OilVoice Magazine | November 2014

Edition Thirty Two – November 2014

Oil decline: Price makes the story Why oil exports are not like ice cream World War III: It’s here and energy is largely behind it

1

OilVoice Magazine | NOVEMBER 2014

Adam Marmaras Chief Executive Officer Issue 32 – November 2014 OilVoice Acorn House 381 Midsummer Blvd Milton Keynes MK9 3HP Tel: +44 208 123 2237 Email: press@oilvoice.com Skype: oilvoicetalk Editor James Allen Email: james@oilvoice.com Director of Sales Mark Phillips Email: sales@oilvoice.com Chief Executive Officer Adam Marmaras Email: adam@oilvoice.com Social Network

Welcome to the 32nd edition of the OilVoice Magazine.

Our analytics show that roughly 20% of our users now access OilVoice from a mobile device, a figure that we expect to increase over time.

In response, we are rolling out a new design that functions on all devices, from desktops to iPads/tablets to mobile phones, so every user has access to OilVoice - wherever they are!

This month we have great articles from ART Oil & Gas and RMRI, and Oil & Gas Investments Bulletin. We'd also like to welcome back some of our regular authors, including Gail Tverbeg, David Bamford, Loren Steffy, David Summers, and Kurt Cobb.

Facebook

Adam Marmaras

Twitter

CEO OilVoice

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

2

OilVoice Magazine | NOVEMBER 2014

Contents

Featured Authors The biographies of this months featured authors Oil decline: Price makes the story

by Kurt Cobb Why it's different this time

by Keith Schaefer Why oil exports are not like ice cream

by Loren Steffy Oil & Gas M&A in upstream sector falls to $34.5 billion in Q3 2014

by Mark Young De-marginalising small oil fields

by Edward Marriott Should we be in the Arctic?

by David Bamford Tech Talk - Pessimistic Talk in a time of surplus

by David Summers Nanotechnology hits the oilpatch

by Keith Schaefer WSJ gets it wrong on 'Why Peak Oil Predictions Haven't Come True'

by Gail Tverberg World War III: It's here and energy is largely behind it

by Kurt Cobb Eight pieces of our oil price predicament

by Gail Tverberg

3 5 9 11 14 19 29 31 33 36 43 46

3

OilVoice Magazine | NOVEMBER 2014

Featured Authors Keith Schaefer Oil & Gas Investments Bulletin Keith Schaefer is the editor and publisher of the Oil & Gas Investments Bulletin.

Loren Steffy 30 Point Strategies A senior writer for 30 Point Strategies and a writer-at-large for Texas Monthly.

Loren worked in daily journalism for 26 years, most recently as an awardwinning business columnist for the Houston Chronicle, and before that, as a senior writer at Bloomberg News.

Edward Marriott ABT Oil & Gas and RMRI ABT Oil and Gas (ABTOG) is creating a new marginal field sector within the oil and gas upstream market: the economic development of small or stranded hydrocarbon accumulations.

RMRI is an independent, risk management consultancy delivering bespoke decision making support for over 20 years.

Mark Young Evaluate Energy Mark Young is an analyst at Evaluate Energy.

David Summers Bit Tooth Energy While one of the founders of The Oil Drum, back in 2005, he now also writes separately at Bit Tooth Energy.

4

OilVoice Magazine | NOVEMBER 2014

Kurt Cobb Resource Insights Kurt Cobb is an author, speaker, and columnist focusing on energy and the environment. He is a regular contributor to the Energy Voices section of The Christian Science Monitor and author of the peak-oil-themed novel Prelude.

Gail Tverberg Our Finite World Gail the Actuary’s real name is Gail Tverberg. She has an M. S. from the University of Illinois, Chicago in Mathematics, and is a Fellow of the Casualty Actuarial Society and a Member of the American Academy of Actuaries.

David Bamford Petromall David Bamford is a past head of exploration and head of geophysics at BP, and a founder shareholder of Finding Petroleum.

5

OilVoice Magazine | NOVEMBER 2014

Oil decline: Price makes the story Written by Kurt Cobb from Resource Insights

So oft in theologic wars, The disputants, I ween, Rail on in utter ignorance Of what each other mean, And prate about an Elephant Not one of them has seen!

--The Blind Men and The Elephant by John Godfrey Saxe When the world's business editors sent their reporters canvassing to find out what is behind the recent plunge in the world oil price, they were doing what they do almost every day for every type of market: stocks, bonds, currencies, commodities and real estate.

In financial journalism more often it's the price that makes the story rather than the story that makes the price. If a story is about something very surprising which almost no one can know in advance--a real scoop--say, an unexpected outcome in a major court case affecting a company's most profitable patent, then the story will move the price of the company's stock.

But much more often prices move, and then business editors send their reporters to find out why. Usually, a number of financial and industry professionals are asked: Why do you think prices went up/down? Then, the story is written and published.

However, on a daily basis, unless there is a big and obvious story like the one above, the only true answers are these: There were more buyers than sellers. (UP) There were more sellers than buyers. (DOWN)

6

OilVoice Magazine | NOVEMBER 2014

These answers, of course, aren't really news. They are more like axioms.

The answers for the recent swoon in the oil price include: 1. Oil is purchased in dollars and the dollar has been rising which puts 2.

3.

4.

5.

downward pressure on the oil price.

Demand is declining in Asia and Europe which is leaving excess oil on the market driving down the price.

Growing production from the United States is adding to world oil supplies and bringing the price down.

Libyan production has rebounded sharply following the country's recent period of unrest.

Saudi Arabia, the only OPEC producer with significant additional production capacity, is pumping more oil to punish other OPEC members with a low price, a move designed to restore discipline among members so that they will

abide by future oil production quotas.

6. Saudi Arabia is pumping more oil to bring the price down to aid the United States in its diplomatic objectives, pressuring Russia, the world largest oil producer.

7. Saudi Arabia isn't trying to help the United States; the kingdom is actually trying to hurt the United States and restore the exporter's dominance in the oil market by crushing the U.S. tight oil boom which requires high prices to be profitable.

8. No, Saudi Arabia is really trying to help the United States in its fight against ISIS by showing its support for the United States and Europe through lowering oil prices and by making the price that ISIS gets for the oil products it now controls lower. The lower price is also harder on Iran which requires high prices to sustain its government revenues.

9. Saudi Arabia is simply trying to defend its market share in the face of waning demand by continuing to pump oil at current levels and offering discounts to customers.

Of course, the above answers aren't necessarily mutually exclusive. People and countries can have multiple objectives served by the same action. And, some or all of the above assessments could be wrong or at least of very little explanatory value.

Now, I'll weigh in. It seems entirely likely that the Saudis are being opportunistic. Like many oil exporters, they need high oil export revenues to pay for their government expenditures, much of which consists of food and fuel subsidies and social programs designed to keep the public docile. In the face of what looks like declining demand, rather than cut production to maintain prices as they have done in the past, they've decided to maintain their market share worldwide by cutting prices. This has the

7

OilVoice Magazine | NOVEMBER 2014

benefit of making much American tight oil production uneconomic, thus discouraging new drilling.

The Saudis know something very important about the U.S. tight oil drillers. Most of them are independents who are loaded with debt and don't have the financial wherewithal to weather a period of sustained prices below their cost of production.

They will quickly reduce their drilling to only those prospects which seem as if they might be profitable at these new lower prices.

That will pave the way for sustained higher world prices later as growth in U.S. oil production comes to a halt. After the damage is done, the Saudis will try to bring the price back up.

It's always possible that the Saudi strategy will fail because what's really happening may be the first stages of a colossal economic and financial crash that will take the world economy into prolonged recession. That would bring the price of oil down to levels not seen in a decade where they might stay for a considerable period.

I'm not predicting that. And, in fact, none of what I've written may have any validity.

Even though the Saudis have publicly stated that they are defending their market share, they may not be telling us exactly what their aims are. Saudi acquiescence to lower oil prices may simply be having consequences the Saudis don't intend, but can't avoid.

In truth, the whole issue of oil prices is too complex and too lacking in transparency to be discussed intelligently when it comes to short-term price movements. I am reminded of the tale of the blind men and the elephant of which the last stanza of a poetic version is quoted above.

But, as I say, price makes the story.

View more quality content from Resource Insights

together

further

Lloyd's Register and Senergy have come together combining 250 years of wisdom, quality and integrity with dynamic, innovative, inquisitiveness.

LR Senergy work in collaboration with clients, blending skills and experience to offer new solutions from reservoir to refinery and beyond.

Find out more at www.lr-senergy.com

9

OilVoice Magazine | NOVEMBER 2014

Why it's different this time Written by Keith Schaefer from Oil & Gas Investments Bulletin Is this downturn in oil prices going to be different for investors? I think it might. In fact, I think North American energy companies have a good chance of withstanding this downfall in prices than any other downturn of the last 40 years.

You wouldn’t know it by looking at the recent carnage in oil stocks—especially the juniors and intermediates, which are off 30-50% in 6 weeks. This is severe, but is not without precedent. (In fact, once OPEC starts squabbling, history says oil prices drop 50% or more.)

But there is an argument that North American industry cash flows won’t be affected as much as the Market is now pricing in. Nor will multiples.

Could it be true—could it be different this time?

Normally, retreats in the oil price due to OPEC bickering is a very painful period– because in energy stocks, not only do fundamentals deteriorate, Price-to-Cash-Flow multiples contract—that’s a double whammy for investors.

To illustrate–my experience is that the average operating costs for North American oil is about $40/barrel. Now, that’s operating cost; not all-in (finding, developing and operating) cost. So at $100 oil, that’s a $60/barrel gross profit. When oil drops to $80/barrel, it’s a 20% drop in price but a 30% drop in gross profit.

The Market gives a higher multiple to more profitable companies. As the oil price has dropped in the last two months, this chart from Canadian brokerage firm BMO Nesbitt Burns shows how multiples have already contracted:

10

OilVoice Magazine | NOVEMBER 2014

But there really are a couple things different about the North American oilpatch now than at any other severe oil price downturn: 1. Everybody has LOTS of land and drilling inventory—literally years, and sometimes even decades of low-risk drilling.

This means a couple things. a) E&P budgets no longer have to spend 40% of cash flows on high priced land grabs, which they have been doing for 10 years now. So that’s a 25-40% increase in cash flows that can start happening if times get tough.

I wrote a story on this earlier this year, based on a report by US brokerage firm Raymond James, which you can read HERE. http://oilandgasinvestments.com/2014/oil-and-gas-financial/free-cash-flow-should-energize-your-oiland-gas-portfolio/ b) And it’s not just that producers have lots of land—their drilling inventory is expanding—for free, due to “downspacing”. Think of the space between wells in a big field. The industry is moving from four wells a square mile to eight—and in some cases 16 or even up to 32!

That’s because the industry is finding they can frack wells much closer together than ever before thought possible without impacting the flow rate of other nearby wells.

On an NPV basis, the wells you aren’t going to drill for 20 years become meaningless—and a potential source of cash for producers in a free market.

2. Improvements in drilling and fracking continue to improve returns. a) In fracking, there was a step change in the summer of 2013 as EOG and Whiting—two large independent producers in the US—started using smaller, more tightly spaced fracks. In essence, they used short wide fracks instead of long skinny fracks—and production increased dramatically. The entire industry is now moving in this direction. b) In drilling, a recent improvement is extra-long horizontal drilling—up to 2 miles— that are improving rates by 50-100% with only a 20% increase in costs. c) The industry is moving to big “pad” drill sites where multiple wells can be drilled from the same place, in a circular or fan formation out from the well. This is reducing drilling costs.

And the last point is—the Market always pays up for certainty/visibility of cash flows.

Economics are obviously important, but so is long term stable cash flow—no matter how big or small it is.

For the first time ever, the North American oil industry has a high certainty of how much oil they can produce for the next 20-30 years—just insert a specific oil price.

11

OilVoice Magazine | NOVEMBER 2014

Every other time that OPEC has squabbled and sent prices down, the US and Canada were chasing conventional oil pools with short reserve lifes—but not this time.

That’s not good for everybody, but it is for the low cost producers.

Look at the stock charts of Canadian natural gas producers Peyto Explorations (PEY-TSX) and Tourmaline (TOU-TSX)—production grew and so did the stock price, in a very low gas price environment. But the stock didn’t move up until the commodity price bottomed in April 2012.

The negative side of this argument however, is that the Saudis need to see oil under $60/barrel to really inflict pain on North American producers.

And until the oil price finds a bottom, none of these arguments are going to matter.

View more quality content from Oil & Gas Investments Bulletin

Why oil exports are not like ice cream Written by Loren Steffy from 30 Point Strategies Support for lifting the 40-year ban on crude oil exports is growing in Congress, but before we embrace the idea of selling U.S.-produced oil overseas, we need to understand what’s actually happening with the surging domestic production that hydraulic fracturing has unleashed.

U.S. production in 2013 reached its highest level since the late 1980s, and some producers believe that with so much oil now coming out of the ground, we should be selling it to the highest bidder — whether that’s refineries in the U.S. or elsewhere.

But we have to keep this boom in perspective. The U.S. produced just under 7.5 million barrels a day last year, according to the U.S. Energy Information Administration. At the same time, we also imported about 7.7 million barrels.

In other words, despite the increase in domestic production, we’re still importing

12

OilVoice Magazine | NOVEMBER 2014

about as much oil as we produce. That’s a huge change from five years ago, but it means we still need imports to meet our energy needs. That perspective gets lost when you see congressmen like Texas Republican Randy Weber invoking the slogan for Blue Bell Ice Cream in discussing crude exports. Weber told Reuters that his view is: “Let’s use all we can and sell the rest. I am a free market kind of guy. A rising tide raises all ships.”

He may be a free market guy, but he’s clearly not a numbers guy. To “use all we can and sell the rest” would mean we would have to double our already high domestic production. We would have to be producing oil at a far greater rate than this country has ever seen. Weber’s comments are the sort that encourage public misunderstanding of exactly what our increased oil production can and can’t do.

The discussion of ending the crude ban is being driven by producers, particularly in the Midwest, who aren’t able to get the highest price for their oil because there isn’t enough refining capacity to handle it. That isn’t because we have more oil than we need, it’s because after years of reliance on imports many U.S. refineries aren’t calibrated to handle the grade of crude being produced in regions such as the North Dakota’s Bakken Shale. Weber — whose district includes Port Arthur, Texas, home to Shell’s huge Motiva refinery — ought to understand this.

Crude oil is not like ice cream. Lifting the ban on exports may have its benefits. It may, for example, help shield world crude prices from the effects of geopolitical upheaval in the Middle East. But it will not replace our imports.

Congress should revisit the crude export ban, but it needs to understand the issue before it does. A far better explanation for lifting the ban comes from Weber’s fellow Texas Republican Michael McCaul, who told Reuters: “The decades old ban on crude oil exports is no longer justified given the current market conditions. Lifting the ban will also give America a new foreign policy tool to provide greater stability in the world oil market.”

In other words, exporting crude may give us more leverage in influencing prices in the global oil market, and that could be important given that the U.S. is still the world’s largest oil consumer, but make no mistake: every barrel we export is one more we’re going to have to import.

View more quality content from 30 Point Strategies

YOUR BASEMENT IS FULL OF DARK SECRETS.

Let’s turn on the light.

Look more closely at your basement with NEOS and discover what might be lurking below. Through multi-physics imaging, NEOS maps variations in basement topography, composition and faulting, any of which can affect field locations, EUR, or the level and BTU content of production. By illuminating your basement and seeing below the shale, you’ll better understand thermal regimes and pinpoint where to drill for optimal recovery and economics.

Some of the world’s leading geoscientists are making brighter decisions with NEOS. Be the next.

Above, Below and Beyond

neosgeo.com

14

OilVoice Magazine | NOVEMBER 2014

Oil & Gas M&A in upstream sector falls to $34.5 billion in Q3 2014 Written by Mark Young from Evaluate Energy Q3 2014 was a quieter period for global oil and gas M&A activity compared to the previous quarter, but 2014 is still on track to have a greater total M&A spend than 2013.

The total value of E&P deals worldwide in the quarter amounted to $34.5 billion, an approximate 30% drop on the total value of deals announced in Q2. North American activity grew for the 5th consecutive quarter but, curiously, deals outside of North America almost dried up completely; deals in North America made up almost 86% of the total deal value worldwide.

The rise in deals in North America could be attributable to various factors.

Unconventional oil resource plays are still the hottest properties on the market, with the Permian basin seeming to the current centre of highest demand. There are also

15

OilVoice Magazine | NOVEMBER 2014

many cases of companies with a diverse variety of assets trying to streamline their property holdings to give a more specific area of focus and as a result many North American assets have been made available for purchase. This stands in stark contrast to a few years ago where companies looked to hoard as much shale and unconventional acreage as possible across every play they could find. With the increasing gas prices and the approaching reality of North American gas exports, gas assets are also becoming more and more marketable. As for deal value drying upoutside of North America, it is very hard to pinpoint any specific factors that would drive down activity. The number of deals announced outside of North America has been reasonably consistent over the last few quarters, so this points to the lack of “big” deals being the main contributor of the low deal value. In Q3 2014, there were only 2 deals announced outside of North America with a value of more than US$500 million, one of those happening on the very last day. In Q1 and Q2 2014, there were 8 and 12 such deals respectively.

US Permian Basin – High Demand in Q3 2014 Whilst Q3 2014 seems to have been a quiet period for global E&P M&A activity, the US Permian basin has seen a hectic few months in contrast. Acquisitions in the Permian basin made up nearly half of the total E&P deal value in the US and just under a third of total E&P deal value worldwide at around US$11.2 billion. M&A activity in the Permian Basin has been on the rise since Q1 2014.

Encana Speeds Up Move to Oil Production with Biggest Deal of the Quarter In late September, Encana, Canada’s biggest gas producer, signed the largest deal of the quarter in agreeing to acquire Texas-based Athlon Energy Inc. for around US$5.93 billion in cash. Once the assumed debt of US$1.15 billion as well as Athlon’s cash position of around US$243 million is taken into consideration, the deal represents a total outlay by Encana of US$6.84 billion.

The deal marks Encana’s entry into the Permian basin, which seems to be the most sought after resource play in North America right now. It is typically oil rich from shale and other tight, unconventional formations. Encana’s acquisition of Athlon is a huge step for the company in quickly realising its goal to become a more oil weighted

16

OilVoice Magazine | NOVEMBER 2014

company. Of all the companies listed on the TSX, Encana is the biggest gas producer but only ranks as the 11thbiggest oil producer. Encana’s board has been seeking to rectify that in recent times, solely focusing efforts on its North American unconventional resource plays. The multi-billion dollar spin-off of PrairieSky Royalty Ltd., which closed in September, was part of this strategy and helped leave the Canadian company with ownership positions in the following shale plays:

Encana’s positions in the plays listed above gives them a large amount of current natural gas production, but any oil is mainly prospective, future production. The position in the Permian basin (roughly 140,000 acres) will add to this, but does give Encana some immediate oil production (the 30,000 boe/d acquired was made up of 80% oil, 20% natural gas) to bolster its figures. The future potential of the asset and Encana’s plans to quickly expand the oil portion of its portfolio will explain the relatively high prices paid per boe/d of production and per boe of 1P reserves ($223k and $38.69 respectively).

All Permian Basin Deals in Q3 2014

17

OilVoice Magazine | NOVEMBER 2014

Whiting to Become the Largest Bakken Producer as Baytex Moves South Whiting Petroleum announced the second biggest deal of Q3 2014 with the US$6 billion acquisition of Kodiak Oil & Gas. The acquisition adds approximately 34,000 boe/d to Whiting’s Bakken portfolio, according to Q1 2014 figures from Kodiak. Its new combined acreage position of 855,000 net acres is still not as large as Continental Resources, which holds over 1.2 million acres in the play, but this additional production combines with Whiting’s own reported Q1 production to give 107,000 boe/d from the first quarter’s operations, which is higher than Continental’s 97,500 boe/d in the same period. The deal is expected to close by the end of the year. The Bakken has seen a lot of deals like this in recent years, with companies agreeing deals that consolidate already significant acreage positions in the play, suggesting that the Bakken is an area where only those with the largest scale operations can succeed. Of course, the flip-side to this is that smaller operators find things difficult and Baytex Energy has followed in the footsteps of Magnum Hunter Resources and QEP Resources (to name only two from recent times) this quarter in selling off acreage in the Bakken.

Baytex Energy is actually a very interesting case study; the company’s US business has changed completely within the first nine months of 2014. At the turn of the year, the company was operating in the Bakken and agreed to acquire Aurora Oil & Gas, a South Texas Eagle Ford producer, in February. Around the time of this deal completing late in the second quarter, Baytex (currently Canada’s 19th biggest producing company) began a portfolio review aimed at identifying and selling producing assets with lower rates of return that would not be the focus of major investment going forward. The Bakken assets that were held at the turn of the year are the first major assets to be sold; Baytex announced a deal with SM Energy in July to sell the Bakken properties for US$330.5 million. So within nine months (the Bakken sale closed in late September) the company’s US business has moved south in its entirety, now completely focused on Texas and the Eagle Ford shale, where wells cost around US$1.7 million less to drill on average, according to latest data from the Evaluate Energy North American shale play database (see note 1).

Murphy Oil sells Stake in Malaysian Assets on Last Day of Quarter The biggest deal outside of North America this quarter was announced on 30th September, as Indonesia’s Pertamina agreed to acquire 30% of Murphy Oil’s Malaysian offshore assets for US$2 billion. Offshore assets can be costly to maintain, and the reduced ownership for Murphy will free up significant funds every year for the company to reassign towards its core Eagle Ford position back in the US or towards other acquisition opportunities. For Pertamina, this may only be the start of things to come as the company continues to struggle with demand back home in Indonesia. More deals like this should be expected from Pertamina as demand for oil and gas is growing while production is falling. Consequently, sourcing cheaper imports are becoming a much higher priority than ever before and acquiring overseas stakes will assist in this endeavour.

18

OilVoice Magazine | NOVEMBER 2014

Top 10 E&P Deals Worldwide in Q3 2014

Notes: 1) In the Bakken, company guidance for the year 2014 gave an average well cost estimate of US$8.9 million, and Eagle Ford wells averaged at a cost of US$7.2 million.

View more quality content from Evaluate Energy

19

OilVoice Magazine | NOVEMBER 2014

De-marginalising small oil fields Written by Edward Marriott from ABT Oil & Gas and RMRI

In the run up to the Scottish referendum there was heated political debate over whether 15 billion, 24 billion or even more barrels of oil equivalent (boe) could still be extracted from the North Sea. It served only to highlight the wide-ranging uncertainty surrounding the total figure.

Yet one assertion can be made with much more confidence. Whatever the extractable total turns out to be, over five billion barrels of oil equivalent contained in some 303 already known, but undeveloped fields across the UKCS could make a considerable contribution towards reaching that total. These are confirmed, appraised discoveries recorded in the IHS EDIN database used by RMRI in research for ABT Oil and Gas. Their numbers include accumulations of all types and sizes in a range of water depths, and they have all at some stage been dismissed by the oil industry as having little or no commercial interest. Many were thoroughly appraised prior to rejection, then were plugged and abandoned or suspended while the license holders moved on to seek richer prizes. These are the marginal fields, so called because they inhabit an uncertain economic margin created by oil price, development costs and the fiscal regime.

The two principle reasons for the marginalisation of fields are their technical difficulty or their size. Either combines with their location to determine whether they are economically viable or not, since proximity to existing facilities enables projects which would otherwise prove too costly for development.

Isolated small fields are particularly interesting because they often contain conventionally recoverable, oil-rich reserves. From the IHS EDIN database, RMRI has identified 105 such fields, in UKCS waters, each containing between 3 and 30 million boe, with a collective reserve of 1.25 billion boe. Their limited output and short productive lives do not justify the capital or operating expense of conventional production methods, especially from a unit cost perspective. In a University of

20

OilVoice Magazine | NOVEMBER 2014

Aberdeen Occasional Paper, Professor Alexander Kemp and Linda Stephen stress that field lifetime costs for small fields can 'become very high on a boe basis.' [1] This steep unit cost as field size diminishes can be demonstrated by charting the capital expenditure (CAPEX) and operating expenditure (OPEX) across a range of reserve sizes. The costs are based upon an RMRI analysis of conventional facilities with liquid processing capacities similar to the two production systems available to ABT Oil and Gas, which are discussed in greater detail later in this article. Adjusting the OPEX according to size of project, Chart 1 plots the unit cost per boe, highlighting, the point at which fields lose viability and the impact of oil price movements upon this. The precarious nature of marginal field economics can clearly be seen.

The chart makes obvious the parabolic increase of cost per boe as field size diminishes, with exponential increase at the lowest end. It also demonstrates the extreme vulnerability of small fields to any fall in oil price.

A bench mark total field cost of $1280 million (ÂŁ800 million) including CAPEX and OPEX, using a ratio of 5:3 is based upon a 10 million boe field from which other field costs are extrapolated. OPEX is adjusted for differences in field size on a per million boe basis by simple addition or subtraction for fields larger or smaller than bench mark size. The GB pound/dollar conversion factor is set at 1.6 and the base oil price at $90

21

OilVoice Magazine | NOVEMBER 2014

After the spectacular fall from $140/boe to $40/boe within six months during the recession, prices have recovered to between $90 and $100/boe and have fairly settled for the past three or four years.[2] Nevertheless, within this period, there have been frequent fluctuations of around $20/boe, creating a zone of extreme uncertainty, plotted on the chart as a spread of $10 above and below the ÂŁ90 base price.

At $90 per boe, fields containing 19 million boe break even, putting 83 fields this size and smaller within the UKCS below economic recovery, with a loss of 747.7 million boe[3]. Costs, however, must be considerably lower than break-even to achieve the hurdle rate for a project to be considered commercially viable and sanctioned. As such, in this model, fields containing up to 25 million boe, the average size of recent discoveries, remain at high risk. A rise in oil price to $100 drops the viable field size to 15.5 million boe, but it will attract investment only if a sustained rise is anticipated; a circumstance not expected by the oil futures market according to both US Energy Information Administration and the CME Group. This makes the prospect of a massive oil price rise giving economic certainty to small marginal fields a highly unlikely.

Price increases, then, cannot be relied upon to transform marginal field development. The macro-economic and geo-political influences that determine oil price cannot be controlled by operators, investors or even government. Besides this, when oil prices more than doubled between 2003 and 2013, any positive impact upon small field economics was limited by a massive fivefold increase in costs over the same period.[4]

22

OilVoice Magazine | NOVEMBER 2014

Cost increases, if anything, pose a greater threat to small field development than falls in oil price. Chart 2 shows that a cost rise of 11.1% (equivalent to a $10 price reduction) takes fields containing less than 30 million boe into the high risk zone, making their commercial viability uncertain. Such an increase, or even larger, is highly probable in a maturing region where rising costs are endemic. As with price, macro-economic factors, such as international demand for labour and equipment, can influence costs, but three main causes - depletion of major reserves, the age of facilities and systemic problems of the region's fundamental development pattern are local to the UKCS. They have meant: 

more small fields in production, increasing unit costs;



increased development costs for technically difficult fields, depleting fields, or



frontier region projects; increased OPEX for maintenance and repairs

 

longer periods of fully-crewed down-time, and periods of non-production without concurrent OPEX reduction.

The last two points signal a major underlying problem: the accelerating effect of increased costs, especially operating costs, against declining production. This drives cost per boe ever higher and the situation has the potential to spiral. In its 2014 Activity Survey, Oil and Gas UK, says: ...in the space of 12 months, around 300 million boe of reserves are no longer considered recoverable as a result of operating cost increases that are shortening the economic life of fields.'[5] Each boe of lost production increases the recovery cost of all remaining barrels, further threatening overall economic recovery of reserves. According to Oil and Gas UK, 'This relentless rise in costs is unsustainable...' A stark symptom of the problem was highlighted by Scotland's Independent Expert Commission on Oil and Gas, who pointed out that 'the number of people needed to produce a barrel of oil (rose) from 18 in 2006 to 45 in 2012.'[6] The pattern of rising costs associated with established means of production makes the future look bleak for small fields. Chart 1 above indicated that fields with reserves below 19 million boe could be permanently lost, and fields containing up to 25 million boe could be considered too high risk for development. However, unlike oil prices, with innovation and new technology it is possible that costs can be controlled by industry and government at a local level. Chart 3 below demonstrates the impact of cost reduction.

23

OilVoice Magazine | NOVEMBER 2014

A cost reduction of 11.1%, commensurate with a $10 price increase, is shown to lower the break-even field size to around 15 million boe – almost one million barrels smaller than an equivalent oil price increase. In addition to bringing more fields within economic reach, larger fields of 19 million boe and above become less risky.

However, many of the fields containing between 3 and 30 million boe identified by RMRI remain uneconomic. To achieve their viability a much greater reduction would be required. As demonstrated by the 50% reduction line, halving costs would reduce viable field size to 7 million boe which would need a price rise to $140/boe. Though very small fields remain at risk, with a potential loss of 53 million boe, cost reductions are shown to have more impact upon the economics of marginal fields than comparable oil price increases.

Whether the level of cost reduction required to unlock small fields can be achieved by conventional means in the UKCS is highly unlikely. Though smaller accumulations have a major contribution to make to the wider economy, left to established methodology, only a small fraction of their 1.25 billion boe is likely to be recovered.

The established development model for the UKCS is a dendretic outgrowth of host platforms and pipelines from major production installations and arterial delivery

24

OilVoice Magazine | NOVEMBER 2014

systems designed to exploit huge fields. Extending this to include smaller and more marginal fields has, so far, been the favoured method small field exploitation.

According to James Harpin, more than half of the small fields developed in the UK North Sea between 2000 and 2010 'depended upon subsea infrastructure tieback to host processing and export facilities'.[7] For fields within reach of suitable platforms this has proved cost effective and will, according to Sir Ian Wood, be further enabled by the cluster development advocated in his UKCS Maximising Recovery Review.[8] If, however small fields can be developed only through linkage to existing infrastructure, as Sir Ian Wood implies when he says, ‘tieback enables small fields to be developed which would have been uneconomic on a stand-alone basis’[9] then the numbers exploited will be severely limited. Since tieback costs increase with distance, it will confine small marginal field development, and much exploration activity, to the catchment areas of existing facilities. Extending beyond this will require an additional complex network of subsea facilities, pipelines and intermediate host platforms, with obvious future decommissioning cost implications.

More crucially, small projects, already economically vulnerable, would continue to be linked to an increasingly costly ageing infrastructure, including major platforms whose primary fields are severely depleted and whose own future is insecure. Many production facilities require increased throughput from satellite fields to remain economic so, unless several robust projects are within geographical reach, the security of the host, and therefore all its dependent fields, will be dictated by its economically weakest satellites.

These problems of existing infrastructure network must inevitably be passed on to third parties seeking to link into that network. For example, even if owners of fixed installations are reluctant to inflate tariffs, the higher expenditure or looming decommissioning costs encountered by many will force a lease rate increase.

Floating Production storage and Offloading (FPSO) vessels provide a means of sidestepping these difficulties. However they were designed for medium to large accumulations, have 24/7 crewing requirements and a high front-end CAPEX which is reflected in lease rates. In addition, with some 20 - 23 FPSOs operational in UK waters,[10] coverage and availability is limited and any increase in demand is likely to have a high impact upon costs.

Licence holders of marginal fields, typically small operators for whom these

25

OilVoice Magazine | NOVEMBER 2014

accumulations could provide game changing opportunities, are particularly susceptible. They are positioned at the interface between the economic requirements of their low-volume, short-life projects and the established UKCS production system, with expensive FPSOs as their only alternative. They are likely to encounter major difficulties in the early project stages as they try to find an economic means of utilising existing facilities. Some of these difficulties, which could precipitate project abandonment, might include: 

inability to negotiate economic terms with infrastructure owners;

 

anticipated space on facilities being withdrawn; key partners pulling out; higher than anticipated costs revealed during the Front End Engineering



Design (FEED) or pre-FEED stages; lack of suitable production and delivery facilities within viable distance, or





difficulty agreeing appropriate financing solutions and attracting required investment.

These examples indicate the hurdles which must be overcome if the potential contribution of marginal fields to the economic recovery of the UKCS is to be maximized. Part of the remedy is highlighted in Scotland's Independent Expert Commission on Oil and Gas when it stresses the requirement for smaller specialist companies in the region, and the need to attract 'agile, entrepreneurial, and therefore often smaller players'.[11] This aptly describes British company ABT Oil and Gas (ABTOG). The company has long recognised the need for a new sector within the upstream oil and gas industry, focussed upon the economic extraction of small or stranded fields. As a result ABTOG are creating the next evolution in offshore oil production: buoyant solutions which can unlock the potential of such accumulations. Central to this is the need to drive down costs and, at the same time free small operators from dependency upon existing infrastructure. Through innovative production and storage systems, ABTOG’s buoyant solutions provide the appropriate means to deliver these two crucial elements.

Having identified appropriate solutions, ABTOG worked with its partners to develop two stand-alone production systems both of which secure dramatic reductions in both CAPEX and OPEX; a taut-tethered Production Buoy and, along with GMC Ltd., a solution specifically cost-effective for the North Sea, which they call the SelfInstalling Floating Tower (SIFT). The potential impact of the SIFT on small field

26

OilVoice Magazine | NOVEMBER 2014

development is shown in Chart 4, below. As this demonstrates, the SIFT is able to reduce cost to a lower level than the 50% cost reduction detailed in Chart 3.

For an initial 10 million boe project, use of the SIFT reduces field-life cost by around 60% of the cost of a comparable established production system. Including generic CAPEX and abandonment costs of $350 million (£220 million), and an OPEX around $130 million (£80million), total cost for a field of this size is $480million (£300 million). This brings the break-even field size to below 5 million boe, and reduces risk for fields containing about 5.25 million boe.

Both the SIFT and the buoy utilise innovative adaptations of proven technology enabling dramatic cost reductions through lower construction costs than alternatives.

They contain all the equipment needed for processing up to 20,000 barrels of fluid per day, adapted for use in low-cost buoyant housing structures. OPEX is held down to a minimum as normally-unmanned operation cuts back crewing costs. There is also capacity for integral storage in the cellular legs of the SIFT, or in a separate seabed tank for the buoy, so tanker offloading avoids the high delivery tariffs of existing pipelines and infrastructure.

Most importantly, the buoyant nature of these systems, linked with ease of installation, simple decommissioning and low-cost refitting and transportation, means

27

OilVoice Magazine | NOVEMBER 2014

that they can be redeployed – possibly several times over during their 25-year design life. Costs are almost halved to around $288 million dollars (£180million) for subsequent deployments, reducing the viable field size by another 2 million boe as shown in Chart 5.

From this it is clear that the SIFT renders fields containing 5 million barrels economically viable during its first deployment, and pushes this figure to below 3 million for second and subsequent deployments. Further than this, the tightening curve of the cost parabola's 'elbow' means the lower 'arm' falls quickly away from the high risk zone, reducing the overall economic vulnerability of all fields containing above 3 million boe. Though real field conditions and project parameters will vary, this gives an indication of the cost reductions that can be achieved using ABTOG’s solutions. Further reductions might come from: 

refinements of design and construction;



tying in multiple wells, or by



identifying similar target field, either within geographical clusters or in scattered locations, reducing refitting cost and time.

With these advantages, the solutions offered by ABTOG have more to offer than a means to exploit known small accumulations. Sir Ian Wood complains that, ‘There has not been a significant (multi hundred million) discovery for five years.’ This makes the need for solutions to the recovery of small marginal fields even more

28

OilVoice Magazine | NOVEMBER 2014

imperative. With the average size of discoveries now around 25 million boe, a way of developing smaller finds is crucial. Apart from the revenue that such discoveries will provide, if exploration continues to be severely curtailed through fear of subeconomic finds, as the Wood Review suggests, then new discoveries will become fewer and some huge, but as yet unsuspected, accumulation might never come to light. There is therefore an urgent need to revitalise exploration by providing the means to transform small, isolated discoveries into economic finds.

Even without new discoveries, identified small fields alone could produce a post-tax profit of £22 billion and boost tax revenue by £19 billion. Further than this, all fields decline and at some point all fields will become marginalised, making their existing facilities uneconomic and decommissioning inevitable. When this happens, ABTOG's solutions could sustain hydrocarbon production from isolated locations throughout the region long after its fixed structures have been decommissioned and cut up for scrap.

Now that the custodian of the UKCS is decided, the UK government must put aside arguments about the size of the region’s hydrocarbon potential and focus on how it can maximise the economic recovery of offshore reserves. Regardless of how much oil remains in the maturing North Sea, small and stranded fields must be transformed from marginal assets to become a key component of the nation’s energy security and economic prosperity for decades to come.

[1]

Prospects for Activity in the UK Continental Shelf after Recent Tax Changes: The 2012 Perspective. Professor Alexander G Kemp and Linda Stephen [2] Macrotrends [3] Of 105 fields identified from IHS EDIN database [4] The UKCS Maximising Recovery Review, February 2014, Sir Ian Wood.

[5] Oil & Gas UK: Activity Survey 2014 [6] Scotland's Independent Expert Commission on Oil and Gas: Managing the Total Value Added.

[7] Measuring the impact of aging infrastructure in the UK North Sea, James Harpin IHS [8] See Footnote 5 [9] Ibid [10] Culled from information listed on fpso.net; fpso.com and A Barrel Full.

[11] See Footnote 5

View more quality content from ABT Oil & Gas and RMRI

29

OilVoice Magazine | NOVEMBER 2014

Should we be in the Arctic?

Written by David Bamford from PetroMall The sanctions-driven freeze on US and European involvement in the Russian Arctic gives us time to consider a fundamental question: Should we be exploring in the Arctic at all?

On the one hand, as an explorer I am aware of, even excited by, USGS notions that the Arctic may contain say 100 bn boe waiting to be discovered. Some would say there’s more even than that. On the other hand, there are (at least) three notions we should consider: 1. As I understand it, the ExxonMobil/Rosneft budget for drilling just two exploration wells in the Kara Sea was ~$700m. Does this mean that the discovery and adequate appraisal of a potentially commercial petroleum accumulation would cost $1.5 – 2bn?

2. At the moment (*as far as I can tell) there is no development technology that will lead to economic production from an Arctic oil field.

3. If an oil spill enters an area of ice, it is not evident (*to me) that our industry has the technology to clean it up.

Now I know that some people take a stance against Arctic exploration, development and production on environmental and moral grounds. And that of course is their right.

However, it occurs to me that the costs of finding, appraising, developing and producing a barrel of oil in the Arctic are going to run ahead of the oil price curve for the foreseeable future, if not indefinitely, and for this reason we might be better devoting our attention to other provinces. I would imagine that if you are an investor sitting say in New York, Houston or Dallas, the US onshore looks a way, way more attractive proposition than the Arctic anywhere. * I have qualified my comments because of course it is perfectly possible that somewhere in Houston, say at EPR Co or BP, there are folk who know perfectly well how to do this. If so, I have not met them and their light is, right now, hidden under the proverbial bushel!

View more quality content from PetroMall

The Essential Building Blocks for New Play Generation Analyse • Integrate • Explore

Our unique construction, the Neftex Earth Model, is a powerful product suite that thoroughly integrates published geoscience data within a robust sequence stratigraphic and geodynamic framework.

Delivering an unrivalled predictive global view of the Earth’s tectono-stratigraphic history and associated resource potential, the Neftex Earth Model provides the essential building blocks that you require to gain valuable regional geological insight and better understand risk in the exploration for Earth resources.

Build exploration success with the Neftex Earth Model.

Contact us today: Website: www.neftex.com Email: enquiries@neftex.com Tel: +44 (0)1235 442699 Facebook: www.facebook.com/neftex Neftex • 97 Jubilee Avenue • OX14 4RW • UK

Now Explore 3318_13_Generic ad re-size Geo Arabia (207mm x 291mm).indd 1

21/05/2014 12:38

31

OilVoice Magazine | NOVEMBER 2014

Tech Talk - Pessimistic Talk in a time of surplus Written by David Summers from Bit Tooth Energy The oil markets are concerned that there is too much oil currently available on the market, and that, as a consequence, oil prices may continue to tumble. Saudi Arabia is reportedly telling Reuters that it is happy with prices that may fall as low as $80 a barrel. As I mentioned the other day, some of this has to do with market share, and the KSA increasing production, and thereby seeking to weaken the likelihood of investment in other places, in turn ensuring their share holds up, not just now, but also down the road. The effect on gas prices has been rapid, with prices in parts of Missouri down to $2.65 a gallon – about a dollar less than I was paying only a week ago.

The effect will also have the benefit of a boost to the economy, which of course can’t hurt in the run-up to an election. But in the longer term it is hard to see how this boost can be sustained for more than a year. In the last post on this I mentioned that, outside of the US, Russia and KSA global oil production had dropped around 3 mbd over the past couple of years. Yet increased production (KSA raised production by 100 kbd in September as part of a total 400 kbd increase from OPEC overall) has, for now, been able to match and surpass this in order to meet the global demand.

OPEC continues to expect that demand will increase by a million barrels a day this year and 1.19 mbd next. They further expect that the increased production to meet this will be met from outside the cartel, with the gain declining from 1.68 mbd this year, to 1.24 mbd next year, holding OPEC production to a decline of 300 kbd from the current 29.5 mbd. Simplistically the gains are maximized in increased production from the United States (880 kbd); Canada (250 kbd) and Brazil (190 kbd). They are anticipating a slight drop in Russian production, as part of an overall decline of 80 kbd for the FSU countries.

Part of the problem in projecting the balance revolves around estimating the production from Libya, Iraq and Iran (LII). Libya has reported raising production back to around 800 kbd, but some of that comes from the Shahara field, which was still involved in factional fighting, even as it came back on line at some 20% of normal.

The three countries produce around 7 mbd (Iran 3 mbd, Iraq 3.2 mbd; Libya .8 mbd) so that the fluctuations in their production and sales can have a very significant impact on the global oil market, and the prices that are paid – but they function within OPEC, and it may be that the current drops in price are reminder that the big dog in that trailer is KSA, currently running at around 9.7 mbd.

It is foolish to try and predict, over the immediate short-term, how the fighting in

32

OilVoice Magazine | NOVEMBER 2014

Libya and Iraq will progress. Similarly it is hard to see how relations with Iran will change, potentially easing sanctions and allowing them to sell more product into the global market would upset the current balance in trade, and could, in the short-term, increase the glut and lower prices.

But supplies from those outside the cartel and the Americas are continuing to decline. That is not going to change. The rates may fluctuate a little (though the current drop in prices is not going to encourage large scale investment in declining fields) but the overall trend is steadily downward. And it is within that picture that potential changes in the production from the three LII countries have to be placed.

Figure 1. Libyan oil production through September 2013. (EIA) Yet, as the fields have brought oil back to the market, there is a concurrent fall in global prices, as the EIA note.

Figure 2. Recent oil production from Libya and the price of Brent Crude (EIA) Pre-conflict Libya was producing over 1.6 mbd, it recovered to 1.4 and is now struggling at around 0.8 mbd. But the prospects for the levels of peace required to sustain even that level do not seem promising. The conflict is worsening and seen as spiraling out of control.

Moving East to Iraq, despite the use of air power, the situation in the North is not

33

OilVoice Magazine | NOVEMBER 2014

improving, although the Kurds have now a pipeline to carry oil up into Turkey that is not controlled by the Islamic State. While it is still a matter of debate how much oil they will be able to sell, they hope that, by the end of next year they may be able to pump as much as 1 mbd, up from the initial 0.1 mbd when the pipeline went on line.

At the same time, in the South, the oil fields lie some distance from the conflict, and there seems little threat, at the moment, to the plans to increase production, and move the majority of the oil to the coast for export. It is, therefore possible to foresee an increase in Iraqi production of perhaps a million barrels a day in the next couple of years. Is it likely? It is hard to say. Factional fighting is always hard to predict, and the willingness of those involved to use explosives makes it even more of a problem to predict what will occur, given the vulnerability of pipelines to attack.

Predicting how Iran will change is similarly conflicted, in that it is hard to predict the behavior of those who control the country, and in turn impact oil exports.

But putting this within the context of OPEC, I suspect that overall production will not fall much outside of the current volumes that the MOMR are predicting – which is sensibly overall stable output over the next year or so. And if that is the case, then I would, as mentioned last time, expect to see that the global surplus of oil supply over demand will gradually disappear over the next year, with the impact becoming evident once we reach the summer of 2016. It would be nice to be wrong, but I think it unlikely.

View more quality content from Bit Tooth Energy

Nanotechnology hits the oilpatch Written by Keith Schaefer from Oil & Gas Investments Bulletin Dropping energy prices—for both oil and natural gas—has investors and analysts checking to see what the break-even price is for oil production in each play in North America.

This is a moving target, and it’s going lower all the time.

34

OilVoice Magazine | NOVEMBER 2014

And I’m going to tell you The Next Phase of increasing profitability—i.e. lower breakeven costs—for the industry.

Now, the #1 reason is for lower break-even costs is better fracking techniques. The industry has not yet found the upper limits of how much oil or gas they can get out from under a square mile patch of land.

Improvements or increased efficiencies aren’t happening every year; they’re not happening every quarter, they are happening every MONTH—as this graph illustrates:

Source: EIA and Unit Economics Here’s another graph that shows how oil production is improving in the Eagle Ford.

Drilling longer wells and putting more frac sand in wells is increasing flow rates from wells on a per-foot basis.

35

OilVoice Magazine | NOVEMBER 2014

So while commodity prices are dropping a lot—cash flows won’t be going down by the same amount. (And in Canada, energy prices have barely budged when you count the lower Canadian dollar.)

So what’s the next Big Thing in fracking that will increase productivity and lower costs? Nanotechnology. This means being able to engineer systems at the molecular level. And oil and gas is all about the molecules.

I’ve discovered a company that has proven nanotechnology in the oilpatch. They are able to use a chemistry that has smaller molecules than their competitors. The smaller molecules can be pushed farther up the fracks, and open more area for oil and gas to be released.

They recently tested 12 wells with one of the largest independent producers in the United States—a $40 billion company. Six wells used this new technology, and six did not. That’s a big deal, because trust me, producers don’t like testing new technology. Adoption rates are slow.

But the results were fantastic—all six of the wells using nanotechnology showed better flow rates—18%-33% better—for the same cost as using regular fracking technology.

I think it has the potential to be the next “killer app” in the Shale Revolution. This company already has positive cash flow, and it trades under $10/share.

The oilpatch is a tight-fisted industry. But “best practices” spreads like wildfire across a play. When they can buy a superior product for the same price (which actually gives better than industry margins to this nanotech supplier), they will buy it.

What I like most about this story is that this the ground floor for this opportunity— they have just started selling it. And they are already making expansion plans at their manufacturing facility for it.

As industry revenues get squeezed with lower commodity prices, they are jumping for a proven product that improves productivity and reduces costs. Get to know this company before it issues its next operational update—click here.

View more quality content from Oil & Gas Investments Bulletin

36

OilVoice Magazine | NOVEMBER 2014

WSJ gets it wrong on 'Why Peak Oil Predictions Haven't Come True' Written by Gail Tverberg from Our Finite World On Monday, September 29, the Wall Street Journal (WSJ) published a story called “Why Peak Oil Predictions Haven’t Come True.” The story is written as if there are only two possible outcomes: 1. The Peak Oil version of what to expect from oil limits is correct, or 2. Diminishing Returns can and are being put off by technological progress–the view of the WSJ. It seems to me, though, that a third outcome is not only possible, but is what is actually happening.

3. Diminishing returns from oil limits are already beginning to hit, but the impacts and the expected shape of the down slope are quite different from those forecast by most Peak Oilers.

Area of Confusion In many people’s way of thinking, the economy is separate from resources and the extraction of those resources. If we believe economists, the economy can grow indefinitely, with or without the use of resources. Clearly, with this view, the price of these resources doesn’t matter very much. If one kind of resource becomes more expensive, we can substitute other resources, once the scarce resource becomes sufficiently high-priced that the alternative makes financial sense. Incomes can rise arbitrarily high–all it takes is for each of us to pay the other higher wages. And we can fix any problem with the financial system with more money printing and more debt.

This wrong version of how our economy works has been handed down through the academic world, through our system of peer review, with each academic researcher following in the tracks of previous academic researchers. As long as new researchers follow the same wrong thinking as previous researchers, their articles will be published. Economists were especially involved in putting together this wrong world-view, but politicians helped as well. They liked the outcomes of the models the economists produced, since it made it look like the politicians, with the help of economists, were all-powerful. All the politicians needed to do was tweak the

37

OilVoice Magazine | NOVEMBER 2014

financial system, and the world economy would grow forever. There was not even a need for resources!

Peak Oilers’ Involvement The Peak Oilers walked into a situation with this wrong world view, and started trying to fix pieces of it. One piece that was clearly wrong as the relationship between resources and the economy. Resources, especially energy resources, are needed to make any of the goods and services we buy. If those resources started reaching diminishing returns, it would be harder for the economy to grow. The economy might even shrink. Dr. Charles Hall, recently retired professor from SUNY-ESF, came up with one measure of diminishing returns–falling Energy Returned on Energy Invested (EROEI).

How would shrinkage occur? For this, Peak Oilers turned to the work of M. King Hubbert, who worked in an area of geology. He wrote about how supply of a resource might be expected to decline with diminishing returns.

Hubbert was not concerned about what effect diminishing returns would have on the economy–presumably because that was not his area of specialization. He avoided the issue by only modeling the special case where no economic impact could be expected–the special case where a perfect substitute could be found and be put in place, in advance of the decline caused by diminishing returns.

Figure 1. Figure from Hubbert’s 1956 paper, Nuclear Energy and the Fossil Fuels.

In the example shown above, Hubbert assumes cheap nuclear would take over, before the decline in fossil fuels started. Hubbert even talked about making cheap liquid fuels using the very abundant nuclear resources, so that the system could continue as before.

In this special case, Hubbert suggested that the decline in resources might follow a symmetric curve, slowly declining in a pattern similar to its original rise in

38

OilVoice Magazine | NOVEMBER 2014

consumption, since this is the pattern that often occurs in extracting a resource in nature. Many Peak Oilers seem to believe that this pattern will happen in the more general case, where no perfect substitute is available, as well. A perfect substitute would need to be cheap, abundant, and involve essentially no cost of transition.

In the special case Hubbert modeled, Hubbert indicated that production would start to decline when approximately 50% of reserves had been exhausted. Peak Oilers often used this approach or variations on it (so called “Hubbert Linearization“), to forecast future production, and to determine dates when oil production would “peak.”

Of course, as technology improved, additional oil became accessible, raising reserves. Also, as prices rose, resources that had never been economically extractible became extractible. Production continued beyond forecast peak dates, again and again.

Peak Oilers got at least part of the story right–the fact that we are in fact reaching diminishing returns with respect to oil. For this they should be commended. What they didn’t figure out is, however, is (1) how the energy-economy system really works, and (2) which pieces of the system can be expected to break first. This issue is not really the Peak Oilers fault–it is the result of starting with a very bad model of the economy and not understanding which pieces of that model needed to be fixed.

How the Economic System Really Works We are dealing with a networked economy, one that is self-organized over time. I would represent it as a hollow network, built up of businesses, consumers, and governments.

Figure 2. Dome constructed using Leonardo Sticks This economic system uses energy of various kinds plus resources of many kinds to make goods and services. There are many parts to the system, including laws, taxes, and international trade. The system gradually changes and expands, with new laws replacing old ones, new customers replacing old ones, and new products replacing old ones. Growth in the number of consumers tends to lead to a need for more goods and services of all kinds.

39

OilVoice Magazine | NOVEMBER 2014

An important part of the economy is the financial system. It connects one part of the system with another and almost magically signals when shortages are occurring, so that more of a missing product can be made, or substitutes can be developed.

Debt is part of the system as well. With increasing debt, it is possible to make use of profits that will be earned in the future, or income that will be earned in the future, to fund current investments (such as factories) and current purchases (such as cars, homes, and advanced education). This approach works fine if an economy is growing sufficiently. The additional demand created through the use of debt tends to raise the prices of commodities like oil, metals, and water, giving an economic incentive for companies to extract these items and use them in products they make.

The economy really can’t shrink to any significant extent, for several reasons: 1. With rising population, there is a need for more goods and services. There is also a need for more jobs. A growing networked economy provides increasing numbers of both jobs and goods and services. A shrinking economy leads to lay-offs and fewer goods and services produced. It looks like recession.

2. The networked economy automatically deletes obsolete products and reoptimizes to produce the goods needed now. For example, buggy whip manufacturers are pretty rare today. Thus, we can’t quickly go back to using horse and buggy, even if should we want to, if oil becomes scarce. There aren’t enough horses and buggies, and there aren’t enough services for cleaning up horse manure.

3. The use of debt for financing depends on ever-rising future output. If the economy does shrink, or even stops growing as quickly as in the past, there tends to be a problem with debt defaults.

4. If debt does start shrinking, prices of commodities like oil, gold, and even food tend to drop (similar to the situation we are seeing now). These lower prices discourage investment in creating these commodities. Ultimately, they lead to lower production and job layoffs. If deflation occurs, debt can become very difficult to repay.

Under what conditions can the economy grow? Clearly adding more people to the economy adds to growth. This can be done by through adding more babies who live to maturity. It can also be done by globalization–adding groups of people who had previously only made goods and services for each other in limited quantity. As these groups get connected to the wider economy, their older, simpler ways of doing things tend to be replaced by more productive activities (involving more technology and more use of energy) and greater international trade. Of course, at some point, the number of new people who can be connected to the global economy gets to be pretty small. Growth in the world economy lessens, simply because of lessened ability to add “underdeveloped” countries to the networked economy.

Besides adding more people, it is also possible to make individual citizens “better off” by making workers more efficient at producing goods and services. Most people think of greater productivity as happening through technological changes, but to me, it really represents a combination of technological changes, plus a combination of inexpensive resources of various kinds. This combination often includes low-cost fossil fuels; abundant, cheap water supply; fertile soil; and easy to extract metal ores.

40

OilVoice Magazine | NOVEMBER 2014

Having these available makes possible the development of new tools (like new agricultural equipment, sewing machines, and vehicles), so that workers can become more productive.

Diminishing returns are what tend to “mess up� this per capita growth. With diminishing returns, fossil fuels become more expensive to extract. Water often needs to be obtained by desalination, or by much deeper wells. Soil needs more amendments, to be as fertile as in the past. Metal ores contain less and less ore, so more extraneous material needs to be extracted with the metal, and separated out. If population grows as well, there is a need for more agricultural output per acre, leading to a need for more technologically advanced techniques. Working around diminishing returns tends to make many kinds of goods and services more expensive, relative to wages.

Rising commodity prices would not be a problem, if wages would rise at the same time as the price of goods and services. The problem, though, is that in some sense diminishing returns makes workers less efficient. This happens because of the need to work around problems (such as digging deeper wells and removing more extraneous material from ores). For many years, technological changes may offset the effects of diminishing returns, but at some point, technological gains can no longer keep up. When this happens, instead of wages rising, they tend to stagnate, or even decline. Figure 3 shows that per capita wages have tended to grow in the United States when oil was below about $40 or $50 barrel, but have tended to stagnate when prices are above that level.

Figure 3. Average wages in 2012$ compared to Brent oil price, also in 2012$.

Average wages are total wages based on BEA data adjusted by the CPI-Urban, divided total population. Thus, they reflect changes in the proportion of population employed as well as wage levels.

What Effects Should We Be Expecting from Diminishing Returns With Respect to Oil Supply?

There are several expected effects of diminishing returns: 1. Rising cost of extraction for oil and for other commodities subject to diminishing returns.

41

OilVoice Magazine | NOVEMBER 2014

2. Stagnating or falling wages of all except the most elite workers.

3. Ultra low interest rates to try to make goods more affordable for workers stressed by stagnating wages and high prices.

4. Rising governmental debt, in an attempt to stimulate the economy and in order to provide programs for the many workers without good-paying jobs.

5. Increasing concern about debt defaults, as the amount of debt outstanding becomes increasingly absurd relative to wages of workers, and as all of the stimulus debt runs its course, in countries such as China.

6. A two way problem with the price of oil. On one side is recession, when oil prices rise to unaffordable levels. Economist James Hamilton has shown that 10 out of 11 post-World War II recession were associated with oil price spikes.

He has also shown that there is good reason to expect that the Great Recession was related to the run-up in oil prices prior to 2007. I have written a related paper–Oil Supply Limits and the Continuing Financial Crisis.

7. The second problem with the price of oil is the reverse–price of oil too low relative to the cost of extraction, because wages are not high enough to permit workers to afford the full cost of goods made with high-priced oil. This is really a problem with inadequate affordability (called inadequate demand by economists).

8. Eventual collapse of whole system.

There have been many studies of collapses of past economies. These collapses tended to occur when the economies hit diminishing returns after a long period of growth. The problems were often similar to ones we are seeing today: stagnating wages of common workers and growing debt. There were more and more demands on governments to fix the problems of workers, but governments found it increasingly difficult to collect enough taxes for all the needed programs. Eventually, the economic systems have tended to collapse, over a period of years. The shape of resource use in collapses was definitely not symmetric. Figure 4 shows my view of the typical shape of the collapses in non-fossil fuel economies, based on the work of Peter Turchin and Surgey Nefedof.

Figure 4. Shape of typical Secular Cycle, based on work of Peter Turchin and Sergey Nefedov in Secular Cycles.

42

OilVoice Magazine | NOVEMBER 2014

In my view, the date of the drop in oil supply will be determined by what appear to on-lookers to be financial problems. One possible cause is that the oil price will be too low for producers (a condition that is occurring now). Governments will find it unpopular to raise oil prices, but at the same time, will be powerless to stop the adverse impacts the fall in price has on world oil supply.

Falling oil prices have especially adverse effects on oil exporters, because they depend on revenues from oil to fund their programs. We are already seeing this now, with the increased warfare in the Middle East, Russia’s increased belligerence, and the problems of Venezuela. These issues will tend to reduce globalization, leading to less world growth, and a greater tendency for the world economy to shrink.

Unfortunately, there are no obvious ways of fixing our problems. High-priced substitutes for oil (that is, substitutes costing more than $40 or $50 barrel) are likely to have as adverse an impact on the economy as high-priced oil. The idea that energy prices can rise and the economy can adapt to them is based on wishful thinking.

Our networked economy cannot shrink; it tends to break instead. Even wellintentioned attempts to reduce oil usage are likely to backfire because they tend to reduce oil prices and have other unintended effects. Furthermore, a use of oil that one person would consider frivolous (such as a vacation in Greece) represents a needed job to another person.

Should Peak Oilers Be Blamed for Missing the “Real” Oil Limits Story?

No! Peak oilers have made an important contribution, in calling the general problem of diminishing returns in oil supply to our attention. One of their big difficulties was that they started out working with a story of the economy that was very distorted.

They understood how to fix parts of the story, but fixing the whole story was beyond their ability. The following chart shows a summary of some ways their views and my views differ:

Figure 5. Author’s summary of some differences in views.

43

OilVoice Magazine | NOVEMBER 2014

One of the areas that Peak Oilers tended to miss was the fact that an oil substitute needs to be a perfect substitute–that is, be available in huge quantity, cheaply, without major substitution costs–in order not to adversely affect the economy and in order to permit the slow decline rate suggested by Hubbert’s models. Otherwise, the problems with diminishing returns remain, leading to declining wages and rising costs of making goods and services.

One temptation for Peak Oilers has been to jump on the academic bandwagon, looking for substitutes for oil. As long as Peak Oilers don’t make too many demands on substitutes–only EROEI comparisons–wind and solar PV look like they have promise. But once a person realizes that our true need is to keep a networked economy growing, it becomes clear that such “solutions” are woefully inadequate.

We need a way of overcoming diminishing returns to keep the whole system operating. In other words, we need a way to make wages rise and the price of finished goods fall relative to wages; there is no chance that wind and solar PV are going to do this for us. We have a much more basic problem than “new renewables” can solve. If we can’t figure out a solution, our economy is likely to reach what looks like financial collapse in the near term. Of course, the real reason is diminishing returns from oil, and from other resources as well.

View more quality content from Our Finite World

World War III: It's here and energy is largely behind it Written by Kurt Cobb from Resource Insights I've been advancing a thesis for several months with friends that World War III is now underway. It's just that it's not the war we thought it would be, that is, a confrontation between major powers with the possibility of a nuclear exchange. Instead, we are

44

OilVoice Magazine | NOVEMBER 2014

getting a set of low-intensity, on-again, off-again conflicts involving non-state actors (ISIS, Ukrainian rebels, Libyan insurgents) with confusing and in some cases nonexistent battle lines and rapidly shifting alliances such as the shift from fighting the Syrian regime to helping it indirectly by fighting ISIS, the regime's new foe.

There is at least one prominent person who seems to agree with me, the Pope.

During a visit to a World War I memorial in Italy last month Pope Francis said: "Even today, after the second failure of another world war, perhaps one can speak of a third war, one fought piecemeal, with crimes, massacres, destruction."

In citing many well-known causes for war, he failed to specify the one that seems obvious in this case: the fight over energy resources. It can be no accident that the raging fights in Syria, Iraq, Libya, and the Ukraine all coincide with areas rich in energy resources or for which imported energy resources are at risk. There are other conflicts. But these are the ones that are transfixing the eyes of the world, and these are the ones in which major powers are taking sides and mounting major responses.

In Syria, Iraq and Libya, of course, it is oil and also natural gas that underlies the conflict. The ISIS forces in Syria and Iraq have seized oil refineries to power their advance. They and every fighting force in the world understands that oil is "liquid hegemony."

In the Ukraine natural gas supplies lurk in the background as rebels (supposedly with Russian help) fight to separate parts of eastern Ukraine from the country. The Russians who hold one of the largest reserves of natural gas in the world have threatened to cut off Ukraine, a large importer, this winter and to curtail supplies to Europe which depends on Russia for about 30 percent of its gas. The threat against Europe is in response to trade sanctions levied on Russia for its alleged role in helping Ukrainian insurgents.

Since summer, a friend and I have been periodically reviewing the World War III game board to assess whether the war is heating up or cooling down. The temperature changes as we have gauged them would look like a sine wave on a graph revealing no definitive trajectory. And, that is just the kind of war that I believe World War III will be--years of indecisive battles, diplomatic ploys, half-hearted engagement by major powers, and new, unexpected conflicts arising in unexpected places.

There are, of course, many other reasons for the conflicts I cite. But I wonder if the major powers would be much engaged in these conflicts if energy supplies were not at stake. So, the resource wars that are developing, especially those relating to energy, are not about direct conquest so much as concern about access to energy resources, or to put it more clearly, concern about possible interruptions to the flow of energy resources.

The low-intensity confrontation in the South China Sea between China and its neighbors, Vietnam and the Philippines, is the most prominent dispute over actual ownership of energy resources rather than the mere flow of those resources. But in the article cited, the Indians, while laying no claim to resources in that area, have said publicly that they are worried that shipping through the South China Sea could

45

OilVoice Magazine | NOVEMBER 2014

be affected if the conflict heats up. Again, we are back to concern about the flow of resources by countries not directly a party to the dispute--yet.

Traditional diplomacy among great powers does not seem to have been effective at resolving these conflicts. And, traditional military operations seem less than effective as well. Kurds in Syria report that U.S. airstrikes against ISIS are not working. This conflict and others like it which are characterized by poorly defined boundaries, shifting participants and unclear goals are confounding major powers and wreaking havoc on countries where these conflicts rage.

One of the most obvious strategies for responding to these conflicts--deep, rapid and permanent reductions in fossil fuel energy consumption through efficiency measures, conservation, and expansion of renewable energy--does not seem to be a prominent part of the policy mix. Such a reduction would not necessarily cause these conflicts to disappear; but they might become far less dangerous since the major powers would be less interested in them and thus less likely to make a miscalculation that would lead to a larger global conflict.

That is the danger that lies in my version of World War III--that it could morph into the kind of global conflict that risks nuclear confrontation between major powers--not because those powers would seek such an obviously insane outcome, but because they might miscalculate and by mistake push the conflict in this terrible direction.

It is not clear how this danger can be avoided given the current trajectory of world energy use. And, it is not clear how to get the world's leaders to focus on the obvious need to reduce not only fossil fuel energy use, but use of all the world's nonrenewable resources in order to forestall conflict.* That humans can have good lives without perpetual growth in the consumption of resources is simply not a possibility in the minds of most world leaders. And that means we should prepare for a very long World War III.

View more quality content from Resource Insights

46

OilVoice Magazine | NOVEMBER 2014

Eight pieces of our oil price predicament Written by Gail Tverberg from Our Finite World A person might think that oil prices would be fairly stable. Prices would set themselves at a level that would be high enough for the majority of producers, so that in total producers would provide enough–but not too much–oil for the world economy. The prices would be fairly affordable for consumers. And economies around the world would grow robustly with these oil supplies, plus other energy supplies. Unfortunately, it doesn’t seem to work that way recently. Let me explain at least a few of the issues involved.

1. Oil prices are set by our networked economy.

As I have explained previously, we have a networked economy that is made up of businesses, governments, and consumers. It has grown up over time. It includes such things as laws and our international trade system. It continually re-optimizes itself, given the changing rules that we give it. In some ways, it is similar to the interconnected network that a person can build with a child’s toy.

Figure 1. Dome constructed using Leonardo Sticks Thus, these oil prices are not something that individuals consciously set. Instead, oil prices reflect a balance between available supply and the amount purchasers can afford to pay, assuming such a balance actually exists. If such a balance doesn’t exist, the lack of such a balance has the possibility of tearing apart the system.

If the compromise oil price is too high for consumers, it will cause the economy to contract, leading to economic recession, because consumers will be forced to cut

47

OilVoice Magazine | NOVEMBER 2014

back on discretionary expenditures in order to afford oil products. This will lead to layoffs in discretionary sectors. See my post Ten Reasons Why High Oil Prices are a Problem.

If the compromise price is too low for producers, a disproportionate share of oil producers will stop producing oil. This decline in production will not happen immediately; instead it will happen over a period of years. Without enough oil, many consumers will not be able to commute to work, businesses won’t be able to transport goods, farmers won’t be able to produce food, and governments won’t be able to repair roads. The danger is that some kind of discontinuity will occur–riots, overthrown governments, or even collapse.

2. We think of inadequate supply being the number one problem with oil, and at times it may be. But at other times inadequate demand (really “inadequate affordability”) may be the number one issue.

Back in the 2005 to 2008 period, as oil prices were increasing rapidly, supply was the major issue. With higher prices came the possibility of higher supply.

As we are seeing now, low prices can be a problem too. Low prices come from lack of affordability. For example, if many young people are without jobs, we can expect that the number of cars bought by young people and the number of miles driven by young people will be down. If countries are entering into recession, the buying of oil is likely to be down, because fewer goods are being manufactured and fewer services are being rendered.

In many ways, low prices caused by un-affordability are more dangerous than high prices. Low prices can lead to collapses of oil exporters. The Soviet Union was an oil exporter that collapsed when oil prices were down. High prices for oil usually come with economic growth (at least initially). We associate many good things with economic growth–plentiful jobs, rising home prices, and solvent banks.

3. Too much oil in too short a time can be disruptive.

US oil supply (broadly defined, including ethanol, LNG, etc.) increased by 1.2 million barrels per day in 2013, and is forecast by the EIA to increase by close to 1.5 million barrels a day in 2014. If the issue at hand were short supply, this big increase would be welcomed. But worldwide, oil consumption is forecast to increase by only 700,000 barrels per day in 2014, according to the IEA. Dumping more oil onto the world market than it needs is likely to contribute to falling prices. (It is the excess quantity that leads to lower world oil prices; the drop in price doesn’t say anything at all about the cost of production of the additional oil.) There is no sign of a recent US slowdown in production either. Figure 2 shows a chart of crude oil production from the EIA website.

48

OilVoice Magazine | NOVEMBER 2014

Figure 2. US weekly crude oil production through October 10, as graphed by the US Energy Information Administration.

4. The balance between supply and demand is being affected by many issues, simultaneously.

One big issue on the demand (or affordability) side of the balance is the question of whether the growth of the world economy is slowing. Long term, we would expect diminishing returns (and thus higher cost of oil extraction) to push the world economy toward slower economic growth, as it takes more resources to produce a barrel of oil, leaving fewer resources for other purposes. The effect is providing a long-term downward push on the price on demand, and thus on price.

In the short term, though, governments can make oil products more affordable by ramping up debt availability. Conversely, the lack of debt availability can be expected to bring prices down. The big drop in oil prices in 2008 (Figure 3) seems to be at least partly debt-related. See my article, Oil Supply Limits and the Continuing Financial Crisis. Oil prices were brought back up to a more normal level by ramping up debt–increased governmental debt in the US, increased debt of many kinds in China, and Quantitative Easing, starting for the US in November 2008.

Figure 3. Oil price based on EIA data with oval pointing out the drop in oil prices, with a drop in credit outstanding.

49

OilVoice Magazine | NOVEMBER 2014

In recent months, oil prices have been falling. This drop in oil prices seems to coincide with a number of cutbacks in debt. The recent drop in oil prices took place after the United States began scaling back its monthly buying of securities under Quantitative Easing. Also, China’s debt level seems to be slowing. Furthermore, the growth in the US budget deficit has also slowed. See my recent post, WSJ Gets it Wrong on “Why Peak Oil Predictions Haven’t Come True”.

Another issue affecting the demand side is changes in taxes and in subsidies. A change toward more taxes such as carbon taxes, or even more taxes in general, such as the Japan’s recent increase in sales tax, tends to reduce demand, and thus give a push toward lower world oil prices. (Of course, in the area with the carbon tax, the oil price with the tax is likely to be higher, but the oil price elsewhere around the world will tend to decrease to compensate.)

Many governments of emerging market countries give subsidies to oil products. As these subsidies are lessened (for example in India and in Brazil) the effect is to raise local prices, thus reducing local oil demand. The effect on world oil prices is to lower them slightly, because of the lower demand from the countries with the reduced subsidies.

The items mentioned above all relate to demand. There are several items that affect the supply side of the balance between supply and demand.

With respect to supply, we think first of the “normal” decline in oil supply that takes place as oil fields become exhausted. New fields can be brought on line, but usually at higher cost (because of diminishing returns). The higher cost of extraction gives a long-term upward push on prices, whether or not customers can afford these prices.

This conflict between higher extraction costs and affordability is the fundamental conflict we face. It is also the reason that a lot of folks are expecting (erroneously, in my view) a long-term rise in oil prices.

Businesses of course see the decline in oil from existing fields, and add new production where they can. Examples include United States shale operations, Canadian oil sands, and Iraq. This new production tends to be expensive production, when all costs are included. For example, Carbon Tracker estimates that most new oil sands projects require a price of $95 barrel to be sanctioned. Iraq needs to build out its infrastructure and secure peace in its country to greatly ramp up production.

These indirect costs lead to a high per-barrel cost of oil for Iraq, even if direct costs are not high.

In the supply-demand balance, there is also the issue of oil supply that is temporarily off line, that operators would like to get back on line. Libya is one obvious example.

Its production was as much as 1.8 million barrels a day in 2010. Libya is now producing 800,000 barrels a day, but was producing only 215,000 barrels a day in April. The rapid addition of Libya’s oil to the market adds to pricing disruption. Iran is another country with production it would like to get back on line.

50

OilVoice Magazine | NOVEMBER 2014

5. Even what seems like low oil prices today (say, $85 for Brent, $80 for WTI) may not be enough to fix the world’s economic growth problems.

High oil prices are terrible for economies of oil importing countries. How much lower do they really need to be to fix the problem? Past history suggests that prices may need to be below the $40 to $50 barrel range for a reasonable level of job growth to again occur in countries that use a lot of oil in their energy mix, such as the United States, Europe, and Japan.

Figure 4. Average wages in 2012$ compared to Brent oil price, also in 2012$.

Average wages are total wages based on BEA data adjusted by the CPI-Urban, divided total population. Thus, they reflect changes in the proportion of population employed as well as wage levels.

Thus, it appears that we can have oil prices that do a lot of damage to oil producers (say $80 to $85 per barrel), without really fixing the world’s low wage and low economic growth problem. This does not bode well for fixing our problem with prices that are too low for oil producers, but still too high for customers.

6. Saudi Arabia, and in fact nearly all oil exporters, need today’s level of exports plus high prices, to maintain their economies.

We tend to think of oil price problems from the point of view of importers of oil. In fact, oil exporters tend to be even more affected by changes in oil markets, because their economies are so oil-centered. Oil exporters need both an adequate quantity of oil exports and adequate prices for their exports. The reason adequate prices are needed is because most of the sales price of oil that is not required for investment in oil production is taken by the government as taxes. These taxes are used for a variety of purposes, including food subsidies and new desalination plants.

A couple of recent examples of countries with collapsing oil exports are Egypt and Syria. (In Figures 5 and 6, exports are the difference between production and consumption.)

51

OilVoice Magazine | NOVEMBER 2014

Figure 5. Egypt’s oil production and consumption, based on BP’s 2013 Statistical Review of World Energy data.

Figure 6. Syria’s oil production and consumption, based on data of the US Energy Information Administration.

Saudi Arabia has had flat exports in recent years (green line in Figure 7). Saudi Arabia’s situation is better than, say, Egypt’s situation (Figure 5), but its consumption continues to rise. It needs to keep adding production of natural gas liquids, just to stay even.

Figure 7. Saudi oil production, consumption and exports based on EIA data.

52

OilVoice Magazine | NOVEMBER 2014

As indicated previously, Saudi Arabia and other exporting countries depend on tax revenues to balance their budgets. Figure 8 shows one estimate of required oil prices for OPEC countries to balance their budgets in 2014, assuming that the quantity of exported oil is pretty much unchanged from 2013.

Figure 8. Estimate of OPEC break-even oil prices, including tax requirements by parent countries, from APICORP. Based on Figure 8, Qatar and Kuwait are the only OPEC countries that would find $80 or $85 barrel oil acceptable, assuming the quantity of exports remains unchanged. If the quantity of exports drops, prices would need to be even higher.

Saudi Arabia has set aside funds that it can tap temporarily, so that it can withstand a lower oil price. Thus, it has the ability to withstand low prices for a year or two, if need be. Its recent price-cutting may be an attempt to “shake out” producers who have less-deep pockets when it comes to weathering low prices for a time. Almost any oil producer elsewhere in the world might be in that category.

7. The world really needs all existing oil production, plus more, if the world economy is to grow.

It takes oil to transport goods, and it takes oil to operate agricultural and construction equipment. Admittedly, we can cut back world oil production with lower price, but this gets us into “a heap of trouble”. We will suddenly find ourselves less able to do the things that make the economy function. Governments will stop fixing roads. Services we take for granted, like long distance flights, will disappear.

A lot of people have a fantasy view of a world economy operating on a much smaller quantity of fossil fuels. Unfortunately, there is no way we can get there by way of a rapid drop in oil prices. In order for such a change to take place, we would have to actually figure out some kind of transition by which we could operate the world economy on a lot less fossil fuel. Meeting this goal is still a very long ways away.

53

OilVoice Magazine | NOVEMBER 2014

Many people have convinced themselves that high oil prices will help make this transition possible, but I don’t see this as happening. High prices for any kind of fuel can be expected to lead to economic contraction. If transition costs are high as well, this will make the situation worse.

The easiest way to reduce consumption of oil is by laying off workers, because making and transporting goods requires oil, and because commuting usually requires oil. As a result, the biggest effect of a cutback on oil production is likely to be huge job layoffs, far worse than in the Great Recession.

8. The cutback in oil supply due to low prices is likely to occur in unexpected ways.

When oil prices drop, most production will continue as usual for a time because wells that have already been put in place tend to produce oil for a time, with little added investment.

When oil production does stop, it won’t necessarily be from high-cost production, because relative to current market prices, a very large share of production is highcost. What will tend to happen is that production that has already been “started” will continue, but production that is still “in the pipeline” will wither away. This means that the drop in production may be delayed for as much as a year or even two. When it does happen, it may be severe.

It is not clear exactly how oil from shale formations will fare. Producers have leased quite a bit of land, and in some cases have done imaging studies on the land. Thus, these producers have quite a bit of land available on which a share of the costs has been prepaid. Because of this prepaid nature of costs, some shale production may be able to continue, even if prices are too low to justify new investments in shale development. The question then will be whether on a going-forward basis, the operations are profitable enough to continue.

Prices for new oil development have been too low for many oil producers for many months. The cutback in investment for new production has already started taking place, as described in my post, Beginning of the End? Oil Companies Cut Back on Spending. It is quite possible that we are now reaching “peak oil,” but from a different direction than most had expected–from a situation where oil prices are too low for producers, rather than being (vastly) too high for consumers.

The lack of investment that is already occurring is buried deeply within the financial statements of individual companies, so most people are not aware of it. Dividends remain high to confuse the situation. By the time oil supply starts dropping, the situation may be badly out of hand and largely unfixable because of damage to the economy.

One big problem is that our networked economy (Figure 1) is quite inflexible. It doesn’t shrink well. Even a small amount of shrinkage looks like a major recession. If there is significant shrinkage, there is danger of collapse. We haven’t set up a new type of economy that uses less oil. We also don’t have an easy way of going

54

OilVoice Magazine | NOVEMBER 2014

backward to a prior economy, such as one that uses horses for transport. It looks like we are headed for “interesting times�.

View more quality content from Our Finite World

Leaders in the world of natural resource location Globe

Getech’s flagship global new ventures platform.

Regional Reports

Focussed assessments of exploration risks and opportunities.

Commissions

Bespoke projects utilising clients’ proprietary data.

Data

Unrivalled global gravity and magnetic coverage.

For further information contact Getech: Getech, Leeds, UK +44 113 322 2200 Getech, Houston, US +1 713 979 9900 info@getech.com www.getech.com