Study on Possible Reductions of Gas Flaring in

Final Report

Commissioned by BGR

Prepared by:

01 July 2019

Table of Contents

1.0 OVERVIEW OF THE PROJ ECT ...... 3

2.0 OBSERVATIONS AND FIN DINGS ...... 3

3.0 COUNTRY CONTEXT ...... 5

4.0 GAS FLARING IN ALGER IA ...... 6

4.1 Magnitude and direction of gas flaring and GHG emissions ...... 6

4.2 Specific Upstream Gas Flare Reduction Projects ...... 8

5.0 STRUCTURE OF THE ALG ERIAN OIL AND GAS SE CTOR ...... 10

5.1 Principal Actors and Stakeholders ...... 10 The Ministry of Energy and Mines ...... 11 ...... 11 Regulators ...... 12 Private O&G Companies ...... 13

5.2 The Gas Market ...... 14

5.3 Legal and Regulatory Framework for Gas Development and Valorization ...... 14

6.0 GEOLOGICAL AND PRODU CTION TECHNICAL ISSU ES ...... 16

ANNEX 1: MAP: OIL AND GAS INFRASTRUCTU RE IN ALGERIA ...... 17

ANNEX 2: NOTES AND ILLUSTRATIONS ...... 18

Note 1: Flared Gas vs. Gas Production ...... 18

Note 2: Issues Related to Algerian Gas Production ...... 18

Note 3: Key Stakeholders on Flaring in the Algeria’s O&G Sector ...... 19

Note 4: Planned Gas Projects -- 2016 ...... 20

Note 5: Major Sources ...... 21

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1.0 Overview of the Project

This report was commissioned by Federal Institute for Geosciences and Natural Resources (BGR) to assess the potential of German Technical Cooperation (TC) in the area of gas flaring reduction in Algeria. Specifically, the Terms of Reference requests:

• Research on the legislative and regulatory framework on gas flaring as well as its status of implementation; • Analysis of the geological, geographic and economic conditions towards the usage of associated gas (AG); • A stakeholder analysis on the subject for Algeria; • Demonstration of other donor’s engagement in this area.

The preliminary report was submitted to BGR in August 2017, and this was to be followed by a mission to Algeria. Due to various scheduling difficulties, the mission was not held until October 2018. This document is the final project report that includes the interim findings, additional research, and the results from the in-country mission.

2.0 Observations and Findings

The principal points established by this project are:

• The legislative and regulatory framework is largely in place. Flaring is prohibited by law, but exceptions can be, and are, made. The regulatory agency Agence Nationale pour la Valorisation des Ressources en Hydrocarbures (ALNAFT) has the responsibility for issuing exceptions. A substantial fee of 20,000 Algerian dinars (approximately 150€) per 1000 meters is payable on flared gas.

As flaring on new fields is prohibited and appears to be strictly enforced, almost all flaring occurs in older fields directly operated by Société nationale pour la recherche, la production, le transport, la transformation et la commercialisation des hydrocarbures (SONATRACH), the state-owned, oil company. Thus, while private oil companies are often operators on newer fields, flaring of AG occurs almost always from older Sonatrach operations.

As Sonatrach has substantial political and economic influence, it was not possible to determine if Sonatrach has a de facto or de jure exemption on flaring and if any fine is assessed on their flaring. Discussions with Sonatrach representatives during the mission suggest that the company is currently paying at least some fines for flaring. Sonatrach reports directly to the Ministry of Energy and Mines.

• From a geological standpoint, oil production (and thus AG) primarily comes Paleozoic (Cambrian-Ordovician and Lower Devonian) and Triassic reservoirs and is dominated by the Sonatrach operated Hassi Massaoud. AG flaring tends to occur at smaller fields distant from the principal fields and connecting gas infrastructure which makes the connection costs relatively high. This is true of all three fields that were identified as potential projects during the mission.

Wet production in Algeria is processed to extract NGLs and the bulk of this processing takes place in the Sonatrach operated Hassi R’Mel field -- the largest gas field and principal gas hub. 3

Once stripped, the gas is partly re-injected to maintain stable reservoir pressure and avoid retrograde condensation. The excess dry gas is then supplied to the domestic and export markets. Some studies suggest that due to the declining trends in both AG production and the increasing volumes of gas needed for re-injection, the system may be short enough raw gas to operate at an optimum level. While new non-associated gas (NAG) production covers the decline in the older fields, the ability to maintain gas production is an ongoing challenge and the cost per unit of gas produced is increasing.

• The most important player in the O&G sector is the Ministry of Energy & Mines 1 to which Sonatrach directly reports. Sonatrach as the principal O&G source for the state is the major funder of the Algerian national budget and as such has immense importance. Any major initiative on gas flaring would require the support of Sonatrach and the tacit consent of the Ministry of Energy.

• The major donor involved on flaring issues in Algeria has been the /GGFR, which sponsored a major flaring project in 2003-2005. In 2018, Sonatrach has endorsed the WB/GGFR “Zero by 2030” Initiative (ZRF 2003). The country’s National Determined Contribution (NDC) under the Paris Accord sets a target of no more than 1% flaring by 2030.

As regards technical assistance , during the October 2018 mission, the Ministry brought forward three flaring sites as candidates for technical assistance -- the flared AG at the oil fields; TFT, and . These three fields are the same ones which the WB/GGFR provided assistance on options to reduce flaring in 2003-2005.

The preferred technical option, both then and now, continues to be to capture the AG and take it to market. Since the WB/GGFR study, the gas infrastructure in the region has expanded substantially, but this relates to NAG production and the flaring sites have not apparently been affected. The issue in 2003-2005 was financing the flaring investment and this appears to still be the main barrier. Importantly since the initial studies, the marginal economics of the flare projects has most likely declined due to natural decline in the AG production (thus increasing costs per unit of gas captured.)

In considering options for technical assistance, areas that could be viable include:

• In Algeria, gas flaring appears to be systemic within the sector and its minimization should be viewed within the context of how policy priorities could be changed to reduce flaring (e.g. giving AG priority over NAG in meeting demand) and strengthening the enforcement by regulatory authorities over flaring. • As the Paris Accord requires limits on Algeria’s GHG emissions, analysis and capacity building on how those GHG limits should be integrated into the investment and operating decisions in the O&G sector, especially for Sonatrach and for the appropriate regulatory agencies. • While data is thin, the WB/GGFR data suggests that substantial flaring exists within the overall process and transportation components of the O&G sector, not just at the oil fields. Considerable knowledge could be added by making an accurate GHG footprint of the sources and volumes of GHG throughout the sector so as to focus on GHG reduction priorities. To do so would require the full cooperation of the Ministry and Sonatrach. • Technical assistance on individual flaring projects appears to add little value. The three projects identified have had well-defined technical solutions for more than a decade. The failure to implement lies with financial or other barriers, not a lack of technically appropriate options.

1 The Ministry is often referred to as the Ministry of but on the Ministry and OPEC websites, the official name is listed as Ministry of Energy and Mines. 4

• Despite appropriate legislation, the enforcement of gas flare regulation appears weak. This could be an area deserving of international assistance, but to be effective the government would need to assure the independence and effectiveness vis-à-vis the state oil company.

Germany provides considerable assistance in support of the Paris Accord and the Nationally Determined Contributions (NDC) developed by the individual countries. Based on the Algerian experience, an argument could be made that technical assistance could focus on helping to measure and quantify the sources and quantities of GHG emissions (such as in the O&G sector) to help set priorities in the implementation of the NDCs.

3.0 Country Context

Algeria is the largest gas producer in as well as being its third largest oil producer 2. The importance of the oil and gas sector to the country’s economy is demonstrated by the fact that it represents approximately 30% of GDP, 60% of government revenues, and almost 95% of export revenues. The O&G infrastructure is well-developed and extensive, moving gas from fields in the central and south-eastern deserts to the central oil and gas hubs, and thence to domestic and international markets (See Appendix 1 for an O&G infrastructure map). For the EU, the country plays a vital role in gas imports, providing almost 12% of imports in 2017 (see Figure 1).

Figure 1: 2017 Extra-EU Imports of Gas from main trading Partners.

Source: Eurostat database

The system is anchored by the two giant fields -- the Hassi Massaoud oil field that still contributes almost 40% of Algerian production and the Hassi R’Mel gas/condensate field that is the largest gas source.

The country ranks fifth in the GGFR’s listing of global flaring countries and the flaring is a major component of the country’s GHG emission. While major flaring reductions have occurred since the 1990s, flaring has increased slightly in the last four years.

2 IEA as cited EIA 2016 5

Despite this increase, the Minister of Environment recently stated an aggressive objective to reduce flaring from a current level of 6% to 1% (presumably of gas produced) by 2020 3 (This is also stated as the 2030 objective in the NDC).

The gas supply/demand market in Algeria is in a sensitive position. Traditional gas supplies from older fields are under stress both by natural field decline and increasing need for upstream pressure maintenance. These factors have caused the government to focus on gas production and have led to several major new investments for non-associated gas production. Several of these projects came on stream in 2016-2018 allowing for a significant increase in production, which contributed to gas exports increasing by 20% over the last five years. Nevertheless, these projects being designed for NAG have had no noticeable impact on reducing flaring.

4.0 Gas Flaring in Algeria

4.1 Magnitude and directio n of gas flaring and GHG emissions

Starting in the 1990s, Algeria developed a stringent program that brought down associated gas (AG) flaring from 33% of the gross natural gas produced in 1995. 4 Historically the high flaring levels were due to the high gas-to-oil ratios (GOR) for the oil fields (many of which would be considered condensate fields) and production focused solely on the high value oil. This has changed as gas became valuable both for the domestic market and internationally. The construction of gas pipeline infrastructure (both domestic and international) and (LNG) infrastructure made the commercialization of large volumes of gas possible (See Note 1). However, as Algeria has major non-associated gas (NAG) fields, gas demand could be met without connecting smaller or higher cost flares, and such flaring continues to this day.

Data over the last five years shows that flaring in absolute volumes is largely stable (See Figure 2).

Figure 2: Current Trend of Gas Flaring and GHG emissions

350 25

300 20

250 15 Bscf

200 10 MMtCO2e

150 5

100 0 2012 2013 2014 2015 2016 2017 2018

AG Flaring (Bscf) AG Flaring(CO2+CH4)

Note: GHG emissions are estimated by 98% of the gas being combusted and 2% un-combusted methane released into the atmosphere Source: GGFR/NOAA Data and CLN

3 Réduction de ses émissions de gaz : L’Algérie réclame des aides financières http://www.lactualite-dz.info 4 EIA 2016 6

During the mission, it was noted that the GGFR flare estimates and those used by Sonatrach were substantially different. Sonatrach estimates that around 4% of total AG production is flared (flaring in first half of 2018 is 1.2 bcm while flaring for the full year of 2017 is 2.9 bcm). This is significantly lower than GGFR/NOAA estimate of 8.8 bcm in 2017.

Part of the reason may be that the location of flares from the NOAA satellite data indicates that substantial gas flaring occurs at the major oil hub of Hassi Messoud and the gas hub Hassi R’Mel as well as Azrew on the Mediterranean coast where the LNG and shipping facilities are located (Figure 3). Thus, the difference in flaring could relate to the distinction between the gas flaring that occurs throughout the entire oil/gas production and supply chain (presumably the GGFR estimate) and the AG flaring that occurs only at oil fields (presumably the Sonatrach estimate).

The flaring at oil fields distant from gas infrastructure (such as the three proposed projects) would likely be flared AG. The flaring at the two major hubs and Azrew are counter-intuitive for AG flaring in that major gas infrastructure, including pipelines and compressors, are available to take gas to market at those very sites.

Figure 3 Location of gas flares and magnitudes in Algeria

Natural gas is an important component within the Algerian oil and gas sector. Importantly many of the aging major oil fields require large amounts of pressure maintenance to reduce and manage natural decline, a situation that requires increasing over time (See Figure 4).

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Figure 4 Principal Uses of Gas in the Algerian O&G Sector

100

Bcm Net production 80 Shrinkage 60 Flared Reinjected 40

20

0

-20

-40

-60

-80

-100 1962 1966 1970 1974 1978 1982 1986 1990 1994 1998 2002 2006 2010 2014

Source: Aissaoui 2016

In examining the flaring in Algeria, an important consideration is that the gas system is very complex and that while some oil fields flare AG simply because of being distant from infrastructure, other flaring may be driven by the industrial processes for treating and transporting oil and gas, or even infrastructure barriers further up the supply chain (This is however only a hypothesis as no specific details on the flaring were provided). This implies that flaring could perhaps be more fully addressed by looking at the issue from a system basis, and not just at individual, upstream flares.

4.2 Specific Upstream Gas Flare Reduction Projects

Regarding investments in gas flaring, in March 2017 the Ministry of Environment stated that Sonatrach had worked on 32 projects to reduce flaring and one project to sequester CO2 5 (no details were provided).

During the October mission, three projects were specifically brought up by the Algerian officials as being high priority as AG flare reduction projects. These are the same three projects that were the focus on a 2003-2005 WB/GGFR project. Given this history, it is worth reviewing the WB/GGFR project and its results.

In 2003-2005, the WB/GGFR partnering with Sonatrach conducted a major gas flaring study. When the project began the WG/GGFR had only recently been established and the Kyoto Protocol was not yet in effect. At that time, it was not known how gas flare reductions would be viewed as to CDM eligibility and if so, what the parameters of any future CDM methodology would be. While the project had major components related to capacity and institutional building, the primary activity related to identification and analysis of actual gas flaring locations operated by Sonatrach so as to assess the technical options and GHG impacts of eliminating the flaring. These results were also to help in developing a CDM gas reduction methodology.

What makes this project especially relevant is that the three gas flaring projects identified and assessed are the same three projects put forward by Sonatrach during the October 2018 mission.

5 Réduction de ses émissions de gaz : L’Algérie réclame des aides financières http://www.lactualite-dz.info

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During the 2018 mission, Sonatrach did not provide quantitative flaring or other data but stated that the most likely option to reducing the flaring was to capture the gas and transport it to market, the same technical option as before (Table 1).

Table 1: Gas Capture Projects Proposed by Sonatrach in both 2005 and 2018

Gas Project 2005 Description of Project 2018 Status The project captures and transports the Ohanet – Gisement de Pétrole et Gaz flared gas from 6 seperate reservoirs to Associés existing gas transmission lines The project captures and transports the All projects continue to flare and the preferred In Amenas – Gisement de Pétrole et Gaz flared gas from 4 seperate reservoirs to option contiunes to be gas capture and transport to Associés existing gas transmission lines market The project captures and transports the Tin Fouye Tabankort (TFT) – Gisement flared gas from 3 seperate reservoirs to de Pétrole et Gaz Associés existing gas transmission lines

All these fields have been on production for decades and are on natural decline. Available information indicates that the natural decline rate is in the 3-5% level -- which implies the current AG production is between one-third and one-half less than when the WB/GGFR study was conducted. Indeed, the flaring could be even less as a fixed proportion of the gas is used for on-site energy before flaring.

All the three fields are in the same general south-western part of the country, near the Libyan border, meaning they are the end of the principal oil and gas infrastructure (Figure 5, p. 10). Security concerns are very real. In January 2013, militants seized control of the Tigentourine gas plant during a four-day siege where dozens of hostages were killed.6 The plant processes NAG from gas reservoirs in the In-Amenas field complex (the same area as the three fields discussed). The plant is a joint venture operated by Norway’s (owned by Statoil at the time), with BP and Sonatrach as partners.

The comparison between the projects over time has important implications as to the importance of these projects in reducing flaring, specifically:

• GHG impacts: Given the almost certain natural decline of AG over time, the impact of the projects on reducing GHG emissions would be significantly less than in the GGFR study. • Project Design: In the GGFR study, the technical design was at the early concept stage, but gas capture and transport were assessed as the most attractive option, this appears to continue to be the case. • Infrastructure and Investment: Since the gas volumes have decreased, the infrastructure needed for the gas capture project would likely be little affected, which with the lower gas volumes and field pressure could require more compression capacity – the highest cost component. This implies that investment per cubic meter of gas captured has increased, perhaps substantially. • Economics: In the initial GGFR project, the economics of the gas capture projects were marginal and thus the importance of earning and selling carbon credits related to the GHG reductions. Given the substantially lower gas volumes, the economics could well be even more marginal, and any value of carbon credits is speculative. • Security, while an issue in 2005, is a greater issue today and must be considered in assessing options.

6 Armstrong, H “The In-Amenas Attack in the Context of Southern Algeria’s Growing Social Unrest” CTC Sentinal, Volume 7, Issue 2 https://ctc.usma.edu/the-in-amenas-attack-in-the-context-of-southern-algerias-growing-social-unrest/

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Figure 5 Location of the Proposed Flare Projects in Relation to Existing O&G Infrastructure

Source: Modified and expanded version based on ALNAFT 2013 7 (The full map is included in Annex 1)

It should be noted that several major gas projects have been implemented over the last few years and have successfully increased gas production, however these projects have apparently been exclusively focused on NAG and that little effort has been made toward capturing AG and reducing flaring. Such a policy is likely driven by the higher economic returns related to NAG and imply that GHG reduction and non-flaring policies are not having the desired effect.

5.0 Structure of the Algerian Oil and Gas Sector

5.1 Principal Actors and Stakeholders

The modern Algerian energy sector was born of the 1971 nationalization of the French-owned assets in the oil sector. Sonatrach was set up and given the responsibility for the full development and operation of the sector, albeit state control has been relaxed over time to bring in Production Sharing Contracts (PSC) with private international oil companies so as to tap their expertise and finance. In the PSCs, Sonatrach typically holds a 51% non-operating interest in the PSC blocks.

7 Alnaft website: http://www.alnaft.gov.dz/images/outils/outils/CARTE_DE_RESEAU%20_DE_TRANSPORT_DES_HYDROCARBURES_TRC_201 3.pdf (25/03/2019) 10

There are many actors in the oil & gas sector, but the Ministry of Energy and Sonatrach acting together are the dominant players. The sector is of such economic importance to the country, the Presidency is assumed to take a direct role in all major decisions. As the de facto implementer of oil and gas policy, Sonatrach has a pervasive role and is the implementer of government policies.

In 2005 Hydrocarbons law took away Sonatrach’s direct regulatory role in the sector and assigned it to two agencies. Figure 6 illustrates its current organizational structure.

Figure 6 Schematic of Principal Algerian Oil & Gas Sector Actors

Algeria Oil & Gas Sector

Ministry of ALNAFT Energy & Mines (Regulator)

Oil & Gas Resources Flaring Volume State Share Appionted Own Operations, Management 100 % 80 % of Oil & Gas Almost all Resources, Primarily Sonatrach (State Oil Company ) 51 % Responsibl e for flaring Private Operators, Minor 20 % of Oil & Gas permits and collecting Resources, Newer Fields of flaring fees

Note: The % share of oil and gas resources are generally reported estimates. Sonatrach does not provide this information. Annex 2, Note 3 shows the major stakeholders involved in flaring and their roles.

Source: CLN

The Ministry of Energy and Mines

The Ministry is the dominant player in the Algerian energy sector via its policy and administrative role and has direct supervision over Sonatrach. It also has major influence on the regulatory agency.

Sonatrach

Sonatrach, dominates the country's hydrocarbon sector, owning roughly 80% of all hydrocarbon production as well as most and downstream infrastructure. While private companies play an important role, Sonatrach is the largest field operator. By law, the company is granted the majority ownership of oil and natural gas projects but is not the operator in PSC contracts.

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In 2017, Sonatrach had revenues of 33.2 billion US$, an increase of 19% from 2016 (driven primarily by the higher oil price). The company’s substantial assets make it the largest oil and natural gas company not only in the country, but also in Africa.8

Regulators

Two regulators exist; National Agency for the Valorization of Hydrocarbon Reserves (ALNAFT) and Hydrocarbons Regulatory Authority (ARH) both created under the 2005 Hydrocarbons Law.

National Agency for the Valorization of Hydrocarbon Reserves (ALNAFT)

ALNAFT is primary regulatory agency in the O&G sector and has the responsibilities for gas flaring matters including the issuing of permits for flaring (on an exceptional basis) and collecting flare penalties. The gas flaring fee was set at 8000 dinars/000m 3 in 2005 and with periodic adjustment was reported during the mission to now be set at 20,000 dinars/000m 3.

ALNAFT has broad responsibilities, and its website 9 lists the following;

• Evaluate the hydrocarbon mining sector by carrying out basin studies, • Promote investments in hydrocarbon research and exploitation, • Manage and update the database on hydrocarbon research and exploitation under the responsibility of the Minister in charge of hydrocarbons, • Study and approve development plans and their periodic updates and the granting of prospecting authorizations, • Call for tenders and evaluate tenders for research and / or exploitation activities and conclude contracts, monitor and control, as a Contracting Party, the execution of research contracts and/or exploitation in accordance with the provisions of the Hydrocarbons Act, • Ensure that the exploitation of hydrocarbon resources is carried out respecting optimal conservation, • Collaborate with the departments of the Ministry in charge of hydrocarbons in terms of sectoral policy and the drafting of regulations governing hydrocarbon activities, • Monitor, control and audit the costs related to the activities covered by the research and / or exploitation contracts, • Determine and collect royalty and proceed to its repayment to the Treasury, • Ensure that the operator has paid the petroleum income tax (TRP) and the land tax, as well as, if applicable, the payment of taxes relating to the flaring of gas and the use of water, • Collaborate with the tax administration for the exchange of tax information concerning research and/or exploitation contracts, • Consolidate a medium and long-term plan for the hydrocarbon sector, based on the medium and long-term plans of the contractors, and send it annually to the Minister in charge of hydrocarbons, • Maintain and update a state of gas reserves, a state of gas requirements for the satisfaction of the national market and a statement of the quantities of gas available for export, • Ensure that the supply of the national market is assured by the contractors, • Periodically determine a gas reference price and the basic prices of exported products (crude oil, condensate, LPG).

Interestingly in these fifteen specified responsibilities, while “optimal conservation” is mentioned, no direct reference is made of flaring or venting, nor the setting or collection of flaring fines and fees.

8 EIA 2016 9 Alnaft website: http://www.alnaft.gov.dz (01/11/2018) 12

The Agency is under the supervision of a five-member Management Committee. The members are nominated by the Minister of Energy and Mines and appointed by Presidential decree.

While a strong legal framework on flaring is in place and flaring fines are high, in 2011 the WB/GGFR noted there was little evidence of monitoring, reporting, and tax collection and this may in part be attributable to the political power of Sonatrach. 10

Hydrocarbons Regulatory Authority (ARH)

ARH implements and enforces regulations related to technical and transportation tariffs as well as free access to oil and gas infrastructure. It also oversees the implementation of environmental regulations in the hydrocarbon sector, specifically:

• designated to take charge of control and regulation of mission activities in the field of hydrocarbons as well as issues related to industrial safety and the environment • oversees the transparent operation of natural monopolies, non-discriminatory third-party access to pipeline and storage systems, and the regulation of margins on the domestic market for natural gas and petroleum products • develops and updates an indicative supply program for the domestic market in petroleum products • authorizes concessions and manages and monitors them. Similarly, it authorizes storage and/or distribution activities of petroleum products • safety inspections of hydrocarbon facilities • ensures compliance with the regulations applicable to hydrocarbon activities, including on- shore and off-shore activities and approves Environmental Impact Assessments. 11

Despite these wide-ranging responsibilities, it does not appear that ARH has any direct role regarding flaring or venting (except on a safety basis).

Private O&G Companies

Private companies play a notable role in the O&G sector, especially related to investment and development of new hydrocarbon resources. While flaring data per company is not publicly available, their total flaring amount is believed to be much lower than that of the state company. They all operate in close cooperation with Sonatrach. The most active companies include Anadarko, , BP. Other include CEPSA, , Total, and Equinor.

Anadarko is the biggest international oil company operating in Algeria. It signed production-sharing agreements with Sonatrach in the late 1980s and since then has produced oil from three mega projects located in the Desert. The company has recently completed a project at its El-Merk facility that minimizes flaring by reinjection of the AG.

BP focuses on gas and operates two major NAG fields: In-Salah and In-Amenas. The In-Salah gas has a high CO 2 content, and BP undertook a major project to remove the CO 2 and reinject the gas into the field. In-Amenas has recently completed a major expansion of its production.

10 WB/GGFR Presentation, 2011, “ International Practices in Policy and Regulation of Flaring and Venting in Upstream Operations” http://siteresources.worldbank.org/INTGGFR/Resources/578035-1164215415623/3188029- 1324042883839/1_International_Practices_in_Policy_and_Regulation_of_Flaring_and_Venting_in_Upstream_Operations.p df 11 ARH website: http://www.arh.gov.dz/index.php/fr/ (01/11/2018) 13

ENI has major investments in both oil and gas. ENI also imports gas via the Enrico Mattei Algeria-Italy pipeline, making it a major customer as well as producer of Algerian gas. 12

In recent years, Algeria has had difficulties attracting foreign investors. In the most recent licensing round in 2014, only 4 of 31 blocks were awarded, and no additional licensing rounds have occurred since. Some analysts believe that the lack of fiscal incentives to attract foreign investors to new projects, coupled with past Sonatrach corruption allegations, are to blame. Algeria's precarious security environment has also been a concern for investors.

Several projects are in the planning and development stage, albeit several of these have had their implementation dates postponed in the past. (Note 4)

5.2 The Gas Market

Domestic Gas Market

According to the International Energy Agency, natural gas accounted for 93% of power generation in Algeria in 2013. 13 Algeria has an important initiative regarding expanding renewables in the electrical sector, which will impact gas demand, but this is only now beginning. The Electricity and Gas Regulation Commission (CREG) forecast for the decade 2014 - 2023 (considering the renewables program) estimates gas demand growth of 5.2%/year in a central scenario, resulting in a demand of 54.6 bcm in 2023. If the renewables program is implemented successfully, growth in gas demand would start to moderate mainly post- 2023. Using these parameters, the 2030 gas demand could be 70 bcm, representing a major claim on Algerian gas production. 14

It should be noted that there are substantial subsidies and price distortions in the sector, and policy adjustments could have significant impacts in limiting future demand.

International Gas Market

As of 2016, Algeria was the seventh largest exporter of LNG in the world as well supplying gas via international gas pipelines. Algeria has four LNG units along the Mediterranean Sea with a total design capacity to process 44 mt/year of natural gas plus three pipeline connections – the largest to Italy and two smaller ones to Spain.

Until recently Algeria's natural gas exports have gradually declined, apparently limited by both gross production decreases and domestic consumption increases. In 2017 however, natural gas exports were 53 bcm, a major increase over the last several years, driven by increased pipeline exports to Europe 15 . Algeria faces pressure to boost natural gas output so at to meet growth in domestic demand and maintain its international gas markets (See Note 2 on issues in Algerian gas production).

5.3 Legal and Regulatory Framework for Gas Development and Valorization

Oil and gas activities in Algeria were governed by law number 86-14 of 19 August 1986 until replacement with law n°05-07 dated 28 April 2005 (Hydrocarbon law) that liberalize to some degree the sector. To further attract foreign investors to exploration and development of unconventional hydrocarbons, the laws were amended (n°13-01 dated 20 February 2013). These laws apply to both

12 Information on all four private companies is from the companies’ websites 13 Cited in EIA 2016 14 Aissaoui A, 2016 15 BP 2017 14 upstream and downstream oil and gas activities. Key points to note with regards to these laws could be summarised as follows:

Ownership oil and gas reserves: Article 3 of law n°05-07 of 28 April 2005, states that Government owns all oil and gas reserves. This was relaxed in 2013. In Article 25 of law n°13- 01, oil and gas reserves are State’s property until they are extracted, and title of minerals transferred to the contracting party.

Hydrocarbon contracts and State participation: Article 24 of the law referred to ‘Exploration and Exploitation Contract’ usually awarded after transparent and competitive tender exercise as approved by decree. These contracts have state participation clause with minimum equity stake not less than 51%. The state does not bear the cost and the risk of exploration.

License duration: According to article 35 of the law, exploitation period is 25 years for oil and 30 years for gas in conventional zone while unconventional zone, 30 years for oil and 40 years for gas.

Gas Flaring: Amended slightly in 2013, gas flaring is prohibited, but the Government on exceptional basis and at operator’s request could grant Flaring Permit (FP). Contrary to the previous law, duration of the FP is no longer set. Revised article 52 of the law allows quantity of gas that can be flared, and flaring permit details set by ALNAFT by decree, on case by case basis. The gas flaring prohibition law does not make distinction between existing AG fields and new oil developments.

During the mission it was confirmed that the flare fine was 20,000 dinars/m 3, however the granting of exemptions and its enforcements was not clarified.

Gas Master Plan: This requirement is dictated by the law. According to Article 62 of the Hydrocarbon law, a ten-year Gas Master Plan shall be drafted by ALNAFT and regularly updated.

Domestic Market Obligations and Gas Sale Contracts: Article 51 of the Hydrocarbon law, states ALNAFT could ask gas producer to help meet national market with respect to their production.

For Gas Sale Contracts, two regimes are bound by the Hydrocarbon law: For sales on the local market, the sale price is determined by ALNAFT considering a series of criteria listed in Article 10 of the Hydrocarbon Law (market-based energy pricing).

Gas intended to be traded on international market, and in accordance with Article 48 of the Hydrocarbon law, the gas sale contracts must contain; a joint sale clause with SONATRACH and copies of these contracts must be sent to ALNAFT for verification and information purposes.

Fiscal incentives: to encourage gas utilization investments, special fiscal treatment such as investment tax credit or uplift or reduced rate for corporate tax is applied to LNG, LPG and electricity generation projects (see Articles 88 and 91 of the Hydrocarbon Law).

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6.0 Geological and Production Technical Issues

Most proved oil reserves are in the country's oldest and largest oil fields. , located in the eastern part of the country, near the Libyan border, is estimated to hold 3.9 billion barrels of proved and probable recoverable reserves, followed by the Hassi R'Mel field (3.7 billion barrels) and the Ourhoud field (1.9 billion barrels).16 According to Sonatrach, the Hassi Messaoud- Dahar province contains about 71% of the country's combined proved, probable, and possible oil reserves, while the basin, the second-largest area, contains about 15%.

Oil and gas fields are largely located on a northeast of a northwest-southeast-trending line connecting Hassi Messaoud with In-Amenas. Recent discoveries have been made in upper Paleozoic and Mesozoic reservoirs. Hydrocarbons are present throughout the entire sedimentary column, but major production currently is restricted to the lower Paleozoic (Cambrian-Ordovician and Lower Devonian) and Triassic reservoirs. Algerian oil fields tend to be high-quality with very low sulfur content. 17

The Basin, encompassing eastern Algeria, southern , and western , has been identified as a major basin. Algeria is estimated to hold the third-largest amount of shale gas resources in the world. The U.S. EIA estimates that Algeria contains 707 trillion cubic feet (Tcf) and 5.7 billion barrels of technically recoverable shale gas and oil resources 18 .

Preliminary exploration work for the shale has been undertaken, but the costs and barriers of development (including sufficient water) cause uncertainty as to its future development.

As to the composition of the gas, both AG and NAG tends to be of good quality – meaning no significant impurities and relatively high energy content. The gas tends to have a relatively high percentage of higher carbon molecules, C 3 and above, but not excessively so. Extraction of C3+ generally occurs at treatment hubs, which suggests that AG flared at the field includes the NGLs.

In one case, the in-Salah project operated by BP, the NAG has a high concentration of CO 2, 7%; significantly above the 2% that is allowed in the gas market. The CO 2 is stripped out (0.3% remaining) and instead of being vented, is reinjected into a sealed reservoir. This is the only one of such CO 2 reinjections in Algeria, and one of the very few in the world. 19

16 Arab Oil & Gas Directory cited in EIA 2016 17 Attar, A., Chaouch A, of the Major Producing Basins of Algeria, AAPG 1988, and EIA 2016, 18 EIA 2015 19 Fairly, P., 2008, “Algerian Carbon Capture Success”, MIT Technology Review https://www.technologyreview.com/s/411417/algerian-carbon-capture-success/ 16

Annex 1: Map: Oil and Gas Infrastructure in Algeria

Source: Modified and expanded version based on ALNAFT 2013 20

20 Alnaft website: http://www.alnaft.gov.dz/images/outils/outils/CARTE_DE_RESEAU%20_DE_TRANSPORT_DES_HYDROCARBURES_TRC_201 3.pdf (25/03/2019) 17

Annex 2: Notes and Illustrations

Note 1: Flared Gas vs. Gas Production

Source: Toledano P

Note 2: Issues Related to Algerian Gas Production

While the decline in Algerian gas production has been well observed, the general belief is that it has been brought about by natural production depletion decline in the old, mature fields and that it could be easily reversed by bringing on new gas production. Indeed, this seems to be the government policy. However, Ali Aissaoui in a paper produced under the Oxford Institute for Energy Studies sees a much more problematic situation.

He notes that since 2004, Algeria’s demand grew at an average annual rate of 4.1% while domestically-sourced decreased by 0.8%/year, resulting in a contraction of total hydrocarbon export volume of 2.6%/year. Natural gas flows are impacted as well. Their decline is first noticeable in gross production, which dropped from 201.2 bcm in 2008 to 179.5 bcm in 2013 before slightly improving to 186.7 bcm in 2014 as and El Merk (associated gas) came on- stream. ( It does improve in 2016, CLN ).

Importantly wet natural gas production in Algeria is cycled for liquids content and that the bulk of this process takes place in Hassi R’Mel. Once stripped of NGLs, gas is partly re-injected to maintain stable reservoir pressure and avoid retrograde condensation and the excess dry gas is then supplied to the domestic and export markets.

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It can be inferred, from the declining trends in gross production and the volumes of gas re-injected, that there may not have been enough raw gas to maintain the cycling process at its optimum level. (Indeed, with the continued depletion of the oil reservoirs, the reinjection level could grow substantially CLN ). This in turn suggests that, notwithstanding additional volumes supplied during the last decade from Ohanet, In-Salah, In-Amenas, Gassi Touil, El-Merk and Menzel Lejmat, production is on a clear decline.

Cost of gas production is also raising. Assuming existing fields are producing at plateau levels, a weighted-average unit cost of production is about $0.60/MMBtu. Obviously, the cost is higher – up to $0.70/MMBtu - if we assume lower production rates from depleting mature fields, which is closer to reality. As for the long run marginal cost of supply it may be approximated by the unit cost of production from the upcoming, most expensive tight-gas project, i.e. Timimoun, at $4.70/MMBtu.

These trends in both volumes and costs have raised concerns over the depletion of easily accessible gas with low production costs and have prompted a serious review of the country’s reserves and resources.

Note 3: Key Stakeholder s on Flaring in the Algeria’s O&G Sector

Stakeholders Who they are Influence on Flaring Policy, strategy and administrative Ministry of Ultimate decision maker oversight for the sector. Directly Energy & Mines controls Sonatrach Partner GGFR State O&G company, controls 80% Decisive. Sonatrach support of production 21 : interests in necessary for flare reduction; Sonatrach remaining 20%, by far largest flare largest flare source operator Partner GGFR & ZRF 2030 Regulators Grants permits for flaring Has mixed priorities, and ALNAFT exemptions and collects flare limited power penalties Oversees tariffs and free access regulations as well as Minor role, unclear as to ARH environmental regulations effectiveness including CO2 emissions. Private Companies Flaring appears limited to International, public O&G Multiple operational, generally follow companies Sonatrach direction NGOs None identified, O&G sector

considered national security area

Donors Very active prior to 2010, limited WB/GGFR activity now

Source: CLN

21 Sonatrach does not provide breakdowns between oil and gas production, but for both categories the share is believed to be in the 80% range. 19

Note 4: Planned Gas Projects -- 2016

Peak output Target start Project name Companies (Bcf/y)1 year South West Gas Project: Phase 1 Touat Engie/Sonatrach 155 2016 Reggane Nord Repsol/Sonatrach/DEA/Edison 155 2017 Timimoun Total/Sonatrach/Cepsa 64 2017 South West Gas Project: Phase 2 Ahnet Total/Sonatrach/Partex 141 2018 Hassi Ba Hamou Sonatrach 64 -- Hassi Mouina Sonatrach 49 2018 Other Gas Projects (expansion)2 BP/Sonatrach 500 2016 Isarene (Ain Tsila) Petroceltic/Sonatrach/Enel 127 2018 Tinhert, Illizi basin Sonatrach 332 2018 Menzel Ledjmet SE Sonatrach 155 2019 1 Billion cubic feet per year is Bcf/y. 2 Field expansion at In Salah is to ensure that the current level of output at In Salah is maintained. Source: Middle East Economic Survey

Source: EIA 2016

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Note 5: Major Sources

Aissaoui A. “Algerian Gas: Troubling Trends, Troubled Policies” Paper: NG 108, Oxford Institute for Energy Studies, Oxford, May 2016

Bengrina M. H., Sigra A.R. L’étude d’impact environnemental – facteur de valorisation des ressources gazières de l’Algérie ou entrave bureaucratique , presentation at International Workshop on Global Gas Markets, , 1-2 December 2014

Klett T.R. Total Petroleum Systems of the , Algeria and Libya—Tanezzuft-Illiz , United States Geological Survey, Denver Colorado, 2000

Sonatrach HSE, “Efforts de SONATRACH dans la réduction des gaz à effet de serre ” presentation at Salon International des Energies Renouvelables, des Energies Propres et du Développement Durable, Oran, 27-29 October 2015

Toledano P., Karishma P., Banerjee S. “Algeria: Associated Gas Utilization Study”, presentation at Columbia Center for Sustainable Investment, New York, May 2017

US Energy Information Agency (EIA) “Technically Recoverable Shale Oil and Shale Gas Resources: Algeria” September 2015, Washington DC

US Energy Information Agency (EIA), “Country Analysis Brief, Algeria” March 2016, Washington DC

World Bank GGFR: “CDM Capacity Building Pilot Projects for Gas Flaring Reduction in Algeria, 2004

(other sources noted in footnotes)

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