be forgiven for thinking was a Brexit-induced slowdown. On 24 July 2017, the UK government’s Department for Business, Energy and Industrial Strategy (BEIS) and the energy regulator Ofgem published a number of documents that reveal their evolving thinking about the future of the GB electricity system. These publications followed on from some significant initiatives by Ofgem and National Grid. This is the first of series of posts assessing where all this activity may be leading.

The full holiday reading list from 24 July was as follows.

Other recent official publications that are relevant in this context and referred to below include:

Overview

The Response and the Plan cover a broad range of subjects; many of the other documents are rather more monothematic. We will follow the topic headings in the Response, referring to the other documents where they are relevant. However, it is helpful to start by framing some of the key themes underlying this area of policy by turning to the Pöyry / Imperial Report.

The CCC has recommended that in order to achieve the ultimate objective of the Climate Change Act 2008 (reducing UK greenhouse gas emissions by 80% by 2050), the carbon intensity of the power sector should fall from 350 gCO2/kWh to about 100 gCO2/kWh by 2030.  Pöyry / Imperial observe that in any future low carbon electricity system, “we should anticipate:

  • a much higher penetration of low-carbon generation with a significant increase in variable renewable sources including wind and solar and demand growth driven by electrification of segments of heat and transport sectors;
  • growth in the capacity of distribution connected flexibility resource;
  • an increased ‘flexibility’ requirement to ensure the system can efficiently maintain secure and stable operation in a lower carbon system;
  • opportunities to deploy energy storage facilities at both transmission and distribution levels; and
  • an expansion in the provision and use of demand-side response across all sectors of the economy.

System flexibility, by which we mean the ability to adjust generation or consumption in the presence of network constraints to maintain a secure system operation for reliable service to consumers, will be the key enabler of this transformation to a cost-effective low-carbon electricity system. There are several flexibility resource options available including highly flexible thermal generation, energy storage, demand side response and cross-border interconnection to other systems.”.

This explains why technologies and mechanisms that can increase system flexibility are a dominant theme in current GB electricity sector policy-making. But Pöyry / Imperial then go on to discuss the extent of the uncertainty that, based on their modelling, they consider exists about how much the main types of flexible resource may be needed on the way to achieving the CCC’s target. This is clearly shown in the table, reproduced below, setting out their assessment of “the required range of additional capacity of different flexible technologies to efficiently meet 2030 carbon intensity targets”.

With the exception of interconnectors, the table shows the amounts of each flexible technology in the low and high scenarios, at each of the three dates, varying by a factor of 5 or more. As regards interconnectors, an illustration of the potential uncertainties in the different scenarios modelled by National Grid in FES 2017 is provided by the two FES 2017 charts below.


Source: National Grid, FES 2017


Source: National Grid, FES 2017

The need for more flexible resources is clear, and Pöyry / Imperial calculate that integrating them successfully, as compared to the use of “conventional thermal generation based sources of flexibility”, could save between £3.2 billion and £4.7 billion a year in a system meeting the CCC’s 2030 target.  But it is also clear that there are many different possible pathways that could be followed to achieve this level of flexibility, and that even if we get to 100 gCO2/kWh by 2030 – which is by no means guaranteed – there will inevitably be, at least relatively speaking, “winners” and “losers” in terms of which flexible technologies, and which individual projects, end up taking a greater or lesser share of what could be loosely called the “flexibility market”.

What will determine who wins or loses out most in this competition will be the same factors as have driven changes in the generation mix in the UK and elsewhere in recent years – in particular, the interplay of regulation and technological change.  In 2016, as compared with 2010, the UK consumed 37% less power generated from fossil fuels and more than twice as much power generated from renewable sources: see the latest Digest of UK Energy Statistics. That shift is the result of subsidies for renewable generating capacity and reductions in the cost of wind and solar plants combined with other regulatory measures that have added to the costs of conventional generators. But whereas in the initial stages of decarbonising the generating mix, the relationship between regulatory cause and market impact has been relatively straightforward, making policy to encourage flexible resources is more complex: it is like a puzzle where each piece put in place changes the shapes of the others.

This is perhaps why the actions recommended by Pöyry / Imperial as having a high priority, summarised below, all sound difficult and technical, and require a large amount of collaboration.

Pöyry / Imperial recommended high priority actions for the flexibility roadmap (emphasis added)
Action Responsible Time frame
Publish a strategy for developing the longer-term roles and responsibilities of system operators (including transitional arrangements) that incentivises system operators to access all flexibility resource by making investments and operational decisions that maximise total system benefits. Ofgem in conjunction with industry 2018
Periodical review of existing system planning and operational standards for networks and generation, assessing whether they provide a level-playing field to all technologies including active network management and non-build solutions (e.g. storage and DSR), and revise these standards as appropriate. Industry codes governance and Ofgem Initial review by 2019
Review characteristics of current procurement processes (e.g. threshold capacity level to participate, contract terms / obligations) and the procurement route (e.g. open market, auctioning or competitive tendering) that enable more efficient procurement of services without unduly restricting the provision of multiple services by flexibility providers. Ofgem in conjunction with SO, TOs and DSOs By 2020
Assess the materiality of distortions to investment decisions in the current network charging methodology (e.g. lack of locational charging, double-charging for stored electricity), and reform charging methodology where appropriate. SO, DSOs and Ofgem By 2020
Assess the materiality of distortions to investment decisions in the absence of non-network system integration charging (i.e. back up capacity and ancillary services) and implement charging where appropriate SO, DSOs and Ofgem By 2020
Publish annual projections (in each year) of longer-term future procurement requirements across all flexibility services including indication of the level of uncertainty involved and where possible location specific requirements, to provide greater visibility over future demand of flexibility services SO and DSOs 2020 onwards

Storage

We looked at the current issues facing the UK energy storage sector and recent market developments in some detail in a recent post, so we will not dwell too much on the background here.

Storage – conceptually if not yet in practice – is the nearest thing there is to a “killer app” in the world of flexible resources.  It has the potential to be an important asset class on a standalone basis, but it can also be combined with other technologies (from solar to CCGT) to add value to them by enabling their output to match better the requirements of end users and the system operator.

In GB, as in a number of other jurisdictions, there is intense interest in developing distributed storage projects based on battery technology (for the moment at least, predominantly of the lithium ion variety), and a strong focus on doing so in a way that allows projects to access multiple revenue streams. There is also a general feeling that the regulatory regime needs to do more to recognise storage as a distinct activity but at the same time to do less to discriminate against it in various ways.

So, what do the Response and the Plan tell us about the vision for storage?

  • The Response points to National Grid’s SNaPS work, “which specifically considers improving transparency and reducing the complexity of ancillary services”.
  • It also points to work that has been done and/or is ongoing to clarify how storage can be co-located with subsidised renewable electricity generating projects and to provide guidance on the process of connecting storage to the grid. BEIS / Ofgem note that they see no reason why a network operator should not “promote storage…in a connection queue if it has the objective of helping others…to connect more quickly or cheaply”, and point out that Ofgem can penalise DNOs who fail to provide evidence that they are engaging with and responding to the needs of connection stakeholders.
  • BEIS / Ofgem highlight the proposals in the TCR Consultation on reducing the burden faced by storage in terms of network charges, notably the removal of demand residual charges at transmission and distribution level, and reducing BSUoS charges, for storage. A response to that consultation is to be published “in the summer”.
  • In relation to behind the meter storage, BEIS / Ofgem observe that at present: “technology costs and the limited availability of Time of Use (ToU)/smart tariffs are greater barriers…than policy or regulatory issues”. This may invite the response from some readers that it is precisely a matter for policy and regulation to promote time of use / smart tariffs: the CEPA Report makes interesting reading in this context.
  • BEIS / Ofgem “agree with the view expressed by many respondents” that network operators should be prevented from directly owning and operating storage” whilst slightly fudging the extent to which this may already be the case as a result of existing EU-based rules on the unbundling of generation from network operation, but “noting” the current EU proposals in the November 2016 Clean Energy Package to prohibit ownership of storage by network operators except in very limited circumstances and with a derogation from the Member State.
  • Flexible connections “should be made available at both transmission and distribution level”.
  • BEIS / Ofgem agree that the lack of a legal definition or regulatory categorisation of storage is a barrier to its deployment. Legislation will be introduced to “define storage as a distinct subset of generation”. This will enable Ofgem to introduce a new licence for storage before the changes to primary legislation are made. The “subset of generation” approach will also “avoid unnecessary duplication of regulation while still allowing specific regulations to be determined for storage assets” – such as whether the threshold for requiring national rather than local planning consent should be the same for storage as for other forms of generation.
  • The prospect of storage facilities benefiting, as generation, from relief from the climate change levy is also noted – although since the principal such relief (for electricity generated from renewable sources) no longer applies, this may be of limited use to most projects.

What the Response says about storage is typical of its approach to most of the issues raised in the CFE. If one wanted to be critical, it could be said that although, on the whole, BEIS / Ofgem engage with all the points raised by stakeholders, there is rarely an immediate and decisive answer to them: there is always another workstream somewhere else that has not yet concluded that holds out the prospect of something better than they can offer at present. On the other hand, perhaps that just highlights the points implicit in the Pöyry / Imperial Report’s recommendations: no one body can by itself create all the conditions for flexibility to be delivered cost-effectively, and it will be difficult fully to judge the success of the agenda that BEIS and Ofgem are pursuing for another two or three years.

But wait a minute.  On the same day as it issued the Response and the Plan, BEIS also published the CM Consultation. The sections of the Response on storage say nothing about this document, but it is potentially the most significant regulatory development in relation to storage for some time.

  • The Capacity Market is meant to be “technology neutral”. Above a 2 MW threshold, any provider of capacity (on the generation or demand side) that is not in receipt of renewable or CCC subsidies can bid for a capacity agreement in a Capacity Auction that is held one year or four years ahead of when (if successful) they may be called on to provide capacity when National Grid declares a System Stress Event.
  • A key part of the calculations of any prospective bidder in the Capacity Market, particularly one considering a new build project, who is hoping that payments under a capacity agreement will partly fund its development expenses, is the de-rating factor that National Grid applies – the amount by which each MW of each bidding unit’s nameplate capacity is discounted when comparing the amount of capacity left in the auction at the end of each round against the total amount of capacity to be procured, represented by the demand curve. Some of the de-rating factors applied in the 2016 T-4 Auction are set out below.
Technology class Description De-rating Factor
Storage Conversion of imported electricity into a form of energy which can be stored, the storing of the energy which has been so converted and the re-conversion of the stored energy into electrical energy. Includes pumped storage hydro stations. 96.29%
OCGT / recip Gas turbines running in open cycle fired mode.
Reciprocating engines not used for autogeneration.
94.17%
CCGT Combined Cycle Gas Turbine plants 90.00%
DSR Demand side response 86.88%
Hydro Generating Units driven by water, other than such units: (a) driven by tidal flows, waves, ocean currents or geothermal sources; or (b) which form part of a Storage Facility. 86.16%
Nuclear Nuclear plants generating electricity 84.36%
Interconnectors IFA, Eleclink, BritNED, NEMO, Moyle, EWIC, IFA2, NSL (project specific de-rating factors for each interconnector) 26.00% to 78.00%
  • In the table above, storage has, for example, a de-rating factor approximately 10 percentage points higher than DSR and hydro and, if successful at auction, would receive correspondingly higher remuneration per MW of nameplate capacity than those technologies.
  • The typical potential storage project competitor in the Capacity Market is now more likely to be a shed full of batteries than a pumped hydro station. This has prompted industry participants to question whether such a high de-rating factor is appropriate to all storage. Ofgem, in considering changes to the Capacity Market Rules proposed by stakeholders, declined to take a view on this, deferring to BEIS.
  • BEIS, in the CM Consultation, finds merit in the arguments that (i) System Stress Events may last longer than the period for which a battery is capable of discharging power without re-charging; (ii) batteries degrade over time, so that their performance is not constant; (iii) a battery that is seeking to maximise its revenues from other sources may not be fully charged at the start of a System Stress Event. It proposes to take these points into account when setting de-rating factors for the next Capacity Auction (scheduled to take place in January 2017, and for which pre-qualification is ongoing), and splitting storage into a series of different categories based on the length of time for which they can discharge without re-charging (bands measured in half-hourly increments from 30 minutes to 4 hours). Bidders will be invited in due course to “self-select” which duration-based band they fall into.
  • Of course, deterioration in performance over time is not unique to batteries – other technologies may also perform less well by the end of the 15 year period of a new build capacity agreement than they did at the start. And, as with other technologies, such effects can be mitigated: batteries can be replaced, and who knows by what cheaper and better products by the late 2020s. However, a fundamental difficulty with the CM Consultation is that it contains an outline description of a methodology, based around the concept of Equivalent Firm Capacity, but no indicative values for the new de-rating factors.
  • It may be that BEIS’s concerns about battery performance have been heightened by the fact that the parameters for the next Capacity Market auctions show that it is seeking to procure an additional 6 GW of capacity in the T-1 auction (i.e. for delivery in 2018). There is reason to suppose that battery projects could make a strong showing in this auction, given their relatively quick construction period and the number of projects in the market, some of which may already have other “stacked” revenues (see our earlier post). Clearly it would be undesirable if a significant tranche of the T-1 auction capacity agreements was awarded to battery storage projects which then failed to perform as required in a System Stress Event.
  • It is arguable that the three potential drawbacks of battery projects are not necessarily all best dealt with by de-rating. For example, the risk that a battery is not adequately charged at the start of a System Stress Event is ultimately one for the project’s operator to manage, given that it will face penalties for non-delivery. Nor is it only battery storage projects that access multiple revenue streams and may find themselves without sufficient charge to fulfil their Capacity Market obligations on occasion: pumped hydro projects do not operate only in the Capacity Market, and even though they may be able to generate power for well over four hours, they too cannot operate indefinitely without “recharging”.  Moreover, National Grid is meant to give 4 hours’ notice of a System Stress Event, which may provide battery projects with some opportunity to prepare themselves.
  • However, the real objection to the de-rating proposal is not that it is not addressing a potentially real problem, but that it is only doing so now – given that the issue was raised by stakeholders proposing Capacity Market Rules changes at least as long ago as November 2016 – and with no published numbers for consultees to comment on.
  • The de-rating proposal illustrates a fundamental feature of the flexible resources policy space: one technology’s problems provide an up-side for competing technologies. Self-evidently, what may be bad news for batteries is good news for other storage technologies to the extent that they are not perceived to have the same drawbacks.
  • Seen in this light, the CM Consultation appears to be the main (perhaps only) example of a policy measure that supports the “larger, grid-scale” storage projects (using e.g. pumped hydro or compressed air technology) about which the Response has relatively little to say. However, a few percentage points more or less on de-rating may not make up for the lack of e.g. the “cap and floor” regulated revenue stream advocated by some for such projects.

In Part 2 of this series we will focus on the role of aggregators (featuring the analysis in the CRA Report on independent aggregators) and the demand-side more generally.

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On the way to a smart, flexible GB energy system? Part 1 (overview and storage)

Price review arbitrations are not all about economics – everyone has to remember the law!

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”.

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Price review arbitrations are not all about economics – everyone has to remember the law!

New National Oil Companies: 5 things to think about

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.

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New National Oil Companies: 5 things to think about

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

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

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

Benefits of energy storage

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

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

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

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

Technology options

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

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

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

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

Models and market factors

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

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

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

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

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

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

Tenders and auctions

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

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

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

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

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

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

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

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

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

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

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

Battery bonanza?

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

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

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

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

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

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

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

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

Regulatory challenges

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

 

 

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

Extractives companies’ human rights records ranked in Benchmark study

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

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

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

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

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

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

Results skew significantly to the lower bands

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

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

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

Gap between policies and performance

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

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

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

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

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

Conclusion

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

Extractives companies’ human rights records ranked in Benchmark study