OilVoice Magazine | January 2014

Edition twenty two – January 2014

What is the real cost of shale gas?

Insight: Costs are killing the North Sea! The real oil extraction limit, and how it affects the downslope Cover image by Enrico Strocchi

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OilVoice Magazine | JANUARY 2014

Adam Marmaras Chief Executive Officer Issue 22 – January 2014 OilVoice Acorn House 381 Midsummer Blvd Milton Keynes MK9 3HP Tel: +44 208 123 2237 Email: press@oilvoice.com Skype: oilvoicetalk Editor James Allen Email: james@oilvoice.com Director of Sales Terry O'Donnell Email: terry@oilvoice.com Chief Executive Officer Adam Marmaras Email: adam@oilvoice.com

Welcome to the 22nd edition of the OilVoice Magazine, the first of 2014.

This month we feature articles from Euan Mearns, Angus Warren, David Bamford, Gail Tverberg, Ilda Sejdia, Andrew McKillop, Kurt Cobb and Chris Bohill.

2013 was a year of growth and change for OilVoice. We invested heavily in our website, improving the jobs board and access to our archive of over 50,000 articles. Now those pieces are in place we're all set for a huge 2014.

Our traffic numbers are at an all time high and 2014 is only just getting started. Take a look at our Media Pack if you’re interested in advertising opportunities on OilVoice.

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Cover image by Enrico Strocchi

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OilVoice Magazine | JANUARY 2014

Contents Featured Authors Biographies of this months featured authors

OPEC warned on oil supply glut

by Andrew McKillop

3 5 14 16 19 29 32 38

'Watch what we do, not what we say': Shell cancels U.S. gas-to-liquids plant

by Kurt Cobb

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What is the real cost of shale gas?

by Euan Mearns Local Content: Effective in the past, problematic in the future

by Angus Warren Insight: Costs are killing the North Sea!

by David Bamford The real oil extraction limit, and how it affects the downslope

by Gail Tverberg A focus on Latin American oil & gas and the companies to watch

by Ilda Sejdia Shale gas myths and reality - part 1

by Euan Mearns

Brent-WTI Premium - Strangers in the night

by Andrew McKillop The risk management black hole in the oil and gas supply chain

by Chris Bohill

44 47

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Featured Authors Andrew McKillop AMK CONSULT Andrew MacKillop is an energy and natural resource sector professional with over 30 years’ experience in more than 12 countries.

Angus Warren Warren Business Consulting Angus is an oil and gas consultant who brings integrity, creativity and a track record of getting results to capturing your organization’s opportunities and resolving its unique issues.

Kurt Cobb Resource Insights Kurt Cobb is an author, speaker, and columnist focusing on energy and the environment. He is a regular contributor to the Energy Voices section of The Christian Science Monitor and author of the peak-oil-themed novel Prelude.

Ilda Sejdia Evaluate Energy Ilda Sejdia is an Oil and Gas Research 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.

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OilVoice Magazine | JANUARY 2014

Gail Tverberg Our Finite World Gail the Actuary’s real name is Gail Tverberg. She has an M. S. from the University of Illinois, Chicago in Mathematics, and is a Fellow of the Casualty Actuarial Society and a Member of the American Academy of Actuaries.

Euan Mearns Energy Matters Euan Mearns has B.Sc. and Ph.D. degrees in geology.

Chris Bohill Biznet Solutions Chris Bohill is the Vice President of consulting and product strategy, Biznet.

Biznet specializes in Supplier Performance Management (SPM), helping clients to optimize and continuously improve supplier’s performance, by creating transparency, reducing risk and improving operational efficiency.

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OilVoice Magazine | JANUARY 2014

What is the real cost of shale gas?

Written by Euan Mearns from Energy Matters   

  



US shale gas production has grown from around 4 billion cubic feet (bcf) per day in 2007 to around 26 bcf/day in 2012 US gross natural gas production has grown from a plateau of 2 trillion cubic feet (tcf) per month in the period 1995 to 2002 to 2.5 tcf per month in 2012 Some believe this is marching the USA towards energy independence while others believe, owing to costs and decline rates, that this may be an energy bubble At the end of 2011, shale gas accounted for 32% of total US natural gas production (EIA data) Pre 2008 financial crash, there were roughly 400 rigs drilling oil in the USA and 1600 drilling gas. Today it is roughly 1400 drilling oil and 400 drilling gas The fall in US prices to <$2 in 2012 has created the illusion that shale gas is cheap while in fact over-production caused a crash in the price in US natural gas to below the level where it was possible for companies to make a profit What is the real cost of shale gas? “Some wells are profitable at $2.65 per thousand cubic feet, others need $8.10…the median is $4.85,” attributed to Ken Medlock, Senior Director of Rice University’s Baker Institute Center for Energy Studies Figure 1 The astonishing evolution of global annual average natural gas prices according to BP. Shale gas development in N America, The Fukushima nuclear disaster and a shortage of LNG explains much of what is going on. The grey bar to the right shows minimum, maximum and median break even prices required for US shale gas according to Ken Medlock of The Baker Institute. These shale gas prices would be really cheap in Japan but are expensive for the USA and still mainly above US spot prices today ($3.85 / mmbtu).

In this second part of three in this mini series on “Shale gas myths and realities” I want to address one of the central questions surrounding this new bounty: is shale gas cheap or expensive? Last week in a bruising exchange on Andrew Montford’s Bishop Hill Blog I made the assertion that shale gas was expensive and not cheap.

This produced a tirade of incredulous opposition.

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Euan, shale gas is cheap. Really, really cheap. It isnâ&#x20AC;&#x2122;t just the gas. It is all the steel pipe needed for drilling and distribution. And all the jobs making the steel pipe.

At that point I had already made some enquiries into the cost of shale gas and made the assertion that break even price was likely between $4 and $8 ($ per thousand cubic feet are roughly equal to $ per million btu and are used throughout). It is extremely important to observe that $4 to $8 is currently cheap if you are in Europe, really cheap if you are in Japan but actually quite expensive if you are in North America (Figure 1) and making relative assertions about life cycle production costs is not a sensible way to proceed.

Before taking a more detailed look at published estimates of the life cycle break even costs of shale gas I first provide an overview of the very brief history and stunning growth rate of shale gas in the USA, since it is only through understanding the past that we may begin to understand the present and perhaps get a glimpse of the future.

US shale gas production to date Figure 2 shows the history of US shale gas production produced by David Hughes [1]. It shows that production is dominated by 4 plays, The Haynesville, Barnett, Marcellus and Fayetteville (Figures 2 & 3). Production has grown from around 4 billion cubic feet(bcf) per day in 2007 to around 26 bcf/day in 2012! The expansion of shale gas production has had material impact upon US gross production that has grown from a plateau of 2 trillion cubic feet (tcf) per month in the period 1995 to 2002 to 2.5 tcf per month in 2012 (Figure 4). Some believe this is marching the USA towards energy independence while others believe, owing to costs and decline rates, that this may be an energy bubble. Where does the truth lie?

Figure 2 Stack of US shale gas production from a presentation by David Hughes [1].

From a standing start in 2000, production has grown to an astonishing 25 bcf per day.

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Figure 3 Map showing the main shale gas and oil plays of the USA and Canada from the EIA. Figure 4 The evolution of US gas production by type since 1993 based on data from the US Energy Information Agency (EIA).

The dislocation in the data series in 2006 comes with the introduction of shale gas reporting. Prior to that shale gas was reported together with conventional dry gas production. At the end of 2011, shale gas accounted for 32% of total US natural gas production.

According to David Hughes, by the end of 2012 that figure had risen to 40% (Figure 2).

The phenomenal growth in US shale gas production did not just happen. The US

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drilling industry went into overdrive beginning around 2003 that saw the total number of rigs more than double to 2000 units by the summer of 2008 (Figure 5). The majority of rigs were drilling for gas and, putting Figure 5 together with Figures 2 and 4, it is apparent they were increasingly targeting shale gas at the expense of conventional gas production that began to decline after many years on plateau (Figure 4). Then, in August 2008 came the financial crash followed by a sharp decline in drilling activity as everyone pondered the future of the global financial system. US drilling activity picked up quickly in 2009 and 2010. But then began a great migration from drilling shale gas to shale oil plays (Figure 4). Pre crash, there were roughly 400 rigs drilling oil and 1600 drilling gas. Today it is roughly 1400 drilling oil and 400 drilling gas.

Figure 5 US drilling rig count from Baker Hughes compared with natural gas production (gross withdrawals) from the EIA. Since 1995, the size of the US drilling fleet has grown from about 700 rigs to 2000 rigs. For a long while, the increased drilling effort was only sufficient to combat declines until the attention turned to shale.

New shale plays clearly provided better production returns than pursuing the very mature conventional gas targets. It remains to be seen if shale provides similar economic returns. There is evidence that gross gas production has plateaued during the past 24 months.

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The migration from gas to oil is quite simple to explain. Overproduction of shale gas dumped the price from over $13 in June 2008 to below $2 in April 2012 (Figure 6). In the same time frame the oil price has been much more robust prompting the great migration from shale gas to shale oil drilling. Natural gas below $2 was fantastic for US consumers and economic growth but led ExxonMobil chief executive Rex Tillerson to famously proclaim: “We are all losing our shirts today.” Mr. Tillerson said in a talk before the Council on Foreign Relations in New York. “We’re making no money. It’s all in the red.”

Figure 6 Henry Hub natural gas spot prices from the EIA. European and Asian governments have looked on with envy as a shortage of natural gas on international markets, caused by the combined impact of the Fukushima reactor tragedy and a fall in LNG supply during 2012, sent prices soaring ever higher, creating enormous disparity in price (Figure 1). The fall in US prices to <$2 has created the illusion that shale gas is cheap while in fact over-production caused a crash in the price in US natural gas to below the level where it was possible for companies to make a profit. This is not good for society who without realising it, is dependent upon profitable energy industries for its survival.

What is the real cost of shale gas?

So what is the actual life cycle production cost of shale gas in North America? There is no single and simple answer. There are a large number of variables that need to be taken into account: 1.

2.

3.

4.

5.

6.

7.

The ultimate gas recovery from a well (EUR) The sunk costs drilling a well The land costs The cost of pipelines, process facilities and transport to market Tax and royalties Interest paid and interest rates Corporate overhead

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There can be enormous variations in some of these variables from State to State, e.g. tax regime, and even bigger variance between N America and Europe. In the various estimates given below it is not clear in some cases if full life cycle or pointforwad economics are used (see caption to Figure 8). The estimate below is attributed to Ken Medlock, Senior Director of Rice University’s Baker Institute Center for Energy Studies: “Some wells are profitable at $2.65 per thousand cubic feet, others need $8.10…the median is $4.85,” These are the prices I have indicated on Figure 1. Figure 7 is lifted from an academic study [2] which seems to indicate minimum costs in the range $4 to $6 / mcf.

Figure 7 Ruud Weijermars [2] in an academic article estimates minimum prices of between $4 and $6 / mcf for various US shale plays.

In a 2012 presentation, shale gas analyst and critic Arthur Berman [3] pointed towards full cycle costs for shale gas in the Barnett, Fayetteville and Haynesville in excess of $8 applying an 8% discount rate (Figure 8). Berman argues that companies consistently over estimate well ultimate recovery and hence relative costs are actually higher than declared.

Figure 8 From a 2012 presentation

by Arthur Berman [3]. In an email from Arthur today: “Point-forward economics do not include entry/land costs, overhead/G&A or debt service.

The table is two years out-of-date so I wouldn’t use the break-even gas prices as other than a guide. The decline-curve analysis remains sound.”

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I have this from the former CEO of a major oil company: It is all a function of gas price. At $4-5/m, there is a ton.

In summary, it seems clear that below $2 the shale gas industry as a whole is unprofitable. The published evidence points to the estimates of Ken Medlock at the Baker Institute as providing a balanced picture. The profitability of individual companies will depend upon the quality of their overall portfolio. Only time will tell if the high end estimates of Weijermars and Berman come to pass as a result of wells producing less than currently assumed. But this is an extremely volatile and active industry with efficiency gains being made all the time, and making forecasts is incredibly difficult, especially about its future.

The future of shale gas in the USA There are signs that the sharp slow down in shale gas drilling is beginning to feed through to a slowing of gas production rate (Figure 5) where a 24 month production plateau may be evident. One of the surprising things is that gas production continued to rise while the rate of drilling fell. This in part is due to a time lag between drilling wells and hook up to the distribution system. Wells need to wait for the pipelines to arrive and at any point in time there is a backlog inventory of new wells that are sitting idle waiting to be hooked up. But drilling efficiency has also improved, fracking and completions are improving and in some areas like the Marcellus of PA, production hot spots are being found and drilled. This excerpt from The Motley Fool: With so many companies using pad drilling, it shouldn’t come as a surprise that the average North American active rig drilled 15% more wells during the third quarter of this year than in the first quarter of 2012, according to Baker Hughes data.

In North Dakota’s Bakken shale, each rig’s daily oil production from new wells is expected to nearly double this year, from slightly more than 250 barrels of oil per day last year to an estimated 496 barrels per day in December, according to the U.S. Energy Information Administration. Similarly, in Texas’ Eagle Ford shale, each rig’s production from new wells is projected to increase to 413 barrels per day, up from about 200 barrels per day last year.

It seems possible that an equilibrium point has been reached where 400 rigs are managing to provide sufficient volumes to offset gas declines. Demand for cheap gas has risen in the USA which still imports small volumes from Canada. It is difficult to envisage in current market conditions a fresh migration of drilling activity away from oil into gas. It seems reasonable to expect, therefore, that the rise in production may come to a halt or may even reverse in the medium term, a situation that will persist until natural gas prices have risen back to a level that attracts rigs away from The Bakken and Eagle Ford.

The spectacular efficiency gains made in drilling times and well productivity must inevitably slow down at some point. The longer term future will be determined by the number of production sweet spots and hot spots that are found. For so long as new wells continue to be better than the old, it will seem like the shale miracle will go on forever.

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On the basis of the foregoing it seems likely that US natural gas prices may continue to rise to beyond $5 in the near term. Citizens may grumble but should also appreciate that at this level, the prosperity of the shale gas industry may be assured for a while at least, and that will be of major benefit to the US economy. At $5, companies with a good quality portfolio of cheap, productive wells may make a lot of money whilst those with low productivity, expensive wells may not.

Disclaimer The information presented here is done in good faith in an effort to provide an objective summary of the current state and near-term prospects of the US shale gas and shale oil industry. The author invests in oil and gas companies but does not hold any stock in US or Canadian listed energy producers.

References 1. The “Shale Revolution” Myths and Realities” Energy Growth Conference First Energy Capital Toronto, Ontario November 19, 2013; J. David Hughes, Global Sustainability Research Inc., Post Carbon Institute 2. Ruud Weijermars, Economic appraisal of shale gas plays in Continental Europe, Applied Energy 106 (2013) 100–115 3. After The Gold Rush: A Perspective on Future U.S. Natural Gas Supply and Price, Arthur E. Berman Labyrinth Consulting Services, Inc. ASPO Conference 2012 Vienna, Austria May 30, 2012

View more quality content from Energy Matters

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UNLOCK THE POTENTIAL IN YOUR FIELD | #4 IN A SERIES

JANUARY 2014

AP

LA CHIA N

S BA

What lies beneath

PA

IN

PE

In Appalachia, geo-hazards revealed with new clarity

N

NS

YL V A NIA

HIGHLIGHTS For millions of years, Appalachian gas has migrated toward the surface along naturally occurring faults.

Frequently, it gets trapped in shallow structures

KEY TECHNOLOGIES:

difficult to see on seismic images. Abandoned and

HYPERSPECTRAL

MAGNETIC

pocket en route to the Marcellus or Utica Shale can

ACTIVE-SOURCE EM

throw a wrench in operations, forcing a producer to set

PASSIVE-SOURCE EM

undocumented wellbores, some a century old, compound the problem. Drilling into a shallow gas

a string of casing and adding up to $250,000 per well in unexpected cost. Fracing near an orphaned wellbore Resistivity slice in a gas dominant area of the near surface.

Oil seeps (green) and gas plumes (magenta) on the surface are superimposed.

or unknown fault is every operator’s worst nightmare.

AREA: Appalachian Basin, Pennsylvania CUSTOMER: Supermajor

Responsible operators want to know the challenges they face “ahead-of-the-bit,” so they can avoid geo-

hazards and design their drilling and hydraulic fracturing programs with utmost regard for the environment. To address

FOCUS: Eco-Assurance TYPE: Unconventional

these challenges, NEOS GeoSolutions has introduced Eco-Assurance , a program based on its proprietary Multi™

measurement Interpretation (MMI) methodology. A combination of airborne magnetic, hyperspectral and electromagnetic (EM) measurements helps to locate orphaned wellbores, reservoir-to-surface fault zones and trapped shallow gas pockets.

NEOS was engaged to conduct a 30-square-mile, basement-to-surface Eco-Assurance survey in Western Pennsylvania.

Airborne-acquired hyperspectral data revealed surface oil seeps and gas plumes, along with wetlands, waterways and the condition of local botany. Sensors were calibrated to the hyperspectral signatures of hydrocarbons unique to the area, and anomalies were verified via ground truthing.

KEY INTERPRETIVE PRODUCTS: ≥ Shallow gas geo-hazard detection ≥ Fault detection ≥ Aquifer mapping ≥ Orphaned wellbore detection ≥ Oil seep and gas plume detection

Magnetic data helped identify fault zones, orphaned wellbores and other iron-based infrastructure. By overlaying the magnetic data on top of maps of known infrastructure, like farms, well pads and pipelines, NEOS was able to locate dozens of previously unknown sites potentially associated with orphaned oilfield infrastructure. A comparison of these

CUSTOMER BENEFITS:

sites and the hyperspectral data indicated if any previously unknown sites were also associated with trace hydrocarbons.

Helps producers protect the integrity of

EM data provided insight into trapped shallow pockets from the surface down toward the target shale intervals. NEOS used

drilling and completion operations with

both active- and passive-source airborne acquisition with proprietary signal processing to generate detailed 3D voxels that

detailed data for avoiding geo-hazards

could be analyzed both in cross section and in depth slices. An analysis of the EM and magnetic data suggested that

and environmentally sensitive areas.

hydrocarbons had naturally migrated along fault planes into some areas of the near-surface over the course of geologic time.

Cost-effective Eco-Assurance is proving its worth not just in Appalachia, but anywhere E&P activities are ongoing.

Integrating multiple airborne geophysical datasets can inform a road map for environmentally sound and commercially efficient operations.

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

OilVoice G E O S O L U T I O N S

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Local Content: Effective in the past, problematic in the future Written by Angus Warren from Warren Business Consulting National oil companies (NOCs) in developing countries have always had an important role to play in the transfer of technology and skills into the country, and as a vehicle for economic development. And local content provisions have always had a key role to play in such endeavours. But recent trends suggest that increasingly restrictive local content requirements will have unintended impacts across a range of issues, including labour costs and the ability of oil companies to deliver projects within challenging time schedules.

Firstly then, what is local content? Local content is commonly taken to mean the obligation on the investor to use local subcontractors and to purchase a certain amount of supplies and equipment in host country. Sometimes a target local content is agreed, e.g. 10% of the project, and the host government may impose heavy penalties for failure to comply with the production sharing contract (PSC) or law.

Local content is often the most heavily scrutinised area of investor performance.

Traditionally, the international oil company (IOC) starting position has been that there should be no government interference in prices for equipment and supplies and that market pricing should prevail. Local content provisions came to be seen by some as another tax which poses irritating logistical challenges such as lack of availability of materials in country and lack of skills in local subcontractors.

Despite the higher costs, governments of many oil producing nations have increased local content requirements, which typically enjoys popular public support. Examples local content provisions are provided below, with the most lenient (from the investor's perspective) first: 1. Vietnam: in the proposed model PSC a Contractor should only be required to give preference to the purchase of Vietnamese goods and services in undertaking operations provided that such goods and services are of internationally comparable quality, available at the required time and quantity, and offered at competitive prices.

2. Kurdistan: The contractor shall give preference to personnel from the Kurdistan Region and other parts of Iraq to the extent such personnel have the technical capability, qualifications, competence and experience required to perform the work.

3. Mexico: the recent model Integrated Services Contracts require 40% local content (but this could vary in future).

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OilVoice Magazine | JANUARY 2014

4. Nigeria: in 2010 the Oil and Gas Industry Local Content Development Bill was signed into law which stipulated, among other things, a minimum Nigerian content on oil and gas projects of up to 100%, depending on the type of activity.

5. Brazil: generally working towards 65%-70% targets for local content, but the average onshore blocks are already over 80% in the 2010 licensing round.

6. Ghana: has set a target of at least 90% local content throughout the oil and gas value chain by around 2020.

7. Gabon: recently implemented a 90% local content requirement for new contracts.

Of course, in countries where the NOC is dominant, the NOC may set its own targets. PEMEX has been mandated by the Mexican government to establish a strategy to support national suppliers and contractors as part of an Integral Strategic Business Plan, the purpose of which is to increase local content to a minimum of 25%.

The trend seems to be for ever more restrictive local content provisions. But these do not come without a cost and the implications of high local content can be severe: 1. Major logistical difficulties for investors in the short and medium term, as local capacity for the delivery of many goods and services may not be readily available.

2. Reduced growth (or even contraction) of oil and gas production in some countries.

3. High inflation and other macro-economic impacts as local spending filters through the economy (as an aside, a friend recently spent $20 on a prawn sandwich in Luanda!).

4. Challenges in the use of some high grade technologies, where the intellectual property rights are normally not transferred by investors to the host countries.

5. More expensive projects, as local oil services companies generally charge more for equivalent equipment than their international competitors.

6. Non-compliance and sub-optimal development risks for investors that will be required to be compensated with higher returns.

7. Administrative burden on investors that are required to account for local content in their projects.

8. Inconsistency with trade agreements (e.g. NAFTA).

Some investors will, of course, seek work arounds to these issues. For example, in order to meet local content requirements in Brazil, several companies will develop technology centres within the country.

However, the trend is for ever more restrictive local content provisions, and it is clear that unintended consequences could be severe on everyone.

View more quality content from Warren Business Consulting

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OilVoice Magazine | JANUARY 2014

Insight: Costs are killing the North Sea! Written by David Bamford from Finding Petroleum I'm not sure I should take issue with a knight of the realm but I do believe Sir Ian Wood's interim review of Maximising Economic Recovery in the UKCS is insufficiently focused on COSTS. Why do I believe this?

Two general reasons and then two specific reports about the UKCS and the NOCS; Firstly, it is well known that as basins mature, costs per boe rise. This is an inevitable consequence of companies sensibly developing the bigger, simpler, fields first and leaving those that are deeper or have more complex reservoir geology and reservoir dynamics, or have more â&#x20AC;&#x2DC;challengingâ&#x20AC;&#x2122; hydrocarbons or are in deeper water until later.

The cartoon below illustrates this concept: early in the life of a play/basin, Value creation is prolific; at a later stage, Costs are overwhelming, Value destruction occurs.

Indeed the expectation that this happens is a key driver of the bigger companies exiting the North Sea for areas that offer higher margins per barrel for example Angola, Brazil, the Caspian and so on, or at least favouring the latter over the former if not completely departing. Thus as the UKCS for example matures, bigger companies with plenty of financial muscle and experience in the application of technology are replaced by a host of smaller, sometimes less well-endowed, companies.

Secondly, as I mentioned in an earlier article, IPA's development project

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benchmarking data base shows that cost over-runs, delays and production shortfalls are unnervingly common, not simply in the UKCS and NOCS but everywhere. A significant driver is management’s swallowing whole simple economic models that ‘prove’ that getting faster to 1st Oil or Gas increases NPV when in fact overdue haste breeds failure.

Then we need to note that specific UKCS development projects, for example: - Rosebank (West of Shetland; Chevron operated): estimates of projected costs up to $8 billion and - Bressay (Northern North Sea; Statoil operated): estimates of projected costs up to $7 billion, are being cancelled or delayed because heavy costs are making them uneconomic.

So the reality is that global industry price inflation is being superimposed on top of the inevitably rising costs per boe.

Furthermore delays and cost over-runs occur even in the well (NPD) regulated NOCS, with the NPD reporting that 24 development projects have over-run by a combined NOK49 billion, with just three of them: - Skarv (BP operated) - Valhalla redevelopment (BP operated) and - Yme (Talisman operated) reported as having over-run by NOK42 billion in total. And some would argue that the NPD is in fact an agent of rising costs in the NOCS...

So I suggest we have a problem in the UKCS and NOCS for which we need to seek all manner of solutions, perhaps especially using technology, backed up by a fresh wave of industry consolidation.

Why do I mention consolidation? My own belief is that we will wait a long time for the actions of governments to persuade the many companies now working in the UKCS and NOCS to act coherently together and that – I emphasise this is just my personal opinion – a wave of consolidation is needed as an enabler of coherent strategies and actions.

Does technology have any role at all to play in delivering better Development Projects and reducing COSTS (cost per boe)?

Oftentimes when I ask such questions, I hear about technologies that are actually solutions looking for a problem to solve. Here I think the problem is quite clear.

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OilVoice Magazine | JANUARY 2014

The real oil extraction limit, and how it affects the downslope Written by Gail Tverberg from Our Finite World There is a lot of confusion about which limit we are reaching with respect to oil supply. There seems to be a huge amount of “reserves,” and oil production seems to be increasing right now, so people can’t imagine that there might be a near term problem. There are at least three different views regarding the nature of the limit: 1. Climate Change. There is no limit on oil production within the foreseeable future. Oil prices can be expected to keep rising. With higher prices, alternative fuels and higher cost extraction techniques will become available.

The main concern is climate change. The only reason that oil production would drop is because we have found a way to use less oil because of climate change concerns, and choose not to extract oil that seems to be available.

2. Limit Based on Geology (“Peak Oil”). In each oil field, production tends to rise for a time and then fall. Therefore, in total, world oil production will most likely begin to fall at some point, because of technological limits on extraction. In fact, this limit seems quite close at hand. High oil prices may play a role as well.

3. Oil Prices Don’t Rise High Enough. We need high oil prices to keep oil extraction up, but as we reach diminishing returns with respect to oil extraction, oil prices don’t rise high enough to keep extraction at the required level. If oil prices do rise very high, there are feedback loops that lead to more recession and job layoffs and less “demand for oil” (really, oil affordability) among potential purchasers of oil. One major cut-off on oil supply is inadequate funds for reinvestment, because of low oil prices.

Why “Oil Prices Don’t Rise High Enough” Is the Real Limit In my view, our real concern should be the third item above, “Oil Prices Don’t Rise High Enough.”

Because of diminishing returns, the cost of oil extraction keeps rising. It is hard for oil prices to increase enough to provide an adequate profit for producers. In fact, oil prices already seem to be too low. Oil companies have begun returning money to stockholders in increased dividends, rather than investing in projects which are likely to be unprofitable at current oil prices. See Oil companies rein in spending to save cash for dividends. If our need for investment dollars is escalating because of diminishing returns in oil extraction, but oil companies are reining in spending for investments because they don’t think they can make an adequate return at current

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oil prices, this does not bode well for future oil extraction.

A related problem is debt limits for oil companies. If cash flow does not provide sufficient funds for investment, increased debt can be used to make up the difference. The problem is that credit limits are soon reached, leading to a need to cut back on new projects. This is particularly a concern where high cost investment is concerned, such as oil from shale formations. A rise in interest rates would also be a problem, because it would raise costs, leading to a higher required oil price for profitability. The debt problem affects high priced oil investments in other countries as well. OGX, the second largest oil company in Brazil, recently filed for bankruptcy, after it ran up too much debt.

National oil companies don’t explain that they are finding it hard to generate enough cash flow for further investment. They also don’t explain that they are having a hard time finding sites to drill that will be profitable at current prices. Instead, we are seeing more countries with national oil companies looking for outside investors, including Brazil and Mexico. Brazil received only one bid, and that for the minimum amount, indicating that oil companies making the bids do not have high confidence that investment will be profitable, either. Meanwhile, newspapers spin the story in a totally misleading way, such as, Mexico Gears Up for an Oil Boom of Its Own. US natural gas is another product with a similar problem: the price is not high enough to justify new production, especially for shale gas producers. The huge resource that some say is there is simply too expensive to extract at current prices.

Would-be natural gas producers cannot tell us this. Instead, we find a recent quote in the Wall Street Journal saying: “We are not dealing with an era of scarcity, we are dealing with a situation of abundance,” Ken Cohen, Exxon’s vice president of public and government affairs, said in an interview. “We need to rethink the regulatory scheme and the statutory scheme on the books.”

Cohen could explain that without natural gas exports, there is no way the natural gas price will rise high enough for Exxon-Mobil to extract the resource at a profit. Without exports, Exxon Mobil will lose money on the extraction, or more likely, will have to leave the natural gas in the ground. With low prices, the huge resource that Obama has talked about is simply a myth–the prices need to be higher. Of course, no one tells us the real story–it seems better to let people think that the issue is too much natural gas, not that it can’t be extracted at the current price. The stories offered to the news media are simply ways to convince us that exports make sense. Readers are not aware how much stories can be “spun” to make the current situation sound quite different from what it really is.

What Goes Wrong with “Climate Change” and “Limit Based on Geology” Views The Illusion of Reserves. Oil and gas reserves may seem to be “be there,” but a lot of conditions need to be in place for them to actually be extracted. Clearly, the price needs to be high enough, both for current extraction and to fund new investment.

Other conditions need to be in place as well: Debt needs to be available, and it

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needs to be available at a sufficiently low rate of interest to keep costs down. There needs to be political stability in the country in question. Something as simple as a continuation of the uprisings associated with the Arab Spring of 2010 could lead to the inability to extract reserves that seem to be present. Other requirements include availability of water for fracking and the availability of skilled workers and drilling rigs.

In the past, we have been far enough away from limits that issues such as these have not been a big problem. But as we get closer to limits and stretch our capabilities, these become more of a problem. Right now, availability of debt at low interest rates is a particularly important issue, as is the need for adequate oil company profitability–things that are easy to overlook.

Wrong Economic Views Leading to Wrong Oil Views. Economists have put together economic models based on a world without limits. A world without limits is the easy approach, because mathematical relationships are much simpler in a world without limits: a relationship which held in 1800 is expected to hold in 1970 or in 2050. A world without limits never offends politicians, because growth always seems to be possible, meaning a never-ending supply of jobs and of goods and services for constituents. A model without limits produces the simple relationships that we are accustomed to, such as “Inadequate supply will lead to a rise in price, and this in turn will tend to create greater supply or substitutes.” Unfortunately, these models omit many important variables and thus are inadequate representations of the world we live in today.

In a world with limits, there are feedback loops that cause high oil prices to lead to lower wages and more unemployment in oil importing countries. Thus “demand” can’t keep rising, because workers can’t afford the higher oil prices. Oil prices stagnate at a level that is too low to maintain adequate investment. High oil prices also feed back into slower economic growth and a need for ultra-low interest rates to raise demand for high-priced goods such as cars and homes.

When prices remain in the $100 barrel range, they are still high enough to damage the economy. Businesses are not much damaged, because they have ways they can work around higher oil prices, especially if interest rates are low. Most of the ways businesses can work around high oil prices involve reducing wages to US workers– for example, outsourcing production to a lower cost country, or cutting the pay of workers, or laying off workers to match lower demand for goods. (Lower demand for goods tends to occur when oil prices rise, and businesses raise their prices to reflect the higher oil costs.)

Workers are still affected by costs in the $100 barrel range, and so are governments.

Governments must pay out higher benefits than in the past, to keep the economy afloat. They must also keep interest rates very low, to try to keep demand for homes and cars as high as possible. The situation becomes very unstable, however, because very low interest rates depend on Quantitative Easing, and it does not appear to be possible to continue Quantitative Easing forever. Thus, interest rates will need to rise. Such a rise in interest rates is likely to push the country back into recession, because taxes will need to be higher (to cover the government’s higher debt costs) and because monthly payments on homes and new car purchases will tend to rise. The limit on oil production then becomes something very remote from

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geology–something like, “How long can interest rates remain low?” or “How long can we make our current economy function?”

The Interconnected Nature of the Economy. In my last post, I talked about the economy being a complex adaptive system. It is built from many parts (many businesses, laws, consumers, traditions, built infrastructure). It can operate within a range of conditions, but beyond that range it is subject to collapse. An ecosystem is a complex adaptive system. So is a human being, or any other kind of animal.

Animals die when their complex adaptive system moves out of its range.

It is this interconnectedness of the economy that leads to the strange situation where something very remote from the real problem (oil limits) can lead to a collapse. Thus, it can be a rise in interest rates or a political collapse that ultimately brings the system down. The path of the downslope can be very different from what a person might expect, based on the naive view that the problems will simply relate to reduced supply of oil.

A Case Study of the Collapse of the Former Soviet Union The Soviet Union was major oil exporter and a military rival of the United States in the 1950s through 1980s. It also was the center of a huge economic system, involving many other countries. One thing that bound the countries together was the use of communism as its method of government; another was trade among countries. In effect, the group of communist countries had their own complex adaptive system. Things seemed to go fine for many years, but then in December 1991, the central government of the Soviet Union was dissolved, leaving the individual republics that made up the Former Soviet Union (FSU) on their own.

While there are many theories as to what all caused the collapse, it seems to me that low prices of oil played a major role. The reason why low oil prices are important is because in an oil exporting country, such as the FSU, oil export revenues represent a major part of government funding. If oil prices drop too low, there is a double problem: (1) it becomes unprofitable to drill new wells, so production drops and, (2) the revenue that is collected on existing wells drops too low. The problem is then a huge financial problem–not too different from the financial problem the US and many of the big oil importing countries are experiencing today.

Figure 1. Oil production and price of the Former Soviet Union, based on BP Statistical Review of World Energy 2013.

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In this particular situation, oil prices (in inflation adjusted prices) hit a peak in 1980.

Once oil prices hit a peak, FSU oil production very much flattened. There was a continued small rise until 1983, but without the very high prices available until 1980, aggressive investment in new oil extraction dropped back.

Not only did FSU oil production flatten, but FSU oil consumption also flattened, not long after oil production stopped rising (Figure 2). This flattening helped maintain exports and the taxes that could be collected on these exports.

Figure 2. Former Soviet Union Oil Production and Consumption, based on BP Statistical Review of World Energy, 2013.

Even though total exports were close to flat in the 1980s (difference between consumption and production), there were some countries where exports that were risingâ&#x20AC;&#x201C;for example North Korea, shown in Figure 4. This mean that oil exports for some allies needed to be cut back as early as 1981. Figure 3 shows the trend in oil consumption for some of FSUâ&#x20AC;&#x2122;s allies.

Figure 3. Oil consumption as a percentage of 1980 consumption for Hungary, Romania, and Bulgaria, based on EIA data.

A person can see that oil consumption dropped off slowly at first, and increased around 1990. All of these countries saw their oil consumption drop by at least 40% by 2000. Bulgaria saw is oil consumption drop by 65% to 70%.

The FSU exported oil to other countries as well. Two countries that we often hear about, Cuba and North Korea, were not affected in the 1980s (Figure 4). In fact,

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Cuba’s oil consumption never seems to have been severely affected. (It is possible that exports of manufactured goods from the FSU dropped, however.) Cuba’s dropoff in oil consumption since 2005 may be price-related.

Figure 4. Oil consumption as a percentage of 1980 oil consumption for Cuba and North Korea, based on EIA data.

North Korea’s oil consumption continued growing until 1991. Its drop-off was then very severe–a total of an 83% reduction between 1991 and 2010. In most of the countries where oil consumption dropped, consumption of other fossil fuels dropped as well, but generally not by as large percentages. North Korea experienced nearly a 50% drop in other fuel (mostly coal) consumption by 1998, but this has since somewhat reversed.

By 1991, the FSU was in poor financial condition, partly because of the low oil prices, and partly because its oil exports had started dropping. FSU’s oil production left its plateau and started dropping about 1988 (Figure 2). The actual drop in FSU oil production meant that oil consumption for the FSU needed to drop as well–a big problem because industry depended upon this oil. The break-up of the FSU was a solution to these problems because (1) it eliminated the cost of the extra layer of government and (2) it made it easier to shift oil consumption among the member republics, so that those republics that produced more oil could keep it for their own use, rather than sending it to republics which did not produce oil. This shortchanged non-oil producing republics, such as the Ukraine and Belarus.

If we look at oil consumption for a few of the republics that were previously part of the FSU, we see that oil consumption was fairly flat, then dropped off quickly, after 1991.

Figure 5. Oil consumption as a percentage of 1985 oil production for Russia, the Ukraine, and Belarus, based on BP Statistical Review of World Energy 2013.

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By 1996 (only 5 years after 1991), oil consumption had dropped by 78% for the Ukraine, by 61% for Belarus, and by “only” 47% for Russia, which is an oil-producing state. At least part of the reason for the fast drop off was the fact that in the years immediately after 1991, oil production for the FSU dropped by about 10% per year, necessitating a quick drop off in consumption, especially if the country was to continue to make some money from exports. The 10% drop-off in oil production suggests that the decline in oil production was more than would be expected from geological decline alone. If the decline were for geological reasons only, without new drilling, one might expect the drop off to be in the 4% to 6% range.

When oil consumption dropped greatly, population tended to decline (Figure 6). The decline started earliest in the countries where the oil consumption drop was earliest (Hungary, Romania, and Bulgaria). The steepest drop-offs in population occur in the Ukraine and Bulgaria–the countries with the largest percentage drops in oil consumption.

Figure 6. Population as percent of 1985 population, for selected countries, based on EIA data.

Some of the population drop is from emigration. Some of it is from poorer health conditions. For example, Russia used to provide potable water for its citizens, but it no longer does. Some is from conditions such as alcoholism. I haven’t shown the population change for North Korea. It actually continued to increase, but at a much lower rate of growth than previously. Cuba’s population has begun to fall since 2005.

GDP growth for the countries shown has tended to lag behind world economic growth (Figure 7).

Figure 7. GDP compared to world GDP – Change since 1985, based on USDA Real GDP data.

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Nearly all of the countries listed above have had financial problems, at different times.

Belarus’s GDP seems to be doing better than the rest on Figure 7. Belarus, like the Ukraine, is a pipeline transit country for Russia. In Belarus, natural gas consumption has increased, even as oil consumption has decreased. This increase is likely helping the country industrialize. Inflation occurred at the rate of 51.9% in 2012 according to the CIA World Fact Book. This high inflation rate may be distorting indications.

Conclusion We can’t know exactly what path our economy will follow in the future. I expect, though, that the path of the FSU and its trading partners is closer to the path we will be following than most forecasts we hear today. Most of us haven’t followed the FSU story closely, because we wrote off most of their problems to deficiencies of communism, without realizing that there was a major oil component as well.

The FSU situation may, in fact, be better that what the Industrialized West is facing in the next few years. The FSU had the rest of the world to support it, offering investment capital and new models for development. Oil production for Russia was able to rebound when oil prices rose again in the early 2000s. As situations around the world decline, it will be harder to “bootstrap.”

One of the things that hampered the recovery of the FSU was the fact that the communist economic model proved not to be competitive with the capitalistic model.

In a way, the situation we are facing today is not all that different, except that our challenge this time is competition from Asian economies that we have not had to compete with until the early 2000s.

Asian economies have several cost advantages relative to the Industrialized West: (1) Asian competitor countries are generally warmer than the industrialized West.

Because of this, Asian workers can live more comfortably in flimsy homes. They also don’t need much salary to cover heating and can more easily commute by bicycle. It is often possible to produce two crops a year, making productivity of land and of farmers higher than it otherwise would be. In other words, Asian competitor countries have an energy subsidy from the sun that the Industrialized West does not.

(2) Asian competitors are often willing to ignore pollution problems, reducing their costs relative to the West.

(3) Asian competitors generally depend on coal to a greater extent than we do, keeping their costs down, relative to countries that use higher-priced fuels.

(4) Asian competitors are less generous with employee benefits such as health care and pensions, also holding costs down.

Economists, through their wholehearted endorsement of globalization, have pushed industrialized countries into a competitive situation which we are certain to lose.

While oil prices tend to push wages down, competition with Asian countries makes the downward push on wages even greater. These lower wages are part of what are pushing us toward collapse.

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To solve our problems, economists have proposed a shift toward renewable energy and the implementation of carbon taxes. Unless these changes are done in a way that actually reduces costs, these “solutions” are likely to make us even less competitive with low-cost competitors such as those in Asia. Thus, they are likely to push us toward collapse more quickly.

To support this position, economists point to climate change models based on the view that the burning of fossil fuels will increase greatly in the decades again. In fact, if collapse occurs in the next few years in the Industrialized West, carbon emissions are likely to fall quickly. Because of the interconnectedness of the world system, the rest of the world will likely also encounter collapse in not many more years, and their carbon emissions are likely to fall quickly, as well. Even the “Peak Oil” emissions that are used in climate change models are way too high, relative to what seems likely to be the case.

If I am right about collapse being a possibility for the Industrialized West, then our problem will be that we as nations become so poor that we can no longer find goods to trade with Asian countries. Most of our goods will not be competitive as exports, and we won’t be able to simply add more debt to rectify the situation. Thus, we will become unable to buy many goods we depend on, including computers and replacement parts for wind turbines.

Breakups of many types are possible. The European Union may cease to operate in the way it does today. The International Monetary Fund is likely to cease operating in the way it does today, because of the collapse of many of its members who provide funding. The US will be subject to strains of the type that lead to break up. If nothing else, oil producing states will want to withdraw, so that they are not, in effect, subsidizing the rest of the US economy.

It is unfortunate that economists are tied to their hopelessly out-of-date economic models. Part of the problem is that the story of “collapse around the corner” doesn’t sell well. The alternate story economists have come up with really isn’t right, but it is pleasing to the many who benefit from subsidies for renewables, and it makes politicians look like they are doing something. The specter of climate change in the distance gives an excuse to cut back oil use, among other things, so has at least some theoretical benefit.

It is unfortunate, however, that we cannot look at the real problem. Unless we can understand the problem as it really is, it is impossible to find solutions that might actually be helpful.

View more quality content from Our Finite World

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A focus on Latin American oil & gas and the companies to watch Written by Ilda Sejdia from Evaluate Energy Latin America is definitely a fascinating region in terms of high levels of oil and gas exploration, major recent discoveries and the ever-changing relationships between State-Controlled Companies and their independent counterparts. The region has 329 billion barrels of oil and 268.3 Tcf proved gas reserves as of year-end 2012, and has seen many new licensing rounds in recent times which provided great investment opportunities for international oil and gas companies of any size. Evaluate Energy provides a quick overview of the main activity in the region and the companies to keep an eye out for in the coming months.

The discovery of spectacular pre-salt oil reserves in Brazil has raised the profile of the country on the global oil and gas stage. According to Brazil’s oil regulator, ANP, pre-salt deep-water fields have the potential to double Brazil's oil reserves and peak output could reach 2.5 million barrels per day. This would double Brazil's current production and bring the country level with major exporters in the region, such as Mexico and Venezuela. Altogether, 71 companies participated in this year’s licensing rounds, with 30 companies (12 domestic and 18 international companies) being awarded exploratory areas. As expected, state-controlled Petrobras (SAO:PETR4) was involved heavily in all rounds, and is entitled of a mandatory 30 per cent share in all pre-salt PSAs (Production Sharing Agreement) following discoveries. Petrobras has also opened up to international involvement in Brazil, forming consortiums with major global oil and gas players, such as Total (EPA:FP), Shell (LSE:RDSA), and China’s CNPC, to help cope with the burden of the high costs involved.

Another success story has been seen in Colombia where Ecopetrol has increased oil and gas output by 18 per cent per year on average since 2008 and on more than one occasion has exceeded Petrobras in terms of market capitalisation, assuming the status of Latin America’s largest listed company. Colombia as a whole has also had a good few years, with a greater degree of market liberalisation following the part privatisation of Ecopetrol, new regulations promoting foreign investment in the oil and gas sector being introduced and improvements in security both having a positive impact.

In Argentina, shale prospects are high with the Vaca Muerta play in the Neuquén Basin estimated to have 661 billion barrels of oil and 1,181 tcf of natural gas, but this is at an early stage of development, with mainly testing taking place so far. It has

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attracted major companies with vast shale experience in North America such as ExxonMobil (XOM), EOG Resources (EOG) and Total, as well as exciting junior companies such as Americas Petrogas (BOE) and Madalena Energy (MVN).

Argentina has introduced flexibility within the energy sector by allowing companies to export up to 20 percent of total output tax free, as well as exemption from foreign exchange controls for companies that invest at least $1 billion over five years.

Moreover, to avoid putting off foreign investors, it has offered a $5bn settlement to Repsol (REP) in an attempt to end the dispute over YPF, which is very likely to be accepted by Repsol (REP) in order to build its post-YPF strategy. Scepticism still remains around the political risk associated with Argentina, which is unfortunately a common theme throughout Latin American countries. There have been many occasions of government intervention driving away foreign investment across the continent, in the form of unsustainable subsidies combined with low prices, foreign currency controls or occasionally the seizure of foreign-owned assets.

Companies to Watch in Latin America Pacific Rubiales Energy Corp. (TSX:PRE) is a TSX-listed oil and gas company with Latin American crude oil and natural gas activities in Colombia, Peru, Brazil, Guatemala and Belize. The company has undertaken aggressive M&A activity in recent times, with total acquisitions of US3.8 billion and US$7.25 billion for 2012 and 2013 respectively. The oil-focused company reported 117.219 mbbl/day (net after royalty) in Q3 2013, representing an increase of 37.8% over the corresponding period in 2012.

Source: Evaluate Energy

Its most recent M&A transaction involved the acquisition of Petrominerales for Cdn$935 million, gaining the company 18 exploration and development properties in Colombia, four blocks in Peru and stakes in two Colombian pipelines, and also increased its oil production by 23,000 mbbl/d according to Q3 2013 results.

Madalena Energy (TSXV:MVN) is a junior company involved in the exploration, development and production of oil and natural gas in Argentina and in Canada (Alberta). During Q3 2013, Madalena Energy reported strong production results; 1.177 mboe/d (46% oil and liquids), an increase of 374% compared with the corresponding period in 2012.

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Source: Evaluate Energy

Overall, the company is improving. The company reported a decreased normalised net loss of US$ 0.922m and a 6.07% decrease in general and administrative costs.

The company is investing in continued improvement, which can be seen by the 89% increase in capital expenditures compared with Q3 last year, which can be mainly attributed to the Companyâ&#x20AC;&#x2122;s Ostracod oil project in Canada. Continuing this positive trend, Madalena Energy announced the closing of a private placement in December 2013, with aggregate combined gross proceeds of $12.2 million that will be used to further its domestic oil assets in West-Central Alberta and drill an additional well in the Vaca Muerta formation in the southern portion of Coiron Amargo where Petrobras announced a successful discovery, recently.

Gran Tierra Energy, Inc (GTE) has crude oil and gas production activities in Colombia, Argentina and Brazil and exploration activities in Peru.

Source: Evaluate Energy

Net income for Q3 2013 was US$33.1 million; a decrease of 26% in the comparable period in 2012. The oil and gas production increased 13% over the corresponding period last year. This can be attributed to increased drilling activity and the reduced impact of pipeline disruptions in Colombia, as well as higher production in Brazil, but

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partially offset by reduced production in Argentina. An interesting feature of Gran Tierra is that its capital structure is debt free since Q3 2011, thus offering a healthy financial foundation that will enable the potential growth in Peru and Brazil.

Moreover, the company announced at the beginning of December 2013 more positive drilling and logging results in Colombia from the Moqueta-12 (Putumayo basin) delineation well and the Mayalito-1 (Llanos basin) exploration well.

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Shale gas myths and reality - part 1 Written by Euan Mearns from Energy Matters With European energy security draining away, any discussion about our energy future should begin with energy security, price and a rounded assessment of the impact that new energy supplies may have upon our environment. European primary energy production peaked at 1136 million tonnes oil equivalent (mmtoe) in 1997 and has since fallen 15% to 970 mmtoe in 2012[1]. It is against this backdrop that many European governments are now embracing The American Dream in promoting shale gas as the cheap, clean, abundant and secure “bridging fuel” to a carbon free energy future. None of this is true.

Shale gas is not cheap, it’s certainly not clean and in geological terms it is a lowgrade resource. Any country going down this route is also making a commitment to drill hundreds to thousands of new wells every year to keep the gas flowing. So where does the truth really lie? In part 1 of 2, I describe what shale gas is and consider environmental factors such as intensity of development, potential contamination of ground water and CO2 emissions. Part 2 will consider economics and shale gas potential of the UK.

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Figure 1 The Northwest corner of Bradford County in Pennsylvania USA [2]. This is a production sweet spot in the prolific Marcellus Shale. Mixed arable land with forest close to the Appalachian Mountains, not too dissimilar to parts of rural England and Europe. How many shale gas drilling pads and production wells can you see in the image? What impact does this have on a landscape already overprinted by Manâ&#x20AC;&#x2122;s roads, farms, towns and quarries? Click on all images to get a large version that opens in a new browser window.

The energy debate With energy prices rising once again and frost creeping under the doors of many pensionerâ&#x20AC;&#x2122;s homes in Scotland, politicians are blaming everyone but themselves for our energy plight. In trying to reach any sensible conclusion in a discussion about our energy future, it is important to understand our energy past. Since the middle of the 19th century growing supplies of cheap fossil fuels (first coal, then coal+oil and then coal+oil+natural gas) powered industrial society enabling the global population to explode to 7 billion souls (Figure 2). This era is coming to an end. Not because of climate change but because we are running scarce of cheap fossil fuel. Hence the great interest in the alternative to cheapfossil fuel i.e. expensive fossil fuel, i.e. shale oil and gas. Cheap fossil fuels brought society a myriad of benefits that we have all come to take for granted (Figure 2). Society is going to have to accept that any effort to replace cheap fossil fuels with alternatives, be it wind power, nuclear power or expensive fossil fuels means there are going to be costs associated with those benefits. These costs come in the way of higher energy bills, inconvenience and environmental degradation. The choice is between accepting these costs and having the lights on at Christmas or not. The energy debate is multi-dimensional, and so there is no right answer. Only a choice between a number of poor options.

Figure 2 In the 18th century, Europeans were running out of wood to burn. And then along came coal, the steam engine and before we knew it, Porsches, iPhones and holidays in Spain. The wealth created by consuming fossil fuels has underpinned the explosion of global population by providing food and amazing advances in medicine such as the eradication of smallpox that killed 300 to 500 million people in the 20th Century. Society would do extremely well to not forget the stunning benefits that coal, oil and gas has provided.

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What is shale gas?

Conventional oil and gas is formed at a depth of approximately 3000 m (10,000 ft) when mudstones (shale) rich in organic matter (the source rock) are heated to about 100?C and squeezed by burial to produce first oil and then gas as burial and temperatures rise. If the organic content is high, so much oil and gas are produced in the mudstone that it creates natural fracture pathways and escapes. Being lighter than water it floats upwards where some is trapped in either sandstone or limestone reservoirs (that act like sponges) that we commonly know as oil and gas fields.

These are super-concentrated accumulations of energy (Figure 3).

In shale gas and shale oil, the organic content of the shale is lower and the gas and oil that is formed by the same processes remains trapped in the shale. These are low grade concentrations of energy distributed through vast volumes of rock. The gas and oil does not escape because the shale is “impermeable”, that is it lacks connected holes big enough to allow fluids to flow through it. The drain in a shower is permeable. A drain covered in hair is not. A sieve is permeable. A sieve clogged with starch after straining rice is not.

Since shale is impermeable and has not given up its gas and oil for millions of years Man has invented a way of making it permeable, namely hydraulic fracturing (fracking). In fracking, a fracking fluid is pumped into the well at extreme high pressure so that the pressure in the well exceeds the confining pressure of the rock which then fractures, enabling the gas or oil to flow. This is tantamount to “blowing up the rock” deep down in the Earth’s crust. But that is only part of the story.

Fracking shale only really works in long horizontal wells drilled along “sweet spot” horizons (Figure 3), where multiple fracking events may be conducted. Drilling long horizontal wells and conducting multiple fracks costs a lot of money and energy. How on Earth can shale gas be cheap?

Figure 3 From the US Energy Information Agency. Pools of conventional oil and gas flow freely to the surface whilst in shale the well is drilled along the gas rich zone and fracking shatters the rock to enable some of the trapped gas to flow into the well bore.

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Intensity of development Of the various environmental impacts discussed below, it is the intensity of shale developments, should they go ahead, that may give reason for concern. In the USA good wells tend to produce between 2 and 5 million cubic feet per day at the start, declining to around 1 million cubic feet per day per well after 2 or 3 years. A universal feature is high decline rates, typically 40% in the first year and 20 to 30% in subsequent years [2]. This means that once you jump on the shale carousel you have to keep drilling to maintain or grow production – lots and lots of wells every year.

To place this in context, the UK currently consumes about 8000 million cubic feet of gas per day [1] and so to provide all of our gas needs from shale would require about 8000 wells.

On average fracking a well requires 1000 truck trips to transport material from and to the well site (email correspondence from a US Oil company CEO) Another way to place this in context is to compare shale production with large conventional off shore gas fields. Initial flow rates from the Ormen Lange gas field in Norway were of the order 350 million cubic feet per day per well [3]. Initial production from the Marcellus shale of Bradford County is typically 4 million cubic feet per day per well. Thus around 88 shale wells may be required to replace a single offshore well. Of course, if it was easy to find large new offshore gas fields in Europe then we wouldn’t be contemplating shale, but we can’t. Most of the large European oil and gas fields have already been found and the reserves used up. And of course, drilling shale onshore dispenses with the need for massive offshore structures and sub-sea pipelines.

The intensity of development should really only be of concern during drilling operations. In Bradford Co Pennsylvania, well spacings are typically 1 to 2 km (Figure 4). And so a neighbourhood may be inconvenienced for a few months while a well is being drilled, but then the drill crew packs up and moves on leaving a clean and tidy drill pad with a well head. But the drill crews may return at some future date to re-frack the well.

Figure 4 Vertical view of Figure 1. I count 9 shale wells, some with tailing ponds. The landscape is already 100% overprinted by Man and once the rigs are gone, the visual impact of the drill pads should not be too significant.

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Gas wells also need to be connected to a processing plant by pipelines that will inevitably result in more disruption during the construction phase. The processing plant will take the form of a mini petrochemicals complex where ethane and longer chain hydrocarbons are removed and used by the petrochemicals industry and impurities like N2 and CO2 are removed and most probably vented.

The scale of shale drilling operations in the USA has been phenomenal. The shale miracle has been brought about by application of sheer American muscle. There are currently 1685 land rigs drilling in the USA (source Baker Hughes). In the UK in October there were 2 land rigs drilling and 34 land rigs in the whole of Europe (excluding Turkey). If the UK and Europe are to emulate the USA then there will need to be an enormous up-scaling of onshore drilling equipment and materials and the accompanying supply chains. All this of course would be extremely good news for employment in the heavy industry sector.

Ground water contamination The most commonly voiced concern about shale drilling and fracking operations is contamination of ground water by the fracking fluid. The Royal Academy of Engineering has conducted a comprehensive review of this and say the following [4]: Concerns have been raised about the risk of fractures propagating from shale formations to reach overlying aquifers. The available evidence indicates that this risk is very low provided that shale gas extraction takes place at depths of many hundreds of metres or several kilometres. Geological mechanisms constrain the distances that fractures may propagate vertically. Even if communication with overlying aquifers were possible, suitable pressure conditions would still be necessary for contaminants to flow through fractures. More likely causes of possible environmental contamination include faulty wells, and leaks and spills associated with surface operations. Neither cause is unique to shale gas. Both are common to all oil and gas wells and extractive activities.

Of all the potential environmental risks associated with drilling shale, the risk to contamination of ground water can be reduced to extremely low levels.

Drilling a well also produces a large volume of drill cuttings (the smashed up rock), drilling mud and frackng fluid. Once the well is fracked, the fluid must be removed to allow the gas to flow. The drilling mud and fluids can become contaminated with heavy metals and naturally occurring radioactive isotopes. If large-scale shale drilling operations were to proceed, any government will require a plan for disposal of these by-products of the drilling process.

CO2 emissions One of the biggest myths associated with shale gas is the notion that it can help reduce CO2 emissions. Burning natural gas instead of coal today can certainly reduce the rate of CO2 emissions (Figure 5). But this is only of any value to the greenhouse gas content of the atmosphere if the coal not burned today is never burned. Of course once we run out of gas to burn we will turn back to coal. The US is currently crowing about the reduction in CO2 intensity of its economy stemming from

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the shale revolution, but much of the coal not burned in the USA has simply been exported and burned else where, amongst other places in Britain.

Figure 5 A comparison of the CO2 intensity of various generating technologies by David MacKay [5]. In natural gas it is C-H bonds that are broken when the gas is combusted to form CO2 + H2O. In coal, it is mainly C-C bonds that are broken when it is combusted to form CO2 + CO2. Hence the much higher CO2 intensity of coal. A country can reduce itsrate of CO2 emissions by substituting gas for coal fired power but attacking the shale gas wedge of the resource pyramid will simply mean the burning of more gas long-term that will ultimately mean higher not lower CO2 emissions.

The real emissions concern with shale gas should focus on the gigantic size of the resource should it be exploited globally (Figure 6). We are beginning to attack a new slice of the resource pyramid. Any government, genuinely concerned about longterm emissions scenarios would quite simply ban shale gas operations.

Figure 6 This estimate of global recoverable shale gas from the BGS [6] contains 6318 trillion cubic feet (tcf).

According to BP [1] global gas reserves currently stand at 6545 tcf of mainly conventional reserves. Developing shale will effectively double CO2 emissions from natural gas and not reduce them.

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In part 2 I will take a cursory look at the economics of shale and explain why Rex Tillerson CEO of ExxonMobil is losing his shirt. I will also take a look at potential shale gas developments in the UK and attempt to summarise the many facets of the shale gas debate.

References 1. 2013 BP statistical review of world energy 2. Marcellus shale gas Bradford Co Pennsylvania: production history and declines 3. Norsk Hydro Tests First Ormen Lange Gas Production Well 4. Shale gas extraction in the UK: a review of hydraulic fracturing June 2012 5. Potential Greenhouse Gas Emissions Associated with Shale Gas Extraction and Use 6. The Carboniferous Bowland Shale gas study: geology and resource estimation

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OPEC warned on oil supply glut Written by Andrew McKillop from AMK CONSULT TIMELY ADVICE TO OPEC Leo Drollas, the head of the Saudi-backed, London-based Centre for Global Energy Studies in a 3 December interview with New Europe on the eve of the 4 December OPEC meeting, itemized several supply-side reasons why present high oil prices are not forever. Apart from the USA's record-breaking output of oil driven by its shale-oil production, Drollas said: 'Next year, Iraqi oil will increase by 300,000 barrels a day, we think at least, there will be 250,000 more from Venezuela, there will be possibly 1 more million barrels from Iran, when Iran comes back, and Libyan oil should return'.

For him, the bottom line was simple: '....so we have a glut on the horizon which should lead to lower prices.'

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To be sure the 4 December OPEC meeting was shuffled aside by analysts - because no decisions were taken, and in the absence of any change, oil prices were firmly pushed upward on markets by brokers and traders hungry for quick gains, drawing upside logic from US employment growth. Saudi Arabia's Oil Minister Ali al-Naimi in interview, December 4, shrugged off the prospect of a glut of new and additional oil supply in 2014. 'Everyone is welcome to put in the market what they can. The market is big and has many variables. When one comes in another comes out,' he said.

Brave words to be sure, but the political impact of Iran's declared intention to reassert its traditional role as OPEC's second producer, after KSA, and put more oil into the market as sanctions wind down should send warning signals to the few members of OPEC able to cut output without dangerously weakening their economies, civil societies and ruling parties. That is KSA, UAE and Kuwait.

At least three member countries not including Iran have signaled, in their own way, that they expect or believe it will be the job of KSA, UAE and Kuwait to cut their output. Venezuela's Energy Minister Rafael Ramirez, and Libya's Oil Minister Abdulbari al-Arusi both claimed in interview at the 4 Dec meeting that the present theoretical 30 million barrels a day (Mbd) official production cap or quota limit set by OPEC, to which Iraq is not bound and other countries largely ignore it, is a bulwark against oil price erosion. Iraq's Oil Minister Abdul Kareem al-Luaibi has several times rejected any question of Iraq limiting the growth of its oil production and oil exports, as an issue of Iraqi 'sovereignty and national pride'. .

The potential for Venezuela, Lbya and Iraq to voluntarily limit production is therefore low or zero. In the case of Iran it is negative - Iran will make all efforts to increase its production and exports, not only for 'national pride' or to reassert its regional political clout, but also to head off serious economic difficulties made worse by the sanctions regime and a major fall in its oil exports and revenues since 2011.

SUPPLY GLUTS PAST AND PRESENT The OPEC Annual Statistical Bulletin for 2013 skates around the unrealistically low 30 Mbd quota or cap, by including Iraq in the data and saying that for year 2012, OPEC's total production was a day average of 32.424 Mbd, producing total OPEC national revenues of a suspiciously exact $1688.2 billion the same year. Staying with its Annual Statistical Bulletin, this lists KSA's daily average oil production as 9.763 Mbd in 2012 - but current production this year has included monthly averages above 10.5 Mbd although according to Saudi oil industry sources cited by Reuters, 8 November, the country's rulers intend to 'throttle back' to about 9.75 Mbd by yearend.

To be sure the potential for simultaneous ramping-up of output from all four of the above-cited countries, and possibly Angola, in 2014, is either unlikely or in no way certain. Neither Iraq nor Libya can count on civil peace and both countries could literally break apart under worst-case civil, ethnic and political strife. However, the potential for Iran raising total output well above its 2012 rate as published by OPEC, of an average 3.729 Mbd, can be considered likely. Likewise Iraq's potential output growth - in the absence of intensified Sunni-Shia conflict - may be considerable and could exceed the 0.3 Mbd forecast by Drollas. Oil output by the breakaway Kurdish north of Iraq is also growing. Outside the Arab OPEC (OAPEC) states, high oil prices

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through 2005-08, and again since 2010 have lifted production in other OPEC members, and outside OPEC, spurring exploration and development. IEA data for late 2013 shows world oil output increased by over 2.5% in 2012-2013.

Backtracking to the pre-2000 context of very low oil prices (in 2013 dollars, under $20 per barrel for prolonged periods) which held through 1986-99, this seriously depressed oil investment and led to major declines in total oil output by the majority of OPEC states. Coupled with political turmoil, the reduction in total oil output capacity, compared to the previous high-oil-price period of 1973-85 was in several cases massive. Libya, for example, was then able to pump as much as 3.3 Mbd on a year-round basis, compared with at most 1.6 Mbd today; Iraqi output could exceed 4.5 Mbd, compared with 2.9 Mbd today, Venezuela's yearly average output on occasions reached 3.8 Mbd, close to 1 Mbd more than current production.

Taking these 3 OPEC states and Iran, their combined production today is as much as 5 Mbd less than their previous combined peak output. The big question is how much of the 'lost capacity' can be recovered and reinstated?

Prior to the 1986 oil price crash (a 65% price decline in 6 months), oil investment driven by high prices had lifted production - but world economic conditions of very slow economic growth and weak or absnet oil demand growth similar to today sparked a price war between producers, ironically led by Saudi Arabia. After a short period of trying to 'defend prices' in 1986-88 through cutting output by as much as 4.5 Mbd, it switched back to 'defending revenues' by reinstating maximum production, albeit at much lower barrel prices. This focuses our attention to what amount of 'fat to trim' is needed to prevent a price rout in 2014.

Producer logic and revenue needs - if not politics - identifies the self-described 'core Arab OAPEC producers' - KSA, UAE, Kuwait - as needing to cut their output in 2014 by at least 1.75 - 2 Mbd, if they want to defend prices. If they do not cut by that amount, unless there are serious and prolonged civil strife or civil war conditions in Libya and Iraq, major political difficulties in Venezuela, reinstated nuclear sanctions against Iran, and a major decline in oil output growth outside OPEC, oil prices are likely to fall by $25 a barrel or more in 2014. This we can note would only be a 25% cut in prices - compared with the 65% cut in 1986 - for reasons including much higher present-day breakevens needed in a higher production-cost environment.

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'Watch what we do, not what we say': Shell cancels U.S. gas-toliquids plant Written by Kurt Cobb from Resource Insights When civil rights advocates grew restless because of President Richard Nixon's right-wing rhetoric on the issue of desegregation, then-Attorney General John Mitchell told them,''Watch what we do, not what we say.''

Those following the hype over America's supposed newfound abundance of oil and natural gas would do well to follow that advice when evaluating what oil and gas company executives and their surrogates say.

When Royal Dutch Shell pulled the plug on its U.S. gas-to-liquids project recently, the company offered the same explanation it used when it shut down its oil shale project earlier this year: Shell sees better opportunities elsewhere. This explanation-much like the I'm-resigning-to-spend-more-time-with-my-family explanation--tends to deflect questions about why things aren't working out.

What's not working out for Shell is a planned $20 billion plant in Louisiana designed to turn natural gas into diesel, jet fuel, lubricants and chemical feedstocks, products typically produced by oil refineries. The plug was pulled, however, while the project was still in the planning stage.

Shell did actually say a little more about why it is abandoning the project in this almost inscrutable piece of corporate prose: Despite the ample supplies of natural gas in the area, the company has taken the decision that GTL is not a viable option for Shell in North America, at this time, due to the likely development cost of such a project, uncertainties on long-term oil and gas prices and differentials, and Shellâ&#x20AC;&#x2122;s strict capital discipline.

Now, here's the same paragraph translated into simple English: The plant is going to cost a lot more to build than we thought it would. Natural gas prices are going up and could easily make it uneconomical to produce diesel and jet fuel from natural gas when compared to making them from oil. And, we don't have unlimited funds to spend on everything we think of just to see if it works.

Shell CEO Peter Voser has voiced doubts about the so-called "shale revolution" in

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the United States (which refers to advances in drilling technology that have opened previously inaccessible shale deposits of natural gas and oil to exploitation). In fact, Shell took a $2.1 billion write-down on its shale assets in the United States. In lay terms, the company had to reduce the value of those assets on its balance sheet to reflect reality. The company also sold small tight oil fields related to shale deposits, fields that it no longer wishes to develop.

Voser said he still believes Shell's remaining $24 billion investment in U.S. shale gas and tight oil will "be a success story for Shell." Three-quarters of that investment is devoted to natural gas from shale. But, Voser added that the potential for natural gas and oil from shale elsewhere in the world has been "a little bit overhyped" citing concerns specifically about Europe.

Now, because this rhetoric is coming from an oil industry CEO, we can assume that he is walking the line between saying things which will get him removed from the invitation lists of his fellow oil executives' cocktail parties--things otherwise known as the awful truth--and misrepresenting the facts to shareholders, which would get him into trouble in other ways.

But abandoning the gas-to-liquids plant speaks much more loudly than Voser's actual remarks. It means Voser expects that natural gas prices simply won't stay low long enough to make such a huge investment pay off. And, that means that he doesn't believe the hype about an ongoing glut of U.S. natural gas.

So, Voser directs Shell to abandon a gas-to-liquids plant, the profitability of which would be destroyed by high prices for the natural gas which the plant must purchase.

At the same time, he has Shell retain most of its shale gas wells, a move which only makes sense if he expects U.S. natural gas prices to go higher. And, those prices will only go higher if there is increased demand or reduced supply, or a combination of both.

It's not hard to figure out the meaning of what Peter Voser is doing. But it is understandably difficult to shut out the constant din of abundance stories sponsored by the industry and its well-financed public relations machine--that is, until you understand that it's not what the industry says that's important, but what it actually does.

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Brent-WTI Premium Strangers in the night Written by Andrew McKillop from AMK CONSULT STRANGERS IN THE NIGHT 'Oil & Gas Journal' in an article by RBN Energy in its July 23, 2013 edition, when the premium or differential for Brent grade oil against US West Texas Intermediate collapsed to nearly zero from highs above $25 in 2011 and 2012, and a 2013 peak of $23 to date, said that despite the rebounds and recoveries, the premium has to decline. Its fundamentals are bad, the logic is bad, and the premium has strong headwinds. For oil brokers and traders, however, the heavily traded 'premium trade' is still good for a flutter on the markets. Brent's premium shook itself out of bed and jumped from $14.64 to $16.21 in the week ending Nov 22, in two days trading but fell back the following week.

GOOD BEDFELLOWS Normal times and their normal premium values - when they existed at all - date to the 1990s and early 2000s. As Dominick Chirichilla of the US Energy Management

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Institute noted in a May 2013 review of the premium and how it developed over time, noted that normalcy for the premium of Brent against WTI is no premium at all, but a small discount for lower-quality Brent against WTI. He said: 'In the 1990s, WTI had an average premium of about $1.30/bbl above Brent (and) from 2000-2009, WTI's premium averaged $0.55/bbl'. Pennies on the barrel difference in WTI and Brent prices, and no disputes. Brent was nearly always slightly cheaper.

As Chirichilla and most other analysts say, some oil fundamentals can be used to explain the yawning gap of Brent oil prices against WTI. In 2011 and 2012 the Brent premium could be attributed to the North American (US and Canadian) shale oil and gas revolution. The growing amounts of new crude oil available in North America meant that the only way to move the increased supply of crude entering the pricecritical US PADD-2 region (Midwest), where the Nymex oil market basing point of Cushing is located, was through the conversion of this crude into refined products. In other words, there was (and still is) a transport problem for the new crude which is being fixed, slowly. Through 2011 and 2012, crude supply was running, and still is running (but less so), above US refined product demand, capacity and production.

Crude oil inventories in the region inevitably surge on a regular basis.

Brent crude oil supply in the eastern hemisphere of the world, with its price determination highly focused on Europe but also influenced by Asian supplydemand, faces a very different context. Especially in Europe, there is a large surplus capacity of refining. Crude backups are rare and Brent prices can therefore 'stick' while WTI prices are driven down, widening the premium for Brent.

The geopolitical risk premium - essentially a Middle East political crisis premium loads to Brent not WTI, but by ricochet lifts WTI. This further spikes Brent against WTI whenever MENA region politics heat up, but the process has fundamental limits on how much oil export supply can be squeezed in the eastern hemisphere. This fundamental is ultra basic - all the major MENA region oil producers need oil export revenues to pay for the food imports they entirely depend on.

PROVISIONAL VICTORY FOR COMMODITIZATION As many analysts and commentators will also say, the 'fundamentals' of global oil resources, production, supply and demand in no way explains why Brent grade oil, of lower quality than WTI is able to be priced at double-digit-dollar levels above WTI. Oil market trading, which grew from the early 1980s and became dominant in oil price setting by about 1987, started in the early 1980s when the U.S. government's decontrol of oil prices changed trading mechanics, with the commoditization of WTI. At that time, US domestic oil production was running at a rate of 8.6 million barrels per day, with about 30% of that oil coming from Texas, but this was heavily cut back by the sharp decline of world oil prices from 1985. The price decline, of around 66% in 1985-86 set a 13-year trend of very low oil prices, and coincided with the growth of eastern hemisphere crude output, notably the European North Sea, on the supply side, and the start of the takeoff in Chinese and Indian oil demand and oil imports, on the demand side.

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Through a period we can date at around 1987-2005, US oil import demand was either high or very high and European and Asian import demand was steady or strong, always at a high level. No basic rational base however existed for the commoditized play on European oil prices versus US oil prices, but trading of the premium has gained its own place in financial market lore and action.

Not at all without risks, as Reuters reported Nov 25, 2013: 'One of the most popular trading bets in oil markets, based on attempts to predict price differences between European and U.S. oil benchmarks, is proving to be one of the trickiest as funds suffer losses after sky-high gains earlier this year'.

In other words its easier make gains when the premium is high, and vice versa.

Rightly called 'a widow maker' by some seasoned oil market analysts and traders, the premium is hard to play-trade when it shrinks near zero and when volatility increases.

One thing is sure and certain. US WTI, unlike Brent has major tailwinds for significant price decline, but to what level few analysts want to say - some put the figure around $70 per barrel based on elevated shale oil production costs. In pure theory this would or should pull down the Brent price, rather than high Brent prices pulling up US WTI. The now intrinsic and basic high volatility of the premium indicates major adjustment is likely - and on a rational basis, this should be an adjustment to reality meaning a shift to very low premiums for Brent against WTI in coming weeks.

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The risk management black hole in the oil and gas supply chain Written by Chris Bohill from Biznet Solutions Chief executives of oil and gas companies might not want to be reminded of this, but typically around 80% their spend, personnel and HSE risk lie beyond their control, and in the hands of suppliers.

As a result, they are unquestionably exposed, probably personally as well as corporately, to legal challenges and compensation claims. There is, after all, nothing quite like evidence of inadequate management of risk to encourage litigants.

This is all because most operators are totally dependent on their supply chains for the day-to-day running of their business. This exposure, if not monitored and managed, can have disastrous consequences. All too often it is the name of the operator we read about in the press following an incident which occurred as a direct result of a problem within their supply chain.

And yet arguably, insufficient recognition is given to the risk the supply chain poses.

The actual management of the supply chain tends to fall under the remit of the procurement / purchasing department who typically focus their efforts in ensuring the best possible contract terms for their company. Ensuring that suppliers continue to deliver on those agreed terms throughout the lifespan of the contract, let alone put in their best performance, is often over-looked or under-valued.

Senior management within the oil and gas companies may be given the clear impression that procurement has got things under control when it comes to the supply chain so the assumption is made that this encompasses management of supplier risk. Indeed it's easy to present onerous reporting systems and a plethora of data as management of risk. However, unless the senior management give supply chain managers and procurement teams their ear, any issues or process weaknesses are unlikely to end up on the board's radar.

We all know how things work in large oil companies. The senior management see the profits rolling in through the supply chain, procurement say they have all the relationships taped so who wants to rock the boat by asking too many questions?

The reality is, however, that this situation should be unacceptable to everyone involved: senior management themselves, procurement, the supply chain and - of course - shareholders, because unmanaged risk is patently toxic.

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The root cause of the problem is a lack of understanding of supplier performance management, or perhaps more the rudimentary and blinkered way in what passes for it, is applied in many organisations.

For many procurement professionals, supplier management is synonymous with rigorous and complex contract negotiations. On-going management is where the huge volume of data comes in. Anything that keeps the supplier on the straight and narrow and helps avoid issues such as regulatory non-compliance or personal and corporate liability claims and disputes, is deemed to be a good thing.

Equally, supplier management is not confined to a piece of software. Any technology is there is to enable you to develop and run your own supplier management process.

If the software becomes a drain on resources or a barrier to openness, communication and co-operation, then it is not doing its job.

In fact, software - while vital - is only one part of the mix. Proper supplier performance management is much more wide ranging, collaborative and relevant.

The starting point should be: how can we work closely with our suppliers so that they share our goals, add value to our business now and over the long term, help us to manage our risks in all areas and improve total cost of ownership?

The process for doing this should be simple and totally transparent. The only way that you manage the risk within the supply chain properly - or indeed any discipline is to create visibility.

The next key principle is alignment of goals. The suppliers' goals and values must be aligned with yours. With suppliers having such an impact in the success of your business how can you achieve your corporate goals and objectives if your key strategic suppliers are not rowing in the same direction? The simple answer is you cannot.

At the same time, supplier performance management should drive the sharing of supplier innovation and application of best practices and continuous improvement, with the ultimate goal of becoming 'customer of choice', a key stepping stone in differentiating you from your competition.

KPIs do, of course, have a role to play. But it's important to use them both sparingly and highly selectively. KPIs should be the link between a company's corporate drivers and its large supply chain. They should encompass such issues as risk management/assessment, Corporate Social Responsibility (CSR), Health and Safety protocols, communications, as well as quality, efficiency and cost expectations. A good supplier performance management partner should work around no more than 10 KPIs per supplier relationship.

It's not just large oil and gas companies that are starting to see the benefits of proper supplier management. In many cases, especially among the big players, the suppliers themselves are adopting systems and presenting them as a benefit to their clients.

This makes perfect sense as this approach offers a modern, co-operative alternative

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to the systems deployed by many procurement departments who are simply stuck in a rut. It's not their fault; it's just that with so much of a company's operations being run through the supply chain, systems based on complex contracts, numerous irrelevant KPIs and heavy-handed control are simply not what's required now.

The world has moved on and it's time to rethink the relationship between oil and gas operators and their supply chains. When the profits are pouring in, as they are now all over this industry, nobody wants to fix something that doesn't appear to be broken. But management of supplier risk within the supply chain and the development of suppliers as key strategic partners is key to ensuring corporate goals and objectives are delivered, safely and without incident. Supplier Performance Management provides the foundation for building such a relationship, while equipping supply chain managers with a global view of supply chain risk, and the tools to manage it effectively.

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