Zeus Energy Consulting Group - Industry Insight: CNG, LNG, Project Finance

Below is just a sample of our observations on some of the essential macro trends we see emerging in the world gas trade.

CNG

Commercialization of CNG Ocean Transport: Technology developers such as Sea NG, Knutsen, TransCanada, in partnership with Overseas Shipholding Group (OSG), and EnerSea, in partnership with “K” Line, appear to be encountering a lack of congestion along the final stretch toward commercializing their respective technologies. However, as first ship orders are placed, and first projects move forward, other well-heeled competitors will almost certainly enter the field with a commitment to capturing share.

Driven largely by sustained record-high petroleum prices, CNG ocean transport appears imminent, and indicators that first projects are just around the corner are found in several recent developments.

First, major classification society approval processes and rules development are noticeably gaining momentum. Second, recent evidence suggests that markets largely dependent on fuel oil are now considering CNG to be a serious regional supply chain alternative in situations where stranded and associated gas deposits are located within distances of, say, 1,500 nautical miles. Third, strategic alliances and partnerships are not only gaining critical mass, but the level of interest among lenders is on the rise. While questions still remain as to the risks (compared with LNG), the leading CNG technology developers appear to be having little difficulty attracting both debt and equity providers.

Given the tightening in the construction market since 2003, CNG may offer comparative supply-chain cost advantages relative to LNG because less field-erected infrastructure is required in connection with loading and unloading. Also, reduced upstream infrastructure CAPEX means less exposure to stranded capital where smaller reserves deposits are concerned.

For these reasons, Zeus expects the race toward first commercial projects to continue to intensify in 2007, and we’d have to say that the likelihood of a first project being announced before yearend is high.

LNG

Pooling of LNG: One of the most significant recent innovations in the LNG industry is the move by additional integrated suppliers, for example, BG and Suez (in addition to Shell and BP), to combine their LNG supplies into common pools to serve a portfolio of customers, thereby rendering the reliance of a single customer on a single upstream supplier less desirable and placing the burden of performance on the integrated supplier. This development has several strategic implications:

First, it allows the integrated supplier to rationalize the global LNG marketplace, diverting cargoes to the highest-paying markets, while supplementing the lower-value markets with domestic gas. During the last half of 2005 and the first quarter of 2006, this strategy paid huge dividends for BG, Suez, BP, and Shell, as they diverted cargoes from the US to Spain and subsequently to northern Europe and Asia.
Second, it improves the likelihood of export projects being built in less-stable countries like Nigeria, Angola and Venezuela. An integrated supplier, like Suez, for example, who has secured supply from Trains 1 and 5 of Atlantic LNG, can more easily afford to contract supplies from a project like Yemen LNG, which has a riskier geopolitical profile.
Third, it will force standards for LNG composition. These integrated suppliers need maximum flexibility to divert cargoes from market to market and cannot risk having a cargo rejected as a result of failure to meet content specifications. Some exporters are beginning to market their gas as "Far East Friendly" or "US Friendly", signaling the beginning of standards.

Migration of free trade into the Pacific: A second key trend to follow over the next decade is the rapid advancement of the market in the Pacific. The huge profits made in the Atlantic Basin in the last half of 2005 and early 2006 will motivate companies to liberalize LNG flows across the Pacific. This trend has several important implications:

First, it is hastening the need for West Coast terminals. Costa Azul has become enormously valuable. Sempra is already expanding it. Other terminals on the West Coast of the US will be built. We anticipate a significant overbuild as numerous integrated suppliers try to gain cross-Pacific market access.
Ship construction will continue to grow rapidly because the Pacific is much larger than the Atlantic. Chinese shipbuilders will take advantage of the strong demand.
An Asian gas futures market is likely to be created in Singapore with the delivery point being a new transshipment terminal to be built on the Island.
We're observing an increase in the number of inter-basin swap transactions being proposed. A Japanese customer, for example, might purchase a spot cargo in Nigeria, find a customer in Spain that has a contract with Qatar, and swap the cargo. The Japanese customer's Nigerian cargo would go to Spain, and the Qatari cargo would go to Japan. Indian companies are doing the same thing. They might buy a cargo from Sakhalin and send it to Japan in exchange for a Japanese cargo from Qatar being rerouted to India.

Market access takes precedence over receiving terminal utilization: Integrated suppliers and their investors are growing less concerned about receiving terminal capacity utilization and more concerned about market access. The receiving terminal tends to represent only 10% of the total supply-chain cost. Having two terminals with access to two continental markets, therefore, increases the supply-chain cost by only 10%, which can be paid for rapidly with only a one-dollar market-price differential. As the trend towards more liberal trade of LNG spills into the Pacific, several key events are likely to occur:

We believe the construction of new receiving terminals will accelerate, possibly exceeding two units of receiving capacity for every unit of liquefaction. This means that, if liquefaction capacity reaches 400 million metric tons by 2020, receiving capacity will rise to some 800 million metric tons, or roughly 120 bcfd of capacity (3.4 bcmd). Global receiving capacity is currently 44 bcfd.
Terminal designs and construction will become even more standardized. Once the current shortages in engineering and construction capacity, raw materials and labor are overcome, the cost of new receiving terminals will fall significantly, possibly below $75 million for a basic single-tank unit, with minimal capital expenditures for jetty construction and dredging.
This trend will broaden LNG delivery to more island markets, like Fiji, Hawaii, and the Philippines, where diesel is still a major power-generation fuel.

Greater transshipment of LNG via small ship, barge, rail and truck: Japan and Spain are leading the way, and the trend can be expected to spill over into other countries. China is already shipping LNG by train from western to eastern China. As more receiving terminals are built, importers will innovate LNG transshipment technologies to better satisfy downstream demand. This will lead to several key trends:

Demand for LNG shuttle tankers and barges may be spurred where LNG can compete against diesel for power markets.
Micro-marine terminals served by barges will allow LNG to move into more densely populated markets.
Trucking of LNG, we believe, will grow exponentially over the next three decades. More LNG will be stored along various nodes of the supply chain for seasonal peak-load requirements.
Firms that can design and quickly install low-cost LNG storage units should see a market in the hundreds of units.
Demand for LNG downstream of the terminal will arise from several current needs, but other markets will certainly be innovated:
- Seasonal storage (e.g., the New England model) will grow where LNG storage is currently constrained.
- In developing markets where pipeline access is limited or prohibited due to environmental issues, trucked LNG will reach isolated consumers.
- Liquid fuel markets (e.g., heavy-duty transportation dependent on diesel, which is currently twice as expensive as natural gas) will be eroded by LNG.
- LNG will defer pipeline repair in areas where trucked LNG is available; however, LNG will drive grid reinforcement in coastal areas where local distribution companies absorb imported LNG bound for the interstate/interregional gas grid.
- LNG test facilities (e.g., startup of new LNG plants, fire schools, etc.) will begin to populate the landscape.

Offshore buoys to snipe high-value peaking markets from established terminals: Offshore turret and buoy systems will allow access to two types of markets:

Densely populated markets where full-scale terminals are prohibited by local citizens' concerns tend to favor development of buoys.
Large industrial buyers who want to establish an inexpensive port into the world LNG trade will exploit this opportunity. This type of buyer may seldom use the terminal, but build it simply to negotiate better gas-supply agreements with domestic suppliers and transporting pipelines.
Modifications to ships to enable use of offshore buoys are currently too expensive. There is strong demand for technologies that can reduce ship-conversion costs. Several competing technologies are under development.

Offshore unloading docks and cryogenic LNG piping to revolutionize LNG terminals: New large-diameter cryogenic-pipe designs reportedly allow LNG to be transported 10 or more miles with little heat influx. This technological advance has several key implications:

Conventional ships might be offloaded miles from shore, while LNG is transported to low-profile tanks onshore, avoiding the need for regasification buoys, long ship delays and expensive modifications to ships.
Expensive liquefaction projects might offload directly to ships in advance of onshore tank completion, thereby shortening time to market by months.
Cryogenic piping or hoses might allow the routine transfer of LNG from one ship to another, thereby allowing break-bulk lightering of ships as they approach markets.

A trend toward economical small-scale liquefaction: Thus far, LNG has gained economies of scale through scale-up of the technology. The reverse is now necessary and can be achieved through manufacturing efficiencies and design standardization. This development would have several implications:

Standard, shop-fabricated liquefaction plants will grow less expensive per ton of capacity. The time is right for this technology, as mega-scale projects have leapt in cost from $200 per metric ton to more than $500 per metric ton.
Smaller-scale liquefaction plants, i.e., between 100,000 and 1.0 million metric tons per year of capacity, will allow access to cheaper gas reserves that exporting nations currently consider suboptimal.
High diesel costs provide a window of opportunity for micro-LNG-terminal solutions to island markets, large industrial consumers, etc.
Floating LNG plants capable of rapid development of small gas fields and subsequent movement to new fields may become an option.

Power Generation

When U.S. Energy Secretary Sam Bodman delivered a staggering right cross to the FutureGen Alliance partners, withdrawing the Department of Energy’s (DOE’s) support for the $1.8 billion project to be sited near Matoon, Illinois, he also made it patently clear that the rules of the game would most certainly change as part of the DOE’s dramatic restructuring of the FutureGen initiative.

In February 2003, the DOE first announced FutureGen, a $1 billion initiative that contemplated the development of a coal-based, 275-megawatt electric generation plant with the aim of demonstrating revolutionary clean coal technology that would produce near-zero emissions.
          Consequently, The FutureGen Alliance – a consortium comprised of (1) some of the largest public utilities and wholesale power marketers, including China Huaneng Group, American Electric Power, Southern Company, PPL Energy Services and Luminant, (2) some of the largest coal producers and mining interests, including Peabody, Foundation Coal, Consol Energy, Anglo American, Xstrata Coal and Rio Tinto, and (3) some of the largest diversified energy companies, including BHP Billiton and E.on US – was formed to partner with the DOE on the FutureGen project.
          Bodman stated that the restructuring aims to demonstrate carbon capture and storage (CCS) technologies through multiple commercial-scale integrated gasification combined-cycle (IGCC) power plants and that the DOE would support IGCC projects by providing funding for the addition of CCS technology to plants that would be operational by 2015. Most importantly, the DOE aims to open the initiative to all companies – in and outside the current FutureGen Alliance.
          The DOE, following Bodman’s announcement, issued a request for information (RFI) to gasification industry participants seeking input on the costs and feasibility of clean coal facilities that achieve the intended goals of FutureGen.
          SYNGAS Refiner news editor Alex Cornitius caught up with the DOE’s Julie Ruggiero who stated that the Matoon project could still be on the table and would be assessed along with all other applicants. However, all clean coal technologies would be considered as long as (1) they are on a commercial-scale, and (2) the development of carbon capture and sequestration (CCS) is at the forefront of the plans. Ruggiero said that the DOE would foot 100% of the CCS bill for projects receiving DOE support, while at the same time reducing the DOE’s percentage contribution to overall capital costs in order to make taxpayer’s dollars go further. Ruggiero cited not only escalating project costs but also the manner in which the Alliance partners moved forward with selection of the Matoon site as reasons culminating in the present circumstances.
          “Bodman’s announcement sent ripples that have apparently resonated among many of our clients,” said Patrick LaStrapes, president of Zeus Development Corp and head of Zeus Energy Consulting Group. “We’ve received several calls since the announcement from many second-tier proponents of gasification technologies intent on understanding whether the door is truly open to innovative developers who might want to take part in a program available to a wider group of industry participants. I’ll say this much. I fully expect to see the emergence of new IGCC and SNG pureplays. The only other phenomenon that we’re experiencing similar to this falls in the area of mid-tier reserves development linked to medium-scale LNG supply chains. There again, were seeing several pureplays by firms who recognize the opportunity to enter a field not dominated by the majors.”
          Some analysts question how the US will commercialize clean coal technologies in such a manner to stay apace with demand without emitting large amounts of carbon dioxide into the atmosphere. Afterall, coal is one of the US’s most abundant primary-energy resources, and some 85-90 percent of the coal produced domestically is consumed by electric utilities and accounts for roughly half of the electricity produced. Some believe that coal will not rise to the challenge, and that nuclear capacity will fill the void.
          However, in order to put that notion to bed, one need only consider two items: (1) the lead times involved in bringing nuclear capacity online, and (2) nuclear’s cost competitiveness. “End of story,” says LaStrapes. “The lead times alone will prefer other alternatives. Natural gas and coal-derived synfuels will fill the void. Gas-fired combined-cycle plants can be built in a fraction of the time required for coal and nuclear plants. I see combined-cycle, as in the past, settling into the intermediate dispatch range and IGCC moving further down into the baseload range of utilities’ load curves. I believe that innovative developers will find a way to make that happen. This is not a field for the fainthearted, but I know several innovators that have the wherewithal to stay the course.”

Project Finance

How the Financial Markets View IGCC in North America: While the range of financing possibilities needed to fuel growth of IGCC have expanded in recent years, as evidenced by the increased flow of high-yield instruments and B-loans into the global power sector, technology risk continues to loom large in the minds of investors. However, this risk does not necessarily mean impasse for North American IGCC. It does mean that debt providers will avoid development risk like the plague. But, to the extent that developers employ proven technologies and mitigate construction risks, non-traditional investors will begin to venture into IGCC projects.

Yes, IGCC must develop a performance track record. And, yes, availability is a chief source of concern among skeptics. Notwithstanding, mitigation measures can lead to a middle ground where investors and developers can reach compromise.

But, before going down that path, let’s consider who the debt providers are that might be attracted to IGCC in North America. First, there’s the market for partial non-recourse project financing, a market populated by the biggest banks. That market is slowly returning, but not exactly springing back from the beatings taken during 2002-2003 on the heels of the Enron crisis and the bursting of the technology bubble. During 2000, global project financing activity had reached a figure just short of $250 billion. By comparison, during 2002, project financings came to roughly $70 billion. The market has yet to return to the robust level of activity reached in 2000.

Then, there are non-traditional sources of capital in the power sector. Originally structured as loan participation vehicles for international infrastructure development, B-loans are, relatively speaking, newcomers to the global power sector, and hedge funds and institutional investors, like insurance companies, for example, are populating the B-loan space, filling the void left by the banks after 2002. However – and this is important – while the banks are slow to return, they will eventually return.

Also, high yield investors have gone to school on the electric power markets in a post-deregulation environment, and they have, over time, developed a better understanding of the new competitive framework for electricity.

Why will these sources of funds venture into the space attributable to IGCC? Sustained higher and increasingly volatile gas prices, of course. Those familiar with the life-cycle economics of IGCC using either coal or petroleum coke know that gas-coal spreads of slightly less than $3.50 per MMBtu render IGCC economical relative to NGCC. At present, the spreads between gas and solid fuels are well beyond $3.50. If the all-in cost of IGCC remains below, say, $1,800 per kW, the above premise holds.

In order of importance, what are some of the other drivers? Generally, stricter environmental standards, and, more specifically, carbon capture and sequestration, favor IGCC over, say, super-critical pulverized coal. Also, IGCC is thermally more efficient than other coal plants and can operate on a much wider range of inferior solid fuels.

What will it take to drive IGCC forward? Absent third-party covenant financing or government tax subsidy, large investor-owned utilities (IOUs) will need to lead the field into IGCC, weathervaning the winds of environmental conscience. Of course, funding help from the DOE to get things moving is always a significant plus.

Project financing will not only require maintaining an operating reserve as a principal loan indenture, but lump-sum turnkey (LSTK) EPCC contracts will require risk mitigation measures that transfer construction/performance risk to EPC firms. LSTK contracts will include wraps on all major equipment, and performance guarantees and acceptance criteria will be subject to strict bank due-diligence requirements. LSTK contracts will spell out liquidated damages, and bonus/penalty clauses will reflect specific lender requirements.

What does this really mean? At the risk of being overly simply, advancing IGCC to the point at which the financial markets fully understand the construction and operating risks associated with the integrated technologies demands experience and deep pockets. Large IOUs must lead (seed) the way, enabling lenders and non-traditional investors to rationalize accepting some of the construction and operating risks. Well capitalized and experienced alliances/partnerships like GE/Bechtel must provide lenders with the comfort needed before they can rationalize shouldering a proportionate share of the construction risks.

All said, large-scale IGCC appears to be on the threshold of commercializing in a big way in North America; but, it’ll require a financial commitment and determination on the part of the more well-heeled, adventurous IOUs and the large EPC firms to make it happen.