After burn?
Liquefied natural gas (LNG) has become a lucrative part of the
global oil and gas business, and by some accounts is entering its
golden age. LNG has become affordable to more countries and an
increasing number of these countries have made the investment in
natural gas storage and transport infrastructure to complete the
value chain from wellhead to burner tip.
For several Asian countries, without indigenous fossil fuels and concerned about over-reliance on crude oil imports from the Middle East in the 1970s, LNG has provided a critical diversification component of their energy supplies. Now countries in Europe, such as Spain, Portugal, Italy, and Turkey, are seriously considering importing significant quantities of LNG on a long-term basis. And in the US, the recent energy crunch may have pushed natural gas prospects high enough to encourage a sustainable LNG market. Finally, LNG's increasingly attractive stature as an environmental fuel of choice bodes well for the industry, and the cost to produce and deliver LNG has dramatically fallen.
But for all the LNG market positives there are a number of questions as yet unanswered that beg a pinch of caution. Will LNG's cost drop enough so that it will sustain a fuel of choice status? Alternatively, is LNG expanding so rapidly that it may soon flood the market with an attendant price collapse? Have LNG's promoters over-estimated the global demand for LNG and its attendant financability? Is the credit gulf between such top-tier LNG importing countries, such as Japan and Taiwan, and second tier candidates, such as India, too great to support significant LNG expansion? Will a global LNG spot market develop or, is the LNG industry about to push itself into a dangerous oversupply situation that could threaten many projects that have increasingly relied on highly leveraged project finance structures?
Regardless of where the LNG market heads, the past several years have seen two major new trends in the LNG business: The market for LNG has materially changed and capital costs have fallen. How LNG projects exploit these changes will distinguish the financable projects from those that merely appear as one-time news flashes. Keys to success will extend beyond the ability to sign a long-term supply and purchase agreement (SPA) with a creditworthy customer.
Changing market needs
The market for LNG has dramatically expanded over the past quarter century, as increasingly diverse customer needs have begun to be addressed by this niche fuel - needs that now extend beyond just ensuring security of supply. Broadly, four major changes in the market are driving an increase in demand:- Fewer concerns over security of supply,- Growing spot sales market,- A desire to de-link LNG prices from crude oil, and- Natural gas' growing status as a fuel of choice.
Fewer concerns over security of supply
Desire for long-term security of LNG supplies, which historically drove LNG contract negotiations, lead to lucrative 20-25 year deals, some with price floors. Most SPAs have provided such predictable revenues that they easily supported the financing and construction of large LNG projects, such as Australia Northwest Shelf, RasGas (also known as Ras Laffan Liquefied Natural Gas Co., 'BBB+'/Stable/-; in Qatar), and Oman LNG (Oman). These SPA deals featured take-or-pay provisions with only limited abilities to defer cargoes from one year to the next because of operational limitations or demand reductions. Typically, the buyer makes good on any deferred volume or agrees to pay liquidated damages. Indeed, no project sponsor would even have considered undertaking the multibillion effort of building an LNG liquefaction and storage complex without an executed supply and purchase agreement that ensured a highly predictable offtake volume and price structure.
The Asian financial crisis in 1998 marked a turning point for LNG projects and signalled a clear need for a more flexible LNG market. In Korea, particularly, the crisis triggered a sharp drop in energy consumption as the economy faltered. As a result, Korea's contractual LNG import obligations far exceeded its needs and it had to curtail LNG deliveries. As the Korean economy recovered, full contractual LNG shipments resumed. The Korean experience highlighted an underlying characteristic about energy markets - energy consumption adjusts considerably as the weather and the economy change, among other factors.
Consequently, potential buyers of LNG, particularly those that have already built a solid base load LNG supply, now want flexible take volume provisions without penalties incorporated into contracts for incremental supplies. Hence, long-term security of LNG supply ranks lower on a buyer's list of priorities. Indeed, fewer buyers want the long-term liability that comes with a 20-25 year SPA. Many LNG buyers are not prepared to take the risk that their end-use customers' requirements (e.g., independent power producers or residential heating) could suddenly drop. Where suppliers can craft flexible contracts, markets for LNG should increase. In the near term, Standard & Poor's expects that LNG suppliers will need to offer a variety of LNG contracts, which may feature one or any combination of the following contract volume provisions:
- Long-term SPAs: Traditional 20-25 year contracts with well-defined volumes with limited abilities to defer LNG cargos from one year to the next.
- Short-term SPAs: 5-10 year contracts with well-defined volumes and limited abilities to defer LNG cargos from one year to the next.
- Flexible-SPAs: LNG contracts that resemble a requirements-based contract without the need to make good on deferrals.
- Seasonal SPAs: Shipping schedules that account for seasonal variations in energy consumption (e.g., summer versus winter).
- Tradable cargos: Provisions that allow the contractual buyer to divert cargos on a spot basis to a different buyer.
- Spot cargos: Contracts for limited cargoes, varying from one to five or so shipments and priced against a benchmark price in the buyer's market.
While such terms may support an expanded LNG market, the credit implications for sellers should be obvious. Absent some form of mitigation, or hedge, uncertain sales volumes will likely increase credit risk for LNG projects. Moreover, netbacks from spot market sales have only recently been high enough to justify the costs during very elevated peak pricing periods.
Growing spot sales
The sudden increase in spot cargoes characterises one of the more dramatic changes to the industry in recent years. Historically LNG tanker construction orders accompanied specific projects; shippers knew that they could virtually guarantee full usage of an expensive tanker for the duration of a long-term SPA. No practical spot market for LNG existed, at least in volumes that could sustain speculatively built tankers. Moreover, the economics of operating receiving and regasification terminals have typically required year-round utilization to justify the enormous capital investments. Such dynamics almost ensured that a spot market for LNG would be slow to develop. That buyers have generally insisted on owning and controlling tankers almost guaranteed that sellers would have a difficult time securing tankers for LNG spot sales.
But the industry has seen a shift in the past few years. Several LNG suppliers have taken a number of LNG tankers out of mothballs, restored them, and put them into service on a short-term basis. Three new projects with excess capacity - RasGas, Oman LNG, and Atlantic LNG - have been able to take advantage of favourable conditions in the US, Europe, and Asia to sell spot cargos. Even traditional buyers of LNG under long-term SPAs, such as Korea, have recently needed spot cargoes during the winter to meet peak season heating needs. In the US, where gas supplies have been inadequate at times, due either to wellhead deliverability limits or transmission constraints, to meet the growing gas-fired power generation market, a spot market may becoming viable, especially if peak electricity prices can justify spot LNG cargo prices. Restoration work on two US regasification terminals that were closed in the 1980s due to lack of demand and abundant energy supplies has recently begun. Unfortunately, the two-three year lead time on new tanker construction will tend to dampen the spot market, except for those with the greatest appetite for risk.
De-linking from crude oil
LNG markets that have developed beyond the traditional markets in Japan, Taiwan, and Korea increasingly want to de-link LNG pricing from the customary Japanese Customs Clearing price (JCC price) - the weighted-average price of a basket of crude oils delivered into Japan. Historically the JCC price was an appropriate benchmark because LNG imports could displace crude oil. But as LNG use spreads, potential buyers want to link LNG prices to alternative fuels. In the US, where LNG importing prospects look promising, LNG contracts may price against Henry Hub natural gas prices - a commodity price strongly linked to electricity prices. Some buyers have proposed linking LNG contract prices to a basket of imported fuels that include coal, among other fuels.
Linking LNG to alternative fuels will tend to make LNG more competitive, but, absent hedging, could pose a credit risk for lenders to suppliers if commodity price risk becomes volatile. Electricity and natural gas prices, for example, show much greater volatility than crude oil. The US, for instance, has recently seen very volatile commodity price movements in the markets - a situation that would certainly raise credit risks for LNG projects solely targeting the US Moreover, most LNG sales into the US will need a landed price of at least $3.25 per million BTU, which exceeds the long-term Henry Hub price of about $2.90, to sustain a long-term business.
Fuel of choice
Natural gas' status as a fuel of choice globally has expanded the demand for LNG in markets where little or restricted access (geographical or temporal) to natural gas would otherwise restrict LNG's growth. Several factors over the past decade have made natural gas a premium fuel globally, especially for power generation. First, compliance with existing, or expected, air pollution standards is driving natural gas' attractiveness. Natural gas-fired generation emits fewer regulated pollutants and waste products, such as sulphur dioxide, nitrogen oxides, and airborne solid particulates, than other types of generation. Ash and radioactive waste are simply not concerns for natural gas users. Such an advantage over other fuels favours LNG, but it likely adds a price premium to natural gas against other fuels on a BTU basis.
Second, gas-fired generation is cheap and quick to build. Combined-cycle gas turbine generators generally require a smaller capital outlay than the construction of nongas-fired generation plants and a shorter construction period. Construction for a gas-fired power plant takes only about two years against a four to five construction period for coal, or even longer for nuclear power. As a result, over the past 10 years, many markets without access to natural gas have either chosen, or are considering the option, to import LNG for power generation where capital for new generation is available. Although, as Enron Corp.'s well-publicised experience with its Dabhol plant in India demonstrates, LNG-fired power generation, despite access to capital, can still present a credit risk in markets not able, or willing (or both), to pay the premium. India alleges that it just cannot afford the power.
And finally, demand for natural gas will likely increase as concern grows over the potential for greenhouse gases to cause global warming. Natural gas emits less carbon dioxide than competing fossil fuels. Hence, even if other fuels are cheaper on a BTU basis, LNG may be more competitive given the externality cost of carbon dioxide emissions or other pollution concerns.
The US market - a special case
The US represents a unique LNG market. For years North America, with the world's most extensive natural gas pipeline system, has been virtually self sufficient in natural gas production, save for New England. In New England, because pipeline capacity constraints have limited natural gas consumption growth, it imported small amounts of LNG through the Boston terminal to meet peak shaving needs in the winter. Last year, however, saw a record run-up in natural gas prices, as prices hit just above $10 per million BTU on average - $40 per million BTU on the west coast. Record temperatures, both hot and cold, and the rapid increase in gas-fired power generation strained North America's ability to supply conventional natural gas. At these rarefied prices, the US gas market became extraordinarily lucrative to LNG exporters, particularly with world LNG prices hovering around $3.20 per million BTU. Unfortunately, low LNG spot tanker availability and few LNG storage and regasification terminals in the US limited the near-term import potential. In response to encouraging price signals, however, a number of oil, gas, and electricity companies, including El Paso Corp., Texaco Corp., and Enron Corp., have announced plans to build storage and regasification facilities to service the US market.
Natural gas prices have recently fallen to about $3 per million BTU in response to new gas-well drilling and moderate weather. Nonetheless, many industry observers have concluded that the US natural gas market, driven by the power industry, has structurally changed and hence, will need LNG imports to meet demand needs that could hit 30 trillion cubic feet a year by 2010. That record gas-well drilling activity in the US is discovering fewer and smaller gas reserves per well with limited deliverability supports these claims. Even so, commodity price risk - something that has shown extreme volatility of late - will likely make a US LNG market a risky bet for some time. Potential new gas supplies in large quantities from Alaska or the Mackenzie Delta could dramatically improve the domestic supply picture. Given the size of capital investments needed on the receiving end, LNG importers will likely enter this market slowly, if not with a healthy scepticism.
Lower capital costs
Changes and improvements to LNG technology have fuelled an explosion of new project announcements. In short, producing and shipping LNG cost much less than it did just a decade ago. As a result, abundant gas reserves that once had little or no value can now commercially reach more customers world-wide than before.
New technology developments and improvements in refrigerant and liquefaction techniques have lowered the capital costs of these most expensive LNG processes. Since 1988, nominal liquefaction capital costs have fallen to about $200 per ton of LNG capacity in 2001 from about $550 per ton, according to data in the Oil and Gas Journal. Technological improvement is also allowing sponsors to build production trains with increasing throughput capacity. The latest designs can process about 3.3 to 3.4 million tons per year of LNG, up from about 2.0 million tons about 10 years ago. Moreover, projects that expand into third and fourth trains, such as Atlantic LNG, Oman LNG, and RasGas, will benefit from economies of scale because they further lower the LNG production cost per ton. Most expanded projects will generally share certain common facilities, such as site preparation, utility infrastructure, LNG storage tanks, loading docks, administrative, and overhead.
Lower tanker prices are also driving the global LNG market, especially the spot market. The cost to build an LNG tanker has fallen dramatically, nearly 50% during the last decade. Since 1997 the cost per tanker has dropped to about $175 million per vessel from about $225 million. Some of the drop occurred during the Asian financial crisis, as Korean shipyards fought for dollar-denominated tanker construction contracts. Prices recently have inched up, as LNG slots are completely full for the next few years. Nonetheless, nominal costs to build tankers have fallen, as shipbuilders have developed new techniques and greater experience with LNG tankers.
Keys to LNG project success
Project finance has played a vital role over the past several years in financing the latest generation of LNG projects - projects, for a variety of reasons, sponsors elected to keep off their balance sheets. Recent project financings have included QatarGas, RasGas, Oman LNG, and Atlantic LNG. Going forward, as buyer needs become more diverse, some project sponsors may find their efforts to structure investment-grade transactions frustrating. Indeed, the flood of new LNG project announcements may be signaling a temporary LNG oversupply (should these announced projects reach commercial completion, especially if total capacity significantly exceeds contract volumes). In Standard & Poor's evaluation of project-financed LNG projects, we begin the analysis with our customary project finance framework (see Standard & Poor's ?Debt Rating Criteria for Energy, Industrial, and Infrastructure?, Project Finance, March 19, 2001). Nonetheless, six key features will tend to distinguish the successful LNG projects.
- Access to stranded gas reserves,
- Lower capital costs,
- Associated product sales,
- Reliable shipping arrangements,
- Balance sheet strength, and
- Creditworthy buyers.
Access to stranded gas reserves
Access to abundant, but stranded, gas reserves is one of the key determinants to success in the LNG business. Absent an LNG project, geographic realities will strand natural gas reserves if a pipeline cannot bring the gas to market. In addition, if natural gas reserve quantities and their reserve lives far exceed domestic needs, much of the economic value will be stranded. For instance, natural gas reserves in Qatar, which are about 500 trillion cubic feet, not only far exceed domestic needs of its population of 400,000 for the next several hundred years or more, but Qatar's distance from major energy consumption centers precludes an economic pipeline solution. The RasGas and QatarGas LNG projects allowed Qatar and project sponsors to profitably monetize these reserves. Other formerly stranded gas reserves that have been successfully monetized through LNG projects include those in Alaska, Algeria, Australia, Brunei, Indonesia, Malaysia, Nigeria, Trinidad and Tobago, and United Arab Emirates. Significant gas reserves currently remain stranded in Egypt, Iran, Russia, Venezuela, and Yemen; these countries are all considering LNG projects.
Besides having access to abundant natural gas reserves, the more profitable LNG projects will benefit from reserves that are easily produced. Gas produced from high-rate wells in large reservoirs will generally improve a project's profitability. Conversely, projects that have to drill many wells in geographically diverse fields may detract from profitability. Such projects may see operating costs increase if they have to build extensive gathering systems, operate many wells, and drill replacement wells as they deplete.
Typically, LNG projects have monetized gas reserves owned by the host country or the host country's state-owned oil company. Project sponsors, whose ranks have always included the major multinational oil companies, operate LNG projects through some type of concession or joint venture agreement, or both. While the terms of the concessions vary, the state captures its economic value through any number of combinations of the following:
- Royalties calculated on the project's net income,
- Royalties calculated on the project's gross revenues,
- A per-unit charge for gas delivered to the project, and
- Dividends based on the project's profitability and the state's percentage ownership in the project.
- To the extent that a project can avoid paying pre-debt service expenses, such as gross revenue royalties, it may enhance its credit strength compared to projects where royalties will appear more like recurring expenses.
Lower capital costs
As the LNG business becomes more competitive, LNG projects can improve their competitiveness by minimising capital outlays. LNG projects, which consist of expensive upstream, gas processing, liquefaction, storage, and offloading port facilities, generally need several billion dollars to be brought on-line. To the extent that project sponsors can bring down the installed cost per ton, projects will become more competitive as they bid for new customers, particularly those willing to sign SPAs for the long-term market.
Extensive engineering and design work done prior to awarding construction contracts will likely keep capital costs down. The newest projects that have come on-line recently spent considerable effort on pre-construction design and engineering work. As a result, project sponsors had very little design and scope changes, a situation common to large construction projects and one that can dramatically drive up costs. Moreover, engineering, procurement, and construction (EPC) contractors could bid on projects with the confidence that preliminary design work will minimise changes and problems often associated with cost increases and schedule delays. In addition, these projects will begin commercial operations ahead of schedule, thus reducing interest costs.
Finally, to the extent that project sponsors can finance LNG projects with long-term debt and favourable interest rate spreads, their projects will be more competitive. Projects that can locate in countries with stable political and regulatory regimes and can also sell to creditworthy customers will likely attract investment-grade financing terms. On the other hand, projects located in challenging environments or those attempting to sell LNG to customers with uncertain credit may need to rely on sponsor equity and expensive political-risk insurance to keep financing costs down, if lenders perceive the risks to be higher.
Associated product sales. In addition to selling LNG, most LNG projects augment their base revenues with sales of by-products of gas processing. In some instances the revenues can be significant and, as such, can lower a project's break-even LNG price. The three most common by-products of LNG production are the following:
- Condensate, which is sold on the world market,
- Sulphur, which is sold on the world market, and
- Natural gas, which is sold into local markets.
Condensate, the light hydrocarbon liquid frequently associated with natural gas production, can be particularly valuable. Unfortunately, only by luck of geologic circumstances will projects be able to sell condensate. RasGas and QatarGas in Qatar produce LNG from a condensate-rich gas reservoir. Other projects either produce LNG from a dry gas with little condensate or do not have rights to the condensate. In the latter case, another production entity may be processing upstream gas, stripping out condensate for sale, and then delivering dry gas to the LNG project. BPAmoco's Atlantic LNG is one such project. On the other hand, if condensate volumes are not significant, the capital costs required to process upstream gas and recover the condensate may offset the revenue potential.
Sulphur, which a project must strip from the natural gas before it goes to liquefaction, generally is not a valuable revenue source. To the extent that a project can recover sulphur-processing costs through sulphur sales, it will be ahead of the game. Obviously, if an LNG project is fortunate to have gas supply that is naturally free of sulphur, it will not have to address the problem.
Reliable shipping arrangements
LNG shipping arrangements will influence an LNG project's success. The further a LNG project is from its targeted market, the higher the cost of shipping. These costs will manifest themselves in the number of ships needed, as well as the operating costs. If the buyer is responsible for shipping, the SPA will tend to discount the contract LNG price to account for shipping. Projects located closer to their markets will likely need fewer ships, all else being equal, because of the shorter round-trip transit time. Projects located farther from their markets, such as Oman LNG and RasGas, have been able to compensate for the greater distance, and attendant shipping costs, through economies of scale, low production costs, and large SPAs. Hence, realized net back profits from distant markets in the Far East or in the Western hemisphere are quite attractive.
Generally, as mentioned above, few buyers will cede control and ownership of LNG tankers to the LNG projects. Nonetheless, some projects are considering building and owning tankers on a speculative basis to take advantage of the growing spot market. Given the cost of a tanker relative to the cost of the upstream and liquefaction capitals, some projects may find it profitable to own one or two tankers, especially if large spot markets continue to develop.
Balance sheet strength
The barriers to entry into the LNG industry are extraordinarily high. One of the biggest barriers is raising the capital needed to build a project. To date only the largest multinational oil companies and state-owned oil companies have had the capital resources to develop LNG projects. While many LNG projects rely on project financing to raise debt, the reality is that these projects all have some limited recourse to their sponsors.
The ability to guarantee construction and completion has proven to be a valuable credit enhancement that only a few companies can provide. Because of the multibillion-dollar costs of an LNG project, no one EPC contractor is willing, or able, to provide the fixed-price, turnkey, date-certain contract typical of many project financings.
Typically a consortium of contractors will build an LNG project, and each contractor will limit its liability to some fraction of its contractual obligations. Hence, the concept of liquidated damages for delays and performance problems carries little meaning for LNG projects. Instead, sponsors have found it easier to guarantee completion, typically on a several basis in proportion to equity interest. Hence, substantially all sponsors will usually need investment-grade credit standings to build an investment-grade LNG project.
In some instances, such as with RasGas, a sponsor may extend its balance sheet to provide credit support during operations if LNG prices fall to levels that cannot sustain debt service. ExxonMobil, for instance, provides RasGas with a revolving $200 million line of credit if LNG prices drop too low to provide debt service. Oman LNG, the Omani state-owned oil company, provides gas to the project and subordinates payment for gas indefinitely if LNG prices are insufficient to service the project's debt.
Creditworthy buyer
Having a creditworthy LNG buyer is not only a key to a successful LNG project, it can be the deciding factor as to whether a project goes forward. Several factors, together, determine whether a market is a creditworthy risk:
- An offtaker with investment-grade credit strength sufficient to back the SPA;
- An offtaker located in a country with a developed natural gas transmission and distribution infrastructure;
- An offtaker with a sufficient balance sheet to finance the construction of LNG shipping, receiving, and regasification facilities;
- A market where LNG has become a critical component of energy supplies and not easily displaced by pipeline gas or other fuels;
- A diversified market where natural gas serves a mix of power generation, industrial, and residential uses (heating and cooking);
- A market located in a healthy and growing economy that can sustain LNG's premium status for the long-term; and
- A public policy supportive of LNG imports - a quality that will tend to result from having a healthy economy.
Absent these characteristics, a LNG project may struggle with long-term profitability concerns. Indeed, if project sponsors and lenders cannot reasonably foresee that a prospective LNG market can sustain the above characteristics, the prospective LNG project may never get past the concept stage.
Over the past couple of years, a large second tier of potential LNG importing countries, including India and China, has raised the prospects for new LNG projects. The potential demand from these two countries is enormous. Neither have indigenous natural gas supplies in any meaningful quantities. Air pollution concerns have grown serious and natural gas-fired power generation may play an important role in improving air quality. But very little infrastructure exists to receive or transport natural gas. Moreover, offtake credit quality will raise concerns with lenders, especially as fewer governments are backing obligations of their sector utilities (as Enron's Dabhol power plant's difficulties with the Indian government vividly demonstrate).
Standard & Poor's sees a mixed outlook for LNG projects. Certainly the macro trends point to an improving market for new LNG projects. On the supply side, declining capital costs, improvements in productivity, and economies of scale are lowering the threshold for economically feasible projects. Demand side prospects are also improving, as LNG becomes more affordable and environmental concerns make natural gas a fuel of choice. In addition, project developers are beginning to address market needs with more flexible contract terms that disengage from the traditional long-term take-or-pay contracts. Many new project announcements point to a new optimism, suggesting LNG's golden age has arrived.
Nevertheless, Standard & Poor's cautions that LNG may not pay off for some investors. An oversupply of LNG projects could drive down LNG prices. The spot market will likely develop much slower than many would like to see, in part due mostly to a lack of LNG tanker availability. And finally, as this year's violent energy price volatility in the US underscores, LNG price uncertainty will, or perhaps, should, make all but the bravest lenders wary of optimistic sponsor forecasts and project scenarios of success. Projects whose economics anticipate a vibrant US LNG market developing may be putting prospective lenders in harm's way.
Oman LNG L.L.C. is a 6.6-million metric tons per year capacity, two-train liquefied natural gas (LNG) plant in Oman that has been in commercial operation since April 2000. Oman LNG is proposing to enter into a US$1.3 billion US dollar-denominated commercial bank facility to refinance the existing debt facilities. The company's shareholders are the Government of the Sultanate of Oman (51%, foreign currency: 'BBB'/Stable); Shell Gas B.V. (Shell) (30%, 'AAA'/Stable); TotalFinaElf E&P Oman S.A. (5.54%, 'AA'/Stable); Korea LNG Limited (5%, not rated); Partex (Oman) Corp. (2%, not rated); Mitsubishi Corp. (2.77%, 'A-'/Stable); Mitsui & Co. Limited (2.77%); and Itochu Corp. (0.92%).
The rating on Oman LNG incorporates the following risks:
Lenders are exposed to commodity price risk, due to the fact that both spot and contract LNG prices are linked to world crude oil prices - a commodity that has shown significant volatility during the past four years.
Oman LNG operates a single-asset facility in a region that is exposed to regional conflicts and disturbances that could temporarily impair LNG deliverability.
The global LNG market has become increasingly competitive, as it risks near-term excess supply capacity.
Oman LNG does not currently own LNG ships, exposing the spot sales of the project to the risk of vessel availability shortage.
Existing and proven gas reserves in the Sultanate of Oman (29.3 trillion cubic feet (tcf)) are lower and less predictable than those in certain other countries in the region, although the independent reservoir consultant and indepe
For several Asian countries, without indigenous fossil fuels and concerned about over-reliance on crude oil imports from the Middle East in the 1970s, LNG has provided a critical diversification component of their energy supplies. Now countries in Europe, such as Spain, Portugal, Italy, and Turkey, are seriously considering importing significant quantities of LNG on a long-term basis. And in the US, the recent energy crunch may have pushed natural gas prospects high enough to encourage a sustainable LNG market. Finally, LNG's increasingly attractive stature as an environmental fuel of choice bodes well for the industry, and the cost to produce and deliver LNG has dramatically fallen.
But for all the LNG market positives there are a number of questions as yet unanswered that beg a pinch of caution. Will LNG's cost drop enough so that it will sustain a fuel of choice status? Alternatively, is LNG expanding so rapidly that it may soon flood the market with an attendant price collapse? Have LNG's promoters over-estimated the global demand for LNG and its attendant financability? Is the credit gulf between such top-tier LNG importing countries, such as Japan and Taiwan, and second tier candidates, such as India, too great to support significant LNG expansion? Will a global LNG spot market develop or, is the LNG industry about to push itself into a dangerous oversupply situation that could threaten many projects that have increasingly relied on highly leveraged project finance structures?
Regardless of where the LNG market heads, the past several years have seen two major new trends in the LNG business: The market for LNG has materially changed and capital costs have fallen. How LNG projects exploit these changes will distinguish the financable projects from those that merely appear as one-time news flashes. Keys to success will extend beyond the ability to sign a long-term supply and purchase agreement (SPA) with a creditworthy customer.
Changing market needs
The market for LNG has dramatically expanded over the past quarter century, as increasingly diverse customer needs have begun to be addressed by this niche fuel - needs that now extend beyond just ensuring security of supply. Broadly, four major changes in the market are driving an increase in demand:- Fewer concerns over security of supply,- Growing spot sales market,- A desire to de-link LNG prices from crude oil, and- Natural gas' growing status as a fuel of choice.
Fewer concerns over security of supply
Desire for long-term security of LNG supplies, which historically drove LNG contract negotiations, lead to lucrative 20-25 year deals, some with price floors. Most SPAs have provided such predictable revenues that they easily supported the financing and construction of large LNG projects, such as Australia Northwest Shelf, RasGas (also known as Ras Laffan Liquefied Natural Gas Co., 'BBB+'/Stable/-; in Qatar), and Oman LNG (Oman). These SPA deals featured take-or-pay provisions with only limited abilities to defer cargoes from one year to the next because of operational limitations or demand reductions. Typically, the buyer makes good on any deferred volume or agrees to pay liquidated damages. Indeed, no project sponsor would even have considered undertaking the multibillion effort of building an LNG liquefaction and storage complex without an executed supply and purchase agreement that ensured a highly predictable offtake volume and price structure.
The Asian financial crisis in 1998 marked a turning point for LNG projects and signalled a clear need for a more flexible LNG market. In Korea, particularly, the crisis triggered a sharp drop in energy consumption as the economy faltered. As a result, Korea's contractual LNG import obligations far exceeded its needs and it had to curtail LNG deliveries. As the Korean economy recovered, full contractual LNG shipments resumed. The Korean experience highlighted an underlying characteristic about energy markets - energy consumption adjusts considerably as the weather and the economy change, among other factors.
Consequently, potential buyers of LNG, particularly those that have already built a solid base load LNG supply, now want flexible take volume provisions without penalties incorporated into contracts for incremental supplies. Hence, long-term security of LNG supply ranks lower on a buyer's list of priorities. Indeed, fewer buyers want the long-term liability that comes with a 20-25 year SPA. Many LNG buyers are not prepared to take the risk that their end-use customers' requirements (e.g., independent power producers or residential heating) could suddenly drop. Where suppliers can craft flexible contracts, markets for LNG should increase. In the near term, Standard & Poor's expects that LNG suppliers will need to offer a variety of LNG contracts, which may feature one or any combination of the following contract volume provisions:
- Long-term SPAs: Traditional 20-25 year contracts with well-defined volumes with limited abilities to defer LNG cargos from one year to the next.
- Short-term SPAs: 5-10 year contracts with well-defined volumes and limited abilities to defer LNG cargos from one year to the next.
- Flexible-SPAs: LNG contracts that resemble a requirements-based contract without the need to make good on deferrals.
- Seasonal SPAs: Shipping schedules that account for seasonal variations in energy consumption (e.g., summer versus winter).
- Tradable cargos: Provisions that allow the contractual buyer to divert cargos on a spot basis to a different buyer.
- Spot cargos: Contracts for limited cargoes, varying from one to five or so shipments and priced against a benchmark price in the buyer's market.
While such terms may support an expanded LNG market, the credit implications for sellers should be obvious. Absent some form of mitigation, or hedge, uncertain sales volumes will likely increase credit risk for LNG projects. Moreover, netbacks from spot market sales have only recently been high enough to justify the costs during very elevated peak pricing periods.
Growing spot sales
The sudden increase in spot cargoes characterises one of the more dramatic changes to the industry in recent years. Historically LNG tanker construction orders accompanied specific projects; shippers knew that they could virtually guarantee full usage of an expensive tanker for the duration of a long-term SPA. No practical spot market for LNG existed, at least in volumes that could sustain speculatively built tankers. Moreover, the economics of operating receiving and regasification terminals have typically required year-round utilization to justify the enormous capital investments. Such dynamics almost ensured that a spot market for LNG would be slow to develop. That buyers have generally insisted on owning and controlling tankers almost guaranteed that sellers would have a difficult time securing tankers for LNG spot sales.
But the industry has seen a shift in the past few years. Several LNG suppliers have taken a number of LNG tankers out of mothballs, restored them, and put them into service on a short-term basis. Three new projects with excess capacity - RasGas, Oman LNG, and Atlantic LNG - have been able to take advantage of favourable conditions in the US, Europe, and Asia to sell spot cargos. Even traditional buyers of LNG under long-term SPAs, such as Korea, have recently needed spot cargoes during the winter to meet peak season heating needs. In the US, where gas supplies have been inadequate at times, due either to wellhead deliverability limits or transmission constraints, to meet the growing gas-fired power generation market, a spot market may becoming viable, especially if peak electricity prices can justify spot LNG cargo prices. Restoration work on two US regasification terminals that were closed in the 1980s due to lack of demand and abundant energy supplies has recently begun. Unfortunately, the two-three year lead time on new tanker construction will tend to dampen the spot market, except for those with the greatest appetite for risk.
De-linking from crude oil
LNG markets that have developed beyond the traditional markets in Japan, Taiwan, and Korea increasingly want to de-link LNG pricing from the customary Japanese Customs Clearing price (JCC price) - the weighted-average price of a basket of crude oils delivered into Japan. Historically the JCC price was an appropriate benchmark because LNG imports could displace crude oil. But as LNG use spreads, potential buyers want to link LNG prices to alternative fuels. In the US, where LNG importing prospects look promising, LNG contracts may price against Henry Hub natural gas prices - a commodity price strongly linked to electricity prices. Some buyers have proposed linking LNG contract prices to a basket of imported fuels that include coal, among other fuels.
Linking LNG to alternative fuels will tend to make LNG more competitive, but, absent hedging, could pose a credit risk for lenders to suppliers if commodity price risk becomes volatile. Electricity and natural gas prices, for example, show much greater volatility than crude oil. The US, for instance, has recently seen very volatile commodity price movements in the markets - a situation that would certainly raise credit risks for LNG projects solely targeting the US Moreover, most LNG sales into the US will need a landed price of at least $3.25 per million BTU, which exceeds the long-term Henry Hub price of about $2.90, to sustain a long-term business.
Fuel of choice
Natural gas' status as a fuel of choice globally has expanded the demand for LNG in markets where little or restricted access (geographical or temporal) to natural gas would otherwise restrict LNG's growth. Several factors over the past decade have made natural gas a premium fuel globally, especially for power generation. First, compliance with existing, or expected, air pollution standards is driving natural gas' attractiveness. Natural gas-fired generation emits fewer regulated pollutants and waste products, such as sulphur dioxide, nitrogen oxides, and airborne solid particulates, than other types of generation. Ash and radioactive waste are simply not concerns for natural gas users. Such an advantage over other fuels favours LNG, but it likely adds a price premium to natural gas against other fuels on a BTU basis.
Second, gas-fired generation is cheap and quick to build. Combined-cycle gas turbine generators generally require a smaller capital outlay than the construction of nongas-fired generation plants and a shorter construction period. Construction for a gas-fired power plant takes only about two years against a four to five construction period for coal, or even longer for nuclear power. As a result, over the past 10 years, many markets without access to natural gas have either chosen, or are considering the option, to import LNG for power generation where capital for new generation is available. Although, as Enron Corp.'s well-publicised experience with its Dabhol plant in India demonstrates, LNG-fired power generation, despite access to capital, can still present a credit risk in markets not able, or willing (or both), to pay the premium. India alleges that it just cannot afford the power.
And finally, demand for natural gas will likely increase as concern grows over the potential for greenhouse gases to cause global warming. Natural gas emits less carbon dioxide than competing fossil fuels. Hence, even if other fuels are cheaper on a BTU basis, LNG may be more competitive given the externality cost of carbon dioxide emissions or other pollution concerns.
The US market - a special case
The US represents a unique LNG market. For years North America, with the world's most extensive natural gas pipeline system, has been virtually self sufficient in natural gas production, save for New England. In New England, because pipeline capacity constraints have limited natural gas consumption growth, it imported small amounts of LNG through the Boston terminal to meet peak shaving needs in the winter. Last year, however, saw a record run-up in natural gas prices, as prices hit just above $10 per million BTU on average - $40 per million BTU on the west coast. Record temperatures, both hot and cold, and the rapid increase in gas-fired power generation strained North America's ability to supply conventional natural gas. At these rarefied prices, the US gas market became extraordinarily lucrative to LNG exporters, particularly with world LNG prices hovering around $3.20 per million BTU. Unfortunately, low LNG spot tanker availability and few LNG storage and regasification terminals in the US limited the near-term import potential. In response to encouraging price signals, however, a number of oil, gas, and electricity companies, including El Paso Corp., Texaco Corp., and Enron Corp., have announced plans to build storage and regasification facilities to service the US market.
Natural gas prices have recently fallen to about $3 per million BTU in response to new gas-well drilling and moderate weather. Nonetheless, many industry observers have concluded that the US natural gas market, driven by the power industry, has structurally changed and hence, will need LNG imports to meet demand needs that could hit 30 trillion cubic feet a year by 2010. That record gas-well drilling activity in the US is discovering fewer and smaller gas reserves per well with limited deliverability supports these claims. Even so, commodity price risk - something that has shown extreme volatility of late - will likely make a US LNG market a risky bet for some time. Potential new gas supplies in large quantities from Alaska or the Mackenzie Delta could dramatically improve the domestic supply picture. Given the size of capital investments needed on the receiving end, LNG importers will likely enter this market slowly, if not with a healthy scepticism.
Lower capital costs
Changes and improvements to LNG technology have fuelled an explosion of new project announcements. In short, producing and shipping LNG cost much less than it did just a decade ago. As a result, abundant gas reserves that once had little or no value can now commercially reach more customers world-wide than before.
New technology developments and improvements in refrigerant and liquefaction techniques have lowered the capital costs of these most expensive LNG processes. Since 1988, nominal liquefaction capital costs have fallen to about $200 per ton of LNG capacity in 2001 from about $550 per ton, according to data in the Oil and Gas Journal. Technological improvement is also allowing sponsors to build production trains with increasing throughput capacity. The latest designs can process about 3.3 to 3.4 million tons per year of LNG, up from about 2.0 million tons about 10 years ago. Moreover, projects that expand into third and fourth trains, such as Atlantic LNG, Oman LNG, and RasGas, will benefit from economies of scale because they further lower the LNG production cost per ton. Most expanded projects will generally share certain common facilities, such as site preparation, utility infrastructure, LNG storage tanks, loading docks, administrative, and overhead.
Lower tanker prices are also driving the global LNG market, especially the spot market. The cost to build an LNG tanker has fallen dramatically, nearly 50% during the last decade. Since 1997 the cost per tanker has dropped to about $175 million per vessel from about $225 million. Some of the drop occurred during the Asian financial crisis, as Korean shipyards fought for dollar-denominated tanker construction contracts. Prices recently have inched up, as LNG slots are completely full for the next few years. Nonetheless, nominal costs to build tankers have fallen, as shipbuilders have developed new techniques and greater experience with LNG tankers.
Keys to LNG project success
Project finance has played a vital role over the past several years in financing the latest generation of LNG projects - projects, for a variety of reasons, sponsors elected to keep off their balance sheets. Recent project financings have included QatarGas, RasGas, Oman LNG, and Atlantic LNG. Going forward, as buyer needs become more diverse, some project sponsors may find their efforts to structure investment-grade transactions frustrating. Indeed, the flood of new LNG project announcements may be signaling a temporary LNG oversupply (should these announced projects reach commercial completion, especially if total capacity significantly exceeds contract volumes). In Standard & Poor's evaluation of project-financed LNG projects, we begin the analysis with our customary project finance framework (see Standard & Poor's ?Debt Rating Criteria for Energy, Industrial, and Infrastructure?, Project Finance, March 19, 2001). Nonetheless, six key features will tend to distinguish the successful LNG projects.
- Access to stranded gas reserves,
- Lower capital costs,
- Associated product sales,
- Reliable shipping arrangements,
- Balance sheet strength, and
- Creditworthy buyers.
Access to stranded gas reserves
Access to abundant, but stranded, gas reserves is one of the key determinants to success in the LNG business. Absent an LNG project, geographic realities will strand natural gas reserves if a pipeline cannot bring the gas to market. In addition, if natural gas reserve quantities and their reserve lives far exceed domestic needs, much of the economic value will be stranded. For instance, natural gas reserves in Qatar, which are about 500 trillion cubic feet, not only far exceed domestic needs of its population of 400,000 for the next several hundred years or more, but Qatar's distance from major energy consumption centers precludes an economic pipeline solution. The RasGas and QatarGas LNG projects allowed Qatar and project sponsors to profitably monetize these reserves. Other formerly stranded gas reserves that have been successfully monetized through LNG projects include those in Alaska, Algeria, Australia, Brunei, Indonesia, Malaysia, Nigeria, Trinidad and Tobago, and United Arab Emirates. Significant gas reserves currently remain stranded in Egypt, Iran, Russia, Venezuela, and Yemen; these countries are all considering LNG projects.
Besides having access to abundant natural gas reserves, the more profitable LNG projects will benefit from reserves that are easily produced. Gas produced from high-rate wells in large reservoirs will generally improve a project's profitability. Conversely, projects that have to drill many wells in geographically diverse fields may detract from profitability. Such projects may see operating costs increase if they have to build extensive gathering systems, operate many wells, and drill replacement wells as they deplete.
Typically, LNG projects have monetized gas reserves owned by the host country or the host country's state-owned oil company. Project sponsors, whose ranks have always included the major multinational oil companies, operate LNG projects through some type of concession or joint venture agreement, or both. While the terms of the concessions vary, the state captures its economic value through any number of combinations of the following:
- Royalties calculated on the project's net income,
- Royalties calculated on the project's gross revenues,
- A per-unit charge for gas delivered to the project, and
- Dividends based on the project's profitability and the state's percentage ownership in the project.
- To the extent that a project can avoid paying pre-debt service expenses, such as gross revenue royalties, it may enhance its credit strength compared to projects where royalties will appear more like recurring expenses.
Lower capital costs
As the LNG business becomes more competitive, LNG projects can improve their competitiveness by minimising capital outlays. LNG projects, which consist of expensive upstream, gas processing, liquefaction, storage, and offloading port facilities, generally need several billion dollars to be brought on-line. To the extent that project sponsors can bring down the installed cost per ton, projects will become more competitive as they bid for new customers, particularly those willing to sign SPAs for the long-term market.
Extensive engineering and design work done prior to awarding construction contracts will likely keep capital costs down. The newest projects that have come on-line recently spent considerable effort on pre-construction design and engineering work. As a result, project sponsors had very little design and scope changes, a situation common to large construction projects and one that can dramatically drive up costs. Moreover, engineering, procurement, and construction (EPC) contractors could bid on projects with the confidence that preliminary design work will minimise changes and problems often associated with cost increases and schedule delays. In addition, these projects will begin commercial operations ahead of schedule, thus reducing interest costs.
Finally, to the extent that project sponsors can finance LNG projects with long-term debt and favourable interest rate spreads, their projects will be more competitive. Projects that can locate in countries with stable political and regulatory regimes and can also sell to creditworthy customers will likely attract investment-grade financing terms. On the other hand, projects located in challenging environments or those attempting to sell LNG to customers with uncertain credit may need to rely on sponsor equity and expensive political-risk insurance to keep financing costs down, if lenders perceive the risks to be higher.
Associated product sales. In addition to selling LNG, most LNG projects augment their base revenues with sales of by-products of gas processing. In some instances the revenues can be significant and, as such, can lower a project's break-even LNG price. The three most common by-products of LNG production are the following:
- Condensate, which is sold on the world market,
- Sulphur, which is sold on the world market, and
- Natural gas, which is sold into local markets.
Condensate, the light hydrocarbon liquid frequently associated with natural gas production, can be particularly valuable. Unfortunately, only by luck of geologic circumstances will projects be able to sell condensate. RasGas and QatarGas in Qatar produce LNG from a condensate-rich gas reservoir. Other projects either produce LNG from a dry gas with little condensate or do not have rights to the condensate. In the latter case, another production entity may be processing upstream gas, stripping out condensate for sale, and then delivering dry gas to the LNG project. BPAmoco's Atlantic LNG is one such project. On the other hand, if condensate volumes are not significant, the capital costs required to process upstream gas and recover the condensate may offset the revenue potential.
Sulphur, which a project must strip from the natural gas before it goes to liquefaction, generally is not a valuable revenue source. To the extent that a project can recover sulphur-processing costs through sulphur sales, it will be ahead of the game. Obviously, if an LNG project is fortunate to have gas supply that is naturally free of sulphur, it will not have to address the problem.
Reliable shipping arrangements
LNG shipping arrangements will influence an LNG project's success. The further a LNG project is from its targeted market, the higher the cost of shipping. These costs will manifest themselves in the number of ships needed, as well as the operating costs. If the buyer is responsible for shipping, the SPA will tend to discount the contract LNG price to account for shipping. Projects located closer to their markets will likely need fewer ships, all else being equal, because of the shorter round-trip transit time. Projects located farther from their markets, such as Oman LNG and RasGas, have been able to compensate for the greater distance, and attendant shipping costs, through economies of scale, low production costs, and large SPAs. Hence, realized net back profits from distant markets in the Far East or in the Western hemisphere are quite attractive.
Generally, as mentioned above, few buyers will cede control and ownership of LNG tankers to the LNG projects. Nonetheless, some projects are considering building and owning tankers on a speculative basis to take advantage of the growing spot market. Given the cost of a tanker relative to the cost of the upstream and liquefaction capitals, some projects may find it profitable to own one or two tankers, especially if large spot markets continue to develop.
Balance sheet strength
The barriers to entry into the LNG industry are extraordinarily high. One of the biggest barriers is raising the capital needed to build a project. To date only the largest multinational oil companies and state-owned oil companies have had the capital resources to develop LNG projects. While many LNG projects rely on project financing to raise debt, the reality is that these projects all have some limited recourse to their sponsors.
The ability to guarantee construction and completion has proven to be a valuable credit enhancement that only a few companies can provide. Because of the multibillion-dollar costs of an LNG project, no one EPC contractor is willing, or able, to provide the fixed-price, turnkey, date-certain contract typical of many project financings.
Typically a consortium of contractors will build an LNG project, and each contractor will limit its liability to some fraction of its contractual obligations. Hence, the concept of liquidated damages for delays and performance problems carries little meaning for LNG projects. Instead, sponsors have found it easier to guarantee completion, typically on a several basis in proportion to equity interest. Hence, substantially all sponsors will usually need investment-grade credit standings to build an investment-grade LNG project.
In some instances, such as with RasGas, a sponsor may extend its balance sheet to provide credit support during operations if LNG prices fall to levels that cannot sustain debt service. ExxonMobil, for instance, provides RasGas with a revolving $200 million line of credit if LNG prices drop too low to provide debt service. Oman LNG, the Omani state-owned oil company, provides gas to the project and subordinates payment for gas indefinitely if LNG prices are insufficient to service the project's debt.
Creditworthy buyer
Having a creditworthy LNG buyer is not only a key to a successful LNG project, it can be the deciding factor as to whether a project goes forward. Several factors, together, determine whether a market is a creditworthy risk:
- An offtaker with investment-grade credit strength sufficient to back the SPA;
- An offtaker located in a country with a developed natural gas transmission and distribution infrastructure;
- An offtaker with a sufficient balance sheet to finance the construction of LNG shipping, receiving, and regasification facilities;
- A market where LNG has become a critical component of energy supplies and not easily displaced by pipeline gas or other fuels;
- A diversified market where natural gas serves a mix of power generation, industrial, and residential uses (heating and cooking);
- A market located in a healthy and growing economy that can sustain LNG's premium status for the long-term; and
- A public policy supportive of LNG imports - a quality that will tend to result from having a healthy economy.
Absent these characteristics, a LNG project may struggle with long-term profitability concerns. Indeed, if project sponsors and lenders cannot reasonably foresee that a prospective LNG market can sustain the above characteristics, the prospective LNG project may never get past the concept stage.
Over the past couple of years, a large second tier of potential LNG importing countries, including India and China, has raised the prospects for new LNG projects. The potential demand from these two countries is enormous. Neither have indigenous natural gas supplies in any meaningful quantities. Air pollution concerns have grown serious and natural gas-fired power generation may play an important role in improving air quality. But very little infrastructure exists to receive or transport natural gas. Moreover, offtake credit quality will raise concerns with lenders, especially as fewer governments are backing obligations of their sector utilities (as Enron's Dabhol power plant's difficulties with the Indian government vividly demonstrate).
Standard & Poor's sees a mixed outlook for LNG projects. Certainly the macro trends point to an improving market for new LNG projects. On the supply side, declining capital costs, improvements in productivity, and economies of scale are lowering the threshold for economically feasible projects. Demand side prospects are also improving, as LNG becomes more affordable and environmental concerns make natural gas a fuel of choice. In addition, project developers are beginning to address market needs with more flexible contract terms that disengage from the traditional long-term take-or-pay contracts. Many new project announcements point to a new optimism, suggesting LNG's golden age has arrived.
Nevertheless, Standard & Poor's cautions that LNG may not pay off for some investors. An oversupply of LNG projects could drive down LNG prices. The spot market will likely develop much slower than many would like to see, in part due mostly to a lack of LNG tanker availability. And finally, as this year's violent energy price volatility in the US underscores, LNG price uncertainty will, or perhaps, should, make all but the bravest lenders wary of optimistic sponsor forecasts and project scenarios of success. Projects whose economics anticipate a vibrant US LNG market developing may be putting prospective lenders in harm's way.
Oman LNG L.L.C. is a 6.6-million metric tons per year capacity, two-train liquefied natural gas (LNG) plant in Oman that has been in commercial operation since April 2000. Oman LNG is proposing to enter into a US$1.3 billion US dollar-denominated commercial bank facility to refinance the existing debt facilities. The company's shareholders are the Government of the Sultanate of Oman (51%, foreign currency: 'BBB'/Stable); Shell Gas B.V. (Shell) (30%, 'AAA'/Stable); TotalFinaElf E&P Oman S.A. (5.54%, 'AA'/Stable); Korea LNG Limited (5%, not rated); Partex (Oman) Corp. (2%, not rated); Mitsubishi Corp. (2.77%, 'A-'/Stable); Mitsui & Co. Limited (2.77%); and Itochu Corp. (0.92%).
The rating on Oman LNG incorporates the following risks:
Lenders are exposed to commodity price risk, due to the fact that both spot and contract LNG prices are linked to world crude oil prices - a commodity that has shown significant volatility during the past four years.
Oman LNG operates a single-asset facility in a region that is exposed to regional conflicts and disturbances that could temporarily impair LNG deliverability.
The global LNG market has become increasingly competitive, as it risks near-term excess supply capacity.
Oman LNG does not currently own LNG ships, exposing the spot sales of the project to the risk of vessel availability shortage.
Existing and proven gas reserves in the Sultanate of Oman (29.3 trillion cubic feet (tcf)) are lower and less predictable than those in certain other countries in the region, although the independent reservoir consultant and indepe
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