OilVoice Magazine | November 2013

Edition twenty – November 2013

UK North Sea oil production decline

Geology beats technology: Shell shuts down oil shale pilot project Did BP, Shell and Statoil and others fix oil prices and behave anti-competitively?

Cover image by Richard Masoner / Cyclelicious

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OilVoice Magazine | NOVEMBER 2013

Adam Marmaras Chief Executive Officer Issue 20 – November 2013 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

Welcome to the 20th edition of the OilVoice Magazine. This edition contains articles from Werner R. Kranenburg, Kurt Cobb, Eoin Coyne, Keith Schaefer, Ilda Sedja, Euan Mearns, Jonathan Moore, Peter Parry, and of course, Andrew McKillop.

There are couple of exciting things happening over at our sister company, Finding Petroleum. We are now rolling out training courses at the prestigious Geological Society in London. Each month next year we aim to have a different oil and gas course, all lead by one of our experienced trainers. All of our trainers have a wealth of industry experience, and our courses can truly be called 'Master Classes'. Take a look at the line-up, and I hope to see you at one of the courses.

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Cover image by Richard Masoner

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OilVoice Magazine | NOVEMBER 2013

Contents Featured Authors Biographies of this months featured authors

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Did BP, Shell and Statoil and others fix oil prices and behave anticompetitively?

by Werner R. Kranenburg

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Time out for the petrodollar 'conspiracy'

by Andrew McKillop

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Another IEA politically correct oil market report

by Andrew McKillop

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The numbers don't add up to U.S. energy independence

by Kurt Cobb

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Peak prosperity for overpriced oil

by Andrew McKillop

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UK North Sea oil production decline

by Euan Mearns

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NOC acquisitions lift oil and gas M&A in Q3 2013 to $47.6 billion

by Eoin Coyne

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Canadian oil and gas company financings pick up in third quarter

by Jonathan Moore

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A focus on East Africa's junior oil and gas companies

by Ilda Sejdia

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Insight: 2014 oil and gas industry planning cycle - Getting it right

by Peter Parry

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The Tuscaloosa Marine Shale: America's next 'hot money' oil play?

by Keith Schaefer

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Geology beats technology: Shell shuts down oil shale pilot project

by Kurt Cobb

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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.

Werner R. Kranenburg Kranenburg Werner R. Kranenburg is an attorney and counselor-at-law admitted to practice law in New York State and various US federal courts and is a qualified arbitrator.

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

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

Keith Schaefer Oil & Gas Investments Bulletin Keith Schaefer, editor and publisher of the Oil & Gas Investments Bulletin.

Ilda Sedja Evaluate Energy Ilda Sedja is an Energy Analyst at Evaluate Energy.

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

Jonathan Moore Evaluate Energy Jonathan Moore is an Energy Analyst at Evaluate Energy.

Peter Parry Bain & Company Peter Parry is a partner in Bain & Company’s London office and a leader in the firm's Global Oil & Gas practice.

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OilVoice Magazine | NOVEMBER 2013

Did BP, Shell and Statoil and others fix oil prices and behave anti-competitively?

Written by Werner R. Kranenburg from Kranenburg In re North Sea Brent Crude Oil Futures Litigation: Civil action addressing 'inaccurate' oil pricing continues in New York In legal proceedings which may prove critical for both physical oil traders and traders in oil-related financial instruments, who should take note for their own possible take action, the focus of attention has of last week firmly shifted to a federal trial court in Manhattan for now. The European Commission stating that "[e]ven small distortions of assessed prices may have a huge impact on the prices of crude oil..." concerns all involved and, besides governmental authorities, market participates have their role to play as well in ensuring the integrity of benchmarks and fairness of competition such as through the courts.

In August last year, a trading arm of French oil major Total SA submitted a letter to the International Organization of Securities Commissions ("IOSCO") in which it says that "[s]ometimes the criteria imposed by [Price Reporting Agencies] do not assure an accurate representation of the market and consequently deform the real price levels paid at every level of the price chain..." It also speaks of the direct impact "inaccurate pricing" and "erroneous prices" have on the pricing of over-the-counter contracts and beyond. IOSCO, an assembly of financial markets regulators, published the letter in its final report1 on Principles for Oil Price Reporting Agencies in October 2012.

Then in May this year, it has been widely reported, three oil majors, namely BP PLC, Royal Dutch Shell PLC and Statoil ASA, and Platts, which compiles and publishes Brent Crude oil prices, were the subjects of unannounced inspections, more commonly referred to as 'raids', by the respective national competition authorities coordinated by the European Commission. As Statoil of Norway reported on the day of the visit, Norwegian "authorities suspect participation by several companies, including Statoil, in anti-competitive agreements and/or concerted practices contrary to [the European Economic Area free trade] Agreement".

Since then, the scope of the European investigations widened, American authorities such as the Commodity Futures Trading Commission (which is a member of IOSCO), the Department of Justice and the Federal Trade Commission are reported to have taken in an interest in the matter and lawsuits have been filed by private

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parties against the three oil majors in various US courts.

The European Commission's regulatory investigations and the US civil legal proceedings focus on two issues: concerns relating to price reporting and regarding potential violations of competition laws.

Following the raids, the European Commission ("EC") stated2 that the "Commission has concerns that the companies may have colluded in reporting distorted prices to a Price Reporting Agency to manipulate the published prices for a number of oil and biofuel products. Furthermore, the Commission has concerns that the companies may have prevented others from participating in the price assessment process, with a view to distorting published prices.' (As Statoil puts it, "[t]he suspected violations are related to the Platts' Market-On-Close (MOC) price assessment process, used to report prices in particular for crude oil, refined oil products and biofuels, and may have been on-going since 2002.")

The first civil action was filed in New York in the week after the EC's inspections, by Prime International Trading Ltd, a Chicago-based proprietary commodity trading company and member of various commodity exchanges. It was the first of several such filings, in New York and elsewhere, based on alleged violations of US federal commodity exchange and competition laws and common laws and the same facts regarding whether defendants conspired to fix, restrain trade in, and manipulate the prices of North Sea Brent Crude oil and Brent Crude oil futures contracts: "Defendants deliberately reported inaccurate, misleading and false information regarding Brent Crude oil prices to Platts... thereby undermin[ing] the entire pricing structure for the Brent Crude oil market."

Nothwithstanding the final consumers and the potential harm done to them as Total and the EC point out, the outcome of these civil proceedings may be relevant to anyone trading from 2002 to the present, in North Sea Brent crude oil derivatives traded on the New York Mercantile Exchange ("NYMEX") and Intercontinental Exchange ("ICE"), regardless of characteristics such as the trader's citizenship or location. (Brent Crude oil futures contracts are traded on the NYMEX and on electronic boards of trade and exchanges, such as the ICE, which are accessible in the United States.) The legal remedies sought include restitution of any sums the oil majors received by unjust enrichment, for their alleged unlawful conduct to be adjudged to be in violation of US federal competition law and a measure to prevent such conduct from occurring again in future.

The latest development as of last week is that a judicial Panel ordered for all the relevant cases to be centralised in the federal trial court in Manhattan, the Southern District of New York3. In its order, the Panel noted centralisation there will "promote the just and efficient conduct of the litigation" and cited the Manhattan locations of the NYMEX and that of Platts. It has not been established yet which private party will lead the centralised litigation.

So, did BP, Shell and Statoil and others fix oil prices and behave anti-competitively?

They are suspected of doing so based on indications from several market participants which have led to the regulatory investigations into whether they did and allegations in legal proceedings they indeed have done so. The time for civil legal

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proceedings and investigations, alongside the regulatory initiatives, is now as well.

These are cases to be followed by market participants concerned and for those seeking to become involved in the proceedings, who themselves may be located anywhere in the world, there is still time to be heard, exert influence in the conduct of the litigation and lead in this effort affecting the industry globally from the front.

1. http://www.iosco.org/library/pubdocs/pdf/IOSCOPD391.pdf 2. http://europa.eu/rapid/press-release_MEMO-13-435_en.htm 3. http://www.jpml.uscourts.gov/sites/jpml/files/MDL-2475-Initial_Transfer-09-13.pdf Link to Open Letter to Commodity Traders Contribution by Werner R. Kranenburg from Kranenburg Werner R. Kranenburg is a New York attorney and qualified arbitrator. Kranenburg, his City of London-based law firm, is concentrated on securities, investment and corporate litigation and arbitration in all courts in New York State and US federal courts, including the Southern District of New York, and before specialised tribunals.

-- http://kranenburgesq.com

View more quality content from Kranenburg

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Time out for the petrodollar 'conspiracy' Written by Andrew McKillop from AMK CONSULT FIRST YOU HAVE TO BELIEVE I have several articles published on this subject, and I break up the 40-odd years of 'the petrodollar system' into at least 3 clear main phases. More important, the present one is the last one. For a valedictory and uncertain, but official rationale for the present phase, the US Federal Reserve Bank of NY has a full statement http://www.newyorkfed.org/research/current_issues/ci12-9/ci12-9.html.

Always thought of by its US and Saudi inventors as a win-win, it has many downsides and can be lose-lose, also. For the global economy it is only lose-lose.

Just as important, the petrodollar and its related recycling started as a secret political initiative and will end political, but possibly public. Its economic, financial and monetary roles were always placed in the back seat, and handed over to 'experts', for example in the US Fed system, IMF and BIS to whine about. The main policy pillars of 'the system' - favouring US-Saudi economic relations and bolstering the US dollar - do not have any significant relation to, and do not resist comparison with the real role, weight and influence of oil and oil trade for the USA, even if it can be construed as sometimes highly favourable to Saudi Arabia.

Taking the USA's total for physical oil trade turnover, that is exports plus imports as about $450 billion a year in 2012, this can be set against either US GDP or US sovereign debt to see how small 'the petrodollar system' really is. We could also compare it with Wal-Mart Inc's turnover of about $469 billion a year in 2012. To be sure, leverage helps a million (we mean a trillion), but that also applies to real estate, mortgages and bolstering the 'value' of Facebook, Apple or Google shares.

One key factor turning a theoretical and political win-win into an economic, financial and monetary lose-lose, certainly for the USA, stems from US debt and 'dollar hegemony', both of them pushed only one way - further - by the petrodollar system.

The number one American export is US dollars, more precisely the repayment of current dollars and promise of future dollars on loans to be received and goods to be imported by the USA. Like any fiat money it is paper currency backed up by absolutely nothing, but the rest of the world's need to import oil (for around 160 countries out of 200) means they need dollars to buy oil - when and if it is billed and settled in dollars. Other trade goods and services, in majority, are billed and settled in dollars, but there's no basic reason this has to be treated as permanent and

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obligatory. The same applies to oil.

The petrodollar system is above all political and concerns the US and Saudi Arabia before anybody else, or anything else. Due to current-ruling Saudi potentates, notably the so-called 'Intelligence chief' Prince Bandar bin Sultan claiming Saudi rule over President Obama's decisions on Syrian bombing, and raging about Obama's non-bombing, the threat of Saudi Arabia 'abandoning the petrodollar' has been circulating. When or if Saudi oil exports were increasingly billed and settled in currencies other than the USD, the present semi-monopoly would disintegrate.

One de facto result would be a strengthening of the USD's world value after a ritual and probably impressive period of 'trial by market'. To be sure market logic, we mean panic would take some time to adjust to the real world, as ever, but the main reason the dollar would strengthen would be the USA's need to print and issue far less and far fewer 'chaff dollars'.

NO CATASTROPHE The doomster argument is all too easy. The biggest reason why good relations with Saudi Arabia are so important to the United States is because the petrodollar semimonopoly will not work without them. For decades, Washington has bowed and cowed, and gone to extraordinary lengths to mollycoddle the Saudis, despite the huge Saudi exposure to any theoretical crash of the USD's value.

Supposedly, Saudi players still believe what they thought Phase One of the petrodollar system meant. During its early days (1972-1985) it meant large gains for KSA - more political than economic - but after that it meant several years (19861991) of large political-and-economic losses. We could even argue 'the system' was de facto idled or mothballed for most of the 1992-2001 period, during which it did little for the USA - and much less than nothing for Saudi Arabia. Continuing with that line of reasoning, 'the system' was only brought back into life, under George W. Bush and Hank Paulson, from about 2005. The above-cited US Fed bank of NY statement especially concerns this last phase - although the bank does not treat it as the end of the line.

One thing on the US side is however sure and certain - in no way would US debt have grown so fast, to such extremes, nor the trade deficit have ballooned in the absence of the 'petrodollar system'. That would certainly not have been a catastrophe! US gains throughout all the phases or formats of 'the system' were always more apparent than real - but the US political elite feeds off appearances, which is one of its basic defects.

The Saudi side, unfortunately, only has defects. With Bandar bin Sultan these are monstrously evident. One of his latest tirades was to also criticize the US for not backing Saudi Arabia's military rampage in nearby small-sized Bahrain, killing hundreds of peaceful demonstrators against the ruling Sunni clique of Bahrain, which totally depends on Saudi support. Concerning Syria, of course, the Saudis could in theory always go and fight their own war, but that is not at all the way that Saudis 'heroically' do things. Presented as a supposed sign of bargaining strength with Washington, aides to bin Sultan repeatedly point out that KSA central bank foreign

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exchange assets are close to $700 billion 'and are almost exclusively denominated in US dollars'. The Saudis could sell these, of course, but dumping that amount on the markets in a princely flourish will result in stupendous losses for Saudi Arabia.

Due to 'the system' always having been secret as well as political, most Americans and the majority of non-Americans have absolutely no idea about it. Because of this, they can more easily believe the one-liner that terminating 'the system' could only 'severely damage the U.S. and world economy'.

Without the prop of petrodollar recycling and its leverage, operated by the US Federal Reserve banking system, and the leading money market banks, it would be very unlikely that the US could run its present fantastic annual trade deficits. The US economy would have to 're-localize', or 'de-offshore'. Would this be a disaster?

CATASTROPHE FOR THE SAUDIS - AND OTHERS Conversely, the disaster for Saudi Arabia would be real and would not ebb away after a few weeks of market panic. We would assume that Bandar bin Sultan's was able, domestically, to put his threats to execution, and Saudi Arabia suddenly sold a large slab of its $700 billion FX stash. It would also exactly invert the petrodollar system - henceforth demanding oil payment in any currency but the dollar. No dollars accepted! What price would KSA set for its oil exports? What would other OPEC exporters do? How would they settle oil sales?

Almost certainly the global oil market system would mutate back to pre-1987, before widespread market trading mainly in dollars. Oil supplies and sales would utilise a wide range of settlement systems. These included baskets of currencies, trade offset bilateral arrangements, barter-type settlement, netback deals, technology deals, even gold and other PMG metals used as payment.

In any event total oil shipments would decline for some time - possibly months or several years. Expressed in some reliable measure-of-value, excluding fiat currencies, oil prices could only decline. Saudi Arabia's government, basically its royal family and its princely clans, gets 92% of its revenues from oil. Putting the Bandar bin Sultan menace to execution, they would have blown their stash of central bank FX reserves, and weakened their economy going forward, probably for years ahead.

For the US and inevitably, the end of petrodollars and their recycling will mean an end to the era of cheap imports and super low interest rates, but will also reset the global economy - not at all to the disadvantage of the USA. China, now the world's No 1 oil importer, will be obliged to move fast to replace dollars for its oil trade. This will mean the RMB appreciates, which is what China doesn't want, but has to accept.

One thing is certain, Saudi sabotage of the US dollar will not be germane to China which holds about $1.25 trillion of US Treasury bonds.

The likelihood of China aligning with the US - if only to save its dollar stash - can be taken as relatively high, but it is sure and certain that China will be limiting its purchase of US debt in the future and itself seeking other trade-and-currency arrangements. This is already a 'sombre signal' for the US, but only if it want to

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continue its race to the cliff edge.

Unfortunately, the petrodollar system, although 'secret' only works if the rest of the planet has faith in it, but aided by 'the system' becoming dysfunctional, perverse or non-performing, the United States is systematically destroying the faith in the dollar that the rest of the world has in our global financial system. Put another way, if for no other reason (and there are plenty!) US debt growth had to decline, due to the petrodollar system terminating, this could only further limit the USA's reckless accumulation of debt. Given the broken back out-of-sight state of national finances and economic expectations in most countries, this would be a 'disaster' but in real terms is not.

View more quality content from AMK CONSULT

Another IEA politically correct oil market report Written by Andrew McKillop from AMK CONSULT IEA THEORY - DEMAND GROWTH AND HIGHER PRICES The IEA's latest Oil Market Report for 12 September 2013 was highly predictable.

Only able to report world oil demand growth at 0.9% for 2012-2013 to date, it pushed forward its estimate for renewed demand growth to 2014, with a 1.1% or 0.9 million barrels-a-day (Mbd) growth forecast. This would raise aggregate world demand to around or about 92.6 Mbd by late 2014.

On prices, the IEA's September report merely said that 'rising geopolitical tensions over Syria's suspected use of chemical weapons and the near total shut-in of Libyan production' raised prices despite record Saudi and Iraqi production inside OPEC, and record US and Russian production outside the cartel. It also noted that prices turned down from mid-September 'as a Russian proposal for Syria to surrender its chemical weapons gained traction'. Since the report's release and to date, October 7, Brent and WTI have lost about $5-$6 per barrel.

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A Wall Street Journal analysis of global energy, published October 7 shows that the U.S. is on track to pass Russia as the world's largest producer of oil and gas combined this year-if it hasn't already. One reason is that Russian output growth is slowing due to multiple reasons including aging oilfield infrastructures and the slow pace of Russia adopting 'fracking' technology, but the main reason is surging US output growth of both oil and so-called natural gas liquids (NGLs) or oil condensates from mixed oil-and-gas output streams. Combined with the reality of weak global oil and gas demand growth, surging supply means that high prices have to turn down - sooner rather than later. On a strict fuel price equivalent base, current US natural gas prices are about $21 per barrel of oil equivalent.

RISING SUPPLY AND STAGNANT DEMAND The IEA avoids the demand-side reasons for 'bearish' price outlooks for world oil in particular, and for global natural gas within 3 - 5 years. The key surrogate for global oil energy demand, excluding non-energy end uses, is world refinery runs. Here, the latest IEA report was able to say that global refinery crude runs reached a seasonal peak in July at about 78.2 Mbd, about 1.8 Mbd more than a year earlier, but rapidly shrinking margins due to weakening demand will soon shift this to an IEA forecast average run of 76.8 Mbd in 3Q 2013.

Compared with one year previous this is a growth of 0.4 Mbd or 0.5%.

Global oil demand for combined fuel + nonfuel utilisation is likely growing at rates much lower than IEA forecasters' estimates and forecasts, for the present year set by the 'oil watchdog' agency at 0.9%, followed by 1.1% for 2014. The IEA, mostly for political-correct reasons, but also through its forecasting methods has a long track record of over-estimating world oil demand growth. Its 'Refinery margins Methodology notes' publication provides ample details on typical refinery output profiles in major world regions, for example much higher diesel fuel yields and therefore operating costs in Europe than USA, due to very different car fleet compositions. The previous economic policy rationale for 'dieselization' of car fleets in Europe - to use lower cost high sulfur crudes - ignoring the cancer threat and health costs of diesel fuel and its residues, has been overturned by increasing world NGL and condensate supply and also by the closing of high sulfur-low sulfur crude price spreads. As a result, fuel prices are high in Europe and set to stay that way further depressing demand growth potentials.

Conversely, refinery operating costs are very low in Asia, as low as $1.50 per barrel compared with extremes up to $7.50 a barrel in Europe, making it rational to forecast continuing Asian demand growth on a pure fuel price basis. This however ignores the global macroeconomic context, as well as national energy, economic and environment policy factors and pressures. At the global macro scale the energy

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revolution focused by 'Wall St Journal', October 7, includes a vastly faster rate of growth of light crudes, NGLs and condensates than heavier and 'conventional' crude supply. Shifting back to Asia and despite its liquid fuel price advantage due to lower cost refining structures with high yields of gasoline, cooking fuel kerosene, and naptha the region is far ahead on a global basis in the transition to natural gas fuelled and LPG-fuelled road transport.

While US shale oil production is expanding fast from a low-or-zero base even 3 years ago, its shale gas production, despite extreme low domestic natural gas prices remains very strong and growing - and certain to spread overseas. Russia, for example, is estimated by many as holding the world's largest undeveloped shale oil + shale gas reserves. As in the US, international shale gas output will precede shale oil, making it a near-certain bet that global natural gas prices have to decline. When they do, the shift away from oil energy in its last major role - for transport - will accelerate and can only do so.

Back to back, the outlook for world and regional oil demand growth is weak. Oil prices, for sure, can 'surf' a little while longer on Syrian atrocities and geopolitical musings about breakdown in the Middle East, but world economic trends and global energy resource development runs right against those comforting theories - for oil brokers and traders, only.

View more quality content from AMK CONSULT

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

NOVEMBER 2013

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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.

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 irst 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.

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

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

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

KEY TECHNOLOGIES: MAGNETIC PASSIVE-SOURCE EM RADIOMETRIC GRAVITY HYPERSPECTRAL PREDICTIVE ANALYTICS

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

KEY INTERPRETIVE PRODUCTS: ≥

Regional resistivity voxels down to 10,000 feet

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Maps of lineaments, fault networks, and intrusives

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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.

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The numbers don't add up to U.S. energy independence Written by Kurt Cobb from Resource Insights Energy independence sounds good, and that's why politicians and oil company executives love to say the words. It's so easy to say, but oh so hard to actually accomplish, which is why the United States has been a consistent importer of oil since the late 1940s.

Recent overblown statements about U.S. energy independence from the oil industry, its paid consultants and the fake think-tank academics it funds simply aren't supported by the numbers. I have discussed this issue in two previous pieces, "The Oil Industry's Deceitful Promise of American Energy Independence" and "Oil and gas industry uses deceptive energy independence message to push U.S. exports". bl Recently, friend and colleague Jeffrey Brown--who is best known for his Export Land Model which foretold of shrinking global oil exports--did some fairly simple math to show how difficult it will be for the United States just to maintain its current production, let alone produce all the oil and natural gas it consumes.

In a recent email Brown, who is a Dallas-based independent petroleum geologist managing a joint-venture exploration program, wrote the following: The EIA's [U.S. Energy Information Administration's] estimate for the most recent four week average crude oil production rate (Crude + Condensate)[which is the definition of oil] was 7.6 mbpd (million barrels per day). Refinery runs were 15.8 mbpd, and net crude oil imports averaged 8.0 mbpd. The numbers for total liquids are, of course, different.

As several people have noted for some time, the primary problem with the tight[oil]/[natural gas] shale plays is the high decline rate.

At a (probably conservative) 10%/year decline rate for existing U.S. crude oil production, in order to simply maintain current U.S. crude oil production, the industry would have to put on line the productive equivalent of every current oil field in the U.S. over the next 10 years, or in round numbers we would need the productive equivalent of 10 new Bakken plays over 10 years, in order to maintain current crude oil production.

Citi Research [an arm of Citigroup] puts the decline rate for existing U.S. natural gas production at about 24%/year, which would require the industry to replace about

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100% of current U.S. natural gas production in four years, just to maintain current production, or we would need the productive equivalent of 30 new Barnett Shale plays over 10 years, in order to maintain current natural gas production.

Companies are not finding one new Bakken play each year; nor are they finding three new Barnett Shale-sized plays each year. In fact, production of U.S. natural gas has been just about flat since the beginning of 2012. U.S. crude oil production continues to grow, outpacing most projections. But, the United States would have to more than double its output from here to supply all of the country's needs.

Keep in mind that U.S. energy independence has almost always been about oil. U.S. coal production has long satisfied U.S. consumption. And, U.S. natural gas imports from 1990 through 2010 averaged just 16.8 percent of total U.S. consumption.

Almost all of that came from Canada, the country's northern neighbor and longtime ally.

That percentage came down in 2011 and 2012 to 14.2 percent and 12.5 percent, respectively. It's possible that U.S. production may yet grow just enough to bring that percentage down to zero. But, given the steep production decline rates for natural gas wells being drilled today, it's doubtful that production at a level high enough to avoid net imports could be maintained for very long.

That leaves us with oil. On average from 1990 through 2012, for domestic use the United States imported about 54 percent of its crude oil and petroleum products such as gasoline and diesel fuel (based on historical data gathered by the EIA). In 2012 the percentage had come down from that average to 48.3 percent.* It's progress, but the country is not even close to becoming energy independent. These percentages are based on crude oil and total petroleum products which include natural gas liquids that come from natural gas wells. It isn't clear how to back out these non-oil liquids in the statistics.

Still, the numbers give us a reasonable look at what the data actually say about the prospect of U.S. energy independence, which really means oil independence. The prospects are not good.

Brown points out that we've been down this road once before when the huge oil find around Prudhoe Bay in Alaska boosted U.S. oil production for a time in the 1980s.

But Prudhoe Bay peaked in 1988 and has been on the decline ever since then. And, with it went total U.S. production until recently.

Given the potential for U.S. tight oil in deep shale deposits and a high oil price which makes it possible to incur the high costs of getting it out, U.S. production could grow for a time. But at some point the high production decline rates for tight oil wells (around 40 percent per year) will be too much of a barrier, and total U.S. crude oil production will begin to decline once again, Brown believes.

The cornucopian's argument is that the third time's the charm, that the industry can now do what they could not do from 1970 to 1977 [after the peak in U.S. oil production] and what they could not do from 1984 to 1991 [during the boom in Alaskan oil production], i.e., indefinitely maintain the rate of increase in production.

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And, of course, we are going to do this with the highest overall decline rates that we have ever seen.

Brown says you have to keep in mind that tight oil wells drilled today will in a few years be producing just a small fraction of what they are producing now. And, that means new wells will have to be drilled just to make up for this decline. Only then can production start to grow. As total U.S. production increases and the number of producing wells grows considerably, the number of new wells needed just to make up for the decline in the production of existing wells will grow along with it. At some point it will become impossible both to make up for declines in existing wells and to grow production.

Brown believes that the United States is unlikely ever again to exceed the 9.6 mbpd of crude oil production it achieved in 1970, the peak year. More likely is a continuation of an undulating decline with occasional upturns followed by fresh downturns.

What he finds ironic is that those who are saying that peak oil is dead are using the United States, an oil producer that saw its production peak more than 40 years ago, as the poster child for their arguments. Yes, the ride down the peak can feature a significant bounce here and there, just as--if you'll forgive the analogy--a dead cat hurled downward can appear to show some life as it bounces off the floor.

The oil age may not be dead yet, but Brown believes that the top is nearby--not just for the United States, but for the world. And, that means we are wasting precious time being lulled to sleep by the oil optimists when we should be preparing for a post-peak oil world. * I arrive at this percentage by subtracting U.S. exports from total U.S. consumption which includes petroleum products refined for export. This gives me actual domestic consumption. I also subtract U.S. exports from U.S. imports to give me net imports.

Then I divide net imports by domestic consumption to yield the percentage of that consumption which is dependent on imports.

View more quality content from Resource Insights

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OilVoice Magazine | NOVEMBER 2013

Peak prosperity for overpriced oil Written by Andrew McKillop from AMK CONSULT THE DEBT CEILING SUPERCEDED AND REPLACED Simple, easily available data on US debt shows the US actually hit its debt ceiling - if we call it $16.7 trillion - back in May 2013, at least five months ago. Today, the sovereign debt of the US is well above $17 trillion, but curiously enough this simple fact never features in the media. What happened is the US Federal Reserve took 'extraordinary measures', followed in the fullness of political time - with the obligatory cliffhangers for TV audiences - by a three-month political extension to any practical decision, except to keep borrowing and spending.

As Warren Buffett said in an interview with CNBC, Washington would get close to the point of extreme stupidity, 'but would not cross that line'.

Likewise the ultra-magic triple-digit price in dollars of US WTI needs extraordinary measures to stay that over-priced. Oil flirted with the $99.99 price floor, today, 21 October. Not so long ago, WTI was very confidently forecast by some of Wall Street's most powerful market manipulators - sometimes called 'investors' - as easily able to attain $125 per barrel before December 31st.

Even by mid-morning, New York time, 21 October, the plunge protection team was clearly at work trying to repair the damage, because falling oil prices are a challenge to New Normal.

The extent to which the team succeeds in its quest, which is recurrent and even cyclic, with its most recent peak in 2008, can be questioned this time around. On strict fundamentals-only, oil is overpriced by at least $20 a barrel. Leaving in place the Syrian surcharge or Middle East risk premium of perhaps $10 a barrel, we get a realistic non-manipulated target price around $89 per barrel for WTI. Without that risk premium we get a maximum sticker price of $80 per barrel for WTI. HELPED OR HINDERED BY THE DOLLAR? Conventional oil analysts and trader lore says that if the USD declines, oil prices in dollars normally rise 'mutatis mutandis' but even if we forgot our Latin, the outlook for the USD plunging - against what? - presents a lot of intellectual problems. Against oil is what the oil bulls hope.

Quoted on Pravda.ru, October 16, scholar Mikhail Khazin said: "Those who are professionally engaged in economic matters, in one voice say that there are not years, but months or even weeks left before the collapse." To be sure he meant a

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collapse of the USD and its role in world trade - especially oil trade. Conversely, Khazin said nothing at all about the Russian ruble becoming the world's new petrodollar, nor the RMB, nor gold - we can tell him that oil-gold trades will be hampered by persistent weakness inside the bullion market, upstream corporate debt for miners hitting extremes, but revenues declining, and soft gold mining stock prices being sure and certain for some while forward.

Forecasts that the USD is going to tank - against what? - face so many hurdles in the real world we can bet with the contrarians that the world value of the dollar will rise a little, if not a lot, in coming days and even weeks. Dragging down the oil price.

In a normal world, nothing like New Normal, as pointed out by Alistair Macleod in a long interview with Chris Martenson on 'Peak Prosperity', October 19, the role of QE worldwide, whether its the US Fed, the ECB, the BOE or BOJ has reached a saturation effect in artificial wealth creation, and is now only a wealth transfer operation. Only those players close to the money spigot will now get the spinoff or 'trickle down' from printed money. Everywhere else in the economy, local and global, we get deflation. Oil prices will therefore deflate - not inflate.

TIMELINES FOR CHANGE Right across the commodities space - except oil - natural resource prices are wilting.

This is new normal. The back-flow current and negative feedback effect is strong, but oil still counts a large number of deep-pocket players habituated - or addicted to getting a reliable return from betting that oil prices will rise. Being slow-witted and slow to change, their paradigm change takes time.

Measured by mostly all-time record highs for major stock exchanges, as in Europe during its fifth straight year of economic decline with 27 million unemployeds making Jobless Europe the No 7 'country' in the EU 28-country grouping - asset prices have reached a peak, or very close to. Further growth can only be slow, but decline can only be fast.

Oil tracks equities a lot more than the USD's world value, meaning that when equities tank - oil tanks.

Whether or not equity markets can be maintained at extreme highs, and then grown some more, is a daily question these days, and the answer will soon be No. Some while before that 'unexpected crisis' occurs, oil will have to tiptoe away from its previous overpriced peak value. At that time, the plunge protection team will abandon its warm, previously reliable support to overpriced oil - and that time could be now or very soon.

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OilVoice Magazine | NOVEMBER 2013

UK North Sea oil production decline Written by Euan Mearns from Energy Matters The streets of Aberdeen are lined with Range Rovers, Porsches and Audis. New commercial property and residential developments are popping up all over and around the city. It is boom time in Europe’s oil capital. And yet UK North Sea oil production is in free fall, despite record high expenditure.

Figure 1 In the period 1999 to 2008, sharply rising oil price more than outweighed plummeting production and the total value of that production kept rising. But with oil price now stabilised and range bound $100$120 / barrel, a continued fall in production will begin to drag the value of that production downwards as capital and operating costs go up.

Data from the BP statistical review of World Energy 2013. Click on all charts to get a larger copy.

Oil Field Decline and Decline Rates Production from most oil fields begins to decline within a few years of production starting as a result of pressure depletion and reserves depletion and ingress of water or gas into the previously oil bearing strata. During the early years of a basin development new discoveries that come on line will normally more than compensate for decline and production may grow. However, as new discovery rate falls and the number of new fields coming on line goes down, decline takes over and can be difficult to reverse.

UK oil production peaked in 1999 and has since declined at an annual rate between 5 and 10% (Figure 2). However, in 2011 decline accelerated to an unprecedented 17.9%. A number of factors contribute to this (Figure 2) including an increase in taxation on North Sea production made without warning in March of that year.

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Figure 2 Annual decline rates based on data displayed in Figure 1. Occasional major new field developments such as Elgin/Franklin in 2001/02 (1) and Buzzard in 2007/08 (2) arrested declines for only 1 year. Major unscheduled field outages in ageing infrastructure (Schiehallion periodically 2009-2013; Elgin, Franklin and Shearwater in 2012) have contributed to accelerating decline. And a spate of helicopter accidents, some fatal, in the period 2009-2013, has disrupted production. A greater industry focus on health and safety following the Macondo blow out in the Gulf of Mexico has also made an impact. An increase in North Sea production taxation announced in March 2011 added fiscal uncertainty, and certainly did no help (3).

Capital and Operating Costs The decline of UK North Sea oil has continued unabated despite record high oil price and investment. Capital expenditure on new field developments and old field refurbishments has grown from £5.2 billion in 2008 to a projected £14 billion this year (Figure 3; data from DECC). Some of the new production from this CAPEX will begin to flow in the years ahead.

Figure 3 Field development capital, exploration and appraisal and operating costs for the UK continental shelf, historic and projected (UK Department of Energy and Climate Change – DECC).

2013 will see record expenditure despite oil and gas production continuing its free fall.

Of greater concern for the industry is spiralling operating costs. Total OPEX for oil and gas has near doubled from £4.5 billion in 2004 to £7.8 billion in 2012 whilst in the same period both oil and gas production have more than halved (Figure 4; data from DECC). These diminishing returns can clearly not continue for ever.

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Figure 4 Plunging production and spiralling costs spells trouble ahead for the UK oil and gas industry. OPEX from DECC, oil and gas production from BP. One billion cubic feet of gas (bcf) = 0.19 million barrels of oil equivalent. Note that chart is not zero scaled.

Impact on Balance of Trade UK oil production got seriously under way in 1976 and grew strongly for a decade having a profound impact upon the UK’s export / import balance in energy. For 20 years, the UK enjoyed a surplus in oil (and gas) production providing energy security and a positive contribution to the balance of trade (Figures 5 and 6).

Figure 5 The new DECC energy portal is a gold mine of UK energy statistics such as the history of oil and oil products imports and exports shown here. Prior to and during World War II (WWII) the UK lacked significant refining capacity and depended upon imported refined products. Post WWII imports of crude oil ballooned presumably matched by expansion of refining capacity. With the advent of North Sea oil production in the 1970s the UK became an exporter of crude oil and some refined products until 2006 when we once again became a net importer.

With the onset of decline post 2000 the UK oil and gas surplus has been eaten away and since 2005 energy imports have once again become the norm and the UK trade balance in energy is spiralling into the red (Figure 6). An energy surplus of £9 billion in 2000 has turned into a deficit of £21 billion in 2012. Where UK energy security once lay at our door step in The North Sea we are now increasingly dependent upon energy imports from Norway, Russia, Africa and The Middle East.

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Figure 6 This chart, kindly provided by DECC, shows the swing from ÂŁ9 billion energy surplus to ÂŁ21 billion energy deficit in only 12 years. To put this in context, the UK current account deficit for 2012 was ÂŁ59.8 billion. About one third of this is down to spiralling energy imports. The government surely has a duty to manage this situation.

Globally, high energy prices have been caused by the passing of a peak in cheap conventional oil production in 2005-2008. New energy resources coming on stream such as shale oil and gas are very expensive to develop and produce. They are not cheap. The high cost of recovering the remainder of North Sea oil reserves is amply demonstrated by Figure 4. While energy prices are clearly a burden on society, high price is far better than energy scarcity or no energy at all. The UK government, misguided by over zealous attachment to market dogma and by Green advocacy has neglected the interests of the UK population by allowing, indeed encouraging, the demise of indigenous primary energy production. Whilst some renewable energy most certainly has a place in the energy mix, an energy policy based on the 2008 Climate Change act with a focus on CO2 reduction strategies completely misses the big picture of providing affordable and secure energy for all and protecting the best interests of the UK economy.

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OilVoice Magazine | NOVEMBER 2013

NOC acquisitions lift oil and gas M&A in Q3 2013 to $47.6 billion Written by Eoin Coyne from Evaluate Energy

Upstream mergers and acquisitions bounced back in the third quarter of 2013 driven by new acquisition activity by NOCs. This follows two relatively subdued quarters in the earlier part of the year. The total outlay of $47.6 billion represents an increase of 99% from Q2 2013 and brings the quarterly tally back into line with the average spending per quarter since the start of 2011 of $48 billion.

A logical conclusion from this rise is that confidence is returning to the oil & gas market following a nervous start to the year, which primarily emanated from economic fears across the western economies. Delving deeper into the data, however, reveals that over $27 billion worth of acquisitions during the quarter were made by either National Oil Companies or companies with a significant government ownership. These companies operate largely outside of the free market, especially in regards to raising finance and passing typical investment appraisals and therefore serves as a poor barometer for the general sentiment of the industry. An equally credible conclusion may be be that the fears that hung over the first half of the year are still resident today, especially with the on-going US debt ceiling stand off and the at best tepid recovery of the European economy. As the graph below demonstrates, deal value by public and private companies were actually lower in Q3 2013 than any period in the past 2 years, as was the total number of upstream deals by any type of company.

The top two deals of the quarter by value were conducted by National Oil Companies and were also for the same asset. Initially, in late 2012, ONGC had a $5 billion bid accepted

by ConocoPhillips for an 8.4% stake in the Kashagan field in Kazakhstan.

KazMunayGas then invoked their

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right to pre-empt ONGC’s bid for the same value during Q3 2013 and, finally, the asset landed in Chinese hands when CNPC gave KazMunayGas an instant $400 million profit when they acquired the stake for $5.4 billion. China has in the past been accused of paying over the odds for oil and gas assets but in the Kashagan stake, they will be paying less than $5 per recoverable barrel of oil for an asset that has had many setbacks along its development, but has just entered its first phase of production during the quarter. The deal comes in a long line of assets that India has lost out to China for, the most notable being the sale of PetroKazakhstan, which ONGC believed it had secured during an auction process only to lose out to CNPC at the final hour. There has still yet to be an official company announcement to confirm it, but if recent rumours are true then India will return the favour to a Chinese government controlled company, by scuppering Sinochem’s previously accepted $1.54 billion bid for a 15% stake in block BC-10 offshore Brazil, a block in which ONGC holds a pre-emption right.

Another National Oil Company that invested heavily during the quarter is Rosneft, who made three large acquisitions totalling $6 billion, all of which targeted additions to the company’s already sizeable reserves in Russia. The acquisitions come despite Rosneft now operating with a high debt-to-equity ratio of 70%, caused by the company’s $57 billion acquisition of TNK-BP in 2012 and the resulting $37 billion increase in debt.

For the third quarter in a row, Mozambique’s large gas discoveries of 2011 and 2012 attracted multi-billion dollar interest, this time via ONGC acquiring a 10% interest in Mozambique’s Offshore Area 1 from Anadarko for $2.64 billion. The deal follows on from ONGC’s initial entrance into the asset during Q2 2013 when they acquired a 6% interest from Videocon for $1.5 billion. This deal, along with the Kashagan asset and Apache’s divestment of their Gulf of Mexico Shelf operations for $3.75 billion, contributed to offshore assets dominating in terms of the type of resource acquired during the quarter with $21.5 billion of deals; 47% of the total deal value was made up by offshore asset acquisitions.

After the deals for offshore and conventional onshore assets, deals involving oil and gas shale assets were the next most popular resource type during the quarter with $6.7 billion worth of acquisitions. Carrying on from the trend in recent quarters, the vast majority of the deals were for oil prone plays as opposed to gas; oil deals took up 74% of the number and 85% of the shale deals by value. The Bakken and Eagle ford shale plays dominated the total value with Oasis Petroleum alone spending

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$1.48 billion for 136,000 acres in the Bakken play. There was also one significant shale deal outside of North America with Chevron agreeing a deal to carry YPF for $620 million to drill 100 wells in a shale oil discovery in the Neuquen basin of Argentina, a discovery which was made in 2010 whilst YPF was still under the control of Repsol. Since this time, YPF has been controversially repatriated by the Argentinian government and this deal marks the first collaboration with another oil company since the repatriation.

In Europe, the largest upstream deal in the region since 2011 was agreed when OMV negotiated the acquisition of interests in various producing fields in the North Sea from Statoil ASA. The initial cash consideration will be $2.65 billion which may rise by another $500 million depending on Statoil meeting development targets on 2 fields in which it will retain operatorship in. The interests include 320 million boe of 2P reserves, contains additional upside, are oil prone and at a cost of $8.28 per boe the deal looks advantageous to OMV. Statoil, however, have their eyes on a larger prize as the development of their Johan Sverdrup discovery looms, which could hold 3.3 billion barrels of oil reserves. This deal will free up a reported $7 billion which may prove crucial given the recent trend of mega project delays and cost overruns.

Largest Deals During the Quarter

Acquirer

CNPC

Seller

KazMunayGas

KazMunayGas ConocoPhillips

Riverstone Apache Holdings LLC Corporation

Sinopec

Apache Corporation

Rosneft

ITERA Oil and

Brief Description CNPC acquires an 8.4% interest in the North Caspian Sea Production Sharing Agreement (Kashagan Field) from KazMunayGas KazMunayGas acquires ConocoPhillips’ 8.4% interest in the North Caspian Sea Production Sharing Agreement (Kashagan Field) in Kazakhstan Fieldwood Energy LLC, an affiliate of Riverstone Holdings acquires Gulf of Mexico Shelf operations & properties from Apache Corporation Sinopec International Petroleum Exploration and Production Corporation, a fully-owned subsidiary of Sinopec Group acquires a 33% minority participation in Apache’s Egyptian oil and gas business Rosneft acquires the remaining 49% of

Total Acquisition Cost ($ million) 5,400

5,000

3,750

3,100

2,900

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Gas Company LLC OMV

Statoil ASA

ONGC

Anadarko Petroleum Corporation

ITERA Oil and Gas Company LLC from Itera Holdings Limited OMV acquires producing assets offshore 2,650 Norway and UK from Statoil ASA ONGC Videsh Ltd., a wholly owned subsidiary of ONGC acquires a 10% interest in Mozambique’s Offshore Area 1, 2,640 Rovuma Basin from Anadarko Petroleum Corporation

This report was created using Evaluate Energy’s M&A database which tracks all global E&P, Refining and Oil Servicedeals on a daily basis and provides a comprehensive set of financial and operating deal metrics.

Evaluate Energy provides efficient data solutions for oil and gas company analysis, with historic financial and operating data, and extensive M&A and assets databases to accompany the emerging shale play offering.

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Canadian oil and gas company financings pick up in third quarter Written by Jonathan Moore from Evaluate Energy Canadian oil and gas companies increased funds raised from financing activities for the second quarter in a row this year. However, aggregate funds and the number of deals completed still remains far shy of the levels seen during the previous year, according to the CanOils Financings Database.

A total of C$2.8 billion was raised by Canadian TSX or TSX-V listed exploration and

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production financings from July to October of this year across 55 deals and the average amount raised was C$50.9 million. Comparatively, during the same period in the previous year, C$5.7 billion was raised at an average size of C$80.7 million for 73 issuances, representing a drop of 51%.

Year to date 2013, there have been 173 issuances for a total of C$7.3 billion, down from the same period last year when there were 257 issuances for a total of C$11.4 billion. The decrease in the number of deals and the amounts raised resulted in the average deal size falling 12% to C$42.8 million from C$48.2 million.

Source: CanOils Equity The majority of deals this quarter – 40 out of 55 – were equity financings, and 80% of the C$1.2 billion raised was from brokered deals. However, twice as many nonbrokered deals closed during the quarter, accounting for an average deal size of C$77million per brokered deal and C$9 million per non-brokered deal. C$500 million (or 43%) was raised publicly and C$657 million through private placements.

The largest equity issues this quarter were completed by TORC Oil & Gas Ltd (TOG) in August for combined proceeds of C$412 million in order to fund the acquisition of assets in southeast Saskatchewan for C$510 million. Part of the financing was raised through a bought deal prospectus offering of C$242 million, the remaining C$171 million was a cornerstone investment by the Canada Pension Plan Investment Board.

Surge Energy Inc. (SGY) completed the next largest equity financing of the quarter for combined proceeds of C$247.5 million, of which C$75 million was used to pay down debt, and the remainder used to fund an acquisition in southwest Saskatchewan.

TSX-V companies completed 29 out of the 40 equity financings, but for total proceeds of C$78 million, an average of C$2.7 million per deal. The largest of these

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was completed by Strategic Oil & Gas Ltd. (SOG) that raised C$19 million from a private placement, which was announced in conjunction with a C$29 million prospectus offering that is expected to close in early October.

Debt There were 15 debt issuances in Q3 2013, totalling C$1.6 billion, of which 82% of this was raised by TSX companies. This is 54% lower than the C$3.6 billion of debt issuances in the same quarter last year. The majority of debt issued was for repayment or refinancing of debt, which totalled C$1.1 billion, or 68%.

Cenovus Energy Inc. (CVE) raised the most from debt issuances this quarter, using the US$800 million raised from two unsecured non-convertible note issuances to partially fund the US$800 million notes which are due for redemption in 2014.

Brokered Deals There were 12 brokered equity financing deals in the quarter, one more than in Q3 2012. National Bank Financial Inc. participated in the most deals (10) this quarter, of which it was lead underwriter in one deal.

Macquarie Capital Markets Canada Ltd. underwrote C$137 million of equity in the quarter from 6 deals. They received C$6.7 million in underwriters’ fees and acted as lead underwriter in 3 of these deals.

Use of Funds Proceeds from 18 financings were to be used for an exploration and development work program, however this only accounted for 2% of the financing value raised.

Even though there were only 9 financings carried out to be used for the repayment of debt, this accounted for 46% of total funds raised. A similar pattern was observed in Q2 2012, whereby 37% of funds raised to repay debt, came from only 18% of the deals.

Source: CanOils

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This report was created using CanOils’ financings database which tracks all Canadian TSX and TSX-V listed E&P financingdeals on a daily basis and provides a comprehensive set of deal metrics. CanOils also tracks daily M&A deals, provides 10+ years of historical financial and operating data for TSX and TSX-V listed oil & gas companies as well as guidance, forecasts and an extensive oil sands product.

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A focus on East Africa's junior oil and gas companies Written by Ilda Sejdia from Evaluate Energy The importance of Africa as an emerging new source of oil and gas can hardly be underestimated; the region had a total of 132.4 billion barrels of oil and 513.2 Tcf proved gas reserves in 2012. Historically, oil and gas reserves have been associated with North and West Africa, where countries such as Algeria, Angola, Egypt, Libya and Nigeria accounted for 84% and 91% of Africa’s oil and gas production in 2012, respectively. In recent years, however, the East African region has become hot property for energy investors, following huge gas discoveries in Tanzania and Mozambique and oil discoveries in Uganda and Kenya. With the increase in reserves and frequency of large discoveries, the region has attracted not only majors and national oil companies, but also junior and independent oil and gas players. One success story here is Cove Energy, a small London-listed oil explorer that was part of large gas discoveries made in the Rovuma Area 1 field during 2010-2011 (8.5% stake in the Anadarko led consortium exploring offshore Mozambique and Tanzania). Following the discoveries, Cove Energy was acquired in February 2012 for £1.22bn by Thailand’s PTT Exploration and Production, after a bidding war with Shell.

This acquisition by PTTEP has attracted great interest into other companies of Cove’s size in the region. The Evaluate Energy database provides a detailed insight into how these companies have been performing, and how much they are spending.

The graph below shows the capital expenditure by region for 34 small and mid-cap

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oil and gas companies in Africa over the last 3 years.

Source: Evaluate Energy Capital expenditures by small and mid-cap Oil and Gas companies in Africa totalled US$39,512 billion during 2012; representing an increase of 20% from 2011 when the total reached US$32,897 billion. The East African region remains the region with the most investment taking place, between US$9.4 to US$12.8 billion in 2012, and has experienced rises by 15% and 24% for 2011 and 2012 respectively. Other regions such as North Africa and West Africa have experienced similar increases in 2012, spending having gone up by 23% and 20% respectively. Capital expenditure in Southern Africa by small and mid-cap companies also displays an upward trend, albeit on a smaller scale, mainly attributable to the recent shale developments in the region.

However, on the whole, huge challenges persist in the East Africa region that must be overcome before full development work can go ahead; the building of infrastructure such as pipelines, LNG plants, refineries, and storage tanks, training of a skilled labour force, and setting a functioning regulatory framework (taxation, legislation, and political stability). The region is working towards the elimination of these hurdles; for example, assuming everything goes to plan, we should see the first LNG exports from East Africa in 2018.

Evaluate Energy’s Companies to Watch in East Africa Africa Oil Corp Africa Oil (TSXV:AOI) is a TSXV listed oil and gas company with exploration and development activities in Kenya, Ethiopia, and Puntland (Somalia). During the interim 2013, the company reported a pre-tax loss of US$9.535m, increases in interest income (attributable to a non-brokered private placement in December 2012) and a slight fall by 3.4% of its Enterprise Value. Despite these less than spectacular financial results, there is cause for optimism. The company has a substantial

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OilVoice Magazine | NOVEMBER 2013

acreage position in this high-potential region (80,000 square kilometres covering five key basins) and it has partnered with the very successful Tullow Oil in Kenya and Ethiopia – their joint drilling plan involves 10 exploration wells and 4 test wells. Also, greater potential was recently identified on the company’s Kenyan and Ethiopian and South Lokichar Basin acreage based on significant increases of the contingent and risked prospective resources, estimated by an independent research.

Ophir Energy PLC Ophir Energy (LSE:OPHR) is a FTSE 250 listed exploration company with an extensive portfolio of assets including 20 licences in 10 countries across East and West Africa. Ophir Energy holds the largest net acreage in offshore East Africa and has recently announced the successful completion of the Pweza-3 appraisal well and flow test in Block 4 in partnership with BG Group in Tanzania. Whilst its focus on blocks with slightly smaller prospective resources, delays in drilling programmes and the inability to farm out some of its acreage have raised a few doubts in recent months, the company does seem to have potential. During the first half of 2013, the company reported a pre-tax loss of US$19.374m, a reduction of G&A costs by 28% from the previous year and a fall in the Enterprise Value by 11%.

Wentworth Resources Ltd. Wentworth Resources (AIM:WRL) is an AIM and Oslo listed E&P Company with exploration activities in Uganda (oil), Mozambique and Tanzania (gas). It has a 31% stake in the coastal Mnazi Bay licence and 11.59% stake in Mozambique. The company also reported a pre-tax loss during the first half of 2013, but recorded a decline in G&A costs by 11% and an increase in enterprise value of 21%. The company used to operate in the power sector in Tanzania, but it has sold this business unit and it is solely focused now on its E&P activities. The company is particularly interesting because it is active in Mozambique’s Rovuma basin the same area as Cove Energy. Alongside the investments coming into East Africa via the proposed LNG projects, another important project in the region that will boost Wentworth is the construction of the Dar es Salaam pipeline – being built by PetroChina – that is expected to be completed in early 2015.

Source: Evaluate Energy The Evaluate Energy database provides clients with full historical financial and operating data and news for the 34 small to mid-cap African-focused companies

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OilVoice Magazine | NOVEMBER 2013

used in this report, which included Afren, Beach Energy, Chariot Oil & Gas, Circle Oil and Pancontinental Oil & Gas, amongst others. In total, the database covers over 300 companies worldwide, delivering efficient data solutions for oil and gas company analysis and benchmarking, with 20+ years of financial, operating data and performance ratios, along with global assets, refinery andM&A databases.

View more quality content from Evaluate Energy

Insight: 2014 oil and gas industry planning cycle - Getting it right Written by Peter Parry from Bain & Company

Energy executives will consider macroeconomic issues, industry trends and tactical specifics as they plan their budgets for the coming year. As commercial and national oil and gas companies work through their annual planning cycles for next year, they are assessing the macro business environment and making careful assumptions about the industry and their companies’ positions in it. These insights define the coming year’s performance targets, confirm priorities, and set board and shareholder expectations. Done well, they serve as a robust backdrop for establishing effective plans, budgets and rolling five-year operating plan updates.

This checklist of 10 key issues for the 2014 oil and gas planning and budgeting cycle covers macroeconomic trends, industry themes and specific tactical considerations.

We recommend using this kind of structured framework to challenge thinking and ensure a highly effective planning process, contributing to high-quality, accurate results.

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A. Macroeconomic trends Global macroeconomic risks have shifted as the modest stabilization in the major advanced economies, including the US and Western Europe, has contrasted with deteriorating conditions in the major developing economies. We expect China’s growth to continue to be volatile through this planning horizon, and that will affect many upstream trading partner countries that have relied on China’s dynamism for their own growth. While the effect of a stabilizing West and a more uncertain East may net overall growth, higher volatility and low-cost capital will make conditions ripe for large, short-term swings in the oil industry. These notes of caution are a passing veil of uncertainty, as midterm GDP growth and low-cost capital create a positive future for the oil and gas industry.

1. Low real interest rates. 2014 plans should consider the likelihood of continued low-cost capital, driven by low real interest rates. Oil and gas companies enjoy strong balance sheet positions with gearing below 30%, while low-cost capital creates new investment and expansion opportunities. More ambitious investors and governments may begin to lower their investment hurdle rates, pushing oil companies’ capital spending levels even higher and increasing national oil companies’ (NOCs’) appetites for acquisition. For oil majors with lagging profit-to-equity ratios, a growth push is one route to close the gap between them and other sectors with higher private equity (PE) ratios.

2. The new normal of political risk. The oil industry has long managed shifting political landscapes. However, in 2014 the industry will have to contend with a new administration in Australia; energy reforms in Mexico and India; difficulties in Egypt, Nigeria and Syria; and perhaps strengthening energy alliances among Russia, China, Brazil and the Caspian countries. Tensions in the China Sea may be exacerbated by a resurgent Japan combined with China’s ongoing transitions.

Few companies have structured processes for embedding short-term disruptive political risk into their annual planning processes. Yet this level of sophistication is exactly what oil companies need in an uncertain environment. We are still likely to see some companies disadvantage themselves by planning to increase performance targets and investment hurdle rates in the face of unstable political settings, instead of creating plans that explicitly deal with a range of possible political developments.

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B. Oil and gas industry themes Capabilities, inflation and price volatility were important themes during 2013 and they will continue to be critical in the 2014 planning cycles of oil majors, national oil companies, oil independents and the oilfield services sector. The first two, capabilities and inflation, dragged down results in the first half of 2013, suggesting they were underplayed in last year’s plans. Price volatility, while not dramatic, was cited by many as a surprise in the first- and second-quarter 2013 results.

These themes are joined in 2014 by weaker capital project inventories beyond 2017.

Where will the next generation of step-change growth come from? The outlook is not great, but some companies could differentiate themselves through their nextgeneration growth projects.

3. Capabilities and capacity. Specialist skills are more valued today than at any other time in the past two decades. But too many companies don’t know how many staff they have in key technical disciplines and what they will need over the next five years. Growth leaders are building into their budget processes detailed plans to strengthen their talent pools and improve their capabilities. ExxonMobil, Shell and BP have moved their upstream operating models to technically thematic organizations—a shift from functional organizations. Some US shale gas players, such as Hess and Chesapeake, are moving to focused asset-based models to get a better handle on costs and build specific technical needs. This will allow the development of strong, differentiated core capabilities, a prerequisite for sustainable growth. We expect more companies to follow this trend in 2014.

4. Inflation. Growth areas like Brazil, Australia and the Middle East, as well as unconventional activities in the US are seeing annual energy industry cost inflation rates of 10% to 15% in some equipment and services. Planning budgets often assume that increased spending will generate more activity, but our analysis finds that many companies are spending more on operations without corresponding increases in activity and, more important, production volumes. Quite a few companies have structured productivity and cost improvement programs (Occidental), restructuring plans (Hess) or project cost reviews (Chevron’s review of its huge Gorgon LNG project in Western Australia) under way. Here, too, we anticipate that many more will need to do this in 2014.

5. Oil and gas price volatility. Price uncertainty continues to challenge energy

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companies as they estimate net incomes and affordability of capital project budgets.

Several companies, including ExxonMobil, Shell and ConocoPhillips, referenced this uncertainty in their 2013 second-quarter results. Lower price realization is a challenge when many companies are still running “marker” gas or crude price in their budgeting exercises.

6. Longer-term project pipeline quality. With so many large developments and expansion programs scheduled to complete by 2017, the industry must define the next generation of projects. Gas export terminals in the US, complex East African gas, ultra-deepwater and Arctic drilling, along with a new round of refinery upgrades to meet new fuel specifications—it’s hard to see these all as high-return projects. We expect many companies will return to mature sites and look for the missed oil, tapping improved recovery techniques, including advanced seismic sensing, digital oilfield applications and the next generation of drilling technology advances. The industry could signal a move away from mega-projects to large reactivation and infill programs upstream and selective expansions around advantaged sites in the downstream.

C. Tactical specifics Planning priorities will vary for each company, but most will include exploration, gas, projects and operational performance.

7. Exploration focus. Exploration is difficult at the best of times, as the license round schedule, drilling success rates, and the costs and availability of rigs all introduce uncertainty. For larger players, materiality and maturation speed are constant concerns, which is why we have seen many companies now quoting resource addition annual performance in addition to proven (P1) reserve additions.

To grow 100,000 barrels of oil equivalent (BOE) per day, producers need to consistently find an extra 35 million to 45 million BOE per year. For the supermajors and large NOCs to sustain production, finding 1 billion to 1.5 billion BOE a year is the challenge.

The priority exploration themes for 2014 include: 

Big gas (East Africa, Australia and the eastern Mediterranean);



Re-exploration: Going back to mature provinces with improved seismic-whiledrilling technology and knowledge (Norway, UK and the Gulf of Mexico);

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  

Deepwater oil (Brazil, West Africa and a full restart in the US’s Gulf of Mexico); Onshore oil (East Africa, India, California and Egypt); Unconventional oil and gas (US, Argentina and Australia).

The number of focus areas required by an oil company depends on its size. But with exploration budgets of $500 million per year for the independents and as much as $5 billion per year or more for the supermajors, there seems to be no shortage of investment dollars targeting emerging trends and new opportunities.

8. Gas. Gas was once the stable part of the portfolio, but mid-term planning has taken on a challenging degree of uncertainty. Unconventional gas in the US has caused major swings in market prices and the value of gas assets. Recent examples include the write-downs by companies that had built up big resource positions, such as Anadarko, BHP Billiton, Encana, Noble, Statoil, Shell and Total; cost escalation for mega offshore projects, as experienced by Chevron Australia; and large new discoveries in East Africa, India, Argentina, the eastern Mediterranean and Australia.

Gas remains a very strong part of the mix and will drive a large part of the volume growth for the international oil companies (IOCs) over the next decade. But project delivery is likely to be slow, with commercialization subject to greater gas-to-gas competition. The best projects will still yield solid returns and support growing demand. But it is more important than ever to hold “advantaged” assets to deliver strong results.

9. Major projects start up. Large conventional projects face two main performance challenges in addition to cost: Will they start up on time, and will they perform to expectations? The larger the project, the more susceptible it is to slippage. Once up and running, most see lumpy performance during the first six months rather than a smooth ramp-up, as the facility transfers from project to operations.

Unconventional projects are different,, more like a long-running manufacturing program with a moving work site. For planning effectiveness, the measure is how many wells can we complete and hook up, how quickly and at what unit cost. For the 2014 plan, it will be vital to know if these criteria are escalating, steady or declining.

10. Realistic operational delivery. The operational reliability of the oil and gas industry continues to be a major challenge and a huge opportunity to realize value.

For example, in the North Sea the average oil production asset performs well below its theoretical potential and has a large backlog of maintenance work (see Figures 1 and 2). From a planning perspective, it is critical to have a clear view of historical performance, as well as reasons to expect stronger or weaker future delivery and the extent to which planned programs and interventions will increase operational performance.

Summary: Getting 2014 right We see a greater premium than ever in getting forecasts and guidance right, not only for internal performance management but also for IOCs to meet stock market

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requirements and for NOCs to contribute to national budgets. The lower profit-toequity ratios in oil and gas indicate a performance gap between this sector and other major commercial sectors—which has as much to do with planning as with delivery.

Whenever possible, the approach to planning should focus on the quality of information and sensitivity analysis around what are often P50 numbers—that is, those with at least a 50% confidence level of being commercially recoverable. It is also important to have a realistic view on timing for new projects as well as the upside to be found in mature assets. With a good checklist as a prompt, 2014 planning could be the best yet.

Figure 1.

Figure 2.

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Contact James Blanchard T +44 (0) 20 7280 3200 E BlanchardJ@rpsgroup.com

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The Tuscaloosa Marine Shale: America's next 'hot money' oil play?

Written by Keith Schaefer from Oil & Gas Investments Bulletin You know what makes the Bakken oil play so special? It is oily AND over-pressured.

All that means is that at a certain depth, there is more pressure than normally should be there—because there’s fluid there.

If that fluid is oil—it’s trapped—then it’s bursting to get out. It sure makes for great flow rates to get the Market excited.

And that’s what is making the new Tuscaloosa Marine Shale (TMS) in Louisiana one very intriguing tight oil play in the US. You look around at almost all the other places in the US that produce oil, and they are either oily OR overpressured. Some parts of the Permian have both. But it’s not that usual.

If a tight oil play is surrounded by impermeable rock deep underground, the oil and gas can’t go anywhere—it just sits there under huge and building pressures.

Sometimes the oil and gas can migrate a bit, but still be under huge pressures.

When they first get drilled and fracked, they can produce some BIG flow rates.

The other thing very impressive about the TMS? It covers at least 2.7 million acres just in Louisiana, and stretches into southwest Mississippi.

(And like every other big tight oil play out there, there’s an independent study that says it has billions of barrels of oil. The TMS study says 7 billion barrels, but hey, that was 1997. There’s probably a lot more since then. ;-)) The last, single most impressive thing about the TMS—it’s proven. There are several wells with over 1000 bopd IP rates. Goodrich Petroleum (GDP-NYSE) has already run from $12-$27 on this play. Sanchez has gone from $17-$27 on this play.

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BACKGROUND The TMS is the source rock for the lower Tuscaloosa Sandstone and Austin Chalk formations which have produced oil for decades. Like most horizontal plays, the industry has long known the oil existed in the TMS. The mystery was how to get it out economically.

The TMS exists between the upper and lower units of the Tuscaloosa formation, which has been the source of conventional oil production in the area for decades for the “Tuscaloosa Trend.”

During conventional vertical well development of the “Tuscaloosa Trend,” the TMS was viewed as nothing more than a nuisance zone that slowed drilling on the way to the lower Tuscaloosa.

Occasionally, though, it did show some oil when the drill bit passed through it which put the TMS on the radar of a few geoscientists who were long-term dreamers.

The TMS attracted some more attention in 1997 when Louisiana State University’s Basin Research Institute released a study estimating that 7 billion barrels of oil lay in place awaiting recovery.

BENEFITS AND CHALLENGES OF THE TMS Like the Bakken and Eagle Ford before it, horizontal drilling, multi-stage fracturing and some serious trial and error now appear set to release some of that giant oil prize.

The Cretaceous-age TMS is big. It covers at least 2.7 million acres in Louisiana and crosses into southwestern Mississippi.

And like I said up top, it’s important to note the TMS is not a “combo” play that is a mix of oil and natural gas or condensate production.

This is an oil play—and there aren’t many of them.

Early wells have shown production to be weighted 90% to 95% light oil.

The TMS is being targeted at depths of 11,000 to 13,000 feet, where the rocks have a thickness of 100 to 250 feet.

The play is extremely overpressured (0.70 psi/ft versus a more typical ~0.45 psi/ft), which results in high oil saturations and helps to naturally lift the oil up the wellbore.

The upside is BIG flow rates.

The downside is that it makes wells more expensive.

But I think the TMS play has several advantages that outweigh cost.

One advantage is its location–Louisiana and Mississippi have a large amount of

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infrastructure already in place. The region already has pipelines, refining capabilities and people with experience in the industry. That reduces development costs.

And there is no severance tax on hydrocarbons recovered using horizontal wells in Louisiana or Mississippi for two years or until the producer recovers their costs of the well–that sure helps economics.

A third is how close it is to the St. James terminal located on the Gulf Coast of Louisiana. Oil sold to the St. James terminal has received a premium to WTI which reached $10 to $20 in 2012. That premium has since shrunk, but could return if pipeline and rail infrastructure can’t keep up with the pace of production growth.

And I keep coming back to this–fourth, this is very “oily” production. Wells drilled so far in the TMS are 90% to 95% black sweet oil. And that 5% associated gas has a high BTU content with approximately 80 to 100 barrels of NGLs per million cubic feet produced.

While the TMS has been compared favorably to the Eagle Ford, the play is deeper and therefore has more expensive wells—the Big Negative. The oily part of the Eagle Ford is 5,000 to 10,000 feet deep, and wells cost $7 to $8 million.

Meanwhile, wells targeting the TMS which is at depths of 11,000 to 13,000 feet, costs for single wells are running at $13 million and higher.

That means that for the TMS to match the economics of the Eagle Ford, either well costs have to come down or production has to outperform.

Goodrich Petroleum (GDP) believes that the cost per well could be shaved down from $13 million for a single well to closer to $10 million if a full development drilling program was to be rolled out. A full development plan brings with it economies of scale and improvements in drilling efficiency through experience.

Goodrich’s competitor Halcon Resources also believes that a well cost of $10 million is a reasonable target that could be achieved.

Both Goodrich and Halcon are operators with considerable experience in the Eagle Ford and have a good idea of gains that can be made as drillers become more experienced with a play and more efficient.

Assuming a base case type curve that allows for 600,000 BOE (barrels of oil equivalent) to be recovered (that’a the EUR–the Estimated Ultimate Recovery) and a $10 million well cost, a TMS well has an IRR of 75% (at $100 WTI). At a high casetype curve that predicts 800,000 BOE will be recovered the IRR jumps to 156%.

That’s a little bit bigger than the Bakken.

In its last quarterly conference call Goodrich Petroleum indicated that its recent Crosby well had produced in excess of 100,000 barrels equivalent in 5 months, and that it is still producing approximately 375 BOE per day at the end of 6 months of production.

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According to Goodrich, plotting that 375 BOE per day of production on their 800,000barrel equivalent “high case” type curve at the 6 month point puts them above the curve.

That is encouraging obviously as that well would be considered very economic.

But it is just one well.

Normally that wouldn’t get me too excited.

But there is more than just one well. Several operators have hit strong wells–so the industry has a bit of tweaking to do, but they have already “cracked the nut” on this play; they know how to produce from it.

Goodrich which has a market capitalization of under $900 million just acquired an additional 185,000 acres in the TMS. That is a big commitment for a company of this size. They now have 300,000 net acres.

The other big player in the TMS? Canada’s Encana (ECA-NYSE/TSX)—the 5th largest natural gas producer in the US. The wells they are drilling and operating actually have the best IP rates I see in the TMS. (I own ECA) Sanchez Energy (SN-NYSE) just spent $78 million to get what I calculate from a complicated press release to be 40,000 net acres—or just under $2000 an acre.

Conclusion—deeper wells mean more expensive wells, but that can also mean higher EURs to compensate for that.

And infrastructure is in place and being close to the Gulf Coast Refinery Complex means lower transport costs and for now high pricing.

The Bakken in North Dakota and the Cline Shale in Texas have been the “hot money” oil plays in the US (the Eagle Ford is more gassy), and the TMS could be the 2014 play.

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Geology beats technology: Shell shuts down oil shale pilot project Written by Kurt Cobb from Resource Insights The belief that technology can always overcome natural limits just took a big hit this week when Royal Dutch Shell PLC decided to shut down its pilot oil shale project in western Colorado after 31 years of experimentation. The ostensible reason is that the company has opportunities elsewhere. Shell says it wants to shift resources away from the intransigent rock and move it to profitable opportunities. That sounds logical. But, it might have sounded logical in any of the last 10 years as oil prices rose to historic heights while oil shale projects languished. Even today the average daily price of crude oil hovers near its historic highs set in 2011 and again in 2012.

The prize for anyone who profitably unlocks these deposits is huge, an estimated 800 billion barrels of recoverable resources. So why isn't oil shale yielding to the mighty combination of deep pockets, sophisticated technology and high prices?

A clue comes from one sentence in coverage in The Denver Post: "Full-scale production would probably have required building a dedicated power plant." In simple terms, it takes energy to get energy. Shell's process requires copious amounts of electricity to heat the rock in place through boreholes in order to release the waxy hydrocarbons embedded in it. In this pilot project, the subterranean rock was heated for three years before liquids were captured and brought to the surface for further processing.

(Oil shale is a promotional term. Oil shale is neither shale, nor does it contain oil. It is better characterized as organic marlstone. It contains kerogen, a waxy, long-chain hydrocarbon that must be extensively processed to make it into a synthetic form of crude oil. Oil shale is often confused with oil taken from deep shale formations such as the Bakken in North Dakota, oil properly called "tight oil.")

The ratio of energy outputs to inputs for oil shale is estimated to be about 2 to 1, according to a study by Cleveland Cutler who has long examined energy return on energy invested. Shell claimed a ratio of around 3 to 1 (though that claim no longer appears on the project site). That seems good until you realize that we are currently running the world on crude which has a ratio around 20 to 1.

Furthermore, the need for water to cool power plants associated with oil shale extraction and for processing the extracted liquids is considerable. And, water is

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increasingly difficult to secure in an area that has seen growing demand combined with more than a decade of drought.

Proponents of oil shale claimed in 1981 that it would be economical to process if oil were to reach $38 per barrel and stay there. The threshold price kept escalating along with the price of oil all the way up to $80 in a 2008 study by the U.S. Bureau of Land Management.

And, yet here we are. Brent Crude, the de facto world benchmark, hovers around $108 dollars. The average daily price for the past three years has remained above $100. In the face of these consistent record high prices, Shell is abandoning oil shale development. And, Shell isn't the only one. Another international major, Chevron Corp., pulled out of its project last year.

There are others who soldier on in the oil shale deposits, and they may eventually find ways to produce a synthetic crude from this rock at a profit. But 30 years of failure suggests that such a development remains far off. And, in a world that is trying to wean itself from fossil fuels because of climate change and the risks of depletion, time may run out.

The path of oil shale is reminiscent of atomic fusion research. Twenty-five years ago, fusion was supposed to be just 25 years in the future. Earlier in the same decade, oil shale was touted as the future of oil. Today, fusion remains the energy source of the future (just as oil shale does), and researchers at the world's main fusion research facility, the International Thermonuclear Experimental Reactor (ITER), say that fusion will perhaps be ready for commercial use by mid-century.

To be fair, the challenges for fusion researchers are daunting. For example, they must build and run a device that operates at interior temperatures of 150 million degrees centigrade--which is 10 times hotter than the core of the sun. And, they must do it safely and in a way that produces more energy than the device consumes.

But, because the challenges are so daunting, it may turn out that fusion will always remain the energy of the future. We already know how to fuse two atoms. And, we know how to process oil shale to produce synthetic oil. But, we don't know how to do either of these things at an energy or financial profit sufficient enough to make them practical for widespread deployment. There is a strong possibility that we may not learn how to succeed with either in a time frame that matters to anyone living today.

That means we must get on with other technologies, energy projects and energy policies that have a more realistic possibility of addressing our energy needs and the climate change caused by our current energy regime.

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