OilVoice Magazine | September 2014

Edition Thirty – September 2014

Making sense of the US oil story Is big oil gearing up for mega-mergers?

North Sea Oil and Scottish Independence: where does the truth lie?

Cover image by DVIDSHUB

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OilVoice Magazine | SEPTEMBER 2014

Adam Marmaras Chief Executive Officer Issue 30 – September 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 Mark Phillips Email: sales@oilvoice.com Chief Executive Officer Adam Marmaras Email: adam@oilvoice.com

Welcome to the 30th edition of the OilVoice Magazine.

We’re always tweaking the OilVoice website based on feedback from our dedicated readers. This month we made changes to the layout of our article pages, making it easier to digest the latest oil and gas news.

This month we have great articles from ABT Oil & Gas and RMRI, and Mars Omega. We'd also like to welcome back some of our regular authors, including Gail Tverbeg, David Bamford, and Mark Young.

If you're interested to know more about seeing your articles featured on OilVoice, please get in touch.

Social Network Adam Marmaras Facebook Twitter Google+ Linked In Read on your iPad You can open PDF documents, such as a PDF attached to an email, with iBooks.

Cover image by DVIDSHUB

flickr.com/photos/dvids

CEO OilVoice

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OilVoice Magazine | SEPTEMBER 2014

Contents Featured Authors The biographies of this months featured authors

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Tech Talk - Rig counts in the Middle East

by David Summers

5

Lifting sub-surface interpretation into the second decade of the 21stC!

by David Bamford

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Making mature petroleum provinces economic

by David Bamford

10

Using clusters as a regional development strategy for marginal fields in the North Sea

by Chidozie Ewuzie & James Fox

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Is big oil gearing up for mega-mergers?

by Loren Steffy

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US companies benefit from move from natural gas to oil production

by Mark Young

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The strange case of US confusion over Kurdish crude

by Anthony Franks OBE

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When "common sense" really amounts to nonsense

by David Blackmon

31

North Sea Oil and Scottish Independence: where does the truth lie?

by Euan Mearns

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Making sense of the US oil story

by Gail Tverberg

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OilVoice Magazine | SEPTEMBER 2014

Featured Authors Chidozie Ewuzie & James Fox ABT Oil & Gas and RMRI ABT Oil and Gas (ABTOG) is creating a new marginal field sector within the oil and gas upstream market: the economic development of small or stranded hydrocarbon accumulations.

RMRI is an independent, risk management consultancy delivering bespoke decision making support for over 20 years.

Mark Young Evaluate Energy Mark Young is an analyst at Evaluate Energy.

David Summers Bit Tooth Energy While one of the founders of The Oil Drum, back in 2005, he now also writes separately at Bit Tooth Energy.

Anthony Franks OBE Mars Omega LLP Anthony is responsible for managing and controlling the extensive information networks, as well as directing and working with the analysis team to create reports for clients, and also works with Hamish in the Liaison and Mediation service.

David Blackmon FTI Consulting, Inc. David Blackmon is managing director of Strategic Communications for FTI Consulting, based in Houston.

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OilVoice Magazine | SEPTEMBER 2014

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

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.

David Bamford Petromall 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 | SEPTEMBER 2014

Tech Talk - Rig counts in the Middle East Written by David Summers from Bit Tooth Energy In recent posts about the situation in the Middle East, I have noted the need for Aramco to increase the number of drilling rigs that it must use, since it is now looking for natural gas in their tight sand deposits rather than finding the large reserves that they had hoped in the shale reservoirs. It is interesting in this regard to plot the number of rigs that have been working in the Middle East.

Getting the overall data from Baker Hughes the rig count can be plotted, over time, to give the following:

Figure 1. Rig Counts in the Middle East (Baker Hughes) If one looks at the trend for the last twelve months, it has remains on a fairly consistent upward trend, following that of the longer time interval plot of Figure 1.

Figure 2. Recent trend in Middle East Rig count (Baker Hughes)

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OilVoice Magazine | SEPTEMBER 2014

Back in the days of The Oil Drum, Euan Mearns and I had this concern, which occasionally surfaced, about these numbers. From my early post on the subject which noted that back in 2005 the KSA were running around 20 rigs, which would not be enough to get them the production they were claiming to need in the future, to Euan’s in 2011, the topic was revisited regularly over the time that the count steadily mounted as the Kingdom had to drill an increasing number of wells just to keep production at around the same overall level.

I am using the KSA as the example, given the large volume of its production relative to that of the others in the Middle East, but as the numbers show, the trend toward increased drilling rate to create enough productive wells to sustain production as the larger volume wells dry up is starting to become a steadily more frantic race across the region.

Rune Likvern used the phrase “Red Queen” in discussing the overall long-term need of the companies in the Bakken to have to drill an increasing number of wells, with individually reducing production, in order to remain in place with regard to overall production. As the production from the Bakken now exceeds a million barrels a day it may seem foolish to be predicting this “squirrel cage” view of the future, but the rig count up there is still running at around 190 rigs, which is not enough to sustain future growth for long, given that access to the sweet spots is limited, and they are beginning to run out of new sites.

So it is in the Middle East. The rig count numbers are mounting steadily, it is reported that there were 88 rigs drilling in the country in October 2012. Last year this rose to 170, and the number is expected to rise to 210 by the end of this year.

Aramco have done remarkably well, over the past decade, in developing new technologies to harvest the attic oil left around the tops of the major producing formations such as Ghawar, as the main body of the fields begin to be exhausted.

But the problem with these secondary rig operations is that they were directed at the smaller pools around the field, rather than tapping into the major volume, and thus they had an expected and finite life. That life is starting to come to a close. Just as, when sucking a thick milk shake through a single immovable straw, when it stops drawing fluid, there is still a fair amount left in the cup. But as you move the straw around and slide it up and down the sides, the amount that you recover gets less, and it takes greater and greater effort to get it, to the point where you quit and discard the carton. And that is where the Middle Eastern oilfields are beginning to find themselves.

The high-quality light oils of the mainland are rapidly running out, and the remaining fields with the promise for sustaining Saudi production at around 10 mbd for the next few years, are the heavier sour crudes from the offshore fields such as Safaniya and Manifa. At the same time there is a need to reduce the increasing amount of oil (now at 3 mbd) being consumed in country, with the hope that this can be replaced by domestic natural gas. But those hopes are being reduced as the shales are found to be less productive than anticipated, and hopes are now switching to the slower production that can, hopefully, be achieved from the tight sands – but at the cost of an increased number of wells, inter alia.

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This is the writing on the wall for global oil production, and in the short-term it will be neglected. Increasing the number of rigs will, in that interval, increase the number of wells that will produce, even though the volume from each well will be less, and the overall life of the wells will similarly reduce, as higher production techniques tap into smaller fields.

But we are now on the treadmill in the squirrel cage, or, as Rune would have it, we have wrapped ourselves in the cape and crown of the Red Queen, and must run faster and faster just to stay in place. (There are additional concerns since, as an example, Manifa could not be brought on line until there were refineries built that could process that crude, and so the options for increasing production beyond the capacity of refineries to absorb that increase is a futile exercise).

There will soon come a time when the gain from the overall increase in new wells will not match the decline in production from older wells, particularly if the effort to “run faster� is restricted to only a few players (Russia for example is not yet putting the effort and investment into increased drilling rates in order to sustain their overall levels of production, and given the age of their major fields are likely now in terminal decline).

Ouch!

View more quality content from Bit Tooth Energy

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OilVoice Magazine | SEPTEMBER 2014

Lifting sub-surface interpretation into the second decade of the 21stC! Written by David Bamford from PetroMall Despite continuing high oil prices, mature producing provinces continue to be challenged by poor economic returns. In part this is due to exponentiating costs. In part it is due to the failure of oil & gas companies to grow reserves, whether by:    

Exploration for new fields Exploitation of existing discoveries Reservoir Management of recently developed fields Deployment of IOR/EOR technologies.

And yet we have a multitude, a “wall”, of new types of data that in principle allows us to better describe prospects and discoveries, and to better describe and monitor producing fields. Assuming we can integrate all these multi-measurements – and that is a big assumption – perhaps we need to move our subsurface analysis and interpretation beyond the LCD provided by IT-department approved, commercially available, work stations? It simply cannot be – or cannot allowed to be – true that the hardware and applications that we see on the vast majority of sub-surface folks’ desks today represents some sort of apogee of digital technology. Compared with most other digital technologies – whether video games, weather forecasting, sports punditry, financial trading – most of our sub-surface interpretation tools have been parked by our IT Departments and the supply behemoths back in the latter days of the 20th Century, not the second decade of the 21st!

My observation is that we have two choices: 1. Machine-led analysis aka “Analytics”.

2. Team-led interpretation via Visualisation. and that – maybe – this is actually an ‘and’ conversation rather than an ‘or’ one.

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OilVoice Magazine | SEPTEMBER 2014

Making mature petroleum provinces economic Written by David Bamford from PetroMall One view of the UKCS and NOCS is that as exploration discoveries get smaller and/or more complex, they become uneconomic, in some companies’ minds condemning the whole region.

However, recent history shows that such an analysis is too simplistic and that provided a single operating entity can control enough resources, then the key parameter is cost/boe and good economics can result from such an operator’s twin approach of finding more resources/reserves and reducing the costs of proving and producing them, by benefitting from scale and synergies, supply chain optimisation etc.

This figure illustrates some of the ‘levers’ available:

Most of these ‘levers’ require the adroit application of technologies, more often than not digital technologies; let’s consider each of them in turn: Exploration It is easy to argue that NW European exploration – in the NOCS, UKCS and onshore – is now so Mature that further significant, economic discoveries should not be expected.

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OilVoice Magazine | SEPTEMBER 2014

However, we simply do not know whether there are new plays to be tested and significant new discoveries to be made because the underpinning work has not been done.

In particular, the petroleum potential of NW Europe has not been assessed by drawing together a detailed chronostratigraphy, global geodynamics and all available public data, from wells, outcrops, publications, maps etc.

This problem is entirely solvable by the techniques of Gross Depositional Environment & Common Risk Segment mapping.

Exploitation There has been no area-wide review of undeveloped discoveries nor of known but non-completed reservoir intervals.

Here the key will be more sophisticated attribute analysis of existing mega-3D surveys, integrated with a profound understanding of rock physics.

Reservoir Management Reservoir dynamics can be far, far better understood by monitoring fluid movements with seismic, fibre optics, flow meters etc, and integrating this factual data with improved, faster, reservoir simulation honouring geomechanics.

This leads both to improved recognition of reserves and therefore production, at the same time lowering costs because well locations and completions have been optimised.

IOR/EOR Too many companies are content with field recovery factors that settle between 30 and 40% whereas technology can take us to 60%+.

A wide range of technologies are now available from ‘Smart Water’ via WAG to CO2enabled EOR. Drilling & Completions Rig costs are the prime driver of ‘oil patch’ cost exponentiation, and are too controlled by a small handful of companies.

We need to promote competition in NW Europe, and promote cheaper options such as coiled tubing drilling and even cheaper options such as wireline tractors, for well intervention and completion. Technology options include sending real time drilling data to shore to improve decision making, ultimately leading to unmanned (safer, cheaper) drilling.

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OilVoice Magazine | SEPTEMBER 2014

Digital Oil Field (DOF) Integrated Operations - DOF technologies - are the way to run fields efficiently and effectively, removing personnel from the production environment (safety), optimising production, reducing costs.

And finally...

It is not helpful for politicians and civil servants to give ‘lectures’ about cooperation and collaboration – perhaps they would do better to set us all an example!

Regional Operating Entities (ROEs) need to control ‘big swathes’ of acreage, covering enough reserves to enable economic development; having 500mm to 1bn boe reserves under the control of one ROE would seem to be the right scale. This requires industry consolidation.

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OilVoice Magazine | SEPTEMBER 2014

Using clusters as a regional development strategy for marginal fields in the North Sea Written by Chidozie Ewuzie & James Fox from ABT Oil & Gas and RMRI The UK North Sea is a mature basin with an extensive and well-developed network of production infrastructure consisting of platforms, pipelines and onshore processing plants and terminals. The basin has so far produced around 42 billion barrels of oil equivalent (boe), and it is estimated that up to 21 billion boe could be further produced[1]. Over the past four decades, this production capacity has been built up using 'daisy chains' of infrastructure that was originally installed to support large offshore projects, but which has since unlocked new opportunities. Each ‘cluster’ of fields typically started out with a single, large, field development in a fallow area, such as the Forties and Brent fields in the 1970’s. To maximise economies of scale, exploration activities were then concentrated around these massive oil and gas fields and often led to new discoveries and prospects being found. Large fields were developed with above-surface infrastructure while smaller and more marginal discoveries were often then developed via subsea tie-back to existing host facilities, receiving terminals, or other subsea infrastructure which acted as a hub for development of the area. These small fields required a low cost development to be commercial, hence the option of tie-backs. This pattern has been repeated over several years, aided by high oil prices, resulting in the growth of infrastructure and production in the basin.

However, production efficiency of oil and gas fields across the UK Continental Shelf (UKCS) has declined from 81 per cent in 2004 to its current level averaging below 60 per cent[2] because the production facilities are experiencing more frequent and longer outages as they age and many are now operating beyond their design life.

This has largely contributed to the 63 per cent fall in oil production over the same period[3], costing the Treasury £6 billion in lower tax receipts[4]. The maintenance procedures necessary to keep these ageing assets operating safely in order to extend useful life is cost intensive ensuring they have very high per barrel operating costs. This upward pressure on costs makes it more difficult for operators of smaller fields to negotiate satisfactory commercial tie-back arrangements with infrastructure owners. As such, infrastructure in mature areas in the North Sea is under increasing commercial pressure as maintenance costs increase and throughput diminishes [5].

The Wood Review notes that the pace of new developments is being constrained in part by the inability of third parties to negotiate appropriate technical and commercial terms to achieve access to existing infrastructure. As a result, developments are taking longer to implement and often end up being sub-optimal[6].

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A New Development Model A massive investment in existing production infrastructure is required to maintain safe and reliable operations and increase production, however, declining production income makes it difficult to support such levels of investment. Therefore, a shift in approach is necessary to facilitate an evolution in the design of low cost production systems that can be independent of ageing facilities. In our earlier article, we introduced two such production systems developed by a British company, ABT Oil and Gas Limited (ABTOG), along with its partners – the Production Buoy and SelfInstalling Floating Tower (SIFT). These are cost effective, mobile standalone production systems suited for use in marginal field developments which are capable of redeployment and can be independent of existing infrastructure. These systems have the added advantage of reduced reliance on expensive installation vessels, simplified project delivery, and can operate normally unattended.

The SIFT is an offshore oil production facility capable of multi-field processing which primarily targets oil and gas fields within 50 – 150 m water depth, ideally suited to the North Sea. It has a design life of 25 years, is redeployable, and can be remotely operated as a Normally Unattended Installation (NUI). It is comprised of structural columns that are fixed via the foundation to the seabed. The structural columns support multipurpose topsides which contain the necessary process, utilities and ancillary facilities required to process the well fluids. The crude oil is stored within the structural columns and additional oil storage cells can be located between the structural columns. The crude is then transported to a terminal via periodic shuttle tanker visits; hence the system can be independent of local infrastructure.

The Concern over Decommissioning As larger fields are depleted and production facilities are abandoned and decommissioned, this will have an adverse effect on future production in the basin.

The loss of strategic local infrastructure as the ‘daisy chain’ fragments will remove a primary means of oil production in the basin leading to more stranded small and marginal fields.

The Wood Review sets out a decommissioning strategy that aims to achieve the maximum economic extension of field life and to ensure key assets are not decommissioned prematurely to the detriment of production hubs and infrastructure.

However, many of these assets are already past their design life and therefore decommissioning, whilst being possibly delayed, is inevitable. In the UKCS, there are several critical hubs at risk of decommissioning. The current course of action places at risk billions of reserves that could be left stranded and extending the useful life of existing assets is cost-intensive. With the ABTOG’s low cost production systems, there is an opportunity to avoid such risks and reframe how mature basins are exploited.

Decommissioning will also have a significant impact on exploration and future discoveries. Exploration activity is declining rapidly as the size of discoveries continue to reduce and this coupled with ageing infrastructure in the basin does not create a conducive environment for the sanction of multi-million pound investments

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that could be deployed anywhere in the world.

The maturity and decline of the North Sea means that decommissioning activities will be ongoing at different hub locations for the remainder of the North Sea’s productive life. Hannon Westwood estimate that by the 2020’s the areal coverage of active hubs may shrink to less than 50 per cent of the area containing prospects or discoveries and some 3 billion boe would remain “unassigned” to hubs and would require either standalone development or extended connectivity to existing hubs[7]. As such, what is required is a focus on proven standalone production systems which can be independent of existing infrastructure and also capable of providing a commercial development for small and marginal fields, thereby maximising recovery and extending the life of the basin. Therefore, given the emergence of ABTOG’s production systems, the current concern over decommissioning is somewhat misplaced.

The Development Potential

Figure 1- Map of a cluster of marginal fields in the North Sea In this report, we have set out to demonstrate an alternative model for the development of a cluster of marginal fields in the North Sea using a SIFT. To illustrate this model, we have modified data from the central North Sea (CNS) where we identified a cluster of five marginal discoveries and end of life fields in a 25 km radius, all located in 100 – 110 m water depths and within the operating envelope of the SIFT. A map of the area is shown in Figure 1 above. Two discoveries within this group are stranded by distance (~ 19 km) and insufficient processing capacity at the nearest platform which is due for decommissioning in around 5 years. Another two are closer to the fixed platform but have been held back by inability to finalise a commercial agreement for a tie-back. The final one is an end of life field due to be stranded when the nearby FPSO is removed. The total mid-case reserve size for all five fields is 25.6 million boe. The end of life field at 3 million boe can be developed because the cost of the SIFT has been amortised over the production life of the first two fields to be developed, therefore the major capital expenditure associated with this field is the well re-entry cost. This unique advantage of the SIFT enables the economic development of minute reserves and therefore maximises economic recovery of the basin. A map of the sequence of development of the fields using a SIFT as a hub or enabler is shown in Figure 2 on the next page.

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OilVoice Magazine | SEPTEMBER 2014

Figure 2- Map showing the sequence of development of the cluster area using the SIFT as a hub To see what can be achieved by this development scenario, a cashflow model was developed to evaluate the development of marginal fields in this cluster area. The development is split into three phases. In the first phase, the SIFT is deployed to the first stranded field and after two years of production, the second stranded field is tied-in. At cessation of production (COP) after six years, the SIFT is retrofitted for a year and redeployed to the mid-point of the two discoveries close to the fixed platform to be decommissioned. These will be developed simultaneously and produce for six years before COP, and then the SIFT is retrofitted again and moved to develop the end of life field using existing wells. Eventually, 25.6 million boe of reserves is produced from all five fields over 20 years from project inception to abandonment.

With oil prices fixed at $90 per barrel and ignoring the impact of inflation, the entire project has a pre-tax NPV10 of £365 million and generates gross revenue of close to £1.5 billion with a combined capital and operating expenditure of approximately £650 million. The project as a whole therefore generates a pre-tax profit of close to £800 million. Taking deductions such as the small field tax allowance, we estimate the tax revenue to be almost £390 million and therefore the post-tax profit is over £400 million. This equates to almost £16 of post-tax profit per boe and £15 of tax revenue per boe.

We have identified over 120 marginal fields in the North Sea which could be developed using a SIFT and we estimate that it would take between 20 – 30 clusters such as the one described above to develop these fields. If we assume that all the fields are developed, the potential worth to the UK economy is estimated to be in excess of £37 billion; over £19 billion of post-tax profit and £18 billion of tax revenue.

While we estimated the contribution to the UK to be in excess of £40 billion in our earlier study, the cluster model is simply one way of unlocking marginal reserves and therefore this is consistent with our earlier results.

Summary and Conclusion The conventional view of marginal field development assumes that as critical infrastructure is lost, tie-backs will become increasingly difficult to implement and less cost effective. Higher costs will lead to medium sized fields becoming marginal

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and small fields becoming sub-commercial. Also, with fewer production hubs available, the basin will continue to decline as the means of production is lost. As such, developing marginal fields in the North Sea has been described as a race against time[8]. This view is mistaken and now outdated as the standalone systems introduced by ABTOG have the dual benefit of utilising pipelines and existing infrastructure if available or acting as a standalone production system if necessary.

The joint industry – government task force – PILOT – estimates that between 0.5 – 2 billion boe[9] of reserves are at risk from the early decommissioning of existing infrastructure while industry experts Hannon Westwood estimate the overall potential loss in reserves due to loss of infrastructure is around 7 billion boe[10]. These reserves that were thought to be at risk from decommissioning and soon to be stranded can now be commercially recovered through the use of ABTOG’s production systems. Improved data sharing, collaboration, greater third party access and fairer commercial and technical agreements for access to infrastructure are all valuable ideals, but it is debateable how these will be achieved in a highly competitive environment, even with a newly constituted and empowered regulator.

Therefore, independent, standalone production systems such as the Production Buoy and SIFT are the right solutions.

ABTOG's solutions present a viable means of developing marginal fields in the North Sea with or without the use of existing production and process facilities. These systems can also be applied to marginal or end of life fields in other regions where access to existing old infrastructure is not viable or simply not available. The UK could benefit via technology and knowledge transfer as these production systems are engineered and built in the UK and can exported to other regions to the benefit of the wider UK economy. In subsequent studies, we will further explore this opportunity.

[1]

http://www.gov.uk/oil-and-gas-uk-field-data#uk-oil-and-gas-reserves PILOT presentation, 31 October 2013 [3] http://www.gov.uk/government/collections/digest-of-uk-energy-statistics-dukes [4] Comparison of UKCS Tax Yield – Budget 2011 and 2013 [5] UKCS Maximising Recovery Review [6] ibid [7] Hannon Westwood hub analysis presentation, December 2011 [8] J. Harpin (2011). Measuring the impact of aging infrastructure in the UK North Sea [9] PILOT presentation, 2 May 2013 [10] See reference 7 [2]

View more quality content from ABT Oil & Gas and RMRI

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OilVoice Magazine | SEPTEMBER 2014

Is big oil gearing up for mega-mergers?

Written by Loren Steffy from 30 Point Strategies Big Oil may once again be getting ready to eat its own. The Guardian’s Ben Marlow raised the prospect once again this week, exploring the idea that Royal Dutch Shell might be warming to the idea of a merger with BP. For the past several years, one of the biggest questions among the majors is what happens to BP. The company’s shares have never recovered from the Deepwater Horizon disaster in April 2010. BP has sold $38 billion in assets to pay the ongoing legal costs, and it has set aside $42.5 billion to cover the cleanup, fines and other costs related to the worst offshore oil disaster in U.S. history.

In October, it announced plans to sell $10 billion in additional assets, this time earmarking the proceeds to boost shareholder value. It also reinstated the dividend it cut after the accident.

Just as things were beginning to improve for BP from an operating standpoint, the company warned that economic sanctions against Russia could post a threat to its holdings there. BP owns 20 percent of the Russian oil company Rosneft , and the payments it receives from the Russian company accounts for one-tenth of its operating income.

In addition to the sanctions, Rosneft could be affected by a pair of European court rulings this week in which the Russia government was found liable for seizing the oil company Yukos a decade ago. The decisions, which combined awarded almost $53 billion to former Yukos shareholders, could have implications for Roseneft, which received some of Yukos’ assets after the seizure. The decisions increased the pressure on BP’s shares this week.

BP’s struggles have long made it the speculation of takeover rumors. The company has a lucrative reserve base, especially in the Gulf of Mexico, but the mammoth legal case related to the Deepwater Horizon has served as a powerful poison pill, keeping would-be suitors at bay. Once the full scope of the legal costs became clear, the theory went, BP could find itself in play.

While it’s still not clear the full extent of BP’s legal exposure, a court ruling on criminal liability is pending and the picture could become clearer in the coming months. At the same time, potential suitors may begin to see any additional liabilities as less of a risk than some of the operating challenges they have undertaken recently.

The pool of potential buyers that could afford to buy a company the size of BP is pretty small, which is why most of the speculation revolves around Shell.

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The majors have all faced a difficult environment in recent years. Exploration costs have risen and commodity prices haven’t followed suit. That’s made it more expensive for companies to replace reserves even as it forces them to look for ever more expensive and riskier prospects to find more oil.

BP sparked the last round of industry mega-mergers when it bought Amoco in 1998.

Exxon promptly bought Mobil, Chevron bought Texaco, TotalFina bought Elf and Conoco merged with Phillips Petroleum. Shell was one of the few majors to sit out the deal making.

In fact, BP’s then-CEO John Browne had a plan to buy Shell, but he never followed through on it, in part because of mounting operating problems that included the fatal Texas City refinery explosion in early 2005.

The question now is whether the deal could go the other way. Shell has faced a series of operating setbacks. It recently abandoned its role in developing natural gas reserves in Saudi Arabia, and it has faced persistent frustrations in efforts to explore for oil in the Alaskan Arctic.

As Marlow points out, the current leaders of the major oil companies aren’t the deal makers that their predecessors were. What’s more, they may have learned a lesson from Exxon Mobil’s $41 billion purchase of onshore independent XTO Energy in 2010. It was the biggest acquisition since Exxon bought Mobil, and it was designed to push Exxon into lucrative U.S. shale plays. But it didn’t pay off for shareholders, and Exxon CEO Rex Tillerson later acknowledged the deal was poorly timed.

Shell may have another concern. BP is a company that has suffered more than a decade of operating failures and safety lapses because of a corporate culture that placed incentives on profits and production over maintenance and safety. Corporate cultures are difficult to change, and it’s not clear how successful BP’s new CEO, Bob Dudley, has been in fixing the problems within BP. Still, if the current price environment persists, and the majors continue to struggle to find the kind of returns they need through exploration, their thoughts might once again turn to acquisitions. Even with BP’s overhanging legal costs and questions about its culture, its asset base may start to look more enticing.

View more quality content from 30 Point Strategies

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OilVoice Magazine | SEPTEMBER 2014

US companies benefit from move from natural gas to oil production Written by Mark Young from Evaluate Energy The last few years have seen many of the oil and gas companies in the United States change their strategy away from natural gas and focus on oil producing assets due to low gas prices. Despite the steady and gradual recovery in the Henry Hub benchmark gas price in the US since the middle of 2012, second quarter data from a group of US oil and gas producers in the Evaluate Energy database shows that this move towards oil production has still been very worthwhile.

Source: Evaluate Energy - The Henry Hub gas price shows a gradual increase on average from Q2 2012 ($2.29/mcf) to Q2 2014 ($4.60/mcf) while the WTI oil price has stayed relatively stable at around $90-$100/bbl in the same timeframe.

To show how worthwhile the strategy change has been, a group of 20 US domestic oil and gas producing companies with market caps between $1 billion and $10 billion have been selected. All of the companies in question were gas weighted - produced more gas than oil - in Q2 2012. The companies in that group that have switched their strategies to now be producing more oil than gas in Q2 2014 are shown in the chart below. The strategy was carried out by either buying oil assets, selling natural gas wells or by simply reallocating capital away from gas to develop oil projects instead.

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Source: Evaluate Energy The other half of the group, shown in the chart below, is still gas weighted. As 3 of these companies - Comstock Resources, Goodrich Petroleum and QEP Resources have shown a distinct movement towards oil production similar to those companies in the graph above, these will be considered as companies who have made a strategy change as well, despite still technically being gas weighted.

Source: Evaluate Energy In the chart below, 5 significant metrics have been chosen to show how these 2 groups of companies have fared since the second quarter of 2012. The group of companies that changed strategy (see note 1) are denoted as “oil” in the chart below, and the companies who remained natural gas weighted are denoted as “gas” (see note 2). Each group’s results for the 5 metrics in the graph below have been taken from the Evaluate Energy database and averaged out for Q2 2012 and Q2 2014. The average % increase in that time for all metrics is displayed in the chart.

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Source: Evaluate Energy As you can see, whilst gas producers are doing better than in 2012, the percentage increases for those companies who switched their strategies to focus efforts on oil production are much greater. There is a slightly larger increase in operating expenses associated to oil production, but this is more than offset by the increases in other areas.

On average, revenues per barrel have increased by double the percentage of the gas producers and the difference between the respective increases in operating netbacks is very striking. This has also translated into higher cash from operations in the financial statements. The market has also clearly approved of the switch to oil, with market caps for the oil producers now nearly 70% higher than they were in 2012.

It is clear that the change in strategy has paid off for those who were able to do it.

Whilst the gas producers are better off with the higher gas prices in 2014, the move to oil has boosted the other half of the 2012 gas weighted peer group by a much larger degree.

Notes: 1) The companies that have changed strategy since 2012 and included in the “oil� group are Bill Barrett Corp. (BBG), Breitburn Energy Partners (BBEP), Carrizo Oil & Gas (CRZO), Energen Corp. (EGN), MDU Resources Corp. (MDU), Newfield

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Exploration (NFX), Penn Virginia (PVA), SM Energy Co (SM) and W&T Offshore (WTI). Comstock Resources (CRK), Goodrich Petroleum (GDP) and QEP Resources (QEP) are also included in this group despite still being gas weighted, as they have shown large movements towards oil production since 2012.

2) The companies who have remained gas weighted and are included in the “gas” group are Atlas Resources Partners (ARP), EV Energy Partners (EVEP), EXCO Resources (XCO), Magnum Hunter Resources (MHR), National Fuel Gas (NFG), Ultra Petroleum Corp. (UPL), Unit Corp. (UNT), and WPX Energy (WPX).

This report was created using second quarter data for 20 US oil and gas companies in the Evaluate Energy database. Evaluate Energy holds quarterly and annual financial and operating data for 300+ of the world’s biggest and most significant oil and gas companies.

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OilVoice Magazine | SEPTEMBER 2014

The strange case of US confusion over Kurdish crude Written by Anthony Franks OBE from Mars Omega LLP The last 96 hours saw the US becoming apparently unthinkingly complicit in the de facto if not de jure economic embargo of Kurdistan. This was followed by a rapid series of political announcements by US officials denying that this was the case.

Confused? Probably not as much as the US administration appears to be -despite denials to the contrary.

The story so far In brief, earlier this week, the Ministry of Oil in Baghdad wrote to a US judge to seek an order for the seizure of a cargo of crude oil - worth some $100M - sat in the United Kalavrvta, a Marshall Islands-flagged vessel, at the time parked off Galveston, Texas.

The Ministry of Oil in Baghdad claimed the crude was illegally produced from Kurdish oil wells. According to a complaint filed in federal court in Houston, the Kurdistan Regional Government (KRG) was accused of having “misappropriated” more than 1 million barrels of oil from Kurdistan and exported it through the Kirkuk-Ceyhan pipeline.

US Magistrate Judge Nancy Johnson then issued an order authorising US marshals to seize the crude cargo and store it ashore for safekeeping until the dispute was resolved.

According to the filing (Ministry of Oil of the Republic of Iraq v. Ministry of Natural Resources of Kurdistan Regional Governorate of Iraq et al, U.S. District Court, Southern District of Texas, No. 3:14-cv-00249) the cargo of crude departed Ceyhan on 23 Jun 14 and has “changed destinations multiple times” while at sea.

Note the Ministry of Oil call Kurdistan a regional governorate, just to cement the canard that Kurdistan is a part of federal Iraq, even though the Kurds’ 1050 km border is now largely shared with the extremists in ISIS, not federal Iraq.

The problem that Washington initially thought it faced was clearly that if it allowed a US refinery to accept the Kurdish crude, it would in effect be saying that it is acceptable for the US and by extension the global energy market to buy Kurdish oil, and this ran the risk of upsetting Baghdad.

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That state of affairs would then allow the wedge of oil between Baghdad and Irbil to drive the two capitals apart. This ignores the fact that the two capitals are now further away from each other than at any time since the fall of Saddam Hussein.

Washington’s position remains they want to see a federal Iraq, including Kurdistan by definition; otherwise their $2T was wasted - and the more than 4486 dead and over 32,000 wounded US servicemen will have fought for nothing.

The US all at sea Back in Galveston, Baghdad had asked the US marshals to monitor the offloading of the crude, and its storage at Iraq’s expense. However, the warrant filed with the complaint did not seek the detention of the tanker, which is too big to berth alongside, requiring offshore lightering.

According to Baghdad’s complaint, a contract for the lightering was already in place; the tanker had already been authorised to proceed with offloading after an onboard inspection by the US Coast Guard.

48 hours ago, in the first of a rapid series of confusing events, the Judge then suddenly decided that - as the tanker was parked in international waters - the order that she had signed could not in fact be executed.

Judge Nancy Johnson said "Seems to me this is not a matter for the U.S. courts to tell the government -- the governments -- of Iraq who owns what. This just seems way outside our jurisdiction.”

The same day that the Judge was getting in a tangle, the KRG Minister of Natural Resources Ashti Hawrami said “The KRG’s lawyers sent a letter to a court in Texas to explain the misrepresentations of the Iraqi federal government. The Iraqi federal government has petitioned a Texas court for an order to seize crude oil legally produced, exported, and sold by the KRG in accordance with the Iraqi constitution and law. The letter indicates the possibility of massive counterclaims against the federal government.”

As a matter of record, the wonderfully titled legal firm ‘Wilmer Cutler Pickering Hale and Dorr LLP’, of 49 Park Lane, London, W1K 1PS sent a letter to the Hon. Gary Miller, United States District Judge (etc) on 29 Jul 14.

The letter was 184 (yes, 184) pages long, and contained a mass of complex detail on the hydrocarbons’ law and the Iraqi Constitution and intra-capital letter exchanges.

Stand offs and Hands off We seem therefore to be seeing a particularly important Middle Eastern version of a Mexican standoff off the south coast of the US:

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  

At stake for Irbil is the ability of Kurdistan to pay its bills and people and achieve a major step towards economic independence; At stake for Baghdad is the potentially terminal fracture of the fragile federal Iraqi construct; At stake for Washington is the credibility and clarity of its position on Kurdish oil, and its reputation with the KRG as a fair-minded international partner.

While this is all going on, there are still a number of tankers carrying Kurdish crude oil transiting the high seas.

The United Emblem has part unloaded its cargo in the South China Sea, although a buyer has not been identified; it left Ceyhan last month with a cargo of some 1M barrels of Kurdish crude.

According to Reuters, “a senior source at Marine Management Services said the ship-to-ship transfer involving the South China Sea cargo was sound.”

Kostas Giorgopoulos was quoted by Reuters saying that The United Emblem is "fixed to a legitimate charterer and performing legitimate operations" and "the ship is still in international waters". Its destination remains unknown, along with the buyer.

We know from Reuters that US chemicals’ firm LyondellBasell had bought two previous cargoes of Kurdish crude delivered to the US in May - without apparently any legal hurdles.

The US denies banning Kurdish oil sales Meanwhile, the US, seemingly bruised at Irbil’s rapid legal counterattack, has spent the last 24 hours denying that they are banning oil sales from Kurdistan.

Yesterday, Deputy Spokesperson for the US State Department, Marie Harf, said “There is no US ban on the transfer or sale of oil originated from any part of Iraq.”

And, in a somewhat interesting comment, she also said “Our policy on this issue has been clear. Iraq’s energy resources belong to all of the Iraqi people. These questions should be resolved in a manner consistent with the Iraqi constitution.”

Not wishing to be left out, Deputy Assistant Secretary for Near Eastern Affairs for Iraq and Iran, Brett McGurk “clarified” on Twitter Washington’s stance regarding the Kurdish oil tanker. He tweeted “There is no U.S. ban on the transfer or sale of oil originating from any part of Iraq. Suggestions to the contrary are false.”

He also stressed that the Washington’s policy on the underlying issue has been clear and consistent; tweeting “Iraq’s energy resources belong to all of the Iraqi people”, which looks remarkably like what Marie Harf said.

Similarly, McGurk urged all sides to solve their differences based on the Iraqi Constitution, saying “The situation demonstrates why it is incumbent on Baghdad and Erbil to find a negotiated resolution. As in many cases involving legal disputes, however, the U.S. recommends that parties make their own decision with advice of

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counsel. These questions should be resolved in a manner consistent with the Iraqi constitution.”

The whole point of the KRG letter to the US Judge was that Irbil’s actions are consistent with their interpretation of the Iraqi Constitution.

But in yet another twist in the tale, only this morning the Kurds’ only US customer LyondellBasell said that after receiving previous shipments it was halting all purchases of what it called disputed Iraqi crude.

The company said in a statement "We have cancelled further purchases and will not accept delivery of any of the affected crude until the matter is appropriately resolved.”

The Indefinite Articles Baghdad’s position that they alone have the authority to sell oil and receive revenue is not born out by scrutiny of the appropriate articles of the constitution. These are as follows: “Article 111: Oil and gas are owned by all the people of Iraq in all the regions and governorates.

Article 112: First: The federal government, with the producing governorates and regional governments, shall undertake the management of oil and gas extracted from present fields, provided that it distributes its revenues in a fair manner in proportion to the population distribution in all parts of the country, specifying an allotment for a specified period for the damaged regions which were unjustly deprived of them by the former regime, and the regions that were damaged afterwards in a way that ensures balanced development in different areas of the country, and this shall be regulated by a law.

Second: The federal government, with the producing regional and governorate governments, shall together formulate the necessary strategic policies to develop the oil and gas wealth in a way that achieves the highest benefit to the Iraqi people using the most advanced techniques of the market principles and encouraging investment.

Professor James R Crawford, Whewell Professor of International Law, offered the following legal opinion of the two articles; this was included in the packet of letters sent to the US Judge: “Article 112 of the Constitution of Iraq gives only a qualified right to the Federal Government to "undertake the management of oil and gas extracted from present fields". This right is to be exercised "with the producing governorates and regional governments", and is subject to a condition of fair distribution of revenue on a basis regulated by law. As to non-producing and future fields, there is under Article 112, Second, no federal right to manage, although regional management of such fields has to respect strategic policies to be formulated by the federal government "with" the KRG.

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The Kurdistan Region Oil and Gas Law is consistent with the Constitution of Iraq and is effective to govern the development of oil and gas in the Kurdistan Region. In the continuing absence of agreement pursuant to Article 112, Second, on the ''necessary strategic policies", the KRG is entitled to manage its oil and gas resources, and should do so openly in a manner which gives effect to the principles set out in that Article.

Existing contracts entered into by the KRG for oil and gas exploration and exploitation since 1992 are valid unless they conflict with the Constitution. Pending agreement between the KRG and the federal government on strategic policies, the authority of the KRG to authorise the conclusion and implementation of new contracts is unqualified.”

So What?

If the US administration is serious that “There is no U.S. ban on the transfer or sale of oil originating from any part of Iraq. Suggestions to the contrary are false,” this leaves the door open for the Kurds to sell their oil to US clients and international buyers.

This will not only relieve the acute economic pain that the Kurds are currently experiencing, but will be a huge step forward for the international oil companies who are still waiting to be paid, and who are also waiting to turn the volume up on their production and sale of oil.

Finally, it will mean that the grip that Baghdad has around Irbil’s throat will be released, and Kurdistan will become a viable independent economy. Baghdad will view this with horror, and thus we can expect Baghdad to be actively lobbying Washington as we speak.

However, the proof of the pudding is in the eating. It remains to be seen if the rapid series of denials by the US administration that they are banning sales of oil “from any part of Iraq” will have the effect the Kurds want desperately to see – the sale of their crude oil unimpeded by objections from Baghdad.

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When "common sense" really amounts to nonsense Written by David Blackmon from FTI Consulting, Inc. Taxpayers for Common Sense (TCS), one of the myriad agenda-based “think tanks” in our nation’s capital, released a decidedly un-common-sensical new study on July 31 titled “Effective Tax Rates of Oil & Gas Companies: Cashing in on Special Treatment”.

The study is 41 pages long, and purports to somehow be an authoritative analysis of how oil and gas companies avoid paying taxes through various tax treatments, and I encourage anyone interested to read it. But what it basically boils down to is an argument that essentially says “golly, if nasty old “big oil” didn’t take advantage of the tax code, they’d pay a higher effective tax rate”. Which is true, as far as it goes.

But nowhere in the report does it also note that if, say, Microsoft, or Tesla, or AT&T, or General Electric, or basically every other corporation that does business in the United States of America didn’t take advantage of the tax code, they would all pay a much higher effective tax rate as well. Nor do the authors bother to note that if they themselves didn’t take advantage of deductions for mortgage interest, state and local taxes and capital losses on their own personal income tax returns, they would also pay a much higher effective tax rate.

See how that works?

As we pointed out in this piece last January, “the oil and gas industry receives the same kinds of tax treatments that every other manufacturing or extractive industry receives in the federal tax code. There is nothing uncommon or out of the mainstream of tax treatments about any of the provisions that have been repeatedly proposed for repeal” by the Obama Administration. Any person who really understands how the tax code works would understand that reality, but TCS obviously relies on the belief that most news reporters and editors are not among such people.

And they would be right, as various news outlets have picked up on the study and run misleading articles about it. U.S. News and World Report even gave space for an opinion piece by TCS President Ryan Alexander. But our favorite thus far was this piece at Salon.com that ran under the absurdly written headline, “Big Oil Companies Pay An Absurdly Low Tax Rate”.

Naturally, Salon zeroes in on perhaps the single most misleading and inaccurate part

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of the entire TCS study: Oil and gas companies can defer tax payments for a variety of reasons, some specific to the industry. If an independent oil and gas company constructs an asset like an oil rig, for example, it can claim a tax deduction for all of its intangible drilling costs (IDC), which include the costs of designing and fabricating drilling platforms.

This allows the company to immediately deduct all of these costs from its taxable income. Normally, a taxpayer who constructs an asset would have to wait for the asset to generate income and expense these costs over time, spreading its tax deductions over 5, 10, or 20 years, depending on the useful life of the asset.

Deducting the entire amount immediately allows the company to defer or delay payment of a portion of the taxes it accrued that year…

[The principal benefit] is the ability to defer more and more of their federal income taxes, year after year… Over time, the total amount an oil and gas company owes the federal government in deferred taxes can become significant. ExxonMobil reported total deferred tax liabilities of $54.5 billion in 2013. It pays no interest to the federal government on the amount it owes, even if it takes 20 years to pay it back.

First of all, TCS attempts to equate the building of “an oil rig” with the “designing and fabricating of drilling platforms”, which are two completely different pieces of equipment that are almost always constructed by completely different companies. It also infers that these activities are typically engaged in by what TCS refers to as “independent oil and gas companies”, by which one can suppose the authors might mean “independent producers” of oil and gas. Salon then attempts to equate the activity described in the first paragraph with tax deferalls allegedly taken by ExxonMobil in the second paragraph. But ExxonMobil is an integrated company, not an independent producer, and quite often is subjected to tax treatments that are vastly different than those that apply to independent producers. Anyone familiar with the oil and gas industry and the tax code would have known that.

As well, anyone who knows how the industry actually works would know that independent producers seldom construct their own “oil rigs” by which one must assume the authors are referring to drilling rigs, and that, in any event, the construction of oil rigs is treated as a tangible capital cost in the tax code, and is not allowed to be classified as an Intangible Drilling Cost (IDC), as the folks at TCS clearly want their readers to believe.

As for the construction of “drilling platforms” – an entirely separate piece of equipment from an “oil rig” – about 50 years of federal case law has led to a series of court and IRS rulings that allow some of the costs to be treated as IDCs in certain fact situations, and some of the costs to be classified as capital costs that must be recovered over multiple years. And, by the way, the underpinning rationale for those court and IRS rulings is the very same rationale that the courts and the IRS apply to every other industry in the United States of America when determining whether specific costs can be deducted in the year in which they are incurred, or must be amortized and recovered over time.

This fundamental and enduring basic concept of federal tax law was apparently beyond the ability of the folks at Taxpayers for Common Sense to grasp when

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constructing the thinly-disguised hit piece they refer to as a study.

At the end of the day, this TCS “study” doesn’t really seem to make a lot of sense.

Those who know how the oil and gas industry, and the tax treatments that apply to it, actually work might even call it nonsense.

View more quality content from FTI Consulting, Inc.

North Sea Oil and Scottish Independence: where does the truth lie?

Written by Euan Mearns from Energy Matters



How much oil and gas is left in the North Sea? 16 billion barrels oil equivalent (boe) according to Sir Ian Wood or 24 billion boe according to Oil and Gas UK? The correct answer for official proved+probable reserves is between 8 and 9 billion boe, a figure that both DECC and Oil and Gas UK agree on. With over 9 different classes of reserves, this debate is sterile and this is not the correct question to ask.



How wealthy will oil make Scotland? In 2013, the direct tax take from oil and gas production for the whole of the UK was £4.67 billion and falling. This compares with annual spending of the Scottish government (plus UK spending on Scotland) running at £65.2 billion. Hence, direct taxation of oil and gas production may account for less than 7% of the Scottish budget.

What we should be asking is where the other 93% is going to come from?

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On 18th September this year people resident in Scotland be they Scottish, English, Irish or Polish will vote on Scotland’s continued membership of The United Kingdom.

The debate is heating up. Oil magnate Sir Ian Wood suggests that remaining oil and gas reserves are about 16 billion barrels oil equivalent (boe). While industry representative Oil and Gas UK suggest a figure of 24 billion boe, a figure preferred by the pro-independnece lobby. As discussed below, both of these numbers as they stand alone are totally meaningless.

Voters are clearly confused and are pleading for real data upon which to base this most crucial of decisions. In this post I attempt to bring some reality to the debate about North Sea oil and gas reserves, production and finance.

Reserves Figures are a Sterile Debate The Society of Petroleum Engineers provides a framework for the classification of reserves based on class and certainty [1]. There are three classes and three certainty levels giving at least 9 different classifications of reserves (Figure 1). And so, when a number of 24 billion boe is reported it is essential to qualify this with the classification terms. Are these 2P reserves? i.e. oil and gas known to exist with a high degree of certainty. Or are they 3P reserves + resources, i.e. oil and gas optimistically hoped to exist, but yet to be discovered or a means of production economically worked out.

Figure 1 Classification of reserves according to The Society of Petroleum Engineers.

The industry standard is normally to report 1P or 2P reserves (the middle of the green band).

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Figure 2 UK North Sea reserves estimates from various sources [2]. The 2P figures from the Government (DECC) and Oil and Gas UK are actually closely aligned at between 9 and 11 billon boe oil + gas (updated to 8 to 9 billion boe). See note at the end of this section). With over 42 billion boe already produced it seems likely that 80% of UK oil and gas is already gone.

A year ago I conducted a review of reserves from different sources including my own back of the envelope calculation using industry standard methodology [2] (Figure 2).

There is a degree of agreement where the proved oil and gas reserves category lies somewhere between 4 and 5 billion boe. Proved + Probable (2P) reserves stand at around 8 billion boe according to DECC [3] and about 9 billion boe according to Oil and Gas UK [4] (see note at the end of this section). How these figures become inflated to 16 and 24 billion is pure speculation.

Oil and Gas UK qualify their numbers with the need to spend £1 trillion to get their high end estimates out of the ground (Figure 3). Considering that current investment levels are running at around £20 billion per year it will take 50 years to reach that target. Most of the existing infrastructure will have fallen into the North Sea long before. Production growth is now negatively correlated with investment (Figure 4) and one needs to ask the question how likely it is that the industry will sink another £1 trillion into this ageing, mature province? It is of course Oil and Gas UK’s business to talk the industry up.

Figure 3 Excerpt for Oil and Gas UK’s 2013 financial report revealing how they get from 7.4 to 24 billion boe [4].

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Figure 4 Despite rising and record levels of investment in the North Sea, oil and gas production has continued to decline [5].

At the current mature stage of North Sea development, oil price is vitally important.

With Brent approaching $100 / barrel, companies in Aberdeen are preparing for recession. There are of course bright spots like Clair, Mariner and Laggan Tormore.

But there are many black spots where companies can no longer afford to maintain rusting platforms producing a mere dribble of oil. The UK industry currently needs sharply higher oil prices to prosper.

[Note added 17:00, 25th August. I received a few emails from DECC providing more up to date figures than the ones I was using that were complied last December: Last year we said P+P reserves were 8.9 billion boe. Which I guess explains where your 9 billion boe comes from. Oil & Gas UK were at 9.9 billion boe so I don’t see why you say between 9 and 11 billion boe. It would be more accurate to report DECC’s current estimate of 8 billion boe and Oil & Gas UK’s of 10 billion boe.

Oil & Gas UK now say 9.4 billion boe (see attached) so the range should be 8 to 9 billion boe rather than 9 to 11 billion boe.

The numbers in the post were therefore revised accordingly.]

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The Harsh Reality of Production Decline Combined UK oil and gas production peaked in 1999 (Figure 5). We have now experienced 14 years of relentless decline. This is not speculation but a fact.

Production today is 32.4% of the 1999 peak value. Decline is a feature brought about by the depletion of reserves and pressure. At first a field will produce dry oil. But with the passage of time increasing amounts of water are produced with the oil. The industry fights decline 24/7. But it is rather like swimming upstream in a river against a strong current. You may want to get upstream but the current relentlessly wants to drag you down.

There are signs that declines are being stabilised for the time being. This has been brought about by record levels of investment that will not be maintained at current prices [5]. Some large new fields due to come on stream in the near future may arrest or temporarily reverse the long-term decline picture. But all of the fields represented in Figure 5 will still be there pulling production down.

Figure 5 The history of UK oil and gas production according to the 2014 BP statistical review of world energy.

With over 42 billion boe already produced from the North Sea [4], it seems likely that about 80% of the producible oil and gas has already gone. The industry will of

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course continue for many decades, but on current data it will be at a much lower level than in the past. However, one can never discount a new oil and gas province being discovered in the waters to the west.

The Financial Reality Direct taxation of the UK oil and gas industry since 1968 is shown in Figure 6 [6].

Direct taxation is in the form of a Petroleum Revenue Tax and Corporation tax that oil and gas operators pay at a higher rate than other companies.

In 2013 the total UK direct tax take from Oil and Gas was £4.67 billion [6]. In 2012/13 total UK and Scottish Government expenditure on Scotland was £65.2 billion [7].

9.1% of the UK total even though we have only 8.3% of the population. Hence direct tax revenues from oil and gas will amount to less than 7% of the total Scottish budget (the North Sea oil tax figure is for the whole of the UK). Important to be sure, but not nearly as important as the 93% (£60.6 billion) that will have to be found from other sources.

Figure 6 Data for total direct taxation of the UK oil and gas industry [6]. The roller coaster ride in tax income comes down to a combination of production rise and fall, oil and gas price rise and fall, changes in operating costs and changes to the taxation regime. The current environment is one where oil prices have more or less

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traded side ways since 2008, production has continued to decline and operating costs have gone through the roof. The industry in Aberdeen is preparing for a new cyclical recession. Contractors are being laid off or their rates cut and the operating companies are preparing to lay off staff.

Whilst important, the direct tax take from North Sea oil is by far NOT the most important aspect of the industry to the Scottish economy. The benefits to the economy comes from the economic activity that the oil industry creates. It creates jobs directly in the operating and service companies and in the supply chains. In 2012 this expenditure amounted to ÂŁ22 billion spent on goods and services, not all of it spent in Scotland. A large amount is spent on salaries to people living in Scotland who then spend this money in local shops, pubs and restaurants. It is true that the tax revenue generated from this activity is shared with the whole of the UK. But it is the economic activity itself that is most important, and this already exists in a Scotland that is part of the UK. Of similar importance is the fact that Scotland is now a hub for hemispheric oil and gas activity. US companies, based in Scotland, may employ staff here servicing the oil industry in Algeria, Azerbaijan or Nigeria. These companies want stability and certainty to continue their business in an increasingly uncertain world. Similarly UK (Scottish) companies that grew out of the North Sea oil boom like The Wood Group serve the global industry providing jobs and prosperity to Scotland. These companies too want fiscal and currency certainty looking forward. The focus on ethereal reserves is a mistake, the focus on direct tax income is a mistake. The focus should be on the continued existence of a multi-billion ÂŁ industry that provides jobs and prosperity for many and a single minded focus on doing nothing that may jeopardise the present or the future.

References [1] SPE: Guidelines for Application of the Petroleum Resources Management System [2] Energy Matters: UK oil and gas reserves [3] DECC: Oil and gas: field data [4] Oil and Gas UK: Economic report 2013 [5] Energy Matters: UK North Sea Oil Production Decline [6] HM Revenue and Customs: Statistics of Government revenues from UK oil and gas production [7] The Scottish Government: Government Expenditure & Revenue Scotland 201213

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Making sense of the US oil story Written by Gail Tverberg from Our Finite World We frequently see stories telling us how well the United States is doing at oil extraction. The fact that there are stories in the press about the US wanting to export crude oil adds to the hype. How much of these stories are really true? If we believe the stories, the US is now the largest producer of oil liquids in the world. In fact, it has been the largest producer since the fourth quarter of 2012.

Figure 1. US Total Liquids production, including crude and condensate, natural gas plant liquids, “other liquids,” and refinery expansion.

Oil “Extenders” One of the issues is that a few years ago, the US created a new oil-related grouping, combining valuable products with much less valuable (lower energy content, less dense) products. Using this new grouping, the US was able to show much improved growth in total “oil” supply. The US EIA now calls the grouping “Total Oil Supply.” I refer to it as “Total Liquids,” a name I find more descriptive. Besides “crude and condensate,” the mixture includes “other liquids,” “natural gas plant liquids,” and “refinery expansion.”

“Crude and condensate” is the original grouping. Often, it is just referred to as “crude oil.”

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“Other liquids” is primarily ethanol from corn. If we produced coal-to-liquids, it would be in this category as well.

Natural gas plant liquids (NGPL) are the liquids that condense out of natural gas when they are chilled and compressed in the natural gas processing plant.

Refinery expansion occurs when a refinery breaks long chain hydrocarbons into shorter ones. The resulting products take up more volume, but don’t really have more energy content. In some ways, the process is like making whipped cream out of whipping cream–more volume, but not really more product. The new products tend to be more valuable–say, diesel and lubricating oil made from something close to asphalt.

The process of breaking (cracking) long hydrocarbon chains is a valuable service to those producing heavy oils, because it makes valuable products from crude that otherwise would not have been useful for most purposes. The cracking process uses natural gas. Because natural gas in the US is inexpensive relative to its price in most other countries, the US can perform this process more cheaply than other countries.

Because of this, it makes financial sense for the US to import heavy crude oil and process it in this way, whether or not US citizens can afford to buy the finished products. (Cracking is not useful on very light oil, such as Bakken oil, since it has primarily short chains to begin with.) If US citizens can’t afford the finished products, they are exported to others.

Whether or not the US should be credited with this expansion of volume is somewhat “iffy,” since the process doesn’t add energy content. Quite a bit of the oil processed in this way uses imported oil, such as oil from the Canadian oil sands.

If we look at the base figure reported by the US Energy Administration, that is, “Crude and Condensate”(Figure 2), the US does not come out as well in original comparison (Figure 1).

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The United States makes much greater use of extenders than do Russia and Saudi Arabia. If we calculate the ratio of extenders to the base (crude and condensate), the ratios are as follows:

Figure 3. Extenders as a percentage of crude oil production, based on EIA data.

Both Russia and Saudi Arabia have much lower ratios of extenders. For both of these countries, the extenders are Natural Gas Plant Liquids.

Natural Gas Plant Liquids (NGPL), have varied in price. For a while, the price was up with the price of crude, but as supply increased, the US price dropped during 2011 (Figure 4).

Figure 4. Price Comparison per Million Btu for Oil (West Texas Intermediate), Natural gas plant liquids, and natural gas, based on EIA data.

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This drop in NGPL price occurred because the US market for at least some components of this grouping became saturated. With too much supply for demand, prices dropped. Excess ethane, for example, could be sold to be burned as natural gas, putting a floor under its price. As a result, recent prices seem to be influenced by changes in natural gas prices.

With the drop in NGPL prices, we hear more talk about the need for exports. We don’t really have use for all of the low value products that are being produced, other than to burn them as part of natural gas. Perhaps someone else does. If someone else does, it might get the price back up.

What is the Real US Trend in Production/ Consumption?

The US EIA makes fuel comparisons based on Btu energy content. This approach makes it easy to see how much of our fuel is US produced, and how much is imported (Figure 5).

Figure 5. Comparison of US production and consumption of oil plus NGPLs, based on EIA data.

Production is indeed rising, but it is still far below consumption–about 55% of consumption in 2013. Many articles make this situation confusing.

The emphasis in most news reports is the drop in imports–that is the difference between the blue line and the red line in Figure 5. If we look at the chart, though, we see that a big reason for the drop in imports is a drop in consumption, with the big step down coming in 2007 and 2008. Oil use is associated with jobs. It takes oil to make and transport goods. Also, workers with good jobs can afford cars and the oil to operate their cars. If they remain students forever, they can’t afford cars.

A person can better see the drop in consumption by looking at consumption on a per capita basis.

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Figure 6. US per capita oil and Natural Gas Plant Liquids production and consumption, based on EIA data.

If prices don’t fall, consumers don’t feel the effect of more production. What they do feel the effect of is falling consumption-the top line. Young people especially have been finding it hard to get good paying jobs. With all of their student loans, it is hard to be able to afford to get married and buy a house. This holds down demand for new homes, and all of the things that go into new homes.

If we look at total per capita energy production and consumption in the US, we see even more of this trend. While production per capita is rising, an even bigger issue is falling consumption.

Figure 7. Total per capita energy production and consumption for the US, based on EIA data.

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US per capita energy consumption has been dropping since 2000. 2000 is the year of peak US employment, as a percentage of the total population.

Figure 8. US Number Employed / Population, where US Number Employed is Total Non_Farm Workers from Current Employment Statistics of the Bureau of Labor Statistics and Population is US Resident Population from the US Census. 2012 is partial year estimate. (Sorry, not updated.)

With a smaller percentage of the US population employed (and lagging salaries for those employed), US consumers cannot afford to buy as large a quantity of energy products. Rising US oil production is not really helping US consumers, because at its high price, we cannot really afford it.

Rising oil production has not brought down oil price, making it more affordable. In fact, the situation is the reverse–high prices are needed for today’s oil production. It is questionable whether today’s prices are even high enough. Oil companies have to keep adding debt, to keep extracting oil. The EIA recently wrote an article about the situation called, As cash flow flattens, major energy companies increase debt, sell assets. Steven Kopits shows this chart of cash flows for Independent Oil Companies in a recent post.

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Figure 9. Image by Steven Kopits showing Free Cash Flow of US independent oil and gas producers, from Platts Guest Blog.

With negative cash flows, companies have to keep increasing their debt levels– something that eventually becomes impossible.

When those producing the oil see that US oil prices are at times not as high as world oil price (Brent), they hope that selling their crude to world export markets, they will be able to get higher prices for their crude. If they are successful, there will be less crude available sold to US producers, perhaps raising the price of this crude sold in this country as well. The net impact may be higher prices for US consumers, making the US consumers even less able to afford the oil products.

Energy Growth is Needed for Economic Growth There is a close tie between energy consumption and economic growth. Perhaps my statement “Energy growth is needed for economic growth,” in the header is a little too strong. Perhaps if energy consumption is flat, with the benefit of technological progress and efficiency changes, there can still be economic growth. There is definitely a connection, though. Energy of the right type is needed for every process we can think of–getting to work, shipping goods, operating our computers, heating metals when they are refined.

The problem comes when what we are facing in shrinkage of energy consumption, over and above what can be accommodated by technological progress and efficiency. Figure 7 hints that this is already happening. Then we have danger of a collapsing financial system, as the low energy consumption growth pushes the

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economy toward contraction. The economy has been held together since 2008 with quantitative easing and zero interest rates. The plan has been to allow consumers more income to spend, by keeping interest rates artificially low. I heard an excellent presentation on this subject recently called Global Financial System on Life Support

by Roger Boyd.

Conclusion I wrote a post recently called The Absurdity of US Natural Gas Exports. The situation with exports of crude oil is not quite as absurd. The issue is that current oil refineries are not configured for the influx of very light oil. Many of them are busy “cracking� long hydrocarbon chains, often using imported oil as their energy source. If US oil producers have the option of selling their crude oil abroad, perhaps they can get a higher price for it. If US oil producers can get higher prices for their oil, this may very well filter through to higher oil prices for US consumers, and less oil consumption by US consumers, but this is not the concern of oil companies.

A major concern with falling per-capita energy consumption it that the financial system may soon reach limits where it is stretched beyond what it can stand. The economy needs energy growth to grow, but the economy is not getting it.

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