OilVoice Magazine | February 2014

8/13/2019 OilVoice Magazine | February 2014

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Edition twenty threeFebruary 2014

Unlocking new insights in the MarcellusEnergy policy freeze frame in 1970s mould

Shell profit warning - the shock that wasn't

Cover image by Enrico Strocchi


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1 OilVoice Magazine | FEBRUARY 2014

Issue 23 February 2014

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Adam Marmaras

Chief Executive Officer

Welcome to the 23rdedition of theOilVoice magazine. This month wehave another bounty of quality articlesfrom our writers, including NEOS,Andrew McKillop, Dave Forest, GailTverberg, Mark Young, Eoin Coyneand David Bamford.

Site visitor numbers are the 'holy grail'of a website like OilVoice. We areconstantly thinking of ways to increaseour readership, and reach more oil andgas professionals each month. Thebigger our numbers, the more valuewe can deliver to ouradvertisers,andthat's what keeps a free to use site likeOilVoice ticking along. So the mood inthe office is understandably up at themoment as our traffic numbers have

reached an all time high. In Januarywe reached 160,000 people, andserved up 600,000 pages. If you wereone of our visitors in January, thenthank you!

Have a great 2014

Adam Marmaras

CEOOilVoice
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Contents

Featured Authors

Biographies of this months featured authors 3Unlocking new insights in the Marcellusby NEOS 5Why EIA, IEA, and Randers' 2052 energy forecasts are wrongby Gail Tverberg 9Shell profit warning - the shock that wasn'tby Andrew McKillop 21Total's investment is a big step for the future of UK shale - But don't get

too excited just yetby Mark Young 26Insight: a small black cloud?by David Bamford 29Oil & gas M&A reaches US$143 billion in 2013by Eoin Coyne 31Insight: Give us a break!by David Bamford 36

The offshore oil drilling revolution, and its game-changing technologiesby Dave Forest 37Energy policy freeze frame in 1970s mouldby Andrew McKillop 41


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Featured Authors

Andrew McKillop

AMK CONSULT

Andrew MacKillop is an energy and natural resource sector professional withover 30 years experience in more than 12 countries.

NEOS

NEOS

NEOS is a solutions-oriented geosciences company that is a leader in theemerging field of multi-measurement subsurface interpretation.

Mark Young

Evaluate Energy

Mark Young is an analyst at Evaluate Energy.

Eoin Coyne

Evaluate Energy

Eoin Coyne is an analyst at Evaluate Energy.

David Bamford

Finding Petroleum

David Bamford is a past head of exploration and head of geophysics at BP,and a founder shareholder of Finding Petroleum.
http://www.oilvoice.com/description/AMK_CONSULT/82b50237.aspxhttp://www.oilvoice.com/description/AMK_CONSULT/82b50237.aspxhttp://www.neosgeo.com/http://www.neosgeo.com/http://www.evaluateenergy.com/http://www.evaluateenergy.com/http://www.evaluateenergy.com/http://www.evaluateenergy.com/http://www.findingpetroleum.com/http://www.findingpetroleum.com/http://www.findingpetroleum.com/http://www.evaluateenergy.com/http://www.evaluateenergy.com/http://www.neosgeo.com/http://www.oilvoice.com/description/AMK_CONSULT/82b50237.aspx


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Gail Tverberg

Our Finite World

Gail the Actuarys real name is Gail Tverberg. She has an M. S. from theUniversity of Illinois, Chicago in Mathematics, and is a Fellow of the Casualty

Actuarial Society and a Member of the American Academy of Actuaries.

Dave Forest

Contributing Editor

Dave Forest is a Contributing Editor for Oil and Gas Investments Bulletin.
http://www.ourfiniteworld.com/http://www.ourfiniteworld.com/http://www.lunarsafari.co.uk/


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Unlocking new insightsin the Marcellus

Written byNEOS

Multi-Physics Approach to Sweet Spot Detection

Oil & gas development in the Appalachian Basin has experienced a dramaticresurgence over the last decade thanks to unconventional drilling and extractiontechniques. Companies have discovered the promise of the Marcellus, a formationthat stretches nearly 600 miles from West Virginia north through Pennsylvania and

eastern Ohio into New York and Canada.

More than 8,000 horizontal wells targeting the Marcellus have been permitted inPennsylvania, with 6,000 of those either in production or under development.Regional reserve estimates vary widely, with most in the 200 TCF (33 billion BOE)range, though some approach 500 TCF (83 billion BOE).

Amid promise and increased activity, there are issues that threaten the Appalachianresurgence such as falling gas prices. While most Marcellus wells were wildlyeconomic just a few years ago, producers must be much more selective in which

parts of the play (and the shale) they target. As a result, companies are seekingbetter solutions that enable them to understand the subsurface.

New Insights into Tioga County

In Tioga County, Pennsylvania, a supermajor wanted to know what geologic factorsdrove some wells within the Marcellus to be more productive than others. Theanswer was not readily apparent on seismic, so a methodology called Multi-Measurement Interpretation (MMI) was introduced byNEOS GeoSolutionsaHouston-based provider of surface and subsurface imaging solutionsto provide abetter understanding of the area of interest.

NEOS set to work on a program to provide the underwriter with an improvedunderstanding of the basins geologic context which included:

Identifying oil seeps and gas plumes on the surface, Detecting abandoned wellbores, Identifying shallow gas geo-hazards, Mapping faults and lineaments from the basement to the surface, Mapping regional structure and lithology throughout the geologic column, and Delineating shale sweet spots that are geostatistically associated with the

most productive wells.
http://www.oilvoice.com/description/NEOS/2189a141.aspxhttp://www.oilvoice.com/description/NEOS/2189a141.aspxhttp://www.oilvoice.com/description/NEOS/2189a141.aspxhttp://www.neosgeo.com/index.phphttp://www.neosgeo.com/index.phphttp://www.neosgeo.com/index.phphttp://www.neosgeo.com/index.phphttp://www.oilvoice.com/description/NEOS/2189a141.aspx


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For this neoBASIN program, NEOS acquired airborne multi-physics datamagnetic, electromagnetic (EM), radiometric, gravity, and hyperspectralover 1,000square miles of Tioga County. These data were integrated with existing geophysical,geochemical, and seismic measurements from various public domain and third-partysources and interpreted by NEOS and operator geoscientists.

The acquired data delivered new insights to the program underwriters, even wheninterpreted individually.

Using hyperspectral analysis, interpreters located numerous oil seeps andgas plumes. The seeps and plumes were then traced back to surface-penetrating faults that were mapped used an analysis of magnetic data. Theresult provided insights into the relative liquids generating potential of thetarget shale intervals in the subsurface.

Airborne EM resistivity measurements provided insights into both lateral andvertical resistivity variations throughout the geologic column, down to roughly

10,000 feet. When the EM voxel was depth-sliced at the Marcellus interval,geoscientists noted that resistive hot spots in the Marcellus corresponded tomany of the countys best well locations.

Geoscientists on the project also incorporated more traditional geophysicalmeasurements into the interpretation. Well logs were analyzed to enhancestructural control and to calibrate the airborne EM data. Seismic data wereincorporated into the regional structural model and, in combination with themagnetic and EM data, provided insights into how faults were creatingpathways for hydrocarbons to migrate toward the surface.

Using Predictive Analytics to find the Sweet Spots

Well productivity can vary widely in an unconventionalshale play, even within the same county. While welldesign plays a part in this variance, so too does thegeology. NEOSs multi-measurement methodology ishelping explorationists understand the geologic driversof well productivity. On the typical survey, nearly 100G&G measurements, attributes, and derivatives are

acquired and analyzed to identify the 10-20 that correlate with the best (or worst)wells in an area. Using advanced geostatistical and predictive analytics methods,

proprietary NEOS software than undertakes a pattern search to identify other partsof the play in which the correlativeattributes appear. The resulting analysis allowsNEOS to develop sweet spot maps.

In the case of the Tioga predictive analytics exercise, twenty G&G measurementswere identified as correlating with the most productive wells in the county. Themeasurements arent without geologic significance, as they relate to four categoriesextremely relevant to well productivity:

Structural context The size and composition of the tank

Reservoir plumbing and Halo effects (above the reservoirs in question)


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Roughly half the correlative attributes corresponded to the structural context of theMarcellus interval, including its thickness, burial depth, and the depth-to-basement.Throughout the Appalachian region (and in many other shale plays), variations inbasement-associated featuresincluding topography, faulting, and lithologyarebeing increasingly acknowledged as having a significant influence on the productivity

and EUR of the overlying shale horizons.

A Promising Future for Appalachia

The complete multi-physics, multi-method approach used for the Tioga neoBASINprogram revealed subsurface features from the basement to the surface, helping theprogram underwriters pinpoint the sweet spots and avoid shallow gas geo-hazardsand therefore optimize their leasing, drilling, and hydraulic fracturing programs in theplay in Tioga County.

The future of Appalachia looks bright with many key operators viewing the region as

a core platform for growth in the years ahead. Since the early surveys in Tioga,NEOS has undertakenadditional projectsin Pennsylvania, compiling nearly 5,000square miles of available regional data that are continuously delivering unique, cost-effective insights into one of Americas greatest resource plays.

View more quality content fromNEOS
http://www.neosgeo.com/global-programs/appalachian-neobasin.htmlhttp://www.neosgeo.com/global-programs/appalachian-neobasin.htmlhttp://www.neosgeo.com/global-programs/appalachian-neobasin.htmlhttp://www.oilvoice.com/description/NEOS/2189a141.aspxhttp://www.oilvoice.com/description/NEOS/2189a141.aspxhttp://www.oilvoice.com/description/NEOS/2189a141.aspxhttp://www.neosgeo.com/global-programs/appalachian-neobasin.html


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L I

Nowhere to hide in Tioga CountyMulti-measurement imaging

reveals secrets of the elusive Marcellus

Thanks to unconventional drilling and

extraction techniques, the Appalachian

Basin has experienced a multi-billion dollar

economic resurgence. In Tioga County,

Pennsylvania, a methodology called Multi-

measurement Interpretation (MMI) has

been introduced by NEOS GeoSolutions to

provide a better understanding of the basin.

NEOS acquired airborne geophysical data

magnetic, electromagnetic (EM), radiometric,

gravity, and hyperspectral over 1,000

square miles of Tioga County. These data

were integrated with existing geophysical,

geochemical, and seismic measurements

from various public domain and third-

party sources and interpreted by NEOS and

operator geoscientists. This low-impact,

environmentally friendly approach revealed subsurface features from the basement to the surface, helping

explorationists pinpoint the sweet spots and avoid shallow gas geo-hazards in the play.

Using hyperspectral analysis, which classifies substances on the surface based on unique spectral signatures

associated with the reflectance and absorption of both visible and invisible light, interpreters located numerous

oil seeps and gas plumes. Of these, 90% were verified by geo-technicians on the ground. The seeps and plumes

were then traced back into the subsurface along various pathways, including faults that had been mapped using

an analysis of magnetic, seismic, log, and EM data.

Airborne EM resistivity measurements provided insights into both lateral and vertical resistivity variations

throughout the geologic column, down to roughly 10,000 feet. When the EM voxel was depth-sliced at the

Marcellus interval, geoscientists noted that resistive hot spots in the Marcellus corresponded to many of

the countys best well locations.

In addition to analyzing the airborne datasets, geoscientists on the project also incorporated more traditional

geophysical measurements into the interpretation. Well logs were analyzed to enhance structural control

and to calibrate the airborne EM data. Seismic data were incorporated into the regional structural model and, in

combination with the magnetic and EM data, provided insights into how faults were creating pathways for

hydrocarbons to migrate toward the surface.

Finally, a cutting-edge geostatistical technique called predictive analytics was applied. The technique allowed

geoscientists to mine all geo-datasets for subtle patterns and correlations that corresponded to the best wells,and to then pattern search for similar correlative attributes in areas that had yet to be drilled. This helped the

projects underwriters to optimize their leasing, drilling, and hydraulic fracturing programs and to target future

ground-based geophysical acquisitions in the most promising areas.

MMI has captured the attention of th e regions major E&P producers. Since the early surveys in Tioga, NEOS has

undertaken additional projects in Pennsylvania, compiling nearly 5,000 square miles of available regional data

that are delivering unique, cost-effective insights into the Marcellus and Utica shale plays.

To learn more about this project or others in the Unlock the Potential series, visit: www.ThePotentialUnlocked.com

Sweet spot map (zoom) over a roughly 200-square-mile area in Tioga

County, Pennsylvania. Hot colors indicate areas most similar to best

producing wells in the region. Circles are sized to the first six months of

production for all horizontal wells.

UNLOCK THE POTENTIAL IN YOUR FIELD | #1IN A SERIES FEBRUARY 2014

OilVoice

KEY TECHNOLOGIES:

MAGNETIC

PASSIVE-SOURCE EM

RADIOMETRIC

GRAVITY

HYPERSPECTRAL

PREDICTIVE ANALYTICS

AREA: Appalachian Basin, Pennsylvania

CUSTOMER: Supermajor

FOCUS:Regional Mapping

TYPE: Unconventional

KEY INTERPRETIVE PRODUCTS:

Regional resistivity voxels

down to 10,000 feet

Maps of lineaments, fault

networks, and intrusives

Maps of regional prospectivity

derived via predictive analytics

CUSTOMER BENEFITS:

Cost-effective regional insight depicting

the most (and least) prospective areas for

leasing, drilling, or further geological and

geophysical (G&G) study.

HIGHLIGHTS


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Why EIA, IEA, andRanders' 2052 energyforecasts are wrong

Written by Gail TverbergfromOur Finite World

What is correct way to model the future course of energy and the economy? Thereare clearly huge amounts of oil, coal, and natural gas in the ground. With differentapproaches, researchers can obtain vastly different indications. I will show that the

real issue is most researchers are modeling the wrong limit.

Most researchers assume that the limit that they should be concerned with is theamount of oil, coal, and natural gas in the ground. This is the wrong limit. While intheory we will eventually hit this limit, because of the way fossil fuels are integratedinto the rest of the economy, we hit financial limits much earlier. These financiallimits include lack of investment capital, inability of governments to collect enoughtaxes to fund their programs, and widespread debt defaults.

One of the things I show in this post is that Economic Growth is a positivefeedback loop that is enabled by cheap energy sources. (Economists have

postulated that Economic Growth is permanent, and has no connection to energysources.) Economic Growth turns to economic contraction as the cost of energyextraction (broadly defined) rises. It is the change in this feedback loop that leads tothe financial problems mentioned above. These effects tend to lead to collapse overa period of years (perhaps 10 or 20, we really dont know), rather than a slow declinewhich is easily mitigated.

If, indeed, most analysts are concerned about the wrong limit, this has hugeimplications for energy policy:

1. Climate change models include way too much CO2 from fossil fuels. Lack ofinvestment capital will bring down production of all fossil fuels in only a few years.The amounts of fossil fuels included in climate change models are based onDemand Model and Hubbert Peak Model estimates of fossil fuel consumption(described in this post), both of which tend to be far too high. This is not to say thatthe climate isnt changing, and wont continue to change. It is just that excessivefossil fuel consumption needs to move much farther down our list of problemscontributing to future climate change.

2. It becomes much less clear whether high-priced replacements for fossil fuels areworthwhile. In theory, they might allow a particular economy to have electricity for a

while longer after collapse, if the whole system can be kept properly repaired.Offsetting this potential benefit are several drawbacks: (a) they make the economy
http://www.oilvoice.com/description/Our_Finite_World/0ff628da.aspxhttp://www.oilvoice.com/description/Our_Finite_World/0ff628da.aspxhttp://www.oilvoice.com/description/Our_Finite_World/0ff628da.aspxhttp://www.oilvoice.com/description/Our_Finite_World/0ff628da.aspx


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with the high-priced replacements less competitive in the world marketplace, (b) theytend to run up debt, increase government spending, and decrease discretionaryincome of citizens, all limits we are reaching, and (c) they tend to push the economiccycle more quickly toward contraction for the country purchasing the high-pricedrenewables.

3. A large share of academic writing is premised on a wrong understanding ofthe real limits we are reaching.Since writers base their analyses on the wronganalyses of previous writers, this leads to a nearly endless supply of misleading orwrong academic papers.

This post is related to a recent post I wrote,The Real Oil Extraction Limit, and How ItAffects the Downslope.

Types of Forecasting Models

There are three basic ways of making forecasts regarding future energy supply andrelated economic growth:

1. Demand Based Approaches.In this method, the analyst first decides whatfuture GDP will be, and uses that estimate, together with past relationships, to workbackwards to figure out how much energy supply will be needed in the future. Theexpected needed future energy supply is then divided up among various types offuels, giving more of the growth to types that are favored, and less to other types.Very often, estimates of growth in energy efficiency, growth in renewables, andgrowth in the amount of GDP that can be generated with a given amount of energysupply are included in the model as well.

This method is by far the most common approach for forecasting expected futureenergy supply, especially at high levels of aggregation. One advantage of thismethod is that can provide almost any answer the analyst wants. Governments arepaying for reports such as the EIA and IEA forecasts, and oil companies are payingfor forecasts such as those byBP,Shell,andExxon-Mobil.Both governments and oilcompanies prefer reports that say that everything will be fine for the foreseeablefuture. Demand Based approaches are good for producing such reports.

Another advantage of this approach is that the analysts dont have to think about

pesky details like where all of the investment capital will come from, or how large animprovement in the ratio of GDP to energy consumption can actually occur. Theycan simply make assumptions and point out that the forecast wont come true if theassumptions dont hold.

2. Hubbert Peak Model.This model is based on an interpretation of what M. KingHubbert wrote (for example,Nuclear Energy and the Fossil Fuels,1956) . The basicpremise of this model is that future supply of oil, coal, or gas will tend to drop slowlyafter 50% (or somewhat more) of the fuel supply potentially available with currenttechnology has been extracted.

In fact, we dont really know how much oil or coal or natural gas will be extracted inthe futurewe just know how much looks like it might be extracted, if everything goes
http://ourfiniteworld.com/2013/12/18/th-real-oil-extraction-limit-and-how-it-affects-the-downslope/http://ourfiniteworld.com/2013/12/18/th-real-oil-extraction-limit-and-how-it-affects-the-downslope/http://ourfiniteworld.com/2013/12/18/th-real-oil-extraction-limit-and-how-it-affects-the-downslope/http://ourfiniteworld.com/2013/12/18/th-real-oil-extraction-limit-and-how-it-affects-the-downslope/http://www.bp.com/content/dam/bp/pdf/statistical-review/BP_World_Energy_Outlook_booklet_2013.pdfhttp://www.bp.com/content/dam/bp/pdf/statistical-review/BP_World_Energy_Outlook_booklet_2013.pdfhttp://www.bp.com/content/dam/bp/pdf/statistical-review/BP_World_Energy_Outlook_booklet_2013.pdfhttp://www.shell.com/global/future-energy/scenarios.htmlhttp://www.shell.com/global/future-energy/scenarios.htmlhttp://www.shell.com/global/future-energy/scenarios.htmlhttp://corporate.exxonmobil.com/en/energy/energy-outlookhttp://corporate.exxonmobil.com/en/energy/energy-outlookhttp://corporate.exxonmobil.com/en/energy/energy-outlookhttp://www.hubbertpeak.com/hubbert/1956/1956.pdfhttp://www.hubbertpeak.com/hubbert/1956/1956.pdfhttp://www.hubbertpeak.com/hubbert/1956/1956.pdfhttp://www.hubbertpeak.com/hubbert/1956/1956.pdfhttp://corporate.exxonmobil.com/en/energy/energy-outlookhttp://www.shell.com/global/future-energy/scenarios.htmlhttp://www.bp.com/content/dam/bp/pdf/statistical-review/BP_World_Energy_Outlook_booklet_2013.pdfhttp://ourfiniteworld.com/2013/12/18/th-real-oil-extraction-limit-and-how-it-affects-the-downslope/http://ourfiniteworld.com/2013/12/18/th-real-oil-extraction-limit-and-how-it-affects-the-downslope/


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wellif there is plenty of investment capital, if the credit system works as planned,and if the government is able to collect enough tax revenue to fund all of itspromises, including maintaining roads and offering benefits to the unemployed.

What most people miss is the fact that the world economy is aComplex Adaptive

System,and energy supply is part of this system. If there are diminishing returns withrespect to energy supplyevidenced by the rising cost of extraction and distributionthen this will affect the economy in many ways simultaneously. The limit we arereaching is not that oil (or coal or natural gas) extraction will run out; it is thateconomic system will at some point seize up, and rapidly contract. The HubbertPeak Method shows how much fuel might be extracted in each future year if theeconomy doesnt seize up because of financial problems. The estimate produced bythe Hubbert Peak Method removes some of the upward bias of the Demand Modelapproach, but it still tends to give forecasts that are higher than we can really expect.

3. Modeling How the Economy Actually Works.This approach is much more

labor-intensive than the other two approaches, but is the only one that can beexpected to give an answer that is in the right ballpark of being correct with respectto future economic growth and energy consumption. Of course, observing signs ofoncoming collapse can also give an indication that we are nearing collapse.

The only study to date modeling how long the economy can grow without seizing upis the one documented in the 1972 bookThe Limits to Growth,by D. Meadows et al.This analysis has proven to be surprisingly predictive. Several analyses, includingthis one by Charles Hall and John Day,have shown that the world economy is fairlyclose to on track with the base scenario shown in that book (Figure 1). If the worldeconomy continues to follow this course shown, collapse would appear to be notmore than 10 or 20 years away, as can be seen from Figure 1, below.

Figure 1.Base scenariofrom 1972 Limits toGrowth, printed usingtodays graphics byCharles Hall and John Dayin Revisiting Limits toGrowth After Peak Oilhttp://www.esf.edu/efb/hall/

2009-05Hall0327.pdf
http://en.wikipedia.org/wiki/Complex_adaptive_systemhttp://en.wikipedia.org/wiki/Complex_adaptive_systemhttp://en.wikipedia.org/wiki/Complex_adaptive_systemhttp://en.wikipedia.org/wiki/Complex_adaptive_systemhttp://www.amazon.com/Limits-Growth-Donella-H-Meadows/dp/0451057678http://www.amazon.com/Limits-Growth-Donella-H-Meadows/dp/0451057678http://www.amazon.com/Limits-Growth-Donella-H-Meadows/dp/0451057678http://www.esf.edu/efb/hall/2009-05Hall0327.pdfhttp://www.esf.edu/efb/hall/2009-05Hall0327.pdfhttp://www.esf.edu/efb/hall/2009-05Hall0327.pdfhttp://www.esf.edu/efb/hall/2009-05Hall0327.pdfhttp://www.esf.edu/efb/hall/2009-05Hall0327.pdfhttp://www.esf.edu/efb/hall/2009-05Hall0327.pdfhttp://www.esf.edu/efb/hall/2009-05Hall0327.pdfhttp://www.esf.edu/efb/hall/2009-05Hall0327.pdfhttp://www.amazon.com/Limits-Growth-Donella-H-Meadows/dp/0451057678http://en.wikipedia.org/wiki/Complex_adaptive_systemhttp://en.wikipedia.org/wiki/Complex_adaptive_system


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One of the findings of the 1972 Limits to Growth analysis is that lack of investmentcapital is expected to be a significant part of what brings the system down.(There are other issues as well, including excessive pollution and ultimately lack offood.) According to the book (p. 125):

The industrial capital stock grows to a level that requires an enormous input ofresources. In the very process of that growth it depletes a large fraction of theresource reserves available. As resource prices rise and mines are depleted, moreand more capital must be used for obtaining resources, leaving less to be investedfor future growth. Finally investment cannot keep up with depreciation, and theindustrial base collapses, taking with it the service and agricultural systems, whichhave become dependent on industrial inputs (such as fertilizers, pesticides, hospitallaboratories, computers, and especially energy for mechanization).

Jorgen Randers2052: A Global Forecast for the Next Forty Years

In 2012, the same organization that sponsored the original Limits to Growth studysponsored a new study, commemorating the 40th anniversary of the original report.A person might expect that the new study would follow similar or updatedmethodology to the 1972 report, but the approach is in fact quite different. (See mypost,Why I Dont Believe Randers Limits to Growth Forecast to2052.)

The model in Jorgen Randers 2052: A Global Forecast for the Next FortyYearsappears to be a Demand Based approach that perhaps uses a Hubbert PeakModel on the fossil fuel portion of the analysis. One telling detail is the fact thatRanders mentions in the Acknowledgements Section only one person who workedon the model (apart from himself). There he thanks My old friend Ulrich Goluke, forcreating the quantitative foundation (statistical data, spreadsheets, and othermodels) for this forecast.Ulrich Golukes biographysuggests that he is able toprepare a Demand Model spreadsheet. It would be hard to believe that he that hecould have substituted for the team of 17 researchers who put together the originalLimits to Growth analysis.

The Need to Add to the Original Limits to Growth Analysis

The original Limits to Growth analysis was primarily concerned with quantities ofitems such as resources, pollution, population, and food. It did not get into financial

aspects to any significant extent, except where flows of resources indicated aproblemnamely in providing investment capital. One thing the model did not includeat all was debt.

In the sections that follow, I show a model of how some parts of the economy thatwerent specifically modeled in the 1972 study work. If the economy works in the waydescribed, it gives some insights as to why collapse may be ahead.

Economic Growth Arises from a Favorable Feedback Loop

Economic growth seems to arise from a favorable feedback loop, as shown in Figure

2, on the next page.
http://www.amazon.com/2052-Global-Forecast-Forty-Years/dp/1603584218http://www.amazon.com/2052-Global-Forecast-Forty-Years/dp/1603584218http://www.amazon.com/2052-Global-Forecast-Forty-Years/dp/1603584218http://ourfiniteworld.com/2013/09/25/why-i-dont-believe-randers-limits-to-growth-forecast-to-2052/http://ourfiniteworld.com/2013/09/25/why-i-dont-believe-randers-limits-to-growth-forecast-to-2052/http://ourfiniteworld.com/2013/09/25/why-i-dont-believe-randers-limits-to-growth-forecast-to-2052/http://ourfiniteworld.com/2013/09/25/why-i-dont-believe-randers-limits-to-growth-forecast-to-2052/http://www.blue-way.net/who-uu.php?lang=2http://www.blue-way.net/who-uu.php?lang=2http://www.blue-way.net/who-uu.php?lang=2http://www.blue-way.net/who-uu.php?lang=2http://ourfiniteworld.com/2013/09/25/why-i-dont-believe-randers-limits-to-growth-forecast-to-2052/http://www.amazon.com/2052-Global-Forecast-Forty-Years/dp/1603584218


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Figure 2.Authors representation of how economic growth occurs in todayseconomy.

This model above is intended to reflect the situation from, say, 1800 to 2000. Thesituation was somewhat different before the use of fossil fuels, when far lesseconomic growth took place. Furthermore, as we will see later in this post, the modelchanges again to reflect the impact of diminishing returns as the cost of energy

production increases in recent years and in the future.

The critical variables that allow economic growth to take place are (1) cheap energyavailable from the ground, such as coal, oil, or natural gasif cheap renewables wereavailable, these would work as well (2) technology that allows us to put this cheapenergy to work to make goods and services, and (3) a way to pay for the new goodsand services.

Debt. In this model, debt plays a significant role. This happens because fossilfuels allow a huge step up in the quality of goods and services, and debt provides away to bridge this gap. For example, with fossil fuels, we have electric light bulbs,metal machines in factories, and farm machinery, all of which vastly improveefficiency. The ability to pay for the new fuel and the new devices using the fuel, ismuch greater after the new devices using the fuel are put in place. The way aroundthis problem is simple: debt.

The use of debt becomes important at many points in the economy. Increased debtcan theoretically help (a) the companies doing the energy extraction, (b) thecompanies building factories to create the new goods and services, and (c) the endconsumers, since all of these benefit greatly from the services that cheap fossil fuelsprovide, and can better pay afterward than before.

Government debt, such as debt used to finance World War II, can also be used tostart and maintain the cycle. John Maynard Keynes noticed this phenomenon, and


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recommended using an increase in government debt to stimulate the economy, if itwas not growing adequately. The detail he was unaware of is the fact that the debtonly works in the context of cheap energy supplies being available to make use ofthis debt, enabling growth.

How the Feedback Loop Works. The loop starts with the combination of a cheap-to-exploit energy resource, technology that would use this resource, and debt thatallows those would like to gain access to the resources to have the benefit of them,before they are actually able to pay cash for them.

This combination allows goods to be produced which initially may not be very cheap.Over time, new methods are tried, allowing technology to improve. Consumers areable to buy increasing amounts of goods and services, both because of their ownincreased productivity (enabled by fossil fuels and new technology) tends to raisetheir wages, and because the improving technology lowers the cost of goods.Government services are expanded as tax revenue per capita increases.

Infrastructure such as roads are expanded making the economy more efficient.

In this context, profits of companies grow, allowing reinvestment. Investment is alsoenabled by increasing debt. This allows the cycle to start over again, with bettertechnology and more infrastructure in place. The economy tends to grow, and thestandard of living tends to rise.

Overview. One way of explaining the tendency toward economic growth is that acheap-to-extract fossil rule has an extremely high return on investment. This veryhigh return enables benefits to all: workers receive higher wages; businesses receivehigher profits; and governments receive both higher tax revenue and the ability tobuild new roads and other infrastructure cheaply.

Another way of describing the tendency toward economic growth is to say that thevalue to society of the (cheap) energy product is far greater than its cost ofextraction. This difference provides a benefit which flows through to many parts ofthe economy. Economists do not recognize that this situation can happen, but itseems to be a major source of economic growth.

The Spoiler: Diminishing Returns

The problem with energy extraction is that we extract the inexpensive-to-extractenergy sources first. Eventually these sources get depleted, and we need to moveon to more expensive-to-extract energy sources. I illustrate this situation with atriangle that has a dotted line at the bottom.

Figure 3.Resource triangle, with dotted line indicatinguncertain financial cut-off.


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Businesses start by extracting the cheapest to extract resources, found at the top ofthe triangle. As these resources deplete, they move on to the more expensive toextract resources, further down in the triangle. Looking downward, it always lookslike there are more resources availableit is just that they are more expensive toextract. This is why reported reserves tend to increase over time, even as supplies

are depleted. The limit is a financial limit, illustrated by a dotted line, which is whyvirtually no one can figure out when the limit will actually arrive.

One somewhat minor point: When I say, Cheapest to extract resources, I amreferring to broadly defined costs. What businesses want is resources that producegoods and services most cheaply for the consumer. Thus, they are really concernedabout cheapest total cost, considering the entire chain that goes all the way to theconsumer, including refining and transportation. The costs would include energyused in extraction, labor costs, transportation costs, taxes, and the cost of debt. Itprobably should include the cost of mitigating pollution effects as well.

A major problem is that as the cost of energy extraction grows, the favorable gapbetween the cost of extraction and the benefit to society (as mentioned in theprevious section) shrinks. There are many ways that this problem manifests itself inthe economy. Figure 4 shows a list of such problem with respect to higher oil prices:

Figure 4.Image by author listing some of the problems created by rising oil prices.

One indirect impact of these issues is that there are more layoffs and fewer new jobopportunities. If we calculate average wages by taking (total US wages) and dividingby (total US population), we see that during periods of high oil prices, wages tend notto grow, as they had in periods when oil prices were lowerjust as we would expect(Figure 5, next page).


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Figure 5.Average US wages compared to oil price, both in 2012$. US Wages arefrom Bureau of Labor Statistics Table 2.1, adjusted to 2012 using CPI-Urbaninflation. Oil prices are Brent equivalent in 2012$, from BPs 2013 Statistical Reviewof World Energy.

Another issue is that it is not just the price of oil that rises. The price of natural gasrises as well. We have not felt this in the United States, because demand has kept

the price down below the price of shale gas extraction. The cost of coal, delivered toits destination, has risen because transport uses oil, and transport costs are asignificant share of total costs. The cost of base metals has also risen since 2002,because oil is used in metal extraction. Food prices in general have tended to rise aswell, because oil is used in production and transport of food. When wages are closeto flat, and the cost of many goods are rising, workers find that their paychecks areincreasingly squeezed.

While costs of making goods in the US are rising, and paychecks are stagnating, anincreasing amount of goods are imported from areas around the world where energycosts and wage costs are lower. This helps keep the cost of consumer goods down,

but it makes the problem of lack of jobs for US workers worse.

With all of these things happening, the government has more and more problemswith its funding. Expenditures continue to rise, but taxes flatten, as the governmenttries to help the economy grow by not raising taxes to match expenditures (Figure 5,on the next page).


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Figure 6.Based on Table 2.1 and Table 3.1 of Bureau of Economic Analysis data.Government spending includes Federal, State, and Local programs.

Government expenditures can be thought of as expenditures out of the surpluses ofthe economy. As indicated previously, these are to a significant extent possiblebecause of the favorable difference between the cost of extracting fossil fuels andthe benefit those fossil fuels provide to the economy. As the use of fossil fuels has

grown over the years, these government services have grown. In recent years, thepresence of more unemployed workers has driven a need for more governmentservices.

Since the early 2000s, government revenues have flattened. The lack of revenue,together with the ever-rising government spending, is what is driving continued bigdeficits. The danger is that this difference cannot be fixed, without huge cuts toprograms that people are depending on, like unemployment insurance, SocialSecurity and Medicare.

How the Economic Growth Loop Changes to Contraction

In my view, what causes a shift to contraction is a shift to higher energy costs. Withhigher energy costs, there is less surplus between the cost of extraction (broadlydefined) and the benefit to society. Because of the smaller surplus, the parts of theeconomy that use this surplus, such as government spending, must shrink.


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Figure 7.Higher energy cost leads to unfavorable feedback loop. (Illustration byauthor.)

We gradually find that all the great things we had learned to enjoyinexpensiveroads and other infrastructure, cheap goods, rising wages, and rising government

servesstart going away. We increasingly find consumers maxed out on debt. Wealso find companies (especially energy companies) reporting lower profits, so theyhave more trouble investing in new energy extraction. The government cannotcollect enough taxes for all of its services, so finds itself needing to keep raising itsown debt levels.

The government can kind of paper over its difficulties with growing debt levels for awhile, by using Quantitative Easing (QE). QE has the effect of making the interestthe US must pay on its own debt lower. It makes the cost of business investment innew plants and equipment (including shale oil drilling) cheaper. It also helps stretchthe incomes of increasingly impoverished workers by allowing monthly payments on

homes and cars to be lower than they would otherwise would be.

The Party Ends With a Thud

Most readers can deduce that a shift from a growing economy to a shrinkingeconomy is not a pleasant situation. It has all of the makings of collapse.

One of the big problems is debt defaults, as it becomes increasingly impossible torepay debt with interest. This creates conflict between borrowers and lenders. Debtdefaults are also likely to cause huge problems for banks, insurance companies, andpension plans, because of the impact on their balance sheets. Some institutions mayclose.


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To the extent new credit is cut off, the lack of credit cuts off new investment inenergy extraction, in buying new cars and trucks, and in almost everything else.Such a cut-off in credit is likely to increase job layoffs and to lead to yet moredefaults. Lack of investment in new energy extraction causes oil supply to fallquicklyfar more quickly than standard decline models would suggest.

Businesses that in the past found that they could benefit from economies of scaleas they grew find that fixed costs stay the same, even as sales shrink. This meansthat they either need to raise prices to cover their higher per-unit costs, or losemoney.

Governments find that they need to cut government services to balance theirbudgets. Discontent grows among citizens as those who lose their benefits becomevery unhappy. Discord grows among political parties, because no one can agreehow to cut programs equitably.

We dont know how this will end, but we do know that the Former Soviet Unioncollapsed into its constituent parts when fossil fuel surpluses were reduced, prior to1991. Egypt and Syria both have had civil unrest as their oil exports ended. Clearlyvery large government changes are possible, as surpluses disappear.

This list of potential impacts could be expanded endlessly, but I will spare readersfrom a more comprehensive list.

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22/45


Shell profit warning -the shock that wasn't

Written by Andrew McKillopfromAMK CONSULT

Shell's new CEO Ben van Beurden has admitted corporate performance in 2013 wasnot what he expected from the group. Just two weeks after taking over the helm atend-December, he gave what journalists and commentators called 'a shock profitwarning', saying that full-year profits excluding 'special items' could be about 25%below 2012's performance. For the 4th Quarter of 2013 Shell's earnings beforespecial items fell by about 50%.

In a mix and mingle of rational and strange explanations, while distancing himself asthe 'New Man' from what happened under previous CEO Peter Voser, the new CEOfirstly blamed lower oil and gas prices, which for oil is a strange claim. He went on towiden his claims by saying that Shell is exposed to "weak industry conditions" indownstream oil, unexpected costs in its drive to become the most natural gas-oriented of the oil majors, higher exploration and infrastructure expenses, highercorporate risks, especially in Iraq, and lower upstream production volumes.

The group's third- and fourth-quarter 2013 earnings figures were badly hit by a 3Q

49% drop in downstream profits, blamed on adverse refining conditions, both inNorth America but especially in Europe, due to structural refining overcapacity andweak energy demand. Van Beurden also cited the huge upstream asset writedownsmade in 2013. Shell was quickly accused by some analysts of 'kitchen sinking', thatis rushing to pump out the bad news, hoping investors will think the worst is over andpast. Van Beurden said these special items ran at $700m for 4Q 2013, and at $2.7bnfor the full year. When these massive writedowns, which will continue through 2014are included in 2013 corporate figures, fourth-quarter earnings will be about 70%lower than one year before. Full year 2013 earnings, at about $16.75bn will be downby around 38% compared with 2012.

Despite Shell issuing its first-ever profits warning in more than 10 years, next daytrading on 17 January only clipped its share price by about 3%. This was in part dueto van Beurden's frequent references to his drive for 'better capital efficiency', whichfor analysts and major investors has to mean Shell will cut back on its runawaycapex (capital expenditure) program. This spending in 2013 racked up a total of$44bn, compared with total corporate turnover of $40.3bn.

Shell and the Gas Bubble

In early November 2012 at London's Royal Institution, outgoing CEO Voserhammered the 'go for gas' strategy Shell has pursued since the 1990s. He argued

that Shell - as an integrated energy major - is creating value from the wholeproduction supply chain, and the corporation sets gas growth as the jewel in the
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crown. He defended the gas strategy with the argument that sustained investmentthrough the implied oil-gas value cycle is what shareholders want, not a stop-startstrategy. Voser also repeated the corporate conviction that investment in gasexploration, production, processing and supply were '30-year assets', and Shell wasnot in the business of chasing 'short-term volume targets or market share'.

From before Voser's time as CEO, and almost certainly through new CEO vanBeuren's watch, Shell has a few fixed or recurring corporate traumas, starting withthe fear Europe will be left behind in the global dash for gas, becoming a continentcompletely reliant on volatile imports, while the rest of the world races towards gasself-sufficiency. Shell strategists believe Europe's decreasing domestic gasproduction is structural - due to policy if not geology - and the continent now has astark choice between importing more gas or allowing shale gas to be developed.

In his early November presentation to London's Royal Society, ex-CEO Voserrepeated another fixed belief of Shell's corporate strategists. They imagine gas

demand is growing so fast in Europe the continent may be left behind for signing upa share of future gas production among the worldwide flurry of new stranded gasfinds and shale gas development.

Voser was simply talking about reality when he signalled the massive rate of globalgas finds, and extended reserve revisions as gas E&P progresses, with huge finds orreserve extensions since 2009 in countries as wide ranging as Mozambique,Tanzania, Azerbaijan, Iraq, Australia, Qatar, Iran, Brazil and elsewhere. But his claimthat European gas demand is on a tear is light years from reality. European gasdemand is falling. Growth potential for gas in Europe is at best modest.

Worse still for Shell, global gas demand growth has repeatedly failed its majoreconomic challenge - that is the expectation, or gas producers' hope thatconsumption will increase despite slowing economic growth, reduced industrialoutput and outplacement, cheap coal supplies, the renewables, energy saving, andseveral other demand-trimming factors. Gas failed this challenge. Teflon-style growthof global gas demand is no longer the case, even if it held previously.Shell's corporate policy statements and reviews on its dash for gas are now at best'forward looking statements', based on the energy world before at latest 2012.Investors may want to more carefully scrutinize these assertions and claims, today.

Two specific gas sectors are easily identified as creating the most serious challengesfor Shell on the downstream side, GTL or gas to liquids conversion, and gas-firedpower production in a few large markets, especially Europe and Japan. On theupstream side, as partly-admitted by van Beuren, the scramble for gas drillingacreages, and the following serial increase of development costs often generatingveritable capex explosions, and nearly always stretched completion schedules whichsometimes double the number of years needed, has made many attractive prospectsturn very sour.

Divest and Survive

Runaway capex, stretched project schedules, declining or stagnant oil and gasmarket outlooks, and increasing country risk in key operating countries are among


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the reasons Shell has been forced into a very active divestment program. It isestimated by some analysts as possibly running to 30 billion dollars through 2012-2015.

Official divestment goals as announced by new CEO van Beuren are for sales of

assets able to raise $15 billion over 2 years. Already known to some journalists andanalysts, this will inevitably target 'mature upstream assets', especially in the nowcapex-intensive 'drilled out' North Sea and a large slice of Shell's refining portfolio inEurope and the US. Some of this concerns non-performing assets which are likely tostay that way, unless huge new capex is thrown at the problem.

More important for Shell's gas strategy, corporate triage will winnow out alengthening list of projects moving up the investment decision ladder, that are nowconsidered too risky or overpriced - at the same time as corporate spokespersonshave said there is no question of Shell reducing its goal of $130 bn of capexspending through 2012-2015. Project triage, due to the urgency of reducing Shell's

runaway spending profile, may well extend from project types with a probablecontinuation of Shell's retreat from refining and oil production, to a complete retreatfrom selected large geographic regions. Analysts suggest the first to be abandonedby Shell may be Australia and West Africa, particularly Nigeria. But a near-totalretreat from the North Sea production and European refining is also not impossible.

Contradicting corporate confidence in a shining near-term future for gas, Shell is alsocutting back its US shale gas operations. It said in September that it was selling itsacreages and production shares in the large Eagle Ford and smaller MississippiLime shale zones. The corporation has also shelved or delayed prospectiveagreements for LNG gas transport and terminals development with US, Canadianand international energy partners.

Corporate capex triage, in part due to unexpectedly long project developmentschedules and high costs in the gas sector, has focused Shell to higher risk projectsoffering higher possible returns. These particularly concern Iraq, where Shell isfocusing oil, gas and petrochemicals development.

In mid-November, ex-CEO Voser announced that Shell and the Iraqi governmentwere close to cementing a deal to build an $11 billion petrochemical complex namedNebras in southern Iraq in what will be biggest move by Shell in Iraq's energy sector.

The project inevitably carries large and increasing country risk. The Nebras projectmay be used by the Nouri al-Maliki government in Baghdad as a bargaining chip inthe lengthening number of disputes that it has with Shell, and the other majorsoperating in Iraq on revenue sharing, production increases, infrastructure spendingand other issues. .

The Shock that Was Not A Surprise

Shell cannot be wrongfooted for its corporate conviction that global gas had to grow.Among the oil majors, it is now the most gas-intensive producer and has global

reach in gas reserves, transport and downstream assets, and value-add throughgas-based petrochemicals. Shell is also a world leader in GTL (gas to liquids)


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conversion. Its Malaysian Bintula plant, opened in 1993, is a model for thisconversion technology, now upstaged by the Shell-Qatar joint venture Pearl GTLproject, the biggest GTL producer in the world.

This can be called the good news. Its Bintula GTL plant, for which simply repairs to a

major accident in 1997 cost about $1 billion, produces about 17 000 barrels a day ofa range of fuel and nonfuel liquids, pricing this technology into a special costdimension utterly dependent on almost-free natural gas for breakeven. The sameapplies to the Pearl GTL venture. If the gas is free, GTL works.

As Shell has found, literally to its cost, LNG ventures have a troubling habit ofmassive cost overruns and stretched completion schedules. Reasons why thecorporation may wind down and divest its Australian production operations aresummarized by the three-letter word LNG.

Among non-American oil majors, Shell was fast off the block in moving into US shale

gas production, but as Exxon Mobil through its gas subsidiary XTO Energy, as wellas the USA's biggest gas producer Chesapeake Corp quickly found, along with otherproducers like Shell, the US shale bonanza can leave a lot of red on companybalance sheets. Overall, US gas is too cheap, but Royal Dutch Shell can do nothingabout it.

Shell's capex spending spree sprang from a pre-2012 optimistic look at world energyto 2020, in which gas 'had to grow', which it will but at a slower rate, and not in theway Shell hoped. Corporate project planning and management also suffered fromthe worst kinds of over-optimism, as one example resulting in Shell's new and riskybet on Iraq, which by supreme irony has made strident demands for Shell to increaseits gas production in the country!

Perhaps not surprising for an oil major with a European HQ, Shell's focus on Europehas repeatedly produced over-optimistic and irrational corporate forecasts of energydemand recovery in Europe, led by gas, followed by project decisions on thatwrongheaded basis. Corporate reading of Europe's energy transition plans believedfirstly that emissions trading would hold up giving an edge to gas-fired powerproduction, and that European refining infrastructures would get major and sustainedEU and member state support for critically needed makeovers and restructuring.None of this happened in the real world.

Shell's supposedly 'shocking' admission its profits will be low for several years -many analysts cite 2017 as the year when the 'annus horribilis' will end - cannot betreated as surprising. This was above all a disaster waiting to happen, and ithappened.

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27/45


Total's investment is abig step for the futureof UK shale - But don'tget too excited just yet

Written by Mark YoungfromEvaluate Energy

On January 13th, 2014, French company Total confirmed that it had become the firstglobal oil and gas major to invest in the burgeoning UK shale gas industry. This is ahuge early milestone for the sector to have achieved, but Evaluate Energy arguesthat whilst this does bring the UK closer to widespread domestic onshore gasproduction, it will still be a long time before even thepossibilityof this becomes areality.

Of course, Totals investment is rightly going to be seen as a huge vote ofconfidence into the sector, and the smaller UK shale companies will no doubt berubbing their hands with glee at such an oil and gas powerhouse coming to their aid.Total will be investing a total of US$46.5 million on 2 exploration wells and pad

construction to earn a 40% interest in 2 onshore licenses, joining Dart Energy, IGasand others in the quest to prove the commerciality of shale gas exploitation at thesesites. These costs show just how imperative it was for small companies like Dart andIGas to get a partner like Total involved, as there are not many companies in theworld that could afford such an outlay on an unproven sector. Total has an optiontola exit after the first vertical well, but its partners will need Total to stick around, ifthe well costs in the US are anything to go by.

Shale gas exploration is not cheap work. Shale gas short history has so far shownthat it takes plays many years of production before costs fall into line with those ofmore conventional plays. Two examples of these mature plays are the Barnett in

Texas, where a typical well will be costing Quicksilver Resources (NYSE:KWK)around US$3 million in 2014 according to the companys December 2013 investorpresentation, and the Fayetteville in Arkansas, where In its own Decemberpresentation, Southwestern Energy (NYSE:SWN) states it will only be spendingUS$2.3 million on each well in 2014. But these are shale plays that are mature interms of the development work being done, so a look at one of the newer gas playsin the US will give a better idea of the costs to be experienced in the UK; the Uticaplay in Ohio is a good point of reference. Last year, approximately 2 years into theUticas development history, Gulfport Energy (NASDAQ:GPOR) budgeted for a costof US$9.2 million per well, Halcn Resources (NYSE:HK) budgeted for US$9.5million, and CONSOL Energys (NYSE:CNX) costs were just under US$15 million, to

give some company-specific examples. This is approximately 2 years into theexploration stage of the play, and the average monthly rig count has been above 20
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since May 2012, according to data from the EIA. If you assume one well per monthbeing drilled by each rig, that would equate to hundreds of wells being drilled on theplay in just over 18 months, and the well costs are still up at around US$10 million onaverage. Total has agreed to fund the drilling of 2 wells in the UK, so the UK still hasan extremely long way to go before costs come down and the need for the presence

an oil and gas major in the sector ends.

The profitability of UK shale gas will not be hampered as much by gas prices as theUS has been, as prices in the UK are higher. So, assuming the high costs do not putTotal off, the next step will be increasing production to the point where it fulfils thegovernments promises over the last few months. Many figures have been cited inthe press from various sources about percentages of UK gas demand that shale gascan satisfy and for how long, but for this we will just stick to a statement by EdDavey, the UK Secretary of State, for Energy and Climate Change, when he said ina speech concerning potential shale gas exploration back in September 2013 thatthe UK is expecting to have to import 70% of its gas needs by 2025, as he predicts

North Sea gas production will have lowered to around 19 million cubic metres perday by 2030. His speech suggests the UK will eventually be looking to get back to itsnet exporter status of 2003, and that shale gas is the answer. So we have to assumethe plan is to, in fact, not import 70% of our gas needs, but produce it from the shaleplay. In 2012, the UKs natural gas consumption was 7,554 million cubic feet per day(mmcf/d) according to BP. If we were to make even the simple assumption thatconsumption was to remain constant until 2025, shale gas would need to provide atleast 5,288 mmcf/d of natural gas. Another look to EIAs data for the US tells us thatthe gigantic Marcellus play (200 times bigger than the UKs play according to Davey)in the Appalachian basin took around 4-5 years of widespread exploration anddevelopment work to reach this level of production in mid-2011, and the average rigcount was over 100 for 2010 and 2011.

This level of activity, i.e. the hundreds of wells needed, is something that is currentlyunimaginable in the UK. The government has released details of more incentives forlocal authorities to issue more shale permits; it will be allowing local authorities torecoup 100% of the business rates of these operations instead of the usual 50%. Butthis will do nothing to stop the environmental activism juggernaut that has plagued

shale gas fracking operations across Europe so far. The UKs only real frackingoperation to date was carried out by private company Cuadrilla Resources, who

Source:Evaluate Energyviathe EIA & BPs StatisticalReview 2013.
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began its own exploration work with one rig to drill one well in Balcombe, WestSussex in mid-2013. Its initial work at the site about a year earlier caused a minorearthquake and began to ring alarm bells for environmental activists across thecountry, and when the company tried to begin fresh work on the site last year, it wasmet with angry protests that lasted for the duration of its stay. The company had to

postpone its work for a few days on the health and safety advice of police due to thenature of the protests, and according to commentators made little effort, or at leastlittle effort that was successful, to assuage the concerns of the protestors at the siteand convince them that its fracking operation was in fact safe and the protest wasunnecessary. This undoubtedly added to the heated nature of the protest, andpublicly-listed companies like the ones Total has invested with will no doubt makemore of an effort to engage with the public about its operations, but it is hard toignore how much of a debacle the drilling of one well has caused. If shale plays needhundreds of wells to start to reach their potential, as operations in the US haveproved, then can the UK really consider any of its shale gas targets realistic with thislevel of widespread public animosity?

The need to import 70% of our gas needs in 2025 is a large financial burden, shalegas could or should play a part in alleviating the pressure, and the involvement of anexperienced, world-renowned and wealthy company is necessary for any of this tohappen. But while the deal with Total is a big step, and should be celebrated assuch, the UK government and the companies involved have at least two more evenbigger steps to take before UK shale gas can be successful. Firstly, public opinionneeds to be dealt with to a point where the operations are at least accepted by amuch wider audience. Secondly, intensive, expensive drilling work needs to takeplace over many years, as well as finding the space in the small, densely-populatedUK to conduct such operations. Totals involvement is definitely a good thing for theUK gas industry, but its only the beginning of a very long and bumpy road, and thereis still no guarantee the UK will make it to the end of it.

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Insight: a small blackcloud?

Written by David BamfordfromFinding Petroleum

What should we make of this, arecent articlediscussing the forward projections of anumber of seismic companies?

They (TGS, PGS, Spectrum, CGG etc) all seem very nervous suddenly: the articlepoints to reducing capex and improving margins but I wonder of oil & gas companiesare getting nervous about big, expensive dry holes in deep water?

Or perhaps their investors are more generally nervous about investment inexploration? As opposed perhaps to putting their money in Tesco, Sainsburys,House of Fraser, Amazon etc!

Why would that be?

Well, we have to admit that explorers have not exactly covered themselves in gloryover the last couple of years..

1. 'Mature' NW Europe, whether in the North Sea or onshore, has had a dismalexploration record.2. There have been several high profile failures in new 'Frontier' basins, for

example offshore French Guiana, Brazil, Namibia3. The costs of offshore, especially deep water, drilling have 'gone through the

roof'.4. Development projects - of those discoveries that have been made - are

increasingly seen as being behind schedule, overrunning budgets and notdelivering the promised production.

Perhaps investors see the queues at supermarket and department store checkouts,

and the scale of one of Amazon's warehouses, as providing better eveidence andbetter places to invest? Are we at a nodal point - one of those moments that inhindsight will be seen as the beginning of a cyclical downturn in the explorationbusiness and therefore in the fortunes of seismic companies?

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Oil & gas M&A reachesUS$143 billion in 2013

Written by Eoin CoynefromEvaluate Energy

Rising F&D costs cause a drop in M&A activity from 2012

The year 2012 was colossal for mergers and acquisitions in the upstream oil and gasindustry. Total volume reached a record $236 billion, an amount 54% up on 2011and with seemingly few shocks in the macro environment, one could have beenforgiven for assuming that 2013 was going to follow in the same vein. This, however,

has not been the case, with the first half of the year producing just $49 billion ofdeals and, despite a late flurry in the second half of the year, 2013 ended with $143billion of global upstream deals, a total that is 39% down from last year.

Global E&P Deal Value 2012-13

The number one driver of confidence and therefore investment in the oil and gas

E&P sector is the current and anticipated price of oil, followed to a lesser extent bythe price of gas, both of which have changed very little since 2012 and do notexplain the fall in M&A activity in 2013. The WTI benchmark price averaged $98 perbarrel in 2013 versus $94 in 2012 and the Brent benchmark averaged $108 perbarrel in 2013 versus $111 in 2012. In terms of gas prices, the US has even seen anincrease in the Henry Hub benchmark ($3.71 per mcf versus $2.75 in 2012) whilstgas prices in the rest of the world outside of North America have remained robust,judging by company reported gas price realizations. The economic performance ofkey countries also fails to explain the subdued level of activity, with China meeting allof its growth targets during the year, Europe faring better as a whole than in 2012and the US economic recovery resulting in its stock markets reaching record highs in

December of 2013.

Source:Evaluate EnergyM&ADatabase
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The real reason for the drop in industry M&A is one that hasntattracted the samelevel of headlines as unrest in the Middle East, offshore oil spills or Arctic drilling, yetits doing more damage to the prosperity of E&P companies; the cost of finding,developing and extracting oil for public oil companies is steadily increasing. A recentstudy by Evaluate Energy looked at the historic financial and operating results of 52

large cap companies and concluded that the full cycle cost required to sustainablyproduce a barrel of crude oil surpassed $85 in 2012, which is 87% higher than the$45 required in 2008. This has had a negative effect on M&A investment in threeways. Firstly, the earnings of E&P companies have dropped in tandem with risingcosts (cumulative net income for the first 9 months of 2013 is down 15% comparedto the same period in 2012, based on the results of 170 companies) which hasresulted in less free cash flow in the industry. The increased cost of successfulexploration and development of existing properties owned by companies hasresulted in less spare capital to take advantage of M&A opportunities. Finally, thedecreased projected profit per barrel means that it has become harder for an assetto meet the requirements of a public companys investment appraisal.

NOCs Stepping up Involvement

The large total deal value in 2012 was boosted by the $57 billion acquisition of TNK-BP by Rosneft, which also pushed the percentage of upstream deals made by state-influenced companies up from 25% of all deals in 2011 to 44% in 2012. Despitelacking a deal of similar magnitude, state-influenced companies maintained this ratioin 2013, accounting for 42% of total deals. The reasons mentioned above for the lackof public company activity do not apply to the same extent for state-backedcompanies, for whom any investment appraisal will be less stringent and based moreon the security of long term reserves rather than a rate of return target percentage.Free cash flow is also less of an issue when a countrys treasury can be utilised as asource of cheap financing.

National Oil Companies also face less political risk. No matter how large a publiccompany is and how skilled its lobbyists are, they will not be able to match thediplomatic assurances that being a state-backed company can bring. This is areason why a company such as Sinopec, backed by the Chinese government, canbe at ease with acquiring Apaches Egyptian assets for $3.1 billion, despite theunrest in the country.

Other notable deals by NOCs during 2013 include CNPC acquiring an 8.4% stake inthe Kashagan project for $US5.4 billion, CNPC acquiring a 20% interest inMozambique Area 4 for US$4.21 billion, Rosneft acquiring a 49% interest in ITERAOil and Gas Company for $US2.9 billion in Russia and OMV acquiring producingassets offshore Norway from Statoil for $US2.65 million.

Africa Rising in Prominence

Another trend that has continued from 2012 to 2013 is the continued rise ofinvestment in African oil and gas projects. Over the past decade, many countriesacross the world have become restrictive to investment from public oil companies via

stricter fiscal policies or through an underlying threat of repatriation, as seen inVenezuela and more recently in Argentina when YPF was seized from Repsol by the


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Argentine government. With the majority of the continent still underdeveloped, thebulk of Africa has remained accommodating to both small cap explorers via openlicensing round auctions and larger cap companies who have the capital andexpertise to develop large scale projects.

Upstream M&A in Africa has increased from US$7 billion in 2011, to US$10.6 in2012 and US$17.4 billion in 2013, which represents rises of 51% and 64% per yearrespectively. A key stimulus in this overall rise has been the huge gas discoveriesmade in the Rovuma basin offshore Mozambique by Anadarko and ENI , which haverevealed approximately 200 TCF of gas in place so far. In 2013 alone, there havebeen 6 deals in the Rovuma basin for a total of $9.3 billion. The most notable ofthese include CNPC acquiring a 20% interest in Area 4 for $4.2 billion, ONGCstriking two deals to acquire a total of 20% in Area 1 for $4.125 billion and Oil Indiapurchasing a 10% interest in Area 1 for $990 million. These deals suggest a cost perrecoverable boe of $3 ($0.50 per mcf), which compared to the potential value permcf on the Asian market of $15+ would initially look like good value. These

discoveries do, however, have the dual problem of being in deep-water and beinggaseous and will therefore require a substantial investment in LNG export facilities,pipelines and possibly even FLNG facilities that are all expensive in terms of capitaland time, before any real profits can be made. This is the reason that the partnersthat Anadarko and ENI have attracted so far have been state-backed companiesfrom gas importing countries, whose investment criteria will be long-term secureresource supply rather than satisfying the criterion of an NPV analysis.

Elsewhere in Africa, Tanzania - lying to the north of Mozambique - has had a similarexperience to its neighbour, albeit to a lesser degree. Drilling of Tanzanias deep-water prospects has exposed gas fields large enough to warrant the development ofLNG export facilities but with Mozambiques discoveries being over 4 times largerthan Tanzanias, Tanzania has failed to attract the same level of investment with onlytwo deals taking place during the year in the country for $7.5 million. Had it not beenfor the large discoveries made offshore Mozambique, its likely that Tanzania wouldhave been the most active country in terms of M&A in Africa during the year ratherthan its neighbour.

North American Shale Acquisitions Diminishing

There has been a significant drop in the volume of shale deals, which has also had

an impact on the global volume of deals in 2013. In 2011, shale deals accounted for$59.4 billion, in 2012 this was reduced to $33.3 billion and in 2013 this has droppedfurther to $22.3 billion. This transition is due in a large part to the existing NorthAmerican gas glut, which has kept a firm lid on the gas price, and also the fact thatmany large cap companies have already built up strong acreage positions and arenow focusing spending on development rather than building up acreage inventory.For the shale deals that did occur during the year in North America, they werestrongly dominated by the oil bearing plays such as the Bakken and Eagle Ford,which accounted for 77% of the total shale deal value; the fact that this ratio stood at25% for 2011 accentuates the dynamic nature of the shale sector.

Conversely, outside of North America there was a record value of shale deals with$1.2 billion of acquisitions. The most notable of these came from Chevron agreeing a


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deal to carry YPF for $620 million to drill 100 wells in the Vaca Muerta shale oildiscovery in the Neuqun basin of Argentina. This shale play was discovered back in2011, but development has so far been slow. With political risks emanating from theArgentinean government, Repsol was leisurely in its development whilst they hadstewardship of YPF. Argentina will be hoping that this aggressive new development

plan agreed by Chevron in this deal will go a long way to revealing and unlocking thepotential of Argentinas shale industry in 2014. Chevron is already active in shaleplays in the US, Canada, Australia, China, Romania, Poland and Ukraine, and thecompany has emerged as possibly the most diverse geographic shale explorer in theworld, so it is a very good partner for Argentina to be working with. The next largestshale deal outside of North America came from the United Kingdom as Centricasecured a $155 million farm in for a 25% interest in the Bowland basin licenses heldby Cuadrilla Resources.

Top Deals During 2013

Acquirer Seller Brief Description Country

TotalAcquisition

Cost (US$

billion)

DevonEnergyCorporation

GeoSouthernEnergy

Devon Energy acquiresGeoSouthern Energys assets in

the Eagle Ford shale oil play

UnitedStates

6.0

CNPC KazMunayGas

CNPC acquires an 8.4% interestin the North Caspian SeaProduction Sharing Agreement

(Kashagan Field), Kazakhstanfrom Kazmunaigaz

Kazakhstan 5.4

Governmentof Argentina

YPF

The Government of Argentinarepatriates Repsol's stake in YPFin return for compensation of $5

billion of ArgentineanGovernment bonds

Argentina 5.0

Linn EnergyBerry PetroleumCo.

Linn Energy acquires BerryPetroleum Corp in an all stockdeal

UnitedStates

4.9

BP Rosneft BP acquires 5.66% stake inRosneft from OFSCROSNEFTEGAZ

Russia 4.9

CNPC ENI

China National PetroleumCorporation (CNPC) acquires28.57% (net 20% in Area 4) ofEni East Africas shares, owner

of a 70% interest in Area 4, inMozambique from Eni

Mozambique 4.2

RiverstoneHoldingsLLC

Apache

Corporation

Fieldwood Energy LLC, anaffiliate of Riverstone Holdingsacquires Gulf of Mexico Shelf

United

States3.8


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operations & properties fromApache Corporation

Sinopec ApacheCorporation

Sinopec International PetroleumExploration and ProductionCorporation, a fully-owned

subsidiary of Sinopec Groupacquires a 33% minority

participation in Apache's Egyptoil and gas business

Egypt 3.0

RosneftITERA Oil andGas CompanyLLC

Rosneft acquires the remaining49% of ITERA Oil and GasCompany LLC from IteraHoldings Limited

Russia 2.9

Source:Evaluate Energy

Outlook for 2014North America

Heading into 2014, the stifled gas price will continue to hamper upstream M&A inNorth America. Although an equalization of the gas price globally will go a long wayto restoring the valuation of gas assets, this will not happen for at least another 4-5years, if at all, a timeframe that is beyond the patience of a typical shareholder in apublic company. Since the shale gas revolution in North American took hold in 2008,gas production has increased by 8 bcf/d, but the first onstream LNG Export terminalis not expected in the US until 2015, with 0.8 bcf/d of capacity rising to 2bcf/d in2016. This will not make a significant impact on the gas price. Until the exportcapacity does make a tangible difference to gas prices, distressed sales of gas

weighted assets is likely to continue with possible buyers coming from private equitycompanies who can afford more patience than a public oil company.

Oil weighted deals will continue though, especially in the existing, established shaleplays, such as the Bakken and Eagle ford, and in emerging shale plays, such as theNiobrara and Wolfcamp.

Africa

Africa will also continue to hold ample opportunities for both juniors and establishedoil companies alike in the coming 12 months. There are currently 5 licensing roundsdue to close during 2014 in the continent including Tanzania, Libya, Angola,Republic of Congo and Kenya with the latter possibly the most exciting of them all.Like Tanzania and Mozambique, Kenya sits on the East African coast, but unlike itsneighbours, Kenyas recent successes have been oil discoveries rather than gas,which will whet the appetite for the worlds largest companies and should result insome prominent bidders when the auction begins.

Mexico

Two of the main drivers for the US oil industry growth in the past decade have been

the Eagle Ford shale play and the Gulf of Mexico, both of which straddle a borderbetween US and Mexico. Whilst the US portions of these plays has developed into a
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multi trillion dollar industry, Mexicos restrictive oil regime has resulted in only afraction of the same success. In December 2013, a bill was passed in Congress toallow foreign companies to take part in the exploration and development of theMexican oil industry via production sharing contracts. The terms of the contractshave yet to be ironed out but 2014 will be a year where Mexico firmly enters the

strategic thinking of the major and mid-cap global independent oil companies.

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Insight: Give us abreak!

Written by David BamfordfromFinding Petroleum

Yes, maybe we need a tax break for the UK North Sea but we also need servicecompanies to charge less.

A couple of weeks ago Oil & Gas UK responded to the figures on futire UK NorthSea oil and gas tax revenues released by the Office of Budget Responsibility (OBR)to coincide with the UK government's Autumn Statement.

The OBR had made a flat-line revenue growth forecast for the period between 2013and 2018 and Oil & Gas UK stated that it did not agree with this view, in fact it took aless pessimistic view.And they suggested that 'With up to an estimated 24 billion

barrels still to be recovered there is a strong future for the North Sea, but as amature basin, this will require, amongst other measures, an encouraging fiscalregime if the recovery of our oil and gas resource is to be maximised.'

Now Oil & Gas UK has around 250 full members and getting all of these singing fromthe same hymn sheet is something they should be congratulated on.

And there is no doubt that some aspects of future oil & gas production requireadditional tax incentives to move ahead - improving Enhanced Oil Recovery byutilizing CO2 from Carbon Capture onshore would be a good example.

But here's an interesting question - at least I think so!
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