“Designing a Distinct and Incentive Driven Legal

and Regulatory Regime as a Means towards

Investment Surety: Making the Case for

Natural Gas in Developing Economies”

A Dissertation by Marcia Ashong, Submitted to the Centre for Energy, Petroleum

& Mineral Law and Policy, University of Dundee.

2011

Contents ABSTRACT……………………………………………………………………………………………………..I

ABBREVIATIONS…………………………………………………………………………………………......II

TABLE OF

FIGURES……………………………………………………………………………………….........................III

CHAPTER 1: INTRODUCTION………………………………………………….................................................1

CHAPTER 2: STATUS OF NATURAL GAS……………....................................................................10

2.1. Gas Worldwide……………....................................................................................................10

2.1.1. Significance of Future Reserves……………..........................................................13

2.2. Natural Gas Specific Issues & Challenges…..........................................................................13

2.2.1. Associated vs. Non-Associated…......................................................................13

2.2.2. Associated…...................................................................................................14

2.2.3. Non-associated…............................................................................................ 16

2.2.4. Volume Risk Allocation…................................................................................17

2.3. Gas Market Considerations: Obstacles for Regulations….......................................................18

2.4. LNG Opportunities and Challenges…...................................................................................20

CHAPTER 3: SECTOR SPECIFIC APPROACH............................................................................22

3.1. Power................................................................................................................................22

3.2. Mining Sector....................................................................................................................23

CHAPTER 4: LEGAL & REGULATORY MEASURES & RISK MITIGATING INCENTIVES........24

4.1. Legal Instruments...............................................................................................................24

4.2. Risks and Legal Arrangements............................................................................................26

4.2.1. Exploration Risks and Legal Arrangements..................................................................26

4.2.2. Development and Production Risks and Arrangements..................................................29

4.3. Nature of Gas Clauses........................................................................................................36

4.3.1. Broad Policy Principles: Ghana Case Study..................................................................38

4.4. Gas Specific Regulation and Government Control.................................................................42

CHAPTER 5: PETROLEUM LICENSING & NATURAL GAS..........................................................47

5.1. Evolution of the Licensing System......................................................................................47

5.2. Petroleum Licensing Today................................................................................................50

5.3. Allocation of Petroleum Prospective Acreage......................................................................52

5.4. Bidding Terms..................................................................................................................55

CHAPTER 6: EVALUATING LICENSING POSSIBILITIES: LESSONS FROM MINING AND

POWER.....................................................................................................................................57

6.1. Designing a Legal Framework for Allocating Natural Gas Rights Lessons from the Mining and

Power Sectors................................................................................................................57

6.1.1. Form of License...............................................................................................61

CHAPTER 7: CONCLUSION.....................................................................................................64

BIBLIOGRAPHY........................................................................................................................66

ACKNOWLEDGEMENT

In life it is often said that “no man is an Island.” Well such a phrase became more glaring

throughout the period of my studies at the CEPMLP (as we have all fondly come to know of

it). It is without a doubt that a Masters degree in Law is turbulent enough but to couple that

with a specialised area (that is, Energy) with all the curve balls life can through at one, it

would have perhaps been suicidal to consider taking such a journey without bearing in mind

that indeed no man is an island.

So it was perhaps my most joyous moment during writing this piece when I discovered that

“aha I will indeed get to thank those that have stuck with me through this vital period of my

life.” First and foremost I want to say a big thank you to my fellow students, without you,

waking up every day would not have been the same – and it is safe to say that through this

short period of our lives we all become brothers and sisters. I am even more excited to know

that no matter where I go in the world I know that I will have a friend just around the corner.

I also want to take this opportunity to thank Mrs Janeth Warden-Fernandez – until I met you,

I was soon forgetting what it really meant to have a teacher; it was translated very eloquently

in English once that “a good teacher is like a candle – it consumes itself to light the way for

others.” This is what you have been to me, and you will continue to hold a very dear place in

my life. I also wish to express my deepest gratitude to Prof. David Cameron and Mr Stephen

Dow, Prof. Cameron, your dedication to your students has been unwavering thank you for

your support through the highest and lowest points, and may you continue to prosper in your

endeavours. Mr Dow, until I attended your lectures, I never knew that years later I would still

be daydreaming about sitting in Mr Dows lecture, you have an uncanny way of delivering

knowledge and most importantly I am eternally grateful for all the humour-filled support you

have given me, and the patient guidance you have afforded me throughout the writing of this

dissertation.

I dedicate this to my mother and my family, most importantly to my beloved grandmother

who recently passed. I pray that I continue to live in her light and go through life with the

same unapologetic vigour she did.

I

ABSTRACT

This research stems from recent developments in the world natural gas markets, exciting

developments that will see surging interests for natural gas in the coming years. In 2009

natural gas reserves were approximately 82% of oil reserves, yet gas consumption was only

approximately one-fifth of oil consumption, moreover, there is a trend showing an increase in

natural gas demand as evidence points to its premium qualities among which is its carbon

emitting benefits.

These trends however, have not necessarily corresponded with sharp increases in natural gas

development projects; the case even more glaring in gas rich emerging economies, some of

whom have commercially recoverable reserves of natural gas, enough to contribute to

national development agendas as well as upstage their importance in the global energy

markets. Even more pressing is the case that the natural gas legal and regulatory frameworks

in these regions remain inefficient for attaining the goals envisaged by policy-makers.

The paper takes stock of the challenges and to rectify the underlying issues, the approach

taken is to attempt addressing them by offering recommendations for the design of regulatory

and licensing regimes, recommendations which attempt to solve these issues from the

perspective of gas rich developing economies- that is, economies where the natural gas

market is either lacking or non-existent. These recommendations it is hoped, would be a

means towards establishing not only a natural gas market but also addressing the concerns of

investors; towards a market which balances both private and public sector concerns.

II

ABBREVIATIONS

AG Associated Gas

BOT Build Operate Transfer

DGO Domestic Gas Obligation

DMO Domestic Market Obligation

E&E Exploration and Exploitation

EGPC Egyptian General Petroleum Corporation

E&P Exploration and Production

ERT Enhanced Recovery Technique

GDE Gas del Estado

GNGC Ghana National Gas Company

GOG Government of Ghana

GSA Gas Sales Agreement

GTP Gas Transfer Price

HC Host Country

HG Host Government

IEA International Energy Agency

IMF International Monetary Fund

IOC International Oil Company

LNG Liquefied Natural Gas

LCV Local Content Vehicle

MIGA Multilateral Insurance Guarantee Agency

NGDT National Gas Development Task Force

NNPC Nigeria National Petroleum Corporation

NOC National Oil Company

OECD Organization for Economic Co-operation and Development

III

OML Oil Mining Lease

OPL Oil Prospecting License

PA Petroleum Agreement

PEMEX Petroleos Mexicanos

PSC Petroleum Sharing Agreement

SA Service Agreement

TOP Take or Pay

US United States of America

UK United Kingdom

YPF Yacimientos Petroliferos Fiscales

IV

TABLE OF FIGURES

Figure 1 Gas Flaring Volume

Figure 2 Nigerian Gas Utilization and Flaring

Figure 3 Nigerian Gas Utilization Forecast

Figure 4 Proven Gas Reserves by Region

Figure 5 Natural Gas Value Chain

Figure 6 Agreements and Risk Distribution Diagram

Figure 7 Commercial Agreement Matrix

1

1. Introduction

Natural gas has become quite the commodity in recent years, it was largely a misunderstood

fuel fighting to find its place as a petroleum commodity but hitherto rarely getting the equal

amount of attention afforded to oil. Nevertheless, it is of little surprise that the demand for

natural gas has increased significantly in the past two decades, particularly now, a time in

history where topical matters such as climate change and the race to find cleaner sources of

energy dominate international agendas.

A fuel which just a few decades ago was considered an „inconvenient truth‟1 is now sort after,

primarily for household heating and large-scale power generation. As early as the 1960‟s

there was essentially no international market for gas. The existing markets were

predominantly internal (that is Europe and the United States), this reality further kept gas

development at bay. Algeria led the way with the world's first gas export from Arzew in the

early 1960s. Libya followed suit with the building of the liquefied natural gas plant (its first

attempt to commercialise and export gas) at Marsa Brega. During this period however,

exploration for natural gas was for the most part discouraged, often the phrase “gas prone”

would be used by oil companies to discourage further exploration or capital expense.2

Globally the importance of natural gas has taken a turning point (there is even talk of a future

where the phrase “associated oil” would be the norm). Between the periods of 1971 to 2000,

world gas demand more than tripled from 895 million tonnes of oil equivalent (mtoe) to

2,085 mtoe.3 Moreover, the preference of gas for power generation has been fuelled by highly

technical and economically efficient gas turbines, (namely; the Combined Cycle Gas

Turbine), technologies whose long term efficiency pave way for future reliability of the

power sector, thereby encouraging gas-rich countries to develop their gas resources as

catalyst for national development.

1 Companies in search of oil, were often faced with large fields of gas finds, proving an added burden as oil

development with associated gas involved heavy reliance on capital costs. Moreover, gas was heavily flared in its early year, Michael Bunter for instance recalls his first experience in the Oil Industry in Libya, where at night the sky would be light up, not from street lights but from flared gas, to such an extent that it would navigate across the dessert. Michael Bunter, Interview, January 21, 2011 2 Ibid

3 International Energy Agency, Security of Gas Supply in Open Markets: LNG and Power at a Turning Point, (IEA,

2004)

2

Considering the growing demand for natural gas, the trend therefore has been to increase the

availability of it. The challenge of energy supply security has unveiled the interest of nations

to develop their stranded reserves as a means to increasing their global market importance.

The challenge looking ahead, however, is that the market must clearly be able to sustain the

supply and demand balance. But with the natural gas market the demand and supply balance

rarely meet at a corresponding equilibrium in response to market signals in ways typical of

other commodities. For that reason the natural gas market has become a major source of

frustration for producers and consumers alike.

Though trends have shown marked increases in the demand in the past decade, often times

the corresponding increase in production rates have been inefficient at meeting the demand

assumptions, this in effect has caused low demand for the fuel considering where availability

doesn‟t exist, there can surely not be demand and alternatives are thus utilised.

There are several reasons for this, one being the very nature of the gas market itself; whereas

with other commodities, where supply and demand are typically balanced by the price

mechanisms, and where buyers are usually responsive to price signals, this does not quite

work the same in the gas market, especially where the consumer in that case is unable to

switch to other fuels so easily (the case for majority of natural gas consumers). Gas

production is contemplated across the value-chain, infrastructure and transportation is thus

fixed, this means a project‟s carrying capacity is predetermined, likewise a consumers ability

to switch based on market signals become limited.4 This is the case with core household

consumers- large industrial consumers on the other hand, take for instance combined

electricity generators may switch from using natural gas to cheaper fuels such as coal or fuel

oil. But even where this is possible, the price of crude oil for instance is determined on the

world market, while natural gas markets, tend to be regionally segmented. The domestic

natural gas market is therefore much smaller than the global oil market, and as such, events or

conditions in the United States‟ gas market for example, seems unlikely to be able to

4 Note that though there exists gathering and fixed transportation systems for oil as well as for natural gas, the

above statement would not lead to cost equalisation of the fuels considering the various dynamics of the end user and or sale agreement- natural gas is typically tied to long term sales agreement and therefore prices are typically fixed ahead of sales.

3

influence the global price of oil.5 It therefore becomes a commodity whose price mechanisms

can vary dramatically from region to region depending mostly on the level of maturity of its

market. We therefore tend the see lower gas prices in regions like the United States and

Europe where gas markets are fully established and where sudden increases in volume is

possible.6

To set aside the lack of equilibrium of the gas market as the main concern surrounding

deficiency in natural gas utilization however, would be painting a narrow picture and drawing

on financing issues alone would create a skewed image of this complex sector, especially

considering recent announcements of ambitious LNG projects.7 A more pressing response

would be to look into factors that stall development of natural gas in developing economies

and ascertain the difficulties they face in regards to the creation of gas markets.

The paper correspondingly suggests that gas development projects in these regions have

largely fallen behind increasing demand, and that such lag is related almost entirely not to the

lack of availability of markets (since viewing from such a perspective limits the scope of the

underlying issue), but to the lack of focus in the legal and regulatory structures needed not

only to develop a functional market, but to sustain it over time. Perhaps there lies our starting

point. Effectively, when dealing with issues intrinsic to the natural gas industry one cannot

start with the market, but must begin with the availability of the commodity, and factors that

affects its abundance or lack thereof for consumption, the paper will focus on factors that are

legal and regulatory in nature needed to address these underlying concerns.

Why Developing Economies?

According to the International Energy Agency‟s (IEA) statistics, global gas demand is

anticipated to grow by an average of 1.5% per annum through to 2030, it is estimated that

much of this growth will come from non-OECD countries.8 The principle determinants

5 Villar J.A., et al, The Relationship Between Crude Oil and Natural Gas Prices, pg.2, Energy Information

Administration – Office of Oil and Gas (2006) 6 Gas delivery is essentially capacity-bound, therefore, the supply of the commodity is restricted in the short-

term, coupling this with the seeming price inelasticity of demand can lead to a highly volatile market 7 Australia recently announced the world’s first floating LNG terminal (see:

http://uk.reuters.com/article/2011/05/20/uk-shell-prelude-idUKTRE74J27V20110520 ), Papua New Guinea also saw the financing of a merchant LNG project meaning that with the adequate environment financing can be attained. 8 International Energy Agency, World Energy Outlook 2009

4

however, of the success of the gas market in these regions would be the ability of the

production rates to meet such increases in demand, in ways similar to the crude market.

Figures already indicate that this increase in demand would mostly be coming from much of

the developing world including Asia; as the trends in their national development agendas

stipulate access to cheaper and cleaner burning energy fuels. Western Europe‟s declining

production rate is a case in point, and much of this can be attributed to its depleting gas

reserves, and so Europe too is said to be on trend for increased demand in gas, especially as it

struggles to wean itself of high carbon emitting fuels. 9

For Europe therefore, gas from

developing economies will assume a whole new importance.

The main concern however, is that for majority of non-OECD economies (who are also

developing economies) natural gas projects have not picked up as analyst would predict, there

seems a dearth of incentives for gas development, moreover, the investment environment has

often been characterised by uncertainties as well as institutional and infrastructural

challenges. The fact that rents associated with gas development often do not match that of oil

rents also poses further doubt for investors. The deficit of local markets in many of these

countries also presents increased complexities in developing project descriptions for

financing purposes.

In OECD economies, these challenges may not be as glaring as national budgets can always

be brought to bear to mitigate institutional, infrastructural and development and market risks.

Furthermore, producers in the OECD operate often in mature provinces with years of

technical and production experience.10

For non-OECD developing economies in particular,

(where majority of future predicted rise in demand lies) they find that inadequate national

budgets forces heavy reliance on international oil and gas companies, these companies

however, have as a main objective to find crude oil so where institutional capacity or

mitigated investment risks are eliminated the discovery of gas often leads to stranded gas

fields due to the perceived risks involved. These economies are also paradoxically burdened

9 In early 2011 it was recorded that Norway may lose close to $186 billion as shortfall of Norwegian gas is

estimated to take place as soon as 2015, slashing its estimates and paving way for supply of natural gas from non-European sources. Bloomberg, ‘Norway $186 billion Gas Loss to Cement Russian Grip on Supply’, at http://bloom.bg/ic1UuE, last visited 17, January 2012 10

It was the discovery of gas at Groningen in the Netherlands that changed the European natural gas market because the European countries had hard currencies to buy and sell first Netherlands natural gas and the gas from the UK and Norway. Further, the existence of long-established and mature gas markets also adds an extra value to estimating risks and understanding pricing constraints

5

with severe developmental concerns; at the heart of which lies in-house availability of the

fuel needed to spearhead growth and private sector development.11

Still, the reliance on

external or private capital for infrastructure development requires significant levels of private

sector incentives and regulatory control measures; the combination of these guarantees, also,

poses increased burden on weaker economies. A delicate predicament, considering the bulk

of the world‟s gas reserves are located in non-OECD countries at 90.9 percent (OECD

reserves were at 9.1 percent of the world‟s total as of 2010 statistics).12

Current Approach

In developing petroleum fields a trend has therefore emerged. Within the past few decades

there has been an increase in regulatory intervention, host governments have seen non-gas

flaring policies as necessary for mandating the simultaneous utilisation of natural gas reserves

found in association with crude oil, incentive driven oil and gas contracts (designed in favour

of gas development as well as oil), Petroleum legislation where provisions are cited for the

abatement of gas development and so on. Many of the methods alluded to here have had little

resolve in curbing the issues of natural gas development in these regions, nor the

development of sustainable gas markets.

Take for instance the non-gas flaring agenda (especially in developing economies), which

though have made some progress in discouraging the flaring of associated gas and

encouraged the development of new technologies to abate gas flaring,13

is not and cannot in

effect be a panacea for the development of non-associated natural gas fields.

Moreover, between the periods of 1994 to 2008, a period of which majority of the non-gas

flaring incentives began, globally, there was a decrease in gas-flaring of 7 percent, (less of

this number can be attributed to the developing economies) 2003 marking the highest rate at

172.067819 billion cubic metres (bcm‟s), up from 150.646706 bcm‟s in 1994 (see figure 1).

Furthermore, it is estimated that over 150 bcm‟s of natural gas are flared or vented annually,

in terms of current market value, gas dissipated annually is worth close to 31.6 billion dollars,

11

For instance considering the importance of access to power as a catalyst for industrialisation, it still remains that case that developing countries remain predominantly short in power capacity, as it is estimated that three-quarters of people living within these regions lack access to power, majority of these countries, however, are known to also have large gas reserves. 12

BP, Statistical Review of World Energy, June 2011, pg. 22 13

See for instance the use of natural gas as a reinjection tool for the enhancement of oil recover

6

equivalent to 25 percent of the United States‟ gas consumption, and 30 percent of the

European Union‟s gas consumption per year.14

It is little surprise that the bulk of flaring is

concentrated in developing economies.

Figure 1

United States Gov. National Geographical Data Center, National Oceanic and Atmospheric Administration

In addition, legislative and contractual incentives have shown some development, but most

improvement has been scanty in these regions. Take for instance Nigeria, whose many policy

attempts have failed at escalating its domestic gas production and utilisations rates to industry

changing levels. In most instances Nigeria‟s flaring levels have come close to matching gas

produced (see figure 2).

Figure 2

14

The World Bank, Global Gas Flaring Reduction Partners Unlock Value of Wasted Gas, 2009, at http://bit.ly/x2NKsX , last visited, 17 January, 2012

7

The Nigerian gas reserves account for the 7th

largest in the world, yet out of a total proven

reserve estimate of 186.9 trillion cubic feet (tcf) with upside potential of up to 300 tcf, only

4.5 bcf is produced daily Non-flaring policies have not worked either, it is estimated that

approximately 40 percent of associated natural gas is flared.15

Since it has been noted that

majority of the oil and gas companies prefer to pay costs associated with flaring violations

than invest in adequate infrastructure for gas processing and delivery, the issue of wasted gas

through flaring it seems has become a long-term challenge. It is also evident that the Nigerian

authorities see this as a regular income stream (N530.48 million as (N530.48 million as

penalty collected from oil companies for gas flaring), income they are reluctant to part with.

Associated gas alone in Nigeria can provide a host of opportunities for developing the

country‟s domestic needs. One of the options for utilisation include converting the gas flared

to cooking energy sources, as well as a viable potential for power generation,16

in relation to

the need to augment the export orientation of the sector, but these opportunities requires a

detailed analysis of the future opportunities available for converting the abundance of gas

resources to practically addressing the regulatory challenges of bringing gas to the internal

market.

The attempts in doing so came in its recent „Gas Masterplan‟, aimed at tackling the issue of

investment in gas development, but the Masterplan has provided little resolve on the issue.

Oil Companies are increasingly unsatisfied with the too little too late incentives created in the

policy plan, and price mechanisms introduced, especially in view of the added risks they are

expected to bear. The result being that, 50 years since Nigeria started crude oil production the

country has utilized barely 30 percent of its natural gas capabilities,17

but even with such

results the potential for natural gas utilization in Nigeria remain optimal with the a focused

framework (see figure 3).

15

“Gas Flaring in Nigeria: An overview of the Associated Gas Re-Injection (Amendment) Bill 2010 (the “Bill”)” Aina Blankson LP, 2011 16

Int. J. of Thermal & Environmental Engineering, “Gas Flaring in Nigeria: Opportunity for Household Cooking Utilization” Volume 2, No. 2 (2011) 17

Malumfashi G. I., ‘Phase Out of Gas Flaring in Nigeria by 2008: The Prospect of a Multi Win Project,’ (Petroleum Training Journal, Vol. 4 No. 2. July, 2007)

8

Figure 3

Potential Demand

forecast for Nigeria’s

Gas Sector - Graph

provided by Abel Nsa

(Gas Division),

Nigerian Department

of Petroleum

Resources (2011-

DPR)

Challenges to Regulation

The problems associated with some of the regulatory measures mentioned, are that they have

either not directly targeted the issues, thereby producing meagre results, or on another level,

they have proved rather to be disincentives for potential investors. Such solutions as will be

demonstrated in the later parts of this research have failed to ascertain the key features of

natural gas which is that gas development in these regions require specific risk mitigation

mechanisms; such that those bearing the brunt of the capital expenses are recompensed by

long-term risk mitigating off-take agreements, it is therefore necessary that any legal or

licensing objectives tries to tie the broken link between the legal and regulatory framework

with the end sales agreement, a framework which addresses the entire value chain.

Furthermore, it is argued that such solutions have ignored the nature of natural gas as a

unique fuel deserving of a unique mechanisms and solutions and also within its unique

jurisdictional context.

Justification for a Legal/Regulatory Approach

In the energy world, any plan to promote an energy sub-sector requires a comprehensive,

detailed legal and licensing regime. Governments in developing economies especially must

rely on Oil companies to effectively and efficiently exploit their natural resources due to the

limitations of national budgets, whether they choose to invest directly or allow private

investors to do so their primary concern remains heavy state control and full maximization of

the benefits associated with natural resource exploitation. Legal and regulatory regimes are

9

thus, utilised to address the relationship structure between the government and the private

concessionaire – to a larger extent they mainly address the level of State control over the

resource in question, the level of state control for the creation of a gas market however, must

also be balanced with the main priority for the government, which is the promotion of

development projects, hence state control and policy orientation must be juxtaposed when

defining rules of participation.

At the core of Petroleum licensing literature has been the primary focus on utilization of oil

reserves; hitherto, little attention was paid to the issues associated with gas development in

light of its inclusion as a petroleum commodity. This is understandable, but can also be

considered a contributory factor to the current status of natural gas utilization particularly in

the developing world. Exploration and production (E&P) agreements entered into between

governments and international oil companies (IOC‟s) have as a common assumption a target

for oil discovery. For this reason, they have been habitually vague as to the terms governing

the discovery of natural gas. One reason might be the difficulties that exist in defining the

contractual limits for natural gas development, therefore a rush to conclude E&P agreements

(often with the primary goal of finding oil) results in very few examples in the world of

adequate gas clauses.

The lack of such focus in natural gas E&P agreements has several effects, an obvious one

being the limitation of the scope for identifying sector specific concerns; this status quo has

most certainly lead to difficulties for many policy makers in identifying the area‟s where

natural gas clearly needs to be separated from it oil counterpart. Herewith, lies the scope of

this research. This work is intended to be a detailed treatment of natural gas within its

geographical limits, be it with regards to its value chain and contracts matrix, its

transportation requirements, its place within the fuel market and its energy usage. It is an

attempt to address challenges faced by developing nations as they look to establish natural

gas markets by offering recommendations for the design of legal and regulatory regimes.

10

2. Status of Natural Gas

2.1. Gas Worldwide

Currently, the world boasts total proven gas reserves of approximately 187.1 trillion cubic

metres (tcm‟s), (note, that is number is estimated to grow by at least 1.5% per annum through

to 2030) of this total, 106.7 tcm‟s are located in the Middle-East, Asia and Africa alone, with

the majority of Europe and Eurasia‟s reserves of 44.8 tcm‟s found in Russia. 18

These

numbers obviously do not include those recently discovered reserves that are yet to be

appraised, thus, the prospects of further gas discoveries in these regions alone and including

the America‟s are surmountable as more and more countries revamp their legal regimes to

accommodate for oil exploration.

The Sub-Saharan African region in particular is considered the next frontier as oil and gas

companies compete to secure prime acreage; recent activities in Ghana, Uganda, Sierra

Leone, and Tanzania and even Kenya to name a few, illustrate this urgency.19

But as oil

companies discover more oil, associated are the discoveries of commercially viable natural

gas fields. In just under two decades the continent‟s proven natural gas reserves has more

than tripled, whereas in the 1980‟s only 5 countries had commercially viable reserves

(namely; Algeria, Egypt, Nigeria, Tanzania, Tunisia)20

, today more than 20 African nations

have proven reserves,21

meaning that after careful geological and financial appraisal, all

conservative indications show with a high degree of certainty that their natural gas resources

are commercially recoverable (see: figure 3 below).

Of the proven gas reserves in Africa, close to 78 percent are located in Nigeria, with the

balance concentrated in a few other countries, namely; Algeria, Egypt, Libya, Angola,

Mozambique, Namibia and Tanzania.22

Total natural gas reserves (proven and probable) are

estimated at 4,765 bcm‟s, with present recoverable reserves at an estimated 870 bcm‟s. The

Kudu fields in Namibia are a case in point, recent drilling results in Namibia by the Shell-

18

Supra, note 12, Natural Gas 19

Mozambique for instance one of the lowest income economies in the world with little industrial activity looks set to take advantage of its recent abundant discoveries of natural gas, Tanzania likewise has found vast reserves of the resource in its Songo Songo and Minazi Bay regions. 20

Supra, note 11, pg.4 21

Gas reserves on the continent could possibly exceed oil reserves. 22

Gas Extraction in Africa, read more at, http://bit.ly/zGiJKF last visited 04 January, 2012

11

Engen-Texaco consortium indicated that the field may have enough natural gas to meet the

needs of the entire Southern Africa region.23

Similarly in North Africa, Egypt's proven estimates range at 0.43 tcm. According to Egypt's

Gas Master Plan, much interest is currently being concentrated around the Nile Delta, with

the possible development of LNG infrastructure. Moreover, Libya has an estimated 1.3 tcm

of natural gas while Tunisia records more than 23 bcm‟s of recoverable reserves, this amount

is supposed to represent British Gas's largest gas field project outside the UK.24

Figure 4

Reserves-to-

Production Ratios

23

Iran has also indicated interest in the Kudu field development, read more at, http://bit.ly/zcBfyB last visited 04 January, 2012 24

Supra, note 22

12

The opportunities for gas development it seems for the most part are extremely diverse and

widespread across Africa. A majority of these Countries are however grossly underutilizing

their proven resources. As of recent data, the total natural gas production rate on the continent

stands at 203.84 billion cubic metres, out of a possible 14.76tcm‟s25

meaning that the

continent is currently utilizing much less than half of its natural gas potential.

The challenges associated with gas development on the Continent cannot solely be assigned

to the difficulties in dealing with associated gas alone, for at most 50 percent of the gas on the

African continent is non-associated gas (the same true for many countries in the Asia Pacific

who among them have total gas reserves of 14.76 tcm‟s).26

Nor can these mostly stranded

resources be a result of their lack of market accessibility, or the lack of demand for natural

gas goods or resources. As is evidenced in Egypt and until most recently Libya, the enabling

legal and regulatory environment often paves way for access to the market as was seen with

Egyptian supply to its Middle Eastern neighbours as well as Libyan export markets to Europe

and other parts of North Africa.

It is important to note, however, that the analysis here should not preclude a countries

inherent right to decide not to develop its natural gas reserves since such a decision can also

be made in the national interest. Furthermore, it must be noted at the outset that though gas

reserves may be initially deemed as commercially recoverable, the dynamics associated with

delivering the commodity to the market including fiscal policies and incentives (as would be

demonstrated) may in fact make the project non-commercial and gas must in fact be stranded

until such issues are resolved. In cases like these, however, a legal/regulatory framework

must also look into balancing the long-term effect of producing the commodity which might

include tax incentives and or subsidizing for policy purposes. To all these issues the question

derived is; to what extent are legal and regulatory measures stalling the progress of natural

gas development in these regions?

25

Africa's proven gas reserves have grown immensely over the past two decades and in 1995 totalled about 6.3 tcm’s with potential reserves estimated at 17.65 tcm’s in 2010. 26

Supra, note 24

13

2.1.1. Significance of Development of Future Reserves

The above potential demonstrated has several underlying effects for the development of

future natural gas reserves in those regions. The availability of in-house reserves (and thereby

no import dependence), for a developing economy immediately implies the ability for that

country to focus almost entirely on taking advantage of the opportunities in addressing power

sector deficits – a major cause of which is high cost of imported fuels which make power

generation projects especially expensive. With in-house gas policy-makers can address this

deficit from several angles, one being setting various parameters in preference for domestic

consumption (for example a domestic gas obligation), conveniently aided by the lack of

exposure to world prices, a domestic gas obligation (DGO) however, must be designed in

such a manner that guarantees a constant and predictable supply of DGO gas, the producers

exposure to DGO gas must be rewarded in a contractual relationship, then comes designing a

DGO to make it either producer specific or field specific (see later discussions of potential

structures available for DGO gas).

In recent years and as energy security continuously plays centre stage in international

relations supply security alone can elevate a nation‟s relevance on a global scale, and address

the risk of relying on external sources of Energy. For these economies, it is essential that the

development link is not broken by frequent shortages of the fuels needed to spearhead

economic growth. But for nations with reserves enough to surpass domestic use, the right

framework can be implemented to support an export market in order for a producer to exploit

the availability of competitive natural gas markets (see later discussions on this topic).

2.2. Natural Gas Specific Issues & Challenges

2.2.1. Associated versus Non- Associated

There are two main classifications for natural gas. Often a distinction is made between

associated gas (AG) and non-associated gas (non-AG), with non-AG being touted as the

lesser of the evils. This distinction is important in the gas world for several reasons, and could

spell the difference between billions of wasted gas and gas simply just left in the ground.

Looking at the data provided earlier, however, it seems at times, and practically, the

14

difference stipulate that non-associated is more heavily produced (or utilized) than associated

gas.

In view of the fact that associated gas is a by-product of oil-extraction and to add a caveat,

where it is discovered in conjunction with an oil discovery (i.e., the same field) the problem

of the utility of AG arises soon after crude oil is produced from the same well. On the other

hand non-AG, which may also be discovered when the intent is to discover oil, but is

discovered not as a by-product but on its own, has only the added burden of “to produce or

not produce.”

The differences in associated and non-associated become even more glaring when

determining the party who will most bear the market volume risks, or if this risk would be

shared by the producer and buyer.

2.2.2. Associated Gas

There are several problems linked with associated gas (AG) that further adds to the difficulty

of assessing its economic value. One key challenge is the inability to predict to a certain

amount of accuracy production rates from AG fields; this seemingly minor challenge comes

with it a host of problems. External factors such as that governing the extraction of the crude

it is associated with, ultimately determine the rate at which AG is produced. For this reason a

sale agreement between a buyer and seller of such a commodity will take into account this

debilitating factor, and as a result grossly lower the price it would be offered were it non-AG.

Even where financing is secured for those purposes, the payback would be negligible

compared that of a non-AG field. The seller enters a long-term “depletion contract” with the

buyer, and in exchange for volume risk protection the seller promises to sell to the buyer all

the gas that can be commercially produced from the field (see later discussions on volume

allocation). Furthermore for AG the higher costs correlating with the separation of crude and

gas as well as the de-contamination process could mean flaring as a cheaper alternative for

the producer.

15

Low AG premiums, thus, makes it difficult to justify capital expenditure on gathering

systems, gas burning technologies, long-distance pipelines, all of which depend on a constant

and dependable supply of gas.27

Moreover, these low premiums makes AG almost always a

locally consumed commodity, as transportation to international buyers would prove

economically difficult to justify. And where there lacks infrastructure bringing in the gas to

the in-house buyer, flaring would in that case becomes a must. So for developing economies

whose natural gas resources are predominantly AG, a careful assessment must be made as to

the importance of producing such gas and to what extent State aid would be utilised to

develop the gas for local consumption.

The trend in producing countries, especially those in the developing economies, have been

not just to prohibit flaring, but also to require oil companies to hand over gas produced from

these fields to the government for utilisation in the domestic realm. Without further analysis,

however, this may seem to be a solution, but not quite. The issue often arises where policy

very rarely corresponds with implementation or reality. The inclination has been towards

Governments opting to pay much less for AG than they would for non-AG (capital costs are

also rarely compensated fully), creating a great disincentive for oil companies to invest in the

necessary infrastructure to deliver the gas to the government.28

Though in recent years there

have been inclinations towards a flare-free world, the truth is that majority of the Countries

that rely on these policies do not in themselves have the adequate infrastructure to bring gas

to bear, so in actuality although the gas can be handed over to the Government or its national

oil company (NOC), there exists no avenue for its utilisation. In the Nigerian example, a

resulting effect was the development of its LNG export market, but considering that Nigeria

boasts a large percentage of the Continents natural gas reserves, its LNG export business is

relatively un-matured, moreover, its short capacity power sector could desperately do with

gas input.29

In areas with large associated gas volumes, gas can be transported into gathering systems to

supply liquefied natural gas (LNG), methanol, or ammonia, or even power generation plants.

However, for this to be possible several scenarios must be possible:

27

Supra, note 15, pg. 5 28

This pricing of natural gas has been a major issue in Nigeria’s natural gas market 29 As well as other issues the lack of incentive to deal with redundant capacity might also be a contributory

factor in the development of the LNG market in Nigeria.

16

1. High volumes of gas must be dedicated in advance to rationalize the substantial

capital costs. This will prove difficult, considering the uncertainty of volumes coming

from associated fields30

2. The above may be rectified where there exists associated gas fields, supplementary

non associated gas can also offset supply fluctuations, as well as the eventual

depletion of field production.31

3. Where pipelines and gathering systems are not optional the possibility of floating

processing and transportation technologies can meet the demand, however, such

vessels are also capital intensive,32

in addition, a facility would need a steady non

declining gas stream, which often can only be achieved by combining associated

gas with non associated gas from other fields.

2.2.3. Non-Associated Gas

Non-associated gas (non-AG) on the other hand may not be produced at all where there lacks

the necessary infrastructure or market conditions to bring commercial reasoning to the

project. There are situations where exploration is specifically aimed at finding gas, such as in

the North Sea or in the Russian case where, a market is available with the necessary pipeline

facilities for delivery, however, in the developing economies this trend is rare (though

increasing). The advantages therefore of non-AG is that unlike AG it can be left underground

till it is deemed economically viable to continue with development and subsequent

production. Furthermore, non-AG production rates are rarely determined by external factors,

except where Government policy is designed to stipulate the rate of production, but even so a

certain amount of predictability can be assured thereby increasing its the end value of the gas

produced from these fields.

The issue of market imbalance and unpredictability can still be a dissuading factor for

investing in such capital intensive infrastructure for gas delivery. Where there are no essential

export opportunities or persuasive fiscal incentives, non-AG are stranded, that is, left in the

ground waiting in anticipation for a market to develop in its favour. This is the case in Africa

30

Hopper, C., Modular Syncrude Conversion Drives: Oilfield GTL Solution for Associated Gas, SPE Journal of Petroleum Technology, February 2009 31

In this regard government can control depletion rates to maximise the potential of these fields 32

For example, a facility capable of consuming 100 to 150Mmscf/D would cost approximately USD 1 billion

17

where although 50 percent of the natural gas on the continent is non-AG, there still remains

relatively low production rates, and utilization.

2.2.4. Volume Risk Allocation:

A major risk factor to be taken in consideration before the development gas fields is the

assessment of who along the value chain will bear the resulting volume risk where it arises

(that is, the possibility of failure in delivery of the commodity). In a competitive natural gas

market, take for instance mature markets in the US and the UK, the upstream section, that is,

the seller and or producer will usually assume such a risk. Essentially, a mature market is

perceived as a less risky environment, where buyers are available and as such producers need

fewer guarantees to ensure project cash-flow, and so price as stated earlier, becomes the basis

for competition.

Even in a mature gas market, the distinction between associated versus non-associated gas

can also lead to discussions of volume risk allocation, for the mere fact that a producer in an

associated gas field is unable to any degree of certainty determine the depth of gas resources,

nor a proven production rate, he would, as stated earlier take the price hit (because the buyer

is unable to nominate volume ahead of delivery) and sell at below competitive rates. Most

associated gas fields are therefore monetised through „Depletion Contracts‟ (or Seller‟s

Option Contract). This type of arrangement typically signifies the nature of the field in

question, that is, associated. In a depletion contract the buyer contracts to purchase all the gas

that can be economically produced from a particular reservoir, such that he is not able to

nominate a certain volume ahead of time unless the field has produced what it can.33

The volume risk is thereby moved to the buyer, in this regard to gain value or increase the

selling price, a producer can take the volume risk, this can be achieved by managing

production from several fields.34

However, such a method would only make sense where the

possibility exists for linking fields, not to forget the added infrastructure cost implications for

connecting several fields to one delivery point. In an environment that lacks a gas market, the

33

Competition Commission, UK., Types of Contracts for Gas Supply, 2003 at http://bit.ly/zti2cV 34

See for instance North Sea gas example. Shell and Exxon have monetised associated gas through this method for years. Source “Stephen Dow (CEPMLP)”

18

direction is towards encouraging investors, that is, producers necessarily results to the need to

shift that volume risk away from producer and onto the buyer. The later parts of this paper

will discuss how this can be achieved.

2.3. Gas Market Considerations : Obstacles for Regulations

Surety in gas development would require the establishment of export and import

infrastructure, wholesale buyers and sellers, and a well conceived value chain, involving all

aspects of upstream and downstream qualities before gas can successfully compete with other

fuels (see figure 5).

Figure 5

Natural Gas Value Chain (specifics links will depend on the project)

So it is the case that the physical components of gas alone, though advantageous on many

fronts are insufficient to realise full investment in gas market development. The very

character (chemical make-up) of natural gas can also be argued to be its main obstacle in

terms of market development. The reason is straight forward, natural gas is not a liquid it is a

gas whose purest form is colourless, odourless and shapeless (that is, it assumes the shape of

its container). It is a combustible mixture of hydrocarbon gases, primarily of methane, but

19

can also include ethane, propane, butane and pentane, classified as either „dry‟ or „wet‟. It is

dry when almost purely methane, having removed almost all other associated hydrocarbons.

On the other hand, it is wet when other commonly associated hydrocarbons are present. Its

composition, thus, can vary widely spelling a host of complications for transportation and

storage, as well as create definitional challenges for downstream refinery and pipeline

allocation agreements, especially where different gas fields comingle into a single pipeline

prior to final delivery.35

On the other hand, much can be said for its environmental premium making it a preferred fuel

mainly because of its low emitting rates. Gas burns relatively cleanly, flexible and easier to

concentrate and direct than other fuels. Its premium qualities give it major advantages in

certain industries such as the glass and ceramics industry,36

offering important environmental

benefits. Furthermore the superiority of its environmental qualities over coal or oil provides a

sure bet in environmental assessment and project appraisal for project financing purposes.37

Its non-polluting characteristics therefore, becomes extremely essential, for countries like

China and other emerging markets whose rapid industrial development need to also be

countered with sound environmental standards.

A policy priority in China‟s current power sector is the diversification of its fuel supply,

mainly away from coal (a fuel which is in abundance in the Country) to less polluting fuels

like gas. The security of supply of coal is therefore not the issue but rather the recent trend is

to wean the country off its largest polluter. A gas premium market as a result, would involve

the replacement of fuels producing these high emissions in favour of gas.38

In China‟s case,

however, several obstacles stand in the way of bringing gas to market as the preferred fuel, at

the heart of this is the lack of incentives needed to develop in-house gas fields.39

On the other

side of the spectrum are measures needed to realise the fullest potential of the gas premium,

35

Picton-Turberville, G., ed., Oil and Gas: A Practical Handbook, pg. 187, (London: Globe Business Publishing, 2009) 36

Hurst, C., Davison, A., Mabro, R., Natural Gas: Governments and Oil Companies in the Third World, pg 14 (Oxford, UK: Oxford University Press, 1988) 37

Although on the same token, external factors such as infrastructure development and environmental costs associated with pipeline development might also counter such benefits 38

International Energy Agency, Developing China’s Natural Gas Market: The Energy Policy Challenges, (OECD/IEA 2002) 39

Though realistically speaking the estimated gas reserves in the country are not enough to meet the demand assumptions

20

including the creation adequate market conditions for the competitor „coal‟ as a less desirable

alternative.

2.4. LNG Opportunities and Challenges

Unlike oil, gas must be transported primarily through pipelines. It is also possible to transport

large quantities in containers for shipment, but this process requires either compression or

liquefaction in the form of liquefied natural gas (LNG). The LNG market is rapidly

expanding; there are currently 337 LNG ships in operation. For governments LNG is still

desirable; the growth of LNG, in this regard has emerged as a result of not its costs

effectiveness but more frequently as a flexible and dependable mechanism for nations

(especially those importing) who wish to access the premium qualities of natural gas.40

For a country developing its natural gas market, LNG is a viable option for the main fact that

it provides a producer with additional avenues for monetising his gas fields, that is, it

provides a further incentive, so whereas the decision for a Government to keep a

predetermined amount in-house for local consumption may become a deterrent, such a policy

can be augmented with allowance for export in which case guaranteeing an investor an

avenue for attaining a competitive price elsewhere. The creation of an LNG export terminal

would achieve this, but the question would be who invests in such infrastructure, the answer

would ideally depend on the type of control the Government would want to assume. An

import terminal for LNG could also serve as a possibility for addressing possible shortfall.41

Though LNG provides further monetising opportunities, worldwide the LNG market share

still remains predominately low (LNG is approximately 8 percent of global gas consumption,

with total gas consumption being 24 percent of total energy consumption, so essentially LNG

is 1.9 percent of global energy consumption) this is due in part to its high upfront costs, such

that without a buyer who in turn has the infrastructure to re-gasify as well as pipeline

capabilities for local consumption, the LNG market in practice, and for that reason, does not

seem to be that more advantageous than conventional methods. Typically, only contracted

40

Politically sensitive cross-border pipelines have played an important role in surging up the need for such a flexible transportation option. The Japanese LNG market was borne out of this need. 41

Note, Africa currently has no import terminals

21

LNG ships would attract financing. As a result, LNG carriers are ordered after long term

contracts have been signed between buyers and sellers tying the gas project with appraised

credit-worthy off-takers. Just like a pipeline, the LNG ship is seldom brought to bear on a

merchant basis, considering that the high upfront costs associated would prevent any lender

from financing without careful assessment of an assignable cash-flow.

Often the appropriate means of addressing the high upfront costs of LNG projects has been

through the design of the fiscal policy to ensure risks are balanced by rewards along the value

chain. LNG projects are typically integrated; for financing reasons it usually makes sense for

lenders to consider the entirety of the project as opposed to a segment of it which might

expose the project to further risk. For regulators integrated projects are also highly attractive

with regards to the ability for the projects to also be fiscally „ring-fenced,‟ in that they

essentially remove concerns associated with unfair transfer pricing. 42

On the other hand bold

fiscal moves might prove to be burdensome administratively, as they require a wholly new

administrative practice, such a process might be a challenge for weaker economies.

Another major stumbling block for investors in developing nations has been that the gas

reserves remain largely under state control in many of these countries. “The inability of

domestic consumers to pay anything like the gas prices received in developed countries has

traditionally meant that local gas projects have been developed by governments.” The LNG

market is therefore desirable as governments are keen to increase export revenues. They also

remain equally dedicated to increasing local gas supply and often these two objectives must

be balanced when designing gas specific regulations.

42

Kellas, G., Natural Gas: Experience and Issues, in The Taxation of petroleum and Minerals: Principles, Problems and Practice , pg.169 ( Daniel, P., Keen, M., McPherson, C., (eds.) Oxon, United Kingdom: Routledge, 2010)

22

3. Sector Specific and Similar Sector Approach

As mentioned earlier, at the outset the limitations in developing natural gas markets was often

associated with the perception that as a petroleum commodity, any legal framework must

essentially be similar to traditional (existing) petroleum legal system. Such an oversight is

now predominantly viewed as wrong and in the author‟s view has often barred the realisation

that lessons can be gained from sectors that function similarly to the natural gas sector.

Understanding these similarities it is presumed, would provide alternative avenues for

addressing the challenges that present themselves when developing a natural gas market, on

the other hand, being aware of their key differences might also provide an avenue for

estimating areas where certain results must be avoided.

3.1. Power Sector

Due to the transportation requirements a proportion of natural gas must typically be

consumed in the country where it is produced, in many respects this makes certain aspects of

the gas market similar to the electricity market. Both requiring complex infrastructure

systems to deliver their various qualities to the market, meaning that essentially where a local

market cannot be established investment would ultimately be stalled until necessary

frameworks are designed to meet expectations. Gas utilization is only possible when

production from reserves finds outlets; so just like electricity, each individual field creates its

own unique market space. For this same reason there is no global price for natural gas or

electricity, as there is for oil or coal respectively.

The similarities between the power and gas sectors do not only correspond in terms of market

similarities, they are also complimentary to each other. For many countries especially those

in emerging markets the power and industrial sectors represent the largest (or potentially

largest) consumers of gas. Almost all developing economies have at their core a huge demand

for power, and in most this demand continues to grow at alarming rates. The potential, thus,

for gas in fuelling this demand is grossly untapped. The early realisation of this can spell

growth for both the power and gas sectors. This complimentary relationship also introduces

to policy makers the opportunity to merge the market risks of both sectors providing an

avenue for their simultaneous development.

23

To achieve this end, a regulatory framework must draw on policy intentions and several

considerations must be made, including:

Assessing the importance of gas fired power generation for local consumption

Assessing the regulatory implications of an integrated power project with natural gas

as feedstock

Addressing ways to merge gas and power sector volume and price risks

Determining the domestic obligation (DGO) for gas in power generation and or

assessing any potential subsidies and the effect they may have on the associated gas

investment

Alternatively, the role DGO can play in merging the price and volume risks

Where gas is to be utilised for local electricity generation, it is important such

measures are in place to relate the power agreement with the gas development and

sales agreement to the extent that gas development efforts are not hindered

Addressing the off-take obligations for both the power and the natural gas sector,

involves careful consideration of the contractual matrix needed to deliver the

obligations and careful assessment of risk allocation.

3.2. Mining Sector

The buck doesn‟t stop there, the lessons that can be borrowed from the mining sector is also

very rarely stated or even deeply analysed. One area of correlation between the two sectors is

the very nature of associated minerals that are extracted in relation to the principle mineral

(for our purposes, the associated minerals). The existence of this possibility has given rise to

a number of policy decisions in relation to how mineral rights are allocated. The design of a

mineral rights allocation system in different jurisdictions have at their core the determination

of whether such mineral rights should be allocated for individual minerals, separately, in

conjunction with other minerals that may be found or sometimes what are known as parallel

licenses.

In the petroleum world, the question would be whether or not to separate a gas PSC for

instance, from the oil PSC and the associated consequences, (see more discussion on this

topic in Chapter 6).

24

4. Legal and Regulatory Measures and Risk Mitigating Incentives

Although there have been marked increases in the demand and uses of natural gas, the

obstacles eluded to in the previous chapter still hinder natural gas development in several

regions as the focus on oil is still foremost on the agenda of hydrocarbon exploration, or that

even though there may be interest in exploiting natural gas resources, often the right

frameworks are not in place to realise those goals. Increasingly however, some governments

have entered into contracts with IOC‟s that are solely dedicated to gas utilisation; Saudi

Arabia, Egypt, Peru and Venezuela to name a few are some of those countries. This chapter

intends to examine some of these structures, the idea is to offer an analytical spectrum of

legal measures governments in developing economies with natural gas reserves or intend to

create natural gas markets can adopt. To add a caveat, it is important to note that the

recommendations are not one-size fits solutions each project must be designed taking into

consideration country specific challenges.

Overview:

The basic underpinning of a petroleum legal framework is drawn in the form of a

hydrocarbon law. The law normally sets out the general principles surrounding the nature of

hydrocarbons and provides broad statements and policy principles surrounding their use.

These principles essentially emphasis the States‟ ultimate control of hydrocarbons, broad

statements of aspirations, and basic provisions that are designed to be non-changeable. Those

provisions that may need periodic adjustment, for instance, administrative procedures and

technical requirements, are stipulated in secondary legislation pursuant to the basic law, also

referred to as regulations. These basic structures subsequently pave way for a wide array of

legal arrangements made between the government and the private party.

4.1. Legal Instruments

A number of legal and fiscal instruments exist that address the rights and obligations of the

title, (or right to perform is certain action) granted by government to the contractor. These

legal instruments usually provide express statements of the relationship structure between the

State and the contractor and the extent of contractual entitlement given to the contractor.

Today there are arrangements to explore, develop or produce petroleum between the host

country (HC) and the contractor (or IOC), namely; Concessions (also known as royalty tax

25

Concession/ Explorations

License

Sales Agreement

Production Sharing

Agreement

systems), Production Sharing Contracts (PSC‟s), Service Agreements (SA‟s), and

Participation Agreements (PA‟s). While each of these arrangements can be used to

accomplish the same purpose, they are conceptually different from each other. Each grants

different levels of access or control to the IOC, provides for different compensation

arrangements, and permits different levels of government and or National Oil Company

(NOC) involvement.43

Even with that said a Service Agreement can very often be similar to a

PSC depending on its provisions; it is also the case that many governments exercise a hybrid

system; that contains aspects of two or more types of arrangements, for instance, a PSC with

elements of a concession, such as royalty structures. At the heart of the conceptual

differences lie key risks within each.44

Unlike earlier petroleum agreements, most of today‟s existing arrangements recognize that

rights and obligations of parties in relation to crude oil exploration and exploitation (E&E)

need to be modified for rights and obligations associated with natural gas E&E. However, it

still remains an oversight, in that the risks associated with natural gas exploration all the way

from production to sales arrangements need to be adequately allocated if a gas market is

envisaged. The natural gas risk structure must therefore be reflected in any legal or regulatory

arrangement (see figure 6).

Figure 6

43

Smith E. E., et al, International Petroleum Transactions, 3rd

Edn, page 429, (Rocky Mountain Mineral Law Foundation, 2010) 44

Ibid

Transportation

26

4.2. Risks and Legal Arrangements

4.2.1 Exploration Risks and Legal Arrangements

Exploration projects in the petroleum world involve a complex set of decision making,

encompassing both technical and financial analysis. Unlike oil exploration projects, projects

to source for natural gas alone are infrequent, and are found mostly in regions with mature

natural gas markets.45

This is due in part to the initial motivation to go exploring for oil and

not gas. In developing economies, the prospecting stage often commences with the desire to

explore for oil, since the discovery of oil provides often easier access to its rents, it is on this

premise therefore, that any analysis of exploration risks takes stock of the risks structures

associated not only with natural gas exploration but also within the context of oil exploration

in these regions.

Geological risks – that is, the risk of not finding the resource one explores for, in this case

natural gas. Where the intention is to solely explore for oil, natural gas geological risks are

often merged with that of oil exploration risks. Generally with oil, “reducing the geological

risks or rather the perception of risks will reduce the exploration and development threshold,

and the risk premium required by investors,”46

however, the same cannot be said for natural

gas, for the most part even where the risks of finding gas is merged with of oil, the

corresponding increase in investment interest is not realised mainly because of the level of

perceived risks at the other stages of the gas value chain – this is especially one reason why

considerations of developing natural gas markets has to be viewed with the perceived risks

along the whole value chain.

Financing risks – Considering most petroleum exploration projects are rarely financed

through complex financial loans or instruments,47

it is typically the case that the project

company or consortium pull in their resources to fund the high capital costs. Once again this

risked may be merged with oil if the goal is the find oil, in which case gas financing risks will

be assumed almost entirely by the oil risks. But once again considerations of the risks not

45

Recently heightened by the discovery of the potential abundance of Shale gas 46

Tordo, S., Petroleum Exploration and Production Rights: Allocation Strategies and Design Issues, pg. 4, working paper no. 179, (Washington D.C., World Bank, 2009) 47

Considering banks will rarely take the risk of financing projects without assignable cash flow

27

just upstream but downstream must be kept in mind when designing arrangements for

allocating natural gas exploration risks (if at all).

Where the project entity, chooses to prospect for natural gas alone, the financing risks

involved for natural gas would be considerably more onerous that that of oil financial risks.

Securing structured financed instruments for exploration projects are extremely rare, if at all.

Therefore the Project Company or consortium typically assumes the entire financial burden

through equity participation. Such a risk is taken after complex financial analysis and

forecasting taking into consideration technical data and geological knowledge, this

information is further weighed with the risks involved at the development and production

stages, that is, the flexibility of the arrangements in lieu of the financial commitments made

by each entity involved.48

HC‟s usually represented by their NOC especially in developing

economies are typically carried through the exploration stages.49

The project companies or

partners then work out a complex set of agreements that share the financial burden and risk

among themselves, with cash calls as payment arrangements.

There are a number of ways natural gas exploration risks may be mitigated, one avenue is for

the HC to participate in its share of exploration not on a carried basis but as a paying

participant, thereby all parties in the project funds to facilitate exploration activities in

relation to their participatory interest relieving the project partners from the added financial

burden of a carried partner, a clear risk sharing incentive. Where the HC lacks these financial

resources, a possible avenue to access the funds needed is through sovereign loan facilities,

such as World Bank guaranteed loans, or through alternative financing means. Financings

provided by international lenders will be necessary and in most cases they will need country

risk support facilities provided by multilateral agencies like the World Bank.50

Often country specific or political risks may also play a role especially where project partners

might fear the risk of the HC not meeting it “cash call” obligations. Private sector participants

have often relied on political or country risk insurance from multilateral agencies like the

Multilateral Investment Guarantee Agency (MIGA) to insure them against these risks.

However, insurances of this kind are typical especially for foreign investors entering into

48

Where the company involved is purely participating for the exploratory stages, it would ideally wish to have an arrangement which gives it the flexibility to transfer its portion of the assets upon discovery. 49

Usually as a recognition of their inability or lack of financial resources to take on such capital intensive work 50

Smith, V., Project Finance Review, pg.27, University of Dundee, 2007

28

developing countries. But due to the cash strapped nature of national budgets the risk of

default by the HC is heightened, it is therefore necessary that direct government guarantees

are secured to ensure the ability of the government participant in meeting cash call

obligations. In a country which is in production stages of oil development, the HC can choose

to meet it cash call obligations by allowing its partners in the natural gas exploration phase to

lift a percentage of its crude as additional security.51

Where this is not possible, another

means of further assurances can be through the establishment of offshore or escrow accounts,

a third party mechanism where funds can be pre-allocated by all project partners prior to the

commencement of exploration activities, the third party escrow trustee would then be in

charge of disbursing the fund needed as per the cash calls.

Another method of encouraging gas exploration would be to go the route of non-risk SA‟s,

that is, similar to Egypt‟s approach in the 1980‟s where explorers for natural gas were

guaranteed fair compensation upon the discovery of the resource, and to the extent that most

or all of such gas was surrendered to the Egyptian government as a contribution to its national

reserves.52

Not only is this method supported by sound guarantees to mitigate the later

development and production risks, it also secures some future financial reward, that is, if the

compensation is designed favourably. However, it would be difficult for developing

economies to assess this reward especially where there lacks the financial capabilities at the

onset, moreover, where the gas is associated the difficulty in assessing the reward structure

for an undeterminable amount of gas would prove difficult.

In most cases for natural gas, the risk at the exploration stages has to be linked with the risks

foreseeable also at the development and production phase of the value chain. The intention of

participants would most likely be to be involved in the whole value chain, and also for

lending reasons it makes for lenders to consider the whole value chain, for this reason

security of title is especially vital for the investor in natural gas projects. The right to transfer

the title to an eligible third party if the title holder so feels, the right to assign the title to raise

funds and also the right to transform an exploration license into a development and

production license without additional financial commitment is essential to calculating the

risks and investment return.

51

The Nigerian National Petroleum Corporation for instance arranges between itself and its Joint Venture participants a payment structure by the ability to lift crude to pay for its participation in exploration 52

Colitti, M., Oil Industry Participation in Natural Gas Development, pg 154, Energy Vol. 10, No.2, (1985)

29

4.2.2 Development and Production Risks and Legal Arrangements

A natural gas exploration framework must therefore be designed to guarantee easy

transferability into development and production license. Licenses and production rights

cannot be suspended or revoked except on specific grounds, which must be objective and not

discretionary, and which must be clearly specified and detailed in any legal arrangement (see

further discussions about the license process in later stages).53

Whereas, in oil the HC may choose to use the signature bonus as a means to increase upfront

rents before the commencement of development or production, this mechanism for natural

gas would prove a disincentive for the mere reason that the rents associated with natural gas

do not match that of crude oil and so must be avoided.

At the development and production stages, it is clearly evident that the resource has been

discovered and the decision of commercial viability has been made and thus subsequent

development and production is required to bring the resource to surface. It is typically at this

stage that financiers become available to the notion of project financial assistance. For oil

financing the arrangement is typically straight forward, with oil the main focus of financing

becomes establishing the appropriate parties for the allocation of economic rent, with

certainty built in through the projects projected outflow and conservative lending

assumptions. Gas however, is a more difficult case than oil mainly because of the contractual

environment needed to build in added certainty to the project. Therefore the lender will

assume very minimal risk if any, the contractual arrangements ahead of sourcing for

financing would need to be designed ahead of time, with designating credit worthy parties

who can take much of the risks away from the producers.54

These can come in various forms

for the natural gas industry, for instance a power generator can become one avenue for

transferring the volume risk away from the producers end at this point volume and price risks

can be transferred with varying mechanisms to secure payment through guarantees (see

figure 7).

53

Supra, note 41, pg 2 54

Note that as mentioned earlier in an environment that lacks the market, the producers typically want risk mitigating assurances

30

Figure 7

55

Development and Production Legal Arrangements:

At the outset most Petroleum Agreements (PA‟s) would make a distinction between the

commitment to natural gas and the commitment to oil, and when the explorer is in search of

oil and finds gas, there is then a scope designed to deal with the consequences, which often

involves a method of negotiating the investment return, that is, the cost recovery curve for

gas if any. Each producing country has a way of dealing with this, some common trends are;

that the upstream explorers are essentially deemed to have no ownership rights to the gas

associated with oil production and are stipulated to deliver the gas to the government or

midstream operator royalty free with costs to do so reimbursed (see Omani example) or

recovered from oil revenues.56

55

Example commercial agreement matrix, supplied by Stephen Dow, CEPMLP (2011) 56

Supra, note 27, pg 171

31

The Angolan Model PSC 2008 provided for instance that:

“Associated Natural Gas surplus to the requirements defined in the preceding paragraph shall be

made available free to Sonangol, wherever the latter so determines. The cost of transportation of said

gas by pipeline is a recoverable cost under the law…If Non-Associated Natural Gas is discovered

within the Contract Area then Sonangol will have the exclusive right to appraise, develop and

produce said Gas for its own account and risk.”57

The Nigerian Petroleum Act by virtue of paragraph 35 (b) (i) of the First Schedule grants the

government the right to take associated gas produced by the licensee or lessee free of cost at

the flare or at an agreed cost and without payment of royalty.58

Under the Nigerian structure

the various licenses have different ownership structures. The rights to explore and exploit

natural gas in Nigeria are granted to investors by the Minister either through the Oil

Prospecting Licence (OPL), the Oil Mining Lease (OML) or the PSC. The OPL and OML

can be held by companies either as a sole risk operation or as a joint venture with the

Nigerian National Oil Corporation (NNPC). The PSC on the other hand allows investors to

bear exploration and production risks in return for cost recovery and production share. The

PSCs does not grant investors ownership rights to gas.59

In other cases (such as is the case with Egyptian PA‟s) the contractor gains more extensive

rights over natural gas and in recognition of the risks taken often a production split more

favourable than that of crude oil is allocated to the upstream producer, and a cost recovery

curve designed also to be more favourable than oil is calculated to reflect the limited rent

implications of natural gas.

Vesting all natural gas produced on the State has a number of effects; one being the lack of

security of tenure, furthermore it is often the case that for gas rich developing economies who

wish to upstage their gas production, and who often do not have the adequate infrastructure to

accommodate delivery of gas from wellhead, that such a provision would in effect prove

futile. Even where provisions exists for the recovery of costs associated with transferring the

gas to the State, some PA‟s use the same cost recovery ceiling as that of crude oil, “this

57

Angola Model Productions Sharing Contract - 2008 58

International Comparative Legal Guide Series, Gas Regulation: Nigeria, pg 180 (2010) 59

The International Comparative Legal Guide to Gas Regulation 2011: A practical cross-border insight into Gas Regulation work- Nigeria, Global Legal Group (2011)

32

should be avoided as the profitability of oil and gas projects differ.”60

The outcome of such a

provision is that investor‟s are deterred and worse there are ultimately no avenues for gas

associated to be dispensed and flaring would be a typical consequence.

On the other hand the vesting of natural gas production rights to the contractor also presents

itself with further challenges in these regions. It has almost become a conventional truth that

any attempt to encourage investment in natural resources often commences with rights

shifting from government control to private sector control coupled with and security of tenure

assurances. Egypt was successful in doing so with its natural gas framework from the early

1980‟s. Before the 1980s, all the gas discovered went automatically to the Egyptian General

Petroleum Corporation (EGPC). In 1981, a new gas provision was introduced which gave

companies extensive gas rights, the reforms were followed in the 1985 Gas Clause which

sought to detail natural gas provisions in PA‟s. In 1988, Shell and EGPC signed the first Gas

Clause which became the standard agreement for any future gas concessions. This and other

subsequent changes in the terms of fiscal terms led to an increase in exploration and

production of natural gas in the 1990s (EIA, 2007).61

Changes in ownership structures alone are insufficient in encouraging upstream producers to

take the necessary risks in developing gas reserves. For an integrated project considerations

have to be made of the implications this may have on downstream activities and government

fiscal take. The contractor‟s production share is often counter-balanced with his fiscal

obligations; this alone could make a project uneconomic from the producer‟s viewpoint.

Fiscal Provisions

The benefits from production are in large part determined by the fiscal terms applicable along

the various links in the value chain.62

Just like crude oil, the natural gas fiscal regime can

vary across jurisdictions and often a number of instruments are utilized to enable the host

60

Duval, C., et al., International Petroleum Exploration and Exploitation Agreements: Legal and Policy Aspects, 2nd edn., pg. 51, (New York, Barrows Company, 2009) 61

Fattouh, B., North African Oil and Foreign Investment in Changing Market Conditions, pg. 15, Oxford Institute for Energy Studies, 2008 62

Supra, note 27, pg. 163

33

country (HC) to acquire as much economic rent as possible.63

In Indonesia for example

whose natural gas fiscal regime is tied closely with the PSC (which is for both oil and gas),

State revenues comprise tax and non-tax revenues; with tax revenues being corporate and

withholding taxes, and non-tax revenues including the State‟s production entitlement and

other revenues in the form of exploration fees and early signature bonuses.64

In our first example above concerning the rights structure in legal systems, the fiscal policy

can be as simple as just a return to the investor of costs incurred from the transportation of the

natural gas to the delivery point. Such a policy when being implemented must be cognisant of

the cost ceiling,65

realising not just the profitability aspects of oil as opposed to gas but also

that the IOC may not be gaining access to revenues associated with natural gas if so

delivered. In essence, a cost ceiling in such a scenario is not taking into consideration the

contractor‟s inability to take advantage of any upside potential of the gas once delivered,

moreover if such a ceiling is low, the upstream producer would in effect be subsidizing the

HC gas production with potentially huge sunk costs.

On the other hand, where the rights associated with discovered gas stipulates a production

share to the upstream producer provisions have to be made that might affect the payment of

royalties or other related fiscal provisions. Often the legal structures have stipulated the

establishment of gas-development feasibility studies. The PA might require that upon the

discovery of natural gas, the contractor is responsible for the study which would involve a

fully detailed analysis of upstream, downstream activities, parties to be involved, legal as

well as technical and economic feasibility studies for joint-development.66

Of the main issues that arise in the feasibility studies are the pricing mechanisms for gas

which determine who on the value chain gains more rent and how. Legal structures have

often addressed gas pricing in a number of different ways. Four traditional methods are:

63

Economic rent being defined as the products sale price minus the cost of production and in the case of natural gas; transportation, distribution and a minimum return on capital employed throughout the value chain. Supra, note 27, pg. 166 64

Supra, note 58 65

Typically in production sharing arrangements the contractor is reimbursed for cost associated with exploration and development, in most situations however and within the fiscal year the cost recovery limit is often capped to allow HC to recoup some revenue. 66

Supra, note 30, pg 186

34

The Cost-plus price: which typically represents the lowest price the upstream

producer would sell its gas to the downstream operations – that all costs are covered.

So essentially the pricing in determined by the costs of upstream development plus an

agreed margin.

The Netback price: unlike the cost-plus, the netback considers rather the cost of

downstream operations with a determined margin making the gas transfer price

(GTP).67

The Fixed price: the price of natural gas is determined by a contractual period often

with mechanisms for price adjustment.

The Market value: here price is ultimately determined by market forces, and factors

such as demand, supply and substitute energy sources play a role in determining final

price.68

It is often stated that the market value price is more favourable to producers as it is the only

method which fully takes into account the market forces as price is determined by what the

end-user pays,69

however, uncertainty arises in regions where the market forces are less

mature, and where such a price mechanism would therefore pose further risk to the upstream

producer who would essentially be bearing the market risks. There are several ways this can

be mitigated:

Protect the upstream producer by establishing within the legal structure for natural gas

a mechanism that guarantees that the producer‟s costs are always covered. This can

however, mean that the upstream operations might be accepting a lower share of the

overall economic rent in exchange for downside protection.

Where a resource tax is associated, reducing the tax burden might reduce the costs

associated with upstream operations, thereby reducing the GTP. This can be justified

at the upstream level considering that often upstream production tends to be

associated with more rigorous fiscal structures.

The reality is that often in such uncertain market environments the most appropriate way of

determining price is by the fixed method, mainly because the gas price is often tied to long-

67

Supra note, 27, pg. 171 68

Supra note, 30, pg. 187 69

Supra, note 30, pg 187

35

term contracts a resulting effect of the risks inherent. The usual means of managing risks is

by using contractual features like the „take or pay‟70

to control market forces. It is also likely

that in immature gas markets the upstream producer would also be involved in the entire

value chain, meaning therefore that it would typically want assume more risks in areas of

potentially more economic rent. Alternatively, where a project is wholly integrated a “fiscal

ring fence” around the entire project can be implemented. On the other hand such bold fiscal

moves might prove to be burdensome administratively, as they require a wholly new taxation

administrative practice, a process like this would be a challenge for weaker economies with

weaker tax administrative apparatus. The feasibility study should ultimately determine where

such an opportunity might lie.

Producer Supplier Arrangements and Risks Allocation

This level of the gas chain is said to be the backbone of the entire gas industry.71

Though

these arrangements come at the later stages of the gas value chain, they nevertheless could be

the source of several structural issues for creating a gas market, and greatly influence the

decision to invest. The essential aim of the producer supplier contract is the shifting of risk

either from the producer entirely or partially to the buyer depending on the level and maturity

of the market. In a developing market it is likely the buyer is a utility provider like power

generators or the State itself. The risk here is that the producer has essentially very few

offtake routes, so certainty is built into the contract creating an avenue for production to

commence. In a strict sense, the producer wants to be paid whether or not the buyer wants the

gas, and thus a contract can address this, the best way of doing so is through a take or pay

mechanism (TOP). TOP is a means through which the volume risk discussed earlier is passed

to the buyer. This obligation is adjusted for flexibility depending on the circumstances.

Extremely risky environment a 100 percent TOP obligation in favour of the producer is

possible, with no carry forward or make-up rights, the excess gas (that is gas not needed by

the buyer) can essentially be used by the producer in whichever manner it chooses.

70

Determine which party has the obligation for the predetermined minimum volume in periods of higher or lower demand. 71

Dow, S., Downstream Energy Law and Policy, Primer: Gas Privatisation, Liberation and Markets, pg 13, 2010

36

4.3. Nature of Gas Clauses

Gas clauses within these PA‟s have typically been the means through which legal rights and

obligations have been illustrated for natural gas. A handful of nations have at a very early

stage realised the potential of including detailed terms in their petroleum agreements for the

treatment of gas. Unfortunately, the numbers of developing nations that have made strides in

this area are few compared to the potential for all such countries to follow suit. There are

typically three types of gas clauses: the, (i) those that stipulate that upon discovery of natural

gas (while exploring for oil) the parties will negotiate the terms to manage exploitation, or as

the author dubs, the “we will negotiate later if need be” clause, (ii) ones that provide for

(typically a paragraph long) broad statements of policy, and stipulate that gas be handed over

to the government with no further details of the relationship structures that arise such as

pricing and or recovery of costs, and finally (iii) the more detailed provisions which takes

into view a host of downstream and upstream issues as well as offering more favourable

terms for IOC‟s in fiscal take as well as in production share. We shall look at a few examples

from some producing nations, as well as describe their implications for attracting investment

for gas development.

We will negotiate later if need be:

A traditional gas clause was clothed in a general language, since the goal was usually for oil

E&E the clause would make a general statement about the treatment of AG and non-AG if

found while exploring oil. The Angolan Model Production Sharing Agreement of 200872

is

such an example of which article 29 says:

1. Contractor Group shall have the right to use in the Petroleum Operations, Associated Natural Gas

produced from the Development Areas.

2. Associated Natural Gas surplus to the requirements defined in the preceding

paragraph shall be made available free to Sonangol, wherever the latter so determines. The cost of

transportation of said gas by pipeline is a recoverable cost under the Law.

3. If Non-Associated Natural Gas is discovered within the Contract Area then Sonangol will have the

exclusive right to appraise, develop and produce the said Gas on its own account and risk.

4. If Sonangol so determines and if agreed with Contractor Group within a term determined by

Sonangol, the discovery of Non-Associated Natural Gas shall be developed jointly by Sonangol or one

of its Affiliates and Contractor Group.

72

Angola Model Petroleum Share Agreement, 2008

37

The above provision is typical of those found in oil-producing developing countries. The lack

of a definitive description of the basic terms relating to natural gas as it does with oil

multiplies the risks for investors at the exploration and exploitation phases. The above

provision seems to grant a contractor the opportunity to use AG produced from the respective

area without any indication or reference to the determination of allowable flaring rates, the

surplus of which is then handed over to the NOC Sonangol, thereby the NOC in this case is in

sole control of the commercialisation of natural gas.73

The model agreement offers no

guideline for the determination of the amount of gas the Contractor should pass on to

Sonangol, and as a result leaves ample room for waste or flaring. From the perspective of the

Contractor, flaring would be the most viable option, since the delivery of gas to Sonangol

would involve extra capital costs (transportation or otherwise), and even where stated as

recoverable and as discussed earlier in this chapter coupled with a cost ceiling would mean

sunk costs. Also, the lack of any detail pertaining to the rate at which costs would be

recovered adds to the vagueness of the clause and further, on the inherent risks within the

provision.

This provision impedes the production of natural gas for the obvious reasons stated above; it

is not surprising that Angola continues to suffer from under-utilization of its gas. In 2007, the

Minister of Oil issued a statement declaring that in an effort to aid natural gas resources, as

well as mitigate the strain flaring causes the environment, a 2010 deadline for non-flaring

was to be initiated,74

the effect however of this deadline has not been felt. Angola not only

still maintains lax provisions for gas in its petroleum contracts but has also stipulated that the

best way of reducing flaring would be to initialise its LNG project, but such a program is

scheduled for 2012 with no indication of the legal regime to usher in a period of Angolan

LNG, but also to sustain investment interest in Angolan natural gas as a long-term strategy. It

therefore remains that Angola will continue to flare high rates of natural gas until the

necessary frameworks gas utilisation as established.

73

In reality however, Sonangol is in Partnership with some contractors to develop the natural gas fields, nevertheless the decision not to include this practice in the main provisions of the PSA might immediately deter natural gas investment 74

Angola Targets 2010 to End Gas Flaring, Petroleum Africa, Oct. 9, 2007, at http://bit.ly/hsRfBO

38

4.3.1. Broad Policy Principles: Ghana Case Study

The Ghana Model Petroleum Agreement75

on the other hand offers a slightly more detailed

provision, a key component of which is the classification of the two types of gas namely; AG

and non-AG and specific conditions for the flaring of AG. Furthermore the Ghanaian model

envisions the participation of the Contractor in the development and subsequent

commercialisation of gas which the Angolan model doesn‟t. A development plan (or

feasibility study as mentioned earlier) subsequent to the discovery of natural gas is to

commence, although no specific reference to the terms of the area held by the contractor as

distinct from that of oil is stipulated.76

The determination of fiscal terms for the production of natural gas following a commercial

assessment are stated to be negotiable and with specific provision that such a term will be no

less favourable than that of oil.77

Allocation of natural gas between the parties are to follow

that of crude oil, however, for incentivising interest in gas production the same provision

stipulates that the royalty rate for gas is to be reduced to 5 percent, where crude is at 12.5

percent. There is no express formula for determining the gas price, and this might inhibit

possible investment interest. The provision makes it difficult to ascertain the points at which

the investor reaps the maximum benefit; there is no clear avenue of assessing rewards along

the value-chain, where for instance an upstream producer might want to be involved in

downstream operations. The Model Agreement does, however, have a downstream focus, it

provides for commercialisation and market feasibility options. Article 14.12 in particular

provides for further discussions on the required contractual arrangements needed to tie well-

head gas with the buyer or consumer, this is envisaged as a component of the wider

commercial assessment to be carried out by the Contractor.

Because gas cannot be exploited unless a market or financial arrangements exist, the

exploration period for gas needs to be extended beyond that of crude oil, this time is typically

75

Model Petroleum Agreement of Ghana, (2000) 76

“Most petroleum arrangements do not recognize the fact that the possible periods and areas defined in the contract may have to be different for gas and for oil, because gas is subject to a development logic different from that of oil,” United Nations Centre on Transnational Corporations, Natural Gas Clauses in Petroleum Arrangements, Series B no. 1, pg. 12, (United Nations, New York, 1987) 77

No specific method for deciphering the gas output price is stipulated

39

used to determine whether gas discovery can be commercially developed.78

This is known as

the right of the Contractor to retain the area as stipulated in the Ghana Model agreement, until

such time as further appraisal can be made, or necessary markets developed to make

exploitation commercially viable. An agreement would be subsequently concluded between

the contractor and the GOG to retain the gas prone area.79

For an AG field the extension of

the gas exploration period would seem challenging, considering that an oil development

program might begin before the gas exploration period concludes. Careful considerations of

possible periods of flaring or interim uses for natural gas during these periods should be

expressly detailed in its gas clause.

The GOG Model Agreement fails to provide the necessary details needed to create a certain

environment for investor confidence in producing gas from its nascent fields. At the onset,

there are no specific incentives for gas exploration, Article 3, which discusses the obligations

during exploration period fails to make specific reference to any special interest that might

arise where natural gas is discovered during such a period. It is important to note however,

that the GOG Model is unique in that sense that exploration and production risks are

essentially indistinct and in most cases there is strong indication of an exploration license

being converted to a right to develop and produce.80

Furthermore, the provision doe not detail price implications as well as downstream

infrastructure required to bring developed gas to market, nor does it provide a process at

creating such an avenue where there is none. There is no joint development plan, or unit

development plans such that the threshold volumes needed to achieve commerciality are

attained.81

The lack of lucid guidelines for the determination of a gas price, a compensation

regime, nor a detailed joint development option for the different tracts of gas undermines any

goal the GOG may have at encouraging the development of a natural gas market.

78

Supra, note 32, pg. 185 79

Papua New Guinea provides a good example of this retention license, as a result of recommendations contained in its 1995 Gas Policy, the fact that there was no mechanism through which potential investors could retain their discoveries until the appropriate time necessary to accumulate commercial quantities necessitated the need for an extension mechanism. Nwokolo A., General Principles Governing International Petroleum Investment and Regulation: How Does Papua New Guinea Measure Up?, pg. 38, (Centre for Energy, Petroleum, Mineral Law and Policy, LLM Dissertation, 2004) 80

“Compare this to the US Gulf of Mexico license where the explorer has no security of tenure to take him to production - which means exploration is solely seismic and possible exploratory drilling,” Stephen Dow 81

Supra, note 32, pg. 185

40

It was thus not surprisingly that as soon as crude oil was discovered in commercial quantities

in Ghana, efforts were under way to ensure the “first oil”82

was delivered on time,

negotiations for the commercialisation of the vast resources of associated gas found at the

Jubilee field lagged behind. Most of the field contractors (a majority of which were smaller

oil companies with no natural gas development experience) were apprehensive, the lack of a

readily available market for the gas, and indistinct guidelines to arriving at a gas price further

added to the delay.83

It so happened that at first oil (15 December 2010 to be exact), the

nascent Jubilee field started flaring with its commercial oil production.84

In December 2010

(same month of first oil) the government established the National Gas Development Task

Force (NGDT) to look into ways the Government can commercialise its gas reserves, the

Task Force were given a mandate to bring recommendations as to how this might be

achieved. There are two fundamental issues at juncture first is ideally such a Task Force

should have been constituted at the onset of natural gas discovery and secondly the task force

seems to have assumed the functions of the feasibility study envisioned in the PA but with no

participation from the upstream producers, this is a grave oversight. The recommendations of

the Task Force led to the incorporation of the Ghana National Gas Company (GNGC, in

2011). With these GNGC the GOG indicated its preference to assume all responsibility to

bring natural gas to the market, however, the mandate of GNGC is purely midstream and

downstream, that is from transportation to end user, there is little incentive for upstream

development initiatives or private sector exploration and production feasibility.

Developments in Detailed Gas Clauses

As evidenced in the illustrations above, the less comprehensive a PA is with regard to the

terms governing gas development, the more uncertainties it provides to potential investors,

thereby increasing their project risk profiles. Some nations nevertheless, have approached gas

provisions from a more practical manner and Egypt is a prime example. In the early 1980‟s

82

The first commercially produced oil 83

This situation was worsened by the uncertain nature of the country’s legal and regulatory regime, its proposal to revamp the old hydrocarbon law and institute a new comprehensive one was still being debated at the commencement of first oil adding further to investor uncertainty 84

The GOG has since entered into a USD1 billion Loan arrangement with the International Finance Corporation as well as the World Bank to transport Jubilee gas from the FPSO to onshore facilities for power generation. The utilisation is said to commence in 2012, however, until then the field will continue to flare large quantities of AG. For a developing country with budgetary imbalances this has added a further burden public funds, which could have been avoided had there been a more comprehensive agreement encouraging private sector funds

41

Egypt had vast amounts of untapped natural gas, but it had hitherto taken the view that gas

was only to be exploited by Egyptian owned entities, evidenced in its early exploration

licenses which stipulated that gas discovered would become the property of the state, this

became a disincentive for foreign contractors looking to utilise gas discoveries.85 In an effort

to change this trend Egypt developed a new gas clause in its concession agreements. The

Shell Winning agreement paved the way for the development of future Egyptian

concessions.86

The novelty of this concession agreement87

is the relative weight given to gas

as it does with oil. The concession also evaluates the two fuels separately in terms of

production split, with more favourable terms for gas as well as adjustments made with regard

to volumes of gas. This is essential keeping in mind that with gas volume and price often

have a strong correlative relationship, especially in the case of developing markets, where it

is possible to sell small volumes of gas at a relatively high price, but larger quantities must be

sold with lower prices, the production splits therefore at the contracting stage must reflect the

issue of volume and price adjustments respectively.

Furthermore this concession is novel in the sense that it specifies conditions for the gas sales

agreement (GSA), for when the NOC purchases gas from the contractor thereby for the

potential investor it provides a clearer vision as to likely downstream implications. This GSA

includes within it terms for take or pay (TOP), with a TOP limit of 75 percent. The

importance of stipulating TOP guarantees cannot be understated the earlier concerns

surrounding the Iraqi gas licensing round in 201088

were undoubtedly assuaged by the

introduction of TOP guarantees.89

The fiscal provisions assume separate terms of cost

recovery for natural gas, but are nonetheless still negotiable. In other examples, the

Indonesian PSA (of the 1980‟s) also splits production share more favourable towards gas, but

also specifies a detailed cost recovery regime for gas.90

The Vietnam model on the other hand

goes even further, where the allocation, royalties, cost recovery and ceiling are all different

for gas and oil.

85

History of Egyptian General Petroleum Corporation, at http://bit.ly/dWmSTU 86

Dean, L., ed., Regional Surveys of the World: Middle East and North Africa, pg. 331, 50th

edn., (London, Europa Publications, 2004) 87

See for instance the “Concession Agreement for Petroleum Exploration and Exploitation between the Arab Republic of Egypt and Ganoul El-Wadi Holding Petroleum Company” 88

Concerns mainly surrounding the lack of infrastructure for gas transportation 89

Supra note, 51 90

Supra, note 32, pg. 188

42

4.4. Gas Specific Regulations and Government Control

From these basic characteristics of the gas market, much like the power sector natural gas is

considered as a public utility and is, therefore, subject to a high degree of regulation, whereas

in oil, having 10% matters because of the scale of the rent (example production cost average

$20, whereas sales average $100), gas price regulation aims to take out the rent.91

This in turn

has led to a different structure and outlook of the gas industry, not only from an industry

perspective but also from a financial one. “This complex has been crystallized in contractual

and legislative practices which are very different for gas than for oil.”92

The degree to which

government involvement could encourage or hinder natural gas development efforts can be

determined by the structure of regulations.

Depending on the policy expectations of the gas bearing country, efforts for strict regulations

or not can be the means towards achieving those ends. For countries who view gas

development as a strong catalyst towards economic development, there are traditionally two

approaches the government can take. The first would be for regulations to be geared towards

gas being solely the responsibility of the country itself, and that only to the State can have

exclusive ownership of the gas reserves, and also the sole right to develop them. Such a

method was adopted early on by a number of countries in the Middle East, for example;

Saudi Arabia, Abu Dhabi and Qatar.93

Another method would be to allow both State and

investor participation in natural gas development but with heavy State and regulatory control,

a third is to completely privatise the natural gas sector with regulations design to manage the

rights of participants. This last scenario is rare considering the growing importance of natural

gas for national development agenda, moreover, privatised gas markets are typically found in

mature gas markets, so for country looking to develop its gas market it is not an ideal starting

point

With State control through regulations the government is left to balance two main objectives;

making sure there is enough of the resource for national consumption and development as

well as international trade to derive revenues, and for most developing economies, the ability

91

Dow, S., Natural Gas Regulations, CEPMLP (2011) 92

Colitti. M., Oil Industry Participation in Natural Gas, pg 152, Energy Vol. 10, no.2, pg. 151-156 (1985) 93

Note that in recent years this trend is changing to allow more private sector participation and rights for oil and gas companies

43

to attract investors in order to augment the States lack of capital and technical capabilities. In

the first case a number of regulations can be implemented to achieve this goal:

Establishing a DGO:

As mentioned earlier, this would essentially obligate producers to allocate a certain amount

of natural gas for local consumption. The rationale being to ensure the benefits of exploiting

the resource is realised in the home territory (this is especially vital for developing nations

whose development agendas require consistent fuel supplies). Through regulations, the DGO

is usually stipulated as a percentage of the gas production (see the Nigerian National Gas

Supply and Pricing Policy and National Gas Supply and Pricing Regulations, 200894

).

Producers are not typically in favour of such regulatory mechanisms as they have the

potential to further distort their bottom line. But DGO‟s can be designed to balance both the

policy objectives of government and investor security. Take for instance the Indonesian

version known as the Domestic Market Obligation (DMO) for natural gas. Indonesian gas

DMO is applied to a specific percentage of the proved reserves a level which is typically

negotiated and agreed by both parties (the government and PSC contractor). Gas DMO

volume then is calculated at the percentage agreed of proved reserves multiplied by the

contractor‟s entitlement percentage on volume after cost recovery (profit gas). 95

To protect

the PSC contractors, the obligation is made applicable to reserves as opposed to the specific

volume allocations, this is keeping in mind not just the issue of volume certainty especially

with AG fields but also the fact that gas sales contracts usually require long-term sales

arrangements.

The percentage reserves subject to DMO gas is stipulated in the PSC as to be negotiated and

agreed by both parties, this is mainly due to the various factors prevalent in determining the

size of the reserves, location relative to closest domestic market, gas prices (both for domestic

as well as for international sales), and costs related to developing and producing the gas.96

The price of the Indonesian DMO gas is also arrived at through negotiations with the

domestic buyer on an arm‟s length basis. It is important to note, however that DGO gas not

94

International Law Office, Nigeria: Domestic Gas Supply and Pricing Reform, 2009, at http://bit.ly/gPSYJU 95

Domestic Market Obligation: A Closer Look, at http://bit.ly/uBc7uy 96

Ibid

44

necessarily concerned with providing gas at less than market rates, this would simply be

subsidized gas. DGO can operate simply as a domestic volume obligation, or it can be

designed with price incentives although, it is typically the case that the price usually paid for

DGO is usually less than the wholesale price. This can be attributed mainly to the local nature

of the gas and the least efforts needed to transport the gas.

Without a strong pricing incentive for non-DGO gas, DGO‟s might actually act as a deterrent

to encouraging investment, especially for a nascent producing country without a mature gas

market. DGO‟s are strong provisions aimed at boosting local supplies and thereby facilitation

the development of the local gas market, however, depending on the market conditions it may

be necessary for regulations to stipulate a process for gradually weaning off DGO gas as a

incentive for investment. DGO obligations have been argued to improperly regulate the

market, the idea is that the gas prices being low and would have created a demand for gas that

would in essence be impossible to satisfy completely making it unsettling for investors who

fear regulators imposing higher percentages of DGO as domestic demand rises.

Furthermore, the potential for exporting gas provides a premium market, it is vital therefore,

that the State expressly gives permission for investors to export gas outside domestic

obligations. The commercial viability of export projects would also depend on a number of

government guarantees, one being that export reserves will not at a future date be anticipated

for local consumption (so essentially the State should give as many express guarantees for

non-DGO as it does for DGO).97

An express guarantee is important especially to the producer

who is also involved in the whole value chain, the investor will enter into international

contracts with international sellers ensuring volume risks are adequately allocated, not to

forget that for financing purposes unless there is a high guarantee of proven reserves for

export the loan process might prove futile.98

97

United Nations Centre on Transnational Corporations, Natural Gas Clauses in Petroleum Arrangements, Series B, no. 1, pg. 12, (United Nations, New York 1987) 98

Alternatively there could be a stipulation for conducting periodic public hearings to determine the amount of gas needed for local consumption as was the case in Canada – but this does not illuminate the risk of change. The Egyptians approached this by requiring proportional amounts of gas to be provided by each contractor (see also the Nigerian example), thus no one contractor is burdened with the obligation

45

End-user price regulations:

This can be done in a number of ways, either through State subsidies to the end-user (or

strictly to the household consumer), or rather as tax burden reductions at the producer end to

reduce GTP, or at the midstream level to achieve the same end. Although end user price

regulations do not directly affect producer end, it can still be detrimental to attracting

investment on that end especially where a credit worthy wholesale buyer cannot be

established, where the buyer fails to maintain its payment obligations the risk is likely to fall

back onto the seller (who is ultimately not paid for the delivery), where the buyer is state

owned the issue is further compounded. To avoid this perception therefore, direct State

guarantees should be implemented to protect the producer from bearing such a risk.

Regulation of Downstream Activities:

Mid and downstream activities also require a system of regulations when developing a gas

market. Depending on who the State chooses to develop the infrastructure (either the HC

itself or a private participant), rules need to be designed for access to this infrastructure

because it is likely that the produced gas will not be coming from one field and thus not one

producer, or buyers who would need to access the transportation to reach end users. In a fully

integrated project, which most developing gas economies are, the contracts simply determine

the access regime (especially for the pipelines) in which case production, transportation and

sales are all on project, This is straight forward as most transportation infrastructure are

monopolies. Where the infrastructure is owned by a private sector participant, the regulatory

decisions on price controls for the natural monopoly elements need to be accessed bearing in

mind the upstream costs, that is, who is paying for the transportation, if the upstream

producer is, the price control must ideally reflect the risks the upstream player bears.

The potential for exporting natural gas provides an essential premium market for gas. It is

therefore vital that regulations also give permission for the producer to export gas outside

domestic obligations and contractual requirements (they may be the same). Because of the

inherent price risks in domestic markets, producers have been hast in seeking LNG export

46

projects.99

But the commercial viability of an export project would also depend on a number

government guarantees, one being assurance by the government that export reserves will not

at a future date be anticipated for local consumption,100

this is important because the producer

would need to get into contracts with the international sellers who inter alia requires volume

guarantees. Moreover for limited or non-recourse financing purposes lenders would be

unwilling to finance projects unless there is a high guarantee of proved reserves for export. It

is submitted that such a guarantee be stipulated in a legislation or regulation.101

99

Supra, note 64, pg 6 100

Ibid, 101

Ibid, pg. 19, another is the mechanism conducting periodic public hearings to determine the amount of gas needed for local consumption as was achieved in Canada. Egypt approached this by requiring proportional amounts provided by each contractor (see also the Nigerian example), thus no one contractor is burdened with the obligation.

47

5. Petroleum Licensing and Natural Gas

Licensing plays an essential role in the legal framework in the natural resources world, it is

the primary avenue where the policy objectives espoused earlier are realised and rights and

obligations are transferred from the State to the party willing to bear those obligations. In the

Petroleum world the word “Licensing” is a broad term which does not just encompass an

authorisation to perform certain duties but that which in Michael Bunters‟ view consists of

several components including, the identification by the right-holder (namely the Government)

of the “potential investment value of a prospective acreage in the national territory for the

purposes of petroleum explorations and production.”102

The later subdivision of this

prospective acreage into unique contractual entities spells in Bunter‟s view another stage of

the licensing process, with the final stage involving the marketing of such interests to

potential IOC‟s and other interested investors. Bunter‟s definition is accurate and

comprehensive. This paper presumes that the state entity holding title to the prospective

acreage has already identified and carved out the unique contractual space for exploration and

or exploitation. So in this analysis of the licensing process we shall adhere to the limits of the

term and focus mainly on the point at which the title holder aims to secure investment for

natural gas development through an allocation process. It specifically analyses the process of

license allocation and their practical result or effect on natural gas development efforts.

5.1. Evolution of the Licensing System:

Many authors would stipulate that the evolution of the modern petroleum licensing system

arose out of the virtual collapse of worldwide oil prices in the late 1980‟s to 1990‟s, which

saw prices fall from $45 per barrel (bbl) to (in some instances) under $10 per bbl and

changed the process by which governments allocated petroleum rights.103

The “oil glut” as it

was then known arose as a combination of factors, but mainly due to the surplus of oil on the

world market as demand correspondingly fell as a result of the 1973 to 1979 energy crisis.

This meant that rents linked with oil production drastically decreased, making production

ventures which were typically economically viable at a certain rate being developed at much

102

Bunter, M., The Promotion and Licensing of Petroleum Prospective Acreage, pg. xvii (The Hague, Kluwer International Press, 2002) 103

Hershey, R.D., Jr., "How the Oil Glut is Changing Business", (The New York Times, 1981-06-21)

48

lower rates than had been anticipated. It is reported that in 1986 there was a 31.4 percent

average in expenditure by the largest twelve companies as compared to the year before.104

The acquisition of new exploratory licenses was thus, rare, so that in an effort to utilize

potentially economic petroleum fields, producing nations started to take the „bull by the

horns‟ so to speak and embarked on an array of incentives designed to lure IOC‟s.105

The UK

in its North Sea operations kick-started a range of fiscal incentives and encouraged costs

savings and risk mitigating measures, these came various forms of risks sharing which

culminated to decreases in project costs.106

As a result the UK‟s marginal government take

which was at 90 percent in 1982, was reduced to 65 percent for older fields and 30 percent

for more recent fields.107

These methods were innovative ways governments sought to not

only reduce the burden on oil companies they also essentially tied the structure of the

petroleum license with the projected value of the commodity.

Others soon followed suit, many revamping their contractual and concessionary based

processes with new comprehensive authorisation regimes, where at their core was the

establishment of arrangements packed full of incentives. Licensing rounds were introduced,

these were perhaps a unique way for oil rich economies to open up their territories for full

competition, on one hand to increase upfront government take (for instance through signature

bonuses), and on the other hand spearheading a petroleum sector with its monetary and fiscal

conditions in favour of foreign investment. These incentives ranged from the reduction and/or

waivers of royalty and tax rates, to lower host government or national oil company (NOC)

participation, thereby lesser control of domestic E&E operations. For downstream activities,

import and trade restrictions were avoided. IOC‟s saw a sweeping surge in their market

control as newly opened acreage was awarded to them on favourable grounds. This period

also saw the development of the extension of production life with the introduction of

enhanced oil recovery techniques (ERT) as well as the encouragement of gas development

projects.108

104

The Oil and Gas Journal, (March 23, 1986) 105

The bargaining power therefore shifted in favour of the IOC’s 106

Supra, note 25, pg. 2 107

Duval, C., et al., International Petroleum Exploration and Exploitation Agreements: Legal and Policy Aspects, 2nd edn., pg. 51, (New York, Barrows Company, 2009) 108

Ibid, pg. 52

49

In the natural gas subsector, Argentina embarked on regulatory changes in its downstream

gas sector, namely; the privatization of the national major State held company Gas del Estado

(GdE), as well as its upstream oil and gas company, Yacimientos Petroliferos Fiscales

(YPF).109

The efforts proved successful110

as exploratory and drilling projects picked up soon

after implementation of the new regulations.111

Brazil closely followed suit with the partial

privatization of Petrobras.112

Natural gas reforms in this era were mostly centred on privatisation and increasing third party

access to infrastructure as a means to incentivising investment, as a result countries that did

not possess the necessary infrastructure at this time, could not utilise the new wave in

attracting investment for development. Countries like Nigeria had they previously had

existing pipeline infrastructure capacity for gas delivery, or readily available local and

internal markets would have seen this period as potentially vital in attracting investment,

instead, rather the oil industry received the majority of its share.

Moreover the period was characterised by an increase in developmental assistance from

multilateral institutions such as the World Bank and International Monetary Fund (IMF), who

embarked on a series of sector development campaigns.113

Mostly benefiting were non-

OECD developing countries where a pre-requisite involved the restructuring and privatisation

of their respective sector activities. World Bank assistance especially was important for many

developing nations whose cash strapped systems proved challenging in the revamping of

national regulatory systems. Support came in the form of system-wide reform assistance, so

as to encourage foreign capital to boost the development of resources. With regard to natural

gas development assistance, the World Bank conducted a study relating to the issues raised

by natural gas discoveries, the study led to the drafting of the World Bank model clause, also

109

International Energy Agency, Regulatory Reform in Argentina’s Natural Gas Sector, pg. 9, (OECD, IEA, 1999) 110

Since 2002, however, the result of the Argentina economic crisis has affected mostly its natural gas sector, a combination of factors such as price controls and untimely tariff adjustments have placed the industry in a precarious situation. 111

Note that this process was particularly straightforward for Argentina because not only did it have the necessary transportation facilities in place prior to its privatization efforts, it also had years of prior experience with its own natural gas and oil and gas entities, in this regard, privatization served mainly as a means towards further opening up a market which was already desirable to some extent to private investors. Not to also forget that Argentina is particularly unique because its positions meant that it has a readily available market waiting to derive benefit from its production 112

Supra, note 29, pg. 50 113

Supra, note 25, pg. 4

50

known as the “World Bank Gas Clause.”114

Turkey for instance adopted this clause, which

much like the detailed clauses described in chapter 3 encompassed the whole value chain

from upstream to downstream operations.115

Gas development efforts, however, still lagged behind, most initiatives rather focused on

fiscal structures for oil production, ignoring the need for detailed provisions addressing

natural gas authorisation and licensing allocation procedures and other ancillary issues. The

modern petroleum licensing era was nevertheless born with a culmination of reforms

resulting in a dominos effect. Most producing countries began to create robust and

comprehensive petroleum allocation systems, following an array of trends; the optimal design

of which reflected a host of factors, such as the policy objectives intended, the prospectivity

of acreage and country specific (of mainly economic and political) considerations.

5.2. Petroleum Licensing Today

It is obvious that in the petroleum sector a countries‟ license allocation system mostly reflects

not just national preferences but also to a large degree the nature of petroleum prices. What

the price of the commodity does is to establish how economic rents are allocated. Where

petroleum commodity prices are at their highest both government and IOC revenues from

petroleum receipt are also at their maximum, where they are at their lowest IOC must balance

this with cost of production and may find after assessment that projects to be uneconomical.

At this juncture a government designing an allocation system considers giving as many

incentives as possible to encourage the IOC‟s decision or make the project more attractive.

So in this case the IOC‟s are said to be in the driving seat if there are negotiations.

In the past decade the increasing nature of current oil prices,116

has resulted in a significant

change in bargaining power, shifting from the IOC‟s the decade before, to the title holders of

petroleum fields (Government). These circumstances became even more exigent for the

IOC‟s as the era of globalisation has witnessed increasing new forms of international

competition, and as some of the world‟s major NOC‟s start to venture into international

114

The Clause was designed to give a comprehensive treatment of natural gas, taking into account a host of issues upstream related right down to the downstream aspects 115

Supra, note 59, pg 189 116

In July 2008 for instance, oil prices rose to a record $147.27

51

markets.117

Producing nations have begun to take advantage of this new scramble for

resources. The evolution of the ever increasing signature bonus illustrates this point. A

culmination of factors, including the need for producing states to capitalise on the new

scramble, has resulted in an unprecedented level of upfront bonuses sought. Compare the $1

million signature bonuses sought in the 1990‟s Nigerian contracting system to the post-2000

numbers, which have ranged from $75 million to $145 million recorded in the 2004 Nigeria

Sao-Tome Joint Development Zones‟ second bid round (a 14,400 percent increase in just

over a decade).118

Similarly, in 2009 ENI paid $902 million in fierce competition for

Angola‟s block 15 (in close proximity to a producing block), the highest bonus ever recorded

for an exploration block.119

Ironically, these amounts are not expected to place unreasonable

burden on the oil companies, provided the discovery volumes live up to expectations.120

In

terms of current crude prices, these amounts closely represents each block, and when

calculated should reflect a fraction of the estimated reserve potential. It would thus not be

economically prudent for governments to refuse such opportunities to maximize rents.

Nevertheless even if the IOC‟s would prefer to avoid these upfront bonus payments, they

have in large parts come to be defined as permanent features in most licensing regimes, and

have evolved into a range of different forms.

What remains to be adequately researched, however, is the effect the size and structure of the

signature bonus would have on the natural gas licensing process. It is assumed that where the

license envisages oil and gas E&E, for the most part the size of the bonus will reflect the

prospectivity of the oil acreage on offer, but where the license on the other hand is solely for

natural gas E&E any design of a bonus structure will have to take into account the additional

risks and costs that would be involved in the gas value chain, especially where the license is a

developmental authorisation. For developing nations in their efforts to attract investment it

may not be prudent have excessive signature bonuses, or even at all, taking on a number of

factors including competition for these fields as well as the anticipation of additional costs at

117

The rise and the influence of NOC’s has been tremendous. An updated list of the most powerful and emergent players

in Oil and Gas now includes mainly State owned oil companies (e.g. Saudi Aramco, Gazprom, China National Petroleum Corporation (CNPC), National Iranian Company (NIOC), Petrobras (Brazil) and many more. IOC’s are facing increasing challenges from NOC’s. 118

World Bank, International Development Association Supplemental Finance Document to the Republic of Sao-Tome and Principe, 2009 119

ENI Reaches TD at Third Well on Block 15/06 – Angola, (International Oil Letter, Vol 25, issue 17, 2009) at, http://bit.ly/g6gJRK 120

Clark, D., Petroleum Prospects and Political Power, (Angola’s War Economy, Institute for Security Studies, 2000)

52

later stages of development. Iraq for instance in its 2010 gas licensing round scrapped the

initially anticipated signature bonus (which amounted to $100 million and $500 million for

each winning bid in earlier rounds), this was said to be an incentive to encourage more

private sector competition in the rounds.121

Bonuses may be justified where a distinction is

made between a gas license which is purely for exploration purposes and that which gives

permission for development, a bonus in that regard might not be a deterrent if geological risks

can mitigated. For a natural gas specific allocation system such bonuses are for the most part

avoided, and should continue to be avoided, until the value of the resource can be estimated

to bring in extra profits to justify upfront government take.

5.3. Allocating Petroleum Prospective Acreage

The design of a petroleum acreage awarding system often commences with the title holder

envisioning several objectives; these are realised by the ways in which the title holder

(typically the government) defines the economic objectives as a means towards ensuring the

maximization of macroeconomic as well as social benefit. To attract investment, the optimum

program must also be flexible; such that it is formulated to adjust due to changing

circumstances. The effective petroleum allocation system typically takes into account:

i. The nature and characteristics of the area to be licensed122

ii. Structure if the market (for instance in a natural gas market the determination of

whether an internal market exists for gas, and if so to what extent)

iii. Ownership structure (this is usually detailed in the type of legal regime)

iv. The existing regulatory and institutional systems in place

v. And other external factors such as future prices, local and international123

Some territories have realised the need to develop distinct objectives for natural gas when

designing such principles. For example, when faced with growing energy demands, the

Mexican government and Petroleos Mexicanos (PEMEX), set out distinctive objectives to

121

Ersoy, E., and Razzouk, N., Iraq Sets Natural Gas Bidding for Oct 1, Scraps Signature Bonuses, Bloomberg, at http://www.bloomberg.com/news/2010-08-02/iraq-delays-bidding-round-for-three-natural-gas-fields-oil-ministry-says.html 122

For instance, a design might take into consideration large pockets of natural gas reserve potential, with a clear mind of the title holder of having these reserves exploited 123

Supra, note 42, pg. 29

53

ensure further investment of its natural gas markets. The licensing policy objectives with

respect to natural gas were:

i. To significantly increase national production of natural gas, for the purpose of

electricity generation

ii. Produce more gas at a lower cost than the import costs

iii. Attract investment

iv. Improve the technical capabilities of PEMEX124

Aided with these objectives, the vision of improving Mexico‟s natural gas market became

more realistic and specific, encouraging the realisation of the said goals.

Though mainly broad, these objectives are later laid out to reflect country specific concerns.

In a highly prospective area for example, a full-on competitive bidding is viewed as the most

efficient way to allocate such acreage. A competitive process will have IOC‟s go head to

head, with the winner ultimately being the party with the “biggest pockets”. If the policy

agenda is tailored towards finding the most efficient and technically capable party, the

competitive system would be adjusted to reflect this, perhaps with requirements that only

contractors with such capability can enter into the competition, thereby ensuring not only the

best qualified party is awarded the exclusive rights, but also allowing the title holder to

maximize upfront rents from the process. This provides various opportunities for the

government entity to develop a system which arrives at whichever consequence it wishes to,

for instance, the Nigerian bidding rounds in 2000, 2005, 2006, progressively, became more

stringent as to their specifications for the inclusion of transference of technical know-how

and local content participation, such that they designed their bidding process to be associated

with local content vehicles (LCV‟s).125

Such a competitive bidding process has been tested in a handful of countries who wish to

develop their natural gas reserves. Pioneers in this respect are Saudi Arabia and Iraq

respectively. Amidst growing demand for natural gas and with vast untapped reserves of the

resource, the Saudi‟s launched their first licensing round in 2003 to attract investment (after a

long-term prohibition on the involvement of IOC‟s) in natural gas development. On offer

were up to three areas for licensing culminating to 150,000 square kilometres (sq) in south

124

Ibid, pg. 82 125

Ibid, pg. 32

54

Gawar, acreage, which Exxon Mobil and British Petroleum had previously bargained over.126

Recently Iraq launched its first licensing rounds since the toppling of Saddam Hussein. The

gas round was conducted in October 2010; five bids were made among which three were

awarded. Gas from these fields have significant roles to play in boosting the country‟s energy

availability, the competitive bidding was designed not only to attract international investors

but also local and regional interests. The strategic presence of Iraq makes it such that majority

of the bidding consortium included regional investors from Kuwait, Syria and Kazakhstan127

to name a few, but the bidding process though competitive by nature did not draw nearly as

fierce a competition as the previous petroleum rounds held earlier in the year, and it is also

the case that the final signing of the contract for the fields was delayed for close to seven

months. 128

Iraq finally signed a formal development agreement for the Akkas gas field

with one of the bid winners, namely; Korea Gas, who later had to increase its stake after Kaz

Munai Gaz the other bid winner withdrew.129

The Iraqi example as well as many other

similar examples in the natural gas licensing world has led many to ask whether in fact gas

licenses should be awarded on competitive bidding process (see chapter 5 for a discussion of

alternative methods). There are however, examples of LNG projects which have drawn high

competition, for instance Algeria‟s Gassi Touil integrated project, but the success of the

integrated LNG projects can in most part be attributed to the proximity of the gas to the

markets that highly require them, and close collaboration between involved States to pull

resources for the success of the project (as was the case with Algeria and Spain).130

It is obvious that the successful implementation of a license awarding scheme can vary across

regions, a number of considerations must therefore be analysed. In natural gas licensing this

is not just simply opening an area up for competitive bidding, nor of the area‟s prospectivity

as is evidenced with Iraq, but as has been realised with various such inadequately successful

licensing awarding schemes, a host of considerations must be kept in mind. One of which is

the interests of those the title holder aims to attract, as well as the reflection of the risk

mitigating circumstances discussed earlier for added certainty and investor confidence.

126

The Mail Archive, Saudi’s Start Their Charm Offensive, July 2003, at http://bit.ly/fXoaoB 127

HIS Global Insight, Iraqi Gas Auction, All But A Neighbourhood Affair, (Oct. 2010), at http://bit.ly/fWfE8B 128

Oil and Gas Insight, New Gas Licensing Round on the Card as Baghdad Signs Amman Pipeline Deal, January 2011, at, http://bit.ly/g5RQ1E 129

KoGas Deal for Akkas Gas Field is Signed, Iraq Business News, at http://www.iraq-businessnews.com/2011/06/01/kogas-deal-for-akkas-gas-field-is-signed/ 130

See also the historical case of the Foxtrot licensing round of the 1990’s , the Foxtrot gas field in Ivory Coast became a successful domestic gas project from a gas discovery relinquished by Philips Petroleum

55

5.4. Bidding Terms

Primary features of the bidding process are the terms of the bid. After careful consideration of

characteristics of the contract area, the nature and structure of the market (including the

markets competitiveness or lack thereof), legal parameters dealing with ownership and access

to resources, regulatory and institutional frameworks and other exogenous factors such as the

interest of participants,131

the government is then in a better position where it chooses to

auction the right through a bidding system, to set the parameters of the bid with those

characteristics and its own objectives in mind. A bidding structure can be in the form of an

administrative process where the above objectives are reflected to screen applicants who meet

the criteria or it may be conducted in an auction, with biddable and non-biddable terms.

Although in a bidding system the winning bid essentially wins the contract setting the terms

of the agreement, prior to the actual bid parameters might be set to for instance; to clarify or

define the terms of the license, such as areas of the license that may be negotiable or not.

Applicants especially in natural gas E&E processes want clarification of what their

obligations would be prior to the bid, for example, in the Iraqi 2010, natural gas licensing

round, the Oil Ministry had to assure prospective investors that were they to win the bid, they

would not have to find export buyers themselves and not have to develop production capacity

faster than the Iraqi midstream capacity was built.132

The assurances amounted to significant

improvements in the bidding terms. It lifted uncertainty lingering over the round, relieving

companies of the responsibility of finding export markets placing responsibility for bilateral

energy relations back with the State this was also a major assurance to mitigation of the

political risk factors.133

131

Supra. Note 91, pg. 29 132

Iraq Improves Gas Licensing Round Terms, by Removing Export Uncertainties, IHS Global Insight, at http://www.ihs.com/products/global-insight/industry-economic-report.aspx?id=106593816 133

Ibid

56

Bidding parameters must also include setting terms of all negotiable positions, it also requires

the government to define those areas of the fiscal structure it wishes to negotiate setting the

minimum target price and how best to collect it 134

(see box 1).

In essence the successful natural gas allocation system is will largely depend on how

effective the policy maker is at designing a process that balances the concerns of both public

and private sector. It would also involve a close collaborative relationship between the

designs of this process, and the details of the authorisation itself, for instance, a bidding

process cannot promise a result which is not ultimately reflected in existing model licenses,

unless clear negotiating parameters are defined.

134

Supra note 91, pg. 31

Box 1. Examples of Bidding Parameters and Terms for Natural Gas

In Trinidad and Tobago (2010 Bid Round), the natural gas terms was set in the PSC bidding structure. The

fiscal regime for companies operating under an E&P Licence was to include a Royalty, a sliding-scale

Supplemental Petroleum Tax (SPT), which is the subject of revision, Petroleum Profit Tax of 50%, and a 5%

Unemployment Levy charged on the base for Petroleum Profit Tax. A production levy up to 3% of Gross

Income was to be payable. Revenues for natural gas were not subject to SPT. There was also to be a new

regime for natural gas, which was to include a mechanism for determining the Government’s share of profit

petroleum and minimum gas price within the PSC while the same mechanism will be used for value export

gas for tax purposes. The State assured investors that Gas marketing will not be restricted to the local

market as in previous contracts and Contractors were free to now explore options for export or joint

marketing.

57

6. Evaluating New Licensing Possibilities- Lessons From Power and Mining

As has been hopefully demonstrated, the design of a licensing regime for natural gas as

opposed to oil deserves careful consideration of the uniqueness of gas, the interests of the

territory bearing the gas reserves, that of the host government and investor alike. A complex

system is likely envisioned because a process of this calibre means the interests of all parties

must be balanced to produce an outcome that is commercially sound to the investor as well as

a project that provides added benefits to the territory where it resides. So far the research has

suggested that perhaps governments especially those in the developing economies, need to

approach natural gas licensing from a wholly new perspective, an approach which not only

evaluates current structures but also one that goes outside the remit of the petroleum

frameworks and seeks to find solutions in similar sectors.

This new approach must begin from the allocation stage right down to the contracting

provisions themselves and to the sales provisions and must comprise wholly new calculated

attention to natural gas. The following is an attempt to illustrate some lessons that can be

derived from sectors that have similar features to the gas sector; it is an effort to borrow

practices and to demonstrate that governments needn‟t always look at traditional means to

resolve complex sector design issues. To do so the author will draw from various other

examples utilised in power and mining sector to ascertain a possible way forward.

6.1. Designing a Legal Framework for Allocation Natural Gas Rights

Lessons from the Mining and Power Sectors

Mining

Historically, petroleum and mining producing states have implemented varying degrees of

legal instruments, but across the two sectors there are both differences and similarities. A key

difference has been that in the petroleum sector a competitive bidding process has often been

the underlining mechanism for awarding rights, whereas in the mining sector the opposite is

the case135

(that is the first come first served approach) except in extraordinary

135

The competitive system is typically used on deposits that have already been fully appraised

58

circumstances.136

The rationales for the diverging ways of allocating rights are straight

forward. For the most part they are often based on the geological aspects of both mining and

petroleum. The geology of petroleum fields, generated by advanced technology through proof

of data is often the host government‟s (HG) main selling feature.137

Data of this kind provides

a robust conclusion as to the economic potential of the particular basin, therefore guided with

this knowledge the HG is typically is a strong negotiating position.138

To maximise rents

therefore, a bidding process allows applicants to go head to head and the deeper pockets as

explained earlier wins the bid.139

On the other hand, mining geological prospects do not tend

to be as group-together to the same extent as petroleum deposits, the relationship thus,

between the size of the deposits, and assumptions of economic potential are less evident. As a

result HG‟s being in relatively weaker bargaining positions often find that the best method to

allocate rights are often through the first-come first served approach (the first applicant gets

the license).140

There are however, a few examples of mining states that have implemented

auctioning for allocating mineral rights, a prime example is Algeria. In 2001 Algeria

established a new mining law which among other things promoted a granting process of

licensing on an auctioning basis, but the results were that though there were increases in

small-scale licenses, developments in large-scale and foreign investment still lagged

behind.141

The operational difficulties in determining to a degree of certainty natural gas reserves adds

to operational costs, where costs are higher governments often have to intervene to encourage

investment through initiated incentives. It must be presumed therefore that with both natural

gas and mining negotiations, the HG is left at the behest of the investor and therefore has a

reduced bargaining power. The question therefore derived is to what extent must the

allocation of a petroleum or natural gas license reflect this reality? Should the allocation

process for natural gas resemble the mining sector because of this feature? And if so why?

136

Land, B.C., The Similarities and Differences between Mining and Petroleum Investment: A Comparison of Investment Characteristics, Company Decisions and Host Government Regulation, vol.5, issue 2, OGEL, 2007, (LLM Thesis submitted to the Centre for Petroleum, Mineral Law and Policy, 1994) 137

Also coupled with greater economic attraction through high rents especially for oil and also certain features of petroleum that predisposes it to competitiveness 138

Note however, that in newly explored areas the HG might have no choice but to go for a non-competitive process, so in essence geological prospectivity plays an essential role 139

Girones, E.O., et al., “Mining Rights Cadastre: Promoting Transparent Access to Mineral Resources” pg. 10 (Washington D.C., USA: Oil, Gas, Mining Policy Division, World Bank, 2009) 140

The extent of the strict adherence to the first come first served approach will vary, some might actually include mechanisms for attracting technically capable applicants 141

Ibid

59

There are several implications for assigning a gas E&E license on a competitive basis; firstly,

if the government is allocating several blocks the decision to assign natural gas rights based

on a bidding procedure is predicated on the assumption that the natural gas development will

be similar across the board, this is not the case. 142

The nature of the downstream contractual

relationship makes it such that each natural gas field or deposit carves out its own economic

future; a competitive system assumes that all rights allocated are done equal terms for all

competitors, so depending on the nature of a contract between the contractor and the buyer of

gas, the economic outcomes with natural gas would differ greatly between deposits.

Nevertheless, the first-come first served approach in mining also has several disadvantages a

major one being that it is not an optimal model for a HG who intends on finding a technically

capable licensee. In the petroleum world this is almost a necessity, for natural gas even more

so because of the supplementary technical capabilities needed in disassociating chemicals,

deep sea operations are even more susceptible to this rule. It is the case then that the first

applicant though willing might not be the best candidate to effectively and efficiently exploit

the resource.

A further issue that typically arises in mining license design is the determination of the

appropriate methods to allocate rights. In the petroleum scenario, this would reflect in the

discourse of ascertaining whether the PSC for gas should be separate from oil as is typically

debated in mining. In some mining countries, for instance Mauritania, title holders can apply

for overlapping exploration licenses, with each one being valid for a different mineral. In this

case, the titleholder‟s rights are non exclusive, (because a license to the same piece of land

can be granted several times, although for different substances). “While the idea behind this

practice is to promote simultaneous exploration for different types of minerals, in practical

terms it presents serious difficulties, because two or more minerals are frequently present in

the same deposit or hosted in the same rock, making separate exploitation impossible. The

deposits of uranium and gold found together in the Witwatersrand district of South Africa are

one of the best-known examples of such a case”.143

142

But we know that this cannot be the case, firstly all deposits will have different profiles and the further difficulties linked with the ability to define to a certain degree of accuracy the degree of deposits 143

Supra, note 138

60

Oil and Gas title allocation must be put through similar scrutiny, understandably a repetition

of the overlapping license, where different title holders exist for exploration and production

would not be ideal for the exact same reason as stated above and even more importantly, a

developing economy with limited institutional capacity will not be able to manage the added

burden of monitoring overlapping production. Where the gas field is non-associated, of

course this would not be an issue, but then comes the question of whether licensees can

transfer their rights elsewhere, to investors who would be specifically interested in exploiting

the gas fields. In this case separating a PSC license for instance, for gas can generate some

positive effects especially in a developing gas market.

Electricity

The form and all the relevant economics of the gas market are also more similar to the

electricity market than to the oil market. There are base loads and peaks, tariffs rather than

prices, discrimination among customers according to the various uses of gas, and

transportation of both are for the most part is fixed.”144

In the power sector, however, the

licensing process is mainly a function of the power regulatory arm of the HG, and is

primarily designed to reflect the nature of the power market (i.e., whether it is capacity short

or capacity excess). An excess capacity environment is typically a competitive power

market,145

in such a case any new entrant would simply need to satisfy minimum conditions

to be awarded rights to generate electricity, the competitive aspect is inherent within the

licensing structure, for instance, it would be structured administratively and is perceived to be

transparent and open, allowing all applicants who meet the criteria to enter the market. In a

strained capacity environment on the other hand, a competitive or open ended allocation

system might not attract as much competitive bidding as required to reach full-capacity, this

is because an open-ended system presents further risk exposure to the participant. New

entrants would not want to access the market where his terms are not similar to that of others,

that is, he expects to come into the system and paid a premium for its services, this will

continue to happen with every new entrant brought into the system until the system reaches

excess. A competitive bidding structure therefore in a capacity strained environment includes

144

Supra, note 52 145

Although there are exceptions, for instance where all the power plants are owned and operated by one entity

61

incentives and further government guarantees and assurances in order to generate interest for

competition.

The natural gas market, however, only starts to resemble the power sector once the gas

reaches the wellhead and is to be transported, that is, from midstream to downstream. There

might be here the opportunity to have separate licenses for upstream natural gas exploration

and development and one for upstream transportation and delivery, with the midstream

allocating mechanism resembling the power sector BOT.

Effectively an appropriate design will differ from country to country. The examples given

here of possible alternatives is to illustrate that often times the characterisation of gas as a

petroleum commodity needn‟t always be so for licensing purposes. As evidenced, the

similarities across different sectors might prove a useful avenue for finding new alternatives

to attracting investment in natural gas and allocating rights as a result. The same can be said

for the licensing instruments themselves, i.e., the terms of the agreement once the license is

issued.

6.1.1. Form of License

As stated earlier, the relevance of understanding the varying degrees of legal instruments is

the difference in their approach in attracting investment for petroleum projects. A royal/tax

system, or PSC have similar results, but depending on their terms they can either be attractive

or not for the investor. Service agreements for instance have attracted much debate recently

and many IOC‟s shy away from them because they are essentially designed to keep as much

power vested with the title holder as possible, such that the investor assumes the limited

position of a legal contractor. The IOC is granted no right to mineral or petroleum rights, in

pure service contracts the benefit of future upside potential is eliminated, booking reserves

becomes challenging.146

146

But as suggested earlier a service contract can also be designed to look very much like a PSC. The buy-back agreement for instance, grants the IOC’s an economic interest, which entitles them to book a portion of the field production, and corresponding reserves. See, supra note 32, pg. 87

62

A key recent debate has been whether or not it would be appropriate to design a whole new

system for gas, instead of merely including robust gas clauses within instruments designed

for oil. Such an alternative has many practical implications. Just like in the petroleum world,

the mining sector has been dealing with much of the same concerns. It is often the case that

during mining operations other minerals are found in association with the primary.147

The

dilemma faced by the title holders is whether to give the licensee the exclusive rights to all

minerals discovered (that is the discoverers right), or issue two separate licenses for the same

contract area. On one hand issuing a single license such us is typically the case with gas and

oil protects the investor and has security of tenure implications. A separate license for one

contract area would therefore not be desirable, but this is only if the separate license was

issued to different entities, making it practically difficult to exploit both resources, thus

adding further complication.

The author suggests an option of having two separate licenses reflecting the stages of the

value chain, with inbuilt security of tenure assurances. This has several advantages,

including allowing exploration license to be easily transferable to appropriate entity for

development and production as well as providing an avenue for third party involvement in

later stages of the chain, i,e., transportation and sales end arrangements. The Allocation

process should guarantee transferability from one stage to another, with inbuilt guarantees.

Regulations as discussed earlier should reflect third party right of access to infrastructure.

A prospecting or development license which would resemble a PSC or Concession

arrangement and a downstream arrangement this can possibly take the form of a BOT as

utilised in the power and infrastructure sector. The rationale at the point of the wellhead, gas

operations start to resemble the power and infrastructure sector, where success in power

projects has often been attributed to the BOT. The BOT approach is essentially a private

sector approach, it has many advantages including:

The use of private-sector financing to provide new sources of capital, thus reducing

public borrowing and reliance on foreign debt

The ability to accelerate the development of projects that would otherwise have to

wait for scarce sovereign resources

147

See for instance the deposits of uranium and gold in the Witwatersrand district in South Africa. See: supra note 77, pg. 9

63

The use of private-sector capital, initiative, and know-how to reduce project

construction costs and schedules and to improve operating efficiency

The allocation of project risk and burden to the private sector that would otherwise

have to be undertaken by the public sector.148

An added benefit is that the BOT structure also incorporates a negotiated price much like a

GSA, but unlike a GSA which is solely design for gas sales, the BOT involves the

development of the infrastructure needed to transport the gas to the buyer or end-user. Since

pricing is a major issue in natural gas, a BOT structure might be desirable in this case. The

price is usually fully passed through with the potential including a premium as a further

incentive. A BOT for gas development can involve the establishment of production

equipment for natural gas or also include the construction of transportation infrastructure.

148

Askar, M., Gab-Allah, A., The Problems Facing Parties Involved in Build Operate Transfer Projects in Egypt, at http://www.civ.utoronto.ca/sect/coneng/tamer/Courses/1299/Ref/BOT-Egypt.pdf

64

7. Conclusion

It is no doubt to governments and analysts alike that the nature of the world gas market is

changing, the recent excitement over large quantities of unconventional gas149

mainly shale

gas150

in the United States is said to be a main force guiding the change in the US gas markets,

but the impact they are said to have on the local and international market are still largely

unknown,151

The temperament of our ever changing globalised world requires that the legal and regulatory

machinery utilised in guiding our dependence on resources also follow a changing pattern. It

is no surprised that stability and renegotiating provisions have assumed such high positions in

contractual instruments within the past decade, this is because of the realisation that the ways

of today may not be the ways of tomorrow, these are not just protection instruments for

investors but also for host countries alike. The same principle should therefore be applied

when reviewing the natural gas industry. Global commentator‟s and analysts have for years

touted the pre-eminence of natural gas, it is often stated as the next transitional fuel152

and yet

the treatment of natural gas within petroleum arrangements for the most part remains modest.

The complex and highly technical features of the industry have created stumbling blocks to

gas exploration, production, transportation, and sales, it is this reason among others that often

times the easiest way to deal with natural gas is often to say “let’s deal with this later.”

But we are at a time in history where the above phrase no longer holds sway. Aside from this

developing nations are on a fast track to development, the recent stagnation of Western

economies due to the global financial crisis has shifted investors further and further to these

regions. Natural gas is perceived to be one catalyst for development, because as a feedstock

fuel its potential to accelerate industrial development has been largely underutilised. It has

been the aim of this paper to emphasis this importance, however, the realisation alone of the

importance of natural gas in these economies is not the ultimate goal here. This paper has

demonstrated that aided with the adequate legal and regulatory framework; one that

recognises the risks involved all the way from country specific to market risks, a clearer

149

Unconventional typically refers to those gas that are more difficult both physically and economically to extract 150

Requiring high-level fracturing to allow for permeability 151

Ernst and Young, The Global Gas Challenge, pg.1 (EYGM Limited, 2010), at http://bit.ly/djmV5k 152

See for instance Daniel Yergin’s “The Next Prize”

65

understanding of where the challenges posed when developing a new gas environment would

be realised. The suggestions here are not one size fits all solutions, but the intention has been

to keep close considering of the nature of the economies which are a main concern of this

paper. In doing so, the idea has been to analyse frameworks where though the details might

differ from jurisdiction to jurisdiction the general premise are nevertheless maintained in all

scenarios.

There are some general themes that policy makers must always take with them after reading

this piece:

1. The rate of predicted change will not be realised until adequate treatment of natural

gas is realised either as wholly distinctive from oil or in conjunction with oil

2. Natural gas markets must be perceived along its value chain – where such a link is

broken investors would be reluctant to consider participation

3. Unlike oil, upstream and downstream relationships in natural gas are crucial and a

detailed framework both upstream and downstream (including sales structures) should

be foreseen by policy makers.

66

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