Month: April 2017

For example the choice for future new power generation investment (or LNG purchases in a country) will be made on the basis of long run marginal cost (LRMC) together with the requirements dictated by other government policy drivers, such as those for security of supply or to support decarbonization commitments. The LRMC considerations will include the full costs of both the generation capacity and the investments and operations associated with fuel supply, to the extent that these are not already committed to be paid under other arrangements.

For instance, LNG will be costed into SRMC considerations based on the landed cost of cargoes delivered to an FSRU facility, and any losses and variable fees charged for regasification and for the supply of the regasified gas through to the power plants in the existing gas pipelines. In this respect, it will ignore the already contracted annual lease costs of the FSRU as sunk cost as well as the land-side investment costs already made in the port to support the regas project as well as any long term committed capacity payment made for the use of the pipeline needed.

In contrast, for long term continued purchase of LNG beyond the contractual years of the initial FSRU, a decision to renew the lease on an FSRU beyond the option date for termination or the leasing of another FSRU facility, must take into account the subsequent use of LNG and the need to bear the full costs associated with the lease extension or new lease when compared with the use of other fuels, including other potential gas supplies. Reality also kicks in once a contract is signed as there is the need to stick to the ToP terms.

 

Marginal Cost can mean a number of things but I would take this to mean the cost you incur to produce the next or incremental MMbtu of gas. So essentially the running costs, not the capex. In other words, having made the investment, you may be prepared to keep a field in production even though it is only covering its day to day costs because the capex is a sunk cost and most producers will disregard that sunk cost when looking at forward decisions. The fact that some producers are prepared to sell at a HH price below estimated marginal cost just demonstrates that different producers have different views on their costs and different views on where HH prices are going.

Marginal cost usually refers to incremental production, and should mean which expenditure has been spent in 2013 to create additional production capacity. Exploration/appraisal costs could also be included, but not sure. It mainly make sense to determine the economic value of additional wells in developed fields with limited or no other capex. It should be computed as EA costs + drilling capex + other capex + opex divided by incremental reserves.

Short run Marginal Cost is the more appropriate comparison when deciding whether or not to produce an extra unit of production; or shut down production altogether.

Full cycle normally means everything involved in bringing a field into production i.e. from buying the licence, exploration, capex for production facilities and then the costs of day to day production plus finally the costs of abandonment. It’s the figure you look at relative to the price of gas in the market before you make the decision to invest. Taxes: it all depends on the producer’s tax position. He may have no tax liability e.g. losses he can offset. So this is down to the individual case. Normally in full cycle you would include taxes to give you a fully costed post-tax assessment.

Long Run Marginal Cost as the basis for comparison as this includes all full cycle costs and is the right comparison with the price in a GSPA that will run for 20 years plus.