QA Session with David Collyer and Gordon Hoeckstra BC Energy Projects: Enbridge's controversial $6.5-billion Northern Gateway and Kinder Morgan's $5.4-billion Trans Mountain pipeline expansion

Energy has become, increasingly, a major focus of the British Columbia economy with billions of dollars of proposed projects. Those include Enbridge's controversial $6.5-billion Northern Gateway and Kinder Morgan's $5.4-billion Trans Mountain pipeline expansion. There are also billions in liquefied natural gas projects being considered by global energy heavyweights such as Exxon Mobil, Shell and the BG Group. The Vancouver Sun talked with Canadian Association of Petroleum Producers president David Collyer for a year-end take on these major projects.

Q Northern Gateway has recently received approval from the federal review panel with 209 conditions (which are tough but "doable," says the company). However, there is staunch First Nations opposition in B.C., supported by environmental groups, who are saying they will launch legal action. Will this pipeline get built?

A I don't think one should conclude by any means that all First Nations are opposed to that particular project or opposed to oil pipelines. But there is no question there are some tough issues to be resolved. I think the (Doug) Eyford report (Prime Minister Stephen Harper's special envoy on First Nations) that was issued a couple of weeks ago is a fairly balanced and pragmatic road map to try to resolve those issues. There's a trust relationship building piece of this, and there's a need obviously to find some way to reconcile issues around claims - although not necessarily solving them in the context of a project. And then you need to try to figure out a way to figure the economic-benefits dimension of it. It's not easy.

Q First Nations claims and consultation concerns around industrial projects seems to be fought out in the assessment process. Are environmental reviews the best place to be dealing with these issues?

A The short answer is no, with some qualifiers. I think we are burdening the regulatory process with more than it can actually deal with. And we are doing it in a process that is almost, by definition, adversarial and doesn't provide much room for finding common ground. I think we're increasingly living in a world where the broader social licence dimensions of energy and the environment need to be dealt with outside the specifics of a project or the specifics of a regulatory process.

Q Is there any work underway to try to address that?

A Again, I think the Doug Eyford report was quite a thoughtful examination of this, and he certainly provided strong encouragement for governments to take the lead in creating that table, but also was pretty clear that First Nations and industry needed to be constructive participants in it. (Eyford recommended creating a Crown-First Nations corporate "tripartite energy working group" as a forum for open dialogue on energy projects).

Q If a panel says yes, and the federal government says yes, but at least among a significant portion of the public, they are saying no to a project, how does it gain social licence?

A We've got a challenge in this country - whether it's an oil and gas project or a wind farm, or natural gas-fired power plant - as most people want the benefits of industrial development, including energy development. But very few people want to be directly impacted by it. And, one of the challenges that governments in Canada have - it's not unique to this counter - is this question of how do you balance the broader public interest with the local interest. I think all that can be done in that context is to try to make sure all reasonable steps are taken to deal with the issues and concerns people have raised from a technical, environmental or safety standpoint.

Q The B.C. government has said that, except for partly meeting the first condition on passing the review, Northern Gateway doesn't pass the other four conditions. (Those are world leading sea and spill response systems, aboriginal benefits and economic benefit for B.C.) And B.C. Environment Minister Mary Polak said she can't see how they can be achieved in the 180-day time frame Ottawa has to make a decision or even within one year.
Can this project be built without B.C. government support? A I guess in theory it can. From a practical or pragmatic stand point, I think, we as industry, and the pipeline proponents, and the Alberta government, have all recognized the need to address the five conditions. We think they're quite reasonable in terms of the types of things they expect. Obviously, the devil is in the details.

Q It's been suggested the fifth condition could be met through a fee or tax on oil that goes through B.C. Is that an idea industry is willing to consider, or is it a non-starter?

A I think it's premature to be specific about what we would consider and what we wouldn't.

Q Another major proposed project just filed its formal application: Kinder Morgan's $5.4-billion Trans Mountain expansion. There is also significant opposition to this project - but it does follow nearly three-quarters of existing route. Will this project be easier to build?

A The First Nations' opposition to the Trans Mountain Kinder Morgan pipeline is not as strong as it is in northern B.C. Conversely, it's the Lower Mainland, and there will be a different set of issues that arise from increased tanker traffic from the Port of Vancouver. I don't think any of these projects are going to be easy, or simple or straightforward.

Q How important is west coast access for bitumen, given there are proposals to get oil to the east coast of Canada, and Canadian oil can get to the U.S. gulf coast where it can be exported as refined products?

A Our view is we need west coast oil market access. Given our view of the production growth potential (in Canada), we think it's really important to be attached to the market that has the greatest potential demand growth - and that's Asia.

Q There is much interest in LNG in B.C. from oil and gas heavyweights: As many as a dozen facility proposals, and maybe half a dozen pipelines. But there is much competition from existing exporters such as Australia, and emerging participants such as the U.S. and East Africa. Will any company make a final investment decision in 2014?

A I am optimistic we will. The market is there. The supply is there. The question is whether we can bring all the pieces together to hit those market windows. Frankly, part of that is making sure we are as competitive as possible and we don't miss these market windows because we're unduly focused on carving up the pie before we create the opportunity.

Q Are you, in part, talking about the B.C. government's LNG tax decision that's been pushed off to 2014?

A I think there's a package of issues that need to be dealt with on competitiveness. the upstream (drilling) dimension, how carbon or carbon tax is going to be handled, electricity generation. The LNG tax is obviously one of those.

Q The public generally appears to be warmer to LNG development than oil pipelines. That said, there are challenges tied to the broader footprint, including greenhouse gases, pollution emissions and fracking. Can these concerns be addressed?

A We need to find a way to overcome them, frankly. We need a conversation at two levels. We obviously need to work on the ground with communities to mitigate concerns that arise from increased activity (fracking and water use) and investment. And we need to find a way to have constructive conversation about some of these broader (energy mix and carbon) issues that can't be resolved, and shouldn't be expected to be resolved, in the context of individual projects.

Happy new year 2014 to you all, dear readers!
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Feliz año 2014 para todos los lectores!

OPEC Pumps Least Crude in More Than 2 Years as Saudi Cuts

OPEC reduced crude production in November to the lowest level in more than two years as output dropped below the organization’s 30 million barrel-a-day ceiling for a third month.

The Organization of Petroleum Exporting Countries pumped 29.63 million barrels last month compared with 29.83 million in October, OPEC said in its monthly oil market report today, citing data from secondary sources. That’s the lowest since May 2011. The group decided to maintain its output limit of 30 million at a meeting in Vienna last week because members were “all satisfied,” Ali al-Naimi, Saudi Arabia’s oil minister, told reporters on Dec. 4.

“In taking this decision, member countries reconfirmed their readiness to promptly respond to unforeseen developments that could have an adverse impact on an orderly and balanced oil market,” OPEC said in today’s report.

Analysts at banks including BNP Paribas SA, Citigroup Inc. and Deutsche Bank AG predict that some members of OPEC, notably Saudi Arabia, will probably need to reduce output in 2014 to prevent a global glut. The U.S. is producing the most oil in a quarter-century, while Iraq, Libya and Iran have said they plan to increase exports in the next several months.

Libyan Ports

Today’s OPEC report was published before the head of Libya’s Petroleum Facilities Guard, Brigadier Idris Bukhamada, said that three oil ports in eastern Libya will reopen on Dec. 15. The Al Magharba tribe, which held a meeting today, forced former PFG leaders to lift their blockade, Bukhamada said by phone from Ajdabiya. The ports, including Es Sider, the largest, had been closed since late July.

Output from Saudi Arabia, OPEC’s biggest producer, fell to a five-month low of 9.63 million barrels a day last month from 9.71 million in October, according to OPEC’s monthly report. Production also dropped in Libya, Nigeria, the United Arab Emirates, Algeria, and Kuwait, while supplies climbed in Iraq, Iran, and Angola.

“Downside risks to the oil price may require OPEC to cut production to defend oil prices,”Michael Lewis, head of commodities research at Deutsche Bank in London, said in an e-mailed report today. “Given our upbeat outlook for world growth we would view any attempt by OPEC to defend the oil price as likely to be successful.”

Brent crude for delivery in January fell 17 cents to $109.22 a barrel at 1:49 p.m. in London on the ICE Futures Europe exchange, after rising as much as $1.06 earlier today, before the news on Libyan ports emerged. The North Sea grade, which is the benchmark for more than half the world’s oil, has dropped 1.7 percent in 2013.

Spread Narrows

OPEC has pumped below its 30 million barrel-a-day target since September, reports for this month and last showed.

The spread between U.S. West Texas Intermediate and Brent crudes will narrow in the coming year, according to the group. “As additional pipeline capacity to the U.S. Gulf coast becomes available,” a glut will ease at WTI’s delivery point in Cushing, Oklahoma, OPEC said. The gap traded at about $10.81 a barrel today after narrowing from $19.01 on Nov. 27, the widest on a closing basis in eight months.

World oil consumption is expected to gain by 1 million barrels a day next year to 90.84 million barrels, according to the report, little changed from last month’s estimate. Demand for OPEC’s crude is forecast to drop to 29.6 million barrels a day, or a decline of 300,000 barrels from this year.

Production from nations outside of OPEC will increase 1.2 million barrels a day next year to average 55.32 million barrels a day, with gains from the U.S., Canada and Russia, OPEC said. That’s little changed from last month’s estimate.

The International Energy Agency, the Paris-based adviser to oil-consuming nations, will release its monthly report tomorrow.

OPEC’s 12 members are Algeria, Angola, Ecuador, Iran, Iraq, Kuwait, Libya, Nigeria, Qatar, Saudi Arabia, the U.A.E. and Venezuela.

Fracking puts U.S. first in shale gas production

The United States, followed by Canada, leads the world in producing natural gas from shale formations as the controversial practice of fracking spreads, the U.S. government reports Wednesday.

Shale gas accounted for 39% of all natural gas produced last year in the United States, compared to 15% of that in Canada and less than 1% in China, according to data from the Energy Information Administration, the statistical arm of the Department of Energy.

"There's no commercially-viable shale gas production outside the United States and Canada," although about a dozen other countries have done exploratory testing, says Aloulou Fawzi, an EIA industry economist. He says China's production, as estimated by independent Chinese energy analysts, is quite small in comparison.

The main reason for the recent U.S. boom in natural gas production -- up more than a third since 2005 -- is the cost-effective combination of horizontal drilling and hydraulic fracturing or fracking. This process typically blasts huge quantities of water, mixed with sand and chemicals, underground to break apart rock and allow the natural gas to flow from the shale into the well.

Many environmentalists oppose fracking, because it can use a lot of water in parched areas, create waste water, trigger small earthquakes and contaminate groundwater. They also worry that the low cost of natural gas reduces demand for carbon-free renewable energy sources such as solar and wind.

Natural gas is already cutting into the share of U.S. electricity provided by coal-fired power plants, which has fallen from 53% in 1993 to 42% in 2011. During that period, EIA says natural gas' share nearly doubled -- from 13% to 25% -- and is projected to hit 30% by 2040.

The agency expects U.S. natural gas production will increase 44% between 2011 and 2040, saying almost all this growth will be due to shale gas. Yet It says there are long-term uncertainties about the productivity of shale formations, because many are so large that only limited portions have been widely tested for production.

Fracking has brought economic revival to areas with the largest shale formations, including the Barnett in central Texas, the Eagle Ford in southern Texas, the Bakken in North Dakota and the Marcellus in Pennsylvania and several neighboring states.

Earlier this week, the agency attributed part of the recent U.S. decline in heat-trapping carbon dioxide emissions to the nation's switch from coal to natural gas, which emits about half as much CO2 as coal per unit of electricity.

Something Big Happened Last Month for first time nearly two decades (US CRUDE OIL NET IMPORTS)

 © 2013, US Energy Information Agency.

Brazil's Giant Libra pre-salt oil discovery: Shell, Petrobras, Total, CNPC and CNOOC won Sharing Contract.

A consortium of companies, including Royal Dutch Shell plc (“Shell”), Petrobras, Total, CNPC and CNOOC, won today a 35-year production sharing contract to develop the giant Libra pre-salt oil discovery located in the Santos Basin, offshore Brazil. The Brazilian regulator, Agência Nacional do Petróleo (ANP), estimates Libra’s recoverable resources of between 8 to 12 billion barrels of oil.

“The Libra oil discovery in Brazil is one of the largest deep water oil accumulations in the world. We look forward to applying Shell’s global deep water experience and technology, to support the profitable development of this exciting opportunity,” said Peter Voser, Chief Executive Officer, Royal Dutch Shell.

Shell holds 20% in the consortium, with Petrobras 40% as operator, Total 20%, CNPC 10% and CNOOC 10%. The consortium will work together in an integrated fashion to support Petrobras, the most experienced operator in the Brazilian pre-salt, and will incorporate each company’s deep water skills, people and technology for the success of the venture.

“Libra offers a unique opportunity to participate in the development of a super-giant deep-offshore oil discovery with strategic partners. Reinforcing our position in the pre-salt Santos basin strengthens and diversifies our upstream portfolio and fits with our strategy to sustain post-2017 production over the next decade. We look forward to participating in the development of these vast resources, and we are confident that the combined deep-offshore expertise represented within the consortium will be a valuable contribution to the growth of Brazil’s oil and gas production”, said Christophe de Margerie, Chairman and Chief Executive Officer of Total.

The production sharing contract is expected to be signed in November 2013. As part of the winning bid, Shell will pay its 20-percent share of the total signing bonus of USD $1.4 billion [3.0 billion reais], and fulfill the minimum work program no later than end 2017.

The ultra-deep water Libra accumulation is located in Santos Basin, approximately 170 kilometers (105 miles) off the coast of Rio de Janeiro. The block covers approximately 1,550 square kilometers in water depths of around 2,000 meters (6,500 feet). The reservoir depth is around 3,500 meters below the sea floor (11,500 feet). The ANP estimates that total gross peak oil production could reach 1.4 million barrels per day. Further appraisal is required to firm up this estimate, the development concept and a first oil date.

Brazil: A massive oil discovery offshore in Sergipe.

Brazil's government will announce a massive oil discovery off the country's northeast coast later this month, according to acting Sergipe state Gov. Jackson Barreto.

Mines and Energy Minister Edison Lobao will travel to Sergipe's capital, Aracaju, on Oct. 23 to officially announce "the world's largest oil discovery of 2013," Mr. Barreto told Sergipe state's official news agency Friday. The event is also expected to include Magda Chambriard, director of the country's National Petroleum Agency, or ANP, Mr. Barreto said.

The two government agencies, however, downplayed prospects for an announcement. The Mines and Energy Ministry could not confirm Mr. Lobao's visit. In a statement, the ministry added that it "has no knowledge of any new oil discovery in the country other than those already announced by Petrobras."

The ANP, meanwhile, said that Ms. Chambriard would visit Sergipe on Oct. 23 to discuss the upcoming 12th-round auction of oil and natural gas exploration blocks. Ms. Chambriard's visit, though, was not related to any impending announcement of a major oil discovery, a spokeswoman said.

Last week, Brazilian state-run oil company Petroleo Brasileiro (PBR, PETR4.BR), or Petrobras, confirmed it had made a "relevant" discovery off Sergipe's coast that would start production of 100,000 barrels a day in 2018, Chief Executive Maria das Gracas Foster said. The executive declined to give any volume estimates for the oil fields.

Petrobras first announced a series of discoveries in late 2012, saying the finds had opened a "new oil frontier" in the country. The discoveries are closer to shore and could be much cheaper to develop than larger oil fields, known as the presalt, found buried under a thick layer of salt deep under water off Brazil's southeast coast. Billions of barrels of crude have been discovered in the region, and the government plans to auction off a field there known as Libra under new production-sharing agreements later this month. Libra is estimated to hold recoverable reserves of between 8 billion and 12 billion barrels of oil.

The Sergipe discoveries have geologists rethinking their models of the area, where the unexplored shallow-water areas of what's known as the Sergipe-Alagoas Basin were thought to hold between 500 million and 1.5 billion barrels of recoverable reserves. Petrobras's discoveries were made in water 2,500 meters deep.

Petrobras operates the exploration blocks containing the new discoveries with a 60% stake. The remaining 40% stake belongs to IBV-Brasil, a joint venture between Indian companies Bharat Petroleum Corp. (500547.BY) and Videocon Industries Ltd. (511389.BY).

Brazil's state-led oil company, Petroleo Brasileiro SA, and its Indian partners have made a "beautiful" oil discovery off Brazil's northeast coast and it will produce a minimum 100,000 barrels of petroleum a day starting in 2018, the company's chief executive officer said on Friday.

Maria das Graças Foster, the chief executive, declined to say how big the discovery is but said it was an important new oil "province" for Brazil and that its large potential reserves would create a rush of jobs and activity to the area that will need to be managed carefully.

On Thursday, Reuters exclusively reported that the discovery, centered on the SEAL-11 offshore exploration block, likely holds more than 1 billion barrels of oil and that the region will soon become Brazil's biggest new oil frontier.

The SEAL-11 block is 60 percent-owned by Petrobras and 40 percent-owned by IBV Brasil, a 50-50 joint venture between India's Bharat Petroleum Corp (BPCL) and Videocon Industries Ltd.

"In 2008 we decided to do a very extensive investigation of the area, and the results we have got have been very good," Foster told reporters at company headquarters in Rio de Janeiro. "This is a beautiful discovery, beautiful discoveries."

In addition to light, high-quality crude oil, the region has important quantities of gas, she added.

Two prospects in the area, known as Farfan and Muriu, are expected to be developed as a single or integrated unit, with at least one floating production, storage and offloading ship (FPSO) producing oil and gas from the area in 2018, Foster said.

Foster said that was the minimum outlook for the area based on spending in the company's $237 billion 2013-2017 investment plan drawn up before the latest drilling and tests in the area.

If confirmed, the new find could make the region the country's biggest new oil frontier since the government unveiled the massive subsalt discoveries off the coast of Rio de Janeiro and Sao Paulo states in 2007.

REFINERY PLANS

Foster also said that Petrobras is totally reforming its plans to build two low-sulfur diesel refineries in Brazil's northeast. The so-called premium refineries planned for the states of Maranhao and Ceara were showing signs they would not be profitable.

The Maranhao refinery is expected to cost about $20 billion to build.

Petrobras, however, has reworked the projects with the help of U.S. based consultants, Foster said, and those projects are now looking stronger. The company hopes to start putting the refineries out to tender as early as March, she said.

The company is also in talks with a Chinese company to take a stake in the Maranhao project, Foster said. The project could lead to the Chinese partner taking a majority stake, she added.

UK to encourage hydrofracking of natural gas.

Proposed U.K. government policies to encourage hydrofracking of natural gas ignited a firestorm of protest this summer, with critics complaining that they were not consulted and that rules will restrict local planners’ authority. But the country appears to have few other options. The United Kingdom is in an energy quagmire that is forcing it to turn to shale gas.

The country’s aggressive carbon emissions goals call for the U.K.’s power supply to be virtually carbon-free by 2030. But the government had been planning to slash emissions with low-carbon power strategies—new nuclear reactors and carbon capture and storage systems on existing power plants—that remain too expensive to build. And conventional natural gas from the North Sea that could buy time for the scale-up of renewable power is dwindling.

Cost matters to U.K. voters. Nearly three-quarters of its citizens are worried about climate change, according to a national poll released by the London-basedU.K. Energy Research Centre in July. But more than four-fifths told the researchers that they are “fairly or very concerned” that both electricity and gas will become unaffordable in the next 10 to 20 years.

If the U.K. can’t find an affordable supply of natural gas via hydrofracking of its shale deposits, it might have to restart mothballed coal-fired power plants to keep the lights on in future decades. “One way or another, we’ll muddle through,” says George Day, economic strategy manager at the Loughborough-based Energy Technologies Institute, a partnership between industrial firms and the U.K. government. “Whether we’ll hit our carbon targets is another question,” says Day.

Those targets would slash greenhouse gas emissions 80 percent by 2050 from 1990 levels. For the country to get there, the U.K. power industry would have to slash its carbon intensity from more than 500 to 50 grams of carbon dioxide per kilowatt-hour by 2030, according to the quasi-independent Committee on Climate Change. Under that committee’s roadmap, 60 percent of new cars sold in 2030 should be electric, rising to 100 percent by 2035.

Day and other government advisors project that such ambitious targets are well beyond what renewable energy alone can deliver, however. Britain’s solar potential pales in comparison to even Germany’s lackluster supply of sunlight, leaving wind power—principally from offshore farms—to carry the burden. “Do we actually have the industrial capacity to deliver 50-plus gigawatts of offshore wind within the next decade or two?” says Day. “That would be very difficult.”

Even some renewables advocates agree that the U.K. must pursue nuclear and carbon-capture technology as well. “It seems likely that you’re going to need all of the above,” says Briony Worthington, shadow minister for energy and climate change for Labour in the House of Lords. At the very least, says Worthington, the U.K. should seek new reactors to maintain nuclear’s 20 percent share of the power supply as a source of low-carbon energy.

The problem for the government is that investment in CCS and nuclear is, at present, nonexistent. To a large extent that is a failure of the European Trading System, which was intended to render low-carbon technologies competitive with fossil fuels. With the collapse of Europe’s carbon market, that incentive is missing.

To attract CCS and nuclear investment, the U.K. established its own carbon prices that are set to rise to £30 per ton by 2020 and £70 per ton a decade later. It has also proposed floor prices for low-carbon power, with the government topping up a generator’s revenues if the market price falls below a fixed threshold. To support CCS it has set aside £1 billion to defray the cost of building early CCS projects.

Still, investors are moving cautiously. Only two CCS projects are eyeing the government’s financing. A consortium led by Shell proposes to capture carbon dioxide from the Peterhead power station in Scotland and pipe it out to the North Sea for sequestration in a depleted oil and gas field. A second project would send carbon dioxide to the North Sea from a coal plant in North Yorkshire. Final investment decisions for those projects are not likely before 2014 or 2015.

Nuclear reactor construction is lagging further. While the government wants to see 16 gigawatts of new nuclear capacity operating by 2025, only one project is getting serious attention: a proposal by French power generator Electricité de France to build a 1,600-megawatt EPR reactor at the Hinkley Point nuclear station, whose 1970s-era reactors are scheduled to shut down in 2023.

Bakken Shale: North Dakota Fracking

Though North Dakota has historically had lower unemployment rates than the rest of the country, it barely felt a hiccup with the onset of the Great Recession. Not only have the number of jobs increased steadily in the region over the past decade, but the average take-home pay has increased at a healthy clip as well.

A big part of that is due to the fact that drilling in the Bakken Shale -- with its enormous oil deposits beneath North Dakota's soil -- has become a very profitable endeavor. In fact, in 2006, North Dakota ranked ninth in daily production of oil in the United States. In just seven years, it shot all the way up to second, behind only Texas. The state currently produces 821,000 barrels of oil per day. 

The big playersTwo players account for a large portion of business in North Dakota's oil fields. Continental Resources leases the most land of any oil company in the state, and stated last year that it plans to triple its oil output by 2017, with the Bakken shale accounting for most of this growth. Hess  also made a big splash in 2010 with a $1 billion land purchase.

At the same time, several smaller players are also turning a profit to the benefit of North Dakotans and shareholders alike. As Foolish colleague Matt DiLallo recently pointed out,Kodiak Oil & Gas and Oasis Petroleum have combined to go from producing about 4,500 barrels of oil per day in 2010 to more than 60,000 by the end of this year.

And even though the Bakken has been active for years now, the land grab continues. Just last month, Whiting Petroleum announced that it was buying 40,000 acres of land for roughly a quarter of a billion dollars.

Telling Washington to stay awayGiven the vested interest North Dakota citizens, politicians, and oil companies have in seeing the Bakken shale continue to produce profits, it's no surprise that the state is wary of the Obama administration's plans to institute nationwide regulations regarding the fracking process, which made this oil boom possible in the first place.

Expected to be released sometime in early 2014, these regulations will likely require disclosures of materials used in the fracking process, specifications to ensure safe well construction, and rules for the management and disposal of wastewater.

Though only 5% of oil in the United States comes from public lands, both sides of the aisle in North Dakota are fighting against intrusion from D.C. politicians. In May, a bipartisan delegation from the state claimed that these federal regulations were completely unnecessary.

"We believe we already have substantial regulations in place that allow for continued oil and gas production while protecting the environment and the health and safety of our citizens," Sen. Heidi Heitkamp (D-N.D.) said.  These regulations include the fact that fracking chemicals are already disclosed via the industry-standard website, Fracfocus.org.

Continental Resources CEO Harold Hamm also claims that while it only takes 30 days to get a drilling permit through North Dakota authorities, doing so through the federal government would take close to nine months. That kind of delay, he argues, inhibits efficient economic development in the region.  

No matter how the regulations play out, finding the right investments while historic amounts of capital expenditures are flooding the industry is crucial to padding your nest egg. You can get a comprehensive look at three energy companies set to soar during this transformation in the energy industry.

On UK energy, Cameron: We cannot afford to miss out on shale gas

Fracking has become a national debate in Britain – and it’s one that I’m determined to win. If we don’t back this technology, we will miss a massive opportunity to help families with their bills and make our country more competitive. Without it, we could lose ground in the tough global race.

As with any advance in technology, fracking – drilling for so-called “unconventional” gas – has rightly drawn scrutiny. But a lot of myths have also sprung up. So today I want to set out why I support it – and deal with the worst of the myths at the same time.

First, fracking has real potential to drive energy bills down. Labour’s mismanagement of the economy means that many people are struggling with the cost of living today. Where we can act to relieve the pressure, we must. It’s simple – gas and electric bills can go down when our home-grown energy supply goes up. We’re not turning our back on low carbon energy, but these sources aren’t enough. We need a mix. Latest estimates suggest that there’s about 1,300 trillion cubic feet of shale gas lying underneath Britain at the moment – and that study only covers 11 counties. To put that in context, even if we extract just a tenth of that figure, that is still the equivalent of 51 years’ gas supply.

This reservoir of untapped energy will help people across the country who work hard and want to get on: not just families but businesses, too, who are really struggling with the high costs of energy. Just look at the United States: they’ve got more than 10,000 fracking wells opening up each year and their gas prices are three-and-a-half times lower than here. Even if we only see a fraction of the impact shale gas has had in America, we can expect to see lower energy prices in this country.

Secondly, fracking will create jobs in Britain. In fact, one recent study predicted that 74,000 posts could be supported by a thriving shale-gas industry in this country. It’s not just those involved in the drilling. Just as with North Sea oil and gas, there would be a whole supply chain of new businesses, more investment and fresh expertise.

Thirdly, fracking will bring money to local neighbourhoods. Companies have agreed to pay £100,000 to every community situated near an exploratory well where they’re looking to see if shale gas exists. If gas is then extracted, 1 per cent of the revenue – perhaps as much as £10 million – will go straight back to residents who live nearby. This is money that could be used for a variety of purposes – from reductions in council-tax bills to investment in neighbourhood schools. It’s important that local people share in the wealth generated by fracking.

The benefits are clear. But it’s also crucial to put to bed the myths. It has been suggested in recent weeks that we want fracking to be confined to certain parts of Britain. This is wrong. I want all parts of our nation to share in the benefits: north or south, Conservative or Labour. We are all in this together.

If neighbourhoods can see the benefits – and are reassured about its effects on the environment – then I don’t see why fracking shouldn’t receive real public support. Local people will not be cut out and ignored. We are issuing very firm guidance: firms looking to frack should make people aware of their plans well before they apply for a permit. Dialogue is important and if residents express specific concerns, then companies should take them on board. From my experience as a local MP, people tend not to oppose developments for the sake of it. But what they do object to is the idea that their neighbourhood should change without any say. We want people to get behind fracking, and a transparent planning process is an important ingredient.

Equally, we must make the case that fracking is safe. International evidence shows there is no reason why the process should cause contamination of water supplies or other environmental damage, if properly regulated. And the regulatory system in this country is one of the most stringent in the world. If any shale gas well were to pose a risk of pollution, then we have all the powers we need to close it down.

When all is said and done, though, one myth still remains – that fracking damages our countryside. I just don’t agree with this. Our countryside is one of the most precious things we have in Britain and I am proud to represent a rural constituency. I would never sanction something that might ruin our landscapes and scenery. Shale gas pads are relatively small – about the size of a cricket pitch. But more than that, similar types of drilling have been taking place for decades in this country without any real protest. The South Downs National Park remains one of the most beautiful parts of Britain, yet it has been home to conventional oil and gas drilling since the Eighties. The huge benefits of shale gas outweigh any very minor change to the landscape.

So my message to the country is clear – we cannot afford to miss out on fracking. For centuries, Britain has led the way in technological endeavour: an industrial revolution ahead of its time, many of the most vital scientific discoveries known to mankind, and a spirit of enterprise and innovation that has served us well down the decades. Fracking is part of this tradition, so let’s seize it.

American Sands Energy (AMSE) - Eastern Utah by David Riedel.

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Oil sands are a critical source of oil for America. Canada is our largest source of imported oil sending two million barrels a day over the border. Half of that comes from oil sands.

There are extensive oil sands on the U.S. side of the border especially in Eastern Utah where it is estimated that 12 to 19 billion barrels of oil reside.

While fracking and natural gas get so much of the attention these days, oil sands have the potential to become a major domestic energy source.

One of the major challenges with mining and processing oil sands is the fact that traditional approaches use several barrels of water in the processing of one barrel of oil.  This is where one company is significantly different—its process uses no water.

American Sands Energy (AMSE) is a development stage company focused on oil sands deposits in Utah. It has licensed technology to process oil sands without using any water and at a cost well below competitive approaches. Since AMSE’s process uses no water, it creates no tailings or other waste that requires containment or permits.

AMSE is raising capital to build out a 5,000 barrel per day facility in Eastern Utah to process sands from mining claims that it owns or partly owns.  The company currently has 150 mn barrels of likely reserves that it controls and is confident it could add 500 mn barrels of reserves in the area quite easily.

American Sands has licensed technology from Universal Oil Recovery Corp., which has a proprietary solvent and process that allows for a very clean, low energy process that uses no water and results in no emissions or waste products. This technology has been tested on a pilot plant for the past two years and has proven to work efficiently. Once up and running in 2015 the plant will be at break-even at oil prices of $45/barrel (WTI crude is currently at $106 per barrel).

AMSE’s unique process mixes a proprietary solvent with the oil sands that separates the oil (in the form of bitumen) from the sand.  The sand is then re-heated allowing the solvent to escape and be recycled for reuse. The process results in clean dry sand that can be sold or used in mining operations and bitumen that can be used as is in road paving operations or processed into other products.

Risks include permitting risk, processing plant scale risks, considerable related party transactions and exposure to a commodity market.

American Sands is currently loss making and has a market cap of $10 million.  The company estimates that its total capital requirements are $70 million to put all of its properties into production.

We have estimated the company’s value using three popular methods for valuing development stage oil companies. Averaging these three estimates and adjusting for CAPEX and time to reach production provides a value of $58.8 million or $1.56 per share. We believe American Sands Energy is significantly undervalued and represents a unique way to play alternative energy sources in the U.S.

More in: AMSE Initiation Report July 2013.

Moran: US Incentive For Keeping Gulf Oil Flowing Will Diminish

By Michael Moran

The Persian Gulf has roiled the world regularly since the Iranian Revolution of 1979 – through an Iran-Iraq war, the Gulf War, bombings in Saudi Arabia and Yemen of US military targets, the Iraq War in 2003 and in 2011 the Arab Spring. In each cases, crises spawned in the Gulf sent shudders through global markets, sending the price of oil sky high and prompted US presidents to order naval task forces based half a world away to put to sea.

Yet by 2030, the incentives will have changed. Yes, the US Navy is still watching, warily. And because oil remains a global commodity where prices everywhere are vulnerable to small disruptions, America remains concerned about any problem that might disrupt the flow of oil and gas through the narrow Strait of Hormuz – the bottleneck that could in an instant take Saudi, Iraqi, Qatari, Kuwaiti and other energy supplies off the market. But it’s not the disaster it was in, say, 1991.

Over the next decade and a half the fleets that really care will no longer fly the Stars and Stripes. More than likely, warships from a host of Asian countries – Japan, China, India and others – will be regular visitors to the Gulf by that time. It will be these nations, not the US or its European allies, who have the greatest stake in preventing a calamity that could damage their economies.

For Americans, this may come as quite a relief. For decades, ever since Britain’s Royal Navy lost command of the seas after World War II, the US Navy has provided something of a free public utility by ensuring that global commerce is free to travel on the long, exposed sea lanes connecting major economies. In effect, American task forces are the Coumadin of the global economic circulatory system, preventing blockages and, occasionally, identifying potential tumors to be excised more urgently.

(Like that blood-thinning drug, of course, overdose and other misuse is possible. By and large, though, most of the world is happy for the US to spend billions annually to guarantee free movement of goods by sea.)

The incentives for the US to bear this particular burden are changing. According to the US Energy Information Administration (EIA), by 2030 the share of US oil consumption fulfilled by Persian Gulf sources will have fallen below 35 percent – and perhaps even further, given the new productivity of old US wells, new discoveries off Brazil and the shale gas and tight oil revolution in the US Midwest.

But South and East Asia is facing a very different future. For China, the figure in 2030 is 75 percent. For South Korea, Japan and Taiwan, the percentage is even higher. India’s suppliers are slightly more diverse, but even there over 60 percent of imports will flow from the Gulf in 2030.

Sliced a bit differently, the data leads IEA to project that Asian economies will be importing 90 percent of Persian Gulf oil by 2030. Indeed, higher prices for oil precipitated by a Gulf crisis – at some point – actually becomes a benefit to a country producing as much oil as the US will in 2030.

“From a strategic perspective, the “Achilles heel” of China is its over-whelming dependence on Persian Gulf energy imports to fuel its rapidly growing economy,” says Samir Tata, a former U.S. intelligence analyst and author on naval issues. “The sea lines of communication over which these vital oil and gas imports are transported by tanker … and the choke points linking them are controlled by the US Navy.”

The Obama administration’s “pivot” to Asia may be the beginning of an end to this free ride. Given the costs – both financial and political – of maintaining the US Fifth Fleet’s carriers, escorts and submarines in the Gulf, and the continuing pressure in Washington to curb expenditures, it may not be long before Asian nations have to figure out a way to guarantee their own oil supplies.

This means a very different reality on the high seas. Nature is always a threat in the deep ocean, of  course, but since World War II commerce has not feared political threats except in specific places relatively close to shore – the Red Sea off Somalia or the Gulf of Guinea on Africa’s West Coast, for instance.

That may change over the next several decades as new players start acting on new incentives.

China’s disputed claims to areas of the South and East China seas have garnered headlines of late, but the management of the vital energy sea lanes through the Indian Ocean and its multiple bottle necks is a probably a more important factor behind the growth of naval budgets in the region in recent years.

After all, China’s disputes with Japan, South Korea, Taiwan, Vietnam and others over territorial waters is about oil and may exist beneath them. National pride, of course, also plays a role.

But the vast stretches of Indian Ocean that all these nation’s oil and gas imports must traverse is, to put it in the lexicon of national security, a “clear and present danger.”

The most publicized manifestation of this trend was the launch last year of China’s first aircraft carrier, a refitted Soviet Navy leftover renamed Liaoning.

Regionally, Indian military leaders have also expressed concerns about a system of port projects along Indian Ocean basin funded or partly owned by China. Referred to in India’s press as the “string of pearls,” these port facilities stretch from Myanmar to Bangladesh, Sri Lanka and Pakistan – with Chinese contractors also building major port facilities in Tanzania and Mozambique. India has also been alarmed by the increased activity of Chinese submarines in nearby waters.

Of course, Chinese companies are involved in port operations around the world – including the Panama Canal. China denies it wants to encircle India – a charge that frequently appears on Indian op-ed pages. Its navy’s expansion has proceeded at a pace that’s hardly surprising given the extent of its economic growth. And naval experts agree China’s navy is no match for Japan’s, would probably struggle against India’s relatively modern and larger fleet, and certainly cannot challenge the US Navy’s regional dominance.

Some regional strategists are hoping that the existence of a common threat to their interests – the risk of an interruption in Gulf oil flows – might foster cooperation rather than competition. So far, that’s simply not been the case. If anything, the region appears as fearful of China as losing its energy supplies.

Last month, Japan and India announced they would hold regular naval maneuvers together in the Indian Ocean – augmenting the annual US-led naval maneuvers that have been held – without China – since 2007.

Naval spending is also rising in Australia, Vietnam, the Philippines and South Korea, too. While few in official circles will say so publicly, as much of this spending is directed at the threat of Chinese domination of these vital sea routes and in the mutual interest all these nations have in securing them against interruption. The plans across the region include six carriers, dozens of powerful surface warships and over 100 submarines at a cost of some $220 billion by 2030.

That’s a regional armada that should keep Somali or Indonesian pirates at bay, to be sure. But it could also turn a reason for cooperation into a casus belli.

But in 2030, when crisis in the Persian Gulf once again threatens to become a debacle of global proportions, things will be different. Yes,  the region’s unique combination of repressive regimes, energy resources, intra-Islamic rivalry and pent up popular frustrations can still explode in violence, sending shudders through global markets, sending the price of oil sky high and prompting naval task forces based half a world away to put to sea. But from an American standpoint, a 2030 spike in global oil prices – at least while tight oil holds out  - might look more like a windfall than a tragedy.

Michael Moran is Vice President, Global Risk Analysis at Control Risks, the global political, security and integrity risk consultancy.

Tim Worstal on Keystone XL: These people really are getting desperate!

I really do understand that there are people out there who don’t want the Keystone XL pipeline to be built. For a number of different reasons, some of them even possibly sensible reasons. But there are at least some of the people opposing that pipeline who seem to be becoming desperate, even to the point of advancing self-contradictory arguments to oppose the pipeline. One such is here, from Consumer Watchdog.

U.S. gasoline prices will rise, with the greatest effect on the
Midwest. The chief purpose of the pipeline is to raise the price
of Canadian tar sands by creating new export markets outside
the Midwest. Statements by Alberta, Canada officials and the
pipeline developers reflect this aim. Their explicit intention is
to export to the Gulf and abroad, which would increase the
price of crude oil and gasoline in the United States and, in
particular, the Midwest.
• Midwest drivers would be hardest hit because the region
currently imports more than half of its oil for refining from
Canada. Increases at the pump could range from 25 cents to
40 cents a gallon, depending on how regional refineries re
spond to paying $20 to $30 more per 42-gallon barrel for
Canadian crude oil.
• Canadian oil currently sent to the Midwest from Canada
would likely be diverted to Keystone XL to reduce Midwest
supply, which would put additional pressure on gasoline prices.
• Midwest refiners have been reaping exceptional profit on
cheaper Canadian oil and will resist giving up that profit to off
-set the large increase in the price of their Canadian crude oil.

That last point doesn’t accord with the first point being made. In fact, that last point makes the first point being made wrong. It’s not possible for both to be true.

Think it through for a moment. Yes, Keystone will mean that more of the Canadian tar stuff reaches the Gulf refineries. This means that less of it will get stranded at Cushing OK. So, yes, the price of crude at Cushing will rise.

This could mean that gasoline prices will rise in the Mid West. But it can’t mean both that gas prices will rise and that excessive refining margins will fall. If excessive refining margins are being made then people in the Mid West aren’t getting cheap gas to reflect the low crude price. That’s where the excessive margins are coming from, from the fact that the gas price is disconnected from the crude price. So, we might either see a fall in those refining margins or a rise in gas prices. But both won’t be happening at the same time. If Keystone removes the oversupply of crude at Cushing then refining margins will fall and there’s unlikely to be much effect on gas prices.

The aim of tar sands producers with refining interests on
the Gulf Coast–primarily multinational oil companies–is to
get the oil to their Gulf refineries, which would process addi
tional oil largely for fuel exports to hungry foreign markets.
Other oil sands investors, including two major Chinese petro
chemical companies and major European oil companies, have
an interest in exporting crude oil and/or refined products
to their markets. Such exports would drain off what the tar
sands producers consider a current oversupply, and help push
global oil prices higher.

And that’s just ludicrous. How is an increase of supply of crude to the international markets going to increase the international price of crude? Have we entered some mirror universe of entirely alternative economics or something? An increase in supply leads to a fall in price, not an increase.

If you’d like a more detailed look at the arguments being made I recommend this from Craig Pirrong, aka The Streetwise Professor.

But my basic diagnosis is that some opponents of Keystone XL are becoming so hysterical in that opposition than they’re becoming incoherent in their arguments.