Competition between proposed export plants in Australia, Canada and the US
While various supply locations for an LNG project appear similar on the surface, a comparison of the key features in the qualitative analysis below demonstrates that the proposed LNG export projects of British Columbia (B.C.), and in some ways Australia, do not compete directly with those in the US. The differences between supply locations show that they will attract and serve LNG buyers with differing needs in addition to diversification-of-supply-region. Thus, while B.C., Australia and US proposals are all ‘fit-for-purpose’, they fit different purposes.
Booking gas reserves is a priority for E&P companies as a financial metric of sustainability, however it is irrelevant for LNG buyers and midstream companies. TCM LNG plants do not directly monetise stranded gas reserves in the way that historically drove international oil companies (IOCs) to build LNG plants. In contrast, the proposed Australian and B.C. LNG plants are connected to dedicated gas fields to monetise stranded gas and may allow for gas reserves to be booked by E&P operators.
Access to E&P risk and reward can be achieved for LNG buyers investing in B.C. or Australia LNG export projects because they are directly connected to natural gas reserves. However, an LNG buyer taking equity in a US LNG export project is only investing in infrastructure and can avoid E&P risk through gas supply agreements in liquid gas markets.
Shipping distances to LNG buyers’ home delivery ports are equal from West Coast US and B.C. However, US Gulf Coast (USGC) LNG supply is almost double the distance from North Asian LNG markets compared to B.C. or US West Coast.
For several US projects, start-up is expected before 2020, while it appears more likely that the big B.C. projects will be commissioning after 2020.
The remote location of B.C. LNG projects will make labour shortages perhaps analogous to Fort McMurray and the experience of oil sands in Alberta as well as Australian LNG projects. The conditions in these two locations are manageable, but have negative impact on cost as well as schedule, and they require the unique capabilities and strengths of an IOC.
US LNG projects will be connected through relatively short and accessible terrain via umbilical gas pipelines, connected to established dry gas infrastructure of the US gas grid, which starkly contrasts the new 500-mile pipelines needed across the challenging Canadian Rocky Mountains.
Speculation abounds regarding the LNG export tax to be imposed by B.C. as a provincial tax. In contrast, it is beyond the jurisdiction of individual states in the US to impose an export tax on LNG.
Price risk diversification
For a traditional LNG buyer with a portfolio of supply indexed to JCC or other crude oil indices, price diversification and portfolio risk management benefits are achieved by re-aligning the supply portfolio to include LNG with the price indexed to a different underlying commodity price such as HH. An Asian LNG buyer with liquefaction tolling capacity begins to assume the characteristics of a US Local Gas Distribution Company (LDC) and can thus consider some of the gas supply strategies used by LDCs in the US. These include outsourcing gas supply to third party gas trading companies and using the Federal Energy Regulatory Commission (FERC) approved structure of an Asset Management Agreement (AMA) for operations, nominations, scheduling, balancing, etc. of pipeline transportation and storage capacity.
Managing gas supply risk for HH indexed LNG
LNG with gas supply price indexed to HH introduces new physical and financial risks for an LNG buyer as well as new tools to manage those risks. As summarised below, it is optional, though not imperative, for an LNG buyer under a TCM to secure multi-decade gas supply; just as LDCs based in the US generally buy gas on shorter term contracts than a traditional 20-year term of an LNG SPA. For example, many LDCs buy gas on 30-day or 3 - 6 month supply agreements that are renewed, restructured and re-priced regularly. Though LDCs are structurally always short of gas supply, they have found certainty in the liquid gas markets of North America to supply the gas they need without multi-year or multi-decade gas commodity obligations. However, these LDCs do make long-term, multi-year, transportation and storage capacity agreements that are in some ways structurally analogous to the long-term commitments made by LNG buyers for shipping.
LNG buyers will manage risks of LNG indexed to HH. Various strategies fit various LNG buyers. A few example concepts are listed below:
- Long-term gas supply agreements with E&P producers or third-party gas marketing and trading companies. Buying resource in the ground as gas reserves and taking on E&P risks (e.g. through joint ventures with E&P operators or E&P ownership).
- Entering into a structured AMA with an established gas marketing and trading company for multi-year gas pipeline operations and gas supply solutions (these might be a single bundled AMA for delivered gas or multiple contemporaneous separate agreements). Benefits of an AMA and gas supply agreement include accessing an established gas desk for nominations, scheduling, balancing, and risk management to eliminate the need to directly hire gas trading and pipeline operations staff. Also there would be a gas volume economy-of-scale by leveraging an existing gas desk that trades much larger gas volumes than just the TCM customer needs. Effectively the established gas desk would probably not need to hire any more people or add any new systems or equipment in order to buy and manage the additional gas supply volume for a TCM customer, which means there would be relatively small incremental costs for the AMA provider in buying the incremental gas. Finally, an established gas desk will already have NAESB gas trading agreements with dozens of E&P producers and other gas traders to facilitate flexibility in buying or selling incremental gas if and when needed.
- Buying long-term gas transportation capacity e.g. Mitsubishi with 20 years of 600 000 million Btu/d on Tennessee Gas Pipeline (TGP) for supply to Cameron LNG.
New challenges for LNG project finance in North America
When it comes to project finance solutions for LNG facilities in North America, the new challenges are much the same as the old ones; solid business fundamentals are key and many remain unchanged.
Perhaps the biggest change for project finance, and in fact a simplifying factor, is the absence of natural gas reserves certification for an LNG tolling agreement. A traditional LNG SPA required a dedicated gas field(s) with a reserves certificate from a reservoir engineering expert firm. However, this is not the case for US facilities connected to multiple interstate pipelines that are supplied by a multiplicity of gas basins, which are operated by a plethora of E&P operators. In many cases the project finance lender can look to existing pipeline grids and liquid gas trading hubs with multiple decades of history of existing gas buyers and sellers for assurance that gas reserves exist and will be developed and delivered in a predictable manner.
On the other hand, a unique new challenge for project finance lenders is bi-directional import-export LNG facilities and integrating smoothly the rights and obligations of existing LNG import customers with the rights and obligations of new LNG export customers. The commercial and financing success of Cameron LNG, Freeport LNG and Sabine Pass LNG demonstrates that these challenges have been resolved.
Written by Guy Dayvault. Adapted to house style by Ted Monroe
Read Part One of this article: Unique global market impacts of North American LNG supply: Part One.
Read Part Three of this article: Unique global market impacts of North American LNG supply: Part Three.
The full version of this article is available in the April issue of LNG Industry.
Read the article online at: https://www.lngindustry.com/special-reports/14042014/guy-dayvault_continues_his_discussion_of_north_american_commercial_impacts_on_global_lng_markets/