Tech Talk - The BP Energy Outlook 2035

BP begins its new forecast for the energy future with the statement:

We project that by 2035 the US will be energy self-sufficient while maintaining its position as the world’s top liquids and natural gas producer.

This illustrates the optimism which BP are projecting in their image of future production. But it carries with it a lot of inherent assumptions, some of which are relatively easy to identify in the summary graphic presentation that accompanied the initial presentation of the new report. Perhaps the most illustrative of their optimism is this plot, which shows the increasingly decoupled changes in energy supply relative to projected increases in GDP.

Figure 1. The reducing dependence on Energy growth as a control on GDP. (All figures are from the new BP Energy Outlook for 2035)

Each year there are significant projections for the future of energy over the next few decades. Recent posts have reviewed this year’s projections from the IEA and ExxonMobil. These projections, were also reviewed last year and those reviews included the previous BP projection although that only projected forward to 2030 – the current review has added five years to this.

The relative contributions of the different fuel sources to the overall mix have not changed appreciably in the past year. Oil is anticipated to continue to shrink in percentage contribution, and coal will also decline in relative contribution after around 2020. Natural gas and renewables are anticipated to make up the supply needed.

Figure 2. Relative contributions of the different fuel sources to overall global energy supply to 2035.

BP have made it a little easier to see how this breaks down by plotting the ten-year increments in fuel contribution as well as the overall totals.

Figure 3. Changes in projected fuel supplies over the period to 2035.

Changing the plot to show the ten-year incremental changes illustrates how coal, now surging as an international fuel source, is anticipated to decline beyond 2020.

Figure 4. Projected ten-year incremental changes in fuel supply through 2035.

Note that in overall total BP is projecting that global consumption will rise by 41% over today’s numbers, most of which increase will come from the rapidly-developing countries of the world.

Figure 5. Regional increments of energy consumption growth over the decades to 2035.

The reliance on the improvements in energy efficiency to stall further growth in energy demand from the OECD countries is evident in this picture.

BP notes that the decade from 2002 to 2012 saw the “largest ever growth in energy consumption in volume terms,” but anticipates that this rate will never be exceeded in the decades to come. And they anticipate that as Chinese growth fades in the decades, so the growth of the Indian and adjacent economies will almost match that of China by the end of the period. As the nations of the world complete their industrialization, so the growth in the demand for fuel will see a greater emphasis on transportation demands.

Interestingly the decline in the demand for coal that BO projects is linked to the completion of industrialization in China, and this assumption is, of course, predicated on oil and natural gas remaining available to meet the demand at a reasonable cost.

Figure 6. Anticipated primary sources for generation of electric power.

The projections for changes in liquid fuel supply are also relatively simply presented. First one can see the projected changes in demand, with the OECD countries declining, as demand increase seems to focus in the Eastern nations.

Figure 7. Anticipated changes in global demand for liquid fuels

It is where this growth in supply is to come from that is of the greatest concern, and BP suggest the following:

Figure 8. The anticipated sources for growth in liquid fuel supply through 2035.

BP note the largest sources of these gains as being:

The largest increments of non-OPEC supply will come from the US (3.6 Mb/d), Canada (3.4 Mb/d), and Brazil (2.4 Mb/d), which offset declines in mature provinces such as the North Sea. OPEC supply growth will come primarily from NGLs (3.1 Mb/d) and crude oil in Iraq (2.6 Mb/d).

One of the more interesting plots in the report shows how, over last year, the changes in US production more than compensated for the declines in production from the MENA countries.

Figure 9. The ability of increased US production to balance declines in production from the nations in turmoil in MENA.

BP anticipates that continued US increases in production will more than balance the anticipated increases in global demand, so that the continued disruptions will not significantly affect global supply even though, as they have historically, they extend for more than ten years. The US gains are anticipated to continue to such an extent that OPEC will be required to rein in their supplies in order to sustain global prices.

Figure 10. Changes in the demand for OPEC oil and the result on their production reserve capacity.

One anticipates, given that KSA has said that they will not increase overall supply much above current levels, that the increases in production that BP anticipate will likely come from Iraq, and Iran if the sanctions are lifted. Given the current situation in those parts the latter seems increasingly more likely than the former. Further BP note that the increasing populations in these countries and their consequent increases in demand for energy is likely to constrain the levels at which these countries can continue to export.

In conclusion, and to justify the heading at the top of this piece, BP anticipate a continued growth in US oil production such that, by 2035 imports are virtually eliminated, being more than offset by the gains in the export of natural gas products. BP anticipates that the latter will increase by 2025 to around 12 bcf/d and continue at about that level.

Figure 11. BP projections for changes in the US oil supply sources for the period to 2035.

Tech Talk - The ExxonMobil 2014 Outlook for Energy

Each year the large oil companies produce their forecasts for future demand and supply of fuel, and these can be compared – both with earlier forecasts and with each other and the forecasts from different agencies. Last week, for example, I looked at the IEA forecast through 2035, while today’s subject is the ExxonMobil (EM) 2014 Outlook for Energy. (See also the 2013 Outlook Review and the 2011 Outlook Review).

In conformity with the IEA review EM consider that the energy growth rate for India will be perhaps one of the more significant metrics of the future. EM note that by 2040 one third of the global population will live in either India or China and between them they amount for half the global increase in energy demand, which is anticipated to be about 35% higher than the 2010 figure. India has already become the third largest energy consumer (after China and the United States).

One of the greatest drivers to energy demand growth comes as the population moves from the farms to the city and, as EM note, China has seen the urban population grow from 25 to 50% of the total in the past 20 years increasing residential power demand 20-fold. But that growth will slow in the future, reaching 75% by 2040. India (and Africa) are however further behind this curve with India being at 30% and Africa at 40%. Thus, as they still have further to move up the ladder, EM anticipate there will be concomitant increases in demand as these changes occur.

Figure 1. Projected growth in energy demand for major groups until 2040. (Illustrations are taken from EM The Outlook for Energy:A View to 2040 except where stated) (The key growth countries are Brazil, Indonesia, Saudi Arabia, Iran, South Africa, Nigeria, Thailand, Egypt Mexico and Turkey).

One of the small niggles with this projection is that it assumes a virtually limitless source of fuel.

Ongoing advances in exploration and production technology continue to expand the size of the world’s recoverable crude and condensate resources. Despite rising liquids production, we estimate that by 2040, about 65 percent of the world’s recoverable crude and condensate resource base will have yet to be produced.

While that projection will be discussed a little further later, it should be noted that in the next decade China’s energy demand will continue to grow at roughly current rates and that they have been quite assiduous in finding new sources to provide that energy. This is already providing some of the backstory to the growing tensions between China and its neighbors in the South and East China seas.

This is noteworthy because, as yet there is not much gap in the world between the quantities of fuels desired, and those available. Yet China is moving aggressively to ensure that it will be able to get what it needs when this changes. Such is not the case either with India, which has often failed in head-to-head bids for energy supplies when going against China, or much of the rest of the world who continue to accept the assurances that EM inter alia are promulgating with reports such as this, that there is a plentiful sufficiency.

Continuing along this unrestricted “ideal world” trail that EM are laying out, they continue to foresee that there will be a substantial improvement in energy efficiency over the next decades, leading to an increased decoupling of the relationship between GDP growth and Energy demand.

Figure 2. Projected growth in GDP and Energy demand through 2040.

Some of this EM project will come from the increased efficiency of automobiles and the greater acceptance of hybrid vehicles, with a penetration of 35% of the market – up from the 1% it held in 2010. While they do not expect that natural gas will have much impact on personal vehicles they do expect some impact with commercial transportation. The changes will lift the light vehicle mileage from the 24 mpg of 2010 to 46 mpg by 2040. (This is 1 mpg lower than their projection for mileage change given last year).

Figure 3. Changes in the composition and size of the global car fleet.

In terms of electricity supply EM foresee a sharply changing picture of the composition of the fuel sources for global supply, with coal barely holding its own throughout the period, and oil declining, while the remaining sources all grow in market size.

Figure 4. Sources of fuel and market size for electric power generation through 2040.

So where will the oil supply come from? Well EM remain confident in the future growth of North American oil.

North American liquids production is expected to rise by more than 40 percent from 2010 to 2040, boosted by gains in oil sands, tight oil and NGLs. With production rising and demand falling, North America is expected to shift from a significant crude oil importer to a fairly balanced position by 2030.

Latin American liquids production will nearly double through 2040 with the development of the Venezuelan oil sands, Brazilian deepwater and biofuels.

The Middle East is expected to have the largest absolute growth in liquids production over the Outlook period — an increase of more than 35 percent. This increase will be due to conventional oil developments in Iraq, as well as growth in NGLs and rising production of tight oil toward the latter half of the Outlook period.

The concern with these projections (which are substantially more optimistic than the IEA forecast, lies in their assumption of unfettered growth. As Ron Patterson just noted the EIA is anticipating that US volumes will peak in 2019, and then decline.

Figure 5. EIA projections for US petroleum production through 2040 (EIA).

Ron, has refined this plot and shows that US production may well peak in either 2015 or 2016, and go into significant decline by 2020. This is quite a contrast to the EM projection.

Figure 6. EM projection for change in liquids production through 2040

EM expect that Deepwater production will increase with major supplies coming from Angola, Nigeria, the Gulf of Mexico and Brazil, with production rising to a peak in around 2040. They expect tight oil supplies, however, to increase by a factor of tenfold from 2010 to 2040. The major new player in that field is anticipated to be Russia whose output is still expected to trail that in North America (which includes Canada and Mexico).

One of the great questions of the next decade relates to the development of the heavy oils of Venezuela and Canada. EM expects that the Canadian production will increase 200% with the rest of the total gain of 300% of the 2010 total presumably coming from Venezuela. However Venezuelan development remains a complex situation.

One of the most promising developments that EM describe is the use of extended reach horizontal wells, that are now allowing sub-sea deposits to be tapped using land-based rigs. At Sakhalin Island, for example, they note that they were able to drill one well in the Chayvo field that extended out 7 miles.

Figure 7. Illustration by EM of their extended reach well capabilities.

The other source that EM cite for increased production comes from OPEC and production gains in the Middle East. Given that Saudi Arabia have stated that 10 mbd is their intended upper limit to production (give or take a little) one presumes that the roughly 9 mbd gain is largely anticipated to come from Iraq. EM don’t actually say, nor did they last year, but it is interesting to end by comparing last year’s projection for future growth with the one shown in Figure 6.

Figure 8. The projected volumes for liquid supply growth as provided by ExxonMobil last year in their 2013 report.

On which cheerful note I wish you all the Compliments of the Season, and hopes that you have a safe and happy break.

Tech Talk - life gets more difficult at Gazprom

There was a time, not that long ago, when if I was short of a topic for a post, I could Google “Gazprom” and there was sure to be a story out there about another expansion, or take over of a national pipeline – or some other sign of the companies growth and power. But in the natural gas industry there has always been a certain volatility. In the United States Chesapeake, the second-largest natural gas producer in the US, is laying off 800 workers as it completes its plans to re-organize by the end of the month. The price for natural gas is around $3.79 per kcf which still falls below the price required to make many wells in tight shale adequately profitable. I have written about gas price problems a number of times in the past, dating back to at least 2009 and though the price is now up over $1 per kcf from those times, as the recent report in the OGJ noted, Chesapeake had, in estimating returns, anticipated it would be up around $7.21.

Gazprom’s problems however relate more than just to the price of natural gas, and the continuing difficulties in defining future price, although those too still exist. In the agreement that the company signed with China last month, for example, although it says:

All the major terms and conditions of future Russian natural gas supplies to the Chinese market via the eastern route were agreed on, namely, the export volume and starting date, the take-or-pay level, the period of supply buildup, the level of guaranteed payments, the gas delivery point on the border as well as other basic conditions of gas offtake. The price conditions will not be linked to the Henry Hub index.

It turns out that the price has yet to be determined. Gazprom is expected to sell its gas into Europe this winter at around $10.62 per kcf, which is down about 7.5% over last year. Nevertheless the Chinese are hoping to pay no more than $7.10 per kcf. And they have more than a little leverage.

Gazprom had been hoping to market the liquefied natural gas (LNG) from the ExxonMobil fields at Sakhalin Island as well as from their own wells, but that discussion has now fallen through so that this becomes a competitive rather than complimentary source of supply. Concurrently China has just confirmed the increase in purchases of natural gas from Turkmenistan.

Not that many years ago all the exported natural gas from Turkmenistan had to run through Gazprom pipes, and thus the company could charge a hefty premium in carrying the gas to Europe and elsewhere. With the opening of pipelines from Turkmenistan to China, that monopoly disappeared, and now the Chinese have agreed to take some 2.3 trillion cubic feet (Tcf) (65 billion cubic meters) of Turkmen natural gas per year, increasing their take by 882 bcf and requiring an additional pipeline to carry this new volume. Given that the country already supplies over half of Chinese natural gas imports, this will continue to squeeze Gazprom’s ability to control prices in Asia.

This new volume will come from a new field in Turkmenistan, the Galkynysh, which is expected to hold a reserve of 900 Tcf. China is investing $8 billion in the development of the field, and the new pipeline to China.

Figure 1. The location of the Galkynysh field within Turkmenistan (Trend)

And Gazprom’s problems don’t end in Asia. Part of the problem that they ran into at Sakhalin Island is that ExxonMobil is working with Rosneft to build an LNG plant through which to market their product by tanker. This circumvents the pipeline monopoly which has allowed Gazprom to dictate terms in the past. The plant is expected to handle 5 million tons of LNG per year, and is anticipated to come on line in 2018. Initial construction contracts have now been signed.

Roseneft, and Novatek have both now been given permission to export LNG, overturning the Gazprom monopoly, and Novatek has the deposits in the Yamal Peninsula that could be more conveniently marketed to Europe, but with LNG tankers that could also reach Asia and beyond. The natural gas will initially come from the South Tambeyskoye field, which has an anticipated reserve of 17 Tcf, with an expected production of around 1 Tcf per year.

Figure 2. Location of the South Tambeyskoye natural gas field, and the planned site of the LNG plant (Novatek )

The plant will operate three trains, each with a capacity of some 5 – 5.5 mmt. It is perhaps no surprise that China is backing the plan with a 20% investment, for which it anticipates being able to purchase at least 3 million tons of LNG pa. An additional 10% of the funding is likely to come from either Japanese or Indian investors. Total of France also has a 20% investment and presumably will gain a proportionate share of the shipments.

As if these challenges to Gazprom’s dominance were not enough trouble, Gazprom is seeking to have two German companies EON SE and BASF SE pony up another billion dollars because Gazprom has been able to increase the reserves at the Yuzhno-Russkoye field in Siberia.

Figure 3. The Yuzhno-Russkoye gas plant in Siberia that feeds into the Nord Stream pipeline (Nord Stream )

Figure 4. Location of the Yuzhno-Russkoye field (Wikipedia)

And just to rub it in, the European Union is planning on hitting the company with anti-trust charges. Given that the company has been able to dominate natural gas sales into Europe though pipelines, and thus has also been able, in the past, to control prices, this new step could prove expensive to the company, just as it faces greater competition in all its export markets. (This does not even consider the potential for LNG competition out of the United States).

The company is getting its supplies from increasingly expensive locations (hence the need for the cash from the German companies) and the income losses that it has seen in the market due to Turkmen competition are already hurting – but it needs more money if it is to be able to keep up its market share.

Before leaving there is an intriguing graph that Ron Patterson has posted at his site.

Figure 5. Process gain in refineries around the world and in the United States (Peak Oil Barrel )

The plot is at the end of a discussion on the difference between counting all the oil produced in a country and the break-down into crude and other sources that add into the total. One part of this is the gain in volume, process gain, that comes when crude is refined. It therefore acts as a marker of the volume of crude that is running through refineries, and as Ron notes, this has now plateaued for the past few years. Interesting!!!

OGPSS - The dangers of complacency

Perceptions based, perhaps on too small a collection of information, can lead into opinions that, on investigation, turn out to be incorrect. Just recently a couple of friends had mentioned that charities that they are associated with were seeing a decline in donations. I built this into a picture of the general public being less able to afford earlier levels of giving, perhaps because of the continued impact of higher costs of fuel. The perception is, however, as a general statement wrong, and (Via the National Park Service from The Giving Institute I learn that:

Americans gave more than $298.42 billion in 2011 to their favorite causes despite the economic conditions. Total giving was up 4 percent from $286.91 in 2010. This slight increase is reflective of recovering economic confidence.

The greatest portion of charitable giving, $217.79 billion, was given by individuals or household donors. Gifts from individuals represented 73 percent of all contributed dollars, similar to figures for 2010.

In the perception that is becoming increasingly prevalent on the future of energy supplies, and particularly crude oil, the current adequacy of supply is projected forward to anticipate no problems with supply in the future. Peak oil is now being suggested to occur, not because the supply is limited, but because, with the increasing use of renewable energy, demand will peak, and then decline. Bloomberg New Energy Finance founder Michael Liebreich is quoted as projecting that the growth in fossil fuel use will almost stop by 2030, while Citi Commodity Researchers are suggesting that the increases in prices will drive increases in efficiency that will bring a peak in oil demand “much sooner than the market expects.”


Figure 1. Projected changes in global oil demand from Citi Commodity Researchers)

This anticipation of future gains in efficiency of use is a common thread to pictures of the future from the three major oil companies that I recently reviewed. All three, ExxonMobil, Shell and BP expect that energy efficiency gains will have a major impact on demand. BP, for example, anticipates that through 2030 energy demand will increase 36%, but that without this improvement in efficiency global energy would have to double by 2030.

One of the problems in assessing the changes in efficiency over time is that, when looking at the past decade, one has to recognize the significant impact of the recession. For example, the Odyssee project looked at energy use in Europe and clearly showed the impact of the recession on demand.


Figure 2. Changes in electricity use in the countries of Europe following the start of the recession. (Odyssee)

What also caught my attention in looking where most of the energy savings were occurring was that it was in countries catching up to Western Europe, rather than in the more established West, and that when the overall savings are totaled these appear to have slowed significantly.


Figure 3. Overall energy savings in the EU relative to a 2000 baseline (Odyssee)

The second problem with the curve that Citi projects lies in the rate at which vehicles are switched from diesel and gasoline to natural gas power. There is currently an economic incentive in parts of the world to make this change, it currently sells at around the equivalent of $2.10/gallon in the USA. Yet it requires both infrastructure and an investment of capital to make the change at any level of significance. Nevertheless it remains a key ingredient of the Pickens Plan that Boone Pickens has been selling around the country for a number of years now.

The fact that Clean Energy Fuels can list all 22 stations that added natural gas pumps along the “Natural Gas Highway” in the November-January period, does not indicate a great rush to build that infrastructure. It is easier to change the local distributor networks, with companies such as Waste Management indicating that they will use CNG in 80% of their new trucks, than it is to see the rapid change of the longer distance haulers, and for passenger vehicles. A recent article in the Washington Post noted that only 20,381 vehicles ran on natural gas of the 14.5 million new cars and trucks sold last year. Further not only does a CNG vehicle cost more to purchase, it also has a lower range, although for some applications that may not be much of a handicap.


Figure 4. Average Annual Vehicle miles travelled by category (Alternate Fuels Data Center )

Yet, at the moment, it is the use of ethanol that is having the most impact on alternate fuel use. Other than that there has been little indication of much change in the market.


Figure 5. Alternate Fuel Vehicles in use from 1995 to 2010. (Alternate Fuels Data Center )

And in this regard Europe has also seen little movement toward the use of natural gas, in contrast with the use of biofuels, and neither has made large gains.


Figure 6. Comparative penetration of liquid fuels market in Europe by biofuels and natural gas (Odyssee)

The problem, of course, is that if these improvements in efficiency and switches to alternate fuels do not occur, then the demand will continue along the Business-As-Usual line, and, as BP forecasts, demand will double by 2030.

The question as to what will be available to meet that enhanced demand remains one of the great imponderables that folk seem, again, unwilling to face. Certainly with a steadily increasing demand, and the constraints on supply that these pages have continued to document over the years, it becomes very difficult to see how price stability can be maintained, where demand exceeds supply at a given price. The problems that this will bring, particularly those nations that now subsidize fuel, a policy that is unlikely to change in Asia, are likely to be major. Yet for countries such as India, which last year has spent the allocated fuel subsidy budget for the year by the end of July the political costs of change remain very high and could well remain in place until the financial burden becomes intolerable. Unfortunately, with the current complacency, at that point it will then be too late to start searching for alternate answers.

OGPSS - The EXXonMobil future - a review

It is the time of year when the major oil companies issue their predictions for the future, and h/t Art Berman, ExxonMobil just released their view of the world, looking forward to 2040. And this is downloadable. If I remember correctly, I first viewed their future projections back in 2011, and with a 2-year step it might be more interesting to see how differences in their world view have evolved in that period.

By 2040 EM anticipates that the global population will be approaching 9 billion, up by around 25% from current numbers. Of that nearly 2 billion additional folk most are expected to be born in the developing countries such as India and in Africa, with the former gaining 300 million and the latter 800 million. Because the majority of the growth occurs in these countries, and the improvement in living standards and working conditions are more energy intensive, (whether air conditioning or iPhones) from a lower base and demand growth is concentrated more in electrical energy demand than that of transportation fuels.

EM continues to believe that, while the economies of the OECD nations will contribute significantly to global growth, with economic output increasing by 80% over the 27-year period, energy demand will remain stable. Growth in demand for power will come from the rest of the world, powering an average 2.8% growth in the global economy over that interval.

Perhaps the greatest change has been in the amount of energy that the company anticipates will not now be needed in that future, as improving energy efficiency cuts back the amount that must be supplied. If we look at the energy projections through 2030 that were made by BP and EM back in 2011, the total growth was expected to continue in an almost linear mode through 2030.



Figure 1. Projections of growth from BP and EM in 2011, looking to 2030.

If one now looks at the shape (the units differ) of the new EM curve there is a dramatic emphasis on a continued improvement in energy efficiency particularly as we get further into the out years. (Note the remaining illustrations all come from the EM document “The Outlook for Energy: A View to 2040”).


Figure 2. Current EM projections for global energy demand in the years to 2040.

The report breaks down the growth in demand into several sectors. And this, at first, is a little irritating. The reason is that, in describing, for example, the growth in residential/commercial energy demand, the track-back on the power sources stops at the point where electric current comes out of the wall. Given that it is the growth in electricity consumption, projected to grow overall by 85%, that is the greatest contributor over the period this is a little disingenuous. Now it is true that there is a whole section devoted to electricity generation, but the lack of the source fuel portrays a little bit of sleight of hand.


Figure 3. Projected residential/commercial energy growth through 2040, by power source.

There is a similar restriction in source categories for the suppliers of industrial power:


Figure 4. Projected residential/commercial energy growth through 2040, by power source.

However, as recognized, the document does have a chapter that deals with the generation of electrical power. EM anticipate that coal will continue to gain market until 2025, but from that point forward, its share will decline as the main competitors, renewables, nuclear and natural gas take an increasing part of the supply.


Figure 5. Change in the source of electrical power and its growth.


Figure 6. The breakdown of electric power fuel sources between OECD and non-OECD countries

One of the reasons for the change, particularly the change to natural gas from coal, comes with the increasing burden of carbon costs, as EM projects.


Figure 7. Anticipated fuel source costs for electricity in 2030.

The low price that is anticipated to continue for natural gas makes it therefore the growth fuel, as figure 5 suggests. When this is combined with the anticipated changes in liquid fuels for transportation, which will see a 40% growth overall, with heavy duty transportation showing the greatest growth, investors in oil and natural gas should be reassured. Cars are expected to achieve an average performance of 47 mpg, which is achieved with the anticipated mix being:


Figure 8. The anticipated growth in automobile performance through the years

Nevertheless the increasing growth of personal transportation in the developing countries is expected to continue to increase demand for oil. With the growth in power generation from natural gas, the two combine to paint a glowing picture of the future of the hydrocarbon industry.

EM project that overall the demand for liquid fuels will rise to 113 million barrels of oil equivalent (mboe) per day by 2040, a 30% growth over 2010 with most of the demand remaining with the transportation needs. The company seems comfortable with industry being able to achieve that level of supply, although the mix will change considerably from that which currently prevails.


Figure 9. Change in the liquid fuel sources that are anticipated over the coming years.

And it is here that I fear that the report becomes overly optimistic. By looking at the relative size of the remaining resource, relative to the production achieved to date, EM foresee no problem in providing the supply targets that are shown in the above figure. EM expect that technical innovation will continue to dramatically improve production from the United States and North America in total. Supply growth is anticipated from tight oil in places such as the Bakken, Deepwater from the Gulf and the tar sands. They project that these will combine to lift North American total liquids production by another 40%. When the production from the offshore Brazilian fields and the heavy oil sands of Venezuela are added, then this reinforces the view that they hold of an achievable target.


Figure 10. Growth in supply of liquid fuels in North America

Yet it is in the Middle East, a region they hardly discuss, that they see the largest growth.


Figure 11. Sources of future growth in liquid fuel supply.

EM don’t actually say where that great growth is likely to come from, but it is very likely heavily weighted towards the most optimistic of estimates for the future production of Iraq, with the ongoing turmoil of the “Arab Spring” being totally discounted.

Well it makes a nice pipe dream, as, I’m afraid, is their anticipation that industry will be able to produce and distribute the target volumes of natural gas that they anticipate will come to save us all from the increasingly higher costs of power. Dare one gently cough and mutter "decline rates"?

If I can put it another way. At the beginning of the report, after projecting a reasonable estimate of global growth over the next 25 years, EM put in a very optimistic level of improvement in energy efficiency in order to significantly lower energy demand. Then, to balance supply to that lower level of demand, they seem to have picked the most optimistic of assumptions about potential growths in that supply. I rather suspect that they are seeing the writing on the wall, but obfuscating it with optimism beyond the bounds of realistic expectation.

OGPSS - An update on Russian plans and the OPEC MOMR

The Arctic is a less forgiving place than many folk care to recognize. Shell have just moved back the date on which they plan to restart drilling in the Chukchi Sea and won’t be going up there this year. At the same time, last August, Gazprom announced that the development of the Shtokman gas field off the Russian coast and also in the Arctic had been put on an indefinite delay. Yet the region still shows considerable promise. ExxonMobil and Rosneft have agreed to exploration in the Chukchi, Laptev and Kara Seas, with the latter considered as possibly having the highest potential.


Figure 1. Location of the Kara and Laptev Seas. (Google Earth)

The blocks that will be explored are South of the island of Novaya Zemlya, in relatively shallow water. They lie north of the Yamal Peninsula, and the Shtokman field is on the other side of the island.


Figure 2. The locations of the East Prinovozemelsky blocks south of the island of Navoaya Zemlya (Rosneft)

Rosneft estimates that the reserves that are recoverable are 6.2 billion tons of oil, and a total of 20.9 billion tons of oil equivalent when the natural gas content is included. The first wildcat well is scheduled to be drilled in 2015.

While Gazprom and Rosneft share access to these offshore resources, Lukoil has found a site at Khatanga Bay in the Laptev Sea where it believes that it can be successful. Despite the difficulties, the need for Russia to sustain production is forcing the companies offshore into more difficult waters, it is where the future production lies, and the Russian economy needs the income.

The February OPEC Monthly Oil Market Report notes that Chinese demand has now topped 10 mbd on a quarterly average, the highest to date and growing at 6%. The greatest increase has been in the use of gasoline. Global demand is anticipated to top 91 mbd by the end of the year. Russia is anticipated to produce some 10.42 mbd on average this year. OPEC has, however, a few caveats:

The Vankor oil field is expected to average 435 tb/d in 2013, a minor increase from the level of 410 tb/d achieved by the end of 2012. Some operators provided that new technologies will be utilized to stop natural decline. On the other hand, the supply forecast remains associated with a high level of risk, due to technical, political, geological and price factors. On a quarterly basis, Russian oil supply is expected to average 10.43 mb/d, 10.42 mb/d, 10.42 mb/d and 10.42 mb/d, respectively. Preliminary figures indicate that Russian oil production stood at 10.46 mb/d in January, steady from the previous month.

As usual it is interesting to compare the OPEC production results for the last few months, based both on the reports obtained from secondary sources, and those numbers that the individual nations provide.


Figure 3. OPEC crude production based on secondary sources (OPEC February MOMR )

It is important to note that Saudi Arabia has dropped its production by around 300 kbd or so for the last couple of months. While I suspect that this to keep markets a little tighter and thus hold prices stable, others might suggest that the may have some slight difficulty sustaining the higher numbers.


Figure 4. OPEC oil production figures as reported by the producing countries. (sources (OPEC February MOMR )

Iran continues to have a disparity of around 1 mbd between the two tables, Iraq still seems to be struggling to get over 3 mbd, and Venezuela has a discrepancy of around 400 kbd. In short, not much new.

Turning back to look for just a moment at Gazprom activities, although they have continued to keep Lukoil out of the Arctic, they have also continued to seek resources abroad. The company has acquired territory in Iraqi Kurdistan and is reported to have an 80% stake in the Halabja project with reserves of around 700 mb. The field lies on the Iranian border in the Kurdish part of the country, and Baghdad objected to the deal going forward. It might, however, help raise Iraqi overall production. Gazprom has two other projects in the region at Garmian and Shakal, and one at Badra which falls under the control of the central government.

And, still in the Middle East, Gazprom is in talks with Israel to buy LNG from the offshore Tamar field and ship it to Asia to serve markets that it cannot easily reach with its pipelines. The intent is to use a floating liquefaction plant that will take gas from both Tamar and Dalit, at the rate of around 3 million tons a year with production starting in 2017.

Gazprom recognizes that, if it is to develop Asian customers it must provide LNG and so it has begun work on an LNG plant in Vladivostock with three trains, each capable of producing 5 million tons of LNG a year, from the Sakhalin, Yakutia and Irkutsk gas fields. With production aimed to begin in 2018, the market will, again, be in the Asia-Pacific region and may be one of the reasons to accelerate production from the Kovyktinskoye field. At the present time Gazprom has brought the Zapolyarnoye up to full production, and they estimate that this will produce 20% of Russian natural gas as the field moves to be the largest producer in the country.

And, while tracking down some of the information for this post, I did find a picture of a polar bear and cub in the region that ExxonMobil is venturing into. It was taken on the island of Novaya Zemlya. Hopefully environmental concerns won't raise the same sort of difficulties in developing these sites that they have in other places further East.


Polar Bear and cub on Novaya Zemlya on the Shores of the Kara Sea (the photo is on Google Earth and was taken at the red arrow in Figure 2 by

Oh, and before I forget the Alaska pipeline continues to run below 600 kbd with an average of 577, 604 bd. for January.

OGPSS - pipelines from the North

Art Berman commented, in regard to my last post on the oil and gas reserves offshore Alaska, that at one time companies looked for an estimated 1 billion barrels in reserves, before they would consider starting down the long road to bringing them to market. With the rising price of oil, that number may have declined a little, but for natural gas a similar need for a long-term assured market is currently potentially raising barriers to progress. As I mentioned in that post, there is a considerable sum involved, not just in acquiring the leases for the sites, but in all the preparatory work needed before the first drill even hits the surface. But even after the wells have come in, the hydrocarbons must still be moved down to the customer, and as the Trans-Alaska Pipeline System (TAPS) showed, it takes time, money and a considerable commitment before that connection can be made.

One of the recent changes that I noted a couple of posts ago, is that more of the reserve in the North Slope is now known to be natural gas, rather than oil. With the current relative natural gas glut in the contiguous United States, that reduces the immediate market, and the potential current price that the gas could bring in. This, in turn, slows lease development. But times change, and with an increase in natural gas demand there will be a growing demand with time. One can also see an increased future need for natural gas in Alberta, where it helps in the production of the heavy oils from the shallow sands around Fort McMurray. And that brings us to the current controversy over the building of another pipeline, this time for natural gas, down from the Arctic.

Possible TransCanada gas pipeline routes from the North Slope, showing connecting pipeline networks, both for it and the MacKenzie River pipeline. (TransCanada)

More particularly I thought I would tie in the problems that the MacKenzie Valley Pipeline has had in Canada, with the debate about the Alaskan pipeline. This is not so much to argue either side, but rather, in showing some of the delays that have arisen, to underscore one of the points that these last few posts have been hopefully suggesting. This is that when somebody says that all we have to do is go out there and drill to solve our energy problems, they really don’t understand the complexities of the real world. The MacKenzie River flows into the Beaufort Sea just to the East of Alaska, in the Canadian Northwest Territories.

Proposed path for the MacKenzie River Pipeline

The recent application for approval of the MacKenzie River pipeline was originally filed in August 2004. But by then the project was already old. Back in 1977 Mr. Justice Berger (a Canadian Judge) who had examined the project over a three-year period, recommended that it be put in abeyance for 10 years, following his Inquiry. A major concern of the time was the expressed opposition of many of the native tribes (First Nations) through whose land the pipeline would run.

Move forward some 34 years, and some of those tribal leaders are now in favor of the project. And while, in that time frame, the Canadian Government had pledged billions to the First Nations of Canada, with recent emphasis being on schools, water and community services, a more likely reason is because of the work of settling land claims, (all the land belongs to the First Nations) and, for example, that the Inuvialuit now own the company that runs the barges up and down the river. At the same time, through the Aboriginal Pipeline Group, the First Nations will now also own a third of the pipeline itself.

At the time that the National Energy Board approved the project it included the development of three natural gas fields (Niglintgak, Taglu and Parsons Lake), about 120 miles of gathering pipelines and an almost 300-mile natural gas liquids pipeline as well as the 743-mile pipeline itself, which will carry 1.2 Bcf/day of gas down to Alberta.

With construction now scheduled to begin in 2014, (and to occur mainly during the winter months) it is expected that the pipeline will be in operation by the end of 2018, at a cost of $16 billion. It will take some $800 million to develop the Niglintgak field with 6 - 12 wells started from 3 pads. It will take some $2.5 billion to develop the Taglu field, with 15 producing wells extended from a single pad, but requiring a compressor and more wells as the field ages. And the cost of the Parsons Lake field is anticipated to be around $2,5 billion with two drilling pads that will hold from three to nineteen wells.

Now move West a tad, and Alaska also has those significant gas resources that I have mentioned in previous posts. They are, however, not quite as far along in the process of getting a pipeline in place to move it to where it becomes a real reserve. I will forego exploring the idea (mentioned in comments on earlier posts) of converting the natural gas to methanol and sending it down TAPS to Valdez, where it would be separated from the oil, and converted into gasoline. (Although, because methanol is corrosive to pipes, the plan is moving toward doing the conversion to gasoline near Deadhorse, and mixing the gasoline with the crude.) The initial target for the project would produce 63 kbd of gasoline, with an original estimate of the cost being around $7.7 billion.

Moving the natural gas itself through a new pipeline, however, requires customers, and while a number of different proposals have been put forward, the lack of such customers at this time recently caused Denali to discontinue their efforts to build a 48-inch diameter pipe that would carry up to 4.5 Bcf/day from the North Slope to Alberta.

Path of the proposed Denali Natural gas line from the North Slope. (Denali )

TransCanada, who remain in the hunt, is also finding it hard to find any firm customers. Given that they estimate that the cost of a similar sized pipeline would run between $20 and $41 billion, depending on whether the line feeds an LNG plant in Valdez, or runs over into Alberta, they are hesitant to move forward, even though they will receive $500 million for planning the project, and getting the regulatory approvals. (The top map shows both alternatives)

The TransCanada/ExxonMobil option to Valdez. (Alaska Pipeline Project)

Nevertheless TransCanada and Exxon, who are now partnering in the Alaska Pipeline Project have held meetings with the project communities likely to be affected by the project, offering refreshments and door prizes for the present and potential feeder lines in the future. Their presentation can be found here, and notes that under the current schedule first gas will flow in 2021.

By that time it is quite likely that there will be more of a demand for natural gas supplies in the anticipated market, but convincing investors and potential customers of that is likely to be an uphill task in the more immediate term, and the project will likely not be able to make headway until those folk show up. And so, while it may not take the almost 40-years of the MacKenzie River pipeline (which isn’t started yet) the current Alaskan effort is likely to take longer than currently hoped.