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NRG

January 2014

Issue 46

News Analysis

Intelligence

Published by

NewsBase

AFROIL 2

Algeria hopes to reverse production

falls 2 ASIAELEC 3

Generating boom in China 3 ASIANOIL 5

OVL enjoys overseas success, but future

looks less clear 5 CHINAOIL 6

Green Dragon emerges from unusual but

beneficial 2013 6 ENERGO 8

Hungary takes the Russian option 8 EUROIL 10

European E&P problems laid bare 10 FSU OGM 11

The rise of the NOCs? 11 GLNG 13

LNG import potential rising in Latin

America 13 LATAMOIL 15

International investors give thumbs-up to

Mexican reforms 15 DOWNSTREAM MEA 16

Kurdish export plans currently little more

than pipe dreams 16 MEOG 18

Iran’s future growth hinges on sanctions

decision 18 NORTHAMOIL 20

Rail accident sharpens focus on crude

transportation 20 REM 22

Phase-shifting the blame in Central

Europe 22 UNCONVENTIONAL OGM 23

China makes shale progress 23

NEWSBASE ROUND-UP GLOBAL

This is the forty-sixth issue of the NewsBase Round-up of Global energy issues.

NRG comes to you entirely at our expense, which we

hope will further increase the value you derive from

subscribing to NewsBase.

NRG covers developments from all global energy

regions and sectors, and brings you the “best of the

best” (as selected by our editors) from each of the

previous month’s weekly Monitors.

The global nature of the energy industry means that

no episode happens in isolation and we hope that

NRG will help to tie up events around the world in

one single issue.

This month, LatAmOil examines the reaction from the

international bond markets to Mexico’s constitutional

energy reform, while MEOG looks at the potential of

the Iranian energy sector to grow if Western-backed

sanctions are lifted.

Please note, it is NOT possible to subscribe to NRG. It is, however, an additional service we provide to our existing subscribers.

NRG NEWSBASE ROUND-UP

–– GLOBAL ––

NRG January 2014, Issue 46 page 2





Algeria is hoping for a turnaround in its

hydrocarbon production, after six years

of declining output and dwindling

interest from foreign firms. During 2013,

despite oil and gas production continuing

to fall, the North African country

exhibited signs of improvement that

should lead to rises in output over the

next five years, according to Sonatrach‟s

chairman, Abdelhamid Zerguine.

In remarks reported on December 27

by Platts, Zerguine told reporters that

Algeria was “showing signs of

recovery”. Speaking on the sidelines of

the company‟s general assembly, he

attributed the recent decline to the award

of some permits to small foreign

operators that did not have the “financial

capacity” to meet the requirements of

local projects, leaving them

“overstretched”. These companies had to

relinquish their licences, Zerguine said,

without naming any specific companies.

Many of the world‟s biggest oil and

gas companies are still active in Algeria,

where Sonatrach dominates the sector,

and is implementing a US$80 billion,

five-year investment programme to

expand its hydrocarbon industry.

However, 2013 was a poor year for the

country, beginning with the deadly

terrorist attack in January on Statoil and

BP‟s In Amenas gas facility, which

ignited latent security concerns about a

market where the threat of terrorist

attacks has long preoccupied overseas

players. Militants from neighbouring

Mali claimed responsibility, with the raid

leaving scores dead, including a number

of foreign workers.

The country‟s crude oil production

stood at 1.14 million bpd in November

2013, down from a peak of 1.37 million

bpd in 2007, according to a recent Platts

survey of OPEC and industry officials.

Meanwhile, as its larger, more mature

fields have depleted, gas production had

also declined. Data from BP showed that

output came in at 81.5 billion cubic

metres in 2012, down 1.7% on the

previous year and marking a steady

decline since 2005.

Local faults

To some extent, Algiers has itself to

blame. It sits on oil reserves of 12.2

billion barrels, the third largest in Africa,

and natural gas reserves of 4.5 trillion

cubic metres, the second largest on the

continent. Even before the attack at In

Amenas, though, international firms

viewed Algerian production terms as

unattractive at a time of rising global

competition. This was mirrored in

embarrassing auctions for oil and gas

exploration licences from 2008 to 2011,

with few foreign investors signing up

acreage.

Unsurprisingly, the Sonatrach

explanation made no reference to local

accountability – and in particular to

Algeria‟s internal struggles with

corruption – or its protracted legislative

processes, a growing resort to resource

nationalism as oil prices have soared and

the increasing pain inflicted on its

overseas production partners.

Algeria‟s hydrocarbon production

began to slow in the wake of new

revenue-sharing laws and taxes

introduced in 2005, and a 2006 clause

that imposed heavy tariffs when oil

climbed over US$30 per barrel. In 2009

alone, production slumped by 5%,

against a backdrop where there was talk

of retroactive renegotiations of contracts.

Confidence in the country‟s energy

environment was undermined by a series

of management shake-ups at Sonatrach,

including one related to a corruption

investigation in 2010, followed by the

replacement 18 months later of the firm‟s

head. As a result, some foreign firms

threatened to quit the country for good.

By mid-2012, though, Algiers was

starting to show it might be ready to

address these concerns, via a pledge to

overhaul its hydrocarbon laws in a way

that would prove more appealing to

foreign explorers. However, when the

new legislation was finally gazetted, in

October 2012, the focus was on potential

shale projects, frustrating existing

partners engaged in conventional

exploration and production.

Last year brought little improvement,

as output continued to decline, and the

violent raid at In Amenas forced global

companies to rethink their stances on oil

and gas fields in the Maghreb region –

and in many cases to consider higher

levels of protection, as perceptions of

regional risk head northwards. Algeria

was also beset by a new corruption

scandal, this time involving alleged

payments involving Eni‟s subsidiary,

Saipem.

AfrOil

Algeria hopes to reverse

production falls

Last year got off to a bad start for Algeria and its energy industry. The government is

hoping this year will stem its declining production

By Kevin Godier

Algeria’s oil production fell to 1.14 million bpd in November

The country’s regulations are considered to be among the most onerous in the world

Results from the delayed bid round will be closely watched






As the year wound down, one item of

good news came from an announcement

that Norway‟s Statoil had decided not to

sell its local assets, and would begin

returning its staff to local Algerian sites

as the fear of new terrorist attacks

tapered off. The government and the

military have maintained their focus on

combating the Islamist threat from Libya,

Mali and other regional trouble spots.

High hopes

Illustrating the more positive outlook for

the sector, Algerian Minister of Energy

and Mines Youcef Yousfi said on

October 1 that he expected oil and

natural gas output to double in seven to

10 years, as the country brings fields in

under-explored regions on stream.

Yousfi told reporters in London that

the Maghreb state was continuing to

make oil and gas finds in the eastern

region, where most of its producing

fields are located. New finds have added

at least 1 billion barrels to the reserves of

Hassi Messaoud, Algeria‟s oldest field

that supplies about one third of its oil

production, he said.

The minister went on to add that the

government planned to step up

exploration in the southwestern region,

start offshore drilling and develop shale

and tight gas reserves. “We have between

300 and 500 technically recoverable

trillion cubic feet [8.5-14.16 tcm] of gas

in tight gas,” he said while attending the

Oil & Money conference. “We are

progressing in the evaluation of shale gas

in the country and it‟s above 700 tcf

[19.82 tcm].”

Importantly, Algeria is keeping export

volumes unchanged by finding new

customers to offset a drop in European

fuel consumption that has affected sales

to the countries such as Spain, where the

economy has tanked. “We have accepted

to reduce our exports to these countries

for a small period of time but generally

we didn‟t reduce our production,” Yousfi

said. “We are exporting some quantities

to new markets.”

On the political front, stability seems

assured. Algerian President Abdelaziz

Bouteflika is seen by observers as very

likely to be re-elected in April, despite

being afflicted by the stroke he suffered

in April 2013. Constitutional changes

allowing him to be elected for a fourth

term must be put in place by February or

March, opening the way for a regime

where other senior cabinet members will

assume key administrative and political

roles.

Less attractive to the global oil and gas

community has been the delay in

implementing Algeria‟s planned fourth

licensing round. A number of dates had

been given for this in 2013, but none

came to pass.

Reversing the ongoing decline in

output by the end of 2018 is undoubtedly

a feasible target, given Algeria‟s strong

energy sector potential and options. But

political and energy sector leaders will

have to demonstrate a more flexible and

entrepreneurial attitude, given persistent

concerns that the incentives attached to

the promised round may still be

insufficient to attract foreign majors.

China‟s big five state-owned power

companies are enjoying their biggest

profits bonanza for 11 years as low

domestic coal prices help to reduce their

operating costs dramatically.

Coal fuels the bulk of the 584,000 MW

of capacity operated by the big five, and

fuel represents about 70% of a thermal

power plant‟s (TPP) operating costs,

according to the Shanghai financial

services company ChinaScope Financial.

“While coal enterprises are suffering

heavy losses, China‟s power generation

sector, especially the five major power

generation corporations, has just started

to make a fortune out of the sharp falling

coal prices,” said ChinaScope.

The big five are: China Huaneng

Group; China Datang, China Huadian,

China Guodian and China Power

Investment.

AfrOil

AsiaElec

Generating boom in China

Low coal prices since 2012 have allowed China‟s big five generators to post their largest

profits for 11 years. Cheap coal means consumption is set to rise further, despite Beijing‟s

concerns about pollution

By Graham Lees

Huadian Power is forecasting the largest profits for 2013, set to be 195% higher than in 2012

Yet the coal industry profits fell by 39% in 2013, leaving loss-making companies US$6.71 billion in the red

Low coal prices have not hindered rising imports or investment in new coal projects

The power sector is still set to be a major consumer of coal as generation move away from the cities






Profits

The biggest individual company profit in

2013 was achieved by Huaneng, with

US$3.44 billion, said the China Daily

newspaper.

It is a swings and roundabouts

business, though. Domestic coal prices

have been falling since the middle of

2012, but prior to then the five giants

suffered severe losses owing to high coal

prices, noted ChinaScope.

In the five years up to the end of 2012,

the corporations now enjoying record

profits clocked combined losses of more

than 100 billion yuan (US$16.54 billion),

said ChinaScope.

Huadian Power has signalled that it

expects its 2013 net profit could be as

much as 195% higher than for 2012,

when its profit was logged at 1.42 billion

yuan (US$234.7 million). The firm said

its electricity production in 2013 was

almost 12% more than in 2012, at 175

billion kWh.

Meanwhile, overall profit levels in

China‟s coal industry fell by almost 39%

in 2013, and the “unprofitable producers”

suffered a combined 40.6 billion yuan

(US$6.71 billion) loss, according to the

China Coal Industry Association (CCIA)

last week.

National coal production climbed by

50 million tonnes to 3.7 billion tonnes in

2013, but consumption grew only 2.6%

to 3.61 billion tonnes, said the CCIA.

This was a major slowdown – over the

preceding 10 years up to 2012, the

average annual production increase was

200 million tonnes, said the industry

agency. “Excess supply is expected to

last this year,” it said.

Imports and investment

It is sometimes hard to comprehend

national policy on coal, which seems to

suffer a kind of schizophrenic existence:

loved on the one hand for its abundant

energy value, reviled on the other for its

devastating pollution and huge effects on

the national health.

As energy research scientist Chi-Jen

Yang, of the Center on Global Change in

the US, told NewsBase earlier this

month, “I don‟t think the contradiction is

intentional. China‟s national and local

policymakers simply have not worked

out a consistent plan for coal use.”

Curiously, the slump in China‟s

domestic coal prices has not curbed coal

imports nor deterred the bigger state coal

miners from planning to invest heavily in

more production.

Imports grew by more than 13% in

2013 over 2012 figures to 327.1 million

tonnes, said the CCIA. Much of this was

low-calorific value cheap coal from

Indonesia – which the central

government had pledged to curb as part

of efforts to reduce urban air pollution.

Even so, China Coal Energy, the

country‟s second biggest miner, has just

announced details of a US$2.8 billion

investment in a large new mine in

northern Shaanxi Province.

Hong Kong-listed China Coal is

targeting an eventual annual production

from the mine of 15 million tonnes,

although it will take five years to develop

fully.

Funding for the new mine will come

from bank loans and the coal produced

will fuel gasification and power projects,

said Bloomberg Finance.

Policy and reforms

China‟s coal industry is clearly not about

to collapse owing to the sliding prices

which are helping the power firms to

profit. The central government is

enacting new rules to help miners survive

and prosper.

State aid plans on tax reforms designed

to ease the financial pressure on coal

miners are imminent, according to the

China Resources Journal.

These reforms include a scheme

whereby coal tax collection will be based

on sales value rather than the existing

system linked to production volume, said

the Beijing Global Times. The maximum

resource tax is expected to be reduced to

5% from 8% at present, it said.

Coal stocks at major mining

enterprises are high, while inventories at

the big power groups are being

deliberately kept low in order to benefit

from sliding prices, the CCIA.

About 300 million tonnes of coal

production, mostly from ageing mines,

was taken out of the supply market in

2012, but 300 million tonnes of new

production is due to come into operation

during 2014, said John Foley, China

editor of Breakingviews, a financial

analysis service of Reuters.

This is in addition to the 100 million

tonnes of new capacity given the go-

ahead for development in 2013.

“If the authorities are serious about

cleaning [urban air pollution in] China,

deeper reforms are needed. Local

governments have little incentive to

enforce [the] closure of inefficient mines

only to see smarter new facilities built in

someone else‟s town,” said Foley in a

January 14 analysis. “Curbs in imports of

the dirtiest varieties may just serve to

keep low-quality domestic producers

alive.”

As NewsBase has noted before, the

central government‟s promise to tackle

coal pollution which suffocates dozens of

big cities does not mean reducing the

volume of coal burnt for energy; it

appears to mean relocating coal burning

away from the urban areas.

Huge new mines are planned in

sparsely populated northern and

northwestern areas, and the coal from

these will fuel new mine-head power

plants or massive coal-to-gas projects

which will in turn feed into power plants.

It will be a costly business. The closure

of small, inefficient mines and power

plants in cities will continue, but the rise

of coal energy in China is a long way

from over yet.

AsiaElec

“China’s power generation

sector, especially the five

major power generation

corporations, has just

started to make a fortune

out of the sharp falling

coal prices”






Over the years ONGC Videsh Ltd (OVL)

has been roundly criticised for failing to

snatch up major foreign oil and gas

assets, frequently losing out to quick-

footed Chinese rivals that enjoy greater

financial and political muscle.

Recent events would suggest that all

this might be changing, with OVL

enjoying a streak of successes in Latin

America, Africa, Southeast Asia and

Central Asia. Though the company

appears to be getting to grips with buying

into high value energy targets, however,

its abilities to compete on the world stage

remain at the mercy of New Delhi‟s

domestic energy policy and the resulting

impact this has on parent company Oil

and Natural Gas Corp. (ONGC).

Overseas victory list

In January, OVL acquired an additional

12% stake in Brazil‟s Block BC-10 from

Petrobras by exercising its pre-emption

rights. OVL now owns 27% of the

deepwater Campos Basin Block, while

operator Royal Dutch Shell holds

balance.

Significantly, the Indian firm managed

to outmanoeuvre Sinochem, preventing

the Chinese state firm from investing in

the block. OVL agreed to pay US$529

million, matching Sinochem‟s offer. The

block produces about 50,000 barrels per

day of oil and, according to ONGC, has

the potential to reach 75,000 bpd by

2017.

The Brazilian success follows OVL

and Oil India Ltd‟s (OIL) completion of

their acquisition of Videocon‟s 10%

stake in Mozambique‟s giant Rovuma

Area-1 gas field for US$2.4 billion this

month. OVL has also bought a 10% stake

in the block for US$2.6 billion from the

US‟ Anadarko Petroleum, with the

Indian explorer set to complete the deal

before the end of February.

“Area-1 has [the] potential to become

one of the world‟s largest LNG

producing hubs and is strategically

located to supply LNG to growing Indian

gas market,” OVL said in a statement last

week.

OVL‟s other successes include

winning two onshore oil blocks in

Myanmar in October 2012, adding to

existing stakes in the A-1 and A-3 gas

blocks and three other offshore acreages

in the Southeast Asian country. In 2013,

meanwhile, OVL acquired a 2.7% stake

in Azerbaijan‟s Azeri, Chirag and

Guneshli fields for US$1 billion.

In December 2013, OVL bid for three

blocks in Sri Lanka in the Mannar Basin

where Cairn India has made two gas

discoveries.

In Venezuela, meanwhile, OVL signed

a memorandum of understanding (MoU)

with Venezuela‟s PDVSA in October

2013 for co-operation in the oil-rich Faja

area. “Venezuela has world‟s highest

reserves and we have a huge market,”

OVL said.

OVL, buoyed by its successes, appears

ready to take on more foreign ventures

and acquisitions in the near future.

Future moves

The company, along with partners, is

looking to buy a 9-10% stake in Russian

gas producer Novatek‟s US$20 billion

Yamal LNG project.

Sudan offered OVL two oil and gas

blocks this week, with the company set

to take 100% stakes in the licences if it

finds them feasible.

Vietnam has offered the company five

offshore exploration areas in South China

Sea as well as the Kossor Block in

Uzbekistan without having to bid.

OVL is also set to discuss a possible

partnership with Ecuador‟s state-run

Petroamazonas later this month.

Moreover, the company is also looking

into investing in Kazakhstan‟s “Eurasia

Project”, which will see the development

of oil and gas assets in the northern

Caspian Sea. The sea boasts 300 oil and

gas fields, including super-giants such as

Karachaganak, Tengiz and Kashagan.

ONGC officials have said the company

has set aside misgivings over Astana‟s

decision last year to block OVL‟s US$5

billion bid to buy US super-major

ConocoPhillips‟ 8.4% stake in Kashagan

in favour of China.

AsianOil

OVL enjoys overseas success,

but future looks less clear

After years of misfires, OVL has racked up a string of foreign acquisitions. Indian energy

policies, however, may cause financial problems for the major further down the line

By Siddharth Srivastava

OVL completed the acquisition of a 12% stake in Brazil's Block BC-10 in January

Its acquisition of a 10% stake in Mozambique's Rovuma Area-1 gas field should complete in February

ONGC has warned output growth and overseas acquisitions are at risk owing to its fuel subsidy burden






Yet, while OVL has a racked up a

number of notable achievements, its

ability to maintain that momentum lies

with the Indian government‟s domestic

energy policy decisions.

Domestic Policy

ONGC has said it intends to spend 11

trillion rupees (US$178.62 billion) by

2030 to add reserves both at home and

abroad. Indeed, it plans to invest more

than US$9 billion in bringing discoveries

in the prolific eastern offshore KG Basin

into production. Yet at the very same

time, the major has warned that its output

growth and overseas acquisitions are

under “serious threat” owing to the

“disproportionate rise in fuel subsidy

burden”.

“There has been significant reduction

in ONGC‟s net realised prices over the

years, from about US$54.5 to in 2012 to

US$40 presently. Profit after tax from

crude oil has already eroded by almost

50% over last three years,” ONGC has

warned.

India needs to focus on ramping up

domestic exploration efforts, as a result

of net annual oil imports costing the

country around US$100 billion per year

leaving the country on the brink of a

severe energy crisis. The country may be

forced to seek a loan from the IMF,

Indian Oil Secretary Vivek Rae warned

this week, saying: “We haven‟t gone to

the IMF yet, but we are pretty close.”

If the government does not work to

free up ONGC‟s finances then the

company is going to find it increasingly a

challenge to finance development at

home and acquisitions abroad.

This will likely leave the country with

fewer stable supplies of foreign oil in the

long run.

China-focused Green Dragon Gas‟

production soared unexpectedly in 2013,

driven by other companies drilling on its

concessions – it was a most unusual year

for the coal-bed methane (CBM)

developer.

In its January 21 statement, Green

Dragon said total gas output for the year

rose by 304% from a year earlier to 7.19

billion cubic feet (203.62 million cubic

metres). Breaking that down, the firm

said it had produced 2.9 bcf (82.13

mcm), up 11% year on year, while

current audits of “third-party activities”

had delivered the remaining 4.29 bcf

(121.49 mcm), with potentially more to

come.

The extra production came from some

of the 1,500 wells drilled by a handful of

the country‟s biggest state-owned majors

on its licences, of which Green Dragon

said it had no knowledge. At the heart of

how this strange state of affairs came to

be is state-owned China United Coalbed

Methane‟s (CUCBM) claim in 2011 that

Green Dragon‟s licences had been

revoked, the central government

enforcing the independent‟s rights in

2013 and the subsequent revelation that

third parties had carried out extensive

drilling work in the intervening period.

From there…

In March 2011, CUCBM announced via

its website that it had ended its co-

operation with Green Dragon in four of

the five production-sharing contracts

(PSCs) it has with the independent and

would not be extending those contracts.

These were the Qinyuan and Shizhuang

North (GSN) Blocks in Shanxi Province,

the Fengcheng Block in Jiangxi and the

Panxie East Block in Anhui. Shizhuang

South (GSS) was left untouched, while

Green Dragon‟s PSC for the Baotian-

Qingshan Block is held with PetroChina.

Despite the announcement Green

Dragon affirmed its claim to the PSCs,

saying that all financial commitments

had been met and that the contracts were

in full force and effect. Such a move was

highly unusual for a privately owned

foreign company to make in China, given

the power of the country‟s state-owned

enterprises (SOEs). Nevertheless, the

company continued to operate the

licences, while CUCBM refused to

answer NewsBase’s requests for

clarification on the matter.

AsianOil

ChinaOil

Green Dragon emerges from

unusual but beneficial 2013

The past year has proved eventful for the CBM developer, with the discovery of more than

1,500 wells drilled across its licences

By Andrew Kemp

Green Dragon's production soared by 304% year on year in 2013, driven by third-party drilling

Around 1,300 wells were located on the producing Shizhuang South Block (GSS)

The company estimates its 1P reserves have jumped more than sevenfold as a result of the drilling






In July 2013, however, Green Dragon

announced that the Chinese Ministry of

Land and Resources (MLR) had

reaffirmed the validity of its licences.

What Green Dragon describes as

CUCBM‟s “erroneous” statement was

removed from the company‟s website

just days prior to the independent‟s

announcement.

On October 8, Green Dragon revealed

that CUCBM, China National Offshore

Oil Corp. (CNOOC), China National

Gasolineeum Corp. (CNPC) and

PetroChina had informed it of 1,500

wells that had been drilled across five of

its PSCs. Around 1,300 of those were

located on the company‟s sole producing

block, Shizhuang South (GSS), and had

been drilled at an estimated cost of

US$500 million.

The company has since revealed the

signing of a memorandum of

understanding (MoU) with PetroChina to

confirm the state-owned company‟s

“participating interests” in the

Chengzhuang Block (GCZ), which is

part of GSS, as well as a heads of

agreement (HoA) with CNOOC on a

“potential transaction” relating to the

drilling work.

In an interview with NewsBase, Green

Dragon‟s chairman and founder,

Randeep Grewal, described the situation

as “globally unprecedented”, stressing

the protections that should have stopped

such a situation from arising in the first

place. He pointed to the company‟s PSCs

as being “directly authorised, certified,

accepted and approved by the State

Council” and the fact that they were

protected by a bilateral investment treaty

between the Netherlands and China.

Green Dragon signed the PSCs via a

Dutch-listed subsidiary.

… to here …

Grewal explained that it had taken two

years for the company to secure its PSC

rights because it had adopted a

“conciliatory approach” in lobbying the

State Council, the Ministry of Commerce

(MOFCOM) and the MLR, rather than

pursuing legal recourse.

With Green Dragon‟s claim to the

licences having received Beijing‟s

support, the four state-owned companies

submitted information on their drilling

activities.

Grewal explained that while the

company had seen signs of some third-

party drilling following CUCBM‟s move

to revoke the contracts, he insisted that

the company had no idea of the scale,

which he described as “overwhelming”.

Green Dragon, he said, had encountered

external drilling activity around 10-15

times prior the concessions‟

reinstatement, with the company

“notifying” CUCBM of each encounter.

“At no time, until recently, did we

have any idea that there was a campaign

to the tune of 1,500-odd wells. That‟s a

whole different level,” he said. “It‟s so

unprecedented that it‟s difficult to

comprehend that something like this

could happen, let alone be vigilant to

such activity.”

While the heavy focus on GSS is of

little surprise, given that it is the only

concession in production, what is

startling is that drilling activity even took

place, given that CUCBM never issued a

statement ending Green Dragon‟s

involvement there. When asked about

this, Grewal simply responded by saying:

“GSS was never threatened because of

the existence of the [overall development

plan] ODP.”

However, Grewal said that, after

having conducted field studies, it was

clear from the amount of infrastructure in

place at GSS that the block was “well

over 50% developed”.

… and beyond

Green Dragon‟s plan for its six licences

has been based on first developing GSS,

before expanding its operational scope.

With GSS‟ development so much further

along than originally expected, the

company‟s development plans have been

accelerated.

With 150 LiFaBriC wells, which use

technology adapted from traditional

horizontal drilling techniques, slated to

be drilled in GSS this year, Grewal does

not expect to there to be much

development work left before the block

is fully completed. When pressed on the

exact relationship with its newfound state

partners, whether there would be a farm-

in agreement and if co-development was

on the cards, Grewal declined to

comment.

However, Grewal said: “By the time

we hit the end of 2015 we should pretty

much be done with GSS and the logical

thing would be to continue that drilling

campaign into GSN.”

He added that there was only a lease

boundary between GSS and GSN, with

the former enjoying extensive

infrastructure development.

ChinaOil






While the past six months have

brought about significantly better news

for the company, spurring a 40% rally in

its share price in the same period, there is

still some way to go before it recaptures

the value lost in the wake of CUCBM‟s

original statement.

Market watch

The uncertainty surrounding Green

Dragon‟s position has seen the London-

listed company‟s value drop from around

US$1.6 billion in March 2011 to slightly

more than US$600 million at present.

Commenting on the valuation, Grewal

said Green Dragon had enjoyed a “very

productive period of time” despite the

uncertainty caused by the CUCBM

notices.

He said: “Our wells have continued to

perform remarkably well, our production

levels are up, our infrastructure has built

up. In every regard operationally we‟ve

done well.”

He added: “What are my expectations

[of the market]? At a minimum we need

to go back to the point before these

erroneous notices were put out. From

there all the accretive activity we have

accomplished should be compounded on

top.”

He pointed to the fact that prior to

CUCBM‟s statement Green Dragon‟s 1P

gas reserves stood at 40 bcf (1.13 bcm)

and 2P reserves stood at 270 bcf (7.65

bcm). Following the retroactive

application of the licences by the MLR,

Green Dragon‟s engineers‟ estimates

based on information provided by the

third parties put 1P reserves at 300 bcf

(8.5 bcm) and 2P reserves at 600 bcf

(16.99 bcm).

The company expects to have

completed an audit on its assets in the

next few months, with Grewal adding

that the “abundance” of data delivered

may delay the announcement of its

reserve data until the end of the first

quarter, rather than in February.

Lessons

Last year, therefore, was an unusual year

– but not unsatisfactory – with Green

Dragon closing out 2013 in a better

position than it entered.

Still it remains to be seen whether

investors rally behind the company,

returning its lost market value.

China is certainly hungry for gas, and

having its licences confirmed by the

central government will be a mark in its

favour.

Yet, understandably, cautious

onlookers will want to see how the

company handles its development

partners in the future.

Even as the company seems to be

emerging from a somewhat turbulent

time, taken from a fairly lengthy period

in the country, it raises serious questions

about foreign independents and their

participation in China‟s CBM sector.

Could this to happen to other CBM

developers that do not have similar

guarantees to fall back upon? While it is

difficult to say with any degree of

certainty, in Green Dragon‟s case Grewal

highlighted the company‟s “first

generation” of licences that had been

maintained in their original form as

having afforded it a much stronger

position from which to protect its

interests.

Speculating on what may have

prompted such a unilateral approach to

Green Dragon‟s licences by the state-

owned giants, Grewal said: “There is a

tremendous amount of pressure on all

domestic producers, including us, to get

domestic gas production up and we‟re all

incentivised to achieve that. [However],

we still have to do it within the confines

of the rules, regulations, PSCs and rigid

obligations in place.”

Hungary‟s US$10 billion loan deal with

Russia to expand the Paks nuclear power

plant (NPP) has come under intense

scrutiny at home as Hungarians wait to

hear the full terms.

The deal was signed last week and was

described by Hungarian Prime Minister

Viktor Orban as an “excellent

professional agreement.” However, the

agreement was struck without any

involvement from the Hungarian

Parliament, while it could also come

under fire from Brussels.

“The information provided about the

deal is way too insufficient,” Judit Barta,

managing director of Hungary‟s GKI

Energy Research Institute, told

NewsBase.

ChinaOil

Energo

Hungary takes the Russian option

Hungary‟s deal with Russia to expand the Paks NPP is causing considerable controversy,

with critics saying the electricity produced will be too expensive for consumers

By Robert Smyth

Russia is to lend US$13.55 billion over 30 years to fund the 2,400-MW expansion of the Paks NPP

Critics say the deal could be seen by Brussels as illegal state aid

The terms of the deal could make the price of power from Paks far too high






“The government had no right to make

such an agreement, as Parliament had

only given a mandate for the government

to look into the possibilities,” she noted.

The loan

Russia has pledged to lend Hungary as

much as 10 billion euros (US$13.55

billion) as a 30-year sovereign loan to

expand the Paks NPP by building two

new reactors that will add 2,400 MW of

new capacity.

This sum should cover around 80% of

the costs of the work, the ceiling of

which is estimated at 12 billion euros

(US$16.25 billion).

Russian nuclear agency Rosatom is set

to build the new blocks, which will more

than double the NPP‟s existing capacity.

The agreement was signed by Russian

President Vladimir Putin and Orban in

Moscow on January 14. Since then,

Orban has said that Hungary cannot be

competitive without it.

Political controversy

Orban has come under criticism at home

for increasing Hungary‟s energy

dependence on Russia, as well as for

rushing into a deal for the plant‟s non-

urgent expansion.

The opposition E-PM electoral alliance

leader and former Prime Minister Gordon

Bajnai has called for a demonstration

against the expansion on February 2,

with the goal of forcing a referendum on

the issue.

Parliament reconvenes on February 3

ahead of a general election on April 6.

The ruling Fidesz party has hit back at

Bajnai‟s comments, saying that when he

was in power before 2010 he was in

favour of expanding the Paks NPP.

Despite the controversy, the Russian

deal represents a quick and decisive

piece of business when compared to the

long drawn-out expansion of the Czech

Republic‟s Temelin NPP.

The first new block could start

operating in 2023, Hungarian State

Secretary Janos Lazar told the press. He

also mentioned that the European Union

had already given its backing to a draft

plan for the building of the new units.

Pricing problems

However, GKI Energy‟s Barta

questioned whether the deal had really

been approved by the EU and said that

there was no pressing need to decide on

the expansion for at least the next five

years.

She also claimed that Lazar‟s

statement that the Hungarian government

would be responsible for paying back the

loan, while the Paks NPP effectively

received the investment cash as a grant,

could represent a case of illegal state aid.

“Brussels will surely launch an inquiry

into illegal state aid should electricity

prices not include interest on the loan

taken. There may also be a probe if the

Paks NPP receives a capital injection or

other state money to help repay loans

already taken for capacity expansion,”

Attila Vago, a senior analyst at Concorde

Securities in Budapest, told NewsBase.

While Vago said there was no question

that Hungary needs cheap energy, as the

country‟s gas and oil imports are high, he

expressed concerns about the potential

terms of the deal.

“The interest on the loan will be huge,

and therefore the sale price of electricity

produced by the new blocks would be too

high,” he said.

Assuming an annual return of 8% on

the equity, which is around 20% of the

estimated investment cost, the eventual

price of the electricity would

theoretically be around 95 euros

(US$128.68) per MWh, more than

double the current wholesale price in

Hungary.

“Someone will cover the difference

and that will probably be the tax payer,”

he said. The 10 billion euro loan will

increase state debt by 10% in terms of

GDP and the interest burden may

represent 0.4% of GDP in the years after

the new nuclear capacity comes on line,

most probably in 2023-24, he added.

“Everything depends on financial

terms. What really concerns me is that all

parties are fully convinced of the

economics and the necessity of this

project, but nobody knows exactly about

the real cost, construction time and future

energy prices,” said Vago.

Hungarian Economy Minister Mihaly

Varga told local TV news channel HirTV

on January 15 that the government was

negotiating to secure the cheapest deal

for Hungary.

Not all analysts have questioned the

agreement. Takarekbank analyst Gergely

Suppan told Hungarian news agency

MTI that the expansion would drive

investment and with it Hungary‟s GDP

growth.

He also welcomed the stable financial

background that the loan provides,

adding that if the interest rate was below

market rates, then a good return on

investment could be realised.

No tender

The agreement also means the tendering

process that was expected to involve five

international players will not see the light

of day.

There is already a Russian connection

at Paks, as its existing four VVER-440

reactors – with 2,000 MW of combined

capacity – were built in the USSR.

They were installed between 1982 and

1987 and fuel is currently provided by

Rosatom subsidiary TVEL.

Vago observed that Hungary, a

member of the EU since 2004, is the first

EU member country to accept Russian

nuclear technology on such a large scale.

“No doubt this is a huge victory for

Russia as well as Putin,” said Concorde‟s

Vago.

However, nuclear energy is not natural

gas, in that Russia cannot utilise it as a

geopolitical weapon, as it often does with

gas.

Therefore Hungary is not necessarily

increasing its energy dependence on

Russia.

Energo






However, Hungary does remain overly

dependent on expensive Russian gas,

even if natural gas imports from Russian

have dropped by as much as 35% since

2008 because of lower consumption and

the growing availability of cheaper gas

from the west.

“If Hungary sufficiently diversified its

gas supply towards the west, it could

achieve lower electricity prices as well,

ceteris paribus [all other things being

equal],” said Vago.

The Paks NPP contributed 43% to

Hungary‟s electricity supply in 2011.

Last October, Orban told a Hungarian-

Indian business forum in Mumbai that

Hungary was planning to raise nuclear

output by 50-75% by 2023.

The deal with Russia seems to be a

technically and financially expedient way

to achieve this for the government, but

Budapest will have to contend with

further political fall-out and reassure

consumers that price will not rise.

European oil and gas exploration and

production has been in the doldrums over

the past two years, with a marked lack of

success offshore in both the UK

Continental Shelf (UKCS) and Norway.

This was the dominant theme of the

Outlook for Oil in North West Europe

conference in London last week, which

used the latest exploration and

production data to assess whether

Europe‟s quest for energy independence

is possible or a pipedream.

Speaking to NewsBase on the sidelines

of the conference, David Bamford, one

of the conference organisers, a former BP

executive and now CEO of New Eyes

Exploration, said that rising costs were a

critical issue.

“What is clear is that high costs are

killing the North Sea,” Bamford said.

“This is despite … the UK Treasury

continuing to incentivise oil recovery and

[looking at] the creation of a new

Norwegian-style regulatory authority.

That will not alter the fact that costs are

rising exponentially and as a result,

projects have been either cancelled or

delayed.”

He said several high-profile schemes

had been cancelled, such as the Kristin

Gas Export project and plans to develop

the Rosebank and Bressay fields. Other

projects that have been delayed include

Johan Castberg, Johan Sverdrup, Linnorn

and Tressak. “But in fact, most of the

projects in the Barents Sea are delayed,”

he added.

UK

Despite such setbacks, there are some

shafts of light in the gloom. Delegates

heard that the rate at which North Sea

fields were being brought on stream after

initial discovery had improved

considerably, rising from 15 years in the

1980s to around five years now. But this

is doing little to halt the overall

production decline rate.

Oswald Clint of Bernstein Research

said: “Although the decline rates in the

fields of the UKCS and the Norwegian

Continental Shelf are not as bad as the

Gulf of Mexico, the „real decline rates‟ in

Europe tend to be understated and the

unavoidable truth is that they are

accelerating.”

Clint went on to say: “Last year, we

saw a decline of 13.8% in the UK and

12% in Norway. This was mainly due to

the higher water cut and it is clear that a

decision will have to be taken soon at the

highest levels on EOR [enhanced oil

recovery] to offset this problem.”

For Malcolm Webb, the CEO of Oil &

Gas UK, the problem is a perennial one.

Commenting on Wood Mackenzie‟s

annual review of UK upstream oil and

gas, which followed on the heels of data

released by the Department of Energy

(DECC) on drilling activity in the UKCS,

he said: “We are just not drilling enough

wells in UK offshore waters and those

that we are drilling are not finding

enough oil and gas. This worrying trend

has been growing for some time. It

started in 2011 with a 50% drop in the

number of exploration wells drilled,

[and] has since failed to recover.”

Webb carried on by saying that the

industry in Europe was facing a crisis

that required immediate action. “Our

members tell us that drilling rig

availability and the ability of smaller

companies to secure equity capital are

major hurdles. In any event, it is clear

that we now face a crisis which demands

urgent concerted action … if we are to

maximise economic recovery of our

offshore oil and gas resource and sustain

future production.”

Energo

EurOil

European E&P problems laid bare

The decline of European oil and gas production continues to thwart the continent‟s hopes

of energy independence

By Nnamdi Anyadike

E&P offshore the UK and Norway and in the Netherlands disappointed in 2013

Decline rates in Europe tend to be understated and are accelerating

A lack of exploration risks a collapse in capital spend in a few years’ time, meaning lower future production






The Oil & Gas UK chief said the

situation was a strange one, given the

record amounts of investment in offshore

developments. “The paradox is that the

UK continues to record annual levels of

capital investment at over GBP13 billion

[US$21.6 billion] … Meanwhile,

production from existing fields has fallen

significantly and the total number of

exploration wells has dropped to just 15

in 2013, according to data just published

by DECC.”

For Webb, it is a problem with long-

term exploration planning. “We are

simply not putting enough reserves into

the hopper for future development,” he

said. “Unless we do something about

exploration now, we face a risk of a

collapse in capital spend in a few years‟

time and hence lower future production.”

An OPEC report released last week

backed up the DECC‟s conclusions,

saying the UK‟s oil supply of 860,000

barrels per day in 2013 was at its lowest

level “since1977.”

Norway

In Norway, Bente Nyland, director of the

Norwegian Petroleum Directorate

(NPD), said: “The biggest challenge is

that costs have increased. Higher costs

have already led to some projects being

delayed ... and higher costs and uncertain

future oil and gas prices are a significant

challenge.” The NPD cut its 2014 oil

production forecast to 1.46 million bpd,

in line with last year, but below a

previous 1.52 million bpd forecast. It

also anticipates flat gas production after

earlier predicting a rise. The agency also

lowered its investment forecasts,

predicting just 2% growth over the next

two years before a decline. “If oil and gas

prices fall and costs remain stable or rise,

this will have an impact on decisions to

start up new projects, and will entail

lower investments than included in the

forecasts. To improve efficiency,

mergers and acquisitions activity may

increase. There are a lot of companies on

the shelf,” Nyland said. “We have said

earlier that this kind of restructuring is

possible, particularly now when you see

the capital strains and you need the

capital to fulfil your obligations. That

might be tough for some of the smaller

companies with no production or

income,” she added.

The Netherlands

The Netherlands‟ government has also

revealed that output from the country‟s

giant Groningen field will decline in the

coming three years. Production last year

stood at 54 billion cubic metres, but

output from the field is expected to drop

to 42.5 bcm per year in the next few

years, before falling to 40 bcm per year

in 2016.

Gas from the Groningen field currently

makes the Dutch government around 12

billion euros (US$16.4 billion) per year.

But by 2016 the loss of gas production

from the field will knock 2.3 billion

euros (US$3.1 billion) off that total.

Previously production to 2020 was

projected to average 49 bcm per year.

Henk Kamp, the Dutch Economy

Minister, said the production cut would

be the result of concerns raised by locals

living nearby who are worried about an

increase in earth tremors, which they

allege have been caused by the high rate

of drilling at the site.

Looking at developments in all three

countries, Bamford‟s conclusion was:

“While the US can contemplate a vision

of oil independence, North West Europe

could be destined to remain hooked on

the global geopolitics of oil, increasingly

shovelling money in the direction of

OPEC.”

In a move that might have given Gordon

Gekko a heart attack, Morgan Stanley,

one of Wall Street‟s most revered and

illustrious trading houses, has sold its oil

trading business to Rosneft, a Russian

state-controlled company. The deal was

struck in late December, when the two

sides announced that they had signed a

binding agreement that would allow the

Russian firm to purchase the Global Oil

Merchanting unit of Morgan Stanley‟s

commodities division.

EurOil

FSU OGM

The rise of the NOCs?

In striking a deal on the acquisition of Morgan Stanley‟s oil trading arm, Rosneft is

advancing into new territory. Current market conditions may inspire other state-run energy

operators to follow its lead

By David Flanagan

The agreement is roughly in line with the Russian giant's drive to expand into new markets

It may give the company a boost as it seeks to move into the LNG export trade

Commodity trading may offer NOCs new avenues for profit in the face of tough competition






But now that the initial raised

eyebrows have dropped again, what does

this deal actually tell us about how

Russian energy companies‟ attitudes are

changing? Moreover, what does it say

about how the oil and gas trading

markets are evolving?

Metamorphosis

First of all, the deal concluded a dramatic

and successful year for Rosneft.

The company was once the steady but

unremarkable workhorse of the Russian

oil sector, but in recent years it has

transformed into a trend-setter and a

rapidly evolving global operator. Its

metamorphosis continued in 2013 with

the acquisition of a stake in the Italian

refiner SARAS, the full takeover of the

Russo-British venture TNK-BP and the

completion of its campaign to acquire

100% of the Russian natural gas operator

Itera. Beyond these transactions, it also

stands to benefit from the step-by-step

revamp of the Russian gas market,

including LNG export opportunities.

And now the deal with Morgan Stanley

marks, in quite spectacular fashion, the

elevation of Rosneft into a more mature

and calculating oil trading enterprise.

New direction

Secondly, Rosneft‟s position as a

national oil company (NOC) underscores

the interesting and unusual nature of this

agreement.

It is difficult to think of a precedent for

such an acquisition, given that we are

accustomed to seeing NOCs following a

predictable pattern in their development.

But under present conditions, they appear

to have become more aware of their

power and therefore more aware that

they have different options. This may

explain Rosneft‟s bold step in buying the

Morgan Stanley oil “book.”

The value of the deal has not been

disclosed. However, Rosneft may be less

interested in the “mark-to-market” value

of the trades and more keen on the

prospect of buying a trading structure

and contractual relationships that it can

now use as it chooses.

It is also interesting that fellow

Russian energy firms such as Gazprom

and LUKoil have largely built up the

trading sides of their business through

organic growth, rather than through

acquisitions. By contrast, Rosneft, by

building its market presence through a

high-profile acquisition, has seemingly

tried to play catch-up with rivals in a

short space of time, and it has arguably

now established the foundation needed to

accomplish this feat in one fell swoop.

Changing market conditions

Along with telling us about the changing

nature of Russian energy companies, the

new deal also reflects shifting

fundamental conditions in the oil trading

market. Indeed, rather than being a huge

surprise, the deal between Rosneft and

Morgan Stanley is really a sign of the

times.

That is, oil prices traded in a narrow

range of US$100-110 for most of 2013,

so the prospects for banks and trading

companies have become quite limited.

With such a calm market, banks and

trading houses cannot make much

money. They need price volatility to

make good profits, and that is simply not

happening.

So together with the ongoing need for

rationalisation after the credit crunch and

the increased regulatory burden, market

fundamentals have not favoured banks in

recent years.

Nor have they created the conditions

necessary for banks to make money in oil

trading. This is part of the reason for

Morgan Stanley‟s decision to unload its

oil trading arm. Others are sure to follow

– most notably Deutsche Bank, which is

closing down its commodity trading

operations.

Higher profile

Rosneft‟s new deal is also consistent

with its ambitious recent evolution.

As noted above, the company

succeeded in building up its activities

through the acquisition of oil-producing

and refining assets in 2013. However, its

strength is not confined to the oil sector.

Rosneft also stands to benefit from other

changes. Specifically, Russia moved

quickly in 2013 to relax rules and

regulations relating to LNG exports, an

area of activity that had previously been

the exclusive province of Gazprom.

The new regime is clearly good news

for Rosneft. The company‟s future

involvement in LNG exports is now

virtually assured, given that it has teamed

up with ExxonMobil of the US to draw

up plans for an LNG plant capable of

supplying Asian markets.

Under these circumstances, the higher

profile that the Morgan Stanley deal

gives Rosneft is highly favourable. It

could even facilitate the company‟s

successful entry into the LNG export

trade by encouraging the development of

synergies in cross-commodity trading,

thereby allowing it to develop additional

gas trading expertise.

As such, the agreement between the

two companies illustrates Rosneft‟s

ambitious new attitude to its own future.

But does the deal also mark the start of a

trend among NOCs across the world?

Facing competition

Certain market trends appear to support

this idea.

One of the key problems for NOCs lies

in the serious level of competition

presented by the growth in US shale gas

production. This is not a problem faced

by Russian oil producers alone.

In the Middle East, it has created a

dilemma for OPEC, which must now

determine how it can represent its

members‟ interests in the face of

competitive pressure from US shale gas.

Consequently questions about the future

role of OPEC, which is of course

dominated by NOCs, are surfacing.

Already some tension within OPEC is

evident, and the largest Middle Eastern

producers – including Iran, Iraq and

Saudi Arabia, all of which may end up

pulling in different directions in the

future – have a growing incentive to

strike out on their own. In other words,

these countries may feel that OPEC

membership will increasingly serve as an

obstacle to their freedom to negotiate and

sign contracts.

FSU OGM






Other trends have also shaken up the

position of NOCs and may spur them

into more self-motivated action. For

example, one trend seen in 2013 – one of

cheap coal stealing market share away

from oil – is sending a signal to NOCs

about the need for action.

In light of these developments, Rosneft

now appears to be leading the market by

example. Middle Eastern NOCs may be

unable to engage in a transaction like the

Morgan Stanley/Rosneft deal for various

reasons, but they will not have failed to

notice it and could be spurred into action

by it. In any event, NOCs cannot rely on

the old-fashioned strategy of simply

increasing oil output, as this will be

inadequate over the longer term. They

must, as Rosneft has now demonstrated,

employ more lateral thinking in order to

ensure that they can make their own

future commercial positions more

lucrative.

Picking up slack

The NOCs now have a big opportunity to

pick up any slack in the oil trading

market left by departing banks and

trading companies.

But while there are many opportunities

for NOCs in the year ahead, they will not

have it all their own way. And indeed,

market conditions will not necessarily

work in their favour.

Many market observers suspect that oil

prices will fall in 2014, as a result of the

potential for increased Iranian crude oil

exports following the relaxation of

sanctions and the continued rise in US

shale gas production. If they are right, the

shift may signal a turn in the so-called

commodity “super-cycle” (if such a thing

exists), whereby rising commodity prices

in the early part of the century are now

being replaced by falling commodity

prices.

If oil is vulnerable to such a price

correction, this is not such good news for

the NOCs, as it obviously erodes their

revenues. But even if oil market

conditions do get tougher for NOCs, this

in itself is also potentially a driver of

change.

Landmark

Last year was a landmark period for

Rosneft. It was the year in which the

company changed its own market

position and in which it altered market

perceptions of its objectives and

ambitions.

With the culmination of the year‟s

work being the acquisition of Morgan

Stanley‟s oil trading business, the group

is now set up for another interesting year

in 2014. We might not see quite so many

headline-grabbing announcements, but

the consolidation work, which will have

the objective of transforming Rosneft

into one of the world‟s foremost NOCs

(and in the longer term, into one of its

most significant energy trading groups)

will now begin.

Perhaps the most interesting element of

this is the question of how Rosneft‟s

changing character may set an example

to other NOCs. That is, on the back of

this deal, it is worth asking whether we

are about to see the rise of the NOCs and

a change in the tide that will be hard to

stop.

Latin America‟s potential to serve as a

key destination market is being closely

examined by the embryonic US LNG

industry, which is continuing to shape up

for a long-term role as one of the world‟s

largest gas exporters. The opportunity

certainly exists, given that Latin America

is becoming an integral part of global gas

trading, with imports rising in Chile,

Argentina and Brazil. Driving the

paradigm is the US LNG market, which

“has the potential of becoming the single

largest LNG producer in the world,” said

Todd Peterson, an advisor to US LNG

projects at Japan‟s Itochu Group.

Speaking on a January 15 panel at a

regional LNG forum in Houston, he

predicted that the US‟ Henry Hub

benchmark “could have quite an impact

on natural gas prices around the world.”

He said that was “going to help

develop LNG projects in the Caribbean,

Central America and South America and

around the world.”

FSU OGM

GLNG

LNG import potential

rising in Latin America

Argentina, Chile and Brazil could become larger importers of LNG, yet price will be key,

as there is competition from domestic production and pipeline imports

By Kevin Godier

Latin American countries require LNG to supplement their energy needs in the medium to long term

Mexico is importing LNG to deal with rising demand, falling domestic output and US pipeline bottlenecks

Imports to Latin America are forecast to rise by 10% per year until 2020, Cedigaz forecasts






Other panellists forecast that, even if

there is a marked rise in oil and gas

exploration and sales activity, many

Latin American countries will still

require LNG to supplement their energy

needs in the medium to long term.

Developing markets across the world

are energy-hungry, but the specific

growth in demand for LNG will pivot

upon a number of factors, including

pricing, politics and the level of

hydrocarbons imports needed, especially

by Brazil and Argentina. Together, these

two markets accounted for 2% of global

LNG imports in 2012, according to

International Gas Union data.

Brazil is, of course, focused upon its

huge pre-salt reserves and Argentina is a

potential producer from vast shale

reserves, and both markets will always

look very hard at the price of regional

pipeline gas, which averages between

US$1 to US$2 per million Btu.

LNG, by contrast, might be available

in a US$4-8 per million Btu range if

commodity prices remain at current

levels. However, analysts see the fuel

acting as a hedge if pipeline shipments

fall prey to politics. LNG could also

address seasonal and yearly supply

variations.

Brazilian imports

In both 2012 and 2013, Brazil was a

robust user of spot LNG to compensate

for the fall in hydropower owing to

drought conditions.

The trend has continued this month,

with ship-tracking data showing that the

Brazilian parastatal Petrobras received a

spot cargo in mid-January, which was

loaded out of storage from Portugal and

delivered to its floating regasification

terminal at Guanabara Bay, near Rio de

Janeiro.

Petrobras has another regasification

plant in the northeastern port of Pecem in

Ceara. Drought in 2013 left Brazil‟s main

hydro reservoirs at their lowest levels

since 2001, when the country had to

impose energy rationing.

Brazil‟s trade balance and Petrobras‟

bottom line were both hurt by the spot

cargoes, and the need to import large

amounts of gasoline and diesel earlier in

2013. However, Brazilian independent

HRT Participacoes em Petroleo

completed a study in 2013 that indicated

LNG might be the best way to bring to

market natural gas deposits found in the

country‟s remote Solimoes region, where

HRT has a 55% interest in 19 exploratory

blocks.

Imports into Argentina are also subject

to seasonal fluctuations and weather

conditions, but demand undoubtedly

exists. On January 15, Argentina‟s YPF

closed a tender for five cargoes delivered

to the country‟s Bahia Blanca and

Recalada ports, according to industry

media. The ports were built in 2007 and

2011 respectively. Argentina has no

long-term contracts to import LNG, but

by October 1, 2013, YPF and state-run

Enarsa had issued seven spot tenders

since December 2012, seeking as many

as 150 LNG shipments.

Of course Argentina sits on sufficient

gas reserves to provide self-sufficiency.

The US Energy Information

Administration (EIA) has estimated that

the nation sits on the world‟s second

largest shale gas reserves at 802 trillion

cubic feet (22.7 trillion cubic metres).

YPF is beginning to drill and develop

shale resources but it could take up to

four years to gain clarity, said Alejandro

Fernandez, operations manager for YPF's

gas and energy department.

“We don‟t have the crystal ball ... LNG

will stay for the next couple of years,” he

was quoted as saying by Upstreamonline

on January 16.

Mexican quest

Latin America‟s second largest economy,

Mexico, has been stepping up its imports

of LNG as rising demand, falling

domestic output and pipeline bottlenecks

for cheap US imports have sometimes

forced it to pay at least four times more

for added supplies.

In March 2013, an energy crunch in

Mexico underlined the country‟s growing

dependence on imports to keep power

flowing. State-run Pemex sought to buy

LNG at any price in order to avert

potential grid failures, paying a price of

US$19.45 per million Btu for a spot

LNG cargo in March, after imports from

the US costing about US$4.40 per

million Btu hit the limit of pipeline

capacity.

Mexico is likely to reduce its costly

imports towards the end of 2014 as major

pipeline expansion works allow more US

gas into the country.

Chile is another Latin American buyer,

as shown by state-run copper mining

company Codelco‟s recent agreement to

buy two cargoes of LNG for the

Mejillones LNG terminal in the north of

the country.

Chile began importing LNG in 2010,

but last year saw the scrapping of a

scheme to add 50% of capacity at

Mejillones because of lack of demand.

In Uruguay, the need for imported fuel

to run its power plants will decline, as

more than 132 MW of wind capacity is

expected to be installed by the middle of

2014, reaching 450 MW by the end of

the year. Nevertheless, GDF Suez has

begun work on the US$1.13 billion GNL

del Plata (Punta Sayago) LNG

regasification terminal, located offshore

of Montevideo, which is expected to

come on line as early as mid-2015.

Starting in 2015, GNL del Plata is

predicted to produce up to 10 million

cubic metres per day of regasified LNG,

supplying this to Uruguay‟s first

combined cycle power plant at Punta del

Tigre.

GNL del Plata will more than cover

Uruguay‟s demand, and so will be

positioned to export gas, particularly to

Argentina.

The world‟s fleet of LNG vessels are

undoubtedly making more stops than

ever in Latin America. Although the

region now only accounts for around 5%

of global LNG imports, it is anticipated

by market commentators to witness one

of the fastest rates of growth this decade.

Imports are forecast to rise by 10%

annually up to the end of 2020, according

to Cedigaz, a compiler of gas market

data. If there were a corresponding

recovery of the nuclear power business in

the world‟s leading LNG consumer,

Japan, the downward pressure on pricing

would greatly enhance the process.

GLNG






The reaction from the international bond

markets to Mexico‟s constitutional

energy reform has been positive, with

atypically high demand seen for new

borrowing from the government and

from state-run Pemex.

Yet the response to the reforms within

Mexico itself remains mixed. The lower

prices and economic benefits promised

by the reform are years away from

becoming a reality, assuming they do

actually materialise. And the legislative

sessions starting in under two weeks will

have to tackle the laws that will enact the

constitutional changes and allow foreign

and private companies to explore for and

produce oil and gas in Mexico for the

first time since 1938.

Bond success

Pemex set records last week by

borrowing US$4 billion from the

international bond markets, the largest

ever by any company from an emerging

market. The company found investors for

three bonds – US$3 billion due in 2043,

and US$500 million each for five-year

and 10-year bonds. It had initially

planned to borrow just US$2 billion

worth of 30-year bonds.

The firm usually makes its largest

bond market forays in January, when

bond funds are usually flush with cash

from new allocations.

A week earlier the government had

placed US$4 billion worth of bonds with

investors, meaning Mexico as a whole

has been able to tap US$8 billion of

investor demand in 10 working days; a

rare feat. Demand was no doubt spurred

by the December decision by credit

ratings agency Standard and Poor‟s to

boost ratings for both the government

and Pemex to BBB+ from BBB.

Typically, the most watched increase is

to BBB- from BB+, a measure that lifts a

borrower out of junk into investment

grade. This opens the door to a vastly

larger number of investors, because so

many funds are barred from investing in

junk-rated companies.

Standard and Poor‟s specifically cited

the December 20 approval of a

constitutional reform that ended Pemex‟s

monopoly on oil and gas exploration as a

key reason for boosting ratings for both

entities. When upstream investment

begins to flow in, which the Mexican

Energy Ministry estimates will start in

late 2015 or early 2016, it will represent

a significant macro-economic boost for

the country and additional revenues for

the federal government.

There are also financial market drivers

stabilising domestic and company

borrowing. Mexico created a system of

private pension funds, which have a

mandate for investing in peso-

denominated debt, switching from a

central government pay-as-you-go

system. The rising pool of workers‟

pension deposits has been meant lower

interest rates and more exchange rate

stability for the government and state-

backed companies, which suffer less

when there are sudden moves in peso-

dollar rates. This was a factor that helped

trigger a debt crisis and a vicious circle

of financial collapse between 1994 and

1995.

Reform push

Attention has now shifted to two factors

– the secondary laws that will contain the

nuts and bolts of how new companies are

to participate, and which fields Pemex

will seek to hold on to via its so-called

“round zero”; in which it has first refusal

on all existing resource-bearing blocks.

Transitory articles demand that the

ruling Institutional Revolution Party

(PRI) pass the second phase of energy

reform within three months of the

constitutional reform. The PRI has said

publicly that it intends to change 23 laws

to enable the direct licensing of resource-

bearing blocks, the sharing of resources,

production or profit, or combinations of

the above.

Pemex must claim its round zero

blocks by March 21 sending detailed

plans of how it intends to produce from

the fields it wants to keep under the

control of the National Hydrocarbons

Commission (CNH), the energy

regulator.

Pemex has so far made it clear that it

wants to hang on to its Bay of Campeche

fields, which delivered around 80% of

the firm‟s output in November.

It is also expected to offload low

margin natural gas fields so it can focus

on higher-margin deposits, a position

reiterated by Pemex‟s director general,

Emilio Lozoya Austin, at several public

events since last April.

LatAmOil

International investors give

thumbs-up to Mexican reforms

International investors have rushed to snap up new bonds issued by the Mexican

government and Pemex in a sign of confidence in the country‟s energy reform

By Amanda Beard

Pemex borrowed US$4 billion from international bond markets last week

The government also placed US$4 billion worth of bonds with investors

The reform process will gather momentum in February when the proposals go before the legislature






“People will be asking how the round

zero will be implemented,” Rogelio

Lopez Velarde, a partner in Lopez

Velarde, Heftye and Soria, a law firm in

Mexico City that specialises in energy,

told NewsBase. “Pemex has to prove why

it should keep the fields based on their

capacity.”

A key question will be whether Pemex

will be allowed to keep fields where it

lacks capacity on its own, based on the

argument that it will be able to find a

skilled collaborator via its own tender or

a negotiated partnership.

“It could be that the government will

insist that they enter an open tender with

their proposed joint venture partner,” he

added. Since the rules have not yet been

made public or passed by the legislature

and regulators have yet to publish their

views on those topics, the round zero

decisions look set to be a watershed

moment for potential participants.

Mexico‟s legislature reopens in

February and the Revolutionary

Democratic Party (PRD), which

staunchly opposes the reform, is seeking

to add a referendum on the reform on to

mid-term ballots. It is improbable that

Mexico‟s politicians would yield to the

referendum‟s results, but the issue

remains highly divisive and is likely to

bring PRD supporters out onto the streets

in protest.

Furthermore, PRI deputies in marginal

constituencies could choose this

legislative session to pressure the party to

narrow the proposed opening up of the

market suggested by the constitutional

reform in order to defend their seats.

Such political concerns are unlikely to

derail the project, though, a fact

emphasised by the appetite amongst

international investors for Pemex and

Mexican government bonds.

It is no secret that the statements of

politicians should often be taken with a

pinch of salt.

But even so few observers have

doubted that the announcement that oil

from the Kurdistan region of Northern

Iraq was flowing to Turkey‟s

Mediterranean oil hub at Ceyhan meant

anything less than that oil exports would

begin sooner rather than later.

The more so after the Kurdistan

Regional Government (KRG) announced

its plans to export 2 million barrels in

January, rising to 4 million in February

and 10-12 million by the end of the year,

after operator Genel Energy announced

that it was ramping up production and

even less so after the Iraqi central

government in Baghdad warned that it

would respond to the start of exports by

taking legal action against shippers,

buyers and against Turkey.

Which meant that the statement by

Turkish energy minister Taner Yildiz last

week confirming that only around

180,000 barrels of Kurdish crude had

been pumped to Ceyhan despite the

pipeline – which was expected to carry

up to 400,000 barrels per day – being in

operation for close to a month, all the

more surprising.

Piping problems

Turkish officials were able to explain

that the unusual nature of the Kirkuk-

Ceyhan pipeline has meant that to date

little Kurdish oil has been able to be

pumped. The line consists of two parallel

pipelines of 40-inch (1.01 metres) and

46-inch (1.17 metres) diameter

respectively both of which were

constructed to carry crude from the

Baghdad-controlled Kirkuk oilfields.

LatAmOil

Downstream MEA

Kurdish export plans currently

little more than pipe dreams

Technical issues mean that the volumes of Kurdish crude arriving at Ceyhan are far lower

than have been suggested, and an agreement with Baghdad now looks to be essential if

they are to increase

By David O’Byrne

Despite weeks of claims, it appears that a paltry 180,000 barrels of Kurdish crude have reached Ceyhan

The Turkish terminal has not been able to deal with the different crude blends, creating a choke point

With the cork still in the bottle, progress appears impossible without talks between Baghdad and Erbil

Turkish officials were able

to explain that the unusual

nature of the Kirkuk-

Ceyhan pipeline has meant

that to date little Kurdish

oil has been able to be

pumped






Now while the 40-inch line has been

co-opted to carry Kurdish crude, the two

lines still feed into the same pipeline

network at Ceyhan meaning that it is

only possible to fill the Ceyhan storage

tanks from one line at a time without

mixing crude from the two lines.

As the crudes carried by the two lines

have a different specific gravity, mixing

is not an option. And as Turkey has

contracted obligations to Iraq to carry the

Kirkuk crude, it has been obliged to

allow Kirkuk crude to flow into the

Ceyhan tanks with Kurdish crude only

able to flow for a few hours a day during

periods when Iraqi flow is halted for

maintenance on the Iraqi section of the

line.

So assuming Yildiz‟s statement is

correct, with little Kurdish crude flowing

there seems little danger of Turkey

reneging on its promise of not allowing

the export of Kurdish crude until a deal

has been brokered between Baghdad and

the KRG in Erbil. But this does raise

some questions. Firstly, why would

Turkey and the KRG have been so keen

to give the impression that exports were

imminent? Turkey must have known in

advance that flow would be limited while

the KRG must have been aware that

flows were far lower than the volumes

needed to make their planned exports.

That would appear to be a simple ploy

to force Baghdad to conclude a deal

rather than be left with a fait accompli –

predictable and hardly surprising.

Equally unsurprising given Baghdad‟s

history of intransigence on the issue, it

has failed to produce anything more than

threats of litigation.

Ceyhan chokepoint

Secondly though, there has been plenty

of warning from both the KRG and

developers in the region that they want to

export through the 40-inch Kirkuk-

Ceyhan line. One developer – Genel

Energy – has completed a line from its

producing field to connect with Kirkuk-

Ceyhan and two more are reported to be

under construction.

So why has no work been done at

Ceyhan to allow crude from the two

pipelines to be tanked separately and

simultaneously? This is less clear. It

could be that it just did not occur to

anyone in Ankara to check the specs of

the Botas Ceyhan terminal to find out

what was possible. The cock-up theory of

history is an enduring one but given the

age of the terminal and experience of

Botas personnel who run it, it seems

unlikely it would have escaped notice.

It could be that the work would be

difficult to complete without alerting

Baghdad as to what was happening, or

that the Iraqi government has some sort

of veto over such work being undertaken

on the line.

This though would imply that Baghdad

should be aware of the technical

bottleneck, which apparently it was not.

Pipeline politics

More interesting perhaps is the question

of why Ankara chose now to confirm the

problem and expose the KRG‟s export

plans as unfeasible. This strongly

suggests some level of dissatisfaction

with the KRG‟s apparent preference for

baiting Baghdad rather than actually

trying to negotiate an agreement.

Yildiz announced before Christmas

that Baghdad and the KRG had decided

to settle the issue between them, without

the help of Ankara.

But those talks do not seem to have

actually commenced until around two

weeks ago with only three meetings

having apparently taken place.

Whatever the truth, the fact now

appears clear that with currently no

possibility of operating both pipelines

simultaneously without the two crudes

being mixed in the tanks, any agreement

between Baghdad and the KRG to allow

exports to start would have to be for a

blended crude, at least until such time as

new pipes can be added to allow

separation and simultaneous flow – a fact

that will be sure to further complicate

negotiations and may have wider

implications for buyers used to buying

Kirkuk crude.

Downstream MEA






November‟s interim agreement between

Iran and the P5+1 was a watershed in

relations between the international

powers and the maverick Islamic

Republic.

While recent news reports have set out

conflicting interpretations of that

agreement, and the likely implications

once the real work of a possible complete

dismantling of sanctions begins, should

Iran comply with their demands, many

companies, some with previous business

experience in Iran, stand to gain if

sanctions are eased further.

When the interim agreement ends in

May, the question of progress in the goal

towards Iranian compliance will be

thrown into relief. Iran insists that its

nuclear programme exists to provide

conventional power, but sceptics, such as

Canada, Saudi Arabia and Israel, remain

unconvinced. Understanding the scope of

the sanctions, and the implications of

their removal, is key.

Key concepts

In December 2013, Patrick Murphy, legal

director at Clyde and Co., gave a

presentation in Dubai outlining the nature

of international sanctions against Iran.

He said that the brunt of the measures

had been introduced by the US and the

European Union, and that with interim

relief being offered in November, time

had come for a reassessment of where

their possible removal might lead.

The key aspect of US sanctions,

broadly in place since the return of

Ayatollah Ruhollah Khomeini to Teheran

in 1979, is a denial of the machinery of

the US dollar-denominated banking

system to Iran. EU sanctions are much

more recent, with a new raft imposed in

2012, but appear to be just as effective.

Murphy said the November deal meant

no new sanctions would be imposed for

six months, and involved the lifting of

embargoes on gold and precious metals,

Iran‟s automotive sector and the

country‟s petrochemical exports. The

licensing of safety-related repairs to

Iranian airlines was also allowed.

Some restrictions on Iran‟s vital oil

sector were lifted: the deal allowed

purchases of Iranian crude to remain in

force at current levels – amounting to a

60% reduction on 2012 – and that the

proceeds from such sales could be

repatriated back to Iran up to limit of

US$4.2 billion. There also seemed some

likelihood of the lifting of prohibitions

on insurance of the transport of those

crude sales.

Renewed optimism

An Iranian official speaking at TOC

Container Supply Chain Middle East

underlined Iran‟s efforts to capitalise on

the new optimism by setting out a list of

tenders for port equipment required at

Bandar Abbas.

Port representative Behzad Alsafi said

Bandar Abbas would be bidding for

several items of equipment and

technology, including vessel traffic

monitoring systems, automated ship

mooring systems, cameras, access

control identification and container

inspection technology. Another Iranian

official attending the conference in Dubai

expressed pessimism about the chances

of a long-term deal being brokered in

May. “I don‟t think anything‟s going to

change,” he said.

Energy expert Justin Dargin, of the

University of Oxford, is more optimistic,

sensing that the time is ripe for change.

He told NewsBase: “Without a doubt,

increased incremental removal of

sanctions appears to be quite likely in the

near future, as Iran has continued its

good faith steps. The latest negotiations

that occurred with the election of Hassan

Rouhani created a much more conducive

environment to move to rapprochement

between Iran and the Western powers.”

He said that the sanctions relief in the

Geneva agreement was a significant first

step.

“Arguably, the most important aspect

of the sanctions suspension in the

precious metals, petrochemicals and

vehicle industries is that on the energy

sector. It grants potential Iranian

customers the optimism that a

comprehensive agreement is around the

corner and that they can begin to

negotiate with Iran over substantially

increasing its exports to their markets in

the short to [medium] term.”

Taking steps

Recently, he said, Iran has begun to

disconnect centrifuges at Natanz plant,

and it has started to curb some of its most

sensitive uranium enrichment as well.

MEOG

Iran’s future growth hinges

on sanctions decision

There is plenty of optimism that Iran‟s energy sector can grow if Western-backed

sanctions are lifted. The issue now appears more one of „when‟ rather than „if‟

By Peter Shaw-Smith

Optimists are hopeful that Iran's energy sector is due for an investment boom

The country’s oil and gas fields are in dire need of foreign technologies to increase recovery rates

With sanctions now being eased, Tehran is whipping up interest among IOCs






The International Atomic Energy Agency

(IAEA) has concurred, he believes, that

Iranian progress is authentic, and has

announced that Iran has indeed halted

uranium enrichment above 5% purity at

both the Fordo and Natanz plants.

“If Iran continues, which is quite

likely, its steps to fulfil the elements of

the nuclear agreement, a partial

regeneration of the Iranian energy

industry would likely take place within

the year. It is partial in the sense that Iran

still needs to upgrade its energy-related

infrastructure, and that would take a

longer time. The restrictions on the

insurance and transport of Iranian oil by

American and European companies are

anticipated to be removed soon as well.”

Not every country is supportive of the

framework of negotiations, Dargin said.

“For instance, Canada, Israel and Saudi

Arabia tend to view the Iranian intention

to negotiate as being a cover to continue

to develop nuclear-weapon technology,

and as a result, Canada vowed not to

remove sanctions.”

Sanctions dance

Unsurprisingly, Iran has sought ways to

avoid the sanctions, and in particular,

directed its global oil trading effort

eastwards, in order to step up deliveries

to countries such as China, Japan, South

Korea and India, which were explicitly

allowed to trade with Iran, although not

to make payment in US dollars, because

“US banks are prevented from

facilitating transactions with Iran”, noted

Murphy. “In order to work around

sanctions, Iran developed a multifaceted

strategy to forestall total economic

breakdown. These strategies were both

short-term and long-term in scope, as

Iran had expected the sanctions regime to

last for some time. Iran offered

significant discounts on its crude exports

to its Asian customers in a bid to get

them to break Western sanctions. This

was part of its overall strategy to rely

more upon the Asian market instead of

the Western market,” Dargin said.

“Additionally, Iran moved to expand

the role of the private sector in the export

market. This was thought by the

leadership to provide a means to bypass

sanctions that were aimed at

governmental agencies. Iran also created

numerous front companies or traders for

export in a bid to evade surveillance.

Moreover, at one point, Iran was

estimated to be storing between 26 to 30

million barrels of oil on its super-

tankers.”

One of the most pressing issues for

Iranian shipping has been the denial of

insurance cover from international

underwriters during the sanctions regime.

As a means to reassure its customers,

Iran created sovereign-backed

reinsurance companies in order to resist

sanctions directed towards its global

shipping network and that of shipping

networks from countries that imported

from Iran, Dargin added. “This move

was not that successful, as the funding

offered was not in line with global

standards,” he said.

Looking downstream

Iran has looked beyond oil exports to its

downstream industry to provide succour

in its time of need, Dargin said.

“As a long-term strategy, Iran sought

to reduce dependence on crude oil

exports through the expansion of the

downstream industry. This was thought

by the Iranian leadership to provide, on

the one hand, more revenue stability and

job creation, and would also reduce the

dependence of Iran on the vagaries of the

Western oil market.”

Iran requires massive investment in its

economic sectors that were hit by

sanctions, he said.

“In particular, the oil and natural gas

sectors are in horrendous shape. As

Iran‟s oilfields are mostly mature, Iran

needs the latest oilfield technology in

order to improve reservoir production

rates. The technology that Iran requires

includes more advanced drilling

equipment, equipment to maintain

pressure in more mature oil wells, as well

as some of the latest seismic imaging

technology.”

Iran‟s 2,800-km coastline is served by

13 major commercial ports. “Iran is in

dire need of port refurbishment. Some of

Iran‟s Asian customers, such as India and

China, have offered generous loans to

refurbish Iran‟s ports that would buttress

its exports to the Asian markets. As an

example, the somewhat decrepit port of

Chabahar, which is essential for Asian

exports, has been the source of interest

from India to provide significant upgrade

and expansion,” Dargin said.

He suggested that Iran could return to

some kind of normality in the near

future.

“As the sanctions were just suspended,

it will take a bit of time for Iranian

exports and imports to reach full

capacity. Additionally, not all sanctions

have been lifted. As Iran was shut out of

the global banking sector for some time,

it will take some time for international

customers to begin to reintegrate

payments to Iran as well,” he said.

“The most important issue is the ability

for Western companies to trade in the

Iranian petrochemical sector. However,

the ultimate impact is likely to be limited

in scope, as prior to the imposition of

sanctions most of Iran‟s petrochemicals

exports went to the Asian market,” he

noted. “Nonetheless, the partial removal

of some of the Iranian sanctions has

allowed Iran some breathing room with

the expectation that exports and imports

will substantially increase to head

towards the pre-sanctions level within a

period of months.”

Despite his optimism, Dargin is under

no illusions about the way forward.

“Suffice it to say, much of the interim

progress depends on the success, or lack

thereof, [of] a final agreement.”

MEOG






The ongoing debate on the comparative

safety of rail and pipeline transportation

of crude oil has been re-ignited after the

train derailment and fire that led to the

evacuation of a North Dakota town in

late December.

Coming as the US moves nearer to a

decision on whether to approve the

Keystone XL pipeline, the incident

involved the crash of a 106-tanker BNSF

train carrying crude east from the Bakken

shale, which collided with another BNSF

train that was carrying grain near the

town of Casselton, about 25 miles (40

km) west of Fargo. Public safety officials

urged the evacuation of more than 2,000

residents as a fire engulfed the oil tankers

and burned for over 24 hours. The train

carrying oil originated in Fryburg, North

Dakota, and was bound for Hayti,

Missouri, on the Mississippi River.

Although no injuries were reported, the

incident marked the fourth major North

American derailment in six months

among trains transporting oil, and has

generated widespread calls for new and

enhanced safety features for crude oil

tankers. The North Dakota crash is “a

wake-up call for what increased oil

production in North America is going to

mean” for US communities, said Oil

Change International‟s executive

director, Stephen Kretzmann. The

Washington-based group opposes the use

of more fossil fuels.

According to Consumer Energy

Alliance‟s executive vice president,

Michael Whatley, more rail accidents can

be expected with the greater use of trains

to carry oil to market. “Trains need to be

a supplement, not a replacement” for

pipelines, Whatley was quoted on

January 1 by Bloomberg as saying.

While both forms of transportation are

safe, in that there are very few incidents

relative to the amount of crude they

transport, “we need expanded pipeline

infrastructure,” he said. Consumer

Energy Alliance is an industry-backed

group that supports Keystone XL.

Record levels of North American oil

are now being moved by rail as US crude

output has hit its highest level since

1988, driven mainly by shale formations

in Texas and North Dakota. Canadian

production – primarily from Alberta‟s oil

sands, is also on the rise. At the same

time, plans for new pipelines have stalled

and existing infrastructure has struggled

to keep up with surging output. The

recent accident will intensify scrutiny of

the safety and environmental risks that

are involved in rail transportation, and

will likely renew questioning of whether

pipelines may be a safer shipping

method.

Some believe that the accident may yet

play out in favour of the proposed

US$5.4 billion Keystone XL, which

would run from Canada to the US Gulf

Coast. The pipeline would primarily

carry oil sands crude, but it would also

receive about 100,000 barrels per day of

light oil from the Bakken formation in

Montana and North Dakota.

NorthAmOil

Rail accident sharpens focus

on crude transportation

Another crash involving a train carrying oil has intensified the debate on the comparative

safety of crude transportation by rail and pipeline once again

By Kevin Godier

A number of major accidents involving oil trains have occurred in recent months

The comparative safety of pipelines and trains feeds into the greater debate on the Keystone XL project

There are concerns that Bakken crude may be more flammable and requires extra safety measures






US President Barack Obama is

expected to rule definitively on the

1,179-mile (1,897-km) pipeline within

the next few months, when the US

Department of State (DoS) will have

completed work on a report that will

weigh up the project‟s environmental

impacts.

Pipelines vs trains

A growing part of the Keystone XL

debate has been on the relative safety of

pipelines versus trains. The evidence to

date has not proved conclusive, with

some suggesting that oil pipelines are

generally safer, with pipeline accidents

having resulted in fewer injuries, but that

they have a higher risk of leaks and spills

than trains. Meanwhile, in March 2013, a

draft supplemental environmental impact

statement released by the DoS indicated

that while derailments probably would

release less oil than a pipeline rupture,

trains have an “increased statistical

likelihood of spills”.

Opponents of Keystone XL have

pointed to pipeline spills that have

recently occurred in Alabama, Michigan

and North Dakota, citing the risk

involved in major projects in particular.

Further concern has been caused by the

fact that two pipelines carrying oil sands

crude from Canada have ruptured in

recent years. Train accidents have also

been prominent, though. A train carrying

oil to the Gulf Coast from North Dakota

derailed in Alabama in November 2013,

triggering fires. A month earlier,

residents were evacuated from a rural

area of Alberta after 13 rail tankers, four

of which were carrying crude, derailed

and also ignited. The worst accident

occurred in July, when a runaway train

transporting crude exploded and killed 47

people in the Quebec town of Lac-

Megantic. In addition, following the

recent crash in North Dakota, a CN train

carrying crude and LPG was reported to

have derailed in New Brunswick in early

January, resulting in a fire and the

evacuation of 150 people nearby.

Pipelines have an additional advantage

in that they generally cross more sparsely

populated regions, whereas there are

more rail lines going through more

populated areas. Costs are also a factor

for companies. It currently costs about

US$7 to transport a barrel of oil from

Alberta to the US Gulf Coast by pipeline.

This is slower than if the oil were

transported by rail, but is also cheaper,

with rail transportation costing between

around two to four times as much.

Developers of several major North

American pipelines awaiting approval

decisions will be watching the unfolding

debate with keen interest. As well as

Keystone XL, notable projects include

Enbridge‟s C$6 billion (US$5.5 billion)

Northern Gateway and its Line 9B

reversal, TransCanada‟s C$12 billion

(US$11 billion) Energy East project and

Kinder Morgan‟s Trans Mountain

expansion.

North Dakota relies on both methods

to transport its crude, as the growth of

output from this remote area has

outstripped pipeline capacity. The state

produced nearly 950,000 bpd of oil in

October. Roughly 700,000 bpd of this

was reportedly shipped by rail, most of it

consisting of the light, sweet Bakken

crude that safety officials are now saying

could be particularly flammable, because

of its high propane and butane content.

Almost 2,500 miles (4,023 km) of new

pipelines were also built in North Dakota

in 2012, and the state has been

encouraging midstream operators to

expand the network to keep pace with

record production in the oil patch. North

Dakota now has about 17,500 miles

(28,164 km) of pipelines. However in

September, a Tesoro pipeline ruptured

and spilled 20,000 barrels of crude at a

remote rural site in northwest North

Dakota, which is the US‟ largest oil-

producing state behind Texas. This led to

the revelation that North Dakota had

recorded almost 300 small oil spills in

under two years but that these had gone

unreported to the public.

New approach?

Although rising output has driven North

Dakota‟s unemployment rate down to the

lowest in the US, calls for a slowdown in

the state‟s oil production have been

voiced in some quarters. The chairman of

North Dakota‟s Republican Party, Robert

Harms, who is also an energy industry

consultant, told Reuters on January 2 that

a “moderated approach” was required.

“Even people within the oil and gas

industry that I‟ve talked to feel that

sometimes we‟re just going too fast and

too hard,” said Harms.

Surging output is forecast to propel the

US past Saudi Arabia as the world‟s

largest oil supplier in 2015, and there are

many doubts over whether the safety

debate will ultimately hold back the rise

of crude by rail, in which shipments have

soared from less than 5,000 tanker loads

in 2006 to an estimated 400,000 in 2013.

Petroleum products were the fastest-

growing category of rail shipments in

2013, the Association of American

Railroads (AAR) said in a recent report.

This indicated that the volume of

shipments rose 31% last year, while

overall traffic rose 1.8%.

The topic of rail safety will not go

away. Regulators are actively seeking

public input on proposed updates to old

crude-by-rail rules covering tanker

toughness and other standards. However,

the commercial pressures are immense.

Against the slow pace of pipeline

approvals, the dynamic crude-by-rail

market looks set to keep growing, as

shown by the number of crude producers

and coastal refiners that have committed

to multi-year contracts to transport

Bakken crude by rail. Indeed, a reported

manufacturing backlog of about 60,000

oil tankers is slated for delivery by 2015,

which makes it inevitable that further

accidents will occur as North America‟s

hydrocarbons industry continues its

learning curve.

NorthAmOil

“Even people within the oil

and gas industry that I’ve

talked to feel that

sometimes we’re just going

too fast and too hard”






Germany‟s attempts to increase its

renewable energy capacity massively

have thrown up another illustration of the

uneven pace of development.

The European leader in renewable

energy capacity and its neighbour, the

Czech Republic, are to regulate power

flows across their borders so that surges

in the amount of German clean energy do

not overload the Czech grid and increase

the risk of power cuts. A similar deal is

likely to be signed between Germany and

Poland later this year.

Prague and Berlin have agreed to

install phase-shifting transformers along

their border with the aim of making

power trading between the two countries

smoother and boosting the security of

supply in the Czech Republic.

The transformers are an unforeseen

result of the massive expansion of wind

energy assets in the north of Germany –

where the country‟s best wind

resources are located – and the

need to transport that power to

the main centres of population

and demand in the industrial

south of the country.

Interconnection

While a large amount of

generating capacity has been

built – in November last year,

some 60% of demand was being

met by renewable sources at

certain times – Germany‟s grid

infrastructure has not kept pace.

A new power line between

Schwerin in the east of the country and

Hamburg was opened in 2013 but only

after years of delays, and any further

upgrades will be similarly slow to

emerge. Eventually, a new link from

Thuringia in the east of Germany to

Bavaria will solve the capacity problems,

but the 250 million euro (US$342

million) link is not expected to come on

line for another two to four years.

The result is that if Germany wants to

transmit renewable power to Bavaria, it

sends it via its eastern neighbours, which

distorts their ability to trade power with

other countries and threatens to overload

their grids. Both Poland and the Czech

Republic have threatened to shut down

their links to Germany when it is very

windy, typically in the latter part of the

year.

The Czech Republic‟s position at the

heart of Europe means it has five

interconnections that make it a natural

transit point for power trading in the

region. CEPS, the Czech transmission

system operator (TSO), explains:

“Electricity flows along the path of least

resistance, consequently, a significant

proportion (up to 50%) of electricity

exports from Germany to Austria flows

through Poland and the Czech Republic

since this path offers less resistance than

a more direct path through the internal

German network.”

The result is that these surges of

mainly wind-derived electricity make

balancing power in the Czech grid

difficult, although not impossible. CEPS

says: “The installation of the phase

shifters will significantly improve control

of unplanned flows on the

interconnector.”

While the immediate cause of the

problem is the lack of internal

transmission infrastructure in

Germany, it is not helped by

infrastructural weaknesses in its

neighbours and it illustrates the

inefficiencies thrown up by

Europe‟s lack of a single

electricity market.

Market rates

If there were a (true) single

market, then Germany‟s cheap

wind energy would be bought by

its neighbours when it was

available, reducing prices for

consumers as well as helping to

decarbonise the system overall.

REM

Phase-shifting the

blame in Central Europe

The Czech Republic and Germany have agreed to install phase-shifters to regulate

transmission, but this may be ignoring a wider problem – the lack of a single EU market

By Mike Scott

Both Poland and the Czech Republic are to control their cross-border transmission from Germany

However, with a true single market, electricity tariffs could be lower and savings passed to consumers

This market would require better investment in transmission and infrastructure, slated for 2016 onwards






However, because power markets

remain defined by national borders,

consumers are losing out on such

substantial efficiencies and economies of

scale. As it is, national power companies

have incentives to stop cheap power from

neighbouring countries reaching

consumers because it reduces the

profitability of their own generating

capacity.

The EU is aiming for the single energy

market to be completed in 2014, but it

seems a forlorn hope. EU member states‟

energy systems are characterised by a

range of different market mechanisms,

regulatory and tax regimes and

technology mixes. Finally, national

politicians guard their countries‟ energy

independence jealously.

So even though, as the Agency for the

Co-operation of Energy Regulators said

recently, delays to the single market for

electricity are costing consumers billions

of euros, many providers are in no hurry

to make it a reality.

According to the chair of ACER‟s

board of regulators, Lord Mogg, “The

advantages brought about by the single

market, such as lower wholesale

electricity prices or a more efficient use

of interconnectors identified in the study,

still have fully to benefit final consumers

in the retail market.”

Yet a single energy market will be vital

for markets looking to exploit their

renewable resources fully, such as

Scotland, Portugal, Ireland and Romania,

which will be able to produce far more

energy than they consume – but will only

benefit from this if they have someone to

sell the energy to.

Northern Europe

Some progress is being made,

particularly in Northern Europe, where

the UK has interconnectors in place with

Ireland, France and the Netherlands, with

plans under way for a link with Norway

– which is also strengthening links with

Denmark and Germany.

Norway, with its abundant fast-

reacting hydropower capacity, could play

a crucial role in integrating the wind

resources of the North Sea into a Europe-

wide system by acting as a kind of

battery for Europe – providing stand-by

power to compensate for fluctuations in

the contribution of variable renewable

energy.

At the moment, though, the focus

appears to be on mollifying incumbent

producers rather than on securing

cheaper power for consumers. Placing

the blame on “unreliable” German wind

energy shifts blame, rather than

addressing the wider problems of the

market – to the detriment of further

renewables development.

Chinese shale gas production witnessed a

surge in 2013, climbing five-fold to 200

million cubic metres, according to

China‟s Ministry of Land and Resources.

The government has pledged to spur the

shale industry‟s development and meet

rising gas demand by prioritising land

approvals, allowing tax-free imports of

equipment and offering subsidies to

explorers.

National Energy Administration

(NEA) deputy head, Zhang Yuqing, said:

“We will continue to work closely with

other departments to reduce problems

regarding government policies and other

regulations reflected in the development

of shale gas, and create a better

environment for shale gas producers.”

Beijing has set an ambitious target of

boosting the country‟s shale gas output to

6.5 billion cubic metres per year by 2015.

The Five-Year Plan, which runs from

2011 to 2015, includes not just

exploration and production but also

transportation and infrastructure, which

China is currently struggling with.

The pipeline network is widely

acknowledged to be insufficient to

transport such huge quantities of gas and

the country‟s terrain makes it even more

difficult to lay any pipelines. This, says a

report released by Kuick Research, will

require huge levels of investment in the

future.

Another problem is the lack of water

supply, as hydraulic fracturing requires

large amounts of water.

Vast resources

Beijing is confident, though, that it will

achieve its shale goals. Kuick describes

the country as “basking in the glory of its

recent world‟s largest shale finds.”

REM

Unconventional OGM

China makes shale progress

China‟s shale gas production reached 200 million cubic metres last year and there are

signs of increasing optimism over the unconventional sector, despite some challenges

By Nnamdi Anyadike

China has the world's largest shale reserves and ambitious targets, but development has been slow

Obstacles include challenging geology and a lack of pipeline infrastructure

Beijing is stepping up efforts to encourage shale development






The US Energy Information

Administration (EIA) reduced its

estimate of Chinese technically

recoverable shale reserves from

1.275 quadrillion cubic feet

(36.1 trillion cubic metres) to

1.115 qcf (31.6 tcm) of of gas,

but China nonetheless remains

the largest holder of shale

resources globally.

China‟s enormous shale gas

resources have been mainly

found in the Sichuan and Tarim

Basins, but other shale deposits

are also scattered all over the

country. Generally, however, the

reserves can be divided into four

regions – North China, South

China, Northwestern and

Northeastern China.

The exploration of shale gas in China

is still in its infancy and concerns were

expressed last year over the pace at

which development was proceeding,

amid speculation that the country would

fail to meet its 2015 production target.

However, exploration is picking speed

and Royal Dutch Shell recently

announced that the exploratory results in

the Sichuan Basin were satisfying.

Sinopec, the country‟s largest refiner,

has set a target of 3.2 bcm in 2015 for its

shale gas project in the Chongqing-

Fuling area, which is almost double its

previous target.

Slow progress

There are still concerns, though, that

government targets may be hard to reach,

as development thus far, despite last

year‟s progress, has been slow. A

National Development and Reform

Commission (NDRC) researcher, Zhang

Yousheng, recently raised doubts as to

whether the goals could be achieved –

much of which rest on domestic

companies PetroChina and Sinopec.

A recent analysis by Forbes was also

pessimistic, saying that the shale gas

revolution would “not be coming to

China anytime soon.” The report draws

on US Secretary of Energy Ernest

Moniz‟s visit to China at the end of 2013,

where he met government officials and

oil industry executives. Moniz pointed to

China‟s “above-ground issues” with

bringing gas to market, which mean that

the country lags behind the US.

“It‟s often forgotten that in the US not

only did we have obviously a favourable

geology for producing these resources,

but we also had by far the most mature

natural gas infrastructure in terms of

pipelines, market structures, trading

hubs, futures contracts, regulation of

production, etc.,” he said. For China to

develop its resources “at a large scale and

in a rapid fashion”, he said, it must tackle

these issues.

Unlike in the US, where independent

producers drove the shale revolution,

taking on risks that oil majors declined,

in China the three giant state-run oil and

gas companies have monopoly power

and developers with North American

shale expertise can only enter the sector

through partnerships with them.

Although China has set ambitious

targets for natural gas production, the

above-ground framework – including

regulations on how much cities will pay

to gas suppliers – still needs to be

adjusted to account for shale

development.

Gas use in China is

anticipated to double between

2010 and 2015 to 230 bcm and

domestic output is growing

slowly, which means more

imports are required,

predominantly from Central

Asia and Russia.

“Judicious investment in shale

gas might change the balance,”

said Forbes, although it added

that there would likely emerge a

gap between China‟s desire for

cleaner-burning fuels and its

ability to source them.

Growing interest

Nevertheless, China‟s shale

prospects are sufficiently appealing to

invite foreign companies to take a look at

what is on offer.

In early January, the Financial Times

reported on the Scotland-based Weir

Group – a leading manufacturer of

pumps used for fracking. Weir‟s CEO,

Keith Cochrane, told the paper: “It‟s

going to be a long time before China

reaches the US level. But there‟s no

question they are serious.” It is thought

that as development takes off, China

could become a sizable market for

companies such as Weir.

Other international oil firms including

ExxonMobil, Chevron, ConocoPhillips,

Shell, Total and Eni have already entered

into agreements to explore China‟s shale

resources. Services firms, such as

Schlumberger, Halliburton, Baker

Hughes and Weatherford, have also

increased their presence in China.

The rest of the world has been warned

not to underestimate China‟s

determination to launch its shale gas

sector. Beijing has been said to be fully

aware of the challenges involved, and is

taking steps to solve them. China‟s

political will is expected to help

accelerate development despite the

obstacles the shale sector is facing.

Unconventional OGM

NRG January 2014, Issue 46 Back Page

For further details on the stories above and NewsBase’s entire product range:

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HEADLINES FROM A SELECTION OF NEWSBASE MONITORS THIS WEEK

Oil and Gas Sector

AfrOil Vanoil appears set to lose its Kenyan licences after failing

to satisfy its contractual commitments.

AsianOil Myanmar may award 30 offshore licences this month.

ChinaOil PetroChina plans to invest US$250 million in drilling up to

30 shale gas wells in Sichuan this year.

FSU OGM Gazprom is reportedly close to a deal with Greece's DEPA

on gas price cuts.

GLNG Japan’s Toho Gas has signed a deal to take 300,000

tonnes per year of LNG from the Cameron LNG project.

LatAmOil Malaysia’s Petronas is considering investment in

Argentina’s Vaca Muerta shale play.

MEOG Aramco expects to begin the prequalification process for

EPC contracts for its Khurais field expansion in mid-2014.

NorthAmOil XTO Energy has struck two separate deals in the Utica

shale and Permian Basin.

Unconventional OGM Suncor Energy has reportedly suspended its plans to

develop its Montney shale acreage in British Columbia.

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