Gas goes global

Unlike the highly liquid global oil market, natural gas has always been traded regionally. Asia, Europe and North America represent three different gas markets with their own unique dynamics.

Regional gas markets

Asia is very reliant on LNG (liquefied natural gas) imports. Natural gas demand significantly outstrips low levels of domestic production. Prices spiked after the Fukushima Daiichi disaster in 2011 when Japan began importing record volumes of gas for electricity generation to replace the output of nuclear power plants that were shut down.

North American gas production has always been strong, but exploded over the past few years. Hydraulic fracturing (or fracking) activity and the discovery of significant shale gas reserves halved North American gas prices between 2010-11. Prices remain at historic lows today. Henry Hub in Louisiana, where North American gas is physically delivered as well as virtually traded, is the world’s most liquid spot and futures market for natural gas. North America’s well-developed pipeline infrastructure also minimises transportation costs and promotes access to the market. And a high degree of competition lowers the barriers to entry.

Europe’s numerous trading hubs are still developing and are yet to match Henry Hub’s liquidity. Until recently the majority of European wholesale gas buyers maintained long-term contracts with mega-suppliers – namely Russia’s Gazprom and Norway’s Statoil. According to the Oxford Energy Institute, 2015 was the first year that more than fifty-percent of gas trades in Europe took place on the spot market. Demand has yet to return to pre-2008 levels and is still soft across the continent, but prices remain consistently higher than in the US.

Gas producers rely on pipeline infrastructure to connect supply with demand centres. This is why North America’s shale gas revolution and the subsequent decline in natural gas prices have not affected European prices – no pipeline crosses the Atlantic. But, LNG can easily be shipped between the continents. Why then are the world’s two biggest gas markets still disconnected?

Intercontinental LNG trade

LNG (liquefied natural gas) is made by cooling natural gas to -162ºC. This transformation to liquid shrinks the volume of the gas 600 times, making it safe and easy to ship. LNG is colourless, odourless and non-toxic. Nevertheless, the added cost of liquefaction, sea transportation in specialised vessels and regasification at the destination has so far limited global arbitrage opportunities.

Yet, a barrage of new LNG investment over the past few years has lead some to speculate that natural gas markets are globalising. The International Energy Agency claims that global liquefaction capacity will increase by forty-five percent between 2015 and 2021, with most of this growth coming from the United States and Australia. If this glut makes enough cheap LNG available then North American and European gas prices might slowly converge.

In February, the Cheniere Energy LNG terminal at Sabine Pass between Texas and Louisiana was the first to begin exporting. In anticipation of a LNG supply glut Eastern European countries, including Poland and Lithuania, have been building regasification terminals. Lithuania is testing floating regasification technology – offshore plants connected by pipeline to the shore. Spain, being part of a peninsula, is isolated from the European continent’s pipeline network. Historically, this has made it an important destination for LNG cargoes. In fact, the economic downturn since 2008 created an opportunity for Spanish buyers to reload LNG cargoes and sell them in Asia where prices are higher. This churn enhances liquidity. Otherwise, LNG is injected into the network all over Europe. There are important regasification terminals in the Mediterranean: Italy, Greece and France, as well as north-western Europe: the UK, the Netherlands and on France’s west coast.

US LNG producers are increasingly flexible too – offering variable volume contracts or FOB (free-on-board) cargoes. Variable volume contracts permit buyers to increase or decrease the amount of gas they take depending on their needs. They may purchase extra volumes to take advantage of high spot prices – reselling the LNG cargo or trading gas locally. Or they may reduce their volume off-take when local demand is low. FOB means a buyer has not yet been found nor locked into delivery. An LNG cargo leaves the liquefaction terminal and can be bought and resold “on board”. The cargo may eventually be dumped in a spot market at a loss if a buyer can’t be found, but LNG suppliers’ willingness to send out FOB cargoes shows liquidity to be improving.

Not yet a single market

European countries are keen to reduce their dependence on Russian gas for political reasons. However, uncertainty remains as to whether US LNG can compete with Gazprom on price.  Analysts at the Oxford Energy Institute estimate Gazprom’s cost of delivering gas to Germany to be 3.5 USD per mmbtu (million British thermal unit). Whereas the break-even price for the cheapest US LNG supplies is around 4.3 USD per mmbtu – even with Henry Hub still trading at historic lows. Gazprom, Europe’s largest gas supplier, has significant spare production capacity and some of the lowest cost production in the world. Given these conditions, LNG traders are unlikely to win a price war on the continent.

In sum, greater supply and liquidity in the global LNG market offers some opportunities for arbitrage between the continents and provides European gas buyers with options. This does have the potential to disrupt Europe’s monopolies and introduce greater competition into the market.  Yet, LNG and pipeline gas markets are not one and the same. Whilst the price gap persists, gas markets will retain their regional characteristics.


 

Renewables menace traditional power model

Lots of things are shaking up the traditional power model. A decade ago gas and coal power plants were very profitable. Retail companies, which distribute to industrial and household consumers, bought wholesale electricity at a price that always covered operating costs and got a healthy boost during peak demand hours. Even fairly inefficient power plants could expect to have enough profitable operating hours to keep in the money.

Electricity generated from renewable energy sources has altered this dynamic, most noticeably in Germany where Energiewende policies encourage renewable energy development. The upfront costs of new renewable energy projects are subsidised. Once operational wind or solar parks are given priority access to the distribution grid – they can always market the electricity they produce. Furthermore, the government pays out a “feed-in” tariff. That is, guarantees a certain price for every megawatt hour of electricity generated by a wind or solar farm.

These policies have discouraged private investment that might have brought more competitive renewable energy technologies, ones that do not require government subsidies, to market sooner. Nevertheless, Germany’s goal to get 60% of its electricity from renewable sources by 2050 is on track. The eventual success or failure of these policies is the experiment the entire world is watching.

However, the rapid expansion of renewables has upset the incumbents – traditional thermal power generators that use coal and gas as fuel. Renewables harm their profitability for a number of reasons.

First of all, the average wholesale electricity price is lower. Once a wind turbine or solar panel is installed operating costs are near zero because the wind and sun are both free fuel sources. The price of electricity depends on where inflexible consumer demand matches producers’ supply. The producers with the lowest operating costs are always called on first. Then the price of electricity creeps up the supply curve until consumer demand is satisfied. Every day, every hour, producers receive a price for the electricity they produce based on the last generator called up in the so-called “merit-order.” The graph below illustrates this.

meritorder

The last generator is always less efficient. This means that its operating costs are higher and it will only generate electricity when the price covers these operational costs. Now that renewables are part of the merit order, we don’t climb as high up the curve as before. On average, prices have decreased, implying the recurrent “last generator” is more efficient than a few years ago.

Second, thermal power plants’ operating hours are down. A lot of electricity is being generated from renewable sources replacing supply previously provided by gas and coal power plants. This point is obvious – money can only be earned when your power plant is online and generating electricity. This adds to traditional power plants’ woes. Prices are weakened, but their sale volumes are also harmed as renewable energy production grows.

Third, renewables are very variable. Already gas power plants have shut down and new projects have been cancelled because they could not survive the renewables’ economic shake-up. However, some days the sun does not shine, or there is no wind, and traditional generators are still needed. This can vary hour-by-hour, minute-by-minute. Only very modern gas facilities are capable of ramping up and down to balance unpredictable renewable production. Although, this is simply not profitable in a weak price climate where operating hours are down. So, these rapid-response power plants are no longer being built. This is called the “missing money” problem.

Fourth: the rise of the prosumer. Households and businesses have been installing solar panels with the hope of decreasing their electricity bills. In some countries, excess electricity that is generated can be injected into the grid earning you cash back from the local electricity retailer. This is how the word prosumer came about. Households connected to the distribution grid were traditionally pure consumers. Having installed solar panels the consumer is now a producer as well. They may even be electricity self-sufficient on sunny days or exceed their own electricity needs, affording them the opportunity to sell back to the grid.

Alone, one solar powered household cannot produce enough electricity to perturb the traditional power model. Yet, the arrival of hundreds and thousands of prosumers on the grid has the potential to be very destabilising as seen with commercial solar generation.

These four issues are part of a bigger problem: electricity infrastructure and markets are inflexible. They were not designed to manage decentralised and unpredictable electricity production. Nevertheless, this is the model we will have to manage in the future. Distribution lines also have ramping limits constraining how quickly power flows can be increased or decreased. Volatile prosumers and commercial wind and solar farms compromise the grid’s technical stability. And we still need back-up for the days and hours when renewable electricity production is low. Managing variable electricity production demands a model where this responsibility is shared by the market players.


Graph was found at www.powermarket.eu

Welcome

The perfect energy source – that is cheap, safe, abundant, reliable, environmentally friendly and producible on any scale – doesn’t exist.[i] When it comes to energy, we can’t avoid making judgment calls. Energy is policy. It is a choice.

Do we want the most stable, reliable electricity production possible? A government-sponsored nuclear industry, like France’s, makes sense.

Or is cheapest best? This is most relevant to developing economies. Coal is abundant, transportable and very cheap. And very polluting. China is the world’s biggest consumer of coal, but it still plays a huge role in countries like Germany, Poland and the US.

Or do we want to reverse climate change? If so, our society needs revolutionary rethinking. Cars, freight and planes would have to all but disappear.

Sunshine and wind are abundant in many countries and not polluting in themselves (the production of parts, installation and noise pollution aside). But who will bear cost of realising an entirely new smart electricity grid? What power generation will be used as back-up on the days the wind doesn’t blow and the sun doesn’t shine?

This blog is intentionally bipartisan. I am interested in solutions, not ideology. Developing solutions that address climate change and pollution, while also supporting development and fairness, and allowing for profitability. This requires both creative thinking and diverse inputs. We can benefit from the efficiency and dynamism markets encourage without rejecting the crucial role governments can and do play – and should, since safety is at stake.

Misunderstanding of energy issues is pervasive – exacerbated by misleading articles in the media. And our politicians struggle to promote their own energy policies, as they themselves lack clarity about the issues.

A lot of activists with worthy motivations – preventing dangerous climate change from engulfing the planet or radiation from poisoning another generation of young Japanese – make hasty suggestions about how to deal with the problems that worry them.

This isn’t surprising as energy issues are complex. They don’t conform to classic economic models. Each sector seems to have its own strange dynamic. Gas is regional. It is transported by pipelines and blighted by geopolitical manoeuvring. And it has yet to make strong in-roads into the transport fuel market to compete with petrol. It is still mainly being used by industry and for heating.

Oil is traded a hundred times more in paper than in physical barrels. This liquidity stems both from its being easy to transport as well as from strong competition. Yet, fundamental constraints affect the oil market too. The stuff of value is the refined petroleum product obtained from processing crudes. And the refineries that do this are both very expensive and inflexible, and can only be used to refine a particular crude oil.

Oil’s price level directly affects inflation and the cost of living in most of the countries that consume it. And, in the big producing countries, it often forms the backbone of their governments’ budgets, and can dramatically increase or decrease income levels.

Electricity may not be the biggest contributor to climate change, but the debate around renewable energy, particularly solar and wind power, takes centre-stage here. Electricity markets reflect their infrastructural base as electricity can’t be stored it must be consumed immediately after it is created.

The make-up of electricity systems varies greatly according to country – and within nations. For example, New Zealand’s predominantly renewable electricity mix is based on geothermal and hydropower. This is only possible because of the country’s local geographic and climatic conditions.

The often forgotten market is dirty, but abundant coal.

Coal is usually local. It is also the fuel that would suffer most if a price for carbon was integrated in its valuation. A little appreciated fact is that shifting 1% of global coal usage to natural gas would be the equivalent of increasing current renewable energy production by 11%.[ii]

A good understanding of the dynamics of the energy industry and markets is necessary if we are to be serious about addressing the global problems we face; whether these are fair consumer prices, climate change, energy poverty and access, economic and industrial growth, energy supply security or global financial stability. I’m very serious about these – although I don’t believe the solutions are easy or obvious. But we mustn’t be dismayed or dissuaded by the complexity of problems that face us. We will discuss them here.


[i] Although a cheekier analyst might suggest that energy efficiency – not wasting energy – is the cheapest fuel we have.

[ii] Data from BP Energy 2035 Energy Forecast, C.Ruhl, January 2014