A new report shows that more than 54 gigawatts of wind power were installed in 2016.
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Mining, Drilling and Discovery
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A new report shows that more than 54 gigawatts of wind power were installed in 2016.
"Over 54 gigawatts (GW) of wind power were installed in 2016 and cumulative capacity grew by more than 12 percent to hit 486.8 GW, according to a new report from global trade association, the Global Wind Energy Council (GWEC)."
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The multi-faceted order primarily targeting the Clean Power Plan is going to get the EPA sued and increase federal-state animosity.
"Today President Trump signed the Energy Independence Executive Order that sets in motion measures to reverse several major Obama Administration climate rules."
Next time you get into your car and drive to the supermarket, think about how much energy you consume on an annual basis. It is widely assumed that Westerners are some of the world's worst energy pigs. While Americans make up just 5 percent of the global population, they use 20 percent of its energy, eat 15 percent of its meat, and produce 40 percent of the earth's garbage.
Europeans and people in the Middle East, it turns out, aren't winning any awards for energy conservation, either.
Oilprice.com set out to discover which countries use the most energy and why.
While some of the guilty parties are obvious, others may surprise you. A note about the figures: we used kilograms of oil equivalent (koe) per capita, which refers to the amount of energy that can be extracted from one kilogram of crude oil. “Koe per capita” can be used to compare energy from different sources, including fossil fuels and renewables, and does here. The numbers represent the most recent data available from the World Bank.
(Image Source: Oilprice.com)
Iceland - 18,774 kg. Yes, that's right, Iceland. Of all the countries in the world, including the richest and largest oil producers, Iceland consumes the most energy per person. How can that be? The reason is basically overabundance. With most of Iceland's energy coming from hydroelectric and geothermal power, Icelanders are some of the planet's least energy-conscious. Click here for a fascinating video of why the Nordic nation uses so much energy.
Qatar – 17,418 kg. Qataris are addicted to oil. According to National Geographic, the population is provided with free electricity and water, which has been described as “liquid electricity” because it is often produced through desalination, a very energy-intensive process. Qatar's per capita emissions are the highest in the world, and three times that of the United States.
Trinidad and Tobago – 15,691 kg. Trinidad and Tobago is one of the richest countries in the Caribbean, and the region's leading producer of oil and gas; it houses one of the largest natural gas processing facilities in the Western Hemisphere. T&T is the largest LNG exporter to the United States. Its electricity sector is entirely fueled by natural gas.
Kuwait – 10,408 kg. Despite holding the sixth-largest oil reserves in the world, and an estimated 63 trillion cubic feet of natural gas reserves, the demand for electricity in Kuwait often outstrips supply. According to the U.S. Energy Information Administration (EIA), Kuwait is perpetually in electricity supply shortage and experiences frequent blackouts each summer. The country has become a net importer of natural gas to address the imbalance.
Brunei – 9,427 kg. The tiny sultanate on the island of Borneo, apart from being a substantial producer and exporter of oil and natural gas to Asia, is also a habitual power hog. The nation of roughly half a million has the region's highest number of cars per capita. Brunei also subsidizes both vehicle fuel and electricity, which is sold to the public at below-market prices.
Luxembourg – 7,684 kg. Landlocked Luxembourg is almost totally dependent on energy imports, mostly oil and gas. Energy consumption has increased 32 percent since 1990, with transportation responsible for 60 percent of the intake, according to an EU fact sheet.
United Arab Emirates – 7,407 kg. Nothing says conspicuous energy consumption like Ski Dubai. The indoor resort featuring an 85-meter-high mountain of man-made snow burns the equivalent of 3,500 barrels of oil a day. The World Resource Institute estimates the UAE uses 481 tonnes of oil equivalent to produce $1 million of GDP, compared to Norway's 172 tonnes.
Canada – 7,333 kg. Oh, Canada. Kind, peace-loving Canadians certainly love their cars, along with space heaters, hot tubs and other energy-sucking toys. But while many equate Canada's energy sector with the oil sands, it is, in fact, other forms of energy that account for the lion's share of consumption. EcoSparkpublished a pie chart showing over half (57.6 percent) of Canada's electricity comes from hydro, with coal the second most popular choice at 18 percent. Nuclear is third (14.6 percent), with oil and gas comprising just 6.3 percent and 1.5 percent, respectively.
United States – 6,793 kg. As the world's largest economy and richest nation, the U.S. should obviously be included as a top 10 energy glutton. However, one puzzling fact is that despite annual economic growth, per-capita U.S. energy consumption has remained around the same level since the 1970s. According to the EIA, one explanation is that the U.S. has simply shifted the energy required to satisfy greater consumption to manufacturing centers offshore.
Finland – 6,183 kg. With over a third of its territory above the Arctic Circle, a cold climate, sparse population and a highly industrialized economy, it is no wonder that Finland is among the highest per-capita energy users in Europe. However, according to the International Energy Agency, Finland plans to diversify its economy away from carbon-based fuels, through a shift to renewables, including biomass, and has approved construction of two new nuclear plants.
By Andrew Topf of Oilprice.com
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 andStrawn 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.
By James Stafford of Oilprice.com
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The 3 Most Important Numbers in Energy
The Insider’s weekly run-down of critical figures and happenings from around the energy world.
42%. Monthly increase in India’s coal imports, according to industry analysts Interocean.
The big jump includes a 36% rise in thermal coal imports, as compared to February. Along with a 63% increase in metallurgical coal shipments.
The numbers confirm the trend of significantly rising coal imports into India. An important observation, as coal prices globally have been moderating. This strong demand however, could put a floor under the market—and perhaps set the stage for a notable recovery.
6.5 million tonnes. Amount that Indonesian state utility PT Perusahaan Listrik Negara (PLN) expects its coal use to rise in 2014.
PLN forecast this week that its total coal demand will hit 78.5 million tonnes this year. An important figure given the rising demand for coal globally—as discussed above.
Indonesia has been one of the few nations able to ramp up export supply to places like India. But more coal being used domestically could limit the amount the nation can ship abroad.
The impact could be particularly significant when combined with recently-announced coal production restrictions from the Indonesian government. And low prices, which are seeing many producers struggle to turn a profit.
92,905. National oil production of Pakistan during March, in barrels per day.
The mark was an all-time high in output for the country’s petroleum industry. Suggesting that the sector here may finally be getting some traction in drilling and bringing new fields on line.
E&Ps have long recognized Pakistan’s potential. But a difficult political situation and limited services sector held back many field developments.
From the looks of last month’s data, those troubles may now be over. Perhaps signaling the opening of a new frontier for exploration.
The surge in U.S. oil production in 2010 has left a glut of oil trapped within the United States. To be sure, the U.S. is by far the largest consumer of oil in the world, so it’s not like all that extra oil sloshing around can’t find a home. But, due to a mismatch between the light, sweet crude coming out of places like the Bakken and the Eagle Ford, and the preponderance of refineries on the Gulf Coast equipped to handle heavier, sourer types of oil, there are local surpluses in supply. As a result, prices are somewhat depressed – for the last few years there has been a large spread between the Brent and WTI benchmarks, at times as wide as $10 per barrel. This has drillers looking overseas for markets.
Yet, U.S. law largely prohibits oil exports. Producers have already had a warm-up debate over energy exports – the glut of shale gas has drillers pushing lawmakers and regulators to approve export terminals for LNG, and the Obama administration has obliged, albeit at a slower pace than the industry wants. Last year, the murmurings of a similar debate – this time over oil – began to emerge. That debate kicked into high gear after the annexation of Crimea by Russia. Producers had shifted back and forth between a litany of arguments to support exports – that LNG and oil exports will grow the economy, create jobs, provide geopolitical benefits, lead to energy independence – which at times fell flat. But, with the Ukraine crisis, the prospect of undercutting Russia’s political machinations finally began to resonate on Capitol Hill. At the same time, Senator Mary Landrieu (D-LA), a huge backer of exports, took the gavel on the Senate Energy and Natural Resources Committee. Working alongside her Republican counterpart Lisa Murkowski (AK), they are aggressively pushing a natural gas and crude oil export liberalization agenda. As far as LNG exports go, they seem to have won. Crude oil is next, and the recent geopolitical events make it relatively likely that the crude export ban will be lifted in the near to mid-term.
Who would win and who would lose should such a scenario play out? The divide within the industry points the way – drillers would win big time, and refiners would lose out. That much is known. But let’s take a closer look.
Losers – Refiners
The U.S. has the ability to refine 17.3 million barrels of oil per day, and 44% (7.7 million bpd) of that refining capacity is located on the Gulf Coast. These refiners stand to lose quite a bit if the U.S. opens up to exports.
Alon USA Energy Inc. (NYSE: ALJ) joined together with a few other refiners to form the Consumers and Refiners United for Domestic Energy Coalition (CRUDE) in order to campaign against lifting the oil export ban. Alon owns the Big Spring refinery in Big Spring, Texas, with a daily capacity of 70,000 barrels. It produces ultra-low sulfur gasoline, diesel, jet fuel, petrochemicals, asphalt and other refined products. The Big Spring refinery uses the light sweet oil from the nearby Permian Basin in Texas. Alon also operates a 74,000 barrel-per-day refinery in Krotz Springs, Louisiana, a little over 100 miles west of New Orleans. Alon’s refineries benefit from relatively cheap U.S. oil, and Alon’s stockprice has risen substantially since mid-2010 alongside the shale oil boom.
A much larger company, Valero Energy (NYSE: VLO), stands to lose if the export ban is scrapped. The largest independent refiner in the United States, Valero has a truly massive Gulf Coast footprint, taking advantage of ample supplies of crude oil coming out of the prolific Eagle Ford, which is now pumping over 1 million barrels per day. In the past Valero made large investments in processing facilities to handle heavy sour crude, which it expected to come in ever larger amounts from places like Canada and Venezuela. For example, Valero’s Bill Greehey refinery complex in Corpus Christi has a capacity of 325,000 bpd, most of it for heavy crude. The tight oil boom in the U.S. changed that, and now Valero is investing $400 million this year to expand light sweet refining capacity, and an additional $865 million on rail and logistics to access the booming oil fields in Texas. The discounted WTI oil in the U.S. is allowing Valero to make hand over fist, and its stockprice has increased by over 200% in the past five years. If the U.S. decided to allow oil to be exported, Valero would lose out big time.
It’s not just Gulf Coast refiners that are worried. PBF Energy (NYSE: PBF) is another refiner that is actively opposing oil export liberalization. A fellow member of the anti-export CRUDE lobby group, PBF has refining positions that benefit from regional supply gluts. PBF operates a massive 170,000 barrel-per-day refinery in Toledo, Ohio. It produces ultra-low sulfur diesel, gasoline, and high-value petrochemicals. The Toledo refinery uses light sweet oil from the Bakken, Mid-Continent, Canada, and the Gulf Coast. Therefore, the current regime governing oil exports is highly advantageous to PBF’s Toledo facility. On the other hand, PBF is a bit more diversified than some Gulf Coast refiners, as it also has two large refineries on the East Coast, one in Delaware and one in New Jersey. With a combined refining capacity of 370,000 bpd, these refineries don’t actually benefit all that much from an export ban, as they import a lot of oil from overseas, which sells at the higher Brent price.
Winners – Drillers
Oil producers would obviously be the big winner of oil trade liberalization. The big boys – the ExxonMobil’s and Chevron’s of the world – would be enormous beneficiaries if the export ban was lifted, but they are so big and diversified that it may only be a blip on their stock prices. The smaller companies that are more pure plays on upstream production would be something to watch.
EOG Resources (NYSE: EOG) is a good choice. It is fresh off an impressive 2013 in which it increased production by an astounding 40%. EOG produced 235,000 bpd last year, with a big bet on the Eagle Ford. Not only that, but EOG recently submitted data to Texas regulators showing promising results from five newly drilled wells, which are already producing 13,000 bpd right off the bat. As they scale up, EOG thinks they will go a long way to helping the company reach their goal of increasing production by another 27% this year. And the Eagle Ford has demonstrated itself to be arguably the best place to be for oil in the United States. If the export ban were to go, EOG would stand to make a pretty penny.
Another company that would benefit from oil exports would be Kodiak Oil & Gas (NYSE: KOG), a pure play bet on the Bakken. It is one of the fastest growing companies in the fast growing oil patch in North Dakota. Kodiak’s oil production jumped by 100% last year, reaching nearly 30,000 bpd. Its reserve profile is tilted heavily towards oil – nearly 83% of its proved reserves are in the form of oil, while only 17% is natural gas. Kodiak projects that it could continue to drill for another 12 years based on its current booked reserves, and that is before considering the fact that they will likely find more. That means the company has enormous growth potential. If and when the ban on exports is lifted, Kodiak will see its value jump. The one downside is the infrastructure constraints that the whole basin is dealing with. Lack of pipeline capacity is forcing the company to move most of its oil around on trains, adding a bit to cost. But, that should sort itself out over the next few years.
Lastly, the Permian Basin is another region that would profit greatly from oil exports. Pioneer Natural Resources Co. (NYSE: PXD) is a major operator in this region, and last year the company produced 161,000 barrels of oil equivalent per day. It holds around 640,000 net acres in the Sprayberry field, and projects that it controls acreage holding more than 8 billion barrels of oil equivalent in this area alone. Pioneer increased production by 12% in 2013, and hopes to boost production by a further 14%-19% this year. Even more exciting, the company expects 2013 levels of production to double by 2018. It also has ambitious plans for the Eagle Ford, from which it produced 38,000 boe per day. Based on these facts alone, Pioneer would be a good investment. But if the U.S. allows oil exports, Pioneer would look even better. The only downside is that Pioneer may already be expensive – its stock has more than tripled since 2011. But, it is still one to watch.
The U.S. has long supported a general policy of free trade. Sometimes it hasn’t practiced what it preached, but there is good reason to believe that proponents of allowing oil to flow out from U.S. ports will win over a skeptical Congress. That campaign has picked up steam in 2014, and it seems just a matter of time before the forty year ban on oil exports gets scrapped. The oil and gas industry usually speaks with a unified voice on policy matters, but the oil export issue has divided them. It is clear to see why that is the case – there are clear winners and losers.
Source : oilprice.com
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The Insider’s weekly run-down of critical figures and happenings from around the energy world.
1970. Last year when Australian oil production was lower than the level for 2013—which came in at 71.9 million barrels.
That mark was down 18.6% from 2012, underscoring Australia’s problems with rapidly-declining oil output. The nation’s total petroleum and liquids production came in at just 140 million barrels for the year. Far lower than the national demand of 346 million barrels for crude oil and transport fuels.
The shortfall could be a major wake-up call for the government to stimulate exploration here. Look for possible drilling incentives coming down the pipeline.
80 to 100. Number of coal-to-olefins plants that analysts at Platts estimate are under construction in China.
The burgeoning Chinese petrochemical sector could be a darkhorse in the global coal market. If coal usage from these olefins facilities sucks up needed supplies from the domestic power market, expect significant shortages to follow.
This could affect not only Chinese coal markets, but also prices abroad as China’s coal buyers ramp up exports to fill the gap.
$2.3 billion. Amount Gulf of Mexico explorer Energy XXI (Nasdaq: EXXI) is paying to acquire EPL Oil & Gas (NYSE: EPL)—creating the largest producer and reserves holder in the shallow-water Gulf Shelf region.
As we noted last week, EPL has done a phenomenal job creating value through the drillbit across its low-cost Gulf acreage. During 2013, the company enjoyed a 34% return on invested project expenditures. Much better than developers are seeing in many onshore shale plays.
Energy XXI may have been reading Three Most Important Numbers, because the firm swooped in this week with an unexpected bid for EPL. The combined firm will hold over 633,000 net acres in the Gulf Shelf, giving it a lot of room to run with unconventional drilling here that has been highly effective in creating value.
How much faith can we put in our ability to decipher all the numbers out there telling us the US is closing in on its cornering of the global oil market? There's another side to the story of the relentless US shale boom, one that says that some of the numbers are misunderstood, while others are simply preposterous. The truth of the matter is that the industry has to make such a big deal out of shale because it's all that's left. There are some good things happening behind the fairy tale numbers, though—it's just a matter of deciphering them from a sober perspective.
In a second exclusive interview with James Stafford of Oilprice.com, energy expert Arthur Berman discusses:
Arthur is a geological consultant with thirty-four years of experience in petroleum exploration and production. He is currently consulting for several E&P companies and capital groups in the energy sector. He frequently gives keynote addresses for investment conferences and is interviewed about energy topics on television, radio, and national print and web publications including CNBC, CNN, Platt's Energy Week, BNN, Bloomberg, Platt's, Financial Times, and New York Times. You can find out more about Arthur by visiting his website: http://petroleumtruthreport.blogspot.com
Oilprice.com: Almost on a daily basis we have figures thrown at us to demonstrate how the shale boom is only getting started. Mostly recently, there are statements to the effect that Texas shale formations will produce up to one-third of the global oil supply over the next 10 years. Is there another story behind these figures?
Arthur Berman: First, we have to distinguish between shale gas and liquids plays. On the gas side, all shale gas plays except the Marcellus are in decline or flat. The growth of US supply rests solely on the Marcellus and it is unlikely that its growth can continue at present rates. On the oil side, the Bakken has a considerable commercial area that is perhaps only one-third developed so we see Bakken production continuing for several years before peaking. The Eagle Ford also has significant commercial area but is showing signs that production may be flattening. Nevertheless, we see 5 or so more years of continuing Eagle Ford production activity before peaking. The EIA has is about right for the liquids plays--slower increases until later in the decade, and then decline.
The idea that Texas shales will produce one-third of global oil supply is preposterous. The Eagle Ford and the Bakken comprise 80% of all the US liquids growth. The Permian basin has notable oil reserves left but mostly from very small accumulations and low-rate wells. EOG CEO Bill Thomas said the same thing about 10 days ago on EOG's earnings call. There have been some truly outrageous claims made by some executives about the Permian basin in recent months that I suspect have their general counsels looking for a defibrillator.
Recently, the CEO of a major oil company told The Houston Chronicle that the shale revolution is only in the "first inning of a nine-inning game”. I guess he must have lost track of the score while waiting in line for hot dogs because production growth in U.S. shale gas plays excluding the Marcellus is approaching zero; growth in the Bakken and Eagle Ford has fallen from 33% in mid-2011 to 7% in late 2013.
Oil companies have to make a big deal about shale plays because that is all that is left in the world. Let's face it: these are truly awful reservoir rocks and that is why we waited until all more attractive opportunities were exhausted before developing them. It is completely unreasonable to expect better performance from bad reservoirs than from better reservoirs.
The majors have shown that they cannot replace reserves. They talk about return on capital employed (ROCE) these days instead of reserve replacement and production growth because there is nothing to talk about there. Shale plays are part of the ROCE story--shale wells can be drilled and brought on production fairly quickly and this masks or smoothes out the non-productive capital languishing in big projects around the world like Kashagan and Gorgon, which are going sideways whilst eating up billions of dollars.
None of this is meant to be negative. I'm all for shale plays but let's be honest about things, after all! Production from shale is not a revolution; it's a retirement party.
OP: Is the shale “boom” sustainable?
Arthur Berman: The shale gas boom is not sustainable except at higher gas prices in the US. There is lots of gas--just not that much that is commercial at current prices. Analysts that say there are trillions of cubic feet of commercial gas at $4 need their cost assumptions audited. If they are not counting overhead (G&A) and many operating costs, then of course things look good. If Walmart were evaluated solely on the difference between wholesale and retail prices, they would look fantastic. But they need stores, employees, gas and electricity, advertising and distribution. So do gas producers. I don't know where these guys get their reserves either, but that needs to be audited as well.
There was a report recently that said large areas of the Barnett Shale are commercial at $4 gas prices and that the play will continue to produce lots of gas for decades. Some people get so intrigued with how much gas has been produced and could be in the future, that they don't seem to understand that this is a business. A business must be commercial to be successful over the long term, although many public companies in the US seem to challenge that concept.
Investors have tolerated a lot of cheerleading about shale gas over the years, but I don't think this is going to last. Investors are starting to ask questions, such as: Where are the earnings and the free cash flow. Shale companies are spending a lot more than they are earning, and that has not changed. They are claiming all sorts of efficiency gains on the drilling side that has distracted inquiring investors for awhile. I was looking through some investor presentations from 2007 and 2008 and the same companies were making the same efficiency claims then as they are now. The problem is that these impressive gains never show up in the balance sheets, so I guess they must not be very important after all.
The reason that the shale gas boom is not sustainable at current prices is that shale gas is not the whole story. Conventional gas accounts for almost 60% of US gas and it is declining at about 20% per year and no one is drilling more wells in these plays. The unconventional gas plays decline at more than 30% each year. Taken together, the US needs to replace 19 billion cubic feet per day each year to maintain production at flat levels. That's almost four Barnett shale plays at full production each year! So you can see how hard it will be to sustain gas production. Then there are all the efforts to use it up faster--natural gas vehicles, exports to Mexico, LNG exports, closing coal and nuclear plants--so it only gets harder.
This winter, things have begun to unravel. Comparative gas storage inventories are near their 2003 low. Sure, weather is the main factor but that's always the case. The simple truth is that supply has not been able to adequately meet winter demand this year, period. Say what you will about why but it's a fact that is inconsistent with the fairy tales we continue to hear about cheap, abundant gas forever.
I sat across the table from industry experts just a year ago or so who were adamant that natural gas prices would never get above $4 again. Prices have been above $4 for almost three months. Maybe "never" has a different meaning for those people that doesn't include when they are wrong.
OP: Do you foresee any new technology on the shelf in the next 10-20 years that would shape another boom, whether it be fossil fuels or renewables?
Arthur Berman: I get asked about new technology that could make things different all the time. I'm a technology enthusiast but I see the big breakthroughs in new industries, not old extractive businesses like oil and gas. Technology has made many things possible in my lifetime including shale and deep-water production, but it hasn't made these things cheaper.
That's my whole point about shale plays--they're expensive and need high oil and gas prices to work. We've got the high prices for oil and the oil plays are fine; we don't have high prices for the gas plays and they aren't working. There are some areas of the Marcellus that actually work at $4 gas price and that's great, but it really takes $6 gas prices before things open up even there.
OP: In Europe, where do you see the most potential for shale gas exploitation, with Ukraine engulfed in political chaos, companies withdrawing from Poland, and a flurry of shale activity in the UK?
Arthur Berman: Shale plays will eventually spread to Europe but it will take a longer time than it did in North America. The biggest reason is the lack of private mineral ownership in most of Europe so there is no incentive for local people to get on board. In fact, there are only the negative factors of industrial development for them to look forward to with no pay check. It's also a lot more expensive to drill and produce gas in Europe.
There are a few promising shale plays on the international horizon: the Bazherov in Russia, the Vaca Muerte in Argentina and the Duvernay in Canada look best to me because they are liquid-prone and in countries where acceptable fiscal terms and necessary infrastructure are feasible. At the same time, we have learned that not all plays work even though they look good on paper, and that the potentially commercial areas are always quite small compared to the total resource. Also, we know that these plays do not last forever and that once the drilling treadmill starts, it never ends. Because of high decline rates, new wells must constantly be drilled to maintain production. Shale plays will last years, not decades.
Recent developments in Poland demonstrate some of the problems with international shale plays. Everyone got excited a few years ago because resource estimates were enormous. Later, these estimates were cut but many companies moved forward and wells have been drilled. Most international companies have abandoned the project including ExxonMobil, ENI, Marathon and Talisman. Some players exited because they don't think that the geology is right but the government has created many regulatory obstacles that have caused a lack of confidence in the fiscal environment in Poland.
The UK could really use the gas from the Bowland Shale and, while it's not a huge play, there is enough there to make a difference. I expect there will be plenty of opposition because people in the UK are very sensitive about the environment and there is just no way to hide the fact that shale development has a big footprint despite pad drilling and industry efforts to make it less invasive.
Let me say a few things about resource estimates while we are on the subject. The public and politicians do not understand the difference between resources and reserves. The only think that they have in common is that they both begin with “res.” Reserves are a tiny subset of resources that can be produced commercially. Both are always wrong but resource estimates can be hugely misleading because they are guesses and have nothing to do with economics.
Someone recently sent me a new report by the CSIS that said U.S. shale gas resource estimates are too conservative and are much larger than previously believed. I wrote him back that I think that resource estimates for U.S. shale gas plays are irrelevant because now we have robust production data to work with. Most of those enormous resources are in plays that we already know are not going to be economic. Resource estimates have become part of the shale gas cheerleading squad's standard tricks to drum up enthusiasm for plays that clearly don't work except at higher gas prices. It's really unfortunate when supposedly objective policy organizations and research groups get in on the hype in order to attract funding for their work.
OP: The ban on most US crude exports in place since the Arab oil embargo of 1973 is now being challenged by lobbyists, with media opining that this could be the biggest energy debate of the year in the US. How do you foresee this debate shaping up by the end of this year?
Arthur Berman: The debate over oil and gas exports will be silly.
I do not favor regulation of either oil or gas exports from the US. On the other hand, I think that a little discipline by the E&P companies might be in order so they don't have to beg the American people to bail them out of the over-production mess that they have created knowingly for themselves. Any business that over-produces whatever it makes has to live with lower prices. Why should oil and gas producers get a pass from the free-market laws of supply and demand?
I expect that by the time all the construction is completed to allow gas export, the domestic price will be high enough not to bother. It amazes me that the geniuses behind gas export assume that the business conditions that resulted in a price benefit overseas will remain static until they finish building export facilities, and that the competition will simply stand by when the awesome Americans bring gas to their markets. Just last week, Ken Medlock described how some schemes to send gas to Asia may find that there will be a lot of price competition in the future because a lot of gas has been discovered elsewhere in the world.
The US acts like we are some kind of natural gas superstar because of shale gas. Has anyone looked at how the US stacks up next to Russia, Iran and Qatar for natural gas reserves?
Whatever outcome results from the debate over petroleum exports, it will result in higher prices for American consumers. There are experts who argue that it won't increase prices much and that the economic benefits will outweigh higher costs. That may be but I doubt that anyone knows for sure. Everyone agrees that oil and gas will cost more if we allow exports.
OP: Is the US indeed close to hitting the “crude wall”—the point at which production could slow due to infrastructure and regulatory restraints?
Arthur Berman: No matter how much or little regulation there is, people will always argue that it is still either too much or too little. We have one of the most unfriendly administrations toward oil and gas ever and yet production has boomed. I already said that I oppose most regulation so you know where I stand. That said, once a bureaucracy is started, it seldom gets smaller or weaker. I don't see any walls out there, just uncomfortable price increases because of unnecessary regulations.
We use and need too much oil and gas to hit a wall. I see most of the focus on health care regulation for now. If there is no success at modifying the most objectionable parts of the Affordable Care Act, I don't suppose there is much hope for fewer oil and gas regulations. The petroleum business isn't exactly the darling of the people.
OP: What is the realistic future of methane hydrates, or “fire ice”, particularly with regard to Japanese efforts at extraction?
Arthur Berman: Japan is desperate for energy especially since they cut back their nuclear program so maybe hydrates make some sense at least as a science project for them. Their pilot is in thousands of feet of water about 30 miles offshore so it's going to be very expensive no matter how successful it is.
OP: Globally, where should we look for the next potential “shale boom” from a geological perspective as well as a commercial viability perspective?
Arthur Berman: Not all shale is equal or appropriate for oil and gas development. Once we remove all the shale that is not at or somewhat above peak oil generation today, most of it goes away. Some shale plays that meet these and other criteria didn't work so we have a lot to learn. But shale development is both inevitable and necessary. It will take a longer time than many believe outside of North America.
OP: We've spoken about Japan's nuclear energy crossroads before, and now we see that issue climaxing, with the country's nuclear future taking center-stage in an election period. Do you still believe it is too early for Japan to pull the plug on nuclear energy entirely?
Arthur Berman: Japan and Germany have made certain decisions about nuclear energy that I find remarkable but I don't live there and, obviously, don't think like them.
More generally, environmental enthusiasts simply don't see the obstacles to short-term conversion of a fossil fuel economy to one based on renewable energy. I don't see that there is a rational basis for dialogue in this arena. I'm all in favor of renewable energy but I don't see going from a few percent of our primary energy consumption to even 20% in less than a few decades no matter how much we may want to.
OP: What have we learned over the past year about Japan's alternatives to nuclear energy?
Arthur Berman: We have learned that it takes a lot of coal to replace nuclear energy when countries like Japan and Germany made bold decisions to close nuclear capacity. We also learned that energy got very expensive in a hurry. I say that we learned. I mean that the past year confirmed what many of us anticipated.
OP: Back in the US, we have closely followed the blowback from the Environmental Protection Agency's (EPA) 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?
Arthur Berman: I'm not an expert on clean coal technology either but I am confident that almost anything is possible if cost doesn't matter. This is as true about carbon capture from coal as it is about shale gas production. Energy is an incredibly complex topic and decisions are being made by bureaucrats and politicians with little background in energy or the energy business. I don't see any possibility of a good outcome under these circumstances.
OP: Is CCS far enough along to serve as a sound basis for a national climate change policy?
Arthur Berman: Climate-change activism is a train that has left the station. If you've missed it, too bad. If you're on board, good luck.
The good news is that the US does not have an energy policy and is equally unlikely to get a climate change policy for all of the same reasons. I fear putting climate change policy in the hands of bureaucrats and politicians more than I fear climate change (which I fear).
See our previous interview with Arthur Berman.
By. James Stafford of Oilprice.com
There are exactly two ways to succeed in investing.
First, be a visionary. Look at the data everyone else is puzzling over and see something they don't. Then translate this into profitable trades ahead of the masses.
Or, be an explorer. Seek out far-afield information beyond the eyes of most casual observers. You then don't need any special insight to beat the herd--when you know something no one else does, even the simplest findings become unique insight.
You just have to know where to look.
That strategy is going to pay off handsomely for the few investors who've lately been following one of the most high-potential energy opportunities on the planet. Thermal coal.
Now, information on the coal sector is easy to find. In some places. Data abound on production and pricing from important players in this space like Australia and America.
But some numbers are much harder to find. Which is what makes this opportunity so high-powered.
The key data points in this case come not from usual-suspect places on the planet. But from a part of the world where information is much harder to come by.
Reliable data on the Indian coal sector isn't the kind of thing you just pull off Wikipedia. In fact, even the country's government and private sector pros often don't agree on the numbers--publishing wildly different figures on coal demand and import volumes.
But to anyone digging into these obscure figures, one message is clear from both sides: India's coal demand is exploding.
India's Coal Minister admits it. This week in questioning he reported that Indian imports of thermal coal jumped 42% during the year ended March 31, 2013.
So far during the current year—he said—it appears the import numbers are headed even higher.
Those figures imply that India's coal consumers are growing their shipments of foreign coal rapidly. To the tune of tens of millions of tonnes of new import demand yearly.
Numbers from private shipping firms--the people who are actually moving the coal into the country--suggest that growth may be even greater. With shipping reports pointing to a rise in imports on the order of 50 million tonnes during the current fiscal year.
That's a big jump. Reminiscent of 2009 when China suddenly and unexpectedly ramped up its coal import demand. An event that swung the balance of global coal markets, causing a run in coal prices, and triple-digit gains for coal stocks.
In other words, these are the kind of structural market changes investors should be paying attention to.
So why hasn’t the wider investment community been jumping on the big changes suggested by growing imports into India?
Because they’re not looking in the right places.
Few investors monitor the raw numbers coming out of India. Instead, most simply look to global coal prices as a proxy for what’s going on in the market.
And those prices have been uninspiring of late. Australia’s Newcastle coal marker, for example, has fallen 10% since the beginning of 2014. The chart below certainly wouldn’t get any readers fired up.
But in the case of the India opportunity, prices are a poor shorthand for understanding the market. Because of what’s been happening with supply.
Specifically, from Indonesia. Coal production and exports out of Indonesia have been rising dramatically—with this country single-handedly meeting most of India’s increased import demand. According to government stats, India’s imports of Indonesian coal grew by 27 million tonnes last fiscal year. Following on a 19 million tonnes increase the year before.
Indonesian producers have thus quietly kept a lid on prices—despite India’s surge in demand.
But here’s where it pays to be watching the action behind the scenes. Because it looks like the Indonesia story is about to change.
The government announced a policy shift last week where it will move to limit production of coal in the country. In fact, legislators are targeting 2014 coal production at nearly the same levels as 2013. Meaning there will be little growth in output to service the import demand from India—which the numbers suggest is continuing to rise, unabated.
As this situation plays out, it’s going to take a lot of investors by surprise. Supply and demand will tighten—which could lead to an upward surge in prices, quickly.
Only then will most observers catch on to the story. Scrambling to buy stocks of coal producers in the Asia-Pacific sphere.
But by knowing where to look, we can see it coming—and position ahead of this stampede of buying. That’s how the big money is made. Keep an eye on this space.
We’ll be looking at which specific companies we see benefiting from this trend in next week’s edition.
Source : Oilprice.com
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Syria has around 2.5 billion barrels of crude oil, which makes it the largest in terms of proven reserves in the eastern Mediterranean, but overall in the global scheme of things, a small player, accounting for less than 1% of the world’s output. But this onshore oil—largely concentrated in the east and northeast--was in the past a critical element of the country’s economy, at one time accounting for more than 25% of Syria’s economic output. Production has now fallen by 95%, while the government has lost control of the oilfields and Islamic rebel groups are engaged in bloody rivalry over them. Once the dust settles, exploration and production companies will also be eyeing Syria’s oil shale potential, which the government estimated in 2010 to be as high as 50 billion tons. Offshore, in Syria’s portion of the Levant Basin—where Israel has already made hefty finds and Lebanon hopes to start exploration if it ever manages to install a new Cabinet to pass the necessary legislation—Russia is closing in already.
Onshore, the situation right now is untenable. Islamic rebel groups are vying for control of the oilfields in the Deir az-Zor (Deir al-Zor) province, and Assad is has little choice but to deal with them as they hold the country’s energy hostage for all intents and purposes. This means more funding for these Islamist rebels, which Assad is hoping to use to his benefit by getting the West to respond to the situation under the umbrella of the “war on terror”.
The most recent development as of 10 February is that one of two key al-Qaida-linked groups has withdrawn from Deir az-Zor having temporarily lost out to its rivals. There are two al-Qaeda splinter groups—both taking their cue from Iraqi jihadists—trying to control Syria’s oil: the Al-Nusra Front and the Islamic State of Iraq and Greater Syria (ISIS). On 10 February, reports began to emerge that ISIS had withdrawn from the province after heavy fighting with Nusra. ISIS has apparently been pushed back to Raqqa province, its stronghold, and Hassaka province.
The dynamics between these former allies is complex. In January, several secular rebel groups and the Islamist al-Nusra began a campaign to push ISIS out of the province starting a complicated battle over territorial and ideological differences. ISIS’ forces are small in number, but they continue to gain new Iraqi recruits and their tactics, including beheadings and terrorizing of civilians, has alienated them from the rest of the rebel outfits. In this microcosm of the Syrian civil war, over 2,300 rebels have reportedly been killed since the beginning of January alone.
On an “ideological” level, the difference between the two Islamic groups is largely over timing. ISIS was trying to set up Islamic caliphates as it went alone, seizing territory and immediately installing Islamic law. Al-Nusra apparently believes it is necessary first to topple Assad and then to install an Islamic government across Syria. The secular rebel groups for now favor Nusra’s approach as the lesser of two evils, and the one that buys it more time to maneuver if they manage to overthrow Assad.
Where does this leave the oil? Deir az-Zor is now controlled, as of 10 February, by al-Nusra and some 10 other rebel groups. This leaves millions of Syrians without power unless Assad cuts deals with the rebels to buy this oil.
The oil supply is controlled from these fields by a network of pipelines running to the key population centers westward. The bulk of the deals are made by al-Nusra with local tribes. But al-Nusra does not control all the fields and supply. There are other actors here who are using this to profit from an illicit trade in oil. These organized criminals, or war profiteers, add another element to the complicated equation.
Further complicating the playing field has been the European Union, which has demonstrated a gross lack of understanding of the situation. In the fourth quarter of 2011, the EU banned imports of Syrian oil hoping to punish the Assad regime. In April 2013, it removed that ban in an effort to support the “Syrian opposition” by buying oil from them, viewing the situation as one of rebel control of the country’s oilfields. The EU approved imports of oil and petroleum products from Syria, exports of oil and gas equipment and technology to Syria, and investment in the oil and gas industry in Syria.
Offshore oil and gas is another matter, entirely. No one controls the offshore, but there’s nothing to control yet at any rate. Oil & Energy Insider broached the subject of Syria’s offshore oil and gas potential in an Executive Report in April 2013. At the time, we noted that in 2011, shortly before the conflict broke out, the Syrian government was preparing to begin bidding for its first offshore exploration blocks in the Levant Basin region, the geology of which is highly prospective with Syria afforded three key basins to tap into: Cyprus, Levantine and Latakia.
According to the US Geological Survey, the Levant Basin, which covers Israel, Syria, Lebanon, Cyprus and Palestine, contains around 122 trillion cubic feet of gas and at least 1.7 billion barrels of oil. The Israeli discoveries in the Levant basin, at its Leviathan and Tamar fields, have brought this into clearer focus. We noted, specifically, that “this is the thing to watch as the end game for the Syrian conflict unfolds.”
That end game is indeed panning out in Russia’s favor. In late December, Syria signed its first-ever agreement for joint oil exploration off the Mediterranean coast. There was no bidding. The deal went to Russian oil and gas company SoyuzNefteGaz.
Under the terms of the 25-year contract, SoyuzNefteGaz will perform offshore drilling, development and production activities in Syria’s territorial waters. The agreement covers 2,190 square kilometers in the Mediterranean waters, at an initial cost of some $90 million, all assumed by SoyuzNefteGaz. It’s a deal that Syria’s opposition has roundly condemned as they believe Syria’s offshore oil blocks are being swapped for weapons that will be used to quell the rebellion.
Source : oilprice.com
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It’s been a tough winter, and not just because of the weather. The markets have given us opportunity but it’s been a barbed-wire wrapped one: Big moves down have looked impossible to buy and have sent me running for conservative, dividend paying stocks.
But this latest swing bringing the Dow again above 16,000 looks equally dangerous. Once again it strikes me that the only reasons to buy stocks are as an arbitrage against surprisingly strong bonds – as long as that 10 year yield hovers near 2.5%, you’ve got no choice but to invest in stocks.
I’ve been trying to relate this bond-arbitrage idea to the oil and gas stocks I cover too; there are prices at which I want to own both the beta plays on domestic production of shale oil and the higher paying (and safe) dividend stocks more often represented by mega-cap integrated oil companies. 2014 is not going to be like 2013 – I imagine a yo-yo, range-bound market that will force us to buy value when it comes and not be afraid to sell it when it rallies. Unless there is a change in Fed policy (and with Janet Yellen at the helm this is more than unlikely), I cannot buy any stocks blindly depended upon any production thesis, no matter how strong. Momentum is out for 2014 – I want value.
Luckily, there is still some value to be had in the market today, even with the Dow at relatively lofty levels – but they’re tough to spot. More often than not, you still have a great thesis that is being bought, but not at the right levels. Look at EOG Resources (EOG), for example – a stock I recommended a week or so ago because it was showing superb strength in the face of a stock market “correction”. At $165 a share, I thought EOG a nice play, but if you missed it, I can’t recommend initiating a position here as it again approaches $180. Same goes for Noble (NBL), a super buy at $61 but less so at $67. Pioneer Natural Resources? I’ll wait until it slips some more, a little closer to $165 again and forego it at $180.
But Anadarko, for example, represents a terrific value – right now.
The obvious question for this E+P goliath is how the final settlement with the Tronox liability will work out. This overhang has trounced the stock even after Anadarko received a very favorable settlement from the deepwater horizon case last summer and watched its shares soar above $95. I think the same scenario is going to play itself out here.
Anadarko has clearly whitewashed it’s liability risks in it’s latest quarterly report, showing only a write-down of $850m, while the ruling from Judge Gropper in December put liability at as much as $14B. But I believe that a settlement will put total costs nowhere near that outer figure and will likely only reach $4-5B. That’s a heavy number but at $82 a share, the market is expecting the worst-case scenario, not this relatively manageable figure.
And Anadarko assets might be the best of all the independent large-cap E+P players out there, with a strong presence in the Niobrara shale play in Colorado, the Eagle Ford in West Texas and the Marcellus shale gas play in Pennsylvania. Add to this the potential future production in the Gulf of Mexico from their Shenandoah field and you’ve got one of the best array of assets around.
2014 is going to be a tough trading year. Finding value will be the name of the game, especially when the indexes dip. But Anadarko represents one such value now. Recommended at $82.
Source : Oilprice.com