OilVoice Magazine | February 2014

Edition twenty three – February 2014

Unlocking new insights in the Marcellus Energy policy freeze frame in 1970s mould Shell profit warning - the shock that wasn't Cover image by Enrico Strocchi

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Adam Marmaras Chief Executive Officer Issue 23 – February 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 Social Network 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 Enrico Strocchi

www.flickr.com/photos/strocchi

Welcome to the 23rd edition of the OilVoice magazine. This month we have another bounty of quality articles from our writers, including NEOS, Andrew McKillop, Dave Forest, Gail Tverberg, Mark Young, Eoin Coyne and David Bamford.

Site visitor numbers are the 'holy grail' of a website like OilVoice. We are constantly thinking of ways to increase our readership, and reach more oil and gas professionals each month. The bigger our numbers, the more value we can deliver to our advertisers, and that's what keeps a free to use site like OilVoice ticking along. So the mood in the office is understandably up at the moment as our traffic numbers have reached an all time high. In January we reached 160,000 people, and served up 600,000 pages. If you were one of our visitors in January, then thank you!

Have a great 2014 Adam Marmaras CEO OilVoice

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Contents Featured Authors Biographies of this months featured authors

Shell profit warning - the shock that wasn't

by Andrew McKillop

3 5 9 21

Total's investment is a big step for the future of UK shale - But don't get too excited just yet

by Mark Young

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Unlocking new insights in the Marcellus

by NEOS Why EIA, IEA, and Randers' 2052 energy forecasts are wrong

by Gail Tverberg

Insight: a small black cloud?

by David Bamford Oil & gas M&A reaches US$143 billion in 2013

by Eoin Coyne Insight: Give us a break!

by David Bamford The offshore oil drilling revolution, and its game-changing technologies

by Dave Forest Energy policy freeze frame in 1970s mould

by Andrew McKillop

29 31 36 37 41

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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.

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

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

Eoin Coyne Evaluate Energy Eoin Coyne is an analyst at Evaluate Energy.

David Bamford Finding Petroleum David Bamford is a past head of exploration and head of geophysics at BP, and a founder shareholder of Finding Petroleum.

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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.

Dave Forest Contributing Editor Dave Forest is a Contributing Editor for Oil and Gas Investments Bulletin.

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Unlocking new insights in the Marcellus Written by NEOS Multi-Physics Approach to Sweet Spot Detection Oil & gas development in the Appalachian Basin has experienced a dramatic resurgence over the last decade thanks to unconventional drilling and extraction techniques. Companies have discovered the promise of the Marcellus, a formation that stretches nearly 600 miles from West Virginia north through Pennsylvania and eastern Ohio into New York and Canada.

More than 8,000 horizontal wells targeting the Marcellus have been permitted in Pennsylvania, with 6,000 of those either in production or under development.

Regional reserve estimates vary widely, with most in the 200 TCF (33 billion BOE) range, though some approach 500 TCF (83 billion BOE).

Amid promise and increased activity, there are issues that threaten the Appalachian resurgence such as falling gas prices. While most Marcellus wells were wildly economic just a few years ago, producers must be much more selective in which parts of the play (and the shale) they target. As a result, companies are seeking better solutions that enable them to understand the subsurface.

New Insights into Tioga County In Tioga County, Pennsylvania, a supermajor wanted to know what geologic factors drove some wells within the Marcellus to be more productive than others. The answer was not readily apparent on seismic, so a methodology called MultiMeasurement Interpretation (MMI) was introduced by NEOS GeoSolutions – a Houston-based provider of surface and subsurface imaging solutions – to provide a better understanding of the area of interest.

NEOS set to work on a program to provide the underwriter with an improved understanding of the basin’s geologic context which included:      

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

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

The acquired data delivered new insights to the program underwriters, even when interpreted individually. 





Using hyperspectral analysis, interpreters located numerous oil seeps and gas plumes. The seeps and plumes were then traced back to surfacepenetrating faults that were mapped used an analysis of magnetic data. The result provided insights into the relative liquids generating potential of the target shale intervals in the subsurface.

Airborne EM resistivity measurements provided insights into both lateral and vertical resistivity variations throughout the geologic column, down to roughly 10,000 feet. When the EM voxel was depth-sliced at the Marcellus interval, geoscientists noted that resistive hot spots in the Marcellus corresponded to many of the county’s ‘best well’ locations.

Geoscientists on the project also incorporated more traditional geophysical measurements into the interpretation. Well logs were analyzed to enhance structural control and to calibrate the airborne EM data. Seismic data were incorporated into the regional structural model and, in combination with the magnetic and EM data, provided insights into how faults were creating pathways for hydrocarbons to migrate toward the surface.

Using Predictive Analytics to find the Sweet Spots Well productivity can vary widely in an unconventional shale play, even within the same county. While well design plays a part in this variance, so too does the geology. NEOS’s multi-measurement methodology is helping explorationists understand the geologic drivers of well productivity. On the typical survey, nearly 100 G&G measurements, attributes, and derivatives are acquired and analyzed to identify the 10-20 that correlate with the ‘best’ (or worst) wells in an area. Using advanced geostatistical and predictive analytics methods, proprietary NEOS software than undertakes a pattern search to identify other parts of the play in which the ‘correlative attributes’ appear. The resulting analysis allows NEOS to develop ‘sweet spot’ maps.

In the case of the Tioga predictive analytics exercise, twenty G&G measurements were identified as correlating with the most productive wells in the county. The measurements aren’t without geologic significance, as they relate to four categories extremely relevant to well productivity:    

Structural context The size and composition of the ‘tank’ Reservoir plumbing and Halo effects (above the reservoirs in question)

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Roughly half the correlative attributes corresponded to the structural context of the Marcellus interval, including its thickness, burial depth, and the depth-to-basement.

Throughout the Appalachian region (and in many other shale plays), variations in basement-associated features – including topography, faulting, and lithology – are being increasingly acknowledged as having a significant influence on the productivity and EUR of the overlying shale horizons.

A Promising Future for Appalachia The complete multi-physics, multi-method approach used for the Tioga neoBASIN program revealed subsurface features from the basement to the surface, helping the program underwriters pinpoint the sweet spots and avoid shallow gas geo-hazards and therefore optimize their leasing, drilling, and hydraulic fracturing programs in the play in Tioga County.

The future of Appalachia looks bright with many key operators viewing the region as a core platform for growth in the years ahead. Since the early surveys in Tioga, NEOS has undertaken additional projects in Pennsylvania, compiling nearly 5,000 square miles of available regional data that are continuously delivering unique, costeffective insights into one of America’s greatest resource plays.

View more quality content from NEOS

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

FEBRUARY 2014

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Multi-measurement imaging reveals secrets of the elusive Marcellus

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Nowhere to hide in Tioga County

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HIGHLIGHTS Thanks to unconventional drilling and extraction techniques, the Appalachian Basin has experienced a multi-billion dollar economic resurgence. In Tioga County, Pennsylvania, a methodology called Multimeasurement Interpretation (MMI) has been introduced by NEOS GeoSolutions to provide a better understanding of the basin.

KEY TECHNOLOGIES:

MAGNETIC

PASSIVE-SOURCE EM

RADIOMETRIC

GRAVITY

HYPERSPECTRAL

NEOS acquired airborne geophysical data – magnetic, electromagnetic (EM), radiometric, gravity, and hyperspectral – over 1,000 square miles of Tioga County. These data were integrated with existing geophysical, Sweet spot map (zoom) over a roughly 200-square-mile area in Tioga geochemical, and seismic measurements County, Pennsylvania. Hot colors indicate areas most similar to best from various public domain and thirdproducing wells in the region. Circles are sized to the first six months of party sources and interpreted by NEOS and production for all horizontal wells. operator geoscientists. This low-impact, environmentally friendly approach revealed subsurface features from the basement to the surface, helping explorationists pinpoint the sweet spots and avoid shallow gas geo-hazards in the play.

PREDICTIVE ANALYTICS

Using hyperspectral analysis, which classifies substances on the surface based on unique spectral signatures associated with the reflectance and absorption of both visible and invisible light, interpreters located numerous oil seeps and gas plumes. Of these, 90% were verified by geo-technicians on the ground. The seeps and plumes were then traced back into the subsurface along various pathways, including faults that had been mapped using an analysis of magnetic, seismic, log, and EM data.

≥ Regional resistivity voxels down to 10,000 feet

Airborne EM resistivity measurements provided insights into both lateral and vertical resistivity variations throughout the geologic column, down to roughly 10,000 feet. When the EM voxel was depth-sliced at the Marcellus interval, geoscientists noted that resistive hot spots in the Marcellus corresponded to many of the county’s ‘best well’ locations.

In addition to analyzing the airborne datasets, geoscientists on the project also incorporated more traditional geophysical measurements into the interpretation. Well logs were analyzed to enhance structural control and to calibrate the airborne EM data. Seismic data were incorporated into the regional structural model and, in combination with the magnetic and EM data, provided insights into how faults were creating pathways for hydrocarbons to migrate toward the surface.

AREA: Appalachian Basin, Pennsylvania CUSTOMER: Supermajor FOCUS: Regional Mapping TYPE: Unconventional

KEY INTERPRETIVE PRODUCTS:

≥ Maps of lineaments, fault networks, and intrusives ≥ Maps of regional prospectivity derived via predictive analytics

CUSTOMER BENEFITS: Cost-effective regional insight depicting the most (and least) prospective areas for leasing, drilling, or further geological and geophysical (G&G) study.

Finally, a cutting-edge geostatistical technique called predictive analytics was applied. The technique allowed geoscientists to mine all geo-datasets for subtle patterns and correlations that corresponded to the best wells, and to then pattern search for similar ‘correlative attributes’ in areas that had yet to be drilled. This helped the project’s underwriters to optimize their leasing, drilling, and hydraulic fracturing programs and to target future ground-based geophysical acquisitions in the most promising areas.

MMI has captured the attention of the region’s major E&P producers. Since the early surveys in Tioga, NEOS has undertaken additional projects in Pennsylvania, compiling nearly 5,000 square miles of available regional data that are delivering unique, cost-effective insights into the Marcellus and Utica shale plays.

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

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

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Why EIA, IEA, and Randers' 2052 energy forecasts are wrong Written by Gail Tverberg from Our Finite World What is correct way to model the future course of energy and the economy? There are clearly huge amounts of oil, coal, and natural gas in the ground. With different approaches, researchers can obtain vastly different indications. I will show that the real issue is most researchers are modeling the wrong limit.

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

One of the things I show in this post is that Economic Growth is a positive feedback loop that is enabled by cheap energy sources. (Economists have postulated that Economic Growth is permanent, and has no connection to energy sources.) Economic Growth turns to economic contraction as the cost of energy extraction (broadly defined) rises. It is the change in this feedback loop that leads to the financial problems mentioned above. These effects tend to lead to collapse over a period of years (perhaps 10 or 20, we really don’t know), rather than a slow decline which is easily mitigated.

If, indeed, most analysts are concerned about the wrong limit, this has huge implications for energy policy: 1. Climate change models include way too much CO2 from fossil fuels. Lack of investment capital will bring down production of all fossil fuels in only a few years.

The amounts of fossil fuels included in climate change models are based on “Demand Model” and “Hubbert Peak Model” estimates of fossil fuel consumption (described in this post), both of which tend to be far too high. This is not to say that the climate isn’t changing, and won’t continue to change. It is just that excessive fossil fuel consumption needs to move much farther down our list of problems contributing to future climate change.

2. It becomes much less clear whether high-priced replacements for fossil fuels are worthwhile. In theory, they might allow a particular economy to have electricity for a while longer after collapse, if the whole system can be kept properly repaired.

Offsetting this potential benefit are several drawbacks: (a) they make the economy

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

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

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

Types of Forecasting Models There are three basic ways of making forecasts regarding future energy supply and related economic growth: 1. “Demand Based” Approaches. In this method, the analyst first decides what future GDP will be, and uses that estimate, together with past relationships, to “work backwards” to figure out how much energy supply will be needed in the future. The expected needed future energy supply is then divided up among various types of fuels, giving more of the growth to types that are favored, and less to other types.

Very often, estimates of growth in energy efficiency, growth in “renewables,” and growth in the amount of GDP that can be generated with a given amount of energy supply are included in the model as well.

This method is by far the most common approach for forecasting expected future energy supply, especially at high levels of aggregation. One advantage of this method is that can provide almost any answer the analyst wants. Governments are paying for reports such as the EIA and IEA forecasts, and oil companies are paying for forecasts such as those by BP, Shell, and Exxon-Mobil. Both governments and oil companies prefer reports that say that everything will be fine for the foreseeable future. Demand Based approaches are good for producing such reports.

Another advantage of this approach is that the analysts don’t have to think about pesky details like where all of the investment capital will come from, or how large an improvement in the ratio of GDP to energy consumption can actually occur. They can simply make assumptions and point out that the forecast won’t come true if the assumptions don’t hold.

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

In fact, we don’t really know how much oil or coal or natural gas will be extracted in the future–we just know how much looks like it might be extracted, if everything goes

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

What most people miss is the fact that the world economy is a Complex Adaptive System, and energy supply is part of this system. If there are diminishing returns with respect to energy supply–evidenced by the rising cost of extraction and distribution– then this will affect the economy in many ways simultaneously. The limit we are reaching is not that oil (or coal or natural gas) extraction will run out; it is that economic system will at some point seize up, and rapidly contract. The Hubbert Peak Method shows how much fuel might be extracted in each future year if the economy doesn’t seize up because of financial problems. The estimate produced by the Hubbert Peak Method removes some of the upward bias of the Demand Model approach, but it still tends to give forecasts that are higher than we can really expect.

3. Modeling How the Economy Actually Works. This approach is much more labor-intensive than the other two approaches, but is the only one that can be expected to give an answer that is in the right ballpark of being correct with respect to future economic growth and energy consumption. Of course, observing signs of oncoming collapse can also give an indication that we are nearing collapse.

The only study to date modeling how long the economy can grow without seizing up is the one documented in the 1972 book The Limits to Growth, by D. Meadows et al.

This analysis has proven to be surprisingly predictive. Several analyses, including this one by Charles Hall and John Day, have shown that the world economy is fairly close to “on track” with the base scenario shown in that book (Figure 1). If the world economy continues to follow this course shown, collapse would appear to be not more than 10 or 20 years away, as can be seen from Figure 1, below.

Figure 1. Base scenario from 1972 Limits to Growth, printed using today’s graphics by Charles Hall and John Day in “Revisiting Limits to Growth After Peak Oil” http://www.esf.edu/efb/hall/ 2009-05Hall0327.pdf

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One of the findings of the 1972 Limits to Growth analysis is that lack of investment capital is expected to be a significant part of what brings the system down.

(There are other issues as well, including excessive pollution and ultimately lack of food.) According to the book (p. 125): The industrial capital stock grows to a level that requires an enormous input of resources. In the very process of that growth it depletes a large fraction of the resource reserves available. As resource prices rise and mines are depleted, more and more capital must be used for obtaining resources, leaving less to be invested for future growth. Finally investment cannot keep up with depreciation, and the industrial base collapses, taking with it the service and agricultural systems, which have become dependent on industrial inputs (such as fertilizers, pesticides, hospital laboratories, computers, and especially energy for mechanization).

Jorgen Randers’ 2052: A Global Forecast for the Next Forty Years In 2012, the same organization that sponsored the original Limits to Growth study sponsored a new study, commemorating the 40th anniversary of the original report.

A person might expect that the new study would follow similar or updated methodology to the 1972 report, but the approach is in fact quite different. (See my post, Why I Don’t Believe Randers’ Limits to Growth Forecast to 2052.)

The model in Jorgen Randers’ 2052: A Global Forecast for the Next Forty Yearsappears to be a Demand Based approach that perhaps uses a Hubbert Peak Model on the fossil fuel portion of the analysis. One telling detail is the fact that Randers mentions in the Acknowledgements Section only one person who worked on the model (apart from himself). There he thanks “My old friend Ulrich Goluke, for creating the quantitative foundation (statistical data, spreadsheets, and other models) for this forecast.” Ulrich Goluke’s biography suggests that he is able to prepare a Demand Model spreadsheet. It would be hard to believe that he that he could have substituted for the team of 17 researchers who put together the original Limits to Growth analysis.

The Need to Add to the Original Limits to Growth Analysis The original Limits to Growth analysis was primarily concerned with quantities of items such as resources, pollution, population, and food. It did not get into financial aspects to any significant extent, except where flows of resources indicated a problem–namely in providing investment capital. One thing the model did not include at all was debt.

In the sections that follow, I show a model of how some parts of the economy that weren’t specifically modeled in the 1972 study work. If the economy works in the way described, it gives some insights as to why collapse may be ahead.

Economic Growth Arises from a Favorable Feedback Loop Economic growth seems to arise from a favorable feedback loop, as shown in Figure 2, on the next page.

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Figure 2. Author’s representation of how economic growth occurs in today’s economy.

This model above is intended to reflect the situation from, say, 1800 to 2000. The situation was somewhat different before the use of fossil fuels, when far less economic growth took place. Furthermore, as we will see later in this post, the model changes again to reflect the impact of diminishing returns as the cost of energy production increases in recent years and in the future.

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

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

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

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

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

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

This combination allows goods to be produced which initially may not be very cheap.

Over time, new methods are tried, allowing technology to improve. Consumers are able to buy increasing amounts of goods and services, both because of their own increased productivity (enabled by fossil fuels and new technology) tends to raise their wages, and because the improving technology lowers the cost of goods.

Government services are expanded as tax revenue per capita increases.

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

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

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

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

The Spoiler: Diminishing Returns The problem with energy extraction is that we extract the inexpensive-to-extract energy sources first. Eventually these sources get depleted, and we need to move on to more expensive-to-extract energy sources. I illustrate this situation with a triangle that has a dotted line at the bottom.

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

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Businesses start by extracting the cheapest to extract resources, found at the top of the triangle. As these resources deplete, they move on to the more expensive to extract resources, further down in the triangle. Looking downward, it always looks like there are more resources available–it is just that they are more expensive to extract. This is why reported reserves tend to increase over time, even as supplies are depleted. The limit is a financial limit, illustrated by a dotted line, which is why virtually no one can figure out when the limit will actually arrive.

One somewhat minor point: When I say, “Cheapest to extract resources,” I am referring to broadly defined costs. What businesses want is resources that produce goods and services most cheaply for the consumer. Thus, they are really concerned about cheapest total cost, considering the entire chain that goes all the way to the consumer, including refining and transportation. The costs would include energy used in extraction, labor costs, transportation costs, taxes, and the cost of debt. It probably should include the cost of mitigating pollution effects as well.

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

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

One indirect impact of these issues is that there are more layoffs and fewer new job opportunities. If we calculate average wages by taking (total US wages) and dividing by (total US population), we see that during periods of high oil prices, wages tend not to grow, as they had in periods when oil prices were lower–just as we would expect (Figure 5, next page).

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Figure 5. Average US wages compared to oil price, both in 2012$. US Wages are from Bureau of Labor Statistics Table 2.1, adjusted to 2012 using CPI-Urban inflation. Oil prices are Brent equivalent in 2012$, from BP’s 2013 Statistical Review of World Energy.

Another issue is that it is not just the price of oil that rises. The price of natural gas rises as well. We have not felt this in the United States, because demand has kept the price down below the price of shale gas extraction. The cost of coal, delivered to its destination, has risen because transport uses oil, and transport costs are a significant share of total costs. The cost of base metals has also risen since 2002, because oil is used in metal extraction. Food prices in general have tended to rise as well, because oil is used in production and transport of food. When wages are close to flat, and the cost of many goods are rising, workers find that their paychecks are increasingly squeezed.

While costs of making goods in the US are rising, and paychecks are stagnating, an increasing amount of goods are imported from areas around the world where energy costs and wage costs are lower. This helps keep the cost of consumer goods down, but it makes the problem of lack of jobs for US workers worse.

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

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Figure 6. Based on Table 2.1 and Table 3.1 of Bureau of Economic Analysis data.

Government spending includes Federal, State, and Local programs.

Government expenditures can be thought of as expenditures out of the surpluses of the economy. As indicated previously, these are to a significant extent possible because of the favorable difference between the cost of extracting fossil fuels and the benefit those fossil fuels provide to the economy. As the use of fossil fuels has grown over the years, these government services have grown. In recent years, the presence of more unemployed workers has driven a need for more government services.

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

How the Economic Growth Loop Changes to Contraction In my view, what causes a shift to contraction is a shift to higher energy costs. With higher energy costs, there is less surplus between the cost of extraction (broadly defined) and the benefit to society. Because of the smaller surplus, the parts of the economy that use this surplus, such as government spending, must shrink.

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

We gradually find that all the great things we had learned to enjoy–inexpensive roads and other infrastructure, cheap goods, rising wages, and rising government serves–start going away. We increasingly find consumers maxed out on debt. We also find companies (especially energy companies) reporting lower profits, so they have more trouble investing in new energy extraction. The government cannot collect enough taxes for all of its services, so finds itself needing to keep raising its own debt levels.

The government can kind of “paper over” its difficulties with growing debt levels for a while, by using Quantitative Easing (QE). QE has the effect of making the interest the US must pay on its own debt lower. It makes the cost of business investment in new plants and equipment (including shale oil drilling) cheaper. It also helps stretch the incomes of increasingly impoverished workers by allowing monthly payments on homes and cars to be lower than they would otherwise would be.

The Party Ends With a Thud Most readers can deduce that a shift from a growing economy to a shrinking economy is not a pleasant situation. It has all of the makings of collapse.

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

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To the extent new credit is cut off, the lack of credit cuts off new investment in energy extraction, in buying new cars and trucks, and in almost everything else.

Such a cut-off in credit is likely to increase job layoffs and to lead to yet more defaults. Lack of investment in new energy extraction causes oil supply to fall quickly–far more quickly than standard “decline” models would suggest.

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

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

We don’t know how this will end, but we do know that the Former Soviet Union collapsed into its constituent parts when fossil fuel surpluses were reduced, prior to 1991. Egypt and Syria both have had civil unrest as their oil exports ended. Clearly very large government changes are possible, as surpluses disappear.

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

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OilVoice Magazine | FEBRUARY 2014

Shell profit warning the shock that wasn't Written by Andrew McKillop from AMK CONSULT Shell's new CEO Ben van Beurden has admitted corporate performance in 2013 was not what he expected from the group. Just two weeks after taking over the helm at end-December, he gave what journalists and commentators called 'a shock profit warning', saying that full-year profits excluding 'special items' could be about 25% below 2012's performance. For the 4th Quarter of 2013 Shell's earnings before special items fell by about 50%.

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

The group's third- and fourth-quarter 2013 earnings figures were badly hit by a 3Q 49% drop in downstream profits, blamed on adverse refining conditions, both in North America but especially in Europe, due to structural refining overcapacity and weak energy demand. Van Beurden also cited the huge upstream asset writedowns made in 2013. Shell was quickly accused by some analysts of 'kitchen sinking', that is rushing to pump out the bad news, hoping investors will think the worst is over and past. Van Beurden said these special items ran at $700m for 4Q 2013, and at $2.7bn for the full year. When these massive writedowns, which will continue through 2014 are included in 2013 corporate figures, fourth-quarter earnings will be about 70% lower than one year before. Full year 2013 earnings, at about $16.75bn will be down by around 38% compared with 2012.

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

Shell and the Gas Bubble In early November 2012 at London's Royal Institution, outgoing CEO Voser hammered the 'go for gas' strategy Shell has pursued since the 1990s. He argued that Shell - as an integrated energy major - is creating value from the whole production supply chain, and the corporation sets gas growth as the jewel in the

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crown. He defended the gas strategy with the argument that sustained investment through the implied oil-gas value cycle is what shareholders want, not a stop-start strategy. Voser also repeated the corporate conviction that investment in gas exploration, production, processing and supply were '30-year assets', and Shell was not in the business of chasing 'short-term volume targets or market share'.

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

In his early November presentation to London's Royal Society, ex-CEO Voser repeated another fixed belief of Shell's corporate strategists. They imagine gas demand is growing so fast in Europe the continent may be left behind for signing up a share of future gas production among the worldwide flurry of new stranded gas finds and shale gas development.

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

Worse still for Shell, global gas demand growth has repeatedly failed its major economic challenge - that is the expectation, or gas producers' hope that consumption will increase despite slowing economic growth, reduced industrial output and outplacement, cheap coal supplies, the renewables, energy saving, and several other demand-trimming factors. Gas failed this challenge. Teflon-style growth of global gas demand is no longer the case, even if it held previously.

Shell's corporate policy statements and reviews on its dash for gas are now at best 'forward looking statements', based on the energy world before at latest 2012.

Investors may want to more carefully scrutinize these assertions and claims, today.

Two specific gas sectors are easily identified as creating the most serious challenges for Shell on the downstream side, GTL or gas to liquids conversion, and gas-fired power production in a few large markets, especially Europe and Japan. On the upstream side, as partly-admitted by van Beuren, the scramble for gas drilling acreages, and the following serial increase of development costs often generating veritable capex explosions, and nearly always stretched completion schedules which sometimes double the number of years needed, has made many attractive prospects turn very sour.

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

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the reasons Shell has been forced into a very active divestment program. It is estimated by some analysts as possibly running to 30 billion dollars through 20122015.

Official divestment goals as announced by new CEO van Beuren are for sales of assets able to raise $15 billion over 2 years. Already known to some journalists and analysts, this will inevitably target 'mature upstream assets', especially in the now capex-intensive 'drilled out' North Sea and a large slice of Shell's refining portfolio in Europe and the US. Some of this concerns non-performing assets which are likely to stay that way, unless huge new capex is thrown at the problem.

More important for Shell's gas strategy, corporate triage will winnow out a lengthening list of projects moving up the investment decision ladder, that are now considered too risky or overpriced - at the same time as corporate spokespersons have said there is no question of Shell reducing its goal of $130 bn of capex spending through 2012-2015. Project triage, due to the urgency of reducing Shell's runaway spending profile, may well extend from project types with a probable continuation of Shell's retreat from refining and oil production, to a complete retreat from selected large geographic regions. Analysts suggest the first to be abandoned

by Shell may be Australia and West Africa, particularly Nigeria. But a near-total retreat from the North Sea production and European refining is also not impossible.

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

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

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

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

The Shock that Was Not A Surprise Shell cannot be wrongfooted for its corporate conviction that global gas had to grow.

Among the oil majors, it is now the most gas-intensive producer and has global reach in gas reserves, transport and downstream assets, and value-add through gas-based petrochemicals. Shell is also a world leader in GTL (gas to liquids)

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

This can be called the good news. Its Bintula GTL plant, for which simply repairs to a major accident in 1997 cost about $1 billion, produces about 17 000 barrels a day of a range of fuel and nonfuel liquids, pricing this technology into a special cost dimension utterly dependent on almost-free natural gas for breakeven. The same applies to the Pearl GTL venture. If the gas is free, GTL works.

As Shell has found, literally to its cost, LNG ventures have a troubling habit of massive cost overruns and stretched completion schedules. Reasons why the corporation may wind down and divest its Australian production operations are summarized by the three-letter word LNG. Among non-American oil majors, Shell was fast off the block in moving into US shale gas production, but as Exxon Mobil through its gas subsidiary XTO Energy, as well as the USA's biggest gas producer Chesapeake Corp quickly found, along with other producers like Shell, the US shale bonanza can leave a lot of red on company balance sheets. Overall, US gas is too cheap, but Royal Dutch Shell can do nothing about it.

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

Perhaps not surprising for an oil major with a European HQ, Shell's focus on Europe has repeatedly produced over-optimistic and irrational corporate forecasts of energy demand recovery in Europe, led by gas, followed by project decisions on that wrongheaded basis. Corporate reading of Europe's energy transition plans believed firstly that emissions trading would hold up giving an edge to gas-fired power production, and that European refining infrastructures would get major and sustained EU and member state support for critically needed makeovers and restructuring.

None of this happened in the real world.

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

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OilVoice Magazine | FEBRUARY 2014

Total's investment is a big step for the future of UK shale - But don't get too excited just yet Written by Mark Young from Evaluate Energy On January 13th, 2014, French company Total confirmed that it had become the first global oil and gas major to invest in the burgeoning UK shale gas industry. This is a huge early milestone for the sector to have achieved, but Evaluate Energy argues that whilst this does bring the UK closer to widespread domestic onshore gas production, it will still be a long time before even the possibility of this becomes a reality.

Of course, Total’s investment is rightly going to be seen as a huge vote of confidence into the sector, and the smaller UK shale companies will no doubt be rubbing their hands with glee at such an oil and gas powerhouse coming to their aid.

Total will be investing a total of US$46.5 million on 2 exploration wells and pad construction to earn a 40% interest in 2 onshore licenses, joining Dart Energy, IGas and others in the quest to prove the commerciality of shale gas exploitation at these sites. These costs show just how imperative it was for small companies like Dart and IGas to get a partner like Total involved, as there are not many companies in the world that could afford such an outlay on an unproven sector. Total has an option tola exit after the first vertical well, but its partners will need Total to stick around, if the well costs in the US are anything to go by.

Shale gas exploration is not cheap work. Shale gas’ short history has so far shown that it takes plays many years of production before costs fall into line with those of more conventional plays. Two examples of these mature plays are the Barnett in Texas, where a typical well will be costing Quicksilver Resources (NYSE:KWK) around US$3 million in 2014 according to the company’s December 2013 investor presentation, and the Fayetteville in Arkansas, where In its own December presentation, Southwestern Energy (NYSE:SWN) states it will only be spending US$2.3 million on each well in 2014. But these are shale plays that are mature in terms of the development work being done, so a look at one of the newer gas plays in the US will give a better idea of the costs to be experienced in the UK; the Utica play in Ohio is a good point of reference. Last year, approximately 2 years into the Utica’s development history, Gulfport Energy (NASDAQ:GPOR) budgeted for a cost of US$9.2 million per well, Halcón Resources (NYSE:HK) budgeted for US$9.5 million, and CONSOL Energy’s (NYSE:CNX) costs were just under US$15 million, to give some company-specific examples. This is approximately 2 years into the exploration stage of the play, and the average monthly rig count has been above 20

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since May 2012, according to data from the EIA. If you assume one well per month being drilled by each rig, that would equate to hundreds of wells being drilled on the play in just over 18 months, and the well costs are still up at around US$10 million on average. Total has agreed to fund the drilling of 2 wells in the UK, so the UK still has an extremely long way to go before costs come down and the need for the presence an oil and gas major in the sector ends.

The profitability of UK shale gas will not be hampered as much by gas prices as the US has been, as prices in the UK are higher. So, assuming the high costs do not put Total off, the next step will be increasing production to the point where it fulfils the government’s promises over the last few months. Many figures have been cited in the press from various sources about percentages of UK gas demand that shale gas can satisfy and for how long, but for this we will just stick to a statement by Ed Davey, the UK Secretary of State, for Energy and Climate Change, when he said in a speech concerning potential shale gas exploration back in September 2013 that the UK is expecting to have to import 70% of its gas needs by 2025, as he predicts North Sea gas production will have lowered to around 19 million cubic metres per day by 2030. His speech suggests the UK will eventually be looking to get back to its net exporter status of 2003, and that shale gas is the answer. So we have to assume the plan is to, in fact, not import 70% of our gas needs, but produce it from the shale play. In 2012, the UK’s natural gas consumption was 7,554 million cubic feet per day (mmcf/d) according to BP. If we were to make even the simple assumption that consumption was to remain constant until 2025, shale gas would need to provide at least 5,288 mmcf/d of natural gas. Another look to EIA’s data for the US tells us that the gigantic Marcellus play (200 times bigger than the UK’s play according to Davey) in the Appalachian basin took around 4-5 years of widespread exploration and development work to reach this level of production in mid-2011, and the average rig count was over 100 for 2010 and 2011.

Source: Evaluate Energy via the EIA & BP’s Statistical Review 2013.

This level of activity, i.e. the hundreds of wells needed, is something that is currently unimaginable in the UK. The government has released details of more incentives for local authorities to issue more shale permits; it will be allowing local authorities to recoup 100% of the business rates of these operations instead of the usual 50%. But this will do nothing to stop the environmental activism juggernaut that has plagued shale gas fracking operations across Europe so far. The UK’s only real fracking operation to date was carried out by private company Cuadrilla Resources, who

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began its own exploration work with one rig to drill one well in Balcombe, West Sussex in mid-2013. Its initial work at the site about a year earlier caused a minor earthquake and began to ring alarm bells for environmental activists across the country, and when the company tried to begin fresh work on the site last year, it was met with angry protests that lasted for the duration of its stay. The company had to postpone its work for a few days on the health and safety advice of police due to the nature of the protests, and according to commentators made little effort, or at least little effort that was successful, to assuage the concerns of the protestors at the site and convince them that its fracking operation was in fact safe and the protest was unnecessary. This undoubtedly added to the heated nature of the protest, and publicly-listed companies like the ones Total has invested with will no doubt make more of an effort to engage with the public about its operations, but it is hard to ignore how much of a debacle the drilling of one well has caused. If shale plays need hundreds of wells to start to reach their potential, as operations in the US have proved, then can the UK really consider any of its shale gas targets realistic with this level of widespread public animosity?

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

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OilVoice Magazine | FEBRUARY 2014

Insight: a small black cloud?

Written by David Bamford from Finding Petroleum What should we make of this, a recent article discussing the forward projections of a number of seismic companies?

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

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

Why would that be?

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

1. 'Mature' NW Europe, whether in the North Sea or onshore, has had a dismal exploration record.

2. There have been several high profile failures in new 'Frontier' basins, for example offshore French Guiana, Brazil, Namibia‌ 3. The costs of offshore, especially deep water, drilling have 'gone through the roof'.

4. Development projects - of those discoveries that have been made - are increasingly seen as being behind schedule, overrunning budgets and not delivering the promised production.

Perhaps investors see the queues at supermarket and department store checkouts, and the scale of one of Amazon's warehouses, as providing better eveidence and better places to invest? Are we at a nodal point - one of those moments that in hindsight will be seen as the beginning of a cyclical downturn in the exploration business and therefore in the fortunes of seismic companies?

View more quality content from Finding Petroleum

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OilVoice Magazine | FEBRUARY 2014

Oil & gas M&A reaches US$143 billion in 2013 Written by Eoin Coyne from Evaluate Energy Rising F&D costs cause a drop in M&A activity from 2012 The year 2012 was colossal for mergers and acquisitions in the upstream oil and gas industry. Total volume reached a record $236 billion, an amount 54% up on 2011 and with seemingly few shocks in the macro environment, one could have been forgiven for assuming that 2013 was going to follow in the same vein. This, however, has not been the case, with the first half of the year producing just $49 billion of deals and, despite a late flurry in the second half of the year, 2013 ended with $143 billion of global upstream deals, a total that is 39% down from last year.

Global E&P Deal Value 2012-13 Source: Evaluate Energy M&A Database

The number one driver of confidence and therefore investment in the oil and gas E&P sector is the current and anticipated price of oil, followed to a lesser extent by the price of gas, both of which have changed very little since 2012 and do not explain the fall in M&A activity in 2013. The WTI benchmark price averaged $98 per barrel in 2013 versus $94 in 2012 and the Brent benchmark averaged $108 per barrel in 2013 versus $111 in 2012. In terms of gas prices, the US has even seen an increase in the Henry Hub benchmark ($3.71 per mcf versus $2.75 in 2012) whilst gas prices in the rest of the world outside of North America have remained robust, judging by company reported gas price realizations. The economic performance of key countries also fails to explain the subdued level of activity, with China meeting all of its growth targets during the year, Europe faring better as a whole than in 2012 and the US economic recovery resulting in its stock markets reaching record highs in December of 2013.

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The real reason for the drop in industry M&A is one that hasn’t attracted the same level of headlines as unrest in the Middle East, offshore oil spills or Arctic drilling, yet it’s doing more damage to the prosperity of E&P companies; the cost of finding, developing and extracting oil for public oil companies is steadily increasing. A recent study by Evaluate Energy looked at the historic financial and operating results of 52 large cap companies and concluded that the full cycle cost required to sustainably produce a barrel of crude oil surpassed $85 in 2012, which is 87% higher than the $45 required in 2008. This has had a negative effect on M&A investment in three ways. Firstly, the earnings of E&P companies have dropped in tandem with rising costs (cumulative net income for the first 9 months of 2013 is down 15% compared to the same period in 2012, based on the results of 170 companies) which has resulted in less free cash flow in the industry. The increased cost of successful exploration and development of existing properties owned by companies has resulted in less spare capital to take advantage of M&A opportunities. Finally, the decreased projected profit per barrel means that it has become harder for an asset to meet the requirements of a public company’s investment appraisal.

NOCs Stepping up Involvement The large total deal value in 2012 was boosted by the $57 billion acquisition of TNKBP by Rosneft, which also pushed the percentage of upstream deals made by stateinfluenced companies up from 25% of all deals in 2011 to 44% in 2012. Despite lacking a deal of similar magnitude, state-influenced companies maintained this ratio in 2013, accounting for 42% of total deals. The reasons mentioned above for the lack of public company activity do not apply to the same extent for state-backed companies, for whom any investment appraisal will be less stringent and based more on the security of long term reserves rather than a rate of return target percentage.

Free cash flow is also less of an issue when a country’s treasury can be utilised as a source of cheap financing.

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

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

Africa Rising in Prominence Another trend that has continued from 2012 to 2013 is the continued rise of investment in African oil and gas projects. Over the past decade, many countries across the world have become restrictive to investment from public oil companies via stricter fiscal policies or through an underlying threat of repatriation, as seen in Venezuela and more recently in Argentina when YPF was seized from Repsol by the

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

Upstream M&A in Africa has increased from US$7 billion in 2011, to US$10.6 in 2012 and US$17.4 billion in 2013, which represents rises of 51% and 64% per year respectively. A key stimulus in this overall rise has been the huge gas discoveries made in the Rovuma basin offshore Mozambique by Anadarko and ENI , which have revealed approximately 200 TCF of gas in place so far. In 2013 alone, there have been 6 deals in the Rovuma basin for a total of $9.3 billion. The most notable of these include CNPC acquiring a 20% interest in Area 4 for $4.2 billion, ONGC striking two deals to acquire a total of 20% in Area 1 for $4.125 billion and Oil India purchasing a 10% interest in Area 1 for $990 million. These deals suggest a cost per recoverable boe of $3 ($0.50 per mcf), which compared to the potential value per mcf on the Asian market of $15+ would initially look like good value. These discoveries do, however, have the dual problem of being in deep-water and being gaseous and will therefore require a substantial investment in LNG export facilities, pipelines and possibly even FLNG facilities that are all expensive in terms of capital and time, before any real profits can be made. This is the reason that the partners that Anadarko and ENI have attracted so far have been state-backed companies from gas importing countries, whose investment criteria will be long-term secure resource supply rather than satisfying the criterion of an NPV analysis.

Elsewhere in Africa, Tanzania - lying to the north of Mozambique - has had a similar experience to its neighbour, albeit to a lesser degree. Drilling of Tanzania’s deepwater prospects has exposed gas fields large enough to warrant the development of LNG export facilities but with Mozambique’s discoveries being over 4 times larger than Tanzania’s, Tanzania has failed to attract the same level of investment with only two deals taking place during the year in the country for $7.5 million. Had it not been for the large discoveries made offshore Mozambique, it’s likely that Tanzania would have been the most active country in terms of M&A in Africa during the year rather than its neighbour.

North American Shale Acquisitions Diminishing There has been a significant drop in the volume of shale deals, which has also had an impact on the global volume of deals in 2013. In 2011, shale deals accounted for $59.4 billion, in 2012 this was reduced to $33.3 billion and in 2013 this has dropped further to $22.3 billion. This transition is due in a large part to the existing North American gas glut, which has kept a firm lid on the gas price, and also the fact that many large cap companies have already built up strong acreage positions and are now focusing spending on development rather than building up acreage inventory.

For the shale deals that did occur during the year in North America, they were strongly dominated by the oil bearing plays such as the Bakken and Eagle Ford, which accounted for 77% of the total shale deal value; the fact that this ratio stood at 25% for 2011 accentuates the dynamic nature of the shale sector.

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

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deal to carry YPF for $620 million to drill 100 wells in the Vaca Muerta shale oil discovery in the Neuquén basin of Argentina. This shale play was discovered back in 2011, but development has so far been slow. With political risks emanating from the Argentinean government, Repsol was leisurely in its development whilst they had stewardship of YPF. Argentina will be hoping that this aggressive new development plan agreed by Chevron in this deal will go a long way to revealing and unlocking the potential of Argentina’s shale industry in 2014. Chevron is already active in shale plays in the US, Canada, Australia, China, Romania, Poland and Ukraine, and the company has emerged as possibly the most diverse geographic shale explorer in the world, so it is a very good partner for Argentina to be working with. The next largest shale deal outside of North America came from the United Kingdom as Centrica secured a $155 million farm in for a 25% interest in the Bowland basin licenses held

by Cuadrilla Resources.

Top Deals During 2013

Acquirer

Seller

Devon GeoSouthern Energy Energy Corporation

Brief Description

Devon Energy acquires GeoSouthern Energy’s assets in the Eagle Ford shale oil play CNPC acquires an 8.4% interest in the North Caspian Sea CNPC KazMunayGas Production Sharing Agreement (Kashagan Field), Kazakhstan from Kazmunaigaz The Government of Argentina repatriates Repsol's stake in YPF Government YPF in return for compensation of $5 of Argentina billion of Argentinean Government bonds Linn Energy acquires Berry Berry Petroleum Linn Energy Petroleum Corp in an all stock Co. deal BP acquires 5.66% stake in BP Rosneft Rosneft from OFSC ROSNEFTEGAZ China National Petroleum Corporation (CNPC) acquires 28.57% (net 20% in Area 4) of CNPC ENI Eni East Africa’s shares, owner of a 70% interest in Area 4, in Mozambique from Eni Riverstone Fieldwood Energy LLC, an Apache Holdings affiliate of Riverstone Holdings Corporation LLC acquires Gulf of Mexico Shelf

Country

Total Acquisition Cost (US$ billion)

United States

6.0

Kazakhstan 5.4

Argentina

5.0

United States

4.9

Russia

4.9

Mozambique 4.2

United States

3.8

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operations & properties from Apache Corporation Sinopec International Petroleum Exploration and Production Corporation, a fully-owned Apache Sinopec subsidiary of Sinopec Group Egypt Corporation acquires a 33% minority participation in Apache's Egypt oil and gas business Rosneft acquires the remaining ITERA Oil and 49% of ITERA Oil and Gas Rosneft Gas Company Russia Company LLC from Itera LLC Holdings Limited Source: Evaluate Energy

3.0

2.9

Outlook for 2014 North America Heading into 2014, the stifled gas price will continue to hamper upstream M&A in North America. Although an equalization of the gas price globally will go a long way to restoring the valuation of gas assets, this will not happen for at least another 4-5 years, if at all, a timeframe that is beyond the patience of a typical shareholder in a public company. Since the shale gas revolution in North American took hold in 2008, gas production has increased by 8 bcf/d, but the first onstream LNG Export terminal is not expected in the US until 2015, with 0.8 bcf/d of capacity rising to 2bcf/d in 2016. This will not make a significant impact on the gas price. Until the export capacity does make a tangible difference to gas prices, distressed sales of gas weighted assets is likely to continue with possible buyers coming from private equity companies who can afford more patience than a public oil company.

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

Africa Africa will also continue to hold ample opportunities for both juniors and established oil companies alike in the coming 12 months. There are currently 5 licensing rounds due to close during 2014 in the continent including Tanzania, Libya, Angola, Republic of Congo and Kenya with the latter possibly the most exciting of them all.

Like Tanzania and Mozambique, Kenya sits on the East African coast, but unlike its neighbours, Kenya’s recent successes have been oil discoveries rather than gas, which will whet the appetite for the world’s largest companies and should result in some prominent bidders when the auction begins.

Mexico Two of the main drivers for the US oil industry growth in the past decade have been the Eagle Ford shale play and the Gulf of Mexico, both of which straddle a border between US and Mexico. Whilst the US portions of these plays has developed into a

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multi trillion dollar industry, Mexico’s restrictive oil regime has resulted in only a fraction of the same success. In December 2013, a bill was passed in Congress to allow foreign companies to take part in the exploration and development of the Mexican oil industry via production sharing contracts. The terms of the contracts have yet to be ironed out but 2014 will be a year where Mexico firmly enters the strategic thinking of the major and mid-cap global independent oil companies.

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Insight: Give us a break!

Written by David Bamford from Finding Petroleum Yes, maybe we need a tax break for the UK North Sea but we also need service companies to charge less.

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

The OBR had made a flat-line revenue growth forecast for the period between 2013 and 2018 and Oil & Gas UK stated that it did not agree with this view, in fact it took a less pessimistic view. And they suggested that 'With up to an estimated 24 billion barrels still to be recovered there is a strong future for the North Sea, but as a mature basin, this will require, amongst other measures, an encouraging fiscal regime if the recovery of our oil and gas resource is to be maximised.'

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

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

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

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Only 40-odd of the 250 full members are oil & gas companies; the rest are oil field service companies and consultants of various sizes. And presumably these companies believe in the statement that "There is something like ÂŁ1 trillion worth of opportunities in the North Sea still to be developed and brought into production. It's a massive prize and it will take decades to deliver' from an earlier Oil & Gas UK pronouncement?

So, my question is this - are these oil field service companies, especially the big ones, and perhaps especially the drilling companies, prepared to drop their prices by say, 20%, as their contribution to delivering this nationally important target?

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The offshore oil drilling revolution, and its game-changing technologies Written by Dave Forest from Oil & Gas Investments Bulletin Last week I looked at the phenomenal success of a new breed of offshore explorers who are using unconventional drilling (read: horizontal drilling and fracking) to unlock billions of barrels of bypassed oil in places like the shallow-water U.S. Gulf of Mexico.

Offshore producers are now getting returns as good as their onshore competitors— but offshore stocks are valued much more cheaply.

But before investors jump off the dock, we need to understand the opportunity.

What’s happened with drilling technology to create such big returns? And why is this

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happening now in the offshore space? What techniques are delivering the biggest successes? And what companies are best-positioned to take advantage?

After all, horizontal drilling offshore isn’t a new idea. French firm Elf Aquitaine was drilling horizontal wells in the Adriatic Sea off Italy during the early 1980s.

In fact, major producers in the U.S. Gulf went through a horizontal “mini-boom” in the early 1990s. Over 20 wells were drilled by operators like Amoco. Results however, were mixed and the technique was largely abandoned for the next decade.

Better Technology Arrives Just In Time So why is horizontal drilling suddenly back in the offshore game and having a big impact?

I see two reasons for today’s surge in activity. One is just moving the new exploration techniques that were perfected onshore—offshore. Offshore wells are 3100x more expensive than onshore, so there is obviously less financial risk onshore if it fails.

But the energy sector is also using some funky technology from other industries— like Apple’s iPhone.

The iPhone uses something called a “small-scale accelerometer”—a device that measures changes in movement around them, telling it you’ve turned the screen sideways and should adjust the view accordingly.

Petroleum engineers simply took this technology and applied it to the drill bit— designing “smart” tools that can tell exactly where they are in space as they move down a well bore.

All this new technology does two things:  

it makes the well cheaper, and improves aim

One of the major challenges in drilling horizontally is making sure the horizontal leg of the well stays within the target formation. Steer too high or too low and the well can pass out of the oil-bearing rock formation. Or the driller could penetrate the oilwater contact—resulting in big inflows of value-killing water (water supersedes oil in the well bore).

But keeping a horizontal well level through the target formation is difficult—especially in places like the Gulf of Mexico, where oil columns can be just tens of feet thick.

That’s where a recent advance called logging-while-drilling (LWD) comes in.

The latest revolution in LWD is a combination of improved technology (machines to collect and transmit data) and better technique (interpreting collected data and using it to make decisions).

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All of these improvements cut their teeth initially in onshore U.S. shale plays.

When horizontal wells began developing shale basins like the Barnett in Texas, operators thought shales were one big blanket of rock. You could basically poke a drill hole into any part of the formation and get more or less the same result. (Stock Promoters still believe that!)

This turned out to be completely wrong. While shales are blanket formations that extend for hundreds of kilometers, they have lots of local variation—thickness, amount of sand, and natural fracturing of the rock.

Operators soon realized that placing a drill hole in the exact best part of a shale could make the difference between a three-month payback and a completely uneconomic well.

The problem was there was no way to tell from the surface where these sweet spots might be. Drillers needed a way to know what the drill bit was “seeing” as it moved through rock—and then react by steering the well into the most favorable location.

Luckily, this need for better downhole tools came just as technology was making some critical leaps. The result is that drillers today can collect very accurate, realtime information on the exact path of a well. That’s critical if you’re trying to steer a drill hole through an eight-foot think layer of shale.

More Information Means Better, Cheaper Wells Shale drilling also pushed drillers to develop a bunch of other tools for collecting downhole geological information. Today, geophysical tools like gamma ray and resistivity meters are all “looking” into the rock around a wellbore as it’s drilled—and transmitting real-time information back to the drilling engineer.

Drilling technology is in fact getting so good that it may make some parts of the exploration process—like seismic—redundant.

That’s incredible—revolutionary even—as almost all E&Ps collect seismic before drilling begins. But the American Association of Petroleum Geologists recently forecast the industry is not far from being able to run “seismic while drilling”, where downhole tools collect seismic data while the well bore is being driven through the formation.

Using this information, drillers can spot—for example—sandy sections within a shale. And steer toward them, or away from them, depending on the best completion techniques known for that particular formation—that’s known as “geosteering”.

Engineers today thus have a lot more data to look at while drilling a well. In fact, initially there was more information than most professionals could interpret on the fly.

That’s led to the development of sophisticated computer modeling techniques.

Software packages that combine all of the data coming from the downhole tools into a comprehensive model of the target reservoir. Updating every few minutes to show

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drillers exactly where the well is—and what rocks and other geologic features lie ahead.

Drillers have made a quantum leap in using such technology over the past few years. Where they used to fumble, they’re now capable of threading a well bore through thin, complex rock layers to pinpoint oil and gas pools.

The accuracy of this technology and technique also means quicker drilling. Which is key when expensive drilling equipment is sitting on a lease. Less time drilling means much lower well costs. And it’s this productivity from the services sector that’s ultimately made North America the only spot on Earth where shale drilling is economic.

What This Means for Offshore Development Which brings us back to the offshore environment—and the revolutionary changes going on there.

Smart offshore operators looked at the developments happening in shale and realized that applications like geosteering and logging-while-drilling are perfectly suited to a place like the shallow-water Gulf of Mexico.

That’s because much of the oil here is hosted in an array of thin sand layers, stacked on top of each other. In the past, only the thickest of these reservoirs were targeted for production.

But all of the new drilling technology—and the skill of drillers in interpreting information from it—has opened up new options for skinny pay zones. It’s now possible to run a horizontal well through a sand that’s only a few feet thick, keeping the well within the formation, and allowing for an effective completion.

For the moment, only a select few operators are taking this game to the offshore.

After all, the well costs here—even in shallow Gulf Shelf—are several times higher than in the onshore. Today, only the most skilled engineers are willing to take that risk.

But the moves are paying off—unlocking millions of new barrels in proved reserves for pioneering E&Ps. This is oil we always knew was in the ground—but no one thought would ever be produced economically.

Thus drillers here are essentially turning nothing into something. And from the look of returns on recent wells, that something might be the biggest play to come along globally for decades.

As mentioned, this revolution is beginning in the Gulf of Mexico. But where else might it soon spread?

Signs are already emerging that places like Asia and the African coast could be the next step for the offshore revolution.

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In the third and final part of this series, I’ll look at where in the world investors can expect big profits next from offshore unconventional drilling.

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Energy policy freeze frame in 1970s mould Written by Andrew McKillop from AMK CONSULT Oil Fear In a January 15, 2014 editorial titled 'Energy Antiquities' the Houston Chronicle underlined that when it concerns energy - we primarily mean oil - the thing to remember for the ever-expanding cohort of persons too young to remember the 1970s was that this decade, in a word, was the Forgettable Decade. Very forgettable.

After the 1973 shock rise of oil prices decided not only by the Arab producers but also by non-Arab Iran and the international oil majors, the rest of the decade was marked by fuel station line-ups and continuous price hikes in several major oil importer countries, which only got worse in 1979-81 following the Islamic revolution in Iran. For many, this was a period of humiliation at and by the gasoline pump.

While the Beatles were happy in the late 1960s wearing collarless Nehru jackets, by the late 1970s these were no longer a joke, when worn by Arab and Iranian oil barons dictating always higher oil prices. The al-Qaeda linkage and equation oil = terror was to come, later on.

The Houston Chronicle asks why is it that so much of US and other western countries' energy policy, today in the 21st century is stuck in a 1970s mold with policies, programs and laws that are as antiquated as a 45rpm plastic disc from the Beatles era?

No Change Antiquated, for some, means traditional. And the tradition of oil shortage, today in

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2014, helps Goldman Sachs and other rightly-named 'market operators and players' keep oil prices near or above $100 a barrel - while a barrel equivalent of coal energy, or gas energy in the US (but not Europe or Asia) languishes at far below $30.

This is transparent global energy market pricing, you said?

For Texans addressed by the Houston Chronicle the subject is numbing and unreal.

Why the US should have a 1970s-model energy policy, today, 40 years later, is especially ridiculous for an oil and gas-producing region of the US that has reversed years of domestic production decline. To be sure, local producers gain from the absurd 'global risk premium' on oil, but certainly not gas in the US, while both industries suffer from antiquated and fear-based policy and legislation, coupled with Washington's gut-level instinct to tax anything that moves.

Houston Chronicle calls this the Pac-Man 1970s fear syndrome that can drag down growth in Texan energy output.

Logically, it says, needed reform must begin with a loosening of shortage-inspired, 1970s-era export and transport regulations that hinder the energy industry's, and the nation's ability to deal with gluts of light crude oil that are very logically expected to build, as well as the enormous increases of natural gas production from shale rock.

The cast-in-concrete shortage-driven, fear-laden 1970s energy policy set, which still exists today, rejected any possibility that US energy production would increase. In fact the shale revolution stretching from Texas across the nation to Pennsylvania and Ohio, and to North Dakota and the upper Midwest expanded domestic oil and gas production beyond the imagination. In the relative blink of an eye.

Unexpected for sure - but was it unwanted, also?

In 2013, the US overtook Russia as the world's leading producer of combined oil and gas fossil fuels. Next to Russia and Saudi Arabia, the US is now third-largest oil producer in the world.

Yet the US domestic oil and gas industry remains handcuffed by outmoded federal regulations that prevent potential new international markets for U.S. Energy producers from operating efficiently, intensified by more than 10 years of rapid growth in US oil refining capacity, and therefore export capability. Industry data shows that the stamp of 1970s oil shortage fears dictated a massive ramp of heavy crude refining capacity along the US Gulf - for example to draw in Venezuelan heavy crudes. The refining industry retooled for heavy crudes, and ignored the explosion of domestic light oil production until too late. It now faces a massive restructuring challenge, with likely domestic shortages of key fuels on a recurring basis, unless oil trade regulations are eased.

Markets That Don't Exist Due to dirt line left in the bath by 1970s energy policy, the US oil refining industry made a response to crude oil supply and market conditions that disappeared years ago. The same happened in Europe, intensified by governmental energy policies even more crisis-oriented and shortage-based than US oil fear. In Europe, from the

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early 1980s and reinforced by the European Commission's Energy directorate for at least 15 years, the one-liner was that the continent's refiners must adapt to cheaper heavy crudes - but produce enough gasoline for European's then gasoline-majority car fleets.

Today, several EU28 countries like France and Germany have 75% diesel car fleets, and the discount on heavy crudes against light crudes has shrunk to almost nothing.

Ignoring real markets, and imagining fantasy market conditions is, to be sure, a privilege for bureaucrats and politicians but at some stage a reset to reality is obligatory. For the US, its light shale oil production is growing quite fast, but its shale gas output and potential output growth is set in another and even higher league.

Downstream of the gas boom, a host of US and international major petrochemical manufacturing companies now call Houston home but unreal pricing for natural gas inside the US - too low - and worldwide - too high - can only continue for so long. As one simple example, petrochemical production of synthetic light oil products direct from natural gas feedstock is not only technically possible but depending on corporate commitment, the gas-to-oil route producing marketable final use oil products is viable. Even at oil price levels around $60 per barrel and at current US natural gas prices, substituting crude oil with gas is economically feasible - but expensive in first investment terms and exposed to massive policy risk.

The 1970s Curse In the US, this energy debate is running today, because a much simpler, lower risk route to value-added is the export of US shale gas as LNG, and import of crudes suited to US Gulf refining. For the Houston Chronicle, the best solution is to change legislation hampering or forbidding access to export markets for both oil and natural gas. At one and the same time, this can restore and maintain market equilibrium for each product, while avoiding both a glut for sweet crude, and a depressed domestic gas market that discourages increased natural gas production.

This won't happen easily. Neither in the US, and even less so in Europe, will energy policy makers give up their 1970s mantra of oil shortage. Checking Nymex or ICE oil market prices, they are comforted that Goldman Sachs and the oil market maker banks plug along with a 'nice price' of $100 a barrel, and ignore the fact this market rigging is totally disconnected from global supply-demand realities. Old worries die hard among the political class in Washington or Brussels, and the bankster-broker 'community' laughs all the way to the Cayman Islands.

In the US, a large political lobby militates for 'keeping energy resources at home', not sent to China, India or Europe. To be sure, this certainly does not include American coal, an industry condemned to oblivion inside the US, because of shale gas and oil, and climate-environment legislation. US coal is now dependent as never before on export markets. However, due to 1970s vintage hysteria on oil shortage, and a diluted version of this hysteria for natural gas, Washington sets the hurdles very high for oil and gas exporting because these are 'strategic and limited' resources.

Ironically, as the Houston Chronicle notes in its editorial, the anti-export lobby in the US puts its political advocates in the same bag as the often-demonized Koch

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brothers, whose main interest is keeping US gas prices ultra-low, with its directly related menace of aborting continued growth of shale gas output. European oil fear, unchanged since the 1970s, dictates a politically forced and chaotic, almost anarchic rush to develop renewable energy, only for electricity generating - which will save almost no oil at all!

These are high-level political issues due to their economic weight and the ingrained, insanely stubborn policy that there is 'imminent shortage' of oil, a perpetual oil crisis.

Only deciders at presidential and prime minister level can change the gameplan and reset the energy playing field to flat. The Houston Chronicle was at best dubious this can happen in the US of Obama, who likely does not share the paper's view that when it comes to energy policy, the 1970s are not just a quaint picture of yesterday but are prehistoric.

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