The BP-TEPCO LNG Deal
Tokyo Electric Power Co's (TEPCO) recently announced sale and purchase agreement (SPA) with BP Singapore for 1.2 million tons per annum (mtpa) of lean LNG over 17 years is just the latest in a string of long-term deals that Asian LNG consumers have signed for supplies originating from the US Gulf Coast. The BP-TEPCO deal is technically a 'portfolio contract' that gives BP the flexibility to source the LNG from anywhere. But given BP's large purchase position in the Freeport project, the TEPCO deal's linkage to Henry Hub spot prices, and the specification of low heating value (lean) LNG, it is a safe bet that much of the supply will originate from the US Gulf Coast.
The Japan OTC Exchange's (JOE) new LNG contract was officially launched today. It is technically being described as a "non-deliverable forward contract," and is starting off as a non-cleared, cash-settled, bilateral contract, but JOE expects that CME will be providing clearing in the near future. The launch of this contract is a positive development for global LNG trading and risk management, and once CME clearing kicks in, we expect a wider and larger group of participants to make use of it. The full details of the contract are presented below:
A Win-Win Deal: Supply Diversification and Risk Management
Statoil's recently announced sale of approximately 0.4 million tons (6-7 cargos) per year for five years (2015-2019) to Lithuanian gas supplier LITGAS makes a whole lot of sense - to both sides. Statoil secures a foothold in the Baltics, an important and growing market that is logistically and strategically compatible with Statoil's asset portfolio. And LITGAS, for the first time, diversifies its gas supply away from Russia, which has historically provided 100% of its needs, increasing both its supply security and its leverage in price negotiations with Gazprom. This has reportedly already paid off, with LITGAS securing a significant discount in its most recent pipeline gas purchases.
Woodside Petroleum reported its financial results a few days ago, and it appears to have had quite a good first half of 2014. This was also an early chance to see the operating results of Woodside's new trading and shipping business, which it established last year to focus on opportunities in the spot and short-term markets.
Source: Woodside Energy Ltd.
After reading E&Y's report, "Analysis of the competitiveness of BC's proposed fiscal framework for LNG projects" a few months ago, we were hoping that more details from their study would be forthcoming, since the analysis raised more questions for us than it answered. But with no new information in the weeks since, we are still left without a clear understanding of the key assumptions underlying E&Y's results, which purport to show that BC's total government-take from its industry is comparable to or below the levels expected in Australia and 5 US States (Alaska, Georgia, Louisiana, Oregon and Texas). Specifically, there are at least 3 key questions that E&Y's report does not address, the answers to which might fundamentally alter the competitiveness of BC's tax regime compared to those of other exporters:
1990-2008: Location Arbitrage Constrains WTI-Brent Spread
There was a time when an oil trader could provide a simple yet satisfying explanation for the relationship between prices for the world’s two most actively traded crude oil contracts: WTI and Brent. WTI (West Texas Intermediate), settled in Cushing, Oklahoma, served as the grade of crude oil underlying the NYMEX’s (and later CME’s, after it acquired NYMEX) flagship oil futures contract. Brent (North Sea Brent), a blend of crudes sourced from several fields in the North Sea, and piped into the Sullom Voe Terminal in the Shetland Islands of Scotland, was the world’s other most watched and used benchmark for crude oil pricing.