By now it's well clear to members of the natural gas industry that liquefied natural gas (LNG) is writing the next chapter in the industry's evolution. The gas business has come a long way from the days of pipeline take-or-pay contracts and the moratorium on gas-fired power generation. It remains to be seen, though, how far "back to the future" LNG might take the industry.
For instance, long-term contracts are back in vogue, at least in some quarters. Developers of LNG regasification facilities need them in order to lock up financing for their mega projects. Building an LNG supply chain is an expensive proposition, and one piece won't work without the others. Many believe it's only the province of major producers and national oil companies with their global upstream presence and giant balance sheets.
Large industrial consumers and local distribution companies -- who previously relied on a robust marketing and trading services sector for supply and risk management -- are now being called upon step up to long-term contracts to support LNG as well as pipeline and storage infrastructure development. At least some state regulators have come around to encouraging longer term supply contracts. The National Association of Regulatory Utility Commissioners (NARUC) in November adopted a resolution to "...encourage gas utilities to develop long-term strategies for capacity and supply contracts to access new and expanded natural gas and LNG supply sources... and consider pre-approval of long-term contracts."
That's obviously a step toward more long-term contracts, but it's not a leap. It still is up to individual state regulatory bodies to decide how much contracting freedom LDCs should have on the front-end and how much scrutiny they should be subject to after the fact. National oil companies historically have sold supply to governments or government-backed monopoly utilities under long-term (20-year) contracts at an index price. The U.S. gas market is more robust, and LDCs don't buy gas that way.
"The international sellers of LNG don't understand the U.S. regulatory structure, and they don't understand why an LDC isn't excited about buying a 20-year contract at index," says Larry Bickle, a managing director at Haddington Ventures, a financial backer of gas storage and LNG regasification, among other projects (see related story). "They don't understand that all they have is downside risk in that."
How this evolves remains to be seen. Whether and what intermediaries -- the majors, the banks, a new breed of marketer -- make a business of interfacing demand and supply also is evolving. It's turning out that LNG might not be the panacea for North American gas supply woes that many thought it would become.
Right now there is predicted to be a shortage of upstream liquefaction capacity (see related story). Without ample liquefaction, building regasification is like laying pipe to a dry hole. Even with substantial development, LNG will account for a relatively small portion of U.S. supply. But it's supply that's procured in a world market where the UK, continental Europe and Asia (Japan now, China soon) all are vying for cargoes.
LNG purchase-sale agreements already contain cargo destination flexibility. That is to say LNG on the water increasingly follows the best price. Sometimes that's in the States, other times not.
Kathleen Eisbrenner, president of Excelerate Energy LLC, says she has done several deals that prove the emerging global dynamics of the LNG marketplace. "We'll end the year having lifted seven cargoes from four different countries representing the Pacific, the Mediterranean and the Caribbean basins. We will have delivered to at least four different terminals."
Eisbrenner recounts how Excelerate bid on and lost a Nigerian LNG cargo but contracted one of its tankers to winning bidder Total to deliver the cargo to the Asian market. That didn't happen because the Asian order was backfilled by an Omani cargo, and Excelerate's tanker was redirected to Iberia. But the Iberian order was backfilled by a cargo from Algeria. "Henry Hub prices raced up, and they [Total] exercised their option to sell to [Excelerate] at Gulf Gateway [deepwater port off the Louisiana coast]. We came to Gulf Gateway and discharged during Hurricane Katrina. And to me that's a great example of the globally volatile markets at work. There is definitely flexibility and fungibility in the system as evidenced by that."
Destination flexibility in LNG contracting is now routine, Eisbrenner says. "Only the first [LNG contract] that I entered into back in 1999-2000 did not include destination flexibility. I think it's recognized industry practice at this point."
And work is just getting under way to streamline the practice. The Association of International Petroleum Negotiators (AIPN) has formed a committee to look at developing a master sales agreement for spot sales, which would include provisions for destination flexibility. To date, two preliminary meetings have been held, says Pat Allison, a partner with Houston law firm Allison & Shoemaker and vice-president of education for AIPN.
"The trend is dramatically toward more flexibility, not less, and the key question is who gets to use the flexibility and at what price," says Steven Miles, a partner with law firm Baker & Botts and co-chair of the AIPN LNG master sales agreement committee. "Buyers and sellers are increasingly sophisticated and recognize that there is significant profitability in the ability to arbitrage cargoes. The debate today in sales and purchase agreements isn't over whether there should be destination flexibility. The debate is over who gets to control it and therefore realize the value of that flexibility and at what price does control and flexibility come."
Looking at historical data, Europe and the UK are generally more attractive markets for LNG during the winter months, while in the summer the U.S. offers more appealing prices, Miles says. "The U.S. gas price is cyclical seasonally, but not as cyclical seasonally as the UK... that's historical data."And back in the United States, unconventional gas resources -- coalbed methane, shales and tight sands -- are having a renaissance and are now drawing the attention of some major producers. Catherine Elder, senior director and head of the fuels practice at RW Beck, maintains that LNG comes to the U.S. not because the country "needs" it but because gas production economics are more favorable elsewhere in the world (see NGI, Dec. 5).
If/when domestic production from unconventional sources ramps up in a few years, could it make LNG less economic? Perhaps. John M. Hopper, president of Falcon Gas Storage in Houston, remembers a recent press report that said domestic producers would have difficulty competing with LNG once importation ramps up because the marginal cost of LNG is lower than the marginal cost of domestic supply. "I'm thinking, now wait a minute. If I go out and drill a thousand Barnett Shale wells in a $10-to-$15 price environment and get payback in a year, so what if the price a year later goes to five bucks, I'm just clipping coupons. And the marginal cost of operating those wells is not very high. So I don't know if I buy that or not.
"Growing capex on domestic E&P now may attenuate LNG demand in a few years. But then again, if LNG doesn't get to the States as fast as some are counting on, demand destruction on the power side could take some of the bloom off the U.S. gas market rose. "I'm a little concerned that we may be over-hyping LNG. At the same time, we clearly are going to have to import significant amounts of LNG," says Bickle. "I think there will be six to eight LNG terminals on the Gulf Coast under construction between now and 2010. I think they'll be a year or two later than most people are thinking. One of my concerns is that the timing on LNG is such that we may get a lot of demand destruction, particularly in the electricity sector." He speculates that significant gas demand destruction could come from combined-cycle gas generators switching to integrated coal gasification. "Once they do that, they're not going to go back to gas."
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