In this article, Dominic Whittome covers recent changes to wholesale energy prices.
Energy prices continued to climb across the board with petroleum leading the field as crude prices rose by over 28%. The relatively modest price environment over 2016 to 2020, followed by the sharp price fall once the pandemic took hold last April, has compromised investment in many North American shale projects, which generally require frequent re-evaluation and investment compared to conventional drilling. Such projects must soon contend with the harsher operating environment expected for oil & gas producers. In particular, subsidies embedded deep within the US tax code, which had helped marginal fracking projects over the line in recent years, look set to be repealed soon. The ‘Green Chapter’ promised by the incoming Biden Administration may well thwart any renaissance in future US exports, even if oil prices do recover significantly from this point on.
Further to the last update, the investment famine in key oil producing countries including Iraq and Libya, across the production, transport, storage and export terminal supply chain, appears to be worsening. New investment has been hampered by comparatively low oil prices, heightened regulatory & financial uncertainties facing international lenders and energy majors and the general perception of mismanagement, political turmoil and civil unrest. All of these have served to thwart a much-needed influx of overseas management & engineering expertise as well as capital itself.
Finally, before the sharp price collapse last April when the pandemic struck home, several reputable research houses had been predicting a long-term recovery in oil prices, or “commodities super-cycle” as one Wall Street investment bank coined. If such predictions hold water and the cost of newly-maintained or recoverable does rise sharply, then the current pandemic may simply be delaying the ‘day of reckoning’ for oil prices, provided this research remains valid today and the market has yet to adopt or discount these expectations into the forward prices.
Taking its cue from petroleum, forward gas prices rebounded 24% over the period and have continued to strengthen going to press. Inventory levels at almost every major gas storage facility on the Continent are now reported well below last year’ levels and below 70% capacity in some instances. Colder Siberian weather was recently forecast by a consensus of meteorological offices and with North European Prompt and Forward markets both on the rise since. On the home front, the UK system may look robust, certainly on paper with a gas input-mix consisting of circa 45% UK Continental Shelf supply, 10% Norwegian North Sea, 5%+ LNG imports and some 40% from a variety of major sources via interconnectors from the Continent. However, there are caveats which are relevant now. First up, the mere existence of LNG import terminals and gas interconnectors is no guarantee that the gas volume needed will finally arrive. Today the GB system has no high-volume gas storage facility to fall back on following the closure of the Rough field in 2017. So, when it comes to finding marginal supplies, the extra gas needed to balance the GB system, the spot or Day-Ahead Market price is ultimately set by the highest international bidders. This task is managed by traders and utilities alike but the associated costs and risk-premiums are increasing, inevitably passing down to the consumer.
The last three months also witnessed economic activity ticking up across South East Asia. Shipping charter rates hitting historic highs and spot LNG prices climbed significantly. But the outlook for the GB gas prices needs to be seen in context of foreseen changes in demand. In the background is the undoubted government effort to wean domestic consumers off gas altogether, now with a ban on the sale of domestic gas boilers as soon as 1st January, 2025. Although how soon such measures will cut gas demand remains to be seen.
Base-load electricity was the more settled commodity of the three but still finished 18% up over the quarter. The power market shares many issues just mentioned in relation to gas and it is set to become more volatile as conventional gas and coal generation is replaced by less-dependable supplies of renewable or imported electricity. Interconnectors will play an increasing role. The GB market already has three major import cables in place and three under construction plus a potentially very long, 1.2 GW wire linking Scotland to Iceland after 2025.
Again, while these import capacity figures may look promising on paper, on-the-day reality can be different. In fact, the reliability questions that surround renewables can also apply to interconnectors. To take one example, in the midst of the current cold snap, the state-of-the-art 1.0 GW BritNed interconnector linking the UK to Holland remains closed for repair until mid-February. Not an isolated example: there are frequent, unavoidable issues with sub-sea cables generally, be they old or new. This is another issue for traders, utilities and end-users to contend with as UK dependence of marginal imports increases. Consequently, Annual Contracts may have higher risk-premiums factored into them as company supply pools become riskier and more expensive to manage.
Another issue, one specific to the Forward Market itself, is weak liquidity. This will only sharpen price volatility and lead to more opaque, untrustworthy OTC market prices, which is a problem for buyers because Annual Contacts are priced against them. The problem is not new. The exodus started with the collapse of Enron and fellow US energy merchants. Their ‘liquidity providing’ role was not taken up in the main by the surviving utilities who took their place. That was followed by the financial crisis and was exacerbated further by strengthening MiFID legislation. The EU’s Market in Financial Instruments directives has made cross-commodity hedging, trading and compliance alike a riskier, more complex and expensive affair, inducing many of the remaining players to exit the Forward Market. This looks unlikely to change post-Brexit, in spite of a deal excluding Financial Services. We may yet see energy majors, now investing in electricity supply & trading operations, move in to fill the void. But there is no evidence of this yet. Barring government intervention, which looks doubtful, the UK power market looks set to remain illiquid for some while. Consequently, OTC prices in the Forward Market could be disproportionately influenced by short-term issues by taking their cue from the Prompt. So, hardly a very efficient-looking market but one which industrial & commercial buyers will be navigating with the April Year 2021 Buying Round now well underway.
About the Author
Dominic Whittome is an economist with 25 years of commercial experience in oil & gas exploration, power generation, business development and supply & trading. Dominic has served as an analyst, contract negotiator and Head of Trading with four energy majors (Statoil, Mobil, ENI and EDF). As a consultant, Dominic has also advised government clients (including the UK Treasury, Met Office and Consumer Focus) and private entities on a range of energy origination, strategy and trading issues.
Prospect Law is a multi-disciplinary practice with specialist expertise in the energy and environmental sectors with particular experience in the low carbon energy sector. The firm is made up of lawyers, engineers, surveyors and finance experts.
This article remains the copyright property of Prospect Law Ltd and Prospect Advisory Ltd and neither the article nor any part of it may be published or copied without the prior written permission of the directors of Prospect Law and Prospect Advisory.
This article is not intended to constitute legal or other professional advice and it should not be relied on in any way.
For more information or assistance with a particular query, please in the first instance contact Adam Mikula on 020 7947 5354 or by email on [email protected].