1. business and industrial
2. energy
3. oil

Edition Thirty One – October 2014
Recognizing the golden age of Texas oil and gas while we're in it
The Importance of Public Image to the Petroleum Industry
Yes or no? Implications for the UK Oil & Gas Industry
Cover image by addddee
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OilVoice Magazine | OCTOBER 2014
Adam Marmaras
Chief Executive Officer
Issue 31 – October 2014
OilVoice
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Welcome to the 31st edition of the
OilVoice Magazine.
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This month we have great articles from
Bond Dickinson, and Oil & Gas
Investments Bulletin. We'd also like to
welcome back some of our regular
authors, including Gail Tverbeg, David
Bamford, and Euan Mearns.
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James Allen
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OilVoice Magazine | OCTOBER 2014
Contents
Featured Authors
The biographies of this months featured authors
3
Low oil prices: Sign of a debt bubble collapse, leading to the end of oil
supply?
by Gail Tverberg
5
Recognizing the golden age of Texas oil and gas while we're in it
by David Blackmon
Big Data is a solution looking for an Upstream problem
by David Bamford
Enbridge's end run points to Keystone protests' futility
by Loren Steffy
The Importance of Public Image to the Petroleum Industry
by Angus Warren
Don't squash my tomatoes, mind the water melons!
by David Bamford
Yes or no? Implications for the UK Oil & Gas Industry
by Uisdean Vass
How do you spend $35 billion in a town of 13,000 people?
by Keith Schaefer
Big natgas exports to Mexico in 2015 is a pipe dream
by Keith Schaefer
The arguments for and against shale oil and gas developments
by Euan Mearns
How does BP's gross negligence affect the pending criminal cases
against its 'company men'?
by Loren Steffy
17
19
22
23
27
28
33
40
48
55
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OilVoice Magazine | OCTOBER 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.
Angus Warren
Warren Business Consulting
Angus is an oil and gas consultant who brings integrity, creativity and a track
record of getting results to capturing your organization’s opportunities and
resolving its unique issues.
Uisdean Vass
Bond Dickinson
Uisdean is a partner in the Oil & Gas Team. He specialises in upstream oil
and gas, both UK and International, and is also involved in advising on oilfield
service contracting and construction as well as advising financiers on oil and
gas issues arising in finance projects.
David Blackmon
FTI Consulting, Inc.
David Blackmon is managing director of Strategic Communications for FTI
Consulting, based in Houston.
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OilVoice Magazine | OCTOBER 2014
Euan Mearns
Energy Matters
Euan Mearns has B.Sc. and Ph.D. degrees in geology.
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.
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OilVoice Magazine | OCTOBER 2014
Low oil prices: Sign of
a debt bubble collapse,
leading to the end of oil
supply?
Written by Gail Tverberg from Our Finite World
Oil and other commodity prices have recently been dropping. Is this good news, or
bad?
Figure 1. Trend in Commodity Prices since January 2011. Brent spot oil price from
EIA; Australian Coal from World Bank Prink Sheet; Food from UN’s FAO.
I would argue that falling commodity prices are bad news. It likely means that the
debt bubble which has been holding up the world economy for a very long–since
World War II, at least–is failing to expand sufficiently. If the debt bubble collapses,
we will be in huge difficulty.
Many people have the impression that falling oil prices mean that the cost of
production is falling, and thus that the feared “peak oil” is far in the distance. This is
not the correct interpretation, especially when many types of commodities are
decreasing in price at the same time. When prices are set in a world market, the big
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OilVoice Magazine | OCTOBER 2014
issue is affordability. Even if food, oil and coal are close to necessities, consumers
can’t pay more than they can afford.
A person can tell from Figure 1 that since the first part of 2011, the prices of Brent
oil, Australian coal, and food have been trending downward. This drop in prices
continues into September. For example, as I write this, Brent oil price is $97.70,
while the average price for the latest month shown (August) is $105.27. It is this
steeper, recent drop, which many are concerned about.
We are dealing with several confusing issues. Let me try to explain some of them.
Issue #1: Over the short term, commodity prices don’t reflect the cost of
extraction; they reflect what buyers can afford.
Oil prices are set on a worldwide basis. The cost of extraction varies around the
world. So it is clear that oil prices will not match the cost of extraction, or the cost of
extraction plus a reasonable profit, for any particular producer.
If oil prices drop, there is a temptation to believe that this is because the cost of
production has dropped. Over a long enough period, a drop in the cost of production
might be expected to lead to lower oil prices. But we know that many oil producers
are finding current oil prices too low. For example, the Wall Street Journal recently
reported, “Royal Dutch Shell CEO: Can’t deny returns are too low. Ben van Beurden
prepared to shrink company in order to boost returns, profitability.” I wrote about this
issue in my post, Beginning of the End? Oil Companies Cut Back on Spending.
In the short term, low prices are likely to signal that less of the commodity can be
sold on the world market. Commodities such as oil and food are very desirable
products. Why would less be needed? The issue, unfortunately, is affordability.
Affordability depends largely on (1) wages and (2) debt. Wages tend to be fairly
stable. The likely culprit, if affordability is leading to lower demand for desirable
products like oil and food, is less growth in debt.
Issue #2: Economic growth tends to produce a debt bubble.
Many economists believe that technological innovation is the key to economic
growth. In my view, economies need a combination of the following to have
economic growth of the type experienced in the last 100 years:1
(Increase in debt) + (cheap-to-extract fossil fuels) + (cheap-to-use non-fossil fuel
resources) + (technological innovation)
In such a case, debt keeps increasing as an economy grows. Unfortunately, this
economic growth is only temporary, because resources tend to become more
expensive to use over time, making the “cheap” resources required for economic
growth disappear.
The problem underlying the rising cost of resources (both for fossil fuels and others)
is that we tend to use the cheapest-to-extract resources first. Technological
innovation continues to occur, but as diminishing returns hit both fossil fuels and
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OilVoice Magazine | OCTOBER 2014
other resources, there are larger and larger demands on technology to keep costs in
line with what workers can afford. Eventually, the cost of resources (net of
technological improvements) rises too much, and economic growth is cut off. By this
time, a huge mountain of debt has been built up.
Let me explain further how this happens. Without fossil fuels, the world is pretty
much stuck with the goods that can be made with wood, or from other basic
resources such as animal skins, cotton, flax, or clay. A small quantity of metal and
glass goods can be made, but deforestation quickly becomes a problem if an attempt
is made to “scale up” the quantity of goods that require heat in their production.2
Once inexpensive coal became available, its availability opened the door to
technological innovation, because it provided heat in quantity that had not been
available previously. While ideas such as the steam engine had been around for a
long time, the availability of inexpensive coal made the production of metals needed
for the steam engine, plus train tracks and railroad cars, available at reasonable
cost.
With the ability to make steel and concrete in quantity (both requiring heat) came the
ability to make hydroelectric dams and electrical transmission lines, thus enabling
electricity for public consumption. Oil, as a liquid fuel, paved the way for widespread
use of additional innovations, such as private passenger automobiles, mechanized
farm equipment, and airplanes. Between coal and oil, many workers could leave
farming and begin jobs in other sectors of the economy.
The transformation that took place was huge: from wooden tools and human or
animal labor to a modern industrial society. How could such a big change take
place? Before the change, the ability to generate a profit that might be used for
future capital investment was very limited. Also, the would-be purchasers of products
made in an industrial economy were very poor. I would argue that the only way of
bridging this gap was debt. See my earlier posts, Why Malthus Got His Forecast
Wrong and The United States’ 65-Year Debt Bubble.
The use of debt has several advantages:
1. It allows the consumer to buy the end product made with the new resources,
assuming the end product isn’t too expensive relative to the consumer’s
earnings.
2. It gives resource-extracting businesses the money they need to buy
equipment and to hire workers, prior to the time they have earned profits from
resource extraction.
3. It gives the companies the ability to build factories, before they have
accumulated profits to pay for the factories.
4. It allows governments to fund needed infrastructure, such as roads and
bridges, before having the tax revenue available to pay for such infrastructure.
5. Most importantly, the “demand” generated by (1), (2), (3) and (4) raises the
price of resources sufficiently that it makes it profitable for companies in the
business to extract those resources.
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OilVoice Magazine | OCTOBER 2014
Because of these issues, debt and cheap fossil fuels have a symbiotic relationship.
(1) The combination of debt, inexpensive fossil fuels, and inexpensive resources of
other kinds allows the production of affordable goods that raise the standard of living
of those using them. The result is what we think of as “economic growth.”
(2) The economic growth provides the additional income needed to pay back the
debt with interest. The way this happens is indirectly, through what is sometimes
described as “greater productivity of workers.” This greater productivity is really
human productivity enhanced with devices made possible by fossil fuels, such as
sewing machines, electric milking machines, and computers that allow workers to
become more productive. Indirectly, the higher productivity of workers benefits both
businesses and governments, through higher sales of goods to consumers and
through higher taxes. In this way, businesses and governments can also repay debt
with interest.
Higher-priced resources are a problem. Higher-priced resources of any kind tend to
“gum up the works” of this payback cycle. Higher-priced oil in particular is a problem.
In the United States, when oil prices rise above about $40 or $50 barrel, growth in
wages stops.
Figure 2. Average wages in 2012$ compared to Brent oil price, also in 2012$.
Average wages are total wages based on BEA data adjusted by the CPI-Urban,
divided total population. Thus, they reflect changes in the proportion of population
employed as well as wage levels.
With higher oil prices, the rise in the standard of living stops for most workers, and
good-paying jobs become difficult to find. There are a couple of reasons we would
expect wages to stagnate with higher oil prices:
(1) Competition with cheaper energy sources. When oil prices rose, countries using
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OilVoice Magazine | OCTOBER 2014
a very high percentage of oil in their energy mix (such as the PIIGS in Europe,
Japan, and United States) became less competitive in the world economy. They
tended to fall behind China and India, countries that use much more coal (which is
cheaper) in their energy mix.
Figure 3. Average percent growth in real GDP between 2005 and 2011, based on
USDA GDP data in 2005 US$.
(2) Need to keep the price of goods flat. Businesses need to keep the total price of
their products close to “flat” despite rising oil prices, if they are to continue to sell as
much of their product after the oil price increase as previously. Oil is one major cost
of production; wages are another. An obvious way to offset rising oil prices is to
reduce wages. This can be done in several ways: outsourcing work to a lower cost
country, greater automation, or caps on wages. Any of these approaches will tend to
produce the flattening in wages observed in Figure 2.
Based on Figure 2, an oil price above $40 or $50 per barrel seems to put a cap on
wages, and indirectly leads to much less economic growth. Even if we didn’t hit this
oil price limit–for example, if we had discovered a liquid fuel that could be produced
in quantity for less than $40 barrel–we would eventually hit some kind of growth limit.
For example, the limit might be climate change or too much population for food
production capability. Even too much debt can be a limit, if citizens’ incomes don’t
rise in a corresponding manner. At some point, it becomes impossible even to make
interest payments if the debt level is too high. Indirectly, citizens wages even support
business and government debt, because business revenues and tax revenues
depend indirectly on wages.
Issue #3: Repaying debt is very difficult in a flat or declining economy.
Once growth stops (or slows down too much), the debt bubble tends to crash,
because it is much more difficult to repay debt with interest in a shrinking economy
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OilVoice Magazine | OCTOBER 2014
than in a growing one.
Figure 4. Repaying loans is easy in a growing economy, but much more difficult in a
shrinking economy.
The government can hide this issue for a very long time by rolling over old debt with
new debt and by reducing interest rates to practically zero. At some point, however,
the system seems certain to fail.
Not all debt is equivalent. Debt that simply blows bubbles in stock market prices has
little impact on commodity prices. In order to keep commodity prices high enough for
producers to want to continue to produce them, the debt really has to get back into
the hands of the potential buyers of the commodities.
Also, any changes that tend to reduce world trade push the world economy toward
contraction, and make it harder to repay debt with interest. Thus, sanctions against
Russia, and Russia’s sanctions against the US and Europe, tend to push the world
toward debt collapse more quickly.
Issue #4: Rising oil and other commodity prices are a problem, especially for
countries that are importers of those commodities.
Most of us are already aware of this issue. If oil prices rise, or if food prices rise, our
salaries do not rise by a corresponding amount. We end up cutting back on
discretionary purchases. This cutback in discretionary purchases leads to layoffs in
these sectors. We end up with the scenario we had in the 2007-2009 recession:
falling home prices (since higher-priced homes are discretionary purchases), failing
banks, and many without jobs. See my article Oil Supply Limits and the Continuing
Financial Crisis.
The reason that low oil and other commodity prices are welcomed by many people
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OilVoice Magazine | OCTOBER 2014
now is because the opposite–high oil and other commodity prices–are so terrible.
Issue #5: Falling oil and other commodity prices are a problem, if the cost of
production is not dropping correspondingly.
If commodity prices drop for any reason–even if it is because a debt bubble is
popping–it is going to affect how much companies are willing to produce. There is
going to be a tendency to cut back in new production. If prices drop too far, it is even
possible that some companies will leave the market altogether.
Even if it doesn’t look like a country “needs” the current high oil price, there may still
be a problem. Oil exporters depend on the high taxes that they are able to obtain
when oil prices are high. If they cannot collect these taxes, they may need to cut
back on programs such as food subsidies and new desalination plants. Without
these programs, civil disorder may lead to cutbacks in oil production.
Issue #6: The growth in oil sales to China and to other emerging markets has
been fueled by debt growth. This debt growth now seems to be stalling.
Growth in oil consumption has mostly been outside of the United States, the
European Union, and Japan, in the recent past. China and other emerging market
countries kept demand for oil high.
Figure 5. Oil consumption by part of the world updated through 2013, based on BP
Statistical Review of World Energy 2014 data.
Ambrose Evans-Pritchard reports, China’s terrifying debt ratios poised to breeze past
US levels. He shows the following chart of China’s growth in debt from all sources,
including shadow banking:
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OilVoice Magazine | OCTOBER 2014
Figure 6. China’s total debt, based on chart displayed in Ambrose Evans-Pritchard
article.
This rise in debt now seems to be slowing, based on a Wall Street Journal report. A
person wonders whether this stalling debt growth is affecting world oil and other
commodity prices.
Figure 7. Figure from WSJ article PBOC Struggles as Chinese Borrowers Hold
Back.
Other emerging markets also seem to be experiencing cutbacks. Since 2008, the
United States, Europe, and Japan have had very easy money policies. Some of the
money available at low interest rates was invested in emerging markets. Now the
WSJ reports, Fed Dims Emerging Markets’ Allure. According to the article investors,
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OilVoice Magazine | OCTOBER 2014
investors are taking a more cautious stance on new investment because of fear of
rising US interest rates.
Of course, other issues affect debt and world commodity demand as well. If interest
rates rise, they many have a tendency to shrink new lending, in general, because
loans become less affordable. Sanctions of one country against another, such as the
US against Russia, and vice versa, also tend to reduce demand.
Issue #7: Debt bubbles have been a problem in past collapses.
According to Jesse Colombo, the Depression was to a significant result the result of
debt bubbles that built up during the roaring twenties. Another, longer-term cause
would seem to be the loss of farm jobs that occurred when coal allowed tasks that
were previously done by farm workers to be done by either electricity or by horses
pulling metal plows. The combination of a debt bubble and loss of jobs seems to
have parallels to our current situation.
Many believe the subprime housing bubble crash contributed to the Great
Recession. The oil price spike of 2007 and 2008 played a major role as well.
Issue #8: If we are facing the collapse of a debt bubble, it is quite possible that
prices of many commodities will fall. This could possibly lead to a collapse in
the supply of many types of energy products, more or less simultaneously.
Figure 8, shown below, is a very rough estimate of the kind of decline in energy use
we could be facing if a debt collapse leads to very low prices of many types of fuels
simultaneously. Prices of many commodities crashed in 2008, and it was only with
massive intervention that prices were propped up to 2011 levels. After the beginning
of 2011, prices began sinking again, as shown in Figure 1.
Figure 8. Estimate of future energy production by author. Historical data based on
BP adjusted to IEA groupings.
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OilVoice Magazine | OCTOBER 2014
Clearly governments will try to prevent another sharp crash in commodity prices. The
question is whether they will be successful in propping up commodity prices, and for
how long they will be successful. In a finite world, fossil fuel energy production
eventually must decline, but we don’t know over precisely what timeframe.
Issue #9: My steep decline contrasts with the “best case” forecast of future oil
consumption given by M. King Hubbert.
M. King Hubbert wrote about a scenario where another type of fuel completely takes
over, before oil and other fossil fuels are phased out. He even discusses the
possibility of making liquid fuels using very cheap nuclear energy. The way he
represents the situation is the following:
Figure 9. Figure from Hubbert’s 1956 paper, Nuclear Energy and the Fossil Fuels.
In such a scenario, it is possible that oil supply will begin to decline when
approximately 50% of resources are exhausted, and the down slope of the curve will
follow a symmetric “Hubbert curve.” This situation seems to represent a best
possible case; it doesn’t seem to represent the case we are facing today. If a debt
collapse occurs, much of the remaining fuel is likely to stay in the ground.
Issue #10: Our economy is a networked system. Increasing debt is what keeps
the economy inflated. If wages fail to keep pace with debt growth, the system
seems likely to eventually crash.
In previous posts, I have represented the economy as a self-organized networked
system, consisting of businesses, consumers, governments (with laws, regulations,
and taxes), financial system, and international trade.
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OilVoice Magazine | OCTOBER 2014
Figure 10. Dome constructed using Leonardo Sticks
One reason the economy is represented as hollow is because the economy loses its
capability to make goods that are no longer needed–such as buggy whips and rotary
dial phones. Another reason why it might be represented as hollow is because debt
is used to “puff it up” to its current size. Once the amount of debt starts shrinking, it
makes it very difficult for the economy to maintain its stability.
Many “peak oilers” believe that if we have a problem with the financial system, all we
have to do is start over with a new one–perhaps without debt. Everything I can see
says that debt is an essential part of the current system. We could not extract fossil
fuels in any significant quantity, without an ever-rising quantity of debt. The problem
we are encountering now is that once resource costs get too high, the debt-based
system no longer works. A new debt-based financial system likely won’t work any
better than the old one.
If we try to build a new system without fossil fuels, we will be really starting over,
because even today’s “renewables” are part of the fossil fuel system.3 We will have
to go back to things that can be made directly from wood and other natural products
without large amounts of heat, to have truly renewable resources.
Notes:
[1] This is really a simplification of the real issues. As world population grows, it is
necessary to obtain an increasing amount of food from the same arable land. Thus, it
is necessary to find new processes to increase food production, at the same time
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OilVoice Magazine | OCTOBER 2014
that soil is quite possibly degrading. Soil is in a sense a “resource other than fossil
fuels,” but I have not mentioned this issue specifically.
Growing pollution problems are in some sense an indirect cost of extracting fossil
fuels and other resources. These represent another growing cost that I have not
specifically identified. Furthermore, there are indirect expenses that do not fit neatly
into any category, such as required desalination plants to handle growing
populations in areas where water is scarce. We may need to consider mitigation
expenses of all types as part of the “cost of resource extraction.”
My point is that it becomes increasingly difficult to offset these many cost increases
with technological innovations. Furthermore, if no changes are made, a larger and
larger share of both the workforce and resources are required for maintaining the
status quo, leaving fewer workers and a smaller quantity of resources to “grow” the
economy.
[2] Wind and water are additional sources of energy, but they are sources of
mechanical energy, not heat energy, so are not helpful unless they can be converted
first to electricity, and then to heat. In quantity, they never were very large in prefossil fuel days.
Figure 11. Annual energy consumption per head (megajoules) in England and
Wales 1561-70 to 1850-9 and in Italy 1861-70. Figure by Tony Wrigley from Opening
Pandora’s Box. Figure originally from Energy and the English Industrial Revolution,
also by Tony Wrigley.
[3] Of course, any existing “renewable” will continue to work until it needs repairs that
are unavailable. Other parts of the system (such as electric transmission lines,
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OilVoice Magazine | OCTOBER 2014
batteries, inverters, and attached devices such as pumps) may fail more quickly than
the renewables themselves.
View more quality content from
Our Finite World
Recognizing the golden
age of Texas oil and gas
while we're in it
Written by David Blackmon from FTI Consulting, Inc.
James Lebas, former chief revenue estimator for the Texas Comptroller’s office,
made news recently when he told the state’s House Committee on Energy
Resources that, working with the Comptroller’s office, he had determined that output
from the oil and natural gas industry now accounts for fully one-third of the entire
Texas economy. Given that the Texas economy would rank 12th among all nations
on earth, that’s an amazing amount of economic activity for one industry to provide.
Yet, it should not surprise anyone who has really been paying attention to the
phenomenal boom the industry has undergone in Texas since 2010. As Lebas, who
now works as a tax and fiscal consultant in Austin, told me when I spoke with him
last week, “It’s best to recognize you are in a golden age while you’re in it.”
Or, as he told the Energy Resources Committee, “When people look back at this in
20 years, this will be seen as part of the golden age. We have reached new highs, it
is paying handsome dividends to the state and the state is doing very well. We’ve
gone from one million barrels a day to three million, and the day may come when we
eclipse the all-time record set in 1972.”
The story of this Golden Age gets even better when one looks at where a ‘Nation of
Texas’ would rank when it comes to oil and gas production: Texas would rank as the
8th largest oil producing nation and the 3rd largest natural gas producing nation on
earth. Granted, Texas is a big ‘ol state, but still, that kind of natural resource
production is pretty amazing from any perspective.
The most recent Federal Bureau of Labor Statistics data indicates that, while the
nation’s economy continued to struggle over the last year, Texas was adding more
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OilVoice Magazine | OCTOBER 2014
than 1,000 net new jobs every day, more than 390,000 for the most recent 12 month
period. By contrast, California, which has highly restricted the growth of its own
energy production, has added just 322,000 net new jobs in the last five years
combined. The state’s unemployment rate of 5.1 percent was a full point below the
national average. Indeed, a recent report from Bernard Weinstein, Associate Director
at the Maguire Energy Institute at SMU showed that Texas has accounted for fully
35% of the nation’s job growth since the year 2000.
Lebas pointed out to the Energy Resources Committee that jobs in the oil and gas
production sector rose above the 400,000 level last year for the first time, at an
average wage ($125,000) that is three times the state average. Tax collections from
the industry via the sales and production taxes exceeded $13 billion during 2013,
and will be even higher this year.
Oil and gas development also helps to create jobs in other industries. The advent of
massive new reserves of affordable domestic natural gas has in recent years led to a
nascent manufacturing renaissance in the U.S. Industries that use natural gas as a
feedstock – fertilizers, chemicals, clothing, plastics, steel, and many others – have
begun to invest tens of billions in new plant and equipment here in the U.S., creating
domestic jobs that had been sent overseas over the last quarter century.
For the state’s government, this Golden Age in oil and gas has also led to a bit of a
Golden Age in the state’s fiscal situation. Prior to the boom’s beginnings in 2010,
Texas state government had been in a state of chronic budgetary shortfalls for about
a decade. In fact, when the legislature convened in January 2009, that shortfall was
estimated to be as high as $25 billion for the following 2 year budget cycle. In 2007,
the legislature and Governor had to figure out how to close about a $10 billion
shortfall.
When the legislature convenes in January of 2015, Lebas estimates that it will enjoy
a budgetary surplus in the vicinity of $7 billion. In addition to that, Lebas agrees with
the Comptroller’s estimate that the state’s Rainy Day Fund will have a balance of
about $8.4 billion, and that is assuming that Texas voters approve a ballot initiative in
November that would allocate about $1.7 billion in Rainy Day Fund money to the
Texas Department of Transportation to help pay for road improvements and repairs.
Guess how the Rainy Day Fund is funded: via severance taxes levied on oil and
natural gas.
So the challenge for the 2015 legislature won’t be how to close a multi-billion dollar
budget shortfall; instead, it will be how not to squander a gigantic budget surplus.
Given all of this, one might think that Texans everywhere would be thanking the oil
and gas industry for its role in creating such a dramatic turnaround in the state’s
fiscal fortunes. And for the most part, that thought would be right – the vast majority
of Texans do appreciate the myriad ways this great industry benefits our state.
But there will always be those who oppose oil and gas development in this state –
and everywhere else – for a variety of reasons, whether real or imagined. Antidevelopment agitator groups have long been active in the Barnett Shale region of
North Texas, and are becoming increasingly active in other parts of Texas.
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OilVoice Magazine | OCTOBER 2014
When I brought that all up to him, Lebas drew this analogy: “Opposing the oil and
gas industry in Texas is like booing Santa Claus at the Christmas parade.”
True story. Sure wish I’d have thought of that.
God Bless Texas.
View more quality content from
FTI Consulting, Inc.
Big Data is a solution
looking for an
Upstream problem
Written by David Bamford from PetroMall
According to my friend Neil McNaughton at OilIT, annual Upstream spend on IT may
reach as much as $60bn by 2016.
And if you were to believe everything you read, “Big Data” is going to swallow a big
part of that, with even Aberdonian academics getting in on the act!
After all, the argument goes, hasn’t Big Data transformed the retail business (forgive
me, I thought that was more likely to be Lidl, Aldi, Poundland, Matalan!); and
allegedly the financial sector, perhaps even for the better? Though on reflection,
probably not for the better in the latter’s case!
So the Big Data cognoscenti are suggesting that transformation of the oil & gas
industry into a stunningly efficient and effective ‘new look’ requires, needs, even
depends on, the adoption of Big Data technologies, practices and attitudes. It’s our
turn!
However, before diving in head-first and investing lots of $s in Big Data technologies,
oil and gas companies might benefit from working out what they are trying to
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OilVoice Magazine | OCTOBER 2014
achieve. What is the problem they are actually trying to solve?
Is it finding more petroleum? Producing more from existing reserves? Accelerating
developments? Cutting costs? Keeping CIOs employed? What is it?
It is true that we nowadays have available a myriad of different data types and can
very easily feel as though we are stood beneath Niagara Falls trying to catch water
in a tin cup!
Assuming we can integrate all these multi-measurements – and that is a big
assumption itself – perhaps we need to move our subsurface analysis and
interpretation beyond the LCD provided by IT-department approved, commercially
available, work stations?
Personally, I have always believed that the best insights are found when everybody
– for example, geologists, geophysicists, petrophysicsts, reservoir engineers,
commercial folk – are looking at the same thing, and working on the problem at hand
as a team. This is a particularly effective way of recognising and thus managing risk
and uncertainty, spotting the data which is really relevant to the solution of the
problem, rather than using everything just because it exists.
Thus digital technology needs to allow petro-technical professionals to not only
access, process, analyse, and interpret sub-surface datasets within a single desktop
visualization context, but also then to collaborate across locations through the
sharing of both data and in-progress interpretations that can be confirmed or
challenged by their colleagues, typically in a large-screen visualisation environment.
This is a “step beyond” – perhaps several steps – many current digital technologies
which seem rooted in the ‘paper’ history of seismic, well logs……light tables!
View more quality content from
PetroMall
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OilVoice Magazine | OCTOBER 2014
Enbridge's end run
points to Keystone
protests' futility
Written by Loren Steffy from 30 Point Strategies
One of the biggest flaws in environmentalists’ strategy of attacking the Keystone
Pipeline has been the assumption that if the pipeline isn’t built, global warming will
be reduced somehow. That, as I’ve explained before, isn’t likely to happen. But it’s
also becoming increasingly clear that blocking the pipeline won’t even stop the flow
of heavy crude from the Canadian oil sand to the U.S.
We’ve already seen an increase in rail shipments of crude oil, a trend that shows
little sign of abating. Now, the Canadian pipeline company Enbridge says it found a
way to avoid the border crossing brouhaha that has delayed Keystone construction
for years.
Building a new pipeline across the U.S.-Canadian border requires approval from the
U.S. State Department, which is where environmental groups have applied much of
their lobbying effort on the Keystone project, proposed by TransCanada. As a result,
the Obama administration has left the project in limbo and is unlikely to take it up
before the mid-term elections.
Enbridge has a similar proposal pending that would expand its Alberta Clipper line.
Instead of waiting, the company said it plans to build a link to an adjacent pipeline,
known as Line 3, which already crosses the border. Enbridge will move the oil from
the Alberta Clipper to Line 3 about a mile and half north of the border, send it into the
U.S., then transfer it back to the main line at another interconnect about 16 miles into
the U.S.
Because the only new construction is the link in Canada, and Line 3 already has
permission to bring oil into the country, no additional approvals are needed.
It isn’t a permanent solution. Enbridge wants to almost double the capacity of the
Alberta Clipper to 880,000 barrels a day, but the move would provide a temporary
increase in capacity for exporting Canadian crude, which has been constrained by a
lack of pipelines.
Environmentalists immediately decried Enbridge’s move, arguing once again that it
would encourage production of Canadian oil sands, for which the extraction process
releases more carbon than conventional oil drilling.
But the problem with the Keystone fight from the beginning is that it’s an attempt to
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OilVoice Magazine | OCTOBER 2014
choke off supply without addressing demand. Given the discount of Canadian crude
to world market prices, crude from the oil sands is going to find a way to market.
Keystone, at least, would be the most advanced and environmentally sound pipeline
ever built. But the efforts to block its permit have pushed oil into older lines and less
safe transportation methods such as rail.
Both the International Energy Agency and the U.S. Energy Information
Administration predict oil demand globally will continue to rise. Constricting supply of
the cheapest supply of crude in the world isn’t going to stop its production, it’s simply
going to redirect it to other distribution channels. As Enbridge just demonstrated, the
incentives to bring the oil to market are too great to allow supplies to be stranded by
politics.
Far from stopping the flow of oil, the battle over Keystone is creating a far greater
threat to the environment than the pipeline ever would.
View more quality content from
30 Point Strategies
The Importance of
Public Image to the
Petroleum Industry
Written by Angus Warren from Warren Business Consulting
Public attention to the petroleum industry may never have been higher and more
critical than it is today.
The intrusiveness of operations in unconventional plays, the climate change debate,
deepwater operational risk, growing interest in Arctic deposits and the search for
renewables are all hot topics in the news and sources of broad concern to the
general public. This in turn puts pressure on governments and institutions to be more
active than ever in regulating and “managing” the industry.
24
OilVoice Magazine | OCTOBER 2014
So what’s driving public opinion?
Ordinary citizens may have valid concerns. These include community disruption due
to intense operations near populated areas, fears that proprietary chemicals, of
undisclosed composition may contaminate the water table, unmetered emissions
from producing infrastructure may aggravate climate change and a general feeling
that industry does not sincerely address these concerns or take appropriate actions.
Some say that public concerns are simply dismissed by the industry as being
unfounded. Often because the technology and science is difficult to explain to the
layman, industry managers may justifiably wish to avoid getting into the complexities
of geomechanics, inorganic chemistry, geology and completion engineering with
those who probably don’t want to know anyway.
There is also a diverse coalition of ideological and vested interests unlikely to be
swayed by industry-funded studies or glossy PR campaigns, that drives the debate
and this can further impact government policy and public opinion relating to
regulations and permits. This coalition also has a well-organized system to directly
impact government decisions and apply legal challenges.
What should be done, if anything?
One of the advantages of a favourable Industry Public Image would be to defuse any
suspicions held by the general public regarding the ethics and competence with
which these complex activities are being conducted by a seemingly opaque industry.
Other advantages include reducing the regulatory burden trend, increasing the
number of institutions willing to invest in petroleum, thus reducing the cost of capital,
reducing the risk of moratoria on fracking & deepwater drilling, and softening
resistance to new pipelines.
Should individual companies have their own Corporate Social Responsibility plans to
show real change and concern? Some argue that increased expenditure on PubIic
Image without a direct link to additional revenue is unfair to the shareholders and
that management would be shirking its fiduciary responsibility. Others argue that for
capitalism to function well in our society managers have to recognize the company’s
responsibility to all stakeholders:
If the executives and directors of a firm believe that creating shareholder value is the
only legitimate objective for business, they must concentrate on stakeholder
relationships to accomplish the creation of shareholder value. The logic is simple.
The business world today is very complex and there is a great deal of uncertainty. It
consists of interconnected networks of customers, suppliers, communities,
employees, and financiers that are vital to the achievement of business success. The
company that manages for shareholders at the expense of other stakeholders
cannot sustain its performance. A system of economic activity based on such
exclusive attention to shareholders is rife for social activism and regulation in a free
society on behalf of the other stakeholders. [Chicago-Kent Law review]
In fact The Economist states that there are often examples of win-win investments
that can be made which improve the public image and display sound Corporate
Social Responsibility. An example of such a win-win investment is given by an ICF
25
OilVoice Magazine | OCTOBER 2014
International study to reduce 19 methane emission sources in the USA resulting in
an estimated $104 Million annual industry savings. To be sure, there are some
caveats to the study but it is very thorough and analytical and could make interesting
reading for those involved in HSE and production operations.
Or should there be some kind of industry wide self-regulation as demonstrated by
the Chemical Manufacturing Association which enabled that industry to have a
bigger say in the design and implementation of the regulatory regime? A move in this
direction appears to have occurred recently in Colorado where some major
producers collaborated with state authorities and the Environmental Defense Fund to
develop regulations to reduce air pollution by eliminating gas leaks. These
regulations would apply not only to themselves but to the industry as a whole in
Colorado.
This might be an interesting bellwether for other areas of the industry because
alignment of all operators towards a common concept of the importance of Public
Image is likely to be difficult to achieve and the lead may need to be taken by some
farsighted, key players to wisely reduce the risk of ill-conceived regulation and overzealous activism while improving their own long term valuations.
View more quality content from
Warren Business Consulting
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OilVoice Magazine | OCTOBER 2014
Don't squash my
tomatoes, mind the
water melons!
Written by David Bamford from PetroMall
Many years ago, in the late 1970's, when I was young and naïve, and still an
academic, I moved to Germany to work on an EU-funded Geothermal Energy
project. We studied the Urach geothermal anomaly in southern Germany and
another one which was more or less under the Ardennes on the north-western
borders of Germany with Belgium. It all went reasonably well until one day we
pitched up at the appropriate committee of the EU in Brussels to ask for some more
money for the Ardennes work. We described the geothermal energy as relatively 'low
grade' and (I think) offered the view that it was probably suitable for running
greenhouse-based market gardening.
At this point the Italian representative on the committee vetoed our request on the
grounds that this would provide unwanted competition for the tomato-growing
industry in his part of Italy. He was, as I recall, a geologist!
I think of this day in my earlier life from time to time, for reasons which I will explain
in my final paragraph, but I was reminded of it just the other day when a BBC radio
correspondent was talking about the EU's response to one of the current geopolitical crises, in particular its manifest lack of strategy, and commented that the EU
does not in fact have strategies, it just balances competing and conflicting national
interests.
Ho hum!
I said in my last article bemoaning the lack of an EU Energy Strategy 'I know
everything happens for a reason, I just wish I knew what that reason was!' Actually, I
think I 'knew' the reason already but it was hidden away.
Here are a few suggestions for the EU Commission to pursue:
1. Encourage the UK and Norway respectively to realise the full potential of the
UKCS and NOCS for exploration, exploitation of existing discoveries, and increasing
recovery factors of existing fields to north of 60% (for oil).
2. Encourage exploration in the 'European' northern Mediterranean.
3. Encourage the exploitation of unconventional oil and gas, for example in France
(the Paris
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OilVoice Magazine | OCTOBER 2014
Basin), Northern Germany, the UK, Poland etc.
4. Pursue Carbon Capture & Storage with vigour so that we can use more coal.
I bet the 'water melons'* try to make sure none of this ever happens!
Finally, I should say that the 'day of the tomatoes' did have a profound effect on my
life because I realised that I was probably better off working for a company than
having anything at all to do with government funding. And looking at the wreckage of
geoscience left behind in the UK from the mid-1990s onwards - decimation of MSc
courses, bias towards 'environmentally correct' research - I have no doubt I was
right.
*Politicians who are green on the outside, red on the inside!
View more quality content from
PetroMall
Yes or no?
Implications for the
UK Oil & Gas Industry
Written by Uisdean Vass from Bond Dickinson
After one of the longest political campaigns in British political history, the end is in
sight.
On 18 September, 2014, the Scottish people will vote on whether Scotland should
leave the union and become an independent country.
A “yes” vote would have enormous strategic, political and economic implications in
the UK and will have effects beyond its borders. One of the sectors that would
potentially feel the greatest effects, however, is the oil & gas industry.
Let us assume that there is a Yes vote on 18 September. What then happens is that
the Scottish and UK Governments will negotiate the terms of Scottish independence.
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OilVoice Magazine | OCTOBER 2014
The Scottish Government targets independence by March 2016.
Policy of Scottish Government
The Scottish Government has understandably taken a lively interest in the UK Oil
and Gas business and has set forth its policy approach in a paper entitled
“Maximising the Return from Oil and Gas in an Independent Scotland, July 2013”
(Scotland 1).
Like the UK Government, the Scottish Government has endorsed the proposals of
the Wood Review. Most recently (July 2014) the Scottish Government’s Independent
Expert Commission on Oil & Gas came out with its detailed report entitled
“Maximising the Total Value Added” (Scotland 2)which endorsed and indeed
amplified Wood. We therefore have a fairly clear idea of the approach the Scottish
Government would take towards the Oil and Gas Sector.
Delineation of Scottish Continental Shelf (SCS)
The biggest petroleum issue will be the delineation of the SCS, and this raises three
separate areas of negotiation, which might be called East, North and West. Most
producing North Sea oilfields are in the Central and Northern North Sea to the east
of Scotland. Off the South East of England, there is the old producing Southern Gas
Basin which will clearly lie in the Remaining United Kingdom (RUK). On the Eastern
side the current United Kingdom Continental Shelf (UKCS) is bounded by welldefined Dutch, German, Danish and Norwegian sectors. How will this large
continental shelf area be carved up?
If Scotland and RUK were separate countries, then International law would apply.
The primary rule in such situations is that the littoral states should resolve the
delineation issue by negotiation. But what if this proves too challenging?
Without entering into a long legal analysis, the basic rule is one of equidistance
tempered by special factors. By analogy (because Scotland will not be a sovereign
state during the negotiations) these rules can be applied to establish the SCS in this
30
OilVoice Magazine | OCTOBER 2014
case. There is however also guidance closer to home. The Scottish Area (Civil and
Criminal) Jurisdiction Order 1987 provides that Scots law applies to installations
located north of a horizontal line (see diagram) (“1987 Line”) extending due east of
the border town of Berwick -on- Tweed. If adopted as the southern frontier of the
SCS, this would give over to Scotland every producing oilfield in the Central North
Sea. While the 1987 Line is not a resource line, all of the oilfields north of it are
serviced from Aberdeen, which might count as a special factor.
As an alternative, another line drawn by the Scottish Adjacent Waters Boundary
Order 1999 (“1999 Line”) (see diagram) is the present southern boundary (on the
east side) of the Scottish maritime and fisheries jurisdiction. The Scottish
Government presently has responsibility for this. This is a resource line which is also
a median line. Median lines are also equidistance lines. While there are some old
producing fields south of the 1999 Line and north of the 1987 Line (Uncertain Area),
their economic value is not of huge importance. We would suggest that it is unlikely
that the continental shelf on the eastern side will move north of the 1999 line.
To the North the UKCS has clearly defined northern frontiers with Norway and
Faroes (autonomous Danish). In this northern area lie the Orkney and Shetland
Islands (Northern Islands) which Scotland acquired from the Kingdom of Denmark in
1470. These Northern Islands will, like the rest of Scotland, vote in the referendum
on 18 September. However, because culturally and ancestrally the Northern Islands
have close ties with Scandinavia, some have suggested that in the event of a strong
“No” in the Northern Islands as against an overall Scottish “Yes”, the Northern
Islanders might wish to seek further autonomy within Scotland, or stay with RUK or
even declare independence.
The unlikely option of the Northern Islanders’ independence would heavily impact on
the area of the SCS. Staying with RUK might be problematic for the Northern
Islanders as British island groups such as Man and Channel Islands have only a
territorial sea of twelve nautical miles.
However, in recognition of the Northern Islands’ special place and importance to the
Scottish independence case, the Scottish Government has promised further
autonomy to the Northern Isles and Western Isles. Scotland’s likely western
boundary is not thought to be a great issue. Scotland is likely to inherit the UK’s
existing boundary with the Irish Republic.
Given the evidence, the great majority of the UK’s present producing offshore oil
fields will fall into the SCS.
Decommissioning Liabilities and Tax
The great oilfields of the Central and Northern North Sea were largely discovered
and brought on to production in the 1970’s and 80’s. At that time, heavy fixed
structures were used for production. Many of these old fields are facing
decommissioning. Because of the Brent Spar debacle in the mid – 1990’s, Western
Europe has entered into a regional treaty on decommissioning called OSPAR. This
imposes strict rules meaning that all structures must, unless a specific derogation is
granted, be lifted and disposed of on land.
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OilVoice Magazine | OCTOBER 2014
A further point for consideration and to be fully addressed is that petroleum fields
whose development plans were approved before March 1993 are subject to
Petroleum Revenue Tax (PRT) which is Ring-Fenced by field and chargeable at 50%
of gross revenue subject to certain deductions. In addition to PRT, all UK licensees
are subject to Ring-Fenced Corporate Tax (at 30%) and Supplementary Charge (at
32%) unless there is an available field exemption for Supplementary Charge.
The costs of decommissioning will be huge and most decommissioning is yet to take
place. Decommissioning is happening now and will increasingly be a major industry
in its own right. Such massive decommissioning costs need careful tax treatment.
The UK offers no yearly tax relief for sums paid into sinking funds for
decommissioning costs (unlike other jurisdictions). Instead, for purposes of PRT,
decommissioning expenditure (made at the end of field life) can be taken against
profits arising from a field all the way back to first profit. With the other two taxes,
decommissioning expenditure can be taken back against profits going back to a date
in 2002.
The upshot is that the UK Government is currently liable (through tax credits) for a
large share of the cost of decommissioning. The industry regards this UK
Government obligation as a huge asset.
The Scottish Government currently pledges to respect the existing tax structure and
to honour the decommissioning tax credit obligations of the UK Government.
However, given that the great majority of tax revenues from the old fields will have
been spent across the Union (i.e. pre-independence), the Scottish Government will
seek to negotiate a substantial contribution from RUK for credit relating to production
in the UK area.
Other Tax Issues
Ring-Fenced Corporate Tax and Supplementary Charge are ring-fenced as to
upstream profits so profits and losses made in different fields by the same licensee
can be taken together to reduce taxable revenue.
In the event that a new Scottish jurisdiction is formed it may be that profits and
losses become isolated in separate legal systems. This important issue will need to
be clearly dealt with to give business certainty.
In the event that Scotland becomes independent, businesses making money through
activities in Scotland or the SCS will have to form entities or permanent
establishments in Scotland for tax purposes.
Though beyond the scope of this article, companies currently engaging in activities in
Scotland in reliance on UK Tax or Investment Treaties will need to consider the
impact of Scottish independence on those treaties. But to give one example, the
current UK/Norway Tax Treaty has extensive provisions on the oil and gas sectors
as well as related transport and personnel services.
32
OilVoice Magazine | OCTOBER 2014
It should be emphasised that only petroleum licensees (i.e. oil companies) are
subject to the three-fold petroleum tax system described above (PRT/Ring-Fenced
Corporate and Supplementary Charge). Those companies engaged in the storage
and transportation of oil can be subject to Ring-Fence Corporate Tax. All other
companies, including oil service companies, are subject to regular Corporate Tax,
the highest rate of which is currently 21%. The current position of the Scottish
Government is to reduce Corporate Tax rates.
The possibility remains therefore that oil service companies in Scotland may benefit
from a lower tax burden in an independent Scotland. The Scottish Government
proposes to keep personal Income Tax at broadly current levels. Unionist critics are
sceptical.
A Scottish Petroleum Jurisdiction
The approach of the Scottish Government to the offshore petroleum regime is very
similar to that taken by the Wood Review. They seek to emphasise tax stability and
tax realism in order to preserve confidence in the SCS. Like the Wood Review,
Scotland 2 emphasises the importance of good stewardship of existing fields.
Scotland 2 looks beyond the Wood Review however in that its overarching goal is to
maximise Total Value Added (TVA) to the Scottish economy. TVA is defined as: (i)
value arising directly from the upstream oil business in wages, profits and taxes; (ii)
value arising from the wages, profits and taxes from the supply chain (service
sector); and (iii) value arising from the extra induced activity of the supply chain in
export markets and other non-oil sectors.
The authors of Scotland 2 are not satisfied that there is as yet a way of properly
calculating TVA. It should be added that Scotland does not envisage using local
content rules to maximise TVA as this would be contrary to EC rules.
The authors of Scotland 2 are in favour of further incentivising new developments by
the use of tax exemptions. However, they favour an exemption system based on
economic factors rather than physical or chemical factors (which now pertains).
The future picture of the SCS would currently appear to be of a closely regulated but
still market-driven petroleum sector incentivised by tax policy, with an emphasis on
stewardship and TVA. Scotland, like the UK, will continue to face the challenge of
how to get successful exploration rates up without affecting tax revenues. The
trajectory of the Wood Review will continue with some further innovative departures.
We must now await the decision of 18 September.
View more quality content from
Bond Dickinson
33
OilVoice Magazine | OCTOBER 2014
How do you spend $35
billion in a town of
13,000 people?
Written by Keith Schaefer from Oil & Gas Investments Bulletin
The LNG (Liquid Natural Gas) countdown is on in Canada. Within weeks, there are
three major catalysts happening that could reshape the entire economy and labour
market of western Canada.
1. The British Columbia government outlines its fiscal regime for LNG
2. The environmental assessment for the Petronas’ LNG facility in Prince Rupert
will be issued
3. The Malaysian national oil company Petronas is widely expected to give a
positive FID–Final Investment Decision–to build North America’s first
greenfield LNG export terminal at Prince Rupert.
I spent three days in Prince Rupert in mid-August to get a first hand look at the
leading sites, and I also drove two hours along the Skeena River over to Kitimat, the
other potential hub, to check out a couple potential sites there as well.
I met with local business people—truckers, barge operators, bankers, town
councillors and real estate developers among many. I visited the community offices
of Petronas and BG Group here, talking to the people there—all just to get an idea of
how these LNG initiatives are viewed in the community, and develop some
relationships I can call on, as the promise of these multi-billion dollar spends turn into
reality.
As a quick background there are at least 14 proposals to export LNG off Canada’s
west coast, and another one to export Canadian gas down to Oregon and ship it to
Asia from there. (You can review them
here:http://www.pipelinenewsnorth.ca/news/industry-news/b-c-s-15-lng-projectswhere-they-stand-today-1.1122622 )
If they all get built, they would export more than the entire 13 billion cubic feet per
day (bcf/d) that all of Canada produces today! Nobody expects that, but 10 years
from now it is conceivable that 5 bcf/d could be leaving Canadian soil.
What could this mean for the economy? Consider that it costs roughly $7.5 billion to
build 1bcf/d of export capacity for aland based terminal. That huge cost is why there
is increasing talk of using smaller, Floating LNG ships that would be built in Asia and
towed over to Canada’s west coast.
34
OilVoice Magazine | OCTOBER 2014
I can’t think of another town in North America—certainly in Canada—that has the
“optionality” of the Prince Rupert area. It’s a town of only 13,000 people, and $15
billion could get spent here in the coming 7 years. It’s actually on an island, but only
by a normal sized bridge you would see on a highway overpass.
The town was founded in 1910 but really only grew after the American army built
hundreds of homes in 1942, and built the road that first connected Prince Rupert to
the rest of Canada—all in the name of getting US troops and armaments to Alaska to
fight the widely expected Japanese naval invasion (which never came).
The two main industries of yore—fishing and forestry—have fallen on hard times.
The town was re-invigorated in the early 2000s with a new deep port—one of the
most modern and efficient in the world. It’s a direct ship-to-rail facility that can have a
full train leaving for Chicago or Memphis—where 80% of the port of Prince Rupert’s
cargo goes—in one day and be in those cities 96 hours after that.
There is a lot of room for expansion at the port. It’s deep and it has lots of protected
coastline.
But the town doesn’t appear to be that excited about LNG just yet—and that is
probably a good thing. A common—almost universal—comment from people was
that the townsfolk are used to big companies promising prosperity, and not delivering
anything.
Despite a shiny new port, the town’s infrastructure is in quite a state of disrepair.
While housing prices and rents are up recently, they don’t compare to the jump that
nearby Terrace BC (90 minutes east) has had, or Kitimat (another 30 minutes south).
Kitimat is where Rio Tinto, formerly Alcan, has its big aluminum smelter. Built in 1954
in a way that could never happen today—two tunnels through a mountain, moving
streams, etc—the entire complex is just completing a huge multi-billion dollar
refurbishment, and has kept that local economy strong.
The local council in Rupert is also heavily weighted to the political left, with the online
resumes of councilors saying how they want to be the guardians for the environment
against industry. Yet surprisingly, nobody sees development or LNG as a critical
issue for the municipal elections coming this November. The City of Prince Rupert
has become active in the LNG game, trying to re-purpose Watson Island, where an
old pulp mill sits, into an LNG site.
One morning I took an hour long helicopter ride around Prince Rupert to see all the
major proposed LNG sites—Grassy Point to the north, and Ridley Island and Lelu
Island to the south. It gave me great perspective on topography and potential
logistics.
35
OilVoice Magazine | OCTOBER 2014
I started up towards Grassy Point, which is the edge of the mainland about 15 miles
north of Prince Rupert. The only road access is via a barge across an inlet onto First
Nations land. As you fly close to Grassy Point, you can’t help but notice a very large,
round and tall (50 metres?) hill that the proponents will have to drill, detonate and
clear away.
I’m not 100% clear yet why the proposed pipelines are coming through what the inlet
near Grassy Point, which the locals call the Portland Canal. It must be a lot cheaper
to run these pipelines in the water.
36
OilVoice Magazine | OCTOBER 2014
One of the big logistical challenges for all these facilities will be the very large tides in
the area—sometimes 20 feet or more, compared to 3-4 feet or less on the Gulf
Coast in the USA.
Grassy Point is more exposed to the ocean than the proposed sites near Prince
Rupert, so they will also have to account for the huge rollers that the ocean creates
quite often.
There is a lot of work happening at Grassy Point—at least one survey crew was
down there with a helicopter, and I saw multiple sites where testing of some kind or
another was being done.
One barge operator I had lunch with said he is busy 16 hours a day, 7 days a week.
Labour is already VERY tight in the Rupert-Terrace-Kitimat area; anybody who can
or wants to work is working. For all intents and purposes, unemployment is zero in
that area. And construction of any LNG facility hasn’t even started.
There is tens of millions of dollars in pre-commitment, pre-construction spending this
year in the region. One new restaurant has opened in Prince Rupert. ;-)
The helicopter only took 10 minutes to fly back over the centre of Prince Rupert—
which, when it’s not raining or fogged in, is snuggled beautifully up against the
mountain on Kaien Island. It was a cloudy day, and the pilot dodged the clouds as
moved a couple miles south to where Petronas and BG are planning to have their
sites.
This is Prince Rupert on the north (front) side of Kaien Island. Flying just around the
corner of that hill you would see Ridley Island.
37
OilVoice Magazine | OCTOBER 2014
Downtown Prince Rupert at top, and kitschy Cow Bay right underneath me
38
OilVoice Magazine | OCTOBER 2014
I think the best sites are in the south, despite the fact that right now, the pipelines
look they are going to come in from the north. Two of the largest proposed LNG
facilities—Lelu Island and Ridley Island—are very close to towns.
BG Group has, IMHO, the best site: Ridley Island, whose northern edge is just over
a mile south of town. It’s a flat piece of land—I don’t think it’s actually even an island
anymore as it has been developed so much–a big coal terminal is already there. It
already has zoning. It has the waterfront that’s deep for an LNG carrier. It’s just out
of sight from the town itself.
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OilVoice Magazine | OCTOBER 2014
Watson Island in foreground with old pulp mill; Ridley Island in background where
grain elevators are. I’m looking west and the land at the top of the photo is the south
(back) side of Kaien Island; Prince Rupert is on the other side.
The only issue is BG doesn’t have a partner or any vertical integration—they have no
upstream producing gas reserves or assets. Former Prince Rupert mayor Herb Pond
is their community relations manager.
BG and Petronas are developing their LNG strategies completely opposite to each
other. Petronas is completely vertically integrated in their approach, having spent $6
billion to buy Progress a few years ago, and having other Asian natural gas buyers in
their consortium.
Petronas is widely expected to be the first group to give a positive Final Investment
Decision (FID) to their LNG plan, and the Market expects this in November or
December. I would suggest it’s going to be 2-3 months later than that. The BC
government will announce their tax/fiscal regime for LNG in late October (industry is
deep in those negotiations now; so it won’t be a surprise). Petronas will announce
the results of their Environmental Application (EA) process in November. This is, to
me, a big wild card, and the chance of something needing tweaking (one set of
tweaks has already been made public) is high.
I have no doubt Petronas will say yes, but they have to say yes at the right time and
in the right way, and I’m not sure that time will be by Year End 2014.
Lelu Island is also flat, and it’s truly just a stone’s throw from the 800-person town of
Port Edward, about 3-4 miles from Prince Rupert proper. I could probably walk to
Lelu Island from Port Edward at low tide in less than two minutes—it’s that close.
And the footprint for the Petronas LNG facility takes up every square inch of that
island. That’s a lot of high concrete close to homes.
The other issue Lelu Island has is that it is right at the mouth of the Skeena River,
the single most important river in the northwest of British Columbia. What the
Ganges River is to India and the Hindu faith, the Skeena is to First Nations here. And
no LNG development is getting off the ground without their full involvement and
support. If they think their fishing will get disrupted, there will be a lot more
negotiating. I would expect ALL of Petronas EA issues to be marine related, and
most of it around it being at the mouth of the Skeena.
Skeena River shot by yours truly
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OilVoice Magazine | OCTOBER 2014
Port Edward has a separate town council–more pro-development–and Petronas has
already given the town millions of dollars to begin improving infrastructure. Council
has visited a Petronas LNG facility in Malaysia, with the noise issue being one of the
top items to investigate—but it ended up being much quieter than the old pulp mill
that shut down 20 years ago.
Late this fall will be a very exciting time for this area. I believe an incredible amount
of prosperity is about to hit this region. It’s building already.
The next Big Stage with LNG will start this fall with the provincial government’s new
tax regime.Then the EA for Petronas gets approved–or not. Then the FID from
Petronas.
But there are challenges. High tides. Big Mountains. Tight waterways. A local labour
force already full.
All the stakeholders will have to pull together to make this the success it should be.
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Oil & Gas Investments Bulletin
Big natgas exports to
Mexico in 2015 is a
pipe dream
Written by Keith Schaefer from Oil & Gas Investments Bulletin
Natural gas bulls point to fast increasing exports of cheap US natgas to Mexico to
bolster their thesis. Even I was guilty of this last year, when I ran a two part series on
this in July 2013.But now I’ve learned this is simply not going to happen—at least
until mid-2016, simply because the Mexican side of the big pipeline push is not ready
for Big Exports until 2016. I found it odd that I hadn’t heard much recently about Net
Midstream’s huge 2.1 bcf/d (billion cubic feet per day) natural gas pipeline from
Texas into Mexico—which is supposed to start December 2014.
A google search showed no new news since December 2013. That’s odd for the
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OilVoice Magazine | OCTOBER 2014
biggest cross border pipeline into Mexico in years. This pipeline should be big news
in the US and Mexico.
But no news on this made me suspicious, so I started digging into some research.
And what I found was
1. Natgas imports into Mexico are still increasing, but at only 8% so far this year,
vs. 30% a year from 2010 to 2013.
2. The Big Mexican Gas Pipe to central Mexico—Los Ramones Phase II—won’t
be ready until mid-2016. That’s when the bulls can start to really get excited.
3. In fact, only 30% of the current cross-border natgas export capacity is being
used because of internal pipeline constraints.
4. Expensive LNG imports have been filling Mexican demand, though that
should peak this year or next. Much cheaper American gas will displace
that—but not for a few years, until enough internal pipelines are built in the
country.
In fact, energy experts Bentek out of Denver Colorado think US natgas exports to
Mexico will only rise 1.5 bcf/d over the next five years—a far cry from the natgas
bulls thinking 2.1 bcf/d is going over the border this December.
“The infrastructure on the Mexican side to get to demand areas isn’t in place,” says
Bentek energy analyst Kaitlin Meese. Bentek, owned by Platts, is one of the top
analytical firms specializing in natural gas pipelines and gas flows.
The pipeline on the Mexican side of the border that connects to the big 2.1 bcf/d Net
Midstream pipe in Texas is called Los Ramones. The smaller Phase 1 should be
ready by December 1 2014, according to FERC (Federal Energy Regulatory
Commission) documents.
Los Ramones Phase 1 will have a design capacity of 2.1 Bcf/d and will run from the
42
OilVoice Magazine | OCTOBER 2014
Net Mexico pipeline at the border to Nuevo Leon, Mexico.
The problem is, Nuevo Leon is already well served with gas infrastructure. So it
doesn’t need that full amount. All that cheap American gas can keep going south—
except for the second problem is: Phase II of Los Ramones—which goes down to
Guanajuato close to Mexico City–won’t be online until Q1-Q2 2016.
Los Ramones Phase II will take 1.43 bcf/d into central Mexico. That’s when US
exports to Mexico can really ramp up.
Source: www.gas.pemex.com
Meese says that as a result of those two issues, Bentek estimates that maximum
utilization of Phase 1 will be 32% or 670 mmcf/d until the second phase is built in
2016.
So the big 2.1 bcf/d pipe export pipe dream will—at most—be just under one-third
that amount for the first 18 months.
Meese was quick to point out that Bentek believes there is upside to their 2019
forecast of only 1.5bcf/d increase in US natgas exports to Mexico.
They are tracking a list of 47 power developments in Mexico that could create up to
43
OilVoice Magazine | OCTOBER 2014
4.3 bcf/d of power demand between now and 2026, with nearly 1.9 Bcf/d of power
burn coming online by 2019. It’s estimated that PEMEX has costs of $6-$7/mcf for
domestic gas, so it makes sense that cheaper US gas could fill almost all that new
demand.
And as PEMEX moves forward with it liberalization plan, it will be very focused on oil
for years—not developing its own natural gas.
Aside from NET Mexico/Los Ramones, there are a few other projects on the Mexican
side that could theoretically get built faster. But most of these are hooking into small
lines on the U.S. side.
And most new U.S. pipeline projects are on the order of 0.1 to 0.3 BCF/d. That’s not
going to make a huge impact on overall demand when you compare it to total U.S.
gas production of 75bcf/d.
Source: Bentek
The only logical explanation for this is that Mexico just isn’t ready to handle more gas
coming from America. It doesn’t have the power demand right now, nor does it have
the pipeline capacity down to the Mexico City-Guadalajara corridor.
When might that happen? Well, how long does it take to complete a billion-dollar
construction project in Mexico? I don’t know—likely no one does, not even the
Mexican government. The best guess offered by Bentek—with a lot of caveats—is at
least two years.
So it turns out, this big story for US natural gas exports to Mexico might not be
around the corner but rather a theme to look for in late 2016.
That’s the main story. Now, there is a side-bar story to US exporting more natgas to
Mexico, and that’s LNG—Liquid Natural Gas.
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OilVoice Magazine | OCTOBER 2014
Here’s what overall Mexican natgas imports looked like for the last five years:
Source: BP Statistical Review
And as the chart below shows—using data from the BP Statistical Review—the hype
about rising US imports into Mexico was justified up until the end last year. Between
2010 and 2013, American producers’ shipments into Mexico doubled—from 0.91
bcf/d to 1.8 bcf/d.
Source: BP Statistical Review
That rise is what got a lot of analysts excited about the potential for export growth
45
OilVoice Magazine | OCTOBER 2014
here. But the numbers so far in 2014 are much less bullish.
In fact Mexican imports of U.S. pipeline gas actually decreased slightly in early
2014—averaging 1.81 BCF/d, compared to 1.84 BCF/d during the first half of 2013.
LNG has picked up the slack—but that’s only going to be temporary; until Mexican
pipeline capacity into the industrial central part of the country can displace it.
Shipments of LNG into Mexico took a big jump during the first half of 2014—rising
66% as compared to same period in 2013, to hit 0.83 BCF/d. As the chart below
shows, that’s a significant rise in LNG supply over the last two years.
Source: BP Statistical Review
Ross Wyeno is an energy analyst at Bentek, and he suggests that LNG imports are
peaking now:
“Manzanillo—the largest LNG import terminal in the country—is now paying a
premium to JKM (Japan Korea Malaysia—ks). So Mexico is paying some of the most
expensive gas in the world.”
“Once internal pipeline constraints are alleviated, they will push that LNG out of the
market and gas exports to Mexico will increase dramatically.”
Mexico will get a break in some of their LNG pricing in 2015 when a 0.5 bcf/d
contract with Peru kicks in—at only 95% of Henry Hub pricing (which is one third of
JKM pricing). But Wyeno suggests that contract is so out-of-the-market, it could get
re-negotiated, and get sold on the open market—creating more room for pipeline
imports from the US.
“The global disparity between US gas prices and global gas prices is way too high
for there to be LNG imports into Mexico once the pipeline infrastructure is put into
46
OilVoice Magazine | OCTOBER 2014
place. A group could buy that contract from Peru and say ‘We’re going to re-agree
upon the terms of this contract and we’re going to put it to an Asian buyer and we’ll
split the spread.’
“That is pretty much what we’ve seen happen with a lot of these other long term
contracts that have been broken.”
That would open up almost 1 bcf/d to US pipeline gas right away. Wyeno says the
US gas industry “could start delivering US gas over the border but you still can’t
necessarily push out that gas until those two companies come to agreement. I’m not
sure how long that takes.”
So cheap US gas exports to Mexico could displace all the 0.8 bcf/d that is now
coming in from (mostly) very expensive LNG—but it will take years to get the internal
pipeline network in place to do that.
It all adds up to great long term potential for US gas producers—but not in 2015.
Editor’s Note: Mexican exports will pay dividends for US natgas producers in 2-3
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48
OilVoice Magazine | OCTOBER 2014
The arguments for and
against shale oil and
gas developments
Written by Euan Mearns from Energy Matters
The energy debate is full of controversy. Whether it is about the pros and cons of
renewable energy, nuclear power or fossil fuels (FF) there are a range of arguments
made on either side. If it was clear cut which arguments were best, there would be
no controversy to discuss. And so it is the case with shale developments, some
strongly in favour, some violently opposed. How are we going to solve our energy
crisis?
[This article was invited by the Australian Institute of Geoscientists where it was
published earlier this month, although it has yet to appear on line.]
The concept of energy crisis has entered the psyche of many in the developed world.
Do we understand the origins of this crisis? In fact, is there an energy crisis at all?
You only need to read the introduction to David MacKay’s gold plated book,
“Sustainable Energy Without the Hot Air” to learn that there are in fact two flavours of
energy crisis at large. The first is the one that is in the press and in the minds of
many politicians and that is the legal imperative for many countries to reduce their
carbon dioxide (CO2) emissions relative to the value of 1990. The second is peak oil,
where a version of that reality sent oil prices sky rocketing from $20 to $150 / barrel
in the period 2002 to 2008, settling back to about $110 / barrel (Brent) in the post
financial crash recovery. The rise in oil prices dragged the price of most other major
energy sources up with it, and it is this real world rise in energy prices that concerns
the “man on the street” in most OECD countries, while the authorities are preoccupied with cutting emissions.
Overlaid upon this real world rise in energy prices, the result of demand rising more
rapidly than supply, has been the bizzare behavior of OECD governments seeking to
implement strategies to curtail the use of FF when naturally high prices were already
doing the job. The two strands of strategy – CO2 emissions reduction and peak oil
(which has morphed into the euphemism called energy security) have become
complexly intertwined. And it is against this sketch of the global energy system that
we must measure the pros and cons of shale oil and gas developments.
The shale oil and gas “miracle” of the USA was not inspired by the Green
movement’s desire to reduce global CO2 emissions. It was inspired by the ‘drill baby
drill’ mantra designed to reduce US dependence on imported FF, mainly oil. And
boy, has this strategy worked (Figure 1). But at what cost? And is it a robust long
term solution? Shale sceptics point to the high decline rates of shale wells and the
49
OilVoice Magazine | OCTOBER 2014
fact that much of the shale industry has been financed by mounting levels of debt.
Indeed, until the extreme cold winter of 2013/14 pushed demand for gas higher and
prices with it, much of the shale gas produced in the USA was produced at a loss [1,
2]. Over supply of course does not undermine the viability of shale gas, in fact, over
supply is more a sign of abundance.
Figure 1 The chart produced by James Hamilton [3] shows crude oil production in
the USA according to area and type in million of barrels per day. The long-term
decline following the 1970 peak was interrupted by the addition of Alaska in the
1980s. More recently the addition of tight oil (shale oil) has had a spectacular impact.
Tight oil production will peak one day, the question is at what production level and
when? When US tight oil production does peak US production will most probably
carry on down although onshore production from the lower 48 states has stabilised in
response to high oil prices. Note that BP report US crude+condensate+NGL
production at 10.0 million bpd in 2013. This chart based on EIA data is showing
crude oil only.
Time lags between drilling shale wells and fracking them and further time lags to
hooking production to a pipeline makes it difficult to analyse the US drilling statistics.
But post 2008 crash there has been a huge migration of rigs away from drilling shale
gas to drilling shale liquids in the Bakken and Eagle Ford plays (Figure 2). Since
2012, US gas production has been maintained with 400 drilling units, down from a
pre-crash peak of 1600 units. It still remains to be seen if 400 drilling units are
sufficient to maintain production long-term.
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OilVoice Magazine | OCTOBER 2014
Figure 2 In 2008 the USA had roughly 1600 rigs drilling for gas and 400 rigs drilling
for oil. Following the 2008 financial crash there has been a major adjustment with
about 1400 rigs drilling for oil and 400 drilling for gas. Gas production is on a plateau
since there is currently nowhere for additional production to go. Presumably the 400
rigs drilling shale gas are sufficient to maintain the 2.6 TCF per month plateau for the
time being. For comparison, in 2013 there were around 135 rigs operational in
Europe and 246 rigs in the Asia Pacific region. A large part of the shale success in
the USA is down to the application of American muscle.
The USA achieved self sufficiency in gas and is perhaps marching towards self
sufficiency in oil (Figure 1) with relative ease, although massive drilling resources
were brought to bear (Figure 2). This is the key argument in favour of shale gas
developments. Shale can provide energy security and jobs and create individual
wealth, in the USA at least, where land owners also own the mineral rights. This
latter point is fundamental to the success of the US industry. Land owners want
companies to drill for and discover resources on their land, it may make them rich. In
a country like the UK, those living on the land see only potential risks from drilling
shale, few, if any personal benefits and individuals are therefore inclined to object to
drilling.
Fracking Concerns
So what are these public concerns in Europe? And where does a country like
Australia stand? Concerns come under five main headings:
51
OilVoice Magazine | OCTOBER 2014
1. Seismic activity associated with fracking appears to be a reality and actually
halted activity on one of the UK’s first wells before it could be completed. I believe
that individuals who live above and perhaps own property on land above fracking
operations have a right to be concerned if the fracking sets off minor earth tremors.
To what extent tremors represent a real risk to life and property is hard to judge. I
suspect that minor tremors will turn out to be harmless. Equally, it is difficult to judge
if tremors should be allowed to halt shale exploration activity. This is really an issue
that requires objective judgement from professionals working in the Geological
Surveys of the countries in question.
2. Ground water contamination is another legitimate concern that again needs to
be evaluated on a case by case basis. Contamination concerns arise from drilling
operations and from “fugitive gas” that is mobilised by fracking operations. In the
Marcellus Shale play in Pennsylvania, one study has shown higher methane
concentrations in drinking water wells that lie close to fracked wells [4]. Ground water
contamination first and foremost needs to be assessed on the basis of whether or
not a well penetrates drinking water aquifers and if it does that the appropriate
arrangements are made to ensure that contamination does not occur during drilling.
Protecting aquifers from fugitive methane is a different issue that is more difficult to
control if it takes place. But the risk needs to be properly assessed. A small but
measurable rise in methane, whilst undesirable, does not necessarily represent a
hazard.
3. Disposal of drilling and fracking fluids that may contain a range of chemical
substances is a further source of environmental concern. Dealing with this issue has
become routine in the USA and can be dealt with appropriately in other countries, so
long as an appropriate regulatory regime is in place.
4. Disruption during drilling and pipe laying activities is a further source of
concern. In large parts of the USA, that are sparsely populated wide open spaces,
this concern has tended to be less relevant but in more densely populated areas like
Pennsylvania and rural England larger numbers of people become impacted by
hundreds of truck loads of materials and the influx of workers. Some will view this
increased economic activity as a benefit, for example the local pub owner, while
others may view it as a scourge, for example the couple newly retired to a cottage in
the country.
5. Fugitive methane from fracking operations adding to atmospheric green house
gasses. Fracking is designed to release methane or liquid hydrocarbons from tight
rock. The idea is oil or gas may flow through fractures into the wells drilled to
produce them. But they may also be released into natural fault zones that connect to
the surface and be released to the atmosphere instead.
How does an individual or a community weigh all of these risks? On the one hand we
need energy supplies to power industry and to keep us warm and comfortable and
on the other a range of potentially negative outcomes that may affect some more
than others. One way to look at the negative outcomes is to appreciate that the
production of conventional oil and gas may lead to seismic activity (for example in
northern Holland [5]); drilling conventional oil and gas wells has the potential to
contaminate ground water supplies; drilling fluids from conventional wells need to be
52
OilVoice Magazine | OCTOBER 2014
disposed of in an environmentally benign way; conventional drilling may lead to
disruption; and, oil and gas are continually leaking naturally from the surface of the
Earth into the oceans and atmosphere without our assistance and without our
noticing.
The discussion around shale developments, therefore, boils down to the scale and
intensity of that activity. Shale wells tend to require significantly more men, machines
and materials to drill than conventional wells and well productivity is normally much
lower compared with wells drilled into a newly discovered conventional oil and gas
province. The trouble that the OECD is facing is that targets for profitable
conventional drilling are getting fewer and further between and oil and gas field
declines have been taking production ever downwards for many years. Shale
developments, even though they are less productive, have offered a way of
increasing production, but it has meant drilling thousands and thousands of wells.
Thus, individually, each of the negative outcomes with shale drilling may apply
equally to conventional drilling, it is the greatly increased intensity of drilling activity
associated with shale developments that is the legitimate cause for concern of
populations living in shale development areas. In the USA, the flow of wealth into
these areas has tempered the concerns of the incumbent populations and there
must surely be lessons to be learned there.
No such thing as a free lunch in energy
A popular theme of mine is that there is no such thing as a free lunch in the energy
world. OECD societies and economies, and increasingly developing economies, owe
their existence and prosperity to the energy derived from fossil fuels and to a lesser
extent nuclear and hydroelectric power [6]. The citizens and governments of these
countries need to learn and understand the basic fact that it is affordable energy and
not money that provides succour for commerce and citizens alike and that no matter
what we do there will be a price to pay for the benefits of harvesting energy from
Earth. If it is not going to be shale developments then it will have to be something
else.
The super concentrated, super giant FF resources of 100 years ago are depleted
and as time has marched on Man has been forced to use progressively less
concentrated, lower grade resources than in the past with the inevitable
consequence that the foot print of that exploitation has increased. First the tar sands
and now shale are the latest manifestation of this march towards less and less
concentrated energy.
It is against this backdrop that individual countries or states need to make a decision
about whether or not they wish exploit the possible shale resources that may lie
deeply buried beneath the surface. Herein lies the crux of the debate for society. It is
often the case that it is of strategic importance that a country may need to secure
affordable supplies of energy for its people whilst it may be a small minority of those
people that may object to and obstruct the development of a resource to the
detriment of the whole society. Governments and citizens must realise that if it is not
to be shale then it will have to be something else. At present nuclear power offers
the only viable alternative way of providing electricity, heat and light in countries
faced with growing competition for FF supplies.
53
OilVoice Magazine | OCTOBER 2014
CO2 Emissions
The account given above of the localised negative aspects of shale development
does not take into account the global perspective of CO2 emissions and potential
impact upon Earth’s climate. And it is here that the shale debate meets a great
climate change paradox. The warming community, be they climate scientists or
government agencies have some how reached the conclusion that burning natural
gas, albeit shale gas, is good, in which they actually mean it is preferable in their
analysis than burning coal. This is because the C-H bonds of methane liberate much
less (about 50% of) CO2 per TWh of electricity produced than burning the C-C
bonds of coal.
This boils down to the rate of CO2 emissions production. Burning gas slows the rate
but not the ultimate amount of emissions. To meet politically set emissions reduction
targets burning methane is preferable to coal. But to reduce the ultimate amount of
total emissions, burning shale gas is absolutely the last thing any government
proclaiming climate concern should contemplate since this introduces to the global
FF budget a whole new slab of fossil carbon to burn. This sends one clear message.
Climate science and the energy policies based upon it is totally confused. It is
confused because it is based upon flawed science.
Australia
And so to conclude I want to try and place some of the foregoing complex web of
considerations into an Australian context. Australia is one of the world’s big energy
producers and exporters. According to BP 2014 the Australian energy balance sheet
was as follows:
Figure 3 In 2013 Australia exported the equivalent of 217 million tonnes of oil. Shale
gas developments in a country like Australia, that have a perceived negative impact
upon some of the country’s population, would in my opinion be difficult to justify,
since Australia has no burning need for more gas. Shale oil developments should
perhaps be viewed differently since an argument can be made that increasing oil
production may enhance Australia’s energy security.
In 2013, Australia had net exports of 217 Mtoe. There is a complex set of arguments
to be made around CO2 emissions accountability linked to the production and export
of FF that I do not wish to go into in this article. It suffices to say that Australia
54
OilVoice Magazine | OCTOBER 2014
exports large quantities of CO2 and has set in motion legislation to abolish the 2011
Clean Energy Act and associated carbon tax [7].
It is worth noting that Australia has significant oil imports whilst exporting significant
volumes of gas and this I believe should have bearing on the shale debate in
Australia. Liquids developments are arguably more important for national security
than gas and should accordingly be viewed more favourably by the population and
by government.
Conclusions
1) A human population of 7 billion and the level of technological development many
of those 7 billion enjoy is derived from the fact that we harvest energy from Earth and
doing so always carries costs. The future course of our energy system must weigh
the benefits of having access to sufficient supplies of affordable energy against these
costs.
2) Shale oil and gas developments in populated rural and urban areas may lead to
legitimate concerns among those populations that should not be ignored or over
ruled. There are ways to negotiate an acceptance for vital resource exploitation.
3) There is no universal answer to the shale development and fracking question.
References
[1] Breaking Energy: Ken Medlock, Senior Director of Rice University’s Baker
Institute Center for Energy Studies
[2] Energy Matters: What is the real cost of shale gas?
[3] James Hamilton on EconoMonitor: Keeping Oil Production From Falling
[4] Increased stray gas abundance in a subset of drinking water wells near Marcellus
shale gas extraction
[5] Earthquakes Force NAM to Reduce Gas Production from Groningen Field
[6] Energy Matters: Energy and Mankind part 3
[7] Promise check: Abolish the carbon tax
View more quality content from
Energy Matters
55
OilVoice Magazine | OCTOBER 2014
How does BP's gross
negligence affect the
pending criminal cases
against its 'company
men'?
Written by Loren Steffy from 30 Point Strategies
U.S. District Judge Carl Barbier’s finding that BP was grossly negligent in the
Deepwater Horizon disaster raises troubling questions about the criminal trial of the
BP “company men” on the ill-fated drilling rig, Donald Vidrine and Robert Kaluza.
As BP’s representatives, Vidrine and Kaluza face 11 counts of involuntary
manslaughter, one for each of the men who died in the disaster. They also face a
single count of violating the Clean Water Act. Barbier makes it clear in his ruling that
BP was reckless in its handling of the events surrounding the accident, which led to
the worst offshore oil spill in U.S. history. In particular, he finds fault with Vidrine’s
conduct. Vidrine, he said in his ruling, misinterpreted a critical negative pressure test
in the hours before the blowout. Based on this mistake, he ordered the rig’s crew to
proceed with displacing the drilling mud in the well, a decision that left the rig
vulnerable to a blowout. Barbier wrote:
“If the negative pressure test had been correctly interpreted, the blowout, explosion,
fire, and oil spill would have been averted. Consequently, the Court finds that the
misinterpretation of the negative pressure test was a substantial cause of the
blowout, explosion, fire, and oil spill.”
While it’s clear that Barbier believes Vidrine’s misinterpretation of the pressure test
directly contributed to the accident, the judge doesn’t address the issue of whether
that bad decision amounts to criminality. It isn’t part of the case that’s before him.
Vidrine’s mistake, though, was just one of a series of bad decisions that culminated
in disaster. Some of those decisions were made months earlier by BP engineers who
designed the well. Barbier acknowledges some of these shortcomings, but he wasn’t
establishing the root cause of the disaster. He was weighing the question of whether
BP was merely negligent, or grossly negligent. Gross negligence carrier far greater
penalties for the company.
To that end, Barbier singles out Vidrine’s misinterpretation of the pressure test as
evidence of BP’s recklessness – in other words, the individual’s behavior helps to
establish corporate culpability.
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OilVoice Magazine | OCTOBER 2014
The more disturbing question, though, goes the other way: what is an individual’s
culpability if he or she works in a culture of recklessness? Companies, of course, like
to blame individuals. It keeps them from having to tackle the more difficult problem of
a flawed corporate culture. Prosecutors, too, like to have individuals they can charge
in a high-profile case like this one. It’s much harder to prove that an executive was
responsible for a subordinate’s bad decision than it is to prove the subordinate made
the bad decision.
Prosecutors argue that Vidrine and Kaluza, alone among all BP employees who
made critical decisions about the Macondo well, are criminally liable for the accident.
Could the Macondo project, a $1 billion undertaking for BP, really hinge on the
interpretation of a single pressure test by one individual?
Even Barbier acknowledges that Vidrine conferred with his supervisor at BP’s offices
in Houston. The decision to move ahead was made, although Vidrine later
expressed doubts about the conclusion of the pressure test. It’s not clear what
Vidrine and his supervisor, Mark Hafle, discussed about the pressure test. Either
way, charging Vidrine and Kaluza with manslaughter sends a chilling message to
company men on rigs across the Gulf. By charging the company men prosecutors
are criminalizing an error in judgment, a judgment that company men make routinely
as part of their jobs. Why approve anything if the risk of misinterpreting one piece of
data could result in you facing decades in prison?
While the prosecution may stymie the decision-making process on the rig, it does
nothing to address the broader cultural failings that predicated it. The root cause of
process safety failures cannot be simple human failing, because we know that
humans will make mistakes. Process safety is supposed to account for human error.
In other words, BP should have had a backstop for Vidrine’s error. The fact that it
didn’t – or that the backstop didn’t work — speaks to a broader failing within the
company’s culture, one it ignored in previous operating failures, such as the Texas
City refinery explosion.
That raises another question: would the cultural response within BP’s chain of
command have been different if managers farther up the line knew that they, too,
might face criminal liability for encouraging the reckless behavior that Barbier found
in his ruling?
Organizations, by their nature, diffuse accountability even as they purport to create a
“chain of command.” Prosecuting the people at the bottom of that chain may be
easier, and it may satisfy our need for “somebody” to go to jail, but it will do little to
ensure an accident like the Deepwater Horizon doesn’t happen again.
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