Long-Term Take-or-Pay Agreements inNatural Gas Industry: Past, Present and Futureby K. Talus, S. Looper, and L.L. Burns

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Oil, Gas & Energy Law Intelligence

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1875-418X

Issue : Vol. 18 - issue 3 Published : May 2020

This paper is part of the OGEL Special Issue on “Changing LNG Markets and Contracts” edited by:

Agnieszka Ason

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Long-Term Take-or-Pay Agreements in Natural Gas Industry: Past, Present and Future

Kim Talus1, Scott Looper2 and Luke Burns3

Introduction

Many large natural gas projects, including LNG projects, are financed on the basis of long-term contracts containing take-or-pay provisions. These contracts help provide the backbone of the financing structure for projects with high capital costs and long payback periods where financing is tied to project revenues because the promise of de-risked long-term revenues on the basis of such take-or-pay provisions comforts investors. The take-or-pay provisions in these long-term contracts are intended to mitigate pricing and demand volatility as well as other market risks by setting a “floor” – both in terms of price and volumes – for the offtake of gas by the counterparty-customer of such a project. Today, the market uncertainties created by COVID-19, and the related negative demand shock, are one example of a situation where take-or-pay provisions in long-term contracts shore-up the continued viability of debt service of certain ongoing LNG or gas projects to existing lenders in the face of such a situation.

A take-or-pay clause in a long-term LNG or gas contract typically obligates the buyer of LNG or gas to take and pay for such LNG or gas, or otherwise pay an agreed price on a heat-content or volumetric basis for any LNG or gas not taken. Take-or-pay obligations are typically pegged to a daily, monthly, quarterly or annual timeframe, but is also sometimes on a cargo-by-cargo basis in the LNG context.4

Take-or-pay clauses are typically not absolute and may include flexibility mechanisms that allow the buyer to adjust the contracted volume or quantity in a limited way. For example, this flexibility may obligate the buyer to only 70% to 90% of the applicable contract quantity. Take-or-pay clauses often also include certain agreed situations where the buyer is excused from its performance of the take-or-pay obligation. These may include force majeure, non-delivered gas volumes (where the seller is responsible for the non-delivery) and gas or LNG refused for quality reasons.

Examples of Take-or-Pay Provisions

The following is an example of a simple take-or-pay pay clause (and is not based on any particular industry form):

1 Kim Talus is the James McCulloch Chair in Energy Law and founding Director of the Tulane Center for Energy Law (Tulane Law School). He is also a Professor of European Energy Law at UEF Law School (University of Eastern Finland) and a Professor of Energy Law at Helsinki University. Kim Talus is also the Editor-in-Chief for OGEL (www.ogel.org) and can be contacted at ktalus@uef.fi 2 Scott Looper is a Partner at Baker Botts LLP. His practice focuses primarily on midstream, LNG and upstream energy industry project development activities. Scott can be contacted at scott.looper@bakerbotts.com. 3 Luke Burns is a Senior Associate at Baker Botts. His practice focuses on acquisitions and divestitures of onshore and offshore upstream oil and gas assets, farmouts and other development arrangements, and both large-scale and small-scale liquefied natural gas (LNG) projects. Luke can be contacted at luke.burns@bakerbotts.com. 4 Typically the take-or-pay is connected to a daily, monthly, quarterly or annual contract quantity concept, which represents a volume of gas or quantity of LNG that the buyer must take during each day, month, quarter or year, respectively.

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During any contract year, buyer shall take and pay for X quantity of natural gas, or pay to seller Y if such quantity is not taken, unless otherwise excused under this Agreement.

By contrast, the following is a more detailed take-or-pay pay clause, with two alternatives (based on the AIPN Model gas sales agreement 2006):

Take or Pay Obligation

In each Contract Year Buyer shall be obligated to take and pay for, or to pay for if not taken, a quantity of Gas at least equal to the Take or Pay Quantity. If, in any Contract Year, there is a Buyer’s Annual Deficiency Quantity, then Buyer shall pay Seller Buyer’s Deficiency Payment determined using the following formula:

ALTERNATIVE 1

BDP = BADQxTOPP

Where:

BDP is Buyer’s Deficiency Payment for such Contract Year,

BADQ is Buyer’s Annual Deficiency Quantity for such Contract Year, and

TOPP is the Take or Pay Gas Price for such Contract Year.

ALTERNATIVE 2

BDP = �BADQ−CFCQ� xTOPP

Where:

BDP is Buyer’s Deficiency Payment for such Contract Year,

BADQ is Buyer’s Annual Deficiency Quantity for such Contract Year,

CFCQ is the Carry Forward Credit Quantity, if any, for such Contract Year, and

TOPP is the Take or Pay Gas Price for such Contract Year.

Broadly speaking, the intention behind these two alternatives, simple and more detailed, is the same. The AIPN model version provides for two alternatives and uses a somewhat more complicated way of communicating the same right and obligation.

The publicly-filed LNG Sale and Purchase Agreement (FOB) between Corpus Christi Liquefaction, LLC (a Cheniere Energy affiliate) and Électricité de France, S.A., dated July 17, 2014, also includes the following sophisticated take-or-pay provision (and relevant definitions summarized in footnotes):

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5.5 Buyer’s Purchase Obligation

5.5.1 During any Contract Year,5 Buyer shall take and pay for the Scheduled Cargo Quantity6 with respect to each cargo included in the AACQ7 and scheduled in the ADP for such Contract Year, less:

(a) any quantities of LNG not made available by Seller for any reasons attributable to Seller (other than quantities for which Seller is excused pursuant to this Agreement from making available due to Buyer’s breach of this Agreement) including quantities not made available by Seller due to Force Majeure affecting Seller or the Corpus Christi Facility;8

(b) any quantities of LNG not taken by Buyer for reasons of Force Majeure;

(c) quantities of LNG for which Buyer has provided a notice of suspension pursuant to Section 5.7; and

(d) any quantity that the relevant LNG Tanker9 is not capable of loading due to the Seller’s delivery of LNG that has a Gross Heating Value10 that is less than the value identified by Seller pursuant to Section 8.1.1(a); and

(e) quantities rejected by Buyer in accordance with Section 5.6.6.

5 References to a “Contract Year” mean a period of time from and including January 1st through and including December 31st of the same calendar year, provided that: (a) the first Contract Year is the period of time beginning on the Bridging Start Date and ending on December 31st of the same calendar year (the “First Contract Year”); and (b) the final Contract Year is the period of time beginning on the January 1st immediately preceding the final Day of the Term and ending on the final Day of the Term (the “Final Contract Year”). 6 “Scheduled Cargo Quantity” means the quantity of LNG (in MMBtus) identified in the ADP or Ninety Day Schedule to be loaded onto an LNG Tanker in a Delivery Window in accordance with Section 8. The schedule for deliveries of LNG during the Contract Year established pursuant to this Section 8.2, as amended from time to time in accordance with Section 8.3, is the “Annual Delivery Program” or “ADP”. “Ninety Day Schedule” means a forward plan of deliveries for the three (3)-Month period commencing on the first Day of the following Month thereafter. “Delivery Window” means a twenty-four (24) hour period starting at 6:00 a.m. Central Time on a specified Day and ending twenty-four (24) consecutive hours thereafter that is allocated to Buyer under the ADP or Ninety Day Schedule, as applicable. 7 The “Adjusted Annual Contract Quantity” or “AACQ”, expressed in MMBtu, for each Contract Year shall be equal to the ACQ for the relevant Contract Year, plus certain adjustments specified in the LNG SPA. 8 “Corpus Christi Facility” means the facilities that CCLNG intends to develop, own and operate (or have operated on its behalf) in San Patricio and Nueces Counties, Texas, in the vicinity of Portland, Texas, on the La Quinta Channel in the Corpus Christi Bay, including the Gas pretreatment and processing facilities, liquefaction facility, storage tanks, utilities, terminal facilities, and associated port and marine facilities, and all other related facilities both inside and outside the LNG plant, inclusive of the Designated Train and all other Trains. “Designated Train” means the third (3rd) Train that is commercially operable, as determined in accordance with Section 4.4. “Train” means an LNG production train located at the Corpus Christi Facility, including those facilities included in the Corpus Christi Facility that are necessary to enable Seller to fulfill its obligations to Buyer from such LNG production train. 9 “LNG Tanker” means an ocean-going vessel suitable for transporting LNG which complies with the requirements of this Agreement and which Buyer uses, or intends to use, in connection with this Agreement. 10 “Gross Heating Value” means the quantity of heat expressed in Btu produced by the complete combustion in air of one (1) cubic foot of anhydrous gas, at a temperature of sixty (60) degrees Fahrenheit and at an absolute pressure of fourteen decimal six nine six (14.696) pounds per square inch, with the air at the same temperature and pressure as the gas, after cooling the products of the combustion to the initial temperature of the gas and air, and after condensation of the water formed by combustion.

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5.5.2 If, with respect to any cargo identified in Section 5.5.1, Buyer does not take all or part of the Scheduled Cargo Quantity of such cargo, and such failure to take is not otherwise excused pursuant to Section 5.5.1, then the amount by which the Scheduled Cargo Quantity for such cargo exceeds the quantity of LNG taken by Buyer in relation to such cargo shall be the “Cargo Shortfall Quantity”.

5.5.3 With respect to any Cargo Shortfall Quantity, Buyer shall pay to Seller Cover Damages in accordance with the following, if Cover Damages are a positive amount.

(a) “Cover Damages” shall be equal to: (i) the CSP11 multiplied by the Cargo Shortfall Quantity; minus (ii) the proceeds of any Mitigation Sale, if any; minus (iii) reasonable and verifiable savings obtained by Seller (including savings related to avoided fuel Gas for LNG production, transportation and Third Party costs avoided) as a result of the Mitigation Sale as opposed to the sale to Buyer; plus (iv) actual, reasonable, verifiable, incremental costs incurred by Seller as a result of such Mitigation Sale (including costs related to transporting, marketing, selling, and delivery of the Cargo Shortfall Quantity). For purposes of calculating Cover Damages, the CSP shall be determined as of the Month in which the applicable Delivery Window begins.

(b) Seller shall use reasonable efforts to mitigate its Losses and reduce Cover Damages payable resulting from Buyer’s failure to take such Cargo Shortfall Quantity by reselling such Cargo Shortfall Quantity (whether as LNG or Gas), to Third Parties (each such sale a “Mitigation Sale”); except that any sale of a quantity of LNG (or Gas) by Seller to any Third Party that Seller was already obligated to make at the earlier to occur of (i) Buyer’s failure to take such LNG; or (ii) Buyer’s notice to Seller that it will not take such LNG, is not a Mitigation Sale.

(c) Notwithstanding the foregoing, if the Cargo Shortfall Quantity is within the operational tolerance of two percent (2%) of the Scheduled Cargo Quantity (“Operational Tolerance”) (such Operational Tolerance to be exercised by Buyer only with respect to operational matters regarding the LNG Tanker, and without regard to Gas markets or other commercial considerations), the Cover Damages shall be zero USD (US$0.00).

5.5.4 Any payment that Buyer makes under this Section 5.5 shall not be treated as an indirect, incidental, consequential or exemplary loss or a loss of income or profits for purposes of Section 15.2.1.

In addition to take-or-pay clauses in long-term LNG or gas contracts, other similar clauses with the same purpose of mitigating market risks and other matters that may have a depressing effect on the buyer’s take are used frequently. An example of this is the following ship-or-pay

11 “CSP” means the contract sales price (expressed in USD per MMBtu) for all LNG made available by Seller to Buyer.

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obligations used in the context of pipeline projects as in the 2009 AIPN Gas Transportation Agreement for pipelines already built:

SHIP OR PAY

Shipper's obligation

Shipper shall comply with the Nomination and Deliveries’ Procedure, shall pay the Monthly Transportation Charges, and shall pay, if any, the Annual Ship or Pay Payment.

1.1 The Adjusted Annual Reserved Capacity

1.1.1 Respecting each Contract Year the Adjusted Annual Reserved Capacity shall (subject to Article 12.2.2) be the Annual Reserved Capacity for that Contract Year after the deduction of the aggregate (without double counting) of the following quantities of Gas arising respecting that Contract Year:

1.1.1.1 any quantity of Lost Gas;

1.1.1.2 any quantity of Gas not delivered by Shipper at the Input Point because of a Force Majeure Event affecting Shipper (to the extent permitted under Article 21);

1.1.1.3 any quantity of Gas not delivered by Transporter at the Delivery Point because of a Force Majeure Event affecting Transporter (to the extent permitted under Article 21); and

1.1.1.4 any quantity of Gas not transported in the Pipeline respecting a Maintenance Day to the extent of the Maintenance RC Reduction applicable to the Maintenance Day.

1.1.2 The Adjusted Annual Reserved Capacity respecting each Contract Year shall never be less than zero.

While take-or-pay clauses are commonly used as a part of the risk division mechanism included in long-term gas contracts, the experiences in the 1980s and 1990’s in the United States made such clauses an unwanted part of the contracts in the US. The next section will now briefly explain these developments.

Example of the Difficult Past: Take-or-Pay Wars in the United States12

While long-term take-or-pay contracts had been used as a risk division mechanism in the US from 1930, the Natural Gas Policy Act resulted in a boom of this type of contracting. Due to government regulation pipelines could not compete on price and as a result they competed through non-price arrangements such as long-term take-or-pay agreements that offer the producer security against demand fluctuations. The producers began to require take-or-pay

12 This section is based on F. Bosselman, J. Rossi, J. Weaver, Energy Economics and the Environment (Foundation Press 2000).

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clauses and pipeline companies accepted. The number of this type of contract went from about 35% in the early 1970s up to about 90% in 1980’s. Eventually, this resulted in prices too high for the market that are locked in through take-or-pay clauses at a time of excess supply.

The gas prices unexpectedly started to rise, the result of various factors including the shift from the old industry structure and pre-existing long-term agreements and because of the policy of the FERC.13 Despite high prices, pipeline companies – believing gas to be in short supply - continued to purchase all available gas on long-term take-or-pay contracts allowing no renegotiation or flexibility. When deregulation revealed that true availability of supply, prices fell sharply and the pipelines found themselves obliged to take volumes of gas, which at prices well above those created by new market conditions. This led to an era of court proceedings (pacta sunt servanda v. force majeure and other legal doctrines) and the enactment of laws that would circumvent pre-existing contract terms.14

By this time, the contractual structure of the gas industry was based on long-term agreements throughout the gas chain: producers and pipeline companies had long-term take-or-pay contracts in place, pipeline companies and local distribution companies had entered into long-term minimum bill contracts (similar to take-or-pay agreements), local distribution companies had captive customers and the price of gas was rising. Industrial players with switching capability had opted for other fuels and this obviously worsened the situation. State regulatory authorities, alarmed at the impact on consumers, began to invalidate minimum bill provisions, allowing distribution companies to extricate themselves from their obligations. This left pipeline companies contracted to take or pay for gas at prices far above market levels. In this situation the FERC started working towards a comprehensive restructuring of the natural gas industry in the US.

These developments made take-or-pay provisions in US natural gas contracts largely disappear for a number of years around 1980’s. The relatively recent LNG project boom following the shale revolution, which profoundly changes the natural gas markets and made export projects possible, have also marked the rebirth of take-or-pay contracting.

Future of Take-or-Pay Clauses

An increasing number of countries or regions are moving towards a more liberalised and competitive model for their markets for natural gas. With liberalised markets for natural gas have been in place in areas like the US or the EU for decades, many Asian countries are now moving towards this direction.15 Even the Eurasian Economic Union is moving to a more market based model though the available details of this market creation efforts suggest that the model will not be based on full liberalisation.16 Also countries in Latin America, including Brazil, are exploring alternatives for a new market model based on competition.17 Creation of

13 For development of the US regulatory regime for natural gas prior to the “take-or-pay wars”, see R Pierce, ‘The Evolution of Natural Gas Regulatory Policy’ (1995) 10 Natural Resources and Environment 53. 14 An overview of the take-or-pay litigation is provided in M Medina, “The Take-or-Pay Wars: A Cautionary Analysis for the Future”, Tulsa Law Review 27 (1991) 2, p. 283-312. 15 https://www.spglobal.com/en/research-insights/articles/asian-lng-landscape-shifts-as-emerging-markets-liberalize (last accessed 7 April 2020). 16 Eurasian Economic Union Treaty dated 29 May 2014, especially Article 83. 17 Energy Intelligence, Oxford Institute for Energy Studies, Vol. 30, No. 28 (10 July 2019).

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liberalised and competitive markets for natural gas will undoubtedly put pressure on take-or-pay clauses with a fixed price in long-term contracts.

There is no doubt that take-or-pay clauses are an essential element for long-term natural gas contracts where these contracts relate to “greenfield” investments or investment where amortisation has not fully occurred. The more difficult questions arise when take-or-pay clauses are included in agreements without these underlying elements; that is, contracts for existing gas projects with infrastructure already in place and paid for.

These situations are much more complicated. The recent antitrust report by the Japan Fair Trade Commission (“JFTC”) in 2017 focusing on international LNG trade and liquidity of international LNG markets18 focused on two particular types of clauses in international LNG contracts: diversion clauses19 and take-or-pay clauses. The approach of the JFTC for take-or-pay for existing projects is telling:

Guarantee of sustainable and full payment of contract by users is an important element for a final investment decision because an LNG project needs a large initial investment and loans. In this sense, providing Take or Pay clauses in a fixed-term LNG contract has some necessity and reasonableness, and providing such clauses is not in itself problematic under the Antimonopoly Act. Some contracts provide Take or Pay clauses even after a full payment of loans related to an initial investment in an LNG project from lenders. Although some sellers point out that they need an additional investment in development of gas fields and other equipment to maintain source gas even after full return on the initial investment, such additional investment is not as large as the initial investment. On the other hand, because an annual contract quantity is defined in concluding a contract, it could be difficult for a buyer to receive the pre-defined annual contract quantity due to later demand fluctuation and so on. Therefore, when a seller’s bargaining position is superior to that of a buyer and the seller unilaterally imposes Take or Pay clauses and strict minimum purchase obligation without sufficient negotiation with the buyer even after the seller has already got sufficient return for initial investment, strict minimum purchase obligation as well as providing Take or Pay clauses are likely to be in violation of the Antimonopoly Act.

The issue raised by the JFTC is that for existing projects, the absolute necessity for take-or-pay may not be there. As take-or-pay clauses make market liberalisation efforts more difficult by reducing liquidity through interlocking the project parties for long periods of time, the approach of the JFTC is understandable in some circumstances.

However, there are other circumstances where the findings of the JFTC can be problematic. In some instances a seller with respect to a completed facility may require long-term derisked cash flows in order to finance one or more other projects that are undergoing development. Similarly, the seller may want to expand its supply infrastructure, and requires significant financing to do so. In these cases, the use of take-or-pay clauses may still be required by the lenders. For example, in order to ensure constant flow of gas for an LNG facility or to

18 https://www.jftc.go.jp/en/pressreleases/yearly-2017/June/170628.html (last accessed 8 April 2020). For background, see https://www.bakerbotts.com/insights/publications/2017/03/japanese-antitrust-scrutiny (last accessed 8 April 2020). 19 For diversion clause discussion see K. Talus; "Contribution of Law and Lawyers to LNG Market Developments: Model Diversion Clause for LNG Sale and Purchase Contracts" OGEL 4 (2018), www.ogel.org.

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eventually increase the capacity of a liquefaction plant, the seller may want to have pipelines in place to a number of different producing areas (ie, not rely on Louisiana fields only and to connect Permian basin with an export project). Here, the project structure may make take-or-pay a necessity even if the current infrastructure is in place and paid for.

Another example where take-or-pay may be of particular import is decommissioning. The seller may be subject to significant decommissioning obligations and a take-or-pay provision may be necessary in order to give comfort to the lenders that the project will be able to cover its decommissioning phase.20

An Example of Take-or-Pay Clauses in Liberalised Markets: European Union

The approach in the European Union and its liberalised natural gas market appears to be accommodating for take-or-pay clauses. In the EU, this applies to both sector specific regulatory framework and the praxis in antitrust enforcement.

The European Commission, which both initiates the legislative process for new energy sector specific regulations and acts as the EU level antitrust authority had the opportunity to examine long-term take-or-pay contracts in its 2007 energy sector inquiry.21

Throughout the sector inquiry various parties submitted views on a variety of matters, including take-or-pay contracts and their suitability in a liberalised gas market. Established buyers, the incumbents, argued that because of the volume risk the purchaser assumes the traditional long-term gas sales agreement, the take-or-pay element of the contract, including the downwards flexibility, is necessary since it allows for the necessary flexibility in their purchase and storage portfolio.22 This view was contrasted by the new entrants, who argued that this element of the contracts internalises the role of the wholesale markets, price and volume risk, with a negative effect on the development of a real EU wholesale market. In their view, liquid wholesale markets would render this element of the contract unnecessary. Companies could use the wholesale markets to manage price and volume risks.23

In a related press release the Commission laid out its view on long-term take-or-pay natural gas contracts and market liberalisation:

“Long contract duration is not, in itself, anti-competitive. It is established Commission policy that long term import contracts have an important role to play when it comes to ensuring Europe’s security of supply. However, where a significant proportion of the gas that can come to the market is locked in for the long-term, the cumulative effect might be that new entrants are excluded from the market. Individual terms and conditions contained in such contracts may also be anti-competitive: e.g. territorial restrictions are generally viewed negatively under Community competition rules. However, legitimate needs to underpin large investments with certain long-term

20 For discussion, see P Roberts, Gas and LNG Sales and Transportation Agreements: Principles and Practice, 5th ed., 2017, at para. 13-022. 21 European Commission, DG Competition report on energy sector inquiry (SEC(2006)1724) 10 January 2007. 22 Ibid., p. 209. 23 Ibid., p. 209 and 210.

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contracts, must be taken into account”.24

This view of the Commission reflects well the approach taken in the EU towards long-term take-or-pay contracts: a careful acceptance that there is a place and need for these contracts.

Article 32 (3) of Directive 2009/73/EC concerning common rules for the internal market in natural gas25 (Third Gas Market Directive) explicitly notes that “The provisions of this Directive shall not prevent the conclusion of long-term contracts in so far as they comply with Community competition rules.”

The significance of long-term contracts is also recognised in the preambles to various secondary EU law instruments. First, both the 1998 Gas Market Directive and the 2003 Gas Market Directive consider upstream long-term gas supply contracts to be beneficial for the EU. The 1998 Gas Market Directive recognised long-term planning as necessary for carrying out public service obligations, taking into account the possibility of third parties seeking access to the system.26 The 2003 Gas Market Directive recognises that long-term gas supply contracts provide an important part of the Member States’ gas supply and should be maintained as a valid option for gas supply undertakings in so far as they do not undermine the objectives of the Directive, specifically, the completion of an efficient and competitive internal gas market, and are compatible with the primary EU law, including competition rules.27 The Third Gas Market Directive from 2009 also notes the same, and provides that

“Long-term contracts will continue to be an important part of the gas supply of Member States and should be maintained as an option for gas supply undertakings in so far as they do not undermine the objective of this Directive and are compatible with the Treaty, including the competition rules. It is therefore necessary to take into account long-term contracts in the planning of supply and transport capacity of natural gas undertakings.”28

In addition to this, the Third Gas Market Directive notes that

“Natural gas is mainly, and increasingly, imported into the Community from third countries. Community law should take account of the characteristics of natural gas, such as certain structural rigidities arising from the concentration of suppliers, the long-term contracts or the lack of downstream liquidity. Therefore, more transparency is needed, including in regard to the formation of prices.”29

24 Energy sector competition inquiry – final report – frequently asked questions and graphics (MEMO/07/15, 10.1.2007.) 25 Directive 2009/73/EC of the European Parliament and of the Council of 13 July 2009 concerning common rules for the internal market in natural gas and repealing Directive 2003/55/EC (OJ L 211, 14.8.2009, p. 94). 26 Directive 98/30/EC of the European Parliament and of the Council of 22 June 1998 concerning common rules for the internal market in natural gas (OJ L 204, 21.7.1998, p. 1), preamble 13. 27 Directive 2003/55/EC of the European Parliament and of the Council of 26 June 2003 concerning common rules for the internal market in natural gas and repealing Directive 98/30/EC (OJ L 176, 15.7.2003, p. 57), preambles 7-8 and 25. 28 Directive 2009/73/EC of the European Parliament and of the Council of 13 July 2009 concerning common rules for the internal market in natural gas and repealing Directive 2003/55/EC (OJ L 211, 14.8.2009, p. 94), preamble 42. 29 Directive 2009/73/EC of the European Parliament and of the Council of 13 July 2009 concerning common rules for the internal market in natural gas and repealing Directive 2003/55/EC (OJ L 211, 14.8.2009, p. 94), preamble 37.

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The Third Gas Market Directive also provides for an exemption for take-or-pay agreements. The first reference to these agreements is provided for in Article 35, which allows a gas company to refuse access to its system on the basis of (I) lack of capacity, (II) where the access would prevent it from carrying out its public service obligations or (III) on the basis of serious economic and financial difficulties with take-or-pay contracts. The derogation for these take-or-pay agreements is then further specified in Article 48:

“If a natural gas undertaking encounters, or considers it would encounter, serious economic and financial difficulties because of its take-or-pay commitments accepted in one or more gas-purchase contracts, it may send an application for a temporary derogation from Article 32 to the Member State concerned or the designated competent authority. Applications shall, in accordance with the choice of Member States, be presented on a case-by-case basis either before or after refusal of access to the system. Member States may also give the natural gas undertaking the choice of presenting an application either before or after refusal of access to the system. Where a natural gas undertaking has refused access, the application shall be presented without delay. The applications shall be accompanied by all relevant information on the nature and extent of the problem and on the efforts undertaken by the natural gas undertaking to solve the problem.”

The decision by the national authorities must then be notified to the Commission. The Commission may then, within eight weeks of the receipt of the notification, request that the national authorities concerned amend or withdraw the decision to grant a derogation. The factors that the national authorities and the Commission must consider in particular in deciding on the derogation are: (a) the objective of achieving a competitive gas market; (b) the need to fulfil public service obligations and to ensure security of supply; (c) the position of the natural gas undertaking in the gas market and the actual state of competition in this market; (d) the seriousness of the economic and financial difficulties encountered by natural gas undertakings and transmission undertakings or eligible customers; (e) the dates of signature and terms of the contract or contracts in question, including the extent to which they allow for market changes; (f) the efforts made to find a solution to the problem; (g) the extent to which, when accepting the take-or-pay commitments in question, the undertaking could reasonably have foreseen, having regard to the provisions of this Directive, that serious difficulties were likely to arise; (h) the level of connection of the system with other systems and the degree of interoperability of these systems; and (i) the effects the granting of a derogation would have on the correct application of the Directive as regards the smooth functioning of the internal natural gas market.30

Considering the continuing significance of those take-or-pay agreements concluded prior to the liberalisation, it is significant to see that Article 48 also notes that a derogation concerning take-or-pay contracts concluded before 4 August 2003 should “not lead to a situation in which it is impossible to find economically viable alternative outlets. Serious difficulties shall in any case be deemed not to exist when the sales of natural gas do not fall below the level of minimum off-take guarantees contained in gas purchase take or pay contracts or in so far as the relevant gas purchase take-or-pay contract can be adapted or the natural gas undertaking is able to find alternative outlets.”

30 Article 48 (3) of the Directive 2009/73/EC of the European Parliament and of the Council of 13 July 2009 concerning common rules for the internal market in natural gas and repealing Directive 2003/55/EC (OJ L 211, 14.8.2009, p. 94).

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EU gas market directives make several references to the question of compatibility with EU competition law. Over the years, the European Commission has also seized the opportunity to examine long-term take-or-pay agreements and have found that certain clauses traditionally included in these type of agreements are problematic under EU competition law.31

Conclusion – After COVID-19

Today, the difference between an international natural gas project, even in the form of LNG, and an international oil project is significant. For a “greenfield” natural gas project, the need to lock -in long-term commitments is important for potential investors and lenders in making an investment decision. This is not the case for crude oil because it is a liquid market and there is always a demand for it at a market price. Despite the relatively recent emergence of a global market for natural gas, there has been no industry consensus on a single global pricing mechanism.

In this context, especially in light of the history of take-or-pay litigation in the U.S. domestic market, the emergence of rigid take-or-pay obligations in long-term gas and LNG contracts seems natural in order to incentivize significant investment in “greenfield” projects and expansion of existing projects in the space. As COVID-19 and its secondary effects grow, we may have a similar response in the international contracting market to what we saw in the U.S. in the 1980s, where litigation and bankruptcies devalues take-or-pay to the point where alternatives, such as ship-or-pay, become preferable, thereby disaggregating integrated companies and forcing midstream service providers to bear the risk of default for new natural gas projects. In the alternative, the lessons learned in the U.S. during the 1980s may have enabled lawyers and commercial teams to shore up their take-or-pay obligations with large, non-cancellable credit or debt obligations that continue to mitigate the seller’s risk, thereby providing investors with more comfort in their energy investments after COVID-19 is (in at least one optimistic scenario) little more than a seasonal worry addressed by something similar to the annual flu vaccine.

Impact on gas market developments towards a genuine liquid commodity market will also have an impact on the need for take-or-pay contracts. A more liquid market should mean that the seller can have more confidence about its ability to sell the product at an international market price. This of course downplays the importance of long-term take-or-pay contracts.

31 For this issue, see K. Talus, ‘Long-term natural gas contracts and antitrust law in the European Union and the United States’, Journal of World Energy Law and Business 4 (2011) 3, 1-67.

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OGEL 3 (2020) - Changing LNG Markets and Contracts OGEL, the global Oil-Gas-Energy Law Intelligence service. OGEL focuses on recent developments in the area of oil-gas-energy law, regulation, treaties, judicial and arbitral cases, voluntary guidelines, tax and contracting, including the oil-gas-energy geopolitics. -- www.ogel.org

Table of Contents - Volume 18, issue #03, published May 2020 - free excerpt available at https://www.ogel.org/journal-browse-issues-toc.asp?key=86 EDITORIAL

• Introduction - OGEL Special Issue on "Changing LNG Markets and Contracts" ��� by A. Ason, London School of Economics

LNG Markets

• Fate and Reform Catalyze Expansion of the Brazilian Natural Gas Market and Open Up Opportunities to LNG ��� by L. Diaz, FTI Consulting

• Greek LNG Market: Current Status and Future Developments ��� by L. Kopitsa and A. Voskos, London School of Economics and Political Science

• The Commercial Challenges Facing Eastern Mediterranean Gas ��� by A. Stanic, E&A Law Limited S. Karbuz, Bilkent University Energy Policy Research Center

LNG Contracts

• The Portfolio SPA: A Tool of Portfolio Marketing ��� by R. Maalouf, De Gaulle Fleurance & Associés

• Brentrification: Modifying the Brent Crude Oil Model to Create a Global LNG Pricing Benchmark with Standardized Contract Terms ��� by K.P. Kinnear, GPD Systems, LLC

• LNG Contract Adjustments in Difficult Times: The Interplay between Force Majeure, Change of Circumstances, Hardship, and Price Review Clauses ��� by K. Christie, M. Han, and L. Shmatenko, Peter & Kim Ltd

• Trends in LNG Supply Contracts and Pricing Disputes in the Asia Pacific Region ��� by S. Finizio, J.A. Trenor, and J. Tan, Wilmer Cutler Pickering Hale and Dorr LLP

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• Natural Gas Price Reviews: Commercial Lessons Learned in Continental Europe ��� by A.M. Pustišek, 2Pi-Energy GmbH; University of Applied Sciences, Stuttgart C. Merkel, Merkel Energy GmbH M. Karasz, THE ENERGY HOUSE GmbH

• Long-Term Take-or-Pay Agreements in Natural Gas Industry: Past, Present and Future ��� by K. Talus, Tulane Center for Energy Law, Tulane University S. Looper, Baker Botts LLP L.L. Burns, Baker Botts LLP

• Destination Flexibility in LNG Sales Contracts ��� by J.E.B. Atkin, Orrick, Herrington & Sutcliffe (UK) LLP

• LNG Disputes Beyond Price Reviews ��� by L. Agosti and B. Moselle, Compass Lexecon

Book Reviews

• The Globalisation of Russian Gas - Political and Commercial Catalysts by James Henderson and Arild Moe (Edward Elgar 2019) - Book Review Essay ��� by K. Talus, Tulane Center for Energy Law, Tulane University

• Gas and LNG Price Arbitrations: A Practical Handbook, James Freeman and Mark Levy (eds), 2nd edition (Globe Law and Business 2020) ��� by A. Ason, London School of Economics

Copyright & Disclaimer © Copyright OGEL 2020. Please visit our website at www.ogel.org for our terms & conditions notice.

Oil, Gas & Energy Law (OGEL, ISSN 1875-418X) is a peer-reviewed academic journal covering all aspects of law pertaining to oil, gas, and energy in general. Since the first issue was published in 2003 it has gained popularity with a large number of (international) energy companies, governmental organisations, law firms, international agencies, academic and think-tank institutions in the field of energy policy and various NGOs.

2020

• OGEL 3 (2020) – Changing LNG Markets and Contracts

• OGEL 2 (2020) – Regulation of Petroleum Development in Guyana

• OGEL 1 (2020) – Social Licence to operate (SLO) in the Extractive and Energy Sectors

2019

• OGEL 5 (2019) – Natural Gas Pipeline Construction and Regulation

• OGEL 4 (2019) – African Extractive Sector (FDI) • OGEL 3 (2019) – The Energy Union in the Next

Decade • OGEL 2 (2019) – Regular issue • OGEL 1 (2019) – Energy Law and Regulation in

Low-carbon and Transitional Energy Markets

2018

• OGEL 5 (2018) – Strategic Considerations in Energy Disputes

• OGEL 4 (2018) – Regular issue • OGEL 3 (2018) – International Energy Law

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• OGEL 2 (2018) – Decommissioning • OGEL 1 (2018) – Regular issue

2017

• OGEL 4 (2017) – Liquefied Natural Gas (LNG) • OGEL 3 (2017) – Energy Law and Policy in the

Middle East and North Africa (MENA) • OGEL 2 (2017) – Brexit • OGEL 1 (2017) – Oil and Gas Law and Policy in

West Africa

2016

• OGEL 4 (2016) – Regular issue • OGEL 3 (2016) – Waste-to-Energy (WtE) • OGEL 2 (2016) – Emerging Issues in Polar

Energy Law and Governance • OGEL 1 (2016) – Mexico's Oil and Gas Sector

Reform

2015

• OGEL 1 (2015) – Regular issue • OGEL 5 (2015) – Yukos Special • OGEL 4 (2015) - International Taxation in the

Energy Sector • OGEL 3 (2015) - Renewable Energy Disputes • OGEL 2 (2015) - Laws Regulating the Polish

Energy Sector - Transition • OGEL 1 (2015) - Natural Gas Developments: An

International and Challenging Legal Framework

2014

• OGEL 4 (2014) - Regular issue • OGEL 3 (2014) - OGEL Special: Governance of

Unconventional Gas outside the United States of America

• OGEL 2 (2014) - Energy Community • OGEL 1 (2014) - Special: Offshore Petroleum

Exploration and Production: Challenges and Responses

2013

• OGEL 5 (2013) - Regular issue • OGEL 4 (2013) - Joint Operating Agreements &

National Oil Companies: Challenges and Dynamics

• OGEL 3 (2013) - Eastern Mediterranean Oil and Gas

• OGEL 2 (2013) - Risks and Responses to Risk in the Energy Sector

• OGEL 1 (2013) - Nuclear Law and Policy

2012

• OGEL 5 (2012) - Regular issue • OGEL 4 (2012) - The Interface between EU

Energy, Environmental and Competition Law - A Survey

• OGEL 3 (2012) - OGEL Ten Years Special Issue: Internationalisation of Energy Law

• OGEL 2 (2012) - Arctic Region: Boundaries, Resources and the Promise of Co-operation

• OGEL 1 (2012) - A Liber Amicorum: Thomas Wälde - Law Beyond Conventional Thought

2011

• OGEL 6 (2011) - Regular issue • OGEL 5 (2011) - Regular issue • OGEL 4 (2011) - Indigenous People and

Resources Development • OGEL 3 (2011) - Cross-Border Pipelines • OGEL 2 (2011) - Comparative Energy Law • OGEL 1 (2011) - Regular issue

2010

• OGEL 4 (2010) - Host Government Contracts in the Upstream Oil and Gas Sector

• OGEL 3 (2010) - Oil Spills • OGEL 2 (2010) - Kazakhstan • OGEL 1 (2010) - Antitrust in the Energy Sector

2009

• OGEL 4 (2009) - Regular issue • OGEL 3 (2009) - Student special • OGEL 2 (2009) - EU - Russia relations • OGEL 1 (2009) - Middle East With a Focus on

Buy Back Contracts

2008

• OGEL 3 (2008) - Eurasian Energy • OGEL 2 (2008) - Venezuela: The battle of

Contract Sanctity vs. Resource Sovereignty • OGEL 1 (2008) - China's Energy and

Environmental Challenges

2007

• OGEL 4 (2007) - Energy Security • OGEL 3 (2007) - Energy Litigation and

Arbitration - Expert Perspectives • OGEL 2 (2007) - Unisitation • OGEL 1 (2007) - Electricity Interconnectors (2nd

special) - Regular issue

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2006

• OGEL 4 (2006) - Pipelines • OGEL 3 (2006) - Africa • OGEL 2 (2006) - Electricity Interconnectors • OGEL 1 (2006) - Liquefied Natural Gas (LNG) -

Regular issue

2005

• OGEL 4 (2005) - Asian Energy Law and Policy • OGEL 3 (2005) - Coal • OGEL 2 (2005) - Windpower • OGEL 1 (2005) - Production Sharing Contracts

2004

• OGEL 5 (2004) - Energy Charter Treaty • OGEL 4 (2004) - Corporate Social Responsibility

(CSR) - Regular issue • OGEL 3 (2004) - Taxation / Latin America • OGEL 2 (2004) - Renewable Energy • OGEL 1 (2004) - Climate Change

2003

• OGEL 5 (2003) - Corruption / Geopolitics of Oil and Gas

• OGEL 4 (2003) - Natural Gas • OGEL 3 (2003) - Energy and Electricity

Regulation • OGEL 2 (2003) - Dispute Management in the Oil,

Gas and Energy Industries • OGEL 1 (2003) - Regular issue