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RIGZONE – Oil Firms Seen Cutting Exploration Spending

RIGZONE – Oil Firms Seen Cutting Exploration Spending.

by  Reuters
|Gwladys Fouche & Balazs Koranyi
|Monday, February 17, 2014
Article title
Global oil firms are about to cut exploration spending, pulling back from frontier areas and jeopardizing their future reserves, industry insiders say.

Reuters

OSLO, Feb 17 (Reuters) – Global oil firms, hit by one of the worst years for discovery in two decades, are about to cut exploration spending, pulling back from frontier areas and jeopardising their future reserves, industry insiders say.

Notable exploration failures in high-profile places such as Africa’s west coast, from Angola all the way up to Sierra Leone, have pushed down valuations for exploration-focused firms and are now forcing oil majors to change tack.

“It is becoming increasingly difficult to find new oil and gas, and in particular new oil,” says Tim Dodson, the exploration chief of Statoil, the world’s top conventional explorer last year.

“The discoveries tend to be somewhat smaller, more complex, more remote, so it is very difficult to see a reversal of that trend,” Dodson told Reuters. “The industry at large will probably struggle going forward with reserve replacement.”

Although final numbers are not yet available, Dodson said 2013 may have been the industry’s worst year for oil exploration since 1995.

As a result, exploration will probably be cut, especially in the newest areas, said Lysle Brinker, the director of energy equity research at consultancy firm IHS.

“They’ll be scaling back on some exploration, like the Arctic or the deepest waters with limited infrastructure … So places like the Gulf of Mexico and Brazil will continue to see a lot of activity, but frontier regions will see some scaling back,” he said.

Oil majors, which have a large resource base to maintain, are suffering the most, as the world is running out of very large conventional oil fields, and access to acreage, particularly in the Middle East, is limited.

That is leaving them with an increasing number of gas projects.

“When you look at the mix of oil and gas of the majors, it is definitely moving towards gas – simply because they can’t access conventional oil, which ultimately I believe will have an impact on oil prices,” said Ashley Heppenstall, the CEO of Sweden’s Lundin Petroleum, which co-discovered Johan Sverdrup, the biggest North Sea oil field in decades.

Prices Down Then Up

Before oil prices rise from a lack of exploration, they are first expected to fall, squeezing margins and forcing further investment cutbacks.

The International Energy Agency sees oil prices down at $102 per barrel next year from the current $108 as several producers ramp up output.

“Oil prices need to remain at elevated levels because there is a risk that a fall in oil prices or a cutback in investments by companies will mean that production growth slows,” said Virendra Chauhan, an oil analyst at consultancy Energy Aspects.

Although world oil reserves increased by 1 percent in 2012, they equalled just 52.9 years of global consumption, down from 54.2 in 2011, energy firm BP has said previously. BP sees consumption up by 19 million barrels a day by 2035, which would represent a 21 percent increase on th U.S. Energy Information Administration’s (EIA) estimate for 2011.

Energy firms have already been shifting capital from conventional to shale production, and this trend could continue as the exploration risk is smaller, the lag from investment to cash-flow is shorter, and project sizes are more manageable.

This is weighing negatively on the shares of exploration-focused companies.

“Explorer stocks are trading at discovery value or a discount to it, so from an equity market perspective, there’s no interest in owning exploration stories. People are losing faith in exploration,” said Anish Kapadia, a research analyst at consultancy Tudor, Pickering, Holt & Co. International.

Shares in Europe’s explorers fell 20 percent over the past year, underperforming a 2-percent rise by the European oil index .

Tullow is down 39 percent in a year, while peers Cairn and Cobalt are down 33 percent, and OGX is down 92 percent.

The spending cutback also cut mergers and acquisitions activity by half last year, IHS data showed, and plans to boost shareholder returns could shift focus to cooperation rather than fully fledged takeovers.

“You will probably see more activity at the asset level more than at the corporate level … More joint ventures, swapping assets, buying and selling of assets,’ said Jeremy Bentham, Shell’s vice-president for business environment.

Insiders believe the cuts may not be reversed until capital tied up in projects like Chevron’s $54 billion Gorgon LNG or Conoco’s $25 billion Australia Pacific LNG start producing cash flow and return.

“There will be less investor pressure, then companies can get activity back up, so this may be a pause of a couple of years where companies scale back,” Brinker said.

The Golden Age of Gas… Possibly: An Interview With The IEA | Zero Hedge

The Golden Age of Gas… Possibly: An Interview With The IEA | Zero Hedge.

Submitted by James Stafford via OilPrice.com,

The potential for a golden age of gas comes along with a big “if” regarding environmental and social impact. The International Energy Agency (IEA)—the “global energy authority”–believes that this age of gas can be golden, and that unconventional gas can be produced in an environmentally acceptable way.

In an exclusive interview with Oilprice.com, IEA Executive Director Maria van der Hoeven, discusses:

  • The potential for a golden age of gas
  • What will the “age” means for renewables
  • What it means for humanity
  • The challenges of renewable investment and technology
  • How the US shale boom is reshaping the global economy
  • Nuclear’s contribution to energy security
  • What is holding back Europe’s energy markets
  • The next big shale venues beyond 2020
  • The reality behind “fire ice”
  • Condensate and the crude export ban
  • The most critical energy issue facing the world today

Interview by. James Stafford of Oilprice.com

Oilprice.com: In 2011, the IEA predicted what it called “the golden age of gas,” with gas production rising 50% over the next 25 years. What does this “golden age” mean for coal, oil and nuclear energy—and for renewables? What does it mean for humanity in terms of carbon emissions? Is the natural gas boom lessening the sense of urgency to work towards renewable energy solutions?

IEA: We didn’t predict a golden age of gas in 2011, we merely asked a pertinent question: namely, are we entering a golden age of gas? And we found that the potential for such a golden age certainly exists, especially given the scale of unconventional gas resources and the advances in technology that allow their extraction. But the potential for a golden age of gas hinges on a big “if,” and we elaborated on this in 2012 in a report called “Golden Rules for a Golden Age of Gas”. Exploiting the world’s vast resources of unconventional natural gas holds the key to golden age of gas, we said, but for that to happen, governments, industry and other stakeholders must work together to address legitimate public concerns about the associated environmental and social impacts. Fortunately, we believe that unconventional gas can be produced in an environmentally acceptable way.

Under the central scenario of the World Energy Outlook-2013, natural gas production rises to 4.98 trillion cubic metres (tcm) in 2035, up nearly 50 percent from 3.38 tcm in 2011. But we have always said that a golden age of gas does not necessarily imply a golden age for humanity, or for our climate. An expansion of gas use alone is no panacea for climate change. While natural gas is the cleanest fossil fuel, it is still a fossil fuel. As we have seen in the United States, the drastic increase in shale gas production has caused coal’s share of electricity generation to slide. Of course, there is also the possibility that increased use of gas could muscle out low-carbon fuels, such as renewables and nuclear, from the energy mix.

OP: When will we see “the golden age of renewables”?

IEA: Although we have not yet predicted a “golden age” of renewables, the current, rapid growth of renewable power is a bright spot in an otherwise bleak picture of global progress towards a cleaner and more diversified energy mix. Still, the investment case for capital-intensive, low carbon power technologies carries challenges. We need to distinguish between two situations:

•    In emerging economies, renewable power often provides a cost-competitive alternative to new fossil based generation and are perceived as part of the solution to questions of energy supply, diversification, and economic development. In China, for example, efforts to reduce local pollution are stimulating major investments in cleaner energy.

•    By contrast, in stable systems with sluggish demand, no technology is competitive with marginal electricity prices, due to overcapacity. Governments are nervous about increasing investment in low-carbon options which impact on consumer prices, and this is causing policy uncertainty. But long term energy security and environmental goals need to be kept in mind.

The overall outlook for renewable electricity remains positive, even as the outlook can vary strongly by market and region. However, the electricity sector comprises less than 20% of total final energy consumption. The growth of renewables in other sectors such as transport and heat has been more sluggish. For a golden age of renewables to materialise, greater progress is needed in these areas, for example, with the development of advanced biofuels and more policy frameworks for renewable heat.

OP: How is the shale boom reshaping the global financial and economic system? Who are the winners and losers in this emerging scenario?

IEA: One of the key messages of our World Energy Outlook-2013 is that lower energy prices in the United States mean that it is well-placed to reap an economic advantage, while higher costs for energy-intensive industries in Europe and Japan are set to be a heavy burden.

Natural gas prices have fallen sharply in the United States – mainly as a result of the shale gas boom –  and today they are about three times lower than in Europe and five times lower than in Japan. Electricity price differentials are also large, with Japanese and European industrial consumers paying on average more than twice as much for electricity as their counterparts in the United States, and even Chinese industry paying  almost double the US level.

Looking to the future, the WEO found that the United States sees its share of global exports of energy-intensive goods slightly increase to 2035, providing the clearest indication of the link between relatively low energy prices and the industrial outlook. By contrast, the European Union and Japan see their share of global exports decline – a combined loss of around one-third of their current share.

OP: The IEA has noted that the US is no longer so dependent on Canadian oil and gas. What could this mean for pending approval of TransCanada’s Keystone XL pipeline? How important is Keystone XL to the US as opposed to its importance for Canada?

IEA: The decision on the Keystone matter is one that must be taken by the United States Government. I am afraid it is not for the IEA to comment.

OP: With the nuclear issue taking center stage in Japan’s election atmosphere, is Japan ready to pull the plug entirely on nuclear, or is it too soon for that?

IEA: This year’s World Energy Outlook, which we will release in November 2014, will carry a special focus on nuclear energy, so please stay tuned. While I won’t discuss what Japan should do, I will say that every country has a sovereign right to decide on the role of nuclear power in its energy mix. Nevertheless, nuclear is one of the world’s largest sources of low-carbon energy, and as such, it has made and should continue to make an important contribution to energy security and sustainability.

A country’s decision to cut the share of nuclear in its energy mix could open up new opportunities for renewables, particularly as some phase-out plans envision the replacement of nuclear capacity largely with renewable energy sources. However, such a decision would also likely lead to higher demand for gas and coal, higher electricity prices, increased import dependency on fossil fuels and electricity, and a more difficult path towards decarbonisation. Such a scenario would therefore make it much more difficult for the world to meet the 2°C climate stabilisation goal, and have potentially negative impacts on energy security.

OP: What is the key factor holding back European energy markets?

IEA: Europe has quite a few advantages but also many hurdles to overcome. If I had to pick one key factor that is holding back European energy markets, I would say it is the lack of cross-border interconnections. Let me explain what I mean. As we showed in WEO 2013, Europe’s competitiveness is under pressure, as energy price differences grow between Europe and its major trading partners – the US, China and Russia. High oil and gas import prices combined with low gas and electricity demand, following the recession, are impacting European economies.

Europe should accelerate the use of its indigenous potential and reap the social and economic benefits from energy efficiency, renewable energies and unconventional oil and gas. In open economies, there are significant advantages to be gained from free trade and a large energy market. One example: Today, we cannot make use of competitive electricity prices across the EU, as physical trade barriers exist and markets remain national. Europe is failing to achieve its potential. The electricity grid and system integration is very low, which also serves as a barrier to the full and efficient exploitation of renewable energy potentials. This is why addressing the issue of cross-border interconnections is so important.

OP: Where do you foresee the next “shale boom”?

IEA: According to WEO projections, there will be little non-North American shale development before 2020 due to the much earlier stage of exploration and the time needed to build up the oil field service value chain. Beyond 2020, we project large-scale shale gas production in China, Argentina, Australia as well as significant light tight oil production in Russia. The current reform proposals in Mexico have the potential to put Mexico on the top of that list as well, but they need to be properly implemented.

OP: What is the realistic future of methane hydrates, or “fire ice”?

IEA: Methane hydrates may offer a means of further increasing the supply of natural gas. However, producing gas from methane hydrates poses huge technological challenges, and the relevant extraction technology is in its infancy. Both in Canada and Japan the first test drillings have taken place, and the Japanese government is aiming to achieve commercial production in 10 to 15 years.

One thing I always mention when I am asked about methane hydrates is this: It may seem far off and uncertain, but keep in mind that shale gas was in the same position 10 to 15 years ago. So we cannot rule out that new energy revolutions may take place through technological developments and price incentives.

OP: Have we hit the “crude wall” in the US, the point at which oil production growth may end up slowing due to infrastructure and regulatory constraints?

IEA: In January 2013, the IEA’s Oil Market Report examined the possibility that as surging production continues to move the US closer to becoming a net oil exporter, there may come a time when various regulations, particularly the US ban on exports of crude oil to countries other than Canada, could have an adverse impact on continued investment in LTO – and thus continued growth in production. We called this point the “crude wall”.

A year later, in our January 2014 Oil Market Report, we noted that with US crude oil production exceeding even the boldest of expectations in 2013 by a wide margin, the crude wall now seems to be looming larger than ever. Having said that, challenges to US production growth are not imminent. Potential US growth in 2014 seems a given, even against the backdrop of resurgent non-OPEC supply growth outside North America.

OP: How is this shaping the crude export debate and where do you foresee this debate leading by the end of this year?

IEA: You are better off asking my friends and colleagues in Washington! This is obviously a sensitive topic. Different people feel differently about it, often very strongly. Oil policy always is the product of multiple, sometimes-competing considerations.

OP: What would lifting the ban on crude exports mean for US refiners, and for the US economy?

IEA: Many refiners and other major oil consumers have said they support keeping the ban amid worries that allowing exports would result in higher feedstock costs and erode their competitive advantage, or shift value-added industry abroad. On the other hand, oil producers have in general come out in favour of lifting the ban, arguing that the “crude wall” may become so large that it cannot be overcome; they see the possibility of a glut causing prices to slump and thereby choking off production. We have not produced any detailed analysis on the economic impact of lifting the ban, so I cannot comment on that part of your question.

OP: Are there any other ways around the “crude wall” aside from lifting the export ban?

IEA: As we wrote in our January 2014 Oil Market Report, much of the LTO is produced in the form of lease condensate, which is most optimally processed in a condensate splitter. There is currently only one such facility in the United States, although at least five others are in various stages of planning and construction.

I mention this issue because one could imagine a scenario under which lease condensate is excluded from the crude export restriction. The US Department of Commerce, which enforces the export ban, includes lease condensates in the definition of crude oil. However, this definition could be changed, or the Commerce Department could simply issue lease condensate export licenses at the behest of the President.

OP: How will the six-month agreement to ease sanctions on Iran affect Iranian oil production? And if international sanctions are indeed lifted after this “trial period”, how long will it take Iran to affect a real increase in production?

IEA: The deal between P5+1 and Iran doesn’t change the oil sanctions themselves. The oil sanctions remain fully in place though the P5+1 agreed not to tighten them further. Relaxing insurance sanctions doesn’t mean more oil in the market.

As for the second part of your question, I am afraid I can’t answer hypotheticals and what-ifs.

OP: What is the single most critical energy issue in the US this year?

IEA: I think that if you take the view that the energy-policy decisions you make now have ramifications for many decades to come, and if you believe what scientists tell us about the climate consequences of our energy consumption, then the single most critical energy issue in the US is the same issue for every country: what are you going to do with your energy policy to mitigate the risk of climate change? Energy is responsible for two-thirds of greenhouse-gas emissions, and right now these emissions are on track to cause global temperatures to rise between 3.6 degrees C and 5.3 degrees C. If we stay on our present emissions pathway, we are not going to come close to achieving the globally agreed target of limiting the rise in temperatures to 2 degrees C; we are instead going to have a catastrophe. So energy clearly has to be part of the climate solution – both in the short- and long-term.

OP: What is the IEA’s role in shaping critical energy issues globally and how can its influence be described, politically and intellectually?

IEA: Founded in response to the 1973/4 oil crisis, the IEA was initially meant to help countries co-ordinate a collective response to major disruptions in oil supply through the release of emergency oil stocks to the markets.

While this continues to be a key aspect of our work, the IEA has evolved and expanded over the last 40 years. I like to think of the IEA today as the global energy authority. We are at the heart of global dialogue on energy, providing authoritative statistics, analysis and recommendations. This applies both to our member countries as well as to the key emerging economies that are driving most of the growth in energy demand – and with whom we cooperate on an increasingly active basis.

Why turning a buck isn’t easy anymore for oil’s biggest players | Jeff Rubin

Why turning a buck isn’t easy anymore for oil’s biggest players | Jeff Rubin.

Posted by Jeff Rubin on January 27th, 2014

Judging by pump prices, Canadian drivers might think oil companies were rolling in profits that only move higher. Lately, though, the big boys in the global oil industry are finding that earning a buck isn’t as easy as it used to be.

Royal Dutch Shell, for instance, just announced that fourth quarter earnings would fall woefully short of expectations. The Anglo-Dutch energy giant warned its quarterly profits will be down 70 percent from a year earlier. Full year earnings, meanwhile, are expected to be a little more than half of what they were the previous year.

The news hasn’t been much cheerier for Shell’s fellow Big Oil stalwarts. Exxon, the world’s largest publicly traded oil company, saw profits fall by more than 50 percent in the second quarter to their lowest level in more than three years. Chevron and Total, likewise, are warning the market to expect lower earnings when fourth quarter results are released.

What makes such poor performance especially disconcerting to investors is that it’s taking place within the context of historically high oil prices. The price of Brent crude has been trading in the triple digit range for three years running, while WTI hasn’t been far off. But even with the aid of high oil prices, the supermajors haven’t offered investors any returns to write home about. Since 2009, the share prices of the world’s top five publicly traded oil and gas companies have posted less than a fifth of the gains of the Dow Jones Industrial Average.

The reason for such stagnant market performance comes down to the cost of both discovering new oil reserves and getting it out of the ground. According to the International Energy Agency’s 2013 World Energy Outlook, global exploration spending has increased by 180 percent since 2000, while global oil supplies have risen by only 14 percent. That’s a pretty low batting average.

Shell’s quest for new reserves has seen it pump billions into money-devouring plays such as its Athabasca Oil Sands Project in northern Alberta and the Kashagan oilfield, a deeply troubled project in Kazakhstan. It’s even tried deep water drilling in the high Arctic. That attempt ended when the stormy waters of the Chukchi Sea crippled its Kulluk drilling platform, forcing the company to pull up stakes.

Investors can’t simply count on ever rising oil prices to justify Shell’s lavish spending on quixotic drilling adventures around the world. Prices are no longer soaring ahead like they were prior to the last recession, when heady global economic growth was pushing energy prices to record highs.

Costs, however, are another matter. As exploration spending spirals higher, investors are seeing more reasons to lighten up on oil stocks. Wherever oil producers go in the world these days, they’re running into costs that are reaching all-time highs. Shell’s costs to find and develop oil fields, for instance, have tripled since 2003. What’s worse, when the company does notch a significant discovery, such as Kashagan, production seems to be delayed, whether due to the tricky nature of the geology, politics, or both.

Shell ramped up capital spending last year by 50 percent to a staggering $44 billion. Oil analysts are basically unanimous now in saying the company needs to rein in spending if it hopes to provide better returns to shareholders.

Big Oil is discovering that blindly chasing production growth through developing ever more costly reserves isn’t contributing to the bottom line. Maybe that’s a message Canada’s oil sands producers need to be listening to as well.

Australian Report Trumpeted By Coal Bosses Does Not Say What They Want You To Think It Says | DeSmogBlog

Australian Report Trumpeted By Coal Bosses Does Not Say What They Want You To Think It Says | DeSmogBlog.

WHAT follows are some thoughts about coal from a report just published in Australia.

A longer-term concern relates to the environmental impacts of large-scale coal use, especially its climate consequences….

Coal is a carbon-intensive fuel and the environmental consequences of its use can be significant, especially if it is used inefficiently and without effective emissions and waste control technologies. Such environmental consequences include emissions of pollutants such as sulphur and nitrogen oxides, particulates, mercury, and carbon dioxide, the main greenhouse gas. Indeed coal-sourced pollution remains the largest source of greenhouse gas emissions from fossil fuel combustion. Hence most forecasts show a very wide range of future coal demand, based on differing degrees of environmental policy implementation.

Now who might have written that?  An environmental campaigner?  An anti-coal activist in a less bombastic mood? Maybe they’re the words of an advocate for action on climate change?

Actually, these are the views of Ian Cronshaw, a long-standing advisor to the International Energy Agency who was commissioned by the Energy Policy Institute of Australia to write a report about coal and its future economic outlook.

The Energy Policy Institute of Australia’s board includes a number of figures who have spent their careers in and around the fossil fuel industry.

The paper, The Current and Future Importance of Coal in the World Energy Economy, consists of just three pages, as well as a header page and a biography page at the back.

Most of the contents are drawn from the various reports put out by the International Energy Agency.

So how was this pamphlet greeted by Australia’s coal industry?  The only media report of note came from The Australian newspaper, which ran the headline: “Coal will ‘dominate global power sector for decades‘” on its front page.

Here are the first two lines of that story, to give you a flavor.

COAL will dominate the power sector globally for decades to come, according to a paper that miners say undermines campaigns by green activists to “demonise” coal.

The paper – written by an International Energy Agency consultant and to be sent to Industry Minister Ian Macfarlane – says coal will remain the dominant power-sector fuel for at least the next quarter of a century despite efforts to diversify power sources and concerns about slower economic growth.

The report in The Australian does not mention Cronshaw’s observations about coal and climate change.

In fact, the words climate change or global warming don’t appear anywhere in the story, even though it takes up almost a third of the three pages of Cronshaw’s analysis. The Australian also chose to quote two coal industry representatives, who took the report’s publication as an opportunity to criticise environmental campaigners.

Graham Bradley, who amongst other things is the chairman of the advisory board for coal company Anglo American Australian, was reported as saying:

Much of the green polemic is not grounded in the fundamental reality that the world needs the lowest-cost energy and at the end of the day the economics will prevail and investment will follow.

Brendan Pearson, chief executive of the industry lobbyists the Minerals Council of Australia which recently subsumed the lobbying work of the Australian Coal Association, said:

Activist campaigns seeking to demonise Australian coal fail to acknowledge that it will be the principal global energy source for decades – transforming economies and helping eliminate poverty.

Both commentators also touted how the report predicted a rosy future for the coal industry in long term. The report does do this, but with a number of large caveats. It is far from the slam dunk which the media report and the quotes might have you believe. For example, there’s this from the Cronshaw report:

The current economic outlook remains very clouded, with many regions either stagnant or seeing slower economic growth. This will naturally impact heavily on global power use and coal consumption. However, most forecasters remain confident that, over the longer term, energy demand growth in non-OECD countries, the key determinant of coal demand growth, will be strong.

The report does map out the strong growth in the use of coal in non-OECD countries, including India and China, and predicts this is where much of the future demand will come from.

In two sentences, the report also points out the benefits of electricity — which, remember, can and is generated from renewable sources as well as polluting coal. The report says:

Such access to electricity is crucial to economic growth; it means food can be stored in refrigerators, children can do their homework, small businesses can function. And overwhelmingly, this electricity has come from coal.

Cronshaw also makes it clear that under the policies currently in place, coal has a strong future. But this is precisely why climate change campaigners are pushing back hard on the mining and the use of coal, because they see these policies as being far too weak.

One analysis of current climate pledges by governments around the world, released during the recent Warsaw UN climate talks, suggested that pledges on the table will currently deliver about 4C of global warming by the end of the century — a gaping chasm between stated ambitions and reality.

Cronshaw again:

It is worth observing that the IEA’s Current Policies Scenario, essentially a business as usual scenario, has global levels of coal demand more than 20% above the central scenario, in which a range of climate policies are cautiously implemented. The power sector is clearly the key coal market, but this sector must also be the focus of any successful climate change mitigation efforts.

That last line is worth reading twice. The coal sector “must also be the focus of any successful climate change mitigation efforts.”

Cronshaw also says the industry could make early gains in cuts in emissions by improving efficiency, but says that, “In reality, the penetration of the most efficient coal-fired power generation technologies is constrained by technical considerations, additional costs and the absence of a global price on carbon.”

The Australian government is in the process of trying to repeal the country’s carbon price, which would have linked to the European emissions trading scheme.

But again, Cronshaw is clear that coal’s future does depend on environmental policy down the line.

Environmental policy will play a decisive role in future coal consumption. In some countries, coal use may be encouraged for economic, social or energy security reasons. If action were taken to provide electricity access by 2030 to the 1.3 billion people in the world without it today (almost all in non-OECD countries), coal could be expected to account for more than half of the fuel required to provide additional on-grid connections. In other countries, policies may encourage switching away from coal to more environmentally benign or lower carbon sources. While a global agreement on carbon pricing has been elusive, a growing number of countries are taking steps to put a price on carbon emissions, including in China where there are several pilot schemes underway, although current pricing levels seen for example in Europe, are too low to materially affect energy choices.

When Graham Bradley from Anglo American Australia says “at the end of the day the economics will prevail and investment will follow” he seems to be ignoring the view expressed in the report which he lauds, which says that in fact, “Environmental policy will play a decisive role in future coal consumption.”

The paper also has a few words to say about so-called “clean coal” technologies – known as Carbon Capture and Storage.  The paper points out that while some progress has been made “CCS has yet to be demonstrated on a large scale in an integrated fashion in the power and industrial sectors, and so costs remain uncertain.”

Cronshaw adds that:

The success of governments globally in encouraging greater energy diversity, improved efficiency, and the development and deployment of clean coal technologies will have a profound bearing on the role of coal in the longer term.

This is an interesting observation, given that both the former and current Australian governments have continued to slash hundreds of millions of dollars from CCS programs.

Despite what you might read in The Australian or through the mouths of vested interests, the future of coal is far from certain.

Just ask the president of the World Bank, Jim Yong Kim, who earlier this weekencouraged governments and institutional investors to take their money out of fossil fuels. Or maybe try one group of philanthropists with $1.8 billion in their coffers, who also this week pledged to divest from fossil fuels.

Or how about the US Export-Import Bank – a government institution that approved more than $35 billion in investments in 2012 – which has said it won’t invest in coal projects abroad unless they are fitted with CCS (which as yet, doesn’t really exist commercially).

Clearly coal will continue to be burned for energy, but as even this report the industry cites explains, emissions need to come down, environmental policies will dictate how quickly and that carbon pricing will drive early efficiency gains.

You can of course see this report two ways, depending upon which side you butter your bread. One way is that the report shows how the current suite of policies to cut greenhouse gas emissions are either too few or are not up to the job — probably both.

Another option is to use the three-page pamphlet as a way to instill confidence in potential investors in coal and to convince politicians that it’s an industry worth supporting.

That second group of people just have to hope that policymakers either fail to actually read the report, or don’t take the risks of climate change anywhere near seriously enough.

Peak Oil Is Dead | Michael T. Klare

Peak Oil Is Dead | Michael T. Klare.

Long Live Peak Oil!

Cross-posted with TomDispatch.com

Among the big energy stories of 2013, “peak oil” — the once-popular notion that worldwide oil production would soon reach a maximum level and begin an irreversible decline — was thoroughly discredited.  The explosive development of shale oil and other unconventional fuels in the United States helped put it in its grave.

As the year went on, the eulogies came in fast and furious. “Today, it is probably safe to say we have slayed ‘peak oil’ once and for all, thanks to the combination of new shale oil and gas production techniques,” declared Rob Wile, an energy and economics reporter for Business Insider.  Similar comments from energy experts were commonplace, prompting an R.I.P. headline at Time.com announcing, “Peak Oil is Dead.”

Not so fast, though.  The present round of eulogies brings to mind the Mark Twain’s famous line: “The reports of my death have been greatly exaggerated.”  Before obits for peak oil theory pile up too high, let’s take a careful look at these assertions.  Fortunately, theInternational Energy Agency (IEA), the Paris-based research arm of the major industrialized powers, recently did just that — and the results were unexpected.  While not exactly reinstalling peak oil on its throne, it did make clear that much of the talk of a perpetual gusher of American shale oil is greatly exaggerated.  The exploitation of those shale reserves may delay the onset of peak oil for a year or so, the agency’s experts noted, but the long-term picture “has not changed much with the arrival of [shale oil].”

The IEA’s take on this subject is especially noteworthy because its assertion only a year earlier that the U.S. would overtake Saudi Arabia as the world’s number one oil producer sparked the “peak oil is dead” deluge in the first place.  Writing in the 2012 edition of itsWorld Energy Outlook, the agency claimed not only that “the United States is projected to become the largest global oil producer” by around 2020, but also that with U.S. shale production and Canadian tar sands coming online, “North America becomes a net oil exporter around 2030.”

That November 2012 report highlighted the use of advanced production technologies — notably horizontal drilling and hydraulic fracturing (“fracking”) — to extract oil and natural gas from once inaccessible rock, especially shale.  It also covered the accelerating exploitation of Canada’s bitumen (tar sands or oil sands), another resource previously considered too forbidding to be economical to develop.  With the output of these and other“unconventional” fuels set to explode in the years ahead, the report then suggested, the long awaited peak of world oil production could be pushed far into the future.

The release of the 2012 edition of World Energy Outlook triggered a global frenzy of speculative reporting, much of it announcing a new era of American energy abundance. “Saudi America” was the headline over one such hosanna in the Wall Street Journal.  Citing the new IEA study, that paper heralded a coming “U.S. energy boom” driven by “technological innovation and risk-taking funded by private capital.”  From then on, American energy analysts spoke rapturously of the capabilities of a set of new extractive technologies, especially fracking, to unlock oil and natural gas from hitherto inaccessible shale formations.  “This is a real energy revolution,” the Journal crowed.

But that was then. The most recent edition of World Energy Outlook, published this past November, was a lot more circumspect.  Yes, shale oil, tar sands, and other unconventional fuels will add to global supplies in the years ahead, and, yes, technology will help prolong the life of petroleum.  Nonetheless, it’s easy to forget that we are also witnessing the wholesale depletion of the world’s existing oil fields and so all these increases in shale output must be balanced against declines in conventional production.  Under ideal circumstances — high levels of investment, continuing technological progress, adequate demand and prices — it might be possible to avert an imminent peak in worldwide production, but as the latest IEA report makes clear, there is no guarantee whatsoever that this will occur.

Inching Toward the Peak

Before plunging deeper into the IEA’s assessment, let’s take a quick look at peak oil theory itself.

As developed in the 1950s by petroleum geologist M. King Hubbert, peak oil theory holdsthat any individual oil field (or oil-producing country) will experience a high rate of production growth during initial development, when drills are first inserted into a oil-bearing reservoir.  Later, growth will slow, as the most readily accessible resources have been drained and a greater reliance has to be placed on less productive deposits.  At this point — usually when about half the resources in the reservoir (or country) have been extracted — daily output reaches a maximum, or “peak,” level and then begins to subside.  Of course, the field or fields will continue to produce even after peaking, but ever more effort and expense will be required to extract what remains.  Eventually, the cost of production will exceed the proceeds from sales, and extraction will be terminated.

For Hubbert and his followers, the rise and decline of oil fields is an inevitable consequence of natural forces: oil exists in pressurized underground reservoirs and so will be forced up to the surface when a drill is inserted into the ground.  However, once a significant share of the resources in that reservoir has been extracted, the field’s pressure will drop and artificial means — water, gas, or chemical insertion — will be needed to restore pressure and sustain production.  Sooner or later, such means become prohibitively expensive.

Peak oil theory also holds that what is true of an individual field or set of fields is true of the world as a whole.  Until about 2005, it did indeed appear that the globe was edging ever closer to a peak in daily oil output, as Hubbert’s followers had long predicted.  (He died in 1989.)  Several recent developments have, however, raised questions about the accuracy of the theory.  In particular, major private oil companies have taken to employing advanced technologies to increase the output of the reservoirs under their control, extending the lifetime of existing fields through the use of what’s called “enhanced oil recovery,” or EOR.  They’ve also used new methods to exploit fields once considered inaccessible in places like the Arctic and deep oceanic waters, thereby opening up the possibility of a most un-Hubbertian future.

In developing these new technologies, the privately owned “international oil companies” (IOCs) were seeking to overcome their principal handicap: most of the world’s “easy oil” — the stuff Hubbert focused on that comes gushing out of the ground whenever a drill is inserted — has already been consumed or is controlled by state-owned “national oil companies” (NOCs), including Saudi Aramco, the National Iranian Oil Company, and the Kuwait National Petroleum Company, among others.  According to the IEA, such state companies control about 80 percent of the world’s known petroleum reserves, leaving relatively little for the IOCs to exploit.

To increase output from the limited reserves still under their control — mostly located in North America, the Arctic, and adjacent waters — the private firms have been working hard to develop techniques to exploit “tough oil.”  In this, they have largely succeeded: they are now bringing new petroleum streams into the marketplace and, in doing so, have shaken the foundations of peak oil theory.

Those who say that “peak oil is dead” cite just this combination of factors.  By extending the lifetime of existing fields through EOR and adding entire new sources of oil, the global supply can be expanded indefinitely.  As a result, they claim, the world possesses a “relatively boundless supply” of oil (and natural gas).  This, for instance, was the way Barry Smitherman of the Texas Railroad Commission (which regulates that state’s oil industry)described the global situation at a recent meeting of the Society of Exploration Geophysicists.

Peak Technology

In place of peak oil, then, we have a new theory that as yet has no name but might be called techno-dynamism.  There is, this theory holds, no physical limit to the global supply of oil so long as the energy industry is prepared to, and allowed to, apply its technological wizardry to the task of finding and producing more of it.  Daniel Yergin, author of the industry classics, The Prize and The Quest, is a key proponent of this theory.  He recently summed upthe situation this way: “Advances in technology take resources that were not physically accessible and turn them into recoverable reserves.”  As a result, he added, “estimates of the total global stock of oil keep growing.”

From this perspective, the world supply of petroleum is essentially boundless.  In addition to “conventional” oil — the sort that comes gushing out of the ground — the IEA identifies six other potential streams of petroleum liquids: natural gas liquids; tar sands and extra-heavy oil; kerogen oil (petroleum solids derived from shale that must be melted to become usable); shale oil; coal-to-liquids (CTL); and gas-to-liquids (GTL).  Together, these “unconventional” streams could theoretically add several trillion barrels of potentially recoverable petroleum to the global supply, conceivably extending the Oil Age hundreds of years into the future (and in the process, via climate change, turning the planet into an uninhabitable desert).

But just as peak oil had serious limitations, so, too, does techno-dynamism.  At its core is a belief that rising world oil demand will continue to drive the increasingly costly investments in new technologies required to exploit the remaining hard-to-get petroleum resources.  As suggested in the 2013 edition of the IEA’s World Energy Outlook, however, this belief should be treated with considerable skepticism.

Among the principal challenges to the theory are these:

1. Increasing Technology Costs: While the costs of developing a resource normally decline over time as industry gains experience with the technologies involved, Hubbert’s law of depletion doesn’t go away.  In other words, oil firms invariably develop the easiest “tough oil” resources first, leaving the toughest (and most costly) for later.  For example, the exploitation of Canada’s tar sands began with the strip-mining of deposits close to the surface.  Because those are becoming exhausted, however, energy firms are now going after deep-underground reserves using far costlier technologies.  Likewise, many of the most abundant shale oil deposits in North Dakota have now been depleted, requiring anincreasing pace of drilling to maintain production levels.  As a result, the IEA reports, the cost of developing new petroleum resources will continually increase: up to $80 per barrel for oil obtained using advanced EOR techniques, $90 per barrel for tar sands and extra-heavy oil, $100 or more for kerogen and Arctic oil, and $110 for CTL and GTL.  The market may not, however, be able to sustain levels this high, putting such investments in doubt.

2. Growing Political and Environmental Risk: By definition, tough oil reserves are located in problematic areas.  For example, an estimated 13 percent of the world’s undiscovered oil lies in the Arctic, along with 30 percent of its untapped natural gas.  The environmental risks associated with their exploitation under the worst of weather conditions imaginable will quickly become more evident — and so, faced with the rising potential for catastrophic spills in a melting Arctic, expect a commensurate increase in political opposition to such drilling.  In fact, a recent increase has sparked protests in both Alaska and Russia, including the much-publicized September 2013 attempt by activists from Greenpeace toscale a Russian offshore oil platform — an action that led to their seizure and arrest by Russian commandos.  Similarly, expanded fracking operations have provoked a steady increase in anti-fracking activism.  In response to such protests and other factors, oil firms are being forced to adopt increasingly stringent environmental protections, pumping up the cost of production further.

3. Climate-Related Demand Reduction: The techno-optimist outlook assumes that oil demand will keep rising, prompting investors to provide the added funds needed to develop the technologies required.  However, as the effects of rampant climate change accelerate, more and more polities are likely to try to impose curbs of one sort or another on oil consumption, suppressing demand — and so discouraging investment.  This is already happening in the United States, where mandated increases in vehicle fuel-efficiency standards are expected to significantly reduce oil consumption.  Future “demand destruction” of this sort is bound to impose a downward pressure on oil prices, diminishing the inclination of investors to finance costly new development projects.

Combine these three factors, and it is possible to conceive of a “technology peak” not unlike the peak in oil output originally envisioned by M. King Hubbert.  Such a techno-peak is likely to occur when the “easy” sources of “tough” oil have been depleted, opponents of fracking and other objectionable forms of production have imposed strict (and costly) environmental regulations on drilling operations, and global demand has dropped below a level sufficient to justify investment in costly extractive operations.  At that point, global oil production will decline even if supplies are “boundless” and technology is still capable of unlocking more oil every year.

Peak Oil Reconsidered

Peak oil theory, as originally conceived by Hubbert and his followers, was largely governed by natural forces.  As we have seen, however, these can be overpowered by the application of increasingly sophisticated technology.  Reservoirs of energy once considered inaccessible can be brought into production, and others once deemed exhausted can be returned to production; rather than being finite, the world’s petroleum base now appears virtually inexhaustible.

Does this mean that global oil output will continue rising, year after year, without ever reaching a peak?  That appears unlikely.  What seems far more probable is that we will see a slow tapering of output over the next decade or two as costs of production rise and climate change — along with opposition to the path chosen by the energy giants — gains momentum.  Eventually, the forces tending to reduce supply will overpower those favoring higher output, and a peak in production will indeed result, even if not due to natural forces alone.

Such an outcome is, in fact, envisioned in one of three possible energy scenarios the IEA’s mainstream experts lay out in the latest edition of World Energy Outlook. The first assumes no change in government policies over the next 25 years and sees world oil supply rising from 87 to 110 million barrels per day by 2035; the second assumes some effort to curb carbon emissions and so projects output reaching “only” 101 million barrels per day by the end of the survey period.

It’s the third trajectory, the “450 Scenario,” that should raise eyebrows.  It assumes that momentum develops for a global drive to keep greenhouse gas emissions below 450 parts per million — the maximum level at which it might be possible to prevent global average temperatures from rising above 2 degrees Celsius (and so cause catastrophic climate effects).  As a result, it foresees a peak in global oil output occurring around 2020 at about 91 million barrels per day, with a decline to 78 million barrels by 2035.

It would be premature to suggest that the “450 Scenario” will be the immediate roadmap for humanity, since it’s clear enough that, for the moment, we are on a highway to hell that combines the IEA’s first two scenarios.  Bear in mind, moreover, that many scientists believea global temperature increase of even 2 degrees Celsius would be enough to produce catastrophic climate effects.  But as the effects of climate change become more pronounced in our lives, count on one thing: the clamor for government action will grow more intense, and so eventually we’re likely to see some variation of the 450 Scenario take shape.  In the process, the world’s demand for oil will be sharply constricted, eliminating the incentive to invest in costly new production schemes.

The bottom line: Global peak oil remains in our future, even if not purely for the reasons given by Hubbert and his followers.  With the gradual disappearance of “easy” oil, the major private firms are being forced to exploit increasingly tough, hard-to-reach reserves, thereby driving up the cost of production and potentially discouraging new investment at a time when climate change and environmental activism are on the rise.

Peak oil is dead!  Long live peak oil!

Michael T. Klare, a TomDispatch regular, is a professor of peace and world security studies at Hampshire College and the author, most recently, of The Race for What’s Left.  A documentary movie version of his book Blood and Oil is available from the Media Education Foundation.

EIA International Energy Statistics for August and September » Peak Oil BarrelPeak Oil Barrel

EIA International Energy Statistics for August and September » Peak Oil BarrelPeak Oil Barrel.

The EIA has finally published its International Energy Statistics. The last one had July data. This one is has two months updates, August and September. All the data I publish comes is Crude+Condensate from January 2000 through September 2013.

Again, all data is C+C in thousand barrels per day with the last data point September 2013.

World

As you can see from the chart World C+C production has leveled out in the last year and one half. September 2013 is slightly lower than February 2012.

There were a couple of major revisions in the July data. Canada was revised down by 269 kb/d while Non-OPEC was revised down by 228 kb/d. There were other small revisions upward. OPEC C+C had no revisions so that left World C+C for July revised down by 228 kb/d.

Both the USA and Canada are on a real tear, owing of course to Light Tight Oil and the Oil Sands. Their combined production is up about 1.9 mb/d since in one year, since last September.

USA + Canada

But they are the only ones on a tear. Almost everyone else is flat to down with a few small producers up slightly.

World Les US & Canada

World less USA and Canada is actually below where it was in June 2004 and is swiftly approaching the bottom it hit after the crash of 2008. The peak was in January 11 and they are down 2.65 mb/d since that point.

Actually only Light Tight Oil is keeping the world from declaring peak.

World Less USA

World less USA is down over 1.5 mb/d since the peak of January 2011.

Non-OPEC is up on the strength of the USA and Canada.

Non-OPEC

However the EIA has OPEC C+C down considerably.

OPEC C+C

Charts of all Non-OPEC producers are now up on the Non-OPEC Chartspage.

Also a new page has been added, World Crude Oil Production by Geographical Area

Fears of global oil crisis aired at Transatlantic Energy Security Dialogue. : Jeremy Leggett’s Triple Crunch Log

Fears of global oil crisis aired at Transatlantic Energy Security Dialogue. : Jeremy Leggett’s Triple Crunch Log.

Jeremy Leggett column in Recharge magazine: “We are betting our entire national economic life on the hope — indeed the expectation — that the fracking boom will continue until well into the 2020s, and that, at a rate and cost we desire, significant amounts of ‘yet to be discovered’ oil will somehow be found to meet the demand.”
“If any of that proves incorrect, we have no plan, no alternative, and have given no thought to how we would respond in such a case.”The speaker is national-security expert Lieutenant Colonel Daniel Davis, a veteran of four tours of duty with the US Army in Iraq and Afghanistan. I am not a military man, but I worry just as much about the energy security of my own country as he does about his. In the UK, the government, the civil service and most of the big energy companies seem perfectly content to replicate the grand gamble under way in the US.
On 10 December, Lt Col Davis and I convened video-linked gatherings in Washington and London of people who share our concerns about the risk of a global oil crisis. We also invited key people who don’t, but who were interested in probing beyond the propaganda that energy-policy discourse seems to attract these days. [Two powerpoints, and Agenda  / Participants / Transcript of first half are appended below.]
Those joining us included retired military officers, security experts, senior executives from a wide spectrum of industry and politicians of all the main parties, including two former UK ministers.
We began with a presentation by Mark Lewis, a former head of energy research at Deutsche Bank. With this background, you might expect Lewis to be a disciple of the conventional narrative of plenty in oil markets. Many of his peers are. But he suggested that three big warning signs in the oil industry point to a counter-narrative of impending problems for supply: high decline rates, soaring capital expenditure and falling exports.
The decline rates of all conventional crude-oil fields producing today are spectacular; the International Energy Agency projects output falling from 69 million barrels per day (bpd) today to just 28 million bpd in 2035. Current total global production of all types of oil is some 91 million bpd.
Consider the spending needed to try to fill that gap.
Capex for oilfield development and exploration has nearly trebled in real terms since 2000: from $250bn to $700bn in 2012. The industry is spending ever more to prop up production, and its profitability is reflecting this trend, notwithstanding an enduringly high oil price. Meanwhile, consumption is soaring in Opec nations. As a result, global crude-oil exports have been declining since 2005. It is difficult to conflate this data and not see an oil crunch ahead, Lewis concludes.
What of the recent addition of two million bpd of new oil production from American shale: the boom that has even been cast as a “game-changer” and a route to “Saudi America” by industry cheerleaders?
Geological Survey of Canada veteran David Hughes, who has conducted the most detailed analysis of North American shale of anyone outside the oil and gas companies, offered some sobering views on this. His data shows that spectacularly high early decline rates in existing shale gas and shale oil (more correctly known as tight oil) wells means high levels of drilling are needed just to maintain production. This problem is compounded because “sweet spots” become exhausted early in field development.
As a result, shale-gas production is already dropping in several key drilling regions, and production of tight oil in the top two regions is likely to peak as early as 2016 or 2017. These two regions, in Texas and North Dakota, comprise 74% of total US tight-oil production.
Like Lewis, Hughes believes that the oil and gas industry is leading the world by the nose towards an energy crisis.
In my book The Energy of Nations, I describe how military think-tanks have tended to side with those, like Lewis and Hughes, who distrust the cornucopian narrative of the oil incumbency. One 2008 study, by the German army, puts it thus: “Psychological barriers cause indisputable facts to be blanked out and lead to almost instinctively refusing to look into this difficult subject in detail. Peak oil, however, is unavoidable.”
This blanking-out extends to the mainstream media, which has enthusiastically echoed the mantras of the oil companies, to the extent that the very words “peak oil” have been positioned as a badge of baseless scaremongering.
We should never forget that in the run-up to the credit crunch, the financial incumbency deployed exactly the same PR tactics against those warning about the fragility of mortgage-backed securities.

Transatlantic Energy Security Dialogue: Agenda, Participants, Part One discussion edited transcript

The Three Witches: Decline rates, soaring capex, and falling exports. Presentation by Mark Lewis.

The “Shale Revolution”: Myths and Realities. Presentation by David Hughes.

The Man Who Predicted the Future for BP Says Peak Oil Is Nigh | Motherboard

The Man Who Predicted the Future for BP Says Peak Oil Is Nigh | Motherboard.

By Brian Merchant

One of the more famous portraits of peak oil. Image: Wikimedia

In a year that saw the United States reach near-historic levels of fossil fuel production, it seemed that the words ‘peak oil’ were scarcely uttered. But it’s still a looming question, that we have yet to satisfactorily answer—when are we going to run out of oil? Have we already started to? A renowned geologist, and a former top analyst for BP no less, says the answer is yes.

“We are probably in peak oil today, or at least in the foot-hills,” Dr. Richard Miller said recently at a talk in London. According to the Guardian, Miller “prepared BP’s in-house projections of future oil supply for BP from 2000 to 2007,” and is bringing peak oil back into focus at the end of a petroleum-soaked year. He says that oil production has already peaked in 37 oil-producing countries, and that global production is declining at about 3.5 million barrels every year. Continued reliance on oil, and the coming shortage, will do nothing less than “break economies.”

Per the Guardian

“We need new production equal to a new Saudi Arabia every 3 to 4 years to maintain and grow supply… New discoveries have not matched consumption since 1986. We are drawing down on our reserves, even though reserves are apparently climbing every year. Reserves are growing due to better technology in old fields, raising the amount we can recover– but production is still falling at 4.1% p.a. [per annum].”

Bottom line being, oil companies and governments are jazzed on new technologies and extraction techniques like fracking and tar sands—Exxon and co are running shiny ads touting domestic energy production—but none of that changes the fact that oil is running out. We’re getting better at scraping the bottom of the barrel, but you can only get so much.

“Production of conventional liquid oil has been flat since 2008,” Miller said. “Growth in liquid supply since then has been largely of natural gas liquids [NGL]—ethane, propane, butane, pentane—and oil-sand bitumen.”

Add Miller’s warnings to a long list of geologists, economists, and environmentalists who say we’re outrunning our dependence on the black gold. In 2008, the Germany-based Energy Watch Group proclaimed “peak oil is now.” In 2005, a group of respected geologists and physicists started the Oil Drum, and warned that demand had begun to outpace production. Their prognosis was repeatedly vindicated.

In 2009, the UK Energy Research Centre concluded that “A global peak is inevitable. The timing is uncertain, but the window is rapidly narrowing.” And even the US Department of Defenseforecast a shortage of oil as soon as 2015.

Which is to say, Miller finds himself in some pretty sterling company, and in a year where the nation had fossil fuels on the brain, his cautions are especially worth considering.

 

Will US Light Tight Oil Save The World? » Peak Oil BarrelPeak Oil Barrel

Will US Light Tight Oil Save The World? » Peak Oil BarrelPeak Oil Barrel.

There has been plenty of hoopla lately concerning the boom in shale (LTO) oil production. From the New York Times: Surge Seen in U.S. Oil Output, Lowering Gasoline Prices

Domestic oil production will continue to soar for years to come, the Energy Department predicted on Monday, scaling to levels not seen in nearly half a century by 2016.

The annual outlook by the department’s Energy Information Administration was cited by experts as confirmation that the United States was well on its way — far faster than anticipated even a year ago — to achieving virtual energy independence.

What the EIA is actually predicting:  AEO2014 EARLY RELEASE OVERVIEW. The data is C+C.

AEO 2014

The first two points were what was actually produced in 2011 and 2012 and the rest of the blue line is what they are predicting for the future. The orange line is what they predicted last year. The predicted numbers this year are a lot higher but the shape of the curve looks the same. They predict US Crude + Condensate will plateau in 2016, actually peak in 2019 and by 2021 be headed for a permanent decline.

Note the difference between AEO 2013 and AEO 2014. The difference rises to just over 2 mb/d and holds that difference util 2030 when it slowly closes down to 1.37 mb/d in 2040. And everything above about 5 mb/d is all Shale, or Light Tight Oil. They expect LTO to rise to about 4.5 mb/d by 2016, hold that level for almost 5 years and for LTO to still be above 2.5 mb/d by 2040. 

Anyway here is what Saudi Arabia thinks about it all. Saudi will not be affected by shale oil output: report:

“Since we doubt that tight oil production will grow as much as most commentators surmise, and since we believe that tight oil production will keep representing only about 3% of total liquids supply, we do not believe that the growth in oil production from tight rock formations in the US, or from shale formations elsewhere, will materially affect Saudi Arabia’s long-term position in the oil industry,” Jadwa said in a study.

And questions are being raised elsewhere: Shale well depletion raises questions over US oil boom

In October, the government began issuing a monthly report on drilling productivity that charted declines in six major U.S. shale plays. The U.S. Energy Information Administration estimates that it takes seven of every 10 new barrels produced in those areas just to replace lost production.

Of course this article is quoting the EIA and their new Drilling Productivity Report.

Speaking of that report, Steve’s blog, SRSrocco Report, has this headline: Eagle Ford Shale Decline Shoots Up A Stunning 10% in One Month!

What Steve is talking about is this. First from last month’s Drilling Productivity Report:

Eagle Ford Dec

And see the difference from the latest report:

Eagle Ford Jan

But getting back to the statement in the “Fuel Fix” article that it takes seven of every 10 new barrels produced in those areas just to replace lost production. If the EIA is correct in their latest report it takes a bit more than 7 of every 10 barrels just to make up for the declines of old wells. If their figures are correct, in Eagle Ford, it takes almost 7.6 barrels of every 10 barrels from new wells just to make up for the decline in production from old wells. And of course that number increases every month.

If the EIA’s decline rates are anywhere close then the Bakken should reach her peak at about 1.25 mb/d and Eagle Ford at about 1.6 mb/d, or at some point very close to those numbers.

Bottom line, all the hype is just hype. The US will likely never reach 4.5 million barrels per day of shale oil, the peak will not be spread out over five years as the EIA believes, and the decline will be a whole lot steeper than the chart above indicates. Shale oil may delay the peak of world oil production for one year, or two at the most.

While it is true that only the Light Tight Oil is keeping Peak Oil from being an obvious fact, that can only last for a year or two, then the US, along with almost every other nation in the world will be in decline.

The EIA’s International Energy Statistics is about a month late already. International oil production data is a really low priority with the EIA. They are much more concerned with the price of kerosene and other such matters than they are with world crude oil, the lifeblood of every economy in the world. So we will have to do without it until they get around to posting that data, if ever. But in the meantime I have constructed the below chart using mostly JODI data, with some EIA data used for countries that do not report to Jodi. I use it just to show what the world oil supply would look like without US Light Tight Oil. The last data point is October 2013.

Jodi World Less USA

According to JODI, the world less USA peaked in January of 2008 and almost reached that point again in July of 2008. In October of 2013 we are down about 2.25 mb/d from that point. Interesting to note also that the world less USA has dropped some 1.5 mb/d since July. July was the last month the EIA’s International Data Statistics has data for.

Euan Mearns, below, asks that this chart be posted. The last data point is October 2013:

World Les US & Canada

It doesn’t look a lot different from the “World Less USA” chart. Down 2.53 Megabytes a day from the peak of July 2006. Keep in mind this is JODI data which differs somewhat from the EIA data. The EIA however only has updates through July 2013. There has been considerable attrition in production since then.

The following charts are based on data from the EIA’s AEO 2014 Early release.

aeo2014uscc1/
aeo2014uslto/

THIS ENTRY WAS POSTED IN UNCATEGORIZED. BOOKMARK THE PERMALINK.

 

peak oil climate and sustainability: When will US LTO(light tight oil) Peak?

peak oil climate and sustainability: When will US LTO(light tight oil) Peak?.

The rapid rise in oil output since 2008 has the mainstream media claiming that the US will soon be energy independent.  US Crude oil output has increased about 2.8 MMb/d (56%) since 2008 and about 2 MMb/d is from the shale plays in North Dakota ( Bakken/Three Forks) and Texas (Eagle Ford). My modeling suggests that a peak from these two plays may be reached by 2016, other shale plays (also known as light tight oil [LTO] plays) may be able to fill the gap left by declining Bakken and Eagle Ford output until 2020, beyond that point we will see a rapid decline.

US Light Tight Oil to 2040

fig 1

There are two main views:

  1. There will be little crude plus condensate (C+C) output from any plays except the Bakken/Three Forks in North Dakota and Montana and the Eagle Ford of Texas.
  2. The other LTO plays will come to the rescue when the Bakken and Eagle Ford reach their peak and keep LTO near these peak levels to about 2020 with a slow decline in output out to 2040.
Where are these “other LTO plays”?  There are a couple of these in Oklahoma and Texas (in the Permian basin, Granite Wash, Mississippian basin), the Appalachian, the Niobrara in Colorado, and others (see slide 17 of the USGS presentation link below).  Is it possible for these LTO plays to offset future declines in the Bakken and Eagle Ford?  I hope to answer that in this post.
When doing my modeling of the Eagle Ford, I needed an estimate of the technically recoverable resource(TRR) for that play.  The April 2013 USGS Bakken Three Forks Assessment roughly doubled their earlier assessment of that play (mostly this was due to not including the Three Forks in their earlier assessment.)
see slide 17 at the USGS Bakken/Three Forks Assessment presentation.
   In light of this I decided to increase the earlier (1.73 Gb) Eagle Ford estimate of undiscovered technically recoverable resources(TRR) from the USGS by a factor of 2.3 to 4 Gb.  To determine total TRR, the proved reserves and oil already produced need to be added to the undiscovered TRR, in the case of the Eagle Ford output to the end of 2011 was only 0.1 Gb and proved reserves were about 1 Gb (check the EIA data on the change in proved reserves since 2009 in districts 1 and district 2 of Texas):

So for the Eagle Ford estimated TRR would be 4+1=5 Gb.

For the North Dakota Bakken undiscovered TRR is 5.8 Gb, 2.2 Gb of proven reserves, and 0.5 Gb of oil produced for a Total TRR of 8.5 Gb. See my previous post for more details.

For the rest of the US we can deduct Bakken (7.38 Gb), Eagle Ford(1.73 Gb), and Alaska(0.94 Gb) from the US total (13 Gb) which leaves about 3 Gb, now assume that a reassessment by the USGS increases this by a factor of 2.3 to 7.2 Gb, then add the Montana Bakken/Three Forks (1.6 Gb) and reserves from the Permian basin and other plays (1.3 Gb) to get 9.2 Gb for a TRR estimate for US “other LTO”(Total LTO minus [North Dakota Bakken/Three Forks plus Eagle Ford play]). Total TRR for all US LTO is 22.7 Gb. (I have assumed LTO from Alaska’s North Slope will not be produced.)

For the North Dakota Bakken/Three Forks and Eagle Ford plays we use the following economic assumptions to find the Economically Recoverable Resource (ERR):

OPEX (operating expenditure) is $4/barrel, royalty and tax payments are 24.5 % of wellhead revenue, annual discount rate is 12 % (used to find the net present value[NPV] of a well over its 30 year life). Transport costs are $12/barrel for the Bakken and $3/barrel for the Eagle Ford.  Well costs are 9 million for the Bakken in Jan 2013 and fall by 8% per year to 7 million in 2016 and for the Eagle Ford well costs are $8 million in Jan 2013 and fall 8% per year to $6.5 million in mid 2017.  Real oil prices follow the EIA’s 2013 Annual Energy Outlook reference case to 2040 and then continue to rise at the 2030 to 2040 rate to the end of the scenario.  All costs and prices are in May 2013$ so they are real prices rather than nominal prices.
The concept of ERR is discussed in detail in the Sept, 2013 post after figure 3.

Figure 1

fig 2
I will use the Eagle Ford play as my template because it has ramped up much more quickly than the Bakken, this is a very optimistic scenario and it is unlikely that there will be greater output from US LTO than the scenario I will present.

The underlying assumptions are:
-the average well will look like the average Eagle Ford well
-ramp up of additional wells will be slow until the peak of combined Bakken and Eagle Ford output
-in 2015 the Bakken and Eagle Ford peak and reach break even levels of profitability by 2016
-in response to reaching break even the number of new wells per month added in both the ND (North Dakota) Bakken and the Eagle Ford are reduced substantially.
-new wells added in the other US LTO plays ramp up as the rate that wells added to the Bakken and EF are reduced
As before we adjust the decrease in new well EUR (both when it begins and how long it takes to reach its maximum) so that the TRR matches our estimate of 9.2 Gb.  In this case the EUR starts to decrease in July 2018 and reaches its maximum monthly rate of decrease of 2.37 % in June 2020. The “other LTO” peaks in 2020 at about 2 MMb/d.
To determine ERR we make identical economic assumptions as our Eagle Ford case above except that we assume transport costs are $5/barrel on average ($3/barrel in EF case).

Figure 2

fig 3

When we combine our North Dakota Bakken/Three Forks, Eagle Ford, and “other LTO” models we get the following chart:

Figure 3

fig 4

This scenario is indeed optimistic, but not nearly as optimistic as the EIA’s scenario for LTO in the 2013 Annual Energy Outlook.  For comparison I computed the ERR for 2013 to 2040 for my US LTO scenario, it was 17.6 Gb over that period, the EIA scenario has a total output of 24.5 Gb over the same period, 40% higher output than an already optimistic scenario.  My guess is that reality will lie between the blue curve and the green curve with the most likely peak around 2018+/- 2 years at about 3.1+/- 0.2 MMb/d.

Dennis Coyne

 Appendix Bakken and Eagle Ford Details
I am still working on this section, check back for details
Using the USGS TRR estimates as our guide we assume new well estimated ultimate recovery (EUR) eventually decreases as the room for new wells in the most productive areas (the sweet spots) starts to run out.  If new wells are producing an average of 450 kb over 30 years before this decrease begins, we assume at some point, say June 2014 the new well EUR starts to decrease maybe by 0.4% per month, the rate of decrease continues to increase for 18 months so that after 18 months the new well EUR is decreasing at a monthy rate of 7.2 %.

fig 5

fig 6

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