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Peak Oil: 98mbd in 2039 - Waning Demand is lowering target & postponing date

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Waning Demand is Lowering/Postponing the Peak

Peak oil  -  98mbd in 2039

July 30 2010 ~ Today's update of our global oil depletion model, Peak Scenario 2200, reveals maximum All Liquids production will be 98-mbd in 2039.  Its post-peak decline will average 0.7% to mid Century, but is poised to then collapse into a catastrophic decline rate of 2.9% from 2061 to 2070.

The current revision reflects three factors:  (a) 6-Gb increase (Regular Conventional up 88-Gb, Kerogen down 70-Gb) in our URR estimate;  (b) adjustment of 2050 target for UDRO to 4.4% from 4.7%;  (c) introduction of a Peak Demand module;  (d) reduction of new capacity future trend to 3.4-mbd from 3.5-mbd present trend.

All Liquids flow will not fall below this year's pace 'til 2059 ... ensuring decades of plentiful supply.  All Liquids will cross the midpoint of its 7.51-Tb URR in 2111, seventy-two years after Peak.  With petroleum-based liquids exhausting in Year 2388, there appears to be only 378 years of oil left!  After that date, flow will be solely dependent on renewable Biofuels.

With all G-20 nations officially free of Recession, my 2008 forecast that most of the world would see economic expansion in 2009Q3 (including the USA) has come to fruition.  Renewed Demand enabled the quarterly production record set in 2008Q1 to be surpassed in 2010Q1.  Tracking of seasonal flows indicates A new monthly record should be set next January.  The pace of 2010 production (85.9-mbd) has surpassed the 2008 annual record (85.4-mbd).  See monthly report.

As we discussed from the onset, McPeakster concern over future MegaProjects was grossly overblown during the Recession, and in reality the majority of cancellations proved to be opportunities to re-contract at more favourable deflated costs.  The pause in annual global production in 2008 was the the 11th since 1975.  Business cycle patterns indicate that we can expect similar softness  in 2017, 2026, 2034 & 2043, and these potential downturns are reflected in the PS-2200 profile.

A record 4.7-mbd of new facilities were commissioned in 2009, resulting in an estimated 4.1-mbd of immediate new flows.  Of this New Capacity, 2.3-mbd was required to offset loss of production due to Underlying Decline Observed (UDO) and the balance brought global Surplus Capacity to a twenty year record of 6.3-mbd by year-end.

Mid-year stats reveal that the Underlying Decline Rate Observed for Year 2010 All Liquids is:  2.9% (2.43-mbd) worldwide,  2.7% (0.27-mbd) in Saudi Arabia & 2.5% (0.22-mbd) in the USA.  This confirms UDRO has formed a sixth cycle top since 1970, with another surge of the decline rate to 3.1% in 2008.  With past experience, we expect the loss factor will bottom @ 2.5% in 2012, before its next cycle high (3.6%) during a probable 2017 Recession.  Extrapolation of the general trend (including its 8.5 year cycles) should see UDRO rise to 4.4% by 2050.

Frankly speaking, our mid-Century target had been as high as 9% in the past.  The reduction to 4.4% results primarily from the moderation of the Underlying Decline Rate in 2008, 2009 & 2010 and further builds the case that our hypothesis that UDRO is cyclical is correct.

The average post-peak production Decline Rate is a manageable 0.7% per year.  This changes for the worse in 2061 when the industry is no longer able draw from Regular Conventional Oil reserves at will.  Resource restraints will manifest quickly in RCO's leap to a reserve/production ratio of 9 ... and a staggering 10% Decline Rate.  Unable to make up the difference in production via non-conventionals, the All Liquids Decline Rate will surge to 2.9% from 2061 to 2070.  This has the potential to be catastrophic should the transportation sector have not significantly weaned itself off gasoline/diesel based fuels.

A module addressing the potential of Peak Demand has been added to Peak Scenario 2200 this month.  It can be best seen in our chart archive that the pre-peak slope reflects less annual growth than the 1-mbd trend of the past three decades.  Incremental annual Demand has been declining since its peak in 2003.  If the long term trend continues, Demand could conceivably cease to increase in 2018.  Using a less aggressive growth rate in this month version has had profound effect on the Peak Date, postponing it nine years to 2039.

In the end, the present projection for Peak was determined by UDRO exceeding the annual new capacity trend amid a deterioration of Demand ... but not an outright and arbitrary cessation of Demand.  The waning of Demand had a profound effect on Surplus Capacity.  Rather than reaching a max of 7.5-mbd in 2012 and exhausting in 2023, the first run of the Peak Demand module saw spare capacity burgeon to 8.6-mbd in 2026 & exhaust in 2040.

The results would have been even higher had not the future new capacity projection been trimmed to 3.4-mbd from its present 3.5-mbd trend.  Assuming our application of a UDRO that rises from 2.5-mbd in 2012 to 4.4% in 2050 is reasonable, it is plausible that the oil sector will pare back annual new capacity even further to avoid an overbuild in Capacity.  OTOH, should UDRO be under-estimated, the new capacity may be increased to maintain balance in the supply chain.

Target Extraction Rates :

  mbd  
2007 84.5 -
2008 85.4 -
2009 84.2 -
2010 85.9

(pending)

2033 95 extraction passes 2 trillion
2035 95  
2039 98 Peak Year & Peak Rate
2049 92 today's 1236-Gb of proven reserves exhausted
2050 91 -
2059 85 first year with flow less than today;  regular conventional drops below 50% of All Liquids
2067 67 extraction passes 3 trillion barrels
2075 61 9.2-billion peak of global population
2100 46 -
2103 46 regular conventional oil exhausts in 2095
2111 43 Extraction 50% of URR
2129 40 extraction passes 4 trillion barrels
2200 48 flows limited to GTL, CTL & BTL
2203 48 extraction passes 5 trillion barrels
2259 60 extraction passes 6 trillion barrels
2300 61 flows limited to GTL, CTL & BTL
2307 42 extraction passes 7 trillion barrels
2388 - world runs out of oil...  (excl BTL)

PS-2200 is a composite analysis of the 7 major components of All Liquids.  Regular Conventional Oil (RCO) is the only category that is post-Peak, down 6-mbd since 2005.  The 11 streams tracked as All Liquids include RCC, NGL (incl refinery gain), and the non-conventionals: GTL (gas-to-liquid), Deep Sea, Arctic, Bitumen (oil sands), X-Heavy, CTL (coal-to-liquid), Kerogen (shale) & BTL (biofuels-to-liquid) ... each with its own unique production profile.

PS-2200 is a flow based bottom-up analysis by TrendLines Research energy analyst, Freddy Hutter.  It is our contribution to the 18 models that comprise the TrendLines Scenarios Avg that we track each month, illustrating industry consensus on the timing of Peak Oil.


URR/EUR

7,513-Gb All Liquids URR/EUR 2010/7/30 PEAK 98-mbd in  2039 2010 flow: 86-mbd
2,145-Gb Regular Conventional Crude 68-mbd  2005 62-mbd
586-Gb Bitumen/X-Heavy 16-mbd  2093 3-mbd
1,663-Gb NGL-GTL-Ref/Gain 19-mbd 2043 & 20-mbd 2360 11-mbd
200-Gb Kerogen 14-mbd  2079 0-mbd
260-Gb Deep Sea & Arctic 16-mbd 2029 & 6-mbd 2080 8-mbd
2,659-Gb CTL 46-mbd 2294 0-mbd
1,229-Gb PAST to 2009/12/31 2-BTL

Peak Scenario 2200 is constructed on a 7,513-Gb URR platform that spans five centuries.  Six of All Liquids seven main components will have exhausted presently economic resource by Year 2388.  After that date, All Liquids is limited to BTL sourcing.  The July revision reflects a 6-Gb increase (regular conventional up 88-Gb, kerogen down 70-Gb) in our URR estimate.

It is a little known fact that if no further discoveries were made after today's date, present proven reserves of 1,236-Gb wouldn't be fully consumed 'til 2049.  Due to the enormous time span over which economic resource is spread, it is more than probable that Demand projections, and perhaps the Peak itself, will be substantially reduced due to technologic obsolescence long before any resource constraints kick in ... akin to the stone age, coal and whale oil dependence.  The adoption of hybrid, electric, natural gas & fuel cell vehicles will lead the transition from gasoline/diesel dominance as a transportation fuel.

As a renewable energy, BTL has virtually no end point.  PS-2200 projects that BTL will attain an ultimate and permanent Peak Plateau of 5.3-mbd in 2030, and will consume a cumulative 725-Gb to Year 2388 (not incl in URR/EUR tally).

All Liquids Peak will occur at 29% depletion of presently-economic resource.  The midpoint of URR will be crossed in 2111, seventy-two years after Peak production in 2039.  Exhaustion of the first trillion barrels of reserves occurred in 2002.  The second trillion will have passed by 2033; the third by 2067 and then the fourth trillion by 2129.

3.6-Tb of liberal augments to Kerogen, GTL & CTL cause the PS-2200's 7.5-Tb URR to vary immensely from the 3.9-Tb Avg found in our 19-model TrendLines Scenarios.  Admittedly, the latter is much more in line with the most recent update of our URR Composite Estimates Study with its slightly different mix of practitioners and sporting a conservative average of 3.8-Tb URR.


Underlying Decline

In a typical profile, annual production builds over time, attains a peak, maintains a plateau, then declines.  Because fields and petroleum provinces are developed over years or decades, some of the wells of a field, or fields within a province, or ultimately provinces within global production ... can be in decline or retired while others are still in growth stage or plateau.  This annual loss factor is the field/province/world's Natural Underlying Decline.

IEA calculates the annual Natural Underlying Decline Rate is 5% in post-peak Regular Conventional Crude fields, and as much as 15% in non-conventional post-peak Deep Sea fields, with a weighted avg of 9%.  A Producer's EOR activity can improve extraction results and diminish this loss factor.  After general EOR activity, IEA calculates the annual loss is 6.7% for Conventional & Deep Sea crude categories that represent 83% of global production.

I call this net absolute figure, more applicable to our depletion studies, Underlying Decline Observed (UDO).  It is expressed in millions of barrels per day (mbd) per annum.  More commonly, analysis of RCC or All Liquids is conducted in percentage terms per time interval - and the Underlying Decline Rate Observed (UDRO) is appropriate.  To maintain a production plateau, Production Capacity must be incrementally increased each year to match UDO loss.

Within a typical petroleum province, roughly a third of fields & wells are relatively recent and are annually ramping up their production rate.  Another third are in plateau.  And the balance are the mature and near-retired wells & fields where significant depletion is reflected by production decline within.

Since November 2007, Peak Scenario 2200 has uniquely provided stakeholders with regular monthly reporting of Global UDO/UDRO status, with a spotlight on the two mature provinces:  Saudi Arabia & the USA.

My March 2009 analysis revealed that Global UDO first became significant during the 1970 American Recession.  Chart#4 illustrates long term global annual UDO (red line), but it is the Underlying Decline Rate Observed (UDRO) inset of annual rates that is most instructive.  I have found that the UDRO exhibits a tendency to ebb and flow.  It became apparent that these cyclical (8.5-yr) crests correlate with all six USA Recessions of the past four decades.  These cycle tops appear to reflect reduced EOR activity during economic contractions, no doubt due to capital & cash flow limitations amid a reduced Demand environment.

These crests (bold red line) further coincide somewhat with depletion rate peaks of  the major petroleum provinces:  the Persian basin (Iraq/Iran) in 1977, USA/Russia All Liquids in 1984, the North Sea in 2001 & the present deterioration in Mexico.

The highest annual surge for UDRO was 6.3% of All Liquids production in 1984 in the wake of the double-dip 80's Recessions.  The recent cycle top of the 2001 Recession was followed by an UDRO trough of 1.9% in 2006, then the 3.1% high of the 2008 Recession.  The loss factor is projected to bottom @ 2.5% in 2012 before its next cycle high (3.6%) during a probable 2017 Recession.  Modeling of the general trend (including its 8.5 year cycles) determines UDRO will rise to 4.4% by 2050.

Extension of the business cycle pattern would see further crests in 2017, 2026, 2034, 2043, 2051 & 2060.  I am extremely comfortable with such a bold forecast 'cuz incredibly, these dates fall in line with our forecast for peak-related heavy depletion associated with Saudi Arabia (2019), Deep Sea (2029), NGL (2043) & global RCO (2061).

Analysis by TrendLines Research reveals that over the last 40 years, UDRO has averaged 2.7% annually.  From 1970, this necessitated the construction of 119-mbd of new facilities:  76 to address UDO & 43-mbd to raise Extraction Capacity from 49 in 1969 to 92-mbd by last December.  In short, the oil sector has been adding 3-mbd/yr ... or a new Saudi Arabia every three years for four decades!  Terminal global production decline will commence upon Annual New Capacity no longer exceeding the UDO trend line.  This intersection is crossed in 2040.

 In a more recent context, from Y2k to 2009, the Industry commissioned 33-mbd of new capacity.  During that ten year span, a full 22-mbd was applied against this Underlying Decline challenge; and the remaining 11-mbd serviced new Demand & added to Surplus Capacity.  This impressive task (3.3-mbd/yr) was equivalent to a new Russia coming on stream every three years.  Visually, the bold red line in charts #3 & #4 tracks annual Underlying Decline Observed.

Cycles aside, the magnitude of loss will generally rise as Peak  approaches.  Viewing the future by our measure, 89-mbd of new capacity will be required to attain our 2035 target of 95-mbd.  7-mbd of this will raise capacity 92 last year to 99-mbd. The other 82-mbd will address UDO loss over the next 25 years. Added to the 76-Gb to cover 1970-2009 decline loss, we calculate a total 158-Gb of Capacity will have been dedicated to this loss phenomenon over the full six decades.

The oil sector presently maintains a seven-year trend for New Capacity of 3.5-mbd/yr, thus already exceeding the rate required to attain our 2035 target.  And, perhaps even a less difficult task considering the record breaking 4.7-mbd new capacity installed in 2009!  Based on present URR Estimates and subject to capital availability, the Industry can maintain this activity level until inevitable resource constraints begin to restrain new development (blue line in chart inset) after 2060.

Below, PS-2200 is compared to the short time frame practitioner estimates for All Liquids UDRO:

   1.5% - CERA (2009-2030 avg)

   1.9% - Adam Brandt (2007 - sole peer-reviewed contribution)

   1.9% - IEA (2008-2030 avg)

   2.9% - Freddy Hutter's Peak Scenario 2200 (June/2010, 4.4% by 2050)

   4.1% - Matt Simmons (2009-2030 avg)

   4.2% - EIA (2009-2030 avg)

   4.2% - Jeff Rubin (2009)

   4.5% - OPEC (2008)

   4.6% - Deutsche Bank (2009, rising to 8% by 2030)

   4.7% - Chris Skrebowski (2010)

   5.0% - Total (2009)

   5.2% - Schlumberger (2009-2030 avg)

   5.25% - Sadad al Husseini (2009)

   6.0% - PFC (by 2030)

   7.0% - UK Energy Research Centre (2009)

   9.0% - consensus at theOilDrum & PeakOildotcom (2009)

CERA has determined that flow from currently in-place Capacity will deteriorate by only 31-mbd in the next 21 years.  In its recent WEO-2008, IEA presumes 45-mbd of new Capacity is required to sustain a plateau 'til 2030.  Because our estimate is 58-mbd, I have little doubt that both their most current forecasts of Peak Oil (CERA's 113-mbd in 2035 & IEA's 104-mbd in 2030) will face further downward revisions in the near future as it becomes clear that they have gravely underestimated the UDO loss factor for All Liquids.  Early in the decade, CERA & IEA had Peak Rates of 128 & 121-mbd respectively!  As they have grasped the scope of their failure to account for underlying decline, we can better understand their pattern of annual downward revisions over the last five years.

The PS-2200 findings surrounding the nature of Underlying Decline vary considerably from the consensus McPeakster hypothesis.  Chatter at PeakOildotcom & theOilDrum proposes that All Liquids UDRO rose fast & furious from 0% in 2002 to 9% in 2009.  Their simplistic musings are void of any explanation for the above mentioned 77-mbd of new facilities built from 1970 to 2009 that failed to increase production!  The 7% figure adopted last Summer by the UK Energy Research Centre is similarly a fabricated figure from thin air.  Acknowledgment by McPeaksters that their scary scenarios are groundless will not occur anytime soon.  These groups are agenda-driven and facts just get it in the way...

Finally, let's give this loss factor some overall context.  The USA sports a 2.5% All Liquids UDRO as an 86% depleted petroleum province in 2010.  Less mature Saudi Arabia at 40% Depletion, sports a 2.7% All Liquids UDRO this year.  Both are reasonably good proxies as to what will be faced on the global scale in the domain of Underlying Decline.  With worldwide Depletion at a mere 16%, it is almost certain that global UDRO will not exceed 5% 'til past mid-Century on the journey to ultimate exhaustion in Year 2388.  All Liquids will commence terminal decline when annual Underlying Decline Observed inevitably starts to exceed annual New Capacity installations.

All Liquids 2009 Underlying Decline Rates Observed:  2.9% (2.4-mbd) and troughing in 2012 Worldwide;  2.7% (0.27-mbd) & rising in Saudi Arabia;  2.5% (0.22-mbd) and rising in the USA.


2035 Outlook

The higher resolution of our PS-2200 "2035 Outlook" (chart#3 above) allows an illustration of two hypothetical scenarios:

(a)  an ultra conservative All Liquids trajectory with an apparent 87-mbd Peak in 2011, declining to 28-mbd by 2035 (hashed lime line), assuming a 3.3% Avg Underlying Decline Rate Observed.  As a Worst Case Scenario, it assumes that the oil & gas sector will never augment today's announced-to-date MegaProjects.

(b)  the more plausible production profile whereby the present Megaproject trend of 3.4-mbd/yr is deemed to continue unabated 'til 2050,  However, annual underlying decline overtakes that pace in 2040 (post-2012 solid lime line) and the end-of-year Supply surge commences terminal decline.  The 2039 Peak is 98-mbd.

In practical terms, recent history (since 1970) has shown that the hypothetical, pessimistic projection line so oft displayed by McPeaksters incrementally rises thru time to meet the growth trend line.  Hence The Wedge as shown continually gets pushed back to "next year".

Viewing the future by our measure, 90-mbd of new capacity will be required to attain our 2035 capacity target of 95-mbd.  7-mbd of this will raise capacity from 92 last year to 99-mbd. There will be 4-mbd of spare capacity.  The other 83-mbd will address the UDO loss over the next 25 years.  Added to the 77-mbd to cover 1970-2009 decline loss, we calculate a total 167-mbd of Capacity will have been dedicated to this loss phenomenon over the full six and half decades.

It takes up to 7 years to bring to fruition very large (MegaProject) capacity facilities.  The Autumn 2008 Credit Crisis jeopardized some planned ventures, and may have deferred what were imminent announcements as stakeholders used the opportunity of a Recessionary environment to rewrite contracts and MOUs in a deflated pricing regime.

To prevent Terminal Decline in the coming two decades, Producers need only monitor the UDO trend and commit to a New Capacity construction program that consistently matches or exceeds that loss.  As seen in Chart#4, Industry has generally and stalwartly installed sufficient new Capacity to meet this challenge ever since 1970.  From a recent low of 2.6-mbd installed New Capacity in Y2k, this metric has been on a steady rise, culminating in 4.7-mbd of facilities last year.

Resource availability for capacity additions poses no constraints before 2061.  With 1236-Gb of proven reserves, the Industry doesn't need a newly discovered barrel of oil 'til Year 2049.

Actual annual production will be affected by Price & Demand forcings, sometimes influenced by natural and geopolitical events.  We have attempted to account for these nuances by adjusting for future economic Recessions and high price periods.  Today's 6.6-mbd of global Surplus Capacity will max out at 8.6 in 2026, and will not exhaust 'til 2040.  Unfortunately, the moderating effect of that spare capacity on crude prices is likely to be outweighed by ever rising upstream costs and further USDollar debasement ... as elaborated upon within our Barrel Meter discussions.


the Peak ... & Terminal Decline

Continuing Production growth versus a reversal into terminal decline is completely dependent on the delicate balance between Annual Underlying Decline Observed (UDO) and Annual New Capacity.  To complicate matters, we have shown that UDO does not rise incrementally each year as universally assumed.  UDRO rocketed to a 6.3% high after America's double-dip 80's Recessions, but then drifted way down to 1.7% by 1999.  Add unpredictable OPEC interference to the fray, and Producers have their work cut out in monitoring quota & UDO losses and stalwartly making up the difference ... and more.

Over the past four decades, new installations have averaged 2.9-mbd/yr.  The current (7-yr) trend rate is an even better 3.5-mbd/yr.  2009 performance was a record 4.7-mbd in newly commissioned flows.  OTOH, the long term Avg for UDO is 1.9-mbd, with a current loss factor of 2.4-mbd in 2010.  The balance of 1.0-mbd/yr increased capacity from 49 in 1969 to 92-mbd in 2009.

Presently, Producers can extract at will from any of the seven categories of conventional & non-conventional resource.  Terminal Decline can be averted so long as New Capacity out paces Underlying Decline.  But, it appears that this race ends in 2040 when the secular trend of rising Underlying Decline Observed finally surpasses the long term average (3.4-mbd) of annual New Capacity installations.  UDO is forecast to rise from 2.5-mbd in 2012 to 4.4-mbd in 2050.

On a second battle front, Producers must face inevitable resource constraints.  The first peak was Regular Conventional Oil in 2005.  The Deep Sea extraction rate starts to decline in 2030, followed by NGL in 2044.  Dwindling proven reserves will one day reach the point where our future annual New Capacity trend rate of 3.4-mbd is in jeopardy and can no longer be maintained at desired levels.  We calculate that event will occur in Year 2061.

Thus at this point in time, it seems that rising annual UDO will cause the eventual demise of rising production (in 2040), while resource constraint will be responsible for a dramatic increase in the post-peak production decline rate (in 2061).  Supply will decline an avg (and manageable) 0.7%/yr from 2040 to 2060, then escalate dramatically to a horrific 2.9% over the next nine years (2061-2070).  It is this precise time frame at which efforts towards mitigation and substitute energy sources must be aimed.

The changes in flow rates are apparent visually in Chart#1, where we can see that the post-peak track approaches a precipice upon RCC commencing its R/P 9 (Reserve/Production Ratio ~ 10%) environment caused by the inability of the sector to any longer replenish proven reserves at will.  Deep Sea resource will exhaust in 2050.  NGLs meet their final demise in 2064.  The end days of the century will see the exhaustion of Regular Conventional in 2095, Arctic resource in 2107 & high-grade Kerogen in 2114.

Depletion of these five All Liquids streams coincides with the stabilization of global population at 9.2 billion in 2075.  It is projected that by 2175 there will be a decline to 8.3 billion.  Added to the fray will be a commencement in decline of the Bitumen & X-Heavy category in 2093.  Fortunately for later generations, the downturn in All Liquids will be short-lived.

Rising non-conventional liquids production will eventually bring stability to the plunging flow trend.  It can be seen in Chart#1 that GTL & CTL streams will be in vigorous growth mode at the turn of the Century.  Renewable Biofuels will of course augment these flows.  It appears at this time All Liquids production will enjoy a 41-mbd multi-decade plateau (2115-2162).

Due to potential technologic obsolescence, long-term Demand is almost unpredictable.  But should there be ample and insatiable Demand, All Liquids supply is indeed calculable.  Growing CTL (coal) & GTL (gas-to-liquid) production could take All Liquids to a secondary peak of 67-mbd in Year 2294.  If consumed, these final fossil fuel streams would exhaust in 2388.

Lacking an understanding of the Underlying Decline Observed process has caused much of the confusion amongst the McPeakster fraternity this past decade.  Their paranoia that reserves of Regular Conventional Oil are simply vanishing (by as much as 9% per annum) has been fed by gloom merchants such as Matt Simmons & Jeff Rubin.

Practically all the 2.4-mbd of this year's UDO will be related to RCO.  RCO peaked in 2005 @ 68-mbd and declined at an annual rate of 2.6% from 2006 to 2009.  Colin Campbell believes light sweet crude will continue that same pace of decline 'til extraction is a mere 35-mbd in 2030.  His commitment to this premise is fundamental to his larger position that All Liquids peaked in 2008 and will be down to 59-mbd in 2030.

The comparable figures for PS-2200 are phenomenally higher (46 & 95) for two reasons.  First, we believe the apparent extraction decline is actually masked by a countervailing rise in surplus capacity.  Factoring this in, the real production decline rate to 2030 will be revealed as a lesser 1.5% per annum.  Second, our model is based on the premise that the cycle crests of underlying decline observed are caused by the American Recessions.  With the USA economy presently in Recovery, it is my position that there is moderation of UDRO underway.

If Campbell's premise is correct, RCO should decline from last year's 61.8-mbd to 60.3 & 58.7 in 2010 & 2011.  Conversely, PS-2200 forecasts flow will hold at a tad over 62-mbd over these 8 quarters.  We proposed last year that 2010 would be seen as the watershed year between these contradictory models.  The correct of the opposing views will take two or three years of data to be revealed, but with a 2010H1 flow rate of 62.3-mbd, we have high confidence in our stated position.  Our sentiment is somewhat buoyed by the recent revision of Peak Date (again) by several McPeaksters from 2008 to mid-decade.

The Campbell Depletion Model continues the 2.6% decline rate to 2050, then projects a softer 1.6% to exhaustion.  In very different outlook, the Hutter PS-2200 foresees a precipitous plunge over the cliff via a 10% decline rate after 2060.  See our depiction of both current RCO projections for their contrary profiles.


Saudi Arabia

Russian & Saudi Arabia have enjoyed a friendly rivalry for the title of World's leading All Liquids Supplier nation for three decades.  OPEC mandated restrictions on member quotas since Autumn 2008 have enabled Russia to slip ahead once again.

Saudi Aramco starts 2010 with an unrivalled 4.5-mbd Surplus Capacity.  As OPEC relaxes quote restrictions with time, Aramco can use this spare capacity to ramp up production; even the remote possibility of new records.  "Remote" because this huge surplus capacity is masking the reality that the Kingdom has just passed a major milestone:  the Peak of its Maximum Sustainable Capacity (MSC).  KSA MSC reached a record 12.5-mbd in 2009.  MegaProject analysis indicates that there are insufficient new facilities planned in the visible horizon to outpace the Underlying Decline factor.

My estimate of the Kingdom's URR has been drastically reduced over the past two years ... to 290-Gb.  The discrepancy between this linearization-indicated potential versus the 900-Gb resource base touted by the Kingdom is rather disturbing.

TrendLines calculates Saudi UDO to be 0.27-mbd/yr (2.7% of 2010 All Liquids).  Even assuming this to be a stable metric, the completion of announced MegaProjects would mean MSC of only 12.0-mbd by the end of 2015.  Saudi Arabia must install an additional 0.6-mbd in new facilities before 2016 to avoid 2009 being deemed its MSC Peak ... an almost impossible task at this juncture.

This historic event is consistent with our analysis that KSA will cross the midpoint of its URR shortly (in 2019).  Regardless, its reserves are quite large and the nation will continue to be the globe's number one (or two) All Liquids supplier for two generations.  Production Capacity will not breach below the 8-mbd threshold 'til 2038.  The unrivalled Surplus Capacity makes it impossible to forecast Saudi peak production.  Aramco has many strategic options and is vulnerable to OPEC mandates.  See our separately released 5th Annual Saudi Outlook for further discussion.


Volatility of Crude Price

2.4-mbd of new capacity was required to offset 2009 global Underlying Decline Observed.  Fortunately, the energy sector has been bringing much more than that on stream each year ... a record 4.7-mbd of new capacity last year, as seen in Chart#4's inset.  The explosion in new facility development late this decade is one of several factors responsible for the recent $94/barrel collapse in the monthly avg of the USA Contract Crude Price.  Regardless of OPEC quota antics in latter 2008, savvy market traders ignored these quota cuts and instead reacted to the more important revelation that "real" and abundant Surplus Capacity was returning to the global system.

From October 2006 to July 2008, the McPeakster fraternity was successful in originating/disseminating web-based rumours that Saudi Arabia's Ghawar giant field was in terminal decline.  PeakOildotcom, theOilDrum, Matt Simmons & Jeff Rubin (CIBC WM) were the main players that wrongly translated a reversal of Saudi extraction to be a harbinger of overall global decline.

But, as the Kingdom increased production from 8.7-mbd to 9.5, the hoax by these perpetrators was exposed.  Prices plummeted as traders raced to eliminate their silly Depletion Fear Premium as a pricing component.  At the height of the July 2008 Price Bubble, the later invalidated FEAR factor had rose to $33 of the $131/barrel contract price.  Embarrassed Producers were the grateful beneficiary of this manipulated situation, as witnessed by their burgeoning windfall profits.  Indeed, the 22 year old rumour of Peak Oil is the best damned thing that has ever happened to the crude producing sector.

The combination of the Russian incursion into Georgia and the record purchase of American Treasury securities/instruments during the 2008 Summer Credit Crisis led to a 20% jump in the USDollar.  With this, geopolitical events thus eliminated almost the entire $31/barrel Dollar Debasement component  that had built up in July 2008.

Another volatile forcing behind the 2008 Crude Spike was related to the perceived growing tightness in Surplus Capacity.  Albeit there was still 2-mbd apparently available, much was not useful as since mid-decade there had been an even greater tightness in spare refinery capacity - and what there was, could not handle the heavier crudes available.  The result was that the Surplus Capacity component of Price inflated to $31 in the Summer of 2008.  Today, traders understand that global surplus capacity exceeds 6-mbd.

Average Upstream costs (exploration & lift) also had accelerated growth of late.  On a production weighted basis, this was a $24 component that heady season.  Inventory tightness varies mostly on a seasonal basis, and sat at $9 per barrel at that crucial juncture.

The final remaining factor concerns the controversial speculation-hedging activity.  It prodded the spot price rise in two ways:  (a) by the sheer total futures contracts volume, and (b) via non-commercial long contracts vs the shorts.  Contrary to overwhelming popular opinion, our research attributes only $3/barrel to this activity at the peak of the bubble.  Futures contracts are mere side bets to the real action ... and can no more affect the Crude Price than sports betting can affect ball game scores.  It does not significantly impede the process of price discovery, but the glamour surrounding the activity evidenced by noise-du-jour most certainly can lead to excessive windfall profits for the producers.

Together, the above factors served to spike up the Price $94 from its level of $37/barrel at January 2005.  In five short months (by late December 2008), it had collapsed to that same $37 level.  To understand the mechanisms behind the topping action, it should be known that as the oil price approached a certain Fuel or Oil Cost/GDP ratio which I call the Demand Destruction Barrier, alternative & conservation measures kicked in to halt the Price inflation.  Until then, high prices played a part in enhancing (but not causing) the Recession in play.

The 2009 Recession was inspired by the real estate bubble and its derogatory effect on disposable income.  In a normal business cycle, even inflated fuel costs are too insignificant to cause economic Recessions.  Another McPeakster myth busted:  correlation does not prove causation.

In 2010 we are presently witnessing another detachment of Crude Price from its fundamentals.  The present status of the price forcings described above (sans Spec/Hedging Activity & Windfall Profits) indicates the real price of oil is only $39/barrel today, based on fundamentals, and another steep correction is inevitable.

Over the past five years, the monthly USA Contract Crude Price was on average 44% greater than the figure its fundamentals would imply ... the "fair value" in effect.  As explained above, July 2008 was a perfect storm of contributing factors.  But even in the headiness of that Summer, Price exceeded fundamentals by only 40%.  Not surprisingly, this metric bottomed at a mere 6% premium during the depth of the Price collapse in December 2008.  But all hell has broken loose since...

By January 2010, Crude Price had skyrocketed to 79% over the number based on its fundamentals - a metric not seen since late 2004!  Some say this is due to Crude Price's vulnerability to USDollar debasement, but our Barrel Meter model attributed only $9 of the June/2010 oil price increase since Dec/2008 to that factor.  A full $25 of the increase is related to Media Noise.  This is being validated by obscene Q1/Q2 windfall profits of the IOCs.  Logic is absent from the present marketplace.  Price discovery is dysfunctional.  Intuition would infer neophytes have taken control of buyer desks of the globe's stakeholders.  Contrary to 2008, when the oil price was attributable to factors surrounding its fundamental components, crude price has been in a bubble since August 2009.  I repeat ... 2008 was not a bubble!

Extrapolating the rate of increases we're seeing among the model's components, Crude Price is on a path that will take it to an unsustainable $135/barrel by 2011Q3.  At that point, the Demand Destruction Barrier will halt and reverse the price run.  A major correction similar to Autumn 2008 will occur, but not before much damage is done.  New Car Sales will re-collapse and several G-20 nations will lapse back into Recession.  Had the USDollar not benefited from the Greek contagion this Spring, it is more than probable the USA economy Recovery would have suffered a relapse.  We now expect a double-dip to surface by this Autumn.

Interpretation of how these and other factors play a part in pricing structure can be viewed via our Barrel Meter Chart & Gas Pump Chart discussions.  The former now includes 1-Yr, 5-Yr & 10-Yr & 25-Yr price targets.


Trivia

Consensus All Liquids URR (4,010-Gb) has doubled since 1995.  Consensus remaining resource (2,749-Gb) has doubled since Y2k.  Proven reserves (1,236-Gb) have doubled since 1978.

Generally, for every $1/barrel increase in Crude, another 33-Gb of resource is added to URR.

Excluding BTL, 1,225-Gb of the 7,513-Gb global URR has been consumed, thus worldwide Depletion is currently 16%.  The Global Depletion Rate is 0.4%/yr today (31-Gb annually extracted liquids as a percentage of global URR).  If measured as a percentage of remaining resource (6,357-Gb), it is a higher 0.5%/yr.

$24/barrel:  Global Avg for Exploration, Development, Lift & Overhead costs in June 2010 (from $6/barrel in Middle East to $45/barrel for tar sands to $65/barrel for deep-sea projects).

$12 Billion - Avg cost of commissioning 1-mbd of new extraction capacity

$26 Billion - Avg cost of commissioning 1-mbd of refining capacity

$5 Billion - Floating LNG plants

$405 Million - Avg cost of new rigs

$5.98 Trillion - Cost of commissioning 60-mbd of new extraction/refining capacity by 2030

Deep Water Record:  Royal Dutch Shell's 9,356' Silvertip well in the Gulf of Mexico & & Anadarko's 16,300' Itaipu exploratory well in the subsalt region of Brazil's Campos Basin.

USA:  Assisted by Kerogen & Biofuels processing, the USA will reclaim its status as #1 World Liquids Producer in 2047; and will exceed its 1985 ALL Liquids extraction record of 11.2-mbd in 2075.  USA passed its 50% URR midpoint in 1966, four years prior to its RCC Peak.

Regular Conventional Crude passed its 50% URR (2,145-Gb) midpoint in October 2009, four years after its global production PEAK.




Disclosure: no positions