Global Energy Blog 

In the 2004 case of U.S. Department of Transportation v. Public Citizen,[1] the Supreme Court established an important limiting principle under the National Environmental Policy Act (NEPA) on the extent to which a federal agency must consider indirect environmental effects in completing NEPA-required reviews of planned agency action. It held that unless an agency has statutory authority categorically to prevent a particular environmental effect, its order cannot be viewed as a legally relevant cause of that effect, thus relieving it of any obligation to gather or consider information on the effect.[2]

As in Public Citizen, this principle often comes into play where the actions of two or more governmental agencies have a role in potentially “causing” a particular environmental effect. If the agency with NEPA responsibilities lacks statutory authority categorically to prevent the indirect effect, it has no obligation to evaluate it under NEPA.[3]

Public Citizen receives substantial play in the orders of the Federal Energy Regulatory Commission (FERC) authorizing pipeline and gas infrastructure under Sections 3 and 7 of the Natural Gas Act (NGA).[4] As the shale gas boom and accompanying buildout of increased gas-fired power generation and LNG export capability have spurred unprecedented demand for new pipelines and gas infrastructure in recent years, they also have sparked unprecedented opposition to gas infrastructure projects by well-organized and well-funded environmental groups like the Sierra Club promoting a climate change/renewable energy agenda.

Such opposition leans heavily on challenges to the sufficiency of the Commission’s reviews under NEPA, giving special emphasis to the claim that, in evaluating new pipeline projects to serve power generation load, FERC must consider the effects on climate change of greenhouse gas emissions (GHG) from the end use of the gas in the power plants served by the pipeline.

Relying on Public Citizen, FERC for the most part[5] has not attempted to quantify such indirect environmental effects, maintaining that its authorization of a pipeline is not the legally relevant cause of the GHG emissions resulting from downstream consumption of natural gas in power plants.

The D.C. Circuit Panel Decision in Sabal Trail

But in the recent case of Sierra Club v. FERC,[6] the majority of a panel of the D.C. Circuit disagreed. In reviewing FERC’s authorization of the Sabal Trail Pipeline designed to serve new gas-fired power plants in Florida, the panel held that the GHG emissions from the power plants are an indirect effect of FERC’s order approving the pipeline and that “because FERC could deny a pipeline certificate on the ground that the pipeline would be too harmful to the environment, the agency is a ‘legally relevant cause’ of the direct and indirect environmental effects of pipelines it approves. Public Citizen thus did not excuse FERC from considering these indirect effects.” [7]

The panel vacated and remanded FERC’s order authorizing construction and operation of the pipeline, pending FERC’s completion and review of the additional environmental studies on the power plant GHG emissions.[8]

In a strong dissent, Judge Janice Rogers Brown disputed the majority’s application of Public Citizen. Relying chiefly on a trilogy of recent D.C. Circuit decisions that had rejected the need for FERC to undertake NEPA consideration of downstream GHG emissions in its authorization of LNG export terminals,[9] Judge Brown pointed out that in those cases: “we held the occurrence of a downstream environmental effect, contingent upon the issuance of a license from another agency with the sole authority to authorize the source of those downstream effects, cannot be attributed to the Commission; its actions ‘cannot be considered a legally relevant cause of the effect for NEPA purposes.'”[10]

While the downstream effects in the LNG terminal cases were contingent on DOE’s authorizing exports of natural gas, the downstream effects in Sabal Trail were contingent upon authorization of the construction and operation of the power plants by the Florida Power Plant Siting Board, a duly authorized agency of the state of Florida with exclusive authority over the licensing of new power plants in Florida. Without the licensing of the power plants, there would be no power plant operations and no resulting GHG emissions.

Significance of Sabal Trail

Sabal Trail is significant on multiple levels. On a practical level, the vacatur and remand to FERC opens a Pandora’s box of NEPA review for the Commission. Although FERC’s environmental staff has performed upper-bound estimates of GHG emissions from downstream gas use associated with new gas pipeline projects since mid-2016, there are no readily available standards to guide such determinations, and its assessments to date have not been tested on judicial review.

The additional required analysis has the potential not only to further delay an already burdened FERC approval process, but also to inject added complexity in sorting out (i) the proper estimates of GHG emissions to use in determining the impact of using gas in the power plants; (ii) the significance of such GHG emissions, especially since there are no readily available metrics to gauge “significance;” and (iii) whether the Commission  should employ the “Social Cost of Carbon” tool developed by the Obama-era Council on Environmental Quality,[11] now withdrawn by executive order[12] in favor of reliance on the metrics set forth in OMB Circular A-4,[13] to evaluate the impact of the GHG emissions and the benefits and detriments generally of a proposed pipeline project.

These challenges portend greater uncertainty and possibly increased likelihood of error in the commission’s evaluations, potentially heightening investor risk in pipeline projects and dampening deployment of capital in the pipeline sector.

Efforts to reach consensus on the proper response to Sabal Trail in the proceedings on remand have already divided the Commission along party lines. In its March 14, 2018, Order on Remand Reinstating Certificate and Abandonment Authorization, the three-Republican majority adhered to the methodology the Commission environmental staff first introduced in mid-2016, employing upper-bound estimates of GHG emissions with explanations of the inherent difficulty in providing more granular detail. It also declined, as in past orders, to employ the Social Cost of Carbon tool, noting the inherent difficulties of meaningfully employing the Social Cost of Carbon in the Commission’s decision-making.[14]

Lastly, the majority questioned whether the Commission has authority to deny a certificate because of concerns about GHG emissions from the end use of gas, noting that Congress or the executive branch, not the Commission, is responsible for deciding national policy on the end use of natural gas.[15]

The two Democratic Commissioners dissented separately, asserting that the order on remand should have included more granular assumptions in the evaluation of GHG emissions, adopted the Social Cost of Carbon to evaluate both the impact of GHG emissions from downstream gas use and the public convenience and necessity of projects generally, and determined that the impact on climate change of GHG emissions from downstream gas use must be factored into the determination of the public convenience and necessity of a new project.[16]

But far and away, Sabal Trail‘s greatest significance is that the panel majority’s application of Public Citizen does not appear defensible, making the case worthy of U.S. Supreme Court review, especially in light of the current administration’s desire to expedite the authorization and construction of new infrastructure. If Sabal Trail is reviewed and reversed by the Supreme Court, FERC will have a far clearer path through its NEPA process in pipeline certificate cases.

Where the Sabal Trail Panel Majority May Have Gone Wrong

The panel majority appears to have misapplied Public Citizen in two separate respects: (i) on the statutory authority of FERC, in presupposing that the Commission has authority under the NGA to deny a pipeline certificate because of concerns about GHG emissions from the end use of the gas transported by a pipeline, and (ii) on causation, as noted by Judge Brown, in wrongly attributing to FERC causation of GHG emissions by the power plants served by the FERC-authorized pipeline, when a separate state agency had sole authority to license the construction and operation of the power plants that are the source of such emissions, and categorically to prevent such emissions by refusing to issue a license.

Whether FERC has statutory authority to deny a pipeline because of concerns about GHG emissions from power plants served by the pipeline

Although the panel majority correctly articulated the touchstone of Public Citizen that “[a]n agency has no obligation to gather or consider environmental information if it has no statutory authority to act on that information,”[17] it failed to apply that limitation in the context of the Commission’s statutory authority to act on the information claimed to be necessary.

To justify collecting information on downstream power plant emissions, the panel needed first to determine that the Commission has statutory authority to deny a certificate to a new pipeline because of concerns about the effects on climate change of GHG emissions from the power plants proposed to be served by the pipeline. Because the panel majority never addressed that issue, the statutory authority element of Public Citizen is missing.

The proffered justification that “FERC could deny a pipeline certificate on the ground that the pipeline would be too harmful to the environment”[18] is insufficient, as it fails to define FERC’s statutory authority in the context of the specific information sought on downstream GHG emissions from the end use of the gas.

Having no express statutory authority to regulate the end use of gas, the Commission’s power to affect end use in certificate cases derives from its authority under Section 7(e) to determine that a proposed service is required by “the public convenience and necessity.” However, the precedent to date indicates that the Commission’s latitude in exercising such authority is limited, confined to furthering Congress’ purpose in enacting the NGA to assure interstate consumers “an adequate and reliable supply of gas at reasonable prices.”[19]

For example, in the leading case, FPC v. Transcontinental Gas Pipe Line Corp.,[20] the Supreme Court upheld the authority of the Federal Power Commission (FERC’s predecessor) to deny a certificate for the transportation of gas from the Gulf Coast to New York City to alleviate inner-city air pollution because of the Commission’s overriding concerns about the end use of the gas for power generation.

Because other fuels could be readily substituted for natural gas under steam boilers, the Commission  determined that using a wasting resource like gas in power plants was an “inferior use,” whose adverse effects on the availability and price of gas to other interstate consumers would be exacerbated if power plant supply deals like the one proposed in Transco were allowed to proliferate.[21]

Whereas the basis for the Commission’s exercise of authority in Transco can be readily linked to the NGA’s statutory purpose and, as the Supreme Court found in Transco, to Congress’ intent in the 1942 amendments to NGA Section 7 to permit the Commission to take account of the potential “economic waste” of gas in exercising its certificate authority,[22] no such statutory grounding is evident to support the notion of denying a pipeline certificate because of concerns about the effects on climate change of emissions from the end use of the gas transported by the pipeline.

Nowhere does the NGA authorize the Commission to regulate the emissions of downstream gas users, much less establish de facto emissions standards for such users to address climate change through exercise of its authority under Section 7(e) to condition or deny pipeline certificates. Lacking any apparent statutory authority to deny a new pipeline based on GHG emissions by downstream gas users, it appears that the Commission had no obligation under NEPA to gather or consider information on power plant GHG emissions in authorizing the Sabal Trail Pipeline.

Whether authorization to operate the pipeline or authorization to operate the power plants is the legally relevant cause of the GHG emissions from the power plants

Judge Brown’s dissent correctly explains why Public Citizen requires that FERC’s certificate order not be found the “legally relevant” cause of the GHG emissions of the power plants served by the Sabal Trail Pipeline. Instead, as Judge Brown explained, the legally relevant cause is the authorization granted by the Florida Power Plant Siting Board to construct and operate the power plants.

Simply put, the GHG emissions are the byproduct of power plant operations and would not occur separate and apart from the licensing of the power plants by the Florida Power Plant Siting Board. And only the Siting Board, not FERC, has the legal authority to prevent such operations. True, the denial of a FERC certificate could make power plant operations more difficult, but it would not affect the legal authority of the owners to continue operations using other supplies of natural gas or alternative fuels to run the generating equipment.

In these circumstances, the chain of causation as to the Commission’s responsibility is broken, meaning that the GHG emissions cannot be attributed to its action. Accordingly, it was not required to consider the indirect effects of GHG emissions from operation of the power plants in its review of the pipeline certificate application under NEPA.

Lastly, to end where we started, Public Citizen is on point. The issue there was whether the Federal Motor Carrier Safety Administration (FMCSA) was required to consider the environmental effects of increased truck traffic between the U.S. and Mexico in instituting its truck inspection program following President Clinton’s lifting of the moratorium on the entry of Mexican trucks into the US. Because the FMCSA lacked statutory authority categorically to prevent the cross-border operations of Mexican trucks, the court determined that it was not the relevant cause of such environmental effects.

Similarly, in Sabal Trail, the issue is whether FERC must consider the environmental effects from the operation of power plants served by a gas pipeline in authorizing the pipeline. By the reasoning of Public Citizen, because FERC lacks the statutory authority categorically to prevent the operation of such power plants, it cannot be viewed as the legally relevant cause of the environmental effects of such operations.

Conclusion

Reversal of Sabal Trail will help to restore rationality to the NEPA review process for new gas pipelines. The panel majority’s suggestion that a new pipeline “causes” new power plants served by the pipeline reverses the commercial reality of project development, putting the fuel supply cart before the market demand horse as the determinant of new pipeline expansions. The fact is that new pipelines do not get proposed or built without market demand for the gas proposed to be transported.

Reversal will also restore restraint in the conception of FERC’s statutory authority to act in the “public convenience and necessity” under NGA Section 7(e). As Transco suggests, FERC’s authority to affect the end use of gas is limited to actions related to advancing the NGA’s statutory purpose; it does not include the power to control directly or indirectly the GHG emissions of downstream end users of gas. Not that control of such emissions is not important or is in some way affected with the “public interest” — it is just that Congress or other agencies, not FERC, have the authority to regulate them.

Lastly, reversal will restore a sensible understanding of Public Citizen. As Judge Brown points out, where another agency has the authority categorically to prevent the GHG emissions from power plants served by a new pipeline by refusing to issue the license for construction and operation of the power plants, FERC’s more limited action in authorizing a pipeline to serve the power plants cannot be viewed as a legally relevant cause of such emissions.

Such recognition of FERC’s authority as limited will also extend comity to requisite state and federal agency actions in the integrated resource planning of new power generation at the state level and the air permitting process at the state and federal levels for GHG and other emissions from power plant operations.

The original version of this article was published by Law360.  James M. Costan is a partner in Dentons’ energy practice. Jay represents clients on a wide range of public utility and energy matters, including energy transactions and federal and state regulation of the sale and transmission of electricity, natural gas and LNG and the licensing of energy projects.  The opinions expressed are those of the author(s) and do not necessarily reflect the views of the firm, its clients, or Portfolio Media Inc., or any of its or their respective affiliates. This article is for general information purposes and is not intended to be and should not be taken as legal advice.

[1] 541 U.S. 752 (2004) (Public Citizen).

[2] Id. at 767-69.

[3] Sierra Club v. FERC, 827 F.3d 36, 49 (D.C. Cir. 2016) (Freeport).

[4] 15 U.S.C. §§ 717b and 717f.

[5] In mid-2016, FERC environmental staff started preparing “upper-bound” estimates of GHG emissions from downstream gas use to support NEPA reviews. Such estimates assume that the full delivery capacity of the pipeline will be consumed 24/7 for gas-fired power generation.

[6] 867 F.3d 1357 (D.C. Cir. 2017) (Sabal Trail).

[7] Id. at 1373 (citations omitted).

[8] The vacatur and remand had minimal effect on pipeline operations, because most construction had been completed by the time of the D.C. Circuit’s decision in late August 2017. Thereafter, issuance of the mandate was held in abeyance pending completion of the rehearing process in late January and then was stayed until late March, affording FERC sufficient time to complete a supplemental environmental impact statement and issue an order reinstating the Certificate of Public Convenience and Necessity on March 14, 2018. Florida Southeast Connection LLC, 162 FERC ¶ 61,233 (2018) (Order on Remand).

[9] Freeport, supra; Sierra Club v. FERC, 827 F.3d 59 (D.C. Cir. 2016) (Sabine Pass); Earth Reports Inc. v. FERC, 828 F.3d 949 (D.C. Cir. 2016) (Earth Reports).

[10] Sabal Trail, 867 F.3d at 1381 (Judge Brown dissenting), quoting Freeport, 827 F.3d at 47, Sabine Pass, 827 F.3d at 68; and Earth Reports, 828 F.3d at 952.

[11] See 81 Fed. Reg. 51866 (Aug. 5, 2016), Final Guidance for Federal Departments and Agencies on Consideration of Greenhouse Gas Emissions and the Effects of Climate Change in National Environmental Policy Act Reviews, available at https://www.federalregister.gov/documents/2016/08/05/2016-18620/final-guidance-for-federal-departments-and-agencies-on-consideration-of-greenhouse-gas-emissions-and.

[12] See 82 Fed. Reg. 16576 (April 5, 2017), Withdrawal of Final Guidance for Federal Departments and Agencies on Consideration of Greenhouse Gas Emissions and the Effects of Climate Change in National Environmental Policy Act Reviews, available at https://www.federalregister.gov/documents/2017/04/05/2017-06770/withdrawal-of-final-guidance-for-federal-departments-and-agencies-on-consideration-of-greenhouse-gas.

[13] https://www.transportation.gov/sites/dot.gov/files/docs/OMBW020Circular0/020No.0/020A-4.pdf.

[14] Order on Remand at PP 22-51.

[15] Id. at P 29.

[16] Id. (separate dissents of Commissioners LaFleur and Glick).

[17] Sabal Trail, 867 F.3d at 1372, citing Public Citizen, 541 U.S. at 767-68.

[18] Id. at 1373.

[19] E.g., California v. Southland Royalty Co., 436 U.S. 519, 523 (1978); NAACP v. FPC, 425 U.S. 662, 669-70 (1976).

[20] 365 U.S. 1 (1961) (Transco).

[21] Similar concerns about the need to husband gas supply for high priority end uses drove the Commission ‘s directive that pipelines institute end-use curtailment plans to address the nationwide gas shortage in the 1970s. See FPC v. Louisiana Power & Light Co., 406 U.S. 621 (1972).

[22] Transco, 365 U.S. at 10-22.

In any solar PV development in emerging markets (whether in Africa, Latin America or elsewhere) attention is immediately drawn to project revenues. Government or utility tender packages focus on mark-ups to power purchase agreements with the offtaker, the strength of any government support agreement, and the terms of any other credit support. It is not uncommon for a project to be well advanced before the developer turns to the “less exciting” project agreements, with land rights frequently one of the most problematic. The site may be split over dozens of parcels of land (many of which are either stuck in probate or not properly registered), the model form of lease may be unintelligible, or the land sporadically crossed by grazing animals.

Most project stakeholders are either invested and actively interested in the success of the project (e.g. the offtaker), or experienced and sophisticated counterparties (e.g. EPC contractors) – the lessor(s) of land rights may be less equipped to quickly agree the required documents.

Recently we have been working on a number of solar PV projects across Africa in jurisdictions with a limited track record of international project finance. Key areas in which we often find that a landowner’s model form of lease does not provide sufficient protection for the project are listed below. Although we have used terminology that will be familiar to lawyers used to common law systems, the same issues arise – and should ultimately be capable of being resolved – in any legal system.

Term 

The term of the lease should be sufficient to cover the asset life of the project, the term of key approvals (e.g. the generation licence, planning permission) and any decommissioning period (whether after an early termination or expiry of the term).  If asset life is extended then ideally the lessee will also have the option to extend the term of the lease.

Pre-conditions/early obligations 

The lease rental payments are ideally structured in such a manner that they are not payable until all government authorisations and permits and third party consents required for the development and operation of the project have been obtained. If early works are required (e.g. an environmental impact assessment) in order to be granted the necessary permits then the lease will need to cater for this or such works will need to be authorised under a separate lease, lease option or licence.

Easements  

If the route of the cable connecting the project to the grid is not included in the site and the Lessor has rights over the relevant land, the Lessor should grant the Lessee and any third party nominated by it easements over the land as required for the connection of the solar PV plant to the relevant electricity transmission lines. Similar rights may also be needed to allow a route from the site to the public highway for construction and maintenance. For these purposes it is critical to confirm that all local land which may be required for an easement is in the control of the Lessor.

Permitted Use  

The Lessee should be allowed to carry out activities related to, in connection with, or for the purpose of, the design (including site appraisal), construction, operation (including export of power), maintenance and decommissioning (and handover, if applicable) of the solar PV plant.

The site subject to the lease should also be sufficient for project use, i.e. it should cover the solar PV panels, ancillary equipment (including e.g. inverters, CCTV and substations).

Lessor’s covenant  

The Lessor should not do or permit to be done any act which has or may have the effect of reducing or interfering with the capability of the power station to generate its maximum potential of electricity. This may extend to limiting rights to cross the site, including prohibiting the grazing of livestock (to the extent not needed by the Lessee to avoid grass cutting), and providing assurances that neighboring land will not shadow the site (e.g. with new buildings or trees).

To the extent that the Lessor is a government agency it may also be reasonable for it to provide assurances that third parties (e.g. local farmers) will not attempt to access the site, possibly alongside local content and/or community benefit provision to ensure local support.

Pre-existing liabilities 

The Lessor should be liable for, and should indemnify the Lessee against, any pre-existing liabilities associated with the site (e.g. environment liabilities). Where possible the Lessor may also need to do its own property searches and title checks (e.g. to check there is no compulsory purchase order affecting the site).

Termination 

Ideally the Lessor shall either have no right to terminate the lease, or its termination rights should be restricted to failure to pay rents (if not cured within a reasonable period upon notice) – remedies for other breaches by the Lessee should be compensation rather than termination.

Direct Agreement

The Lessor will need to covenant that it will at the request and reasonable cost of the Lessee enter into a direct agreement with any lender providing financing for the project such that the lender has a right to step in and novate before the Lessor exercises its rights under the lease, including any right to terminate the lease (if any) or re-enter the site.

The authors are grateful to Gillian Goldsworthy, Senior Associate in the Real Estate team of Dentons’ London office, for her assistance with this piece

On 27 February 2018 the CJEU issued its judgment in the Western Sahara Campaign case (Case C-266/16). In a short judgment, the court held that the 2006 partnership agreement in the fisheries sector (Fisheries Agreement) and a 2013 protocol to that agreement are inapplicable to the territory of Western Sahara. This was because including Western Sahara within the scope of these agreements would be contrary to “rules of general international law applicable in relations between the EU and Morocco”, particularly the principle of self-determination, and to the UN Convention on the Law of the Sea.

Why are we writing about fish in an Energy blog? As we explained in an earlier post on this case, the international law principles on which it turns are potentially relevant to other agreements about natural resources in areas where local populations claim rights of self-determination.

By interpreting the Fisheries Agreement and the 2013 protocol in this way, the CJEU did not have to determine whether agreements that did deal with resources in Western Sahara would be valid under EU and international law (a question Advocate General Wathelet answered in the negative). Nevertheless, the court’s willingness to invoke and apply international law principles, in particular that of self-determination, is an interesting demonstration of the possible impact of those principles. This may well be of broader importance with regard to agreements that purport to deal with other territories whose populations assert – or may in future assert and gain support for – the right to self-determination.

The court’s judgment relies heavily on its December 2016 judgment in Polisario (Case C-104/16), issued after the request for a preliminary ruling was made in Western Sahara. In Polisario, the court had held that the Euro-Mediterranean “association” agreement (the Association Agreement), as well as a Liberalisation Agreement (concerning liberalisation measures on agricultural and fishery products) had to be interpreted, in accordance with international law, as not applicable to the territory of Western Sahara. The Association Agreement and Liberalisation Agreement were initially also included in the Western Sahara reference, but in light of Polisario those aspects were withdrawn by the English High Court.

When interpreting the scope of the Fisheries Agreement and the 2013 protocol, AG Wathelet had considered that, unlike the agreements addressed in Polisario, the Fisheries Agreement and the 2013 protocol were applicable to Western Sahara and its adjacent waters. He reached this view on several bases, finding it was “manifestly established” that the parties intended the agreements to include Western Sahara, that their subsequent agreements and actions were consistent with this interpretation, and that it was also supported by the genesis of the agreements and previous similar agreements.

The court took a different view (without reference to the AG’s Opinion). First, noting the Fisheries Agreement is stated to be applicable to “the territory of Morocco”, the court held that this concept should be construed as meaning “the geographical area over which the Kingdom of Morocco exercises the fullness of the powers granted to sovereign entities by international law, to the exclusion of any other territory, such as that of Western Sahara”. It stated that, if Western Sahara were to be included within the scope of the agreement, that would be “contrary to certain rules of general international law that are applicable in relations between [the EU and Morocco], namely the principle of self-determination”.

The Fisheries Agreement also refers to “waters falling within the sovereignty or jurisdiction” of Morocco. Referring to the UN Convention on the Law of the Sea, the court noted a coastal state is entitled to exercise sovereignty exclusively over the waters adjacent to its territory and forming part of its territorial sea or exclusive economic zone. Given Western Sahara did not form part of the “territory of Morocco”, the waters adjacent to it equally did not form part of the Moroccan fishing zone referred to in the agreement. A similar conclusion followed with regard to the 2013 protocol’s scope.

While more closely tied to the text of the fisheries agreements than the AG’s Opinion, the judgment suggests the court may seek to arrive at an interpretation of such agreements that respects international law insofar as possible. It is therefore a significant restatement of the importance of international law principles, particularly self-determination, to questions regarding sovereignty over natural resources in occupied territories, and therefore has potential ramifications for international agreements which purport to deal with such resources.

Legislation to impose a price cap on domestic energy bills was introduced into Parliament on 26 February 2018. The accompanying announcements from the Department for Business, Energy and Industrial Strategy (BEIS) indicate that the new regime will be in place by Winter 2018-19. This may feel like the end of a long story, and in a sense it is, but it is also the beginning of a new phase for GB retail energy markets: one in which, for the first time in many years, price regulation is likely to play a significant role in shaping the domestic energy supply market – albeit on an explicitly temporary basis.

How did we get here?

Theresa May singled out energy companies who “punish loyalty with higher prices” in her Conservative Party conference speech in October 2017, and a draft of the Domestic Gas and Electricity (Tariff Cap) Bill was published shortly afterwards. The House of Commons Select Committee that scrutinises the work of BEIS then examined the draft Bill, and produced a broadly favourable report on it in January 2018 (both the Committee’s report and the feedback on the draft Bill that they gathered from a range of stakeholders can be found here).

Going further back, the Bill represents unfinished business from the Competition and Markets Authority (CMA) investigation of the GB energy supply markets that concluded in 2016. The instigation of that investigation by the sector regulator, the Gas and Electricity Markets Authority (Ofgem), almost four years ago, was itself the culmination of years of public debate about energy prices and the allegedly excessive profits made by GB utilities.

The CMA found “an overarching feature of weak [domestic] customer response which, in turn, gives suppliers a position of unilateral market power concerning their inactive customer base which they are able to exploit through their pricing policies or otherwise”. In particular, huge numbers of customers of the “Big 6” suppliers who showed little interest in or awareness of the possibility of shopping around for a better deal, found themselves on high “standard variable tariffs” (SVTs). As a result, the CMA identified “customer detriment associated with high prices” of “about £1.4 billion a year on average for the period 2012 to 2015 with an upwards trend”. However, the CMA panel that conducted the investigation decided (by a 4:1 majority) not to impose a price cap to address the harm to SVT customers generally – although they did decide in favour of a price cap for customers supplied through a prepayment meter (PPM). For others, the majority of the panel concluded that measures designed to increase the chances of those on SVTs signing up for a better deal were enough.

The CMA’s conclusions failed to satisfy the public and political appetite for dramatic regulatory action. This was partly because in the period following the CMA’s report, average Big 6 SVTs showed little or no sign of decreasing, while their cheapest tariffs seemed to be increasing, and partly because many of those on high SVTs were also economically or digitally disadvantaged. Poorer customers appeared to be subsidising offers of more competitive prices to the more affluent – or perhaps the larger suppliers were just not very efficient. As the impact assessment published alongside the Bill (a more vigorous and forcefully expressed document than many of its kind) puts it: “a majority of people lose out, with disproportionate impact on the vulnerable”. These – and other, more overtly political reasons – made the move towards a cap unstoppable, notwithstanding the counter-argument that protecting those who didn’t shop around would be likely to result in higher prices for those who did, undermining the development of a properly competitive supply market in the longer term. Interestingly, during the course of the Select Committee’s inquiry, more industry voices than might previously have been expected came out in favour of a cap. (For a sober economist’s justification of the cap, see the evidence given by Professor Martin Cave, who was the dissenting member of the original CMA panel, to the Select Committee.) The charts and table below, published (or derived from data published) on Ofgem’s website in December 2017, tell their own story.

Where exactly are we now?

The Bill follows the text of the draft Bill closely. The table below sets out the key features of the tariff cap regime in the draft Bill and the Bill as introduced, and how the substantive changes from the draft correspond to recommendations made by the Select Committee in its report.

It will be immediately obvious from the above summary that the Bill leaves Ofgem with the hard work of actually setting the cap and drafting the standard licence conditions that will give it effect, and balancing a number of potentially conflicting objectives as it does so. From first publication of proposed tariff cap conditions to their entry into force is likely to take at least 4 months (allowing for one month to consider feedback from the initial consultation). Consultation that takes place before the Bill receives Royal Assent is permitted.

Accordingly, having the new regime in place by Winter 2018-19 looks achievable. Even with Parliamentary timetables dominated by Brexit legislation, it should not be too difficult to find the relatively short amount of time required to debate this Bill, given the broad consensus behind the cap.

Will Parliament be happy to leave it to Ofgem to come up with the all-important numbers? It should: Ofgem is an independent economic regulator (whose independence from political control remains, at least for the moment, guaranteed by EU law). The potential to disrupt delivery of the cap may lie rather with the energy suppliers themselves, or anyone else who may seek to challenge Ofgem’s eventual decision on the level of the cap or other related licence provisions in the courts.

Some suppliers tried to persuade the Select Committee that Ofgem’s decisions on the cap should be subject to a right of appeal to the CMA, rather than only being challengeable by way of judicial review by a court. Their representations unsurprisingly emphasised the benefits of the CMA’s expertise and faster-track procedures more than what they may have perceived as the higher threshold that has to be satisfied for a court to entertain a challenge by way of judicial review or the narrower administrative law grounds on which a court can determine that a decision that is subject to judicial review is sufficiently flawed to be struck down and remitted to the decision-maker (here Ofgem) to reconsider.

In a number of ways, the legislation has been constructed so as to reduce the risk of a successful challenge: Ofgem has been given a fairly clear (if by no means simple) job to do in a particular context, and a court may well be slow to second-guess e.g. the regulator’s judgments when prioritising the competing objectives it must bear in mind when setting the tariff cap (see above).  But even if JR remains the only route for a challenge in the Bill as enacted, the possibility that a challenge will be launched cannot be ruled out, since if the calculations made by the CMA and others are even half right, there is a lot of money at stake here for some suppliers.

What next?

Whether or not Ofgem has to defend any of its tariff cap decisions in court, this new function is going to be a significant item of work for the regulator over at least the next two and a half – and possibly as many as five – years. This is likely to have a number of consequences.

It is hard to see how Ofgem can make judgments about e.g. how “to ensure that holders of supply licences who operate efficiently are able to finance activities authorised by the licence” without potentially routinely engaging with those suppliers on the commercial costs of their businesses in a degree of detail, and level of intensity, to which they are unaccustomed as part of “business as usual” activity. Consideration of the efficient costs of operation is normally what Ofgem does in relation to the natural monopoly businesses of transmission and distribution, not the competitive business of supply (although of course, it is a founding premise of the tariff cap regime that competition is not working properly in the domestic supply sector). Inevitably, individual suppliers will assert that their businesses do not fit particular assumptions Ofgem may make: yet the legislation explicitly precludes making “different provision for different holders of supply licences”.

Perhaps the only way to avoid this level of regulatory attention would be for suppliers unilaterally to follow in the direction proposed by Centrica during the course of the Select Committee’s inquiry as an alternative to a tariff cap, by not having SVTs or default tariffs; but that in itself would not be without its challenges, not least from a customer engagement perspective.

The partial re-regulation of domestic tariffs is by no means the only significant regulatory development that will occur in the energy supply sector over the period when the tariff cap is in force. Government and others have been at pains to stress that changes such as the rollout of smart meters and the introduction of market-wide half-hourly settlement, that could enhance competition in energy supply markets, are not to be seen as reasons not to have the cap. Recent history suggests that the number of such obligations on suppliers only moves in one direction: up. And unlike in the case of “pass-through” costs such as network operator charges, obligations like market-wide half-hourly settlement may be inescapable, but there is likely to be plenty of scope for argument over how much they should cost suppliers to comply, against a background of reduced SVT revenues. Meanwhile, Ofgem has opened up the whole question of the place of suppliers in the regulatory architecture with a call for evidence (November 2017) on the future of supply market arrangements.

Whatever happens, there is a strong chance that Ofgem’s performance, in the eyes of most politicians and the public, will be seen as overwhelmingly focused through the lens of the tariff cap and its impact on SVT customers’ bills. The next few years will not be easy either for the regulators or the regulated.

UPDATE – 6 MARCH 2018

Ofgem has published a letter setting out its timetable for developing the tariff cap condition, as well as its other ongoing work to protect vulnerable customers from overcharging.  A series of working papers is promised over the next few months, with draft licence conditions being issued in August 2018 and the tariff cap being in force by the end of the year – subject to the progress of the Bill.

UPDATES – OFGEM WORKING PAPERS

12 March 2018: Ofgem has published its first working paper on how it will go about setting the tariff cap, drawing heavily on earlier work in the context of the cap for the protection of vulnerable consumers.

28 March 2018: Ofgem has published its second tariff cap working paper.  This deals with the possible use of a “market basket” of competitive tariffs to set or adjust the tariff cap – and provisionally concludes that such an approach is not one to follow here.

9 April 2018: Ofgem has published its third tariff cap working paper.  This deals with “headroom” – i.e. “an amount above the efficient level of costs, which could be used to enable competition to co-exist with the cap”.

19 April 2018: Ofgem has published two more tariff cap working papers.  The fourth working paper is concerned with how the tariff cap will take account of the economic and social policy costs faced by suppliers.  The fifth working paper considers in more detail one of the reference price methodologies first outlined in the second working paper.

UPDATE – CONSULTATION ISSUED ON 25 MAY 2018

Today Ofgem published a consultation consisting of an “overview” and 14 Appendices (altogether more than 400 pages).  Ofgem explains that the consultation does not propose at what level the cap should be, but explains how it might go about setting the cap.  Once the Bill has received Royal Assent, a further, statutory consultation is expected to be issued in August 2018, enabling the cap to “come into force by the end of this year so that it is place to provide protection to consumers this winter”.

In a landmark opinion, Advocate General Wathelet (the AG) of the European Court of Justice (CJEU) has invited the court to conclude that fisheries agreements between the EU and Morocco are in violation of the international law principle of self-determination, and therefore invalid under EU law. It comes as a clear reminder that EU institutions must respect international law principles binding upon them when entering into international agreements.

If the court follows the AG’s lead, the case could have ramifications for other territories whose populations may claim rights to self-determination, such as Catalonia and the Kurdistan Region of Iraq, and for the validity under international law of agreements with the states occupying those territories.

Background

The territory of Western Sahara is occupied by Morocco, a situation widely considered to breach the principles of international law entitling peoples to self-determination. The UN recognises Western Sahara as a non-self-governing territory occupied by Morocco.

The reference to the CJEU emanates from an English court case brought by Western Sahara Campaign UK, an NGO aiming to support the recognition of the Western Saharan people’s right to self-determination. It argues that the EU-Morocco agreements (insofar as they purport to apply to Western Sahara) violate that right and so are contrary to the general principles of EU law and to Article 3(5) of the Treaty on European Union, under which the EU is required to respect international law. Under the agreements, the EU paid Morocco for access to waters including Western Sahara’s.

As the measures in question related to the validity of EU law, the English court referred the case to the CJEU, itself characterising Morocco’s presence in Western Sahara as a “continued occupation”.

The Advocate General’s Conclusions

Article 3(5) of the Lisbon Treaty states that the EU will respect the principles contained in the UN Charter, of which Article 1 sets out the principle of self-determination of peoples, while Article 73 promotes self-government. Yet the EU fisheries agreements with Morocco purport to deal with waters off the coast of Western Sahara.

The AG considered, first, that, where the relevant principles of international law (here, both treaty and customary law forming part of general international law) are “unconditional and sufficiently precise”, a claimant can rely on them to challenge EU actions. He noted that the right of self-determination, because it formed part of the law of human rights, was not subject to these requirements, but in any event met them. Similarly, (i) the principle of permanent sovereignty over natural resources and (ii) the rules of international humanitarian law applicable to the exploitation of Western Sahara’s natural resources were also sufficiently precise and unconditional to be invoked by the NGO.

Examining whether the fisheries agreements breached the international legal principles in play, the AG examined in some detail the historical background to Morocco’s occupation. An advisory opinion issued by the International Court of Justice in 1975 had stated that Western Sahara was not a “territory belonging to no one” at the time of its earlier occupation by Spain. A referendum on self-determination under UN auspices was thus envisaged, but Morocco considered this unnecessary on the basis the population had already de facto determined themselves in favour of returning the territory to Morocco. The AG, however, concluded that Western Sahara was integrated within Morocco “without the people of the territory having freely expressed its will in that respect”.

Because the fisheries agreements with Morocco make no exception for Western Sahara, the AG considered the EU is in breach of its obligation not to recognise an illegal situation resulting from the breach of the right to self-determination, and to refrain from rendering aid or assistance in maintaining that situation.

The AG also emphasised that as “Western Sahara is a non-self-governing territory in the course of being decolonised … the exploitation of its natural wealth comes under Article 73 of the United Nations Charter and the customary principle of permanent sovereignty over natural resources”. He found that the fisheries agreements did not contain the necessary legal safeguards to ensure that the natural resources were used for the benefit of the people of Western Sahara. On that basis also, in his view the provisions of the agreements were not compatible with EU or international law.

Impact of the opinion

It remains to be seen whether the CJEU will follow the AG’s opinion. The opinion is nevertheless significant, not only for the Western Saharan situation. It is a robust restatement of the importance of the right to self-determination, and of the consequences that may flow where it is held to be breached, as well as of the importance of the protection of natural resources in occupied territories.

The arguments set out in this opinion will undoubtedly influence independence discourse in territories as disparate as Catalonia and Kurdistan, and the CJEU’s decision, expected at the end of February, will be keenly anticipated.

The reaffirmation of the principle of permanent sovereignty over natural resources is of particular interest regarding the Kurdistan Region of Iraq, where the exploitation of natural resources has been a contentious issue for decades. Kurdistan’s status as a semi-autonomous region with the right to manage its oil resources is enshrined in Iraq’s 2005 Constitution, and the Region has not declared independence.  Although not analogous with the Western Sahara situation, one can envisage questions being raised as to the compatibility with international law of any agreements which states may have or may enter into with the Iraqi federal government that relate in some way to resources in Kurdistan territory.  It may well be argued that these too fail to respect the Kurdish people’s sovereignty over their natural resources and/or their right to self-determination (as well as potentially breaching the constitutional provisions).  The AG’s comments as to the unconditional and precise nature of these principles paves the way for challenges before national courts on the basis that these are binding upon states, which may not enter into agreements that disregard them.

Case C-266/16 Western Sahara Campaign, Opinion of Advocate General Wathelet, 10 January 2018

The authors are grateful to Seonaid Stevenson, a trainee solicitor at Dentons, for her assistance with this piece.

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.

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.

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.

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).

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.

• The centrepiece was the BEIS / Ofgem response to the joint “call for evidence” on a “smart, flexible energy system” that they issued in November 2016 (CFE). As well as the response itself (the Response), there is a “smart systems and flexibility plan” (the Plan), ending with a helpful summary of the current state of play and next steps.
• Alongside the Response and the Plan, BEIS publicised some significant funding initiatives for battery technology under the umbrella of the government’s industrial strategy, on which the Secretary of State for BEIS, Greg Clark, gave a speech in Birmingham.
• The final contribution from BEIS was the innocuously titled “Capacity Market: improving the Framework” (the CM Consultation).
• Ofgem set out its “views on the design of arrangements to accommodate independent aggregators in energy markets” (the IDA policy paper), supported by an “assessment of the economic value of demand-side participation in the Balancing Mechanism and an evaluation of options to improve access” from Charles River Associates (the CRA Report).
• At the same time, Ofgem published work by Cambridge Economic Policy Associates on the distributional impacts of time of use tariffs (the CEPA Report).
• Finally, an Ofgem update and a launch statement and other documents kicked off a Significant Code Review on mandatory half hourly metering (the SCR Papers).

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

• Ofgem’s “Impact Assessment and Decision on industry proposals…to change electricity transmission charging arrangements for Embedded Generators” (the TDR Decision);
• Ofgem’s consultation on a targeted review of network charging (the TCR Consultation);
• National Grid’s consultation on the evolution of balancing services markets in GB, entitled “System Needs and Product Strategy” (SNaPS) and available here;
• National Grid’s “Future Energy Scenarios 2017” document (FES 2017), available here.
• The 2017 Report to Parliament – Meeting Carbon Budgets: Closing the policy gap from the Committee on Climate Change (CCC), as part of the supporting research to which the CCC published a Roadmap for Flexibility Services to 2030, prepared by Pöyry and Imperial College London (the Pöyry / Imperial Report).

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.

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.

• 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.