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.
According to Reuters, Chevron has been "struggling to lock-in 20-year sales contracts for its Gorgon liquefied natural gas (LNG) export plant in Australia." In spite of its targeted commercial operation date of mid-2015, only 65% of capacity has been contracted. We wanted to share a few of our reactions to this.
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.
A robust suite of LNG forward curves is a key prerequisite for the proper valuation and risk measurement of LNG portfolios. Tamir Druz of Capra Energy and Carlos Blanco of Black Swan Risk Advisors provide an overview of effective methods for constructing long-term LNG forward price curves, along with in-depth guidance and illustrative results for a proxy-based approach.
The University of Calgary's recent report, Risky Business: The Issue of Timing, Entry and Performance in the Asia-Pacific LNG Market, warns that an uncoordinated fiscal and regulatory policy for Canadian LNG exports risks derailing project development in British Columbia, and that the B.C. LNG tax is, in essence, a revenue grab that may make these projects non-viable. While the report is very comprehensive and well-researched, and does raise some legitimate points and risks, the report's conclusions are premised on some fundamental assumptions that should be questioned:
Capra Energy is proud to have assisted the State of Israel in the design of its transfer pricing policies for LNG exports. The Ministry of Finance has publicly released the report, “Comparative International Review and Recommendations for Israel's Natural Gas Transfer Pricing Policy,” which is available here: Ministry of Finance website.
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.
In the March 2014 issue of Commodities Now, Dr. Carlos Blanco of NQuantX, our alliance partner, and Tamir Druz of Capra Energy discuss the mechanics for pricing and hedging long-term LNG and natural gas transactions that are indexed to crude oil or petroleum product prices. Using a sample contract, they present the step-by-step process for determining contract pricing and executing financial hedges for the underlying exposures (fuel oil, gasoil and foreign exchange risk).
Click here to read Hedging, Risk Management and Valuation of Long-Term Oil-Indexed Supply Contracts in the latest issue of Commodities Now.