Wednesday, December 7, 2011

Meg Energy Oil Exploration Update (double production to 65,000 by 2013, 260,000 b/d in 2020, Surmont 2018, phase 3)

    Meg Energy is one of Canada's largest oil exploration companies that owns 100% of a 3.7 billion barrel, 80 block section of Christina Lake, one of Canada's largest oil megaprojects (development began in 2008). In the first nine months of 2011 the company produced 25,450 bbls/d up 33.4% from 19,071 b/d in the corresponding period of 2010, but only 20,945 in 3q11 due to maintenance activity (versus 19,339 b/d in 3q10, all production comes from Christina Lake). Production and revenue recorded record highs in the second quarter of 2011, at 27,826 b/d and $279m respectively. Production is forecast to reach 29-31,000 b/d by the end of 2011 attributable to new equipment being installed at Christina Lakes' second phase expansion (when construction work there is completed in 2013 (operating at 100% compared to less than 30% currently) operations there will bring in an additional 35,000 b/d, more than doubling current production possibly to as high as 65,000 b/d). C$500 million of the C$1.4 billion in total project costs needed by phase 2B has already been spent with the balance coming in 2012. The company has only been producing since the last quarter of 2009 when output was 2,427 b/d.

MEG Energy has $937 million to spend next year on growth projects (which represents 70% of its $1.37B 2012 capex) the majority of which has already been allocated to phase 2B with the rest ($1-200m) going to the 3rd phase (initial construction), the exact amount to be determined pending a key regulatory decision in 1H2012 (3rd phase is key since it will add 150,000 b/d). There's also Surmont that should be coming online close to 2018 (Surmont has vast resources of heavy oil but very little of it represents upgraded reserves). MEG capital expenditure was $243.218 million in the July-September period (2011) compared to only $96.561m in 3q 2010. Maintenance costs and more money going to growth projects increased long term debt which is now at $1.792b up from 1.005b in 3q10. The last phase isn't expected to be completed until 2015-2020 and so the maximum 260,000 b/d estimate probably won't be reached until the latter part of that period.

The steam required to melt bitumen so that it can be brought to the surface by the process known as steam assisted gravity drainage, is produced at a power plant that doubles as a cogeneration plant which allows the company to turn excess steam into power able to be sold to the Alberta Power Grid (the extra money helps reduce operating costs ----> which increases operating netback). Western Canadian Select price is lower than WTI because it is a mixture of heavier oils/bitumen and synthetic oil and thus produces fewer barrels of oil per metric ton (prior to processing). Production costs per barrel were down significantly in the nine month period to $16.38 from $22.81 due to higher production volumes and Christina Lake producing at a normal phase (not ramp up phase as in 2010). Revenue from extra power sold to Alberta power grid (cogeneration plants) reduced net operating costs down to $11.95 from $18.63/bbl. In the 3rd quarter Meg received enough compensation from sold power to pay down per barrel operating costs by $5.13 ($4.43/b in the nine month period), that's up significantly from $2.13/bbl in the 3q10 ($4.18 in 9m10).

According to the company, its 1.9 billion barrels of 2P reserves are worth $12.1B, there's also another 1.8 billion barrels of inferred resource worth $7.0b (the company's market cap is under $9B). Christina Lake covers a large area, Cenovus Energy and ConocoPhillips already operate a large scale, synthetic oil project there that produces under 30,000 b/d that's also undergoing expansion (they tap into the McMurray Formation). The project is within the well known Athabasca Oil Sands of central-east Alberta.

Approximately 20% of Alberta's oil sands are close enough to the surface to be recovered by open pit mining, the rest requires vairous in-situ technologies. Alberta's royalty rates on oil production have fallen from an avg of $3/bbl to $2/bbl over the last decade and that has made it an even more attractive place to produce. Oil sands can be over five times more expensive to produce than conventional however with oil prices up more than 400% since 2001 that barrier to investment is becoming less of an issue (if the price of oil remains at or over $60/bbl which makes oil sands production economically viable, Alberta's oil production could reach as high as 11M bbls/d by 2045). Reason that heavy oil commands a lower price on the open market than WTI? You need 1.7 barrels per metric ton more of the <10 degree API heavy oil versus lighter oil because its high specific gravity (density as compared to a reference) makes its API gravity lower leading to fewer barrels produced according to this calculation. In the first nine months of 2011 the price of WTI oil was up 23.0% to $95.48/bbl from $77.65/bbl ($89.76 in the 3q11).


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