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Must FERC weigh GHG emissions in pipeline reviews?

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.

 

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Must FERC weigh GHG emissions in pipeline reviews?

CJEU rules on validity of natural resources agreements

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.

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CJEU rules on validity of natural resources agreements

EU Advocate General restates importance of self-determination to validity of natural resources agreements

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.

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EU Advocate General restates importance of self-determination to validity of natural resources agreements

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

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

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

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

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

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

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

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

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

Changes to the Mining Act 2010

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

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

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

Natural Wealth and Resources (Permanent Sovereignty) Act 2017

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

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

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

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

Impact and potential claims against Tanzania

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

New National Oil Companies: 5 things to think about

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

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

State participation

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

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

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

Role of the NOC

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

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

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

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

Financing

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

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

Governance

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

Staffing and training

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

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

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New National Oil Companies: 5 things to think about

Extractives companies’ human rights records ranked in Benchmark study

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

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

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

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

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

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

Results skew significantly to the lower bands

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

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

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

Gap between policies and performance

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

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

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

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

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

Conclusion

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

Extractives companies’ human rights records ranked in Benchmark study

Iran Issues Pre-qualification for Upstream Tenders

Iran is said to be targeting an increase in oil production from 3.85 to 4 million barrels per day by the end of 2016. Iran is also hoping to start export of a new heavy oil, called West Karun, and which is expected to compete with Iraq’s Basra Heavy crude, which has gained a significant market with US and Asian refiners since its launch in 2015.

Iran’s new upstream contract, the Iran Petroleum Contract (IPC), was delayed by parliamentary amendments but is now scheduled for launch in January 2017. The State-owned National Iranian Oil Company (NIOC) has already signed up an IPC with local firm, Persia Oil and Gas Development Company, which is one of eight Iranian contractors authorised to team up with international joint venture partners. Whilst Iran’s production costs may be rock bottom, foreign investment (and currently foreign exchange) is needed to deliver scale and speed of development.

NIOC (on behalf of Iran’s Ministry of Petroleum) has published its “Pre-qualification Questionnaire for Exploration and Production Oil and Gas Companies,” to be completed by 19.11.16 in order for NIOC to publish a “Long List” of qualified applicants on 7.12.16. This list is intended to be valid for two years as a pre-requisite for participating in upstream tenders. NIOC intends to then invite a short-list of qualified applicants from the long list, depending on project type (Short List).

Long List applicants will be scored according to typical technical and financial criteria but with some additional emphasis seemingly echoing NIOC’s objectives, including “scale” and “internationality”. The greatest score (25%) is allocated under the heading “Reliability” to credit ratings. Whilst it seems unusual to delegate financial capability diligence simply to reliance on a third party credit rating agencies, it does reduce the internal resources needed to sift financial data. That said, a number of those with credit ratings (and by definition, public equity or debt) may not yet have the appetite for Iranian investments, whilst those privately funded entrepreneurs and companies with strong balance sheets, may not seemingly participate, assuming that NIOC doesn’t choose to deal with non-compliant applicants.

“Scale” is assessed in terms of production rates and wells drilled over the last three years, with technical capability assessed over the same period and broken down into experience type including conventional and fractured operations, and improved and enhanced oil recovery. Choosing the last three years of oil pricing where some operations may be moth-balled etc. may be significant, but given that it is unclear as to how applicants may be assessed competitively, this is perhaps academic, provided a minimum threshold is demonstrated.

“Internationality” is judged against an “applicant’s headquarters’ business and/or registration place” which is seemingly designed to allow some flexibility to avoid being disadvantaged by a tax headquarters and otherwise to make the best of an organisation’s international operations, and possibly from more than one headquarters, if one takes a literal interpretation of the punctuation.

For the purposes of the Short List, applicants are “requested” to specify their “priorities and interested fields” and whether they wish to act as operator or non-operator. This clearly allows room for judgement versus competitors as to whether applicants would wish to share their commercial position at the outset.

It seems likely that most of the credit-rated applicants who would qualify, are already known to NIOC / have registered their interest more or less formally. The collation of extra data should enable NIOC to take into account preferences, but to grade applicants and to allocate tender opportunities in a manner perceived as transparent and which tends to avoid the dominance of any particular constituencies. Whilst the application of such process could be regarded as a short-term disincentive to some with an incumbent position, it could also be used to justify the favouring of incumbents, safe in the knowledge that the market was tested first. Otherwise, such process is likely to be regarded more generally as a welcome codification of what is expected to be a hotly-contested new market for lower cost developments.

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Iran Issues Pre-qualification for Upstream Tenders

Energy Brexit: initial thoughts

In the energy sector, as elsewhere, it is far too early to give any definitive view on the effects of the UK electorate’s vote to leave the EU, or to offer a comprehensive analysis of the merits of the options now facing the UK Government. Here we offer some initial thoughts on these subjects.  Further posts will follow in the coming weeks, months and years.  No doubt some of what we say here and subsequently will turn out in retrospect to have been wide of the mark, but this is an occupational hazard of providing current commentary in a fast moving area.

This is a rather long post. We hope that those that follow will be shorter.

  • We begin by looking briefly at the relationship between EU and UK energy policy to date.
  • We then consider the EEA as a possible model for developing that relationship post Brexit.
  • After glancing at the anomalous position of nuclear power, we move on to consider how the UK could reinvent parts of its energy policy if it were free of EU / EEA law constraints.

Overall, our conclusions are not surprising.

  • EU and UK energy policies are in many ways closely aligned.  Yet EU membership undoubtedly constrains UK policy choices in a way that some find detrimental to UK business and/or consumer interests.
  • Most of those constraints would remain if the UK were to leave the EU but remain a member of the European Economic Area (EEA).  But even this limited change would bring with it a need, or at least the opportunity, to re-evaluate quite a large number of (in some cases fairly significant) pieces of law and regulation.
  • If the UK were to seek its fortune outside both the EU and the EEA, Government would be able, at least from a legal point of view, to introduce some very radical changes to current energy policies – and in some cases it might well be tempted to do so (although it would still face some international law constraints and would no doubt need to factor in the effect of doing so on the terms that could be negotiated with other states and the tariffs that might be imposed as a consequence).
  • There will be no substitute, as energy Brexit unfolds, for keeping a close eye on what is proposed in relation to each policy area (even if it is not presented directly as a response to Brexit).  Even if “this country has had enough of experts”, Government will need clear advice from the energy industry more than ever over the next few years.

Putting things in perspective

This Blog will focus on how Brexit affects energy law and policy. We recognise that for many with interests in the UK energy sector, the most immediate concerns may well be about other aspects of Brexit: for example, how it affects their willingness to invest in Sterling assets; whether there will be positive adjustments to the UK’s tax regime; how it could affect the employment status of their non-British workers; or how the post-referendum ferment will simply delay key Government and business decisions.  We are happy to discuss any of those issues with you, but for now, an analysis of Brexit in areas of law and policy specific to the energy sector seems as good a place as any to start to appreciate the complexities opened up by the result of the 23 June 2016 referendum.

Common ground and policy continuity?

A few days after the referendum, Amber Rudd, then Secretary of State for Energy and Climate Change, began a speech by saying: “To be clear, Britain will leave the EU”, and then went on to itemise at some length why this should not mean any big shifts in UK energy policy.  As she put it: “the challenges [securing our energy supply, keeping bills low and building a low carbon energy infrastructure] remain the same.  Our commitment also remains the same”.

It is not hard to find examples of the fundamental objectives of EU and UK policy being aligned.

  • The UK has been a leading advocate since the 1980s of the kind of liberalisation of electricity and gas markets that is now fundamental to the EU’s internal energy market rules.
  • EU and UK policy has favoured open and transparent markets in which free competition is promoted as a way of delivering lower prices and other benefits to consumers.
  • Both the EU and UK have sought to control the adverse environmental impacts of energy industry activities.  More recently, the threat of dangerous climate change has given added impetus to efforts to promote decarbonisation, renewables and energy efficiency.
  • In practical terms, the UK has been the most open of EU markets to the ownership of energy sector assets by foreign companies (although the most notable cases have involved acquisition rather than simply EU companies relying on freedom of establishment).
  • The UK can claim to have been promoting electricity generation from renewable sources for some time before the EU had an effective renewables policy.
  • The UK, having adopted the first national scheme of “legally binding” greenhouse gas emissions targets in the Climate Change Act 2008, played a leading role in developing the EU’s position on the CoP21 agreement reached in Paris in December 2015.

The first tangible indication of post-Brexit policy continuity came with the Government’s announcement on 30 June 2016 that it would implement the independent Committee on Climate Change’s recommendation for the level of the Fifth Carbon Budget, covering the period 2028-2032.  (It would perhaps be uncharitable, in the circumstances, to suggest that on a strict view of the Climate Change Act 2008, the relevant Order should have been debated by Parliament and made by 30 June 2016, and not simply laid before Parliament for approval by that date.)

Sources of irritation

Broad principles are one thing and the detail of regulation is another. There are plenty of examples of tension between EU energy sector policy and regulation and UK preferences.  We are not aware of any poll data on how many of those who voted to leave the EU had energy policy on their minds, but there have certainly been times when EU regulation has not developed as the UK Government would have wished.  At other times, the existence of EU law requirements of one kind or another as a constraint on freedom of action by the UK authorities has given some ammunition to those who argue that as it is a national Government’s function to “keep the lights on” (at a reasonable price) and choose the fuel mix, the EU’s energy policies have impermissibly eroded an aspect of UK sovereignty.

  • The UK was a strong proponent of the enlargement of the EU into Central and Eastern Europe, but the accession to the EU of countries such as Poland may well have helped to ensure that the EU Emissions Trading Scheme (EU ETS) has never set as tight a cap on emissions, and therefore as high a price on CO2 emissions, as the UK would like in order to drive decarbonisation of the power sector and industrial energy use.
  • Various EU rules on environmental, state aid, renewables and single market matters can arguably be blamed for fatally increasing the power costs of UK energy intensive industries to a point where the UK has hardly any steel or aluminium producers left.
  • EU Directives on industrial (non-CO2) pollution have driven a cycle of closures of coal-fired generating stations which some would see as having prematurely diminished the UK’s security of energy supply and limited its ability to benefit from cheap US coal prices.
  • Opposition to the granting of planning permission for onshore wind farms in many parts of the UK (or at least England and Wales) was probably materially intensified by developers arguing (supported by Labour Government policy) that planning authorities were under a duty to grant permission so as to facilitate the achievement of Renewables Directive targets.
  • Since the UK (unlike Germany, for instance) has no domestic PV manufacturing interests that it wishes to protect, it would prefer not to pursue the current EU policy of imposing a “minimum import price” on Chinese solar panels (thus helping the UK solar industry to come to terms more quickly with the Government’s decision to curtail subsidies to it).
  • Generally, as the body of EU energy regulation has grown in strength and reach, and as UK Government energy policy has involved increasing amounts of intervention in the market (for example so as to promote low carbon generation), EU law has become a significant constraint on how the UK Government achieves its objectives, even when those objectives are consistent with EU objectives.
  • The tension between EU and UK policies can be seen in the case of Capacity Markets.  The European Commission, which has no voters worried about “the lights going out” to answer to, sees these as essentially unwarranted interferences with market mechanisms which threaten artificially to partition the EU single market for electricity.  DG Competition is reviewing Capacity Markets in a number of EU Member States (not including the UK, whose regime it has approved under state aid rules already).  It is ironic that the Commission’s work at several points highlights the UK’s approach as a model of good practice, when many in the UK consider that its Capacity Market has failed in some of its primary objectives, and partly blame decisions taken to secure clearance from the Commission for the regime’s defects.
  • There is also a lingering suspicion that the UK sometimes makes matters worse for itself by taking a more conscientious approach to the implementation of EU law requirements (even those it does not entirely support) than some other Member States.

No doubt the UK is not the only Member State dissatisfied with aspects of EU energy policy and regulation. But for now, no other EU Member State has set itself on the course of withdrawal from the EU.

It is unlikely that energy policy will determine the UK Government’s Brexit implementation strategy. However, focusing just on this one area, if one assumes that the UK will not radically change the overall direction of its energy policies and will remain committed to tackling all three challenges of the familiar security-decarbonisation-affordability trilemma referred to by Amber Rudd, how might the UK Government and others seek to maximise the opportunities opened up by Brexit?

Back to the future?

We must begin by considering the “EEA option(s)” – putting to one side, for present purposes, the question of whether a way can be found to preserve existing free trade arrangements with the EU without continuing to allow all EEA nationals their current rights of free movement into the UK.

In 1972 the UK left the European Free Trade Association (EFTA) to join the European Economic Community, forerunner of the EU.  Subsequently, the remaining members of EFTA entered into bilateral trade agreements with the EU, many joining the EU.  The European Economic Area (EEA) was formed by an agreement concluded in 1993 between the European Community (not yet officially the EU), its Member States, and three of the four remaining EFTA states (Norway, Iceland, Liechtenstein – Switzerland remained outside the EEA).  What would it mean for the UK to leave the EU and become a party to the EEA as an EFTA state once more?

First, consider the other members of the club that the UK would be (re-)joining.

  • In 2015, the UK had a population of 65 million and a nominal GDP of $2,849 billion.  The four current EFTA states had a combined population of less than 14 million (more than half of which is made up by non-EEA Switzerland) and GDP of just over $1,000 billion (of which, again, Switzerland accounted for more than half).
  • In 1992, Switzerland voted by a 0.3% margin not to join the EEA in 1992 and Norway voted by a 2.8% margin not to join the EU.  Iceland dropped its bid to join the EU in 2015: fisheries policy (not covered by the EEA Agreement) was a sticking point, not for the first time.
  • Norway is the EU’s second largest supplier of both oil and natural gas.  It accounts for almost 30% of EU gas imports, as compared with Russia’s 39%.  But virtually all of its electricity is generated from renewable sources (overwhelmingly hydropower).
  • Market structures in the energy sectors of EFTA States are somewhat different from those in the UK.  Norway and Iceland are both characterised by a degree of state ownership than has not been familiar in the UK for many years.  Switzerland’s power sector is highly fragmented.
  • Both Norway and Iceland could export considerable amounts of power via interconnectors.  For potential importers such as the UK, this is attractive because, unusually, most of these countries’ renewable power output, being hydropower or geothermal, is “despatchable” on demand rather than being a “variable” source of supply like wind or solar power.
  • Switzerland has electricity interconnection capacity approximately equal to its peak power demand.  It exports and imports power equivalent to more than half its total consumption to and from its EU Member State neighbours.  The UK is making progress on interconnection, but is still some way from meeting a 2005 EU target of 10% of installed capacity.
  • Norway, although not subject to the EU legislation that underpins the EU’s electricity cross-border “market coupling” regime, nevertheless manages to participate in it.  (Note that Switzerland is reported to have been excluded from the same mechanism after its referendum vote against “mass migration” – i.e. free movement of people.)

Next, consider how the EEA works legally.

  • The EEA Agreement sets out the basic “free movement” rules as they were in the EC Treaty in 1993 so as to create an extended free trade area.  This does not extend to all the goods covered by the EU single market, and it only applies to products originating in the EEA.  Most importantly, it does not include the provisions which create the EU customs union, so that the EFTA states are not obliged to maintain the same tariffs in respect of products from third countries as the EU does under its “common commercial policy”.
  • If the UK were within the EEA, other EEA states would not be able to discriminate against energy products which the UK exported, provided that they “originated” in the UK.  That would cover, for example, power generated in the UK and exported over an interconnector. The implications of the rules on origination for trading in oil and gas extracted in non-EEA countries but entering the EEA in the UK would need to be considered (along with applicable WTO rules) if the EU were to raise its tariffs for those products from its current level of zero.
  • Most EU legislation is comprised of Directives and Regulations.  These are proposed by the European Commission, negotiated by representatives of the EU Member States (the European Council), with amendments typically being proposed in parallel by the European Parliament and a political compromise being reached between Council, Parliament and Commission on a final text in the so-called “trilogue” procedure.   Once they have been adopted in this way, Regulations in principle do not require national implementing measures, because they are directly applicable throughout the EU, whereas Directives generally require Member States to enact specific legislation to implement them.
  • EEA law is meant to correspond to EU law within the scope of the EEA Agreement.  All EEA law originates from the EU legislative process described above and the EFTA States only have the right to be consulted on its terms – they have no representation in the European Council or Parliament, and they have no vote on the final text.
  • However, EU legislation does not have any effect in the EFTA States just by being adopted at EU level.  Once an EU Directive or Regulation has been adopted, it must first be determined whether it falls within the scope of the EEA Agreement.  The EFTA Secretariat leads this work, which is not always straightforward.  For example, the EEA Agreement essentially takes (parts of) the EC Treaty as it was after the Single European Act but before the Maastricht, Nice Amsterdam or Lisbon Treaties.  As such, it does not include a provision equivalent to Article 194 TFEU, which has formed the legislative base for a number of measures in the energy sector.  This immediately makes it harder to determine whether any Article 194-based measure is within EEA scope.
  • If a measure is in scope, Article 102 of the EEA Agreement states that it is to be adopted by the EEA Joint Committee “to guarantee the legal security and homogeneity of the EEA”.  In most cases, measures are adopted in their entirety with no substantive amendments.  However, amendments are possible if it is agreed that they do not affect “the good functioning” of the EEA Agreement.  Adoption, and any amendment, is recorded by making entries in the various topic-based Annexes to the EEA Agreement.  Energy is dealt with in Annex IV (which can be compared with the European Commission’s list of measures covered by its DG Energy), but Annex XX (Environment) and others are also relevant.  There is a helpful online facility for tracking what point a given piece of EU legislation has reached in the process of EEA adoption – or otherwise.
  • The EEA Joint Committee takes decisions “by agreement between the [EU], on the one hand, and the EFTA States speaking with one voice, on the other”.  Article 102 is in effect an “agreement to agree”.  Absent such agreement, it allows the relevant part of the relevant Annex to the EEA Agreement to be “suspended” – so far, apparently, an unused mechanism.
  • In order for an adopted measure to take effect within the laws of all the individual EFTA States, national implementing legislation is required.  Note that this is the case regardless of whether the original EU measure is a Directive or a Regulation, since Norway and Iceland apparently could not accept, as a matter of constitutional law, a process by which Regulations automatically take effect in their jurisdictions without national implementation (and the Norwegian and Icelandic legislatures do not appear to have been able to find a solution to this problem along the lines of the UK’s s.2(1) European Communities Act 1972).
  • Compliance with EEA laws that are brought into force in this way is enforced both by national courts in EFTA States and by the EFTA Surveillance Authority (ESA), whose position is analogous to that of the European Commission in that respect.  Amongst other things, the ESA performs the function of determining whether cases of state aid are compatible with the EEA Agreement just as the Commission does in respect of EU law.
  • Finally, the EFTA Court is there to hear cases brought by EFTA States against each other or by or against the ESA as regards the application of the EEA Agreement.  As in the case of EU law, failure by a Member State to implement EEA requirements can result in infringement proceedings before the Court.
  • Although the EEA legislative process is somewhat slower than that of the EU (see below), both the ESA and the EFTA Court tend to process cases more quickly than their EU counterparts (but then, so far, they have also had notably lighter workloads).

The EEA Agreement in action

The way in which some familiar pieces of EU legislation have been processed for the purposes of the EEA Agreement provides some interesting examples of how the EEA works in practice.

It can take a long time to adopt some measures.

  • The EU adopted its “Third Package” of electricity and gas market liberalisation measures in 2009 and they came into force in the EU in 2011: the process of EEA adoption has not progressed beyond submission of a draft decision to the European Commission (in 2013).
  • The REMIT Regulation on energy market transparency, adopted and in force in the EU since 2011 is still “under scrutiny” by EFTA.  Neither of the general Directives on energy efficiency, 2006/32/EC and 2012/27/EU, yet appears close to being adopted.
  • The EU Emissions Trading Scheme Directive of 2003 and the Industrial Emissions Directive of 2010 had to wait until 2007 and 2015 respectively for adoption into the EEA Agreement.  However, in the latter case, the process could at least package the adoption of the Directive itself with that of a large number of implementing measures taken under it at EU level.

Other EU energy measures have been considered to fall outside the scope of the EEA.

  • The Directives on security of gas or oil supply, such as the Oil Stocking Directive, 2009/119/EC do not form part of the EEA Agreement.
  • Since tax harmonisation falls outside the scope of the EEA Agreement, the Energy Products Taxation Directive has not been adopted by the EFTA States.
  • The EU’s continuing sanctions measures against Iran (those adopted “in view of the human rights situation in Iran, support for terrorism and other grounds”), like other EU Common Foreign and Security Policy measures, are not part of EEA law.

How flexible is the application of EU law in the EEA?

  • In some cases, adoption of EU measures has included significant derogations, such as for Iceland in relation to the energy performance of buildings and geothermal co-generation, and for Liechtenstein in relation to rules on renewable energy.  Derogations and other amendments involve a more protracted process of approval on the EU side, since they are a matter for the Council and not just for the Commission.
  • There have been a number of ESA proceedings in respect of alleged state aid of various kinds.  As is the case with European Commission decisions, these sometimes exhibit rigorous application of economic principles, and sometimes, to a cynical eye, could be thought to carry a slight hint of political expediency.

How would the UK fit in to the EEA / EFTA energy sector?

If the UK were to become an EFTA / EEA State tomorrow, it would find itself, by virtue of its generally fairly scrupulous past compliance with its obligations as an EU Member State, considerably ahead of its EFTA peers in implementing EEA law.

As in every other area of policy, legislating for Brexit at UK level involves, at least in theory, a large number of choices. Any domestic legislation that implements a Directive could in principle either be left as it is, amended or repealed.  The Government would also have to decide whether to legislate, if only on a transitional basis, to preserve (with or without amendment) the application of each EU Regulation that currently has effect in the UK without any implementing domestic legislation.

In some cases (such as the Regulations which impose the minimum import price for Chinese solar panels in the UK), allowing such Regulations to cease to have effect on Brexit would be an easy choice. In other cases (for example REMIT, or the various Regulations made under the Energy-using Products Directive that impose labelling requirements on electrical goods based on their energy efficiency), there could be a strong case for preserving their effect as a matter of domestic law even as they ceased to apply as a matter of EU law.

But for a Government of Ministers who have long harboured ambitions of doing more to “get rid of red tape”, Brexit is likely to be too good an opportunity to pass up. In so many previous attempts to shrink the statute book, Ministers have had to accept – however reluctantly in some cases – that measures which implemented EU law were untouchable.  This time, there will be pressure to get rid of some of those.  In each case where a straight repeal is contemplated, the consequences of having a regulatory vacuum in the relevant area should be carefully considered and the views of relevant stakeholders taken into account.  Business may need to be alert to what is proposed and ready to engage fully at short notice whenever this process takes place – which could either be in parallel with Brexit negotiations or after they are concluded.  It would make sense for the default position at the start of the UK’s EU-non membership to be one in which the effect of pre-Brexit Directives and Regulation is preserved, at least for an initial transitional period, by a widely-drafted general saving clause in the legislation that undoes s.2(1) of the European Communities Act.

However, if the Government plans to join the EEA as an EFTA State, the task of sifting through decades of EU legislation on this “pick ‘n’ mix” basis should arguably only be a priority in relation to two classes of measure: (i) those that fall outside the scope of the EEA Agreement; and (ii) those that have yet to be adopted at EEA level, to the extent that there would be a clear UK advantage in disapplying them or modifying their effect on a temporary basis.

In the first category (measures outside EEA scope) it is not clear there would be many “quick wins”.

  • One possible example is the suggestion made by Brexit campaigners during the referendum that leaving the EU would enable the Government to abolish VAT on domestic energy bills – a move that would help to offset the increases in electricity bills driven by levies on suppliers to pay for the cost of renewable electricity generation subsidies.
  • In other areas highlighted above as falling outside the scope of the EEA Agreement, it is less clear what would be gained by an immediate move away from the existing EU-based law.  For example, on the whole UK levels of taxation on energy products exceed the minima set out in the Energy Products Taxation Directive – although it may help to have additional room for manoeuvre in reforming business energy taxation.  As regards sanctions against Iran, the factors to be taken into account probably go well beyond energy policy considerations.  It is possible that increased flexibilities from the removal of Oil Stocking Directive requirements would assist the struggling UK refineries sector, but the UK would still remain subject to the parallel requirements of the International Energy Agency’s International Energy Program Agreement.  Refineries might benefit more from the removal of rules implementing the Industrial Emissions Directive (but, as noted above, this is part of the EEA Agreement, and so unlikely to be disapplied if the plan is to join the EEA).

In the second category (candidates for possible temporary disapplication), there may be more scope for opportunistic (de-)regulation, but it is not obvious what the overall strategy would be.

  • Pragmatically, the disapplication of a requirement based on EU law that the UK authorities do not like may be an unnecessary step to take in some cases.  For example, if the UK has left or is about to leave the EU and it looks as if the target set for reducing the energy consumption of public sector buildings in Regulations implementing the Directive 2012/27/EU is not met in 2020, and the Directive has not yet been adopted into the EEA Agreement, would the Government bother to repeal the Regulations, or simply do nothing?  That said, it is too early to be sure that the European Commission will abandon or slow-track any infringement proceedings against the UK for non-implementation of EU law: after all, it might, for example, be part of the arrangements for the UK’s withdrawal that, where the UK was subject to infringement proceedings at the time of leaving the EU – particularly in respect of failure to implement a measure that is also part of the EEA Agreement – those proceedings could be carried on to their conclusion, whether by the EU or EFTA authorities.
  • Similarly with Directives which have been adopted at EU level, and may be required to be implemented before the UK leaves the EU: the UK could take the view that it need not implement them unless and until they are included in the EEA Agreement.  The Medium Combustion Plant Directive, with a transposition date of 19 December 2017, could perhaps safely be included in this category – although there have been indications that in order to prevent undue exploitation of the Capacity Market and other incentives for distributed generation by diesel-fired plant, the Government may actually wish to implement this early.
  • Timing is everything in this context.  EU Regulation 838/2010 imposes a cap of €2.5/MWh on average electricity transmission charges in the UK.  This has been implemented in a provision of National Grid’s Connection and Use of System Code, which previously split the charges 27:73 between generators and suppliers, but now requires suppliers to pay a >73% share and is also the subject of some dispute because of the artificiality of imposing an ex ante Euro-denominated cap on a market that operates in Sterling.  After Brexit, the cap could simply be removed (at least until the Regulation becomes part of the EEA Agreement), but unless the current modification processes move very slowly or the Brexit negotiations move very fast, Ofgem is likely to have to grapple with the issues that it raises sooner than that.  Incidentally, this example illustrates two further points about implementation: (i) that it is sometimes necessary or appropriate to make provision in domestic law to give effect to an EU Regulation; and (ii) that (in the energy sector at least) it is not just the conventional categories of statute law (Orders and Regulations) that need to be combed when reviewing the implementation of EU law: licence conditions, industry codes and other regulatory documents are also part of the picture.

Another important question in this scenario, and one which there is not space to pursue in any depth here, is the impact of Brexit on the EU’s Energy Union project.  Some elements of the proposed Energy Union package may well fall outside the scope of the EEA Agreement, which will no doubt please those who were concerned that “UK business gas supplies could be diverted to households in Europe, under EU crisis plan” (referring to the proposed new principle of “solidarity” in the Commission’s gas security of supply proposals).  Other elements are likely to result in what would amount to a Fourth Package of internal electricity and gas market measures – parts of which the UK might wish to implement before the other EFTA States have  implemented the Third Package, but in the negotiation of which, even if it is completed during the time of the UK’s remaining EU membership, it is hard to see the UK playing a decisive role.  Amongst other things, Energy Unions is likely to confer more power on ACER, the collective body of EU energy regulators.  Yet there is no guarantee that Ofgem would retain its position within this body if the UK were no longer an EU Member State (even if it were an EEA State, unless and until the EEA adopted the new rules).

Confused? You won’t be alone.  But note in passing that one difference between the Second and Third Packages is that only the latter imposes an obligation to roll out smart meters to 80% of customers by 2020 (subject to a positive cost-benefit analysis).  Surely nobody would use the UK leaving the EU, and thus (even if temporarily) not being obliged to follow this requirement as a reason to repeal or not enforce Condition 39.1 of the Standard Licence Conditions of Electricity Supply Licences, which implements it in UK law?

For the avoidance of doubt, if the UK were to join the EEA as an EFTA state, it would remain subject to EU state aid rules, under which state aid which distorts competition is unlawful and liable to be repaid if it is not first cleared by the European Commission / ESA. Many of the UK’s key current energy policies, such as the Capacity Market and Contracts for Difference (CfDs), involve an element of state aid.  State aid clearance for them by the European Commission has been very carefully negotiated, and the need to seek clearance for any significant changes to them has been a constraint on recent policy development.  The ESA has adopted guidelines on state aid for energy and environmental protection that are effectively identical to those of the Commission and it is likely to take a similar view of UK energy policies involving state aid.

In the field of climate change, the UK would no longer be represented by the EU at future UNFCCC conferences. Like the other EFTA States, it would be required to submit its own nationally determined contribution (NDC) towards the achievement of the goals of the CoP21 Paris Agreement, rather than coming under the umbrella of the general EU-wide NDC.  The mechanisms of the Climate Change Act 2008 should provide a sound basis for this.

In short, in the “EEA scenario”, the energy sector is unlikely to see big changes from the UK side as a result of Brexit, but as there may be a sustained effort by Ministers to make the most of even temporary flexibilities, the industry will need both to be alive to the detail of proposed changes and prepared to advise the Government on how the inherent flexibilities described above can best be used in UK policy changes. It is also possible that the arrival of the UK would put some aspects of the way that the EEA operates under strain, both within EFTA itself and in its relations with the EU.  One can imagine the UK sometimes being impatient at the slowness of EEA adoption of some EU law and at other times wanting to push the boundaries of EFTA independence further than the EEA Agreement will easily tolerate.  Inevitably, a recalcitrant UK would be a bigger problem than a recalcitrant Liechtenstein.

Nuclear options?

It is a fair bet that very few voters on 23 June were asking themselves whether a vote to “leave the EU” was meant to suggest to the Government that it should cease to be a party to the Euratom Treaty establishing the European Atomic Energy Community. For what it is worth, in strict legal terms, Brexit should not necessarily imply leaving Euratom, since it, alone of the three original “European Communities” has not been terminated or submerged in the EU.  (It also forms no part of the arrangements between the EU and EFTA States in the EEA Agreement.)

The UK Government may feel that these subtleties are not to be relied on in implementing the “will of the people”.  “Article 50” notices of an intention to withdraw could presumably be served in respect of both Euratom and the EU Treaties (relying on Article 106a Euratom as to Euratom).  Would leaving Euratom be a problem?  The UK had a nuclear industry (arguably a more successful one) before it joined the EEC in 1972, and for many years some of the key international safety, liability and other industry-specific rules were to be found only in the relevant IAEA Convention and not in any European Directive.  Ceasing to be party to Euratom would not affect those.

However, it is hard not to see leaving Euratom as a backward step for a country whose Government has strong nuclear aspirations.   For example, the ability to continue to participate in European nuclear research projects, including on nuclear fusion, is something that the Government would presumably want to safeguard, but beyond the next few years, it would not be guaranteed outside Euratom.  An alternative (if it was felt to be too politically uncomfortable for the UK to stay in Euratom) might be for the UK to suggest to the remaining Euratom States that they make use of Article 206 Euratom to conclude an association agreement with the UK (if that is politically acceptable to all parties) – although this could presumably have the disadvantage of the UK being obliged to follow rules and policies which it would not have input into on an equal footing.

Meanwhile, only time will tell whether French Government support for EDF’s proposed Hinkley Point C nuclear power station will survive Brexit. At this stage it is hard to say that there is any legal reason for the project not to go ahead if the UK is no longer an EU Member State, but Brexit could provide an excuse for either Government if they wanted to terminate the project for other reasons.  EDF’s Chinese partners, may, of course, have a view about that.

The Energy Community

Unlike in some other sectoral areas of law affected by Brexit, energy has the benefit of a ready-made multilateral precedent for the EU and non-EU states to enter into a “single market” agreement which does not (at least explicitly) involve free movement of persons. The Energy Community was formed in 2005 by a treaty between the European Community and a number of Balkan states.  It now comprises the EU, Albania, Bosnia and Herzegovina, Kosovo, the former Yugoslav Republic of Macedonia, Moldova, Montenegro, Serbia and Ukraine.  Georgia is in the process of joining; Armenia, Norway and Turkey are observers.

Some, but not all of these countries are candidates for EU membership and/or have signed up to forms of EU association agreement that commit them to comply with core single market rules, but with only limited provision for the free movement of persons. The Energy Community Treaty and associated Legal Framework commit the Contracting (non-EU) Parties to implement a number of key EU law energy provisions, including the Third Package, security of gas and electricity supply rules, the Renewable Energy Directive, energy efficiency rules, the Oil Stocking Directive, competition and state aid rules and key air pollution and environmental impact assessment rules.  Although supervision of the implementation of Contracting Parties’ obligations is by a Ministerial Council rather than an independent regulatory agency or court, there are sanctions for persistent and serious non-compliance (suspension of Treaty rights).

If energy was our only industry and the UK Government wanted to spare itself the pain of taking decisions on what to do with all current EU energy law applicable in the UK, the Energy Community might be a more attractive club to join than the EEA. But in practice, that option may not be available and other industries may rank higher in terms of political priority in negotiating Brexit.

Freedom and sovereignty

Those who campaigned for Brexit had relatively little to say specifically about energy matters.  But their general pitch to voters was that Brexit would give businesses operating in the UK freedom from unduly burdensome regulation and that it would restore to UK voters, or at least the UK Government, power to determine the UK’s economic and industrial policies.

Given the constraints that EEA membership would impose on the UK Government’s freedom of action in many areas of energy policy, it is necessary to consider what use it could make of the additional freedom or “sovereignty” it could acquire in energy matters if it chose, or was obliged, to forego the ready-made packages of the EEA Agreement and Energy Community for a non-EU law-based model.

Here are some changes that it would probably only be possible to make in a non-EEA UK.  We are not here speculating on whether the Government would be inclined or likely to follow any of these approaches: they are discussed only to illustrate the extent of the potential flexibility that may be available to change current policy.

  • The Government could abandon any further attempt to stimulate private sector investment in new renewable electricity generating capacity, or the uptake of other forms of renewable energy, on the basis that it would no longer have a 2020 target to meet and that it would be better for the UK to wait until renewable technologies have become cheaper by virtue of wider deployment elsewhere in the world.  It could impose a moratorium on all new consents for such projects and suspend or abolish all remaining subsidies for new projects (and it would not have to carry out a Strategic Environmental Assessment before doing so, as EU law would currently require).  Before taking this line, which would help to deliver lower increases in consumer bills over time, the Government would have to weigh carefully: the impact on UK jobs; the potential damage to the UK’s reputation as a place with a stable and supportive regime for energy infrastructure investment (arguably already damaged by the politically driven abolition of onshore wind subsidies and cancellation of support for the commercialization of Carbon Capture and Storage (CCS)); damage to the UK’s reputation as a leader on climate change issues; and the prospect of objectors being able to construct a successful legal challenge to one or more of the steps taken in pursuit of such a policy by arguing that it would make it impossible to keep within one or more of the UK’s carbon budgets, so breaching the Climate Change Act 2008.  (Although note that if a future Government were to wish to repeal that Act, it could do so whether the UK was in or out of the EU / EEA, if it was prepared to live with the resulting  damage to its international reputation.)
  • If the Government was content to carry on subsidising renewable power to some extent, it could – free from EU state aid rules – adopt a less even-handed approach to the allocation of CfDs to new projects.  This may make it easier for the Government to follow what may in any event be its natural inclination to make subsidies available only for offshore wind farms and a few much less established technologies.  Equally, it could choose to subsidise a further coal-to-biomass conversion at Drax even if the Commission’s current state aid scrutiny finds that the existing CfD terms offered to Drax are too generous to be given state aid clearance.  And it may be more able than it is under EU law to give substantial weight to “UK content” in the plans put forward by developers when awarding CfDs.  On the other hand, it could adopt a simpler form of CfD for smaller projects, rather than subjecting 5 MW generating stations to a form of contract much of which was developed for a 3.2 GW nuclear facility.
  • On the other hand, Government could take the view that the low carbon option that really needs subsidising is heat networks, and it could divert all funds notionally earmarked for renewable electricity generation into the provision of heat network infrastructure instead –  subsidising it to a degree that would not be given state aid clearance in order to give a real boost to a market that has been slow to develop for a long time.
  • A different approach would be to focus subsidy entirely on energy storage, with a view to enabling as much variable generating capacity as possible to become, in effect, despatchable.  This is arguably the next frontier for wind and solar power and by boosting demand for storage it could help to reduce its costs in the same way as subsidies have helped to do for solar panels in particular.  That much could possibly be achieved within the EU rules, but it might also help, in such a scenario, to make storage a regulated utility function, and to allow National Grid to invest in storage capacity in a way that EU unbundling rules at present may either not allow, or make it unduly difficult for it to do (if storage is classed as “generation”).
  • It seems unlikely that Brexit would constitute a Qualifying Change in Law (QCiL) for the purposes of the standard terms of CfDs, such that it would entitle the CfD Counterparty to terminate any CfD which has already been entered into solely because of Brexit, because a QCiL must, in essence, have an effect on a particular project, rather than all or most projects, or the whole economy.
  • Government has been disappointed, from an energy security point of view, at the failure of the Capacity Market auction system to produce a clearing price that can serve as the basis for financing large-scale CCGT power stations.  However, in its proposals to change the approach to be taken in the next two auctions, it did not feel able to go as far as to suggest an auction just for CCGT capacity, as this would be incompatible with the existing state aid clearance for the Capacity Market (which is subject to legal challenge).  With no state aid rules to follow, Government could choose to hold a CCGT-only auction.  Other more radical variants on the current rules could include separate auctions for CHP plant (or handicaps in the auction process for non-CHP generating units).
  • Without the constraints of the Industrial Emissions Directive, it might be possible for Government to allow coal-fired plants to follow a gentler path towards closing by 2023/2025 (as its current policy envisages that they will) in which they were allowed to run for a longer period of time without adapting to tighter emissions limits.  However, this might militate against new CCGT development (as well as carbon budget targets).
  • Unconstrained by state aid rules, Government could allow and encourage National Grid to develop an offshore pipeline system to distribute carbon dioxide to potential permanent storage sites under the North Sea, as part of its regulated business, so as to kick-start a CCS industry.
  • Government could escape the flawed EU ETS with its apparently inevitably too-low carbon price and join an emissions trading scheme that delivers a higher carbon price.  There is an increasing number to choose from internationally, from California to China.
  • If Government were to take the view that establishing some form of state-backed entity was the best way to make the decommissioning regime in the North Sea oil and gas industry work effectively, or to ensure that there was a “buyer of last resort” for strategically vital assets whose current owners lack the incentive to carry on running and maintaining them, this is something that would be easier outside the EU / EEA state aid rules.
  • Finally, if the Competition and Market’s Authority’s current proposals for a limited price cap for some domestic energy supply contracts, which were to some extent constrained by EU law, prove inadequate, future regulatory action could go further in this direction.

Depending on which horn of the energy / climate change trilemma you think is most inadequately served by current UK Government policy, you may find any of the above, or other steps that an EU / EEA UK could not take, very attractive. What we would emphasise here, though, is that removing the constraints of EU / EEA law could lead to significantly more volatile energy policy-making in the UK, and greater politicisation of energy regulation.  Note that even Ofgem’s independence is currently underpinned by requirements of EU law, as well as fairly consistent UK tradition.  If the UK were to go down the out-of-EU-and-EEA route, we would suggest that the Government, however radical any departures it decides to take from current energy policies may be, should take steps to ensure that they develop within a stable overall framework, in which business can plan sensibly for the long term.  It may be necessary to impose some more home-grown constraints (like carbon budgets) to make up for the EU ones which would have been shaken off.

A special deal with the EU?

There may be some who dream of the UK reaching a form of accommodation with the EU (going beyond the energy sphere) which is sui generis and somehow the best of all possible worlds.  Leaving aside the question of whether that is politically feasible, it is important to bear in mind that the Commission and the Governments of the other EU Member States may not be the only people to whom such a deal would have to be sold.  On other occasions where the EU has departed from established legal norms it has found itself having to deal with the unsolicited and not necessarily positive input of the Court of Justice of the EU: indeed in the case of the EEA, parts of its founding Treaty had to be renegotiated to accommodate the Court’s concerns.  This may complicate matters.

Non-EU / EEA law constraints imposed by international law

A non-EU / EEA UK would not be constrained by EU / EEA law, but it would not be free of other international law constraints that have a bearing on regulation of the energy sector. We will consider this topic in more detail in a later post, but for now, note the following examples.

  • If the UK were to negotiate and become party to a free trade agreement with the EU / EEA other than the EEA Agreement, it is likely that (as other such agreements have), it would include requirements to enforce competition law and a prohibition on state aid.  Accordingly, all the non-EU / EEA UK energy policy options referred to above which would be contrary to EU state aid rules could be the subject of disputes under a UK-EU / EEA free trade agreement if they were implemented.  If, on the other hand, the UK were not to negotiate such a bespoke free trade agreement and were to rely instead on WTO rules, such measures may still fall foul of the WTO rules against subsidies.
  • The decommissioning of oil and gas infrastructure is regulated by the Convention for the Protection of the Marine Environment of the North-East Atlantic (more familiarly known as the OSPAR Convention), one of a number of international conventions relevant to the environmental aspects of the energy industry.
  • The Energy Charter Treaty and bilateral investment treaties to which the UK is a party may offer protection for those who invest in the UK energy sector, and cause the Government to refrain from taking action that would create claims against it under them.

More generally, if the UK were to follow this path, it is possible that any radical departures in energy policy could affect the terms of trade deals that could be negotiated with other states, and any tariffs imposed by them.

Co-operating with EU / EEA countries outside the EU / EEA

It is to be hoped that Brexit will not mean the end of useful co-operation on energy matters between the UK and other EU / EEA States acting individually. We note in this context that the UK did not sign up to the recent political declaration by North Sea countries regarding their initiative on co-operation to develop a more co-ordinated approach to the development of offshore electricity transmission infrastructure in the North Sea (known as NSCOGI), despite having previously supported this initiative.  No doubt the fact that the document was signed less than three weeks before the June 23 referendum did not help, but given the potential strength of the UK’s offshore wind industry and the savings that could be made by developing offshore links on a “hub and spoke” rather than “point to point” pattern, it would be a pity if the UK were to drop out of NSCOGI.

Closer to home

This Blog, like many similar publications, has talked in bland terms about “the UK”. This overlooks:

  • the possibility that Scotland will ultimately leave the UK rather than the EU;
  • the fact that the devolved government in Northern Ireland has (nominally) complete and (practically) very extensive powers to make its own rules on energy matters;
  • the existence of a Single Energy Market across the island of Ireland and a single set of electricity trading arrangements (BETTA) across England, Wales and Scotland; and
  • the fact that post-Brexit the Republic of Ireland will be the only EU Member State whose connection to the EU single market in gas runs entirely through non-EU territory.

There will be more to say on these points, and on other intra-UK energy Brexit issues, in later posts.

On a practical level, businesses would do well to review those parts of their key existing contracts (and any important contracts under negotiation) that contain provisions where rights and obligations could be triggered by the occurrence of Brexit: obvious examples include provisions on force majeure, change in law, material adverse change, hardship and currency-related matters. Again, more on this to follow.

(Provisional) conclusions

EU and UK energy regulation have become so intertwined over the years, and the energy industry is so international in a variety of ways that it is inevitable that Brexit will affect all parts of the UK energy sector to some degree. And those parts of it that are arguably not so directly affected are themselves subject to other massive regulatory interventions at present in any event (notably the energy supply markets in the wake of the Competition and Markets Authority’s investigation).

What will change in the energy sector as a result of the UK electorate voting to leave the EU? At this stage, it is tempting to say simply: “If we stay in the EEA, nothing will really change.  If we try to go it alone, who knows?  The only certainty is years of uncertainty”.  We hope that the preliminary observations in this post have shown that the position is rather more complex and dynamic, and the range of issues to be addressed and possible outcomes is wider than is sometimes supposed.

For now, we would suggest that it is important to follow the details closely, because unless you believe that the result of the referendum will somehow not be implemented, there is no more justification for complacency about the ultimate consequences of Brexit for the energy sector than – if one supported remaining in the EU – there was about the result of the referendum itself.

If you have questions about the issues raised in this post, or about other aspects of Brexit as it relates to your business, please get in touch with the author or your usual Dentons contact.

 

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Energy Brexit: initial thoughts

The New North Sea – Part 3: Top 10 “MER UK” issues for exploration activities

Exploration is undoubtedly a key area of focus for the bodies responsible for achieving MER UK. In its Corporate Plan, the OGA lists “revitalising exploration” as one of its priorities. It also sets out a proposed pathway for reaching its target of 50 E&A wells drilled per annum by Q1 2021. In addition, an ‘exploration sector strategy’ is awaited which will hopefully set out in more detail how the OGA intends to apply the MER UK Strategy to exploration operations. Our third post in this series sets out our top 10 key “MER UK” changes which may have a bearing on exploration operations in the North Sea.

1. All exploration activities must comply with the central obligation of achieving MER: All offshore petroleum licensees must comply with the MER UK Strategy (pursuant to the changes to the Petroleum Act 1998, brought in by the Infrastructure Act 2015). The MER UK Strategy was developed by the Secretary of State and sets out the proposed strategy for achieving the principal objective – “the objective of maximising the economic recovery of UK petroleum” (see also our previous post on the MER UK Strategy). It is binding upon relevant persons operating in the UKCS, specifically holders of offshore petroleum licences and operators of petroleum licences.

The MER UK Strategy expressly requires licensees under an offshore licence to plan, fund and undertake exploration activities within the licence area, in a manner that is “optimal for maximising the value of economically recoverable reserves” within the licence area. The MER UK Strategy contains more detail as to how “relevant persons” should act. Some of these are discussed in more detail below, but the key requirement is to carry out all functions in a manner compliant with MER.

2. Failure to comply with MER: Failure to comply with the MER UK Strategy may lead to sanctions. The Energy Act 2016 grants the OGA powers to impose sanctions on offshore petroleum licensees for failing to comply with the MER UK Strategy, or for failing to comply with a term or condition of the offshore licence. The possible sanctions range from enforcement notices and fines to, ultimately, the removal of the operator of a petroleum licence and/or revocation of the licence.

3. No relinquishment until firm commitment carried out: The MER UK Strategy provides that, except where the licensee would not make a “satisfactory expected commercial return” (as defined in the MER UK Strategy), a licensee cannot relinquish a licence until it has completed any work programme, to which it made a firm commitment in the licence.

4. Regional exploration plans: The OGA may produce plans setting out its view of how it expects obligations in the MER UK Strategy to be met. The plans may cover exploration activities carried out within specific regions of the North Sea, for example West of Shetland.

As far as we are aware, the OGA has not yet developed any exploration plans. If the OGA wishes to produce a plan under the MER UK Strategy, it must first consult with those persons it thinks may be affected by the plan. As the plans are binding, we recommend you engage with the OGA on any proposed plan that may affect your exploration activities (and potentially future activities down the line, including development and decommissioning).

If you intend to carry out activities in a manner inconsistent with any plan published by the OGA, you will need to first consult with the OGA.

5. Collaboration and competition law issues: The MER UK Strategy requires licensees to consider whether collaboration or cooperation with other licensees or service providers could reduce costs and/or increase the recovery of economically recoverable petroleum, and to give due consideration to such possibilities.

At the same time, the MER UK Strategy states that no obligation imposed by the Strategy permits conduct which would otherwise be prohibited under legislation, including competition law. There appears to be an inherent conflict between these requirements. It is your responsibility to ensure that you do not infringe competition laws whilst complying with MER.

6. New technologies: According to the MER UK Strategy, licensees must ensure that, in carrying out their activities, new and emerging technologies are deployed to their optimum effect. This may also be the subject of an OGA plan, which you may be required to comply with.

7. OGA attendance at meetings: Under the Energy Act 2016, the OGA will have powers to attend meetings between licensees and other relevant persons discussing matters relevant to achieving MER. This includes formal meetings such as Opcom meetings, as well as meetings conducted through electronic means (e.g. telephone calls). The organiser of the meeting has to provide notice to the OGA of any such meetings (14 days’ notice, unless it is not practicable to do so) and provide any papers relating to the MER UK issue, which are distributed to the attendees to the OGA. If an OGA representative does not attend, the organiser must provide a summary of the discussion to the OGA.

In practical terms, employees organising meetings need to be aware of what “MER” issues are, in order to know when the OGA should be given notice and what papers to provide. Waivers of confidentiality from other persons may be required. In addition, papers given to the OGA should only cover those issues relevant to the OGA and not commercially sensitive information.

Whilst these new powers appear to be fairly onerous, they may be useful, if there is an issue that you want the OGA to be involved in.

8. Information and samples: There are new provisions in the Energy Act that give the Secretary of State the power to create regulations to require licensees, operators and owners of petroleum infrastructure to retain specified petroleum related information and samples. Notably, the regulations can require a party to keep information and samples even where it is no longer a licensee (as a result of transfer, surrender, expiry or revocation).

Procedures will need to be put in place to ensure the data and samples are retained. In addition, each licensee is required to have an information and samples coordinator within the organisation to supervise data retention and correspondence with the OGA.

If a licence is transferred, surrendered, revoked or expires, then the OGA can request that the licensee informs it of what is to happen with information and samples (in an information and samples plan). The plan must provide for the party to either: (i) retain the information and samples, (ii) transfer to a new licensee or (iii) secure appropriate storage. So on a transfer of a licence, the licensee has the choice of potentially incurring costs to retain or store the data and samples, or handing over its intellectual property to another licensee.

9. MER UK disputes: Relevant persons, including offshore petroleum licensees and owners of upstream infrastructure, may refer disputes relating to fulfilment of the MER, or relating to activities carried out under an offshore petroleum licence, to the OGA for a non-binding recommendation on how to resolve the dispute. It should be noted that the OGA also has the power to decide on its own initiative to consider a dispute involving such issues.

As there is already a separate procedure for disputes relating to third party access, the new powers do not apply to such disputes relating to third party access.

10. Satisfactory expected commercial return: The general principle behind the MER UK Strategy is that investment made in the UKCS should be made such that the maximum value of economically recoverable petroleum is recovered, and that assets should be in the hands of those who are willing to make such investment.  So the MER UK Strategy contains a safeguard that no licensee or owner of infrastructure is required to invest or fund activity if it would not make a satisfactory expected commercial return. The definition is fairly vague, but prescribes that a satisfactory expected commercial return is not necessarily a return in line with corporate policy.  If a licensee feels that it would not make a satisfactory return, but a “satisfactory expected commercial return” could be made, the licensee could ultimately be required to sell the asset.

 

 

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The New North Sea – Part 3: Top 10 “MER UK” issues for exploration activities