OilVoice Magazine - Edition 55 - October 2016

Edition Fifty Five— October 2016

One Hundred Years of Natural Gas? Not At These Prices Victoria bans fracking, but leaves questions over gas supply Energy in a world of uncertainty

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One Hundred Years of Natural Gas? Not At These Prices Written by Art Berman from The Petroleum Truth Report

One hundred years of natural gas? Not at these prices.

U.S. gas production is declining and shale gas output is down almost 2.5 Bcf per day. Production is decreasing while consumption and exports are both increasing.

EIA data indicates a supply deficit by the end of 2016.

Henry Hub spot prices have doubled since early March. Will companies show discipline to preserve higher prices?

Not a chance. They will drill more wells if investors continue to provide capital. This, however, will probably be too little too late to stop the decline in gas production that is already underway.

Real Gas Prices Have Never Been Lower In February 2016, I wrote that an increase in natural gas prices was inevitable and in April, I wrote that prices would double. Now, spot prices have doubled from $1.49 on March 4 to $2.97 per mmBtu on August 29 (Figure 1).

Still, real natural gas prices (in July 2016 dollars) have never been lower. Average prices so far this year are just $2.20 per mmBtu. That's the lowest annual price in since 2000 and it is lower than any monthly price except April 2012.

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Figure 1. Real natural gas prices have never been lower than in 2016. Henry Hub natural gas prices are in CPI-Adjusted July 2016 dollars. Source: EIA, U.S. Bureau of Labor Statistics and Labyrinth Consulting Services.

Prices have increased because total dry gas production has declined 1.6 Bcf per day (Bcfd) from its peak of 75.29 Bcfd in February. Shale gas production has declined 2.4 Bcfd from its peak of 44.17 Bcfd (Figure 2).

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Figure 2. Total natural gas and shale gas production have declined since February 2016. Source: EIA August 2016 STEO, EIA Natural Gas Weekly Update and Labyrinth Consulting Services, Inc.

Figure 3. Shale gas production has declined 2.4 billion cubic feet per day since February 2016. Source: EIA Natural Gas Weekly Update and Labyrinth Consulting Services, inc.

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All shale gas plays have declined including the Marcellus which is down -0.64 Bcfd (Table 1). Even the relatively new Utica play has declined -0.12 Bcfd. The legacy plays have declined the most: Haynesville, -3.77 Bcfd; Barnett, -1.91 Bcfd; and Fayetteville, -0.92 Bcfd. No new horizontal wells have been drilled in either the Barnett or Fayetteville since early 2016.

Table 1. Shale gas play declines from maximum production. Source: EIA Natural Gas Weekly Update and Labyrinth Consulting Services, Inc. Shale gas plays were supposed to provide 100 years of supply but there never was 100 years of gas.

It was a story told to promote the erroneous idea that the U.S. had so much gas that it could afford to squander and export this valuable natural resource. It is true that some of the production decline from shale gas plays is because the plays are not commercial at current prices.

But whose fault is that? Conscious over-production reduced the price below the marginal cost so promoting increased consumption and export became the only ways to increase price.

The U.S. government has been a great ally of the shale gas companies. The SEC changed reserve reporting rules in 2010 making it easier for companies to book reserves and borrow against them. EPA air pollution regulations since 2011 have led to the closing of dozens of coal-fired power plantsin favor of increased dependency on natural gas for electric power thus increasing demand. The U.S. Department of Energy has granted almost blanket approval to applications for LNG (liquefied natural gas) and pipeline export in recent years also increasing demand. And in 2011, the U.S. Department of State under Hillary Clinton created the Bureau of Energy Resources, a 63-person group to promote shale gas export and the spread of fracking technology around the world.

Meanwhile, E&P companies destroyed billions of dollars in shareholder value. They did this by knowingly producing gas into a non-commercial market and then, diluting shareholders by issuing more stock to fund more drilling and production.

Comparative Inventories Tell The Story Natural gas storage is at near-record levels for this time of year. This surplus distracts from the likelihood of a supply deficit by the end of 2016 suggested by EIA STEO data (Figure 4).

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Figure 4. Natural gas supply should go into deficit by January 2017. Source: EIA September 2016 STEO and Labyrinth Consulting Services, Inc. Periods of production growth led to lower prices and lower gas-directed rig counts.

Flat production led to supply deficits that resulted in higher prices and more drilling.

During the last deficit in 2013 and 2014, spot prices averaged $4.06 per mmBtu. The ensuing low prices have resulted in less drilling and flat production.

It is, therefore, reasonable that the increase in gas prices since March 2016 will result in more supply but how high might gas prices go before that happens?

Comparative inventories are the best indicators of price trends. Comparative inventory is the difference between current storage volumes and the 5-year average of storage levels for the same week. Figure 5 shows that there is an excellent negative correlation between comparative inventory and spot gas prices.

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Figure 5. Comparative inventories are the best indicators of price trends. Source: EIA and Labyrinth Consulting Services, Inc. That is because the U.S. gas market is a disequilibrium system in which production and consumption are never in balance. During the months of winter heating, consumption greatly exceeds production. Withdrawals from storage provide the portion of supply that remains unmet by production. Once winter is over, production exceeds consumption. Additions to storage restore that portion of supply needed for the next winter heating season.

Gas traders compare the current year's evolving inventory level with that of previous years to determine if storage will be adequate to meet winter demand. If the rate of inventory buildup is judged to be ahead of expected winter demand, the price of futures contracts decreases. If that rate is deemed questionable to meet winter demand, the price of those contracts increases. Producer response to price signals is typically delayed until a price trend emerges to justify increased or decreased drilling. The potential for over-shoot and under-shoot is great.

Comparative inventory is, therefore, the best measure of the disequilibrium in the seasonal supply chain. It effectively removes the seasonal effects of energy use and plant maintenance that sometimes confuse the interpretation of absolute inventory levels.

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Figure 6 shows that the fall in comparative inventories since May 2016 has been significant compared to both the 5-year average and to 2015 inventory levels.

Figure 6. Comparative Inventories (CI) have fallen sharply since May 2016. Source: EIA and Labyrinth Consulting Services, Inc.

Despite falling comparative inventory, prices commonly decrease in the late summer based on probable inventory levels needed to meet winter consumption. Although that may be happening now, I believe that higher prices will prevail by the end of 2016.

A simplified cross-plot of comparative inventory and spot prices suggests a range of likely year-end prices between $3.00 to $3.75 with a most-likely case of of approximately $3.35 per mmBtu (Figure 7).

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Figure 7. Simplified 2014-present comparative inventory vs. spot price cross-plot suggests a $3.00 - $3.75 price range for year-end 2016. Source: EIA and Labyrinth Consulting Services, Inc. Shale Gas Company Performance Is Weak What will happen if gas prices increase to approximately $3.35 per mmBtu in the next several months? Operators with access to capital will probably add rigs and increase production. That is the correct response to market price signals in a market that believes company claims that they are making money at current gas prices.

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IEA-EIA Oil-Glut Bomb Written by Art Berman from The Petroleum Truth Report IEA and EIA dropped an oil-glut bomb this month. Their September monthly reports indicate that the world continues to have a glut of oil with little hope of a balanced market in the near future.

IEA's Oil Market Report focused on weakening demand growth for oil.Their quarterly data shows that year-over-year demand growth has decreased consistently from 2.3 mmb/day in the third quarter of 2015 to 1.4 mmb/day for the second quarter of 2016 (Figure 1). The forecast for the third quarter is only 1.2 mmb/day.

Figure 1. IEA world liquids demand growth is decreasing. Source: IEA OMR September 2016 and Labyrinth Consulting Services, Inc.

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IEA downgraded its forecast for 2016 to an average of 1.3 mmb/day annual demand growth and only 1.2 mmb/day for 2017.

EIA monthly data from the September STEO (Short Term Energy Outlook) shows that world oil-consumption growth has declined from more than 4% in late 2015 and early 2016 to 2.1% in August 2016 (Figure 2).

Figure 2. EIA Consumption Growth is Decreasing With Increasing Oil Prices. Source: EIA September 2016 STEO and Labyrinth Consulting Services, Inc.

EIA data indicates that maximum consumption growth as a percentage occurred when oil prices were falling into the low-$30 range and that it has weakened as prices increased into the mid- to upper-$40 range. This suggests the global economy is too weak to support oil prices in the current range.

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The world production surplus increased in August because production increased and consumption decreased. The over-supply rose to +0.97 million barrels of liquids per day from near-market balance (+0.12 million barrels per day) in June (Figure 3).

Figure 3. EIA World Liquids Production Surplus: +0.97 Million Barrels Per Day. Source: EIA September STEO and Labyrinth Consulting Services, Inc. READ MORE ON FORBES

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Victoria bans fracking, but leaves questions over gas supply Written by Samantha Hepburn from The Conversation The Victorian government has announced it will permanently ban unconventional gas, often produced through the controversial process of hydraulic fracturing or 'fracking'. Legislation to implement the ban will be introduced this year.

This ban follows a 2015 report on unconventional gas. Following extensive review, committee members were split over whether to implement a full ban or extend the moratorium on onshore gas development by five years.

The ban announced by the government won't apply to offshore gas. The government will also legislate to extend a moratorium on onshore conventional gas until 2020.

Any future decision to approve onshore conventional gas exploration and production will be subject to review by an expert panel.

So will the ban make a difference?

Where did the ban come from?

The moratorium has been in place since 2012. It applies to all types of onshore gas (tight, shale, coal seam and conventional gas) and to any approval for fracking, exploration drilling activities and the use of chemicals us in fracking.

Last year the Victorian government examined the ban and consulted farmers and other landholders, environment and community groups, the gas industry, gas market analysts, hydrogeologists, manufacturers, tourism operators, local governments and the general public.

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The final report was the product of more than 1,600 submissions over a six-month period, as well as the findings of the Victorian Auditor-General Report on Unconventional Gas.

The rationale for the ban comes from two core factors. The first is the significant degree of community concern about the social and environmental impacts of onshore unconventional gas, particularly those associated with hydraulic fracturing.

Secondly, the future economic benefits connected with unconventional gas development did not appear, from the findings of the reports, to outweigh those risks.

Indeed, the final report found that it was unlikely that strong unconventional gas reserves were present in large commercial and extractable qualities in Victoria's brown coal fields.

On the other hand, any development would be highly likely to have a dramatic effect on the region's agriculture and tourism sectors.

Can fracking be permanently banned?

The existing regulatory framework does not recognise any ban on onshore unconventional gas. Indeed, the provisions in the Mineral Resources Sustainable Development Act explicitly include exploration and mining licences for coal seam gas projects.

However, these regulatory frameworks are being completely overhauled. It is clear that the new provisions will introduce a permanent prohibition on unconventional exploration and development in Victoria. The scope and nature of the ban will depend upon the wording of these provisions.

Any law that is introduced cannot be overridden at the national level because the ownership and management of all onshore minerals and hydrocarbons, including gas, are vested in the state.

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Pros and cons

The ban will end the strong environmental concerns that continue to exist around unconventional gas production. It will also alleviate some of the emerging conflicts over land allocation and water usage that have emerged between regional food, tourism and energy sectors.

The ban will also ease climate concerns connected with the generation of energy from fossil fuels. In Australia, fugitive emissions from coal mining, oil and gas production account for approximately 8% of Australia's greenhouse gas emissions.

Gas extraction, whether conventional or unconventional, can result in significant methane seepage. To date, very few baseline studies are available to compare seepage from drilling and fracking with natural methane seepage.

The ban is likely, however, to have a negative impact on supply, which may affect domestic gas pricing. This is particularly the case if the moratorium on onshore conventional gas production continues and no policy is implemented requiring gas producers to reserve a percentage of produced gas for domestic usage.

The 2015 Gas Market Report, released in March this year, showed that the nexus between international gas prices and east coast LNG production for export, domestic demand and domestic gas prices has become increasingly complex.

Theoretically, eastern Australia has enough reserves to supply the domestic and export markets for the next 20 years. But if the market is divided into the north (Queensland and Cooper Basin) and the south (Victoria and New South Wales) there is unlikely to be enough reserves in the south to meet forecast demand, particularly following the ban.

This will inevitably require the development of more gas reserves in other areas of the south, or imports from the north. If international gas prices and demand support more east coast LNG production, things will get worse as this supply will not be available in the north.

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Victoria will, however, continue to utilise gas exploration and production in offshore gas wells in Bass Strait. There are 23 offshore platforms in the strait and ExxonMobil has held these titles for many years.

The offshore gas wells have traditionally supplied most of Victoria's domestic gas market. Consequently, if the ban did apply to offshore gas exploration and production, it would have a profound effect on domestic gas supply.

Such a ban is, however, unlikely. First, it could not apply to offshore wells located beyond the territorial sea because these come under Commonwealth jurisdiction.

Second, a ban could not be applied retrospectively. Hence it would not affect established offshore title holders who have been supplying the domestic gas market for many years.

Samantha Hepburn - Director of the Centre for Energy and Natural Resources Law, Deakin Law School, Deakin University

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Despite claims to the contrary, science says fracking not causing increased earthquakes Written by Marita Noon from Energy Makes America Great

People in seven states, from South Dakota to Texas, were awakened Saturday morning, September 3, by Oklahoma's most powerful earthquake in recorded history.

The 5.8 tremor was centered near Pawnee, OK. Several buildings sustained minor damage and there were no serious injuries.

That we know.

What we don't know is what caused the quake—but that didn't stop the alarmist headlines from quickly blaming it on 'fracking.'

Green Party candidate Dr. Jill Stein promptly tweeted: 'Fracking causes polluted drinking water + earthquakes. The #GreenNewDeal comes with none of these side effects, Oklahoma. #BanFracking'

A headline in Forbes stated: 'Thanks to fracking, earthquake hazards in parts of Oklahoma now comparable to California.'

The Dallas Morning News proclaimed: 'Oklahoma shuts down fracking water wells after quake rattles Dallas to Dakotas.'

NaturalNews.com questions: 'Was Oklahoma's recent record breaking earthquake caused by fracking?'

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A report from ABC claims: 'The increase of high-magnitude earthquakes in the region has been tied to the surge in oil and gas operators' use of hydraulic fracturi ng, or fracking...'

Citing a March 2016 report from the U.S. Geological Survey (USGS) on 'induced earthquakes,' CNN says: 'The report found that oil and gas drilling activity, particularly practices like hydraulic fracturing or fracking, is at issue. Saturday's earthquake spurred state regulators in Oklahoma to order 37 disposal wells, which are used by frackers, to shut down over a 725-square mile area.'

Despite these dramatic accusations, the science doesn't support them. The USGS website clearly states: 'Fracking is NOT causing most of the induced earthquakes.'

An importantstudyfrom Stanford School of Earth, Energy & Environmental Sciences on the Oklahoma earthquakes, which I wrote about last year, makes clear that they are 'unrelated to hydraulic fracturing.'

While the exact cause of the September 3 quake is still undetermined, geologists close to the research do not believe it is fracking related. (Realize 5.5 El Reno earthquake, centered near the western edge of Oklahoma City, in 1952 was from natural causes.) At a September 8 meeting on Seismicity in Oklahoma, according to Rex Buchanan, Interim director of the Kansas Geological Survey: 'There was relatively little conversation about fracking and far more conversation about wastewater.'

William Ellsworth, Professor (Research) of Geophysics at Stanford University, told me that while no specific information about this direct case is available: 'I don't have any information that would allow me to rule out fracking. However, it is extremely unlikely. Fracking occurs for a few days at most, if at all, when the well is being finished. Wastewater injection goes on continuously for years and years.'

The error in the reporting occurs, I believe, because people don't generally understand the difference between drilling and hydraulic fracturing, and produced water and flowback water, and, therefore, merge them all into one package.

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Yes, it does appear that the increase in induced, or human-caused, earthquakes may be the result of oil-and-gas development, yet totally banning fracking, as Stein and Hillary Clinton support, would not diminish the tremors.

First, not every oil or gas well is drilled using hydraulic fracturing. As Ellsworth mentioned, fracking is a part of the process used on some wells. However, much of the drilling done in the part of Oklahoma where the seismic activity first occurred is conventional and doesn't involve fracking—which provided a premise for the Stanford researchers' study.

When a well uses the hydraulic fracturing enhanced recovery technology, millions of gallons of water, plus sand and chemicals, are pumped into the well at high pressure to crack the rock and release the resource. When the oil or gas comes up from deep underground, the liquids injected come back to the surface too. This is called flowback water. That water is separated from the oil and/or gas and may be reused, recycled (as I wrote about in December), or disposed of in deep wells known as injection wells—which are believed to be the source of the induced seismic activity.

'Ha!' you may think, 'See, it is connected to fracking.' This brings the discussion to produced water—which is different from flowback water.

This type of wastewater is produced at nearly every oil and gas extraction well— whether or not it is fracked. The water, oil, and gas are all 'remnants of ancient seas that heat, pressure and time transformed,' explains Scott Tinker, Texas' state geologist and director of the University of Texas at Austin's Bureau of Economic Geology. He continues: 'Although the water is natural, it can be several orders of magnitude more saline than seawater and is often laced with naturally occurring radioactive material. It is toxic to plants and animals, so operators bury it deep underground to protect drinking-water supplies closer to the surface.' In Oklahoma, the wastewater is often injected into the Arbuckle formation.

While the hydraulic fracturing process is typically only a few days, the produced water can be brought to the surface with the oil and/or gas for years. With the increased oil and gas extraction in the past several years—before the 2014 bust, the

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volumes of wastewater also soared. In parts of Oklahoma, ten barrels of wastewater are produced with every barrel of oil.Scientific American reports that some of those high-volume injection wells 'absorbed more than 300,000 barrels of water per month.'

The authors of the Stanford study were 'able to review data about the amount of wastewater injected at the wells as well as the total amount of hydraulic fracturing happening in each study area, they were able to conclude that the bulk of the injected water was produced water generated using conventional oil extraction techniques, not during hydraulic fracturing,'writes Ker Than for Stanford. Professor Mark Zoback, lead author of the study states: 'We know that some of the produced water came from wells that were hydraulically fractured, but in the three areas of most seismicity, over 95 percent of the wastewater disposal is produced water, not hydraulic flowback water.' Ellsworth agrees. Last year, he told the Associated Press: 'The controversial method of hydraulic fracturing or fracking, even though that may be used in the drilling, is not physically causing the shakes.'

So, if banning fracking won't stop the shaking, what will? The geologists contacted for this coverage agree that more work is needed. While the quakes seem to be connected to the wastewater injection wells, there are thousands of such wells where no discernable seismic activity has occurred. Oklahoma has been putting new restrictions on some of its thousands of disposal wells for more than a year to curb seismic activity and that, combined with reduced drilling activity due to low prices, has reduced the rate of the tremors. In Texas, when the volumes of wastewater being injected into the vicinity of that state's earthquakes were reduced, the earthquakes died down as well. Other mitigation strategies are being explored.

Jeremy Boak, director, Oklahoma Geological Survey, told me: 'The Oklahoma Geological Survey is on record as concluding that the rise from 1-2 M3.0+ earthquakes per year to 579 (2014), 907 (2015) and the current 482 (to date in 2016) are largely driven by increased fluid pressure in faults in the basement driven largely by injection of water co-produced with oil and gas and disposed of in the Arbuckle Group, which sits on top of basement. Both the increase and the current decreasing rate appear to be in response to changes in the rate of injection. There are natural

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earthquakes in Oklahoma, but the current numbers dwarf the inferred background rate.'

Interestingly, most of the aforementioned reports that link fracking and earthquakes, ultimately acknowledge that it is the wastewater disposal, not the actual hydraulic fracturing, that is associated with the increased seismic activity—but, they generally fail to separate the different types of wastewater and, therefore, make the dramatic claims about fracking.

Boak emphasized: 'There are places where there are documented cases of earthquakes on individual faults occurring very near and during hydraulic fracturing operations, including one published case in Oklahoma. These are generally small earthquakes, although some larger ones (M4.0+) have occurred in British Columbia.

Therefore, it is technically very important to maintain the distinction between injection-induced and hydraulic fracturing-induced earthquakes, or we may take the wrong action to solve the problem. Should the OGS and Oklahoma Corporation Commission (OCC) staff find further Oklahoma examples of such earthquakes, the OCC will take action. The current issue of injection-induced seismicity must take precedence.'

When you hear supposedly solid sources blaming hydraulic fracturing for earthquakes, remember the facts don't support the accusations. Fracking isn't causing Oklahoma's increased earthquakes.

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Energy in a world of uncertainty Written by Mike Schwartz from Eka

Political, environmental, international, and economic: the fast-moving macro factors that affect the oil and gas industry have created more volatility - and more data points that must be analyzed to make sense of it all. As Michael Schwartz at EKA explains, it's not just political operatives that have to understand the polls.

The 2016 presidential election is entering its final weeks, and soon the stump speeches, Twitterstorms, debates and pseudo-scandals will all be in the rearview mirror.

But for international energy markets, uncertainty continues. The new president is going to have a major impact on the U.S.'s energy future - and with it the oil and gas industry. But that assumes they can work effectively with a newly elected, deeply partisan, and gridlocked Congress - which is by no means guaranteed.

Short-term vs long-term change

As it does every four years, the political melodrama emphasizes unpredictability and change. But once the hoopla is done and inauguration balls are over, other policy shifts and changes in America's economy - and the uncertainty they produce - come back into focus.

So while pundits and pollsters have been polishing their mathematical models and pronouncing on the latest from the horse race, professional future-gazers in the oil and gas business have been looking at many more factors. One example is the Federal Reserve. The effect of any rise in interest rates could reverberate immediately throughout the dollar-dominated industry.

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On the domestic front, oil and gas producers also need to understand the emerging competitive landscape as the energy mix changes. As Hillary Clinton infamously made clear in West Virginia, America's coal industry is facing a different future. With less fanfare, renewable energy has been establishing a strong but disruptive foothold in the U.S. To counter this, new technologies have boosted oil and gas operators by making LNG and unconventional oil and gas economically viable.

Uncertainty on all sides

On the international front, the agenda of whomever takes over the oval office is likely to be dominated by the geopolitics of the Middle East, Russia and China - whose economic slowdown has already had an impact on energy and commodity prices.

Saudi Arabia's recently appointed oil minister, Khalid Al-Falih has made it clear that the Kingdom's oil glut is over, while expressing his firm conviction that the oil market will grow in absolute terms in the next two decades. But that still leaves new tensions between Sunni Saudi and Shiite Iran. How these tensions play out, and how Saudi Arabia responds to Iranian oil coming back into world markets, is still a matter of educated speculation.

Further north, Russia's oil and gas industry has certainly taken a hit from low oil prices. But its vast gas supplies and willingness to deploy them for strategic advantage in Europe are another area of uncertainty. Meanwhile, Venezuela, with its large oil reserves, continues to experience a rolling series of political, economic and humanitarian crises.

Perhaps the biggest unknown of all, however, is climate change and the impact of attempts to mitigate it. Resolutions made at the 2015 United Nations Climate Change Conference (COP 21) in Paris have brought international agreement on tackling climate change closer than ever before. And now that both the U.S. and China have signed up, the likelihood of it having an impact on the oil and gas industry seem greatly increased. But the non-binding commitments and lack of enforcement mechanisms mean that long-term success is by no means guaranteed.

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Volatility at top speed

Uncertainty is something that oil buyers, sellers, and heavy consumers have learned to live with. This has always been a volatile and fluctuating market. And the costs of being on the wrong side of a position can be both devastating and wide reaching.

But the pace of change is accelerating dramatically. The volume of data produced by and about any given event has increased exponentially, as has the velocity at which it is disseminated. The time between an event taking place and its impact being felt is vanishingly small.

Oil and gas businesses need to be on top of these macro factors, while also assessing and understanding information coming in from global supply chains, logistics and transport operations, global currency fluctuations, and the micro-data transmitted from newly connected equipment and sensors. According to the 2016 Upstream Oil and Gas Digital Technology Trends Survey, sponsored by Accenture and Microsoft, 'Digital investment today is focused on mobility and the Internet of Things (IoT) - with analytics and IoT predicted to lead the way over the next 3-5 years.' That's alongside the constant assessment of risks associated with markets and prices, credit and counterparties, and international regulation.

All of this has become too much for non-specialist tools to handle. To manage in today's environment, an industry-specific analytics solution, like Eka's Commodity Analytics Cloud, that has commodity-specific algorithms, and which that can merge data from multiple systems and analyze huge amounts of information while instantaneously turning into actionable insights is necessary.

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Data, visibility and technology

Anyone in this market needs an accurate picture of the world's economic, political and demographic shifts. It is essential to know the potential meaning of the U.S. president being refused a red carpet in China, or personally insulted by his counterpart in the Philippines. They need a view on Brexit, political tensions in West Africa - and the impact of weather or piracy on traditional shipping routes.

They also need to make sense of that picture. Above all they need to make timely, informed, evidence-based decisions. Advanced data management and analytical capability, such as that provided by Eka's next-generation ETRM software, are the tools around which any oil and gas trading or buying strategy must be built. Without them, firms will be stuck in the slow lane: and by the time they react to the latest economic or political data, the new president will be running for a second term.

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More Montney assets hit market in wake of Seven Generations' Cdn$1.9bn deal Written by Eoin Coyne from CanOils Two Canadian producers are seeking to capitalize on the enduring pulling power of the Montney play by putting assets up for sale, according to CanOils' newest report focused on M&A activity in August.

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RMP Energy Inc. (TSX:RMP) and Chinook Energy Inc. (TSX:CKE) have healthy balance sheets and a good inventory of development assets. Both have extensive holdings in the Montney shale. They form the bedrock of the total 12,700 boe/d of publicly disclosed Canadian assets put up for sale in August 2016. The listings follow the recent Cdn$1.9 billion acquisition by Seven Generations Energy Ltd.'s (TSX:VII) of predominantly Montney assets from Paramount Resources Ltd (TSX:POU), which showed Montney assets can still attract strong interest for high value deals.

RMP Energy Inc.

The largest Canadian asset listing in August involved RMP Energy initiating a strategic alternatives process, retaining Scotia Waterous and FirstEnergy Capital Corp. The majority of RMP's production is derived from the Ante Creek and Waskahigan fields. RMP produces 8,425 boe/d (43% liquids) based on Q2 2016 production figures. The company owns 24.6 million boe of 1P reserves (36% liquids).

Active RMP Energy Inc. wells as of July 31, 2016

Source: CanOils Monthly M&A Review, August 2016

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Chinook Energy Inc.

Chinook Energy Inc. has also initiated a strategic alternatives review and has retained Peters & Co. as its exclusive financial advisor. Chinook is predominantly Montney-focused with 2,890 boe/d of production during Q2 2016 and 12.9 million boe (16% liquids) of 1P reserves. Chinook said it is open to expanding its core operations via acquisitions or by establishing a new core of operations. They will also entertain a merger, sale or JV with a well-capitalized entity to help develop existing assets.

Also this month...

Away from the Montney, August saw Virginia Hills Oil Corp. (TSX-V:VHO) initiate its own strategic review process, while Grant Thornton, in its role as receiver for RedWater Energy Corp., retained CB Securities to advise in the sale of a portion of RedWater's assets.

Full details on all of these assets up for sale, as well as a detailed look into all of August's biggest M&A stories, can be found in CanOils' latest monthly M&A review.

View more quality content from CanOils

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The US And China: Saudi Arabia's Big Picture Oil Strategy Written by John Richardson from ICIS

THE above chart should tell you a great deal of what you need to know about Saudi Aramco's interest in buying the LyondellBasell Industries (LBI) refinery that's located in the Houston Ship Canal in the US: 

Between January 2007 and October of this year, the Eagle Ford shale-oil field in Texas will have seen the efficiency of oil output from reach of its rigs increase by 2,700%



The Bakken field in North Dakota is meanwhile set to see its oil output per rig jump by 730%.



The Permian basin, which is again in Texas, will see a 710% improvement with the Permian Basin offering a lot of potential for further innovation.

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These efficiency improvements have of course dramatically reduced production costs. For example, US shale oil company Pioneer Natural Resources reduced its Q2 2016 production costs to just $2.25/bbl - $12.25/bbl.

And any sensible analysis of the macroeconomic trends will tell you that this innovation will go on and on and on, as the US shale oil industry is a vital for source of growth for the US economy.

Aramco - and with it of course the Saudi Arabian government that owns Aramco has been very well aware of all these dynamics for several years now. So it just doesn't add up to suggest that the Saudi market share strategy in oil markets has ever been about driving the US shale oil industry out of business, as the Kingdom has long understood that this is impossible.

Winning the New Volume Game

The strategy is instead a recognition that we are in a world where oil will remain very, very cheap compared with its recent history. If we can get rid of our tendency to anchor our analysis in to only studying recent price history, we will get closer to good oil-price forecasting. Why not $26/bbl as a future long term average price?

The LBI purchase would help Aramco secure volumes in these three ways: 1. The US is now importing only 1.3m bbl/day of Saudi crude compared with $1.8bn in 2003, and securing this refinery will help to partially reverse this trend.

2. The LBI refinery is capable of processing heavy, sour crude. Aramco is unable to sell its heavy sour crude to many refineries in Europe and Asia because they are only configured to handle light, sweet grades of oil.

3. Aramco would increase its Gulf Coast refining capacity by 50%, and in so doing of course gain a bigger share in local gasoline, diesel and kerosene etc. markets.

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The LBI deal would also help Aramco execute Saudi Arabia's Vision 2030. Vision 2030, which was announced in April, involves adding more value downstream of oil through additional investments in both refining and petrochemicals.

Politics, though might get in the way of Aramco acquiring LBI's Houston refinery.

Vision 2030 and One Belt, One Road

But Aramco is of course not just focusing on the US as it tries to fulfil these national strategic objectives. It has already invested in refinery capacity in Europe, Indonesia and Japan - and it operates a joint venture refining and petrochemicals complex in Fujian province in China.

China is particularly important for Saudi Arabia because China's oil demand is expected to grow from 6m/bbl today to 13m bbl/day by 2035.

And from the perspective of China it needs Saudi crude because, unlike the US, there is no realistic prospect of it becoming energy independent.

There is another important mutual interest: Saudi Arabia's Vision 2030 strategy and China's One Belt, One Road initiative are both centred on creating new job opportunities.

Whilst pointing out that tactically these two programmes are different, in an article on its website Aramco writes that 'they are similar in that they both put forward transformative yet achievable initiatives that capitalise on areas of national strength for the benefit of their populations'.

Aramco adds that 160 Chinese companies are already working in Saudi Arabia, including Sinopec at the Aramco/Sinopec joint venture Yasreef refinery in Yanbu.

'Vision 2030, coupled with the One Belt, One Road initiative, presents new opportunities for China and Saudi Arabia to go beyond the current level of collaboration and partnership and contribute even more to the development of the two countries,' says Aramco.

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As for further Saudi investments in China, in January Aramco disclosed that it was in discussion with CNPC and Sinopec to build refineries in China.

And at the end of August, Aramco chairman Khalid al-Falih said that talks with CNPC for a refinery in Yunnan province were at an advanced stage, and that 'we hope to reach an agreement this year'.

All of this is a further reminder that in the New Normal world, any good analyst needs to spend most of her or his time focusing on the political and social issues.

Saudi Aramco In A Low Oil Price World Written by John Richardson from ICIS

NEWS of plans to list 5% of Saudi Aramco is obviously some four months old. There is thus a danger that in the welter of other later events, the long term significance of this decision ends up being overlooked. That would be a bad mistake in your scenario planning.

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Funding from the IPO could be used for more refining and petrochemicals projects over the next few years, with the recent announcement of a Aramco/SABIC project perhaps fitting into this category.

The evolving Aramco story also serves asn important reminder that we are in a world where social and political, as well as economic, factors will increasingly shape the oil and petrochemicals businesses.

Building more refineries and petrochemicals plants, and then going even further downstream into manufacturing finished goods, is partly about job creation. The Saudi median age is just 26.4 compared with 37.6 in the United States and no less than 40.4 in the UK.

Industrial diversification also seems to reflect the new oil-market realities. As I quoted as the FT as saying as saying back in April:

Any move to proceed with a sell-off could indicate that Saudi Arabia is preparing for a period of low crude oil prices that could last for years, requiring new sources of income and investment.

In July there was the important announcement that Aramco and SABIC are working on a $30bn oil-to-petrochemicals project, which would be located at Yanbu on the kingdom's west coast. A joint feasibility study is underway with start-up scheduled for 2020.

If this project happens then funding may come from the Aramco IPO. The investment would also dovetail with Saudi's wider Vision 2030 agenda, which centres on adding more value to hydrocarbon reserves.

Analysts with a too-narrow view of the world will look at this project and conclude that it makes no real cost-per-tonne of production sense to crack naphtha in Saudi Arabia. They will say that it would instead make more sense to continue to put the country's surplus naphtha on a ship and send it to Asia to crack, as you would then be nearer the big petrochemicals end-users.

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But you need to ignore this very narrow logic by again recognising that we are in a low oil-price world. Adding local value to naphtha could in the future therefore make more sense than exporting the naphtha.

Crucially, also - as I said at the beginning - this is about generating jobs through industrial diversification: 

Ethane crackers only produce ethylene in commercial quantities, but in a liquids cracker you end up with propylene, C4s and aromatics. You can thus add more derivatives plants downstream of liquids cracking - and then a wider range of employment-generating factories downstream of propylene, C4s etc.

-e.g. a factory that makes auto components from polypropylene.



There is anyway a lack of new ethane supply in Saudi. This leaves a choice of either cracking naphtha or not building many more new petrochemicals plants in the kingdom. (As an aside, SABIC is in parallel pursuing an ethane cracker project in the US with ExxonMobil, where of course ethane is in abundant supply).



Bringing Aramco and SABIC together in this way is a clear win/win, if the project goes ahead. Aramco has the oil and refining strength and SABIC the petrochemicals expertise.

Aramco may also work with more foreign investors in petrochemicals. It already has its PetroRabigh joint venture with Sumitomo Chemical and the recently startedup Sadara joint venture with Dow Chemical

What might this man for global petrochemicals supply and demand balances? The chart at the beginning of this post is just one example to get the debate going - our global view on polypropylene in 2025. How might events in Saudi Arabia change this particular outlook?

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The Aramco story is also of much more immediate relevance. It will help you put into the right context all the noise around the informal OPEC meeting in Algeria on 26-28 September.Contradictory reports, almost every day, say an agreement by OPEC to freeze production is either more or less likely.

You need to note that: 

Saudi Arabia knows that even if it freezes or cuts production this will make no long term difference to the prices because of a.) Increasing US shale-oil efficiency and B.) We have gone beyond, or a close to going beyond, peak demand growth for oil.



It thus makes more sense for Saudi to pump as much oil as it can whilst it can rather than run the risk of leaving its most valuable national asset in the ground for good. Other producers are likely to come around to the same thinking, that's if they haven't already arrived at this place.

Even if somehow there is deal in Algeria to freeze output for short term reasons, I wouldn't as a sign of a change in Saudi strategy. And what are the real chances of a widespread, sustainable accord to freeze production? Very slim, I would argue.

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BP in the Bight: why the planned oil spill response is too slow to protect the coast Written by Andrew Hopkins from The Conversation

Australia's offshore petroleum industry regulator is set to rule next week whether to grant oil giant BP's application to drill in the Great Australian Bight.

But BP's environmental plan, released last week, suggests that the company's proposed plan for dealing with a blowout displays less urgency than would be expected in some other parts of the world.

If a blowout does occur, BP proposes to cap it with a piece of equipment known as a capping stack. These devices did not exist at the time of BP's Gulf of Mexico blowout in 2010, when a capping strategy had to be developed on the run, which is why it took 87 days to cap that well.

Since then, capping stacks have been designed, constructed and located strategically around the world. For its proposed operations in the Bight, BP would have access to a capping stack in Singapore. It would take up to 35 days to bring this stack to the Bight and cap the well.

The company has rejected the suggestion that a capping stack be located locally. It claims that the time needed to transport the device from Singapore to the Bight is not a critical issue. In its earlier environmental plan, released last October, BP said that capping a blowout would require significant preparatory work, by which time the Singapore capping stack would have arrived.

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Yet the idea of spending more than a month to plug a flowing well hardly seems compatible with avoiding major environmental damage. According to BP's own estimate, oil from a spill in the Bight could reach the shore in as little as nine days.

A recent exercise in the Gulf of Mexico shows that a blowout could be capped in 15 days, using a locally available capping stack. In this respect, BP's estimate of the time it would take to cap a blowout is a long way short of industry best practice.

Whether or not travel time from Singapore is the critical issue, it is worth noting that there are five different capping stacks available for use in the Gulf of Mexico and three for use in UK waters. The expectation is that these stacks could be on site within 24-48 hours.

Note also that new rules imposed by the US regulator for drilling in the Arctic require that a capping stack be located within 24 hours' travel time of the drill site. If the Arctic justifies this level of protection, why not the Bight?

Drilling a relief well

Should the capping strategy fail for any reason, BP has a backup plan for stopping the flow. This is to drill a relief well to intersect the blowout well below the sea floor and 'kill' it by pumping it full of heavy fluid or cement.

The question this raises is: where would BP find a spare drilling rig to carry out this operation? After the Montara blowout off Western Australia in 2009, a suitable drilling rig was located near Singapore. But this rig would have been no use in the deep water of the Bight.

Oil companies operating in Australian waters have a memorandum of understanding among themselves to provide a suitable drilling rig in an emergency. Yet it remains unclear how easy it would be for another company to release a rig quickly for this purpose. As such, BP has assumed that it will take up to 149 days to acquire an appropriate rig, drill a relief well and plug the blowout.

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The new Arctic regulations require that a relief rig be available nearby, to guarantee that a relief well can be drilled before winter sea ice moves in. The situation in the Bight is not as constrained by the seasons, but even so, 149 days seems an unacceptably long time to plug a well.

The Gulf of Mexico blowout was stopped in 87 days, during which time it inflicted damage worth at least A$40 billion. Who knows what the toll would have been if it had lasted almost twice as long?

Protecting the shore

Finally, BP has various strategies for reducing the amount of oil reaching the shoreline in the event of a spill. These include using dispersant chemicals, both subsea, at the point of release, and on the sea surface. The company puts particular emphasis on subsea dispersal, but recognises that this strategy would also be subject to delay.

It estimates that subsea dispersal would begin within 10 days 'where that is possible'. This can never be a fully effective way to prevent coastal pollution, because BP's modelling suggests oil would begin arriving on the coast in less time than this.

BP has also noted that traditional methods of containment and recovery of oil using booms and skimmers 'are not expected to provide significant benefit' in the open ocean.

What seems more likely in the event of a spill is that the company will find itself fighting a last-ditch battle against the oil as it approaches sensitive parts of the shoreline, and where this fails it will implement shoreline and oiled wildlife clean-up.

It is difficult to forecast any other scenario, given the time frames described in BP's own documents. Its published response plan gives no guarantee that an oil spill in the Bight would not reach the shoreline and damage the environment.

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Experience elsewhere in the world suggests that these timelines can be tightened.

The question for the regulator is whether BP has reduced the risk to a level that is 'as low as reasonably practicable'.

It is by no means obvious that the answer is yes.

Andrew Hopkins is the author of Disastrous Decisions: The Human and Organisational Causes of the Gulf of Mexico Blowout.

Andrew Hopkins - Emeritus Professor of Sociology, Australian National University

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