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Soros Signals Argentina’s Shale is Biggest Place to Be

By: staffjam Wednesday September 3, 2014 7:26 pm

One of the world’s legendary investors is upping his bet on Argentina’s shale oil and gas industry in a show of confidence for shale production in South America’s largest unconventional prize —and a big boost for both supermajors and smaller players making big waves in the heart of new discovery areas.

George Soros has doubled his stake in YPF SA, the state-owned oil company in Argentina, which sits atop some of the world’s largest shale oil and gas resources, and is about to get even larger following a new discovery over the last couple of weeks of a second key shale play.

Argentina holds an estimated 27 billion barrels of technically recoverable oil and 802 trillion cubic feet of technically recoverable shale gas, much of it located in the Vaca Muerta, an enormous shale formation in the Neuquen basin — the second-largest shale gas deposit and the fourth-largest shale oil deposit in the world.

And on Aug. 14, YPF announced the discovery of oil in another shale formation—Agrio shale–in the same basin.

Some estimates suggest that combined, the two plays’ reserves could be worth as much as $3 trillion.

“I am very excited with this [Agrio] discovery that proves that Vaca Muerta and Chubut’s D-129 formation aren’t the only shale deposits we have to exploit in Argentina,” YPF CEO Miguel Galuccio told reporters, according to Bloomberg. “The tests are very promising but still, it is too soon to provide figures.”

In the meantime, Soros’ confidence helps override some negative incidents that had held back investment in Argentina’s shale, including the government’s 2012 expropriation of YPF, then owned by Spanish firm Repsol, and the government’s failure to make a July 30 bond payment, which has resulted in a standoff with a hedge fund over unpaid bills back to the last default in 2001.

The government of Cristina Fernandez de Kirchner, however, has taken steps to repair Argentina’s relationship with international markets, and even tweaked tax laws in 2013 to give special benefits to big oil companies willing to invest more than $1 billion in the country.

The move was immediately followed by Chevron’s announcement that it would enter into a joint venture with YPF. To incentivize the global energy industry to further invest, additional steps are being taken, including discussions for a new hydrocarbon bill that could further standardize and incentivize the industry for both supermajors and mid-sized companies.

The newest discovery is certainly vindication for Soros’ gamble on Argentina. His company, Soros Fund Management LLC, took a strong position in YPF in the second quarter of this year, doubling its position. It now controls 3.5 percent of YPF’s American depositary receipts, worth $450.5 million.

Soros’ move suggests that his firm is not focusing on the short-term problems facing Argentina, but believes that the geological fundamentals are more important. By increasing his stake in YPF, he is betting that Argentina is sitting on some lucrative plays that could be bigger than the Eagleford or Bakken in the United States.

According to the Financial Times, “Some of the world’s largest hedge funds have been snapping up Argentine stocks, betting on an economic recovery in the country even though it defaulted on its debt for the second time in 13 years.”

And while the market has caught on to the ‘Soros Factor,’ it hasn’t yet caught on to the smaller companies that are positioned to benefit from the Vaca Muerta shale and the new Agrio find.

The Neuquen basin is also where YPF, in partnership with Chevron, is producing crude from the Vaca Muerta shale and is expecting to have nearly 300 wells drilled in the Loma Campana/Loma La Lata area.

It’s great news for Chevron, but it’s also great news for smaller players with big footprints on this scene who will benefit from all the supermajor drilling in the emerging Vaca Muerta and the new Agrio shale formations—as well as from the confidence boost provided by Soros.

There are only a few junior companies who have significant land holdings in Argentina’s Neuquen Basin, among them, Madalena Energy Inc., which will benefit from Chevron’s plans to drill 300 wells just west of the junior’s Coiron Amargo block.

The point is that as the supermajors drill, the smaller companies reap the benefits, positioning themselves for big rewards with big players who are eyeing their large tracts of land in this promising basin.

“Given the size of the resource prize in both Vaca Muerta and Agrio, Argentina is home to one of the biggest unconventional plays in the world,” said Kevin Shaw, CEO of Madalena Energy, which controls around 1 million net acres in Argentina and plans to begin shale development in the Agrio formation later this year or in early 2015.

“Some of the largest oil companies around the globe are continuing to actively drill and appraise     Argentina’s Vaca Muerta shale and  are now starting to do work in the Agrio shale,” Shaw said.

For oil and gas explorers both big and small, Argentina is back–with possibly more shale than the United States, and the industry is more active than ever..

Like Warren Buffet, when George Soros makes a big move, people notice. Their decisions, which sometimes run counter to conventional wisdom, are often seen in hindsight as signals of trends that few investors are noticing.

Source: http://oilprice.com/Energy/Crude-Oil/Soros-Signals-Argentinas-Shale-is-Biggest-Place-to-Be.html

By. James Stafford of Oilprice.com

 

New Technology Could End The Debate Over Pipeline Safety

By: staffjam Thursday August 28, 2014 7:16 pm

Who could have ever imagined that North America would surpass Saudi Arabia as the world’s largest producer of oil and natural gas liquids? A decade ago, that would have seemed laughable.

Yet that’s exactly what has happened; and it’s not just Saudi Arabia that has been left in North America’s dust — Russia has, too.

The surge in North American oil and gas production is arguably the most important development in energy over the last decade. That’s the good news. The not so good news is that North America doesn’t have nearly enough oil and gas pipelines to accommodate its 11-million-barrel-a-day output level.

The famously unresolved proposed Keystone XL pipeline would carry oil from Canada to the U.S. Gulf Coast, but its future is in legal and political limbo. The controversial Northern Gateway pipeline, proposed as an alternative to Keystone XL, would connect Canada’s oil sands to the Pacific Coast, allowing greater volumes of oil to be shipped to Asia, but it, too, is still on the drawing board.

Both are good examples of how pipelines – considered the safest way to move oil and gas – have become politicized and scrutinized, and not without reason. Despite their reliability, pipelines still lead to an unacceptable rate of safety mishaps. They corrode and rupture, which threatens workers and nearby communities. In 2013 alone, over 119,000 barrels of oil were spilled in 623 incidents.

America’s existing pipelines are getting older and more prone to corrosion, and over the next five to 10 years, there will be a significant increase in the number of new pipelines.

And that is creating a huge opportunity for better pipeline safety technology.

Monitoring and detecting corrosion in pipelines is still a crude affair (no pun intended). Pipeline companies tend to underspend on safety, concerned only with meeting the minimum regulatory requirements.

One of the major ways pipeline operators detect corrosion is with a “pig,” a machine that travels down the inside of a pipeline looking for problems.

Pigs are not new — the industry has long relied heavily on them—and the newest generation of pigs, known as “smart pigs,” is considered an improvement over the pigs of yesterday. Smart pigs give a read on the state of the pipeline, such as cracks, corrosion, and metal loss. Operators receive this information in a control room and can then dispatch crews to fix the problem. As of 2012, 93 percent of pipeline inspections were conducted using smart pigs.

But smart pigs might not be enough. Enbridge (NYSE: ENB), a major Canadian pipeline company, has spent over $4.4 billion to upgrade pipeline safety. It is spending big bucks after one of its pipelines spilled oil into the Kalamazoo River in 2010 – a corrosion breach that Enbridge’s smart pigs failed to detect ahead of time.

And that’s the problem: despite recent advances, smart pigs aren’t terribly accurate. They also require pipeline operations to shut down (you can’t pump oil through a pipeline if there is a machine in the way), and analyzing the data smart pigs gather can take some time. The Wall Street Journal ran an article last year that talked about the pitfalls of smart pigs, even as pipeline companies continue to depend heavily on them.

So alternative methods to detect trouble spots are needed. One method for detecting corrosion uses a device from outside the pipeline. A series of sensors placed on the outside of the pipeline can search for corrosion without interfering in operations.

Pipeline safety company Fox-Tek, a subsidiary of Augusta Industries (CVE: AAO), uses such a system to detect corrosion, as well as a fiber optic system to detect bends, strains and stress in pipelines.

But the real innovation in Fox-Tek’s system is its data analytics package. Companies that use smart pigs usually need to spend months doing post-inspection analysis, but Fox-Tek has developed proprietary software that does continuous and automatic analysis.

Fox-Tek’s sensors gather information and automatically send back confidential reports on everything the company needs to know – temperature, pressure, strain, rates of corrosion, etc. in the form of handy graphs, charts and diagrams. It eliminates the need for an army of people to go out and inspect pipelines and then come back to do the analysis.

The pipeline safety market is massive and growing, but one of the major hurdles for new technologies like advanced sensors and software will be reluctance by pipeline companies to proactively invest in corrosion management and maintenance. In the past, they have largely focused on the bare minimum and viewed safety as a regulatory requirement.

However, there seems to be a sea change in the pipeline industry, particularly since operators are running into an environmental backlash. The blocking of several high-profile pipelines may have finally gotten the attention of the industry. Bringing local communities onboard and acquiring permits from regulators will require pipeline operators to demonstrate improved safety throughout their networks.

But above all, pipeline companies will see dollars saved by using cost-effective monitoring systems to reduce pipeline leaks. Enbridge has been forced to spend around $1 billion to clean up its mess in the Kalamazoo River, which was the result of a corrosion breach. It could spend a fraction of that to have better information on pipeline corrosion to prevent a growing problem from getting worse. That could reduce the frequency of future pipeline spills.

This could be a game changer in terms of how oil and gas pipelines are viewed in North America. If operators use smart software to catch small problems before they can turn into big ones, the common view of pipelines as accidents waiting to happen could be erased. Instead of seeing them as an environmental risk, the public may grow to see them as just another piece of modern infrastructure that facilitates commerce.

Source: https://oilprice.com/Energy/Energy-General/New-Technology-Could-End-The-Debate-Over-Pipeline-Safety.html

By. James Stafford of Oilprice.com

Back to Permian: US Oil Comes Full Circle

By: staffjam Tuesday July 15, 2014 11:26 am

Much larger than Eagle Ford and once thought to have reached peak production, new technology has brought us full circle back to the Permian Basin in Texas and New Mexico, where the recent shift to horizontal well drilling has rendered this play the unconventional ground zero.

Determining where the next real oil boom will be depends largely on following the technology, and while the Permian Basin has been slower than others to switch from vertical well drilling to horizontal drilling, horizontal has now outpaced vertical, and investors are lining up to get in on the game.

Until about 12 years ago, virtually all wells in the Permian were vertical. As of last fall, however, horizontal and directional rig counts—meaning, non-vertical drilling rigs—have now begun to exceed vertical, according to RBN Energy.

But what they’re also looking for are developers who are seeing strong economics in both vertical and horizontal wells. It’s all about balance, and this co-mingling of multiple zones, with the ability to complete both horizontal and vertical wells economically is the best bet for investors.

The Permian Basin now boasts the top rig count in the US. Just this week, the number of rigs exploring for oil and natural gas in the Permian Basin increased by to 560, according to the weekly rig count report released Thursday by Houston-based oilfield services company Baker Hughes.

What’s more, according to Bernstein Research, the Permian Basin will top the charts for North American spending growth in 2014, with an amazing 21% increase. And 2013 was already a stellar year for the Permian.

Permian production last year increased by 280,000 boe/d to 2.3 million boe/d, comprised of 1.4 million b/d of oil and 5.3 bcfd of gas, according to the US Energy Information Administration.

This technology has changed the way we think about the Permian Basin, once the darling of American oil production and then lost in the shadow of Eagle Ford and Bakken. While Eagle Ford and Bakken were viewed as the “bigger plays” at the start of the unconventional boom in the US due to the fact that new technology debuted here harder and faster, the Permian is back and it’s bigger than ever.

“The Permian Basin is much larger than the Eagle Ford play, and it also contains over 20 potentially productive zones, while Eagle Ford has only one zone,” Parker Hallam, CEO of Crude Energy—a small-cap company, not publicly traded, operating in the Permian, told Oilprice.com.

Hallam particularly noted the “excellent quality rock” in the Wolfcamp, Fusselman, Cline, Mississippian and Strawn zones.

“The Wolfcamp is one of the better producers in the Permian. It can be up to 1000 feet thick and is composed of multiple individual zones, several which could be production. Wolfcamp is attracting a lot of attention right now because of the horizontal drilling through the normally tight limestone,” he said.

Hallam also noted that while horizontal drilling is changing the future of the Permian Basin, “vertical completions using new technology like fracking and co-mingling multiple zones are turning out top results and drillers are seeing strong economics in these wells.”

Leading the pack in the Permian are Devon Energy Corp., Concho Resources, Pioneer Natural Resources and Chevron, with Wolfcamp probably the key focus of development activities, and the leading formation in terms of production increases. Devon in particular is being singled out by analysts for its large acreage in the Permian, couple with its transformative turnaround that could render it one of the largest crude oil producers in the US.

The only challenge with the Permian—which is on trend to see continual increases in production—is the pipeline takeaway capacity, according to RBN Energy. “The bottom line is that crude oil production in the Permian is growing rapidly, and today there is not enough pipeline takeaway capacity to efficiently handle the volume”, but that should correct itself soon with new pipelines coming online.

Bloomberg quoted Bruce Carswell, West Texas operations manager for Iowa Pacific Holdings, as saying that the forecast through July is that volumes are going to continue to move out of the region by rail.

The Permian Basin Petroleum Index, put out by Amarillo economist Karr Ingham, which examines several industry metrics to measure the health of the oil and gas business in the region, was almost 10 percent higher in May than a year earlier.

Regardless of pipeline capacity, Permian Basin crude is shaping up to be the next big oil boom thanks to new technology. Eagle Ford and Bakken became economical only after being drilled horizontally, so with the final shift to dominate horizontal drilling in the Permian, the game has only just begun.

Source: https://oilprice.com/Energy/Crude-Oil/Back-to-Permian-U.S.-Oil-Comes-Full-Circle.html

By James Stafford of Oilprice.com

New Spy Technology to Spawn Oil Revolution

By: staffjam Monday March 3, 2014 3:04 pm

The future of oil exploration lies in new technology–from massive data-processing supercomputers to 4D seismic to early-phase airborne spy technology that can pinpoint prospective reservoirs.

Oil and gas is getting bigger, deeper, faster and more efficient, with new technology chipping away at “peak oil” concerns.  Hydraulic fracturing has caught mainstream attention, other high-tech developments in exploration and discovery have kept this ball rolling.

Oil majors are second only to the US Defense Department in terms of the use of supercomputing systems, which find sweet spots for drilling based on analog geology. These supercomputing systems analyze vast amounts of seismic imaging data collected by geologists using sound waves.

What’s changed most recently is the dimension: When the oil and gas industry first caught on to seismic data collection for exploration efforts, the capabilities were limited to 2-dimensional imaging. The next step was 3D, which gives a much more accurate picture of what’s down there.

The latest is the 4th dimension: Time, which allows explorers not only to determine the geological characteristics of a potential play, but also tells them how a reservoir is changing in real time.   But all this is very expensive.  And oilmen are zealous cost-cutters.

The next step in technology takes us off the ground and airborne—at a much cheaper cost—according to Jen Alic, a global intelligence and energy expert for OP Tactical.

The newest advancement in oil exploration is an early-phase aerial technology that can see what no other technology—including the latest 3D seismic imagery—can see, allowing explorers to pinpoint untapped reservoirs and unlock new profits, cheaper and faster.

“We’ve watched supercomputing and seismic improve for years.  Our research into new airborne reservoir-pinpointing technology tells us that this is the next step in improving the bottom line in terms of exploration,” Alic said.

“In particular, we see how explorers could reduce expensive 3D seismic spending because they would have a much smaller area pinpointed for potential.  Companies could save tens of millions of dollars.”

The new technology, developed by Calgary’s NXT Energy Solutions, has the ability to pinpoint prospective oil and gas reservoirs and to determine exactly what’s still there from a plane moving at 500 kilometers an hour at an altitude of 3,000 meters.

The Stress Field Detection (SFD) technology uses gravity to gather its oil and gas intelligence—it can tell different frequencies in the gravitational field deep underground.

Just like a stream is deflected by a big rock, SFD detects  gravity disturbances due to subsurface stress and density variations.   Porous rock filled with fluids has a very different density than surrounding solid rocks. Remember, gravity measurement is based on the density of materials. SFD detects subtle changes in earth’s gravitational field.

According to its developers, the SFD could save oil and gas companies up to 90% of their exploration cost by reducing the time spent searching for a reservoir and drilling into to it to determine whether there’s actually any oil and gas still there.

“Because it’s all done from the air, SFD doesn’t need on-the-ground permitting, and it covers vast acreage very quickly. It tells explorers exactly where to do their very expensive 3D seismic, greatly reducing the time and cost of getting accurate drilling information,” NXT Energy Solutions President and CEO George Liszicasz, told Oilprice.com in a recent interview.

Mexico’s state-owned oil company Pemex has already put the new technology to the test  both onshore and offshore in the Gulf of Mexico, and was  a repeat customer in 2012.  They co-authored with NXT a white paper on their initial blind-test used of the survey  technology.

At first, management targeted the technology to frontier areas where little  seismic  or well data existed.  As an example, Pacific Rubiales Energy is using SFD technology in Colombia, where the terrain, and environmental concerns, make it difficult to obtain permits and determine where best to drill.

The technology was recently  contracted in the United States for unconventional plays  as well.

Source: http://oilprice.com/Energy/Energy-General/New-Spy-Technology-to-Spawn-Oil-Revolution.html

By. James Burgess of Oilprice.com

The Boundless U.S. Natural Gas Boom: Exclusive Interview with EIA Chief

By: staffjam Sunday February 23, 2014 7:09 pm

The Energy Information Agency (EIA) has predicted that natural gas production in the US will continue to grow at an impressive pace. Right now output is close to 70 billion cubic feet a day and is expected to reach over 100 billion cubic feet per day by 2040. The trend is likely to continue without hitting a geologic “peak”, and along with this trend will come new marketing opportunities for America.

In an exclusive interview with Oilprice.com, EIA Administrator Adam Sieminski discusses:

  • What’s at stake in lifting the US crude export ban
  • Whether lifting the ban is inevitable
  • Why energy-related CO2 emissions will likely climb this year
  • What we can expect from US coal output through 2014
  • Why US natural gas production will continue to grow strongly
  • Where we can expect (unexpectedly) new production to come from
  • Why Alaska just might surprise us
  • Where the biggest new shale opportunities lie
  • How production increases might come from ‘non-shale’ formations
  • The potential for Colombian shale
  • What to expect from Mexico’s reforms
  • What the Panama Canal expansion really means
  • Why we will see new marketing opportunities for the US

Interview by James Stafford of Oilprice.com

Oilprice.com: US mainstream media are heralding the debate over lifting the US crude oil export ban as potentially one of the most critical for this year. While most agree this is not likely to happen anytime soon, is it an eventuality?

Adam Sieminski: When I first took office at the EIA, I said that light sweet crude oil production was growing very rapidly, and that it would ultimately have a number of impacts on the energy infrastructure in the US; for instance, that we would see changes in things like movement of oil by rail.  We would see changes in refinery configurations designed to deal with light sweet crude. The Gulf Coast refineries in the US over the past decade were upgraded to run heavy sour imports, and so there are issues with the ability of refineries in the US to handle rapid increases in light sweet crude oil production.

I noted at the time that at some point, policymakers were going to be confronted with all of these changes resulting from the enormous shift in thinking about US production growth.  Five or 10 years ago, everybody thought that US oil production would just go down, and demand would always go up. Now we have in the EIA’s forecast over the next five years very strong growth in crude oil production and weak growth—if not negative trends—going on in gasoline and liquid fuels demand.  This creates an interesting atmosphere.

Is lifting the crude export ban inevitable? I’m not sure that anything is inevitable. Certainly what I’ve learned in the last five years is that the inevitable declines in production and growth in demand didn’t come true.

Oilprice.com: What are the congressional hurdles faced here?

Adam Sieminski: I don’t know that there’s a hurdle. That’s a question that’s going to be dealt with by policymakers. Energy policy issues generally tend to involve environmental concerns, national security concerns, and economic concerns.

The biggest hurdle that congress faces is just having good information on future trends in supply and demand, refinery configurations and pipeline and railroad transportation infrastructure.

Oilprice.com: What would be the consequences of lifting this ban, for the industry, for refiners, for consumers?

Adam Sieminski: Well, that’s going to be part of the debate. I don’t have the answer to that, and I doubt that anybody at this point has the complete answer to that question. What is the economic impact? Does it increase jobs or not? What is the environmental impact of producing, moving and refining the crude oil? What are the national security implications? Is it better to keep the oil here, or to move it into global markets where it might have an ameliorating effect on volatility? There are a lot of questions, so I’m not going to try to pre-judge that debate.

Oilprice.com: The EIA has noted that after two years of declining production, US coal output is expected to increase in 2014, forecast to rise almost 4%,  as higher natural gas prices make coal more competitive for power generation. At the same time, there is concern about the EPA’s proposed new carbon emissions standards for power plants, which would make it impossible for new coal-fired plants to be built without the implementation of carbon capture and sequestration technology, or “clean-coal” tech. Is this a feasible strategy in your opinion?

Adam Sieminski: Well, the facts as you laid them out are certainly what the EIA is looking at.  Natural gas prices have gone up, so in 2013, we already saw some recovery in coal at electric utilities. As a consequence, energy-related carbon dioxide emissions actually climbed in 2013 and probably are going to do so again in 2014 for the reasons that you stated.

Longer term, even without changes by the Environmental Protection Agency, there’ll be coal retirements, and the amount of coal being burned in the US will eventually come below the amount of electricity being generated by natural gas. So sometime after the year 2030, we will have more electricity in the US being produced from natural gas than from coal.

Oilprice.com: What can we expect from US onshore natural gas production over the next two years;
over the next five years? And where will production increases offset declines?

Adam Sieminski: Well, the EIA has been pretty clear on this in our Annual Energy Outlook Reference case for 2014, which we published in mid-December. We reiterated what we said the previous year: natural gas production in the US is going to continue to grow very strongly. We are close to 70 billion cubic feet a day of output now. That number will be over 100 billion cubic feet a day by 2040. Shale gas will be easily 50% or more of production by 2040.

We also see increases in natural gas production from geologic formations that we don’t consider to be shale gas. We think that there might also be some production, believe it or not, from Alaska, because the economics ultimately will favor construction of an LNG facility in Alaska that would allow production from the associated gas in the North Slope of Alaska.

Just in the last five years, we’ve seen natural gas production in the US from shale go from about five billion cubic feet a day to nearly 30 billion cubic feet a day–a huge increase. A lot of that is coming from places like the Haynesville—and more recently the Marcellus in Pennsylvania and West Virginia. In our view, those production trends are going to continue without the likelihood of running into a plateau from a geologic standpoint.

Oilprice.com: How do you see future extraction, development and commercialization of oil and gas resources in the Americas playing out over the next 5-10 years?

Adam Sieminski: Well, the big new opportunities, I think–certainly in the US and Canada–lie in the development of shale resources. There are oil and gas shale resources in places like Argentina, Mexico, Columbia, and elsewhere across the Americas. Whether or not the very rapid development of shale resources in the US can be duplicated in a lot of other countries—even in the Americas—remains to be seen. Certainly there has been some interesting progress in developing shale resources in Canada and Argentina.

I’ve been hearing from many people that they’re quite hopeful there will be developments in shale in Colombia, and given the constitutional changes that have now been agreed in Mexico, that opens up an opportunity for Mexico to step into this area.

One of the things that is happening is the increase in oil production in the US and the fact that we have very sophisticated refineries with very strong technology, while relatively low natural gas prices are allowing us to run our refineries at higher utilization rates and dispose of surplus products—by exporting petroleum products like gasoline and diesel fuel—into Latin America and Canada.

In a sense, this creates a manufacturing opportunity for the US to take a raw material, process it, and sell it abroad. It also fits in pretty well with the fact that a number of countries in Latin America have had difficulty in building and upgrading their own refineries.  So it’s opened up a marketing opportunity for the United States to take advantage of.

Oilprice.com: What can we expect from Mexico’s recently adopted energy reforms and what regional effect could this have?

Adam Sieminski: Well the Mexican government and Pemex, the state oil company, are very excited about the opportunities they see for Mexico to increase its production and to take advantage of some of the new technologies that are available through cooperation with non-Mexican companies. They believe that it is going to be instrumental in reversing some of the difficulties they’ve had in oil production and natural gas production.

It certainly looks to the EIA as something that we’re going to have to watch very carefully when considering the longer-term outlook for Mexican energy production.

We actually bumped up the Mexican numbers because of the opportunities we think will be created by constitutional reform there. If the implementation of that proceeds along the lines that the Mexicans are considering, I think we’ll probably have to look at it again.

Oilprice.com: In its latest report, the EIA notes that the Americas accounted for 20% of global natural gas trade, and while 80% of that was via pipeline, the rest was traded as LNG. How do you see this proportion changing over the next 5-10 years?

Adam Sieminski: Well, I suspect that we’re going to see more of both. Our longer-term outlook shows US pipeline exports of natural gas to Mexico going up, and we also see LNG exports from the United States increasing. We’re not responsible for permitting. What we try to do is look at the economics. We run our national energy modeling system to basically say, “What would the economics do if you let them run?” And that shows we’re likely to see increases in exports of both LNG and pipeline gas.

Interestingly, the model also says that there’s plenty of production to do that and still allow demand in the US to go up considerably. We’re seeing demand increases in natural gas use by refineries; it’s a big refinery fuel. And in the industrial sector, we see significant gains in natural gas consumption occurring in areas like bulk chemicals, food processing, and elsewhere. And then the biggest increases in natural gas may come from electric utilities, which will likely be using more natural gas relative to coal to provide electricity growth in the United States.

Oilprice.com: Is the US Department of Energy moving too quickly or too slowly to approve LNG exports to non-FTA countries?

Adam Sieminski: I think that the Department of Energy’s Department of Fossil Energy, which is responsible for permits, is moving exactly the way it should under the law to make the kinds of findings necessary from a legal standpoint. I wouldn’t characterize it as too fast or too slow. I would say that from what I can see, it’s just right given the legal framework.

Oilprice.com: When could we expect the US to become a net gas exporter?

Adam Sieminski: The EIA’s forecast is that the US will become a net exporter of natural gas before the end of this decade.

We’re already a net exporter of coal. In terms of electricity, most of our trade is with Canada, and that never really seems to have been much of an issue. The US is also a net exporter of petroleum products, so we now export more gasoline and diesel fuel than we import. We import a lot of oil products, particularly into the East and West Coasts. But we are a big exporter, mostly from the Gulf Coast, with the increase in refinery utilization down there. The overall picture now is one in which the US trade deficit is being reduced by growing oil and petroleum product exports.

The only big outstanding question is: could the US potentially be a net exporter of crude oil? In the EIA’s Reference case forecast, that doesn’t seem likely. Despite the fact that our production is rising while demand is falling, we’re still importing about five million barrels a day net of of crude oil and products. It doesn’t seem likely that net importsd are going to go to zero–at least not given the facts as we currently see them. It’s possible, in a high petroleum resources case combined with a technology and policy-driven low demand case, but not probable.

One thing you want to keep in mind is what it would mean, exactly, if the US were completely self-sufficient in energy. Some people like to use the phrase, “energy independence.” We would still be part of a global trading system in energy, and particularly petroleum products and crude oil. And if oil prices go up globally, they’re going to go up in the United States. If there’s a geopolitical problem somewhere or a weather problem somewhere—anything—the US would be impacted just as it has always been. The US has a lot of interest in what’s going on around the world, in the Middle East and elsewhere, regardless of whether it is independent or self-sufficient in fuels. Those political and economic interests will remain whether we become an exporter or not.

Oilprice.com: What role will the expansion of the Panama Canal play in this?

Adam Sieminski: What they’re doing is widening the Panama Canal. They’ll make the Canal itself wider and the locks longer, and the net result will be the potential to save in transportation costs through the use of larger oil tankers and LNG tankers. This offers an opportunity to reduce the costs associated with global trade. It is something that I know Panama and all of the customers who use the Panama Canal are very interested in seeing happen. There have been some cost and labor issues, but I’m sure those will be resolved and this expansion will eventually be completed. When that happens, it’s going to reduce the cost of moving goods back and forth between the Atlantic and the Pacific, and that’s going to apply particularly to things like liquefied natural gas and oil.

Source: http://oilprice.com/Interviews/Boundless-Natural-Gas-Boundless-Opportunities-Interview-with-EIA-Chief.html

By. James Stafford of Oilprice.com

Are Canadian Energy Stocks Set for a Rebound?

By: staffjam Thursday November 21, 2013 5:42 pm

As Canadian energy stocks are finally seeing a bit of a push, and demand for Canadian commodities looks set to rise, juniors are confident that economics will ensure that Canadian oil—the cheapest in the world—will find its way to more markets, with or without Washington’s approval of Keystone XL. In the meantime, some sweet spots in the Western Canada Sedimentary Basin, like the Montney shale formation—are showing promise as gas turns into oil for the bigger players, while the juniors are hoping to piggyback on this new success.

In an exclusive interview with Colin Soares, the CEO of High North Resources we discuss:

•    How Libya and Warren Buffet boosted Canadian energy stocks
•    Why we can expect stronger demand for Canadian commodities
•    Why simple economics favors Canada’s cheap crude
•    Why Canadian juniors are banking on $70 oil
•    Why oil price volatility will haunt us
•    Why we shouldn’t expect a big change in Canadian crude price differentials just yet
•    Why Washington’s approval of Keystone XL isn’t as critical as before
•    What we can expect from all the hush-hush over the Western Canadian Sedimentary Basin
•    How the key for juniors in the Montney shale is to piggyback off the shift from gas to oil exploration

Interview by James Stafford of Oilprice.com

James Stafford: For the first time in months, Canadian ETFs are seeing an increase in flows—especially for financial and energy stocks. What is pushing this?

Colin Soares: I think there were a few factors. International money started flowing back into Canadian energy as global oil prices jumped 15%, on the back of Libya production falling down.  WTI followed suit and all of a sudden the Canadian oil price was over $100 a barrel.  Cash flow and profitability soared in Q3 2013.

Canadian management teams have got so used to deep oil price discounts, we focus only on developing top assets—ones that payout in a year on $75 oil.  That’s certainly true for the juniors—and there are hundreds of them in Canada.  We have become a lot more disciplined in the last year as investors switched from growth at all costs to sustainable growth; growing within cash flow.

Then I think you just combine all that with the fact that the valuations on Canadian oils were so cheap—from juniors like us right through to seniors like Suncor. Warren Buffett bought a big chunk of Suncor this year and I think that helped money flows into our sector as well.

James Stafford: Can we expect stronger demand for Canadian commodities?

Colin Soares: Absolutely. The Americans are not allowed to export their crude, and Canada is. We now have the cheapest oil in the world, and simple economics says it will find a way to a market. The light oil might go to the west coast via a new pipeline, or it might travel across Canada to the eastern Maritime provinces, but it will find a way—for both heavy and light oil.

The US will always want our heavy oil, as their refining complex is mostly heavy oil. And our heavy oil trades at a discount to both Mexican and Venezuelan heavy oil.

James Stafford: What does this mean for Canadian juniors?

Colin Soares: It means we can budget on at least $70 oil, which is what we’re doing.

James Stafford: Canadian heavy crude is sold at a large discount to US and world crude, but analysts are now predicting the end of these big price “differentials” as they’re called, for Canadian heavy oil. Do you see an end to this volatility, and what factors will contribute to closing this gap?

Colin Soares: No, volatility will absolutely stay. Just having one refinery go down creates a big differential for a few days. And of course, pricing is seasonal as refinery maintenance happens in spring and fall, and oil prices are lower then, and the differentials are bigger then. You just get used to that and budget an overall price. Strong projects, with good economics will make money regardless of fluctuations in the oil price.

At High North we have been using a $70/barrel oil price to calculate our numbers and we are confident that we still have one of the fastest payouts of any wells in North America.

James Stafford: How do you see this playing out by the end of the year and into the first quarter of 2014?

Colin Soares: Differentials will stay larger than normal—though what’s normal anymore?—through Q1 2014 until more pipeline capacity gets into place around North America.  There is 800,000 barrels a day of refining capacity coming online in just the next two weeks!  That is more competition and will raise North American oil prices.

And pipelines are racing to keep up to production increases and doing a good job.  TransCanada’s Keystone South project will be starting in just a few weeks taking oil from Cushing down to Houston.

James Stafford: How much depends on Washington’s approval of the northern leg, the Keystone XL pipeline?

Colin Soares: Fundamentally, not as much as before—because of huge increases in crude being transported by rail—but from a market point of view I think it’s still a big deal– I  think market valuations would increase with Keystone approval.
But even with the approval of the Keystone XL, we are still a long way off until the pipeline is built and price differentials narrow to be really tight. Once again, good projects with strong economics will make money regardless of the fluctuations in the oil price.

James Stafford: Will Canada continue to increasingly rely on rail transport for oil products despite the Quebec train disaster?

Colin Soares: Yes, and in the US as well.  Right now Canada is transporting about 200,000 bopd of oil by rail, and experts are thinking that will more than double in two years. Until new pipelines are approved and built, oil products will rely more on rail.

James Stafford: As we head into a New Year, what will be the key drivers for the Canadian oil and gas industry?

Colin Soares: I think the market will be more focused on balance sheet and financials, not just straight growth, or growth at any price.  It’s a lot more about sustainability now.  With a lower oil price, you will have to show you can grow inside cash flow, or very close to cash flow.  Plays where the wells payout their costs really quickly—like around a year–will get a premium.   And that’s the type of asset we have.

James Stafford: Canada’s National Energy Board just said the Montney Formation in the
Western Canadian Sedimentary Basin is one of the largest gas deposits in the world—some 450 trillion cubic feet of gas, 14.5 billion barrels of liquids and 1.1 billion barrels of oil.  What does that mean for the Canadian energy industry?

Colin Soares: For gas, it means we have decades of supply—and low cost supply.  All those liquids like propane and condensate pay for the gas wells—so the gas has almost no cost to it.  The liquids make the gas very economic.

And so when everybody starts drilling these big gas wells, they’ve been finding oil as well.  And you’re seeing  a lot more exploration now targeting light oil to the North.  The oil is shallower, and so it’s cheaper to get it out of the ground—it’s actually a perfect play for a junior like High North.

James Stafford: How much can we expect to be spent on developing the Montney oil play for this year and next?

Colin Soares: There are several companies working in north-western Alberta who are having success developing the Montney oil play. Long Run Exploration recently announced a $110-million expenditure to develop its Montney oil project—they’re right beside us developing a big fairway. RMP Energy recently raised $50 million through GMP Securities, bringing their capital budget to $168 million for their Montney project.

James Stafford: What’s the sweet spot in the Montney formation for oil?

Colin Soares: That’s too early to say yet.  I would love to say we are in the sweet spot, being as Long Run is just to the north and east of us and RMP is just to the south and west, but the reality is that RMP right now looks like it has an initial sweet spot at Ante Creek.

But there is still a learning curve involved with drilling successful wells. The key for the juniors is to piggyback off the knowledge of larger players like Long Run and RMP.

James Stafford: Colin, thanks for taking the time to join us today.

Source: http://oilprice.com/Interviews/Are-Canadian-Energy-Stocks-Set-for-a-Rebound-Interview-with-Colin-Soares.html

The Big Winners in Kenya’s Oil Debut

By: staffjam Wednesday October 23, 2013 11:09 am

Kenya will start pumping its first commercial oil next year and begin exporting in 2016, but this is just the opening salvo: new discoveries in recent months and fast-track new well development make Kenya the darling of East Africa from an investor’s perspective.

Kenya is set to soar past Uganda, which discovered oil much earlier, but is now having a hard time getting it out of the ground and into the market. And the next five months should bring not only news of the first commercial output for Kenya, but new commercial prospects coming online.

As the discoveries pile up for pioneers British Tullow (TLW-LSE) and Canadian Africa Oil (AOI-TSXv), the plan now is to escalate development and further the pace of exploration, while a third winner in this scenario—Taipan Resources (TPN-TSX)—is set to benefit enormously by owning acreage right next to the pioneers’ high-reward prospects.

Tullow, in partnership with Africa Oil–made the first discovery in western Kenya just last year, and in total have discovered more than 300 million barrels of oil equivalent resources in Kenya’s South Lokichar Basin, and they are still exploring.

In late September, the duo announced a fourth crude-rich discovery at Ekales, hitting a net oil pay of 60-100 meters. Significantly, this discovery is right between the Ngamia-1 and Twiga South-1 wells that first put Kenya on the oil map, and the reservoir properties are similar.  Drilling success here has been 100% and this is the fourth consecutive wildcat discovery in this basin since March 2012.

In the next 12 months we can expect another 12 wells to be drilled along Kenya’s “string of pearls”, and what investors are sure to be eyeing is the fast progress on two new wells–Bahasi and Sala–being drilled by Tullow and Africa Oil. These wells—targeting 700 million barrels between just the two of them—are in eastern Kenya, and this is where Taipan is.

The catalysts here for Taipan are increasing by the day.

The Bahasi is a 300-million-barrel well that was spudded earlier this month and should be completed around December this year. Upon completion of Bahasi, Tullow and Africa Oil will start drilling the Sala well, which is a massive 402-million-barrel prospect.

This spreads the discovery net wider, and Taipan is eagerly eyeing the results because both new wells are right next to their own Block 9 acreage, so a hit for one here means a hit for all.  They’re all targeting the same geology—the Tertiary part of the Lower Cretaceous.

Africa Oil and operator New African Global Energy also expect to spud the highly prospective El Kuran well this month. El Kuran is just to the north of and on trend with Taipan’s Block 1. It’s a low-risk prospect because there has already been a discovery and it’s really about testing commerciality and flow rate.

And with the 100% success rate for drilling in Northern Kenya so far, there is reason to be optimistic.

For Taipan, there are plenty of other catalysts as well, including a farm-out agreement earlier this month for 55% of its Block 2B with Premier Oil Investments Limited, which will cover the cost of drilling and testing its Pearl-1 prospect. The drilling campaign should be in place by the second quarter of next year.  A lot of information on geology will come to light—before Taipan drills–from the Bahasi and Sala wells.

It was only in 2012 that Tullow and Africa Oil struck the first oil in Kenya. This makes a commercial production timetable of 2014 and export goal of 2016 an amazing success story and puts Kenya leaps and bounds ahead of its neighbors.  With a string of successes and money pouring into the country from major oil companies—over $100 million in deals have recently been announced—Kenya’s risk/reward ratio is tipping heavily into investor’s pockets.

By. James Stafford

Originally published at Oilprice.com

No More Spills? New Technology Could Transform the Pipeline Sector

By: staffjam Monday August 12, 2013 8:57 am

The 2010 Kalamazoo spill and the 2013 Exxon leak in Arkansas are the most glaring incidents, but these are just the big leaks that are found right away and reported.

Most leaks are found eventually—but there is money to be saved and damage to be avoided by catching them at the smallest rupture. Right now, we rely on pigs in the pipeline to do this.

It’s called “pigging”. Pigs are inspection gauges that can perform various maintenance operations on a pipeline—from inspection to cleaning—without stopping the pipeline flow. The first “pigs” were used strictly for cleaning and they got their name from the squealing noise they emitted while travelling through the pipeline. The current generation of “smart pigs” can detect corrosion in the pipeline and are thus relied on for leak detection.

The Kalamazoo and Arkansas leaks were massive and caused by complete pipeline ruptures. These are rare incidents that account for less than 10% of leaks. But the small leaks–those that traditional pipeline detection systems don’t catch—account for more than 90% of US pipeline leaks.

According to a recent report from the U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration (PHMSA), the majority of leaks are smaller but can persist for months or even years, and those that are even reported are generally done so by people who have stumbled upon them by accident.

The fact remains that current systems and technologies only detect 50% of leaks. We need new solutions if we want to avoid another Arkansas, or another Kalamazoo.

The “pigs” are the darlings of the regulators, who force operators who have had any problems to “pig” their lines at a massive cost of over $1,000 per kilometer.

Certainly, today’s smart pigs are well advanced beyond their ancestors—the balls of rags wrapped with barbwire, but they have their shortcomings.

Pigs can spot general corrosion and identify potential areas of concern, but they cannot detect pinholes in pipelines as their spatial resolution is poor and they can only see corrosion that is 1-2 inches in size. This is significant because a small leak of 10 barrels per day from a liquid pipeline operated at a standard pressure would come from a hole much smaller than this.

They are also only deployable over tens of kilometers, not the thousands needed.

Even if all the pipelines in the world were “pigged” every year, a pipeline operator would still not be able to ensure that small leaks are being detected.

For the larger pipes, the industry relies on SCADA. SCADA is a basic infrastructure monitoring system, where remote hubs relay data back to central monitoring point, using fiber-optic cable or other communications equipment. But it is not enough on its own.

A case in point is this: A SCADA system was working normally on the Pegasus pipeline in Arkansas at the time of the rupture and helped Exxon verify that an accident had occurred. Pegasus did not, however, have a Computational Pipeline Monitoring (CPM) program in place on the pipe. It wasn’t enough. Indeed, in late 2012, PHMSA issued a 17-page warning to Exxon about its insufficient pipeline leak detection.

Then we have Keystone XL, which is always in the spotlight, most recently when TransCanada said it would opt out of new pipeline leak detection systems and stick with traditional methods that many believe are not good enough.

The 90%+ of leaks are small and more of a concern for the miles and miles of aging pipelines that crisscross the US, while new pipelines, like Keystone XL will benefit from new technologies during their construction, such as better pipe metallurgy and better welding. This will mean less chance of leaks, but not a zero chance. The fact is that the leak detection systems that will be used by new pipelines like Keystone XL (assuming it gets the green light), are not really any better than the current fare.

There is new technology floating around out there—but it’s new and relatively untested in the marketplace.

RealSens remote-sensing pipeline detection technology aims to pick up where SCADA and the pigs leave off, detecting leaks over an entire pipeline network.

According to Banica, Synodon’s CEO, realSens can actually save companies money by detecting the leaks sooner and faster and thus reducing the amount of spilled product and the environmental damage. But it’s a new technology that was only introduced into the market 12 months ago.

Still, some of the big operators remain skeptical of new pipeline leak detection systems, as their cost-saving applications are as yet unproven.

“The first hurdle is that operators might not be aware that it exists and what the capabilities are. The second hurdle is that they have a hard time believing it works and have to see proof through customer field tests, which are currently ongoing,” Banica told Oilprice.com.

But the issue of pipeline leak detection will increasingly be on everyone’s radar following the Quebec train disaster that killed at least 38 people, and counting. No pipeline failure has ever come close to this level of human carnage. This will help shape the transport debate.

What the Quebec tragedy demonstrates, says Banica, is that pipelines are a far better option than rail. “Whereas pipelines do not kill as many people as rail (or even truck transport, as more drivers die due to accidents), they do pose a bigger environmental risk than rail due to larger potential leaks and releases.”

Source: http://oilprice.com/Energy/Energy-General/No-More-Spills-New-Technology-Could-Transform-the-Pipeline-Sector.html

By. James Burgess of Oilprice.com