Energy Industry Trends Review

Energy Industry 

Trends Review 

Issue 18: 2011 

Editorial 

Trends snapshot 

Economic outlook

Editorial 

With the outlook for upstream oil and gas exploration and production 

still looking strong, infrastructure challenges are big concerns for the 

growth picture in some key markets. This is particularly true for the 

North American market. The International Energy Agency (IEA), in its 

Medium Term Oil and Gas Market 2011 report, has forecast demand 

for North America (defined by the IEA as Canada, the United States 

and Mexico) rising by 1.5 million barrels/day (b/d) in 2010 to 15.6 

million b/d by 2016, but highlights challenges around pipeline 

infrastructure which could affect this forecast. 1 

What is clear is that the US pipeline market 

in particular is undergoing a dramatic 

transformation. These deals not only involve 

new projects to transport greater volumes 

of unconventional oil and gas to market, 

but are also bringing into focus pipeline 

companies that are seeking greater consolidation 

and scale to grow their companies 

after a long period of operating in a market 

which, up until a few years ago, showed 

few prospects for growth. Notably, many of 

the transformations underway are seeing 

companies divest riskier exploration and 

production (E&P) operations (Williams, 

Kinder Morgan and Atlas Energy) to focus 

purely on their infrastructure businesses, 

broadening their operations and thereby 

realizing greater market value. 

In the United States this quarter, there 

have been several significant infrastructure 

deals. Hot on the heels of Energy Transfer 

Equity’s $9.5 billion deal to buy Southern 

Union Company and its gas pipeline system 

came Kinder Morgan’s mega-$38 billion 

(including debt) purchase of fellow 

midstream giant El Paso. Such deals are 

not only indicative of how the industry 

views the significance of North America’s 

tight resource assets, but is also a clear 

indication that infrastructure is back in 

focus as oil and gas companies position 

themselves for the next wave of change in 

the industry. With this deal, Kinder Morgan 

will become the fourth-largest energy 

company (in terms of market capitalization) 

in North America, but will notably 

be a company with almost no upstream 

2 

assets (after the planned sale of El Paso’s 

E&P company is completed). Kinder Morgan 

will be a pure infrastructure business and 

the largest midstream company in North 

America. The combined company’s pipeline 

network has a huge footprint; which means 

that expansions, extensions and additional 

acquisitions (particularly around the shale 

gas plays) can be accomplished at a very 

low cost, compared to building new 

projects completely from scratch. 2 

While merger and acquisition (M&A) data 

shows midstream transaction values for the 

third quarter of 2011 down on the previous 

year, activity in the fourth quarter is set to 

be stronger, with midstream transactions 

accounting for 64 percent of total transaction 

value for the quarter to date (November 

21, 2011) compared to only 26 percent 

for upstream, with total midstream deals 

valued at around $45 billion. 3 

The infrastructure frenzy in the United 

States is not only limited to gas pipelines. 

In one of the latest deals, Enbridge will buy 

ConocoPhillips’ 50 percent interest in Seaway 

Crude Pipeline System for $1.15 billion, 

and is expected to reverse the flow of oil in 

the pipeline, thereby alleviating the glut of 

oil located in US Midwest markets by providing 

an outlet for this oil to US Gulf Coast 

refineries. Enbridge expects the pipeline to 

begin operating in reversed service with 

an initial capacity of 150,000 b/d by the 

second quarter of 2012 (subject to receipt 

of regulatory approvals). The flow reversal 

in the Seaway pipeline is expected to have 

an impact on the West Texas Intermediate 

(WTI) oil price, by linking it back to export 

markets and bringing it more into line with 

the Brent oil price (there has been a substantial 

differential between WTI and Brent 

spot prices over the past two years). What 

the market can be certain about is that the 

North American pipeline market will look 

very different over the next few years than 

it does today. 4

Economic 

Oil supply 

Oil price 

4 

August 2011 September 2011 October 2011 

Global gross domestic product (GDP) growth will moderate to around 4 percent through 2012, from more than 5 percent in 2010. Real GDP in the 

advanced economies is projected to expand at a slow pace of about 1.5 percent in 2011 and 2 percent in 2012, due to continuing financial market 

volatility and sovereign debt challenges for some EU countries. China’s GDP growth is forecast lower for 2012 at 9 percent, largely due to a decline 

in manufacturing and rising inflation. Japan’s GDP is forecast to recover in 2012 to show 2.3 percent growth. 5 

Global oil supply rose by 1 million b/d to 89.3 million b/d in October 2011 from September, driven by recovering non-Organization of Petroleum 

Exporting Countries (OPEC) output. OPEC supply is well above year-ago levels, due to the political situation in Libya. A recovery in the 

non-OPEC output and some improvement in Libya and Angola supported the increase with a continued strong supply outlook for the Americas. 6 

Oil demand Global oil demand is expected to rise to 89.2 million b/d in 2011 and reach 90.5 million b/d in 2012. Some of the demand boost stems from 

temporary factors such as seasonal heating oil tank filling, while oil-fired power generation in Japan is providing an upside to demand, as utilities 

switch to oil as well as gas for power generation. There are, however, increasing concerns of a slowdown in demand due to the economic situation 

in the Eurozone and the United States. 7 

Gas supply 

Oil prices over the past quarter have been characterized by extreme volatility and futures price movements are currently showing 95 percent correlation 

with financial market movements since July. The Eurozone debt crisis and return of Libyan crude exports has led to some easing in crude prices, with some 

analysts now revising 2012 crude forecasts on the back of expected demand slowdowns. 8 

Global gas production is expected to continue to increase and meet future demand with further exploration and development of unconventional gas 

notably in the United States, which is now progressing with its plans to export liquefied natural gas (LNG). Gas production is due to resume from Libya 

to Europe in fourth quarter 2011 which, along with high levels of gas in storage, indicate a very strong supply situation here. Gas supplies in Japan still 

remain tight. 

Gas demand Short-term gas demand continues to vary significantly by region, with significant demand still evident in Asia, notably Japan and Russia, but with 

Europe and North America still showing weaker demand due to milder autumn weather conditions and the continuing weak economic outlook. 

Longer-term demand for natural gas will continue to grow (from 3.1 trillion cubic meters [tcm] in 2009 to 4.75 tcm in 2035); an increase of 

55 percent. 9 

Gas price 

Refining 

M&A 

Gas prices for most markets are expected to increase next year over 2011, due to better demand. The US market remains an exception due to the 

continued robust supply situation and weak demand. Prices are under pressure in Europe as Libya gas exports are due to restart. LNG prices 

remain high in Asia, notably Japan, where they are almost at parity with oil prices. 

Global refinery crude runs were averaging 75.5 million b/d in third quarter 2011. Global refinery crude estimates for fourth quarter 2011 have 

been revised lower for most regions due to shutdowns and seasonal maintenance in Europe, disruptions to refinery operations and unscheduled 

stoppage in Asia as well as seasonal maintenance in the United States. Recent refining margins have showed some recovery in the third quarter 

due to an outage at Shell’s refinery in Singapore, which temporarily tightened the market. 10 

Oil price and market volatility has led to a decline in oil and gas merger and acquisition (M&A) activity, now at its lowest level since 2008. North 

America continues to be the focus of the largest deals, with focus on the unconventional oil and gas sector still strong. A US pipeline deal for the 

Seaway pipeline will lead to a planned flow reversal and signals the end of the US Midwest supply glut and coming back into line with the WTI 

and Brent crude oil price differentials. 

Rig activity The rig market continues to look buoyant as the continued high oil price drives upstream activity. The number of oil rigs in the United States exceeded 

2,000 as of the beginning of November 2011, and US drilling activity has finally surpassed pre-crisis highs in October. There is a trend of US producers 

starting to bring in-house some rig and key servicing, such as pressure pumping. 11 

Companies Higher oil and gas prices once again contributed to higher profits for the integrated oil majors during the third quarter of 2011, even though asset sales, 

geopolitical problems and maintenance turnarounds led to another decline in production. Oilfield services companies continue to show strong profits 

supported by high levels of upstream activity, though some independents are struggling with individual issues and exposure to poor US natural gas prices.

Economic outlook 

Key trend—Global GDP growth is expected 

to moderate to around 4 percent through 

2012, from more than 5 percent in 2010. 

Real GDP growth in the advanced economies 

is projected to expand at a slow pace 

of only 1.5 percent in 2011 and 2 percent in 

2012; the slowdown reflects crisis-hit advanced 

economies, notably the continuing 

sovereign debt and banking sector problems 

in the Eurozone and the continued uneven 

economic recovery in the United States. 

China’s GDP growth is forecast slightly 

lower for 2012 at 9 percent (compared to 

9.5 percent forecast for 2011), largely due 

to a decline in contracting manufacturing 

and rising inflation. 12 

The slowdown starting in 2011 reflects 

developments in crisis-hit advanced 

economies like the Eurozone, where 

sovereign debt and banking sector problems 

have proven more tenacious than expected. 

Real GDP growth in the major advanced 

economies is forecast to rise only modestly, 

from about three quarters of a percent in 

the first half of 2011 to about 1.5 percent 

in 2012, as the effects of temporary 

disturbances abate and the fundamental 

drivers of expansion slowly reassert 

themselves. Activity is expected to be more 

robust in a number of other advanced 

economies, especially in those with close 

ties to emerging Asia. 13 

In emerging and developing economies, 

GDP growth is expected to fall from about 

7 percent in the first half of 2011 to 

about 6 percent in 2012; this slowdown 

in growth is regarded to be mainly due 

to capacity constraints, policy tightening 

and slowing foreign demand. Inflationary 

pressures continue to concern emerging 

and developing economies with headline 

inflation expected to settle at about 6 

percent in 2012, down from more than 7.5 

percent in 2011, as energy and food prices 

stabilize, but demand pressures drive core 

inflation. Inflation is expected to stay high 

through the period 2011–2012 in the former 

Soviet Union, MENA (Middle East and North 

Africa) and Sub-Saharan Africa regions, 

5 

averaging 7 to 10 percent. Some economies 

are seeing noticeably higher inflation than 

their regional peers; for example, Argentina, 

India, Paraguay, Venezuela and Vietnam. 14 

Observation 

The turmoil in the Eurozone continued this 

quarter, with the bailout of Greece now 

confirmed. With the prime ministers in 

Greece and Italy resigning and the centerright 

party winning the general election in 

Spain, the pace of developments continues 

to be dramatic. The Eurozone economy 

managed only modest growth in the third 

quarter of 2011, with a rebound in Germany 

and France failing to dispel fears of a 

looming recession across the 17-country 

region. However, it is evident that the third 

quarter has been much shielded from the 

financial market turbulence, with the real 

impact not expected to be fully felt until 

the next quarter and in early 2012. For 

example, the Organization for Economic 

Co-operation and Development (OECD) is 

also forecasting that the United Kingdom is 

entering a recession. It predicted that the 

UK economy would shrink by 0.1 percent 

this quarter and 0.6 percent in the first 

three months of 2012. As of the beginning 

of November, new Italian prime minister 

Mario Monti was ready to announce his 

government while new Greek prime minister 

Lucas Papademos will face a vote to give 

him a three-month mandate to implement 

the new austerity budget measures, and 

overall, the situation in Europe remains 

volatile. 15 

The shift in focus of the Eurozone crisis 

has brought Italy and Spain more into the 

spotlight. Italy accounts for 17 percent 

of Eurozone GDP and 23 percent of total 

Eurozone debt. Italy’s gross debt as a 

percentage of its GDP is second only to 

Greece at around 121 percent, compared 

to 166 percent for Greece. 16 The situation 

in Spain continues to concern markets, as a 

more conservative government has won the 

general election there and is not expected 

to drive through the necessary reforms to 

prevent contagion there. 

What is surprising about the International 

Monetary Fund’s (IMF) 2012 forecasts is 

the view that the Japanese economy is 

estimated to grow by around 2.3 percent, 

(compared to growth estimates for the 

United States of between 1.5 and 2 percent, 

and the Eurozone by around 1 percent). This 

forecast signals that Japan is expected to 

start recovering from the current crisis, but 

also that the situation in the United States 

and the Eurozone is generally not expected 

to change. Japan is currently taking steps 

to make its oil supply chains more disasterresistant, 

due to lessons learned from 

serious fuel shortages in the wake of the 

March earthquake, when Japan’s domestic 

refining capacity at one point fell to about 

2.7 million b/d (900,000 barrels short of 

daily demand). 17 

This quarter also saw less positive growth 

news for China: with GDP growth forecast 

lower for 2012 at 9 percent (from 9.5 

percent in 2010), largely due to a decline in 

manufacturing and rising inflation. Some 

banks like Standard Chartered Bank, for 

example, have revised their GDP growth 

forecasts for China. Standard Chartered 

Bank has lowered its China GDP forecast 

for 2012 from 10 to 8.5 percent, saying, 

“Inflation has remained more elevated and 

domestic growth momentum has slowed 

more gradually in 2011 than we forecast. 

This has delayed the turn in policy—China’s 

monetary policy was not loosened in third 

quarter 2011 as we expected … momentum 

has clearly been lost in manufacturing 

growth, and CPI (consumer price index) 

inflation has now peaked, we believe.” 18 

Some analysts are forecasting more of 

a “hard” landing for China, not from its 

economic slowdown but, rather, from some 

more structural factors such as inflexible 

exchange rates, high property prices and 

pure demographics, which will see the 

influx of rural labor into the cities fall off 

and increasing social inequality, leading 

to potential rapid wage inflation and 

social unrest. 19

Oil supply 

Key trend—Global oil supply continues to 

look strong, with total oil production for 

October 2011 running at around 89 million 

b/d. There was some recovery in the non- 

OPEC output and also a continued strong 

supply outlook for the Americas. OPEC 

supply rose by 95,000 b/d to 30 million b/d 

in October, with higher output from Libya, 

Saudi Arabia and Angola, partially offset 

by lower output from other members. The 

“call on OPEC crude and stock change” for 

2011 is largely unchanged at 30.5 million 

b/d, while higher non-OPEC supply is 

expected to average around 30.4 million 

b/d in 2012. Effective OPEC spare capacity 

is estimated at 3.31 million b/d and OPEC 

has its next ministerial meeting in Vienna in 

December, during which it is likely to keep 

its production level unchanged. 20 

Non-OPEC oil supply is estimated to have 

fallen by 300,000 b/d to 52.6 million b/d 

in September 2011, largely due to weather 

and maintenance related shut-ins in North 

America, maintenance in the North Sea, 

unplanned outages in the Middle East and 

outages and maintenance in Latin America. 

Continued mature field decline, slower than 

expected ramp-up of new production and 

unplanned outages have caused a reduction 

in the expectations for non-OPEC growth 

for the fourth quarter of 2011. Growth for 

the next quarter is expected to come from 

Latin America and Russia, but will be offset 

by declines in non-OPEC Asia such as Malaysia, 

China and Indonesia. This same trend 

in 2012 is expected to lead to an overall 

reduction in non-OPEC supply growth for 

the coming year by 180,000 b/d to around 

900,000 b/d. 21 

This quarter, US oil production fell by 

57,000 b/d to an estimated 8 million b/d 

in August as production declined in the 

Gulf of Mexico and in the Lower 48 states, 

with US production expected to decline in 

coming months. News is more positive in 

the Gulf of Mexico, where a hurricane-free 

season allowed for the continuation of the 

post-Macondo recovery in production, with 

the pace of new well completion accelerating. 

The number of drilling permits issued to 

firms hoping to drill on their existing leases 

rose to 13 in October—nearly three times 

6 

the average seen so far this year—and is 

now approaching historical levels of 15 to 

20 permits per month. Analysts continue to 

focus on the considerable potential of the 

US tight and shale oil plays, which have the 

potential to produce more than 1.4 million 

b/d by 2020—reducing US imports. 22 

OPEC’s output is still running around 

300,000 b/d below pre-Libyan crisis levels 

of 30.5 million b/d from January 2011, and 

was producing just over 30 million b/d in 

October 2011. Libya’s return to the global 

market looks set to rebalance production 

flows for several OPEC member countries 

that stepped in to fill the gap caused by 

most of Libya’s 1.6 million b/d production 

capacity being shut in. Libyan production is 

now expected to return to production levels 

of around 600,000 b/d by the end of 2011. 

Saudi Arabia has cut back its production 

by an estimated 200,000 b/d to 9.6 million 

b/d in September. Saudi Arabia also recently 

announced that it is unlikely now to implement 

plans to raise its oil output capacity 

to 15 million b/d, arguing that increased 

production and expansion projects elsewhere, 

such as in Iraq and Brazil, should 

be adequate to meet global demand. Iraqi 

output in September reached its highest 

level in almost 10 years of 2.74 million 

b/d. However, production fell in October, 

following attacks on pipelines in the 

south of the country. Production of around 

650,000 b/d at the southern part of the 

Rumaila oilfield was initially shut following 

two bomb attacks (total production 

from the BP-China National Petroleum 

Corp. [CNPC] joint venture developing the 

Rumaila field had been running at around 

1.24 million b/d prior to this). 23 

Observation 

Libya’s return to the global market has contributed 

to a potentially more stable global 

supply outlook. Increasing supplies from 

Libya along with the rebound from unprecedented 

levels of unscheduled outages and 

maintenance, as well as growing production 

in Latin America, the Caspian, Russia, Australia 

and the United States should support 

supply growth in 2012. 

The picture starts to look less positive if 

a significant decline in demand occurs, 

leaving the market looking oversupplied 

and putting downward pressure on the oil 

price, although the increasing growth in US 

oil supply is likely to boost that economy as 

imports there continue to fall. 

There continue to be concerns on the supply 

side that security issues are continuing 

to affect oil production operations, notably 

in Iraq and Nigeria, but also potentially 

elsewhere in the Middle East and Africa 

as geopolitical unrest continues. In Iraq, 

the BP/CNPC consortium has been experiencing 

some production delays due to 

security issues, and there has also been a 

flare up of continuing troubles in Nigeria. 

Oil production in Nigeria fell in September 

to 2.18 million b/d, following a series of 

pipeline outages on the Bonny and Forcados 

network due to sabotage and oil theft. 

In October, Shell declared force majeure on 

its Forcados exports for October, November 

and December 2011 following the production 

shutdown due to sabotage on the 

Forcados pipeline. 24 

This quarter, oilfield services company 

Schlumberger has been talking about the 

potential impact of security issues on 

operations, notably in Libya and Iraq. Many 

companies operating in these countries 

are trying to manage security issues so 

that they do not lead to project delays and 

impact significantly on operating costs. 

Schlumberger has stated that it would need 

to deploy about 100 security personnel in 

Libya to resume activities there this year, 

and was still employing around 400 security 

personnel in Iraq. 25 

Other potential complications on the supply 

side include challenges in Iraq over relations 

with Kurdistan. More than a halfdozen 

projects are due to come onstream in 

Iraq up to 2013, which could add more than 

6 million b/d to Iraq’s production (which 

when added to current production, could 

put Iraq producing around 9 million b/d). 26 

However, not only are security challenges 

still an issue in the country, but now there 

are increasing concerns that oil companies 

that signed contracts with Iraq for fields in 

the center and south of the country might

lose these contracts if they continue to 

sign deals with Kurdistan. ExxonMobil has, 

this quarter, signed the first agreements 

with Kurdish Regional Government (KRG) 

in Kurdistan to explore for oil and gas in 

six blocks in the Kurdish region of Iraq. The 

company is already operating in Iraq, producing 

around 370,000 b/d of oil from the 

West Qurna field, under a service contract 

with the Baghdad government. The Baghdad 

government has previously excluded 

companies operating in the Kurdish region 

from oil contracts in the rest of the country 

and has warned that any deal with the KRG 

could result in the termination of contracts 

in Iraq. This could not only result in delays 

in bringing the Iraq fields to full production, 

but will also contribute to the general 

uncertainty around legal and regulatory 

issues in Iraq currently. 27 

Oil demand 

Key trend—Global oil demand is expected 

to rise to 89.2 million b/d in 2011 (growth 

of around 1 million b/d year on year) and 

reach 90.5 million b/d (growth of 1.3 

million b/d year on year) in 2012. Some of 

the demand growth is the result of some 

temporary factors in the market such as 

seasonal demand for heating oil; oil-fired 

power generation in Japan is providing 

some upside to demand as utilities there 

switch to using oil for power generation 

as well as gas as nuclear capacity is down. 

Overall, however, the demand picture 

remains very susceptible to continuing 

economic upsets and forecasts for a 

slowing economic growth outlook 

particularly in the OECD markets. 

This quarter saw stronger than anticipated 

OECD demand in August, which somewhat 

offset the effects of the worsening economic 

situation in the Eurozone. OECD demand 

forecasts for the fourth quarter of 2011 

are not expected to change significantly, 

despite the northern hemisphere moving 

into winter, largely due to the economic 

situation. The third quarter of 2011 did 

show some stronger-than-expected demand 

from some product categories, making it 

possible that OECD demand might still 

show some growth for 2011 as a whole. 

However, there are continued pockets of 

real weakness, such as gasoline demand in 

7 

the United States, where demand has been 

falling month on month. However, the IEA’s 

current outlook still sees OECD demand as 

a whole declining by around 0.7 percent to 

45.8 million b/d in 2011 and falling by 0.6 

percent in 2012. 28 

Non-OECD oil demand grew by 2.7 percent 

year-on-year (or around 1.2 million b/d) in 

August, down from 3.6 percent growth in 

July. The slowdown stemmed from relatively 

weaker demand growth in China and 

Saudi Arabia. China’s monthly apparent 

demand (calculated as refinery output plus 

net product imports) rose by 5.8 percent 

year on year in August as slower refinery 

runs outweighed higher product imports; 

strong demand growth in China was driven 

by higher demand for residual fuel oil, jet 

fuel and gasoil. With GDP growth in China 

forecast to be around 9 percent in 2012, 

the outlook in China looks robust if slightly 

slower. Total product demand in China is 

expected to reach over 10 million b/d in 

2012 from around 9.5 million b/d in 2011. 29 

Indian economic prospects are seen somewhat 

higher for 2011 and lower for 2012, 

with GDP growth now expected at 7.8 and 

7.5 percent, respectively. Demand in Russia 

has shown little sign of slowing, growing 

by 10.4 percent year on year in August; 

the 2012 forecast is expected to increase 

slightly to 3.5 million b/d. In Brazil, demand 

is expected to grow at a robust pace, by 1.8 

and 2.4 percent for 2011 and 2012, respectively, 

to reach 2.85 million b/d in 2012. 30 

In Japan, oil demand growth was supported 

by the fact that the main utilities 

companies used 217,000 b/d of crude oil 

in October versus around 140,000 b/d a 

year earlier (according to the Federation of 

Electric Power Companies of Japan), as they 

continue to switch to oil and gas for power 

generation due to continued nuclear power 

plant outages. As a result, the consumption 

of fuel oil rose to 190,000 b/d from around 

50,000 b/d in October 2010. Japan’s GDP 

forecast for 2012 is forecast to grow at 2.3 

percent, and product demand generally is 

expected to continue to be strong in 2012. 31 

Observation 

The outlook for oil demand remains little 

changed overall despite the continued 

financial market upsets. The IEA sees that 

global oil demand has grown at a “moderate, 

but stable pace” in recent months, 

suggesting that the impact of any economic 

downturn is either not yet being felt in 

global oil markets (and the worse might be 

yet to come) or that any declines in demand 

are being offset by growth elsewhere such 

as in Japan and China. 

It is perhaps surprising that analysts see 

the situation for GDP growth in Japan as so 

positive for 2012, given the impact of the 

earthquake and tsunami earlier this year. 

The IMF is forecasting that the Japanese 

economy will grow by around 2.3 percent 

in 2012, signaling that Japan is expected to 

recover from the current crisis more rapidly 

than anticipated. Japan is currently taking 

steps to make its oil supply chains more 

disaster-resistant, due to lessons learned 

from serious fuel shortages in the wake of 

the earthquake and tsunami when Japan’s 

domestic refining capacity at one point fell 

to about 2.7 million b/d (900,000 barrels 

short of daily demand). 32 

With OECD demand growth only forecast at 

around 0.6 percent growth for 2012 (with 

possible further downward revisions if the 

Eurozone economic crisis becomes more 

severe), the impetus for strong market demand 

for oil and products will have to once 

again come from Asia and, primarily, China. 

While Chinese oil demand has been slower 

than in 2010, so far this year it has contributed 

to more than half of global incremental 

demand, and is likely to do so again next 

year. Markets can also take heart that even 

if there is a slowdown in China (which is 

unlikely) there is also strong demand for oil 

in other non-OECD economies; for example, 

gasoil demand in Russia is particularly 

strong and expected to reach over 690,000 

b/d in 2011, compared to 634,000 b/d for 

the whole of 2010. 33

October 2011 was also the first month of 

the new “60-66” taxation regime for the 

Russian oil industry, which has cut duties 

on crude oil and some refined products to 

stimulate output of high-grade oil products 

and crude. As a result, there was a 

marked increase in Russian oil production in 

October, with oil production reaching 10.3 

million b/d (production levels not seen since 

pre-Soviet days in Russia). 34 

Oil price 

Key trend—Concerns around the Eurozone 

debt crisis and return of Libyan crude 

exports has led to some softening of crude 

prices. However, this quarter also saw 

crude oil prices being supported by supply 

constraints, which led to some contraseasonal 

inventory draws. There has been a 

continued disconnect between Brent crude 

prices and the US WTI oil price in response 

to the situation at Cushing, with landlocked 

supplies of WTI still not finding an export 

market outlet and depressing the WTI oil 

price as a result. 

As of November 21, 2011, WTI crude oil 

futures for January delivery were trading at 

around $99/barrel, with Brent futures trading 

at around $109/barrel. Crude oil futures 

prices were rising as markets focused on 

the possibility of greater involvement by the 

IMF in bailing out Eurozone governments. 

Short-term futures oil prices are expected 

to continue to be supported by financial 

market effects, causing volatility and a 

strong correlation of oil prices with stock 

market movements. 35 

In the short term, there appears to be 

more downward pressure on the oil price, 

as Libyan oil begins to return to the world 

market and as global economic growth 

overall is slowing. Downward pressure on 

oil prices generally is also coming from a 

rising dollar, although the market is seeing 

prices rise and fall according to financial 

market effects on any given day. 

8 

Some analysts are maintaining or raising 

their 2012 oil price projections. For example, 

J.P. Morgan has maintained its price 

projection of $115/barrel for Brent, and increased 

its price projection for WTI to $110/ 

barrel in 2012 (from $97.50/barrel forecast 

in October). J.P. Morgan said it sees the 

Brent-WTI spread narrowing to $5 and $3 

per barrel in 2012 and 2013, respectively, 

due to the planned reversal of the Seaway 

pipeline. 36 

The OPEC Reference Basket price decreased 

in October, moving below the significant 

$100/barrel level in the first week for the 

first time since mid-February. The downward 

movement in the OPEC Reference 

Basket in early October was attributed to 

the weak performance of the global crude 

oil market on the back of the debt crisis in 

Europe. 

Observation 

The crude oil price outlook is softening slightly 

for the remainder of 2011, but has continued 

to be volatile throughout the quarter as 

it reacts to financial market effects. Some 

analysts have noted a 95 percent correlation 

between futures crude oil prices movements 

and the S&P 500 since July 2011. 37 

In early November, the WTI oil price started 

to make up some ground on Brent oil prices, 

but generally the prices have seen a $10 

to $20/barrel divergence throughout 2011 

due to the supply situation at Cushing. 

If this happens, we are now likely to see 

much more of a recovery in WTI prices as 

crude is released from the hub at Cushing 

to export markets, and this is expected 

to result in a significant narrowing of the 

WTI-Brent spread. The impact on WTI might 

be greater (depending on the volumes it 

might carry) as the US government has 

announced that a decision on TransCanada 

Pipelines’ 600,000 b/d Keystone XL pipeline 

would be postponed until 2013. This makes 

the Seaway pipeline the only short-term 

option to alleviate the situation at Cushing 

(according to some analysts, by the second 

quarter of 2012 the reversed Seaway could 

have a throughput of around 150,000 b/d, 

eventually rising to a maximum of 400,000 

b/d by early 2013, all flowing toward US 

Gulf Coast refineries). 38 

Gas supply 

Key trend—Global gas production is expected 

to continue to increase and meet 

future demand with further exploration 

and development of unconventional gas, 

notably in the United States, which is 

now progressing its plans to export LNG. 

The short-term gas supply situation looks 

robust, but LNG capacity has tightened 

considerably, largely due to the situation 

in Japan. Longer term, the IEA is forecasting 

that global gas production of between 

3.9 tcm and 5.1 tcm is required to meet 

projected levels of consumption by 2035. 

Conventional gas will still account for the 

bulk of global gas production by 2035, but 

the share of unconventional gas will rise 

from 13 percent in 2009 to 22 percent in 

2035 and it provides 3 percent of incremental 

production to 2035. 39 

This quarter has seen Europe’s largest 

exporter, Gazprom, challenged by price 

disputes and falling exports, with preliminary 

Russian Energy Ministry data showing 

Russian gas exports for October 2011 falling 

by 9.2 percent from October 2010 (with 

some analysts noting that this was the 

lowest October production in the history of 

Gazprom). This is largely due to the effects 

of early stockpiling of gas by European 

countries ahead of fourth-quarter 2011 

price increases as well as Gazprom disputes 

with EU countries like Poland. Gazprom 

gas sales to Europe alone in October were 

almost flat year-on-year at 9.536 bcm. 40 

In the United States, the Energy Information 

Administration (EIA) expects US 

marketed natural gas production to average 

65.6 billion cubic feet (bcf)/d in 2011, a 3.8 

bcf/d (6.1 percent) increase over 2010. This 

growth comes from higher onshore production 

in the Lower 48 states, which more 

than offsets a year-over-year decline of 1 

bcf/d (17 percent) in the Gulf of Mexico. 

The EIA expects that total marketed production 

will continue to grow in 2012, but 

at a slower pace, increasing 1.3 bcf/d (2 

percent). Growing domestic natural gas 

production has reduced reliance on natural 

gas imports to the United States and the 

EIA now expects that pipeline gross imports 

of natural gas will fall by 6.7 percent to 

8.5 bcf/d during 2011, and by another 1.4

percent to 8.3 bcf/d in 2012. Projected US 

imports of LNG will fall from 1.2 bcf/d in 

2010 to 0.9 bcf/d in 2011 and even further 

to 0.7 bcf/d in 2012. 41 

Also in the United States, BG Group signed 

an $8 billion deal this quarter with a unit of 

Cheniere Energy Partners to buy 3.5 million 

tonnes/year of LNG over 20 years (starting 

in 2016 with a possible 10-year extension) 

from Cheniere’s new Sabine Pass LNG export 

terminal in Louisiana. This deal marks 

the first move to export some of the shale 

gas production from the US Gulf Coast to 

international markets. Cheniere has also 

reportedly signed a second export deal 

with Spanish utility Union Fenosa, which 

is a $9 billion 20-year agreement 

for 3.5 million tonnes/year of LNG. 42 

Short-term LNG supply continues to be 

strong, with new capacity continuing to 

come onstream. LNG as a share of global 

gas demand increased to 9 percent in 2010 

and is expected to increase further in 2011 

(with LNG now accounting for between 

25 to 30 percent of all gas traded). While 

Japan has seen its LNG demand grow by 21 

percent since the nuclear disaster in March 

this year, much of the anticipated growth 

in gas usage in Asia is likely to come from 

China and India. Chinese imports of LNG 

have increased 27 percent in the first half 

of 2011 and India is expected to double its 

gas usage from 2008 to 2015. With domestic 

supply failing to keep up with growing 

industrial demand, some countries are looking 

to ramp up their LNG import infrastructure 

to facilitate easier trade and increase 

their gas supply flexibility. Overall, global 

LNG imports are up by 11 percent over the 

first half of 2011 due to strong relative 

increases from the United Kingdom, 

Canada and Chile; incremental volumes 

are also up in the United Kingdom, Japan, 

Korea and China. 43 

Observation 

In Europe, the fall in domestic gas production 

continues to increase European 

dependency on imported gas. Under the 

current scenario, Russia is expected to gain 

most from this shortfall, but, despite Gazprom’s 

investment plans, there are concerns 

that the company is behind schedule with 

9 

production growth plans. Meanwhile, the 

market continues to change with LNG looking 

increasingly attractive to many countries. 

With the European Union tightening 

European gas market regulations for piped 

gas, Gazprom’s focus has been turning to 

international markets. However, despite up 

to 60 million tonnes of new annual LNG 

capacity under consideration in Russia, for 

now, only one LNG export plant is operating: 

Sakhalin-2. It therefore looks like 

Russia will be playing catch up in the LNG 

supply market for the foreseeable future, 

particularly with US Gulf Coast LNG exports 

on the horizon. 

If significant exports of LNG start to come 

out of the US Gulf Coast LNG export terminals, 

there is potential for more interconnectedness 

of global gas markets and 

prices, particularly now as the widening of 

the Panama Canal will offer a more direct 

route to Asia for larger LNG tankers from 

2015. (BG Group and Cheniere have both 

signed the first deals in October 2011, to 

start exporting LNG from the Sabine Pass 

terminal from 2014 and other deals are 

likely to follow.) 

BG and Cheniere are reportedly offering 

in their contracts options to allow buyers 

to cancel any liftings without penalty if 

they give advance notice. This means that 

essentially the sellers of US Gulf Coast LNG 

are selling gas based on Henry Hub spot gas 

prices (market related and competitive) and 

they are offering their buyers an unprecedented 

cancellation option (making these 

deals very flexible). With US Henry Hub 

prices at around $4/million btu and Asian 

LNG prices over $15/million btu, the potential 

for price arbitrage is considerable. 44 

As a result of these considerable hedging 

and price arbitrage opportunities between 

US and Asian gas markets, the LNG market 

is becoming a more attractive place for 

conducting business for investment banks. 

This quarter, J.P. Morgan announced a deal 

with Cheniere Energy to import LNG into 

the United States. Under the two-year deal, 

the two parties will jointly buy cargoes of 

the gas from overseas and share the profits 

from selling them into the US market. 

J.P. Morgan, already a big player in the 

downstream US gas market, will enter the 

LNG market through access to Cheniere’s 

Sabine Pass import terminal in Louisiana, 

which it is likely to use as a hedging tool. 

Most of the larger investment banks have 

all entered LNG trading over the past few 

years, including Morgan Stanley, Citigroup 

and Barclays Capital, with an increasing 

focus on the US gas market. 45 

Gas prices 

Key trend—Natural gas prices for most markets 

are expected to increase next year over 

2011, due to better demand. The US market 

remains an exception due to the continued 

robust supply situation and weak demand 

and gas prices are under pressure in Europe 

as Libya gas exports are due to restart. 

Supply to the global gas market remains 

robust and the segmentation of the global 

gas market into distinct pricing regions 

shows no sign of altering in the short term, 

although developments like increased shale 

gas production (and continued weak spot 

price market) in the United States, leading 

to potential US LNG exports, will start to 

change pricing dynamics. Over the next five 

to 10 years, the market is likely to see a gas 

price which is increasingly global (supported 

by possible US Gulf Coast LNG exports), 

which connects all three key demand markets 

(Asia, the United States and Europe). 

Gas price futures in Europe started to rise 

this quarter in anticipation of the coming 

winter but, in reality, a warm autumn has 

put some downward pressure on prices. In 

August, the United Kingdom’s wholesale 

natural gas price for the coming winter 

traded at its highest level in more than 34 

months at 78.25 pence/therm. This was 

caused by an expected reduction in output 

over the autumn from QatarGas so that it 

could hold essential maintenance to some 

of its production trains. (Qatar is the single 

largest supply source of LNG for the United 

Kingdom.) By mid-November 2011, however, 

the day-ahead gas price in the United 

Kingdom was only trading at 60.70 pence/ 

therm, with futures prices for December 

also weak at 60.90 pence/therm. 46

Libya is expected to restart gas exports in 

late November/December 2011, and there 

are fears that this additional supply in the 

European market will cause a gas price 

decline due to the continued mild weather. 

The Libya-Sicily Greenstream pipeline is 

expected to start shipping gas to Italy in 

December with gas storage in Italy already 

reportedly nearly full. This is likely to cause 

other producers, notably Russia, Norway 

and Qatar, to lower or divert their gas 

production putting substantial pressure 

on European gas prices. 

Gazprom has posted high profits so far 

this year, supported by high gas prices and 

a surge in orders from customers locking 

into deals to avoid later estimated price 

increases. However, more recently, the 

company is experiencing a fall in exports 

due to some customers stockpiling gas 

ahead of winter price rises. Gazprom is 

reportedly in talks with customers such 

as Germany’s RWE, which is looking for 

cheaper gas (in light of Germany’s move 

away from nuclear power and continued 

low spots prices at key European hubs) and 

is also continuing talks with Japan’s major 

utilities that are looking for secure gas 

supplies, due to power generation supply 

concerns. 47 

US gas prices continue to be weak, as rising 

domestic production and slow demand 

growth influences price movements there. 

The Henry Hub spot price averaged $3.56/ 

million btu in October 2011, 34 cents lower 

than the September 2011 average and 49 

cents lower than the August 2011 average. 

The EIA has lowered the 2011 forecast by 

6 cents to $4.09/million btu and also the 

2012 forecast by 19 cents to $4.13/million 

btu. 48 Should US Gulf Coast LNG markets 

become more linked to higher price markets 

in Europe and Asia through LNG exports, 

there are expectations that this might 

eventually lead to a rise in US gas price. 

On the downside, it might also cause US 

oil imports to rise (as gas becomes less 

competitive as a fuel for power generation) 

at a time when both US oil and LNG 

imports have been falling steadily. 

10 

Short-term LNG prices remain high, notably 

in Asia, where Japan continues to struggle 

with the impact of the Fukushima (and 

other) nuclear plant shut-downs. Around 

80 percent of the country’s nuclear capacity 

remains offline (just 11 of its 54 reactors 

are now operating) and there has been no 

word on potential restarts. LNG demand in 

Japan has risen by 31 percent in October 

over September to 3.9 million tons and LNG 

prices in Asian generally, have exceeded 

$17/million btu in late September and are 

expected to reach parity with (Brent) oil 

prices soon (some analysts expecting Asian 

LNG spot prices to increase to as high as 

$20/million btu over the coming winter). 49 

Observation 

Short-term price rises in the European 

market are more reflective of preparation 

for the coming winter than any real change 

in supply/demand fundamentals, but overall 

demand in both Europe and the United 

States is weak, and being exacerbated by a 

mild autumn. With increasing amounts of 

Libyan gas coming back into the market, it 

is unlikely that European or US gas prices 

will rise substantially over the coming winter. 

Gazprom continues to try and market 

its gas more in line with current market 

realities of lower spot prices generally. In 

the United States, while there might be excitement 

over the potential for the gas price 

rises due to LNG exports, the reality is that 

natural gas prices are likely to languish for 

some time. US natural inventories remain 

high and if they are still robust at the end 

of the 2011–2012 heating season, then 

there is almost no prospect of any change 

in the gas price situation there. 

Longer term, the growing share of LNG 

in global gas supply and increasing opportunities 

for short-term trading of LNG 

are expected to contribute to a degree of 

convergence in regional prices, and LNG 

price rises generally. Global LNG demand 

grew 9 percent in the first half of 2011 and 

13 percent over the past 12 months, with a 

high percentage of LNG shipping capacity in 

use due to the situation in Japan. Countries 

such as the United Kingdom are importing 

increasing amounts of LNG; UK demand 

grew by 76 percent year on year in the first 

half of 2011. Despite the amount of LNG 

new build projects underway, the market is 

likely to see some tightening of spare LNG 

production capacity over the next two years 

until new LNG supply projects come onstream. 

According to some analysts, global 

spare LNG production capacity is likely to 

shrink to 26 million tonnes a year in 2011 

with spare capacity flattening out by 2014, 

which will translate to about 2 million 

tonnes per year of spare capacity. 50 

While there is likely to be significant continued 

spot LNG price differentials between 

the United States, Europe and Asia, reflecting 

the relative isolation of these markets 

from one another and the cost of transport 

between regions, the rise in Asian demand 

and the potential of new LNG exports 

starting from the US Gulf Coast will start to 

connect these three markets. This is likely 

to start to change LNG market dynamics 

and introduce, what many market analysts 

are calling, the first truly global gas price. 

Most analysts are predicting that North 

American LNG could be delivered at about 

$9/million btu. Such a low price could encourage 

Asian utilities to seek a new pricing 

regime linked to the US gas price benchmark 

(Henry Hub) rather than oil prices and 

would be a welcome relief for the large 

Asian Utilities most of whom are expecting 

to pay between $17 and $20/million btu for 

their gas this winter. 51

Gas demand 

Key trend—Short-term gas demand 

continues to vary significantly by region, 

with significant demand still evident in 

Asia, notably Japan and China, but with 

Europe and North America still showing 

weaker demand due to milder weather conditions 

and the continuing weak economic 

outlook. Longer-term demand for natural 

gas will continue to grow (from 3.1 tcm in 

2009 to 4.75 tcm in 2035) according to the 

IEA’s Medium Oil and Gas 2011 outlook; an 

increase of 55 percent. 52 

In the short term, gas demand in Europe 

continues to be weak, with poor economic 

conditions continuing to affect demand as 

well as the impact of a significant volume 

of prepaid Russian and Libyan gas, which 

has not yet reached the market. In the 

United Kingdom, gas demand during this 

winter is expected to be lower, due to the 

continued shift by power producers to use 

coal for power generation. The UK power 

distribution operator National Grid has 

revised power plant availability down by 4 

percent this winter to 61.3 gigawatts (GW), 

adding that power producers are expected 

to “strongly favor” cheaper coal instead of 

gas for electricity generation. 53 

In Italy, gas demand fell with lower offtake 

from power producers and industrial 

customers (total Italian gas demand in the 

power generation sector was 2.20 billion 

cubic meters (bcm) this October, while it 

stood at 3.15 bcm in October 2008). Spanish 

gas demand also witnessed a drop of 10 

percent in October from the same month 

last year due to warmer weather and power 

utilities switching to coal. However, there 

is evidence of slight increases in French gas 

demand, which is now forecast to increase 

by 2.3 percent in 2011, to 537 terrawatthour 

(TWh) due to five new gas-fired power 

plants coming online this year. Some analysts 

are forecasting European gas demand 

would be around 7.5 percent lower in 2011 

than in 2010, a faster annual rate drop than 

at the height of the international recession 

in 2009, due to weak demand and mild 

autumn weather. 2012 might show some 

recovery to reach 456 bcm (from estimates 

of 449 bcm for 2011) if the economic situation 

starts to improve. 54 

11 

US gas demand continues to be weak, with 

the EIA expecting that total natural gas 

consumption will grow by only 1.7 percent 

to 67.1 billion cubic feet per day (bcf/d) 

in 2011. Rising use of natural gas in the 

industrial and electric power sector in the 

US accounts for most of the increase in 

total US consumption in 2011 (with 

projected growth rates of 2 percent and 

1.5 percent, respectively). Projected total 

US natural gas consumption is expected 

to increase slightly by 1.1 percent to 67.9 

bcf/d (higher projections of residential and 

commercial consumption account for much 

of this change in the forecast). 55 

LNG demand continues to increase in Asia, 

due to the ongoing situation in Japan and 

rising demand in other nations like China 

and Korea. China’s LNG imports rose 27 

percent to 5.2 million tons in the first half 

of 2011 from a year earlier and reached 

a record over the summer of 2011. Petro- 

China has now started trial operations at its 

Jiangsu LNG terminal and China National 

Offshore Oil Corporation has stated that it 

might increase LNG imports by 16 percent 

via its Guangdong facility this year. India’s 

LNG imports increased 26 percent in the 

first half; with the country forecast to 

double its gas to up to 2016 (to around 

400 million cubic meters a day) with 

domestic supply only expected to supply 

half of this forecast demand. 56 

Observation 

While short-term demand in Europe generally 

has been weak this quarter, the outlook 

for gas demand remains strong over the 

next few years. Analysts are predicting that 

there will be high demand for new gas turbines, 

particularly from the United Kingdom, 

Germany and France. In the United Kingdom, 

around 14 GW of new turbine orders 

are expected to be placed as roughly 11 GW 

of aging plants will shut down by 2017. 

In Germany, gas is expected to play an 

increasingly important role due to the government’s 

decision to close down nuclear 

power plants in favor of more renewable 

energy supply. Due to the short-term gap 

in renewable energy supplies coming on 

stream, Germany will require short-term 

gas power capacity replacements. In France, 

the Fukushima nuclear situation is causing 

a re-evaluation of that country’s dependency 

on nuclear power, and if a left-wing 

government wins the 2012 French general 

election, it is likely that gas use in France 

will increase considerably also. 57 

The short-term outlook for LNG is that the 

market will continue to tighten largely due 

to the situation in Japan. It is expected that 

globally there will be limited LNG capacity 

additions over 2012-2014, including the 

Pluto project in Australia and Angola LNG 

(with the second “wave” of significant LNG 

capacity only coming onstream toward the 

end of 2014). There is also expected to be 

demand for LNG imports from new markets 

such as Thailand, Vietnam, Singapore, 

Indonesia and Malaysia (with the latter 

also being LNG exporters, but Indonesia, 

for example, is allowing private companies 

to start importing gas due to local shortages). 

This is expected to have an impact on 

Indonesia’s net exports and might lead to 

tightening LNG supplies in Asia generally. 58 

Refining 

Key trend—Global refinery crude estimates 

for the fourth quarter of 2011 have been 

revised lower for most regions due to 

shutdowns and seasonal maintenance in 

Europe, disruptions to refinery operations 

and unscheduled stoppages in Asia as well 

as seasonal maintenance in the United 

States. Global refinery crude runs averaged 

around 75.5 million b/d in the third quarter 

of 2011 with stronger US runs only partially 

offsetting lower than expected throughputs 

in Asia. Asia saw significant refinery outages 

and delays in starting up new capacity, 

which contributed a fall in crude runs of 

around 30,000 b/d. As a result of refining 

disruption, refining margins have showed 

some recovery this quarter (largely due to 

the outage at Shell’s 500,000 b/d Pulau 

Bukom refinery in Singapore, which tightened 

the market temporarily) but, generally, 

refining margins continue to be under pressure 

with September margins having shown 

a steep fall from August levels. 59

European crude refining runs estimates 

are largely unchanged at 12.2 million 

b/d for the fourth quarter of 2011 (down 

from 12.4 million b/d in the third quarter). 

Regional runs rose 165,000 b/d in August 

to 12.6 million b/d, 325,000 b/d below a 

year earlier. Refinery stoppages continue to 

be heavier than in 2010 so far this year, in 

part due to economic and some unforeseen 

shutdowns. While the loss of Libyan supplies 

since February has prompted several 

refiners to undertake turnarounds earlier 

than planned, several plants are currently 

reducing runs or shutting altogether due 

to poor margins. In terms of scheduled 

maintenance, the main contributors are 

the Netherlands, with both Shell’s Pernis 

and BP’s Rotterdam undertaking work in 

October. In Germany, Gelsenkirchen was 

down for most of October and in Greece, 

Petrolas Elefsis was also undertaking work. 

Also notable is the 49-day partial shutdown 

of Statoil’s 120,000 b/d Kalundborg refinery 

in Denmark from late September. European 

refining margins were depressed by weakening 

gasoline crack spreads in September, 

but also a widening fuel oil discount 

contributed, pressuring margins at simple 

refineries in particular. Toward the end of 

the quarter, crack spreads improved both 

due to weaker crude prices and the fire at 

the Pulau Bukom refinery in Singapore. In 

addition, the Urals oil price weakened relative 

to Brent giving extra support to Urals 

margins. 60 

US crude runs were lower in September, 

falling some 300,000 b/d from a month 

earlier, mostly due to lower Gulf Coast 

runs. September runs were nevertheless 

stronger than expected, and were in part 

supported by the lack of any hurricanerelated 

shutdowns on the Gulf Coast. By 

the end of September, however, refining 

margins decreased both on the Gulf and 

West Coasts following a sharp deterioration 

in gasoline cracks and this, combined with 

an increase in maintenance shutdowns, 

will further reduce runs over the balance 

of the year (however overall runs are 

forecast to remain above 2010 levels on 

an annual basis). 61 

12 

The IEA has revised non-OECD refinery 

throughputs lower for both the third quarter 

and fourth quarters of 2011 following 

weaker-than-expected runs in China in 

August and disruptions to refinery operations 

in other parts of Asia (primarily due 

to the fire and closure of Shell’s refinery 

in Singapore). Total non-OECD runs are 

expected to increase to 39 million b/d for 

the fourth quarter of 2011 (an increase of 

675,000 b/d year on year) with China also 

showing higher runs toward the end of 2011 

due to the restart of PetroChina’s Dalian 

refinery in early September, as well as the 

start up of new capacity. In Asia, Singapore 

refining margins fell even though product 

cracks improved toward month-end due to 

the fire at the Singapore refinery. Weak fuel 

oil product cracks at the beginning of the 

month depressed margins as did relatively 

stronger Tapis crude prices. 62 

Observation 

This quarter, any boost in refining throughputs 

and margins were due to short-term 

outages and maintenance rather than any 

endemic changes in the industry outlook for 

refining. There is still significant rationalization 

underway globally in the industry 

focused on OECD markets. ConocoPhillips 

announced at the end of September it had 

idled its Trainer refinery on the US East 

Coast and that the refinery would permanently 

shut if no buyer is found within six 

months. The announcement comes only 

weeks after Sunoco said it would also 

sell or shut its two East Coast plants. In 

Europe, Eni idled its Venice refinery on poor 

margins, while LyondellBasel announced 

the French Berre l’Etang refinery will close 

permanently. Finally, in Japan, Showa Shell 

completed the shutdown of the Oghimachi 

factory, in line with previously announced 

plans. 

OPEC has announced in its 2011 World Oil 

Outlook that the global refining surplus 

might reach 10 million b/d by 2015 unless 

some refining capacity is closed and such 

overcapacity will continue to depress refining 

margins. OPEC estimates that around 

6.8 million b/d of new crude distillation 

capacity is expected to be added globally 

in 2011-2015, half of which will be in the 

Asia-Pacific region, mainly in China and 

India. 63 

Refiners are also struggling to cope with 

developments underway in key markets, 

which will affect their operations and 

margins. On the negative side, in the United 

States, the decision by Enbridge to reverse 

the flow in the Seaway pipeline starting 

next year will begin to end the advantaged 

feedstock position that Midwest refiners 

have been enjoying in that market. The glut 

of crude in the market, which could not 

find an outlet to the US Gulf Coast refiners, 

has depressed prices for WTI crude and 

helped create a record spread between the 

price of WTI crude and Brent Crude. It will 

mean that Midwest refining margins are 

likely to decline, along with the profits of 

some refiners in that region. 64 

On a more positive note, changes to fuel 

taxation in the European Union is likely to 

have a positive effect on refining margins 

here, according to analysis by OPEC’s 2011 

World Oil Outlook, by increasing diesel 

demand. An EU proposal to remove diesel 

tax advantages and put the fuel on par 

with gasoline would mean that diesel taxes 

would have to rise in more than half of 

the European Union’s 27 member states, 

helping redress the balance of refined 

product needs in the region by encouraging 

more use of gasoline, stimulating European 

output. “The (current directive) has led to a 

situation in which the open market diesel 

price is higher than that for gasoline due to 

greater diesel demand, but retail prices for 

final consumers are reversed at the pump 

because of lower taxation rates—this creates 

even more demand for diesel, despite 

EU shortages. This proposal could also be 

viewed as a signal to EU member states 

to reverse unwarranted tax advantages to 

diesel and to steer toward a more balanced 

future demand pattern which is sustainable 

for the refining industry.” OPEC expects that 

diesel’s tax could go up to 0.41 euros per 

liter from 0.33 euros per liter while gasoline 

would stay roughly unchanged at 0.36 

euros per liter. 65

Merger and acquisitions 

Key trend—Oil price and market volatility 

has led to a decline in oil and gas M&A activity, 

which is now at its lowest level since 

2008. North America continues to be the 

focus of the largest deals with midstream 

activity forecast to increase substantially. 

In 2010, there were a total of 1,717 M&A 

deals in the global oil and gas sector, with 

the total deal value at about $322 billion. 

This year (up to the end of October 2011), 

the sector has seen 1,508 mergers valued 

at around $211 billion. 66 

In the third quarter of 2011, according to 

data from IHS Herold, upstream transaction 

values fell to $31.9 billion as compared to 

$77.6 billion in the third quarter of 2010. 

The deal count also witnessed a drop from 

75 to 52 in the third quarter of 2011. A lot 

of the value in upstream M&A is still being 

driven by activity in the US shale gas sector. 

BHP’s all-cash $15 billion takeover of US 

shale-focused Petrohawk Energy was the 

largest global corporate deal in more than 

two years, accounting for nearly half of 

third-quarter 2011 worldwide deal value. 

BHP will pay $12.1 billion in cash, giving it 

access to shale oil and gas assets across one 

million acres in Texas and Louisiana. The 

deal comes just months after BHP agreed 

to buy Chesapeake Energy’s Arkansasbased 

gas business for $4.75 billion. Other 

significant deals this quarter also focusing 

on US shale basins included Statoil’s $4.4 

billion bid for Brigham Exploration. Statoil 

is looking to enter the Bakken and Three 

Forks shale plays in North Dakota with 

its purchase of Brigham, which has current 

production of 21,000 b/d, potentially 

increasing to 100,000 b/d over the next five 

years. As part of its US shale play strategy, 

Statoil is looking to build more shipping 

capacity, with a focus on pipelines, but has 

not yet committed itself to any specific 

pipeline project. Hess Corporation has 

carried out a transaction in the Ohio Utica 

Shale (a $593 million cash-plus drilling 

carry joint venture with Consol Energy and 

the $750 million corporate acquisition of a 

privately held Marquette Exploration). The 

French major Total has also made it known 

that it is looking for further opportunities 

13 

in the US shale plays. Total currently has no 

operated production from US shale plays, 

but has been participating in a joint venture 

with Chesapeake Energy in the Barnett 

Shale in North Texas for nearly two years. 67 

Downstream total transaction value for the 

third quarter of 2011 was down 36 percent 

compared to third-quarter 2010 and deal 

count was lower to 11 as compared to 13 

for the same period in 2010. The natural gas 

distribution sector contributed more than 

one third of downstream total transaction 

value in the third quarter of 2011 driven by 

ATCO’s $1.1 billion acquisition of a natural 

gas network that serves Western Australia. 

Both refining transactions were sales of 

assets by Murphy Oil Co. in the United 

States. With these sales, Murphy Oil exits 

the refining business to focus on its E&P, 

service station and terminal businesses. 68 

While the number of midstream transactions 

fell dramatically in the third quarter of 2011 

to the lowest level since the first quarter 

of 2009, fourth-quarter 2011 activity is 

increasing and pipeline deals are starting 

to drive the market in North America. 

Kinder Morgan, the US oil and gas pipeline 

company, has agreed to a $38 billion deal 

(including debt) to buy El Paso Corporation, 

another pipeline operator, creating 

the fourth-largest energy company in 

North America by market value. The deal 

represents a bet by Houston-based Kinder 

Morgan on the future growth of North 

American natural gas supplies, giving it 

operations in all the leading areas for US 

shale gas production. Another significant 

transaction this quarter was Energy Transfer 

Equity’s most recent $9.5 billion offer to 

acquire Southern Union Group for $44.25 

per share in cash. On the oil pipeline side, 

there was a significant deal this quarter 

with the $1.15 billion Enbridge has agreed 

to pay for ConocoPhillips’s half of the 

Seaway line which originally ran from the 

Gulf Coast to Oklahoma, serving Conoco’s 

Ponca City, Oklahoma, refinery. Because of 

the large amount of oil in the Midwest, the 

Seaway line has recently been running at 

very low capacity and its reversal looks like 

it will be the first pipeline online to be able 

to move enough crude out of the oil hub of 

Cushing, Oklahoma to the refineries along 

the US Gulf Coast, cutting into the price 

premium held by North Sea Brent blend 

against the price US benchmark West Texas 

Intermediate and avoiding the need to build 

completely new infrastructure. 69 

Observation 

M&A deal volume and activity continues 

to be dominated by the US unconventional 

sector this quarter, where increasingly there 

are concerns that the growth picture might 

be constrained by infrastructure challenges. 

Total US oil production from shale plays is 

currently estimated at 700,000 b/d but is 

estimated to increase substantially, depending 

on access to pipeline shipping capacity. 

For example, in one key US shale production 

area, the Eagle Ford in South Texas 

(where there are still very few pipelines), 

companies continue to rely on trucks and 

railways to handle the increasing oil production 

output. 70 As shale gas production 

also increases, the US Interstate Natural 

Gas Association of America Foundation (a 

trade group) estimates that companies will 

need to build 35,600 miles of large scale 

natural-gas pipelines between 2011 and 

2035 to meet market demands, at a cost 

of $178 billion. 71 

As a result, the focus of M&A activity has 

now moved its focus to infrastructure 

deals, as companies seek to capitalize on 

this growth and as a result, the US pipeline 

market is undergoing a dramatic transformation. 

Deals like the Kinder Morgan 

acquisition of El Paso, or Enbridge’s deal for 

a 50 percent share of the Seaway pipeline, 

will change the way the US infrastructure 

market operates. These deals not only 

involve new projects to transport greater 

volumes of unconventional oil and gas to 

market, but are also bringing into focus 

pipeline companies that are all seeking 

greater consolidation and scale to grow 

their companies after years of operating in 

a market which up until a few years ago, 

showed few prospects for growth. Notably, 

many of the transformations underway are 

seeing companies divest riskier E&P operations 

(Williams, Kinder Morgan and Atlas 

Energy) to focus purely on their infrastructure 

businesses, broadening their operations 

and thereby realizing greater market value.

Rig activity 

Key trend—The rig market continues to 

look buoyant as the continued high oil 

price drives upstream activity. According to 

data from Baker Hughes, during the third 

quarter of 2011, the average number of rigs 

under operation generally witnessed steady 

growth (though there were declines in some 

markets) as compared to the same period in 

2010; North America (17 percent), Europe 

(33 percent), Middle East (6 percent), Africa 

(-15 percent), Latin America (13 percent), 

Asia-Pacific (-10 percent). The number of 

oil rigs in the US exceeded 2,000 as of the 

beginning of November 2011 and drilling 

activity has finally surpassed pre-crisis lows 

(a year ago the rig count stood at 1,668 

rigs). Gas rig activity in the United States, 

however, has been starting to slow over 

recent weeks. The number of rigs drilling 

for natural gas in the United States fell to 

865, toward the end of November 2011, the 

lowest level since January 2010, down from 

highs of 936 just a few weeks ago. 72 

Globally deepwater and ultra-deepwater 

rig availability remains tight, with day rates 

for deepwater and ultra-deepwater rigs 

increasing and contracts becoming longer, 

as the market tightens. Deepwater drilling 

activity continues to recover in the US Gulf 

of Mexico, where a hurricane-free season 

allowed for a continuation of the post- 

Macondo recovery in production, with the 

pace of new well completions accelerating. 

So far this year, the U.S. Bureau of Ocean 

Energy Management, Regulation and Enforcement 

has given approval to more than 

40 drilling permits, with 13 being issued 

in October—nearly three times the average 

seen so far this year; awards are now 

approaching historical levels of 15 to 20 

permits per month. 73 

There continues to be a steady rise in orders 

for rigs as drillers replace old fleets and step 

up exploration and production activities 

to take advantage of high global crude oil 

prices. Analysts expect the world’s two largest 

rig builders by market share (Singapore 

based Keppel Corporation and Sembcorp 

Industries Ltd.) to continue to receive 

strong orders for rigs in 2011, which is likely 

to boost their profits over next two to three 

years. Both Keppel Corp. and Sembcorp 

14 

Marine have seen their share prices rise on 

the back of better-than-expected US retail 

sales and hopes that Europe will act soon 

to resolve its debt crisis. The stocks of the 

rig builders generally have been recovering 

from a recent sell-down due to concerns 

about a possible slowdown in orders amid 

a weakening global economy as oil prices 

stay high and there is strong demand from 

countries like Brazil. Sembcorp management 

is reportedly seeing higher enquiries for 

semi-submersible rigs and remains upbeat 

on new order intake, especially on potential 

rig orders from Brazil. 74 

Observation 

As the rig market continues to tighten and 

rig rates rise, the outlook for the services 

industry and rig suppliers in particular is 

much improved. The industry is showing 

high rig utilization in most markets, with 

rig rates rising as demand increases. 

As demand for rigs and oilfield services 

increases in high growth markets, it is fair 

to say that a trend is emerging of some 

companies either buying rigs or increasingly 

looking to bring key services in-house. This 

is particularly true of the US onshore oil 

and gas market, where producers are buying 

onshore drilling rigs and related equipment 

to keep their costs in check, rather than 

rent from the market at increased prices 

amid strong demand for work in shale 

fields. While prices to rent rigs and costs 

of operating them are increasing, some 

analysts are noting that the rise in prices 

for buying a rig have risen more slowly, 

meaning buying a rig is more cost efficient. 

With a 15 to 20 percent increase in the 

cost of land-based drilling, North America 

had the highest cost escalation in the past 

12 months (according to some analysts), 

meaning that in this environment, company 

can recoup the $20 million or so cost of 

a rig within two years. Some smaller US 

producers are also bringing key services like 

pressure pumping in-house to better control 

costs and access to services as oil and gas 

fracking activity continues to increase. 75 

Companies 

Key trend—Most of the major oil companies 

have continued to generate high profits 

in the third quarter owing to higher oil 

prices—though declining production and 

rising costs are still much in evidence. Most 

of the majors reported a fall in production 

with new field start-ups failing to match 

natural declines in portfolios and significant 

portfolio rationalization still taking place. 

This quarter also saw the continued effect 

of unforeseen situations such as the conflict 

in Libya and delays in getting back to 

work in the Gulf of Mexico. While industry 

costs fell in 2009 and 2010 due to the global 

economic crisis, the trend appears to be 

on the turn, with some analysts expecting 

industry cost rises of 6 percent for 2012. 76 

Higher oil and gas prices once again contributed 

to higher profits for the integrated 

oil majors during the third quarter of 2011, 

even though asset sales, geopolitical problems 

and maintenance turnarounds led to 

another decline in production. Each of the 

majors recorded production declines for the 

quarter, ranging from a less than 1 percent 

decline at Total to 10 percent-plus declines 

at BP and ConocoPhillips. Total’s relatively 

small production decline was due in part to 

increased output at Russian gas producer 

Novatek, in which Total took an equity 

stake earlier this year. BP’s third-quarter 

production fell 12 percent to 3.32 million 

barrels of oil equivalent (boe)/d, largely 

on the back of major turnarounds and 

production declines in the Gulf of Mexico. 

Conoco’s sharp production decline came 

from a variety of sources, shut-ins in Libya, 

asset sales and reduced output at the Peng 

Lai 19-3 field offshore China following an 

oil spill. 77 

Profits were also strong at the larger 

oilfield services companies, that continue 

to benefit from the upturn in upstream 

activity, as well as national oil companies 

(NOCs) generally. However, Brazil’s NOC, 

Petrobras, actually reported a drop in profits 

this quarter of 26 percent as government 

price controls prevented it from capitalizing 

on high crude prices and its fuel costs 

increased. Petrobras’ profit was curbed by 

price controls for gasoline and diesel while 

a weaker local currency increased imported 

fuel costs. (Petrobras’ gasoline imports quadrupled 

this year to about 30,000 b/d.) 78

Observation 

Analysts are starting to look beyond the 

bumper profits many of the oil companies 

announced on the back of higher oil prices, 

and are now looking for evidence of how 

the oil majors in particular, can maintain 

income growth if production is falling. 

After six or seven quarters of strong profit 

growth driven by rising oil prices, it is looking 

doubtful as to whether companies can 

continue to increase earnings next year and 

beyond, if oil prices start to plateau or fall. 

Challenges for oil companies are not only 

limited to the upstream part of the business. 

While downstream profits were 

also strong this quarter, this environment 

continues to be difficult. Companies are 

dealing with stagnating demand in OECD 

markets and refining overcapacity with 

more new refining capacity being added 

especially in the Middle East and Asia. 

(There is significant new refining capacity 

coming on-stream between 2015–2017 and 

continued structural overcapacity, which 

is likely to result in continued massive closures, 

particularly in OECD markets.) Globally, 

according to data from the IEA, crude 

distillation capacity is expected to increase 

by 9.6 million b/d between 2010–2016, of 

which 95 percent will be located in non- 

OECD nations like India and China. (China 

alone is estimated to account for around 

40 percent of oil demand growth between 

2010 and 2016.) 79 

The growth outlook for downstream activities 

in Asia is also not without its concerns. 

Some analysts are predicting that Asian 

refiners could earn as much as 20 percent 

less in 2012 from processing a barrel of 

crude into product than this year’s average, 

as they get squeezed between new additions 

to capacity and expectations of slowing 

global demand growth. Refiners who do 

not have more complex refineries could be 

forced to cut production with those refiners 

planning expansions and facing delays due 

to declining demand. Most refiners continue 

to look to China for positive news, and more 

specifically, to China’s gasoil demand which 

is increasingly driving higher margins for 

refiners. 80 

15 

Generally in the downstream sector, oil 

companies are increasingly focusing on 

what they can do to reduce costs, improve 

process efficiencies and how they can 

use technology to better manage refining 

portfolios. Some are choosing to deintegrate 

their operations, like Marathon or 

ConocoPhillips, and are spinning off their 

downstream operations into a separate 

company. Others, like Total, are reorganizing 

their downstream operations into a more 

integrated operation, effectively merging 

its refining and petrochemicals operations 

together. For smaller refiners, that do not 

have integrated operations, one solution 

might be to see how they can mimic what 

Total is doing by completely integrating 

refining and petrochemicals and looking for 

partnerships with petrochemical companies, 

to offset declining refining margins or to 

see how they can best position themselves 

to access high growth markets like China. 81 

Demand for gasoil/diesel in China looks 

strong in both the short and long term. 

Refiners in China in October 2011 bought 

about 320,000 tonnes of diesel to cover 

domestic shortages of diesel (used for 

power generation during times of shortage). 

High Chinese demand for diesel is likely 

to continue to support refinery margins 

for producing diesel into the early months 

of 2012, according to industry analysts. 82 

Longer term, gasoil demand in China 

is expected to increase to around 4.5 

million b/d by early 2016, and it is likely 

to continue to underpin refining margins 

over this period. 83

Endnotes 

1 “Medium Term Oil and Gas Markets 2011, 

IEA, ©OECD/IEA. 

2 “Kinder Morgan’s El Paso deal forms new 

pipeline giant,” October 17, 2011, The Globe 

and Mail, via Factiva, © 2011 The Globe and 

Mail Inc. 

3 Quarterly Transaction Review Report, © 

IHS Herold, Inc. 

4 “Seaway oil pipe to be reversed after 

Enbridge deal,” November 16, 2011, Reuters 

News, via Factiva, © 2011 Reuters Limited. 

5 IMF World Economic Outlook Update, 

“Slowing Growth, Rising Risks,” September 

2011, © 2011 International Monetary Fund. 

6 “IEA Oil Market Report,” November 10, 

2011, © OECD/IEA - http://omrpublic.iea.org. 

7 “For S&P 500 Trajectory Clues, Look To 

Oil,” November 9, 2011, Dow Jones News 

Service, via Factiva, © 2011 Dow Jones & 

Company, Inc. 

8 Ibid. 

9 “IEA Oil Market Report,” November 10, 

2011, © OECD/IEA - http://omrpublic.iea.org. 

10 Ibid. 

11 “US oil rig count at record high-Baker 

Hughes,” November 4, 2011, Reuters News, 

via Factiva, © 2011 Reuters Limited. 

12 IMF World Economic Outlook Update, 

“Slowing Growth, Rising Risks,” September 

2011, © 2011 International Monetary Fund. 

13 Ibid. 

14 Ibid. 

15 “OECD predicts recessions in UK and 

Eurozone,” November 28, 2011, Guardian 

Unlimited, via Factiva, © Guardian 

Newspapers Limited 2011. 

16 “Market test looms; Initial financial 

tick on Italy faces series of bonds hurdles,” 

November 15, 2011, The Daily Telegraph, 

via Factiva, © 2011 News Ltd. All Rights 

Reserved. 

17 

17 

17 “Disaster reform eyed for oil industry,” 

November 18, 2011, Daily Yomiuri, via 

Factiva, © 2011 The Daily Yomiuri All 

Rights Reserved. 

18 “Standard Chartered Lowers China 

Growth Outlook,” October, 25 2011, Dow 

Jones International News, via Factiva, © 

2011 Dow Jones & Company, Inc. 

19 “China’s economy may face hard 

landing; analysts see ominous signs in 

credit, employment and monetary policy,” 

October 25, 2011, MarketWatch, via 

Factiva, © 2011 MarketWatch, Inc. All 

Rights Reserved. 

20 IEA Oil Market Report, October 12, 

2011, © OECD/IEA, http://omrpublic.iea.org/ 

omrarchive/12oct11full.pdf. 

21 Ibid. 

22 “Offshore drilling permits soaring 13 

wells OK’d in October are seen as sign of 

new confidence,” November 3, 2011, Houston 

Chronicle, via Factiva, © 2011 Houston 

Chronicle. 




24 Ibid. 

25 “Views Differ on Restoring Libyan Oil 

Output,” October 12, 2011, The New York 

Times, via Factiva, © 2011 The New York 

Times Company. 

26 “Iraq oil starting to come on strong,” 

October 31, 2011, CNN Money, via Factiva, 

© 2011 Cable News Network. A Time Warner 

Company. All Rights Reserved. 

27 “ExxonMobil to Explore for Oil in Iraqi 

Kurdistan,” November 11, 2011, Dow Jones 

Business News, via Factiva, © 2011 Dow 

Jones & Company. 




29 Ibid. 

30 Ibid. 

31 “Japan burns 200,000 bpd more crude 

for power in October,” November 14, 2011, 

Reuters News, via Factiva. © Thomson 

Reuters. 

32 “Disaster reform eyed for oil industry,” 

November 18, 2011, Daily Yomiuri, via Factiva, 

© 2011 The Daily Yomiuri. 




34 “Russia oil output hits new high after 

duty cut,” November 2, 2011, Reuters News, 


35 “Nymex Crude Gains On Pause In Europe 

Worries,” November 18, 2011, Dow Jones 

Business News, via Factiva © 2011 Dow 

Jones & Company, Inc. 

36 “J.P. Morgan raises WTI price forecasts 

for 2012, 2013,” November 16, 2011, Reuters 

News, via Factiva, © Thomson Reuters. 

37 “For S&P 500 Trajectory Clues, Look To 

Oil,” November 9, 2011, Dow Jones News 

Service, via Factiva, © 2011 Dow Jones & 

Company, Inc. 

38 “Enbridge reverses oil pipeline toward 

Gulf; Seaway Crude pipe can carry up to 

400,000 barrels from Cushing,” November 

16, 2011, MarketWatch, via Factiva, © 2011 

MarketWatch, Inc. 

39 “Medium Term Oil and Gas Markets 

2011,” IEA, © OECD/IEA. 

40 “Russia oil output hits new high after 

duty cut,” November 2, 2011, Reuters News, 


41 “Short Term Energy Outlook,” November 

8, 2011, US Energy Information Administration, 

© EIA. 

42 “BG Inks Landmark US Gas Export Deal 

With Cheniere,” October 26, 2011, Dow 

Jones International News, via Factiva, © 

2011 Dow Jones & Company, Inc. 


2011, IEA, © OECD/IEA. 

44 “Lower Natural Gas Prices Will Impact 

E&P Stocks,” October 21, 2011, Barron’s 

Online, via Factiva, © 2011 Dow Jones & 

Company, Inc. 

45 “Low gas price challenge for J.P. 

Morgan-Cheniere deal,” November 7, 2011, 

Reuters News, via Factiva, © 2011 Reuters 

Limited.

46 “UK gas prices drop on milder weather 

forecast,” November 23, 2011, Reuters 


47 “RWE breaks free from some expensive 

gas contracts,” November 10, 2011, Reuters 

News, via Factiva © 2011 Reuters Limited. 


8, 2011, US Energy Information Administration, 

© EIA. 

49 “LNG Surges as Japan Vies With China, 

Exxon’s Shipments Grow,” September 19, 

2011, Reuters News, via Factiva, © 2011 

Reuters Limited. 

50 Ibid. 

51 Ibid. 



53 “UK faces colder-than-normal winter— 

National Grid,” October 11, 2011, Reuters 


54 “High EU gas prices at odds with big 

supply surplus,” October 21, 2011, Reuters 



8, 2011, U.S. Energy Information Administration, 

© EIA. 

56 “LNG Surges as Japan Vies With China, 

Exxon’s Shipments Grow,” September 19, 



57 “Europe to order 70 GW of gas plants by 

2017,” September 4, 2011, Reuters News, 


58 “Indonesia to allow private industry to 

import gas,” July 18, 2011, Reuters News, 

via Factiva, © Thomson Reuters. 




60 Ibid. 

61 Ibid. 

62 Ibid. 

18 

18 

63 “Global Refining Surplus Could Reach 

10 million b/d by 2015, November 8, 2011, 

Dow Jones Newswires, via Factiva, © Dow 

Jones International News. 

64 “ConocoPhillips’ Refining Margins 

Impacted as Refineries Have Trouble Keeping 

Up with Production,” November 22, 

2011, Trefis.com, via Factiva, http://www. 

trefis.com/stock/cop/articles/86442/conocophillips-refining-margins-impacted-asrefineries-have-trouble-keeping-up-withproduction/2011-11-22. 

65 “EU diesel tax proposal could help 

refining sector—OPEC,” November 8, 2011, 


Limited. 

66 “Oil, gas sector ripe for picking as 

mergers surge; Shale resource plays 

contribute to merger & acquisition boom,” 

October 21, 2011, Market Watch, © 2011, 

MarketWatch, Inc. All Rights Reserved. 

67 IHS database, © IHS Herold, Inc. 

68 Ibid. 

69 Ibid. 

70 “Oil, gas sector ripe for picking as 

mergers surge; Shale resource plays 

contribute to merger & acquisition boom,” 

October 21, 2011, Market Watch, © 2011 

MarketWatch, Inc. All Rights Reserved. 

71 “Deal to Create Pipeline Giant—Shale- 

Gas Frenzy Drives Kinder Morgan’s $21.1 

Billion Offer for El Paso Corp,” October 17 

2011, The Wall Street Journal, via Factiva, 

© 2011, Dow Jones & Company, Inc. 

72 “US natgas rig count at 22-month low,” 

November 23, 2011, Reuters News, © 2011 

Reuters Limited, via Factiva. 

73 “Pace of US Gulf Drilling Permits Has 

Picked Up,” October 4. 2011, Dow Jones 

Newswires, via Factiva, © 2011 Dow Jones 

& Company, Inc. 

74 “Singapore Hot Stocks—Rig builders up 

on order hopes,” October 17, 2011, Reuters 


75 “For oil explorers, it pays to buy, not 

rent,” September 16, 2011, Reuters News, 


76 “Oil Majors to report Q3 profit jump, 

investor’s eye 2012,” October 21, 2011, 


Limited. 

77 “Higher prices help Big Oil profits, but 

production slowdowns raise concerns about 

supplies,” October 27, 2011, Associated 

Press Newswires, via Factiva, © 2011 The 

Associated Press. All Rights Reserved. 

78 “Petrobras Profit Slides 26 percent on 

Currency, Higher Fuel Costs,” November 11, 

2011, Reuters Reuters News, via Factiva, © 

2011 Reuters Limited. 



80 “Asia 2012 refining profits to fall on 

new capacity, cooler demand,” November 

2, 2011, Reuters News, via Factiva, © 2011 


81 Ibid. 

82 “China makes rare diesel imports to 

cover domestic shortages,” November 4, 




2011, IEA, © OECD/IEA.

About Accenture 

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