Refining Community Logo

Alberta's Royalty Reststructuring

Home Forums Coking News: DCU, Upgrader 1.Coker (registered users only) Alberta's Royalty Reststructuring

This topic contains 1 reply, has 2 voices, and was last updated by  Charles Randall 15 years, 4 months ago.

  • Author
  • #3938


    Just wondering if anyone has an opinion on the Alberta governments plans to increase conventional oil and gas, as well as oil sands royalties. Are refiners considering the fact that some oil sands projects may not move forward when considering upgrading to accept Canadian crude?

  • #7258

    Charles Randall

    RE: Royalty on Conventional Oil & Gas
    The declining rate of Conventional crude in Canada was part of the reason for the fast forward in Oil Sands development. Since continued Conventional crude production will require higher technology recovery process and some leading edge Enhanced Oil Recovery application (EOR) – the additional cost would probably require additional tax &/or royalty support since crude prices are already at top side of market. But since most declining Conventional Oil going forward (2007+) will stay at home in Canadian Refineries – this will become more of a closed CA loop.
    RE: US Refiners Upgrading for Hyv Canadian – considering some CA Oil Sands projects not going forward?
    First – all refineries that want to survive are moving up in complexity = more capability for heavy/cheaper crude supply = Need run LP models on margins for several optional crude supplies.  Most refineries charge a mix of crude’s & only when the crude is the cheapest, has highest margins &/or supplier contribution on plant conversion capital cost, do they lock in for a single source. CA Oil Sands hvy. crude blends delivered by new/reversed/existing Pipelines into Midwest refineries (and other regions as well) will be lot cheaper than imports from ships into US coastal regions for consuming Midwest refineries.
    Second – The cost of producing CA Oil Sands crude blends is moving substantialy lower than finding & producing Conventional crude – mostly as result of the Canada shift technology from Mining into SAGD process for current round of projects. Therefore it is HIGHLY unlikely any future production is going to disappear, BUT which company does the project and when it comes online DOES change – just as all oil industry projects across the world have done. There are always hurrdles for Oil projects around construction cost, financial funding, and permits among others. So it becomes a matter of WHEN not IF the new CA production will be there for refineries & coker expansions which themselves often take a minimum of 2-3 years to complete.
    As long as the crude price and product prices move up in locked step – there is always an option to pay the higher price for lighter crudes when Summer Gasoline or Winter Diesel markets peak out because of the higher product yields during time peak prices. But most time complex refineries always have higher margin on the heavy crude to at least cover the additional coker op cost, if not some addtional coker margins. This is also an advantage of the CA oil sands project which can make a WTI look alike sweet crude = a synthetic crude; a light to medium heavy crude = a synthetic-bitumen blend or dilute-synthetic-bitumen blend; or the heavy crude = a dilute bitumen blend crude. Few people realize almost all Global marker crudes like WTI, Brent, Dubai, Kuwati &  Arab Medium are blends of crudes also.
    I believe that the negative approach Venezuela has taken to the US market along the lines of higher tarrifs, taxes and sizing assets will provide a good lesson in this area. It is likely Venezuela could end up causing a Non-Conventional heavy crude glut inside a Conventional crude shortage market as it fights for continued US market share (with its own decreasing US refining assets) during time when additional new Canadian NonConventional crude has new pipeline access to not only the Midwest refineries but Gulf & other regions via Cushing crude distribution linkage.  The combination of shifting supply preference from complex US Refineries – most JV partners, and into regions where some Latin American countries have history of financial instability, or regions like Asia/China that are severly limited on refining complexity (and the few new worldscale refineries that are not are linked to cheaper/closer MidEast JV partners) set the stage for demand backlash. It is believed Chavez needs break-even value of $52/BBL to support his government & investment programs – the cost for these programs also means that he is not sufficiently re-investing in existing wells for Upgrader production.
    These arent counting potential demand impacts from Ethanol blending programs going to 25%, advances in alternate vehicles becoming 10% US vehicle fleet and possiblity of US gasoline imports dropping from 12% down to just an exchange with its North American / NAFTA suppliers. It does assume Venezuela is totally screwed on any future crude supplies into US Midwest Coking Refineries vs a CA pipeline source.  As comparison regionally on Refining Complexity : US averages a 11 (coking refineries doing hvy crude average 15-18), Western Europe & Australia average about 7, South America & Asia/China average a 4-7 complexity (Brazil & Mexico average 7).

You must be logged in to reply to this topic.

Refining Community