6 Key Oil & Gas Discoveries of 2013 – Who's Worth Owning

6 Key Oil & Gas Discoveries of 2013 – Who's Worth Owning The pace of oil and gas exploration is frightening, and discoveries are weekly, if not daily, with volumes investors would only have dreamt of a decade ago. With each new discovery, it becomes difficult to keep track of the playing field, and even more difficult to rank the potential. There are also a lot of juniors popping up on the scene now, exploring, finding and developing with the intent to lure the bigger players to buy them out. So we'll make it easy for you here, with our list of 6 key oil and gas discoveries so far this year, followed by a short list of the companies we think have the best potential—and they're not necessarily the ones who have made the biggest discoveries. Last year, it was all about East and West Africa, with game-changing finds in Kenya, Mozambique, Angola, Ghana and Ivory Coast that have sent explorers on a feeding frenzy looking for analog plays in the region and finding plenty. This year, so far, we like the discovery revival in the Gulf of Mexico and handful of new sub-salt and pre-salt plays. 6 Key Discoveries of 2013 Shenandoah-2/Gulf of Mexico In mid-June, Anadarko Petroleum (APC) announced a major new discovery in this deep-water play: more than 500 million barrels of crude oil in the Shenandoah-2 well. This find is important: the implications are massive and this means we could be looking at a major oil rush in the Lower Tertiary trend. (Anadarko shareholders should be thrilled). And it wasn't easy (or cheap): Anadarko drilled through some six miles of rock in water at a depth of 5,800 feet. The Lower Tertiary trend and its sub-regions could hold up to 15 billion barrels of oil. What this discovery means is that the US oil boom is far from over, and the Gulf of Mexico Lower Tertiary trend is still surprising us. Anadarko's find solidifies a trend that began with ExxonMobil's 2010 discovery of the Hadrian field (700 million barrels); Royal Dutch Shell's discovery of the Appomattox field (500 million barrels); Chevron's discovery of the Moccasin field (200 million barrels); and BP discovery of the Mad Dog field (est. 4 billion BOE). Coronado Prospect/Gulf of Mexico In May, Chevron Corp (CVX) announced a new discovery at its Coronado prospect in the Gulf of Mexico, at the Walker Ridge Block 98-1 well. The well is some 190 miles off the coast of Louisiana in the Lower Tertiary sub-salt trend, in water of around 6,127 feet, but it's been drilled to a depth of 31,866 feet! (One of the deepest wells ever drilled and probably cost at least $250 million, though we don't know for sure). The scale of the reserves is still under appraisal for commercial viability, and Chevron currently holds a 40 percent working interest in the prospect. Other owners of the Coronado prospect are ConocoPhillips ( COP ) with a 35 percent stake, a subsidiary of Anadarko Petroleum Corp. ( APC ) with a 15 percent stake, and Venari Offshore LLC with a 10 percent stake. Harpoon Discovery/Newfoundland In mid-June, Norway's Statoil announced it was evaluating a new discovery of high-quality oil off the coast of Newfoundland, about 500 kilometers northeast of St. John's. The Harpoon discovery is under some 1,100 meters of water. While we don't know the extent of the Harpoon discovery just yet, what we like is that it is only 10 kilometers from the earlier Mizzen discovery, which is estimated to hold between 100 million and 200 million barrels of oil. Statoil owns a 65% stake in Harpoon (the rest is owned by Husky). Offshore Cote d'Ivoire In late April, France's Total SA announced a major discovery in the deep waters off the western coast of Cote d'Ivoire, encountering 91 feet of net oil pay while drilling in Block CI-100 in about 7,400 feet of water. It was the first block Total drilled. What is significant about this discovery is not the net feet of pay, but the fact that it confirms an extension of reserves in the Tano basin, home to the giant Jubilee field in neighboring Ghana. The Jubilee field is one of the richest oil fields in Africa with potential reserves eclipsing 1.8 billion barrels. This is the second major find in Cote d'Ivoire recently; last year Tullow Oil—which is also exploring in Ghana, made an offshore discovery here as well. Gullfaks, North Sea In April, Statoil said it could be sitting on 40-150 million recoverable BOE in the North Sea in its Gullfaks license, where it is still working to confirm its findings. Gullfaks is in the North Sea's Shetland Group/Lista Formation. The Gullfaks finds are younger, shallower deposits than its primary areas. Gullfaks has three permanent installations that have so far produced over 2.4 billion barrels of oil and over 56 billion cubic meters of gas. Statoil is the operator of the license, with a 70% interest, along with Petoro (30%). The Gullfaks discovery follows two other recent massive discoveries in the North Sea: Johan Sverdrup and King Lear. Santos Basin/Libra, Brazil In May, Petrobras doubled the estimate for its Libra field to 12-15 billion barrels. This makes it Brazil's largest ever discovery. Brazilian officials say it could easily produce a million barrels of oil per day once it is fully developed—that's TWICE the output of OPEC-member Ecuador. Production could begin in five years, with plans for up to 12-18 production vessels permanently anchored on the field, each of them pumping up to 30,000 barrels per day. For state-run Petrobras, which owns the field, it means more expenditures and more debt (and it's already drowning). The answer: Petrobras is taking the show on the road, preparing to offer foreign investors up to a 30% stake in this amazing prospect. (The Libra auction will take place in October, and 70% of the field will be up for grabs). WHAT'S WORTH OWNING Genel Energy (LON:GENL) We can't get enough of Anglo-Turkish Genel, which is advancing like a hurricane in Kurdistan (discovery after discovery and amazing drilling success), and also faring nicely in Africa. Shares in the company have advanced almost 50% over the past year on success in Kurdistan, and now it's about to hit the roof as its crude oil pipeline nears completion and is slated to start pumping crude to Turkey by the end of September. There is a short window of opportunity here to get in while this is still a bit undervalued. (And there are a number of undervalued stocks operating out of Kurdistan). Genel is the largest producer in Iraqi Kurdistan, and its holdings are impressive. We're talking about 7 production-sharing contracts with some nice geological diversity. Its largest producing fields in Kurdistan are Taq Taq and Tawke, which have an estimated gross proven and probable reserves of 1.4 billion barrels of oil and gross proven, and probable reserves of 1.9 billion barrels. By 2014, Genel is aiming for a production capacity of 140,000 net bopd. Anadarko Petroleum (APC) Anadarko has great onshore assets in the US Gulf of Mexico and diverse offshore, deep-water assets off the coasts of Algeria, Ghana, Mozambique, Brazil, China, Indonesia and New Zealand, with proven oil and gas reserves at about 2,560 million BOE as of end 2012. We're looking at liquids-natural gas ratio of 46%-54%. For 2012, Anadarko saw a 10% increase in overall production. This year, Anadarko plans to spend some $5.5 billion developing its onshore US assets alone, and about $1 billion on its overseas plays. So we expect another nice increase in production for 2013. The company will shift its key activities a bit to account for low natural gas prices, so we'll see more focus and money spent on the Gulf of Mexico and less at the Marcellus shale, for instance. Anadarko is trading at $86.10 per share with a total market cap of more than $43.1 billion. In the second week of June, shares of Anadarko rose 3.7% on the news of a major new discovery in the deep waters of the Gulf of Mexico (Shenandoah-2, mentioned above). Noble Energy Inc (NYSE:NBL) When you think about the Levant Basin these days, you think about Houston-based Noble Energy. In late May, Noble announced a new discovery in the Mediterranean Sea, just 20 miles northeast of its Tamar field in its Karish well after drilling to a total depth of 15,783 feet. The well encountered 184 feet of net natural gas pay, and Noble thinks it potentially holds up to 2 trillion cubic feet of natural gas. This brings its estimated combined resources in the Levant Basin—including the Tamar and Leviathan fields—up to 38 trillion cubic feet of natural gas. Noble is definitely on a roll in the Levant Basin, and this latest discovery is its 7th so far in the eastern Mediterranean. Back in the US, it's more good news for Noble. In mid-June, Noble confirmed that its second Gunflint appraisal well in the deep waters of the Gulf of Mexico had an estimated gross resource of 65-90 million bbl of oil equivalent. This means Noble's plans for a subsea tieback development at Gunflint are a green light for this year. Production is targeted for the end of 2015 at both Noble's Gunflint and Big Bend deep-water discoveries in the Gulf of Mexico. Oryx (OXC) Sorry, but it's got to be Kurdistan—again, but this time Oryx, a company we've written about before but you may not have heard of. If you haven't you're missing out. About a month ago, Oryx—the upstream division of AOG--offered up 17% of its shares (16,700,000 common shares) on the Toronto Stock Exchange for C$15 per share) with gross proceeds of $250 million. The proceeds will allow Oryx to complete its exploration and appraisal plans through mid-next year, and they expect some serious results over the next 12 months. Oryx is the brainchild of Swiss billionaire Jean Claude Gandur, who made his grand entrance onto the oil and gas scene in 2008 with the sale of Addax Petroleum to China's Sinopec for $7.2 billion. Since then, he's been out of the fossil fuels game—so Oryx is his re-entry ticket. Gandur owns 77% of Oryx through AOG. Oryx is exploring in west Africa and Iraqi Kurdistan, but it's the Kurdistan assets we really like. Gandur is an excellent diplomat who can navigate power brokers, which will make or break a junior company in this territory. Oryx isn't making any money yet, but it will, and that's why we think now is the time to get in on this. It could very easily go the way of Addax, which was making about $300 million annually in net income when it was sold to Sinopec. Gandur has dumped $700 million into Oryx, which has been busy buying up licenses and drilling wells. It's sitting quite nicely in Kurdistan right now with a 100% focus on oil and 143 billion bbls of proven oil reserves. By. OilPrice.com Premium Analysts

Piggybacking on the Hunt For Massive Oil Discoveries: Interview with AOS

Piggybacking on the Hunt For Massive Oil Discoveries: Interview with AOS Africa is becoming the top choice for North American oil companies looking to diversify, and the East African Rift is the hottest of the hot, with Kenya waiting on commercial viability, Angola and Ghana already on the road to rival Nigeria and two newcomers—Namibia and Zambia—where the doors have been thrown open for exploration. Getting in on Namibia and Zambia is an extremely expensive endeavour, but here's a way to de-risk this adventure, keep your shareholders calm and strategically position yourself to take advantage of the next big find without footing the massive drilling bill: Buy up a ton of acreage and sit back and let others do the expensive exploration and drilling on territory adjacent to yours. Then strike and watch offers come in. In an interview with Oilprice.com, Alberta Oil Sands (AOS) CEO, Binh Vu … discusses: • How to get in elephant-sized plays in the East African Rift • How to save cash by piggy-backing on others' expensive exploration • Why Namibia could be a major oil monster • What makes Zambia such an attractive oil venue • Other African plays that are worth looking into • Why it's hard for juniors to compete in Africa • Why someone will always need Canadian oil sands • What heavy oil economics will look like over the coming years • Why Canada's Algar Lake is a major sleeper play • What qualities investors should look for when betting on juniors Interview by James Stafford of Oilprice.com James Stafford: With the oil discoveries in Kenya and a lot of optimism over other rifts and lake systems including those present in Uganda, Zambia, Tanzania, etc. the East African Rift System has become an emerging oil hot spot. What we want to know is how to make money here without spending a ton of cash in exploration and drilling? What's the smart way to stake a claim on the East African Rift Basin? AOS: That is a great question. The truth is that this area has become quite expensive as it has been found to be increasingly prolific. Major signing bonuses, deposits, and commitments are required in spots like Kenya, Tanzania, and Uganda. There is very little opportunity for the junior explorers to compete. We believe that Zambia is a fabulous jurisdiction because it shares the geology and rock age in certain large areas that have hosted the Lake Albert Discovery and the Block 10BB Kenya discovery. However, it is totally underexplored for hydrocarbons and thus provides much cheaper access to very prospective areas. Our company has successfully tied up ~18 million acres or what we believe covers about 33% of the attractive rift areas in Zambia - which equates to oil and gas rights over about 8% of the country. James Stafford: How does an exploration company on a budget go about covering and "high-grading" targets over such a large area? AOS: Without a doubt that is a highly important question for any company engaged in the pursuit of elephant-sized targets in new frontiers. One of the things that we do is first is aim for concession agreements that don't tie us to expensive immediate seismic commitments. Second we eschew large and expensive 2-D seismic programs in favor of a process of high grading using satellites, other remote sensing techniques, and 'ground truthing'. We estimate that by using satellite data analysis over a number of criteria--gravity gradiometry, thermal emissivity analysis, geobotany analysis including vegetation anomalies and geo-microbial review over specific high-graded areas on our acreage--we can save millions of dollars and years of time. We then get to specific areas that are ready for smaller, focused electroseismic surveys / 3-D surveys, and that can then be attacked as drillable targets either to take on ourselves, or to farm down to majors who are looking for the next major rift discovery. James Stafford: What does the playing field look like right now in Zambia? Who's there, what are they doing, and how are you positioned to take advantage of all the money being spent there on exploration and drilling? AOS: There are a number of companies there and we have focused on two lakes as well as two dry rifts that show very promising gravity responses from the most up to date databases. Our number one focus is on Lake Tanganyika. This lake spans through Burundi, Tanzania, DRC, and Zambia. There are currently to our knowledge at least three major active seismic programs on Lake Tanganyika including one recently completed by Beach Energy, an Australian company with a $1.75 billion valuation. Beach is directly adjacent to AOS, on the Tanzania side of the Lake. It is likely that Lake Tanganyika will see at least 1 drill hole in 2014. We like Lake Tanganyika as the right spot for the next Lake Albert (3.5 billion barrels reserves) discovery because of the almost identical geological setting and rock age as well as the size of the Lake and the major indications of an existing petroleum system. Lake Tanganyika has multiple oil slicks and natural oil seeps including one that is believed to be the largest natural oil seep in the world. You can see it from Google Earth. James Stafford: You've also recently acquired acreage in Namibia, which just made its first-ever commercial oil discovery. What are the prospects here and what kind of timeframe are we looking at? AOS: I'm glad that you asked that. Namibia to us is a potentially direct analogue to all of the major offshore discoveries in Brazil (plate tectonics theory) and Angola to the north. Offshore Namibia has the identical age and rock type as the discoveries in offshore Angola. Combined, those two countries have nearly 30 billion barrels in reserves. Namibia itself, however, remains highly underexplored with only 16 wells drilled in 20 years--seven on Kudu Gas Field alone--and the majority of the rest were shallow shelf wells. People are starting to get the idea and now. BP, Petrobras, Repsol, Galp Energia, HRT, are all there. HRT has had success there on their first well of this three-well campaign where they discovered light oil for the first time. Their second well was dry. The third well on which they will begin drilling in August in their PEL-24 block which borders directly on to AOS' 2.5 million acre land package in the Orange Basin - blocks 2712A and 2812A. We are at ground zero. HRT rates their play chance there at 25% and to my knowledge it is their biggest target--a 30 billion barrel monster. If that one works, I would think that there will be companies knocking down our door. We will know likely in late September, maybe the beginning of October. Regardless, there should be at least five more wells drilled and $500 million to $1 billion being spent offshore Namibia over the next 12-18 months, so it really fits well with our strategy of being in highly active basins where majors and big independents are spending lots of money around us to prove up major discoveries. James Stafford: AOS' new Africa portfolio is an ambitious diversification of its original assets in Alberta oil sands. Why the need for diversification here? AOS: It is indeed; however, I think that what shareholders need to understand (and many of ours do not) is that AOS has been traded for the last 24 months strictly on its balance sheet. It basically always trades at its cash per share. Why is that? Very simply there is or has been in recent times, very little capital market appetite or excitement for small companies developing SAGD oilsands plays. Athabasca Oil was one bright spot, but that was a marvel of financial engineering that caught a window. AOS has 500+ million barrels of oil sands resources which are getting no value. Combine a terrible junior market with complete apathy for this asset class, and the result is a share price that declines almost in lockstep with the treasury, and a total lack of response or enthusiasm to basically just about any kind of positive news. We feel that while AOS is underpinned by its cash and by real assets on which the company has spent almost $65 million developing since 2007, it adds meaningfully to shareholder value by bringing into the fold, as cheaply as possible, blue sky scenarios with major lottery ticket potential and requiring little to no cost commitments over the next 12-18 months. Ultimately, as we gain approval at our flagship Clearwater project in Alberta, part of our plan as we examine our options to unlock value in two distinct plays could be to dividend out our African assets to shareholders into a new company on a 1 for 1 basis, such that shareholders retain 1 pure play share of Oilsands in Alberta (Clearwater, Grand Rapids, Algar Lake), and one pure play share of our 21 million acre and growing high-impact African exploration portfolio (Zambia, Namibia, DRC). James Stafford: Mainstream media reports generally put a price tag of $75 to produce a barrel of Canadian oil sands, but is this really reflective of the true price once you get past the start-up phase? AOS: Some of the junior oilsands development companies that have made the transition to SAGD have stumbled without a doubt. Connacher and Southern Pacific being two recent examples. I believe, however, that the economics are actually superlative once all problems are solved, and of course you can go on producing for a very, very long time. The margins of an operation in full-swing and after start-up/growing pains, are much better than the mainstream media is reporting. James Stafford: For how long will the US continue to need crude from Canada's oil sands given current levels of production from US shale plays? What is the production price comparison here? Will it cost more to sustain production from wells in the Bakken and Permian Basins? AOS: This is an interesting question. My personal view is that whether it be the US or someone else, there will be no shortage of demand for what the Canadian oil sands can produce. Further, there is a lot more certainty in terms of consistency and longevity of the oil sands assets and their production profile, once they get going. James Stafford: What are your predictions for North American heavy oil economics over the next 2-3 years? Plenty of investors think this is the place to be with a lot of refineries coming out of turnaround and getting heavier and heavier despite all the light shale oil. Will demand for heavy oil rise? AOS: I read analyst prognostications on this stuff every day. They can certainly have different complexions depending on who you are listening to. To me it's pretty simple: I don't believe that prices are going to go outside of a range (below, or above) where extremely healthy margins can be made by good operators, for their shareholders. We will be range-bound here at healthy levels is my overriding feeling on this. James Stafford: What can we expect from AOS in terms of Canadian oil sands development in the next 6-9 months; in the next 2-3 years? What drilling will occur across AOS' oilsands acreage? AOS: Alberta Oilsands has four main projects domestically, and two of them are sleepers. For our flagship Clearwater asset with 373 million barrels of resources we hope to receive ERCB permits for production in Q4 of this year at an initial rate of up to 5,000 bopd, with a phase II of up to 40,000 bopd. This will be a game changer for us, and is the one thing that probably will move our market much higher immediately. Our Grand Rapids project has resources of 119 million barrels and we have just completed an EUR study that demonstrates its ability to produce as much as 30,000 barrels a day, for 40 years. This is highly encouraging and is totally overlooked by the market. Our third asset is a sleeper asset, in my opinion. AOS has taken on a partner to drill its Algar Lake project. We chose this partner because of its history of great exploration success. The team has, from scratch, made two separate billion+ barrel discoveries in Alberta and Saskatchewan and sold each to the majors. They want to turn their focus to Algar Lake now because it has the potential for cold flow production. Cold flow CAPEX is ~25% of SAGD CAPEX. On the OPEX side and on the operational complications side, it is basically the same story as well. Those are fundamental and major benefits. If I can find a couple hundred million barrels of cold flow today, I think that the world is at my door. The 5 well program this winter will be enough to tell us if we have the next Pelican Lake - CNRL's most profitable operating division per barrel, full stop. James Stafford: It is no doubt a very difficult time right now for most junior oil and gas explorers and developers--whether with a domestic focus, or an international focus. What do you tell investors? AOS: I would say that I don't see that risk capital coming back for some time. It will be very opportunity specific and success driven. You want to look for companies that have the ability to survive for a while with the cash in the bank, are underpinned by real assets with a real value, and also can provide the excitement and possibility of a geometric return on investment. James Stafford: And does AOS qualify for those criteria? AOS: Not to toot our own horn here James, but my view of the world is: AOS is trading at just above cash value. Our combined PV10 between Clearwater and Grand Rapids is $823 million--or about 225X our market cap net of cash. We have a very small burn rate. We have multiple catalysts that can take us much higher in the next few months, including: Success in Namibia by HRT in September; approval at Clearwater for production in Q4; partners on our vast African acreage, or other discoveries near our rift acreage; demonstration of cold-flowing reservoirs at Algar Lake; and a strategic partner for Clearwater or Grand Rapids. If any of these things come to fruition I think that the market and our own shareholders will sit up and take notice again and realize that right now they get all of those potential outcomes for free while we sit trading at cash value, with 500 million barrels of oil booked, and 21 million acres of prime exploration ground with 100s of millions of dollars being spent right around it. James Stafford: Thanks very much for sharing your views with us on both the African landscape for exploration and discovery, as well as the outlook for heavy oil prices and oil sands development in Canada. Source: http://oilprice.com/Interviews/Piggybacking-on-the-Hunt-For-Massive-Oil-Discoveries-Interview-with-AOS.html

Mineral Rich Australia May Contain World's Next Major Oil Find

Mineral Rich Australia May Contain World's Next Major Oil Find Australia's massive mineral exports allowed it to weather the global recession, which began in 2008, quite nicely. The U.S. government's Energy Information Administration noted in its country's analysis for Australia, "Australia, rich in hydrocarbons and uranium, was the world's second largest coal exporter in 2011 and the third largest liquefied natural gas (LNG) exporter in 2012. Australia is rich in commodities, including fossil fuel and uranium reserves, and is one of the few countries belonging to the Organization for Economic Cooperation and Development (OECD) that is a significant net hydrocarbon exporter, exporting over 70 percent of its total energy production according to government sources. Australia was the world's second largest coal exporter based on weight in 2011 and the third largest exporter of liquefied natural gas (LNG) in 2012." Six months ago Brisbane company Linc Energy Ltd.Energy released two reports, based on drilling and seismic exploration, estimating the amount of shale oil in the as yet untapped 30,000 square mile Arckaringa Basin surrounding Coober Pedy ranging from 3.5 billion to a mind boggling 233 billion barrels of oil. If the upper end estimates are correct then it means that the Arckaringa Basin is six times larger than the Bakken, seventeen times the size of the Marcellus formation, and 80 times larger than the Eagle Ford U.S. shale deposits. To put the potential of the Arckaringa Basin in context, Saudi Arabian reserves are estimated at 263 billion barrels. So, what next for Linc Energy Ltd.? The company has been in discussions to find a partner to develop the Arckaringa Basin after hiring Barclays Plc to help with the process and expects to narrow the talks to one group in a "few weeks," according to Linc Energy Ltd. chief executive officer Peter Bond. Bond added that Linc Energy Ltd.is talking with at least four parties from outside Australia interested in the shale oil project in the Arckaringa Basin. Linc Energy Ltd . said that the characteristics of its Australian acreage "compare favorably" to the prolific Bakken and Eagle Ford shale regions of the U.S. Global energy companies including Chevron, ConocoPhillips, Statoil ASA and BG Group Plc are already making shale investments in Australia. Australian State Mineral Resources Development Minister Tom Koutsantonis said, "Shale gas and shale oil will be a key part to securing Australia's energy security now and into the future. We have seen the hugely positive impact shale projects like Bakken and Eagle Ford have had on the U.S. economy. There is still a long way to go, but investment in unconventional liquid projects in South Australia will accelerate as more and more companies such as Linc Energy Ltd.Energy and Altona prove up their resources." Natural gas? Six basins in Australia stretching from coastal Queensland to Western Australia's far northwest contain recoverable shale resources of as much as 437 trillion cubic feet of gas, all of which was previously inaccessible because it is contained in shale formations, which could be unlocked by "hydraulic fracturing." But the U.S. Department of Energy predicts that Australia's shale gas industry will develop at a "moderate pace" because the nation's shale oil and gas resources do not as yet have the advanced production infrastructure that has underwritten the U.S. production boom. And what if estimates for the Arckaringa Basin basin pan out? We'll leave the final word to the EIA, which notes, "Australia's stable political environment, relatively transparent regulatory structure, substantial hydrocarbon reserves, and proximity to Asian markets make it an attractive place for foreign investment. The government published an Energy White Paper in 2012 that outlines its energy policy including balancing its priority of maintaining energy security with increasing exports to help supply Asia's growing demand for fuel." Accordingly, Adelaide had better upgrade its airport to handle all those energy company corporate jets that may well be visiting soon. Source: http://oilprice.com/Energy/Crude-Oil/Australia-Next-Petro-Superstate.html By. John C.K. Daly of Oilprice.com

Six Tech Advancements Changing the Fossil Fuels Game

Oil and gas is getting bigger, deeper, faster and more efficient, with new technology chipping away at “peak oil” concerns. While hydraulic fracturing has been the most visible revolutionary advancement, other high-tech developments are keeping the ball rolling—from the next generation of ultra-deepwater drillships, subsea oil and gas infrastructure and multi-well-pad drilling to M2M networking, floating LNG facilities, new dimensions in seismic imagery and supercomputing for analog exploration. ADVANCED SEMI-SUBMERSIBLES & 6TH GENERATION DRILLSHIPS Rig advancements are coming online in tandem with the significantly increased momentum to drill in deeper waters as shallower reserves run out. For 2012, 49% of new offshore discoveries were in ultra-deepwater plays, while 28% were in deepwater plays. What we're looking at now are amazing advancements in deepwater rigs, with new semi-submersibles capable of drilling to depths of 5,000 feet or deeper. Beyond that, though, new sixth generation enterprise-class drillships can go to depths of 12,000 feet! From a global perspective, there are 120 ultra-deepwater rigs in existence—and demand is on the steep rise. SUBSEA PROCESSING Subsea processing can turn marginal fields into major producers. Subsea production systems are wells located on the sea floor rather than the surface. Petroleum is extracted at the seafloor, and then 'tied-back' to an already existing production platform. The well is drilled by a moveable rig and the extracted oil and natural gas is transported by riser or undersea pipeline to a nearby production platform. Subsea systems are typically in use at depths of 7,000 feet or more. They don't drill, they just extract and transport. The real advantage of subsea production systems is that they allow you to use one platform—strategically placed—to service many well areas. And as the cost of offshore production rises, this could represent significant savings. Subsea production could rival traditional offshore production in less than 15-20 years, and we're looking at expected market growth for subsea facilities of around $27 billion in 2011 to an amazing $130 billion in 2020. Analysts expect E&P companies to invest more than $19 billion in subsea production equipment in 2013 alone--and up to $33 billion by 2017. Subsea processing can handle everything from water removal and re-injection or disposal, to single-phase and multi-phase boosting of well fluids, sand and solid separation and gas/liquid separation and boosting to gas treatment and compression. Subsea processing allows producers to separate the unwanted elements right on the seafloor, without using complicated and expensive flowlines to bring these elements up to the above-water processing facility to remove them and then send them back down to the seafloor to be re-injected. We're cutting out the middle man here. The middle man in this case is the process known as “subsea boosting”. What we're talking about, essentially, is saving space and time (which means money) by performing processing activities on the seafloor rather than sending fluids back and forth between the seafloor and the processing facilities above water. We are particularly interested in a new subsea rotating device that promises to enhance dual-gradient drilling (DGD). This is a system being developed by Chevron, which is hoping to deploy the system is the Gulf of Mexico later this year. What the DGD system will do is render the thousands of feet of mud that is bearing down on the wellbore … well … weightless. And then we have subsea power grid plans, which have been making progressive leaps since 2010 towards the advancement of electric grids installed on the floor of the sea to run processing systems at the site of underwater wells. It reduces the need for so many platforms on the water surface, and makes the entire process much less complicated. The ultimate goal here is to be able to operate offshore wells remotely from land—saving countless billions. MULTI-WELL-PAD DRILLING: OCTOPUS IN THE HOUSE One of the greatest drilling developments of the last decade is multiple well pads, which some like to refer to as “Octopus” technology. Imagine gaining access to multiple buried wells at the same time, from a single pad site. This is what “Octopus” technology is doing, first in a canyon in northwestern Colorado in the Piceance Shale Formation and then in the Marcellus shale. It's definitely not your traditional horizontal drilling. Traditionally, to drill a single well, a company needs a pad or land site for each well drilled. Each of these pads covers an average of 7 acres. The Octopus allows for multiple well drilling from a single pad, which can handle between 4 and 18 wells. So, a single pad on 7 acres can now be used to drill on up to 2,000 acres of reserves. More than anything, it means that drilling will be faster, faster, faster … And less expensive in the long run once it renders it unnecessary to break down rigs and put them together again at the next drilling location. It's simple math: 4 pads usually equals 4 wells; now 1 pad can equal between 4 and 18 wells. Here's how the technology works: A well pad is set up and the first well is drilled, then the rig literally “crawls” on its hydraulic tentacles to another drill location from the same pad, repeatedly. And it's multi-directional. It takes about two hours between each well drilling. With traditional horizontal drilling methods, it takes about five days to move from pad to pad and start drilling a new well. Last year, Devon Energy (DVN) drilled 36 wells from a single pad site using Octopus technology in the Marcellus Shale. More recently, Encana (ECA) drilled 51 wells covering 640 underground acres from a single pad site with a surface area of only 4.6 acres in Colorado. Multi-well pad drilling is also revolutionizing drilling in Bakken, and this is definitely the long-term outlook for shale. It will become the norm. It's also good (or at least slightly better) news for the environment because it means less drilling disturbance on the surface as we render more of the process underground. SUPERCOMPUTING & SEISMIC DIMENSIONS EINSTEIN WOULD APPRECIATE Oil majors are second only to the US Defense Department in terms of the use of supercomputing systems. That's because supercomputing is the key to determining where to explore next—and to finding the sweet spots based on analog geology. What these supercomputing systems do is 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. Now we have 3-dimensional imaging that tells a much more accurate story. But it doesn't stop here. There is 4-dimensional imaging as well. What is the 4th dimension, you ask: Time (and Einstein's theory of relativity). This 4th dimension unlocks a variable that allows oil and gas companies not only to determine the geological characteristics of a potential play, but also gives us a look at the how a reservoir is changing LIVE, in real time. The sound waves rumbling through a reservoir predict how its geology is changing over time. The pioneer of geological supercomputing was MIT, whose post-World War II Whirlwind system was tasked with seismic data processing. Since then, Big Oil has caught on to the potential here and there is no finish line to this race—it's constantly metamorphosing. What would have taken decades with supercomputing technology in the 1990s, now can be accomplished in a matter of weeks. In this continual evolution, the important thing is how many calculations a computer can make per second and how much data it can store. The fastest computer will get a company to the next drilling hole before its competitors. We are talking about MASSIVE amounts of data from constant signal loops from below the Earth's surface. For example, geologists generate sound waves using explosives or other methods that dig deep into the Earth's surface and then are sample 500 times per second. Only a supercomputer could possibly process all this complex data and make sense of it. We've moved beyond geographical interpretations, such as pursuing exploration based on geological proximity, like Tullow's Ethiopia play is on trend with its massive Kenya finds. This is child's play. What we're talking about is using supercomputing to tell us that standing in prolific Brazil is pretty much the same as standing in Angola; or that Ghana is analog to French Guiana. Supercomputing advances remove a great deal of the risk involved in undertaking expensive drilling when you're not sure what's there. Supercomputing essentially puts the idea of peak oil to bed for the foreseeable future. LNG TECHNOLOGY: FLOATING IS NOT A FANTASY Liquefied natural gas (LNG) technology—from LNG seaborne tankers and LNG trains to floating LNG facilities have quickly gone from concept to commercialization, opening up new possibilities in new frontiers and rendering the remote—well, much less remote. Liquefaction of natural gas is the process of super-cooling natural gas to minus 260 degrees Fahrenheit (minus 162 degrees Celsius) at which point it becomes much safer and easier to transport. After shipped to its destination, regasification plants at importing or receiving terminals return the fuel to a gaseous state. Floating LNG production, storage and offloading concepts are revolutionary because they have the ability to station a vessel directly over distant fields, removing the need for offshore pipelines and adding the advantage of mobility—these floating facilities can be moved to a new location once existing fields are depleted. Floating liquefaction technology can bring additional LNG supply by accessing stranded gas reserves that were previously thought to be too remote, small or otherwise challenging for conventional land-based LNG development. Shell's most prized LNG project is its Prelude Floating Liquefied Natural Gas (FLNG) Project in Australia, which is moored some 200 kilometers out to sea and will produce gas from offshore fields and liquefy it onboard. This vessel will be six times bigger than the biggest aircraft carrier and will cost between $10.8 and $12.6 billion to build—but it also means that Shell won't have to pay rising prices in Australia's onshore LNG plants. The facility will produce about 3.6 million metric tons of LNG and 1.3 million tons of gas condensate a year. M2M FOR OIL & GAS: GETTING SMARTER AND MORE CONNECTED The hottest arena in the smart grid world is machine-to-machine (M2M) technology—an industry worth $1 trillion. It's relevance to the oil and gas industry should not be underestimated. Now it's about to get even bigger because the cost of sensors used to make M2M possible has fallen so much that they are BEYOND commercially viable; and wireless networks are now cheap and everywhere. This is the next frontier in cross-sector technology. M2M device use in the oil and gas industry is set to more than double, as these technologies (including SCADA Telemetry-- supervisory control and data acquisition) emerge as key differentiators in expediting oil and gas exploration and accelerating operational efficiencies. Adopting M2M early on enables remote monitoring and allows for more flexible control of assets from wellhead to pipeline. It also enables fiscal metering, drilling monitoring and fleet management, as well as worker safety and accident response. It means higher productivity and eventually, lower costs for the oil and gas industry. This is the important part: The number of devices with cellular or satellite connectivity deployed in oil and gas applications worldwide is expected to rise more than 20% over the next several years. The top two applications for M2M in the oil and gas sector are in-land pipeline monitoring and onshore well-field-equipment monitoring. The drivers are new regulations, rising operating costs (think unconventional drilling) and increasing competition (a lot more players on the field, and the rising ranks of the juniors). WHO TO WATCH (AND OWN) In the high-tech hydrocarbons game these are our four picks: General Electric (GE) for subsea infrastructure; Transocean (RIG) for deep and ultra-deepwater rigs, Schlumberger for 3D seismic, and FMC Technologies. As upward pressure pushes up day rates for deep-water (especially ultra-deep) rigs, it's Transocean (NYSE:RIG) all the way. This year's already been a pretty good year for Transocean, despite some rather serious legal problems, and it's got a nice backlog of contracts. But we're also looking at Ensco and SeaDrill. But hands down, it's GE Oil & Gas, General Electric's fastest-growing segment, with annual 16% revenue growth over the last three years. GE is one of the most diverse companies out there, and it has carved itself a nice niche in the oil and gas sector. And it's impressively forward-thinking—from massive LNG projects to subsea drilling equipment. GE is positioned to experience significant growth. This year has been an amazing year for GE Oil & Gas, with a list of contracts that would impress the biggest skeptic. Since January, GE has sealed a $620 million, 22-year contract for QGC's Queensland Curtis LNG plant offshore Australia; a $333 million 16-year contract extension for Russia's Sakhalin-2 LNG plant; a $500 million contract Petrobras for new pre-salt projects in Brazil; $600 million in multiple-customer propulsion system contracts; and most recently, a $147 million deal with Statoil for carbon dioxide injection. Adding to GE Oil & Gas' market share here is the recent acquisition of Lufkin Industries. Though it had a very rough time of things during the financial crisis, GE has turned around—and quickly. Downsizing GE's Capital Division has been fortuitous, and we see huge things ahead for this company. By. OilPrice.com Premium Analysts This report is part of Oilprice.com's premium publication Oil & Energy Insider. Oil & Energy Insider gives subscribers an information advantage when investing, trading or doing business in the energy sectors. Successful investors, hedge funds and senior executives, have access to high level intelligence and power in ways that you, as an individual investor, are locked out of (the game is and never has been fair.) Let us help you level the playing field by using our network of traders, intelligence assets and high level partnerships to ensure you are making the right investment decisions. To find out more on how you can get a legal inside advantage in the energy markets please take a moment to visit: http://oilprice.com/premium

Chernobyl at Sea? Russia Building Floating Nuclear Power Plants

So much for the lessons of Fukushima. Never mind oil spills, the Russian Federation is preparing an energy initiative that, if it has problems, will inject nuclear material into the maritime environment. Speaking to reporters at the 6th International Naval Show in St. Petersburg, Baltiskii Zavod shipyard general director Aleksandr Voznesenskii said that the Russian Federation's first floating nuclear power plant "should be operational by 2016." Baltiysky Zavod is Russia's biggest shipbuilding complex. According to Voznesenskii, the "Academician Lomonosov" FNPP will be the first vessel belonging to the new line of floating nuclear power plants that can provide energy, heat and water to remote and arid areas of the country, with mass production scheduled for the near future. The "Academician Lomonosov's" technology is based on the USSR's construction of nuclear-powered icebreakers. The Russian media is speculating that the FNPPS will first be used in remote areas of the northeastern Arctic Russia and the Far East, as these regions currently suffer from a lack of energy, slowing their development. Each 21,000 ton vessel will have two "modified KLT-40 naval propulsion reactors" that will provide up to 70 megawatts of electricity or 300 megawatts of heat, sufficient for a city with a population of 200,000 people. Additionally, the floating NPPs can provide water desalination services capable of supplying up to 240,000 cubic meters of fresh water per day. Perhaps referring to Soviet-era nuclear icebreakers is not such a hot idea, at least for those with historical memories. Launched in 1957, the Lenin, the USSR's first nuclear powered icebreaker, was powered by three OK-150 reactors. In February 1965, there was a loss of coolant incident, and some of the fuel elements melted or deformed inside reactor number two. The debris was removed and stored for two years, and subsequently dumped in Tsivolki Bay near Novaia Zemlia two years later. The second accident was a cooling system leak, which occurred in 1967, shortly after refueling. Not a reassuring development for the Soviet Arctic environment. "Academician Lomonosov's" keel was laid in April 2007 at the Sevmash shipyard in Severodvinsk on the White Sea, but the project was subsequently transferred to the Baltiskii Zavod. The "Academician Lomonosov's" 21,500 ton hull was subsequently launched in 2010, although construction work was frozen in mid-2011because of bankruptcy proceedings against the shipyard. The company was subsequently acquired by state-owned United Shipbuilding Corporation and Rosenergoatom signed a new contract with the Baltiskii Zavod for the "Academician Lomonosov's" completion. The "Academician Lomonosov" has 69 crew and specialists. Ominously, the "Academician Lomonosov" has no engines, so it needs to be towed. The vessel is equipped with two modified KLT-40 reactors. But, not to worry. The Baltiskii Zavod shipyard stressed that The "Academician Lomonosov" and its successors are all designed with a safety margin exceeding all possible threats which makes its nuclear reactors invulnerable to tsunamis and other natural disasters and the ships meet all the requirements of the International Atomic Energy Agency (IAEA) and do not pose a threat to the environment. The factory further states that 15 nations, including China, Indonesia, Malaysia, Algeria, Namibia and Argentina have already expressed interest in buying floating nuclear power plant. The "Academician Lomonosov"will be sent to Vilyuchinsk, Kamchatka for operational testing. Rosatom then aims to construct seven more FNPPs by 2015, with four of them likely to be located on the northern coast of Siberia's Yakutia. Other Arctic areas provisionally scheduled to receive FNPPs include port cities along the Russian Federation's arctic coastal Northern Sea Route and Pevek in Chukotka. An added benefit of the FNPP as envisaged in Moscow is that the provision of nuclear power to the Arctic and Far East will free up more oil and natural gas for foreign export, allowing the Russian federation to generate additional hard currency. Tow cables snap, Arctic conditions can be unpredictable, ships sink. As the ocean is the common heritage of humanity, perhaps the international community might evince a tad more interest in this project. Source: http://oilprice.com/Alternative-Energy/Nuclear-Power/Chernobyl-at-Sea-Russia-Building-Floating-Nuclear-Power-Plants.html By. John C.K. Daly of Oilprice.com