118392_BMI Algeria Oil and Gas Report Q4 2010

Q4 2010www.businessmonitor.com

oil & Gas RepoRt

issN 1748-3786published by Business Monitor international ltd.

alGeRiaINCLUDES 10-YEAR FORECASTS TO 2019

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ALGERIA OIL & GAS REPORT Q4 2010 INCLUDES 10-YEAR FORECASTS TO 2019

Part of BMI’s Industry Survey & Forecasts Series

Published by: Business Monitor International

Copy deadline: August 2010

Algeria Oil & Gas Report Q4 2010

© Business Monitor International Ltd Page 2



CONTENTS

Executive Summary ......................................................................................................................................... 7

Algeria Energy Market Overview .................................................................................................................... 9

Global Oil Market Review .............................................................................................................................. 12

Drifting With The Tide .............................................................................................................................................................................................. 12 Quarterly Trends ...................................................................................................................................................................................................... 13 Deepwater Turbulence .............................................................................................................................................................................................. 13

Global Oil Market Outlook ............................................................................................................................. 15

Waiting For The Wind To Change ............................................................................................................................................................................ 15 Oil Price Forecasts ................................................................................................................................................................................................... 15

Oil Supply, Demand And Price Outlook ....................................................................................................... 17

Short-Term Demand Outlook .................................................................................................................................................................................... 17 Table: Global Oil Consumption (000b/d) ............................................................................................................................................................ 18

Short-Term Supply Outlook ...................................................................................................................................................................................... 18 Table: Global Oil Production (000b/d)................................................................................................................................................................ 19 Longer-Term Supply And Demand ....................................................................................................................................................................... 20 Oil Price Assumptions ......................................................................................................................................................................................... 21 Table: Crude Price Assumptions 2010 ................................................................................................................................................................. 21 Table: Oil Price Forecasts ................................................................................................................................................................................... 21

Regional Market Overview ............................................................................................................................ 22

Oil Supply And Demand....................................................................................................................................................................................... 22 Table: Africa’s Oil Consumption, 2007-2014 (000b/d) ........................................................................................................................................ 23 Table: Africa’s Oil Production, 2007-2014 (000b/d) ........................................................................................................................................... 24 Oil: Downstream ................................................................................................................................................................................................. 25 Table: Africa’s Oil Refining Capacity, 2007-2014 (000b/d) ................................................................................................................................ 25 Gas Supply And Demand ..................................................................................................................................................................................... 26 Table: Africa’s Gas Consumption, 2007-2014 (bcm) ........................................................................................................................................... 26 Table: Africa’s Gas Production, 2007-2014 (bcm) .............................................................................................................................................. 27 Liquefied Natural Gas ......................................................................................................................................................................................... 28 Table: Africa’s LNG Exports, 2007-2014 (bcm) .................................................................................................................................................. 28

Business Environment Ratings .................................................................................................................... 29

Composite Scores................................................................................................................................................................................................. 29 Table: Regional Composite Business Environment Rating .................................................................................................................................. 29 Upstream Scores .................................................................................................................................................................................................. 30 Table: Regional Upstream Business Environment Ratings .................................................................................................................................. 30 Algeria Upstream Rating – Overview .................................................................................................................................................................. 31 Algeria Upstream Rating – Rewards ................................................................................................................................................................... 31 Algeria Upstream Rating – Risks ......................................................................................................................................................................... 31 Downstream Scores ............................................................................................................................................................................................. 32 Table: Regional Downstream Business Environment Ratings ............................................................................................................................. 32 Algeria Downstream Rating – Overview .............................................................................................................................................................. 33 Algeria Downstream Rating – Rewards ............................................................................................................................................................... 33 Algeria Downstream Rating – Risks .................................................................................................................................................................... 33



Risk Summary ................................................................................................................................................ 34

Political .................................................................................................................................................................................................................... 34 Economic .................................................................................................................................................................................................................. 34 Business Environment ............................................................................................................................................................................................... 34

Industry Forecast Scenario ........................................................................................................................... 35

Oil And Gas Reserves ............................................................................................................................................................................................... 35 Oil Supply And Demand ............................................................................................................................................................................................ 35 Gas Supply And Demand .......................................................................................................................................................................................... 36 LNG .......................................................................................................................................................................................................................... 37 Refining And Oil Products Trade .............................................................................................................................................................................. 37 Revenues And Import Costs ...................................................................................................................................................................................... 38

Table: Algeria’s Oil And Gas, 2007-2014 ........................................................................................................................................................... 39 Other Energy ............................................................................................................................................................................................................ 40

Table: Algeria’s Other Energy, 2007-2014 .......................................................................................................................................................... 41 Key Risks To BMI’s Forecast Scenario ..................................................................................................................................................................... 41 Long-Term Oil And Gas Outlook .............................................................................................................................................................................. 41

Oil And Gas Infrastructure ............................................................................................................................ 42

Oil Refineries ....................................................................................................................................................................................................... 42 Table: Refineries In Algeria ................................................................................................................................................................................. 42 Gas Pipelines ....................................................................................................................................................................................................... 42

Macroeconomic Outlook ............................................................................................................................... 46

Table: Algeria – Economic Activity ..................................................................................................................................................................... 48

Competitive Landscape ................................................................................................................................. 49

Table: Key Players In The Algerian Energy Sector ............................................................................................................................................. 50 Overview/State Role ............................................................................................................................................................................................. 50 Licensing And Regulation .................................................................................................................................................................................... 51 Government Policy .............................................................................................................................................................................................. 52 Licensing Rounds ................................................................................................................................................................................................. 52 International Energy Relations ............................................................................................................................................................................ 53 Table: Key Upstream Players .............................................................................................................................................................................. 54 Table: Key Downstream Players ......................................................................................................................................................................... 54

Company Monitor ........................................................................................................................................... 55

Enterprise Nationale Sonatrach ........................................................................................................................................................................... 55 Anadarko Algeria................................................................................................................................................................................................. 61 Eni Algeria Production ........................................................................................................................................................................................ 65 BP Algeria ........................................................................................................................................................................................................... 68 BHP Petroleum (Algerie) ..................................................................................................................................................................................... 71 CEPSA ................................................................................................................................................................................................................. 73 Statoil Algeria ...................................................................................................................................................................................................... 75 Hess – Summary .................................................................................................................................................................................................. 77 Maersk Oil – Summary ........................................................................................................................................................................................ 77 Repsol YPF – Summary ....................................................................................................................................................................................... 77 Royal Dutch Shell – Summary ............................................................................................................................................................................. 78 ConocoPhillips – Summary .................................................................................................................................................................................. 78 Total – Summary .................................................................................................................................................................................................. 78 BG Group – Summary .......................................................................................................................................................................................... 79



Talisman Energy – Summary ............................................................................................................................................................................... 80 Gazprom – Summary ........................................................................................................................................................................................... 80 Others – Summary ............................................................................................................................................................................................... 81

Long-Term Oil And Gas Forecasts ............................................................................................................... 82

Regional Oil Demand .......................................................................................................................................................................................... 82 Table: Africa’s Oil Consumption, 2012-2019 (000b/d) ........................................................................................................................................ 82 Regional Oil Supply ............................................................................................................................................................................................. 83 Table: Africa’s Oil Production, 2012-2019 (000b/d) ........................................................................................................................................... 83 Regional Refining Capacity ................................................................................................................................................................................. 84 Table: Africa’s Oil Refining Capacity, 2012-2019 (000b/d) ................................................................................................................................ 84 Regional Gas Demand ......................................................................................................................................................................................... 85 Table: Africa’s Gas Consumption, 2012-2019 (bcm) ........................................................................................................................................... 85 Regional Gas Supply ............................................................................................................................................................................................ 86 Table: Africa’s Gas Production, 2012-2019 (bcm) .............................................................................................................................................. 86 Algeria Country Overview ................................................................................................................................................................................... 86

Methodology And Risks To Forecasts ....................................................................................................................................................................... 87

Glossary Of Terms ......................................................................................................................................... 88

BMI Methodology ........................................................................................................................................... 89

How We Generate Our Industry Forecasts .......................................................................................................................................................... 89 Energy Industry ................................................................................................................................................................................................... 89 Cross Checks ....................................................................................................................................................................................................... 90 Oil And Gas Ratings Methodology....................................................................................................................................................................... 90 Table: Structure Of BMI’s Oil & Gas Business Environment Ratings ................................................................................................................. 92 Indicators ............................................................................................................................................................................................................. 93 Table: BMI’s Upstream Oil & Gas Business Environment Ratings – Methodology ............................................................................................ 93 Table: BMI’s Downstream Oil & Gas Business Environment Ratings – Methodology ........................................................................................ 94 Sources ................................................................................................................................................................................................................ 95



Executive Summary

The latest Algeria Oil & Gas Report from BMI forecasts that the country will account for 9.36% of

African regional oil demand by 2014, while providing 18.02% of supply. African regional oil use of

3.06mn barrels per day (b/d) in 2001 rose to 3.75mn b/d in 2009. It should average 3.81mn b/d in 2010

and then rise to around 4.26mn b/d by 2014. Regional oil production was 7.93mn b/d in 2001, and in

2009 averaged 9.67mn b/d. From a projected 10.23mn b/d in 2010, it is set to rise to 11.93mn b/d by

2014. Oil exports are growing steadily, because demand growth is lagging behind the pace of supply

expansion. In 2001, the region was exporting an average of 4.87mn b/d. This total had risen to 5.92mn b/d

in 2009 and is forecast to reach 7.67mn b/d by 2014. Angola has the greatest production growth potential,

with Nigerian exports set to climb if it can resolve recent quasi-political issues.

In terms of natural gas, the region in 2010 will have consumed an estimated 122.9bn cubic metres (bcm),

with demand of 165.6bcm forecast for 2014. Production of an estimated 219.5bcm in 2010 should reach

305.2bcm in 2014, which implies net exports rising from 97bcm to 140bcm in 2014. In 2010, Algeria’s

share of regional gas supply is an estimated 37.82%, rising to 38.17% by 2014. The country’s share of

demand in 2010 is an estimated 18.44%, with 18.02% predicted by 2014.

For 2010 as a whole, we continue to assume an average OPEC basket price of US$83.00/bbl, +36.4%

year-on-year (y-o-y). Risk is now clearly on the downside, thanks to the slow progress made during June.

However, a full-year outturn in excess of US$80 remains a strong possibility and we see no need to

review our assumptions at this point. The 2010 US WTI price is now put at US$87.63/bbl. BMI is

assuming an OPEC basket price of US$85.00/bbl in 2011, with WTI averaging US$89.74. Our central

assumption for 2012 and beyond is an OPEC price averaging US$90.00/bbl, delivering WTI at just over

US$95.00.

For 2010, the BMI assumption for premium unleaded gasoline is an average global price of

US$95.45/bbl. The overall y-o-y rise in 2010 gasoline prices is put at 36%. Gasoil in 2010 is expected to

average US$93.23/bbl. The full-year outturn represents a 35% increase from the 2009 level. For 2010,

the annual jet price level is forecast to be US$95.90/bbl. This compares with US$70.66/bbl in 2009. The

2010 average naphtha price is put by BMI at US$83.53/bbl, up 41% from the previous year’s level.

Algeria’s real GDP is assumed by BMI to have risen by 3.1% in 2010, with forecast average annual

growth in 2010-2014 put at 4.0%. We expect estimated oil demand of 341,000b/d in 2010 to rise by up to

4.0% per annum to 399,000b/d in 2014. State oil company Sonatrach dominates the industry, operating

in partnership with various international oil companies (IOCs), and accounts for 60% of the country’s oil

output. Thanks largely to IOC investment, combined oil and gas liquids output is forecast to increase

from an estimated 1.89mn b/d in 2010 to 2.15mn b/d in 2014, with exports heading towards 1.75mn b/d.



The country’s OPEC membership and assigned production quota could frustrate volume growth

ambitions. Gas production of an estimated 83bcm in 2010 should reach 117bcm by 2014. Consumption of

an estimated 28bcm in 2010 is expected to rise to 34bcm by the end of the forecast period, providing

exports of 83bcm.

Between 2010 and 2019 we are forecasting an increase in Algerian oil and gas liquids production of

37.9%, with volumes rising steadily from an estimated 1.89mn b/d in 2010 to 2.60mn b/d by the end of

the 10-year forecast period. Oil consumption between 2010 and 2019 is set to increase by 42.3%, with

growth slowing to an assumed 4.0% per annum towards the end of the period and the country using

485,000b/d by 2019. Gas production is expected to rise to 135bcm by the end of the period. With demand

rising by 55.1% between 2010 and 2019, export potential should rise from 56bcm to 92bcm, in the form

of LNG and by pipeline. Details of BMI’s 10-year forecasts can be found in the appendix to this report.

Algeria takes second place in BMI’s composite Business Environment (BE) ratings table, which

combines upstream and downstream scores. It now holds sixth place in the updated upstream Business

Environment ratings, sandwiched between Angola and Egypt. The country’s score benefits from healthy

oil and gas reserves, a large number of non-state companies active in the upstream sector and decent

licensing terms. Algeria is near the top of the league table in BMI’s updated downstream Business

Environment ratings, with some high scores but progress further up the rankings unlikely. It is ranked

third behind Egypt, thanks to high scores for gas consumption, nominal GDP, likely refining capacity

expansion and oil demand growth.



Algeria Energy Market Overview

Algeria is a major oil producer, with considerable reserves and production upside potential. It is a

member of OPEC, which theoretically restricts its ability to expand output. The country is also an

important supplier of gas to Europe, both via pipeline (to Spain, Italy and Portugal) and in the form of

liquefied natural gas (LNG). The June 2010 BP Statistical Review of World Energy suggests that Algeria

had proven reserves total of 12.2bn barrels (bbl) of oil in 2009. Algeria hopes to increase its crude oil

production capacity significantly over the next few years by attracting more foreign investment.

Oil and gas exports, which make up more than 95% of Algerian exports by value, are the main driver of

economic growth. Algeria’s average crude oil production in 2009 was an estimated 1.3mn b/d. Together

with more than 300,000b/d of condensate and at least 200,000b/d of natural gas liquids, the country

pumped around 1.81mn b/d. The country was pumping 1.25mn b/d of crude alone in June 2010, having in

2009 reduced output in accordance with the late 2008 OPEC agreement. Estimated sustainable crude

capacity is thought to have exceeded 1.40mn b/d by the end of 2009.

Oil consumption, at 331,000b/d in 2009, leaves substantial export potential. Some 90% of the country’s

oil exports are destined for the EU, mainly Italy, Germany and France. The crude produced is generally of

an exceptionally high quality, with low levels of sulphur, which makes it highly suitable for EU refiners

and their strict fuel standards. As of January 2010, Algeria had four oil refineries – a large complex in

Skikda, and small plants in Algiers, Arzew and Hassi Messaoud – with combined capacity of 462,000b/d.

Gas reserves were estimated at 4,500bcm in 2009, although increased exploration activity could rapidly

increase this total. Production in 2009 of 81bcm and consumption of around 27bcm provided an export

capacity of 55bcm, more than a third of which takes the form of LNG. Algeria meets some 20% of EU

gas demand.

For Algeria, gas was the dominant fuel in 2009, accounting for an estimated 61.7% of PED, followed by

oil at 36.2%, and coal with a 1.8% share of PED. Regional energy demand is forecast to reach 1,075mn

tonnes of oil equivalent (toe) by 2014, representing 19.3% growth over the period since 2010. Algeria’s

estimated 2009 market share of 4.35% is set to climb to 4.47% by 2014, with hydro-electricity making an

insignificant contribution and the country having no nuclear capability. Electricity generation in Algeria

is largely based on gas. The fuel in 2009 provided 97.5% of generated electricity. Oil accounts for around

1.8% of generation, with hydro claiming a tiny sliver of the power pie. Renewables do not yet make a

meaningful contribution.

According to BMI calculations, Algeria at the end of 2009 had installed electricity generating capacity of

more than nine gigawatts (GW), virtually all based on conventional thermal sources. In 2009, Algeria



generated an estimated 41TWh and consumed an estimated 31TWh of electricity. Since 2000, electricity

generation has increased by more than 40% and consumption by 45%. Surplus power was exported to

Morocco and Tunisia.

Algeria in 2009 brought online six gas-fired power stations with 2GW of capacity, according to a June

2010 statement from the head of the state-owned utility company Societe Nationale de l'Electricite et du

Gaz (Sonelgaz). The power stations were built at a cost of US$6bn as part of a 2006 emergency plan to

satisfy rising electricity demand in the country, Noureddine Boutarfa told Algerian public radio. ‘Today,

Algeria has sufficient means of production until 2012,’ at which point new power stations will start

operating, Boutarfa said.

State-owned national company Sonatrach operates the largest oil field in Algeria, Hassi Messaoud,

where peak production should be 600,000b/d. Sonatrach also operates the 180,000b/d Hassi R’Mel field

and other smaller producers, including Tin Fouye Tabankort Ordo, Zarzaitine, Haoud Berkaoui/Ben

Kahla and Ait Kheir. IOCs have increased steadily their share of Algeria’s oil production with the largest,

Anadarko Petroleum of the US, having a gross capacity in excess of 500,000b/d. Other major foreign

investors include US-based Hess, BHP-Billiton of Australia, UK major BP, Spain’s Repsol YPF and

CEPSA, Royal Dutch Shell, Norway’s Statoil and Total of France.

Algeria is planning to go ahead with a licensing round by the end of 2010 in spite of the recent shakeup of

the country's energy ministry and state-run oil company, Reuters reported on June 23 2010. The news

service quoted an anonymous energy ministry official who emphasised the need to bring foreign expertise

into the country's upstream sector.

Algeria's former energy minister, Chakib Khelil, announced plans for a new licensing round in March

2010, saying that the fiscal terms were likely to remain unchanged. The comments raised the likelihood

that the 2010 licensing round would end much the same as the 2009 round, which saw just three out of 10

permits on offer allocated to investors. Most IOCs cited unattractive fiscal terms as the reason for their

reticence.

Since Khelil's announcement, Algeria's energy industry leadership has undergone a transformation.

Sonatrach, which dominates the country's oil and gas industry, saw a corruption scandal bring down its

CEO, Mohammed Mezian, and senior management. Those officials are now either in jail or house arrest

while a corruption investigation continues. The scandal also saw the dismissal of Khelil, who had

previously acted as OPEC chief and headed the country's energy ministry for a decade. Khelil was

replaced as energy minister by Youcef Youcefi and Mezian was replaced as Sonatrach CEO by Nordine

Cherouati. Both appointees are seen as close to the military, which was seen to be pushing forward the

corruption investigation.



The new team has stopped short of making public pronouncements on improving terms for oil and gas

investors. The comments of anonymous officials as reported by Reuters, however, do appear to show that

at least some in the government recognise the need to attract foreign investment and expertise. The

comments raise the possibility of the new leadership looking at improving licensing terms for the

upcoming auction round.



Global Oil Market Review

Drifting With The Tide

Although Q2 started with encouraging oil market strength, this had largely dissipated by the end of the

quarter. Little changed in terms of oil market fundamentals but there was a major shift in sentiment

among investors and forecasters. Eurozone economic woes, China jitters and a general sense of

macroeconomic fragility meant that oil prices were dragged lower with equities and currencies. Crude

once again became a stock market proxy, with little enthusiasm for the commodity. Seemingly endless

bad news from the Gulf of Mexico hardly helped encourage oil market speculation, as BP’s very public

battle with US President Obama cast a shadow over future upstream developments and oil company

prospects. None of this was actually negative in terms of near-term price prospects, but investors needed

little excuse to avoid oil.

Demand projections for 2010 continued to firm up during the second quarter, even though the jury is still

out regarding the strength and sustainability of the economic recovery. The imposition of ‘tougher’

sanctions by the UN against Iran failed to increase oil market tension. Inventories have changed little and

OPEC policy appears to be one of ignoring likely over-supply in the hope that it will go away without

action being required.

According to the International Energy Agency (IEA)’s July 2010 monthly Oil Market Report (OMR),

OECD end-May commercial oil inventories stood at 2,757mn barrels (bbl), up 35mn bbl from the April

level. This increase was broadly in line with the five-year average stock build, representing a relatively

benign development. More worrying, perhaps, is an estimated build of 3.5mn bbl in June, at a time when

a draw of around 8.7mn bbl is usually expected. Crude stocks emerged lower, but this improvement was

outweighed by a products gain largely in the US.

In terms of production, the worrying OPEC output trend seen earlier in the year appears to have been

reversed or, at least, stabilised. June saw global oil supply fall by more than 250,000 barrels per day (b/d)

according to the IEA. OPEC and non-OPEC producers saw volumes fall during the month. Crude oil

supply from OPEC averaged 28.9mn b/d in June (IEA estimate), down by 65,000b/d when compared with

the previous month. Much of this reduction, however, reflects Iraqi cutbacks, with the 11 core members

actually increasing supply by some 40,000b/d. Quota compliance of around 59% is now pretty stable and

close to the historical OPEC norm.

Non-OPEC supply in Q2 has been fairly stable when compared with the first quarter, but has shown a

clear weakening trend during the three months. Output of around 52.7mn b/d in April slipped to 52.4mn

b/d in May and emerged still lower at around 52.2mn b/d in June. Among the major contributors to the



June downturn were Norway and the US. Average Q210 non-OPEC supply is put at around 52.4mn b/d,

compared with 52.5mn b/d in Q1.

Quarterly Trends

The Energy Information Administration (EIA) in its July 2010 monthly report suggested that Q210 global

oil demand was 85.50mn b/d, compared with 85.26mn b/d in Q110 and 83.88mn b/d in Q209. Non-

OECD demand is reported at 40.87mn b/d, compared with 39.41mn b/d in the previous quarter and

39.53mn b/d in Q209. The OECD states saw a 1.22mn b/d quarter-on-quarter fall in consumption during

Q210, amounting to 44.63mn b/d. In Q209, OECD demand was 44.35mn b/d, based on EIA data.

According to the Paris-based IEA, Q210 global consumption averaged 86.57mn b/d, compared with

86.04mn b/d in Q110 and 83.89mn b/d in Q209. The year-on-year (y-o-y) change was a gain of 3.19%.

OECD demand in Q210 is reported at 45.20mn b/d, compared with 45.99mn b/d in Q110 and 44.46mn

b/d in Q209. Non-OECD consumption in Q210 was reportedly up 4.92% y-o-y at 41.37mn b/d. In Q110,

non-OECD consumption was 40.06mn b/d.

OPEC’s July 2010 monthly oil report states Q210 global oil demand at 84.40mn b/d, down from 84.76mn

b/d during the previous quarter and up from 83.26mn b/d in Q209 (+1.37%). OECD demand is said to

have risen by 0.13% y-o-y, with North American consumption higher by 1.96%. Non-OECD demand was

up 2.78% y-o-y, according to the OPEC data.

The EIA Q210 estimates suggest that non-OPEC oil supply was 51.28mn b/d, compared with the Q110

level of 51.42mn b/d and the 49.98mn b/d recorded in Q209. Russia, the US and Canada were significant

contributors to the supply increase. OPEC output for Q210 is put at 34.71mn b/d, up from 34.51mn b/d in

Q110 and the 33.59mn b/d delivered in the second quarter of 2009.

Global Q210 production based on IEA data was an average 86.44mn b/d. This compares with 86.62mn

b/d in Q110. The non-OPEC element for the most recent quarter is 52.40mn b/d, easing lower from

52.52mn b/d in Q1. Overall OPEC volumes, including gas liquids, are said to have fallen from 34.09mn

b/d to 34.04mn b/d between Q110 and Q210.

OPEC itself believes that non-OPEC oil supply averaged 52.03mn b/d in Q210. OPEC crude output was

assessed at 29.17mn b/d during the quarter, with the cartel pumping an average 29.20mn b/d in June.

Deepwater Turbulence

There will be lasting repercussions resulting from the Deepwater Horizon incident in the Gulf of Mexico.

It is inconceivable that deepwater drilling programmes will not be revised and disrupted as a result of the



record-breaking oil spill that appears to be threatening BP’s future. Ultra-deepwater discoveries and

development represent a significant part of the non-OPEC oil industry’s growth potential. Even in

countries that are less sensitive than the US to environmental issues, we can expect to see higher costs,

modified methods of operation and project delays as the industry responds to this fresh challenge.

Preliminary estimates from the EIA in the wake of the deepwater drilling moratorium announced by US

Energy Secretary Ken Salazar in late May suggest a shortfall in US supply of around 31,000b/d in Q410

and about 82,000b/d in 2011. The IEA believes that delays to new projects resulting from the Macondo

oil spill have already shaved 30,000b/d off both 2010 and 2011 US crude production. It warns that

extended project delays could reduce its 2015 projection for US Gulf production by

100,000b/d‐300,000b/d.

On June 22, a US district court judge lifted the partial deepwater drilling moratorium, arguing that it was

too broad a measure that discriminated against companies with untainted safety records. Damage to the

regional economy and to the US energy industry was no doubt another factor taken into consideration. On

July 8, an appeals court backed the decision, but the Obama administration is believed to be considering a

more focused moratorium. At present, however, there is no deepwater drilling in the GoM.

In the US Congress, a wave of proposed legislation is making progress through various committees, with

key proposals including new safety measures, increased demands on companies active in deepwater

drilling, greatly enhanced liability for operators and a possible ban on drilling within 75 miles (121km) of

the US coastline.

Once a framework is in place, other countries with deepwater prospects can be expected to adopt some or

all of the US measures. EU Energy Commissioner Günther Oettinger has called for an EU deepwater

drilling moratorium, although there appears to be limited support and equally limited risk. The North Sea

has less deepwater potential than other regions, with pretty demanding regulation already in place.



Global Oil Market Outlook

Waiting For The Wind To Change

With fair winds and following seas, oil prices could gather momentum during the remaining months of

2010, moving briskly ahead after a period in the doldrums. Market fundamentals are generally favourable

but a wave of negative sentiment needs to be overcome before progress can be made. Oil has recently

become a victim of broader macroeconomic pessimism, tracking equity and currency trends rather than

energy market conditions. If stock markets can gain ground in the third quarter, crude and products prices

should follow them higher. Looking ahead to 2011, the supply and demand picture is again reasonably

attractive and should be able to support further modest oil price gains.

Our 2010 target of US$83.00 per barrel (bbl) for the OPEC basket price is still just about attainable, but

only if a recovery gets underway soon and can be sustained throughout H2. The demand side of the

equation looks reasonable and supply risk is arguably more on the downside from here. Inventories

continue to be an area of concern but, overall, the oil market looks in reasonable shape for a mildly

bullish phase.

Any momentum gained during the second half of 2010 should be carried through into 2011. Oil demand

growth next year is likely to fall somewhat short of the forecast 2010 level, reflecting OECD efforts to

reduce oil dependency in the wake of high fuel prices and environmental initiatives. Helping offset this

factor is a likely slowing of non-OPEC supply expansion. With potential delays and cost overruns in the

frontier areas following the Deepwater Horizon disaster, volumes are expected to grow more slowly. This

provides breathing space for OPEC, which will hope to regain a little market share during 2011.

Oil Price Forecasts

In terms of the OPEC basket of crudes, the average price in Q210 was US$76.59/bbl, up modestly from

the US$75.40/bbl recorded during the previous three months. In Q209, the OPEC price averaged

US$58.81/bbl, so the most recent quarter has seen a year-on-year (y-o-y) gain of 30%. Prior to the weekly

average low of US$68.95 reached in late May 2010, the OPEC basket had been as high as US$83.36/bbl

(weekly average) at the beginning of that month. Becalmed in much of June and July, the price traded in a

narrow range of US$71-74/bbl. The monthly averages for the second quarter of 2010 have been

US$82.33, US$74.48 and US$72.95/bbl. BMI is currently assuming that July will deliver an average

close to US$76 if the price rallies as expected from here.

In terms of other marker prices, North Sea Brent averaged US$78.30/bbl during Q2, with WTI achieving

US$77.78, Urals (Mediterranean delivery) at US$76.89/bbl and Dubai realising an average US$78.12.



These averages have been calculated using OPEC data and monthly prices from the International Energy

Agency (IEA).

As mentioned above, the BMI assumption for July 2010 OPEC crude is US$76.00/bbl and, for the third

quarter we are expecting an average of US$86.67/bbl. This suggests a 13% strengthening of quarterly

realisations when compared with Q210 and a y-o-y gain of US$19/bbl when compared with Q309

(+28%).

For 2010 as a whole, we continue to assume an average OPEC basket price of US$83.00/bbl (+36.4% y-

o-y). This is the forecast introduced in our October 2009 quarterly report. Risk is now clearly on the

downside, thanks to the slow progress made during June. However, a full-year outturn in excess of

US$80/bbl remains a strong possibility and we see no need to review our assumptions at this point. Any

failure of prices to rally significantly in Q3 will mean a downgrade in our October quarterly report.

The 2010 US West Texas Intermediate (WTI) price is now put at US$87.63/bbl. The July 2010 monthly

report from the US-based Energy Information Administration (EIA) predicts a 2010 average WTI crude

price of just under US$79/bbl, rising to US$83.00 in 2011. BMI is assuming an OPEC basket price of

US$85.00/bbl in 2011, with WTI averaging US$89.74. Our central assumption for 2012 and beyond is an

OPEC price averaging US$90.00/bbl, delivering WTI at just over US$95.00/bbl.



Oil Supply, Demand And Price Outlook

Short-Term Demand Outlook

The BMI oil supply and demand assumptions for 2010 and beyond have once again been revised for all

71 countries forming part of our detailed coverage, reflecting the changing macroeconomic outlook and

the impact of environmental initiatives. Investment in exploration, development and new production has

been rising as a result of higher crude prices, but deepwater activity has been set back by events in the

GoM. Costs associated with oil field development and exploration/appraisal drilling have begun to rise

again, with deepwater programmes now particularly vulnerable.

We have once again made only modest changes to forecast oil production levels, in line with recent

OPEC output and known project delays, with no clear evidence of large-scale spending changes by

international oil companies (IOCs) or national oil companies (NOCs).

According to the updated BMI model, 2010 global oil consumption will now increase by 2.06% from the

2009 level. This represents an upgrade to the forecast contained in the April 2010 quarterly report. The

2010 forecast represents slightly higher OECD demand (+0.94%) and a revised non-OECD increase of

3.12%. The overall increase in demand is estimated at 1.74mn b/d. North America is now expected to see

expansion of 244,000b/d (+1.17%), with OECD European demand set to recover by 142,000b/d

(+1.10%). Non-OECD gains are expected to be 2.50% in Asia, 1.69% in Latin America, 3.64% in

Central/Eastern Europe, 4.07% in the Middle East and 1.66% in Africa.

The IEA, in its July 2010 Oil Market Report, predicts a slightly more bullish rise in 2010 oil demand of

2.13%, or 1.80mn b/d. The organisation’s assumptions suggest an impressive 4.35% rise in non-OECD

consumption (+1.71mn b/d). This points to 0.13% higher OECD oil demand, lagging the likely economic

recovery and any weather-related benefits accrued in Q1.

July 2010 EIA estimates suggest that world demand will rise y-o-y from 84.26mn b/d to 85.82mn b/d,

with the 1.56mn b/d increase in consumption amounting to a gain of 1.85%. This view sits just below the

somewhat more optimistic BMI assumption and the IEA’s still more generous estimate. Non-OECD

demand is predicted to increase by 3.91% (1.52mn b/d), while OECD demand is expected to rise by just

30,000b/d (0.07%). Consumption in the US is expected to increase by 200,000 b/d (1.07%). With

Canadian demand 3.26% higher and that of Europe 0.97% lower, it is in Japan that the US energy body

sees the greatest risk of a decline – forecasting a fall of 3.21%.



OPEC’s July 2010 report suggests a likely increase in 2010 global oil consumption of 0.95mn b/d, or

1.12%. OECD demand is forecast to fall by 150,000b/d (0.33%). Non-OECD demand is expected to

average 40.04mn b/d, compared with 38.93mn b/d in 2009 (+2.85%).

Table: Global Oil Consumption (000b/d)

2007 2008 2009 2010f 2011f 2012f 2013f 2014f

Africa 3,578 3,710 3,753 3,813 3,904 4,001 4,131 4,262

Middle East 6,469 6,864 7,146 7,422 7,709 7,904 8,161 8,376

NW Europe 13,642 13,541 12,963 13,105 13,145 13,202 13,292 13,297

N America 23,003 21,785 20,881 21,125 21,070 21,187 21,304 21,422

Asia/Pacific 25,761 25,994 26,348 27,008 27,679 28,515 29,300 30,064

Central/Eastern Europe 5,965 6,129 5,831 6,043 6,205 6,368 6,537 6,712

Latin America 7,597 7,724 7,631 7,760 7,906 8,070 8,259 8,412

Total 86,075 85,855 84,651 86,391 87,742 89,405 91,149 92,719

OECD 44,999 43,395 41,508 41,900 41,636 41,868 42,055 42,194

non-OECD 41,076 42,460 43,143 44,491 46,106 47,537 49,094 50,526

Demand growth % 1.33 (0.26) (1.40) 2.06 1.56 1.90 1.95 1.72

OECD % (1.20) (3.56) (4.35) 0.94 (0.63) 0.56 0.45 0.33

Non-OECD % 4.26 3.37 1.61 3.12 3.63 3.10 3.27 2.92

f = forecast. Historical data: BP Statistical Review of World Energy, June 2010/BMI. All forecasts: BMI.

Short-Term Supply Outlook

According to the revised BMI model, 2010 global oil production will rise by 2.52%, representing an

OPEC increase of 3.47% and a non-OPEC gain of 1.80%. The overall increase in supply is estimated at

2.20mn b/d in 2010, which represents an upgrade from the forecast delivered by the April 2010 quarterly

report. We continue to assume that the existing OPEC production ceiling will be retained for the whole of

2010, but that actual output will remain close to the Q210 level. Should quota adherence deteriorate

further, then OPEC volumes could emerge rather higher.

The EIA was in July 2010 forecasting a 620,000b/d y-o-y rise in non-OPEC oil output, representing a

gain of 1.23%. World oil production is predicted to be 85.89mn b/d in 2010, up from 84.23mn b/d

(+1.66mn b/d) in 2009. The US organisation expects a 1.04mn b/d (3.07%) upturn in OPEC oil and

natural gas liquids (NGL) output.



OPEC itself sees 2010 non-OPEC supply rising by 740,000b/d to 51.86mn b/d. In 2010, OPEC NGLs and

non-conventional oils are expected to increase by 0.49mn b/d over the previous year to average 4.84mn

b/d. The July 2010 OPEC monthly report argues that the call on OPEC crude is expected to average

28.7mn b/d, representing a downward adjustment of 105,000b/d from its previous assessment and a

decline of 300,000b/d from the previous year. This suggests little scope for members to raise output.

The IEA’s 2010 assumption for non-OPEC oil supply is 52.40mn b/d, representing a rise of 1.47%. This

somewhat cautious view is based on output declines in Mexico, the UK and Norway, which offset partly

the growth predicted for Brazil, Russia, China, India and Colombia. OPEC production of NGLs is

expected to rise sharply from 4.66mn b/d to 5.26mn b/d. Increased biofuels supply (+16%) and a slight

downturn in processing gains imply a need for OPEC crude volumes of 28.83mn b/d in 2010. This is very

close to OPEC’s estimated Q210 output.

Table: Global Oil Production (000b/d)

2007 2008 2009 2010f 2011f 2012f 2013f 2014f

Africa 10,229 10,190 9,671 10,225 10,514 10,874 11,375 11,931

Middle East 25,207 26,229 24,407 24,861 25,182 25,500 25,923 26,673

NW Europe 5,160 4,881 4,628 4,543 4,162 4,009 3,812 3,724

N America 10,167 10,002 10,408 10,475 10,545 10,565 10,585 10,600

Asia/Pacific 8,474 8,689 8,568 8,911 9,159 9,300 9,254 8,979

Central/Eastern Europe 12,954 12,977 13,368 13,628 13,854 13,936 14,044 14,402

Latin America 10,119 9,857 9,749 10,045 10,304 10,340 10,465 10,632

OPEC NGL adjustment 4,300 4,600 4,660 5,260 5,870 5,989 6,135 6,361

Processing gains 1,985 2,084 2,290 2,200 2,230 2,275 2,320 2,366

Total 88,573 89,493 87,795 90,004 91,584 92,572 93,689 95,406

OPEC 34,642 35,568 33,076 33,784 34,320 35,018 35,871 37,192

OPEC inc NGLs 38,942 40,168 37,736 39,044 40,190 41,008 42,007 43,553

Non-OPEC 49,631 49,325 50,059 50,960 51,394 51,564 51,683 51,852

Supply growth % 0.27 1.04 (1.90) 2.52 1.76 1.08 1.21 1.83

OPEC % (0.17) 3.15 (6.05) 3.47 2.93 2.03 2.44 3.68

Non-OPEC % 0.61 (0.62) 1.49 1.80 0.85 0.33 0.23 0.33

f = forecast. Historical data: BP Statistical Review of World Energy, June 2010/BMI. All forecasts: BMI.



Longer-Term Supply And Demand

The BMI model predicts average annual oil demand growth of 1.84% between 2010 and 2014, followed

by 1.47% between 2014 and 2019. After the forecast 2.06% global demand recovery in 2010, we are

assuming 1.56% growth in 2011, followed by 1.90% in 2012, 1.95% in 2013 and 1.72% in 2014.

OECD oil demand growth is expected to remain relatively weak throughout the forecast period to 2019,

reflecting market maturity, the ongoing effects of recent demand destruction and the greater commitment

to energy efficiency. Following the 4.35% decline in 2009 OECD oil consumption and the forecast 0.94%

rise in 2010, we expect to see a decrease of 0.63% in 2011. On average, OECD demand is forecast to rise

by 0.33% per annum in 2010-2014, then fall by 0.12% per annum in 2014-2019.

For the non-OECD region, the demand trend in 2010-2014 is for 3.21% average annual market

expansion, followed by 2.74% in 2014-2019. Demand growth is forecast to recover from 1.61% in 2009

to 3.12% in 2010 and 3.63% in 2011.

BMI is forecasting global oil supply increasing by an average 1.68% annually between 2010 and 2014,

with an average yearly gain of 1.64% predicted in 2014-2019. We expect the trend to be at its weakest

towards the end of the 10-year forecast period, with gains of just 1.21% and 0.62% predicted in 2018 and

2019.

Non-OPEC oil production is expected to rise by an annual average of 0.71% in 2010-2014, then 0.28% in

2014-2019. OPEC volumes are forecast to increase by an annual average of 2.91% between 2010 and

2014, rising to 3.19% per annum in 2014-2019.



Oil Price Assumptions

The OPEC basket price, having averaged an estimated US$76.59/bbl in Q210, is forecast to be US$86.67

in Q3 and US$93.33/bbl in Q4. The full year forecast remains an average of US$83.00/bbl. Brent, WTI

and Urals prices for 2010 are put at US$84.96, US$87.63 and US$83.80/bbl respectively.

Table: Crude Price Assumptions 2010

Q110 Q210e Q310f Q410f 2010f

Brent (US$/bbl) 76.24 78.30 87.62 97.68 84.96

Urals – Med (US$/bbl) 75.32 76.89 86.62 96.36 83.80

WTI (US$/bbl) 78.67 77.78 90.36 103.69 87.63

OPEC basket (US$/bbl) 75.40 76.59 86.67 93.33 83.00

Dubai (US$/bbl) 75.83 78.12 86.49 94.23 83.67

e/f = estimate/forecast. Source: BMI.

By 2011, there should be further growth in oil consumption and more room for OPEC to regain market

share and reduce surplus capacity through higher production quotas. We are assuming a further increase

in the OPEC basket price to an average US$85.00/bbl, implying Brent at US$87.01, WTI at

US$89.74/bbl and Urals at US$85.82. For 2012 and beyond, we continue to use a central case forecast of

US$90.00/bbl for the OPEC basket.

Table: Oil Price Forecasts

2007 2008 2009 2010f 2011f 2012f 2013f 2014f

Brent (US$/bbl) 72.52 96.99 61.51 84.96 87.01 92.13 92.13 92.13

Urals - Med (US$/bbl) 69.51 94.49 61.04 83.80 85.82 90.87 90.87 90.87

WTI (US$/bbl) 72.26 99.56 61.68 87.63 89.74 95.02 95.02 95.02

OPEC basket (US$/bbl) 69.08 94.08 60.86 83.00 85.00 90.00 90.00 90.00

Dubai (US$/bbl) 68.37 93.56 61.69 83.67 85.69 90.73 90.73 90.73

f = forecast. Source: BMI.



Regional Market Overview

West and North Africa have an important role to play in terms of global oil supply, with Angola’s

offshore deepwater wealth an increasingly important factor. Nigeria is struggling to contend with

domestic political problems that have been hampering oil expansion. Gas is another important export

product for the region, largely in the form of LNG. North Africa and Nigeria play a growing role in the

supply of the world’s gas. The likes of Nigeria, Libya and Algeria have been renegotiating contract terms

with foreign partners so as to retain a greater share of hydrocarbons revenues.

Oil Supply And Demand

Perennial problem child Nigeria and West African rival Angola face further OPEC-related friction if they

continue to push for a revised output ceiling. A return by Nigeria to higher production levels has been

taking place, and further progress is possible during 2010/11. Thanks to this and the Angolan trend, our

data suggest that Africa is set to play an increasingly important role in world oil supply, with Angola

remaining a magnet for foreign investment – in spite of deepwater drilling concerns.

Overall African oil production will average a forecast 10.23mn b/d in 2010. By 2014, we see output rising

to at least 11.93mn b/d, when Angolan volumes are likely to have reached a plateau. We are assuming

steady growth from Algeria and Libya, with Nigeria seeing recovery from recent depressed levels.

African demand is set to increase from an estimated 3.81mn b/d in 2010 to 4.26mn b/d by 2014,

providing an export capability increasing from an estimated 6.41mn b/d to 7.67mn b/d.



Table: Africa’s Oil Consumption, 2007-2014 (000b/d)

Country 2007 2008 2009 2010f 2011f 2012f 2013f 2014f

Algeria 288 311 331 341 355 369 383 399

Angola 70 81 85 94 108 124 149 179

Cameroon 27 31 33 34 36 38 40 42

Republic of Congo 6 6 7 7 7 8 8 8

Egypt 650 693 720 734 756 779 810 835

Equatorial Guinea 1 1 1 1 1 1 1 1

Gabon 13 13 14 14 15 15 16 17

Libya 260 268 274 279 287 296 308 320

Nigeria 291 286 280 288 303 318 342 367

South Africa 550 532 518 523 531 539 547 555

Sudan 88 89 84 87 92 96 101 106

BMI universe 2,244 2,311 2,345 2,404 2,491 2,584 2,706 2,830

Other Africa 1,334 1,399 1,408 1,409 1,413 1,417 1,425 1,432

Regional total 3,578 3,710 3,753 3,813 3,904 4,001 4,131 4,262

f = forecast. Source: Historical data: BP Statistical Review of World Energy, June 2010; BMI

Oil use of 3.06mn b/d in 2001 rose to 3.75mn b/d in 2009. It should have averaged 3.81mn b/d in 2010

and then rise to around 4.26mn b/d by 2014. Algeria accounts for an estimated 8.94% of 2010 regional oil

consumption, with a likely market share of 9.36% by 2014.



Table: Africa’s Oil Production, 2007-2014 (000b/d)

Country 2007 2008 2009 2010f 2011f 2012f 2013f 2014f

Algeria 2,016 1,993 1,811 1,885 1,925 1,965 2,050 2,150

Angola 1,720 1,875 1,784 1,890 1,970 2,150 2,300 2,400

Cameroon 82 84 73 73 72 80 84 85


Egypt 710 722 742 730 715 685 700 683


Gabon 230 235 229 250 260 255 250 245

Libya 1,820 1,820 1,652 1,660 1,695 1,725 1,800 1,865

Nigeria 2,305 2,116 2,061 2,240 2,275 2,350 2,450 2,700

South Africa 16 15 11 12 15 17 16 16

Sudan 468 480 490 565 600 630 691 735

BMI universe 9,965 9,939 9,434 9,980 10,262 10,615 11,107 11,655

Other Africa 264 251 237 245 252 259 269 277

Regional total 10,229 10,190 9,671 10,225 10,514 10,874 11,375 11,931


Regional oil production was 7.93mn b/d in 2001, and in 2009 averaged 9.67mn b/d. From an estimated

10.23mn b/d in 2010, it is set to rise to 11.93mn b/d by 2014. Algeria in 2010 accounts for an estimated

18.44% of regional oil supply, and its market share is expected to be 18.02% by the end of the forecast

period.

Oil exports are growing steadily, because demand growth is lagging behind the pace of supply expansion.

In 2001, the region was exporting an average 4.87mn b/d. This total had risen to 5.92mn b/d in 2009 and

is forecast to reach 7.67mn b/d by 2014. Angola has the greatest production growth potential, with

Nigerian exports set to climb if it can resolve recent quasi-political issues.



Oil: Downstream

Table: Africa’s Oil Refining Capacity, 2007-2014 (000b/d)

Country 2007 2008 2009 2010f 2011f 2012f 2013f 2014f

Algeria 450 450 462 562 594 594 594 594

Angola 39 39 39 39 39 39 39 239

Cameroon 42 37 37 37 37 37 70 70


Equatorial Guinea na na na na na na na na

Egypt 726 726 726 726 726 726 726 976

Gabon 17 24 24 24 24 24 24 30

Libya 378 378 378 450 450 550 550 650

Nigeria 505 505 505 505 505 505 540 540

South Africa 485 485 485 485 485 485 485 485

Sudan 122 122 122 122 122 122 122 122

BMI universe 2,785 2,787 2,799 2,971 3,003 3,103 3,171 3,727

Other Africa 267 441 441 463 510 510 510 536

Regional total 3,052 3,228 3,240 3,434 3,513 3,613 3,681 4,263


Refining capacity for the region was 3.14mn b/d in 2001, rising gradually to 3.24mn b/d in 2009. Angola,

Algeria and Nigeria are all expected to increase significantly their domestic refining capacity, with the

region’s total capacity forecast to rise from an estimated 3.43mn b/d in 2010 to 4.26mn b/d by 2014. In

2010 Algeria has an estimated 16.38% of regional refining capacity, and its market share is forecast at

13.94% in 2014.



Gas Supply And Demand

Table: Africa’s Gas Consumption, 2007-2014 (bcm)

Country 2007 2008 2009 2010f 2011f 2012f 2013f 2014f

Algeria 24.3 25.4 26.7 27.5 28.9 30.5 32.1 33.7

Angola 2.5 3.5 4.0 5.0 6.0 7.0 8.1 9.3

Cameroon na na na na 0.2 0.2 0.2 0.2

Republic of Congo na 0.5 0.5 1.0 1.0 1.2 1.5 2.0

Egypt 38.4 40.8 42.4 44.6 46.8 48.9 51.3 53.4

Equatorial Guinea 1.4 1.5 1.5 1.6 1.7 1.8 1.9 2.0

Gabon 0.1 0.1 0.1 0.2 0.5 1.0 1.0 1.0

Libya 5.3 5.5 5.8 6.3 7.0 7.8 9.0 9.6

Nigeria 10.6 12.3 8.9 13.0 15.0 18.5 21.0 25.0

South Africa 5.9 6.5 7.0 7.0 9.0 10.0 10.5 12.0

Sudan na na na na na na na na

BMI universe 88.5 96.1 97.1 106.4 116.1 126.8 136.6 148.2

Other Africa 16.6 16.6 16.6 16.6 16.6 16.6 16.6 17.4

Regional total 105.1 112.7 113.6 122.9 132.6 143.4 153.2 165.6

f = forecast. na= not applicable. Source: Historical data: BP Statistical Review of World Energy, June 2010; BMI



Table: Africa’s Gas Production, 2007-2014 (bcm)

Country 2007 2008 2009 2010f 2011f 2012f 2013f 2014f

Algeria 84.8 85.8 81.4 83.0 90.0 103.0 111.0 116.5

Angola 2.5 3.5 4.0 5.0 6.0 12.0 15.0 16.3

Cameroon na na 0.1 0.2 0.2 0.2 0.2 0.2

Republic of Congo na 0.5 0.5 1.0 1.0 1.2 1.5 2.0

Egypt 55.7 59.0 62.7 64.0 66.0 70.0 73.0 75.0


Gabon 0.1 0.1 0.1 0.2 0.5 1.0 1.0 1.0

Libya 15.3 15.9 15.3 16.2 17.0 18.0 19.5 20.5

Nigeria 35.0 35.0 24.9 35.0 38.0 42.0 49.0 55.0

South Africa 3.3 3.3 3.5 3.5 3.5 5.0 7.0 7.0

Sudan na na na na na na na na

BMI universe 201.7 209.8 198.7 214.5 228.6 258.9 283.8 300.2

Other Africa 2.7 5.0 5.0 5.0 5.0 5.0 5.0 5.0

Regional total 204.4 214.8 203.7 219.5 233.6 263.9 288.8 305.2

f = forecast. na = not applicable. Source: Historical data: BP Statistical Review of World Energy, June 2010; BMI

In terms of natural gas, the region in 2010 will have consumed an estimated 122.9bcm, with demand of

165.6bcm forecast for 2014. Production of an estimated 219.5bcm in 2010 should reach 305.2bcm in

2014, which implies net exports rising from 97bcm to 140bcm in 2014. In 2010, Algeria’s share of

regional gas supply is an estimated 37.82%, rising to 38.17% by 2014. The country’s share of demand in

2010 is an estimated 18.44%, with 18.02% predicted by 2014.



Liquefied Natural Gas

Table: Africa’s LNG Exports, 2007-2014 (bcm)

Country 2007 2008 2009 2010f 2011f 2012f 2013f 2014f

Algeria 24.7 21.9 20.9 20.5 21.1 21.5 27.9 27.8

Angola na na na na na 5.0 7.0 7.0

Cameroon na na na na na na na na


Egypt 13.6 14.1 12.8 13.9 13.7 15.6 16.2 16.1

Libya 0.8 0.5 0.7 0.7 0.7 0.7 0.7 0.7

Nigeria 21.2 20.5 16.0 20.0 21.0 21.0 26.0 27.5

Regional total 60.3 62.2 55.1 59.9 61.2 68.6 82.4 83.8

f = forecast. na = not applicable. Source: Historical data: BP Statistical Review of World Energy, June 2010; BMI

The highest growth in LNG exports by 2014 will come from Nigeria (+37.5% from 2010) and from Egypt

(+15.6%) thanks to its IOC-partnered schemes. There will also be growing volumes from Libya and

Algeria. Angola has significant longer-term gas export potential, although the first volumes have yet to

flow and the most rapid growth phase will occur in the next decade. Equatorial Guinea aims to become a

regional LNG export hub, while Cameroon looks set to become an LNG exporter by around 2016.



Business Environment Ratings

The African region comprises 11 countries, including all major West and North African states.

Government influence remains very high, with limited privatisation activity. Oil production growth for

the period 2010-2014 ranges from a negative 6.5% for Egypt to a positive 30.1% in Sudan, while oil

demand growth ranges from 6.1% to 90.4% across the region. Gas output is forecast to rise in most

countries, led by a 400% rise in Gabon (from a very low base), 226% in Angola and 100% in Congo. The

spread of gas demand growth estimates ranges from 4.1% to 131.4%. The political and economic

environment varies, depending partly on market maturity and specific factors such as the quasi-political

oil disruptions in Nigeria and sanction-prone Sudan.

Composite Scores

Composite Business Environment scores are calculated using the average of individual upstream and

downstream ratings. South Africa now holds the top slot of the regional league table and Sudan is at the

bottom. The composite upstream and downstream scores are 62 points and 41 points respectively, out of a

possible 100. The range is narrow, compared with other regions.

South Africa has pulled clear of Algeria, and leads by six points that should see it safe for a few quarters.

Algeria is just one point clear of Egypt and Nigeria, which share third place. Angola is capable of moving

higher if the risk outlook improves, breaking away from Libya with which it currently shares fifth place.

Gabon is now three points behind its hydrocarbons-rich West African neighbours, but is five points clear

of Congo. Cameroon is hot on the tail of Congo, while remaining clear of regional laggards Equatorial

Guinea and Sudan at the foot of the table.

Table: Regional Composite Business Environment Rating

Upstream Rating Downstream Rating Composite Rating Rank

South Africa 60 63 62 1

Algeria 56 56 56 2

Egypt 52 58 55 3=

Nigeria 58 51 55 3=

Angola 57 51 54 5=

Libya 61 47 54 5=

Gabon 61 41 51 7

Rep of Congo 51 40 46 8

Cameroon 50 39 44 9

Equatorial Guinea 45 41 43 10

Sudan 38 44 41 11

Source: BMI. Scores are out of 100 for all categories, with 100 the highest.



Upstream Scores

Gabon/Libya and Sudan are now the best and worst performers in this segment, showing that the overall

pecking order is quite different from that for combined scores. Gabon has moved higher to share first

place with Libya, with both just one point ahead of a vulnerable South Africa. Nigeria and Angola have

longer-term potential to climb higher, with South Africa a near-term target. Algeria is closing in on

Angola and Nigeria, taking sixth place with 56 points.

Republic of Congo and Egypt are bickering over seventh place with 51 and 52 points respectively.

Cameroon is just one point further back and has longer-term potential to catch the two of them. All three

should be able to stay ahead of Equatorial Guinea and Sudan for the foreseeable future.

Table: Regional Upstream Business Environment Ratings

Rewards Risks

Industry Rewards

Country Rewards Rewards

Industry Risks

Country Risks Risks

Upstream Rating Rank

Gabon 58 65 59 80 40 66 61 1=

Libya 63 70 64 60 43 54 61 1=

South Africa 44 70 50 95 62 83 60 3

Nigeria 68 50 63 55 33 47 58 4

Angola 61 60 61 60 28 49 57 5

Algeria 50 85 59 55 39 49 56 6

Egypt 40 70 48 75 42 63 52 7

Rep of Congo 46 55 48 70 37 58 51 8

Cameroon 53 20 44 80 35 64 50 9


Sudan 35 30 34 60 21 47 38 11

Scores are out of 100 for all categories, with 100 the highest. The Upstream BE Rating is the principal rating. It comprises two sub-ratings ‘Rewards’ and ‘Risks’, which have a 70% and 30% weighting respectively. In turn, the ‘Rewards’ Rating comprises Industry Rewards and Country Rewards, which have a 75% and 25% weighting respectively. They are based upon the oil and gas resource base/growth outlook and sector maturity (Industry) and the broader industry competitive environment (Country). The ‘Risks’ rating comprises Industry Risks and Country Risks which have a 65% and 35% weighting respectively and are based on a subjective evaluation of licensing terms and liberalisation (Industry) and the industry’s broader Country Risks exposure (Country), which is based on BMI’s proprietary Country Risk Ratings. The ratings structure is aligned across the 14 Industries for which BMI provides Business Environment Ratings methodology, and is designed to enable clients to consider each rating individually or as a composite, with the choice depending on their exposure to the industry in each particular state. For a list of the data/indicators used, please consult the appendix. Source: BMI



Algeria Upstream Rating – Overview

Algeria now holds sixth place in the updated upstream Business Environment ratings, sandwiched

between Angola and Egypt. The country’s score benefits from healthy oil and gas reserves, a large

number of non-state companies active in the upstream sector and decent licensing terms.

Algeria Upstream Rating – Rewards

Industry Rewards: On the basis of upstream data alone, Algeria ranks sixth in the African region, above

Republic of Congo. The country ranks fourth in terms of oil reserves and second for gas reserves, but

only fifth and ninth respectively for oil and gas production growth prospects.

Country Rewards: Contributing to Algeria’s equal fourth position with Gabon in the Rewards section is

its top-ranked country rewards rating, well ahead of Egypt, Libya and South Africa. Algeria ranks first by

the number of non-state operators in the upstream sector.

Algeria Upstream Rating – Risks

Industry Risks: Algeria is ranked equal eighth with Angola in the Risks section of our ratings. Its equal

last place with Nigeria for industry risks is attributable to a moderately attractive licensing environment

being countered by limited privatisation progress. Moves to impose windfall taxes on oil producers are

seen as a negative and a possible indication of greater state control over upstream assets.

Country Risks: Its broader country risks environment is somewhat more attractive, ranking Algeria sixth

ahead of Congo. The best score is for physical infrastructure, which represents the only major benefit for

private companies. Long-term policy continuity receives a mid-range score, but the ability of private

companies to operate is hindered by the country’s low scores for rule of law and corruption.



Downstream Scores

South Africa and Cameroon are in the top and bottom places respectively in the downstream ratings, with

the former driven by the size of the fuels market, privatisation moves and the competitive landscape, plus

a reasonable country risk rating. Egypt still holds second place, but is at some risk from Algeria. Both are

currently well clear of Angola, which has been caught by Nigeria. Sudan has moved ahead of Equatorial

Guinea and Gabon, with Congo and Cameroon squabbling at the foot of the ladder.

Table: Regional Downstream Business Environment Ratings

Rewards Risks

Industry Rewards

Country Rewards Rewards

Industry Risks

Country Risks Risks

Downstream Rating Rank

South Africa 46 88 56 100 47 79 63 1

Egypt 64 58 63 45 53 48 58 2

Algeria 63 52 61 40 55 46 56 3

Angola 66 50 62 15 46 27 51 4=

Nigeria 56 72 60 20 45 30 51 4=

Libya 54 38 50 30 54 39 47 6

Sudan 38 54 42 55 39 49 44 7

Equatorial Guinea 38 26 35 60 49 55 41 8=

Gabon 30 42 33 70 41 58 41 8=

Rep of Congo 40 38 40 65 7 42 40 10

Cameroon 38 30 36 45 45 45 39 11

Scores are out of 100 for all categories, with 100 the highest. The Downstream BE Rating comprises two sub-ratings ‘Rewards’ and ‘Risks’, which have a 70% and 30% weighting respectively. In turn, the ‘Rewards’ Rating comprises Industry Rewards and Country Rewards, which have a 75% and 25% weighting respectively. They are based upon the downstream refining capacity/product growth outlook/import dependence (Industry) and the broader socio-demographic and economic context (Country). The ‘Risks’ rating comprises Industry Risks and Country Risks which have a 60% and 40% weighting respectively and are based on a subjective evaluation of regulation and liberalisation (Industry) and the industry’s broader Country Risks exposure (Country), which is based on BMI’s proprietary Country Risk Ratings. The ratings structure is aligned across the 14 Industries for which BMI provides Business Environment Ratings methodology, and is designed to enable clients to consider each rating individually or as a composite, with the choice depending on their exposure to the industry in each particular state. For a list of the data/indicators used, please consult the appendix. Source: BMI



Algeria Downstream Rating – Overview

Algeria is near the top of the league table in BMI’s updated downstream Business Environment ratings,

with some high scores but progress further up the rankings unlikely. It is ranked third behind Egypt,

thanks to high scores for gas consumption, nominal GDP, likely refining capacity expansion and oil

demand growth.

Algeria Downstream Rating – Rewards

Industry Rewards: On the basis of downstream data alone, Algeria ranks third, behind Egypt and

Angola, of the 11 countries, reflecting the country’s fourth-ranked refining capacity and oil demand, plus

second-ranked gas consumption. Refining capacity expansion and gas demand growth are third and fifth

respectively for the region.

Country Rewards: Algeria ranks third behind Angola in terms of the Rewards section, and its country

rewards rating holds fifth place in the region. Population ranks the country fifth, while growth in GDP per

capita is seventh-highest. Competition attracts a below-average score.

Algeria Downstream Rating – Risks

Industry Risks: In the Risks section of our ratings, Algeria is ranked sixth just ahead of Cameroon. Its

eighth-highest score for industry risks, behind Egypt and Cameroon, reflects the regulatory regime and

limited progress in terms of privatisation of government-held assets.

Country Risks: Its broader country risks environment is attractive, ranked first, ahead of Egypt. The best

score and optimum score is for short-term economic external risk, followed by short-term policy

continuity. Physical infrastructure is somewhat better than the regional norm but operational risks for

private companies are increased by the state’s short-term economic growth risk, rule of law and legal

framework.



Risk Summary

Political

The recent visit of the Chinese State Councillor Dai Bingguo to Algiers is intended to improve the already

prolific bilateral relations between the two countries. In a statement offered to Algerian President

Abdelaziz Bouteflika, the Chinese official said that this visit was an opportunity to listen to the Algerian

leadership's views on ways to upgrade the Sino-African relations. These developments are set to serve

both the interest of the two nations involved, as well as those of Africa in general. Two agreements were

signed during this visit, covering an exchange programme in the field of higher education and scientific

research, as well as a memorandum of economic and technical cooperation.

Economic

We expect Algeria's current account surplus growth to pick up in 2010 and expand to 17.8% of GDP,

after last year's figure reading 9.7%, the lowest of the decade. This year's increase will be primarily

attributable to a projected 34.2% y-o-y growth in exports, due to still elevated oil prices, but also a low

base in 2009. Imports will also grow but only by 10.0% in 2010, contributing to the widening of the

current account surplus. The progress in general trade is, however, susceptible to oil price volatility, given

that hydrocarbons exports are accountable for a projected 98.5% of total exports in 2010.

Business Environment

A new monthly 0.5% tax on revenues of mobile operators was imposed by the Algerian government this

month. This has a direct impact on Djezzy, the Algerian unit of Egypt's mobile phone operator Orascom,

implying a further US$4.6mn deducted from its US$1.82bn total annual revenue. This will add to

previous shocks suffered by Djezzy, with the 2009 introduction of a 5% sales tax on credit recharges

charged on the operators, and the 42.0% lowering of interconnection rates in the same year. This is a

mark of Algeria's unpredictable and often damaging policies towards foreign investors. Given the

government's plans to prioritise local businesses over foreigners, there could be more bad news in the

pipeline for the likes of Djezzy.



Industry Forecast Scenario

Oil And Gas Reserves

With recent oil discoveries, plans for more exploration drilling, improved data on existing fields and use

of enhanced oil recovery schemes, proven oil and gas reserves should rise. The June 2010 BP Statistical

Review of World Energy estimate for proven oil reserves is 12.2bn bbl. There is scope for expansion,

with BMI assuming 12.5bn bbl by 2012. Estimates of ‘recoverable oil resources’ range as high as 43bn

bbl. Exploration success rates in the Berkine Basin have been high and several billion barrels of oil may

lie in the area. With gas, we see the 2009 reserves estimate of 4,500bcm rising to 4,800bcm in 2014.

In August 2009 BP announced plans to invest US$2bn over five years (or an average of US$400mn a

year) in Algeria. The investment would signify a continuation of BP’s strategy in the country, where it

had spent a total of US$5bn in the previous 12 years (equal to an average of US$417mn a year). BP plans

to drill new exploration wells, maintain production at the In Salah and In Amenas gas fields, and develop

a US$100mn carbon capture and storage (CCS) project at the In Salah field. These plans, of course, pre-

date the Deepwater Horizon affair in the US Gulf, with capital expenditure set to be reviewed in its wake.

Oil Supply And Demand

Productive crude capacity is thought to

have reached 1.40mn b/d by the end of

2009, although June 2010 crude output

averaged an estimated 1.25mn b/d.

Including condensates and gas liquids,

total production in 2009 was around

1.81mn b/d.

Anadarko Petroleum has announced

that the development of the El Merk oil

field project is on schedule, with

production due to start in late 2011. In an

August 2009 conference call with

investors, the company’s CEO, Jim

Hackett, said site preparation was under

way, with the majority of contracts having been awarded.

We are assuming OPEC resistance to continuing output expansion in excess of quota, limiting Algeria’s

production growth. Combined oil, condensate and gas liquids output is forecast to increase to 2.15mn b/d

Algerian Oil Production, Consumption And Exports

2000-2014

f = forecast. Source: Historical data: BP Statistical Review of World Energy, June 2010. Forecasts, BMI.



in 2014, with exports heading towards 1.75mn b/d. We expect Algerian oil demand of 331,000b/d in 2009

to rise to 399,000b/d by 2014.

Gas Supply And Demand

Algeria’s total natural gas export

capacity, via pipeline and LNG tanker, is

now believed to be more than 70bcm a

year. This should increase rapidly as

major new gas fields, export pipelines

and LNG facilities come online.

Algeria’s goal was to export 85bcm a

year by 2010, but our forecasts suggest

that this target is not feasible before

2014/15. We forecast that 2009 gas

production of 81.4bcm will reach

116.5bcm by 2014. Consumption of

around 26.7bcm in 2009 is expected to

rise to 33.7bcm by the end of the forecast

period, providing exports of 82.8bcm.

The Gassi Touil venture, in the Saharan Berkine Basin, has suffered considerable delays and cost

overruns. It is now set to enter production no earlier than 2013. The project includes a liquefaction

terminal, which will be located in the industrial area of Arzew. The gas to be used will originate from

reserves that have already been discovered in the Gassi Touil, Rhourde Nouss and Hamra areas. The

project delay accounts for a reduction in terms of gas export forecasts.

Plans to expand significantly exports of gas by sea and pipeline have been delayed by Sonatrach.

Customers may have to wait two years to receive the extra volumes, putting extra pressure on the

European gas market. According to Sonatrach’s former chairman and CEO Mohamed Meziane, a 31%

increase in pipeline and LNG supplies can be expected by 2012, rather than the original 2010 start date.

GdF Suez and Sonatrach have announced that they will jointly develop the Touat gas field in the south-

west of Algeria. According to a July 2009 joint company statement, the partners were to start work on the

US$1.5bn project later in 2009, with the aim of bringing the field onstream in 2013. Peak output should

reach around 4.5bcm per annum.

Algerian Gas Production, Consumption And Exports

2000-2014

f = forecast. Source: Historical data: BP Statistical Review of World Energy, June 2010. Forecasts, BMI.



Total and its Spanish partner CEPSA were due to have started the development phase of the Timimoun

gas project in late 2009 following the receipt of final regulatory approvals in October. The Timimoun

field is expected onstream in 2013, with annual output of 1.6bcm.

LNG

Algeria was the world’s first producer of LNG and was the fourth largest exporter of LNG in 2008

(behind Qatar, Malaysia and Indonesia), with around 10% of the world’s total. Most of the gas goes to

Western Europe. The Algerian government believes that it will become the world’s biggest LNG exporter

by 2011/2012, thanks to project expansion.

Poland hopes to receive its first shipments of LNG from Algeria by 2010-2011. The governments of the

two countries signed a memorandum of understanding (MoU) on energy cooperation in January 2007 as

part of Poland’s plans to wean itself off its dependence on energy supplies from Russia. Polish gas

monopoly PGNiG has held exploratory talks on a possible supply contract with Sonatrach.

GdF Suez, Europe’s leading LNG importer, signed a deal with Sonatrach in December 2007 to extend

existing LNG supply contracts from 2013 to 2019. The contracts had a total annual value of around

EUR2.5bn (US$3.7bn) under the market conditions of the time. The deal was agreed during French

President Nicolas Sarkozy’s visit to Algeria, and several other agreements on energy were signed,

including a wide-ranging accord on civil nuclear power and a commitment from French major Total to

invest EUR1bn (US$1.5bn) in a new petrochemical plant in the country.

Sonatrach has awarded construction contracts for an LNG plant at Arzew, which will have a capacity of

4.7mn tonnes per annum (tpa). The project will be fully financed by Sonatrach at a cost of DZD227bn

(US$4.49bn). Gas for the facility will be sourced from Algeria’s Gassi Touil and Rhourd Nouss fields,

with a planned 2013 start-up.

Refining And Oil Products Trade

There are currently four operating refineries in Algeria: two mid-sized 60,000b/d refineries at the port

cities of Algiers and Arzew, a 30,000b/d plant near the Hassi-Messaoud flagship oil field and a large

300,000b/d complex in the Skikda industrial park on the north-east coast. The Skikda complex is being

expanded. A US$1.2bn modernisation contract was awarded to Samsung Engineering in May 2009, with

the view of boosting refining capacity by 32,000b/d in 2012, while a subsidiary of China’s CNPC handed

over a new turnkey 100,000b/d processing unit in July 2009, which should enter production in 2010.

In March 2009 Sonatrach announced that it would invest US$63.5bn in petrochemical plants and

refineries, as well as oil field expansion, between 2009 and 2013. This represents a 41% increase from an



estimated US$45bn planned for 2008-2012. We are assuming refining capacity rising from 462,000b/d in

2009 to 594,000b/d by 2014. The country has considerable refined oil products export capability, which

delivers substantial revenues to the treasury.

Revenues And Import Costs

Our OPEC basket oil price assumption for 2010 is US$83.00/bbl, rising in 2011 to US$85.00/bbl. For

2012-2014 we forecast US$90.00/bbl. The implication is for Algerian oil export revenues to rise from an

estimated US$46.78bn in 2010 to US$57.53bn in 2014. Gas export revenues in 2010 are estimated at

US$18.48bn and could be US$29.81bn by 2014. Combined Algerian oil and gas revenues are put at

US$65.25bn in 2010, rising to US$87.34bn by the end of the forecast period.



Table: Algeria’s Oil And Gas, 2007-2014

2007 2008 2009 2010f 2011f 2012f 2013f 2014f

Proven reserves, bn barrels 12.2 12.2 12.2 12.2 12.3 12.5 12.5 12.5

Oil production, 000b/d 2,016 1,993 1,811 1,885 1,925 1,965 2,050 2,150

Oil consumption, 000b/d 288 311 331 341 355 369 383 399

Oil refinery capacity, 000b/d (EIA, BMI) 450 450 462 562 594 594 594 594

Oil exports, 000b/d (BMI) 1,728 1,682 1,480 1,544 1,570 1,596 1,667 1,751

Oil price, US$/bbl, OPEC basket 69.1 94.1 60.9 83.0 85.0 90.0 90.0 90.0

Value of oil exports, US$mn (BMI base case) 43,570 57,755 32,878 46,776 48,723 52,437 54,745 57,526

Value of petroleum exports, US$mn (BMI base case) 56,965 77,913 46,243 65,254 69,534 78,507 83,187 87,339

Value of oil exports at constant US$50/bbl, US$mn 31,536 30,697 27,010 28,179 28,660 29,132 30,414 31,959

Value of oil exports at constant US$100/bbl, US$mn 63,072 61,393 54,020 56,359 57,321 58,263 60,827 63,917

Value of petroleum exports at constant US$50/bbl, US$mn 42,020 40,393 36,728 39,311 40,902 43,615 46,215 48,522

Value of petroleum exports at constant US$100/bbl, US$mn 84,039 80,786 73,456 78,622 81,804 87,230 92,430 97,044

Refined petroleum products exports, 000b/d (BMI) 117 94 85 165 180 166 151 136

Gas proven reserves, tcm 4.50 4.50 4.50 4.50 4.60 4.80 4.70 4.59

Gas production, bcm 84.8 85.8 81.4 83.0 90.0 103.0 111.0 116.5

Gas consumption, bcm 24.3 25.4 26.7 27.5 28.9 30.5 32.1 33.7

Gas exports, bcm (BMI) 60.5 60.4 54.7 55.5 61.1 72.5 78.9 82.8

Value of gas exports, US$mn (BMI base case) 13,395 20,157 13,365 18,478 20,811 26,070 28,443 29,814

Value of gas exports at constant US$50/bbl, US$mn 10,484 9,696 9,718 11,132 12,242 14,483 15,802 16,563

Value of gas exports at constant US$100/bbl, US$mn 20,967 19,393 19,436 22,263 24,484 28,967 31,603 33,126

LNG exports, bcm 24.7 21.9 20.9 20.5 21.1 21.5 27.9 27.8

LNG price, US$/mn BTU 7.73 12.55 9.06 12.36 12.65 13.40 13.40 13.40

LNG revenues, US$mn (BMI) 5,346 7,696 5,302 7,092 7,484 8,079 10,452 10,411

f = forecast. Source: Historical data: BP Statistical Review of World Energy June 2010, EIA, unless otherwise stated



Other Energy

Power consumption amounted to an estimated 30.7TWh in 2009 and is forecast to reach 38.9TWh by the

end of the forecast period, providing a broadly balanced market, assuming 5.3% average annual growth

(2010-2014) in electricity generation.

Conventional thermal sources are expected to remain the dominant fuel for electricity generation in the

coming years, with many power projects under construction or planned that will use natural gas. BMI’s

projections see estimated gross Algerian power generation of 41.0TWh in 2009 rising to 53.4TWh by

2014, having in 2009 risen by 2.8%. Algeria’s thermal generation in 2009 was an estimated 40.8TWh, or

3.84% of the regional total. By 2014, the country is expected to account for 4.06% of thermal generation.

Algeria has signed a nuclear cooperation accord with the US that may enable it to develop nuclear power

generation capability in the long term. The country has large uranium deposits and two nuclear research

reactors, but has no immediate plans for nuclear power. Under the accord, US nuclear officials will work

with partners from Algeria’s Atomic Energy Commission to determine possible projects of common

interest. Algeria plans to sign similar agreements with South Africa, which has Africa’s only nuclear

power plant, and Egypt. Its traditional partners are China, which helped supply a 15MW reactor at Ain

Ouassara in Algeria’s Djelfa region, and Argentina, which helped to build a 3MW reactor at Draria near

Algiers. Algeria signed a deal with Russia in January 2007 on possible nuclear cooperation. Iran has also

offered to share nuclear expertise.

Algeria has no significant hydro-electric power generating capacity and there are no major development

projects. BMI is predicting just 0.8TWh of hydro-power generation by 2014.

The Hassi R’mel integrated solar combined cycle power station is a hybrid power station near Hassi

R’mel in Algeria. The plant combines a 25MW parabolic trough concentrating solar power array,

covering an area of over 180,000m2, in conjunction with a 130MW combined cycle gas-turbine plant. The

plant has been developed by New Energy Algeria (NEAL), a joint venture between Sonatrach Sonelgaz

and SIM.

Reports on news service Reuters suggest that Algeria’s largest private company, Cevital, is planning to

build a US$8bn solar power complex in Algeria to export renewable electricity to Europe. The plant will

have around 2GW of capacity and the company is now seeking foreign investors to help fund the project.



Table: Algeria’s Other Energy, 2007-2014

2007 2008 2009 2010f 2011f 2012f 2013f 2014f

Coal reserves, mn tonnes na na na na na na na na

Coal production, mn tonnes na na na na na na na na

Coal consumption, mn toe 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7

Electricity generation, TWh 37.0 40.0 42.8 43.4 45.6 48.1 50.8 53.4

Thermal power generation, TWh 37.0 39.8 40.8 43.0 45.1 47.5 50.1 52.6

Hydro-electric power generation, TWh 0.2 0.3 0.3 0.4 0.5 0.6 0.7 0.8

Consumption of hydro-electric power, TWh 0.2 0.3 0.3 0.4 0.5 0.6 0.7 0.8

Consumption of nuclear energy, TWh na na na na na na na na

Primary energy consumption, mn toe 35.6 37.6 39.7 41.3 43.1 45.5 47.5 50.1

f = forecast; na = not applicable. Source: Historical data, BP Statistical Review of World Energy, June 2010. Forecasts: BMI.

Key Risks To BMI’s Forecast Scenario

Oil price sensitivity is high and has a dramatic impact on the Algerian economy. Should the OPEC basket

price average US$50/bbl for the years 2010-2014, export revenues (crude oil and natural gas combined)

would average US$39.31bn to US$48.52bn. However, at an average of US$100/bbl, the total income

ranges from an estimated US$78.62bn to US$97.04bn.

Long-Term Oil And Gas Outlook

Details of BMI’s 10-year forecasts can be found in the appendix to this report. Between 2010 and 2019

we are forecasting an increase in Algerian oil and gas liquids production of 37.9%, with volumes rising

steadily from an estimated 1.89mn b/d in 2010 to 2.60mn b/d by the end of the 10-year forecast period.

Oil consumption between 2010 and 2019 is set to increase by 42.3%, with growth slowing to an assumed

4.0% per annum towards the end of the period and the country using 485,000b/d by 2019. Gas production

is expected to rise to 135bcm by the end of the period. With demand rising by 55.1% between 2010 and

2019, there should be export potential increasing from 56bcm to 92bcm, in the form of LNG and by

pipeline.



Oil And Gas Infrastructure

Oil Refineries

There are currently four operating refineries in Algeria: two mid-sized 60,000b/d refineries at the port

cities of Algiers and Arzew, a 30,000b/d plant near the Hassi-Messaoud flagship oil field and a large

300,000b/d complex in the Skikda industrial park on the north-east coast. The Skikda complex is being

expanded. A US$1.2bn modernisation contract was awarded to Samsung Engineering in May 2009, with

the view of boosting refining capacity by 32,000b/d in 2012, while a subsidiary of China’s CNPC handed

over a new turnkey 100,000b/d processing unit in July 2009, which should enter production in 2010.

Table: Refineries In Algeria

Refinery Capacity

(b/d) Owner

(Contractor) Completed Details

Skikda 300,000 Sonatrach/Naftal 1980 Processes Saharan Blend

Algiers 60,000 Sonatrach/Naftal 1964

Arzew 60.000 Sonatrach/Naftal 1972 Built by Itochu

Hassi-Messaoud 30,000 Sonatrach/Naftal 1962

Total Capacity 450,000

Planned Additional Capacity

Skikda 100,000 CNPC 2010

Source: Company data

Skikda Refinery

The Skikda refinery, founded in 1980, is the largest refinery in the country and one of the largest in

Africa. The refinery runs on Saharan blend, which is sourced from the area of Hassi Messaoud via

pipeline and from the Skikda oil terminal. The plant is linked to a petrochemicals complex in the same

city.

Gas Pipelines

Algeria is a major gas exporter, sending abroad 33.8bcm of gas through its pipelines in 2009, with

another 20.9bcm exported in the form of LNG. Currently, the country has two operational gas export

pipelines from its flagship Hassi R’Mel gas field: one to Spain and one to Italy. The 12bcm Maghreb-

Europe gas pipeline (MEG, also known as the Pedro Duran Farrell pipeline) came onstream in 1996,

linking Hassi R’Mel to the southern Spanish city of Cordoba. The Trans-Mediterranean pipeline

(TransMed, aka Enrico Mattei pipeline) runs via Tunisia to Sicily and thence to mainland Italy. An



extension of TransMed delivers Algerian gas to Slovenia. TransMed currently has a capacity of 24bcm,

with plans to increase this to 35bcm by 2012.

Trans-Mediterranean (Trans-Med)

A third trunk of the Trans-Mediterranean (Trans-Med) natural gas pipeline from Algeria to Italy was put

into operation on February 28 2010. The new 549km section of the Enrico Mattei pipeline will expand

capacity on the route by 7bcm a year, boosting Algerian export revenues by US$1.5bn, according to the

country's energy minister Chakib Khelil, speaking at the launch in Bir El Ater. Although the launch of the

new section represents progress in developing Algeria's gas export infrastructure, the country's other

major gas export projects, which have already been delayed, are likely to be pushed back further owing to

a corruption investigation at Sonatrach that has stymied decision-making at the company.

The Enrico Mattei pipeline runs from Algeria via Tunisia to Sicily and thence to mainland Italy, with an

extension that delivers Algerian gas to Slovenia. The nameplate capacity of the Enrico Mattei pipeline is

24bcm but actual throughput is around 27bcm. The new branch increases capacity to around 33.5bcm,

according to media reports.

Medgaz

Another three Algeria-Europe pipelines

are in various stages of

planning/development. The start-up of

the Medgaz pipeline from Algeria to

Spain has been delayed until June 2010.

Gas Natural’s CEO, Rafael Villaseca,

had already warned in July 2009 of a

possible delay to mid-2010, but at the

time the claim was rejected by the

Medgaz consortium and by Algeria’s oil

minister, Chakib Khelil, who insisted that

work at the pipeline would be completed

in November 2009 and that it would

become operational before the end of the

year. Pedro Miro from the Medgaz

consortium confirmed to the media on November 9 that tests on the pipeline were now scheduled to start

in March 2010, with the pipeline planned to become fully operational in around June.

The 210km pipeline, which is designed to transport gas from Algeria to Spain, Portugal and France, will

be able to transport 8bcm once it is fully onstream. The pipeline, which is estimated to cost EUR0.9bn,

stretches from Beni Saf in Algeria to Almería in southern Spain.

Algerian Gas Export Routes To Europe

Source: BMI



Medgaz is owned by a consortium of Sonatrach (36%), France’s GDF Suez (12%) and Spanish

companies CEPSA (20%), Iberdrola (20%) and Endesa (12%). Gas Natural has been keen to acquire a

10% stake in the pipeline, but price disagreements appear to persist, with Gas Natural keen to pay the

same price for the stake as it would have done had it joined the project at the beginning, while Algeria

believes that the company should pay market prices, seeing as the project is now close to completion.

The planned expansion of gas interconnectors between Spain and France, which are to link in to Medgaz,

are expected to open up new European markets for Algerian gas, solidifying the country’s position as a

key regional supplier.

Gasdotto Algeria-Sardegna-Italia (GALSI)

The launch of the Gasdotto Algeria-Sardegna-Italia (GALSI) pipeline has been delayed by yet another

year to 2014, the consortium’s chairman, Roberto Poti, said in November 2009. The project, which is

designed to carry 8bcm a year of Algerian gas to Sardinia and onwards to mainland Italy, has suffered

from technical and regulatory difficulties. The delay in GALSI’s start-up has been caused by a change of

route and a slower-than-expected regulatory authorisation process, Poti announced at a conference on the

project held in the Sardinian capital, Cagliari. Originally due online in 2012, the launch had been already

pushed back to 2013 in May 2009. The second year-long delay is a surprise.

The GALSI pipeline is designed to link the Hassi R'Mel gas hub in central Algeria with the island of

Sardinia and thence to Tuscany and the European grid. The total budget for the project has been set at

EUR3bn. The GALSI consortium is made up of Sonatrach (41.6%), Italian utilities Edison (20.8%), Enel

(15.6%) and Hera (10.4%) and a vehicle of the Sardinian regional government, Sfirs (11.6%).

Trans-Sahara Pipeline

Further along the development timeframe is the ambitious trans-Sahara pipeline project that aims to

transport as much as 30bcm of Nigerian gas via Niger and Algeria to Europe. The participating African

countries have finalised an agreement to build the 4,300km pipeline in July 2009, following an MoU on

the matter in 2002. Nigerian National Petroleum Corporation (NNPC) and Sonatrach will each own a

45% stake in the project, with Niger holding the remaining 10%. Algerian energy minister Chakib Khelil

stated after the signing ceremony that the three countries could decide to sell part of their share to foreign

companies, with Bloomberg quoting the minister as saying that about 20%, or US$2bn, will be equity,

allowing companies to take a 2-3% stake. Total, Italy’s Eni, Shell and Russia’s state-controlled

Gazprom have all expressed their interest in participating in the project.

The trans-Sahara project, with capital costs estimated at US$10bn for the pipeline and US$3bn for

gathering centres, is planned to come onstream in 2015. However, there are major downside risks to that

scheduled start-up date. Violence in the Niger Delta is a constant threat and the underdevelopment of

Nigeria’s gas industry makes it doubtful whether the country will be able to boost production and build up



its infrastructure in time to meet both its committed LNG export volumes and supply the pipeline by

2015.



Macroeconomic Outlook

Oil-Driven Path To Budget Surplus

BMI View: We expect Algeria's budget to remain in deficit due to diminishing hydrocarbons revenues

and public spending growth in 2010. Over the long term, we see the budget returning to surplus towards

the end of our forecast period, thanks to a recovery in oil prices. Nevertheless, in the absence of

consistent developments in other sectors, the Algerian economy remains vulnerable to oil price volatility.

Highly reliant on hydrocarbon exports, Algeria entered the global economic slowdown from a strong

position, with real GDP having grown by an average of 3.4% y-o-y in real terms from 2006 to 2008. With

hydrocarbon export revenues falling drastically as a result of the drop in oil prices over H208, economic

growth had to be supported by the government. Although public spending was relatively high prior to

that, it was funded by significant hydrocarbon revenues. In 2009, however, total revenues contracted by

25.9% (hydrocarbon revenues fell by 34.1%), enough for the 11% increase in expenditure to generate the

highest budget deficit in Algeria since the mid 1990s, at 7.5% of GDP.

Budget Balance: From Deficit To Surplus

We predict this budget deficit to narrow to 2.2% of GDP in 2010, holding the balance in negative territory

for the second consecutive year, after seven years of running a surplus. Although revenues will grow by

27.4% y-o-y, low base effects mean they will remain below total spending in nominal terms, resulting in a

budget deficit. The government's plan to increase the share of other sources of revenues will contribute to

reducing the gap between the two sides of the budget balance. Improving the revenue administration and

increasing income tax collections, based on the 2008 wage increase, will contribute to a recovery in

revenues. Investment in infrastructure and employment support programmes (youth unemployment came

in at 24% in 2009, keeping total income tax revenues well below potential) will drive the 13% y-o-y

expansion in total public spending.

The recovery in oil prices is the basis for the bright outlook of the budget's recovery from 7.5% of GDP

deficit last year to our projected 2.2% in 2010. With hydrocarbon revenues accounting for almost 80% of

the budget's recent gains, however, potential volatility in oil prices could obstruct the consolidation of the

Algerian fiscal position.

We expect an increase in hydrocarbon prices to revive revenues through a boost in exports, reducing the

need for government spending. With the economy expected to be resuscitated by the recovery in global

demand, a lower need for public spending will see the total expenditure growth rate fall to 4%, down

from 13% in 2010. As such, we see the budget returning to surplus starting 2012, coinciding with the year

when BMI expects Brent Crude to trade at US$92/bbl, following a leap from our US$85/bbl 2010



projection. The turning point will also be signalled by a 16.1% y-o-y increase in hydrocarbon revenues,

generating 14.3% of total revenue growth. Along these lines, we see the budget surplus widening further

to 4.4% by 2014.

Non-Hydrocarbon Growth In The Picture

The risk of lower oil prices and the long-term unpredictability of the market will drive the government to

develop macroeconomic strategic programmes aimed at reducing the dependence on global economic

progress. The government announced plans to support the growth of domestic firms to generate stable

revenues, making the non-hydrocarbon private sector more inward oriented. Previously, the Algerian

government announced that domestic companies will benefit from preferential treatment over foreign

investors, allowing them to obtain shares of US$286bn planned to be spent over the next five years on

modernising the economy. Furthermore, the authorities plan to stimulate private investment by extending

tax incentives for infant industries competing with lower import prices from foreign more mature

companies.

We expect non-hydrocarbon revenues, accounting for around a quarter of total revenues, to grow by an

average of 8% over our forecast period, supported by sustained progress in tax collection. The

government's plans to make clean tax records a prerequisite for all financial transactions and to simplify

the revenue administration bode well in this regard. The increasing importance assigned to the

effectiveness of public spending will also help to reduce the gap between expenditure and revenues,

turning it into surplus over the long-term. The reform of budget management will be supported by the

activity of projects assessment house Caisse Nationale d'Equipments et des Developpement, which has

been appointed to evaluate the rationality and economic profitability of public investments.

Risks To Outlook

Despite all the measures to boost the non-hydrocarbon private sector, if the global demand downturn

scenario plays out and oil prices fall, the Algerian public sector would have a hard time sustaining long-

term growth. On top of that, aggressive measures to give priority to domestic businesses could turn out to

be a double-edged sword for long-term economic growth: the law according to which contracts must first

be offered to a national tender, with Algerian firms being the only ones eligible, could scare off foreign

investors and create an aversion towards the market among foreign investors over the long term. The

attempt to nationalise the profitable Egyptian mobile phone operator Orascom's Algerian unit, after

hitting it with tax demands, is a good illustration of the volatile and unpredictable policies the government

comes out with. All these would reduce growth and hence fiscal revenues, posing downside risks to our

projection that the Algerian budget balance will return to surplus towards the end of our forecast period,

and could lead to a prolonged budget deficit, mainly driven by increased public expenditure.



Table: Algeria – Economic Activity

2005 2006 2007 2008e 2009e 2010f 2011f 2012f 2013f 2014

Nominal GDP, DZDbn 1 7498.6 8391.0 9306.2 10192 9719.6 11773 12621 13909 14694 15539

Nominal GDP, US$bn 1 103.3 117.1 134.1 156.9 134.0 160.3 169.4 190.5 207.0 222.0

Real GDP growth, % change y-o-y 1 3.7 3.6 3.1 3.5 2.3 3.1 3.9 5.2 4.1 3.7

GDP per capita, US$ 1 3145 3511 3961 4565 3841 4525 4711 5221 5590 5913

Population, mn 2 32.9 33.4 33.9 34.4 34.9 35.4 36.0 36.5 37.0 37.5

Industrial production index, % y-o-y, ave 3 1.6 -0.5 0.3 2.0 1.5 1.5 1.5 1.5 1.5 1.5

Unemployment, % of labour force, eop 1 15.4 12.3 11.8 11.3 10.2 10.0 9.8 9.7 9.6 9.4

e/f = estimate/forecast.Sources: 1 IMF/BMI. 2 World Bank/BMI calculation/BMI; 3 ONS/BMI.



Competitive Landscape

! The main government vehicle is Sonatrach, which accounts for around 80% of oil production and over

90% of natural gas supply. Refining and fuels distribution are also owned and operated by Sonatrach.

! IOC involvement is extensive, although their production entitlement fell in the late 2000s owing to

adverse contract changes. All major projects are carried out in partnership with the state using

production sharing contracts (PSCs).

! Italy’s Eni has become the country’s biggest foreign oil producer, having increased its presence

through the acquisition of UK exploration company Lasmo and First Calgary. Average liquids

production was 80,000b/d in 2009.

! Anadarko Petroleum is the second biggest foreign contributor to Algerian oil production. It has 9% of

its proven reserves in the country (about 300mn boe). Net liquids production in 2008 stood at

58,000b/d.

! In 2008 CEPSA contributed 40,000b/d of oil production to Algeria’s total through interests in two

major projects. Fellow Spanish group Repsol YPF has extensive exploration interests.

! BHP Petroleum has a 45% equity stake in the Rhourde Oulad Djemma (ROD) project, which entered

production in 2004 and entitled the group to a net of around 27,000b/d in 2009. BHP also has a 45%

stake in the US$1bn Ohanet gas/condensate development in Illizi province.

! Maersk is a partner in the major HBN, HBNS and Ourhoud fields, with net output of around

30,000b/d in 2008.

! Hess has a JV with Sonatrach, called Sonahess, which is investing US$500mn over five years to

enhance recovery from the el-Gassi, el-Agreb, and Zotti fields. The project yielded 14,000b/d net to

Hess in 2009.

! Through directly owned interests, French major Total received a net 27,000b/d from Algeria in 2009,

with an additional 19,000b/d from its stake in CEPSA.

! BP has no significant oil volumes, but is now a major gas player. The British major operates three key

upstream gas projects, one of which – In Salah – is Algeria’s largest gas development. BP works

alongside Statoil, which acquired interests in Algeria in 2003.



! ConocoPhillips and Talisman Energy are partners in the MLN project and have production of around

11,000b/d and 15,000b/d respectively.

! In February 2006 Shell and Sonatrach signed an agreement covering possible upstream and LNG

development projects in Algeria.

Table: Key Players In The Algerian Energy Sector

Company 2008 sales,

US$bn % share of total sales

No. of employees Year est. Ownership

Sonatrach 76 100 120,000 1963 100% state

Anadarko Algeria 2.1 11 na 1991 100% Anadarko Petroleum

Eni Algeria na 1.5e na 1981 100% Eni

BHP Petroleum na 16.5e na 1989 100% BHP Billiton

BP Algeria na 0.4 156 1956 100% BP

Naftal na 100 na na 100% state

Sonahess na na na 2000 49% Hess

CEPSA Algeria na 1.5 na 1996 49% Total

Statoil 0.6 na 25 2003 100% Statoil

Maersk Oil & Gas na na na 1990 100% AP Moeller

ConocoPhillips na na na 1993 100% ConocoPhillips

Talisman Algeria na 3 na na 100% Talisman Energy

Total Algeria* na 1.0e na 1952 100% Total

na = not available/applicable; e = estimate; *Includes 49% stake in CEPSA. Source: BMI.

Overview/State Role

State oil company Sonatrach operates in partnership with various IOCs, taking the major share of

production from key projects and accounting for 80% of the country’s oil output. Sonatrach is hoping to

increase Algeria’s crude production capacity significantly with the help of foreign capital and expertise.

Energy minister Chakib Khelil is aiming to double the number of companies operating in Algeria to 40 by

the mid-2010s.

Oil refining is controlled directly by Sonatrach, following the reintegration of its Naftec subsidiary in

May 2009 after 11 years as separate entities. Oil distribution is carried out by Sonatrach’s Naftal

subsidiary. In 2008, the government announced plans to end Naftal’s retail monopoly and to liberalise

fuel prices, although progress in this area is glacial.



Licensing And Regulation

Three main legislative changes since the mid-2000s have had a negative impact on foreign investment in

Algeria’s oil and gas sector. First, in 2006 Algiers introduced a higher windfall tax on oil production. The

tax is triggered when Brent crude prices average above US$30/bbl. The applied rate ranges from 5% to

50% of production. The new windfall tax brought the government an additional US$4.3bn in 2008. This

had an immediate impact on project economics. Both the rate applied and the attached conditions are

determined by individual company contracts, with some of them being more generous than others.

Nonetheless, the controversial tax risks alienating IOC partners, with one of the major operators in the

country, Anadarko, going as far as initiating arbitration proceedings against Sonatrach.

Second, Algeria passed a new investment law in August 2008 that limits foreign stakes in all energy

projects to 49%. To ensure compliance, the government is to renegotiate contracts, particularly in the

petrochemicals sector, which have not yet received final authorisation. Although the energy minister,

Chakib Khelil, did not identify any specific projects, recent deals where foreign players have taken

majority stakes include a US$3bn project to build a cracking unit in western Algeria, in which Total holds

51%, and a scheme to construct a US$2.4bn ammonia plant in the same region, in which Omani group

Suhail Bahwan Group has a 51% stake.

Third, Khelil said in April 2008 that the country planned to stop agreeing to long-term gas deals in favour

of negotiating shorter-term sales contracts. In the short term, this will allow Algeria to maximise the

revenues it generates from gas exports.

Contracts

In November 2004 Algeria awarded a tender to Spain’s Repsol YPF and Gas Natural for a US$2bn gas

project at Gassi Touil, a field containing 255bcm of proven reserves. In October 2007 Algerian state oil

and gas company Sonatrach announced that it would proceed with the project alone, having terminated

its agreement with the Spanish companies owing to delays and cost over-runs. Repsol announced in a

press statement on its website in November 2009 that a court had ruled that neither it, nor Gas Natural

and Sonatrach, will have to pay compensation to the other party in the dispute over the Gassi Touil

scheme. Given that engineering contracts were awarded only in June 2009, first shipments from the

project are now unlikely before 2013, some four years later than planned originally.

In addition, under the court ruling, Repsol and Gas Natural will not receive reimbursement for their

investments in the project, which will indicate a net loss of around EUR105mn for Repsol and EUR60mn

for Gas Natural, according to Dow Jones Newswires. The court has, however, ordered Sonatrach to

purchase the Spanish companies' shares in the project for a price similar to the consortium's current liquid

assets. A price for the assets has not been disclosed.



Government Policy

The Algerian government plans to invest US$63.5bn in its energy sector between 2009 and 2013, a 41%

increase from an estimated US$45bn planned for the five-year period of 2008-2012. US$9.7bn of the

latter figure is expected to come from foreign partners. The revision of contracts may introduce downside

risks to the foreign direct investment (FDI) proportion of the investment target.

Licensing Rounds

Under the 2005 Hydrocarbons Law, Sonatrach lost its role as the licence administrator. Starting from the

seventh licensing round, held in 2008, upstream tenders are managed by the Agence Nationale pour la

Valorisation des Resources en Hydrocarbures (ALNAFT). Compliance with the contract terms is ensured

by another new body, Agence Nationale de Contrôle et de Régulation des Activités dans le Domaine des

Hydrocarbures (ARH). The 2005 Hydrocarbons Law requires Sonatrach to hold a mandatory minimum

51% share in every oil and gas exploration contract.

Ninth Licensing Round

Algeria is planning to hold a licensing round before the end of 2010, the country's energy minister,

Chakib Khelil, told Reuters in a March 8 interview. The minister did not provide any details of the type of

acreage or the number of permits that will be offered. He did say, however, that the fiscal terms on offer

during the country's previous round, which was completed in December 2009, were unlikely to be

changed for the new round. If Algeria is to avoid a repeat of the poor outcome of the eighth round, it will

have to offer much more prospective acreage, given the lack of fiscal leeway. Even so, potential investors

may be put off investing in the country owing to concerns over corruption, with an investigation currently

in progress against Sonatrach, and more broadly by concerns over global oil and gas demand.

Eighth Licensing Round

December 2009 saw Algeria award three out of 10 E&P licences in its latest (eighth) bidding round. A

consortium led by China National Offshore Oil Corporation (CNOOC) was awarded the Hassi Bir

Rekaiz permit, while a Total-led consortium received the Ahnet permit and a Repsol-led group was

granted the South-East Illizi permit. Although Algeria's energy minister, Chakib Khelil, has said that he is

content with the outcome of the licensing round, with only three out of 10 permits having been awarded,

the result seems rather sobering, particularly after similar results in the previous licensing round.

Seventh Licensing Round

The seventh round was completed in December 2008. Four contracts worth a total of US$272mn were

signed the following month with Britain’s BG Group (Guern el Guesa Block), Germany’s E.ON Ruhrgas

(Rhorde Yacoub Block), Russia’s Gazprom (El Assel Block) and Italy’s Eni (Kerza Block). Barring Eni,

none of these companies had a large presence in the country. Out of 16 blocks on offer located in the

southern Berkine and Ahnet basins, bids were received for only four. The total of eight bids contrasts

sharply with more than 70 in the previous round. Although the government blamed poor economic



conditions, the muted interest suggests the negative impact of recent investment-prohibitive legislation.

The blocks’ apparently low prospectivity has been cited by IOCs as another reason behind weak interest

in the auction. Other deterrents included Sonatrach’s demands for upstream acreage in the IOCs’

respective countries and Algeria’s stifling bureaucratic procedures. The sixth licensing round was

completed in April 2006, with BP among a number of European majors to win drilling rights.

International Energy Relations

Algeria signed a number of energy agreements with its eastern neighbour, Tunisia, in July 2009 that are

aimed at strengthening the countries’ energy relations. The two countries agreed to increase electric

power interconnection capacity, develop gas distribution in the Tunisian border region and set up an ad

hoc committee to examine ways to develop Tunisia’s gas storage capacity, for domestic and export

purposes. Algeria also agreed to increase the ‘net back’ volumes paid to Tunisia for transporting its gas

via the Transmed (Enrico Mattei) pipeline from 6bcm to 7bcm and to boost LPG exports to Tunisia to

300,000tpa.

In July 2009, Algeria also signed a deal to construct the trans-Sahara pipeline with Niger and Nigeria. The

pipeline is planned to supply Europe, via Algeria, with as much as 30bcm of Nigerian gas a year.

In July 2007 the EU and Algeria agreed a deal on gas contracts between EU member states and

Sonatrach. The deal eliminated territorial restrictions in all existing and future contracts and amended the

circumstances in which profit sharing mechanisms (PSMs), which oblige buyers to share profit with

suppliers, are applied. Sonatrach has agreed to remove destination clauses that are seen as anti-

competitive, as they prohibit buyers of Algerian gas from reselling to third parties. Further, the agreement

will remove PSMs from gas pipeline deals and limit the application of PSMs to LNG contracts.

Gas Prices

Algeria's Minister of Energy and Mines, Chakib Khelil, has said that the country will ask fellow gas

producers to cut output in order to shore up gas prices. Gas prices have been driven down by the rapid

expansion of LNG projects and persistently low demand in the wake of the global economic downturn.

While a lack of solidarity between gas-exporting countries means that the move is unlikely to succeed,

low gas prices have become an important issue for countries such as Algeria that rely on gas exports for a

large proportion of their budgetary needs.

Speaking in a press briefing at the International Energy Forum in the Mexican city of Cancún on March

29, Khelil said that current gas prices of US$4/mn British thermal units (BTU) are 'not sustainable' for

Algeria. According to Bloomberg, Khelil said that the country wanted prices to increase to around US$6-

7/mn BTU. The report stated that Khelil will ask other gas-producing countries to cut output when they

meet at the Gas Exporting Countries Forum (GECF) in Algeria on April 19. Bloomberg stated, however,

that Algeria has not yet gained support for an output cut from other gas exporting countries.



After fellow gas exporter Russia announced in February 2010 that it had renegotiated gas prices with

some of its European customers, Algeria said that it will not follow Gazprom's example of linking the gas

price of some of the gas volumes sold to Europe to spot prices. Algeria stated that Sonatrach already

occasionally sells cargoes of LNG on the spot market when there is surplus capacity. Instead of linking

gas prices to the spot market, Reuters reported that Algeria would be willing to change other aspects of

companies' supply contracts, such as the length (from 10 years currently to five years), to account for

lower demand and allow for greater flexibility.

Table: Key Upstream Players

Company Liquids production

(000b/d) Market share (%) Gas production (bcm) Market share (%)

Sonatrach 1,650e 82.8 80e 92.5

Anadarko Algeria 58* 3 na na

Eni Algeria Production 80 4.3 0.2 0.2

Total Algeria 27 1.4 1.4 1.4

CEPSA Algeria 40* 2 na na

BHP Billiton 26.7 1.1 na na

BP Algeria 22 1.1 1.6 1.6

Statoil Algeria na na 4.1e 4.1

Hess 14 0.7 na na

Maersk Oil & Gas 30.1* 1.5 na na

ConocoPhillips 11e 0.5 na na

Talisman Algeria 15.1* 0.7 na na

e = estimate; na = not available/applicable; * 2008 data. Source: BMI, Company data 2009

Table: Key Downstream Players

Company Refining capacity

(000b/d) Market share (%) No. of retail outlets Market share (%)

Sonatrach/Naftal 550 100 1,709e 100

e = estimate. Source: BMI, Oil & Gas Journal 2010 Worldwide Refining Survey



Company Monitor

Enterprise Nationale Sonatrach

Company Analysis

State-owned Sonatrach is the world’s 11th largest oil company in terms of

production, the second-largest seller of LNG and ranks third by gas

exports. Its role in the Algerian oil and gas sector will change

dramatically under new legislation recently approved by the country’s

parliament. Sonatrach currently benefits from the strong cash flows and

superior technologies of its foreign partners, which enable the state

company to deliver growing volumes of oil and gas to the market, while

returning increasing revenues to the government. The company acts as a

major employer, with an estimated 120,000 staff on the payroll,

considerably more than any of its IOCs partners.

SWOT Analysis

Strengths: Involvement in all key hydrocarbons interests

Unrivalled access to exploration acreage

Substantial production upside potential

IOCs provide much of project funding

Weaknesses: Limited financial or operational freedom

Cost and efficiency disadvantages

Limited geographic diversification

Opportunities: Scope for significant output rise with OPEC policy

Considerable untapped gas export potential

Large areas of unexplored territory

Restructuring with new hydrocarbons law

Threats: OPEC could slow rate of oil expansion

Changes in national energy policy

Address

! Enterprise Nationale Sonatrach 80 Ave Ahmed Ghermoul Algiers Algeria

! Tel: +213 (2) 548 011

! Fax: +213 (2) 547 700

! www.sonatrach-dz.com

Financial Statistics

Revenues

! DZD5,459bn (2008)

! DZD4,347bn (2007)

! DZD4,223bn (2006)

! DZD3,536bn (2005)

Net income

! DZD643.1bn (2007)

! DZD539.6bn (2006)

! DZD575.3bn (2005)

Operating Statistics

! No. of employees: 120,000

! Year established: 1963

! Oil/condensate production: 1.59mn b/d (823,744b/d direct; 763,470 in partnerships) (2007)

! Gas production: 74bcm (est.) (2007)

! Refining capacity: 450,000b/d



Market Position

In March 2005 the Algerian National Assembly approved the hydrocarbon bill, originally proposed in

2001, which was supposed to do away with Sonatrach’s monopoly and open up the sector to increased

foreign involvement. Under the legislation, Sonatrach was to be restructured into two separate entities,

one to manage property rights (ALNAFT) and the other to act as a regulatory body (Sonatrach Spa).

However, subsequent legislation in 2006 reversed much of the liberalisation aspects of this decree.

Sonatrach Spa is to become a commercial company that will compete with IOCs for upstream oil and gas

contracts in Algeria and no longer control the tenders for hydrocarbons blocks. The new entity would

have an option to take a 20-30% working interest in the development phase of every project, but must

exercise that option within 30 days of ALNAFT declaring a prospect commercially viable. Sonatrach’s

restructuring would release it from some of its domestic commitments and organise its operations more

efficiently.

Sonatrach operates the largest oil field in Algeria, Hassi Messaoud, which pumped 400,000b/d of crude in

2008. The target is for this field to deliver 600,000-750,000b/d by 2013 through EOR and development of

satellite fields. Sonatrach also operates the 180,000b/d Hassi R’Mel field and other smaller producers,

including Rhourde El Baguel, Tin Fouye Tabankort Ordo, Zarzaitine, Haoud Berkaoui/Ben Kahla and Ait

Kheir.

The country’s largest gas field is Hassi R’Mel, located north of Hassi Messaoud. It produces around

22bcm per annum, accounting for roughly a quarter of the country’s output. The field produces a further

18,000b/d of crude and condensate. Sonatrach’s key subsidiaries include the petrochemicals producer

Société Nationale de la Pétrochimie (ENIP), Naftec (refineries), Helios (helium production), Naftal

(fuels retailing), Cogiz (marketing of industrial gases) and SNTM Hyproc (maritime transport). The

company operates two LNG plants at Skikda and Arzew, producing around 26.9mn tpa. The bulk of the

country’s output is exported to Europe. Gas is also exported via the Transmed pipeline to southern Italy.

A second major pipeline, Medgaz, linking Algeria to Spain, should be operational by mid-2010.

Sonatrach’s 100% subsidiary Naftec (reintegrated into Sonatrach in 2008) operates the country’s four

refineries – Skikda, Algiers, Arzew and Hassi Messaoud – which have a combined processing capacity of

450,000b/d. Fellow subsidiary Naftal is responsible for the transport, distribution and sale of LPG, fuels,

lubricants, bitumens, tyres and other specialised products. The company operates 1,709 service stations,

with approximately 1,200 of these outlets operated by franchisees. The Algerian group also has

operations in Yemen, Sudan, Niger, Iraq, Peru, Brazil and Bolivia. Among the group’s most important

international holdings is a 10% stake in the upstream portion and 11.1% of the transport section of the

Camisea gas project in Peru.



Strategy

Sonatrach plans to spend US$63.5bn domestically and internationally over 2009-2013, according to a

March 2009 strategy update. This is a 41% increase on its previous plan to invest a total of US$45.5bn

over 2008-2012. The company will invest in oil field expansion with the aim of maintaining production at

1.4mn b/d. Some of the spending will be directed towards refineries and petrochemical plants. The

company also aims to boost gas exports from 62bcm to 100bcm by 2015. This target does not include

exports through the trans-Sahara pipeline that Algeria and Nigeria have begun developing. According to

energy minister Chakib Khelil, Sonatrach needs an oil price of US$40-50/bbl for its investments to pay

off.

While investment in Algeria will likely be the focus of the new funds, the company will continue to push

its overseas interests. Sonatrach began its overseas expansion with the purchase of a minority stake in the

Camisea project in 2003. It is also looking to expand oil and gas production in neighbouring Niger and

Mauritania, and further afield in Nigeria. It is seeking refining and petroleum marketing opportunities in

Asia. In Latin America, the focus is on gas and harnessing LNG expertise.

Sonatrach is expected to invest heavily in the development of North Africa’s pipeline network, which will

be crucial if it is to boost gas exports to Europe. Over the course of the next five years, the company plans

to upgrade the existing network of 16,200km of oil and gas pipelines and extend it by over 5,000km.

The midstream development programme will focus on the construction of three gas trunklines. The

pipelines, currently in the planning phase, will run from the Hassi R’Mel gas hub to Skikda and on to El

Kala, supplying an estimated 8bcm to the planned GALSI pipeline – which will link Algeria directly to

Italy, as well as the Koudiet Eddraouch gas-fired power plant being built by Spain’s Iberdrola and US

firm General Electric (GE). The nearly finished GZ4 pipeline extends from Hassi R’Mel to Beni Saf in

north-western Algeria via Arzew, and will be used to supply 8bcm annually to the Medgaz pipeline to

Spain. Finally, Sonatrach is planning to build the GR4 pipeline to transport gas from the Gassi Touil

fields in the Berkine Basin to Hassi R’Mel.

The company is also hoping to sell to the North American market. In October 2005 US energy trading

and marketing company Sempra signed an agreement with Sonatrach to market Algerian LNG to the US

Gulf coast. While Europe is set to remain its main market because of geographical proximity, Sonatrach

is seeking to diversify its customer base. Asian LNG buyers have also previously shown interest in

Algerian gas.



Latest Developments

In April 2010 Sonatrach announced two new discoveries of oil and gas in the Berkine Basin. The new

finds were made with exploration wells in the 405a and 405b1 blocks in Menzel Ledjmet South East-9

(MLSE-9) and Zemlet el-Regab South (ZERS-1). Earlier in April, Sonatrach revealed two discoveries of

oil and gas with its Akamil-2 and Antar Est-2 wells in the Tinrhert area of the Illizi Basin in Algeria. The

Akamil-2 well on Block 239a flowed at approximately 600b/d of oil. The Antar Est-2 well on Block 244a

flowed at a rate of approximately 194,000cm/d of gas and 555b/d of condensate. These discoveries bring

the total number of hydrocarbon discoveries by the company in 2010 to seven.

Earlier in April, Sonatrach announced its financial results for Q110. The company reported earnings of

around US$14bn, up from US$10.7bn in Q109. The results were attributed to improved world oil prices.

The company's earnings from oil and gas exports were up by more than 30% over the period.

In March 2010, Sonatrach hit gas pay in the Menzel Ledjmat contract area of the Berkine Basin. The

Tessekha extension-1 well flowed at an initial production rate of 1.25Mcm/d of gas. Sonatrach also

announced two smaller hydrocarbon finds in the Berkine and Oeud Mya basins, without providing any

further details.

Algerian authorities launched a full-scale investigation into Sonatrach’s business practices in January

2010, prompting fears of polarisation of the energy industry. CEO Mohamed Meziane and 14 other senior

executives were removed from the office pending the results of the investigation, which potentially

signals a fresh round of in-fighting within Algeria’s closely-knit power cliques. The inquiry has also

spread to contracts signed by Sonatrach with foreign companies.

In July 2009 French utility GDF Suez and Sonatrach announced that they would jointly develop the

Touat gas field in the south-west of the country. Work on the US$1.5bn project began in January 2010, a

few months behind schedule, with the aim of bringing the field onstream by 2013. Peak output should be

around 4.5bcm. GdF holds a 65% stake in the Touat licence, with Sonatrach holding the remaining 35%.

Sonatrach, however, will hold 75% of the area’s reserves, which are estimated at 445mn boe. Under the

companies’ plans, 10 fields will be developed, with 40 production wells to be installed. The plans also

include the construction of gas collection and processing infrastructure, plus the construction of a link to

the pipeline that Sonatrach is planning to build to connect south western Algerian fields to the Hassi

R’Mel hub. Sonatrach will manage the fields’ gas sales.

GDF Suez signed a deal with Sonatrach in the beginning of December 2007 to extend existing LNG

supply contracts from 2013 to 2019. The contracts had a total annual value of around EUR2.5bn

(US$3.7bn) under the market conditions of the time. The deal was agreed during French President

Nicolas Sarkozy’s visit to Algeria, during which time several other agreements on energy were signed,



including a wide-ranging accord on civil nuclear power and a commitment from Total to invest EUR1bn

(US$1.5bn) in a new petrochemical plant.

Sonatrach announced its second discovery in 2009 in June of that year, hitting oil with its Ain Antar East-

1 (AAE-1) well on the Tinrhert prospect on Block 244A, in Illizi Basin near the Libyan border. The well

tested at 720b/d.

Also in June 2009, Sonatrach awarded three large gas engineering contracts. Japanese engineering firm

JGC won a DZD100bn (US$1.12bn) deal for EPC work at the Gassi Touil field. Under the 42-month

contract, JGC will build infrastructure for 54 wells in seven fields. A consortium comprising Swiss-based

group ABB and Algeria’s Sarpi was awarded a contract worth DZD16bn (US$179.3mn) to build a gas-

gathering plant and metering stations in the Haoud Berkaoui field. The 32-month contract involves

building facilities to gather the associated gas and transport it to a treatment centre in Guellala.

Finally, in June 2009 Canada’s SNC-Lavalin received a US$1.1bn, 39-month contract to build a gas

gathering system, a gas processing plant and carbon dioxide reinjection facilities to serve four fields:

Rhourde Nouss Central, Rhourde Nouss Southwest, Rhourde Adra and Rhourde Adra South. The gas

processing plant will be nearby Qartzites de Hamra. The gas will be shipped to a new train at the Aznew

LNG terminal. The gas processing plant and the LNG train are due for completion in 2012 and will allow

Sonatrach to export an additional 3.6bcm of gas. The project will also enable production of 16,000b/d of

condensate.

Sonatrach awarded a EUR200mn (US$268.7mn) contract for the construction of a marine export terminal

near the city of Arzew to Italian service major Saipem in May 2009. The engineering, procurement and

construction (EPC) contract includes the building of a marine export terminal for the future urea/ammonia

plant, which is expected to be completed by mid-2011.

Sonatrach awarded a US$2.6bn contract to renovate the 300,000b/d Skikda refinery to Samsung

Engineering in July 2009. The project will require Samsung to upgrade the Skikda refinery facilities, as

well as to build chemical plants and increase the plant’s oil refining capacity. The work is due to be

completed by 2012. Sonatrach delayed the Skilda contract by two months because of structural problems

related to the reintegration of Naftec. Problems with Naftec have also delayed bidding for the revamping

of the 58,000b/d Algiers refinery, even though Naftec completed the FEED contract in November 2008.

According to MEED, contractors were expecting bid documents in Q109, but Sonatrach has yet to give

potential bidders an official explanation for the delay.

In H109 Sonatrach made US$20bn in oil and gas sales. This suggests that Algeria was on track to meet its

goal of US$30-40bn in oil and gas revenues in 2009. In 2008 Sonatrach earned US$76bn in hydrocarbon

revenues on the back of record oil prices, plus a further US$4.3bn in windfall taxes from IOCs.



The Medgaz pipeline, which will carry Algerian gas to Spain and onwards to Western Europe, is expected

to come onstream as late as mid-2010 following the persisting problems with the pumping stations.

Sonatrach holds a 36% stake in the pipeline. At full capacity, Medgaz will transport 8bcm of gas a year.

A contract to supply Endesa with 0.960bcm annually for 20 years was signed in 2006.

In November 2008 Sonatrach announced three new gas discoveries in the Sahara desert, raising the total

number of hydrocarbon discoveries in 2008 to 16, according to the domestic news agency APS. Two of

the discoveries were made at Block 239C and Block 239A in the Illizi Basin, which are 100% owned by

Sonatrach. The third gas find was made at Block 350 in the Oued Mya Basin, which Sonatrach owns in

partnership with China National Petroleum Corporation (CNPC). No details of the flow rates or

reserves estimates were released.

In June 2008 India’s Petronet announced it would sign a deal with Sonatrach for the supply of 1.7bcm of

LNG for 25 years from December 2009.

In May 2008 Sonatrach announced a gas discovery at the Tirechoumine-2 well at Block 337b in Ahnet in

the In Salah area. Test flow rates were 2,072cm/d, according to a company press release.

Early April 2008 saw Sonatrach announce four oil and gas discoveries. The finds consisted of two gas

condensate fields at Blocks 226 and 229b in the Illizi Basin, which were discovered with partner Medex,

plus two oil and gas discoveries at Block 240b in the same basin and Blocks 427 and 439 in the Amguid

Basin. Reserves estimates have not been released.

In March 2008 Sonatrach announced that it had discovered a new gas field in the south western Hassi

Mouina region with partner Statoil. This follows a discovery announced in December 2007 at Block 338a

in the Ahnet Basin, where well OTS-2 produced gas from two reservoir formations at depths of less than

1,200m, with test flows of 237-404cm/d. At the same time, Sonatrach announced another discovery in

partnership with Statoil at Block 321b in the Gourara Basin, where the TNK-1 well produced gas at a rate

of around 6,971cm/d.

Sonatrach announced in October 2007 that it would proceed with the Gassi Touil LNG project without

IOC involvement, having terminated a 2004 agreement with Spanish partners Repsol YPF and Gas

Natural. The decision to go it alone is a surprise, as the company has relied upon IOC investment and

technical input for the majority of its major projects. There are other companies willing to participate in

the scheme, but Sonatrach has seized the opportunity to maximise its involvement and retain the revenues

from the project. The integrated project will include gas pipelines and an LNG facility. Initial production

at Gassi Touil should begin in 2013, with the bulk of its gas destined for Spain and other European

markets.



Anadarko Algeria

Company Analysis

Anadarko was an early entrant to the Algerian oil sector and is now the

second largest foreign producer after Eni. The company has been

involved in some of the country’s biggest discoveries, but production

over the past few years has been slowly declining as a result of the

government’s prohibitive energy policies, infrastructure restrictions and

the country’s OPEC membership. With Algeria lobbying hard for a

larger OPEC quota, accompanied by dramatic volume growth,

Anadarko is well placed to increase volumes of Algerian crude

significantly. There remains considerable exploration upside potential in

the country, providing scope for significant expansion of the group’s

reserves base. While an increasing number of North American explorers

are being drawn to the Saharan fields of Algeria, Anadarko retains a

competitive advantage.

SWOT Analysis

Strengths: Established presence in mature assets

Strong relationship with state oil company


Numerous exploration prospects

Weaknesses: Slow rate of output expansion

Limited gas exposure





Deteriorating relations with the state

Windfall production tax

Demanding licensing regime

Address

! Anadarko Algeria Corporation 4 Chemin des Glycines Hydra Algiers Algeria

! Tel: +213 (2) 691 398

! Fax: +213 (2) 230 630

! www.anadarko.com


Sales revenues

! US$1.13bn (2009)

! US$2.08bn (2008)

! US$1.78bn (2007)



Net Oil/Liquids Production:

! 58,000b/d (2008)

! 65,000b/d (2007)



Market Position

Anadarko holds interests in around 16,200sq km gross and claims 206mn bbl of proven reserves in

Algeria (83mn bbl of them being undeveloped), which is 9% of its global total. Nine fields discovered by

Anadarko are in production and 2008 volumes reached 58,000b/d, down from 65,000b/d in the previous

year. Algerian sales accounted for 10% of Anadarko’s total revenues in 2008. Since it began drilling in

1991, the US firm claims to have discovered 15 fields that contain more than 2bn bbl of oil. These fields

are operated in association with Sonatrach and partners Maersk and Eni.

Production is currently centred on Block 404 in the Berkine Basin, the site of the Hassi Berkine and the

Ourhoud fields. The Hassi Berkine field (HBN) is located between Block 404 (Sonatrach/Anadarko) and

Block 403 (Sonatrach/Eni), with development costs and production split 74.5/25.5, with the Anadarko

association paying the larger share. First oil was produced in December 2001, with several satellite fields

starting up in April 2002 including Hassi Berkine South (HBNS), Hassi Berkine South East (HBNSE),

Rhourde Berkine (RBK), Qoubba North (QBN), Berkine Northeast (BKNE) and Berkine East (BKE).

Gross production from the fields was 232,000b/d in 2007.

The Ourhoud field, located in the southern section of Block 404 and extending into Block 406a and Block

405, was discovered by Anadarko in 1994 and is the second largest oil field discovered in Algeria. It also

lies across Blocks 405 and 406a – operated by Sonatrach in partnership with Talisman/ConocoPhillips

and CEPSA respectively. Sonatrach acts as the operator of the Ourhoud consortium in partnership with

six other companies. Preliminary equity shares of the field include Sonatrach/Anadarko (37.5%),

Sonatrach/CEPSA (56.8%) and Sonatrach/ConocoPhillips (5.7%). Production started up in November

2002, with volumes of 238,000b/d reached in 2007. The US firm’s other interests in Algeria include

interests in exploration blocks 208, 211, 406b and 403c/e.

Strategy

According to its 2009 annual report, Anadarko plans to drill 10 development wells in Algeria in 2010 in

blocks 404 and 208, with production from El Merk in Block 208 expected to start in 2011. These plans

could well be slowed by the government’s imposition of the ‘exceptional profits’ tax, which, despite its

rather misleading name, levies a charge ranging from 5% to 30% on the full amount of gross production

when the Brent oil price is above US$30/bbl. Anadarko claims that, assuming an average Brent crude

price of US$60/bbl, the tax could would cost the company US$450mn. The damaging consequences of

the tax led Anadarko to initiate arbitration with Sonatrach in February 2009.

With the company holding 83mn bbl of undeveloped Algerian reserves, the tax could have significant

consequences on the economic feasibility of future projects. Consequently, Anadarko is thoroughly

reviewing its Algerian investment strategy. The first sign of divestment was seen in the company’s



decision to forgo exploration drilling in 2009. Given the company’s declining output, this could damage

its longer-term prospects in the country.

The arbitration represented a significant escalation of the disagreement given Anadarko’s 20-year history

in Algeria, in which it has enjoyed comparatively good relations with the government. Much depends on

whether Algeria feels that its energy industry continues to depend on Western investment or whether it

could be substituted with Russian and, potentially, Chinese interest.

Latest Developments

According to a March 2009 report in MEED, Anadarko and Sonatrach have been able to resolve their

issues regarding the terms of windfall taxes and will go ahead with the El Merk oil hub development,

having put it on hold in 2008. Falling input costs, however, have lowered the required financial

commitments, easing the negotiations. The report has been confirmed by the award of engineering

contracts for the project later that year. El Merk will include a central processing facility, export pipelines

and field infrastructure. These facilities will process output from Block 208, Block 212, El Merk itself

and HBNS. The entire development will be able to process 108,000b/d, 55,000b/d of condensate and

75,000bbl of LPG. Despite the delay in awarding the engineering contracts, in August 2009, Anadarko

announced that the El Merk is on track to start production in late 2011, ahead of 2012 originally

envisaged.

Italian pipe laying firm Bonatti was awarded a US$149.7mn EPC contract to construct three pipelines

from the El Merk field, with a crude pipeline to Houd El Hamra and LPG and condensate pipelines to

Gassi Touil. The contract was retendered following the decision by the original tender winner US

contractor Bechtel to turn down the contract in May 2009. April 2009 saw Swiss-based engineers ABB

awarded a US$490mn contract to design and install pipelines, field gathering stations, gas distribution

manifolds, flowlines/trunklines and water and gas re-injection facilities. A US$2.2bn contract for a

central processing facility was awarded to UK-based Petrofac in March 2009. El Merk’s FEED was

carried out by US-based Brown & Root-Condor.

Anadarko started discussions over the exact definition of Algeria’s ‘exceptional profits’ tax in February

2007. The company had already provided for an additional US$100mn for its liabilities from August 1

2006 (the date at which the law became valid) to the end of 2006. This figure was calculated at a time

when the government had yet to state whether the tax, which kicks in when Brent crude prices rise above

US$30/bbl, was to apply to the full value of production, or to the value in excess of US$30/bbl. The

difference is significant. The government clarified later in 2007 that the tax would be applied to the full

value of production.



In 2008 production from the HBNS field and its satellites averaged 139,000b/d of oil (gross), down

41,000b/d from the previous year, and production from five of the satellite fields averaged 35,000b/d of

oil (gross). Production from the HBN field averaged 72,000b/d oil (gross) and output from the Ourhoud

field averaged 238,000b/d (gross).



Eni Algeria Production

Company Analysis

Through the 2001 acquisition of Lasmo, Eni became one of the biggest

participants in the Algerian oil and gas sector. It is now a major oil

producer, and is also active in bringing Algerian gas to Italy. The

country forms a key part of Eni’s historic North African focus and a

high level of ongoing financial commitment seems assured. Thanks to

its oil services subsidiaries, Saipem and Snamprogetti, Eni’s powerful

connections and track record put it in a strong position to win field

development, pipeline and processing contracts. Of the major IOCs, Eni

arguably has the best Algerian portfolio, providing the basis for oil and

gas supply growth plus reserves expansion. As one of the largest Italian

firms, Eni is constantly under pressure to provide ever-increasing levels

of hydrocarbons to the domestic Italian market.

SWOT Analysis

Strengths: Established presence in mature assets



Involvement in gas exports

Extensive exploration portfolio

Weaknesses: Slow rate of output expansion

Some procurement problems encountered

Opportunities: Scope for significant output rise




Gas exports face stiff regional competition

Extensive state involvement


Address

! Eni Algeria Production BV (Branch Office) 28 Rue Mohamed Idir Amallal El Biar Algiers Algeria

! Tel: +213 (2) 921 619

! Fax: +213 (2) 921 688

! www.eni.it


Net liquids output:

! 80,000b/d (2009)

! 80,000b/d (2008)

! 85,000b/d (2007)

Net gas output:

! 0.2bcm (2009)

! 0.2bcm (2008)

! 0.2bcm (2007)




Market Position

The company signed its first gas import agreement with Sonatrach in the 1970s and since 1983 gas has

been delivered via the 2,200km Transmed pipeline connecting the Sahara to Italy’s Po Valley, through

Tunisia and into the Sicilian Channel. An agreement for a second gas pipeline was signed in 1991, with

the level of imports rising from 12.3bcm to 19.5bcm a year. Eni also imports some 2bcm of Algerian

LNG through the Italian terminal at Panigaglia, near La Spezia. Eni was the first IOC to sign a PSC with

Sonatrach following the sector’s reopening to foreign companies.

Eni has interests in blocks 403 and 403a, which contain the ROM, Bir Rebaa North, Bir Rebaa West and

Bir Rebaa South West fields. Major producing assets include a 25% interest in Block 404; a 34.6%

interest in HBN; 12.25% in the Hassi Berkine South (HBNS); 12.25% in the Hassi Berkine South East

(HBNSE), Berkine Northeast (BKNE) and Rhourde Berkine (RBK) fields; 4.59% in Ourhoud; and a 49%

stake in ZEA. The acquisition of First Calgary will boost Eni’s Algerian reserves by about 190mn boe,

with the Menzel Ledjmet East (MLE) field project set to start production in 2010. The Italian firm also

has interests in the exploration Block 212 in Amedjene, Block 440 at Wadi El Teh, Blocks 402a/401a

(55%) in the Berkine Basin and Block 222 in the Sahara Desert. The group’s oilfield services and

construction affiliates Snamprogetti and Saipem have been involved in a number of key projects in

Algeria, including the design and construction of the Algerian section of the Transmed pipeline system.

Strategy

Eni is doing a good job of securing Algerian hydrocarbons interests for the Italian market. The country

forms a key part of Eni’s historic North African focus and a high level of ongoing financial commitment

seems assured. Thanks to its oil services subsidiaries, Saipem and Snamprogetti, Eni’s powerful

connections and track record put it in a strong position to win field development, pipeline and processing

contracts. Continuing supply concerns over Russian oil and gas is bound to increase political pressure on

Eni to expand its Algerian output.

Latest Developments

In April 2010 Eni warned that Sonatrach had initiated discussions with it on shifting part of its tax burden

to the Italian company, according to a report by the Wall Street Journal. According to comments made in

Eni's 2009 annual report, Sonatrach has alleged that it is paying part of Eni's share of tax in licences held

jointly by the two companies. Eni said that if Sonatrach succeeds in passing on part of the tax burden, the

profitability of some of the PSAs held by Eni in the country will be reduced.

In March 2009 Saipem signed an energy infrastructure deal worth US$1.85bn with a JV between the Eni-

owned First Calgary and Sonatrach. The EPC contract covers natural gas gathering systems, processing

plants and export pipelines. Saipem will build facilities to produce and process humid gas and oil from

Algeria’s Ledjemet field, Sonatrach said. The agreement also involves the construction of pipelines to



transport natural gas, liquefied petroleum gas and condensate from Ledjmet to Gassi-Touil. The

installations are due for completion by 2012 and the facilities will be able to treat 9.91Mcm/d of gas

(3.6bcm per annum), 10,000b/d of condensate and 14,000b/d of LPG.

In December 2008 Eni was announced as a winner of exploration acreage. Eni was awarded the right to

explore the Kerza Block where it has committed to drill eight wells at a cost of US$69mn.

In November 2008 Eni completed the takeover of Canadian independent First Calgary Petroleum for

CAD923mn (US$872mn), gaining access to a 75% interest in the perimeter area of the Ledjmet Block.

The company has said that about half the estimated 1.3bn boe of reserves located in the block is natural

gas. First Calgary’s Algerian assets will boost Eni’s reserves by about 190mn boe. Its Menzel Ledjmet

East (MLE) Field project is set to start production in 2010, with Eni’s share of output from the MLE field

expected to reach 30,000boe/d by 2011.

In January 2006 Eni announced that it would bring forward plans to expand its gas pipeline network to

Russia and Algeria, as surging Italian demand and concerns over supply worried the political

establishment. The expansion was due for completion in 2009 rather than 2011, but it is unclear whether

works have been finished. The TTPC pipeline supplies Algerian gas to Italy via Tunisia and will have a

capacity of 3.3bcm a year following the expansion.



BP Algeria

Company Analysis

Historically, BP’s involvement in Algeria has been restricted to modest oil

volumes that are not meaningful in a group context. It has done little to

develop a position in the country’s oil sector, but has chosen Algeria as the

foundation for its European gas supply business. The In Salah and Amenas

projects provide BP with large volumes of gas for sale into Mediterranean

Europe and beyond. However, by downsizing its exposure to the major

Algerian gas projects through a partial sale to Statoil, BP appears to have

hedged its bets. The country remains a meaningful part of the group’s

portfolio, but risk has been reduced.

SWOT Analysis

Strengths: Major player in future gas exports


Scope for significant reserves expansion

Weaknesses: Modest presence in upstream oil segment

Reported project delays could slow growth

Opportunities: Considerable untapped gas export potential


Threats: Gas exports face stiff regional competition


Demanding fiscal regime

Address

! BP Algeria 12 Rue Slimane Amirat Colonne Voirol Hydra-Alger Algeria

! Fax: +213 (21) 484 041

! www.bp.com


Net oil/liquids output

! 22,000b/d (2009)

! 4,000b/d (2008)

Net gas output

! 1.6bcm (2009)

! 2.0bcm (2008)

! 2.4bcm (2007)



Market Position

The US$2.5bn In Salah development is the largest new gas project in the country, and involves the

development of seven gas fields in southern central Algeria. Dry gas from the fields is transported via a

500km pipeline to a major gas collection point at Hassi R’Mel, where it is exported to markets in Spain

and Italy. Production is around 9bcm a year. BP has a 33.15% interest in the project, together with Statoil

(31.85%) and Sonatrach (35%).

BP’s second major gas development is the US$1.1bn In Amenas project in the Illizi Basin in south-

eastern Algeria. This project came onstream in 2007 and is expected to produce around 9bcm of gas and

50,000bbl of liquids a year. Shareholding in the project is split between BP (50%) and Statoil (50%).

BP is also involved in exploration in Algeria, having been awarded three new blocks covering more than

30,000sq km in Algeria’s proven wet gas basins in April 2005. One block, Hassi Mat Mat, is adjacent to

the giant Hassi R’Mel gas field, which has proven reserves of over 2.8tcm of gas. The other two blocks

are next to the In Amenas project.

Strategy

Central to the firm’s strategic vision for the country is the supply of gas to Western European economies,

in particular Spain and the UK. In 2003 BP and Sonatrach signed an agreement to form a new JV that

would import LNG to the UK, possibly expanding to other markets such as the US in the future. The two

companies successfully bid for the long-term capacity rights to the Isle of Grain import regasification

facility in the UK, which started commercial operations in December 2008. The capacity rights will

enable the companies to source and supply 5.1bcm of LNG to the UK, representing around 5% of UK

domestic demand. The first Algerian LNG cargo arrived at the Isle of Grain in May 2009.

In August 2009 BP announced plans to invest US$2bn over the next five years (or an average of

US$400mn a year) in Algeria. The targets would signify a continuation of BP’s strategy in Algeria, where

it has spent a total of US$5bn in the past 12 years (equal to an average US$417mn a year). In H209-2010,

BP planned to drill three new exploration wells, maintain production at the In Salah and In Amenas gas

fields, and develop a US$100mn carbon capture and storage (CCS) project at In Salah. Further, BP stated

that it is interested in bidding for new Algerian acreage, provided the licensing terms are sufficiently

attractive.

Latest Developments

In April 2010 BP announced that its Algerian unit expects to maintain its annual output level of 9bcm at

the In Salah gas field by deploying new equipment, which will come onstream at the end of 2010.



BP, alongside its partners Statoil and Sonatrach, plans to install an US$800mn compression project at the

In Salah field in early 2010, as well as drilling new production wells in the south of the block. The

development is aimed at sustaining production at the current level of 9bcm. Similar development projects

are planned for the In Amenas field, which also produces 9bcm plus an additional 50,000b/d of

condensate and LPG. Total gas exported from the two fields accounts for almost a third of Algeria’s total

gas exports.

At the Bourarhet South Block (230, 231), where BP made a discovery in 2008 with Tin Zaouatene-1 well,

the company has undertaken seismic studies and planned to start drilling three new exploration wells by

the end of 2009. BP is hoping to have an idea of the block’s potential reserves by 2012.

BP and Total sold their 12% stake in the Medgaz pipeline to the project’s existing shareholders. Both

companies have been reticent on the reasons for the sale. While the existing shareholders will be pleased

by their marginally higher interest in the project, the benefits for BP and Total are less clear.



BHP Petroleum (Algerie)

Company Analysis

The oil and gas arm of Australia’s BHP Billiton mining group has built a

strong exploration presence in Algeria, as well as a growing share of oil

production. It was a bidder in the sixth licensing round and sees the country

as a key part of its international E&P portfolio. Technical issues delayed the

start-up of the group’s ROD project, but this is not likely to reduce BHP’s

commitment to Algeria. The focus is very much on oil rather than gas,

although the Ohanet project does provide some gas exposure. BHP looks set

to double its share of Algerian production over the next few years, making it

one of the biggest foreign producers.

SWOT Analysis

Strengths: Good spread of oil interests



Extensive involvement in exploration

Weaknesses: Little gas export exposure

Relatively slow output growth

Has experienced technical problems







Address

! BHP Petroleum (Algerie) Inc PO Box 262 Algiers Algeria

! Tel: +213 (1) 912 802

! Fax: +213 (1) 912 459

! www.bhpbilliton.com


Net liquids production:

! 26,760b/d (2009)

! 20,200b/d (2008)



Market Position

The firm holds a 45% stake in the US$500mn Rhourde Oulad Djemma (ROD) development, which is

operated by Eni (55%). The ROD project involves the development of six deposits – ROD, SFNE,

RERN, BSF, RDB and RAR – all located on blocks 401a/402a in the Berkine Basin. The ROD and SFNE

deposits extend into the Block 403a/d concession, operated by Eni and Sonatrach, and a unitisation

agreement has been put into place to govern joint ownership and commercial arrangements, giving BHP

Billiton a 36.04% equity stake. First oil was delivered in October 2004, with production reaching more

than 76,000b/d in 2006. The fields contain over 300mn bbl of recoverable reserves.

The mining group also has a 45% stake in the US$1bn Ohanet wet gas development in Illizi province.

Production started in Q403, with output expected to peak at a rate of 26,000boe/d of condensate,

21,000boe/d of LPG and 18.3Mcm/d of gas. Other shareholders in the project include Japan Ohanet Oil

& Gas (30%), Woodside (15%) and Petrofac (10%). Under the terms of the project’s risk service

contract with Sonatrach, all stakeholders in the JV receive a share of condensate and LPG output for eight

to 12 years, after which all entitlements will be transferred to Sonatrach. Woodside is reportedly looking

to divest the Ohanet stake to concentrate on Australian LNG, providing BHP with an opportunity to

increase the share in the prospective project.

BHP also has interests in exploration in Algeria, having acquired three exploration concessions covering

more than 20,000sq km in 2005-2006. The first licence is Ksar Hirane (Blocks 408a and 409), located to

the north of the Hassi R’Mel gas field, where BHP is operator with 50:50 partner Woodside. The partners

carried out a 2D seismic survey over 1,330km in June 2006. The other licences are Hassi Bir Rekaiz,

north-west of ROD, and Oudoume, north-west of Ohanet.

BHP’s proven Algerian liquids reserves stood at 25mn bbl in June 2008.

Strategy

BHP’s expansion into exploration in Algeria over the past few years suggests that the company has

decided to extend its interests in the country gradually. Production is still set to increase but over a more

extended timeframe, perhaps allowing the firm to concentrate on other regions while waiting for the right

opportunity to build further on its Algerian holdings.

Latest Developments

In 2007 the Algerian government scrapped plans to construct a GTL plant, citing high costs. BHP had

been considering submitting a bid for the project.



CEPSA

Company Analysis

Although Spanish CEPSA is predominantly a domestic downstream

company, it was early to recognise the potential of Algeria’s upstream

sector and its pioneering investment paid off handsomely, with CEPSA

now one the biggest foreign oil producers in the country. Despite the

Spanish group’s overseas expansion campaign, Algeria is likely to remain

its key foreign holding. The company wishes to maximise production, but

is not expected to be an aggressive explorer or acreage bidder. It is,

however, involved in gas export infrastructure projects.

SWOT Analysis

Strengths: Large shares in major producing fields



Involvement in gas export infrastructure

Weaknesses: No exposure to gas supply

Slow pace of oil output growth







Address

! CEPSA Route de Cina BP 200 Hassi Messaoud Wilaya de Ouargla Algeria

! Tel: +213 (29) 737 789

! Fax: +213 (29) 731 348

! www.cepsa.es


Revenues (group)

! EUR22.8bn (2008)

! EUR18.9bn (2007)

! EUR18.5bn (2006)

! EUR18.4bn (2005)

Net income (group)

! EUR748mn (2007)

! EUR812mn (2006)

! EUR1,010mn (2005)



! Net oil/condensate production: 40,000b/d (2008)



Market Position

CEPSA has interests in the RKF (100%) and Ourhoud (39.8%) oil fields in Block 406a. In 2007, the RKF

field produced around 20,000b/d of crude while production at the Ourhoud field averaged 135,000b/d.

Net production in 2008 stood at 40,000b/d, down 37% y-o-y. CEPSA’s Algerian reserves, on the other

hand, grew by 80% in 2008 to 149mn bbl.

CEPSA also holds an 11.25% stake in the exploration Block 325a/329 in the Timimoun Basin, together

with major shareholder Total (38%). The Spanish refiner holds a 20% stake in the Medgaz consortium,

which is constructing a new gas pipeline linking Algeria to Spain. Exports are expected to start in mid-

2010.

Strategy

CEPSA should demonstrate a holding pattern over coming years, holding its existing and very profitable

concessions without seeking additional assets.

A development plan for the Timimoun Block, approved in October 2009, includes the drilling of 37 wells

over 26 years. CEPSA completed the initial required work programme on the block in 2006, spending

EUR8.4mn on processing 2D and 3D seismic data and drilling three wells. Initial production is expected

in 2013.

Latest Developments

CEPSA extended the contract for the RKF field for a five-year period in June 2008.



Statoil Algeria

Company Analysis

A late entrant to the Algerian oil and gas sector, Norway’s Statoil used a deal

with BP to acquire a large presence in the new generation of gas export-

oriented projects. It now shares two major gas projects pretty much equally

with BP and Sonatrach, receiving its first revenues in the second half of 2004

as In Salah delivered its first gas. Although Algeria is now a major part of the

group’s international upstream portfolio, it has yet to build a meaningful oil

exploration presence in the country and does not yet have any direct oil

exposure, although the In Amenas field began delivering gas liquids from

2006. Statoil has access to a Sonatrach discovery on its gas-rich exploration

acreage, so the company is poised to become one of Algeria’s leading gas

producers and exporters.

SWOT Analysis

Strengths: Large stakes in major gas projects

Substantial long-term production upside potential

Good gas-prone exploration acreage

Weaknesses: No upstream crude oil exposure

Little oil exploration potential

Opportunities: Considerable untapped gas export potential


Threats: Gas exports face stiff regional competition


Demanding fiscal regime

Address

! Statoil Algeria 23 Chemin Chekiken Val d’Hydra 16035 Algiers

! Tel: +213 (0) 21 98 12 00

! Fax: +213 (0) 21 59 12 39

! www.statoil.com


Revenue

! US$598mn (2008)

! US$576mn (2007)

Assets

! US$1,843mn (2008)

! US$1,370mn (2007)

Investments

! US$278mn (2008)

! US$162mn (2007)


Net gas/condensate output

! 30,400boe/d (2008)



Market Position

Statoil’s key Algerian assets are the In Salah gas project (31.8%) and the In Amenas gas condensate field

(50%). Deliveries from In Salah began in July 2004 and In Amenas came onstream in May 2006, with

production currently at a plateau of 9bcm of gas and 60,000b/d of condensate. Gross recoverable reserves

for these two projects are estimated to be 2.28bn boe, including 170bcm of gas from In Salah and 140bcm

from In Amenas. Net production reached 30,400boe/d in 2008.

In July 2004 Statoil was awarded operatorship of the Hassi Mouina gas block and began seismic testing at

the concession in December 2005. This covers an area of 23,000sq km in the Timimoun Basin. Hassi

Mouina lies near the In Salah gas field. Statoil is the operator of the block with a 75% stake and

Sonatrach has 25%. Sonatrach has already drilled one well in the block and made a gas discovery, which

Statoil will be allowed to develop. The work programme in the three-year mandatory exploration phase

covered two wells and 400km of 2D seismic. In addition, Statoil will agree with Sonatrach on an

appraisal programme for the discovery. The optional exploration phase is two years and covers one well

and 100km of 2D seismic.

Strategy

Building upon the August 2005 MoU with Sonatrach, Statoil has announced that it is considering a

number of options to bring the relationship forward, including several LNG projects. Officials at

Sonatrach have also announced a determination to expand international cooperation with Statoil,

especially on domestic Norwegian concessions.

Latest Developments

In August 2008 Statoil made a sixth discovery in the Hassi Mouina licence. The existence of dry gas was

confirmed in exploration well TNK-2 in the southern part of the licence. The previous TNK-1 discovery

well flowed at a rate of around 6,971cm/d. No reserve estimates have yet been released.



Hess – Summary

US independent Hess has a 49% stake in a JV with Sonatrach called Sonahess, which is investing

US$500mn over five years to enhance recovery from its three oil fields: el-Gassi, el-Agreb and Zotti.

Hess’ share of crude production averaged 15,000b/d in 2008, down 32% y-o-y. The fall was caused by a

lower entitlement following changes in the state contact laws. In addition to this project, Hess has 60% of

the exploration rights for Block 401c, adjacent to the prolific Hassi Berkine region.

Maersk Oil – Summary

Maersk is involved in two PSCs, the first covering blocks 404a, 208 and 211 (12.25%) and the second

covering Block 403c/e (25%). The Danish company is therefore a partner in the major HBN, HBNS and

Ourhoud fields, with its share of production at 30,100b/d in 2008, unchanged since the previous year.

Exploration activities started in 1990. As of January 2008, 33 exploration wells had been drilled, resulting

in 18 discoveries (one in 2007), some of which tested at flow rates above 21,000b/d. Further exploration

drilling was to take place in 2009.

Maersk joined the lawsuit filed by its US partner Anadarko in February 2009 in protest against the

controversial ‘extraordinary profits tax’ levied by the government in 2006.

Repsol YPF – Summary

Although Spanish major Repsol YPF has no production assets in Algeria, the company has been rapidly

expanding its exploration portfolio since the mid-2000s in the hope of building a solid business in the

country. Repsol is the operator of several permits, including Rhourde El Rouni Central (55%), Reganne

(33.75%), M’Sari Akabli (33.75%) and, as of early 2010, South East Illizi (100%).

In particular, Repsol harbours high hopes for the Reganne concession, with plans to drill eight more wells

following the discovery of natural gas in the basin in early April 2007. Repsol has a 33.75% interest in the

consortium that made the discovery, with Sonatrach holding 25%, Germany’s RWE Dea 25% and

Italy’s Edison 18.75%. Initial tests at the two exploratory wells yielded close to 740mcm/d.

In April 2009, Repsol announced a gas discovery with the TGFO-1 well on the M’Sari Akabli permit in

the Ahnet Basin. The initial tests produced flow rates of 363mcm/d. The discovery is Repsol’s seventh in

the country. Repsol operates the M’Sari Akabli block with a 33.75% stake alongside Sonatrach (25%),

RWE Dea (22.5%) and Edison (18.75%). The Ahnet discovery follows three further gas finds announced

in January 2009. Initial tests at the wells showed combined output of 1Mcm/d. The first of the discoveries

is located in the Reggane Basin, where the KLS-1 well registered gas flows of 629,000cm/d. The second



find was made at M’Sari Akabli, where the OTLH-2 well registered test flows of 359mcm/d. The third

was made with the AI-2 well in Gassi Chergui in the Berkine Basin. It produced test flows of 158mcm/d.

In September 2007 Sonatrach terminated a 2004 agreement with Repsol and Gas Natural for Gassi

Touil, a major upstream and LNG project, citing delays and cost over-runs by the Spanish companies.

Both the Spanish companies and Sonatrach launched legal proceedings to obtain reparations from each

other. An Algerian court, however, ruled in November 2009 that none of the parties (Repsol, Gas Natural

and Sonatrach) owes any liabilities. Repsol owned a 48% share, Gas Natural a 32% share and Sonatrach

the remaining 20% in the EUR5bn project.

Under the ruling, Repsol and Gas Natural will not receive reimbursement for their investments in the

project, which will indicate a net loss of around EUR105mn for Repsol and EUR60mn for Gas Natural.

The court has, however, ordered Sonatrach to purchase the Spanish companies' shares in the project for a

price similar to the consortium's current liquid assets. A price for the assets has not been disclosed.

Following the contract revocation, energy minister Chakib Khelil said the disagreement would not affect

other investment opportunities for Spanish firms in Algeria. Repsol YPF will be hoping that is the case.

Royal Dutch Shell – Summary

Shell’s Algerian activities are mainly confined to exploration. In 2005, the Anglo-Dutch major was

awarded operatorship of the Reggane Djebel Hirane and Zerafa fields. In February 2006, Shell signed an

MoU with Sonatrach over possible hydrocarbons cooperation, which covers possible upstream and LNG

development projects.

ConocoPhillips – Summary

US major ConocoPhillips holds interests in three fields in the Menzel Lejmat Block (405a), with average

net production of 11,000b/d in 2007. Development of the El Merk (EMK) area, where Conoco holds

17%, is in progress, with first production expected in 2012. The drilling programme at the Ourhoud field

(3.7) continues, with seven wells completed in 2007.

Total – Summary

French major Total has been active in the Algerian upstream segment since 1952. Its production comes

from the Hamra (100%) and Tin Fouyé Tabankort (TFT, 35%) gas fields, as well as through its 49%

interest in CEPSA, which holds equity in the Ourhoud and Rhourde EL Khrouf (RFK) fields. In 2008

Total’s direct activities produced 59,000b/d, a 2% rise y-o-y. A stake in CEPSA added a further

20,000b/d. In March 2006 Total reported a gas discovery in its Timimoun permit in Algeria, with initial

flow rates of 235,000cm/d. Total operates the permit with a 37.75% stake, working alongside CEPSA and

Sonatrach. The Timimoun licence, which comprises blocks 325A and 329, was originally split 85:15



between Total and CEPSA. Sonatrach farmed into the block following the discovery and later boosted its

stake to 51% to comply with legislation passed in August 2008 requiring state majority ownership in all

energy projects.

ALNAFT granted its final approval for the Timimoun development plan in October 2009, paving the way

for Total and partners to begin development drilling by the end of 2009. In total, 36 wells are to be drilled

on the permit by 2035. The Timimoun field is expected onstream in 2013 with annual output of 1.6bcm.

Around US$100mn will be invested on bringing the field onstream, while total capital expenditure

(capex) in the project over its lifespan is estimated at US$1bn.

While no marketing strategy has been released, BMI expects the Timimoun field to be connected to the

Reganne-Hassi R’Mel pipeline, from where gas will be exported via one of the export pipelines running

from the Hassi R’Mel hub. The most likely route is through the Medgaz pipeline, in which Sonatrach and

CEPSA both hold stakes.

In January 2010 Total won the Ahnet exploration permit under Algeria’s eight licensing round. The

permit covers 17,358sq km and includes seven blocks, with reserves estimated at around 500bcm of gas.

Under the contract with Sonatrach, Total has agreed to raise production at the licence to 4bcm a year.

Sonatrach was looking to secure capex of US$2.8-3.5bn for the initial phase of the project, but the deal

with Total envisions only US$1.5-2bn of total investment through to 2014. Total will hold 47% in the

Ahnet licence, with private company Partex holding 2% and Sonatrach 51%. Total plans to submit the

development proposal by mid-2011, with first gas scheduled for 2014-2015. Sonatrach is looking to build

a gas pipeline from Ahnet to Hassi Messaoud from where gas could be transported via existing gas

pipelines to Hassi R’Mel, the country's main hub for export to Europe.

BG Group – Summary

Britain’s BG Group entered Algeria in 2006 through a farm-in agreement with independent Gulf

Keystone to acquire an interest in the Hassi Ba Hamou (HBH) PSC in Western Algeria. Following

completion of the transaction in December 2006, BG Group has a 36.75% operating interest in the HBH

PSC, which comprises five blocks (317b, 322b3, 347b, 348 and 349b) and contains the Hassi Ba Hamou

gas discovery. The remaining interest in BHB PSC is split between Gulf Keystone (38.25%), which BG

is in the process of buying, and Sonatrach (25%). Following the expiration of the initial contract in 2009,

BG and Keystone have agreed to enter the second two-year exploration period and relinquish 30% of the

PSC area. First gas is expected at the licence in 2014.

In July 2009, Gulf Keystone announced that it will suspend further investment in Algeria while it looks to

divest its BHB stake to concentrate on its Iraqi Kurdistan assets. The announcement provoked a negative

reaction from BG, which demanded Gulf Keystone pays it US$7.5mn of investment costs. In response,



Gulf decided to escalate the row, filing for arbitration under the JV agreement. Together with the

Algerian government and Sonatrach, BG has veto over Gulf Keystone’s PSC divestment.

In February 2010 Gulf Keystone announced that it had reached an agreement with BG Group to settle its

dispute over the payment of costs at the HBH area. Under the settlement, the two sides have agreed to

cease arbitration proceedings, allowing Gulf Keystone to sell its stake in the HBH assets to BG Group for

a cash payment of US$9.9mn. The settlement is subject to the approval of government authorities and

Sonatrach. In a statement, Gulf Keystone's executive chairman, Todd Kozel, said that he believed the

settlement would be followed by the sale of the company's remaining Algerian assets. The RM-1

exploration well at the BHB permit struck a 61m gas column in June 2008. The well produced test flow

rates of 246mcm/d.

Talisman Energy – Summary

Under a PSA with Sonatrach, Canada’s Talisman holds a 35% interest the Greater Menzel Lejmat North

(Greater MLN) fields and the Menzel Lejmat Southeast (MLSE) field (Block 405a), a 2% interest in the

Ourhoud Unit (Blocks 405a, 404 and 406), and a 9% interest in the El Merk field (blocks 405a and 208).

In 2008, Talisman’s share of Algerian oil production averaged 15,100b/d, up from 13,200b/d in 2007.

The company drilled four development wells in Algeria in 2008, below the 10 originally planned. In

2009, Talisman expects to conduct engineering work on the EMK project. In Q109 Talisman drilled three

wells and began expanding the gas facilities at the Greater MLN Phase 2 project.

Gazprom – Summary

Russian state gas giant Gazprom began drilling its first Algerian well in March 2010. Gazprom has been

seeking closer ties with Algeria in an attempt to coordinate their respective European gas supply

strategies.

Gazprom launched its drilling campaign at the El Assel Block in the Berkine Basin with the spudding of

the Rhourde Sayah-2 exploration well. The well is due to reach planned depth in June 2010. Three more

wells on the block are scheduled through to 2011. Gazprom acquired the El Assel contract in December

2008 as part of Algeria's seventh licensing round. The block, located close to the country's gas hub of

Hassi R'Mel, is Gazprom's only Algerian asset, and one of its first upstream properties in Africa. The bid

for the block was preceded by the signing of a broad MoU on cooperation between Gazprom and

Sonatrach in 2006.

Gazprom's launch of operations in Algeria is taking place amid lower investment from IOCs. Although

BMI believes Algeria contains significant gas reserves and upside output potential, both above and below

ground risks are high. The country's unattractive business environment and high drilling costs suggest that



Gazprom's involvement in the country may serve strategic ambitions, such as gaining a stake in the

proposed Trans-Sahara Pipeline running through Algeria, which if built would compete with Russian gas

pipelines for European market share.

Others – Summary

In May 2005 China’s state-owned CNPC secured a US$400mn contract with Sonatrach to develop the

Skikda condensate project. CNPC’s engineering subsidiary completed the construction of a 100,000b/d

refinery at Skikda in July 2009. Sonatrach is the sole owner the refinery.

It was disclosed in February 2006 that a consortium involving Vietnam’s state-owned PetroVietnam and

Thailand’s PTTEP plans to spend US$3bn developing a project in Algeria, aiming for production in

2009. Sonatrach is also a partner in the concession, with reserves potential estimated to be up to 2bn bbl.

Irish explorer Petroceltic International is the operator of the Isarene permit (blocks 228 and 229a) with

a 75% stake. Sonatrach owns the remaining 25%. Petroceltic began its five-to-seven well Algerian

exploration programme in May 2009, making several minor to mid-sized gas discoveries – INE-2, AT-1,

AT-2, TMZ-1, GTT-1 and INW-2 – which could potentially amount to several commercial fields.

Petroceltic claims that data from the three AT wells suggest that the gas field could flow at rates

exceeding 850mcm/d after fracture stimulation. The INW-2 well, the last in the exploratory drilling

campaign, tested at 473mcm/d in February 2010. Petroceltic will spend 2010 on further well testing.



Long-Term Oil And Gas Forecasts

Regional Oil Demand

An acceleration of the 2010-2014 oil demand trend is predicted for the 2014-2019 period, reflecting the

underdeveloped nature of several key economies, plus ongoing wealth generation thanks to robust energy

prices and rising export volumes. The region’s oil consumption is expected to increase by 18.4% in 2014-

2019, after 11.8% growth in 2010-2014. Over the extended 2010-2019 forecast period, Angola leads the

way, with oil demand increasing by an estimated 303%, followed by Nigeria’s impressive 83% growth.

South Africa lags behind the rest of the field, as a result of greater market maturity and the lack of

hydrocarbons income that stimulates economies elsewhere in the region.

Table: Africa’s Oil Consumption, 2012-2019 (000b/d)

Country 2012f 2013f 2014f 2015f 2016f 2017f 2018f 2019f

Algeria 369 383 399 415 431 449 467 485

Angola 124 149 179 215 258 296 341 378

Cameroon 38 40 42 44 46 48 50 53


Egypt 779 810 835 860 885 912 939 968


Gabon 15 16 17 18 19 20 21 22

Libya 296 308 320 333 346 360 375 390

Nigeria 318 342 367 395 425 456 491 528

South Africa 539 547 555 564 572 581 598 607

Sudan 96 101 106 111 117 123 129 136

BMI universe 2,584 2,706 2,830 2,964 3,110 3,256 3,422 3,578

Other Africa 1,417 1,425 1,432 1,439 1,446 1,453 1,461 1,468

Regional total 4,001 4,131 4,262 4,403 4,556 4,710 4,883 5,046

f = forecast. Source: BMI



Regional Oil Supply

An 9.5% gain in African oil production during the 2014-2019 period represents a significant slowing

from the rate of expansion seen in 2010-2014 (16.7%), and reflects a plateau in likely Angolan output,

with no other major country expected to have substantial longer-term upside potential. Nigeria is by far

the biggest contributor to growth, with output forecast to rise by 52% between 2010 and 2019. Its nearest

rivals, with 38% growth forecast, are Algeria and Libya. Egypt and Congo have the weakest production

trends, with likely 18% and 12% declines between 2010 and 2019.

Table: Africa’s Oil Production, 2012-2019 (000b/d)


Algeria 1,965 2,050 2,150 2,300 2,450 2,510 2,550 2,600

Angola 2,150 2,300 2,400 2,550 2,500 2,400 2,250 2,100

Cameroon 80 84 85 85 83 82 80 78


Egypt 685 700 683 665 649 633 617 601


Gabon 255 250 245 240 235 230 226 221

Libya 1,725 1,800 1,865 1,910 1,995 2,050 2,150 2,300

Nigeria 2,350 2,450 2,700 2,950 3,150 3,300 3,400 3,400

South Africa 17 16 16 15 15 14 14 14

Sudan 630 691 735 770 755 740 725 710

BMI universe 10,615 11,107 11,655 12,263 12,594 12,705 12,743 12,743

Other Africa 259 269 277 285 293 302 311 321

Regional total 10,874 11,375 11,931 12,548 12,887 13,007 13,055 13,063




Regional Refining Capacity

Africa is set for a 46.8% increase in crude distillation capacity between 2010 and 2019, contributing

modestly to the expansion of the world’s over-stretched refining industry. Cheap and plentiful local crude

supplies should increasingly make it a region of choice for refinery investment, although government

control of the downstream industry will need to be eased. Angola has particularly ambitious expansion

plans, reflecting the surge in crude supply and growth in local demand. Nigeria is also expected to

increase its capacity substantially, with Libya and South Africa also planning new refining sites. The

region should increase in importance as a net exporter of refined products.

Table: Africa’s Oil Refining Capacity, 2012-2019 (000b/d)


Algeria 594 594 594 594 594 594 594 594

Angola 39 39 239 239 239 239 239 239

Cameroon 37 70 70 70 70 70 70 70



Egypt 726 726 976 976 976 976 976 976

Gabon 24 24 30 30 30 30 30 30

Libya 550 550 650 650 650 700 700 700

Nigeria 505 540 540 720 720 720 720 720

South Africa 485 485 485 485 485 885 885 885

Sudan 122 122 122 122 122 122 122 122

BMI universe 3,103 3,171 3,727 3,907 3,907 4,357 4,357 4,357

Other Africa 510 510 536 562 590 620 651 683

Regional total 3,613 3,681 4,263 4,469 4,497 4,977 5,008 5,040




Regional Gas Demand

Gas demand growth could accelerate somewhat between 2014 and 2019, when compared with the 34.7%

rate expected for the 2010-2014 period. There is likely to be some 40.5% gas market expansion in the

region in the final five years of the period. Expansion of gas consumption is expected to be at its greatest

in Angola, Cameroon, Nigeria, South Africa and the Republic of Congo. Egypt and Libya are likely to lag

behind the field.

Table: Africa’s Gas Consumption, 2012-2019 (bcm)


Algeria 30.5 32.1 33.7 35.1 36.7 38.3 39.9 42.6

Angola 7.0 8.1 9.3 10.6 12.2 14.1 16.2 18.6

Cameroon 0.2 0.2 0.2 0.3 0.3 0.3 0.3 0.3

Republic of Congo 1.2 1.5 2.0 2.0 2.4 3.0 3.0 3.0

Egypt 48.9 51.3 53.4 55.5 57.7 60.0 62.5 65.6


Gabon 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0

Libya 7.8 9.0 9.6 10.0 10.4 10.8 11.2 11.7

Nigeria 18.5 21.0 25.0 29.0 35.0 40.0 44.0 48.0

South Africa 10.0 10.5 12.0 12.5 13.0 17.0 17.0 17.0

Sudan 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

BMI universe 126.8 136.6 148.2 158.1 170.9 186.8 197.4 210.4

Other Africa 16.6 16.6 17.4 18.2 19.2 20.1 21.1 22.2

Regional total 143.4 153.2 165.6 176.3 190.0 207.0 218.6 232.6




Regional Gas Supply

A production increase of 35.6% is forecast for Africa in 2014-2019, representing a deceleration compared

with the 39.1% predicted during the 2010-2014 period. Angola’s explosive growth in the first half of the

forecast period is not sustainable at the same rate, although its volumes could still rise 106% in 2014-

2019, compared with 226% in 2009-2014. Nigeria is the other key player in the region. Gas production is

expected to increase by 82% in 2014-2019, after 57% in 2010-2014. Cameroon could see production

increase from 0.2bcm to 5.0bcm during the 10-year period.

Table: Africa’s Gas Production, 2012-2019 (bcm)


Algeria 103.0 111.0 116.5 122.0 125.0 130.0 132.0 135.0

Angola 12.0 15.0 16.3 17.6 24.2 26.1 28.2 33.6

Cameroon 0.2 0.2 0.2 0.3 4.8 4.8 4.9 5.0

Republic of Congo 1.2 1.5 2.0 2.0 2.4 3.0 3.0 3.0

Egypt 70.0 73.0 75.0 77.0 84.0 86.5 89.0 92.0


Gabon 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0

Libya 18.0 19.5 20.5 25.0 25.5 26.0 26.0 27.0

Nigeria 42.0 49.0 55.0 62.0 69.0 75.0 89.0 100.0

South Africa 5.0 7.0 7.0 7.0 6.0 6.0 6.0 5.0

Sudan 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

BMI universe 258.9 283.8 300.2 320.7 348.8 365.4 386.2 408.9

Other Africa 5.0 5.0 5.0 5.0 5.0 5.0 5.0 5.0

Regional total 263.9 288.8 305.2 325.6 353.8 370.4 391.2 413.9


Algeria Country Overview

Between 2010 and 2019 we are forecasting an increase in Algerian oil and gas liquids production of

37.9%, with volumes rising steadily from an estimated 1.89mn b/d in 2010 to 2.60mn b/d by the end of

the 10-year forecast period. Oil consumption between 2010 and 2019 is set to increase by 42.3%, with

growth slowing to an assumed 4.0% per annum towards the end of the period and the country using

485,000b/d by 2019. Gas production is expected to rise to 135bcm by the end of the period. With demand

rising by 55.1% between 2010 and 2019, there should be export potential increasing from 56bcm to

92bcm, in the form of LNG and by pipeline.



Methodology And Risks To Forecasts

In terms of oil and gas supply, as well as refining capacity, the projections are wherever possible based on

known development projects, committed investment plans or stated government/company intentions. A

significant element of risk is clearly associated with these forecasts, as project timing is critical to volume

delivery. Our assumptions also take into account some third-party estimates, such as those provided by

the US-based Energy Information Administration (EIA), the International Energy Agency (IEA) and

OPEC and certain consultants’ reports that are in the public domain. Reserves projections reflect

production and depletion trends, expected exploration activity and historical reserves replacement levels.

We have assumed flat oil and gas prices throughout the extended forecast period, but continue to provide

sensitivity analysis based on higher and lower price scenarios. Investment levels and production/reserves

trends will of course be influenced by energy prices. Oil demand has provide itself to be less sensitive to

pricing than expected, but will still have some bearing on consumption trends. Otherwise, we have

assumed a slowing of GDP growth for all countries beyond our core forecast period (to 2014) and a

further easing of demand trends to reflect energy-saving efforts and fuels substitution away from

hydrocarbons. Where available, government and third-party projections of oil and gas demand have been

used to cross check our own assumptions.



Glossary Of Terms AOR additional oil recovery KCTS Kazakh Caspian Transport System

APA awards for predefined areas km kilometres

API American Petroleum Institute LAB linear alkyl benzene

bbl barrel LDPE low density polypropylene

bcm billion cubic metres LNG liquefied natural gas

b/d barrels per day LPG liquefied petroleum gas

bn billion m metres

boe barrels of oil equivalent mcm thousand cubic metres

BTC Baku-Tbilisi-Ceyhan Pipeline Mcm mn cubic metres

BTU British thermal unit MEA Middle East and Africa

capex capital expenditure mn million

CBM coal bed methane MoU memorandum of understanding

CEE Central and Eastern Europe mt metric tonne

CPC Caspian Pipeline Consortium MW megawatts

CSG coal seam gas na not available/ applicable

DoE US Department of Energy NGL natural gas liquids

EBRD European Bank for Reconstruction and Development NOC national oil company

EEZ exclusive economic zone OECD Organisation for Economic Co-operation and Development

e/f estimate/forecast OPEC Organization of the Petroleum Exporting Countries

EIA US Energy Information Administration PE polyethylene

EM emerging markets PP polypropylene

EOR enhanced oil recovery PSA production sharing agreement

E&P exploration and production PSC production sharing contract

EPSA exploration and production sharing agreement q-o-q quarter-on-quarter

FID final investment decision R&D research and development

FDI foreign direct investment R/P reserves/production

FEED front end engineering and design RPR reserves to production ratio

FPSO floating production, storage and offloading SGI strategic gas initiative

FTA free trade agreement SoI statement of intent

FTZ free trade zone SPA sale and purchase agreement

GDP gross domestic product SPR strategic petroleum reserve

G&G geological and geophysical t/d tonnes per day

GoM Gulf of Mexico tcm trillion cubic metres

GS geological survey toe tonnes of oil equivalent

GTL gas-to-liquids conversion tpa tonnes per annum

GW gigawatts TRIPS Trade-Related Aspects of Intellectual Property Rights

GWh gigawatt hours trn trillion

HDPE high density polyethylene T&T Trinidad & Tobago

HoA heads of agreement TTPC Trans-Tunisian Pipeline Company

IEA International Energy Agency TWh terawatt hours

IGCC integrated gasification combined cycle UAE United Arab Emirates

IOC international oil company USGS US Geological Survey

IPI Iran-Pakistan-India Pipeline WAGP West African Gas Pipeline

IPO initial public offering WIPO World Intellectual Property Organization

JOC joint operating company WTI West Texas Intermediate

JPDA joint petroleum development area WTO World Trade Organization



BMI Methodology

How We Generate Our Industry Forecasts

BMI’s industry forecasts are generated using the best-practice techniques of time-series modelling. The

precise form of time-series model we use varies from industry to industry, in each case being determined,

as per standard practice, by the prevailing features of the industry data being examined. For example, data

for some industries may be particularly prone to seasonality, meaning seasonal trends. In other industries,

there may be pronounced non-linearity, whereby large recessions, for example, may occur more

frequently than cyclical booms.

Our approach varies from industry to industry. Common to our analysis of every industry, however, is the

use of vector autoregressions. Vector autoregressions allow us to forecast a variable using more than the

variable’s own history as explanatory information. For example, when forecasting oil prices, we can

include information about oil consumption, supply and capacity.

When forecasting for some of our industry sub-component variables, however, using a variable’s own

history is often the most desirable method of analysis. Such single-variable analysis is called univariate

modelling. We use the most common and versatile form of univariate models: the autoregressive moving

average model (ARMA). In some cases, ARMA techniques are inappropriate because there is insufficient

historical data or data quality is poor. In such cases, we use either traditional decomposition methods or

smoothing methods as a basis for analysis and forecasting.

Human intervention plays a necessary and desirable part of all our industry forecasting techniques.

Intimate knowledge of the data and industry ensures we spot structural breaks, anomalous data, turning

points and seasonal features where a purely mechanical forecasting process would not.

Energy Industry

A number of principal criteria drive our forecasts for each energy indicator.

Energy Supply

Supply of crude oil, natural gas, refined oil products and electrical power is determined largely by

investment levels, available capacity, plant utilisation rates and national policy. We therefore examine:

! National energy policy, stated output goals and investment levels;

! Company-specific capacity data, output targets and capital expenditures, using national, regional and

multinational company sources;



! International quotas, guidelines and projections, such as OPEC, the International Energy Agency

(IEA) and the US Energy Information Administration (EIA).

Energy Consumption

A mix of methods is used to generate demand forecasts, applied as appropriate to each individual country:

! Underlying economic (GDP) growth for individual countries/regions, sourced from BMI’s estimates.

Historical relationships between GDP growth and energy demand growth at an individual country are

analysed and used as the basis for predicting levels of consumption;

! Government projections for oil, gas and electricity demand;

! Third-party agency projections for regional demand, such as the IEA, EIA and OPEC;

! Extrapolation of capacity expansion forecasts, based on company- or state-specific investment levels.

Cross Checks

Whenever possible, we compare government and/or third party agency projections with the declared

spending and capacity expansion plans of the companies operating in each individual country. Where

there are discrepancies, we use company-specific data as physical spending patterns to ultimately

determine capacity and supply capability. Similarly, we compare capacity expansion plans and demand

projections to check the energy balance of each country. Where the data suggest imports or exports, we

check that necessary capacity exists or that the required investment in infrastructure is taking place.

Oil And Gas Ratings Methodology

BMI’s approach to our Oil & Gas Business Environments Ratings (BER) is threefold. First, we

disaggregate the upstream (oil/gas E&P) and downstream (oil refining and marketing, gas processing and

distribution), enabling us to take a nuanced approach to analysing the potential within each segment, and

the different risks along the value chain. Second, we identify objective indicators that may serve as

proxies for issues/trends that were previously evaluated on a subjective basis. Finally, we use BMI’s

proprietary Country Risk Ratings (CRR) to ensure that only those risks most relevant to the industry have

been included. Overall, the ratings system, which is integrated with those of all industries covered by

BMI, offers an industry-leading insight into the prospects/risks for companies across the globe.

Conceptually, the new ratings system is organised in a manner that enables us clearly to present the

comparative strengths and weaknesses of each state. As before, the headline Oil & Gas BER is the

principal rating. However, the differentiation of Upstream/Downstream and the articulation of the



elements that comprise each segment enable more sophisticated conclusions to be drawn, and also

facilitate the use of the ratings by clients, who will have varying levels of exposure and risk appetite for

their operations.

Oil & Gas Business Environment Ratings

This is the overall rating, which comprises 50% Upstream BER and 50% Downstream BER:

Upstream Oil & Gas Business Environment Ratings

This is the overall Upstream rating which is composed of limits/risks (see below);

Downstream Oil & Gas Business Environment Ratings

This is the overall Downstream rating which comprises limits/risks (see below).

Both the Upstream and Downstream BER are composed of limits and risks sub-ratings, which themselves

comprise industry-specific and broader country risk components:

Limits Of Potential Returns

Evaluates the sector’s size and growth potential in each state, and also broader industry/state

characteristics that may inhibit its development;

Risks To Realisation Returns

Evaluates both Industry-specific dangers and those emanating from the state’s political/economic profile

that call into question the likelihood of expected returns being realised over the assessed time period.



Table: Structure Of BMI’s Oil & Gas Business Environment Ratings

Component Details

Oil & Gas BER Overall rating

Upstream BER 50% of O&G BER

Limits of potential returns 70% of Upstream BER

Upstream market 75% of Limits

Country structure 25% of Limits

Risks to realisation of returns 30% of Upstream BER

Industry risks 65% of Risks

Country risk 35% of Risks

Downstream BER 50% of O&G BER

Limits of potential returns 70% of Downstream BER

Upstream market 75% of Limits

Country structure 25% of Limits

Risks to realisation of returns 30% of Downstream BER

Industry risks 60% of Risks

Country risk 40% of Risks

Source: BMI



Indicators

Overall, the rating uses three subjectively measured indicators, and 41 separate indicators/datasets.

Table: BMI’s Upstream Oil & Gas Business Environment Ratings – Methodology

Indicator Rationale

Limits of potential returns

Upstream market

Resource base

– Proven oil reserves, mn bbl To denote total market potential. High values are given a better score.

– Proven gas reserves, bcm As above.

Growth outlook

– Oil production growth, 2009-2014 Proxy for BMI’s market assumptions, with strong growth given higher score.

– Gas production growth, 2009-2014 As above.

Market maturity

– Oil reserves/ production Used to denote whether industries are frontier/emerging/developed or mature markets. Low existing exploitation in relation to potential gets higher scores.

– Gas reserves/ production As above.

– Current oil production vs peak As above.

– Current gas production vs peak As above.

Country structure

State ownership of assets, % Used to denote opportunity for foreign NOCs/IOCs/independents. Low state ownership scores higher.

Number of non-state companies Used to denote market competitiveness. Presence (and large number) of non-state companies scores higher.

Risks to realisation of returns

Industry risks

Licensing terms Subjective evaluation of government policy towards sector against BMI-defined criteria. Protectionist states are marked down.

Privatisation trend Subjective evaluation of government industry orientation. Protectionist states are marked down.

Country risk

Physical infrastructure Rating from BMI’s Country Risk Ratings (CRR). Evaluates constraints imposed by power, transport and communications infrastructure.

Long-term policy continuity risk CRR. Evaluates risk of sharp change in broad direction of government policy.

Rule of law CRR. Evaluates government’s ability to enforce its will within the state.

Corruption CRR, to denote risk of additional illegal costs/possibility of opacity in tendering/business operations affecting companies’ ability to compete.

Source: BMI



Table: BMI’s Downstream Oil & Gas Business Environment Ratings – Methodology

Indicator Rationale

Limits of potential returns

Downstream market

Market

– Refining capacity, 000b/d Denotes existing domestic oil processing capacity. High capacity considered beneficial.

– Oil demand, 000b/d Denotes size of domestic oil/gas market. High values are accorded better scores.

– Gas demand, bcm As above.

– Retail outlets/1,000 people Indicator denotes fuels retail market penetration; low penetration scores highly.

Growth outlook

– Oil demand growth, 2009-2014 Proxy for BMI’s market assumptions, with strong growth accorded higher scores.

– Gas demand growth, 2009-2014 As above.

– Refining capacity growth, 2009-2014 As above.

Import dependence

– Refining capacity vs oil demand, %, 2009-2014

Denote reliance on imported oil products and natural gas. Greater self-sufficiency is accorded higher scores.

– Gas demand vs gas supply, %, 2009-2014 As above.

Country structure

State ownership of assets, %

Used to denote opportunity for foreign NOCs/IOCs/independents. Low state ownership scores higher.

Number of non-state companies

Indicator used to denote market competitiveness. Presence (and large number) of non-state companies scores higher.

Population, mn Data from BMI’s Country Risk team. Indicators used as proxies for overall market size

and potential.

Nominal GDP, US$bn As above.

GDP per capita, US$ As above.

Risks to realisation of returns

Industry risks

Regulation Subjective evaluation of government policy towards sector against BMI-defined criteria.

Bureaucratic/intrusive states are marked down.

Privatisation trend Subjective evaluation of government industry orientation. Protectionist states are marked

down.

Country risk

Short-term policy CRR. Evaluates the risk of sharp change in broad direction of government policy.



Table: BMI’s Downstream Oil & Gas Business Environment Ratings – Methodology

Indicator Rationale

continuity risk

Short-term economic external risk

CRR. Evaluates vulnerability to external economic shock, the typical trigger of recession in emerging markets.

Short-term economic growth risk CRR. Evaluates current growth trajectory and state’s position in economic cycle.

Rule of law CRR. Evaluates the government’s ability to enforce its will within the state.

Legal framework CRR, to denote risk of additional illegal costs/possibility of opacity in tendering/business

operations affecting companies’ ability to compete.

Physical infrastructure CRR. Evaluates constraints imposed by power, transport and communications

infrastructure.

Source: BMI

Sources

Sources include those international bodies mentioned above, such as OPEC, the IEA, and the EIA, as well

as local energy ministries, official company information, and international and national news agencies.

118392_BMI Algeria Oil and Gas Report Q4 2010

Documents

Transcript of 118392_BMI Algeria Oil and Gas Report Q4 2010