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Shale gas price hedging: a cash machine at stake?

April 17th, 2011 by Pierre-Adrien Ludwig, Mines ParisTech

The fast development of shale gas has revolutionized the American natural gas market; shale gas production now represents more than 20% of the domestic consumption. Meanwhile, natural gas prices dropped: the NYMEX price now stagnates around $4/MMBtu from $12 in June 2008. How is it possible to ensure a fast-increasing and profitable production at such prices? Part of the answer is that producers were actually paid a much higher price, thanks to hedging strategies on commodity markets. But now, pessimistic market expectations make it harder and harder to benefit from this mechanism, putting an important share of this capital-intensive industry’s cash resources at risk.

In a context of high market uncertainty, with an increasing supply and stagnating prices, shale gas producers have been extensively using hedging as a way to mitigate their price risk and to ensure a profitable gas production. Whereas it is very unusual for international companies to do so, shale gas producers use price financial derivatives as part of their strategy; by using swap contracts, they are indeed able to fix the selling price of a share of their production to come.

The first reason why hedging has been used is that the development of shale gas was not lead by Supermajors but by independent and often specialized companies such as Chesapeake, XTO (acquired by Exxon Mobil in 2009), Anadarko, Devon, and EnCana. Supermajors bet on a global commodity price increase and are therefore seeking the highest oil price leverage possible, by investing on high risk/high reward projects: being exposed to commodity prices is a core element of their strategy. An international oil company’s objective is indeed to pay dividends to its shareholders thanks to high-return project; it is made possible by its strong balance sheet, which allows it to take risks that a smaller company would not dare to take. Independent shale gas producers have the opposite risk profile: these companies’ risk is highly concentrated as they rely on a unique exploitation technology, produce gas in a single or few countries, and sell their whole production in the same market. Hedging natural gas prices is therefore a way to mitigate operational and country risk, and to secure their profit to come.

Secondly, the industry is structurally capital-intensive and has some particularities compared with conventional gas exploitation. The market has experienced a “rush for acreages”, during which producers acquired quickly large concessions in order to secure the most promising acreages, despite limited knowledge of geological conditions, which required additional cash. The high need for cash combined with their price-sensitive nature explains the will to secure their selling price through hedging.

Finally, by nature, shale gas wells tend to have much steeper decline curves than conventional gas wells. As a consequence, profit must be made in a shorter period, and the price risk is more concentrated in the early months of production than for conventional gas.

Shale gas producers have more or less successfully implemented price hedging strategies for their production. The following graph shows the hedging gain or loss that has been made quarterly by the largest independent shale gas producers in the US, compared to the Henry Hub spot price. It is defined as the gain (loss) due to the price differential between the spot price and their actual selling price for their hedged production.

This chart shows a high variance in the exposure to spot prices among these companies. Unsurprisingly, hedging losses have been made during the 2008 peak of natural gas prices, and gains have been made since the beginning of the collapse of the Henry Hub in mid-2008. Indeed, when the Henry Hub rocketed in 2008, some of these companies had already hedged part of their future production at a lower price, because this sudden increase was unexpected. The opposite phenomenon happened in 2009 and 2010, and producers thus managed to hedge at much higher prices.

Companies do not restrict their hedging strategies to exchanges such as the NYMEX. They also use over-the-counter (OTC) transactions, which consist in trading financial instruments directly between two parties; it can be a way to achieve to lock higher prices than on the exchange. The following benchmark shows the NYMEX-related price at which shale gas producers have been able to sell their production, on a quarterly average basis. It is compared to the quarterly average of the Henry Hub spot price and to futures contracts: for a given quarter, the blue area indicates a range of futures contracts with a delivery due during the quarter.

The comparison between reported selling price and the Henry Hub spot price highlights the premium brought by hedging to the profit of these companies. Some of them are able to sell at a price more than 30% higher than the spot price, enhancing dramatically their wells’ rates of return. The comparison with the NYMEX futures contracts shows that most of the companies only hedge a small share of their production and therefore do not reach futures prices. In the other hand, Chesapeake and XTO achieve to sell at prices above the range of futures. The use of OTC transactions is one of the main explanations. The most striking example is the creation by Chesapeake of a multi-counterparty hedging facility with thirteen counterparties which provides it a hedging capacity of about four years of production. In addition, Chesapeake’s obligations are secured by its reserves, while the counterparties’ are secured by cash, providing new liquid assets for Chesapeake’s investments.
Shale gas producers have been widely using price hedging in order to secure their cash flows, and it has been a successful choice over time for these companies. Some of them have even developed their own trading infrastructure in order to optimize their hedging strategies. A recent study by Citi showed that in 2010, hedging gains represented on average 14% of top shale gas companies cash flows and up to 30 or 40% for some companies. Natural gas price hedging has indeed been a non negligible source of cash, and an accelerating factor for the development of shale gas. But given the widespread gloomy forecasts, due to the current gas glut and a still fast-increasing supply, hedging at high prices is logically becoming increasingly difficult for gas producers, and it does not provide the financial leverage it used to. The price differential between a futures contract with a delivery due in 12 months and the spot price has narrowed to below $0.5/MMBtu, far from the historical $1.5/MMBtu. Producers are now seeking new ways of improving their returns, such as focusing on oil-rich gas reservoirs; with a $107/bbl oil price, it remains a safe value, far from the worry about natural gas.

Pierre-Adrien Ludwig, Mines ParisTech

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6 Responses to “Shale gas price hedging: a cash machine at stake?”

  1. Paul Hunt Says:

    Very interesting post. Thank you. Do you envisage a round of mergers and acquisitions by the majors as the going gets tougher for these players? The previous limited participation of the majors in the US gas market has been accompanied by limited exercise of market – generally to the benefit of final consumers. It would be a shame if this were to change.

  2. Daniel Go Says:

    I do not believe that owners of gasoline companies are losing much money with gas crisis around the globe. I’m pretty sure they have their own strategies for this problem, as it has been occurring for more than a decade, or so. What seems to be the problem here is the disadvantage the final consumers are getting–they are paying more!

  3. Chingis Dugarzhapov Says:

    Today’s high rates of shale gas extraction (even in spite of pessimistic market previsions) are caused by huge investments of oil companies in research in this area after oil shock in 2008. Till now, we can say that these investments gave a significant feedback.

    In my opinion, inability to secure future cash will hardly attract more supermajors to the market. Expansion of the activity in the shale gas industry forces to look for new acreage, outside of the United States. However, the techniques of shale gas extraction are known for its strong negative ecologic point. The most important US extraction points are in Texas and North Dakota. New big exploitations can be envisaged only in desert area, such as Northern Australia, Southern Africa and China, where experts can close eyes on ecologic aspects. In Western Europe, where environment is strictly protected, this initiative will not pass.

    In 2005 biggest American oil companies bought permissions for exploration of its territory on aspect of shale gas. Even despite stunning success of industry during 2009 in US, as well as fruitful unconventional gas reservoirs found in Poland, in December 2009 polish government signed a new 37-year contract with Gazprom. This shows that today even countries that policy is relatively relaxed towards ecology, can not completely rely on shale gas. Besides environmental aspect, there is a lack of technology advance in the area – there is no unique technology applicable on every shale gas deposit. Latest large acquisitions in the industry aim more purchasing of technologies rather than extraction capacities.

    Limited participation of majors in the market is due to their heavy weight and high inertia, while other smaller start-up companies have already occupied (at least) US market.

  4. Jeff Makholm Says:

    The freewheeling investment in, and production of, shale gas in the United States is indeed faciliated by the highly liquid market for financial hedges. But that begs a question: Why is financial hedging such a big element in shifting risk among parties in the United States and not, say, in Poland?
    The answer is the open, highly transparent and competitive market for gas transport in the United States and the utter lack of such in Europe. After 2000, the restructured and regulated interstate pipeline system in the United States became an open highway to market any gas that can reach it–the key reason why the futures market for commodity gas exists in the United States (and is 2,600 times the size of Europe’s, as reported by Jean-Michel Glachant–citing me–in his recent vision for the EU target model in gas).
    Shale gas producers in the Unted States can openly sell their gas at competitive prices ANYWHERE the interstate pipeline system reaches without the “permission” of the handful of firms that own the bulk of regulated pipelines themselves. Hence the easily availability of financial hedge products. Potential Polish shale gas producers confront a closed and cartelized EU gas supply system where the major pipeline owners/gas suppliers have successfully blunted any serious moves to pursue transparency, real unbundling, or rivalry in transpot (indeed the 3rd energy market package is an elegant example of broad-based institutional entry-deterrence serving the interests of the EU’s incumbent suppliers). Hence the lack of such a hedge market in the EU.
    Shale gas has been a game changer in the United States, helping to drive the competitive price of gas in 2011 down to half the energy-equivalent price of oil. The same would save the 155 million gas consumers in the EU27 well more than 50 Billion Euros a year. It all hinges on the availability of competitive pipeline transport–which, if shale gas production is to proceed in Europe as it has in the United States, will require much work, on behalf of Europe’s gas consumers this time, in the 4th energy market package.

  5. Managed Futures Says:

    The collapse of Amaranth Advisors after losing over 5 billion dollars trading natural gas futures shows us just how complex and difficult hedging in this market can be.

  6. Marie Busson, Mines ParisTech Says:

    Announced as the American Eldorado in 2007, it is worth looking back on the first 5 years of exploration and production to see whether cherished shale gas has kept its word. The most effective way to do it may be to focus on America’s biggest shale gas’ basin: Marcellus, in Pennsylvania.

    Despite a relative high gas price in the USA and enormous estimated resources – more than 400 trillion cubic feet -, production of shale gas was not cost effective until Oil & Gas companies assessed that hydraulic fracking could be a cheap way of producing shale gas. Non-majors American companies rushed on the acres and paid a high price based on the trillion cubic feet they could extract. They did not meet resistance from the near population. Americans know already the ins and outs of Oil & Gas production, Marcellus’s area is not densely populated and, perhaps the most important of all, proprietors of the acres also own the subsoil, according to the American law, meaning they earn part of the profits generated by the production.

    More than 1200 wells have been drilled in 2011 alone, namely 1000 times more than in 2007, enabling experts and companies to refine their assumptions. They both reached two main conclusions: some reserves won’t be workable with hydraulic fracking’s technique, and basin’s exploitable reserves are not homogeneous at all, resulting in a new unproved technically recoverable resource figure of 141 Tcf for the Energy Information Administration, (84 Tcf for the United States Geological Survey, often considered as the expert), 4 times less than the former estimation.
    On top of that, the Environment Protection Agency (EPA) began to study shale gas production’s consequences on nature and humans. They not surprisingly found that flowback water injected in deep groundwater for disposal was toxic and therefore made that water brackish, that chemical additives were harmful for humans, and at last that wells exploitation emitted more toxic gas than the exploitation of conventional resources (+3.5% to +12%). EPA is due to release rules on April 3rd, with a global objective to implement more environment friendly techniques and reduce gas emissions by 95%, which will undoubtedly increase shale gas production costs, and maybe hinder production if the State does not subsidize it.

    But those bad news hit some foreign companies harder, namely Mitsui. This Japanese company invested 1.4 $bn in 2010 for 100,000 acres in Marcellus with the long-term objective to liquefy gas and transport it to Japan to secure its energy supply, which seems now barely conceivable.
    Ironically enough, this phenomenon reoccurred for the same company in Poland, which holds 9% of working interests in a 2.1 million acres’ shale gas project. On March 16th this year, official estimation of resources dropped from 5.3 Tcf to 1 Tcf.

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