1st April 2016
The Time is Now for Natural Gas
Over the coming decades, Natural Gas will experience unprecedented growth, benefitting from widespread availability, increasingly low cost, and benefit to the environment. Gas will likely overtake coal in terms of primary energy perhaps within a decade, and will probably eclipse oil to become the world’s most important energy source, by mid-century. The “Oil and Gas Industry” will soon become the “Gas and Oil Industry”.
For gas to truly emerge from the shadow of its big brother, oil, it will need to further establish its own identity. Gas must have its own trading and pricing arrangements, which are unique to gas and not borrowed from the oil market. This has already happened in some parts of the world, such as North America, is well underway in Europe and is now taking a grip more quickly than many people have anticipated.
Those utilities and gas buyers who are still in an exclusively oil indexed world may want to heed the wise words of Benjamin Franklin who said “by failing to prepare, you are preparing to fail”.
The Emergence of Hub Pricing – Born in the USA
This “coming of age” for natural gas started in the USA in the 1970s and 80s, as the industry expanded, and new upstream supplies and interstate pipelines were built to meet demand. Those with a major stakeholding in the US gas market realized early in its evolution that natural gas would benefit under a regulatory system that enables transparency and generates pricing signals that are a function of supply and demand, rather than fixing gas prices as a function of oil. Under the various FERC (Federal Energy Regulatory Commission) rulings throughout the 70s and 80s, a liberalised or “unbundled” industry structure emerged comprising upstream producers, who could access a variety of delivery routes to the customer, and customers who likewise had a choice of supplier and delivery point.
As this network of privately funded upstream sources, and pipeline and storage infrastructure emerged, so a pricing structure emerged with it. Gradually, as the trade in natural gas increased, a market evolved whereby gas was traded at significant points in the gas delivery system. These were typically hubs comprising the junction of two or more important pipelines, together with a market for delivery capacity in the pipelines that were connected to the hubs. As a result, different prices emerged at various hubs, where the price difference notionally reflected the secondary market for firm or interruptible transmission capacity between them. The most famous hub of all, Henry Hub in Louisiana, emerged as a key crossroads for gas that still represents the benchmark US gas price.
Following this evolution, the concept of “hub pricing” was born in the USA, and it is a term that is used more and more readily in the natural gas sector. The word “hub”, is however somewhat misleading in the context of continental Europe. In Europe, and many of the emerging gas “hubs” around the world, the term is used much more conceptually, to represent a zone or sometimes a national or regional transmission system, such as the National Balancing Point (NBP) in the UK, which is a notional location within the UK’s gas transmission system. However, the relationship between NBP, for example and the Title Transfer Facility (TTF) in the Netherlands, a similar notional hub, still largely reflects the availability of transmission capacity to move the gas from one hub to another, or in this case from within one zone into another zone.
Figure 1: Many trading hubs have emerged in the US and Canada but Henry Hub remains the reference point for US natural gas prices with AECO being the main pricing point in Canada (source GCA)
Sailing Towards Future Global Gas Market Integration
As we look to the future, the concept of hub pricing could come to represent LNG - potentially still on the high seas - which falls broadly within a particular geography where regional or local supply and demand has created a price signal, to which the seller or buyer of the LNG can respond. The logical end point is a network of hubs, or trading locations globally, where there is a deep and actively traded market for natural gas (in gaseous or LNG form), and where the price linkages between those hubs is a function of the availability of the means to move the gas from one market to another, either in a pipeline or in a ship (or in future even in a railway wagon, or road tanker).
Figure 2: Status of World Gas Trading Hubs today
As things stand today, the USA and Canada, from a regional perspective, reflect exactly this model. For the most part, Northwest Europe is also sufficiently evolved to reflect supply, demand and pipeline capacity. With the start of Atlantic trade in LNG increasing through 2016, the US and Europe have a market linkage for the first time. The creation of a price linkage between the US and Canada (Henry Hub and AECO) and Europe (NBP and TTF) has already begun to impact on prices, setting a price signaling mechanism to which gas flows have started to react. Reflecting this market development, one of the larger European exchanges is now offering its customers the chance to trade so called “basis” between Henry Hub and NBP, thereby spreading the global gas market even wider.
In the last few weeks we have seen NBP prices weaken, and the spread between Henry Hub and NBP stabilize at around $1.75 to $2 per MMBtu, broadly reflecting the price incentive that will attract LNG to European buyers. A similar mechanism appears to be emerging for Asian LNG deliveries.
Learning from the UK Experience of Market Deregulation and Unbundling
The emergence of NBP as a major trading hub and price setting mechanism was actually a secondary feature of what was initially an operational requirement. The early 90’s saw two government inquiries and considerable customer frustration over previous attempts to provide third party access to British Gas’ transmission pipelines. Finally it was determined that a financial and operational “unbundling” from the merchant, transmission and storage, and production functions of British Gas was necessary. A clear and transparent set of rules was required for emerging third party shippers, and the other parts of British Gas alike, to adhere to.
After consultation with a wide set of stakeholders the rules that emerged was referred to as the Network Code. It required people using the transmission system to maintain a balance of gas nominated into the system from upstream production, with gas delivered to customers. Recognising that for a host of operational reasons, these balancing operations would inevitably be imperfect, a balancing mechanism was established. Shippers who under-delivered on a day had to pay a system determined price for gas to balance their portfolio. Those putting too much gas into the system were cashed out, based on that day's balancing needs. This financial mechanism was used to incentivise shippers to keep their portfolios in balance, and maintain appropriate operational pressures within the transmission system. It then led to a secondary market with shippers trading gas with one another. As the market developed, so financial players started to get involved. A number of exchanges, whose traditional commodities included things like precious metals, crops, or coffee, saw that these same principles could apply to an NBP based contract for gas.
Increased “Churn” led to an Open UK Gas Market in the ‘90’s
As the market developed and the number of participants grew for those only interested in the financial trading of gas contracts, the concept of churn emerged. Churn is used to measure the ratio of gas traded to gas physically delivered. It is a measure of how many times a therm of gas is bought and sold before it finally makes its way to the customers burner tip. As a guide, a churn somewhere higher than about 15 and with more than around 100 active participants trading gas is usually thought of as the requirement for a sustainable trading location. Both NBP in the UK and TTF in the Netherlands currently achieve these churn levels, but the other emerging European hubs – including Zeebrugge (ZEE), Point d’echange de gaz (PEG) and Netconnect (NCG) – still lag well behind. For comparison, churn for Henry Hub traded gas would be of the order of 400 and market participants would be counted in the 1,000’s.
During the mid to late 90s onward, the sophistication of the UK gas market started to approach that of the USA and Canada, though with the overall marketplace being about one tenth of the size of North America, the depth and liquidity of the market did not compare. As a result, most of the larger buyers, such as utility companies or power generators, continued to rely on longer term gas supply agreements, as well as participating in shorter term traded gas, but increasingly the reference price for all gas became NBP.
Today, the UK represents a totally open gas market where gas is simply traded as a function of supply and demand. It is perfectly possible to bring a cargo of LNG to the UK with relative ease in terms of ensuring a suitable delivery window at one of the several LNG regas terminals. This enables an LNG producer to simply be a “price taker”. As we witness the startup of LNG exports from the Gulf Coast of the USA, driving a convergence of North American and European gas pricing, allowing for transport, we are finally entering a period where gas prices start to adhere to a global model of supply, demand and shipping costs. Price conformity will accelerate with the emerging LNG supply glut.
Pipeline Connections coupled with Regulatory Change – the Recipe for Continental Europe
Another interesting feature of the way hub pricing has taken hold in Europe has been the two pronged effect of regulatory and legislative measures to establish a more open and transparent gas market in Europe coupled with more physical interconnections. In the last 10 years or more we have seen progressively stronger regulation applied by the EU in terms of the First, Second and Third energy “Package” designed to achieve total financial and ownership separation of the merchant and gas delivery functions across Europe. However, this was insufficient on its own to establish functioning markets.
Figure 3: Development of European Hubs has followed pipeline interconnections (source GCA)
In the end, it was the physical connection of the UK gas market and that of Continental Europe that sparked material change which once started gained momentum very rapidly. With the building of the Interconnector Pipeline from Bacton in the UK to Zeebrugge in Belgium (also a major LNG import terminal) and subsequently the BBL pipeline to the Netherlands, continental buyers were able to participate themselves in the UK wholesale gas market and have gas delivered to their own customers in Europe. Some of the more sophisticated European gas companies soon realised the commercial benefits of leveraging UK wholesale gas with flexibility alongside their long term take or pay contracts (with suppliers such as Gazprom, Statoil or Sonatrach); an extremely valuable tool in managing their gas costs and portfolios.
Consequences of Gas Price Discovery in Europe in the ‘00’s
This balancing of UK based wholesale price gas and long term oil indexed gas reached a crescendo in the mid to late 2000s. A fundamental gap opened up between gas procured on the open market, which was benefitting from a diverse range of pipeline and LNG supplies, compared to gas priced on oil, which was reflecting a rising oil price. An arbitrage emerged which largely meant that oil indexed contracts were turned down to the minimum permitted under the contract, and gas companies bought as much gas as possible on the wholesale market. Meanwhile, those without the contractual flexibility to do that started to experience major financial losses, as a result of selling oil indexed gas into a market which had settled around supply/demand fundamentals, at a much lower level.
This prompted two things to happen. First, some buyers were able to trigger price review clauses, or resort to other legal means to cause a re-appraisal and re-examination of the traditional oil based pricing. For the most part many of the old oil based prices had to be reset to reflect what had by now become an accepted market price. Secondly, where the traditional long term suppliers found their contracts being run at so-called “Minimum Bill”, i.e. the smallest delivery contractually allowed, there was a commercial incentive to sit down with buyers to renegotiate a more reasonable and sustainable arrangement.
What is The Impact on Emerging Economies with a Growing Gas Demand, such as South East Asia?
The first consideration is the current proliferation in LNG supply, which is now undermining the traditional relationships between buyer and seller in Asia. Significantly increasing competition for market share by major LNG suppliers is manifesting itself in much lower spot prices, exacerbated by the low oil price. As a result, buyers are less willing to tie themselves to multi-year supply contracts with high take or pay arrangements. Many large users of energy are becoming aware of the array of choice now available, and the potential for negotiating lower energy prices. However, in the absence of an established reference price, other than oil, the natural gas market continues to occupy a half-way house between the old world of oil indexation and the emerging world of regional hub pricing. A secondary factor in many South East Asian countries is that the gas market resembles that which existed in the UK at the start of gas market reform in the 1990s, where arrangements to buy gas and have it shipped through the natural gas infrastructure to the customers’ factory or power station are largely absent.
Figure 4: The price basis for gas in the US/Canada and the UK is now firmly based on gas on gas competition, which has now been embraced in most of Europe. Asia is trending in the same direction.
If the model in the US, UK and Europe creates a guide for today’s market in South East Asia (and potentially South America), we could expect to see:
• An increasingly competitive gas supply environment, coupled with;
• Demand from gas customers for new and competitive pricing arrangements; and
• A regulatory and legislative push to create a transparent mechanism for delivery of the gas.
If this evolution is indeed the likely outcome, producers of gas, whether by pipeline or LNG, can connect their product to individual buyers. This creates both an economic platform to incentivise new production, and achieves the lowest possible cost of energy for consumers.
Conclusion – As Gas Market Evolution Continues Rapidly, Be Prepared to Avoid the Risks and Take Advantage of the Opportunities
Over the next 5 years or potentially even less time, as gas markets in parts of Asia, Africa and South America, start to follow open and transparent market and pricing structures, we could see the emergence of a truly global pricing mechanism for gas. As in the more developed national and regional markets, this will likely be based on a range of pricing hubs reflecting major trading locations, with gas flowing between them in response to pricing signals.
For gas to achieve its destiny as the pre-eminent energy source to drive the global economy these evolutionary steps are not just desirable but essential, to achieve an efficient, low cost, reliable and sustainable gas industry which will underpin a strong growth trajectory for the next century or more.
Market players need to look back at some of these market developments worldwide in order to:
• Fully understand these changing dynamics to be first to seize opportunities that will follow.
• Avoid risks of financial losses in the short term.
• Develop a medium to long term strategy to build a sustainable gas business and continue to benefit from the evolution in the market place.
GCA’s Global Gas and LNG group are working on mandates globally to assist clients with their plans and preparations and we welcome the opportunity to engage with all stakeholders in the gas value chain.
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