Climate Change in Law. Current Perspectives. Week 7.

21 June, 2022

Climate Change and long-term energy contracts

Author: David Mildon KC.

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  1. Planning for climate change has become increasingly topical. The senior executives of multinational companies are under pressure to demonstrate that they are taking such changes into account in their long-term investment decisions.
  2. This paper will look at a narrow sub-set of the legal topics which public opinion has forced onto centre stage. It raises problems which have been around for some time and for which there is at least some experience both at the point of contractual negotiation and in the implementation of existing contracts.
  3. It will focus on the energy industry (in its widest sense) because this is where the economic and legal impacts of climate change tend to be felt first. It will also focus on long-term relationships because that is a context which tends to present a significant share of imponderables.

Long-term Contracts and Assured Returns

  1. Long-term contracts have been a feature of the energy industry for a very long time. Many energy projects involve large investments with a payback spread over decades rather than years. Funding depends on the assurance of a market for the energy produced. This in turn has spawned what are in essence sale contracts with specialised characteristics.
  2. From the earliest days of the development of hydrocarbon reserves in the North Sea investors insisted on being able to sell future product under contracts which, in some cases, were still operative forty years later. Some of these contracts were explicitly negotiated on a “depletion” basis. They were intended to continue until the hydrocarbons from a named source ran out.
  3. Revenue from this type of resource was guaranteed by the now familiar “Take or Pay” obligations which became almost standard in long-term contracts for the sale of natural gas. Similar concepts were then deployed in so-called “Toll or Pay” contracts for the provision of liquefaction and regasification services at elaborate (and costly) shore terminals. And in the shipping industry very long-term bareboat and time charters proliferated in relation to the more specialised forms of carrier.
  4. It has been similar in the electricity industry following privatisation in the 1980s. Power is frequently sold under very long-term Power Purchase Agreements, which guarantee a return to the power plant which could not have been built without the assurance of a long-term return. It is the same with the transmission infrastructure. This is financed on the strength of contractual commitments to pay for transmission capacity whether used or not.
  5. A common feature of all these arrangements is a need to protect the return on a seller’s investment. But it is important not to look at these transactions exclusively from the seller’s point of view.
  6. In many instances the buyer has a long-term interest which it needs to protect. In the electricity industry in the Far East, including China, coal fired power stations need to lock in supplies of coal for very long periods at prices which are consistent with what can be obtained from the sale of electricity. It is the same in Europe where gas fired power stations need to buy long-term supplies on a reliable basis.
  • These are all sectors in which one or sometimes both parties are exposed to a policy environment in which the regulatory and fiscal position cannot be expected to remain unchanged for the life of a very long-term agreement.

Making Contractual Provision for Regulatory Change

  • For this reason it has for a long time been standard to make provision for what is to happen when the regulatory or fiscal environment changes. Price or tariff reviews are a commonplace which attempt to re-align the contractual consideration on a periodic basis.
  • Other techniques focus on the kind of charges, imposts, levies and windfall taxes to which the energy industry is periodically subject. A common drafting technique is to allow the “pass through” of changes – not just in tax in its narrowest sense, but also changes in the cost of compliance with regulatory charges and obligations.

ROCs, Carbon Credits and Trading in Carbon Emissions

  • The point to which I would like to turn, because it is specific to climate change, is the effect of climate mitigation measures which are market based.
  • As of now the most obvious example is carbon trading in virtual obligations which represent a unit of carbon emitted or captured, with the latter commonly described as a “carbon credit”.
  • The concept has a history which goes back at least twenty years when the UK incentivised investment in renewable power generation by introducing a statutory “renewables obligation”, which itself replaced something called the Climate Change Levy. The detail of this is beyond the scope of this paper, but at the risk of over-simplification the renewables scheme worked (and continues to work) essentially as set out below. For those who wish to drill down into the detail, the principal SI is the Renewables Obligation Order 2015 [2015] SI no 1947 as amended from time to time.
  • Suppliers of electricity to customers, whether for commercial, domestic or any other purpose, are required to produce to the industry regulator, OFGEM, evidence showing that a prescribed proportion of the electricity supplied within each annual period has been generated from renewable sources. That evidence has to consist of certificates known as “Renewables Obligation Certificates” or “ROCs” (for short) issued by the regulator to generators who have demonstrated to the regulator’s satisfaction that the electricity to which the certificates relate has been generated from prescribed renewable sources.
  • Each ROC certifies that a volume (in MWh) of electricity has been generated during a relevant period from prescribed renewable sources.
  • In the alternative such electricity suppliers have been permitted to discharge their “renewables obligation” by making a prescribed payment to the regulator. That payment is sometimes referred to as the “buy-out” price.
  • The prescribed proportion of total electricity supplies to which the obligation attached was deliberately set at a low level (around 3%) in the early years but rising steeply over the life of the scheme to much higher levels by the mid-2020s.
  • The practical effect of the “buy-out” price was to act as a cap on the cost to an electricity supplier of complying with its renewables obligation. Below the cap, the price that a supplier would be prepared to pay to obtain the requisite ROCs was a function of supply and demand. If renewable generating capacity remained scarce relative to the prescribed proportion of ROCs which the scheme required suppliers to produce, this would drive the price of ROCs up towards the buy-out price. If large volumes of renewables came on stream, that would drive the value of the ROCs down – but the underlying policy aim of the scheme would have been vindicated.
  • As an added incentive to investors in renewables capacity, the regulator was and is required to re-cycle the proceeds of the buy-out price to prescribed renewable generators in proportion to the volumes of renewable electricity produced.
  • The scheme has the attributes of a bespoke tax and subsidy regime in which the proceeds of a tax are hypothecated to prescribed beneficiaries.
  • For present purposes a critical feature of the scheme is that the ROCs were designed as marketable instruments. An electricity supplier could discharge its Renewables Obligation not just by buying ROCs as an incident of the purchase of electricity from a duly certified renewable source, but also by buying ROCs in the secondary market. This in turn led to many of the usual incidents of tradeable paper, including contracts for future delivery and options.
  • Over the years the ROC scheme acquired all sorts of “bells and whistles”, including extra ROCs for certain types of renewable generating capacity which were deemed worthy of additional support.
  • In 2014 the UK government introduced a new form of support for renewables, known as the “Contracts for Difference” (or “CfD”) scheme. The renewables obligation (and the resulting ROCs) remained in place for existing renewable generating capacity which had been built in reliance on the existence of the ROC scheme, but new investments in such capacity benefited instead from what was essentially a guaranteed revenue return per MwH for the electricity produced.
  • The CfD scheme operates by paying a flat index-linked strike price for the renewable electricity produced, with the differences between that and the current wholesale market price for electricity being funded by a government-owned entity, at a cost which is a charge known as the Supplier Obligation levy imposed at a rate per MWh of electricity supplied on the electricity supply industry as a whole. The scheme retains some market elements, notably the requirement for investors to bid for CfD protection in what have become a succession of auction rounds.
  • In parallel with the renewables obligation and extending over some other industries have been “Emissions Trading Schemes” promoted by the EU (known as “EU ETS”) and now replaced in the UK by a similar scheme known as “UK ETS”.
  • Once again the detail of these schemes is beyond the scope of this paper, but what is relevant for present purposes is that, as with the renewables obligation, carbon trading is designed to create a market for the emission of carbon (in tonnes emitted), which has to be offset in whole or in part by the purchase of credits from persons engaged in activities which are judged beneficial to the environment because they capture carbon rather than release it. In economic terms the intent is to impose an additional cost on those whose activities emit carbon, which can be re-cycled as a benefit to those whose activities capture carbon.
  • As with ROCs, these carbon credits are designed to be marketable and tradeable, with scope for similar market derivatives such as futures and options.

Treatment of Carbon Credits by Long-Term Contracts

  • At this point I want to return to the context which I identified earlier, namely the very long-term energy contract which includes provision for periodic price/tariff review and/or the pass through of the consequences of changes in tax or regulation.
  • I shall start with price or tariff review under a long-term (eg 25-year) Power Purchase Agreement for the output of a newbuild generating facility. The buyer is an electricity supplier which sells into the UK electricity market. There are provisions for periodic price review. The buyer says changes in the renewables obligation or the ETS are imposing increased costs which should be taken into account. The seller says that the costs could have been mitigated by a more sophisticated emissions or ROC trading strategy. Is this relevant? If so, how?
  • Or take a similar situation, but where the issue arises under a “pass through” clause which refers in broad terms to changes in any tax, charge or impost “of whatsoever kind”. Does the obligation to pay the buy-out price under the Renewables Obligation scheme come within this kind of rubric? Is it different if the buyer has chosen to discharge the obligation by buying ROCs at considerable additional expense to itself? As with the price review example, does it matter if the seller says that the costs could have been mitigated by a more sophisticated emissions or ROC trading strategy?
  • These are real live issues, which tend to arise under contracts with arbitration clauses, so the outcome remains under wraps and unknown to the uninitiated.
  • My own view, which I think tends to be shared by others who sit on arbitration panels dealing with this kind of issue both in the UK and in other jurisdictions, eg in the Far East, where similar questions have arisen, is as follows.
  • Firstly, every price review or pass through clause is different and the actual wording needs to be studied with care in each case.
  • With a price review, it is often but not always possible to detect an intention to re-base the price by reference to prescribed criteria which are generally similar to those which lay behind the original contract price. If those criteria were intended, even in part, to reflect the costs that the buyer would face in getting the product to market, it is not difficult to see why a change in those costs caused by a change in the regulatory regime should be taken into account on a price review. But I say “taken into account” advisedly. If the evidence is that a prudent operator would have hedged the price risk inherent in its RO or ETS obligations and the buyer has not done so, I can see an argument for saying that the new price should reflect what ought to have been done rather than what was actually done in order to discharge these statutory obligations.
  • Pass through clauses can be different. It is not always obvious what words like “impost” or “charge” mean. There is often an argument for giving the words used a reasonably broad meaning. But, equally, it is unlikely to have been intended that the pass through should be completely open-ended. It is generally implicit that the person claiming the benefit of the pass through should have acted as a prudent operator in taking steps to mitigate the statutory obligation or charge.
  • For these reasons my own experience is that arbitrations in this field can be closely fought and involve trading and expert evidence. The amounts at stake can be considerable.