The Oil Price: Noone Really Knows What's Going On; Russia economic growth usa oil oversupply opec report

Just two months ago, the World Bank estimated in its commodity forecast report that the price of crude oil will average $51.4 per barrel in 2016, virtually unchanged from the average price last year ($52.5), but since then oil has fallen all the way down to $30 with no bottom in sight.

Just this month the price reached an 11 year low for the third session in a row ($36), despite positive news regarding US supply (stockpile down -5.8m barrels vs +1.1m estimate). The price was as high as $110 as recently as 2014 but $30 oil was not uncommon in the 1990's and early 2000's.

Now Opec which represents a third of the world's oil output, is coming out and saying that improved overall demand will lead to a recovery in the price ($70 by 2020).

And Russia - the world's second largest producer - is saying it doesn't expect oil prices to recover beyond $30 in 2016 which says a lot coming from a nation that loses $2 billion in revenues for every dollar decline.

My opinion - Oil prices will swing wildly in both directions in the upcoming years so prepare accordingly.  However peak oil is not the issue.

this opinion is based on

• The USA oil oversupply cannot continue especially at current prices - most oil production increases in the US are attributable to North Dakota shale exploration the pace of which cannot continue at current prices.
• New Canadian pipelines (Energy East Pipeline will allow Canada to fully utilize refinery capacity in New Brunswick / Northern Gateway Pipeline / others) will permanently lower glut of supply in US North Western PADD regions).
• Higher oil exploration costs in general as tradition sources dwindle (shifts from light crude -> heavy oil which requires more expensive processing).
• However
• in much of the world the infrastructure and technology to utilize renewable sources of energy is not yet in place or too expensive to implement.  Furthermore, it is those parts of the world where most of the population and economic growth is happening (Africa, India, Economy of the Arab League).

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

Keystone pipeline rejection creates opportunity for Pacific Rubiales Energy, Oil Update (OPEC, refinery margins, oil prices, Gulf Coast)

     As promised, Saudi Arabia increased its crude output during the third quarter of 2011 bringing OPEC crude production up to 29.9 mbbls/d from 29.2 mbbls/d (opec implemented a 30m b/d cap a couple years ago). However, it wasn't enough to offset the 1.6 million barrels a day of crude lost due to the situation in Libya. Average WTI price fell from $102.3/bbl in 2Q11 to $89.5/bbl in 3Q11 meanwhile Brent Crude fell by only $3.6/bbl to $113.4/bbl, contracting the spread by $8.6/bbl.
A small increase in refinery margins boosted demand for oil by refineries. Margins dubbed crack spreads were at $6.8/bbl during the last three months (4Q) which is up from the previous quarter but still down from the previous year when they were $10.1. Refineries have responded to the marginal increases in the third and fourth quarter by increasing capacity: In the 3Q the following changes hapened: Repsol up 86,000 bpd, Port Arthur up 50,000 bpd, Brazil's Araucaria up 50,000 bpd. In Aruba, a 235,000 bpd refinery was reopened.

Refineries in the Gulf Coast the destination of the proposed Keystone xl pipeline, also receive regular bulk-cargo shipments of oil from Colombian producers like Ecopetrol (58% of exports in April went to the Gulf Coast/foreign investment limited due to state ownership however if you're from Colombia then I recommend taking advantage of the country's recent domestic sale of 10% of the company's stock) and Pacific Rubiales Energy (Toronto-based but Colombia-focused).  The Keystone Pipeline would carry 700,000 bpd of Albertan oil to refineries in an area known as Padd III where WCS oil commands higher prices than it does in Padd II due to a glut of supply there already (55% of Canadian oil goes to the Northern region Padd II due to its proximity to Canadian pipeline routes).

Some background on Pacific Rubiales Energy
Pacific Rubiales Energy produces castilla-blend crude, a commodity type that has seen its realized market price grow by 39% in the third quarter of 2011 to $93.87. Pacific Rubiales is a joint partner in Colombia's most lucrative oil fields at Rubiales & Quifa (gross production from the two areas combined is up 56.9% in the 3Q11 stemming from more than 27 successfull drills).
In just the last quarter, Pacific Rubiales sold 9,342,859 barrels of oil equivalent which is more than it sold during the entire year only a few ago (837,860 bbls is from purchases used in trading). New drilling at Quifa increased total daily production there to 40,000 barrels up from just over 3,000 bpd last year. Rubiales production hit a high of 190,000 bpd at the end of September 2011 up from the daily average of 125,145 barrels in the third quarter of 2010 (keep in mind that PRE's share is only 50% at Rubiales and 60% at Quifa; there's also royalties that bring the net production down slightly). The company has four other semi-major producing fields which produced at a rate of 12,752 bpd combined in the last quarter (up from 11,187 in 2010). One of them, the largest which is La Creciente is significant to the company because it is one of a few that is 100% owned. Total production at La Creciente was up 18.2% during the last quarter.

Risks associated with Pacific Rubiales - Union disruption at the largest fields Rubiales and Quifa cost the company 1,343,084 total barrels of output last quarter (491,933 net share after royalties). Each time a disruption takes place it takes the company a week to bring production back to normal levels. Also of note: due to higher royalties on higher production, PRE's net ouput share after royalties from the 60% owned Quifa field was only 1.77X La Creciente (19,241 vs 10,857) in 3Q11 despite avg total gross field production being 3.19X greater (35,222 vs 11,053). The OCENSA pipeline which Pacific Rubiales now relies on for most of its pipeline transport, is being blamed for soil, groundwater and crop contamination. That resulted a lawsuit against British Petroleum and Ecopetrol who built it back in 1997.

Positives - For the third quarter 2011 revenue increased by 103% qoq even though the price of oil only increased 42%. Net income per share was the second highest for a quarter in company history at 72c basic, 68c diluted. That compares to a 26c loss in the first quarter of 2011. Net revenue in the third quarter was $828,285 up 41.9% compared to quarter ended March. Quarter revenue was down, however from $957,509 in the quarter ended June, due to the price of oil being slightly lower.
In just the last quarter the company along with partner Ecopetrol (EC) built 4.4 km of new road and 30 new electical substations at Rubiales and 27.7 km of new road at Quifa. In addition Rubiales increased its water treatment capacity by 150,000 bpd to 1.8 million bpd. The company keeps breaking production milestones! Total production at all the fields it has a joint/controlling partnership in reached 239,000 bpd on November 7, 2011. In terms of public companies Pacific Rubiales is one of Colombia's fastest growing oil producers. On January 24, 2011 Pacific Rubiales Energy stock (TSX:PRE) was up 2.6%. By the end of the day the stock price was 37% higher than 1-year low. Its 50-day moving average is up 0.5% in just the last five days.

Why Pacific Rubiales matters to refineries in Houston
The Gulf Coast received four of the seven large cargos of oil exported from terminals operated by Pacific Rubiales Energy. That's nearly half of the 8.2 million barrels of oil that was exported (over 90,000 bpd), up significanty (just over 5.0m barrels exported in 2Q10) due to the increased oil output. With the crack spread recovering from early 2011 levels, refineries on the Gulf Coast of the U.S. are welcoming the increased supply. There's already a binational pipeline connecting Venezuela and Colombia meaning that Pacific Rubiales most likely has access to refineries in Venezuela too so there's nothing limiting demand as in the case with Canadian companies. Canada hasn't seen one new refinery built in the last 35 years/there is one however that's pending, it will be operated by Canadian Natural Resources. Also of note: In April, 58% of Ecopetrol's exports went to the Gulf Coast.

Mexico's Oil Reserves are falling fast
Through partnerships with Ecopetrol Pacific Rubiales is well connected. Ecopetrol accounts for 60% of Colombia's oil output, it also has pipeline networks throughout the country. Pacific Rubiales transports over 14,000 bpd by truck (that's growing) and as of October 21, 2011 Mexican trucks are allowed to cross over into the U.S.
Perhaps in the near future pipelines will be built to connect Colombia/Venezuela to Mexico considering Mexico's oil reserves are rapidly being depleted (down to 14.7 billion barrels in 2008 from 25 billion barrels in 1999, that's a 41.2% drop in only nine years!). In addition to that the oil field that used to account for two-thirds of Mexico's oil production in 2011 only accounted for about 25% (current production at Cantarell is around 900,000 bpd the lowest since the 1990's). I think that a pipeline connecting Mexico to Venezuela and Colombia will eventually happen. Could be a couple years could be a decade but it's not unfathomable.