While President Obama has been keen to stress the “British” in British Petroleum, there are some facts that might make uncomfortable reading for those in the US who support the harshest possible penalties for the unfolding disaster. Of BP’s total workforce of 80,300 employees, 22,800 are based in the US, while 37 per cent of all those employed by BP in the E&P sector also call it their home. Around 40 per cent of all of the company’s fixed assets are located in the US, compared to just 20 per cent in Europe. BP also produces nearly 4mbpd of hydrocarbons and is looking to bring on 42 projects over the next five years, with a total production of around 1mbpd. Total crude production in the US from major fields is around 665,000bpd. In addition, BP is at the forefront of the development of shale gas in the US, being active in the Woodford, Fayetteville, Haynes and Eagle Ford shales, holding total resources of around 42tnft³ in the lower 48 states and Canada. Its in-house expertise has repeatedly led to greater production from shale gas wells after their acquisition. With this in mind, it is clear that the economic fallout from bankrupting BP would reverberate throughout the US economy at a time when it is still trying to shake off the aftermath of the financial crisis of late-2008. There is also the fact that BP hasn’t stood for British Petroleum since 1998, when it merged with Amoco (American Oil Company).

The logical thing to ask then, is how much could be redirected from BP’s coffers to pay for the resulting environmental damage, without killing the goose that lays the golden eggs. The obvious answer is the amount made available to shareholders. Back in 2009, BP’s profit after tax stood at around US$16.759bn, slightly more than the US$16bn some analysts argue the company could be made liable for as a result of the disaster and a similar figure could well be expected for this year. Expectations that BP’s total liability could reach this level have received a boost from the recent news that BP’s chairman, Carl-Henric Svanberg, has announced that the company will defer a decision on its next dividend payment until late-July. While a fine of this proportion would do little to impact BP’s long-term profitability, the loss of dividends for a whole year, could create some painful balance sheet issues for the company, as well as driving its share price and market valuation down to the point where it could make a tempting takeover target.This process is already under way. As of writing, the company’s share price has fallen by around 40 per cent over the course of the crisis, with its total value dropping from US$122bn to US$73bn partly due to the news that the Justice Department is looking to find ways of preventing BP from issuing dividend payments until the full value of its liability is made know.

Ironically, the open-ended and yet to-be-decided scale of its liability for the oil spill will serve as a strong deterrent to any sharks scenting blood in the water. The social ramifications of an non-payment of dividends would also be significant, given that BP is responsible for an alarming one-sixth of dividend payments to British pension funds. However, this is hardly a concern to those on the US east coast who have seen their livelihoods ruined by the advancing oil slicks or the Obama administration. Diplomatically, it could therefore result in the first true test of the “special relationship” between the USA and the UK for both President Obama and the British Prime Minister, David Cameron. Mr Cameron so far has opted for a conciliatory pose, saying that he “completely understands” President Obama’s frustration with BP.

As of the time of writing, BP has indicated that has so far spent US$1.43bn in its efforts to stem the flow of crude oil and clean up the resulting spills, not including US$360m for the construction of barrier islands designed to limit the impact of the spill on Louisiana’s coastline. A real issue for the company is the latest threat from President Obama to charge it for all the wages of those oil workers who will be twiddling their thumbs as a result of the moratorium on offshore drilling in the gulf. In addition, the latest estimates from a US government panel suggest that the actual amount of crude leaking from the riser could be between 25,000-30,000bpd, roughly double the 12,000-19,000bpd previously indicated. This doesn’t bode well for BP’s total liability, given that this will be calculated on the total size of the oil spill, and the US Clean Water Act stipulates that oil companies can be fined up to US$4300 per barrel of crude leaked into the environment, suggesting that BP could be fined as much as US$47bn. The new estimate is based on data from before the riser was cut, a move that could have increased the flow of oil still further. BP’s capacity to siphon off oil from the broken well is expected to reach 25,000bpd by the week beginning June 14, which given the new estimates, might not be enough to prevent crude from further leaking in the ocean.

In terms of the leakage of oil from the broken riser, it feels as though the end could be in sight, given that a cap has been successfully put in place and the bulk of the oil flow is now being siphoned off into a floating tanker. Unfortunately, the imminent hurricane season has the potential to undo all of BP’s work to date, but given the industry has weathered many such seasons, since the start of operations in the Gulf of Mexico, it is possible that it may just prevent further work on the riser during the most severe weather conditions. A more permanent containment cap is expected to be fitted by the end of July and two relief wells are being drilled, which might offer the best solution to the problem, but they are not expected to be complete until August.

The blame game

From a corporate standpoint, it is easy to imagine BP’s lawyers sharpening their knives in preparation for the successful blocking of the oil flow and the completion of clean-up operations. While BP is responsible for the incident under American law, it is only a matter of time before legal recriminations begin between BP, rig-owner Transocean and Halliburton, which was in charge of cementing the well. In addition, Transocean’s involvement will be investigated by the Department of Justice as part of its criminal investigation into the incident. It is certainly going to be a headache for would-be prosecutors, thanks to a muddled chain of command. According to Transocean’s emergency response manual, the company’s offshore installation manager is “fully responsible” for activities on board the rig and that BP’s representative is there to assist, but its well control section also states that managers from both companies have to come to a joint decision in the event of an emergency. Also BP’s senior representative is required to consult with shore-based managers in Houston to “decide appropriate well control measures” in the event of a serious problem.

What doesn’t look good for BP is the narrative that was unfolding prior to the disaster. The project was well behind schedule, costing the company US$500,000 a day. In addition, it appears that it overrode some of its own regulations to go ahead with operations, such as the use of a lower performing well casing, despite several problems, such as leaking seals in the riser, which fatally failed to function, when drilling hit a gas pocket. There is also the fact that all of the valves in the blow-out preventer failed at once and the questionable decision to replace the drilling mud with seawater, despite the fact that fluid was being forced up the drill pipe in the absence of drilling, a clear danger sign. Prior to the accident, the Deepwater Horizon rig was in the process of capping the well, so that it could move away and allow a ship to begin the process of harvesting the oil. It is worth noting that BP’s E&P operations have been under intense pressure to cut costs, due to the company’s relatively poor performance in this area compared to their competition. Before the spill, these measures had some success as BP reported a 12 per cent reduction in upstream unit costs in 2009, but it is unclear as to what compromises may have been made to achieve these savings.

Meanwhile, Transocean’s attempts to limit its liability to US$26.7bn by citing a 1891 law have attracted condemnation from some quarters, particularly given BP’s decision to not seek the US$75m cap of damages created by the 1990 Oil Pollution Act. This action is being opposed by the Justice Department, which in a letter dated May 24, said: “”It is simply unconscionable, in the circumstances of this case, that Transocean is attempting to use this same shield of liability potentially leaving thousands of people who have been damaged by your clients’ actions with no remedy.”

Halliburton is also on the firing line, given that some experts have indicated that flaws in the cementing process for the Deepwater Horizon well, which it performed for BP could have been the cause of the disaster. Last year, it was implicated in a similar industrial accident off the coast of Australia, where a blow-out resulted in a fire on an oil rig and the release of hundreds of thousands of gallons of oil into the sea over a 10-week period.

The long-term impact for BP is uncertain. While as previously discussed, the initial financial impact is unlikely to prove a death-blow, the damage done to its reputation is likely to be far more pervasive and lingering, particularly as it follows on from the 2005 oil refinery explosion at Texas City, which resulted in the deaths of 15 workers and injured 170 others. Given that the company was already underperforming compared to its peers and will face harsher borrowing conditions until the extent of its liability for the Deepwater Horizon incident is fully known, it is hard to see how it remain an independent operation going forward. On the other hand, the sheer size of its assets and the potential competition issues, would make it a difficult target for a conventional takeover, suggesting that a friendly merger would be a more likely possibility. It would be an extremely ironic twist of fate if harsh sanctions by the US government were to ultimately result in the purchase of BP by PetroChina particularly if it meant US oil being earmarked for the Chinese mainland. A far more likely candidate, given the ferverent political opposition to such a move, would be ExxonMobil, the world’s largest independent oil company.

Whose head will roll?

In the wider public relations war, while Tony Hayward has come under fire in the US for his handling of the accident, in particular for a misjudged and off-the-cuff comment that he wanted his life back, it could well be that he will retain his position. Current buzz has it that several BP directors are far more angry with the company’s chairman, Carl-Henri Svanberg, who has been conspicuous only by his absence during the course of the disaster, despite the duty of a chairman to provide support to his chief executive officer in such a time of crisis.

President Obama also appears to have suffered some fall-out from the incident and perhaps unfairly so, given that all of the expertise rested in BP’s hands and there is little the US military could have done to improve the situation. Ironically, given his proficiency at communication, the main accusation has been that he has done little to show real emotion over the unfolding disaster, highlighting the careful tight-rope any president must walk between the dignity of the office and the emotional needs of the American people. Unfortunately for the President, the situation is being crafted into a narrative that could see him labeled as a “wimp”, in the same way that Jimmy Carter was back in 1973. There are several parallels between the two presidents and it is ironic to note that if President Carter’s call to reduce US dependency on oil had been properly heeded back then, then the chances of the Deepwater disaster occurring would have been much less.

The expertise and underwater experience from the handling of the Deepwater Horizon disaster will be vital, given the shift towards ultra-deep water exploration and production.

Wider implications

The wider implications of the disaster are substantial. As Tony Hayward pointed out at the launch of BP’s annual statistical review, “The world’s largest increase in oil production by far came from the US, mainly from the Gulf of Mexico.” In addition, experts believe a permanent ban on drilling in the Gulf of Mexico, would decrease US oil output by 300,000bpd over the next five years. This highlights the risk to the US economy posed by the offshore drilling moratorium, particularly in light of the IEA’s prediction that the world will need to bring the equivalent of six Saudi Arabias worth of new capacity by 2030. It is also clear that the regulations surrounding the offshore industry will be tightened. Their lax state is likely to have played a major role in the disaster and considerable action will be needed to prevent a recurrence of this tragedy. The scale of the potential changes can be seen from the British response to the 1988 Piper Alpha disaster in the North Sea. This result in over 100 new maintenance and safety regulations and the separation between the regulatory functions of field licensing and offshore safety. It is clear that operating costs will rise, but given the current climate, it is unlikely that oil companies will protest loudly, as they only have to look to BP’s clean up costs to realise that the previous system may well have been a false economy. Given the pace of deepwater E&P elsewhere in the world, it could well be that it may ultimately have a silver lining in that it has made it clear to oil companies that they need to develop the underwater expertise capable of resolving such problems quickly. In this context, it is interesting to note that Petrobras, the Brazilian state oil company, has been keen to learn from BP’s experiences. There is also the nightmarish scenario in which the industry could have had to cope with a similar disaster at deeper depths or in a more fragile environment such as Alaska.

Perhaps the most startling of these is the news, reported by The Oil Drum, is that the current CEO of Petrobras, José Sergio Gabrielli de Azevedo, has warned that the world will need to bring online the equivalent of one Saudi Arabia every two years to offset future oil decline rates, although he later reduced this to once every three years in a more recent interview with Business Week in January 2010. This is a fundamentally more pessimistic outlook than that of the International Energy Agency that believes that the equivalent of four Saudi Arabias will be needed to be brought online to keep oil production at today’s levels between now and 2030.

Figure 1: World oil capacity and demand to 2030. Source: Petrobras, translation by Luis de Sousa of The Oil Drum.

However, Mr Gabrielli’s comments are in accord with a rising number of similar statements from major oil CEOs, such as Total’s Christophe de Margerie, who has gone record as saying that global oil production won’t ever exceed 89mbpd. Thierry Desmarest, Total’s chairman, said that world oil production could peak in about 10 years, in an interview with the AFP News Agency on the outskirts of the Davos World Economic Forum.

Meanwhile, although BP and Shell have not come out in favour of the peak oil camp, they are still suggesting that a rough time lies ahead in terms of the oil demand/supply balance. Shell’s Peter Voser told his audience at Davos that the oil industry will need to invest a staggering US$27trn over the next 20 years to satisfy demand, while BP’s Tony Hayward believes that output will have to be increased to 100mbpd due to increasing demand from emerging economies.

A sticking point for peak oil’s proponents is the fact that the official stance of Saudi Aramco, Saudi Arabia’s national oil company, is dismissive regarding peak oil supply, choosing instead to worry about oil demand in OECD countries peaking as a result of a shift towards greater use of renewables and the electric car. At the Davos summit, Saudi Aramco’s CEO Khalid al-Falih said that: “The concern about peak oil is behind us,” and that “of the 4trn [barrels] of oil the planet is endowed with, only 1 has been produced. Granted most of what remains is more difficult and complex [to exploit] … there’s no doubt we can do a lot more than the 95, 100[mbpd] that are projected in the next few decades.”

However, while Mr al-Falih’s comments regarding the size of the oil’s remaining oil reserves on paper are correct, they are also misleading when one considers the point from the perspective of oil as an energy source. It is human nature to use the largest and easiest to exploit resources first and therefore, when oil first started being pumped to the surface on a large scale, roughly for one barrel of oil’s worth of effort, 100 hundred more barrels of oil could be produced. This ratio has fallen steeply over the last decades and will fall further as we look to ultra-deep fields and Canada’s oilsands to compensate for the decline in the availability of shallow reservoirs of sweet light crude. This is a major issue for civilisation as a whole, as below a certain level of net energy produced, many activities start to become effectively uneconomical. There is also a real issue that the infrastructure we are dependent on, particularly in the oil and gas sector itself,was built back when the situation was much more favourable, making the issue of the energy needed to maintain the current system, a very pressing one. The situation is somewhat akin to the number of companies that are struggling to cover their pension obligations, which have accumulated as a result of the increase in the average age people reach past retirement. There is also the point that Sadad al-Husseini, the recently retired head of exploration and production for Saudi Aramco, said in an interview back in October 2007, that global oil production has already reached its maximum sustainable plateau and will start to fall within 15 years.

There is also the issue that the size of official oil reserves does not hold up to scrutiny. Back in 1985, Kuwait massively increased the size of its oil reserves on paper, which was thought to be prompted by the decision by OPEC to assign production quotas according to the size of each member country’s reserves. Many other OPEC members followed, including Iran, suggesting that the size of the oil reserve base is substantially inflated. In fact, according to Dr Mamdoubh G Salameh, consultant for the World Bank, back in 2004, a reasonable estimate of OPEC oil reserves would be 516bnbbl, 300bnbbl less than the official figure, based on an average global recovery rate of 29 per cent. This matters, given that Saudi Arabia and Iraq alone are sitting on around half of the world’s untapped reserves.

The UK Industry Taskforce on Peak Oil, lead by Sir Richard Branson, has warned the government that peak oil will mean a crunch that could potentially dwarf the scale of the financial crisis seen in late 2008.

“The next five years will see us face another crunch – the oil crunch. This time, we do have the chance to prepare. The challenge is to use that time well,” Branson will say.

“Our message to government and businesses is clear: act,” he says in a foreword to a new report on the crisis. “Don’t let the oil crunch catch us out in the way that the credit crunch did.”

The Taskforce includes Ian Marchant, CEO of Scottish and Southern Energy group, and Brian Souter, the CEO of transport operator Stagecoach. Chris Skrebowski, the independent oil consultant who prepared a peak oil report for Branson and his colleagues, has indicated that the main factor that has prevented a full-blown energy crisis from occurring already has been the global recession.

“The next major supply constraint, along with spiking oil prices, will not occur until recession-hit demand grows to the point that it removes the current excess oil stocks and the large spare capacity held by Opec. However, once these are removed, possibly as early as 2012-13 and no later than 2014-15, oil prices are likely to spike, imperiling economic growth and causing economic dislocation.” (The Guardian)

Peak oil in practice for the power sector

So what does this all mean for power utilities? To a certain extent, the industry has already learnt its lesson from the 1973 oil crisis. In the aftermath, there was a concerted move away from the use of fuel oil in power generation. Speeding up the ongoing shift towards renewables would be extremely advisable, given that a post-peak situation would drive prices of all fossil fuels up sharply, although the rise of shale gas may help to cushion the blow initially. Perhaps the most dramatic issues for power companies will be the impact on demand. It is logical to assume that the resulting economic downturn will be most severe in those countries that are the largest net importers of energy. This includes the US, Japan and South Korea, as well as many European countries. Concentrating future investment in those countries with as yet untapped oil resources such as Brazil and Iraq could therefore be a shrewd move. China is an interesting case, given its efforts to lock up oil resources in Africa and Latin America. However, it is unlikely that the US would be willing to take this lying down, once the situation becomes apparent. In such a scenario, relations between the two countries will continue to degenerate, making it harder for US companies to gain access to Chinese markets and vice versa.

In general, a peak-aware outlook would also try to maximise the resilience of operations over short-term profitability. Given that high energy prices would lead to a shift away from globalisation, it’s a fair bet to say that the best approach to supply chains will be sourcing locally and with as few links in the chain as possible. This principle extends to investment in renewables. Those that rely on exotic and rare metals and minerals, such as photovoltaics or thin-film technology, will probably lose out to their more robust and simpler counterparts such as concentrating solar power (CSP) or wind power. In terms of conventional power generation, trading a few points of operating efficiency for turbines and generators with cheaper, more easily-replaced components would also be a step in the right direction as would slowly ramping up on-site security. This is specially a concern for transmission and distribution companies, given the high value of scrap copper on today’s markets. In addition, efforts to encourage employees to live more locally could also prove to be a wise move. Given possible opposition from shareholders to any changes that immediately impact on the bottom line, it may well be worth drawing up a peak oil contingency plan to go into effect once the price of fuels and other key input hit an agreed-upon sustained high.

Coal is potentially a false saviour. While BP’s statistical review states that as of 2008, we had 133 years of coal remaining compared to only 42 years of oil, this is at current levels of consumption. Given that this is at current rates of consumption and that the amount of energy contained in these reserves is roughly comparable, coal reserves would dwindle surprisingly quickly under a post-peak scenario, especially as the issue of net energy would also rear its ugly head with alarming speed. However, there is some potential from underground coal gasification, which could significantly boost effective reserves. Another issue is of course that a massive surge in coal use without the use of CCS could backfire dramatically given the impact it would have on global warming and CO₂ emissions. There is also the problem that even under a business-as-usual scenario, it may be hard for coal production and exports to ramp up sufficiently, primarily due to rising domestic demand, with recent examples being China and soon, Vietnam.

The great game

Governments will find themselves with a real dilemma: up the tax burden on power utilities to compensate for spiralling deficits, but create the risk of major blackouts later down the line, or take the fiscal pain in exchange for continued investment. In a post-peak world, the spectre of further military intervention would be a real concern and it would not be surprising if Iraq is just the beginning of a trend, with Iran set to be next on the menu, if the current rumblings are to be taken to their logical conclusion.

From a dispassionate perspective, there are real questions as to whether or not war can ever result in a net gain of energy, particularly given the estimated US$3trn price tag of the second Iraq war. However, even if this is the case, if Mr Gabrielli is correct, then this merely postpones the inevitable for a year or two, such is the rate of oilfield decline and the world’s thirst for oil. A major issue is that the wide-sweeping changes and possible hardships needed to adjust economies to a post-peak world will be extremely difficult for democracies to implement. The US is perhaps the best example, encumbered as it is with a system of checks and balances, which although admirable in intent, creates massive bureaucratic inertia. China is naturally in a much better position, but has problems of its own, such as massive overbuilding, pollution and dramatically rising expectations among its citizens. While the Chinese youth of today appear willing to trade political freedom for prosperity, if their government is unable to uphold its side of the bargain, then civil disorder could be a real issue, particularly when one considers the large excess of single men created by sex-specific abortion, coupled with the one-child policy and the cultural preference for sons.

The major oil-exporters in the Middle East, will be cushioned to some extent from the crisis, but this will hinge on what extent they can diversify their economies from oil, given the reduced purchasing power of their traditional customers. Power utilities in such regions may be able to generate substantial revenue via carbon capture for enhanced oil recovery and as exemplified by the current Masdar city project can and are moving towards greater use of solar power.

The financial crisis seen in 2008 could be a taste of the things to come. One of the major issues of our economy is that the attractiveness of investment hinges on the assumption that the economy is growing as a whole, hence the interest payable on the loan or finance necessary for new projects, is compensated by the fact that its relative value drops as a percentage of the wider economy. This point has been championed by Gail Tverberg, a frequent contributor to The Oil Drum and a speaker at the 2^nd International Biophysical Economics Conference in New York. In a post-peak world, economic growth is either constrained or thrown into reverse, making it harder to justify investment. A related issue is that there is the danger of a oil-constrained global economy suffering from a boom-bust cycle in which every recession drags the price of oil below the point that merits necessary investment in the energy sector, creating a vicious cycle. We will soon know if this is to be our fate, given exceptions of a return to the situation we saw in 2008, by 2012-14.

The stakes couldn’t be higher

Many in the peak oil community often, rather unflatteringly, liken the human race to a culture of bacteria growing in a limited amount of medium. At first there is a lag phase as the bacteria adapt to their new environment, then a log phase in which they grow exponentially, using their resources up at a geometric rate, followed by a plateau as they began to run out of nutrients and start poisoning themselves with their own waste products. Finally, there is then a massive die-back, as the remaining nutrients are not enough to support the large population generated during the exponential growth phase. This metaphor extends to our global population, particularly given that the earth’s carrying capacity for humans in terms of food is artificially boosted by our use of fossil fuels to make fertilisers and engage in intensive agriculture.

As chilling as this scenario is, there is some hope, in that new technologies could free us from our addiction to oil. The recent advances in nuclear fusion are particularly encouraging, but there is a catch. Although commercially-mature nuclear fusion would free us from having to mine and refine uranium and dispose of the resulting waste, the technology is still some years off (potentially up to 50 years away) and even if we had it now, the capital costs and build time for a fusion plant would be roughly comparable to those of today’s nuclear fission reactors. Another issue is that if economies do start to contract, R&D budgets would be slashed, putting fusion indefinitely out of arm’s reach. It is also clear that there are major limits on the extent to which technology can boost oil production. Despite massive financial incentive along with huge subsidies and tax-breaks, the oil industry has not been able to bring crude production in the US or the UK back to pre-peak levels.

To summarise, the actions the power sector needs to make in preparation for a post-peak world are already in progress, primarily being driven by energy security and climate change concerns but the pace of investment may not be able to cope with the speed of the unfolding collapse. To be fair, the concept of peak oil is not one that is universally subscribed to, but politicians and other senior figures are always under substantial pressure to promote confidence in the economy, while the message of peak oil if widely publicised, makes it harder for oil companies to recruit and obtain investment. It should also be remembered that many economists do not include hard biophysical constraints in their thinking and we as human beings have an innate tendency to discount or disbelieve scenarios which we find unpleasant, witness those convinced that climate change is bad science at best and a conspiracy theory at worst. While coming to terms with the coming storm may be hard, history has always rewarded those who took a good, hard look at how things are in reality and acted accordingly, over those who put their heads in the sand.

The original presentation by Mr Gabrielli in Portuguese can be downloaded here, or click this link for a partial English translation and commentary at The Oil Drum.

The latest report from Chris Skrebowski and his colleagues on the case for peak oil and the potential impact it will have on the UK can be downloaded from http://peakoiltaskforce.net/ as of February 10.

An older, but extremely through report by Germany’s EnergyWatch Group on the issue of peak oil can be downloaded here

The original version of this article stated that Mr Gabrielli’s presentation indicated that oil supply was expected to peak this year (2010). It is now understood that this was not the actual intent. Instead it was “put together intending to show a reasonable estimate of the “challenges” that oil supply will face in the long term.” Petrobras’s Press Office, Lucio Pimentel also stated that: “Once again, we do not believe it is possible to predict a peak oil date. In particular, we do not believe it will happen in 2010.”

This does however, smack of an inability to “call a spade a spade”. For example, one could still state that it is extremely “challenging” for the UK to boost its oil production, when in fact the country’s oil output peaked in 1999.

In Canada, oil companies are quietly harvesting one of the largest reserves of fossil fuels in the planet, but at the same time are coming under fire for the resulting impact on the environment, both in terms of water use and greenhouse gas emissions. Regardless of the drawbacks, the combination of minimal geopolitical and geological risk and close proximity to what is currently the largest market for crude oil in the world has made Alberta’s oil sands seemingly irresistible to oil companies and investors. The rapid commercialisation of the reserves has created conditions reminiscent of the Californian gold rush of 1848-1855, with whole new towns, such as Fort McMurray sprouting up as if from nowhere.

Oil sands, as the name suggests, are essentially bitumen or viscous heavy oil, with a API of 15-16, mixed with sand. Once the oil has been separated from the sand, it is then upgraded (this is necessary due to the fact that heavy oil is substantially discounted, compared to lighter, more easily-refinable oil) and then transported to a refinery, either in Canada or the US. The location of the refinery is contentious, given the large quantities of CO₂ released in the process and the future cost of emissions under possible carbon trading schemes.

Upgrading units are expensive and generate significant CO₂ emissions when in operation, so there is likely to be a shift towards handling the upgrading process at the refinery. This is precisely what is happening at Husky’s 200,000bpd Sunrise project, which will ship its output in the form of bitumen to refineries in the US.

In an interview with IFandP, Barry Munro, Ernst and Young’s Canadian oil & gas industry leader, pointed out that one of the major attractions of the Canadian oil sands is that they offer investors and developers a reserve base of around 50 years. The only other country capable of matching this is Saudi Arabia (see Table 1 for details of the province’s bitumen reserves.).

Mr Munro explained that it is effectively impossible for Canada to reduce its CO₂ emissions by 20 per cent by 2030, when over the same period, it expects to increase its oil production by five-fold. In terms of CO₂/bbl, Canada is about the same as Mexico and Venezuela, he elaborated. However, Canada’s oil companies are far more publicly accountable than PDVSA, Venezuela’s national oil company.

In addition, Canadian interests mesh to a far greater extent with those of the USA, especially given the fact that Hugo Chavez has loudly voiced his opposition to the US, going so far as to call President Bush “Satan” at a UN meeting. Mr Munro is therefore of the opinion that Canada can offer its southern neighbour secure long-term supplies and in the process, edge out its Latin competitor.

The Athabasca River supplies the majority of water to
the oil sands companies in Alberta, but according
to environmentalists this is beginning to have a
detrimental effect on fishstocks in the river as
allocations have reached dangerous proportions.

He also felt that the water card has been somewhat overplayed, claiming that in oil sand production, 90 per cent of the water used is recycled which compares favourably to corn ethanol, given that the latter is five times more water intensive. However, allocations from the Athabasca river, which supplies the oil sand producing regions with the majority of their water, are now greater than 10 per cent of its flow, a proportion which environmentalists warn is dangerous to the fish that inhabit the waters.

Another issue is that of air quality. A US EPA appeal board in June put an end to the proposed expansion of the Wood River III refinery, which is owned by ConocoPhillips and EnCana, by refusing to grant the necessary air permits. The two companies were looking to invest US$4bn in upgrading the refinery to handle the oil sands.

Due to increasing public concern regarding the environmental impact of their activities and mounting pressure from the Canadian government, oil sands companies have banded together in the hope that together they might be able to develop a system capable of economically capturing and sequestering the CO₂ generated from oil sand operations. The resulting organisation called ICO2N (Integrated CO₂ Network), has proposed a scheme which, if realised, “has the potential to reduce Canada’s CO₂ emissions by 20Mt [a year]”, according to its website. The situation is made if not more complicated, then at least more expensive, by the fact that oil sands projects in Canada are located a long way from areas where enhanced oil recovery using CO₂ could be a possibility.

CCS is increasingly looking like it will become a mandatory addition, as opposed to an optional extra, as the Canadian government has ordered that new oil sands projects and coal-fired plants that commence production after 2011, will have to sequester the bulk of their CO₂ emissions by 2018. John Baird, the Canadian environment minister, has estimated that the cost of compliance with such regulation will cost the relevant industries CAD25/t by 2010, before climbing to CAD50 and CAD65/t by 2016 and 2020, respectively.

Companies that fail to take appropriate measures are to face criminal prosecution under the scheme. Given that Canada is already emitting well above its target in terms of greenhouse gases, it is little wonder that the government is starting to take a stand on this issue. Existing oil sands plants will not completely escape, as those started after 2004 will be subject to more robust, cleaner fuel burning standards.

If oil prices remain strong and move back above US$147/bbl in the medium term, then oil sand companies may well be able to simply buy carbon credits as opposed to building their own CCS plants. This is because the Canadian government is setting its own carbon trading market and the credits involved can be used by oil sand operators for compliance with their targets.

The need for natural gas

The other major constraint for the industry as a whole is the amount of natural gas required to treat the oil sands to the point where they can be refined. Currently, this amounts to some 0.6bnft³pd, but it has been estimated that this could increase to 2.2bnft³pd by 2020. When one considers that Canadian gas production dropped 5.9 per cent in 2007, down to 16bnft³pd then its clear that high natural gas use is unlikely to be sustainable in the long term. Interestingly, there signs that nuclear power is being put forward as an alternative. Both Areva and Canada’s own nuclear vendor, Bruce Power, have expressed interest in building up to four 1GW nuclear reactors, with the aim of powering the oil sands industry. In the meantime, Alberta’s provincial government, in association with the industry, has developed “fuel gas best management practices” to ensure that as much gas as possible is conserved.

Bitumen production

There are a number of novel strategies currently being employed to extract the bitumen from oil sands. The traditional open-cast mining approach typically converts four tonnes of material (including overburden) into two tonnes of oil sands, which in turn is processed into 1.2 barrels of bitumen, before finally resulting in a single barrel of synthetic crude. Mr Munro highlighted the efforts of Petrobank, a company which is looking to perfect an in-situ refining process, trademarked as THAI (Toe-to-Heel Air Injection). The method starts a fire underground, which is maintained using air injection wells. The resulting combustion zone warms the oil to the point where it can flow. Horizontal production wells can then harvest the oil.

This approach has several key advantages. Unlike more traditional methods, it requires very little fresh water. The company also claims that it results in 50 per cent lower CO₂ emissions than would otherwise be the case, and because the action occurs beneath the surface, operations have a smaller surface footprint, making reclamation easier and less expensive. Although the system sacrifices some of the reserve in order to heat the oil to the point where it can be extracted, Petrobank claims that THAI can recover an estimated 70-80 per cent of oil-in-place. As the reserve itself provides the energy needed for its extraction, natural gas consumption is also reduced.

Similar techniques include:
• Cyclic steam stimulation, which as the name suggests, injects steam into the oil sands deposit
• Steam-assisted gravity drainage (SAGD) involves injecting steam into a horizontal well to reduce the viscosity of the bitumen to the point where it can flow into a lower parallel wellbore. One advantage from this process is that although the resulting sour crude is sold at a discount, by-products can be used to fuel the process and the required upgrading unit is about half the price of the type normally needed.
• Vapour extraction (also known as VAPEX) uses solvents instead of steam. As 80 per cent of the tar sands in Alberta are too deep to be exploited via open-cast mining, in-situ techniques are likely to remain the methods of choice.

Unfortunately, according to Strategy West, a Calgary-based firm, steam-based in-situ projects are more CO₂ intensive than their open-cast mining counterparts, generating around 65kg/bbl, compared to only 15kg/bbl for mining operations. There is also the emissions from refining to consider. According to a WWF report, refining bitumen from oil sands produces eight times as much CO₂ as processing traditional oil.

As a result of the above, in-situ methods are more sensitive to any changes in greenhouse gas emission regulations or compliance costs, which according to Bob Dunbar, president of Strategy West, are “one of the main uncertainties facing the industry right now” (The Daily Oil Bulletin). Mr Dunbar believes that such costs could add US$5/bbl or more to production costs.

Suncor’s oil sand from Fort McMurray, Alberta, is mined using shovels that
hold 100t, loading huge 240-38t trucks. Image courtesy of Suncor

Although last year saw mining projects account for 286mbbl of bitumen production, significantly more than the 196mbbl from in-situ projects, the latter are growing at a faster rate, increasing by 7.1 per cent in 2007, compared to only 4.3 per cent for mining, according to the Energy Resources Conservation Board of Alberta (ERCB). The Board’s July update states that at year-end 2007, around two-thirds of initial minable established reserves were under active development.

The combination of longitude and lack of coastline, results in cold harsh winters. As a result, oil sands operators in Alberta at the mercy of the weather. This can mean that production is disrupted. For example, recently, the Canadian Oil Sands Trust, reported that instruments at its Syncrude Canada oil sands venture froze up due to temperatures of around -40˚C in January causing output to stop. Full production was not resumed until February. As a result, Syncrude had to reduce its full-year forecast from 115mbbl down to 108mbbl.

Transporting the product

Alberta is landlocked and the US is a strong, profitable and relatively nearby market for synthetic crude, so moving blended bitumen (blending is done to improve its flow characteristics) by pipeline is the preferred method of transportation. Canada’s crude oil pipeline network is already the largest in the world and currently has an asset value of approximately US$20bn, transporting 1.85mbpd of crude a day to international markets according to the Canadian Energy Pipeline Association (CEPA). Despite this impressive scale, the Association has indicated that Canada’s pipeline assets will have to double in size by 2015 in order to meet forecasted production increases.

As can be seen from Table 2, there are a number of pipeline projects recently completed or due for completion. In fact according to CEPA, at least US$20bn worth of projects are on the drawing board. The Keystone pipeline is one of the most ambitious, and is being constructed by a partnership between TransCanada, Calgary, Alberta and ConocoPhillips, at a cost of US$5.2bn. The pipeline has recently won approval from the Canadian government and received US approval to cross the border between the two countries in March. Once constructed it will cover 2148 miles, from Hardisty, Alberta, to Wood River and Patoka in Illinois, and also to Cushing in Oklahoma. The line to Illinois is expected to be complete in late-2009, with the Cushing line following in late 2010.

The challenges ahead

Although changes to GHG emission regulations are a concern, the industry is more influenced by the price of crude, as the costs involved in oil sands production are a quantum leap above conventional oil projects in, for example, the Middle East. There is considerable variation in the oil price suggested by analysts as being the break-even point for oil sands. StatoilCanada claims that US$80/bbl or higher is required, which contrasts with the US$60-70/bbl and US$50/bbl, suggested by Mr Dunbar and Barry Munro, respectively.

In addition, the Albertan oil sands cannot escape some of the problems impacting the oil industry at large, such as the ballooning capital costs associated with new projects. The last four major oil sand projects have experienced cost overruns in excess of 60 per cent and projects expenses are now running 200 per cent above those seen at the beginning of this decade.

A contributing factor to this situation is a labour shortage. This is putting pressure on operators to increase wages and has already delayed the onset of full production at Canadian Natural’s Horizon mine to early 2009, consequently pushing up the cost of the project by eight per cent and taking it to an eye-watering US$9.27bn. A report by the Construction Owners Association of Alberta has warned that a construction labour shortage is expected to continue right through 2009. The inflationary environment has led Imperial Oil to hold off its decision regarding the construction of a US$8bn oil sands mine until the start of next year.

A more abstract issue is that of energy return on investment. Producing crude from oil sands is so energy intensive that it yields only 5-10 per cent of the net energy gained from conventional light crude production. Therefore, it is worth bearing in mind that the oil sands, despite their abundance, may not strictly be the best investment in terms of overall energy gain.

Investment outlook

Regardless of these problems, investment is expected to continue to flow into the region, albeit at a more sober level than that previously experienced. Mr Dunbar expects capital expenditure to average US$25.2bn in 2008-20, with bitumen production reaching 6mbpd by 2020. This is a more optimistic scenario than that envisaged by the ERCB, which in July, released an update predicting that bitumen production will reach 3.23mbpd by 2017 (up from the 1.32mbpd seen in 2007), 1.46mbpd of which, will come from in-situ projects.

Suncor Energy, one of the key players in the Albertan oil sands, is single-handedly looking to spend CAD7.5bn as capital expenditure in 2008, 80 per cent of which has been earmarked for growth projects, primarily in oil sand projects. In addition, ConocoPhillips’ president Kevin Meyers announced back in February that his company is poised to dramatically boost its output from oil sands projects in the coming years. ConocoPhillips currently produces 60,000bpd of crude from oil sands, approximately half of which is from a nine per cent stake in the Syncrude Canada joint venture, with the balance coming from two joint ventures with EnCana.

However, a number of developments have been delayed, such as the Fort Hills expansion and the Kai Kos Dehseh, Sunrise and Joslyn creek mining projects. Canadian Natural Resources Ltd has deferred its upgrader indefinitely and Total has made a similar decision with regard to its Northern Lights project. The investment environment is also complicated by the difficulty of acquiring finance in a post-sub-prime world and with all the major prospective areas already snapped up, exploration activity is likely to essentially be over, according to Michael Kahn, vice-president and director of TD Securities a financing company, involved in oil sands development.

This, coupled with the high costs involved in developing oil sand projects does mean that the industry has little to fear from new entrants at this point in time. The fact that both Mexico and Venezuela are likely to see declines in their oil production due to inadequate investment and the increasing scarcity of oil resources, particularly those accessible to the international oil majors, means that demand for their product is almost guaranteed.

Oil sands companies have been quick to take advantage of the rising price of sulphur, a by-product of bitumen refining, on the international market. ERCB has reported that it has risen from US$50/t in mid-2007 to US$150-350/t. China has been the main importer of sulphur from Alberta, but the province is starting to see stiff competition from the Middle East, which contributed to a 24 per cent decline in exports to China in 2007. The country uses sulphur in the production of phosphate-based fertilisers and sulphuric acid.

Where will it go from here?

So, to summarise, the two most important factors that together determine the prosperity of the oil sands industry are oil prices and the growing issue of CO₂ emissions. While the former may have fallen back, long-term expectations are still bullish, due to the problems facing both international and national oil companies. Also, despite the recent dip in US oil demand, there is little sign that the next administration will be able to wean the country off its oil addiction.

The future requirement for carbon capture and sequestration is more of a concern, as it will involve implementing a number of novel technologies on a massive scale. The risk is fundamentally one of cost. It may well be possible to sequester carbon from oil sands projects, but doing so and still generating an healthy return may be a different matter altogether.

For more information, consider visiting:
http://oilsands.alberta.ca/ – this has a full map of current and proposed oil sands projects in its industry section
www.cepa.com
www.suncor.com

The World Petroleum Congress is held once every five years and is perhaps the largest and most prestigious gathering of oil analysts, industry representatives and executives. This year, Madrid, Spain, hosted the 19th Congress at the modern and spacious IFEMA-Feria de Madrid exhibition centre, coinciding with the country’s victory in Euro 2008 football championships, which added an extra flourish to the opening dinner. The Congress got off to a rousing start with an address by Andreas Piebalgs, the EU commissioner for energy.

He was emphatic in saying that “only international action is enough to make an adequate response to today’s energy challenge.” He called for greater transparency and better access to data, arguing that the greater barrier to investment is uncertainty. Mr Piebalgs was also adamant that without renewables and energy efficiency “there is no sustainable solution.” Worryingly, he voiced his belief that even with its current renewable energy policy, the EU is likely to be importing more oil and gas than it does today.

During his presentation, Mr Piebalgs concisely summarised the main goals of EU energy policy: a 20 per cent increase in energy efficiency and the use of renewables, by 2020 and a 20 per cent reduction in CO₂ emissions by the same year. A delegate suggested that the current trend of announcing carbon emission or renewable energy targets, where the percentage reduction or uptake is equal to the year of the deadline (minus 2000), made it difficult to accept that the targets had been agreed after a careful consideration of the scientific evidence. Mr Piebalgs responded by saying that on the contrary, the targets had been chosen after careful consideration of the science and represented the minimum reductions required by the evidence. He commented that the European Commission is trying to reduce the impact of biofuels on the price of food, partly by promoting the development of alternative technologies.

Tony Hayward, CEO of British Petroleum (BP) was up next. He began by commenting that the rising price of energy is a signal that supply is not responding to demand. He then addressed three commonly held “myths”: speculation, below-ground factors and the idea that renewables are the answer to the energy problem. Mr Hayward believes that the huge upsurge in demand from China has effectively used up any spare capacity and that this, coupled with the difficulties facing oil companies above-ground, was the primary cause of high oil prices. He pointed out that when Europe underwent the industrial revolution, it affected 200-250m people, when the USA followed, another 300-350m underwent urbanisation, but now 1-2bn people are industrialising with a huge impact on the price of all commodities.

Mr Hayward claims that the world still has 40 years of oil and 60 years of natural gas left and that therefore below-ground factors are not an issue. He also commented that although renewables are growing rapidly, it is a mistake to believe that they can be brought online fast enough to be a solution in themselves.

In his mind, the shortage of people and resources in the oil industry was a key problem to overcome, with retirement looming for a large proportion of skilled workers. Interestingly, Mr Hayward noted that as 80 per cent of the world’s oil resources are controlled by national oil companies (NOCs), but independent companies have the most advanced technology, there is a real need for new forms of contractual agreement and that there should be a move away from ownership of a field automatically meaning production.

He said that efforts should be made to increase the recovery rate from oilfields, which globally averages only 35 per cent of oil in place.

This was later given weight during a technical session in which a speaker explained that every extra one per cent of additional recovery is equivalent to around 60 gigabarrels of crude, representing two years of world production at current rates. Mr Hayward commented that taxation was at dangerously high levels, given the scale of investment required to meet demand in the future.

Carlos Perez de Bricio, chairman and CEO of Cepsa, an international exploration and production company with Spanish roots, operating in the Mediterranean, Canada, Latin America and the UK, said that the industry will have to start producing high cost oil and natural gas to meet demand in the years to come and that more should be done to attract young people to the oil industry.

Antonio Brufau, CEO of Repol YPF, remarked that within the next 50 years, developing nations will end up using around 50 per cent of the world’s energy supply and saw their rapid development as a positive shock to the world economy, but which was responsible for the high ramp up in prices, which could delay improvements in the standard of living for their populations. Mr Brufau also pointed out that currently independent oil companies are responsible for around 70 per cent of all investment in the oil industry and that further incentives are required, particularly government frameworks to encourage long-term investment. He argued that further investment in refining would lead to increased energy security. Another point Mr Brufau made was that EU is increasingly competing for energy resources and that the fragmented nature of the European market was not helping matters.

One theme that the majority of speakers touched on was the importance of carbon capture and sequestration. Mr Hayward suggested that a higher CO₂ price than that supported by the market might be needed to make CCS a reality, given that it would have to be scaled up by a factor of 20-50 times – a considerable challenge. Mr Van der Veer, chief executive of Royal Dutch Shell, said: “It is difficult to see how coal can grow as predicted without CCS.” He was supportive of pre-combustion methods and the idea that all new power plants should be built “capture-ready”, but expressed caution as the technology surrounding the field is changing rapidly.

He hoped that the US would soon adopt a cap-and-trade system, and commented that the CDM and the possibility of enhanced oil recovery, should help to promote CCS in China and the Middle East, respectively. In addition, Mr Van der Veer called for an international CCS system “which produces fully convertible carbon credits” as well as a global energy fund to provide finance for new projects. Renewables and nuclear power should be part of every country’s energy portfolio, Mr Brufau commented.

When asked as to whether any of the speakers foresee any physical shortages, Mr Hayward didn’t see that happening and that the high oil prices are already causing a 5-10 per cent decline in oil demand in OECD countries. Mr Van der Veer added that peak oil was a good concept but is predominantly about the “easy oil”.

When the question was raised as to whether the current phenomenon of share buybacks was adversely affecting research and development, Mr Van der Veer said that the two are completely different issues and that other constraints meant that it is impossible for Shell to ramp up R&D any faster than it is currently doing. He also explained that as far as Shell is concerned, share buybacks are about creating value for shareholders and creating a stronger balance sheet.

On the subject of NOC/IOC co-operation Mr Brufau said that it is essential, while Mr Van der Veer believed that the role of IOCS is to be one step ahead in technology, giving integrated project management as an example.

At a press conference later that day, Mr Van der Veer said that the LNG industry has completely changed. Rather than having to wait until you have all your customers sealed up, now if you produce LNG you have ample possibilities to sell, he elaborated. While discussing the outlook for Russia, he disclosed that Shell has been shortlisted for development of the Yamal gasfield. Shell’s CEO also made the point that such is the size of the Yamal field that it is incorrect to think of it as a single conventional gasfield. On the subject of Iraq, he said that there had been substantial progress in the past few months and that a contract could be signed within weeks or months, declaring his preference for the former. However, he pointed out that legal and fiscal terms had yet to be agreed.
The plenary session on the second day of the conference addressed the topic of “deliverability challenges security of supply and demand perspectives.”

During the session, Mr Chengyu Fu, president of China National Offshore Oil Corporation (CNOOC), said: “When Saudi Arabia announced an extra 200,000bpd of oil production, the oil price didn’t stop. This might lead us to believe that the increase in price has nothing to do with fundamentals. However, we need to ask what is behind the speculators. I believe it is severe concerns about supply and demand, now and in the future.” He went on to point out that currently, the OECD is still using 17bbl per capita per year, while non-OECD countries are using only 2.5bbl. Until recently India and China were both using around 1bbl/year/person, but now this figure is closer to 5bbl. After listing the range of factors such as geopolitics, which influence the oil price, Mr Fu said that concerns about demand and supply are warranted but added “I believe there is enough for sustainable growth for the next 30 years.”

No easy oil?

Christophe de Margerie, CEO of Total, explained that it was important to understand that oil is not as easy to get hold of as it used to be. As an example, he pointed to the Russian continental shelf as an important area for development in the future and commented that joint ventures and the exchange of assets are key to spreading the risk associated with developing new fields. He believes that more cooperation is needed within the industry.

Somewhat controversially he stated that in Total’s view, oil production will reach a plateau of 95mbpd by 2020, partially due to the fact that a large proportion of new capacity will be swallowed by decline rates of 5-6 per cent. Mr de Margerie predicted that over 50mbpd of new capacity will come online between 2005 and 2015 and suggested that the natural gas industry is likely to face the same challenges experienced by oil producers in a few decades time. Production growth is primarily led by advances in technology and megaprojects, Mr de Margerie explained. He defined project management as the ability to take technical and financial risks and drew attention to the twin constraints of expertise and equipment in a booming market for projects.

The average cost of developing a 200,000bpd project was around US$7-8bn, which partially explains the high cost of oil as US$80/bbl is required to break even according to Mr de Margerie. Also on the subject of price, he commented that meeting the challenge is not just the task of oil producers, it is also “the responsibility of consuming nations to say how much they will need.”

This theme was picked up by Dr Chakib Khelil, president of OPEC and the Algerian minister of energy and mines. He explained that OPEC is responding to supply concerns by embarking on significant capacity expansions and upstream investment, with over 120 projects in development, at a cumulative cost of US$150bn. Dr Khelil said that the cartel plans to increase capacity by 4mbpd by 2012. At the same time, US$60bn has been earmarked for downstream investment, with the aim of removing the current bottlenecks facing the industry. He predicted that OPEC’s contribution to world oil production is likely to increase in time, eventually rising above 50 per cent.

However, the industry is faced with a large amount of uncertainty, Dr Khelil explained. The economic outlook, oil demand, the increasing volatility of oil prices, the possibility of a looming financial crisis and its impact on investment and demand, together with fluctuations in the value of different currencies are all working to make predictions difficult. Between US$90bn and US$140bn in investment could be needed by 2010 he claimed, with the gap between the minimum and maximum scenarios widening further ahead, with the investment required by 2020 to be between US$160bn and US$230bn.

During the question-and-answer session, Dr Khelil said that the current high oil prices were not in the interest of consumers or producers and that the prices are fixed by the market and not OPEC. Surprisingly, he added that he thought that there would be peak oil, but it “would be due to new technology and more use of coal and gas.” At a press conference later that day, Dr Khelil said: “it is difficult to believe that we will experience shortages in oil and gas distribution during the next 50 years.”

One of the most interesting things about Dr Khelil’s comments is that the points he made are difficult to reconcile with fears that OPEC oil reserves are on the decline. For the cartel to even be contemplating a massive investment programme with the aim of boosting the country’s oil production, it must be confident that it has the reserves base in place to support it.

Strong global LNG market and energy efficiency

Rex Tillerson, chairman and CEO of ExxonMobil, was next to speak, choosing to focus on the topic of LNG. He started by saying that oil and natural gas are expected to account for 60 per cent of the world’s energy supply in 2039 and that a strong global LNG market would bolster energy security. Mr Tillerson continued by highlighting the partnership between Qatar and ExxonMobil in the LNG arena and said that operations are increasingly benefiting from economies of scale. Once the partnership’s new Q-max ships are launched, its shipborne LNG capacity will increase by 80 per cent, giving ExxonMobil more capacity than any other company.

Mr Tillerson also discussed the topic of energy efficiency. Over the past 25 years, world energy efficiency has been growing at one per cent per annum, he commented. He believes that there are still great gains to be made in the transport sector, via a move towards lighter cars and the adoption of advanced technologies such as homogenous fuel ignition. He also pointed to the development of hydrogen and the move towards electric-hybrid cars. The high price of oil creates the temptation for companies to break partnerships, a temptation that should be resisted, Mr Tillerson concluded.

During the Q&A session, Dr Khelil commented that technologies such as 3D or 4D seismic geo-modelling and horizontal drilling has played a major role in increasing the size of oil reserves. He went on to say that technology has been responsible for 70 per cent of the increase in reserves seen in the past 30 years, by increasing the amount of oil that can be delivered from each field.
Mr Tillerson took exception to Total’s oil supply outlook, saying that in the current price environment, producers are clearly going to redouble their efforts to boost recovery rates and that new capacity does not automatically require new oilfields. He qualified this by saying that enhanced or increased oil recovery methods require good management of reservoir depletion to be applicable. Mr de Margerie responded by saying that Total’s target is not based on reserve limitations, but rather on “other things happening in the world”.

The role of oil subsidies

When the panel was asked to discuss the role of oil subsidies, Mr Khelil spoke first, saying that it is important to look at them in terms of purchasing power. If developing oil economies were to jump to price parity, this would mean that people in such countries would be paying US$500-3000 a year for oil. Therefore, he argued, you can’t ask such countries to pay the same price but you still need rational expenditure.

On the subject of whether oil subsidies in China were sustainable, Mr Fu replied: “I believe in any country, subsidies are not long-term policy.” He went on to say that the economy can’t support them in the long-term, but China can see a slow-down in growth, without affecting its ability to meet government targets. With regard to the major challenges facing CNOOC, he believes that the company needs to grow faster in the next five to 10 years, ideally by 7-11 per cent per annum to 2010, thus creating a need for more capital. Mr Fu said that there are tremendous reserves in offshore China, but as they are predominantly in the form of heavy oil (11-16api), it is necessary to invest in new technology and refineries, which CNOOC is currently doing.

Why biofuels?

A question from the audience lightened the mood. Mr Tillerson was asked why the US produced ethanol. He replied: “Because the corn states have 40 senators” He went on to note that Exxon has not ruled out biofuels, but at present he didn’t see much value that the corporation could add. However, Mr Tillerson claimed that Exxon is focusing its efforts on examining the potential of second-generation biofuels and is financing supporting programmes.

A thought-provoking meeting

What has been covered in this article is only a small portion of the analysis and information available at the congress, which proved to offer the very best in stimulating discussion and debate. It also provided an opportunity for companies to showcase their expertise, both in the technical sessions and in the extensive exhibition hall.

The next World Petroleum Congress will be held in 2011 in Qatar, a highly appropriate host, given its booming LNG sector, and IFandP looks forward to bringing you the most pertinent details.

For more information consider visiting the following websites:
www.19thwpc.com
www.opec.org

The vast majority of electrical power is produced by centralised power plants – primarily natural gas-, oil-, and coal-fired. Unfortunately, these power stations give off large amounts of harmful pollutants and greenhouse gases. Combined cycle plants use residual heat to improve overall power generation efficiency. However, the distance to consumers makes it difficult to otherwise utilise combined heat and power (CHP) effectively. Transmission networks carry energy to the consumers, sometimes hundreds of miles away and line losses further degrade overall efficiency. Fortunately, advances in distributed generation technologies – in particular, fuel cells – offer solutions for primary (baseload) power that can augment the grid in ways that improve efficiency, reliability, and environmental impact.

Distributed generation vs the power grid

Today, most of the electricity produced in the US is provided by regional utilities and supplied to customers via the grid. As a matter of fact, of the 3800mMWh of electricity produced in the US in 2003, only 4.1 per cent (156mMWh) was non-utility generation. Commercial utilities produced 3.6 per cent (135mMWh) to meet local power needs, and the remaining 0.5 per cent (21mMWh) was attributable to other sources. Wind, solar, hydro and other renewable energy sources augment the grid and are making a respectable contribution. Much of this energy, however, is vulnerable to the whims of nature and thus difficult to manage for the utilities. This is the case for wind and solar in particular.

Slowly, however, the landscape is changing, as distributed power generation becomes more practical. Commercial businesses and institutions such as hotels, universities, and government facilities, to name but a few, are moving toward energy independence and reduced reliance on the grid. Doing so provides a degree of flexibility not otherwise possible and reduces the grid congestion and power transmission issues associated with centralised generation. There is also another advantage of distributed generation: proximity to the consumer. This provides an opportunity to use CHP effectively, thus reducing overall energy costs and boosting the efficiency of the process considerably. Fuel cells also offer the unique advantage of compactness, competitive operating costs, and “ultra-clean” emissions. They also operate 24/7 and so are easily managed in concert with grid power.

Why fuel cells?

With power availability rated in excess of 95 per cent and an electric power generation efficiency far exceeding other processes, fuel cell technology has advanced to the point where it is now a viable alternative to combustion-based plants for a growing number of baseload power applications. Today, fuel cells are reaching their potential as the cleanest and most reliable source of distributed power generation.

Historically, fuel cells have been limited in practicality because of the need for a supply of hydrogen to operate. Certain systems, however, known as direct fuel cells, or DFCs, have been developed and are unaffected by such a limitation, as they operate on natural gas, biogases (from food processing and wastewater treatment) and propane. They have even been shown to generate clean power from diesel fuel and coal gas, fuels traditionally associated with high pollution. How is this possible? The systems internally reform hydrogen from the source fuel. Whatever the fuel source, DFCs emit dramatically reduced CO₂ greenhouse gas compared with combustion alternatives, and only negligible amounts of pollutants, such as NO_x and SO_x.

How direct fuel cells work

In essence, fuel cells are electrochemical devices that combine fuel with oxygen from the ambient air to produce electricity and heat, as well as water. The non-combustion process is a direct form of fuel-to-energy conversion and is much more efficient than conventional heat engine approaches. CO₂ emissions are reduced, due to the high efficiency of the fuel cell and the absence of combustion negates the production of NO_x and SO_x pollutants.

Fuel cells incorporate an anode and a cathode with an electrolyte inbetween, similar to a battery. The material used for the electrolyte and the design of the supporting structure determine the type and performance of the fuel cell. The DFC uses a carbonate-based electrolyte, which operates at high enough temperature to allow generation of hydrogen within the cell. Fuel and air reactions for the DFC occur at the anode and cathode, which are porous nickel (Ni) catalysts. The cathode side receives O₂ from the surrounding air.

Fuel (typically methane from natural gas or biogas) is supplied to the anode, which reforms the fuel into H₂. The gas is then consumed electrochemically. The O₂ supplied to the cathode, along with CO₂ recycled from the anode side, reacts with the carbonate salt electrolyte to produce carbonate ions that pass through the electrolyte to the anode, where they combine with the H2 to produce water, CO₂ and electrons. The electrons flow through an external circuit to the cathode, thus producing the desired power.

Figure 1: Block diagram of a direct fuel cell power plant. HRU is an acronym for hydrogen reforming unit.

Fuel cells and CHP

DFC power plants have an exhaust temperature ranging from 650°F to 750°F. This heat energy can be captured to provide heat for buildings, swimming pools, and other facility needs. In fact, the already high efficiency of fuel cells can be increased from around 47 per cent to more than 80 per cent by the use of thermal energy. Alternatively, the heat can be used with a turbine generator to convert the heat to electrical energy. Simple systems are commercially available today which can add 2-3 percentage points electrical efficiency by converting some of the thermal energy to electricity. More integrated fuel cell/turbine hybrid systems are under development which will operate with about 60 per cent electrical efficiency.

Fuel cell plants are typically located within or near to the facility where the electricity is to be used. This is a distinct advantage over conventional central plants that are usually located too far for effective utilisation of waste heat.

There are also certain other CHP considerations regarding the trade-off between heat and electricity that highlight the benefits of fuel cells over turbine and other combustion generators. Electricity generated during a cogeneration process has a significantly greater value than that of the associated waste heat, in fact, up to 10 times as much. Thus, the generation of electricity is paramount in the economic efficiency equation, since the more electricity that can be produced by the power plant, the less must be purchased from the grid.

With traditional sources of distributed power generation – eg, reciprocating engines, microturbines, etc – CHP can mask the underlying electrical power generation efficiency of the power source. Whatever CHP adds to the overall efficiency, there is no getting around the actual electrical power-generating efficiency of the plant. Thus, in the case of a microturbine, eg, operating at typically less than 30 per cent electric power generation efficiency and a reciprocating engine at 35 per cent electric power generation efficiency, considerably less of the overall output of the system is in the form of electricity. In contrast, the DFC operates at 47 per cent electrical power generation efficiency.

The bottom line is this: DFC fuel cells offer the distinct advantage of a higher ratio of electricity to heat – electricity that would be relatively expensive, if it had to be purchased from a grid – while capturing much of the heat generated by the CHP process for productive use. The higher ratio of electricity to heat also means that DFC operation is more effective at reducing carbon emissions compared to CHP systems with lower electrical efficiency.

Baseload power applications for stationary fuel cells

Fuel cell power plants are uniquely well-suited to a variety of distributed generation applications. In particular, hotels, food and beverage processing plants and wastewater treatment plants are discussed below. In addition, however, DFC power plants are in operation at wastewater treatment plants, manufacturing facilities, universities, hospitals, correctional institutions, government facilities, and even as pure grid support applications.

Take, for example, food and beverage processing. Digester gases are produced by the digestion of organic matter (which is done to reduce the amount of solid waste produced at a facility). Fuel cells can use the methane-containing digester gas to produce electricity and heat (which is used in the digesters). This avoids the need to flare unused gas and it provides the power much more cleanly than if the gas were used in a combustion-based generator.

The Sierra Nevada Brewing Company in Chico, California, has installed a 1MW DFC power plant to address its clean energy needs. The system is fuelled by digester gases given off in the beer production process and augmented with natural gas. The plant provides virtually all of Sierra Nevada’s baseload power requirement, of which about 40 per cent is produced using digester gas. The DFC power plant converts the digester gas into the most electricity possible by distributed generation technology, thereby maximising this limited resource. The result is high quality, utility-grade electric power, usable heat, and ultra-clean emissions. Waste heat is used to produce steam for the brewing process. The overall energy efficiency for a DFC plant is twice that of power supplied from the electrical grid.

The Dublin San Ramon wastewater treatment plant in Pleasanton, California, has a 600kW fuel cell power plant onsite. Sludge from the conventional sludge treatment process is anaerobically digested to reduce the volume of solid organic manner, producing methane gas in the process. The fuel cell receives the treated digester gas and converts it into electricity. Electrical power produced in the process is used to operate the plant, and heat produced by the fuel cell is recovered and used to heat the sludge, thus optimising the anaerobic digestion process.

Figure 2: 600kW Direct FuelCell installation at the Dublin San Ramon Services District uses anaerobic digester gas to power the wastewater treatment process.

Fuel cells are also helping many states in the US meet their recently-adopted Renewable Portfolio Standards (RPS), which have set electricity providers the task of obtaining a minimum percentage of their power from renewable energy resources by a certain date. Currently there are 28 states plus the District of Columbia that have RPS policies in place. Together, these states account for more than half of the electricity sales in the United States. Connecticut has turned to the Connecticut Clean Energy Fund (CCEF) to administrate their RPS programme. The CCEF, created and funded by the state legislature to encourage wider installation of clean energy technologies for the benefit of Connecticut ratepayers, established “Project 100” to encourage the installation of 100MW of electricity generated by renewable means by 2008.

After careful review of various proposals utilising an array of renewable energy technologies, the CCEF and the Department of Public Utility Control (DPUC) selected Direct FuelCell power plants from FuelCell Energy for installations totalling 16.2MW of Class I renewable energy. The project consists of three main fuel cell installations – a 2.4MW installation at Stamford Hospital, a 4.8MW installation at Waterbury Hospital, and a 9MW hybrid fuel cell/turboexpander installation at a gas pipeline transmission centre in the city of Milford. The success of the Project 100 scheme has led the CCEF to expand the RPS programme to cover 150MW of renewable power generation by 2020, through the recently announced “Project 150”.

Over in California, the state’s self-generation incentive programme (SGIP) has been amended so that fuel cell operators can benefit from subsidies for plants of up to 3MW in size, further demonstrating the desire of US policy-makers to support this promising new technology. The SGIP previously reimbursed fuel cell power plant owners US$4500/kW for biogas-run units and US$2500/kW for those operating on natural gas for installations of up to 1MW. Under the revised scheme, the first 1MW of a project is entitled to 100 per cent of the incentive, while the second and third megawatts are eligible for 50 and 25 per cent of the subsidy, respectively.

Another development, which underlines the appeal of this new technology among independent power producers (IPPs), is the order for 25.6MW of FuelCell Energy’s power plants and fuel cell modules from POSCO Power, FCE’s South Korea distribution partner. POSCO will be siting these units in various IPP and utility applications within South Korea. This brings POSCO’s total purchases of FCE products to date to 38.2MW.

The new plants and modules are expected to be delivered by mid-2009 and will make a positive contribution in the ongoing effort to reduce the country’s dependence on imported fuel. At the same time, this new development will help to decrease the emissions of greenhouse gases and other pollutants associated with power generation. It has effectively doubled FCE’s project backlog and represents almost US$70m in sales.

Fuel cells in natural gas transmission

In addition to providing efficient, distributed baseload power, fuel cells can be used to harness energy that would be otherwise wasted in the transport of natural gas via pipelines. The gas is transported over long distances at high pressure, which must be reduced before it reaches its final destination. The expansion in volume of the gas can be used by a turbine (also known as a turboexpander) to drive an electric generator. The process requires that the fuel be pre-heated to prevent excessive cooling during expansion and by using waste provided by the DFC, emissions that would be created by combustion technologies are eliminated. The combination of the DFC and pressure energy recovery generation (ERG) leads to greater levels of efficiency, lower pollutant emissions and higher capacity factor.
This approach has been developed by Enbridge Inc, a leading North American energy transportation and distribution company, and FuelCell Energy, resulting in the DFC-ERG (Direct FuelCell – Energy Recovery Generation) system, which produces up to 10MW of utility-grade power generation, with an electricity efficiency of up to 65 per cent, negligible NO_x and SO_x emissions and dramatically reduced CO₂ output as compared to traditional fossil-fuelled power generation. The system, in some markets, can offer a lucrative revenue stream from the export of electrical power to the utility grid and the sale of renewable energy credits.

Figure 3: The DCF-ERG system: The generation of power generation
via natural gas decompression.

Conclusions

With few exceptions, the worldwide community of nations recognises the impact that pollution is having on the environment. As a result, will coal and other fossil fuel power plants eventually disappear? Not likely. Certainly, however, there will be a continuing effort to augment centralised power generation with renewable sources of energy and on-site distributed generation.
The benefits of on-site power include grid congestion relief, higher efficiency through reduced line losses and CHP, and emissions reductions through the use of ultra-clean technologies. While traditionally distributed generation has been viewed primarily as backup power, fuel cells offer the opportunity to produce baseload power 24/7 with negligible emissions and dramatic reductions in greenhouse gases. Fuel cell power plants are beginning to take centre-stage for distributed generation of baseload power in a variety of commercial, industrial and utility markets.

John Franceschina is vice president of business development for FuelCell Energy. He has more than 18 years of experience in the energy industry.

For more information about FuelCell Energy’s range of products, visit their website here.