UK's North Sea gas infrastructure must compete with LNG

One way offshore gas infrastructure players can maximize capacity is through enhancing the availability of their infrastructure to other or new players. The UK is constantly looking at its position on third-party access (TPA) for offshore to ensure a pro-competitive environment but is struggling with the fact that its upstream pipelines and offshore processing facilities were initially built to process and transport the output of specific oil or gas fields.

Spare capacity is progressively made available for use by third parties on payment of a tariff for transportation and processing services. This essentially means that field-dedicated lines can only keep their economic viability if they can be made accessible to smaller nearby fields.

Despite the best efforts of the UK government, there is still considerable room for gains by all parties if development of small fields is made more viable by owners allowing easy, economic access to existing infrastructure.

Infrastructure operators also need to develop business models capable of accurately calculating the cost of access to their infrastructures, a process that currently is far easier for onshore than for offshore infrastructure. As yet, transparency for offshore gas tariffs does not exist in the same way as for onshore gas tariffs.

Most European gas companies now publish indicative tariffs for onshore infrastructure and have unbundled their upstream and infrastructure businesses. In the UK, shared offshore infrastructure players need to begin developing the models and skills required to set up and manage the infrastructure most effectively.

While TPA is now a fact of life for all UK infrastructure operators, TPA with transparent tariffing is yet to be achieved. TPA with transparency should, in turn, generate more competition and greater capacity use.

Marketing; storage

UK offshore infrastructure owners are now much more focused on marketing and seeking new customers. Operators, however, still tend to retain an essentially upstream-focused view of the business that will contribute to a loss of value when the UK net-export gas position reverses.

Up to now, offshore gas field owners entering into contract negotiations have essentially done so with no clear view of how tariffs and commercial terms relate to storage options, customer demand, or the competitive threats from alternative sources of gas supply. As buyers seek to gain competitive advantage, they are looking to continually reduce their costs, particularly through the operation of "just in time" supply contracts.

Customers, however, especially in the industrial sector, are also constantly looking for ways to reduce their costs, and it is they who are striving to push upstream the risk and costs of the flexibility they need.

Structuring of tailor-made products and competitive pricing—considering the existing or future portfolio—will therefore increasingly become a requirement of gas suppliers in the UK market.

Infrastructure operators also need to look more closely at gas storage, which is becoming more important for flexibility and security against terminal and infrastructure disruptions. The UK has a current gas storage capacity of 3.7 billion cu m. Some companies like Statoil are already investing in new gas storage in the UK.

In December 2002, Statoil acquired the rights to build an underground storage site at Aldbrough in the east of England that will be able to store around 0.16 billion cu m of gas. In December 2002, Statoil's vice-president for the UK, Mike Kelly, said of the deal, "This facility will provide us with a back-up for our gas deliveries from the Norwegian continental shelf. It also gives us useful trading tools to enhance the value of our gas portfolio."

Statoil's deal followed hot on the heels of Centrica's deal to acquire the Rough storage facility through its acquisition of Dynergy Storage Ltd. in November 2002. This deal, however, is currently under review by the UK.Competition Commission and may result in Centrica having to sell all or part of the business or change how it is operated. Rough can store up to 2.8 billion cu m of gas and deliver at about 40 million cu m/day.

LNG's resurgence

The UK will not only be looking toward gas pipeline imports or higher storage ability to meet its supply challenges. It will form a growing reliance on LNG.

LNG is undergoing something of a global revolution in terms of costs, shipping, and contract management, and its ability to compete with piped gas grows stronger each year. In the last 10 years, the cost of producing, transporting, and regasifying LNG has fallen from an estimated $3.50-$4.10/MMbtu to $2.80-$3.40/MMbtu, as estimated by Drewry Shipping Consultants Ltd., London.

BP PLC recently stated that 10 years ago investment in the full chain for LNG represented around 25% of BP's total market capitalization. Today, due to the reduction in LNG costs and BP's growth, that investment would represent only 2%.

Royal/Shell Group recently announced the go-ahead of the Sakhalin 2 LNG project in eastern Russia. Only a few years ago, this project was unviable. Today with the evolution of LNG technology, Sakhalin 2 is economic and its operations will take place in waters that are frozen for 6 months each year. It will have a capacity to supply 9.6 million tonnes of LNG, nearly 10% of current total global LNG supply.

Projects like Sakhalin are pushing LNG into the forefront of global gas demand. It is at the cutting edge of LNG technology and will allow Asian gas customers to diversify their sources of gas supply.

Drewry estimates that up to 250 LNG vessels will be required by 2010 to cope with the growth in LNG demand. This will require 60 new vessels, sustaining the LNG shipping boom already apparent in the market. This growth and the continued reduction in costs could lead to as much as 10% of UK gas demand being met by LNG imports by 2010.

For this amount of LNG to reach the UK, new contracts and regasification terminals are required.

ExxonMobil has already signed a heads of agreement to import LNG from Qatar as early as 2006. Such a project could be the largest in Europe delivering around 12 bcmy of LNG to the UK. To meet such LNG growth, there are plans to convert existing LNG storage sites into regasification terminals, such as National Grid Transco PLC's site on the Isle of Grain that is already connected to the national transmission system, or to build new terminals, such as the 6-bcmy import terminal at Milford Haven in Wales planned by Petroplus International NV.

ExxonMobil is also considering a terminal at Milford Haven with an import capacity of about 21 bcmy.

While advances in technology are allowing for lower prices of LNG and demand for LNG continues to increase at double the rate of piped gas, the more flexible management of LNG contracts is also making it a stronger competitor to piped natural gas.

As such major LNG players as BP, ExxonMobil, and Shell expand their LNG business, they are starting to build more flexibility into optimizing LNG supply to market. In June 2003, BP's John Browne cited an example of that flexibility in action when an LNG vessel bound for Spain from the Middle East was finally sent to Tokyo, as BP was "putting in place a range of flexible, physical, and commercial assets and positions which recognize the new orderU."

While this flexibility is currently only partly available, as vessels are still mainly owned by the gas liquefaction companies and are often dedicated for certain receiving terminals (making opportunities for arbitrage rare), as LNG growth continues, the industry is likely to see more deals like this.

Pipeline operators respond

Faced with growing competition from LNG, some pipeline operators have been vocal in looking for a more equitable treatment of fiscal costs for UK Continental Shelf infrastructure, in so far as they cover future new infrastructure use.

In the last UK budget in April 2003, the government finally announced the abolition of Petroleum Revenue Tax (PRT) on new tariff income for offshore infrastructure. Fields developed before 1993 are currently liable for PRT (at a rate of 50%) on tariffs received for the use of their associated pipelines and platforms from third-party business. As a result of the changes, tariffs received from future new developments will not be liable to PRT.

While infrastructure is receiving some tax relief from the UK government, the EU is imposing new regulations on both pipeline and LNG projects as a result of the redrafting of the European Gas Directive (which will be in force from July 2004).

The changes include TPA requirements for new infrastructure investments including LNG and storage facilities, with companies only being exempt from these provisions on a case-by-case basis under particular circumstances like "the level of risk attached to the investment is such that the investment would not take place unless an exemption was granted" or that "the exemption is not to the detriment of competition or the effective functioning of the gas market."

Also in the US in 2002, the Federal Energy Regulatory Commission announced a policy change by allowing the construction of an LNG gas receiving terminal at Hackberry, La. By allowing this project to go ahead, the FERC announced its intention to remove economic and regulatory barriers to the development of LNG import terminals and to encourage gas-on-gas competition where markets are competitive and other criteria are met.

LNG operators are already arguing against their treatment under the EU Directive, saying that LNG import terminals more resemble production facilities rather than pipelines.

Furthermore, even though LNG is becoming a more flexible commodity, the reality is that substantial investments have been required in the past for the upstream development, liquefaction, and ships for today's LNG supply. LNG producers must ensure markets and terminal capacities to realize the value of their projects.

Import mix

Imports for the UK gas market will probably be a broad mixture of both infrastructure and LNG supply, thus ensuring security and diversity of supply for the long term. It is most likely that despite increasing under-capacity in UK gas infrastructure, shorter term supply will be met by piped Norwegian gas, with longer term supply from piped gas from Russia and North Africa and LNG from the Middle East and Nigeria and also Russia.

Russia is looking to develop its giant Arctic Shtokman field with a new LNG terminal at Murmansk rather than build long pipelines to Europe. Although most of the Shtokman LNG would be destined for the US market and Shtokman is a long-term development, its option of LNG rather than new gas infrastructure to Europe could influence the fate of UK North Sea gas infrastructure.

The liberalization of the UK gas market has been very effective in creating competition and choice in both the gas and electricity markets. Competitive pressures improved both performance and productivity in the industry.

What can be expected is that the changes in supply sources will keep UK gas prices high over the next few years. As the volumes of cheaper gas decrease as a result of North Sea maturity, new volumes will have to be found from higher price sources, such as Norway, Russia, Algeria, and LNG.

North Sea infrastructure operators should be able to capitalize on the new high-price environment by developing more flexible and competitive contract pricing and creating a greater and deeper understanding of their customers, thus competing much more effectively with LNG.

Some suppliers to the UK are not necessarily in a hurry to take advantage of the growing pockets of spare gas infrastructure capacity.

The partners of Norway's Ormen Lange field, at the end of January 2003, announced they would build a new gas pipeline to the UK rather than connect the field to the existing infrastructure. Tax benefits were believed to have played a part in the operator's choice of building a new dedicated line.

Gas from Norway's Ormen Lange field will be transported for processing to Nyhamna on the Norwegian coast then piped south to the Sleipner hub and from there to Bacton. Talks between the UK and Norway on a scheme of how to treat field development and pipelines in the North Sea have so far been unsuccessful and have forced Statoil to postpone its submission for plans for this pipeline to third-quarter 2003.

As competition for the lucrative UK market increases, however, key suppliers are careful about how much control they are prepared to give up. Suppliers are looking for ways to differentiate their supplies and secure lucrative long-term contracts, and some control of key infrastructure is seen by many as a key factor in achieving such aims.

There are several other key pipeline projects, which are being considered for new supply to the UK.

• Gazprom's plan to build a $6 billion gas pipeline to the UK under the Baltic Sea could be delivering 30 bcmy by 2007. In June 2003, the UK and Russia signed a bilateral energy pact that incorporated an agreement to cooperate in the construction of this pipeline.

The North European Gas Pipeline project, currently under discussion, would connect Gazprom's existing network via Vyborg (near St. Petersburg) with the UK by running beneath the Baltic to Germany, overland to the Netherlands, then subsea again to the UK.

Companies that Gazprom has named as potential partners in the Baltic Pipe project include Gasunie (which could theoretically supply Russian gas under its contract with Centrica) as well as other big players in the UK wholesale and large-user market including BP, Royal Dutch/Shell, Total SA, Germany's Ruhrgas AG and Wintershall AG, Finland's Fortum, and Norsk Hydro.

• Interconnector (UK) Ltd., which manages the pipeline between Zeebrugge and Bacton, is currently installing compression facilities to double the import capacity to the UK (up to now called "reverse flow") to 16.5 bcmy from the current 8.5 bcmy by December 2005. This could even be enhanced to 25 bcmy with possible completion dates of October 2006 or 2007.

Gazprom has also announced plan to boost spot gas sales via Interconnector to the UK. Gazprom has, via its subsidiary Wingas, booked 40% of the expanded capacity in Interconnector.

• A possible second interconnector from Den Helder in the Netherlands to the UK, sponsored by Gasunie, that will have the capacity to deliver 10 bcmy from 2005.

Facing the challenge

There are critical steps, then, that UK infrastructure operators must take to meet the challenges they face, particularly with the growing competitive strengths of LNG.

• They need to develop a framework for managing the optimal contract and customer mix and track the portfolio value.
• They also need to model the wider supply chain and commercial view of capacity allocation, including how key constraints and contract terms influence the capacity allocation decision and the cost of flexibility.
• Profiling the types of strategies employed by downstream customers and the impact of these strategies on their interactions with the company is very important.

Finally, building the contract, capacity, and customer intelligence into a tool to support negotiations on a customer-by-customer basis will ensure effective contracts and infrastructure management.

By responding quickly and skillfully to the main challenges relating to contracts and portfolios, capacity and customers, UK infrastructure players will be well placed both to win the competitive fight against LNG and optimize their revenues.

Ultimately driving out value through short-term maximization of infrastructure could be all that UK operators have left to play with.

LNG is on a global "roll"; demand for it is increasing, the costs of it are declining, and its contracts will become more flexible and pricing more transparent.

In the long term, the competition for the UK gas market may have already been won.

Authors' note: Sources for information contained in this article include the BP Statistical Review of World Energy 2002, UK DTI Brown Book, issues of the Petroleum Economist, various company web sites, and personal interviews conducted by Accenture.

The authors
Alexander Landia (alexander [email protected]) is the country managing director of Accenture in Russia, based in Moscow. He is a partner in Accenture European Energy practice specializing in strategy, corporate finance, risk evaluation, and mergers and acquisitions for energy companies. He received a PhD in 1998 from Tbilisi Institute of Mathematics of Georgian Academy of Sciences. Before joining Accenture in April 2001, Landia was director and head of the oil and gas in the global debt division of Dresdner Kleinwort Wasserstein.

Michael Herrmann ([email protected]) is senior manager with Accenture, based in Frankfurt but currently working out of Moscow. He joined Accenture in 1998 and has worked since then in the energy and resources industry. He holds a PhD (1992) in theoretical physics from the Technical University of Darmstadt, Germany, and held a 2-year research grant at the University of Washington, Seattle.

Julie Adams ([email protected]) is a manager in the strategic research group of Accenture, based in London. Before joining the company, she was a commercial negotiator for Agip UK. She also has extensive consulting experience, gained in 8 years as an upstream energy consultant with Arthur D. Little Ltd. Adams holds a BA (honors) in French and history from Warwick University and a post-graduate diploma in information technology.