Tech Talk - Production, Profit and Projection

As we move steadily through the first month of this new year, US production of crude has continued to increase, with the EIA now showing levels of around 8.2 mbd production.

Figure 1. US Domestic Crude production through the end of 2013 (EIA TWIP)

Finished gasoline production has been floating around a level of 9.2 mbd.

Figure 2. U.S. Finished gasoline production at the end of 2013. (EIA TWIP)

At the same time ethanol production continues at around 0.9 mbd.

Figure 3. U.S. Ethanol production at the end of 2013 (EIA TWIP)

US gasoline demand, on the other hand, has fallen below 9 mbd, in the normal seasonal decline during the winter months.

Figure 4. US gasoline demand at the end of 2013. (EIA TWIP)

In the latest Director’s Cut of the news from the North Dakota Department of Mineral Resources the state reports that production averaged 973 kbd in November, up from 945 kbd in October). The rig count is running around 190 rigs (below the all time high of 218 – roughly 18-months ago) and the agency notes that companies are moving toward a higher density for horizontal wells as a means of enhancing oil recovery. They estimate that at the current rig count there will be enough work under this program to sustain the industry for more than 20-years. However production will decline as the richer spots are drained, and in the most favorable scenario production will rise for another 2 to 3 years before stabilizing and then declining. At present the rate of growth in production is in the range of 300 kbd per year.

Figure 5. North Dakota Oil Production – historical and projected (ND Dept of Mineral Resources )

This is roughly similar to the growth in production from the Eagle Ford Shale in Texas over the past year.

Figure 6. Changes in production from the Eagle Ford Shale in Texas (Texas Railroad Commission )

Growth in production from the deep waters of the Gulf are likely to be closer to 50 kbd. Even combined, and recognizing that there may be some additional production from developing shale prospects, it is difficult, as the above three regions hit production peaks in the near future, to anticipate that US production will increase by the 2 mbd that is projected by some forecasts.

Some of this doubt comes from North Dakota agency itself, which has some concerns over the continued ability of the industry to attract drilling capital, as well as the impact of additional regulations. This limit of available funds is something that Gail Tverberg has pointed out in a recent post. Shell is only one of the major companies recognizing that the increasing costs of development in more difficult parts of the world are not being offset by compensating increases in production, price and profit. As operations around the world continue to attest, (offshore Brazil being but one example) just because the money is invested does not mean that production will of a certainty arrive on the original date forecast, nor will it be at the original price estimated. In the case of Brazil, while new fields show the promise for the future with a steady increase in the reserves that the country projects, this has yet to be reflected in increased production.

Figure 7. Growth in projected reserves offshore Brazil over the past 30 years (Offshore )

The problems of development are being blamed on a lack of available drilling rigs as well as budget constraints. This may be a considerably simplified version of the realities which are likely to continue to see delays in production against target figures into the medium term future. This is unfortunate since there remain few places where global production can be expected to increase in the near future.

In the latest Monthly Oil Market Report (MOMR) OPEC notes that non-OPEC supply growth is anticipated to be 1.2 mbd this year, with the bulk of that growth coming from the United States, Canada, Brazil and the two Sudans. Oil production from the Canadian oil sands is anticipated to reach 3 mbd by 2015 on its way to a total production estimate of around 6 mbd by 2035, at an approximate growth rate of 100 kbd per year.

Figure 8. Anticipated growth in Canadian oil production (NEB )

Perhaps more than most the Canadian growth is likely to follow the projected path, although there, as in other parts of the world, the need to ensure future capital for the increasingly expensive operations, and the provision of sufficient infrastructure to handle the increased production are matters that will continue to provide caveats to the overall levels achieved.

And as regards the increase in production from Sudan and South Sudan, certainly the conditions in South Sudan are not encouraging to hopes for increased production at any time in the near future. Fighting in the regional capital of Malakal shows the increasingly tribal nature of the conflict and this may well indicate that fighting will not easily be stopped and order (let alone oil flow) restored. This is of concern to China, which imported some 14 million barrels of oil from the region in 2013 but is now faced with the problems of sustained investment in the face of lost production and facilities after seeing a similar collapse in production from Libya. And while these problems are considered relatively small at the moment, at this time when global production and supply are relatively closely tied, the continuation of problems will mean the China must look elsewhere for that production, with consequent impacts on overall prices.

The problem, as the very short list from OPEC illustrates, is that there are not that many places around the world where increased production is likely and where China can invest to achieve the levels that it anticipates that it will need as demand continues to grow. And as the market becomes more competitive, so prices are unlikely to decline much (apart from regional short term issues such as the recent desire in the US to produce more diesel from refineries). Yet while this will give some reassurance to those seeking to invest capital in the industry it comes at a time where there remain concerns over regulation in some countries, and conflicts in others both of which cause investors to hesitate in their commitment. The problem is that there aren’t that many alternative strategies that hold much hope for working.

Tech Talk - A Dickensian Situation revisited

Back in March 2005 I posted my first offering to the new site that Kyle and I had agreed to call “The Oil Drum.” Now, some eight years later, this will be my final Tech Talk to appear on that site, and it is perhaps appropriate to go back to that first post, and make a couple of comments on how it panned out. It read as follows:

When I was young I was fascinated by a small china statuette that my Grandparents had of Mr Micawber. He is a character, and a sympathetic one, in Charles Dickens's book "David Copperfield", in the course of which he goes into debt, His explanation of his financial condition can be compared to the coming world experience as we now live through Hubbert's Peak. You might, in today's phraseology, call this the Money quote:

'My other piece of advice, Copperfield,' said Mr. Micawber, 'you know. Annual income twenty pounds, annual expenditure nineteen nineteen and six, result happiness. Annual income twenty pounds, annual expenditure twenty pounds ought and six, result misery. The blossom is blighted, the leaf is withered, the god of day goes down upon the dreary scene, and - and in short you are for ever floored. As I am!'.

In this case consider that our expenses, i.e. the world use of oil, went up last year to around 83 million barrels every day (mbd). (A barrel is 42 gallons). Now as long as our supplies (income) can match this outlay then we are in happiness. This was, in relative terms, where we ended last year.

However this year our expenses are going to go up. It is a little difficult to predict exactly how much but current predictions are for this to be around 2 mbd. Let us equate this to the old English sixpence (which was back then worth about a dime. Twenty pounds being worth about $100).

If we follow the Micawber example if our income, world oil supply is equal to or greater than our expenses then we can stay happy. But here is the rub.

When world oil production is just about as high as it can be (non-OPEC countries are now producing just about as fast as they can) and OPEC spare capacity is down to around an additional 1.3 mbd. then our income this year will likely not be much above 85 mbd, if it gets there. (In a later post I will explain why it probably won't).

So we are at the point where within the next few months income and expenditures will be in balance (Micawber's twenty pounds). Except that the industry being a big one there are always things going wrong. In the latter part of last year for example we had:
• the hurricanes in the Gulf that closed down about 0.5 mbd of production for several months,
• oil production in Iraq, which should be around 3 mbd, but because of pipeline bombings etc dropped below 2 mbd,
• there were frequent threatened strikes on the oil platforms in Nigeria,
• and Russian production declined more drastically than had been anticipated.

Some of these are still with us, some have been resolved. And other problems, such as the complete employment of the world tanker fleet, have yet to make an impact. But any one can drop supply.

Yet while our supply (income) is about at a peak (twenty pounds), our expenses (demand) are still going up by this sixpence a year. So that some time this year expenses will have gone from twenty pounds to twenty pounds and sixpence. A number of economists had been predicting that there would be a reduction in the rise in demand to keep us below that figure, but it is already clear that they do not adequately recognize the considerable needs in China and India that drive this increase (and they only have to read the papers to see it).

The big question is when will we reach the point that we cross over the balance point. Right now with the Saudi Arabian government saying that they can increase production by up to 1.5 mbd one might think we could get through to just about the end of this year. Unfortunately some of us are a little cynical about that number, and I'll explain why in another post.

One final gloomy thought - production in other countries (such as the UK) is falling, and the countries that used that supply must find another source. And if we are now at the peak of production, then our income cannot increase above twenty pounds and and may indeed fall back below twenty pounds, while our expenses will continue to increase to twenty pounds and sixpence. It is not the absolute size of the market that will now drive, but the relatively small fluctuations that take us out of balance.

The result is misery, and we are for ever floored.

Looking around it is reasonable to note that we don’t see the level of misery that, from reading that post, one might have expected to happen. We have gone through a major recession, yet demand has, overall, increased and production has risen to meet that demand. Yet looking at how this has been met is instructive.

Figure 1. Changes in liquid supply sources from 2000 to 2040 as anticipated by Exxon Mobil, with lines added to show 2005 and 2013. (The Outlook for Energy: A view to 2040)

I have added lines to show the situation in 2005, when the piece was written, and for this year. It is worth noting that, using the definitions that Exxon Mobil give, conventional crude and condensate production has, indeed, declined since I wrote those words. And if one includes Oil Sand and Deepwater then production has remained fairly stable at the levels back in 2005, and will (according to EM) likely stay so into the projected future.

The three sources that I had underestimated, in terms of production growth were in Biofuels (which is now at around 2 mbd), the growth in Natural Gas Liquids (which for OPEC alone is now projected to reach 6 mbd by next year up from around 3 mbd in 2005, and the growth in tight oil. This latter development, particularly with the use of long horizontal wells that are artificially fractured and injected with a slick-water suspension of a proppant, has been very successful in developing resources which were otherwise at best marginally economic. However the relative contribution that this is expected to make in overall supply is not that great, and I expect that, because of the high decline rates in individual wells, that this will only contribute on the margin of the problem.

When I began writing at The Oil Drum I was concerned that there was a lack of understanding of the impact that reservoir decline rates would have on long-term supply. As larger fields are depleted, so the world turns to smaller fields and these drain more rapidly, so that more and more are needed. (The Red Queen situation that Rune Likvern and others have so aptly described.

Deepwater resources have proven to be more difficult to bring on line than originally estimated and thus, for example, in the case of Brazil OPEC now anticipates that the production from the Lula field (originally Tupi) will only offset declines from wells in the rest of the country, with perhaps only a gain of 10 kbd overall from the addition of the 100 kbd expected from wells now coming on line. And thus, while this is a resource getting more attention (there are expected to be 60 Deepwater rigs in the Gulf of Mexico by 2015) the slow pace of development may not fill the increasing gap left as conventional oil production continues to fall, as Exxon Mobil suggest.

In retrospect, therefore, I was wrong in anticipating a relatively immediate impact from an anticipated imbalance between oil supply and demand. But, within the time frame the price of oil has risen, and the future looks no happier than it did back in 2005. The threats have changed – we seem to be in a quiescent period for major Gulf Hurricanes, for e.g. – but the threat of growing and spreading turmoil in MENA makes it less certain that we can count on much increase in production from Iraq, among others. Russian production rebounded more than I expected, but whether that can be sustained is still in doubt. The hope, at the beginning, was that the threat would spur increased looks into alternate sources of liquid fuel. But while there was a flurry of activity into biofuels (and I myself saw algal work that held a great potential, - though funding has now disappeared for that effort) there is less of a feeling of urgency in the air. Wind and solar sources have reached a point where they are no longer novel, and there is not much else in the near term that holds much potential.

Oil production takes money and resources, but most critically it takes time. Without that investment, particularly in viable alternatives, the oil “income” (supply) will likely soon start to fall short of the oil “expenses” (demand) and as Mr. Micawber so aptly said “we are forever floored.”

When these posts began, technical blogs, such as TOD, posed the potential for mass education in a way that had not been seen before. Readers have been kind in regard to the quality of the posts themselves. But the contributions from those interested, and those in industry who took the time to comment and debate ended up making this much stronger than the initial words in any post. Expertise came in many forms and informed me as well as the rest of the readers in what turned into a wonderful opportunity for many people to understand some of the complexities of supplying the world with hydrocarbon energy. I was thus able to help bring a little understanding of the energy business to vastly more folk than I had in the entirety of my academic career.

I will always be grateful to Kyle for giving me the opportunity to make this contribution, and to his efforts which led to its great success. I can illustrate that with some numbers – as an academic I took persuasion to allow my class size to rise much above 20, and at Bit Tooth Energy I see about 300 readers on a typical good day – Kyle had us above that number in a very few months, and at its peak TOD was handling 200 times that number. The site would not have continued too long as it grew in size without the indefatigable SuperG, who kept the site up under wide ranging pressures, and took care of the technical side of the house. Leanan brought and kept us readers, and provided many of the topics that we needed to create the posts on site, and Gail kept me going with encouragement and support in more difficult times. Nate orchestrated the closing posts and that was not easy.

The folks Kyle brought in to build an international forum were formidable and highly productive, and so to them, and to all of the gentle readership I say again a heartfelt “Thank You!”

(Heading Out – Dave Summers in the mundane world – will continue to write Tech Talks at Bit Tooth Energy, though he writes on a wider range of topics at that site).

The Citicorp Energy Projection - a Gentle Cough

Gasoline prices remain high, and Reuters recently noted that there are enough countries with civil unrest, technical problems and bad weather that there are around a million barrels a day of possible supply that are not getting to the market. . Yet with Saudi Arabia continuing to reassure that it is willing to pump more oil, if needed, there appears to be, superficially, little cause for supply concerns this year. By the same token, in the longer term, concerns over supply also seem to be increasingly discounted. For example Citigroup has just released a new report on Energy 2020:North America as the new Middle East. The report suggests that there is really no concern with future supplies of oil and gas, perhaps most clearly shown with this plot:

The Citigroup view of the coming energy future (Citigroup)

I would argue that the numbers for Saudi Arabia and Russia are difficult to realistically justify. For the Kingdom, which is reported to be producing 9.9 mbd, to increase production by another 2 mbd is optimistic, given the ageing of their primary fields and the decline in remaining volumes that I will discuss in future posts in the current series on that country. The projection of an increase in Russian production is a similar concern. With the decline in production from Western Siberia there is not enough new production coming from Timan-Pechora and Eastern Siberia to sustain existing levels let alone see an increase in production – a point that has been made by Russian officials in the past. However the real concern lies with the relatively unrealistic image that is being projected for US production over the next eight years.

North American shale plays (EIA map, cited by Citigroup)

The image that the above figure projects is that the country is covered in shale, all waiting to provide its wealth to the nation. But that is not the case and shale plays have been a hot topic for a number of years now. And while the map above shows a carpet of shale that has the potential to produce oil and/or natural gas it does not clearly enough distinguish the considerable difference between deposits that are presently economic, and those that are not. (The small number of fields that are labelled as prospective does not speak well for the future).

If one examines the prediction for future production it shows that overall US growth in production of all liquids will rise from some 9 mbd at the end of 2011 to 11.6 mbd in 2015 and then go on to a figure of 15.6 mbd in 2020. (Note that this includes natural gas liquids (NGLs), refining gains and growth in the production of biofuels). The contribution of the various sectors is broken down into:

Projected growth in US production (Citigroup )

In the Deepwater category Citigroup cite existing production from Atlantis, Perdido, Shenzi, Silvertip, Tahiti, and Thunder Horse. Future gains will then come from Big Foot, Gunflint, Hadrian, Jack, Knotty Head, Lucius, Moccasin, St. Malo, Stones, Tubular Bells and Vito. Tiber, Buckskin, Kaskida, Appomattox and Heidelberg. But the report sees gains in the Gulf of Mexico (GOM) total liquids as likely peaking in 2016 at around 2.2 mbd and the gains projected in the above table that might come beyond that as being an “upside potential” based on a change in regulatory factors and the ability of oil companies to bring their reserves on line.

Citigroup projection of future production from Deepwater (Citigroup)

Part of my problem with this approach is that it totally seems to discount the declining production and failure to meet target projections from existing GOM platforms which, among others, has been well documented by Jean Laherrère (here, here and here) and by Darwinian at The Oil Drum (TOD). Looking at the fields that Citigroup have cited it is pertinent to examine first their relative size, as Jean illustrated.

Discoveries in the GOM (Jean Laherrère)

In this context it might be well to remember that as a rule of thumb (from the Russian posts) a 500 mmboe field may produce around 120 kbd. However it should be noted that some of the GOM fields are having problems reaching their target, and that production is falling at a rate of around 20% per year, as Darwinian showed for the cumulative production of Thunder Horse Atlantis and Tahiti, which were projected to produce 550 kbd in total.

History of production from Thunder Horse, Atlantis and Tahiti combined (Darwinian )

With production having already fallen 300 kbd from projections, mainly through lower production from Thunder Horse and Atlantis, it is hard to see how to justify the numbers that Citigroup are using.

The Citigroup projection for Alaska anticipates possible gains from the Shell activities in the Chukchi Sea, although the exploratory wells have yet to be drilled and the geographical challenges to be met in bringing that oil ashore are not yet fully addressed. The Alaskan pipeline is currently flowing at around 609 kbd, which is high enough to prevent wax and ice build up, but with ongoing declines in production and problems arising once the flow falls below 600 kbd how long it can continue to perform satisfactorily is open to question. They cite heavy oil operations at Milne Point which has been declining in production, and West Sac which is a very heavy, cold oil which has raised considerable technical issues in achieving the production of around 15 kbd at present, with existing plans only adding 150 million barrels in total to reserves. The other source that is cited is to produce the light crude from the National Petroleum Reserve in Alaska (NPRA). Given that the bridge from Alpine into the Conoco-Phillips wells in the NPRA has just been approved suggests that an increase in production from the region is still some time away. Put together it suggests that the estimates for a 500 kbd increase in Alaskan production within the next eight years is not a reasonably likely occurrence.

Location of fields and development along the North Slope (Free Republic )

And the third source that Citigroup cite are the oil from shale deposits shown at the top of the post. They see growth of 2.4 mbd in oil production and 1.5 mbd in NGLs from the increase in production from natural gas. The production gains are broken down as follows:

Projected sources of oil from shale plays (Citigroup)

The plot, again, includes a large volume of “upscale potential” which might come from a change in regulations, government and oil company attitudes. I have written about some of the more realistic views of the possible future production of the Bakken and the Niobrara, the Tuscaloosa and the Chatanooga. In this regard it is worth noting that while Citigroup see production from the Bakken rising to around 1 mbd in 2016, and being sustained at that level through 2022, this is not the view of the folk in North Dakota who are monitoring well production and permits.

Anticipated production from the Bakken and Three Forks in North Dakota (DMR March 2012 )

It is instructive to this argument to note that Fidelity E&P has just celebrated reaching a production record of 3,500 bd in the Bakken which it derives from 58 wells. As they continue to run 5 rigs, and have been able to drill a long lateral horizontal well in 28 days they should be able to increase production this year, but they are fighting the rapid decline in existing wells, which requires that more wells be drilled every year, and that (as the better spots become drained) so the drilling activity must accelerate to sustain existing production.

Typical Bakken well production (ND DMR )

Production from the Bakken in North Dakota reached 546 kbd in January, and this production came from 6,617 wells which gives an average of 82.5 bd production from each well. Activity is such that some 250 wells are waiting on fracture services and rigs capable of drilling 20,000+ ft are at 95% utilization in the area. And prices of natural gas are down to $1.89/kcf. Bear in mind that, after a while, it becomes harder to find a spot where no-one has already been.

Map of wells planned and drilled in a section of the Bakken (DMR Presentation to Farm Bureau )

On the ground it looks more like this:


Well sites in the Bakken (Vern Whitten for DMR – Farm Presentation)

The North Dakota Department of Mineral Resources has a series of very informative presentations on the Bakken, including hydraulic fracturing, and the above were taken from the Presentation to the Piece Country Farm Bureau on March 15th.

Current plans anticipate that the Niobrara may reach 250 kbd of production by 2020. The problem, however, as Art Berman has skillfully pointed out is that, as the ND plot above shows, the current wells have a high decline rate, and production levels drop dramatically once the wells are brought on line. Art has explained the background to this for gas wells drilled into shale but the impact for oil wells, where the oil has a higher viscocity than the natural gas, can be significantly greater. Given that well costs are in the order of $10 million per well (depending on location DMR gives the ND price at around $8.5 million, and numbers for the Eagle Ford have been quoted at $8 million) the amount of oil that must be produced over the first few years to justify investment is significant. There are, for example, some 1,400 wells producing in the Eagle Ford play. The play produced 30.4 million barrels of oil in 2011, and is anticipated to add 200 kbd of production this year with the potential to reach 1.2 mbd by 2015. But the high decline rates mean that wells must be replaced rapidly to sustain those levels of production.

It is this disregard for the declining production from existing and future wells that appears to be neglected in the Citigroup study. Those plays which will yield rapidly in generating high initial well production will, in turn, be the first that decline significantly and need replacement. Yet replacement will, over time, have to be in poorer parts of the formation, requiring that multiple wells replace the initial producer, and so bounds on production will be reached, likely before the end of the decade. Citigroup anticipate that the risks in development of the shale plays, whether in Texas or California, come as much from an inability to transport the oil generated and from environmental policy, they see few geological risks – which is a pity, since it is the geology that will control production and its decline, and the ultimate profitability of these ventures.

And finally Citigroup see that cellulosic ethanol will come into its own this decade, and that it will provide half the 2 mbd of biofuels produced in 2020. Unfortunately the economics of large scale production that have led to failures of ventures to date have over-ridden the mandated production levels that the group cite as their foundation, and there is no indication that this will change in the next eight years.

In short, though this is an interesting exercise it is too full of “could” and thus will not make much of a useful contribution to meaningful discussion of future production.

The 2012 Exxon Mobil view of the future

Each year the major oil companies publish their projections on fossil fuel supplies as they foresee them developing over future decades. Last year I reviewed those for BP; Exxon Mobil; and the projections from Shell. Exxon Mobil (EM) has just released their new set of projections. With this publication they have also stepped a little further into the future, looking to an end point in 2040, rather than the shorter 2030 time frame of last year’s report.

One of the immediately striking effects of the change in end date is the highlight on the growth of the global population. In last year’s document the global population was expected to reach 7.9 billion by 2030, now the projection is for the population to increase to nearly nine billion by 2040. We are at roughly 7 billion today, and the acceleration in the future growth rate of the population will make it more difficult to improve the average global lifestyle. This is particularly true when the locus of that growth is defined as coming largely from India and Africa.

Anticipated growth in population in various parts of the world (EM Outlook for Energy 2012)

More tellingly EM anticipates that the number of households will increase by 50% over the next 30 years, and with that growth comes the demand for electrical power. EM looks at both industrial and domestic energy demand growth, tying it in with this population growth, and expects that, while OECD GDP will more than double, it will do so with only a small amount of growth in energy demand, with the somewhat smaller growth in GDP in the rest of the world using a considerable amount more of the growth in energy demand that EM foresees. In countries such as China the increased demand for space and energy come as, with greater affluence, families will no longer remain crowded into multi-generational dwellings but will move more to single family occupancy.
(As an update and an illustration how two different folk can view the same document, you might find Gregor's post on the same topic of some interest).

Where the growth in demand will come from (EM Outlook for Energy 2012)

With the rising affluence of the developing countries, EM still continues to see continued improvements in energy efficiency lowering the overall average household demand for energy through the next three decades. It is an argument that I believe requires more justification than they provide. It is interesting, apropos my recent interest in Azerbaijan and Turkmenistan, that EM do not see much change in the fortunes of those who like around the Caspian Sea. It is perhaps a cynical, but realistic view of where that energy wealth will end up.

Change in domicile, and the energy demand for the average home (EM Outlook for Energy 2012)

The most important part of the Review however, since it deals with energy, is how EM decides where this future energy will come from. They see a large movement towards diesel in the transportation industry as hybrids and electric vehicles reduce gasoline demand, and increased fuel efficiency with lighter vehicles combine to stabilize the overall levels of gasoline required.

Change in the fuel mix needed for transportation.

Overall the amount of oil needed for transportation will continue to increase, overall by about 80%, and when this is combined with other needs, EM sees that global demand for oil will increase, by 2040 to around 110 mbd at a steady rate of increase overall from today, although the way in which the mix is put together is anticipated to change considerably. (And as an aside this projects less than a 1 mbd per year increase in demand, which falls below the levels which others, such as OPEC, foresee. OPEC anticipate a growth in demand of 1.1 mbd in 2012, according to the December MOMR).

Anticipated sources for oil through 2040 (EM Outlook for Energy 2012)

There are many features of interest in this summary chart. Given the decline rates that are now evident in conventional wells around the world, I do not see the discoveries being made that will justify the production levels that EM are predicting. The plot which is included, showing the production history from discoveries of different ages, is telling in this regard.

Production for well discoveries of a certain time (EM Outlook for Energy 2012)

EM notes that modern wells are more likely to be drilled with long laterals, rather than the simple vertical or slightly deviated wells of little more than a decade ago. But these new wells carry with them a much higher decline rate at the end of their lives than do the conventional wells (often more than double). Thus, as production declines from the older wells, so reliance must pass to new-found deposits, and that particular reserve is, as the above graph shows, somewhat thinner than volumes from the past, which are now starting to decline.

The savior of the next decades is foreseen to be the offshore Deepwater deposits, and certainly as one looks along the shores of Africa, South America and the Gulf of Mexico, to name but three, there is a considerable potential for some gain. Whether it will provide the sustained volumes needed to balance other declines and also produce enough to match increased demand is going to be a continuing question. With that in mind it is worth revisiting last year’s review to see where EM expect this Deepwater oil to come from.

Deepwater oil production (EM Outlook for Energy 2011)

As befitting an oil and gas company, perhaps, EM expects that oil production will remain a major part of the energy mix through 2040, with natural gas rising to carry an increasing burden of the overall picture at the expense of coal, and biomass whose shares of the global market are expected to decline starting somewhere about now.

Change in natural gas demand over the next 30 years. (EM Outlook for Energy 2012)

Composition of the fuel mix according to EM over the decades

Even though they project that coal will still be the cheapest fuel to buy and while solar will remain a luxury item, nevertheless EM anticipate that coal’s share of the electricity generating market will fall to less than 30% by 2040, and to less than 20% of the overall energy supply. This remains consistent with their opinions from last year. However they are now projecting a larger role for oil than they expected last year (when it was around 26% of total supply by 2030 and falling).