Oil Buyer's Guide 2013 Review

2013 Year end review

Oil Buyer’s

Guide

OutlOOk 2014: VOicesRegulators, executives, and analysts weigh in on the export ban and the widening spread. Page 4

differentialsBrent’s premium to WTI began to widen again in the second half of the year as the longer-term differential was expected to widen further. Page 5

reGiOnal differentialsBakken crude differentials are seen narrow-ing as more rail and pipeline options become available. Page 6

VerBatim: PrOductiOn fOcusExxon says it expects global shale develop-ment to take time to develop amid legal hurdles and other obstacles, as companies reflect on the past year and look to 2014. Page 7

OPecOPEC’s production declined in 2013 amid dis-ruptions in Libya and plunging Iranian exports. Page 8

demand OutlOOk Modest demand is expected as production continues to rise in 2014. Page 9

refininG OutlOOk U.S. players were favored in 2013 as the shale boom caused a decoupling of U.S. and Euro-pean margins. Page 10

lnG OutlOOkThe U.S. is shifting to exporting LNG as terminals are proposed to meet growing gas production. Page 11

Q&aPortfolio manager Ed Cowart says to watch companies with Permian exposure in 2014. Page 12

cOntents

stOry Of tHe year: tHe sPread by Grant Smith, bloomberG newS

The price gap between the world’s two biggest oil benchmarks probably will nar-row this year as U.S. exports of refined fuels reach a record and crude supply from the Middle East and North Africa recovers.

West Texas Intermediate, the U.S. benchmark, will average $6 a barrel less than Europe’s Brent in 2014, from almost $15, according to Commerzbank AG. Goldman Sachs Group Inc. is predicting $9 and Barclays Plc $8.

While the U.S. is pumping the most crude oil in a quarter century, laws prohibit most exports, driving down costs for domestic refiners and spurring record shipments of everything from diesel to gasoline. The forecasters expect Brent prices to weaken as regional supply recovers, led by Iran and Libya.

Brent futures for February settlement on ICE Futures Europe in London closed at

$106.75 a barrel on Monday, for example, $14.95 more than the corresponding WTI contract on the New York Mercantile Exchange. The spread averaged $10.65 last year, reaching as high as $23.44 on Feb. 8.

WTI also may rise because of expand-ing pipeline capacity from Cushing, Oklahoma, where the crude is priced, to America’s refining hub on the Gulf Coast. Stockpiles of 40.7 million barrels at Cush-ing are 21 percent lower than a year ago, government data show.

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“Ask me that question again in 15 min-utes! I think the spread will narrow, but it just widened a little again on the news of disappointing U.S. production and inven-tory and ongoing issues in the Middle East. We could be seeing an upside bias on WTI crude soon due to a number of factors, including the opening of the southern leg of Keystone, expectations of a decision on Keystone XL, talk of lifting the crude export ban, and re-opening of the Sharara oil field in Libya. There are so many factors that come into play in world markets, I don’t think anyone can say with certainty one way or the other.”

— Chris Faulkner, CEO of Breitling Oil Corp.

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By tHe numBers Compiled by JeSSiCa reSniCk-ault

$98.05 average wti price

$108.70 average brent price

39% amount the brent-wti spread narrowed from 2012

30.58 average opeC daily production milliOn BaRRels

7.36 average u.S. daily production milliOn BaRRels

31% increase in average monthly north american railcar loads of oil

37% increase in railroad incidents involving crude

377 average 2013 u.S. crude in storage milliOn BaRRels

99.2 average 2013 crude in offshore storage milliOn BaRRels

$89.35 price of one exxon mobil share

5.59 barrels of reserves per exxon share

$548 Cost of 5.59 barrels of wti at the end of 2013

25 place exxon mobil would have among world powers, if its revenue were Gdp

3 increase in u.S. diesel exports

1% decrease in u.S. domestic diesel prices

23,215 China’s monthly crude imports, in metric tons

$637 Cost of an average oil and gas m&a deal by a Chinese company milliOn

$330 Cost of an average oil and gas m&a deal by a u.S.-based company milliOn

9.7% 2013 proposed cut to ethanol volumes required by the renewable Fuels Standard of 2007

5% ethanol production decline since eia measurements began in 2011

1.7% year-on-year decline in the newedge Commodity trading index of hedge Funds

86% decline in assets under management at energy hedge fund Vector Commodity management in first four months of 2013

18 mOnths amount of time higgs Capital commodities hedge fund was open before closing due to lack of capital stability

32% traders and analysts surveyed by bloomberg who said they had little confidence in assessed prices of crude and other commodities

3 u.S. lnG export projects approved in 2013

$9.277 premium for lnG in Japan over lnG in u.S. a mmBtu

58 average age of a top 10 oil Ceo

58 age of hugo Chavez at his death in 2013

97.5% Value lost by oGX in 2013

$449 amount oGX owed for a platform at a non-producing field milliOn

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OutlOOk 2014: VOices

Energy executives, analysts and regulators expect a review of U.S. oil export policies may begin in 2014 as refined product shipments continue to soar. The year ahead also holds the potential for approval of TransCanada’s Keystone XL pipeline and unrest in the Middle East. Comments from interviews and conferences, including the Platts Global Energy Outlook Forum, have been edited and condensed.

— Jessica Resnick-Ault

On persistence with Keystone: “From what I can see they’re still refining 7.5 million barrels a day in the Gulf Coast. 4.5 million barrels a day of that is imported from elsewhere around the globe. U.S. multi-nationals and others are developing the oil sands. That hasn’t stopped. So when our shippers tell me ‘We no longer want to connect growing production in the Bakken and growing production in Canada with those refiners in the Gulf Coast’ is when we give up. And at this point in time, 100 percent of those shippers continue to sup-port us through their long-term contracts.”

Russ Girling, CEO TransCanada

“We’ll see product exports go up slightly in the near term. The U.S. is exporting 3 million barrels a day, so we’re actually a net exporter of oil products. There is an in-creasing production of light sweet crudes, with 1.3 million barrels a day from the Eagle Ford, and we’re getting more from the Permian Basin. Five years ago, the U.S. was making huge investments to run heavy crude on the Gulf Coast, so some of this crude is going to the East and West Coasts, and some to Canada. There’s a whole range of solutions that the market will come up with.”

Adam Sieminski, U.S. EIA Administrator

On exports: “That law was a child of the 1970s. We will provide data to the Depart-ment of Commerce if they want to evalu-ate a change. We are aware that there are big differentials.”

Ernest Moniz, U.S. Energy Secretary

“I’m a free market proponent, so we should let everything go where it wants to go. People are starting to realize that eventually it will happen, but, like always, we’ll wait until it hurts.”

Charif Souki, CEO Cheniere Energy

“We need to act before the crude oil export ban causes problems in U.S. oil production, which will raise prices and therefore hurt American jobs.”

Lisa Murkowski, Senator, R-Alaska

“Well the thing about this year compared to 2011 is you had the same amount of disruption as 2011. We had at one point this year nearly 3 million barrels off the market. But the difference this time around is North America. If we didn’t have the North American story, we’d be at a much higher price environment right now. So what you want to watch for in 2014 is, do we have another big producer go offline? If we have problems for example in Iraq, I think that’s what would propel us to a significantly higher price environment.”

Helima Croft, Barclays Analyst

u.s. Product shipments rise on u.s. crude export Ban; Brent Premium could Grow on unrest

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CO1 Comdty (Generic 1st 'CO' Future)CL1 Comdty (Generic 1st 'CL' Future)Brent - WTI

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Bloomberg ®Charts 1 - 1

.ARB48M U Index (WTIBrent 48month out ARB)



the Wti-Brent spread Widened in 2013 Because of abundant north american supply

despite short-term narrowing, long-range expectations Veered toward a Wider spread

Source: Bloomberg LP


differentials defined by mario de la oSSa, bloomberG Commodity SpeCialiSt

WTI Declined in Fourth Quarter as Spread Widened

Long-Term Brent-WTI Spread Widens on Mid-Continent Outlook

The spread between WTI and Brent averaged $10.63 in 2013, compared with $3.94 over the past decade. The widening gap reflects an abundance of U.S. supply at a time of disrupted exports from Iran, Iraq and Libya. Brent prices will average $105 a barrel in 2014, from $108.71 in 2013, according to the median of esti-mates from the seven analysts who most accurately predicted this year’s level in a survey last December. Global supply is expanding as the U.S. pumps oil trapped in shale-rock formations, driving domestic output to the highest in a quarter century and curbing demand for the crude priced off Brent. Iran, Iraq and Libya will also pro-duce more in 2014, the forecasters said.

— Grant Smith, Bloomberg News

The chart of the four-year-out WTI-Brent contract models a long-term fair value for WTI compared with Brent over time. While there may be some short-term narrowing as U.S. runs pick up and Libyan produc-tion returns, the market expects a wider spread over the next four years. A supply surplus on the WTI side, more than a Brent phenomenon, has contributed to the widening. The four-year spread jumped in June after a seasonal slowdown in U.S. refinery runs, which cut demand for U.S. crude grades, leading to oversupply. Any relaxing of the U.S. ban on exports could alter the spread.

—Mario De La Ossa, Bloomberg Commodity Specialist

SEE THE PLAY. BE THE PLAY. KNOW WHAT’S MOVING IN COMMODITIES BEFORE YOU MAKE YOUR MOVE CPLY <

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Bakken vs.LLS Discounts Stay Near Rail Parity

Discounts Narrowed in June, Then Widened

Discounts for U.S. Crude Expected to Narrow

USCSUHC1 Index (Bloomberg Bakken (Clearbrook MN) Crude Oil Differential)USCSLLSS Index (Bloomberg Light Louisiana Sweet Crude Oil Differential)USCSLLSS Index - USCSUHC1 Index



USCSSYNS Index (Bloomberg Syncrude Sweet Blend Crude Oil fob Edmonton Spot DIfferential)USCSUHC1 Index (Bloomberg Bakken (Clearbrook MN) Crude Oil Differential)USCSWCAS Index (Bloomberg Western Canada Select Crude Oil Differential)WCS Diff vs. Brent (USCSWCAS Index + ENCO1 Index)



FLDSY 14 Index (Bloomberg Fair Value Price/Lig).IMPBKNDF U Index (Cal14ImpliedBakkenDiff)



Source: Bloomberg

Source: Bloomberg

Source: Bloomberg

The discounts for syncrude, Bakken crude and WCS narrowed in June as attractive refining margins resulted in high refinery runs. The discounts then widened in the second half of the year and began to narrow as the year drew to a close amid announcements of improved rail terminals and pipeline networks.

The discount for buying Bakken crude from North Dakota instead of Light Louisiana Sweet crude on the Gulf Coast narrowed in 2014 as more pathways to market opened up. Bakken crude ended the year right above rail parity — about $12 a barrel — the cost for transporting the crude to the Gulf Coast by rail.

The 2014 LLS forward curve suggests a $4.00 premium to WTI, a sub-stantial discount to 2013’s average of $9.35. Using a rail transport cost of $12.25 to the US Gulf Coast implies a Bakken value of $8.25 under WTI. The bullish outlook for U.S. Gulf Coast refining combined with improving rail and pipeline logistics supports the narrower Bakken discount.

reGiOnal differentials by mario de la oSSa, bloomberG Commodity SpeCialiSt

u.s. differentials Began to narrow in late 2014 ahead and are expected to contract further

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VerBatim: PrOductiOn fOcus Compiled by JeSSiCa reSniCk-ault

Shale developments, obstacles to production and predictions for 2014 dominated executives’ remarks at conferences and on calls in De-cember and January. Below is a compilation of recent quotes on the sector by oil companies’ management teams. Comments have been edited and condensed. For full transcripts from outlook calls and conferences, enter TNI OIL TRANSCRIPT<GO>

“Unconventional resources do exist in lots of other places around the world. And we and many other companies are working with these countries to help develop those resources. And yet what you’ll see is most of those tend to come in later in the outlook, because for lots of reasons including the legal struc-ture, it’s going to take time to develop those resources in other places and it’s going to be very country specific. So if you look at our outlook, you do see significant growth and unconventional resources everywhere in the world, but it comes in later as they kind of follow North America.”

— Exxon Mobil Vice President of Strategic Plan-ning, William Colton, speaking on the company’s

conference call on its global outlook.

“In 2014, we have a bit of a unique op-portunity, because we are going into a

exxon sees Global shale lagging; newfield sees u.s. shale Projects on the rise

Analysts’ Estimates for Oil Production and Earnings: EEO <GO>, enter ticker, and then 4<GO>.

cOmPany market caP (in BilliOns) 2013 GaaP ePs estimate 2013 PrOductiOn 2013, kBOe/d

analysts’ PrOductiOn fOrecast in kBOe/d

Exxon Mobil Corp. $434.97 $7.42 4,239 4,251.00

Chevron Corp. $235.47 $11.39 2,610 2,657.40

Royal Dutch Shell $229.59 $3.27 3,262 3,220

PetroChina $224.74 $0.11 3,697 NA

BP Plc $151.72 $1.22 3,310 3,522

Total SA $140.84 $6.33 2,300 NA

Gazprom $99.06 $1.45 8,771 NA

Eni SpA $86.63 $2.50 1,701 1,718

ConocoPhillips $85.35 $6.85 1,578 1,523

Source: Bloomberg

year where we do not have major turn-arounds. We do have maintenance. The numbers will ebb and flow but not like you’ve seen in the last several years. So it’s going to be a fantastic opportunity for our team to be able to demonstrate some of the progress that we’ve made.”

— Suncor Vice President of Oil Sands & in Situ, Mark Little, speaking on the company’s analyst

day teleconference.

“We look at it a couple of different ways. Our Mississippian and Permian and other zones that we’re finding in our mid-continent business have matured to a point where we are ready to invest more capital in it. So why do this now versus later? We think a couple things. The Gulf of Mexico, it’s a higher risk, more volatile business in our earnings stream. It was masking some of the growth in our on-shore business, and we’re at a point now where we’re ready to redeploy that capi-tal. Our job as managers is to deploy the shareholders’ capital where we think we can get the best risk-adjusted return. So for us, taking this and putting it back into our mid-continent and onshore business we think is the right move longer term for shareholders.”

— SandRidge CEO James D. Bennett, speaking on the company’s conference call about selling its

Gulf of Mexico assets.

“When you look at our production in 2013 in the third quarter, we grew sequentially 14 percent over Q2 and year-over-year we’re at nearly 300 percent volume growth. We’ve given guidance that we’ll be at 18 rigs on average for 2014. I’m going to guess we’ll probably be at 18 rigs by the middle of the first quarter. So we are ramping up there. We have some examples of some recent completions. We’re currently at 320,000 net acres under lease. We’re still leasing.”

— Continental Resources Senior VP Richard Muncrief, speaking at the Capital One SouthCoast

Energy Conference.

“As far as our execution, as I’ve already said, we brought forward what I remem-ber in February being described as a robust, aggressive, lofty plan of growth over the next three years, and we’ve made the numbers. I think we raised guidance three times throughout the year. And again, when you actually think of our individual cost structure, in every single item we either made it or beat it in 2013. And we worked very hard to make sure that trend is going to continue in 2014 and 2015, and now, also in 2016.”

— Newfield Exploration COO Gary Packer, speaking at the CapitalOne Southcoast

Energy Conference

1 2 3 4 5 6 7 8 9 10 11 12


OPEC Output Declined with Global Oil Demand

Iran’s Oil Exports Plunged on U.S., EU Sanctions

Libya 2013 Production Fell Below 2012 Recovery

‘Incessant’ Theft, Sabotage Curb Nigerian Output

0

5

10

15

20

25

30

35

J F M A M J J A S O N D

Mill

ions

of B

arre

l/Da

y

Ecuador Venezuela Libya AngolaAlgeria Nigeria Qatar IranUAE Kuwait Iraq Saudi Arabia

Source: Bloomberg

2011

2012

2013 Iran

OPEC Ex-Iran


2011

2012

2013 Libya

OPEC Ex-Libya


2011 2012

2013 Nigeria

OPEC Ex-Nigeria


Kuwait and the UAE increased their production by 5.3 percent and 4.7 percent, respectively, in 2013 to make up for some of the shortfalls as Libya, Iran and Nigeria pumped less oil. Algeria’s output declined by 6 percent to 1.16 million b/d from 1.23 million b/d in 2012.

Iran’s oil exports plunged to about 1 million barrels a day last year from 2.5 million before sanctions started in 2012 that barred banks and insurers from handling sales of the fuel. The plan to ease the reinsurance ban is scheduled to take effect on January 20.

Ninety days of protests at Libya’s 300,000 b/d Sharara fields ended in December, raising chances for increased production in 2014. Disruptions at the nation’s ports and oilfields pushed production to 210,000 b/d in November and December, from a 2013 peak of 1.4 million b/d in March.

“Incessant crude oil theft” reduced Nigerian oil production to 1.89 million b/d in the third quarter of 2013, according to a central bank report. Sabo-tage related to political unrest also reduced output, prompting Chevron and several other foreign producers to seek buyers for their oil leases.

OPec WatcH Compiled by deirdre Fretz

OPec Production declined 3.4 Percent in 2013 on lower demand, disruptions in libya Output in the 12-member Organiza-

tion of Petroleum Exporting Countries declined to an average of 30.7 million barrels a day in 2013. That’s 3.4 percent less than 2012.

Saudi Arabia’s output varied from a low of 9 million barrels per day in February when it implemented a program aimed at curbing excess supply and supporting

prices, to a 24-year high of 10 million b/d in September to make up for lost produc-tion elsewhere.

Libyan output fell to 832,000 barrels per day for the year, a 39 percent decline from a year ago as the new government’s efforts to revive the oil industry were sty-mied by feuding militias and protests.

Production in Venezuela declined 8.8

percent in December to 2.45 million b/d. The nation may add to the fluctuations in OPEC output in 2014.

“The economic situation in Venezuela is very bad and the non-petroleum sector is in desperate need of dollars, causing PDVSA to have to dedicate more money to the Central Bank,” said Carlos Rossi, president of EnergyNomics on Dec. 31.

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0

10

20

30

40

50

60

China U.S. OECD Europe Rest of World

% o

f Wor

ld To

tal

% of World Oil Demand % of World GDP

Source: IEA, IMF

0

0.2

0.4

0.6

0.8

1

1.2

1.4

1.6

1.8

OPEC IEA EIA

Mill

ion

Barr

els

Incremental Barrels Supply

Incremental Barrels Demand

Source: OPEC, IEA, EIA Bloomberg

modest demand seen in the face of rising Production from shale in 2014

major Projections all suggest crude supply Will Outpace demand again in 2014

demand by VinCent G. piazza, bloomberG induStrieS

U.S., Europe, China Drive Incremental Oil Demand

Oil Supply Forecast to Outrun Demand in 2014

Major themes affecting the crude oil industry include more modest demand caused by shifting demographics and fuel efficiency in the developed econo-mies, as well as tepid demand in China, which may be brought upon by more measured GDP growth. The U.S., Europe and China account for more than 50 percent of global GDP and roughly 47 percent of oil demand. Oil demand in the U.S. and Europe has been steadily declining, given the maturation of the population and fuel efficiency standards. In China, incremental oil demand growth may have peaked as attempts are made to neutralize the impact of pollution and modernize its fossil fuel-based economic structures. In the long term, this may suggest lower oil demand.

Projections of incremental crude oil supply from OPEC, the IEA and the EIA all sug-gest supply will outpace demand in 2014. Incremental crude oil supply grew by 1.3 million barrels a day in 2013 compared with incremental demand of 0.8 million barrels a day, according to the IEA. Higher supply is also expected in 2014 and should suppress an oil price rise absent exogenous events such as extended geo-political hostilities, which tend to depress interim crude oil capacity. Key crude oil industry indicators continue to point to higher supply, driven by growth in North America. U.S. crude oil output has risen 17 percent from a year earlier. Crude oil inventories remain above historical aver-ages both globally and in the U.S.


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CRKS321C Index (Bloomberg WTI Cushing Crude Oil 321 Crack Spread/US Gulf Coast)CRKS321M Index (Bloomberg Minas Crude Oil 321 Crack Spread/Asia)CRKS321B Index (Bloomberg Dated Brent Crude Oil 321 Crack Spread/Northwest Europe)



OLCATWLD Index (BP Statistical Review Global Crude Oil Refinery Capacity)OLCATEUR Index (BP Statistical Review Europe Crude Oil Refinery Capacity)OLCATFSU Index (BP Statistical Review Former Soviet Union Crude Oil Refinery Capacity)



the u.s. shale Boom Has caused a decoupling of refiners’ margins, favoring u.s. Players

Growth from new markets may trump taxes Weighing on european refiners



refininG OutlOOk by VinCent G. piazza and philipp Chladek, bloomberG induStrieS

Refiners Have Similar Processing and Manufacturing Costs

Overcapacity Weighs on Margins as Plants Remain Open

Global refining margins, known as the 3-2-1 crackspread, have historically been linked, with North America, Europe and Asian margins following a similar pattern until 2011. Margins have since decoupled due to the rapid growth of U.S. light sweet crude oil production, along with transport and refining capacity bottlenecks in the U.S. Lower-cost crude feedstock due to plentiful domestic volume output, less expensive natural gas powered by shale production, higher plant complexity and a more developed infrastructure offers U.S. refiners a profound and sustainable competitive advantage relative to peers across the Atlantic and other regions. This advantage may be more defensible longer term given closures of legacy, mature capacity and the difficulties in constructing new plants.

With dependable and less costly domestic production of both crude and shale gas increasing, U.S. refiners possess a margin advantage relative to foreign peers. For European refiners, bulls focus on growing demand in Turkey and Russia, as well as new marine fuel sulfur content regula-tions that may boost diesel needs. Bears counter that new taxes may lower diesel demand, while U.S. shale removes an important export market. Less gasoline use and biofuel competition may lead to further plant closures. An end to the politi-cally motivated boycott of Iranian crude oil purchases may reopen a substantial sup-ply source for nearby refiners, especially in the eastern Mediterranean.


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lnG OutlOOk Compiled by deirdre Fretz

u.s. to shift from importer to exporter after Becoming first in Global natural Gas ProductionThe U.S., the world’s largest producer

of natural gas since 2012, will become the third-largest exporter of LNG by 2020, Morgan Stanley estimates.

There are 50 proposed and operating LNG terminals in the U.S. designed to import the fuel for proprietary use or for wider distribution. Many are now planning to retool their facilities for export.

Cheniere Energy Inc.’s terminal at Sabine Pass, Louisiana, this year became the first in the U.S. lower 48 states to ob-tain all the licenses required to export gas.

“The major driver that supports exports is the differential between natural gas in the U.S. versus Asian LNG pricing,” said Bobby Gaspard, vice president of LNG marketing at Freeport LNG Development

LP, which is planning a Texas export ter-minal for 13.2 million tons by 2019.

Natural gas prices in Japan were about $16.90 per million Btu at the end of 2013, or about four times the price in Texas.

When the newly widened Panama Canal opens in 2015, it will reduce the cost of shipping LNG from the U.S. Gulf Coast to Asia, furthering the flow of exports.

LNG Imports to China Rise, Shipments to the U.S. Decline (Volume, in billions of cubic meters)

lOcatiOn 2013 2012 2011 2010 2009 2008asia 210.575 225.672 206.654 180.367 154.137 161.614 to China 21.203 20.023 16.612 13.477 7.506 4.556 to Japan 107.933 118.504 107.065 95.299 87.708 94.124 to South Korea 48.725 49.308 49.927 44.371 34.230 38.905eurOPe 50.557 70.438 89.515 88.070 72.312 58.671 to Spain 15.611 21.764 24.015 28.483 27.796 30.187 to United Kingdom 9.369 14.468 24.927 18.633 11.043 1.197nOrtH america 11.664 14.105 18.657 22.659 19.590 14.562 to Mexico 6.055 4.640 4.188 5.675 3.175 2.659 to United States 2.598 4.987 10.155 12.702 12.902 10.013 to South America 12.963 12.543 9.673 8.587 2.182 0.526

Source: DTN

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Q & a

Ed Cowart, portfolio manager and managing director at Eagle Asset Management, spoke with the Oil Buyer’s Guide’s Jessica Resnick-Ault about the outlook for 2014 and beyond. Cowart is an energy sector specialist and oversees Ea-gle’s Equity Income program, including holdings such as Chevron Corp., Occidental Petroleum Corporation, ConocoPhillips and Honeywell.

Q: We’ve started 2014 with very cold weather. What does this mean for oil companies and production? A: This is really going to disrupt some production in the colder areas — this is, afterall, an outdoor activity and at some point you can’t put people outside when it gets too cold. Sometimes it gets too cold for the infrastructure as well — sometimes things freeze up. In terms of working these into an investment thesis, this is really a non-event. There will be some service companies — Weatherford, Baker Hughes and Halliburton — that I suspect will reference the cold weather in their earnings reports. The projects will be deferred, but business is not lost because of this, infrastructure isn’t destroyed. It’s like a strike. They pass, and then business goes back to usual.

Q: For 2014, how do you expect the spread to develop? Do you expect U.S. crudes to continue to be discounted?A: I think it stays pretty wide. If we get Libya, Iraq, maybe even Iran back online, which I think is a low odds probability, but is not out of the question, that will tend to squeeze the Brent price down a bit. But it doesn’t look like the market is anticipating a lot from any of those three countries. What we have on the other side is pretty strong demand from emerging markets.The story there is still energy intensity, which is still below what the developed markets are seeing. In terms of the spread, I don’t think we go back to $20 but $8 to $12 is a pretty good number for the next few months. That’s more of a guess than a forecast.

Q: What’s your outlook for the shale revolution? A: We know that there’s not any other province out there in terms of black oil. I

Watch eOG and Pioneer in 2014 amid Permian Growth, eagle asset’s ed cowart says

Age: 65

Education: Dartmouth College, Bachelor’s Degree

Recent Read: Private Empire, about the history of Exxon Mobil, which explains about how the greatest planning company in the world planned for all the wrong things, like high natural gas prices and low oil.

Warm-Weather Vacation Spot: South Florida — we’re not all the way down south — but this is a place people like to come in the winter! But I don’t mind visiting winter as long as I know I can leave.

think there’s a limit to how much domestic production is going to rise. While that is going on, we’re going to have pressure on domestic prices, because of a lack of infrastructure. No one had expected we would need to take crude from the middle of the country to the edges.

Q: Do you think the Keystone XL pipe-line will get approved? A: The odds are slightly in favor, but I don’t think it’s a slam dunk. The Keystone goes through an area that’s already cov-ered in pipelines. I don’t believe there is a principled objection to Keystone.

Q: As we look at the different shale ba-sins, there’s been a lot of talk about the Permian. What’s your take on that?A: I like the Permian a lot, too, because it is such a complex geologic formation. The industry has known that there was oil in the Permian if not for 100 years than for close to 100 years. You can think of the Permian as kind of a wedding cake — it’s got multiple layers, there’s different producibility in each one of the layers, you have to use different produc-tion techniques, but you can stand on a point in the Permian and just depend-ing upon which basin you’re in — the Midland or the Delaware — you might have five or six different intervals that you can test and produce from a single drill-ing pad. That’s something no one in this industry thought they would see. I think the Permian is like a riddle out in West Texas. People just keep finding new and interesting things about the geology out there. The game changer in the industry is the technology.

Q: What’s the next big development in shale for 2014 and beyond? A: I think shortening the frack stages — instead of doing it every 200 yards, doing it every 100 yards or so. You take the same hole, the same drill bore, and frack it at shorter intervals, which is something EOG has been working on for a long time. The great cosmic opportunity that the industry has is to get more of the hydro-carbons that we know are in place back to the wellbore and produce, rather than that we’re going to find a new source of oil in the lower 48 states.

Q: You mentioned EOG. What other companies should be watched in 2014? A: EOG is one, I think Devon is one — there’s been a great flurry around the Permian basin names, like Diamondback, which is a small name out there. Pioneer is the best known. We’ve been reluctant to get involved with single-basin names. We like a little more diversity. Our style is a little more conservative, I suppose. I would look at EOG, I would look at Pioneer. There’s no telling. There may be names that are off the radar screen right now that will end up with a great production versus the size of the company. Once you get too big, it’s hard to move the needle. That’s the problem a lot of the big major compa-nies have right now. They can get some big production, but their legacy holdings are declining at 10 or 12 percent per an-num, so it’s difficult for these big compa-nies to really move the needle.

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