OilVoice Magazine - Edition 44

Edition Forty Four – November 2015

Low Oil Prices - Why Worry?

Why I've Started Buying Oil Stocks Again The trends that will keep the oil price below $60/B

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Adam Marmaras Manager, Technical Director Issue 44 –November 2015

OilVoice Acorn House 381 Midsummer Blvd Milton Keynes MK9 3HP Tel: +44 207 993 5991 Email: press@oilvoice.com Advertising/Sponsorship Mark Phillips Email: mark@oilvoice.com Tel: +44 207 993 5991 Social Network Facebook Twitter Google+

Welcome to the Forty Fourth edition of the OilVoice Magazine. We're into November now, and the end of the year is in sight – and what a year it has been! Plenty of news filtering through of service companies struggling, and people losing jobs. Let's hope that 2016 is a fresh start for the industry, and we see a return to viable pricing.

We have another bumper edition of the OilVoice magazine for you this month. I'm always astounded at the quality of industry writing available, and how lucky we are to be able to share it with you. Remember, if you like a writer in our magazine, take a moment to visit their site and explore what else they have to offer.

Linked In Read on your iPad You can open PDF documents, such as a PDF attached to an email, with iBooks.

We are pressing ahead with our training, and have added some exciting "all new" courses to our line-up. Our next course "An Introduction to Petroleum Systems" only has a few places left, so be sure to take a closer look if you are interested.

Enjoy the magazine, and catch you next month!

Adam Marmaras Managing Director OilVoice

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Table of Contents The trends that will keep the oil price below $60/B

by Andreas de Vries

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Primed for Exploration

by Tom Liskey

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Low oil prices are here to stay as the US shale oil revolution goes global

by Roberto F. Aguilera & Marian Radetzki

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UK Government's Delusional Energy Policy and Implications for Scotland

by Peter Strachan, Alex Russell and Geraint Ellis

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Low Oil Prices - Why Worry?

by Gail Tverberg

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The Price Of Oil: Another Huge Historical Shift

by John Richardson

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Why I've Started Buying Oil Stocks Again

by Keith Schaefer

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Declining oil price and the Nigerian economy: An opportunity for national oil and gas industry and local content reform

by Abhishek Agarwal, Udechukwu Oguagha and Stephen Vertigans

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Schlumberger's Quiet Moonshot

by Doug Sheridan

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The trends that will keep the oil price below $60/B Written by Andreas de Vries from Andreas de Vries According to economic theory, in a perfectly competitive market the price of a good will equal the marginal cost of production. The marginal cost of production is the cost of producing an extra unit of output. The theory states that if it costs $10 to produce an additional unit, while the selling price is $20, firms will rush to produce that extra unit since they can make money on it. This additional supply will drive the price down and this trend will continue until the market price is brought down to the marginal cost of production.

In the oil & gas industry this rule has definitely applied.

The main reason why the crude oil price began to rise following the turn of the century, eventually reaching $100/B in 2008, was not that the world was running out of crude oil (Peak Oil). It was running out of conventional crude oil.

Conventional crude oil production appears to have peaked sometime during 2006.

From that moment onward the oil companies had to tap into resources which were more difficult to access and, hence, more costly to produce, in order to meet growing demand from the BRIC countries - especially China. In other words, the marginal barrel had become substantially more expensive. If the world wanted this additional crude oil it would have to pay for it, and so prices rose.

Source: Energy Information Agency (www.eia.org)

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Of course, in 2014 the crude oil price fell again, down to the $40/B - $60/B range.

This was due to fact that when the crude oil price was high, the oil & gas industry was the most interesting business proposition for investors. From 2009 through 2013 the oil & gas industry raised about $850 billion in new capital, a massive 27 percent of all new capital raised globally during this period. This money oil & gas companies poured into development of unconventional sources of oil, such as ultradeepwater, oilsands and tight oil (shale), which had become economically viable due to the high oil price. Total capital investment by the industry rose 50 percent compared to 2008 and consequently production increased. Tight oil in the United States alone added 3.5 million barrels of production per day to global supply.

Global economic growth, on the other hand, did not keep pace, meaning that crude oil supply grew faster than crude oil demand. When during 2014 the IMF then began warning about a coming era of mediocre growth, it became clear that the crude oil market would be in a prolonged state of oversupply and the price collapsed.

This is only a temporary suspension of the rule of marginal cost pricing, however.

Right now the market is adapting to the new reality. The low crude oil price has caused a sharp decline in oil & gas capital investment already, and this is expected to continue throughout 2016. Eventually this will cause supply to drop to the level of demand. Once the rebalancing is complete, the rule of marginal cost pricing will again drive the crude oil price.

What crude oil price will this lead to in the short-, medium- and long-term?

Short-Term (less than 10 years out) Between 2011 and 2013 the cost of the marginal barrel increased from $89/B to $114/B. But, the current low price environment has put a lot of pressure on the operators of unconventional resources to reduce their costs, which has brought the cost of the marginal barrel down substantially. For example, due to innovations (improvements in drilling, reduced water usage, reduced sand usage, refracking, reservoir modeling improvements) tight oil production in the United States is on way to a 65% cost reduction. The average break-even price for US independent producers is now estimated to be around $42/B, with a low of just $24/B for some parts of the Bakken Shale. That is why many American shale companies say they can now be as successful at $65 a barrel as they had been at $100 a

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barrel.

There remains a lot of tight oil in the United States that the fracking technologies can be applied upon. These technologies could also be exported relatively easy to other parts of the world with tight oil reservoirs, such as Russia, Argentina, and the United Arab Emirates.

Therefore, barring a major unforeseen uptick in global economic growth, tight oil will be able to meet the increase in demand over the next 10 years. Since this oil can now be produced at a cost in the 40/B - $60/B range, this effectively means the crude oil price will remain in this range.

Medium-Term (between 10 to 20 years out) Two trends will have a major impact on the crude oil price in the medium term.

The first is the trend of continuous innovation in fracking technologies. The players in the fracking industry will not stop innovating now that they have reduced production costs. Due to competition the cost of the marginal production technologies will continue to go down, lowering the cost of the marginal barrel of crude oil, as the number of recoverable barrels will continue to go up.

The second trend that will drive the crude oil price in the medium term is the transportation sectors' gradual move away from petroleum. Currently, more than 60% of crude oil produced is used for transportation. However, Tesla is leading the popularization of electric vehicles. In fact, Tesla could be said to be revolutionizing the car industry, asVolkswagen recently announced it would pivot to electric vehicles. Renault-Nissan's CEO Carlos Ghosn explained this move when he said: 'A decade ago many people thought electric cars would never make it. The transformation in thinking about electric cars is (now) complete. EVs are on their way to becoming a mainstream choice'. Toyota responded to this trend by announcing it will target a 90% reduction in the emissions of its vehicles through utilizing hybrid and fuel cell technologies.

These changes in the car industry will limit the growth in crude oil demand and thereby extend the period during which the current marginal production technologies can be used to meet crude oil demand.

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Long-Term (more than 20 years out) The global energy industry is on the eve of major disruption. All three obstacles that have so far prevented renewables from really taking on oil, natural gas and coal are currently in the process of being overcome by technological innovation.

Continued research into solar power coupled with industrial scale production of solar panels has lead to the cost of solar power for electricity generation dropping much faster than anticipated earlier. Apparently, in parts of the United States utility-scale solar power generation capacity can now be delivered at a price below that of natural gas based power generation plants and a similar milestone is expected to be achieved in Europe within another 10 years. This means that in the not too distant future, on a cost basis renewables will be able to fully compete with hydrocarbon energy sources.

The intermittency of solar and wind energy and their limited mobility have been further obstacles to renewables powering the global economy. Energy storage is close to overcoming these issues, however. Battery innovations over the last 20 years have lead to an increase in capacity and a decrease in cost. Mass production of the batteries at Tesla's gigafactorywill move energy storage technology further forward. Tesla hopes this will enable it to capture the home and grid energy storage market, that eventually could be worth as much as $50 billion. But a number of other companies with venture capital backing are furthering alternative battery technologies to beat Tesla to it.

Lastly, the global focus on reducing emissions and the Millenial's preference for renewable energy, which mean that through switching to renewables companies can establish for themselves a competitive advantage, will ensure a continuation of this technological progress. Over time this trend will weaken the link between energy demand and crude oil demand, meaning less and less of the growth in the energy market will translate into growth in crude oil demand, until eventually the link breaks entirely and overall crude oil demand starts to go down.

In the long run, therefore, demand will prevent the crude oil price from rising.

View more quality content from Andreas de Vries

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Primed for Exploration Written by Tom Liskey from Drillinginfo Despite oil's tailspin over the past year, the Northern Latin American offshore is maintaining momentum. Boardrooms in Houston and London are tightening belts to compensate for shrinking profit margins amid the uncertainty, but the recent uptick in Caribbean area activity has yielded two headline grabbing discoveries in maritime Guyana and Colombia.

This surprising, if not long-sought, turn of events has put the focus on the global industry's splash in the regional offshore. Advances in seismic acquisition and imaging and deepwater drilling has only helped to improve the industry's odds in finding oil. That may come as a surprise to some since until recently the Greater Caribbean Basin was little more than a sideshow to the frenzied drilling activity in the Gulf of Mexico. Even before oil topped US$ 100 per barrel, state-run Pemex in Mexico and the US industry were developing offshore oil production at a fast clip.

Yet the Northern Latin American and Caribbean offshore-at best-were still seen as high risk bets. Now the roster of oil explorers active in the Northern Latin American and Caribbean offshore includes some of the industry's biggest names: Anadarko Petroleum, ExxonMobil, Repsol and Norway's Statoil...the list goes on.

The reasons behind the trend are diverse. Despite the promise of Venezuela's Petrocaribe oil supply agreement, energy-starved recipients of the dead Hugo Chavez's supply deal were pommelled by sky high petroleum import bills. Because while state-run PDVSA supplied poorer economies in the region with discounted crude for much of the past decade, these Venezuelan oil consuming nations ran up billions of dollars in unpaid import debt.

Caracas allowed them to pay for 60% of the cost for oil at the time of purchase, while putting aside 40% of that cost to finance critical development projects at home.

Economic advancement was stymied by high prices and the global recession in 2008. Venezuela's current president, Nicolas Maduro, continues to praise Petrocaribe's role in regional energy security, but the end result has been less than hoped for. Now many in Washington and the region doubt Petrocaribe's long-term sustainability. Amid these concerns, regulators are laying the groundwork for a

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series of licensing rounds.

Aruba Repsol may have the inside track in Aruba. In 2014 it nabbed Total and BG as farmin partners in the 14,370 sq km Aruba Offshore E&P Block. Highlighting recent activity, Aruba's Minister of Economic Affairs, Communication, Energy and Environment, Mike de Meza, reported that the Repsol-led effort will decide on drilling a wildcat well in early 2016.

The Repsol-operated block extends over 120km north of onshore Aruba into water depths spanning 50m to 3,000m. In 2014, Dolphin used the Polar Duke survey vessel to carry out a 3,200 sq km 3D seismic survey.

Barbados One of the smaller producers in the Caribbean Sea, Barbados, in 2015, unveiled a new licensing round showcasing seven shelf and deep-water blocks in the Northeast Caribbean Deformed Belt. Specifically, the Barbados round includes the 2,470 sq km River Bay Block; the 2,479 sq km Black Belly Block; the 2,489 sq km Holetown Block; the 2,498 sq km Paynes Bay Block; the 1,342 sq km Man Jack Block; the 2,772 sq km Flying Fish Block; and the 1,694 sq km Steel Donkey Block.

The closing date for bid proposal is on 30 December 2015, while the Division of Energy and Telecommunications says it has already received one proposal for Black Belly.

Meanwhile the country's onshore is getting a boost as well, as the government wants to stimulate production from aging oil assets and increase natural gas output to help cover an energy shortage on the island.

The Caribbean-focused Bajan Hydrocarbons is looking to work with state-run Barbados National Oil Company Limited to develop a 'huff and puff' carbon dioxide pilot program on the 600-bo/d Woodbourne Field.

The Bahamas Nestled in the blue water Caribbean, The Bahamas has a package of draft

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compendium oil regulations poised for a second reading in The Bahamas House of Assembly. This Petroleum Act, if approved, will go far in modernizing the country's upstream and potentially bring new oil investment to The Bahamas.

Currently, UK-based Bahamas Petroleum Company (BPC) holds a group of blocks offshore south of The Bahamas, close to the Cuban border. BPC was able to secure an extension for the second exploration period for its Southern Basin, Cooper, Donaldson and Eneas licenses. The company is looking for a farm-in partner.

Belize While Belize produces onshore crude from fields like the Belize Natural Energyoperated Spanish Lookout, plans for offshore development has been more contentious. In 2015, the Geology and Petroleum Department, which falls under Ministry of Energy, Science, Technology and Public Utilities, released a draft copy of a proposed Petroleum Exploration Zones and Exploration Guidelines. But Oceana Belize and other conservationist groups unleashed a campaign to halt offshore exploration, claiming the country's reef system would be at risk. Offshore exploration in the near term also looks unlikely. A court in 2013 banned drilling in six Production Sharing Agreements (PSAs) held by Princess Petroleum, Island Oil, SOL, PetroBelize and Miles Tropical and Providence Energy.

Costa Rica The Eco-friendly Central American nation has banned oil exploration through 2021 after President Luis Guillermo Solis in August 2014 extended a moratorium. The original three-year moratorium expired in early August 2014. US-based Mallon Oil Company was awarded six exploration blocks in 2000, though the awards were never signed.

Colombia Colombia's barely touched offshore is in the spotlight after two recent discoveries.

The largest discovery is the Petrobras-operated Orca-1 deepwater NFW. Located in the eastern portion of the Tayrona Block, Orca is estimated to hold an initial 1.5 Tcf in reserves.

In the 8,725 sq km E&P license block, the Brazilian operator holds 40% stake,

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Repsol has about 20% and Ecopetrol holds the remaining 30%. Statoil secured 10% stake from Repsol. Elsewhere in the Colombian offshore, Anadarko Petroleum tapped the Dolphin Bolette Drillship to spud the Kronos-1 and Calasu-1 wells on the Fuerte Sur and Fuerte Norte blocks. Anadarko in July reported that Kronos encountered 39 to 70 net meters of natural gas pay before drilling activity was suspended. That means the well proved the presence of a working petroleum system. Anadarko (50%) and Ecopetrol (50%) are partners in the area. Anadarko also holds the COL-1, COL-6 and COL-7 blocks, which it picked up at Ronda 2014.

In Colombia, more drilling is in the works with Repsol pouring over plans to drill the Siluro-1 wildcat in the RC-11 contract in the eastern part of the Caribbean.

Separately, Ecopetrol and ONGC will drill the Molusco-1 NFW on the RC-9 Block in the Guajira Offshore Basin in 2016.

At a governmental level, the Mines and Energy Ministry sees much potential offshore. In late September 2015, policymakers unveiled a four-point Petroleum Competition Plan aimed at boosting the oil industry through 2030. The plan envisions new investment, strengthening the National Hydrocarbons Agency, making projects more economically attractive as well as improving the permitting process.

Cuba After a string of disappointing exploration results from PDVSA (Cabo de San Antonio 1X), Repsol (Jag端ey 1) and Petronas (Catoche 1), among others in 2012, Cuba is trying to spur greater activity in its Exclusive Economic Zone in the Gulf of Mexico.

State-run CubaPetroleo (Cupet) is throwing out the welcome mat even as relations between Havana and Washington thaw.

While Cuba is touting a new taxation law that caps profits on oil and other minerals at 22.5%, new developments are afoot. Among them, Cupet and PetroVietnam in late September 2015 reaffirmed plans to advance energy cooperation on the archipelago. While the country's most recent offshore campaign fizzled out without any discoveries, officials indicate that Angola's Sonangol, which holds two licenses offshore Cuba, has not shut the door on future drilling.

Dominican Republic After the Dominican Republic raised US$ 2.5 billion via a global bond sale to help

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pay a major chunk of that nation's Venezuelan oil debt, or about US$ 1.9 billion, the government is planning a new licensing round. Energy and Mines Minister Antonio Isa Conde recently detailed plans to hold a competitive bidding process aimed at bringing explorers to the country. Oil field giant Schlumberger is digitizing geophysical data to create a National Hydrocarbons Database (BNDH). The Caribbean nation aims to launch the oil round in 2016.

French Guiana Supermajor Shell, using the Stena IceMax Drillship, drilled the unsuccessful GM-ES2, GM-ES-3, GM-ES-4 and GM-ES-5 well program to investigate the Cingulata fan system containing the Zaedyus discovery in the 2012-2013 time period. Given the lackluster results and lower oil prices, no firm plans going forward have been announced. Even so, Hague and London Oil (HALO), the company formerly known as Wessex, and which also holds a 44.11% interest in Northpet Investments Limited, is reviewing options for its interest in the Guyane Maritime Permit, offshore French Guiana.

In 2011, then-operator Tullow made the initial discovery with its Zaedyus well. A handful of other companies have filed for permits, but no new developments have occurred.

Guyana After years of waiting in the shadows, the spotlight has finally fallen on Guyana with ExxonMobil's Liza-1 discovery in the Stabroek Block. The well, earlier this year, encountered more than 90 m of high-quality oil-bearing sandstone pay. Highlighting its importance, the discovery, if commercial, will bring in much needed revenue and boost economic development for the financially strapped nation. While the news of the discovery has been exciting for Guyana, it has also rekindled Venezuelan claims to nearly half of the former British colony, including the potentially lucrative offshore.

But the drop in oil prices has tempered optimism somewhat. One of the country's long-standing explorers, CGX Energy, the Canadian company controlled by Pacific E&P (formerly Pacific Rubiales Energy), recently announced its decision to delay plans to spud Kabukalli 1 well on the offshore Corentyne Block as it waits for oil prices to recuperate. The company is also looking for a new farm in partner.

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Haiti While onshore, it is worthwhile to note activity in the impoverished nation, which shares the island of Hispaniola with the Dominican Republic. This past summer, and amid much local fanfare, Haitian Petro-Gaz Haiti SA (PGH) spun the drill bit on its six-block holding. PGH has an agreement with Trinidad-based Caribbean Well Service Company Limited to operate the projects. No results from the drilling have been announced.

Honduras BG, which is being acquired by Shell, has completed the first phase of exploration work on the offshore contract it holds in the offshore Mosquitia and Patuca Basins.

Upcoming plans call for a 2D seismic survey on the acreage that extends some 35,000 sq km offshore Honduras. A multibeam echo sounder and seabed coring program, which began in July, covered an area of the Patuca Basin exceeding 10,000 sq km in the northern part of the block.

Jamaica Jamaica got a shot in its arm in November 2014 after Tullow Oil inked a Production Sharing Agreement (PSA) with the Petroleum Corporation of Jamaica for a group of blocks covering 32,065 sq km offshore in the Walton and Morant basins. Tullow's acreage position includes 10 blocks and part of one shallow water block located just south of Jamaica's western tip.

Tullow Oil plans to carry out low cost studies, reprocessing work and potentially a new 2D and 3D seismic shoot if it decides to move ahead with any exploration.

According to the Inter-American Development Bank, Jamaica imports 84% of its energy needs. The bauxite industry is a larger energy consumer.

Mexico Mexico, Latin America's second largest economy, grips the western fringe of the Caribbean Sea. One cannot talk about the region without mentioning this nation's oil opening. Mexico has lost over 1 million bo/d in output since 2006 and is moving aggressively to boost production despite the sharp drop in prices.

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The result of President Enrique Pe単a Nieto's hard won campaign to modernize the energy sector, the country's 2014 Round Zero process, gave state-run oil company Pemex firm footing in the Mexican upstream with 83% of the country's 2P reserves and 21% of its prospective resources. That includes a raft of fields that Pemex is farming out like Exploratus and Trion in the Perdido Fold-belt and the natural gas Kunah-1 and Piklis-1 discoveries in the Catemaco Fold-belt.

In tandem with Pemex's search for partners, National Hydrocarbons Commission's (CNH) is orchestrating a series of bidding rounds spanning the onshore and offshore.

As of 30 September 2015, Mexico had completed the first two tranches of this multiphase Round 1 process. While expectations initially ran high, the turnout at CNH's 15 July 2015 bidding for 14 offshore exploration blocks was subdued. In the end, the Talos Energy, Sierra Oil and Premier consortium picked up the only two tracts awarded at the event: Block 2 and Block 7.

The second batch of fields to go under the gavel on 30 September saw broader industry participation with Eni of Italy winning rights to the Contract 1. That's the license area that includes the Amoca, Mizton and Tecoalli shallow water fields. Also at the 30 September auction, Houston-based Fieldwood Energy and Mexican partner Petrobal on 30 September 2015 scooped up rights to Contract Four's Ichalkil and Pokoch fields while the Argentine consortium Pan American Energy and E&P Hidrocarburos stopped up the Contract 2 area Hokchi Field.

All eyes are now on Mexico's pending deepwater tranche, which has been delayed as regulators draft contract terms. This leg in the Round 1 process may draw high bids from companies eager for a slice of the country's deepwater riches, particularly in light of several Lower Wilcox discoveries on both sides of the maritime border in the Perdido Fold-belt.

While it remains to be seen, however, if big budget-averse supermajors plan to participate in this upcoming tranche, more rounds are expected.

The Energy Secretariat (Sener) in early July 2015 unveiled the country's draft plan to offer more than 900 onshore and offshore areas encompassing conventional and unconventional resources in four rounds through 2019. Dubbed the Five-Year

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Licensing Plan for Hydrocarbon Exploration and Extraction 2015-2019, Sener said the round include areas with proven oil and gas reserves as well as exploration tracts.

Nicaragua While Nicaragua was one of the main benefactors of the Venezuelan backed Petrocaribe deal, the Sandinista-led government has made strides in opening the nation's upstream after the National Assembly approved a bill aimed at shoring oil exploration in the impoverished nation.

Earlier this year, Norway's Statoil picked up four new licenses in Nicaragua's frontier Pacific Ocean Sandino Basin. These blocks: C1; C2; C3; and C4, are held in partnership with state-run Empresa Nicaraguense de Petroleo (Petronic). Statoil holds 85% while Petronic holds the balance.

Meanwhile in the Caribbean, US-based Infinity Energy Resources, in a planned partnership with Granada Exploration, hopes to explore the offshore Perlas and Tyra licenses. Infinity has already acquired 1,050km in 2D seismic over the acreage. In one recent setback, however, the oil explorer EastSiberian had its application to act as a qualified exploration and exploitation contractor rejected by the Nicaraguan Ministry of Energy and Mines.

Panama Panama's Energy Secretary, Victor Urrutia, told participants at an event in Houston in May 2015 that the nation is planning a bid round, though no firm date was given.

Industry sources say that several companies, particularly offshore explorers, have expressed interest in exploring the Central American nation. Panama potentially can offer acreage east of the Panama Canal, including tracts in the Pacific Marhin offshore Garachiné-Sambús Basin. The Empresa OTS Latinamérica LLC (OTS) 2011 study estimated reserves of 900 million barrels of oil.

Suriname The smallest nation in South America, this former Dutch colony, which produces about 16,000 bo/d onshore, holds offshore ambitions. Drilling this year was focused on the back-to-back offshore wildcats Popokai 1 (Apache's deepwater Block 53) and

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Spari 1 (Teikoku Oil and Tullow Oil shallow water Block 31). While Spari was noncommercial, Apache has not revealed any results from its wells. Suriname recently unveiled a new 'Open Door Invitation'for onshore and offshore blocks in the former Dutch colony. The open tracts onshore Suriname includes Nickerie, Coronie and the Commewijne Block.

Trinidad and Tobago Voters in natural gas-rich Trinidad & Tobago this past September 2015 swept Keith Rowley, head of the People's National Movement (PNM) party into power. With energy production waning, the duo-island nation is hoping to turn the corner.

Energy Minister Nicole Olivierre says the sharp drop in oil and condensate production is spurring regulators to look at a licensing round covering both onshore and offshore acreage to help revive the nation's energy fortunes.

Natural gas-rich production has dipped to 3.86 Bcf/d from 4.3 Bcf/d five years ago while liquids production has slipped to 81,000 bo/d from 98,100 bo/d in the same time period. There is some merit to the belief that Trinidad and Tobago still have plenty of untapped potential. With a 2014 Ryder Scott Reserves Report in its pocket, identifying 127 prospects within acreage currently operated under Production Sharing Contracts and E&P Licenses, the country is optimistic.

Venezuela The largest OPEC producer in the region, Venezuela is turning to its offshore. The socialist-led nation, which shut the door on many shareholder-owned oil companies, has an ambitious plan to lift production to 6 million bo/d by 2019, versus current output now of 2.85 million bo/d.

But to do that, the country needs new E&P investment in the onshore and offshore.

According to top policymakers, Venezuela is evaluating ways to boost offshore hydrocarbon production. Jose Gregorio Prieto, vice minister of Venezuela's Ministry of the Popular Power for Energy and Petroleum (Menpet), in early October 2015 said that the OPEC nation may ramp up offshore natural gas exploration efforts in a bid to boost reserves in the area of the islands La Tortuga and La Blanquilla. In fact, natural gas holds much of the allure for the country's offshore ambitions. Venezuela produces between 6.7 Bcf/d and 7 Bcf/d, but still runs a deficit of the fuel.

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The Northern Latin American and Caribbean offshore are emerging. New round offerings will only add fuel to the pace of current activity. And while appraisal work remains to be done for the ExxonMobil-operated Liza-1 well in Guyana and Petrobras' Orca find in Colombia, it still remains to be seen how low oil prices will impact activity going forward.

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Low oil prices are here to stay as the US shale oil revolution goes global Written by Roberto F. Aguilera & Marian Radetzki from The Conversation Oil price rises over the past 40 years have been truly spectacular, but the recent fall is probably here to stay, thanks to increasing production. We discuss these trends in our new book, The Price of Oil, published this month.

In constant money, prices rose by almost 900% between 1970-72 and 2011-13. This can be compared with a 68% real increase for a metals and minerals price index, comprising a commodity group that, like oil, is exhaustible.

Oil has increased in price unlike any other commodity

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In our view, it is political rather than economic forces that have shaped the inadequate growth of upstream oil production capacity, the dominant factor behind the sustained upward price push.

But we believe the period of excessively high oil prices has now come to an end. The international spread of two revolutions will assure much more ample oil supplies, and will deliver prices far below those experienced over the past decade.

The new oil revolutions Beginning less than a decade ago, the shale oil revolution has turned the long run declining oil production trends in the United States into rises of 73% between 2008 and 2014. An exceedingly high rate of productivity improvements in this relatively new industry promises to strengthen the competitiveness of shale output even further.

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The US shale oil revolution has triggered a dramatic increase in output A series of environmental problems related to shale exploitation have been identified, most of which are likely to be successfully handled as the infant, 'wild west' industry matures and as environmental regulation is introduced and sharpened.

Geologically, the United States does not stand out in terms of shale resources. A very incomplete global mapping suggests a US shale oil share of no more than 17% of a huge geological wealth, widely geographically spread. Given the mainly nonproprietary shale technology and the many advantages accruing to the producing nations, it is inevitable that the revolution will spread beyond the United States.

We have assessed the prospects of non-US shale oil output in 2035, positing that the rest of the world will by then exploit its shale resources as successfully as the United States has done in the revolution's first ten years. This would yield rest of world an output of 19.5 million barrels per day in 2035, which is similar to the global rise of all oil production in the preceding 20 years - a stunning increase with farreaching implications in many fields.

Another related revolution is beginning to see the light of the day, but news about it has barely reached the media. It is being gradually realised that the advancements in horizontal drilling and fracking can also be applied to conventional oil extraction.

If the rest of the world applies these techniques to conventional oil, as the United State has done, this would yield a further addition of conventional oil amounting to 19.7 million barrels per day by 2035.

The oil output increases are bound put downward pressure on prices, either by preventing price rises from the first-half 2015 levels, averaging some US$57 per barrel (Brent spot), or by pushing them back to these levels if an early upward reaction takes place.

Our optimistic scenario, which appears increasingly likely, sees a price of US$40 by 2035.

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Global implications The global spread of these revolutions and the ensuing price weakness that we envisage for the coming two decades will, on balance, provide a great advantage both to the oil industry and to the world economy at large.

Not surprisingly, public income from oil in producing nations may fall if they fail to compensate for falling prices by expanding output. We also suspect that the effects of the resource curse - where, paradoxically, nations with large resources don't experience economic growth - will ease as prices decline.

The two revolutions will apparently cement and prolong the global oil dependence, with implications for climate policy. The efforts to develop renewables for the purpose of climate stabilisation will become more costly, requiring greater subsidies, in consequence of lower oil prices.

The abundance caused by the revolutions will lead to hard to fathom changes in international political relations. Much of the oil importers' urge for political intervention and control will dissipate as access to oil becomes less urgent.

For instance, the heavy diplomatic and military presence of the United States in the Middle East is likely to be questioned when the country's dependence on oil from the region is further reduced.

The growth and geographical diversification of supply would not only suppress prices, but would also promote competition among suppliers and make it more difficult for producers to use energy sales in pursuit of political ends.

Roberto F. Aguilera Adjunct Research Fellow, Energy Economics, Curtin University Marian Radetzki Professor of economics, Lule책 University of Technology

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UK Government's Delusional Energy Policy and Implications for Scotland Written by Peter Strachan, Alex Russell and Geraint Ellis from Robert Gordon University This piece was written by Professor Peter Strachan and Professor Alex Russell of Robert Gordon University, and Professor Geraint Ellis of Queen's University, Belfast.

Prime Minister David Cameron and Chancellor George Osborne have made it clear that they wish to build a new fleet of nuclear power stations and further to exploit the gas reserves locked up in the UK's shale deposits. The Conservative government at Westminster are now undertaking an economic 'charm' offensive to convince the general public and other stakeholders that both nuclear power and on-land shale gas extraction are good for the economy of the UK, and that any associated risks are manageable through planning and regulation.

The devolved administrations of the UK, however, are taking a far more precautionary approach (and in fact in some cases, have 'no' say on nuclear power), with Northern Irelandrecently adopting what amounts to a planning ban on fracking for shale gas, there is a fracking moratorium in Wales, and in Scotland a fracking moratorium has now been extended to include the controversial technique known as underground coal gasification (UCG).

It is against this backdrop, that we reflect on the Conservative government's energy position and analyse the implications of UK energy policy, with a particular emphasis on Scotland. With the Scottish National Party (SNP) annual conference now underway, we also consider wider constitutional consequences.

Public Opinion on Nuclear Power and Shale Gas With mixed public opinion for new nuclear build and a palpable drop in public support

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for on-land shale gas extraction it appears unwise for the Conservative government and particularly their Secretary of State of Energy and Climate Change, Amber Rudd, not to reflect a little deeper on some of the implications of its current crusade on nuclear power and fracking. The current approach suggests to us that the Conservative government is more fixated on generating new tax take (and profits for large energy companies) rather than ensuring public concerns, and society's longterm welfare, are fully addressed.

Is it just about the economy?

Belief in a nuclear and shale gas boom appears to run deep within Conservative Party ideology, reflecting its free market tendencies: it is being promoted by the Prime Minister, Chancellor, Ministers with responsibility for Energy (such as Andrea Leadsom) and by Scottish Conservative MSPs (such as Murdo Fraser Convenor of Hoylrood's Economy, Energy and Tourism Committee). Combined with those with major economic interests, the Conservative government's energy policy appears to rest predominantly on the claims of the economic benefits that nuclear power and fracking will generate, including new tax take, job creation and reduced heating and lighting bills for consumers.

Setting aside for now wider concerns, are such economic claims credible when it comes to shale gas?

The Shale Gas Mirage Although the economic benefits of shale seem to glitter, we don't think it is actually, made of gold. Indeed, the UK lacks basic on-land fracking gas infrastructure and a skilled supply chain, while some of the companies involved are not based in the UK and so are likely to channel profits to overseas investors. Furthermore, in the current climate of falling oil prices, rock bottom gas prices, and a European gas market that is unlikely to be sympathetic to British shale gas, the very logic of rushing into fracking appears as unstable as a shale bed after it has been fracked. These are serious risks to the economics of onshore extraction, which are compounded when combined with the wider concerns over fracking activity.

What are these wider concerns?

Even if on-land shale gas extraction eventually proves economically feasible in the

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UK, the benefits accrued by the few people who will share the spoils must be balanced against the need to protect land, the use and contamination (from for example 'flowback') of valuable water resources, broader health concerns, as well as the visual impact of multiple gas pads, never mind the potential for land tremors. It is crucially important that the UK learns from the environmental, safety and health concerns that are now being more fully reported, as well as the permitting and regulatory failings that have become apparent in the US dash for shale gas.

There are also major concerns that the opening up of such major fossil fuel reserves is incompatible with greenhouse gas emission targets of the UK and its component parts,including Scotland. With the fast approaching UN climate change conference in Paris, Conservative government shale intentions will surely prove to be an awkward conversation for Amber Rudd, particularly as this follows the early closure of the Renewables Obligation (RO) scheme, the slashing of solar power support, and other recent decisions, all of which Al Gore, the former vice president of the United States recently considered to be somewhat puzzling.

Further, the removal of renewable sources of electricity from the climate change levy exemption is already having a devastating impact on energy infrastructure investment in the UK (for example Drax has pulled out of a ÂŁ1 billion Carbon Capture project), and there are increasing concerns that without a further big push the UK may not now meet their UK-EU 2020 renewable energy targets, with potential knock on consequences from EU fines.

To conclude this part of the discussion, the UK now appears to have lost its hard won status as a leading international player on energy and climate change issues.

Implications for UK Energy Policy on Scotland Scotland is an energy rich country, the UK's energy bank, with abundant offshore oil and gas, and renewable energy resources such as onshore wind and hydro, and with significant potential for offshore wind, wave and tidal power.

During the past decade Scotland has led the renewable energy revolution in the UK. But over the period of a few months, Holyrood now finds itself in a position whereby its world class and highly successful energy policy now appears to lie in tatters.

At a time when Scotland was fast moving towards its 2020 100 per cent renewable

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energy target; this now looks unachievable in the current energy framework set by the Conservative government's retreat from renewables. If this continues, we imagine that Holyrood may well have to make the tough decision to publicly declare the abandonment of their renewable and world leading climate change targets, blame London for it, and highlight how it could be different if Scotland had autonomy on these issues.

In terms of shale gas extraction the Scottish government in announcing its fracking moratorium back in January 2015 and only this month widening this to include underground coal gasification (UCG) has made clear it wishes to take a more cautious and evidence based approach, compared to the dash for shale gas pursued by their counterparts at Westminster. In addition, the SNP have been long opposed to new nuclear build in Scotland and has pledged to block any future proposals using their extensive planning powers, so this is another strand of contention between Edinburgh and London.

Another factor but beyond the scope of the current article, is the UK transmission charging regime, which appears to discriminate against electricity generation in Scotland. Existing transmission charging arrangements have for example contributed to the decision by Scottish Power to close its Longannet coal power station.

In summary, Conservative government priorities around on-land shale gas extraction and new nuclear build, combined with existing transmission charging arrangements, are fracturing Holyrood's relationship with Westminster. And at a time when political debate continues to focus on the question whether Scotland should be an independent country.

Final Thoughts Debates over Chinese investment in the UK nuclear industry over recent weeks have further highlighted the credibility issues behind the Conservative government's energy priorities. Whilst fixated on the need to deliver a new ÂŁ25 billion nuclear power project at Hinkley Point C, the UK nuclear landscape in recent years has witnessed significant political and policy support in the form of market restructuring.

Even so, we only slowly inch towards delivering the project, while the outcome of the legal challenge from Austria, has the potential to further embarrass the free-market credentials of the Chancellor.

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When it comes to on-land shale gas extraction the Conservative government must also move beyond only considering economic opportunities and more fully consider the wider implications, or, opposition will spiral and the shale industry will become dogged down with local planning dispute after dispute. This is already being exacerbated by Amber Rudd threatening to intervene to ensure that centrally imposed timescales for planning decisions are adhered to, which will become a major challenge if councils try to assimilate the thousands of public objections usually prompted by energy and other development proposals.

These issues jar the greatest in Scotland, which has based a large part of its future on a thriving (sustainable and low carbon) energy economy, which is now being choked by the approach being pursued by the Conservative government at Westminster.

We would strongly recommend that the Conservative's take more stock of their energy intentions, and to consider further the implications of their energy policies on its relationship with Scotland and the other devolved administrations.

It is already clear that in Scotland nuclear power, fracking for shale gas and transmission charging are going to feature heavily in the lead in to next year's Holyrood election. We suspect that UK energy policy as currently constituted may well have a devastating impact on the electoral fortunes of the Scottish Conservative and Unionist Party, and potentially even the Union itself. Of course, time will tell.

This piece was written by Professor Peter Strachan and Professor Alex Russell of Robert Gordon University, and Professor Geraint Ellis of Queen's University, Belfast.

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Low Oil Prices - Why Worry?

Written by Gail Tverberg from Our Finite World Most people believe that low oil prices are good for the United States, since the discretionary income of consumers will rise. There is the added benefit that Peak Oil must be far off in the distance, since 'Peak Oilers' talked about high oil prices. Thus, low oil prices are viewed as an all around benefit.

In fact, nothing could be further from the truth. The Peak Oil story we have been told is wrong. The collapse in oil production comes from oil prices that aretoo low, not too high. If oil prices or prices of other commodities are too low, production will slow and eventually stop. Growth in the world economy will slow, lowering inflation rates as well as economic growth rates. We encountered this kind of the problem in the 1930s. We seem to be headed in the same direction today. Figure 1, used by Janet Yellen in her September 24 speech, shows a slowing inflation rate for Personal Consumption Expenditures (PCE), thanks to lower energy prices, lower relative import prices, and general 'slack' in the economy.

Figure 1.

'Why has PCE Inflation fallen below 2%?' from Janet Yellen speech, September 24, 2015.

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What Janet Yellen is seeing in Figure 1, even though she does not recognize it, is evidence of a slowing world economy. The economy can no longer support energy prices as high as they have been, and they have gradually retreated. Currency relativities have also readjusted, leading to lower prices of imported goods for the United States. Both lower energy prices and lower prices of imported goods contribute to lower inflation rates.

Instead of reaching 'Peak Oil' through the limit of high oil prices, we are reaching the opposite limit, sometimes called 'Limits to Growth.' Limits to Growth describes the situation when an economy stops growing because the economy cannot handle high energy prices. In many ways, Limits to Growth with low oil prices is worse than Peak Oil with high oil prices. Slowing economic growth leads to commodity prices that can never rebound by very much, or for very long. Thus, this economic malaise leads to a fairly fast cutback in commodity production. It can also lead to massive debt defaults.

Let's look at some of the pieces of our current predicament.

Part 1. Getting oil prices to rise again to a high level, and stay there, is likely to be difficult. High oil prices tend to lead to economic contraction.

Figure 2 shows an illustration I made over five years ago:

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Figure 2. Chart made by author in Feb. 2010, for an article called Peak Oil: Looking for the Wrong Symptoms.

Clearly Figure 2 exaggerates some aspects of an oil price change, but it makes an important point. If oil prices rise-even if it is after prices have fallen from a higher level-there is likely to be an adverse impact on our pocketbooks. Our wages (represented by the size of the circles) don't increase. Fixed expenses, including mortgages and other debt payments, don't change either. The expenses that do increase in price are oil products, such as gasoline and diesel, and food, since oil is used to create and transport food. When the cost of food and gasoline rises, discretionary spending (in other words, 'everything else') shrinks.

When discretionary spending gets squeezed, layoffs are likely. Waitresses at restaurants may get laid off; workers in the home building and auto manufacturing industries may find their jobs eliminated. Some workers who get laid off from their jobs may default on their loans causing problems for banks as well. We start the cycle of recession and falling oil prices that we should be familiar with, after the crash in oil prices in 2008.

So instead of getting oil prices to rise permanently, at most we get a zigzag effect.

Oil prices rise for a while, become hard to maintain, and then fall back again, as recessionary influences tend to reduce the demand for oil and bring the price of oil back down again.

Part 2. The world economy has been held together by increasing debt at everlower interest rates for many years. We are reaching limits on this process.

Back in the second half of 2008, oil prices dropped sharply. A number of steps were taken to get the world economy working better again. The US began Quantitative Easing (QE) in late 2008. This helped reduce longer-term interest rates, allowing consumers to better afford homes and cars. Since building cars and homes requires oil (and cars require oil to operate as well), their greater sales could stimulate the economy, and thus help raise demand for oil and other commodities.

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Figure 3. World Oil Supply (production including biofuels, natural gas liquids) and Brent monthly average spot prices, based on EIA data.

Following the 2008 crash, there were other stimulus efforts as well. China, in particular, ramped up its debt after 2008, as did many governments around the world. This additional governmental debt led to increased spending on roads and homes. This spending thus added to the demand for oil and helped bring the price of oil back up.

These stimulus effects gradually brought prices up to the $120 per barrel level in 2011. After this, stimulus efforts gradually tapered. Oil prices gradually slid down between 2011 and 2014, as the push for ever-higher debt levels faded. When the US discontinued its QE and China started scaling back on the amount of debt it added in 2014, oil prices began a severe drop, not too different from the way they dropped in 2008.

I reported earlier that the July 2008 crash corresponded with a reduction in debt levels. Both US credit card debt (Fig. 4) and mortgage debt (Fig. 5) decreased at precisely the time of the 2008 price crash.

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Figure 4. US Revolving Debt Outstanding (mostly credit card debt) based on monthly data from the Federal Reserve.

Figure 5. US Mortgage Debt Outstanding, based on the Federal Reserve Z1 Report.

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At this point, interest rates are at record low levels; they are even negative in some parts of Europe. Interest rates have been falling since 1981.

Figure 6. Chart prepared by the St. Louis Fed using data through July 20, 2015.

I showed in a recent post (How our energy problem leads to a debt collapse problem) that when the cost of oil production is over $20 per barrel, we need everhigher debt ratios to GDP to produce economic growth. This need for ever-rising debt contributes to our inability to keep commodity prices high enough to satisfy the needs of commodity producers.

Part 3. We are reaching a demographic bottleneck with the 'baby boomers' retiring.

This demographic bottleneck causes an adverse impact on the demand for commodities.

Demand represents the amount of goods customers can afford. The amount consumers can afford doesn't necessarily rise endlessly. One of the problems leading to falling demand is falling inflation-adjusted median wages. I have written about this issue previously in How Economic Growth Fails.

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Figure 7. Median Inflation-Adjusted Family Income, in chart prepared by the Federal Reserve of St. Louis.

Another part of the problem of falling demand is a falling number of working-age individuals-something I approximate by using estimates of the population aged 20 to 64. Figure 8 shows how the population of these working-age individuals has been changing for the United States, Europe, and Japan.

Figure 8. Annual percentage growth in population aged 20 - 64, based on UN 2015 population estimates.

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Figure 8 indicates that Japan's working age population started shrinking in 1998 and now is shrinking by more than 1.0% per year. Europe's working age population started shrinking in 2012. The United States' working age population hasn't started shrinking, but its rate of growth started slowing in 1999. This slowdown in growth rate is likely part of the reason that labor force participation rates have been falling in the United States since about 1999.

Figure 9. US Labor force participation rate. Chart prepared by the Federal Reserve of St. Louis.

When there are fewer workers, the economy has a tendency to shrink. Tax levels to pay for retirees are likely to start increasing. As the ratio of retirees rises, those still working find it increasingly difficult to afford new homes and cars. In fact, if the population of workers aged 20 to 64 is shrinking, there is little need to add new homes for this group; all that is needed is repairs for existing homes. Many retirees aged 65 and over would like their own homes, but providing separate living quarters for this population becomes increasingly unaffordable, as the elderly population becomes greater and greater, relative to the working age population.

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Figure 10 shows that the population aged 65 and over already equals 47% of Japan's working age population. (This fact no doubt explains some of Japan's recent financial difficulties.) The ratios of the elderly to the working age population are lower for Europe and the United States, but are trending higher. This may be a reason why Germany has been open to adding new immigrants to its population.

Figure 10. Ratio of elderly (age 65+) to working age population (aged 20 to 64) based on UN 2015 population estimates.

For the Most Developed Regions in total (which includes US, Europe, and Japan), the UN projects that those aged 65 and over will equal 50% of those aged 20 to 64 by 2050. China is expected to have a similar percentage of elderly, relative to working age (51%), by 2050. With such a large elderly population, every two people aged 20 to 64 (not all of whom may be working) need to be supporting one person over 65, in addition to the children whom they are supporting.

Demand for commodities comes from workers having income to purchase goods that are made using commodities-things like roads, new houses, new schools, and new factories. Economies that are trying to care for an increasingly large percentage of elderly citizens don't need a lot of new houses, roads and factories. This lower demand is part of what tends to hold commodity prices down, including oil prices.

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Part 4. World oil demand, and in fact, energy demand in general, is now slowing.

If we calculate energy demand based on changes in world consumption, we see a definite pattern of slowing growth (Fig.11). I commented on this slowing growth in my recent post,BP Data Suggests We Are Reaching Peak Energy Demand.

Figure 11. Annual percent change in world oil and energy consumption, based on BP Statistical Review of World Energy 2015 data.

The pattern we are seeing is the one to be expected if the world is entering another recession. Economists may miss this point if they are focused primarily on the GDP indications of the United States.

World economic growth rates are not easily measured. China's economic growth seems to be slowing now, but this change does not seem to be fully reflected in its recently reported GDP. Rapidly changing financial exchange rates also make the true world economic growth rate harder to discern. Countries whose currencies have dropped relative to the dollar are now less able to buy our goods and services, and are less able to repay dollar denominated debts.

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Part 5. The low price problem is now affecting many commodities besides oil.

The widespread nature of the problem suggests that the issue is a demand (affordability) problem-something that is hard to fix.

Many people focus only on oil, believing that it is in some way different from other commodities. Unfortunately, nearly all commodities are showing falling prices:

Figure 12. Monthly commodity price index from Commodity Markets Outlook, July 2015. Used under Creative Commons license.

Energy prices stayed high longer than other prices, perhaps because they were in some sense more essential. But now, they have fallen as much as other prices. The fact that commodities tend to move together tends to hold over the longer term, suggesting thatdemand (driven by growth in debt, working age population, and other factors) underlies many commodity price trends simultaneously.

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Figure 13. Inflation adjusted prices adjusted to 1999 price = 100, based on World Bank 'Pink Sheet' data.

The pattern of many commodities moving together is what we would expect if there were ademand problem leading to low prices. This demand problem would likely reflect several issues: 

The world economy cannot tolerate high priced energy because of the



problem shown in Figure 2. We have increasingly used cheaper debt and larger quantities of debt to cover this basic problem, but are running out of fixes.

The cost of producing energy products keeps trending upward, because we extracted the cheap-to-produce oil (and coal and natural gas) first. We have no alternative but to use more expensive-to-produce energy products.

Many costs other than energy costs have been trending upward in inflation-



adjusted terms, as well. These include fresh water costs, the cost of metal extraction, the cost of mitigating pollution, and the cost of advanced education. All of these tend to squeeze discretionary income in a pattern similar to the problem indicated in Figure 2. Thus, they tend to add to recessionary influences.

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

We are now reaching a working population bottleneck as well, as described in Part 4.

Part 6. Oil prices seem to need to be under $60 barrel, and perhaps under $40 barrel, to encourage demand growth in US, Europe, and Japan.

If we look at the historical impact of oil prices on consumption for the US, Europe, and Japan combined, we find that whenever oil prices are above $60 per barrel in inflation-adjusted prices, consumption tends to fall. Consumption tends to be flat in the $40 to $60 per barrel range. It is only when prices are in the under $40 per barrel range that consumption has generally risen.

There is virtually no oil that can be produced in the under $40 barrel range-or even in the under $60 barrel a range, if tax needs of governments are included. Thus, we end up with non-overlapping ranges: 1. The amount that consumers in advanced economies can afford.

2. The amount the producers, with their current high-cost structure, actually need.

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One issue, with lower oil prices, is, 'What kinds of uses do the lower oil prices encourage?' Clearly, no one will build a new factory using oil, unless the price of oil is expected to be sufficiently low over the long-term for this use. Thus, adding industry will likely be difficult, even if the price of oil drops for a few years. We also note that the United States seems to have started losing its industrial production in the 1970s (Fig. 15), as its own oil production fell. Apart from the temporarily greater use of oil in shale drilling, the trend toward off-shoring industrial production will likely continue, regardless of the price of oil.

Figure 15. US per capita energy consumption by sector, based on EIA data. Includes all types of energy, including the amount of fossil fuels that would need to be burned to produce electricity.

If we cannot expect low oil prices to favorably affect the industrial sector, the primary impact of lower oil prices will likely be on the transportation sector. (Little oil is used in the residential and commercial sectors.) Goods shipped by truck will be cheaper to ship. This will make imported goods, which are already cheap (thanks to the rising dollar), cheaper yet. Airlines may be able to add more flights, and this may add some jobs. But more than anything else, lower oil prices will encourage people to drive

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more miles in personal automobiles and will encourage the use of larger, less fuelefficient vehicles. These uses are much less beneficial to the economy than adding high-paid industrial jobs.

Part 7. Saudi Arabia is not in a position to help the world with its low price oil problem, even if it wanted to.

Many of the common beliefs about Saudi Arabia's oil capacity are of doubtful validity.

Saudi Arabia claims to have huge oil reserves, but as a practical matter, its growth in oil production has been modest. Its oil exports are actually down relative to its exports in the 1970s, and relative to the 2005-2006 period.

Figure 16. Saudi Arabia's oil production, consumption, and exports based on BP Statistical Review of World Energy 2015 data.

Low oil prices are having an adverse impact on the revenues that Saudi Arabia receives for exporting oil. In 2015, Saudi Arabia has so far issued bonds worth $5 billion US$, and plans to issue more to fill the gap in its budget caused by falling oil prices.

Saudi Arabia really needs $100+ per barrel oil prices to fund its budget. In fact,

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nearly all of the other OPEC countries also need $100+ prices to fund their budgets.

Saudi Arabia also has a growing population, so it needs rising oil exports just to maintain its 2014 level of exports per capita. Saudi Arabia cannot reduce its exports by 10% to 25% to help the rest of the world. It would lose market share and likely not get it back. Losing market share would permanently leave a 'hole' in its budget that could never be refilled.

Saudi Arabia and a number of the other OPEC countries have published 'proven reserve' numbers that are widely believed to be inflated. Even if the reserves represent a reasonable outlook for very long term production, there is no way that Saudi oil production can be ramped up greatly, without a large investment of capitalsomething that is likely not to be available in a low price environment.

In the United States, there is an expectation that when estimates are published, the authors will do their best to produce correct amounts. In the real world, there is a lot of exaggeration that takes place. Most of us have heard about the recent Volkswagen emissions scandal and the uncertainty regarding China's GDP growth rates. Saudi Arabia, on a monthly basis, does not give truthful oil production numbers to OPEC-OPEC regularly publishes 'third party estimates' which are considered more reliable. If Saudi Arabia cannot be trusted to give accurate monthly oil production amounts, why should we believe any other unaudited amounts that it provides?

Part 8. We seem to be at a point where major debt defaults will soon start for oil and other commodities. Once this happens, the resulting layoffs and bank problems will put even more downward pressure on commodity prices.

Wolf Richter has recently written about huge jumps in interest rates that are being forced on some borrowers. Olin Corp., a manufacture of chlor-alkali products, recently attempted to sell $1.5 billion in eight and ten year bonds with yields of 6.5% and 6.75% respectively. Instead, it ended up selling $1.22 billion of bonds with the same maturities, with yields of 9.75% and 10.0% respectively.

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Richter also mentions existing bonds of energy companies that are trading at big discounts, indicating that buyers have substantial questions regarding whether the bonds will pay off as expected. Chesapeake Energy, the second largest natural gas driller in the US, has 7% notes due in 2023 that are now trading at 67 cent on the dollar. Halcon Resources has 8.875% notes due in 2021 that are trading at 33.5 cents on the dollar. Lynn Energy has 6.5% notes due in 2021 that are trading at 23 cents on the dollar. Clearly, bond investors think that debt defaults are not far away.

Bloomberg reports: The latest round of twice-yearly reevaluations is under way, and almost 80 percent of oil and natural gas producers will see a reduction in the maximum amount they can borrow, according to a survey by Haynes and Boone LLP, a law firm with offices in Houston, New York and other cities. Companies' credit lines will be cut by an average of 39 percent, the survey showed.

Debts of mining companies are also being affected with today's low prices of metals.

Thus, we can expect defaults and cutbacks in areas other than oil and gas, too.

There is a widespread belief that if prices remain low, someone will come along, buy the distressed assets at low prices, and ramp up production as soon as prices rise again. If prices never rise for very long, though, this won't happen. The bankruptcies that occur will mean the end for that particular resource play. We won't really be able to get prices back up to where they need to be to extract the resources.

Thus low prices, with no way to get them back up, and no hope of making a profit on extraction, are likely the way we reach limits in a finite world. Because low demand affects all commodities simultaneously, 'Limits to Growth' equates to what might be called 'Peak Resources' of all kinds, at approximately the same time.

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The Price Of Oil: Another Huge Historical Shift Written by John Richardson from ICIS

FIRST came the collapse of the Berlin Wall in 1989 followed by the reunification of Germany and the integration of Eastern Europe in general into the Western way of running the world.

Then came China's rise following the Deng Xiaoping 1992 'Southern Tour' and China's admission to the World Trade Organisation in 2001.

As these hundreds of millions poor eastern Europeans and even poorer Chinese migrant workers found better jobs then, of course, consumption of everything made from oil received a tremendous boost.

Simultaneously - and this is crucial to our understanding of what is happening today in oil and other commodities markets - waves of strong demand for all things manufactured in eastern Europe and especially in China surged out of the US, Canada and Europe. The reason was that the richest, and also crucially the biggest, middle class demographic cohort in the history of the entire world - the Babyboomers - were coming of age. They had moved out of their early twenties in the 1980s and had thus finished their education, found jobs and were starting families.

So they needed lots of things made from oil - for example, the first generation of disposable nappies. And of course they needed, and also could comfortably afford, automobiles to ferry their kids backwards and forwards to kindergartens. And the fact that the kids had to be placed in kindergartens or nursery schools told us that something else absolutely crucial about both the quantity of demand for oil and its

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affordability: These were dual-income households as women were working as well.

Like the Babyboomer generation, the introduction of hundreds of millions of women into the Western workforce provided another enormous 'one off' boost to the global economy.

Then, as sadly happens to all of us, the Babyboomers got older. But for many years this wasn't at all a bad thing because with greater age came both the ability to buy greater quantities of oil, and all the things made from oil - and an eagerness to buy an ever-higher quality of goods made from oil.

This virtuous march of time reached its zenith from around the mid-1990s to the middle of the first decade of this century. During that period, the Babyboomers were reaching the peaks of their middle class professional careers, and so they were earning lots and lots of money - more money by sheer quantity than any demographic cohort in the history of the world had ever earned, adjusted for inflation.

As we moved into the 2000s another very important event took place: The Babyboomers' kids grew up and became independent. For the first time for many years these super-rich middle class people didn't have to worry about paying university and college and fees, and so the statement, 'heh, honey I've always really wanted a Porsche,' was for the first time met with the reply, 'Sure, go out and get one'.

But then things started to go wrong. From the middle of the first decade of this century, the Babyboomers began to retire - and they are not being replaced, and simply cannot be replaced for at least 25 years.

Quite suddenly, the Babyboomers didn't have as much money as before because they were living on pensions. Not all of them had saved prudently enough for their retirements, and even hose who had stashed away lots of money were badly hit by the bursting of the dot com stock market bubble. Their savings were then hit in later years by the US sub-prime crisis and the end of the China commodities bubble.

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Plus, it is an inescapable fact - all the evidence points this way - that people spend less when they get older. They already own most of us what they need. Buying a two-seater expensive sports car therefore ends up being seen as silly, unnecessary and also an uncomfortable fit for ageing bodies.

A problem is that many people who analyse oil and other commodities markets were still very young, if they were born at all, in 1989. Or if they are of the right vintage, they have simply forgotten that world history is capable of major shifts in direction, as the collapse in the Berlin Wall so clearly tells us.

Another issue is that many of the other people who study oil markets don't even think about history, as they were never taught history beyond the basic level at school.

They are instead purely statisticians, geologists and engineers etc. Here is an interesting question for you: How many oil and chemicals companies make it mandatory that all of their oil analysts have studied history?

This crucial lack of understanding hasn't led to a shortage of opinions on the 'demand' side of the oil story. The problem has instead been that these opinions have never stood up to serious analysis because the people expressing these opinions haven't received the proper direction or training.

Would you set loose somebody who is only a history graduate on a survey of recoverable reserves at an oil field? Of course not. So why set someone loose on studying demand who not only doesn't understand history, but also has little grasp of all the social, political and environmental factors that are reshaping the world?

Let me give you just three examples of demand side opinions about oil, and all the things made from oil, that have never stood up to serious analysis:

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1. OK, the Babyboomers are retiring in record numbers, but China and the rest of the emerging world is becoming middle class. Hundreds of millions more middle class in the emerging world will easily replace this lost demand from the Babyboomers.

2. The US economy is back, thanks to the shale-oil and gas booms and the 'trickle down' effect of the Fed's stimulus policies. So the American consumer will yet again ride to the rescue of global oil demand.

3. So what if air pollution is killing 1.6 million people in China every year? Who cares if there is a new global consensus on global warming? These are just concerns for a minority of 'tree huggers', and have nothing to do with the global oil industry.

This is why we are where we are today: Too many people expecting that supply side cutbacks by themselves guarantee a significant and sustainable recovery in oil prices over the next few years - and that this recovery will by itself indicate a return to a healthy global economy.

Sure, there are many counterarguments out there to what I have detailed above. But they have to be informed, carefully thought-through arguments as the thinking on oil demand that got us into this mess in the first place has clearly failed. Disagree?

Then why was it that most people missed last year's oil-price collapse?

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Why I've Started Buying Oil Stocks Again Written by Keith Schaefer from Oil & Gas Investments Bulletin I'm off to Dubai for a week of meetings, but I want to leave you with some ideas that should leave you...questioning...The Bear Case on oil.

I want to be clear...I'm not a perma-bull on oil. Far from it. I'm an investor, and a trader, looking for a trend. Energy is my chosen field right now.

So I don't care which direction oil moves-as long as it moves; show me a trend. The oil price staying flat is a trend.

So where is oil going? While the reality is-nobody knows-there is some evidence emerging that suggests the global oil market is a lot tighter than most people believe.

Here's three points to consider: 1. Charlie Brown and The IEA (International Energy Agency) Remember poor oil Charlie Brown trying to kick that football? Lucy tricked him every time.

The International Energy Agency trick investors every year. Because the IEA makes the same error each and every year: they chronically underestimate global oil demand by a wide margin.

US brokerage firm Raymond James took the IEA's initial reporting of global oil supply and demand over a 15 year period and compared it to what the IEA's final figures were for the same period several years later.

They found that on average the IEA had to revise its demand estimates higher by 700,000 barrels per day.

Bolding and underling of their conclusion intentional!

That is the size of the error in an average year. What then happens in a year where

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oil prices have been cut in half?

This year there is good reason to believe that the IEA has underestimated demand by a lot more than 700,000 barrels per day. The IEA's initial second quarter report included a 1.7 million barrel per day 'plug' which was required to balance their numbers.

A 'plug' is accountant lingo for 'I can't figure this out'. It's like a contingency fund.

The IEA had to include this plug because inventory levels didn't rise as much as the IEA's estimates of supply and demand said they would.

The IEA thought that the oil market was oversupplied by 3 million barrels per day, but they could only account for 1.3 million of those barrels.

I know it's a crazy thought....but could the plug relate to the IEA underestimating demand? I know I'm thinking outside the box, I mean after all they have only done exactly that for the past 15 years in much less volatile markets.

With oil prices under $50 per barrel, it would make a lot of sense that they have underestimated demand this year by much more than they usually do.

Remember, the IEA data is a primary source of inputs for oil market analysts. That means that this underestimation by the IEA has filtered through oil analysis everywhere-potentially making almost every analyst's estimates of demand significantly too low.

2. Chicken Little Says China's Oil Demand Is Falling An acorn dropped on Chicken Little's head and she ran around telling everyone who would listen that the sky is falling.

That was an overreaction.

China's economy is clearly slowing, and that has translated into the media repeating over and over and over again how weak China's demand for oil is.

It is very easy explanation for weak oil prices, but I don't think these Chicken Little's have actually checked any data to support their claims.

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The reality is that China's oil demand is just fine thank you very much.

According to Platts Chinese oil demand was up 10% year on year in August of 2015.

It's up about 8.8% on the year in total. and wasn't August the month that the weakness in China's economy really rattled the markets?

Clearly China isn't firing on all cylinders. But it's also clear oil consumption is not suffering. That doesn't seem to add up, but there is an explanation.

What has happened is that Chinese demand is changing.

Oil demand from industrial consumers (users of diesel) has levelled off as subsidies of infrastructure projects have dropped. What has more than offset this is consumption growth of gasoline and kerosene from non-industrial consumers.

An even bigger surprise (certainly to me) might be what has happened to China's oil inventories over the summer.

As Stephen Kopits of Princeton Energy Advisors points out, August commercial oil and refined products inventory levels relative to rates of consumption in China didn't just not increase....they actually decreased.

That can't happen if oil demand is plummeting.

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Source: Prienga.com As Kopits said....'Anyone looking for excess commercial oil inventories will not find them in China.'

That's weird, because if the IEA's 1.7 million missing barrels aren't in China....where else could they be?

3. Where Is The Contango?

A few weeks ago Goldman Sachs rattled a few cages by suggesting that the oil glut had actually gotten worse in recent weeks and that $20 per barrel oil was a real possibility.

Since Goldman was likely using the 3 million barrel per day oversupply figure it took from the IEA for Q2, saying things had gotten worse was really saying something.

If the oil glut is as huge as Goldman suggests a question that has to be asked is 'why aren't we looking at a severe contango in the oil futures market'?

A contango structure in the futures market is when front month oil prices trade at a discount to future month oil futures prices. The futures curve slopes upwards and to the right.

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In an environment where there is a massive oversupply we would typically expect to see a severe contango situation where front month prices trade at a big discount to future months. Too much near term supply would obviously put significant pressure on near term prices.

When oil demand collapsed in 2008/2009 and a serious oversupply situation clearly existed the difference between the front month and a year forward was over $23 per barrel for WTI. As of last week the year forward price for WTI was roughly $4 higher.

That doesn't seem to scream 'glut'.

The Market Does Seem To Be Saying That A Bottom Is In There's more. Did you see the market action following last week's EIA report. The report was decidedly bearish.....yet oil stocks performed well and oil held up too.

To me that says the Market believes-that while oil will not go up in a straight line...the bottom is in, and that psychology (for now) is all that's needed to see a lot of money come back to the sector.

Of course, the Market could be wrong, but last week's action was compelling. (There will almost certainly be some consolidation/choppy price action in oil this week as the Market digests these gains).

It's enough to get nibbling my favourite oil stocks in small chunks. One is absolutely the lowest cost, most profitable producer I see in the whole world at US$50 oil. The second is an old favourite who...did what the good management teams do in down markets. They buy other assets cheap, and get themselves (and their shareholders) in a great position to profit.

Volume and price are both picking up on this stock as it gets off the mat. The first move is always the biggest. To get this stock, and why I like it, click here.

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Declining oil price and the Nigerian economy: An opportunity for national oil and gas industry and local content reform Written by Abhishek Agarwal, Udechukwu Oguagha and Stephen Vertigans from Robert Gordon University

Although the economies of all oil exporting countries are suffering during the current sharp drop in the price per barrel, the immediate consequences are the severest in countries that rely most heavily on the oil business. Nigeria is amongst the five countries most affected by the fall in oil prices and consequently is at the forefront of countries facing particularly difficult economic challenges. With oil accounting for over 96% of Nigeria's export revenue earnings and 75% of government revenue the recently elected Buhari Government is already facing huge economic challenges.

Yet, conversely, the deteriorating oil price can be utilised to address fundamental weaknesses within the oil sector which would accord with Buhari's political mandate.

His electoral success was arguably built around his two main reputational strengths, security and anti-corruption. Delivering electoral promises on security has resulted in directed military campaigns against Boko Haram. Against this backdrop Buhari's recent decision to appoint himself as Oil Minister reflects how reforming energy and addressing endemic corruption is as fundamental, if not more so, to Nigeria's future as defeating Boko Haram.

The reasoning behind Buhari's focus on oil and corruption is not new. There have been long standing accountability and transparency issues at all levels of

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government and industry. An example is the failure of the Nigerian National Petroleum Corporation (NNPC) to account for billions of dollars owed to the federal government over the last few years. The subsequent drop in the oil price, shortly after Buhari's inauguration in May 2015, means that addressing such corruption has become even more urgent. Moreover, the huge decrease in revenue has also been compounded by the major blow to the Nigerian economy when the US shale gas boom reduced oil imports from Nigeria.

Consequently, the dependency on diminished oil and gas revenue, allied to high levels of inefficiencies and corruption throughout the supply chain, threatens the country's economic sustainability. The Deutsche Bank estimated Nigeria's budget would break-even with 2015's oil price of $122. However, the recent downturn in oil price has forced the federal government to adjust its budgets twice to accommodate an estimated $65 a barrel and reduce capital spending plans by less than 10% of the 2015 budget. The oil price has now dropped to under $50 a barrel and on-going over-production could see further decline.

Furthermore, the naira fell to under one-third against the dollar, highlighting the inability of the Nigerian government to balance its budget. This has adversely affected the Nigerian banking sector, where approximately 20% of loans are granted to local oil and gas companies. The central bank has had to devaluate the naira to accommodate the fall in oil price; thus, Nigerian oil and gas companies that rely on foreign loans will either have to pay more in naira to offset the borrowing or will be unable to pay back.

Against this bleak political and economic setting, Buhari has taken personal control to reform the oil industry, utilising the political goodwill that was generated during the election campaign. However, given the volatile nature of Nigerian politics and the unrest caused by last week's ministerial nominees, that goodwill is already dissipating and prompt actions are required if the government is to maintain widespread support.

To this end there have been a number of changes introduced. For instance, the federal government has introduced various austerity measures, which includes federal government securing an external loan of $5.7bn to finance infrastructural projects, and the introduction of fiscal consolidation to cut public expenditures for 2015.

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To control the devaluation of the Nigerian currency, the Central Bank of Nigeria sold its foreign exchange reserve and raised the interest rate. The resulting exchange rate depreciation affected many cost parameters, which is in itself a new hurdle for local oil and gas companies in Nigeria. This challenge has been exacerbated by demands made by the International Oil Companies (IOCs) for a discount on existing contracts undertaken with local Nigerian companies, to cushion the blow of falling oil prices. Although the Nigerian government has indicated that the local content requirements would be maintained, the growing success of the Nigerian local content policy has been put into jeopardy due to the IOCs demands. However, agreeing to the discount demands is not financially sustainable for most local companies, yet these companies are unwilling to take legal action for fear of losing any future contracts. The only logical approach local companies can take is to negotiate their way to reduced discounts, though this would be entirely dependent on the negotiation powers held by these companies. This would mean that the discount requests from IOCs would be settled at different levels across the Nigerian oil and gas sector.

The current situation should provide further stimulus to the Nigerian government and be seen as an opportunity for industry reform. With considerably less oil revenues for the foreseeable future, the government has economic, as well as moral and political, reasons for ensuring that public revenues are not diverted into private, overseas bank accounts. Similarly the vast amount of oil that is lost through a failing infrastructure or looted from upstream and downstream needs to be better retained in order to improve revenue.

Indeed, the government's key priorities should be strengthening the local content requirements to safeguard the interests of local companies as well as investing further in building local capacity, to ensure that greater revenue generated from the oil and gas industry is retained within the country. This would stimulate investment in petroleum refineries and the petrochemical industry, thus reducing oil importation expenditures and boosting the country's economy. A neglected, yet fundamentally vital, question for the short to medium term future of oil and gas in Nigeria is whether the local content policy, and therefore the local companies, can meet and balance the aforementioned accountability and transparency issues, discount requests of the IOCs, as well as the impacts of the devalued currency as a result of the falling oil prices.

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Stakeholders in the oil and gas industry have called on the President to close all the loopholes in the local content policy and requested that competence is given priority among local companies that are to be protected by this policy. The recent decision made by Buhari's new government to exclude 15 local companies from lifting crude oil could be seen as an appropriate response to this plea, or a step too far that would hinder the progress of the local content agenda. Nevertheless, there is light at the end of the tunnel. Buhari's intention to restructure the Nigerian National Petroleum Commission might improve accountability and transparency in the industry.

However, the time and effort it would take to tackle the accountability and transparency issues would be a hindrance to the investors' need for expedited decision-making by the government.

In these challenging times to revive the Nigerian oil and gas industry and in the process the Nigerian economy, President Buhari has to ensure that the money lost in the price downturn is at least partly offset both by more monies and oil being retained by the government. Moreover with around 60% of the population living below the poverty line when the barrel price was high, the government must ensure that the remaining benefits of being one of the world's largest oil producers is spread more equally and effectively across more extensive supply chains, if this administration is to enhance its prospects of avoiding an ending similar to that of its predecessor.

This work was partly supported by the Petroleum Technology Development Fund (PTDF).

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Schlumberger's Quiet Moonshot Written by Doug Sheridan from Energy Point Research Schlumberger's bid for Cameron Int'l is big news in a flinching industry. The vision behind the deal is ambitious - even a bit brash. It's more than just the consolidation of two large oilfield suppliers. The technical aspects of the plan could unleash industry ripples for decades to come.

Cameron's long-time focus has been on the 'heavy iron' used in the oil patch.

Schlumberger hopes to expand on that role by creating fully integrated drilling and production systems around its various products. The idea amounts to an operating system that efficiently manages processes from downhole to delivery.

It's an alluring concept, one that cuts across much of the upstream landscape. To better understand its moving parts, we laid out some of the segments and suppliers likely to be affected.

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Chart 1: Oilfield Product and Service Customer Satisfaction Matrix - EnergyPoint Research On a combined basis, Schlumberger-Cameron will participate in more than twothirds of the 37 upstream segments listed in the chart. In theory, this positions the company to supply near-complete drilling and completion/production systems. By contrast, a Halliburton-Baker Hughes combination will have offerings in about half as many segments. The same goes for equipment giantNational Oilwell Varco.

Obstacles to successfully executing the strategy loom, however. For example, many drilling contractors prefer to standardize equipment across their fleets. The practice helps lower costs and improve performance. While E&Ps might commit to a single supplier for downhole products and services for a given well, expecting drillers to do the same for rig components could prove a stretch.

So far, Schlumberger has been hush about the specifics of the new platform. The company may not have all the answers yet. One glaring question is whether it will take an Android or iOS approach; that is, create an adaptable system for use by equipment and services from varied suppliers or clinch tightly to a proprietary model that syncs exclusively with Schlumberger-Cameron products.

There's also the issue of preference. While Schlumberger enjoys large market share in many segments, EnergyPoint's data suggest it's often not the customer satisfaction leader. The same holds true for Cameron. For its grand strategy to work, many buyers will be asked to abandon more favored vendors for a hypothetical greater good. It's not clear they will.

Winning over customers will depend a lot on whether Schlumberger can get the software right. It won't be easy. The processes involved are varied and complex. If key oilfield products and services — including those of competitors — don't integrate seamlessly, the system could hurt performance instead of improving it.

A little over a decade ago, the company was well positioned to tackle such an ambitious task. At the time, its SchlumbergerSEMA unit was knee-deep in the digital and communications space, with over 20,000 employees. Schlumberger management was fluent in everything from smart-cards to wireless metering technologies.

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Schlumberger divested of SEMA in 2004 after the tech bubble burst. That leaves a company predominately focused on oilfield products and services to develop and maintain sophisticated software that could consist of millions of lines of code and take dozens of man-years to complete. From a distance, it seems like a less-thanperfect match.

Opening up the system's architecture could help. Not only would it reduce the number of problems arising from disparate technical formats, users would be better able to assist in troubleshooting and maintaining the underlying software — making it more secure and stable. Open licensing would also reduce clients' fears of being held hostage to a single vendor.

Yet, signs are Schlumberger will take a more proprietary approach. The lure of controlling the details around — and reaping the majority of profits from — such the platform is simply too great. After all, leading-edge technology sells awfully well, both in the oil patch and on Wall Street. And captive customers mean greater pricing power and higher margins. As a result, expect more iOS and less Android.

Competitors won't idly stand by, however. Service suppliers like Halliburton and Weatherford will likely work with equipment manufacturers like NOV, GE Oil & Gas and Aker Solutions to offer alternatives. And systems specialists can be expected to come forward with their own, most likely open, software and operating solutions. If so, Schlumberger could find itself odd man out.

Schlumberger's greatest challenge, however, might be overcoming customer skepticism. For years, integrated suppliers have argued that more is better.

That bundling works best. That integration unlocks value. Yet customers seem unconvinced, especially as performance has all-too-often been dictated by the weak links in the chain.

To the extent Schlumberger can eliminate the weak links, it has a chance to achieve something special. To the extent it can't, the strategy could end up as an emptyhanded foray into a space better served by Silicon Valley.

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