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Energy Market Mergers – quick guide to EU Competition Law assessment

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

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

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

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

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

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

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

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Energy Market Mergers – quick guide to EU Competition Law assessment

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

Why won’t UK shale be subject to the renewable energy community stake requirement?

As noted in our recent post on Shared Ownership, the UK Department for Energy and Climate Change (DECC) has published its Community Energy Strategy (Strategy) which anticipates that by 2015, it will be normal for new renewable energy developments to offer project stakes to local communities (and which could be enforced by an enabling power in the draft Infrastructure Bill 2014). At a recent renewable energy industry event, it was asked why shale developers are not similarly targeted by the Strategy to offer stakes to local communities?

Analogy to a new tax

In short, because it would likely be argued to be unfair. Shale developers have already paid and committed to fulfil minimum work obligations onshore under a petroleum, exploration and development licence, in order to have the right to explore for and later extract hydrocarbons from the sub-surface (and off the Crown). Any later requirement to give a royalty or equity interest to a local community, could be regarded as being analogous perhaps to an unexpected new tax. In addition, having to obtain DECC consent or adding say a community interest company (CIC) vehicle to a hydrocarbon licence, could be administratively cumbersome.

Misalignment of local opposition

That said, renewable developers may argue that buying or leasing surface land rights for renewable energy generation, and later having to give a stake to a local community, is little different philosophically. However, the current Strategy proposal is perhaps designed to address the apparent misalignment between national poll results (which are reported to suggest a majority are in favour of renewable energy); and local communities (who often resist wind and solar developments in their own localities). Such opposition is often then said to be reflected in local authority planning application refusals, which in turn reduces renewable energy development and impacts national carbon targets.

Reduced justification for compensation

By comparison, opposition to shale developments, is perhaps expected to be less driven by local planning or land-use opposition, as opposed to broader ideological and environmental concerns, which may not be as effectively addressed with active community participation – few well-heads will have the “wow factor” of a windmill. In addition, once DECC’s current consultation on granting horizontal drilling access rights (to ease shale and geothermal developments) runs its course (see our recent post Compulsory access rights “in the national interest”), then developers will possibly have less need for community alignment on specifically land-use environmental concerns. Indeed, the relative thickness of exploitable UK shale resources means that relatively few well-pad sites on the surface could be used to access large areas of sub-surface resource horizontally, causing little environmental impact (truck movements apart). This may reduce any justification for giving local communities a substantive share of the profits.

Conclusion: proactivity in hindsight

It is also important to note that the nascent shale industry, to the extent represented by the recently invigorated UK Onshore Operator’s Group (UKOOG), has perhaps already drawn some of the sting of potential community engagement regulation, by pro-actively suggesting well-pad and production payments (albeit modest in amount) for local communities. Whilst the renewables industry is more mature, numerous and with diverse interests, it may be noted that a sophisticated regulator is rarely motivated to act, except where market failure is perceived. Therefore, if the shale industry were to fail to implement the recommendations volunteered by the UKOOG, DECC may be tempted to re-assess the absence of unconventional developments from the Strategy and Infrastructure Bill’s proposals for community participation. In hindsight, now that DECC has seen a need to prompt the renewable energy industry into volunteering community participation, it appears less likely that community payments divorced from equity stakes or project profitability alone, will meet the regulator’s perception of community needs.

For further analysis on the potential application of UK and other international examples for tailoring legislation, farm-in and joint operating agreements in developing unconventional basins, please see our Shale Guide, recently presented and discussed over two days in Washington DC at a World Bank and OGEL symposium, aggregating the learning of representatives covering 18 countries.

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Why won’t UK shale be subject to the renewable energy community stake requirement?