Where we are: Relationships, contracts evolve along supply chain

Jan. 24, 2005
International LNG trade continues to experience significant growth and diversification.

LNG RISK PROFILE—1

International LNG trade continues to experience significant growth and diversification. Trade grew an average of 7.9%/year from 1995 to 2003, a more rapid growth than by any other sector of the energy industry. In 1995, 92 billion cu m of gas traded as LNG from eight exporter countries to eight importer countries expanded to 169 bcm in 2003 from 12 exporter countries to 13 importer countries.1 Analysts suggest that growth of LNG supply over the next decade will average up to 10%/year, based upon project commitments2 with several more exporter and importer countries about to join the trade.

Such growth will require continued huge capital investments along the entire LNG supply chain. This growth continues to be accompanied by an expanding spectrum of risks and opportunities for the industry.

More sophisticated supply chain structures and contractual interactions are developing in conjunction with the more flexible, short-term LNG trading arrangements that seem destined to expand during the next decade.

This first of two articles will analyze the evolution and developments of the international LNG industry in the past 5-10 years. The conclusion (OGJ, Feb. 14) will present these new international LNG market dynamics under a generic strengths-weaknesses-opportunities-threats (SWOT) analysis.

Evolution

Some 15 years ago the traditional model for all LNG supply chains consisted of integrated upstream groups (gas production plus liquefaction plus shipping), consisted of major international oil and gas companies (IOCs) and state-owned national oil and gas companies (NOCs), selling LNG to integrated downstream groups, consisting of creditworthy state-controlled gas or electricity utilities (SGUs) primarily in Asia and Western Europe (Fig. 1).

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Moreover, the LNG sales contract was 20 years or longer, with CIF delivery terms, involving rigid take-or-pay terms with prices linked to crude oil or fuel oil but including a floor price to protect investors in liquefaction plant construction from price collapse.

Sales contracts with at least two LNG buyer consortia were involved in providing diversified offtake security for each liquefaction plant. Such contractual arrangements suited both buyers (long-term security of supply at prices linked to main competing fuels) and sellers (guaranteed sales at or greater than a minimum price to underpin investment and guarantee a long-term, low-risk healthy return on investment).

Contracts were relatively simple and projects relatively easy to finance and insure with limited credit risks for lenders.

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During the 1990s partially nonintegrated LNG supply chains emerged with buyers involved in separate arms-length consortia operating the shipping and purchasing the LNG on an FOB basis at the liquefaction plant port (Fig. 2).

This arrangement provided long-term buyers, particularly Japan and South Korea, more flexibility in managing their LNG supplies. It also offered those buyer nations opportunities to share more directly in the profitability of LNG shipping, expand their domination of LNG ship building, and increase their influence over long-term shipping charters associated with the major LNG supply chains.

Equity interests in the arms-length shipping company usually involved participants from both upstream and downstream consortia.

The LNG markets had also then evolved to include substantial amounts of FOB sales contracts as well as the more traditional CIF contracts. Sales terms otherwise remained similar with long-term take-or-pay arrangements. In Japan, the Japanese Crude Cocktail (JCC) became the oil price benchmark for LNG.

In some contracts floor-prices were replaced by moderated crude pricing equations that softened LNG price increases in high-oil-price environments and LNG price decreases in low-oil-price environments, providing a more stable LNG contract pricing mechanism.

LNG delivered prices remained higher in Asia than in Europe due to more competitive gas supply and prices in Europe.

During the same period Japanese and South Korean LNG buyers began to take minor nonoperated equity interests in the development of upstream components of the LNG supply chain (liquefaction plants and gas fields). This enhanced their security of supply and also provided them with valuable knowledge of the complex technical and operational issues associated with LNG supply.

IOCs also realized that there was potential to extract value along the supply chain by taking equity positions in LNG shipping and regasification to tie in with their gas trading businesses in emerging deregulated gas markets of Europe.

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Cross-involvement of participants (Fig. 3) from their traditional positions in the LNG supply chain became common during the 1990s in conjunction with new liquefaction projects (e.g., Qatar, Oman, Trinidad). This trend has expanded in the past few years and seems likely to continue to do so (e.g., China National Offshore Oil Co. has taken equity interests in regasification terminals sanctioned for mainland China, in liquefaction projects in Australia, and in Indonesia and LNG shipping companies that will supply those Chinese terminals).

Nonintegrated supply chains

In certain LNG supply chains, the components have become even more fragmented since the late 1990s. Liberalization, and in some cases full deregulation, of the downstream sector, short-term contracts, swap sales, removal of the destination clause3 in many of the more recent sales contracts have introduced much more flexibility in the LNG markets.

The building of many new receiving terminals worldwide, commencing in Europe, has also opened up new long-term and short-term markets. IOCs and some ship builders have seen competitive advantage in owning shipping capacity that is not contracted to specific LNG supply chains and capable of being deployed at short notice to exploit opportunities to supply LNG to different markets at different times.

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This has further led IOCs to purchase some LNG on an uncontracted basis without a specified destination—the so-called LNG merchant model (Fig. 4). In certain upstream markets, gas fields in different licenses held by different joint-venture groups have combined to fund the building of tolling liquefaction plants4 where liquefaction plant and upstream gas development is nonintegrated (e.g., Trinidad and Egypt). In such arrangements it is now possible to have several upstream components to the LNG supply chain:

  • Gas fields involving several equity groupings (often including the NGC) subject to different types of fiscal arrangements (e.g., negotiated production sharing agreements and tax–royalty licenses). Because governments take the major share of revenues under production sharing agreements (commonly 70% to 90%), they often want to see LNG revenues flow all the way back to the gas field licensees rather than revert to the liquefaction plant that may benefit from tax holidays or uplifts that would limit the government take.
  • Feed-gas pipelines to liquefaction plants involving distinct equity holdings, tariff structures, and taxation terms.
  • One or more liquefaction plants with several trains each with distinct equity holdings established on a fixed-rate-of-return construction basis, perhaps reverting to state ownership once payback is achieved, and charging each gas supplier a negotiated tariff for liquefying gas and loading LNG for export.

Similarly it is possible to have several components in the downstream LNG supply chain if open-access rules are applied to the import and regasification terminal. Several different companies could contract portions of the capacity available in an LNG receiving terminal from its owners for specified periods at market rates. This would enable each of these capacity holders to source LNG from different supply chains and deliver regasified gas to different buyers through capacity purchased in the transmission system.

The import and regasification terminal also then operates essentially as a tolling plant charging each capacity holder a processing fee for receiving and regasifying its LNG. Rather than move progressively towards this non-integrated model, however, the industry has shown signs in the past 2 or more years of backtracking on open-access rules to secure more investment in new import and regasification terminals.

Open access at terminals

Selling LNG into the deregulated and liberalized markets of North America and Western Europe has led to somewhat more restrictive contractual arrangements evolving at the downstream end of the LNG supply chain (Fig. 5). These revolve around open-access rules for the gas pipeline transmission systems and distribution networks, coupled with many exemptions to such open-access rules negotiated for new LNG regasification terminals.

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In December 2002, the US Federal Energy Regulatory Commission ruled that the proposed LNG import terminal at Hackberry, La. (OGJ, Nov. 10, 2003, p. 64), could be built without complying with the open-access requirements that had previously been strictly applied to all parts of the US gas transmission chain as part of ensuring open competition in the deregulated gas market.

Known as the "Hackberry Decision," it has encouraged proposals to build new receiving terminals in the US without developers being forced to offer capacity to third parties at "market" rates. Such open-access exemptions have proven critical in securing equity investment to build such terminals by providing the shareholders in the regasification projects guarantees that they will maintain control over most or all of the LNG capacity of the plant for a substantial period of time, enabling them realistically to recover and benefit from their investment of risk capital.

As well as in the US, such exemptions have been applied for and granted during 2004 in Western Europe (e.g., France and UK) for new import and regasification terminals under development.

Combined with the evolution to at least partial de-integration of recently constructed and planned LNG supply chains is the diversification of LNG supplier and buyer countries away from those traditional LNG buyers with high credit ratings.

At the upstream end, countries such as Nigeria, Egypt, Yemen, Equatorial Guinea, Peru, Bolivia, Trinidad, Venezuela, Iran, and Angola pose challenges for financing, insurance, security of supply, and fiscal stability. At the downstream end, countries such as India, China, Turkey, and Mexico also pose financing and insurance challenges and concern for sellers over the long-term fiscal and contractual stability.

Concerns over lack of experience and best-practice standards also raise short-term concerns over operational reliability and safety.

The ongoing diversification of the LNG markets has raised issues over LNG quality and specifically over NGL content with respect to lower calorific value and Wobbe Index limits on pipeline gas specifications in US and UK relative to Asia and most of Western Europe.

LNG from liquefaction plants in Alaska, Algeria, and Trinidad meets these lower NGL content specifications. LNG from most liquefaction plants in the Middle East, Nigeria, and Asia do not (OGJ, Oct. 11, 2004, p. 48). This requires investment at some point in the supply chain to remove NGL or to dilute the regasified LNG with an inert gas (usually nitrogen).

This investment is most likely to be at the import terminals in UK and US. This issue has raised the importance of LNG quality specifications within the contractual framework, however.

Diversification, deintegration, and deregulation are adding complexity to the contractual framework of planned LNG supply chains on an ongoing basis. The large amounts of capital required at the upstream end of all LNG supply chains (i.e., gas field development and building new liquefaction plants) means that it is common practice for such projects, whether integrated or nonintegrated to be project financed largely with debt on a nonrecourse or limited-recourse basis.

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In developing economies, debt finance will usually also involve export credit guarantees and loans as well as commercial bank loans and in some cases bonds (Fig. 6). Such project finance layers another level of complexity into the contractual framework and introduces more rigorous requirements for the contracts to dovetail, guarantees, insurance, etc. to provide security to lenders.

The production sharing agreement or license terms under which the government approves the plant remains the ultimate contractual driver.

Because so much debt finance and high upstream taxation rates are involved in such projects, the rules allowing deduction of interest paid on project debt from taxation liabilities can significantly affect the overall profitability of a liquefaction project. The government approval of the credit agreements is therefore often an integral part of the project approval process.

GTL

In addition to the evolution described for the LNG supply chain, over the past 5 years gas-to-liquids technologies have finally come of age and commercial plants of substantial scale are under construction, particularly in Qatar, where at least four projects are proceeding.

The large amounts of capital currently being invested in large-scale GTL plants in traditional LNG producing regions is destined to affect the future LNG industry, probably for the most part in a positive way.

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As illustrated in Fig. 7, GTL and LNG are processing gas for sale into two distinct but complementary markets: LNG supplying gas primarily to power-generation markets; GTL supplying synthesized petroleum products (middle distillates, naphtha, and lubricants) primarily into transportation fuel markets.

Large-scale international GTL projects, such as those under way in Qatar, require similar complex contractual frameworks to the upstream components of the LNG supply chain. The breakeven price for LNG has progressively moved downwards over the past 15 years to less than $3/MMbtu (delivered) for some supply chains. This has been achieved by economies of scale and technological and operational improvements.

Similar expectations exist for the infant GTL industry with the key players striving initially to bring GTL plant capital costs down to less than $20,000/b/d of capacity5 by developing more efficient and less energy-consuming catalysts. If this is achieved together with operating efficiencies, then such plants can remain profitable even in low oil and petroleum product price environments (i.e., $10-15/bbl, which seems a long way below oil market expectations of 2005).

By combining LNG and GTL development strategies companies and countries should be increasingly able to reduce market risks and improve their ability to secure financing on more favorable terms.

Only if substantial cost reductions and technological breakthroughs occur in GTL processes and GTL establishes a performance track record will it become a serious competitor to LNG by becoming the remote gas-monetization process of choice in securing capital investment for new build facilities. To become such a competitor, GTL would have to demonstrate a greater return on investment than LNG.

In a sustained high-oil-price environment and with limited approvals for building additional crude oil refining capacity in the main petroleum product markets GTL could offer such improved returns in the medium term.

With such a short track record, however, GTL will likely retain a higher investment risk profile than LNG for at least the next decade. It is more likely to remain as a complementary opportunity rather than competitive threat.

Notes

1. BP Statistical Review June 2004

2. For example, Cedigaz 2004. My own analysis assumes average of 7.5%/year growth restricted by lack of LNG import and regasification capacity.

3. EU has for competitive reasons insisted that sellers no longer have the right to stipulate that gas delivered to one buyer cannot be resold without the LNG suppliers' approval and right to share in any profits made from re-sale transactions

4. Tolling plants charge gas producers a processing fee to liquefy their gas, which is then sold under contracts involving gas field producers and LNG buyers, not necessarily involving the equity owners of the liquefaction plant itself.

5. Brown, A., Shell Web Presentation, October 2003.

The author

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David Wood ([email protected]) is a London-based international energy consultant specializing in the integration of technical, economic, risk, and strategic portfolio evaluation and management. He received a BSc in geology from Leicester University (UK) and a PhD from Imperial College, London. Research and training concerning contracts, economics, gas, LNG, portfolio, and risk analysis are key parts of his work.

Correction
In the LNG world map ("2004 LNG World Trade," supplement to OGJ, Dec. 13, 2004), the following table was incorrectly printed. See the correct version below:

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