Peak Oil? Suncor, Cenovus Energy, Penn West, CNRL & Alberta: Conventional Output Higher

        With the exception of a brief period in the late 1990's when oil prices were too low as to encourage oil sands growth, oil production in Alberta has been in a long term upward trend.

Over the last decade output of crude and synthetic crude has risen sharply, however conventional sources like light & medium oil have not and that has given some credibility to the peak oil theory. Recent data coming out of Alberta shows a surprising reversal to this trend: Production light and medium oil will reach 500,000 bpd in 2014. In 2011 alone, medium/light oil output increased by 70,000 bpd which represents the largest year on year gain in over a decade; that trend is expected to continue into the near future. Keep in mind that the trend is still very new, between 2002 and 2010 output from conventional sources declined by 33%, 50% since 1995. The last time conventional oil was produced at a rate higher than it currently is, was back in 2006. Remember though that future supply depends a lot more on heavier crude than conventional (the oil sands are on track to account for 88% of Alberta's oil production by 2017 up from 64% in 2007).

Alberta disadvantages:
--> More than half of oil exports go to refineries in an area known as PADD II in the US Midwest. Because of a glut of supply, Canadian oil is more heavily discounted there than it is in PADD III which is Texas (why getting the Keystone pipeline approved is so important).

--> Western Canadian Select (WCS) oil trades $33 below West Texas Intermediate (WTI).
--> Export market not diversified : 99% of Canadian oil goes to only one market, the United States.

Alberta advantages:
--> Among lowest royalties in the world, something that makes it easier to attract foreign investment.
--> Canada is home to 90% of the world's oil reserves outside opec.
--> Calgary is home to more than 2,000 petroleum companies. TSX Venture Exchange makes attracting investment easier to do for statups.

At Canadian Natural Resources Limited Canada's leading producer, drills for conventional are are yielding better results; conventional oil production will grow by 17% in 2012 even though the number of wells drilled will be reduced by 62 (956/2000 wells vs 1018/2004 in 2011).

The company's reserves of light and medium oil in Alberta came in at 150 on Dec 31, 2010 up 6.4% from a year before. That compares to a -4.9% in the North Sea (to 252M bbls) and -11.8% offshore West Africa (to 120M bbls). Furthermore, in November 2011 company president Steve Laut credited much of the 24% 2012 increase in crude oil output to "Canadian light oil & NGL's growth". Growth in North American light oil will be +17% in 2012 due to the implementation of a new Enhanced Oil Recovery (EOR) program. The overall growth in BOE will also be spurred by expansion of the company gas facility in NE British Columbia but still Alberta will remain the most important source.
As oil sands production grows, companies such as Canadian Natural Resources are improvising in order to reduce their reliance on water from the Athabasca river, so that they continue to remain below the usage limit set by the province (was 360 million m3 a couple years ago, only about 1% of water from the river is used by the province and oil and gas operations); CNRL now separates water from solids more effectively by injecting carbon dioxide captured from its hydrogen plant into tailings lakes reducing the need for additional water. The Athabasca River is fed by a glacier 1,200 km away. 90% of conventional oil reserves are controlled by state owned oil companies.

Cenovus Energy                 (more indepth coverage by me can be found at Cenovus Energy production reserves)  
On February 15, 2012 Cenovus released data for the 2011 fiscal year and the results are very impressive!  Even though the stock was down little more than 1% on the day of the news TD Newcrest upgraded CVE from hold to buy.
Net asset value per share is $37 up 32% from 2010 year-end ($28).
Net Income $1.95/share (+37%) even though operating earnings were +55% to $1.64/share.  The company profited $1.478b on the year ($1.081m in 2010, $680m in 2009, $2.487b in 2008).

-> Total proved reserves up 17% to 1.9455 billion barrels of oil equivalent.  What's most notable there is the amount of bitumen reserves.  On December 31, 2010 bitumen reserves were 1.154B boe.  Today they are 1.455B boe an increase of 26%.  Contingent resources increased 34% to 8.2B boe.  Reserves of light and medium oil (& ngl's) +3.6% to 115M boe but natural gas -13% to 200M boe (which is inline with company plans to focus capital away from gas to bitumen, long-term production target is 400 MMcf/d, 575-600 for 2012). 2P proved + probable reserves +10.7% to 2,660.7M boe.
-> Production:  Total Oil/Bitumen/NGL's 134,000 bpd which is up 3.88% vs 2010 (129,000 bpd), up 12.61% vs 2009 (119,000 bpd).
Oil sands +13.56% or 8 bpd to 67,000 bpd, +52.27% vs 2009.  Christina Lake 12,000 bpd +50% vs 2010 (4Q2011 150% higher than 4Q2010 20,000 bpd).  Quarterly high was 4Q2011 at 75,000 bpd (13.6% higher than 3Q2011 which is the largest quarter to quarter increase in a while).
Conventional oil down 2,000 bpd to 68,000 bpd (Pelican Lake, Weyburn -10% to 36,000 bpd).
Natural gas output took a 737 nosedive (no pun intended :) from 737 MMcf/d (122.8 boe/d) to 656 MMcf/d (~110,000 boe/d).  Gas production averaged 837 MMcf/d in 2009 (140 boe/d).

 -> CAPEX: $3.1-$3.4B planned for 2012 which is more than the $2.7B spent in 2011 ($900M at Foster Creek + Christina Lake, $400M at the Wood River Refinery in Roxana, Illinois).
-> Cash flow +33% to $3.3.  Operating Cost at CL +23% to $20.2/bbl (+28% not excl fuel).  Weyburn's operating costs were also up but they are still roughly half of CL.

Christina Lake consists of seven phases of development.  The last phase G won't be completed until the start of 2019.  Phase E is 30% complete, phase D is 70% complete.  When project is complete Christina Lake will production at a rate of 278,000 bpd (in the last quarter production was only 20,000 bpd).


Suncor
Last year Suncor's total production was hit hard by the situtation in Libya however there is optimism surrounding the company right now; 3 of its 5 fields there have already resumed operations (Jan 2012).
Also up at Suncor, oil sands output ! In December of 2011 Suncor's oil sands output averaged a monthly record high of 345,000 bpd, that record was broken the next month in January 2012 when 355,000 bpd production was reached.
Remember too, that oil sands output was only 162,000 bpd as recently as May 2011. Suncor finished 2011 averaging just over 10,000 bpd in Libya up from nothing; 2Q of last year it took on a $514 million writedown in the value of its Libyan assets.

Suncor is Canada's largest oil company by market capitalization (though second to Canadian Natural Resources in terms of production) and is the largest producer of oil sands oil through a 12% interest in the Syncrude Canada Ltd. mine, a 41% stake in the Fort Hills mine and operations at Firebag & Mackay river.

Penn West Exploration        Penn West 3Q 2011 Report    Penn West 4Q 2011 Report

4Q: For the 2011 year 18.0% of total oil and gas sales went to royalty payments ($661m/$3667m) down from 17.8% in 2010.  Expenses were 69.0% higher ($1503m --> $2540m) mostly due to the company's gain on dispositions being $910m lower than in 2010.
Prices In the 4Q, light oil and liquids was sold at an average price of $88.76/boe (up 25%), heavy oil $76.88/boe (up 24%), natural gas $3.47/mcf (down 8%).  For the year oil and liquids were priced at $86.19 (up 24%), heavy oil $69.07 (up 14%), natural gas $3.78/mmcf (down 10%).  HOWEVER because of the company's constantly changing hedging strategy, oil prices realized varied even more;  light oil realized in 2011 was $87.18 (up 30% from 2010), heavy oil $76.88 (up 24%), natural gas hedging included, $3.47 (down 15% because in 2010 hedging caused it to gain an additional $0.31/mcf).
In 2011, light oil and ngl's represent 52.31% of total output (85,316/163,094 bpd) up from 49.02% in 2010 (80,706/164,633 bpd) heavy oil 17,892 bpd or 10.97% of production (down from 11.09% 18,260 bpd), natural gas 59,886 boe/d or 36.72% of production (down from 39.9% 65,667 bpd).
Overall, operating netback declined the most for natural gas, -53% to $0.99/mcf.  The reserve replacement ratio was 234% up from 122% in 2010, 73% of which was liquids (65% liquids in 2010).  Although gross revenue (+19% to $3.604B) and funds flow (+30% to $1.537B) were up, net income was -43% to $638M making earnings per share $1.37 basic (-45%), $1.36 diluted (-45%).

For 2012 the company has hedged 60,000 bpd of liquids at between US$85.53 and US$101.16.

In 2011, light oil and ngl's production was up 6.20% to 85,316 bpd (+2% to 90,185 in the 4Q), conventional heavy oil down 2.0% to 17,892 bpd (but +6.15% to 17,886 bpd in the 4Q), natural gas down 9% to 359 mcf/d (but steady in the last quarter at 364 mcf/d).
Royalties for the 2011 fiscal year: +23% to $16.83/boe for light oil, +15% to $10.01/boe for heavy oil, $0.54/mcf for natural gas (down 7%).  Overall risk management loss per boe was $1.06/boe (+212%) but overall netback (profit) per boe was still up 23% due to prices being 20% higher overall.

Risk management losses (hedging prices) were less negative than they were in 2010.  $2.03/bbl for light oil (down 25% vs 2010), and $0 for natural gas (compared to a gain of $0.42/mcf in 2010).

3Q: During the first nine months of 2011 revenue from light oil and ngl's went up 36% ($1417 --> C$1921m) compared to only 5% for heavy oil. Peak oil doesn't seem to be a reality for Penn West either: For the first three quarters of 2011 light oil production was up by 7.14% or 5,578 bpd even though total oil production by Penn West declined 1.80% or 2,952 bpd to 161,171 bdp.
9M2011 light oil & ngl's output: 83,675 bbls/d (3Q: 83,287 b/d) total production: 161,171 bbls/d (3Q: 161,323 b/d)
9M2010 light oil & ngl's output: 78,087 bbls/d (3Q: 80,614 b/d) total production: 164,123 bbls/d (3Q: 164,087 b/d)

2012 forecast: total production up to 174-178,000 bpd up from 162-164,000 bpd in 2011. capex spending in 2012 estimated to be $1.6B.         Like North American Interests on Facebook

Oil Sands Reserve Estimate Has The Potential To Increase But Future Developments Could Face Obstacles Due To Environmental Concerns

Alberta Energy Board's reserve estimate for the oil sands assumes a 20% recovery rate but companies using Steam Assisted Gravity Drainage to recover in-situ crude have a recovery rate in excess of 60% (Infomine: Oil Sands Mining In Canada Industry Review) meaning that reserves located within the oil sands district could climb much higher in the near future (total resource is around 1.6 trillion barrels or 18% of the world's total, energy board reserve estimate is 173 billion barrels). Since the estimate was made, other technologies like Petrobank's Toe To Heel Air Injection method have been introduced, raising production efficiencies even further (THAI is 17% more effective than SAGD, Petrobank is so confident in its technology that it has invested heavily in regions with great quantities of resource but little reserves (Kerrobert, Dawson) (McDaniel and Associates Consultants Ltd.)

When production was 726,000 bpd in 2007 (60% as much as it was in 2008, 22% as much as it is expected to be by 2020) the oil sands released 1 billion ft3 daily of carbon through the burning of natural gas used in various stages of production and upgrading. That accounted for about 40% of Alberta's and 5-8% of Canada's greenhouse emissions. If production triples in the next decade those emissions consequently will be higher and given Canada's commitment to the Kyoto Protocol, future oil sands projects could be at risk if a less tolerant government is elected (Canada's current opposition party (2011, NDP) was led by someone who opposed the oil sands on environmental grounds). (cbc.ca: Layton would slash oilsands subsidies (March 31, 2011) Canada ranked 7th in emissions in 2008 up from 8th for most of the previous decade but it only ranks 15th in per capita emissions (2008). By 2045 oil sands will produce close to 11M bbls/d and that will continue for a century. Between 2012 and 2020 oil output from the tar sands will double (1.7 mbpd --> 3.4 mbpd) and triple in the next 25 years to 5.1 million barrels per day. Tar sands crude is over five times more expensive to extract than middle east oil however with oil prices up more than 400% since 2001 and Alberta continuing to charge one of the lowest royalty rates in the world (fell from $3 to $2/bbl between 2001 and 2009) there is much profit to be made.

According to Alberta's 2012 budgetary report, total oil production will reach 3M bpd by 2014, 2.4M of that is from non-conventional sources like bitumen (bitumen royalties totalled $5.7B in 2011 will be $9.9B in 2014).  2011-2012: non-conventional oil production was at 1.78 million barrels per day.  Conventional oil production will be 500,000 bpd in 2013.  Provincial royalty revenue:  Bitumen contributed $5.7B of the $6.5B total which includes conventinal, in 2012, 30% higher than the $4.4B earned the year before.  Total will be around $12.2B in 2014.

Furthermore, energy consumption experienced the biggest yearly increase since 1973 in 2010, in 2010 it was up 5.6% largely due to China (up 11.2% surpassing the USA) and non-OECD nations (63% higher than 2000 levels). (World energy consumption up 5.6% in 2010, biggest rise since 1973: BP) Oil accounts for about a third of the world's energy needs (about 140 out of 420 million BTU's (2011 pace as of August).

52% of all economically viable oil available to private investors resides in Alberta, Canada

Alberta is home to nearly 170 billion barrels of proven and probable oil reserves (much of it amongst easily processed oil sand) exceeded only by Saudi Arabia and Venezuela (AP:China eyes Canada oil, US's energy nest egg) In Alberta alone, more than 1.6 trillion barrels of oil in inferred resource isn't even included because extraction methods SAGD and THAI/CAPRI aren't able to bring it to the surface by economically viable means. However, considering conventional sources only, Canada has major sources outside Alberta (Saskatchewan and Newfoundland combined have about 1.4 times as much oil reserves as Alberta). (NEB - Energy Reports Canadian Energy Ovewview) 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; the government of Alberta requires that oil companies bring the land back to 'equivalent land capability' that is, restore it to a level that makes it useful to the community either as boreal forest (which was initially destroyed) or pasture for bison (though many companies have only restored a fraction of that, for example Syncrude Oil restored 22%). Oil sands operations have been approved to use about 360 million m3 of water from the Athabasca River (runs through the mining district, water source is a glacier over 1,200 km away), that's twice as much water used by the entire city of Calgary though less than 1% of the water from the river is used by the province and oil operations; 24 m3 of water is used to produce 1 m3 of synthetic oil.
By 2045 oil sands will produce close to 11M bbls/d and that will continue for a century. Between 2012 and 2020 oil output from the tar sands will double (1.7 mbpd --> 3.4 mbpd) and triple in the next 25 years to 5.1 million barrels per day.

With crude oil fetching higher prices in Asia, Canadian producers are looking to expand into new markets (nearly all Canadian oil (2M bbls/d) currently heads south, 2010). (Reuters:Foes fight Canada pipeline to rich Asia market) The supply chain has, more recently been overwhelmed in the United States due to the release of 30M barrels of reserve oil onto the market Parkersburg News and already filled up pipelines and storage tanks. With China's interest in Canada growing, the 728 mile Northern Gateway pipeline from Edmonton to Kitimat, BC is gaining the attention of politicians and oil companies eager to broaden their customer base.

Ironically, environmentalists are both helping and hampering efforts to provide access for Asia; The oil pipelines face fierce opposition from environmentalists and Native Indian groups concerned over wildlife and possible oil spills (like what happened with Enbridge in Michigan in 2010); at the same time American environmental groups have opposed the oil sands on the grounds that it makes excessive use of water and increases greenhouse gas emissions.

Keystone XL, another oil pipeline struggling through the approval phase, aims to bring more of Canada's oil to the United States in an effort to reduce their dependency on Middle East oil 'potentially to nil'. Among other top sources, Mexico is an unsustainable source due to dwindling reserves there and Saudi Arabia (number 2) is viewed as unstable due to its situation within the Middle East. TransCanada's $7 billion pipeline project would double Alberta's oil exports to the United States. Though Obama rejected the permit in January 2012 he didn't completely shut the door on the project, saying that the company is free to re-apply. Whether or not the project goes ahead one thing is for sure, Alberta will continue to produce oil. As of last summer there were 22 active exploration projects in Athabasca alone.

The reason that it's 52% even though all of Canada doesn't have half of the world's oil is that, much of the new oil being discovered/produced is heavy-extra heavy oil and a lot of it is in countries like Venezuela which don't allow foreign investment/ownership of their state run oil companies. Even in Colombia where capitalism is as popular as it has ever been, big oil companies like Ecopetrol remain off limits to foreign investors (in August Ecopetrol (majority state owned) will have its biggest share sale since 2007 in which it will make available between 3 and 5% of Ecopetrol shares but only Colombian citizens are allowed to participate).