ECONOMICS
of the
ENERGY INDUSTRIES
Prepared by
www.beg.utexas.edu/energyecon
[email protected]
2009 PREFACE TO ECONOMICS OF THE ENERGY INDUSTRIES
This workbook was prepared in 2000 for the initial launch of New Era in Oil, Gas & Power Value Creation
with a subsequent update in 2004. New Era is the property of the Center for Energy Economics at the Bureau
of Economic Geology, Jackson School of Geosciences, The University of Texas at Austin. The workbook is
intended to provide background and supplemental information for New Era delegates, as well as delegates and
students in all of CEE's major training and capacity building programs in the United States and worldwide.
The inspiration, information, ideas and topics incorporated in the workbook evolved from CEE's first
international training experience in the mid- to late 1990s in Central Asia under the auspices of the US
Agency for International Development (USAID)/PA Consulting (then Hagler Bailly) initiative for those
republics.
The workbook data reflects the conditions of global energy markets at the time it was prepared. Clearly,
global energy markets have become ever more complex even during the brief span of time to present.
However, the major themes have not changed. If anything, they are in even more sharp relief, if still unclear
as to solutions.
•
•
•
•
•
•
Energy is essential for improved quality of life, standards of living and economic development and
growth.
Great tension exists between the desire for affordable energy, the desire for environmental improvement
(in particular for answers regarding climate change), adoption of new energy technologies and alternatives
and the policies and approaches used by governments to balance these many needs.
The balance between public and private interests relative to energy supply, energy access and energy
reliability continues to be tenuous and difficult to achieve.
The quantity and quality of energy data and information continues to be very poor, posing a distinct
constraint on analysis and decision making.
Managing the risk and uncertainty inherent in the energy/economy/environment milieu continues to be a
distinct hurdle for both public and private enterprises and government bodies.
Gaining political and public support for the hard decisions to be made and implemented requires distinct
skills and capabilities.
Since our 2004 update, global energy value chains have been tested vigorously. Soaring oil prices - mainly a
reflection of the strong emergence and establishment of China, India and other large energy consumers pushed implicit demand for crude oil to the limits of the global supply and delivery system. After soaring well
above $100 per barrel, oil has collapsed back to a price that just meets widely accepted estimates of cost
structure and profitability. New domestic deliverability of natural gas in the United States has pushed a key
international marker, Henry Hub in South Louisiana, below the psychological barriers of $3 to $4 per million
Btu. The entire global energy value chain has been impacted by the widespread economic and financial
dislocations experienced by all nations, to some degree, since 2007. Was oil price a trigger for broad and deep
recession? This question is under debate as the causes and effects for the recession are sorted out. In any
case, it is clear that oil demand in the US and other countries began to adjust downward as early as 2006, as
high costs ate into both household and business income. A significant factor allowing the higher price signals
to persist were subsidies that a large number of governments kept in place in attempts to prevent political
unrest. All of these repeated lessons and the related challenges of forging robust business and public policy
strategies for diverse, clean, affordable energy supplies and infrastructure are ingrained in the New Era
program.
In this workbook we lay out broad principals associated with the economics of the energy value chains, the
roles of governments and markets, and make the case for clear data and analysis to support both business and
government strategic thinking and implementation. The content reflects our broad experience as a team in
many different countries and segments of the industry. In the subsequent sections, we refer to a number of
case studies; these are available online at
http://www.beg.utexas.edu/energyecon/publications.php#case_studies. We encourage users to access these
case studies and provide feedback to us. We also encourage your feedback on this workbook, as we strive to
make continuous improvements on content and quality of this product.
-- Michelle Michot Foss
Chief Energy Economist and Head, CEE
Economics of the Energy Industries
TABLE OF CONTENTS
SECTION 1 – GLOBAL SCAN
CHAPTER 1 - INTERNATIONAL ENERGY MARKETS
Crude Oil
1-1
Natural Gas
1-6
Electricity
1-8
Markets
1-10
Functions of Spot and Futures Markets
History of Spot and Futures Markets
Characteristics of Spot, Forward and Futures Markets
Forecasting Long-Term Crude Oil Prices
The Role of International Organizations
1-13
Organization of Petroleum Exporting Countries
International Energy Agency
International Trade Regimes
Industry and Government Associations
SECTION 2 – COMMERCIAL FRAMEWORKS
CHAPTER 2 – ENERGY VALUE CHAIN OVERVIEW
CHAPTER 3 – OIL VALUE CHAIN OVERVIEW
Introduction
3-1
Oil Value Chain Components
3-2
Key Segments and Activities
Key Policy and Regulatory Considerations
Investment in the Oil Value Chain
3-4
The Link Between Investment and Commercial Frameworks
3-5
Global Perspectives
Commercial Framework Principles for the Oil Value Chain
CHAPTER 4 – NATURAL GAS VALUE CHAIN OVERVIEW
Introduction
4-1
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
i
Economics of the Energy Industries
Natural Gas Value Chain Components
4-3
Key Segments and Activities
Key Policy and Regulatory Considerations
Investment in The Natural Gas Value Chain
4-6
The Link Between Investment and Commercial Frameworks
4-8
Global Perspectives
Commercial Framework Principles for the Natural Gas Value Chain
CHAPTER 5 – ELECTRIC POWER VALUE CHAIN
Introduction
5-1
Electricity Industry Restructuring
5-2
Key Drivers
Key Characteristics
Electric Power Value Chain Components
5-7
Key Segments and Activities
Key Policy and Regulatory Considerations
Investment in the Electric Power Value Chain
5-11
The Link between Investment and Commercial Frameworks
5-12
Global Perspectives
Commercial Framework Principles for the Electric Power Value Chain
CHAPTER 6 - ROLE OF GOVERNMENT
Governments, Economic Organization and Energy
6-1
The Goals of Governments
6-3
A Case Study of Upstream
Combining Upstream, Midstream and Downstream – the Natural Gas and Power Case
Appendix 1. Commercial Frameworks for National Oil Companies
Appendix 2. Energy Regulators
6-8
6-42
CHAPTER 7 - PROJECT EVALUATION AND CAPITAL BUDGETING
The Time Value of Money
7-1
An Example
Present Value and Future Value Concepts
Major Steps in Evaluating Capital Investment Projects
7-3
Capital Budgeting
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
ii
Economics of the Energy Industries
Capital Budgeting Criteria
Net Present Value
Internal Rate of Return
Risk and Return Concepts
7-7
Incremental Cash Flow Analysis
7-9
Estimating the Initial Investment
Estimating the Annual Operating Cash Flows
Estimating the Terminal Year Cash Flows
CHAPTER 8 - PROJECT FINANCE
Introduction
8-1
Types of Project Finance
8-1
Advantages of Project Finance
8-2
Disadvantages of Project Finance
8-3
Project Risks
8-4
Project Financing Across the Energy Value Chain
8-5
Upstream
Pipelines
Electric Power
Sources of Funds
8-11
Appendix 1. Diagram of a Typical Project-Financed Deal
8-16
Appendix 2. Top 10 global project finance deals 2003
8-17
SECTION 3 – ENERGY VALUE CHAIN SEGMENTS
UPSTREAM:
CHAPTER 9 - EXPLORATION AND PRODUCTION
Economics of Exhaustible Resources
9-1
Optimal Depletion
9-1
Shortcomings of the Theory
9-4
Reserve Additions
Common Pool Problem
Exploration and Production
9-5
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
iii
Economics of the Energy Industries
Geological Characteristics
Economic Factors
Political Aspects
Technical Aspects of E&P Operations
9-7
Models of E&P Investment
9-9
Oil Price Shocks
Appendix: Fiscal Terms for Upstream Projects – An Overview
9-15
MIDTSREAM:
CHAPTER 10 - PIPELINES
Introduction
10-1
Pipeline Economics
10-7
A Model of Pipeline Investment
10-8
Appendix: Contracting and Rate Design: Reference Materials
10-12
CHAPTER 11 - NATURAL GAS PROCESSING
Introduction
11-1
A Model of Natural Gas Processing Plant Investment
11-2
CHAPTER 12 – LIQUEFIED NATURAL GAS
What is LNG?
12-1
Reduction of Gas Flaring
Natural Gas Trends
12-1
Role of LNG in Global Natural Gas Trade
12-2
New LNG Supplies
Atlantic Basin
Pacific Basin
LNG Value Chain
12-5
Liquefaction
Transport
Regasification
LNG Pricing Mechanisms
12-8
Project Ownership and Financing
12-9
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
iv
Economics of the Energy Industries
Potential for LNG Spot Trade
12-11
Challenges of Building LNG Infrastructure in the U.S.
12-12
Appendix: World LNG Imports by Origin, 2002
12-14
DOWNSTREAM:
CHAPTER 13 - REFINING AND MARKETING
Refining
13-1
Refining Technology
13-4
A Model of Refining Investment
13-4
Marketing
13-8
The Case of Gasoline in the U.S.
A Model for Marketing Investment
13-10
CHAPTER 14 – ELECTRIC POWER GENERATION
Introduction
14-1
Power Plant Economics
14-1
Key Considerations
Costs
Merchant Power Plants
14-6
The Components of Generation Value
Gas and Power Prices and Optionality
Example on Optionality
A Model of Power Plant Investment
14-12
SECTION 4 – TRADING, MARKETING, AND RISK MANAGEMENT
CHAPTER 15 - ENERGY TRADING & RISK MANAGEMENT: A STORY OF EVOLUTION
Introduction
15-1
Evolution in the Energy Industry
15-1
The evolution of the natural gas industry
The evolution of the electric utility industry
The regulatory structure
The Demands of Competition
15-5
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
v
Economics of the Energy Industries
Relationships between utilities and new entities: The restructured market
Managing Risk in a Competitive Environment
15-6
Risk Management Goals & Strategies
The Role of Marketers and Brokers
Financial market advancements: NYMEX and others
New Systems in Risk Management
SECTION 5 – ALTERNATIVES
CHAPTER 16 - ALTERNATIVE SOURCES OF ENERGY
Introduction
16-1
Electric Power Generation
Transportation
Challenges
Alternative Generation Technologies
16-3
Alternative Transportation Technologies and Fuels
16-7
Economics of Alternative Generation Technologies
16-10
Economics of Alternative Transportation Technologies and Fuels
16-15
GLOSSARY
CONVERSION FACTORS
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
vi
Economics of the Energy Industries
SECTION I –GLOBAL SCAN
CHAPTER 1 – INTERNATIONAL ENERGY MARKETS
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
Economics of the Energy Industries
CHAPTER 1 - INTERNATIONAL ENERGY MARKETS
Crude Oil
The world crude oil demand and supply have always presented an interesting imbalance, especially after
the middle of the 20th century. Industrialized countries have usually lacked necessary resources to supply
their own oil needs, and countries with abundant resources and production capacity have not needed all
they could produce for their own economies. This imbalance created a mutually beneficial situation
where industrialized countries imported oil from resource-rich countries which, in turn, developed their
economies with revenues from oil exports. Although oil supply shocks of the 1970s pushed industrialized
countries to substitute alternative fuels for oil, and increase conservation and efficiency efforts, oil
remained a major fuel for these economies. Efforts of building oil stocks as an insurance against possible
future shocks as well as the slow nature of implementing the policies mentioned above kept demand for
oil strong and created the financial environment for development of resources outside the Organization of
Petroleum Exporting Countries (OPEC). Lower prices of the 1980s and increasing demand from growing
economies worldwide enhanced the market for oil. Nevertheless, as the following chart demonstrates, the
Middle East, with 686 billion barrels of proved reserves, accounts for 65% of world’s total crude oil
reserves. Most of these reserves are in the hands of countries that are members of OPEC.
Proved Crude Oil Reserves (thousand million barrels)
1200
1000
800
Rest of the World
600
Latin America
Africa
400
FSU
USA
200
Middle East
0
1981
1991
Source: BP Statistical Review of World Energy 2001.
2001
The table next page presents the data on oil production and consumption in different regions for the years
1970, 1980, 1990, and 2000. Clearly, the imbalance between producing and consuming regions are
getting larger. For example, North American production is staying fairly constant while its consumption
continues to rise, making the region increasingly more dependent on imports. In 1970, the region needed
less than three million b/d of imports while, in 2000, more than eight million b/d, or more than one third
of total consumption in the region was imported.
Asia Pacific is another region with increasing dependence on imports despite increases in its production.
Between 1970 and 2000, import needs of the region increased from about five to 13 million b/d despite
the dampening effect of the Asian economic crisis on oil demand. Note that the increase in consumption
within the Asia Pacific region is mostly responsible for the increase in the emerging market economies
(EMEs) as evidenced at the bottom of the table below. Overall, the share of EMEs in total consumption
increased from 13% in 1970 to 32% in 2000 while the share of OECD countries fell from 74% to 62%.
About half of the increase occurred in the 1990s.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
1–1
Economics of the Energy Industries
Crude Oil Balance (thousand b/d)
Production
Consumption
1970
1980
1990
2000
1970
1980
1990
2000
North America
13,255
14,065
13,855
13,905
North America
16,280
19,350
19,450
22,360
S. & Cent. America
4,830
3,745
4,505
6,835
S. & Cent.
America
2,185
3,325
3,545
4,665
Europe
845
2,945
4,550
6,955
Europe
13,685
15,895
14,965
15,925
FSU
7,125
12,115
11,565
8,035
FSU
4,990
8,515
8,410
3,475
Middle East
13,900
18,895
17,530
22,990
Middle East
1,150
2,040
3,395
4,345
Africa
6,105
6,225
6,675
7,820
Africa
725
1,380
1,995
2,470
Asia Pacific
1,980
4,940
6,730
7,970
Asia Pacific
6,725
10,565
13,720
20,665
TOTAL WORLD
48,040
62,930
65,410
74,510
TOTAL WORLD
45,740
61,070
65,480
73,905
Of which OECD
13,915
17,115
18,840
21,545
Of which OECD
33,975
40,255
40,510
46,335
OPEC
23,505
27,255
24,555
30,825
European Union 15
11,985
13,175
12,245
13,305
Non-OPEC
17,415
23,565
29,285
35,640
Other EMEs
6,110
11,180
15,510
23,415
Source: BP Statistical Review of World Energy 2001.
On the other hand, Europe has been able to lower its import needs in the 1990s, partially due to increased
production (mostly from the North Sea) and partially due to keeping demand under control. Europe
imported more than 10 million b/d in 1990 as compared to nine million b/d in 2000. Note that the share
of 15 members of the EU in world oil consumption decreased from 26% in 1970 to 18% in 2000.
The Middle East, Africa and the FSU remain the significant exporting regions. Increasing production in
the 1990s also caused South and Central American exports to double between 1990 and 2000 from about
one million b/d to more than two million b/d.
In Africa, production increased only about 9% between 1970 and 1990 but since then it has risen 17%.
This increase allowed African exports to also increase from about 4.7 million b/d in 1990 to 5.3 million
b/d in 2000 despite an increase in consumption of about 24% between 1990 and 2000.
The Middle East production has risen significantly from about 17.5 million b/d in 1990 to almost 23
million b/d in 2000, after a decline in the 1980s. As consumption in the region remains fairly low at 4.3
million b/d (albeit reflecting a 26% increase from 3.4 million b/d in 1990), the region exported roughly
4.6 million b/d more in 2000 than in 1990.
The FSU region finally reversed the declining trend in production. Although still not as high as in the
1980s, the region now produces more than eight million b/d. More importantly, with new production
expected from the Caspian region producers as well as from Russia, and consumption not expected to
increase as rapidly, the FSU exports are expected to increase from the current level of 4.5 million b/d to
possibly 10 million b/d by 2010.
The Middle East is clearly the major supplier of oil to the world with almost 19 million b/d (44% of total
exports), followed by Africa with about 6 million b/d (14% of total exports), the FSU (mostly Russia at
this time) with more than 4 million b/d and Latin America with more than 3 million b/d (see map and
table below). North America (mostly the U.S.), Asia-Pacific (Japan in particular and increasingly China)
and Europe are major importing regions.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
1-2
Economics of the Energy Industries
The following table confirms the previous observation that most of the increase in oil imports occurred
outside the developed world. Imports almost doubled to more than 16 million b/d between 1990 and 2000
in the rest of the world, although the U.S. imports also increased by about three million b/d (or, 38%) in
the 1990s. Note that Western Europe has been able to sustain an import level of about 10 million b/d
throughout the 1990s.
Crude Oil Trade Movements (thousand b/d)
Imports
USA
Western Europe
Japan
Rest of World
TOTAL WORLD
Exports
USA
Canada
Mexico
South & Central America
FSU & Central Europe
Former Soviet Union
Central Europe
Middle East
North Africa
West Africa
Asia Pacific
Rest of World
TOTAL WORLD
1990
1992
1994
1996
1998
2000
8,026
9,801
4,802
8,812
31,441
7,888
10,319
5,306
9,884
33,397
8,929
9,840
5,612
11,671
36,052
9,400
9,539
5,685
13,994
38,618
10,382
9,971
5,259
14,776
40,388
11,092
10,066
5,329
16,179
42,666
889
955
1,387
2,367
2,659
n/a
n/a
14,212
2,604
2,248
2,182
1,938
31,441
918
1,101
1,469
2,374
–
2,211
87
15,453
2,849
2,679
2,414
1,842
33,397
943
1,323
1,421
2,695
–
2,531
130
16,513
2,652
2,675
2,517
2,652
36,052
978
1,484
1,656
3,011
–
3,239
92
17,170
2,756
2,916
2,790
2,526
38,618
1,011
1,603
1,770
3,240
–
3,569
121
18,702
2,712
3,094
2,490
2,076
40,388
890
1,703
1,814
3,079
–
4,273
121
18,944
2,732
3,293
2,767
3,050
42,666
Source: BP Statistical Review of World Energy 2001.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
1–3
Economics of the Energy Industries
Data on crude oil and product exports for 2000 are presented below. Clearly, the Middle East is the
largest exporter of crude oil (16.7 million b/d) as well as products (2.2 million b/d). The share of the
Middle East in total exports of crude oil is about 50%. The second largest exporter of crude oil is West
Africa with 3.2 million b/d, accounting to about 10% of total world exports although Africa is not a
significant exporter of products. The FSU is the third largest exporter of crude oil (2.9 million b/d) and
the second largest exporter of products (1.4 million b/d).
2000 Crude Oil and Product Import and Exports (thousand b/d)
USA
Canada
Mexico
South & Central America
Western Europe
FSU
Central Europe
Middle East
North Africa
West Africa
East & Southern Africa
Australasia
China
Japan
Other Asia Pacific
Unidentified*
TOTAL WORLD
Crude
imports
8,932
909
–
893
8,065
6
1,015
84
158
56
447
487
1,408
4,306
6,493
–
33,259
Product
imports
2,160
161
365
219
2,001
117
252
96
106
165
100
96
375
1,024
1,753
417
9,406
Crude
exports
64
1,290
1,736
2,089
1,276
2,862
2
16,741
2,009
3,234
120
344
208
2
965
316
33,259
Product
exports
826
413
77
990
834
1,411
119
2,204
723
58
6
104
144
79
1,001
417
9,406
Source: BP Statistical Review of World Energy 2001.
The U.S. and Asia Pacific export significant amounts of products although their crude oil exports are
relatively small. The U.S., alone, exported 826,000 barrels of products a day in 2000 (almost 9% of the
world total). Countries in the Asia Pacific region exported more than one million b/d, or 11% of the
world total. This is because of the large size of downstream industry in these regions.
North American imports are quite diversified and come from within North America (27%), South and
Central America (22%), the Middle East (21%), Africa (14%) and Western Europe (11%). Western
Europe also has a fairly balanced portfolio of supplying regions with 36% coming from the Middle East,
and 26% from each of Africa and the FSU. In comparison, Japan and Asia Pacific depends heavily on
one region: 79% of Japan’s and 74% of other Asian imports originate from the Middle East.
2000 Inter-area Movements of Oil (Thousand b/d)
TO
North S. & C. Western Central
Africa
America America Europe Europe
FROM
North America
3,440
336
425
South & Central America 2,723
–
250
Western Europe
1,460
29
–
FSU & Central Europe
66
162
2,578
Middle East
2,619
427
3,666
Africa
1,779
152
2,607
Australasia
48
–
–
Asia Pacific
241
6
31
Unidentified
149
–
509
TOTAL IMPORTS
12,527
1,112
10,066
Source: BP Statistical Review of World Energy 2001.
–
4
197
806
198
62
–
–
–
1,268
10
12
175
10
705
115
–
4
–
1,032
Australasia China Japan
8
4
2
–
203
–
–
318
47
583
4
8
52
96
770
338
30
477
8
1,783
77
4
6
6
4,189
54
95
891
6
5,329
Other
Asia
Pacific
84
73
141
152
6,115
978
275
412
14
8,246
Rest of
Unidentified Total
World
21
–
48
99
52
64
–
19
–
303
–
–
–
417
–
–
–
–
–
417
4,407
3,079
2,110
4,394
18,944
6,151
449
2,399
733
42,666
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
1-4
Economics of the Energy Industries
The data on demand and supply balance in the world crude oil market for four quarters of 2001 are
summarized in the table below. During the fourth quarter of 2001, for example, total oil demand from
Organization for Economic Cooperation and Development (OECD) members was 48.7 million b/d (about
64% of total world demand). During the same period, oil supplies from OECD were only 23.4 million
b/d, which accounts about to 30% of total world supply. The U.S., by far the single largest consumer of
oil, produces roughly 9 million b/d, or 44% of its demand for oil. Japan is almost totally dependent on
imports to meet its demand of 5.6 million b/d. Note that the share of OECD in world demand and supply
remain fairly constant throughout the year although world demand and supply fluctuate from one quarter
to another. The increase in winter fuel demand experienced in the fourth and first quarters mostly in
OECD countries also cause the fluctuations in the global demand.
Quarterly Crude Oil Demand and Supply Balance (million b/d)
2001
4th qtr.
3rd qtr.
2nd qtr.
1st qtr.
DEMAND
US & Territories
Canada
Mexico
Japan
South Korea
France
Italy
United Kingdom
Germany
Other OECD Europe
Australia & New Zealand
20.36
2.15
1.95
5.64
2.19
2.09
1.91
1.74
2.82
6.85
1.00
19.98
2.00
1.94
5.12
1.97
2.05
1.93
1.70
2.97
6.84
1.00
19.93
1.94
1.90
4.98
2.01
1.97
1.77
1.69
2.76
6.59
1.03
20.18
2.03
1.97
6.11
2.33
2.10
1.86
1.75
2.70
6.80
1.02
Total OECD
China
FSU
Other Asia
Other non-OECD
48.70
4.78
3.55
7.01
12.57
47.50
4.81
3.51
6.72
12.80
46.57
4.87
3.52
6.96
12.77
48.85
4.92
3.67
6.96
12.54
Total non-OECD
TOTAL DEMAND
27.91
76.61
27.84
75.34
28.12
74.69
28.09
76.94
8.96
2.80
3.41
6.45
1.74
9.07
2.72
3.65
6.14
1.62
9.04
2.77
3.52
6.06
1.63
8.79
2.84
3.59
6.35
1.68
Total OECD
FSU
China
Other non-OECD
Total non-OECD, non-OPEC
23.36
8.46
3.21
11.47
23.14
23.20
8.93
3.28
11.30
23.51
23.02
8.68
3.31
11.11
23.10
23.25
8.64
3.31
11.26
23.21
OPEC
31.73
30.15
29.93
31.07
TOTAL SUPPLY
78.23
76.86
76.05
77.53
1.62
1.52
1.36
0.59
SUPPLY
US
Canada
Mexico
North Sea
Other OECD
Stock Change
Source: The Oil & Gas Journal.
On the supply side, OPEC continues to dominate the market, producing 30 to 32 million b/d. Note that
OPEC supplies are more volatile across the four quarters than OECD or other non-OPEC supplies,
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
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Economics of the Energy Industries
reflecting the swing, or marginal, producer role the organization (or at least some of its members) plays in
the world crude oil market.
Natural Gas
Most of the world’s proved natural gas reserves (about 72%) are located in two regions: the FSU and the
Middle East, although there is little production relative to the size of its reserves in the latter region (see
chart below). Both regions hold roughly 2,000 tcf (or about 56 tcm) of natural gas reserves as compared
to world total reserves of 5,300 tcf (150 tcm).
Proved Natural Gas Reserves (trillion cubic meters)
160
140
Asia Pacific
120
Africa
100
Middle East
FSU
80
Europe
Latin America
60
North America
40
20
0
1981
1991
Source: BP Statistical Review of World Energy 2002.
2001
Natural Gas Balance (bcf/d)
Production
Consumption
1970
1980
1990
2000
1970
1980
1990
2000
North America
64.4
63.0
61.0
72.5
North America
65.1
62.4
61.0
74.0
S. & Cent. America
1.7
3.2
5.6
9.2
S. & Cent. America
1.7
3.4
5.7
8.9
Europe
10.6
23.1
21.8
28.7
Europe
11.1
26.7
32.0
44.4
FSU
18.9
41.4
77.8
68.6
FSU
18.1
35.9
64.1
53.0
Middle East
2.0
3.6
9.7
20.0
Middle East
1.6
3.4
9.4
18.2
Africa
0.2
2.4
6.5
12.4
Africa
0.2
1.4
3.4
5.7
Asia Pacific
1.6
6.8
14.6
25.6
Asia Pacific
1.6
6.9
15.3
27.9
TOTAL WORLD
99.4
143.5
197.0
237.0
TOTAL WORLD
99.4
140.1
190.9
232.1
Of which OECD
72.9
7.2
5.1
83.9
15.9
14.6
82.5
15.4
33.8
103.2
21.3
63.9
Of which OECD
74.4
7.7
4.5
88.2
19.9
11.5
95.6
24.0
26.3
127.5
36.5
48.7
European Union 15
Other EMEs
European Union 15
Other EMEs
Source: BP Statistical Review of World Energy 2001.
Despite the size of their reserves, the FSU and the Middle East are not the largest producers of natural
gas. North America has been the leading producer as well as consumer of gas for decades although the
FSU production increased significantly from 19 bcf/d in 1970 to 69 bcf/d in 2000 while the North
American production increased only from 62 bcf/d to 72 bcf/d over the same period (see table above).
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
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Economics of the Energy Industries
Although there has been a ten-fold increase in production in the Middle East since 1970, with only 20
bcf/d, the region ranks as the fifth largest producing region after Europe that produced almost 29 bcf/d
and the Asia Pacific region that produced almost 26 bcf/d in 2000. Note that the share of OECD
production fell from 73% in 1970 to 44% in 2000 while the share of production from the EMEs increased
from 5% to 27% over the same period.
Consumption values are very similar to production values. This is partially due to the fact that natural
gas, unlike oil, is difficult and expensive to ship via tankers over long distances, especially without longterm agreements among producers and consumers (see the LNG chapter, Chapter 12, for further
discussion of these issues). As a result, most gas is used or traded locally. Accordingly, consumption
numbers are almost identical to production numbers for North America, South and Central America, the
Middle East and Asia Pacific.
Nevertheless, there is significant trade between the FSU region and Europe as well as between Africa and
Europe. The FSU exports about 15-16 bcf/d while Europe imports about 16 bcf/d. There are about six
bcf/d of exports from Africa (see map below).
In 2000, the U.S. imported more than 100 bcm (or about 10 bcf/d) from Canada (see table below). After
the U.S., Germany was the second largest importer of natural gas with roughly 87 bcm. Unlike the U.S.
that received most of its gas from one source, German imports came from a variety of suppliers including
Denmark, Netherlands, Norway, the UK and Russia. Russia was the largest supplier with 34 bcm.
France with more than 32 bcm and Italy with more than 27 bcm of imports are the other large importers.
Like Germany, these countries also received most of their imports from Russia – 13.5 bcm for France and
21.1 bcm for Italy. In total, Russia exported more than 125 bcm in 2000 (or, more than 12 bcf/d).
Norway was the third largest exporter of gas after Russia and Canada with almost 50 bcm and the
Netherlands was ranked fourth with more than 36 bcm.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
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Economics of the Energy Industries
Selected Trade Movements by Pipeline (bcm)
To
North
America
USA
Canada
Mexico
To
Europe
Austria
Belgium
Bulgaria
Czech
Republic
Finland
France
Germany
Hungary
Italy
Netherlands
Poland
Romania
Slovakia
Spain
Switzerland
Turkey
UK
From
From
To
USA
Canada
Mexico
S. & Cent. America
Argentina
Bolivia
–
1.78
3.11
101.66
–
–
0.17
–
–
0.09
4.07
0.04
1.90
–
–
Denmark
–
–
–
France
–
–
–
Germany
0.32
0.24
–
Brazil
Chile
Uruguay
From
Netherlands Norway
–
0.50
5.90
5.45
–
–
UK
–
0.21
–
Russia
5.10
–
3.20
–
–
–
–
1.02
–
7.50
–
–
2.50
–
–
–
–
–
–
–
–
–
–
–
–
–
0.50
–
–
–
–
–
–
0.30
–
–
–
–
–
0.90
–
–
0.20
0.20
–
–
1.40
–
–
–
6.02
17.70
–
6.10
–
–
–
–
–
0.60
–
–
–
12.12
19.60
–
–
5.50
0.50
–
–
2.31
–
–
2.00
–
0.80
3.00
–
–
6.50
–
–
–
–
–
–
–
4.30
13.47
34.00
7.80
21.10
–
6.90
3.20
7.90
–
0.60
10.30
–
Source: BP Statistical Review of World Energy 2001.
Electricity
In 1999, 14 trillion kWh of electricity was generated worldwide (see chart next page). While the share of
North America stayed roughly the same since 1980 at about 27%, Far East & Oceania’s share increased
significantly from 13% in 1980 to 23% in 1999. Western Europe, the next largest region, generated 2,785
billion kWh, or 17% of the world’s total in 1999, as compared to 1,845 billion kWh, or 19% of the
world’s total in 1980.
Electricity generation in Eastern Europe & FSU actually declined from 1,604 billion kWh (16%) in 1980
to 1,509 billion kWh (9%) in 1999, mostly after the break-up of the Soviet Union and consequent
economic collapse in the early 1990s.
Central & South America increased its generation from 308 billion kWh (3%) to 752 billion kWh (5%).
The net electricity generation in the Middle East more than quadrupled from 92.41 billion kWh in 1980 to
418 billion kWh in 1999, but still accounting for only 3% of the world’s total.
Similarly, doubling of the African generation from 190 billion kWh in 1980 to 394 billion kWh did not
change the share of the region within the world’s total, which stands at 2%.
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Economics of the Energy Industries
Net Electricity Generation by Region (billion kWh)
16000
14000
12000
North America
Central & S. America
Western Europe
E. Europe and FSU
Middle East
Africa
Far East and Oceania
10000
8000
6000
4000
2000
Source : Energy Information Administration (EIA)
0
1980
1990
1999
The fuel portfolio for 1980, 1990 and 1999 used in power generation worldwide is depicted in the chart
below. The world continues to generate most of its electricity by burning fossil fuels, i.e., coal, natural
gas and oil products, in conventional thermal facilities. Generation from these facilities increased from
5,589 billion kWh in 1980 to 8,798 billion kWh in 1999 although the share of these fuels in total
generation declined slightly from 70% to 63% over the same period.
Net Electricity Generation by Fuel (billion kWh)
16000
Source : Energy Information Administration (EIA)
14000
12000
10000
8000
6000
4000
2000
0
1980
Conventional Thermal (Coal, Oil and Gas)
Geothermal, Renewable, Wood & Waste
1990
1999
Nuclear
Hydroelectric
Hydroelectric facilities are still the second largest source of electric power in the world with 2,607 billion
kWh in 1999, but their share also declined from 22% in 1980 to 19% in 1999. Nuclear generation that
expanded significantly from 684 billion kWh in 1980 to 2,396 billion kWh in 1999 replaced the lost share
of conventional and hydro generation and now it accounts for 17% of world’s total generation as
compared to only 8% in 1980.
Finally, geothermal generation increased from 31 billion kWh (0%) to 227 billion kWh (1%). Other
sources of power generation such as wind, solar and biomass are not large enough to register in this chart
(see Chapter 16 for detailed discussion of alternative technologies).
However, generation by fuel show significant variation across different regions of the world. In North
America, conventional fuels account for 64%, nuclear for 18%, hydro for 15% and renewables for 2% of
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
1–9
Economics of the Energy Industries
net generation. The role of natural gas has been increasing within the conventional thermal fuels. Similar
to the world trend, nuclear generation expanded its share from 11% in 1980 at the expense of
conventional and hydro generation, which used to account for 69% and 20% of total generation in 1980.
Between 1980 and 1999, Western Europe also went through a similar shift from conventional and hydro
sources of generation towards nuclear power, whose share increased from 12% to 31%. Over the same
period, the share of conventional thermal in total generation declined to 48% from 64% and the share of
hydro fell to 19% from 23%. Renewables account for the remaining 2% of generation in 1999. With
increased emphasis on global warming and commitment to Kyoto protocol, Western Europe will likely
increase the use of renewables such as wind in the near future. Already, Germany and Denmark are
investing large sums in wind farms.
In Far East and Oceania, 72% of generation was from conventional thermal facilities in 1999 (same as in
1980). Nuclear power increased its share from 7% to 13% between 1980 and 1999 mostly at the expense
of hydro whose share fell to 14% from 21% over the same period.
The only region where hydro generation appears to have expanded is Eastern Europe and FSU. But, the
increase in hydro’s share from 13% to 17% between 1980 and 1999 is partially due to economic collapse
of the region in the 1990s, which resulted in the production and use of oil and gas. The generation from
conventional thermal fell from 1,309 billion kWh in 1980 to 1,000 billion kWh in 1999, resulting in a
decline in the share of these fuels from 82% to 66%. Another reason for this decline is the expansion of
nuclear generation from 5% to 16%.
In Central and South America, hydroelectricity continues to dominate with an increased share of 70% in
1999 as compared to 65% in 1980. Almost all of the remaining generation comes from conventional
thermal facilities that use oil products or natural gas, which is increasing its share at the expense of oil
products.
In the Middle East and Africa, practically all electricity is generated at conventional thermal facilities –
96% in the former and 80% in the latter. Africa’s second largest source of electricity generation is hydro
facilities, accounting for 17% of total in 1999, down from 32% in 1980.
Markets
Functions of Spot and Futures Markets1
Markets for energy commodities, like those for other commodities, have two functions. First, they
provide a medium for discovering the market-clearing (or, equilibrium) price for oil, natural gas and
products. Second, they render the transfer of stocks from the current period to future periods possible.
Accordingly, there are basically two types of trade in these markets: (1) one based on the immediate
delivery handled by "spot" markets, and (2) another based on delivery at some future date carried out
through "forward" and "futures" markets. The difference between current and future prices provides a
good signal about market conditions.
The spot price will tend to be higher than futures (or, forward) prices if inventories are perceived to be too
low or are expected to be low in the near future relative to long-term expectations (this is known as
"backwardation"). For example, during the Gulf Crisis following the invasion of Kuwait by Iraq, spot
prices increased significantly relative to prices for contracts in 6 to 12 months into the future with
expectations of a particularly harsh winter combined with the supply disruption. More routinely, the
forward curve for gasoline prices will indicate backwardation in late spring or early summer as driving
season puts pressure on refineries and inventories. Similarly, in winter months the forward curve for
natural gas price will manifest a declining trend as people expect the demand for natural gas to fall as the
heating season comes to an end in few months. Note, however, that there could be market conditions
either on the demand or supply side (or both) that can change these seasonal patterns.
1
See Chapter 15 for details on the role of these markets for energy trading, marketing and risk management.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
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Economics of the Energy Industries
Alternatively, the futures price may become larger than the spot price if current inventories are considered
plenty but a decline is expected in the long-term (this is known as "contango"). For example, during
1986, increased production from Saudi Arabia and others lowered prices considerably and raised
inventories in consuming countries that took advantage of low prices. As markets did not expect excess
supply situation to continue, futures prices remained higher than spot prices. More common contango
forward curves can be observed in fall months for gasoline or in summer months for natural gas. As
before, unexpected developments can change these trends influenced by regular seasonality expectations.
History of Spot and Futures Markets
Historically, most crude oil and products were traded on the world market under long-term contracts at
"official" prices of exporting countries. Although spot markets for oil existed since the 1960s, only after
the first oil shock, they started to claim a larger share of the trade. Trading in spot markets accounted for
only 3 to 5% of the total trade before 1980, but this share reached 50% internationally and 20% in the
U.S. during the first half of the 1980s. The shift toward the spot market was also expedited by the second
oil shock accompanying the Iranian Revolution that rendered the contract prices unreliable. The contract
prices started to be adjusted so frequently that they were practically indistinguishable from spot prices.
After the crash in 1986 major oil-exporting countries adopted “formula pricing” which tied contract prices
to spot prices, calculating the former as the spot price of a certain benchmark crude oil plus or minus an
adjustment factor, which considered quality differences, sources, destinations and shipping distances. For
example, Saudi exports to the U.S. were priced based on the U.S. Gulf Coast spot price of Alaskan North
Slope (ANS) until 1994, and based on West Texas Intermediate (WTI) spot price since then. The spot
price for WTI is usually considered to be following its futures price, which we will discuss next.
In March 1983, the New York Mercantile Exchange (NYMEX) introduced trading in a crude oil futures
contract with delivery of light sweet crude oil at Cushing, Oklahoma. Heating oil and gasoline contracts
were introduced earlier in 1978. All these contracts have very specific definitions in terms of quantity,
quality, and delivery conditions (available at www.nymex.com). This standardization and the
clearinghouse role played by the exchange makes trading at NYMEX, and other established exchanges,
much safer than over-the-counter trading arrangements and more transparent for all market participants.
Although several streams are deliverable (including U.K. Brent, Norwegian Ekofisk, Algerian Saharan,
Nigerian Bonny Light, etc.), the futures contract for crude oil tracks WTI light. During the first year,
daily crude oil futures trading has risen as high as 10,000 contracts and averaged around 6,000 (one
contract involves the purchase or sale of 1,000 barrels).
The success of the NYMEX experiment and the ending of official pricing by OPEC initiated the
formation of a futures market for U.K. Brent at International Petroleum Exchange (IPE) in the late 1980s.
Unlike the NYMEX contract, the IPE contract does not provide for physical delivery, but instead tracks
the Brent forward contract and employs cash settlements.
In 2002, the volume of light sweet crude oil contracts traded in NYMEX range from 100,000 to 150,000
contracts for just few front months. Near-month contract volume is most significant ranging from 40,000
to 90,000 contracts a day. Open interest can be more variable ranging from as low as 30,000 or as high as
150,000 contracts for just the near-month contract. At the same time, trading in Brent crude can reach an
average of about 50,000 contracts and an average open interest of over 150,000 contracts. The volume of
trade in these futures markets can reach levels that are two or three times as large as the actual oil
consumption in a given day.
The fact that these futures contracts reached such volume and share of the market in relatively short
period of time is significant, especially considering that there are about 100 trading institutions including
spot, futures and informal markets. Moreover, many experts consider NYMEX and IPE oil futures prices
as global benchmarks. The electronic trading at NYMEX through NYMEX ACCESSSM allows traders
around the world to buy or sell even when the exchange is closed. Accordingly, crudes heavily traded
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
1 – 11
Economics of the Energy Industries
(“heavy” within the region, not relative to overall trade) in Asia such as Dubai Fateh or Malaysian Tapis
are priced by adding fairly fixed spreads to closing prices of WTI and Brent contracts.
Although it does not have as much importance for the world as the crude oil and products trades, natural
gas trading at NYMEX is very significant for the North American market. After the restructuring of the
natural gas market in the 1980s, NYMEX introduced a natural gas contract with Henry Hub in Louisiana
as the reference point in the early 1990s. 100,000 contracts a day are traded just for the few front months.
Open interest can be 200,000 contracts for the same months.
Characteristics of Spot, Forward and Futures Markets
Spot Markets. Transactions in spot markets involve the delivery of oil within two to four weeks of
closing the deal. Two to four weeks may seem long for an exchange considered "current," but moving
large volumes of oil over long distances may take that long. Contracts in larger spot markets are uniform
in quality, quantity and terms in order to make transactions simpler and less costly. Transactions may
occur any time of the day between parties located anywhere in the world.
Forward Markets. Unlike spot markets, forward markets administer transactions of contracts with future
deliveries. No cash is required at the time of transaction, and contracts are mostly settled by cash
payments before the expiration of the contract without physical delivery. The transaction between a
buyer and a seller is direct without an intermediary body. Forward markets are used as a hedging device.
For example, in order to avoid potential increases in the cost of oil, a refiner may prefer purchasing its
future feedstock at current prices.
Futures Markets. Similar to forward markets, futures contracts involve delivery at some time in the
future and therefore serve as another hedging device. Unlike forward markets, payments are made at the
time of transaction. Also, the inclusion of a clearinghouse (operated by the futures exchange) between a
buyer and a seller makes changing positions ("short" versus "long") easier for traders. A trader in short
position can change his/her position by buying futures. Alternatively, a long position can be altered by
selling futures. These transactions do not require the consent of the buyer and the seller of original
contracts as transactions are carried out through the clearinghouse. Because of the ease of changing
positions, futures markets have become primary modes of hedging. Every day, producers sell futures to
protect themselves against future declines in the price of oil, and consumers buy futures to protect
themselves against price increases in the future.
In all of these markets, there are primarily three types of players: hedgers, speculators and arbitrageurs.
Those who employ forward or futures markets for hedging purposes tend to be price level sensitive and
concerned about market moving against them. These tend to be asset owners either on the production or
consumption side. They prefer few long-term transactions to protect themselves against unfavorable price
movements in the future. Speculators, on the other hand, benefit from volatility of prices; they undertake
many short-term transactions, trying to buy low and sell high and not hold any positions for too long.
Finally, arbitrageurs try to take advantage of differences in prices across different regions, different time
periods or different fuels. The role and impact of each of these market players on the price is a topic of a
continuing debate. Some feel that speculators increase volatility by their short-term, profit-driven
transactions. Increased volatility hurts both producers and consumers because of their unpredictability
and their negative impact on investment decisions. Others, however, feel that speculators play a crucial
role of creating liquidity in the marketplace and hence increasing the accuracy and value of price signals.
Forecasting Long-Term Crude Oil Prices
Since the first oil shock, forecasting the price of oil has proved to be quite challenging. Researchers from
the academia or the industry and organizations such as the U.S. Department of Energy (DOE) and the
International Energy Agency (IEA) have undertaken regular forecasting analyses. Historically, however,
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
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Economics of the Energy Industries
forecasts have failed significantly in accuracy. The following chart presents four price forecasts from
different periods performed by the DOE.2 For comparison purposes, the actual price is also presented.
Historical Price of Crude Oil and Price Forecasts
140
120
Actual
1979
1987
1990
1982
100
80
1992$/b
60
40
20
0
1950
1960
1970
1980
1990
2000
2010
Source: Michael C. Lynch. “The Failure of Long-Term Oil Market Forecasting.” in Advances in the Economics of Energy and
Resources, Volume 8, 1994.
Forecasts indicate that prices are expected to increase at a significant rate after the second oil shock (1982
forecast), but also after the crash of oil prices in 1986 (1987 forecast). The exhaustible resource theory
(see Chapter 9) implies such an increase in the price of exhaustible resources as their cumulative
production rises. However, we also discuss the flawed assumptions of the model leading to the
conclusion of rising prices. For example, the model does not allow for reserve additions. However, the
additions to resource base have been very significant since the 1970s and remain a crucial factor affecting
the accuracy of predictions about future supply of oil. Forecasters also failed to incorporate into their
models technology development that enhanced production from existing fields. The effects of
conservation and efficiency programs, and those of increasing role of alternative fuels were not assessed
properly, either. In retrospect, one can also claim that, in the 1970s and 1980s, forecasters
overemphasized or misinterpreted the power of OPEC. All of these led to underestimation of the world
oil supply. When combined with usually overestimated demand, it is no wonder we ended up with
increasing price forecasts.
However, the failure of forecasts in the past does not imply that forecasting cannot be useful. The future
price of oil has significant bearing on evaluating oil projects. The decision makers would very much like
to know future price trends with as much accuracy as possible. Forecasting can be very helpful in that
area if it is carried out with meticulous attention to every relevant variable. Futures trading in established
exchanges, where numerous stakeholders buy and sell contracts, provide fairly dependable indication of
future prices at least for the next six months to a year.
The Role of International Organizations
Organization of Petroleum Exporting Countries
Organization of Petroleum Exporting Countries (OPEC) was formed by Venezuela, Saudi Arabia,
Kuwait, Iran and Iraq in 1960. At that time, these five countries owned about 67% of the world's proved
oil reserves, and produced over 37% of the world's oil. Their intention was to influence the price of crude
oil and eventually increase their oil revenues. The organization was modeled after previous efforts of
2
In Chapter 9, we provide an updated version of this chart by Michael Lynch with a lot more forecasts, some much more recent,
that support the discussion in this section.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
1 – 13
Economics of the Energy Industries
output management in the U.S. such as the Texas Railroad Commission and the Interstate Oil Compact.
In particular, the Compact formed by five oil producing states (Texas, Oklahoma, Louisiana, Kansas and
Illinois) provided an example of intergovernmental organization for output management.
The rest of the OPEC members joined the organization during the 1960s and the early 1970s (Qatar,
1961; Libya and Indonesia, 1962; Abu Dhabi, 1967; Algeria, 1969; Nigeria, 1971; Ecuador 1973;
Dubai and Sharjah, 1974; and Gabon, 1975). By 1973, the organization accounted for almost 70% of the
world oil reserves, and its share in production increased to 53%. The failure of the organization to
maintain a successful quota system, and lower oil prices brought about by the crash in the mid-1980s
increased frustration among some members. As a result, Ecuador left the organization in December 1992
and Gabon withdrew as of January 1995.
$/b
million b/d
OPEC Output and Price of Oil
35
40
35
30
Price
30
25
OPEC Output
25
20
20
15
15
10
10
5
5
0
0
1960
1965
1970
1975
1980
1985
1990
1995
2000
Sources: Oil & Gas Journal and BP Statistical Review of World Energy
The unexpected four-fold increase in crude oil prices in December 1973, following the October war in the
Middle East, has been widely attributed to the activities of OPEC operating as a cartel. Prices are
accepted to be substantially higher than if they had been solely determined by market conditions and
OPEC is accused of curbing production in order to raise prices. Significant increases in the price are
usually matched with a considerable decline in OPEC production (see chart above). This is most apparent
for the second shock of the 1979-82 period where rising prices coincide with falling production by OPEC,
including the most recent agreement among OPEC members in 1999-2000. Alternatively, the decreasing
prices of the 1980s, especially the crash in 1986 coincides with significant increase in OPEC output. In
early 1986, Saudi Arabia increased its output by more than three 3 million b/d.
Over the years, especially after 1973-4, OPEC production declined while their reserves increased. In
1973, OPEC countries were responsible for 53% of total world production while they owned almost 70%
of total world reserves. By 1992, the percentage of world reserves owned by the members of OPEC
increased to 78%, while the production share of the organization fell below 40% after a historical low of
29% in 1985 (see chart below).
Throughout the 1990s the organization’s 11 members produced approximately 40% of the world’s oil.
They own almost 80% of the world’s proved oil reserves. Obviously, the absence of Ecuador and Gabon
did not affect the position of the organization in the world crude oil market. The increase in the share of
OPEC in world’s oil reserves and the decline in its production share are consistent with the behavior of a
cartel trying to keep the world price of oil high by curbing its production in response to increasing noncartel output.
OPEC members also account for about 45% of world’s gas reserves. Members in the Persian Gulf alone
are estimated to own more than 1,800 trillion cubic feet of gas (34% of the world’s proved gas reserves).
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
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Economics of the Energy Industries
Despite significant reserves, OPEC’s share in world gas production is only around 16% after increasing
significantly in the late 1990s. Half of this production comes from Algeria, Indonesia and Qatar. Gas
production to reserves ratio in the Middle East is below 1%. However, this is quickly changing as
significant resources are being allocated to development of natural gas fields by Qatar, Saudi Arabia and
others in the region. The production of natural gas is projected to increase at about 6% a year during the
next ten years. This rate can increase if Iran and Iraq can overcome international restrictions and finance
their projects.
OPEC's Share in World Oil Production & Reserves (%)
56
80
52
76
72
44
40
68
Reserves
Production
48
Production
36
Reserves
64
32
28
60
1960
1965
1970
1975
1980
1985
Sources: Oil & Gas Journal and BP Statistical Review of World Energy
1990
1995
2000
However, OPEC did not show the characteristics of a textbook cartel until the early 1980s when it
adopted a quota system. The organization did not have an explicit policy of production or profit sharing,
or policing devices to detect and punish overproducing members. The Arab-Israeli war and the
accompanying oil embargo to the western world by Arab exporters in 1973-74, the revolution in Iran and
the beginning of the war between Iran and Iraq at the end of the 1970s were events mostly outside the
control of OPEC (see chart below). Nevertheless, these developments caused the price of oil to increase
significantly and allowed the organization's members to reap substantial benefits. The opportunistic
nature of the organization was demonstrated by some members (e.g., Saudi Arabia) that did not fully
compensate for the loss of output although they had the excess capacity, for example, in the late 1970s
and early 1980s when Iranian and Iraqi production was not available to the world.
45
40
Nominal Dollars per Barrel
35
Iran-Iraq War
Venezuela Unrest
Saudis abandon "swing
producer" role
Operation Desert
Storm
OPEC cutbacks
30
25
20
Arab Oil
15 Embargo
9/11 attacks
10
Iraq Invades Kuwait
Iranian Revolution
Asian economic crisis; Iraq oilfor-food
5
0
1970
1975
1980
1985
1990
1995
Refiner Acquisition Cost of Imported Crude Oil (Saudi Light Official Price for 1970-73)
2000
2004
Source: EIA
Also, the transfer of property rights from multinational oil companies to host governments that took place
mostly in the 1973-4 period provided another vital change in the market. Perhaps most important of all,
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
1 – 15
Economics of the Energy Industries
the rapid industrialization of the world in the 1960s increased the demand for crude oil. Alternative
energy sources were considered scarce and costly. All these circumstances provided an opportunity for
large producers to charge much higher prices for crude oil than their cost of extracting it.
In short, OPEC did not really have to act as a cartel in those years; the economic and political conditions
provided the organization with a chance to enjoy monopoly profits. This was only natural for a group of
producers that owned almost 70% of world's total oil reserves and that had excess capacity (the reservesto-production ratio for OPEC has been 70-80 years in the 1990s as compared to less than 16 years for
non-OPEC producers as a group - see chart below).
Reserves to Production Ratio (years)
90
22
80
OPEC
70
OPEC
18
Non-OPEC
60
16
non-OPEC
20
50
14
40
30
12
1960
1965
1970
1975
1980
1985
1990
1995
2000
Sources: Oil & Gas Journal and BP Statistical Review of World Energy
After OPEC adopted the quota system, however, Saudi Arabia quickly became the "swing supplier,"
reducing its production as necessary to balance supply and demand. The Kingdom rejected that role in
mid-1985, when its output had fallen to about 25% of its 1980 peak of 10 million b/d, and increased its
output to five to six million b/d range in a very short period of time. Increased Saudi supplies resulted in
the price collapse of 1986. Prices did not return to the pre-1986 level until the Persian Gulf conflict of
1990-91, and then only briefly.
The collapse of the oil price in late 1990s, however, was a serious blow to the members of the
organization. Most of them never diversified their economies; oil revenues are crucial for maintaining the
health of the economy, level of social services and hence happiness of their societies. Historically low
prices in 1997 and 1998 (at about $10 per barrel) hurt OPEC economies badly. In reaction, led by Saudi
Arabia and with the help of some non-OPEC producers such as Russia. Mexico and Norway, the
organization was able to implement and manage a quota system successfully. For the first time, OPEC
announced a price band and managed production levels accordingly. Members obeyed their cuts for a
sustained period of time. Together with the recovery of the world economy from Asian crisis, oil prices
recovered in late 2000 and 2001. But, as oil prices stayed high and world demand continued to increase,
members stopped following quotas, and cooperation of non-OPEC producers ended. Clearly, the
organization, and especially Saudi Arabia, has the potential to impact the price of oil but doing so requires
extreme conditions to convince other producers to cooperate and is not sustainable once those conditions
disappear.
What can we expect from OPEC in the future? In general, for producer cartels to operate successfully
over the long run, a number of “rules” apply. For one, it helps if the commodity in question in
homogenous in quality. Second, the more concentrated the commodity is geographically, the easier it is
for producer associations to form and organize. Third, cohesion within the producer association is
essential, and difficult to achieve and sustain. Fourth, the easier it is for consumers to reduce their
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
1 - 16
Economics of the Energy Industries
demand for a commodity, either through substitution or conservation, and the easier it is for new
producers to enter the industry (partly a function of geographic allocation of the commodity and
Changing Dynamics of Global Oil
Cartel Commodities
13.5%
39.0%
Market Shares:
Nominal commodity prices, indexed
38.5%
6
Cocoa
Coffee
Sugar
Tin
Copper
Oil
3
38.0%
12.5%
37.5%
12.0%
37.0%
2
20
01
19
95
19
98
19
89
19
92
19
83
19
86
19
77
19
80
19
71
19
74
36.0%
19
65
19
68
0
19
59
19
62
36.5%
19
56
1
19
50
19
53
13.0%
FSU
4
OPEC
5
% OPEC
% FSU
Historically, OPEC
has increased
production to protect
market share
11.5%
11.0%
1Q02 2Q02 3Q02 4Q02 1Q03 2Q03 3Q03 4Q03
Sources: Data from various commodity exchanges, UH
Source: IEA, U.S. EIA
homogeneity), the more difficult it is to sustain cartel activity.
The upshot is that for a number of commodities in which various forms of producer collaboration and
organization have been tried, success is difficult to achieve and sustain (see chart above at left). Over a
long period of time, prices for a basket of commodities have declined rather than increased (the usual goal
for producers). Despite all its problems described earlier, OPEC has been one of the more successful
cartels, outperformed only by the DeBeers diamond cartel. The relative cohesion within OPEC since
institution of the price band for the OPEC crude oil basket in 2001 has been remarkable by historical
standards for both the association and the history of cartels in general. OPEC’s dominance in the global
oil market is, however, increasingly challenged by the Former Soviet Union producers (in particular
Kazakhstan and Russia), which will increasingly test cohesion of the cartel in future years. A key
balancing mechanism in the battle for market share will be demand for crude oil in the large emerging
markets of China and India.
International Energy Agency
The International Energy Agency (IEA) is an autonomous body within the framework of the Organization
for Economic Cooperation and Development (OECD). The IEA was established in November 1974, in
response to the first oil shock, to implement an energy program that would provide energy security for its
members. In those days, governments were most concerned about receiving uninterrupted oil supply.
One of the immediate actions taken was to create oil inventories in order to avoid the economy-wide
impact of another oil shock.
The IEA has 23 members (as compared to 27 members of the OECD). Its basic goals are:
•
co-operation among IEA participating countries to reduce excessive dependence on oil through
energy conservation, development of alternative energy sources and energy R&D,
•
an information system on the international oil market as well as consultation with oil companies,
•
co-operation with oil producing and other oil consuming countries with a view to developing a
stable international energy trade as well as the rational management and use of world energy
resources in the interest of all countries,
•
a plan to prepare participating countries against the risk of a major disruption of oil supplies and
to share available oil in the event of an emergency.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
1 – 17
Economics of the Energy Industries
Although these activities remain fundamental for the IEA, the Agency extended its operations and focus
to emerging markets, especially in Asia. These countries are expected to account for more than half of
the world energy demand early in the next century. The increased consumption of fossil fuels and
reliance on nuclear power in order to avoid dependence on imported oil are already causing
environmental concerns. Also, the emergence of Central Asia and, to a certain extent, Latin America as
potentially significant suppliers of oil and gas have changed the structure of the world energy markets.
Recently, the IEA started to assist non-member countries in developing energy strategies and adopting
energy policies that will contribute to their economic development and enhance global energy security.
Liberalization of the marketplace is considered a priority by the Agency, which suggests building
transparent and open markets and increasing competition through privatization and less government
intervention. This will attract foreign investment and technology to help develop the economies of these
countries. Finally, the Agency advises these countries that improving energy efficiency can help ease
import dependence as well as environmental concerns.
International Trade Regimes
Increasingly, energy trade and investment flows are dominated by the presence of international trade
regimes that set the “rules of the game” for access, content, intellectual property rights and a host of
variables. International trade regimes also incorporate conflict management and dispute resolution
mechanisms. The impact of international energy trade on domestic policies has long been a source of
conflict. The following diagram shows why.
International trade flows across national
boundaries,
driven
by
comparative
advantages, create pressure for host
governments to accommodate through trade
laws, regulatory frameworks that compliment
Trade Laws
private investment and reduce barriers to
Pressure from
entry via open access.
Balancing these
Trade Flows
Regulation
Strength of
pressures is the relative strength of state
State
ownership and control. When states act to
Ownership/
protect incumbent interests, international trade
Control
Open Access
flows are disrupted. Generally, the strongest
trade flows are where host government
Jurisdictional
Diminishing
regimes are most accommodating. These
Boundary
Monopoly Power
relationships hold for both goods and services,
5/11/2004
20
and range from examples such as open access
for the exchange of goods to use of
infrastructure (roads, railways, pipelines, shipping lanes, airline landing rights, financial systems and so
on) for market entry. In effect, international trade impacts internal policies and politics – and thus the
derivation of conflict.
How International Trade
Challenges Domestic Regimes
Examples of prevalent international trade regimes that affect energy include the World Trade
Organization (WTO) negotiations for services; the North American Free Trade Agreement (NAFTA)
which binds Canada, the United States and Mexico; the European Common Market which binds 25
countries from west to east Europe; El Mercado Común del Sur (Mercosur) which binds Argentina,
Brazil, Paraguay and Uruguay; Association of Southeast Asian Nations which binds ten countries; and a
variety of regional trade arrangements in Africa (SADC, Southern African Development Community;
COMESA, Common Market for Eastern and Southern Africa; SACU, Southern African Customs Union;
CBI, Cross-Border Initiative; EAC, Commission for East African Cooperation; IOC, Indian Ocean
Commission; WAEMU, West African Economic and Monetary Union). In addition to global and
regional trade regimes, countries often engage in bilateral or bilateral-to-multilateral arrangements.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
1 - 18
Economics of the Energy Industries
A key question is whether international trade regimes lead to harmonized rules with respect to the
distinctive set of practices that link energy value chain economics and policy/regulatory frameworks for
successful, commercial investment and project development – what we term “commercial frameworks.”
Certainly, the spread of best practices in energy sector development and management can be facilitated
through trade regimes. The illustration of relationships between trade and domestic policies dictates the
extent to which best practices will be fully shared and implemented. The relative level of overall
development of countries also has a substantial impact. Energy sectors that are comparatively
undeveloped may not be best served by commercial frameworks designed for more advanced countries
and markets. To the extent that domestic policies reflect unique socioeconomic, political and cultural
histories and traditions within countries, harmonization of rules can be difficult to achieve. The North
American and European Union internal market are strong cases in point. That said, there is little doubt,
and strong empirical evidence, that international trade exerts at least some degree of impact on domestic
regimes and at least incremental movements toward emerging international standards for private
investment and access.
Industry and Government Associations
Energy is often a sensitive and complex subject, and energy sector development – as indicated through
the remainder of this book – is not an easy undertaking. In the global context, numerous industry and
government associations, as well as professional societies and standards organizations and societies, that
coordinate technology and intellectual property, access, investment, capital flows, research and
development, policy/legal/regulatory best practices and the like. Some of the more prominent
associations include the World Energy Council and World Petroleum Council; large energy trade
associations that span the international arena, such as the International Gas Union, American Petroleum
Institute and Edison Electric Institute; the large professional societies that spur collaboration among the
core science and engineering disciplines, such as Society for Petroleum Engineers, American Institute for
Chemical Engineering, Society for Exploration Geophysics, American Institute of Petroleum Geologists
and the International Association for Energy Economics; government associations like the National
Association for Regulatory Utility Commissioners, the Canadian Association of Members of Public
Utility Tribunals, IberoAmerican Energy Regulators and the emerging International Energy Regulators
Network.
Bilateral and multilateral lending and financial institutions also serve to coalesce international and
regional energy interests. The World Bank and the various regional development banks are not small
players in global energy investment flows, trade flows, energy sector restructuring and evolution of
commercial frameworks. The United Nations also has impact through the various UN agencies and
programs that address energy, environment and infrastructure. These institutions and many others within
the constellation of non-governmental organizations (NGOs) have come to dominate discourse on
everything from corruption and transparency, to environment and human rights. This makes the milieu
for energy sector development a complex and dynamic one indeed.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
1 – 19
Economics of the Energy Industries
SECTION 2 – COMMERCIAL FRAMEWORKS
CHAPTER 2 - ENERGY VALUE CHAIN OVERVIEW
CHAPTER 3 – OIL VALUE CHAIN OVERVIEW
CHAPTER 4 – NATURAL GAS VALUE CHAIN OVERVIEW
CHAPTER 5 – ELECTRIC POWER VALUE CHAIN OVERVIEW
CHAPTER 6 –ROLE OF GOVERNMENT
CHAPTER 7 – PROJECT EVALUATION AND CAPITAL BUDGETING
CHAPTER 8 – PROJECT FINANCE
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
Economics of the Energy Industries
CHAPTER 2 - ENERGY VALUE CHAIN OVERVIEW
What are energy value chains? In any industry, a logical set of relationships exists as goods are produced,
transported, distributed and consumed. For the energy sector, the value chains constitute extraction of
primary energy fuels, transportation networks that aggregate fuels, local distribution networks that serve
end users. In the crude oil value chain, oil must be converted through refining to manufacture petroleum
products that can be utilized. These products, in turn, are distributed through an array of wholesale and
retail outlets. Natural gas can be directly used (for heating, cooking) and thus can enter local distribution
networks or gas utilities. Natural gas and oil can both be converted to electric power and distributed as
electricity (electrons become the commodity). Natural gas, like crude oil, can also be converted into an
array of intermediate products that become input to the huge number of goods that we are all so familiar
with today – plastics, waxes, fertilizers, paints, and many others. In the energy value chains, as with
value chains for other industrial sectors, considerable value or increased profit or economic rent is created
as energy fuels are transported, converted, distributed. These relationships can be discerned when prices
across the value chains are analyzed. An example is provided below for the U.S.
Case Study: The United States Energy Value Chains and Prices
1999 Data (U.S. EIA, Annual
Energy Review)
Transport+Treatment
$2.26
IN – RAC
(16 mmb/d)
Domestic $17.82
Import
$17.23
Composite $17.46
CRUDE OIL VALUE CHAIN
Transportation
(pipeline, tanker,
truck, rail)
6 mmb/d
U.S. Avg.
DFPP
$15.56/bl
Oil and gas field
production
24 tcf
Wellhead
$2.07/mcf
Marketed production 20 tcf
Dry Gas 19 tcf
Net Imports 4 tcf
Gathering,
processing
MARGIN (BL)
Motor Gasoline $9.53
Jet Fuel
$5.12
No. 2 Distillate $5.04
Residual FO ($3.44)
Composite
$7.89
Refining (to petroleum
products: gasolines, jet
fuels, diesel, fuel oils,
etc.)
Wholesale and
retail marketing
End users: individuals,
businesses, governments,
institutions
Petrochemicals
(feedstocks for
intermediate products)
Wholesale
marketing
Conversion to final
products (fertilizers,
plastics, etc.)
$1.04 (to City Gate)
City Gate $3.11
Natural gas pipeline
transportation
Natural gas liquids
transportation
(pipeline, truck,
tanker)
NATURAL GAS VALUE
CHAIN
LNG
Field-to-liquefaction 10-20%
(Percentages reflect approx.
share of total LNG value chain
cost; $/MMBtu amounts
assume 2,500-mile voyage)
OUT (BL) (17 mmb/d)
ON HIGHWAY (BL)
Motor Gasoline $32.80 (8 mmb/d) Motor Gasoline $47.04
Jet Fuel
$22.59
No. 2 Distillate $24.15
Residual FO $15.79
End users:
Residential $6.60
$3.49 Commercial $5.26
Natural gas
distribution
Industrial $3.04
Electric Utilities $2.56
$0.97
Wholesale and retail
marketing and distribution
Propane* sold to resellers:
$0.78/gallon (refinery)
Propane sold to end-users:
$1.27/gallon
LNG tanker
shipment to
markets
15-25%
$0.40/MMBtu
Liquefaction
(liquefied natural
gas or LNG)
25-35%
$1.00/MMBtu
* About 2mmb/d of propane produced at refineries, about
538,000 b/d at gas plants; about 1 mmb/d LPG sold for end use.
Industrial $3.04
(Fuel and feedstock for
industrial processes,
including petrochemicals)
Conversion back to gas
phase for pipeline,
distribution, end use
5-15%
$0.40/MMBtu
Direct use (electric
power generation)
25-35%
Within the U.S., crude oil is produced and wellhead value recorded as domestic first purchase price
(DFPP). Refineries typically use both domestic and imported crude as inputs, with a basket of prices
referred to as refiner acquisition cost (RAC). Refining output reflects gains – the increased volume of
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
2-1
Economics of the Energy Industries
referred to as refiner acquisition cost (RAC). Refining output reflects gains – the increased volume of
petroleum products that are created as molecules in a barrel of crude oil are separated and recombined
with other inputs. The values in the chart above indicate the amount of value created as crude oil inputs
are converted into final outputs and then sold, with motor gasoline distributed through retail outlets
located along major highways being the example price indicator. Likewise for natural gas, the U.S. uses
both domestic consumption and imported supplies. Natural transportation to the city gate (the meter point
for local distribution companies or utilities) is reflected as the difference between city gate and domestic
wellhead price. City gate distribution value is shown as the difference between what residential end users
pay and the city gate price. Natural gas can be transported directly from wellhead to electric utilities for
power generation as well as to industrial users. An example of the value of this transportation is the
difference between what industrial users pay for their natural gas fuel and feedstock and the domestic
wellhead price. Note that transportation costs to electric power generators and industrial customers –
given the large volumes of natural gas they use as compared to small residential and commercial
consumers – are quite competitive. Beyond power generation, a separate value chain exists for
transmission and distribution of electricity. End user pricing across different types of customers closely
follows end use pricing for natural gas, i.e., distributed electricity entails higher marginal costs and
therefore higher retail prices for small residential and commercial customers than for large volume
commercial and industrial users. Liquid petroleum gas (LPG) can be used as petrochemical feedstock but
is more typically sold through wholesale and retail markets. The later chapter on liquefied natural gas
(LNG) in Section 3 of this book provides more detail on LNG value chain costs.
Importantly, the values indicated in the chart above do not reflect profit margins. Economic rents are
created, but earnings for companies that operate within or across value chain segments are dictated by
commodity price cycles (including commodities created through the conversion of energy fuels); the
operators’ own efficiencies and technical capabilities; rules enforced by governments with respect to
taxes, royalties and fees; rules that impact discrete costs associated with operations, such as
environmental protection and mitigation; the level of competition within and across the value chain
segments; and so on. Refining and petrochemicals are notoriously volatile when it comes to margins
associated with discrete products. Electricity as a commodity is highly volatile in most countries that are
experimenting with more competitive regimes for electric power generation, transmission and
distribution.
Within the global energy industries, business strategies become defined around the goals and objectives
of optimizing energy value chains and leveraging core assets across the value chains. From a public
interest point of view, energy business activities across the value chains can raise a host of issues. The
extent of vertical and horizontal integration can raise barriers to new entrants. From an energy business
perspective, integration – in particular vertical integration – is a key mechanism to insulate the firm
against volatile commodity price cycles and risk and uncertainty associated with the huge investment
requirements often needed to launch or expand energy projects. Economies of scale can rapidly develop,
especially with application of information technologies in wholesale and retail markets. In many cases,
energy businesses seek to expand economics of scale and scope, using market share as protection against
business and commodity cycles. Governments often accommodate market power in the energy sector
through regulated entry or access and regulated pricing to reduce the opportunities for monopoly abuse or
other forms of market failure (see chapter on role of government later in this section). The constant
tension in highly networked, value chain driven industries is the tendency for competition to rapidly
deplete profit margins, triggering strong incentives for industry consolidation. Thus, a critical balance
between energy industry activity and government actions to protect public interest must be achieved to
facilitate energy sector investment. Best practices in commercial frameworks (the rules and norms
created by governments to facilitate commercial activity) are all about achieving this critical balance,
while also being mindful of the many issues (access, transparency, public involvement, environmental
protection) that impact energy development.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
2-2
Economics of the Energy Industries
CHAPTER 3 – OIL VALUE CHAIN OVERVIEW
Introduction
Fossil fuels (oil, natural gas and coal) make up roughly 88% of the world’s primary energy consumption,
while oil accounts for 38% of the global primary energy consumption (see chart below). Oil is expected to
remain the dominant energy fuel in the world for the foreseeable future. Oil is an important part of our
everyday life. Oil gives us mobility, fuels many industries and provides electricity. Millions of products
are made from oil and gas, including plastics, medications, clothing, cosmetics, and many other items you
may use daily. However, most important use of oil is in the transportation sector.
In the U.S., 97% of the energy that drives the transportation sector (cars, buses, subways, railroads,
airplanes, etc.) comes from fuels made from oil.1 Auto manufacturers are developing cars to run on
alternate fuels such as electricity, hydrogen and ethanol. However, the electric batteries need to be
charged and the fuel to generate the electricity could be oil or gas. The hydrogen needed for fuel cells
could also be generated from natural gas or petroleum-based products. Even as alternative fuels are
developed, oil remain crucially important to assuring that people can get where they need to be and want
to go for the foreseeable future.
World Primary Energy Consumption 2002
Nuclear
Energy 6%
Hydro
Electric 6%
Oil 38%
Coal 26%
Natural Gas
24%
Source: BP Global Statistical Review of World Energy June 2003
In the industrialized world, increases in oil
use are projected primarily in the
transportation sector, where there are
currently no available fuels to compete
significantly with oil products. In the
developing world, oil consumption is
projected to increase for all end uses. In
some countries where noncommercial fuels
have been widely used in the past (such as
fuel wood for cooking and home heating),
diesel generators are now sometimes being
used to dissuade rural populations from
decimating
surrounding
forests
and
vegetation, most notably in Sub-Saharan
Africa, Central and South America, and
Southeast Asia.
As economies around the world continue to grow, businesses and emerging middle classes are demanding
greater mobility for themselves and their products. In addition, world population is expected to grow to
approximately 7.6 billion by 2020 from roughly six billion at the beginning of the 21st century. That will
mean a huge increase in the demand for transportation fuels, electricity, and many other consumer
products made from oil and natural gas. World vehicle ownership is projected to increase from 122
vehicles per thousand people in 1999 to 144 vehicles per thousand in 2020, with the growth occurring in
developing nations. Airports are being added in these countries as well, expanding jet fuel demand. Oil
products such as gasoline, diesel and jet fuel are expected to remain the primary fuels for transportation
throughout the world for the foreseeable future. Transportation fuels are projected to account for almost
57% of total world oil consumption by 2020.2
1
2
U.S. Energy Information Administration (EIA), Annual Energy Review, 2001, March 2003.
EIA, International Energy Outlook, 2002.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
3-1
Economics of the Energy Industries
Oil Value Chain Components
Key Segments and Activities
The key segments of the oil value chain are exploration and production, transportation, refining,
distribution and marketing. The segments can also be divided into upstream and downstream. Upstream
activities are closer to the crude oil source, and "downstream" activities, such as distribution and
marketing of refined products, are closer to the consumer. Sometimes, crude oil transportation and
refining are classified as midstream.
Crude Oil Value Chain
UPSTREAM
OIL
MIDSTREAM
Transportation
(pipeline, tanker,
truck, rail)
DOWNSTREAM
Refining (to petroleum
products: gasolines, jet
fuels, diesel, fuel oils,
etc.)
Wholesale and
retail marketing
End users: individuals,
businesses, governments,
institutions
Petrochemicals
(feedstocks for
intermediate products)
Wholesale
marketing
Conversion to final
products (fertilizers,
plastics, etc.)
Exploration and
production
GAS
NATURAL GAS VALUE
CHAIN
Upstream
Exploration: The activities that lead to discovery of new natural crude oil resources. Exploration risk is
one of the strongest forms of risk.
Production: Extraction of discovered supplies from hydrocarbon fields. If there is associated natural gas,
it must be separated.
Midstream
Transportation: There are two modes of transportation for inter-regional trade: tankers and pipelines.
Tankers have made global (intercontinental) transport of oil possible, and they are low cost, efficient, and
extremely flexible. Pipelines, on the other hand, are the mode of choice for transcontinental oil
movements.
Not all tanker trade routes use the same size ship. Each route usually has one optimal economic size based
on voyage length, port and canal constraints and volume. Thus, crude exports from the Middle East, high
volumes that travel long distances, are moved mainly by Very Large Crude Carriers (VLCC’s) typically
carrying over two million barrels of oil on every voyage. In contrast, ships out of the Caribbean and South
America to the U.S. are routinely smaller and enter ports in the U.S. directly. Because of such ship size
differences, a long voyage can sometimes be cheaper on a per barrel basis than a short one.
Pipelines are critical for landlocked crudes and also complement tankers at certain key locations by
relieving bottlenecks or providing shortcuts. Pipelines are the primary option for transcontinental
transportation, because they are at least an order of magnitude cheaper than any alternative such as rail,
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
3-2
Economics of the Energy Industries
barge, or road, and because political vulnerability is a small or non-existent issue within a nation's border
or between neighbors such as the U.S. and Canada. Pipelines are also an important oil transport mode in
mainland Europe, although the system is much smaller in view of the shorter distances.
Downstream
Refining: Refining is a complex series of processes that manufactures finished petroleum products out of
crude oil and other hydrocarbons. While refining began as simple distillation, refiners must use more
sophisticated additional processes and equipment in order to produce the mix of products that the market
demands.
Distribution and Marketing: Delivery of refined products via pipelines, trains, and trucks for retail
marketing by gas stations, fuel oil companies and other marketers.
Key Policy and Regulatory Considerations
Clearly, crude oil is traded in a global market with numerous players with a wide variety of demandsupply characteristics. As discussed in Chapter 1, OPEC can have significant influence on the price of
oil. In most resource rich countries, national companies dominate the sector. There is also considerable
geopolitical risk considering the major export region for oil is the Middle East. Given these risks and
importance of oil in economic development, consumer governments usually follow policies targeting
supply security. By diversifying their suppliers, they manage geopolitical risks. Building fuel
substitution capability wherever feasible and increasing demand side response via energy efficiency and
conservation programs also help economies absorb supply shocks. Many countries also hold petroleum
reserves (see the section on IEA in Chapter 1).
On the supply side, the biggest challenge is the ability to invest in resource rich countries under
commercially viable terms. In many countries, access to upstream by private investors is either not
allowed or very limited. In others, investment infrastructure is not acceptable (see below for more
discussion of this topic). In addition, both buyers and sellers may impose restrictions. For instance, the
U.S. prohibits imports from Iran and Libya, and the United Nations allowed only limited sales of Iraqi oil
during the 1990s. On the seller's side, Mexico formerly limited sales to the U.S. to 50% of its exports,
reflecting concerns about dependence on the U.S. specifically and about dependence on one geographic
market in general. Saudi Arabia's national security concerns, on the other hand, dictate that it maintain a
very high profile as a supplier to the U.S. market, even at the cost of lower netbacks.
In most developed countries, activities across the oil value chain are mostly unregulated. There is not
much economic (i.e., price) regulation on crude oil or, for the most part, its products. Most emerging and
least developed economies, though, continue
to employ subsidized pricing for fuels such as
kerosene or LPG that are used by the poor for
cooking and heating. It is also possible to
observe subsidies for distillates used in
industry or power generation.
National
companies play an important role in
administering or benefiting from these pricing
schemes.
C r u d e P r ic e
I n d u s t r y M a r g in
Tax
S o u rc e : O P E C
However, the industry is the target of taxes
that are imposed primarily for the purpose of
raising funds for governments, especially in
developed countries. Some of these funds
may be used in building and maintaining
roads but most are incorporated into the
general revenue stream of governments to
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
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Economics of the Energy Industries
finance other projects. A part of these taxes can also be said to represent the cost of externalities
associated with oil consumption, e.g., emissions from tailpipes. The chart above demonstrates the wide
range of tax policies pursued by a group of OECD countries. While taxes account for less than one third
of total price of gasoline in the U.S., they make almost three fourths of the price in the UK. The U.S. is a
large country and its economy is very much dependent on low-cost transportation of goods and services
as well as people. On the other hand, the UK is a small island where land transport does not constitute a
major cost item for most businesses or individuals.
The oil industry is also subject to a variety of operational safety, health and environmental regulations.
For example, because of the tailpipe emissions, gasoline consumption is a major contributor to air quality
problems, especially in large cities. Governments around the world employ different approaches to
lowering the level of emissions. Some limit access to cities by all vehicles (e.g., alternating days based on
license plate numbers); others impose fees for entering congested areas of the city (e.g., the recent
experiment in London); but most common is the regulation on fuel specifications. The simplest action
involves switching to unleaded gasoline or cleaner burning LPG or CNG; but reformulation of gasoline
can become very complicated and expensive for both refiners and consumers. For example, there are as
many as 18 different kinds of gasoline specifications that exist throughout the U.S. This greatly hinders
market flexibility, as the lack of a uniform specification prevents gasoline from moving from one region
to another. Furthermore, some U.S. regional markets such as the West Coast and the Midwest generally
function in isolation, which only increases the risk of shortfalls. Recently, more stringent regulations
mandated the lowering of sulfur content to 120 parts per million (ppm), and the elimination of oxygenate
and octane enhancer methyl tertiary butyl ether (MTBE). The replacement of MTBE with ethanol in the
reformulated gasoline market led to a reduction in the entire U.S. gasoline supply, as ethanol has to be
blended with smaller quantities of gasoline to avoid a high level of volatile materials that breach the new
restrictions. Differences in fuel specification can also lower the liquidity in global trading of products.
Investment in the Oil Value Chain
The cost of finding and producing crude oil can range from as little as $2 per barrel in the Middle East to
more than $15 per barrel in some fields in the U.S. The range is so wide because there is great
uncertainty about existence, quality and size of oil reserves. Finding oil involves a series of steps:
identifying a prospect, drilling a well, appraising the size of the discovered field and determining whether
the find is commercially viable. Production wells are then drilled and gathering pipelines are assembled
to transport the oil to central points for further shipment. These are all very capital-intensive activities. As
such, the upstream segment involves the most investment risk. Accordingly, it provides greater rewards in
terms of profit and return on investment than other segments of the value chain. Between 75 and 80
percent of the crude oil ultimate value is captured in the upstream segment of the value chain. Recent
technological advances have reduced the uncertainties and contributed to more efficient use of capital,
enhancing the industry's success, even in a low-price environment. Technological innovation not only
makes it easier to find new deposits of oil and gas, but to get more oil or gas from each reservoir that is
discovered.
In order to fuel growing world economies, led by China and the U.S. and closely followed by India and
other emerging economies, there is a need for significant investment in the near future. Part of the
urgency is a result of the bust experienced after the collapse of oil price in late 1990s following the Asian
economic crisis and ill-timed OPEC decision to increase quotas. Companies cut their investment budgets
and many expensive fields in mature regions such as the U.S. stopped producing. According to the
International Energy Agency (IEA), total investment needed between 2001 and 2030 is roughly $3
trillion, most of which will be for exploration and development activities.
A number of issues will impact this investment outlook. The reduction in capital spending for upstream
activities as the international oil industry continues to consolidate after the tough times in late 1990s.
Large producing basins (e.g., in North America and North Sea) mature. Perhaps more importantly,
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
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Economics of the Energy Industries
governments of most resource rich countries (and their national companies) continue to constrain entry by
international companies. Moreover, there has been increasing scrutiny concerning the reserves of most
Middle Eastern producers. Since these countries upgraded their reserves numbers by almost 300 billion
barrels in the late 1980s, there has not been significant international investment in these countries and not
many new field developments. As the world oil market becomes tighter, the veracity of these reserves
and the investment needed for their development become more important topics of debate.
Investment Requirements in the Oil Sector ($ billion)
2001–2010
2011–2020
2021–2030
$689
$740
$793
Unconventional Oil
49
60
96
Refining
122
143
147
Tankers
37
79
76
Pipelines
20
23
23
TOTAL
$917
$1,045
$1,135
Exploration & Development
Source: International Energy Agency
In particular, Saudi production capacity has been attracting a lot of attention. According to some analysts,
Saudi oil production from existing fields may be near peaking and next generation of Saudi oil will be
harder and hence more expensive to extract.3 It is important to understand Saudi potential well because
the Kingdom produces roughly 10% of world’s oil (roughly eight million b/d) and is the only producer
with significant excess capacity (estimated at about two million b/d). The EIA, IEA & OPEC forecasts
are consistent: by 2010, oil demand will reach about 90 million b/d, which requires the addition of about
8 million b/d in extra production capacity. By 2020, forecasts diverge but range between 104 (IEA) and
110 million b/d (EIA and OPEC), indicating an additional increase of production capacity by 14-20
million b/d. According to the EIA, Saudis will produce 13.6 million b/d in 2010, and 19.5 million b/d in
2020. Aramco officials at the CSIS meeting claimed that the Kingdom could produce up to 15 million
b/d. Saudis can produce up to 12 million b/d for some time and no more.4 Even if the gap between EIA
expectations and Saudi production estimates can be closed, that would require significant amount of
investment to flow into the Kingdom starting fairly soon. But the Kingdom has been closed to
international investment in upstream oil since the 1970s. There seems to be no indication for a change in
this policy and Aramco’s ability to raise the financing is debatable.
The Link between Investment and Commercial Frameworks
Global Perspectives
There is more trade internationally in oil than in anything else. This is true whether one measures trade by
volume, by value, or by the carrying capacity needed to move it. Volume provides insights about whether
markets are over- or under-supplied and whether the infrastructure is adequate to accommodate the
required flow. Value allows governments and economists to assess patterns of international trade and
balance of trade and balance of payments. Carrying capacity allows the shipping industry to assess how
many tankers are required and on what routes. Transportation and storage play a critical additional role
here. Generally, crude oil and petroleum products flow to the markets that provide the highest value to
the supplier. Everything else being equal, oil moves to the nearest market first, because that has the lowest
transportation cost and therefore provides the supplier with the highest net revenue, or the highest
3
For example, the Center for Strategic and International Studies held a seminar on February 24, 2004 on this topic: Conference: Future of Global
Oil Supply: Saudi Arabia. Presentations can be seen at http://csis.org/energy/events.htm.
4
Quote from Edward O. Price Jr, a past executive in both Aramco and Chevron, in “Forecast of Rising Oil Demand Challenges Tired Saudi
Fields,” Jeff Gerth, The New York Times, February 24, 2004.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
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Economics of the Energy Industries
netback. If this market cannot absorb all the oil, the balance moves to the next closest one, and the next
and so on, incurring progressively higher transportation costs, until all the oil is placed.
Unlike upstream and pipelines, refining and marketing is less risky but is also significantly less profitable,
especially during the 1990's. For example, in the U.S., gross refinery margins have been squeezed from
their peak in the 1980s while operating costs and the need for additional investment to meet
environmental mandates has grown. In addition, much of the investment made during the 1980's was
designed to take advantage of the differential between the dwindling supply of higher quality crude oils
and the growing supply of heavier and higher sulfur crudes. When that differential narrowed, however,
the financial return on those investments declined.
The quality of the crude oil dictates the level of processing and re-processing necessary to achieve the
optimal mix of product output. Hence, price and price differentials between crude oils also reflect the
relative ease of refining. A premium crude oil like West Texas Intermediate, the U.S. benchmark, has a
relatively high natural yield of desirable naphtha and straight-run gasoline. Another premium crude oil,
Nigeria's Bonny Light, has a high natural yield of middle distillates. By contrast, almost half of the simple
distillation yield from Saudi Arabia's Arabian Light, the historical benchmark crude, is a heavy residue
("residuum") that must be reprocessed or sold at a discount to crude oil.
Different markets frequently place different values on particular grades of oil. Thus, a low sulfur diesel is
worth more in the U.S., where the maximum allowable sulfur is 0.05 percent by weight, than in Africa,
where the maximum can be 10 to 20 times higher. Similarly, African crudes, low in sulfur, are worth
relatively more in Asia, where they may allow a refiner to meet tighter sulfur limits in the region without
investing in refinery upgrades. Such differences in valuing quality can be sufficient to overcome
transportation cost disadvantages, as the relatively recent establishment of a significant trade in longdistance African crudes to Asia shows.
As markets evolve and environmental regulations change, refineries may need to adjust their production
accordingly. In general, there is a trend towards lighter products, mainly because they emit fewer
pollutants when burned. But, the world may also need to develop more of the heavier oil fields as well as
oil sands. In order to supply the lighter products needed, refineries should be able to process these
heavier crudes while remaining profitable. For example, Mexico and Venezuela pro-actively took the
strategic decision to make as large and as profitable a market as possible for their poor quality crude,
since their reserves are unusually biased toward those hard-to-place grades. Both countries therefore
targeted their nearest markets, the U.S. Gulf Coast and the Caribbean, for joint venture refinery
investments. They began with refineries that had traditionally run their crude, and then with refineries
that might be upgraded to do so.
Commercial Framework Principles for the Oil Value Chain
As discussed before, about three fourths of the value across the oil value chain is generated in the
upstream. This is the riskiest investment in the industry; accordingly, investors require higher rewards.
Since oil, like many other natural resources, are treated as national by many countries and state companies
and policies dominate the sector, private investment is restricted. Where it is allowed, commercial
frameworks are not always conducive to investment. As a general observation, richer the resource base is
(i.e., lower the technical risk is), the tougher the fiscal terms offered by countries become; in Chapter 6
we provide a detailed discussion of this relationship and in Chapter 9 we provide more background on
fiscal terms. In addition, legal and regulatory infrastructure may not be sufficiently evolved to support
such large investments. Petroleum laws may be non-existent or not implemented. Taxation policies of the
government can be unstable. The legal system may limit contract dispute resolution. All of these increase
the uncertainty of investment. Of course, OPEC and, in particular, Saudi Arabia continue to manage the
oil market by adjusting the output of the organization. Most recently, OPEC has been administering a
price band with some success (see Chapter 1).
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
3-6
Economics of the Energy Industries
Increasingly, these large scale investments attract the scrutiny of environmental and human rights NGOs
who put pressure on companies, governments and development agencies such as the World Bank for
increasing transparency, ensuring benefits for host communities, improving environmental practices, and
the like. These considerations apply to long distance, international pipelines as well. In certain regions,
development of export pipelines is a prerequisite for the viability of upstream investment; examples
include the Caspian region, Alaska and Chad. Even if the companies can demonstrate that the fields can
be developed with minimal environmental damage and with benefits for the communities, a pipeline
traveling hundreds of miles not only increases the cost of oil but also raises opportunities for conflict
between the investors and hosts for environmental, social or historical reasons. Mitigation of this risk
surely increases the cost further. For example, sponsors of the Baku-Ceyhan pipeline had to conduct
thousands of interviews with host communities and undertake numerous studies to assess environmental
and social impact of the pipeline.
Perhaps the most important issue for the industry is the volatility of oil price. The industry had a history
of price spikes, mostly resulting from geopolitical developments originating from the Middle East.
Recently, though, disruptions in many other regions such as the strikes in Venezuela and civil unrest in
Nigeria had significant impact on the price of oil. Naturally, major economic crises such as the Asian
crisis of the late 1990s can cause havoc in the sector as well. This uncertain nature of the oil price caused
investment to come and go in waves, causing boom-bust cycles in the industry. Companies have not been
able to manage these cycles very well, either investing heavily in boom times or holding back investments
for too long even after busts are over. High investment periods potentially create the excess supply
conditions of the future, contributing to the eventual bust, especially if an economic recession occurs.
Holding back investment for too long pushes prices high, destructing demand sometimes permanently.
These cycles damage the industry’s ability to attract and keep high quality employees from management
to engineering and to field operations.
Relevant Case Studies:
Apertura in Venezuela
Brazil’s Restructuring of the Oil & Gas Industry
Chad Cameroon Pipeline
Deepwater Developments in Angola
Deepwater Developments in Brazil
Deer Park Refinery
Energy Inc. Deepwater Projects
Environmental Catch-22 in Nigeria
LPG Subsidies in India
Nigerian National Petroleum Company
North Atlantic Canada
Oil Monetization in Azerbaijan
Refining Sector in Kazakhstan
Small Refiner Bias
Soviet Legacy on Russian Petroleum Industry
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
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Economics of the Energy Industries
CHAPTER 4 – NATURAL GAS VALUE CHAIN OVERVIEW
Introduction
Natural gas has come a long way as a good with intrinsic value. Natural gas was once considered a mere
byproduct of oil and thus not worth the significant capital investment required to find, gather, treat,
transport and distribute this resource. The relative abundance, wide dispersion and cleanliness of natural
gas has propelled it to the forefront of the fossil fuels so that natural gas today is poised to become a
global commodity, a bridge fuel to the next energy future and a source of molecular building blocks to
new materials. The key policy challenges lie in differentiating the various markets associated with natural
gas molecules and fashioning competitive supply, demand and pricing mechanisms; designing appropriate
policy approaches for components of the natural gas value chain that bear public service attributes and
thus affect the public interest; and mobilizing capital investment while balancing efficiency and equity
concerns.
Whereas oil is a global commodity, transported in a variety of ways, and with consistent pricing in dollar
terms, natural gas tends to be a regional fuel. The use of natural gas is limited by transport options –
pipeline for overland delivery, ship for transoceanic delivery as liquefied natural gas (LNG). Natural gas
is also traded in currency denominations according to location of use. Thus, natural gas is not yet
considered to be a fungible, global commodity, like oil. Because domestic use of natural gas tends to be
dominated by pipeline transportation and distribution of methane, both of which may tend to have natural
monopoly characteristics, much of the natural gas business has been characterized by state intervention in
various forms to manage market power and protect the public interest. Broad experimentation with
competitive markets for natural gas since the mid-1980s has yielded a variety of results and many lessons,
as well as hastened the convergence of natural gas and electric power. For all of these reasons, natural
gas is a fuel that has both great potential but also unique challenges with regard to policy and regulatory
design and implementation.
The supply security “premise” for natural gas should be no different than for the energy sector overall, or
for other specific fuel markets. In general, the greater the diversity of supply, the smaller is the
geopolitical risk. This is particularly important because natural gas prices in many parts of the world
remain strongly linked to oil, a result of interchangeability for these fuels and the lack of separate markets
to establish natural gas prices. Rather than separate “demand side” considerations, they should be
incorporated into the supply portfolio. To the extent that policy and regulatory approaches provide for
choices to be made with regard to natural gas consumption, then demand will adjust to changes in supply
and thus price, enabling imbalances to be rationalized. Price signals transfer information, facilitating
choices. A specific political issue in many countries is the degree to which customers should be, or can
be, exposed to price volatility. It is clear, from a number of instances around the world, that minimal
political interference is best, but political will to support “light handed” policy and regulatory regimes is a
distinct limitation. These supply security considerations lead to the realization that flexible, transparent
frameworks for private investment and operation across the natural gas value chains are the essence of
best practices. These approaches facilitate price discovery, spur technological innovation for both supply
and demand and provide for midstream hedging solutions such as storage, a key ingredient to ensure
supply-demand balances.
Natural gas is an important and rich source of energy for the world, but the physical characteristics of
this fuel source, the economic features of the natural gas value chain and its extension to electric
power as gas-fired power as a prominent strategy pose particular challenges to investors (suppliers)
and their customers. Natural gas transportation options tend to be constrained, with pipeline
transportation and distribution the dominant mode. Within domestic markets, there must be sufficient
demand and “willingness to pay” in order to justify investment in transportation and distribution
infrastructure. For gas to become a “global” fuel like oil (as liquefied natural gas or LNG; through gas© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
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Economics of the Energy Industries
to-liquids or GTL conversion; or some other strategy), there must be sufficient demand and opportunities
for arbitrage – that is, it must be possible to create gains from trade between sellers and buyers.
We use the term “natural” to distinguish gaseous and associated liquid hydrocarbons produced from the
earth with those that are “manufactured,” typically from coals (and often referred to as “town gas”).
Methane (one carbon and four hydrogen atoms) typically comprises as much as 85 percent of a natural
gas stream, depending upon whether the natural gas occurs with crude oil or separately, and is thus the
most abundant molecule. Other molecules, in varying proportions, include ethane, propane, butane,
carbon dioxide, oxygen, nitrogen and impurities like hydrogen sulfide and rare gases that must be
removed before public use. Liquefied petroleum gas (LPG) – a propane/butane mixture – is stripped out
of field production and can be shipped by pipelines or separately by truck or tanker for uses like
petrochemical manufacturing, in backyard grills or for vehicle transport fuel. In many countries,
particularly those with short heating seasons, LPG comprises the principal domestic fuel source for water
and space heating and cooking. Natural gas liquids (NGLs) – ethane and larger molecules – also are
stripped out as feedstocks for petrochemicals (methane can also be used for petrochemical applications,
but much larger volumes of methane are required than for the heavier molecules). These molecules can
also be transported by pipeline, truck or tanker. Other than pipeline delivery, methane can be liquefied
and thus transported economically over large distances (in liquefied natural gas or LNG ships or by truck;
LNG cargos may contain molecules other than methane if there is no processing at the point of
liquefaction). Or methane can be compressed (compressed natural gas or CNG) and transported shorter
distances by truck and eventually, depending upon emergence of viable technologies and cost structures,
in CNG tankers. CNG and LNG allow methane to be used as a vehicle fuel where LPG can be used
directly.
Defining Natural Gas*
Natural gas is a gaseous mixture of hydrocarbon compounds, the primary one being methane. Methane is a
colorless, flammable, odorless hydrocarbon gas (CH4) which is the major component of natural gas. It is also an
important source of hydrogen in various industrial processes. Methane is a greenhouse gas. The U.S. Energy
Information Administration measures wet natural gas and its two sources of production, associated/dissolved
natural gas and nonassociated natural gas, and dry natural gas, which is produced from wet natural gas.
•
Wet natural gas: A mixture of hydrocarbon compounds and small quantities of various nonhydrocarbons
existing in the gaseous phase or in solution with crude oil in porous rock formations at reservoir conditions.
The principal hydrocarbons normally contained in the mixture are methane, ethane, propane, butane, and
pentane. Typical nonhydrocarbon gases that may be present in reservoir natural gas are water vapor, carbon
dioxide, hydrogen sulfide, nitrogen and trace amounts of helium. Under reservoir conditions, natural gas and
its associated liquefiable portions occur either in a single gaseous phase in the reservoir or in solution with
crude oil and are not distinguishable at the time as separate substances. Note: The Securities and Exchange
Commission and the Financial Accounting Standards Board refer to this product as natural gas.
•
Associated-dissolved natural gas: Natural gas that occurs in crude oil reservoirs either as free gas
(associated) or as gas in solution with crude oil (dissolved gas).
•
Nonassociated natural gas: Natural gas that is not in contact with significant quantities of crude oil in the
reservoir.
•
Dry natural gas: Natural gas which remains after: 1) the liquefiable hydrocarbon portion has been removed
from the gas stream (i.e., gas after lease, field, and/or plant separation); and 2) any volumes of
nonhydrocarbon gases have been removed where they occur in sufficient quantity to render the gas
unmarketable. Note: Dry natural gas is also known as consumer-grade natural gas. The parameters for
measurement are cubic feet at 60 degrees Fahrenheit and 14.73 pounds per square inch absolute.
* Adapted from the U.S. EIA, see www.eia.doe.gov/glossary.
Worldwide, the natural gas industry has grown rapidly in recent years. Nations with rich natural gas
resources have aggressively added new petrochemicals capacity. These huge investments tend to be quite
lumpy and the products subject to intense global competition (with commensurate impacts on the
feedstock molecules), leading to the well-known cyclicality in these businesses. Likewise, LNG
investments are also sizeable, lumpy and subject to global forces, and also fast growing. For nations that
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
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Economics of the Energy Industries
do not have large enough domestic demand relative to the size of their resource base, or that have not
developed petrochemicals capacity for conversion of natural gas to other products, LNG is an important
means of deriving value for their natural resource endowments through international trade. LPG as a
domestic energy source has also grown, proving to be a relatively cheap (in terms of local infrastructure)
and clean replacement for biomass. In particular, LPG has replaced wood (and is therefore preferable in
places where deforestation has been rampant) and animal dung. LPG also represents an improvement in
both cleanliness and safety over kerosene, also used as domestic fuel. Where LPG is in wide use, typical
policy challenges include pricing and transparency in market organization. Because LPG is most often
found as a domestic fuel in poorer countries, the tendency has been toward government control of final
prices charged to customers and to heavily subsidize these prices. These policy approaches are usually
neither fair nor effective; they are also costly to governments. In many countries, lack of transparent
market organization for LPG contributes to widespread theft, increasing distortions and injuring the
consumers least able to make alternative choices.
Above all, it is the growth in demand for piped methane as a clean convenient option for consumer energy
markets that has garnered the greatest interest. Thus, from hereon “natural gas” refers to pipeline delivery
of methane and the myriad operational and commercial aspects involved.
Natural Gas Value Chain Components
Key Segments and Activities
Generally, worldwide, natural gas/methane infrastructure systems consist of the following operational
elements.
Natural Gas Value Chain
Electric Power
Generation
(Utilities, IPP,
Industrial)
Pipeline
Transportation
Electric Power
Transmission
Electric Power
Distribution
Local Distribution
Industrial
(Direct Use)
Processing
(If Needed)
Commercial
Re-gasification
Residential
Gas Separation,
Gathering
Oil and Gas Field
Production
Oil Refining
Liquefaction
(LNG)
LNG Tanker
Shipment to
Markets
Liquids Transportation
(pipeline, truck, tanker
or petrochem stream
for butanes+)
Marketing and
Distribution
(propane, butane)
Direct Use
(eg., vehicle transport)*
*Note that
compressed
methane and
LPG are also used
for vehicle
transport.
Methane stream
Liquids (LPG) stream (propane, butanes, etc.)
Power stream
No reproduction, distribution or attribution without permission.
Gas Liquids
Extraction
Upstream
Exploration: The activities that lead to discovery of new natural gas resources. Exploration risk is one of
the strongest forms of risk.
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Economics of the Energy Industries
Production: Extraction of discovered supplies from hydrocarbon fields either with crude oil (as
associated natural gas) or separately (non-associated natural gas). If natural gas is associated with crude
oil, it must be separated.
Midstream
Gathering: Collection of natural gas production from multiple wells connected by small diameter, low
pressure pipeline systems and delivery to a processing plant or long-distance pipeline.
Processing and treatment (if necessary): Processing is the separation of heavier molecules and
unwanted substances such as water from methane gas stream. If the gas stream contains impurities such
as hydrogen sulfide then treatment is required.
Storage: Containment of supplies, usually in depleted underground reservoirs or caverns like those
associated with salt domes. Storage can be located either near production or near demand.
Transportation: Delivery of gas from producing basins to local distribution networks and high-volume
users via large diameter, high volume pipelines. In countries that are federal republics, pipeline systems
may be distinguished by whether they cross state or provincial boundaries (for example in the U.S.,
interstate pipelines as opposed to intrastate systems that operate within the state jurisdiction). Countries
vary greatly with respect to allowable pipeline specifications for heat content, as measured by British
thermal units (Btu) in the U.S., Canada and elsewhere, and as related to the presence of molecules other
than methane in the piped stream. For example, pipelines transport and distribute methane or “dry” gas in
Canada and the U.S. That is, heavier molecules are removed before the natural gas stream enters the
pipeline system. Exceptions do exist, such as the Alliance Pipeline, which transports “wet” gas from
British Columbia to Chicago, where molecules other than methane are stripped out in processing for use
in other markets. Pipeline standards generally are set for safety reasons.
Liquefaction, shipping and re-gasification: Known collectively as the LNG value chain, this entails
conversion of gas to a liquid form via refrigeration to result in a cryogenic fluid (temperature -256°F) for
transportation from a producing country or region to a consuming country or region via ship. LNG is
stored until it is returned to the gas phase (re-gasification, using vaporization) for pipeline transportation
within the consuming region. In the U.S., LNG is also used to store natural gas produced from domestic
fields until it is needed, primarily for peak use. Both storage and transport of LNG are done at nearly
atmospheric pressure.
Downstream
Distribution: Retail sales and final delivery of gas via small diameter, low pressure local gas networks
operated by local distribution companies or LDCs (often termed gas utilities).
End use and conversion: Direct use or conversion for use in other forms (petrochemicals, electric power
or vehicle fuels).
Commercial Practices
The following commercial elements serve to bind the operating segments of the natural gas infrastructure
system and link suppliers, transporters and distributors with their customers.
Aggregation: Consolidation of supply obligations, purchase obligations or both as a means of
contractually – as opposed to physically – balancing supply and demand.
Marketing: Purchase of gas supplies from multiple fields and resale to wholesale and retail markets.
Retail marketing constitutes sales to final end users (typically residential, commercial, industrial, electric
power and public sector).
Capacity brokering: Trading of unused space on pipelines and in storage facilities.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
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Economics of the Energy Industries
Information services: Creation, collection, processing, management and distribution of data related to all
the other industry functions listed here.
Financing: Provision of capital funding for facility construction, market development and operation startup.
Risk management: Balancing of supply, demand and price risks.
Key Policy and Regulatory Considerations
Altogether, the elements described above constitute the natural gas value chain. The various segments are
highly interdependent but, in an open, competitive market, they also can be highly competitive. The
policy challenges associated with increased worldwide use are numerous. Frameworks for efficient
discovery and optimal production are the first hurdle. Efficient and equitable mechanisms, often at odds,
for pipeline transportation and local distribution are the second major hurdle. Methane is of little use in
consumer energy markets without pipeline infrastructure. These large systems tend to be characterized by
strong technical economies of scale and high barriers to entry. Particular problems also emerge with
respect to the public interest/public service component of these facilities, mainly with respect to reliability
and pricing on systems that are usually operated in monopoly, duopoly or limited competitor regimes. In
all cases, a specific policy quandary is how best to achieve prices for natural gas transportation and
distribution through tariff designs that yield something close to what competitive markets might be able to
achieve, with contestability (potential competition) usually providing a basis for market-based pricing in
larger markets.
A third challenge is development of transparent markets for natural gas supply and consumption. If
pipelines are an essential feature, a central question is whether molecules have intrinsic value or whether
the combination of pipeline and molecule together must constitute the service. Increasingly, the trend has
been to separate infrastructure and product (often termed “unbundling”) and to search for ways of
providing competitive access to pipeline systems for multiple suppliers and users of natural gas (often
termed “third party access” or “open access”). In these cases, pipelines become like toll roads, priced
through tariff design as noted above, while molecules become priced in discrete competitive markets.
When pipelines become subject to third party access regimes, the commercial activities described earlier
and associated with pipeline operations, i.e., the linking of suppliers to buyers, can be separated into
competitive business activities. Once subjected to competitive markets, methane molecules become
commoditized. With all market participants as price takers, new sources of risk and new policy
challenges arise. In recent years, the rapid commoditization of methane in the U.S. and Canada triggered
growth in marketing and trading (both of the physical product as well as financial derivatives) as separate
businesses. With methane a commodity, and pipeline capacity close to being commoditized, balancing
supply and demand across a market becomes both more efficient and more fragmented, as new
combinations of activities and relationships across the value chain become established. The fuel’s
growing importance in the international economy, as natural gas becomes globalized via LNG shipments
and disparate national and regional markets become linked, has meant new incentives for technical
improvements in supply and demand management and balancing. The principal segments of a natural gas
infrastructure system – exploration, production, transportation and distribution – share substantial capital
requirements and comparable, albeit different, risks. The long lead times required for development of
each sector’s assets present both industry and policy makers with the problem of adequately anticipating
changes in supply and demand. These projections must be accurate and timely to consistently attract the
necessary long-term investment and minimize market disruptions and distortions. Inadequate projections
create conflicts to the extent that they result in supply-demand imbalances which neither industry nor
government has the flexibility to correct in a timely manner.
Both the evolution of market-based policies for natural gas and international trade linkages mean timely
and accurate data and information on supply, demand and prices, a fourth requirement. A fifth and
increasingly complicated challenge is dealing with integration, with respect to industry organization and
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
4-5
Economics of the Energy Industries
international trade. Industry organization can encompass both vertical (meaning up and down the value
chain) and horizontal (meaning over some geographic or market extent) integration. Paradoxically, the
forces for integration within a natural gas industry often occur in spite of policy objectives that seek to
instill de-integration and competition as part of transitions to competitive markets. Integration of physical
infrastructure across international boundaries has grown rapidly with increased demand for piped
methane. As transportation and information technology have improved, so have the opportunities for
system linkages – first within a country, then among geographically contiguous nation states and
increasingly across the globe. With improved physical and commercial linkages comes an ever greater
need for more complex, sophisticated and coordinated policy solutions, posing new dilemmas in
international trade.
Investment in the Natural Gas Value Chain
In general terms, we speak of the challenges to
build the “natural gas factory,” a concept that
Building the Natural Gas Factory
encompasses the importance of seamless
interactions across the key value chain segments.
UPSTREAM
MIDSTREAM
DOWNSTREAM
Exploration and
Processing
Distribution and
In particular, international investor goals have
Production (E&P)
Storage
End Use
Pipeline Transportation
Residential
coalesced around the need to “monetize” natural
LNG
Commercial
Liquefaction
Industrial
gas production which has no current market
Shipping
Power
outlets, that is, gas which is “stranded” or
Re-gasification
Generation
Transmission
uneconomic to produce. To a large degree, gas
Distribution to End Use
Investor Goals
monetization is being driven by the international
Commercialize natural gas production, by:
•Increasing diversity of midstream options
financial community and by initiatives such as
•Gaining access to downstream participation where supported
Global Gas Flaring Reduction5, especially in
by markets (“power the world with gas”)
•Export
areas where natural gas is associated with crude
oil production.
We estimate that there is
No reproduction, distribution or attribution without permission.
between 1,000 and 1,500 trillion cubic feet (Tcf)
of stranded gas resources worldwide.6 In some case, gas is stranded because of physical distances and
technical complexities associated with transportation. In many instances, however, gas is stranded
because of a lack of sufficient demand in locations where the gas is produced. This condition is prevalent
among developing and emerging market countries that are gas rich. Three main strategies are evident.
•
Build transportation infrastructure density for domestic markets or regional export opportunities
(midstream). This first strategy rests on the abilities of host governments to facilitate investment in
pipeline networks. It means having commercial frameworks in place that not only attract investors
but also protect affected public interests. For regional natural gas trade to occur, contiguous countries
must have commercial frameworks that are similar enough to encourage market participants to
develop cross-border networks, deal with risks, and efficiently allocate gains from trade.
•
Convert gas to power, mainly for domestic use but in some cases for export. The global push to
utilize relatively clean burning natural gas for power generation for both environmental benefits and
power generation diversification has triggered strong convergence between the natural gas and
electric power value chains. Importantly, how commercial frameworks for electric power are
structured can have profound implications for natural gas value chain development.
•
Export gas into the global marketplace through LNG, GTL or other strategies. These strategies often
link natural gas and crude oil for pricing and contractual arrangements.
5
See http://www2.ifc.org/ogmc/global_gas.htm.
Information derived by the University of Houston, Institute for Energy, Law & Enterprise. Various reports and proprietary studies. Contact
[email protected] for details.
6
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
4-6
Economics of the Energy Industries
A set of natural gas system dynamics is
emerging worldwide, leading to specific
considerations for frameworks. Both exploration
and production and power generation (although
Profit driven; ROR decision based on
it is a downstream activity for natural gas
E&P (LNG)
expected prices; monetize stranded reserves
businesses) are competitive activities that
Profit driven; ROR decision based on
Power Gen
respond to vigorous private participation driven
expected prices; fuel competition for gen
by rate of return (ROR) decisions formed on the
Pipelines
Regulated asset optimization; market rates?
Transmission
bases of expectations about price.
For
Regulated asset optimization; proximity to
exploration
and
production
(E&P)
operators
with
LDCs
final customers (gas, power); market rates?
global positions, the desire to monetize stranded
End use based on expected prices; access to
End Users
natural gas resources is quite strong, and
competitive supply
accomplished either via regional pipeline
networks or LNG.
For power generation
No reproduction, distribution or attribution without permission.
developers, fuel competition is a distinct
advantage in project economics. The midstream gas business of pipeline transportation and the
transmission of electric power are dominated by regulation because of technical economies of scale
associated with pipeline systems, as is local distribution of both natural gas and electric power.
Historically, these activities have been undertaken by monopolies, either as private, regulated companies
(the U.S. and Canada, for instance) or as sovereign owned enterprises (most of the world before market
experimentation). Within regulatory regimes, the goal from a business perspective is asset optimization
via capacity utilization. Market-based rates or tariffs can instill flexible pricing in accordance with
supply-demand balances. End users are most interested in, and desirous of, competitive supply and
pricing. The major trend today is therefore to push the benefits of competitive supply through the value
chain to competing customers.
Benefits of Competitive Supply
Worldwide Natural Gas System
Dynamics: Framework Issues
Investment Trends: IEA Outlook,
2001-2030, U.S.$trillions
E&P
$1.73
LNG
$0.25
Power Gen
$4.20
Pipelines
$0.71
Transmission
$1.60
Issues:
•Impact on cash flow funded
E&P with industry consolidation
•Energy financing with fewer
merchant risk managers
•Sovereign debt with fiscal
scrutiny and liberalization
•Development assistance with
budget and performance
scrutiny in donor countries
•Incentives to attract capital
A substantial level of investment is required
worldwide to promote the use of natural gas as a
cleaner burning fossil fuel, and to facilitate the
expansion of competitive markets. The recently
published global investment outlook by the
International Energy Agency (2003) includes
estimates totaling nearly U.S. $13 trillion for
new infrastructure investments across the natural
gas value chain, including electric power.7
A number of issues will impact any investment
outlook for natural gas and the convergence of
$12.78
natural gas with electric power. One is the
reduction in capital spending for E&P as the
Source: IEA Global Investment Outlook, 2003
No reproduction, distribution or attribution without permission.
international oil industry continues to
consolidate, large producing basins mature and
governments constrain sovereign commitments to national oil companies. As more E&P activity is
subjected to global capital markets, investment will closely follow upstream returns. A second, more
recent, phenomenon is the reduction in global capital flows as a result of the collapse of the U.S. energy
merchant businesses, most of whom were financing new pipelines and power generation in many global
locations with specific natural gas monetization strategies. In developed markets like the U.S. and
Canada, the collapse of the energy merchants has also reduced liquidity in the natural gas marketplace
(i.e., reduced the number of market participants), complicating risk management practices. Sovereign
LDCs
WORLD
TOTAL
$4.29
7
International Energy Agency, World Energy Investment Outlook, 2003. The IEA estimate for power generation includes investments using
fuels other than natural gas, but the IEA outlook also emphasizes the extent to which natural gas could be a dominate fuel for electricity.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
4-7
Economics of the Energy Industries
debt for infrastructure investment has been dramatically reduced over the years, a result of market and
fiscal reforms (increasing the need for, and pressure on, private capital flows). Development assistance
for infrastructure investment is also under pressure, as donor countries scrutinize more actively the results
achieved thus far. All of these factors, and others, imply a more complicated picture for countries looking
to provide incentives for private, foreign direct investment in their energy sectors.
The Link between Investment and Commercial Frameworks
Global Perspectives
Natural gas policy across nations is most easily differentiated by how the value chain is organized and
operates with respect to the balance between markets and government, that is, sovereign ownership of or
control over the critical segments of the value chain. A strong pattern of government ownership, control
or, in the least, intervention in natural gas enterprises and markets exists around the world as a result of
several factors:
•
The high degree of interdependency across the value chain segments;
•
The propensity toward integration;
•
The fact that, in most cases, large deposits of natural gas are associated with oil (a strategic
commodity for many producing nations);
•
The energy security aspects of natural gas supply and delivery; and
•
The public interest/public service concepts embedded in pipeline infrastructure for both long distance
transportation and especially local distribution.
In most countries, the natural gas value chain has been developed through integrated, sovereign owned or
heavily controlled enterprises. The rare exceptions are the U.S., Canada and Australia, all of which
allowed natural gas system infrastructure to emerge through the activities of private, investor owned
companies. For the U.S. and Canada, this experience extends roughly 100 years; for Australia, since the
1960s. The U.S. is even more unique in that private ownership of much of the resource base is allowed –
indeed, it is a powerful tradition. Federal and/or state ownership of the natural resource is limited to
certain onshore lands and offshore, and even in these cases development of sovereign owned and
controlled resources has always been through competitive acquisition of leases in organized auctions and
private investment in exploration and production (a tradition also maintained in Canada, which has
limited private ownership of natural gas resources in southern Alberta province while the vast majority of
the resource base, both onshore and offshore, is controlled by the provincial crown governments, and
Australia where states and territories play a comparable role). Of great interest is the transition in many
countries away from sovereign ownership and/or control of integrated natural gas enterprises, as well as
the push for ever more competitive markets in many locations, including Canada and the U.S.
To a large extent, these transitions have been driven by specific needs – for increased efficiency and to
introduce new innovations; to solve fundamental problems in pricing and service; to attract investment
into the natural gas value chain. As with any industry, natural gas market development requires sufficient
supply availability and enough demand to justify the infrastructure systems to connect buyers and sellers.
To attract this investment, governments have experimented with policies designed to stabilize the
investment environment by optimizing participant choice at predictable prices that reflect, or at least
attempt to mimic, actual supply and demand conditions. During the past 15 years or so, the progression
toward competitive markets has meant movement toward market determination of investment, and
operation of assets subject to real time supply-demand interactions. Under these conditions, actionable
information must be timely, accurate and transparent. For such information to be truly actionable, the
decision maker also must have timely access to whatever system capacity the information prompts that
decision maker (supplier, customer or intermediary) to demand. Finally, competitive markets must
comprise systems where this information and capacity cannot be dominated or manipulated by a few
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
4-8
Economics of the Energy Industries
anticompetitive participants. These conditions are difficult to create, implement and maintain, and imply
new and changing roles for market participants and government overseers.
The range of experimental approaches for natural gas and electric power frameworks extends from
privatization to commercialization, in which sovereign interests are not necessarily removed but rather
some form of market incentives are provided to instill improved performance of state-owned enterprises,
and from regulation to full deregulation and removal of government control (a phenomenon that does not
yet exist). In many early experiments, a natural inclination was to assume that the role of government
would be diminished as private participation increased and competitive markets advanced. In contrast,
the role of government often has increased – although this may be a transitional phase as problems and
complexities are addressed (with the U.S. a perfect case in point). At minimum, the role of government is
altered, in complex ways. In most country examples where competitive market experiments have
advanced, governments must accomplish the following.
•
Keep pace with fast moving, complicated market structures and operations.
•
Ensure market transparency, especially the availability of good quality, unbiased data and
information.
•
Mitigate market power through new, information technology-driven processes and business
organizations
•
Resolve disputes and conflicts, or provide requirements for dispute resolution mechanisms.
•
Address public concerns about development of and access to energy resources and infrastructure,
providing rules that protect consumers while at the same time protecting commercial rights of
suppliers and facilitating investment.
The main driver for emerging gas/power frameworks continues to be the desire to substitute for (or
displace) sovereign commitments for energy development. This means a transfer of development risk to
private investors, with associated adequate rewards. A continuing challenge is balancing market
liberalization with investment risk. A looming question around the world is whether, and how, to
specifically price “reliability” which, for natural gas systems that include convergence with electric
power, means deliverability of supplies and adequate pipeline transportation and distribution capacity, as
well as sufficient gas-fired power generation capacity and associated electricity transmission and
distribution networks. Natural gas storage, like electric power reserve margins, provides a reliability
management solution. The bottom line for societies where reliability is highly valued is greater potential
returns to risk-taking investors. Natural gas frameworks continue to be customer driven, and directed by
opportunities for commercial arbitrage in ways that optimize regional trade patterns via comparative
advantages.
From the investor point of view, the fundamental concepts continue to be: that investors differ according
to their own risk profiles; that there is a direct risk-reward relationship; and that the cost of investment
opportunities will vary in accordance with demand for those opportunities (that is, projects with the most
appealing potential returns relative to risk will command premiums from investors).
A number of critical questions are inherent in the evolution of natural gas frameworks. Foremost among
these is whether regulators can also be market facilitators, and whether regulators are best placed to
design markets. In both of these cases, conflicts of interest may reside given that the regulator is also
charged with maintaining market integrity. There seems to be no good answer to the question of how
many regulatory jurisdictions might be required. Most countries continue to maintain regulatory entities
only at the national level (the U.S. and Canada again being notable exceptions), but customer issues, like
politics, are local in nature. If no method of resolving disputes around local systems is provided, energy
sector reform and development can either become gridlocked or disintegrate into local disputes. From
both government and investor points of view, regional harmonization of regulatory practices in locations
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
4-9
Economics of the Energy Industries
where regional trade in natural gas (and electric power) is vigorous, or could be so, offers both good and
bad implications. Investors may prefer opportunities to arbitrage across different regulatory regimes.
Governments and their societies may prefer national as opposed to extra-national preferences, especially
for energy security reasons. In any case, the World Trade Organization and nascent energy services
negotiations are much less likely to be a “harmonizing force” following the disarray of the Cancún
meeting in 2003. Finally, at the regional level, and even across jurisdictions in countries that are
republics or federations, harmonization presents the specific problem of dealing with energy sectors in
different stages of development or market transitions.
Commercial Framework Principles for the Natural Gas Value Chain
The regulatory framework necessary to facilitate
investment in natural gas system infrastructure in
Achieving Competitive Supply
more competitive regimes is a complicated one.
Increasingly, the tendency is to encourage
Pricing Supply
The challenges:
competitive sales of natural gas, treating natural
•Entry of new suppliers
•Managing common pools
gas as a commodity and separating the fuel from
•Developing liquidity to establish
pipeline transportation and, in some cases,
locational basis
COMPETITIVE SALES
•Protecting
market
transparency
distribution systems necessary for delivery to
•Wellhead producers
•Dealing with third party
•Third party wholesalers
customers. These policies, typically referred to
wholesalers that are affiliated
with regulated infrastructure
as “unbundling,” “open access” or “third party
•Access for new supplies
access,” typically require that pipeline operators
•Balancing short term cycles and
provide capacity to any entity wanting to ship
long term capital requirements
for resource development
gas on a system (“shippers”) in fair and unbiased
ways (“nondiscrimination”).
That is, the
No reproduction, distribution or attribution without permission.
pipeline operator cannot refuse service, so long
as capacity is available, or make capacity available on more favorable terms to an entity affiliated with the
pipeline in some way. In many countries, similar approaches have been used for electric power, with
electricity (electrons) as the commodity.
Regulated Infrastructure as the
Conduit for Supply Competition
Pricing Transport, Distribution
RESERVATION (DEMAND)
Fixed cost of investment
•Return on equity
•Taxes
•Long term debt
•A&G, DA, O&M
COMMODITY (USAGE)
Variable cost of operation
•O&M
The Overall Challenge:
Balancing the Market
The challenges:
•Rate-making transitions
•Setting maximum allowable
rates with market transparency
•Pricing new capacity
•Dealing with access for
new capacity
•Determining contestable
transportation markets
•Dealing with market power
•Balancing short term cycles and
long term capital requirements
for delivery
Mean reversion is a reality if marketclearing participants exist
DEMAND
LOW
No reproduction, distribution or attribution without permission.
SUPPLY
Prices
HIGH
No reproduction, distribution or attribution without permission.
The problem of pricing transportation and distribution for pipelines and electric power transmission and
distribution grids remains one of how to allocate the fixed costs of the investment and the variable cost of
use across a market (given daily or seasonal patterns and overall levels of demand). Congestion
management is a specific problem, which can be resolved through pricing. Fundamentally, the
“commodity” market (natural gas or electricity sales, in countries that have liberalized both fuels) tends to
be characterized by price trends that revert to long run means as supply-demand imbalances are resolved.
However, transportation and distribution capacity, especially for electricity, tend to be associated with
“reliability” and thus treated differently, with different pricing schemes to ensure ample reserve margins
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
4 - 10
Economics of the Energy Industries
(such as capacity pricing). This often means a mismatch between dynamic, mean-reverting commodity
markets and the infrastructure networks used to transport and distribute gas and power to final customers.
With respect to demand, energy sectors
characterized by many customers as opposed to
Achieving Competitive Demand
dominant or monopsony buyers reduce the
Pricing Consumption
instances of distortion, but complicate the
The challenges:
•Political will to allow wholesale
Market
process of transfer and reaction to price changes.
Price
price fluctuations to flow to retail
This is especially true if the desire is to increase
users
Margin
competitive access to natural gas and electric
•Price discovery and
transparency
power supply for the smallest customers on local
Retail Cost •Market structure (unbundling)
distribution systems. In general, retail customers
•Market power
•Market oversight
can expect to pay a price that includes the
•Balancing short term cycles
wholesale cost of natural gas or electric power
Wholesale and long term capital
Cost
(including E&P or wellhead cost for gas, cost to
requirements for delivery
generate electricity, and cost to aggregate and
transport to the LDC system including wholesale
No reproduction, distribution or attribution without permission.
marketing and any associated services); a retail
cost (including the LDC system cost); and provide a reasonable profit margin to suppliers. Various
countries have experimented with competitive retail programs for gas and power, with mixed results. In
the U.S., larger commercial and industrial users of natural gas have pursued unbundling options in order
to lower prices and increase services. This shift resulted in the transfer of LDC system costs to smaller
users, mainly core, residential customers. The process has been rational – large users routinely
“subsidize” the more expensive, marginal costs for LDCs of serving smaller customers creating a market
distortion – but it is, nonetheless, an artifact of market transitions that must be dealt with by policy
makers and regulators because of political repercussions. Rarely, in the U.S., do small customers have
competitive choices for their suppliers, a failing of our natural gas regulatory regime.
A final consideration when it comes to natural
gas system frameworks is the transfer of risk.
As noted earlier, when natural gas value chains
are either sovereign owned or controlled, or
regulated private activities, consumers are
shielded from price risk.
With market
liberalization, commodity price risk is created
and must be dealt with. Likewise, capacity price
risk is also created. In both cases, risk flows can
be complex, moving back and forth across the
value chain. The existence of risk accepting
entities is essential in order to balance the
marketplace and attract and sustain investment in
both resource development and infrastructure.
Price Volatility and Risk are the
Trade Offs for Competition
Commodity price risk flows
E&P
Pipelines
LDCs
End Users
Power
Transportation capacity price risk flows
Risk accepting entities
Locational basis incorporates commodity risk and distance from market
(including available capacity for transportation).
No reproduction, distribution or attribution without permission.
In summary, experience around the world to date
points to the continuing challenges of balancing investor and government viewpoints on a number of
fronts. These include investment requirements and returns; transition to commodity markets and
associated risk management requirements; dealing with incumbent interests that face uncertainties of
transition – regardless of whether they are sovereign owned enterprises or private regulated enterprises;
wrestling with geopolitical uncertainties and, for investors operating out of their home countries, political
and country risk. There are also the myriad of difficult and often “deal-breaking” issues such as
environmental protection and mitigation (including rights-of-way), local content requirements or
preferences, social and labor impacts and assurance of local benefits to be derived from energy
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
4 - 11
Economics of the Energy Industries
infrastructure projects. Effective “commercial frameworks” integrate the legal, regulatory, fiscal
components for investment with these “soft” issues in order to increase project success and sustainability.
Indeed, our concept of sustainable development rests on the incorporation of best practices to manage and
mitigate soft issues in order to protect and maximize benefits from the energy investment, especially for
affected local host communities.8
Relevant Case Studies:
Apertura in Venezuela
Bolivia-to-Brazil Pipeline
Brazil Power Market Crisis
Brazil’s Restructuring of the Oil & Gas Industry
Convergence Merger
Gas and Power in Peru
Gas Monetization in Bangladesh
Gas Monetization in Bolivia
Gas Monetization in Nigeria
Natural Gas Marketization in North America
Nigerian National Petroleum Company
Trans-Caspian Gas Pipeline
Trinidad LNG Project
8
With regard to “commercial frameworks” and related concepts, the author refers here to work that has been done and is ongoing by the author
and others at the UH IELE.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
4 - 12
Economics of the Energy Industries
CHAPTER 5 – ELECTRIC POWER VALUE CHAIN OVERVIEW
Introduction
A modern economy is dependent on reliable supply of electricity. There is strong correlation between the
electrification and economic growth. On the other hand, typical electricity systems, consisting of central
generation facilities, long distance transmission lines and distribution networks, are capital intensive. As
a result of the importance of electricity for economic and social development and the scale economies
involved in delivering electricity to consumers, a vertically integrated and monopolistic structure became
the norm around the world from the early days of the industry. In most places, a government-owned
monopoly generated, transmitted and distributed electricity. In the U.S., investor owned utilities
performed these duties as monopolies within franchise territories but under government regulation.
Regulators set the price that these utilities could charge their customers, allowing for cost recovery and a
reasonable rate of return, and determined service quality and customer protection rules. Despite the
difference between the ownership structure in the U.S. and that in the rest of the world, electricity had
been treated as a public service almost everywhere, with the heavy involvement of the state.
Starting in the 1980s, however, the governments around the world started to restructure their electricity
sectors, allowing competition in generation and sometimes in marketing of electric power. In most
countries, restructuring required the separation of state monopolies into generation, transmission and
distribution entities, privatization of all or some of these, and the creation of a regulatory agency to
oversee these newly created marketplace and the players in it. Many of the states or territories in the
U.S., Canada, and Australia, and many countries in Latin America, Europe and Asia have embarked on
sector reform and are currently at various stages. New generation technologies (in particular, combined
cycle gas turbines), inefficiencies in state and regulated utility investment programs, high electricity costs
and lack of government funds to sustain system expansion needed for economic growth are among the
most important reasons for this restructuring trend (see the section on Electricity Restructuring below).
Despite more than 20 years of global experience with restructuring, electricity is not yet seen as a
commodity by most people, including consumers, policymakers and industry professionals. In
restructured markets, electricity prices have become much more volatile, reflecting primarily fluctuations
in demand throughout the day as well as across seasons. In the absence of financial tools and capacity to
manage this price risk, most consumers as well as market players have had difficulty adjusting. In some
cases, their electricity costs increased. Highly publicized market manipulation in California not only
exposed the flaws in California’s market design (and hence underlined the difficulty of designing
competitive electricity markets) but also shook confidence in restructuring. Blackouts and brownouts
experienced in the U.S., New Zealand and Europe raised concerns about adequacy of investment in the
transmission infrastructure in a competitive electricity industry. All of these developments underscored
the fundamental difference between seeing electricity as a public service and treating it as a commodity
with its own market dynamics.
However, the rising gap between the need for capacity expansion to fuel economic growth and the
inability of governments to fund these expansions remains a strong driver in many countries for some
form of restructuring that allows for private investment in the sector. Inefficiency of regulation, with its
long history in the U.S., continue to give momentum to increasing the level of competition not only on the
generation end but also on the retail end by providing customers with choice and responsibility to react to
market prices.
Competitive markets also seem to offer more opportunities for increasing energy efficiency and
conservation, attracting investment into renewable or other alternative technologies, and expanding
options such as distributed generation. To the extent customers are exposed to market price signals (i.e.,
limited or no price regulation in competitive segments of the industry), fluctuating according to the daily
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
5-1
Economics of the Energy Industries
load curve, they have more incentives to modify their consumption patterns in order to minimize their
costs. For example, reduction of peak consumption levels by some customers (due to high peak prices)
will help reduce prices for all and sustain reliability of the grid. In competitive retail markets, electricity
providers compete not only on the basis of price but also via offering a variety of products (e.g., contracts
based on time-of-use pricing) and services (e.g., energy efficiency and conservation assistance). Some of
the most successful retail products are renewable energy contracts; many customers are willing to pay a
premium for electricity generated from renewable sources such as wind. Clearly, as customers’
responsiveness to price increases, not only the existing generation and transmission capacity will remain
sufficient and reliable for longer but also help contain emissions from the least efficient (hence most
polluting) thermal plants.
In most places around the world, though, the immediate challenge remains increased access to electricity.
There are more than one billion people in the world without access to electricity; and many more have
limited or unreliable access. The International Energy Agency (IEA) estimated that more than $4 trillion
for new generation capacity, $1.6 trillion for new transmission lines and several trillion dollars for
distribution networks would be needed globally between 2001 and 2030.9 Although reforms allowed
private investment by merchant companies (independent power producers, or IPPs) to flow into many
countries in the early 1990s, failure to collect payments, inappropriateness of retail tariff levels, lack of
operational and management freedom, and absence of a legal framework defining investors’ rights and
obligations as well as adjudicating tariff adjustments and disputes fairly caused a significant decline in
international investment.10 The challenge is developing transparent and sustainable frameworks through
restructuring that will allow investment across the electric power value chain.
Electricity Industry Restructuring
Since the late 1980s, numerous jurisdictions have attempted significant electricity reform measures. In
those nations where electricity assets have been publicly owned, privatization or corporatization has been
a major element of reform. Many nations have also opened their doors to foreign investment in the
electric power industry for the first time. Restructuring efforts of the 1990s have their roots in
developments in the U.S. The U.S. opened up its electricity market to independent (i.e., non-utility, nonregulated) generators with the passage of the Public Utilities Regulatory Policies Act of 1978 as part of an
overall energy legislation, which also started the deregulation of the natural gas wellhead price controls
(Natural Gas Policy Act). By the mid-1980s, natural gas production increased significantly and gas-fired
generation based on increasingly efficient turbine technologies established natural gas as the fuel of
choice for power generation. It was not long before these merchant generators (independent power
producers, or IPPs) started looking for opportunities around the world.
Countries such as Chile (which started its reform in 1982), New Zealand (1987), Norway (1991), and
Argentina (1992) were early reformers. However, the UK, which embarked on sweeping restructuring
and privatization of its electricity sector beginning in 1989, was probably the inspiration for reforms in
many places that followed the trend. Perhaps, ironically, more than half of the U.S. states continue to
maintain their regulated utilities. This situation is primarily due to federal-state jurisdictional conflicts that
prevented harmonization of market design and regulation characteristics across the nation, and the long
history of regulation that allowed investor owned utilities to hold strong negotiating positions during
market restructuring debates. The California crisis also scared many states either to shelf ongoing
restructuring process or to postpone indefinitely starting the restructuring process.
In countries with federalist forms of government, state or provincial governments have often led the way
in electricity sector reform. In Australia, for instance, reforms in the state of Victoria predated national
9
World Energy Investment Outlook, the International Energy Agency (IEA), 2003.
See the following report by the World Bank for detailed discussion of these and other considerations for investors: What International Investors
Look for When Investing in Developing Countries: Results from a Survey of International Investors in the Power Sector. Energy and Mining
Sector Board Discussion Paper No. 6, May 2003.
10
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
5-2
Economics of the Energy Industries
reforms. Similarly, in Canada, the province of Alberta was the first province to adopt electricity reform
measures in 1996. In the U.S., the State of California had been at the forefront of state-initiated electricity
reforms, passing its restructuring legislation in 1996. California suspended its restructuring process after
the flawed model put in place led to price spikes and shortages, partly caused by market manipulation, in
2000. But, other states including those in the Northeast, many in the Midwest and Texas continue with
mostly successful competitive structures, and the federal regulator (Federal Energy Regulatory
Commission) has been trying to develop a standard market design based on regional transmission
organizations.
Key Drivers
The electricity crisis in California, though the most cited example of electricity market failure, is not the
only case where a variety of problems have been associated with restructuring. Some form of market
manipulation occurred in many markets especially during the transition period (e.g., the UK and Texas in
their early years). Although regulators addressed most of these cases immediately and to the satisfaction
of most market participants if not all, the vulnerability of the open market remains a major issue. The
blackouts of summer 2003 in the U.S. and Europe led to concerns about reliability; many argued that
restructuring was the main cause for these blackouts. Many are concerned that the level of investment in
new generation and, in particular, transmission capacity will not be adequate and timely in competitive
markets, and hence raising concerns about generation adequacy and grid reliability. Despite these
problems and concerns, many regions continue to pursue restructuring of the electricity sector. Because,
the fundamental drivers for change in the 1980s remain equally compelling today:
¾ Investment shortages, particularly in developing countries
¾ High electricity prices
¾ Technological developments, particularly those related to the growing efficiency of natural gas
turbines
Investment Shortages. In the developing world, a Brazil’s Power Market Crisis
lack of access to capital has hindered investment In 2002, hydroelectric capacity accounted for 88% of total power in
The projected demand growth of 3400 MW per year was more
in electricity infrastructure. Governments could Brazil.
than double the rate at which new capacity had been added over the last
not continue to support inefficient state utilities two decades. Such high dependence on hydro resulted in relatively cheap
while budget deficits and debt increased. As a power ($22 per MWh). But, this dependence came at a price. Roughly
every four years, Brazil suffers a drought which can severely deplete the
result, many countries have opened their reservoirs and cause a shortage of power. In 2001, Brazil experienced the
electricity sectors to foreign investment, most drastic shortage ever, forcing the government to ration power in
to prevent extensive blackouts. In the heavily populated and
primarily in generation.
This has been order
industrialized Southeast region, cutbacks in usage from 15 to 25% were
particularly true for countries that suffered most required from the industrial sector at great cost to the economy and the
during the debt crisis of the 1980s, especially in working population. Brazil allowed private investment in thermal capacity
natural gas); but it was difficult to incorporate gas-fired power
Latin America. Moreover, during the 1980s, (mostly
when hydro power became available again at low cost. Many IPPs faced
financial institutions, in particular commercial financing problems when their PPAs were not honored and some pursued
banks, incurred severe losses from loan defaults arbitration. Investors held back in response to this uncertain policy
environment. See our case study for details.
among developing nations, which may have had
a limiting impact on the developing world’s
access to some world capital markets and may have driven developing countries to allow greater direct
investment from abroad.
With more than one billion people without access to electricity and world economies growing fast, the
governments’ need for private investment remains as relevant as it was in the 1980s. The IEA estimated
the need for power sector investment by 2030 at roughly $10 trillion, about 40% of which is expected to
happen in OECD countries replacing old assets. Governments most in need of system expansion
represent the poorest countries and, as such, will have to be more proactive in their policies to secure their
share of the remaining $6 trillion.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
5-3
Economics of the Energy Industries
High Electricity Prices. Electricity prices vary considerably across regions and countries, mostly
depending on the fuel portfolio. For example, many countries in Latin America (Peru, Colombia and
Brazil) and others around the world (Pacific Northwest of the U.S., Norway) rely on relatively cheap
hydropower for almost all of their electricity needs. As a result, electricity prices have been relatively
low as compared to other industrialized countries. But, if not managed well and if more capacity cannot
be added in a timely manner, shortages will occur as they did in Brazil in the early 2000s (see nearby box
on Brazil’s power crisis).
Electricity prices also vary considerably with the ownership structure of the industry and the degree of
regulation. The resulting price differentials can have a significant effect on a region’s degree of
competitiveness. They can also affect real standards of living. Many high-cost electricity regions were
among the earliest reformers. For instance, in 1995 electricity prices in California were 43% higher than
the U.S. average, and industrial electricity prices in Germany were 15% higher than in the Organization
of Economic Cooperation and Development (OECD) as a whole. Not surprisingly, the consumers (in
particular, large industrial and commercial consumers) in these regions were avid proponents of
competition. The cost of electricity continues to be a key cost factor for most industries, perhaps even
more so now than before due to increased computerization of most processes. As such, industries will
continue to push for restructuring that can lower their electricity prices.
Technological Developments. Electricity generation has always been thought to exhibit economies of
scale, which required the construction of larger plants. Developments in natural gas technology, however,
have changed this belief. It is now possible to build smaller units that also increase efficiency. In recent
years, almost half of new generation capacity added around the world has been natural gas-fired.
Gas-fired capacity offers several technological advantages over its alternatives. A state-of-the-art
combined-cycle gas turbine (CCGT) plant is more efficient than coal or nuclear units (roughly 55%
versus 35% on average – 7,000 versus 10,000 heat rate). Advances in turbine technology and plant design
are pushing efficiency rate of 60-65%. Gas-fired plants also have shorter construction times. The time
needed to build a natural-gas-fired generation unit averages 18 to 36 months, compared to three to five
years for coal plants, and five to seven years for nuclear plants. Construction time is only one of the
factors that increase the capital cost of coal and nuclear facilities, which are on average 2-3 times more
costly on a kW basis than a modern CCGT plant (see Chapter 14 for detailed comparisons of costs among
different generation technologies).
Natural gas plants are also more flexible. The maximum efficiency of a gas-fired power plant is achieved
at a much smaller level of capacity than a coal-fired unit. As a result, the size of a new natural gas plant
can be adapted readily to various changes in demand and the plant can be built closer to the load.
Intrinsic cleaner-burning characteristics of natural gas, especially when combined with higher efficiency
of gas-fired plants, have also contributed to increased popularity of natural gas. Environmental
regulations are becoming more stringent not only in developed countries but worldwide. Carbon dioxide
emissions, although not regulated everywhere yet, are increasingly becoming subject to restriction.
Compliance with these regulations increases the cost of coal relative to natural gas, which is able to
defend this advantage even at higher natural gas prices.
All of these advantages make the financing of gas-fired plants easier for smaller, independent players and
hence lower the need for integrated utilities. This is one of the realizations of the industry since PURPA
initiated the establishment of the merchant plant business that has led people to believe that competition
in generation was possible and would lead to lower prices.
Technological developments in other generation technologies from renewable technologies such as wind
and solar to clean coal will continue to provide alternatives to investors. As consumers’ exposure to
market prices expands, their interest in energy efficiency and conservation technologies will also increase.
Storage technologies and small scale distributed generation technologies may also play an important role
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
5-4
Economics of the Energy Industries
in the electricity industry of the future. These and other technologies are at different stages of
development. Their commercialization is stimulated by increased competition and market price signals.
But, at the same time their continuous improvement impels and supports restructuring efforts because
they provide options to market participants and offer increased efficiency in energy production and
consumption.
Source: EIA
Key Characteristics
Generally speaking, electricity restructuring in the world has involved a separation of the industry along
the lines of its different functions (known as unbundling) as well as a rewriting of the rules that allowed
for competition in generation and, in some places, marketing parts of the industry. Outside the U.S., new
regulatory agencies were created to supervise the activities of private players in this new marketplace, to
protect consumers against market manipulation, to develop service quality standards, and to ensure the
successful implementation of the competitive model. There are differences among the approaches used
by different countries, but they all involved most of the following actions:
•
Unbundling of generation, transmission, distribution and marketing functions.
•
Open access to the transmission and distribution grid.
•
Creation of electricity trading arrangements (e.g., pools).
•
Creation of independent system operators (ISOs).
•
Creation of an independent regulatory agency (if one did not already exist).
•
Privatization of electricity assets through sale or public auction, or the corporatization of the
governance of the assets.
•
Deregulation of electricity prices.
•
Retail competition.
Each one of these actions deserves further discussion.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
5-5
Economics of the Energy Industries
Unbundling of generation, transmission, distribution and marketing functions. The traditional vertically
integrated structure is broken up and generation is separated from the wires (transmission and
distribution, or T&D); mainly because potential for competition has been readily visible in generation due
to advances in efficient gas turbine technologies as discussed before. Divestiture of generation assets,
where administered, helps establish healthier competition faster. Separation of local distribution
networks, their privatization and, if desired, retail competition (marketing) in each region may also help
by creating a large number of customers who are looking for the “best deal”; this is especially the case for
largest consumers such as industrial facilities.
Open access to the transmission and distribution grid. The transmission grid remains as a regulated
natural monopoly because transmission expansion remains a capital-intensive activity and system
reliability requires central control of grid operations. Similarly, local distribution networks will remain
regulated. As such, for competition in generation and marketing to yield benefits, companies active in
these sectors need to have fair and non-discriminatory access to the wires. This is especially important if
the separation between generation activities of an ex-utility and its transmission operations is not well
established.
Creation of electricity trading arrangements (e.g., pools). One of the most important design decisions
relates to the wholesale market structure. Initially, a central pool, or exchange, model was popular.
Although there are variations, a typical pool functions as follows: generators submit bids on the amount
of electricity they are willing to provide and the price at which they would be willing to provide this
amount for different time blocks next day (e.g., 24 hourly blocks) to the pool operator. Next day, the pool
operator dispatches bids from the lowest to highest price in real time until demand in any particular time
block is met. The market price for each time block is set as the price of the last dispatched unit. In many
places (most notably, the UK and California) the pool was manipulated. Although they lack the same
level of price transparency as pools, markets that depend mostly on bilateral transactions have been more
stable. The UK replaced its central pool with a bilateral system; California pool is now defunct.
Although bilateral transactions may account for majority of electricity trades, there will always be need
for real-time balancing transactions because of the volatility of electricity load throughout the day as well
as across days and seasons. These “real-time” markets (day-ahead, hour-ahead) are usually run by system
operators (see below) and bid-based pools. For example, in Texas, on average 90% of electricity is
transacted based on bilateral contracts and the rest is traded in a balancing market where various ancillary
services are exchanged.
Creation of independent system operators (ISOs). As the transmission segment of the industry continues
to manifest significant economies of scale, it is kept as a natural monopoly. However, in order to ensure
fair and transparent access to the wires by all generators and consumers, an independent entity is created
to have full authority over the control of the grid. These entities are usually not for profit. In some
regions (such as the PJM market in the U.S.),11 the ISO is responsible both for reliable operations of the
grid and settlement of commercial issues (e.g., running and settling balancing and ancillary services
markets). In others (such as California), ISO and a power exchange tried to coexist but failed. There is
growing trend towards the former structure, at least in the U.S.
Creation of an independent regulatory agency. Since most countries had state monopolies, independent
regulation was not necessary. But restructuring creates new, private entities and rules for a new,
competitive market. A regulator is needed to license new players and new entrants, set and implement
service quality standards, develop and administer customer protection rules, and monitor market behavior
to prevent abuses or manipulation among other tasks. These are all important functions that help
regulator fulfill its most crucial duty, which is to promote healthy development of the competitive
marketplace.
11
The PJM market covers the states of Pennsylvania, New Jersey and Maryland.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
5-6
Economics of the Energy Industries
The independence of the regulator from government as well as stakeholders is desired so that market
participants can have confidence in fairness of the regulator. This requirement is even more critical when
there are remaining state entities in generation or other segments of the industry after restructuring.
However, establishment of these agencies, appointing their boards, staffing them with qualified people
and proving their independence have not been easy. In many countries, they have been treated as just
another government bureaucracy, which resulted in political appointment of the regulators. Finding
qualified board members and staff had been difficult because there was no in-country experience with
private investors or competitive electricity markets. Sometimes, regulators were chosen from the ranks of
known opponents to restructuring. As such, in many places, the independence and competence of the
regulatory agency remain questionable. Under these circumstances, the transition to competition has been
more difficult and confrontational.
Privatization of electricity assets through sale or public auction, or the corporatization of the governance
of the assets. When state monopolies are unbundled, most generation assets are privatized (sometimes
nuclear and hydro facilities are exempted), preferably to as many different players as possible so that
healthy competition can blossom. After all, the purpose of restructuring is not to replace the state
monopoly with private market power. Remaining state assets can be forced to compete with the private
entities; but for them to succeed they need to develop the appropriate corporate structure provided, of
course, that an independent regulator is able to create a level playing field where neither private nor state
entities are favored. Transmission and distribution assets can be privatized but usually remain under state
ownership; either way, the grid shall be run by an independent system operator to provide nondiscriminatory open access. Privatization as part of the restructuring process yielded some of the expected
results in many jurisdictions (see box nearby on the early experiences in Argentina, Chile and Peru).
Deregulation of electricity prices. Competition requires Results of Restructuring
electricity prices to be determined in a market environment Three Latin American countries are among the leaders of
restructuring trend: Chile, Argentina and Peru. To
either through bilateral contracts or spot pools. Prices set the
varying degrees, all three countries benefited from the
below cost or differently for various consumer groups for following improvements early in the restructuring
social policy reasons will deter investment. If governments process: transmission losses declined, service quality
improved, and investment in more efficient generation
offer higher-priced power purchase agreements (PPAs) to increased. See our case studies on these countries for
attract investors but continue to subsidize consumer rates, details on these benefits.
they will not be able to relieve their budgets from the
burden of the electricity sector. In more open and liquid markets, competition will increase volatility of
the electricity price; regulators usually employ price caps to limit the magnitude of price spikes. If set too
low or interfered with often, these price caps will also discourage investment. Given the history of
electricity as a “public service,” deregulation of electricity prices remains one of the most difficult
challenges for governments undertaking sector reform. It is simply too high of a risk for many politicians
to even consider taking; some politicians in developing countries may go as far as offering free electricity
to win elections. Unfortunately, under these circumstances, investment in new generation will not come.
A survey by the World Bank confirms strongly that the ability of retail prices to allow cost recovery is a
key concern for power plant developers.12
Retail competition. Retail competition is needed to incorporate demand side of the market. In most
places, industrial and large commercial users have been able to shop for their electricity suppliers as they
have the incentive in the form of large savings. But, smaller users have not been too interested in
comparison shopping even in Texas where the market has been open for all customers from day one
(January 1, 2002) and both regulators and companies have been actively marketing retail choice. In
Texas and elsewhere where retail competition is available to all customer classes there is an unfortunate
paradox at work. Small customers do not have strong incentives to switch because savings are limited.
Unfortunately, since there are millions of them, their impact on the system is large and can be critical
12
What International Investors Look for When Investing in Developing Countries: Results from a Survey of International Investors in the Power
Sector, Energy and Mining Sector Board Discussion Paper No. 6, May 2003, The World Bank.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
5-7
Economics of the Energy Industries
during peak hours, pushing prices high for everyone and occasionally jeopardizing reliability. As such,
the realization of demand side response by all types of customers is becoming a cornerstone of
restructuring efforts in most advanced markets. Naturally, in regions where electrification of the masses
remains a priority, retail competition will not be an immediate concern.
Electric Power Value Chain Components
Key Segments and Activities
While there are numerous jurisdictions that restructured their electric power sectors, there are many that
maintain the traditional vertically integrated utility structure (investor owned utilities in the U.S. and
Electric Power Value Chain
Physical flow
Financial flow
Integrated
Utilities
System
Operator
Merchant
(IPP)
Transmission
In d us tria l
Local
Distribution
Marketing
Self (mostly
Industrial)
Co m me rc a
i l
Re s i de n ti a l
state-owned monopolies in most other places). The following chart depicts both this utility structure with
its captive customers and the restructured marketplace that allows for competition in generation by
merchant companies as well as self-generators and in marketing. Note that transmission and distribution
segments remain regulated monopolies as discussed before.
Upstream
Generation: Production of electric power using a variety of technologies and fuels. Thermal power is
generated from the burning of fossil fuels (oil, natural gas and coal) in steam or combustion turbines.
Nuclear power is generated from the fission of uranium. Hydro power is generated using motive power
of water in turbines. Windmills convert the motive power of wind into power and solar technologies
convert heat content of solar rays into electricity.
Midstream
Transmission: A system of high voltage (usually greater than 69 kilovolt) lines, substations, and control
systems that allows for transportation of electricity over long distances from generation plants to load
centers. Traditionally, copper is used to manufacture transmission lines; but new materials are researched
to reduce losses during transmission and the need for maintenance. In restructured markets, transmission
operations are managed by a system operator, which is usually independent from other stakeholders and
not for profit.
Storage: Electricity cannot be easily stored. Energy is usually stored in the fuel itself before it is
converted to electricity. Compressed air, pumped hydroelectric, advanced batteries and superconducting
magnetic energy storage are the four main technologies being studied for possible electricity storage. If
economic storage technologies can be deployed, the electricity industry and markets will change
significantly. Price volatility will likely decline, system reliability should be enhanced, and intermittent
technologies such as wind and solar will attract more interest.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
5-8
Economics of the Energy Industries
Downstream
Distribution: Retail sales and final delivery of electric power via low voltage local networks (poles and
wires commonly seen in neighborhoods) operated by local distribution companies or LDCs (regulated
utilities). Substations on the transmission system receive power at higher voltages and lower them to
24,900 volts or less to feed the local networks. At key locations, voltage is again lowered by transformers
to meet customer needs.
End use: Direct use of electric power by residential, commercial and industrial consumers.
Commercial Practices
The following commercial elements serve to bind the operating segments of the electric power
infrastructure system and link suppliers, transporters and distributors with their customers.
Aggregation: Consolidation of small consumers in order to increase the negotiation power in competitive
retail markets.
Marketing: Purchase of electric power from multiple suppliers and resale to wholesale and retail
markets. Retail marketing constitutes sales to final end users (typically residential, commercial,
industrial, and public sector).
Information services: Creation, collection, processing, management and distribution of data related to all
the other industry functions listed here.
Financing: Provision of capital funding for facility construction, market development and operation startup.
Risk management: Balancing of supply, demand and price risks.
Key Policy and Regulatory Considerations
Altogether, the elements described above constitute the electric power value chain. The various segments
are highly interdependent but, in an open, competitive market, they also can be highly competitive. The
policy challenges associated with introducing competition or increased access to electricity are numerous.
The first hurdle is the creation of frameworks for efficient and sustainable investment. New laws, new
regulatory agencies and new regulations are needed. Newly established regulatory agencies have
difficulty finding qualified personnel, developing regulations consistent with the restructuring law,
proving their independence and establishing authority. Even experienced regulators have to learn new
skills and develop new functions, such as market monitoring, to continue to serve consumers while
ensuring the success of the new competitive market design. Market participants need to adjust to new
rules. New entrants without experience in the sector or in competitive energy markets not only have a
tougher time adjusting but also challenge the resources of the regulators. All of this cost significant sums
and create uncertainty, which sometimes delay or increase the cost of investment, resulting in high
electricity prices.
Designing markets for competition is the second hurdle. There have been numerous cases of market
players taking advantage of flaws in market design. Some of these actions can be perfectly legal
according to the rules of the new market. Nevertheless, they raise the price. Even if the price increase is
limited and temporary, it can hurt the market development because of reaction from media, consumers
and policy makers. In particular, there are two related design issues: 1- operation of the physical grid, and
2- structure for electricity trade, i.e., financial transactions.
Many in the industry have been concerned about maintaining grid reliability in a competitive
marketplace. After all, increasing generation capacity cannot be sufficient to increase access to electricity
if transmission grid cannot be maintained and expanded in a timely fashion. Transmission investment
remains regulated and, in general, less attractive for investors than generation. Moreover, the management
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
5-9
Economics of the Energy Industries
structure of the grid offers a variety of challenges to reliability. Significant blackouts experienced around
the world in 2003 seem to have supported these concerns. The blackout in the U.S. northeast on August
14, 2003 was historical in its duration and expanse, costing the economy billions of dollars. One of the
main culprits for this blackout was a utility that failed to maintain its grid and communicate the problems
it started to experience to neighboring control areas (i.e., utilities) early enough to avoid the cascade
effect. For many, these blackouts were a result of restructuring; for others, it only proved that a regional
ISO, instead of individual utilities, would have done a better job managing the grid and avoiding the
problem.
In short, the market design remains the fundamental point of conflict among those involved in market
restructuring. The competitive models across the world share certain common characteristics such as
unbundling of vertical integration and open access to wires, but vary (sometimes significantly) in other
respects such as wholesale market structure and trading rules, capacity payment schemes, and
transmission system management. A poorly designed market will lead to problems, which will shake the
confidence of stakeholders in the market and hence render the transition period longer and more
How to ensure the maintenance,
expansion and reliable operation of
the T&D system?
How to ensure the
expansion of generation
capacity with a “healthy”
reserve margin?
TRANSMISSION
RELIABILITY
GENERATION
ISO geography?
For profit v Regulated?
Access Rules?
Congestion Management?
Resource adequacy?
Capacity payments?
Capacity markets?
Number of competitors? Or,
market share?
WHOLESALE
MARKET DESIGN
Spot market: Pool?
Bilateral contracts?
Combo?
Nodal?
Zonal?
Other?
Price transparency?
Stranded gas?
© 2006 CEE-UT
NATURAL GAS
complicated. In particular, a market design that does not treat reliability as its central concern would seem
to be destined for failure from both economic and political perspectives. The following graph depicts the
central role of reliability in designing competitive electricity markets and a set of related issues. Every
one of these issues can have a negative impact on reliability, and hence shake confidence in the market, if
not structured properly.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
5 - 10
Economics of the Energy Industries
Most of these issues were discussed before in the Electricity Industry Restructuring section. Some are
worth a closer look. Although a small merchant transmission business is emerging (at least in the U.S.),
building new transmission lines and maintaining the existing infrastructure continue to remain the
jurisdiction of regulated utilities or state monopolies in most of the world. Even if merchant business
proves to be viable, siting, licensing and constructing new facilities will continue to be a long and costly
process in most of the developed countries as public’s resistance to major infrastructure investment near
where they live continues to be a growing problem. Under regulation, returns on these investments seem
to be too low to justify dealing with the siting problems or to raise capital. For example, one of the
solutions discussed after the August 14 blackout in the U.S. was to increase allowed rate of return on
transmission investment. Unless mitigated by regulatory and political means, these problems may
jeopardize timely investment in the T&D infrastructure and hence reliability. For most of the world,
however, the primary obstacle still is the capital requirement for these projects.
Investment adequacy remains an issue on the generation side as well. Many countries signed long-term
power purchase agreements (PPAs) to attract independent power providers (IPPs). In most cases, PPAs
turned out to be higher priced than either domestic generation costs, end-user tariffs or both. IPPs required
these higher rates (especially in early years of their operation) to show lenders cash flows sufficient to
recover their investment in otherwise non-competitive regions where there are market risks in the form of
subsidized pricing policies, high rates of system loss due to theft and strong presence of state entities.
But, in many places, electricity generated could not be dispatched because there was public outcry about
higher rates or state could not afford to buy it or generation by state entities were favored or other similar
reasons. As a result, local authorities tried to renegotiate or cancel the PPAs despite arbitration clauses
the contracts had (e.g., in Turkey, India, and Indonesia among others). Naturally, these plants could not
contribute to generation adequacy in these countries.
In more open markets, authorities have employed
capacity requirements (target reserve margins)
administered by system operators and/or regulatory
agencies as well as capacity payments (or markets) to
encourage investment in sufficient generation capacity.
But, evidence on capacity schemes have been mixed so
far; they mostly failed to provide the right price signals
(sometimes due to political interference to design them
for favoring certain types of fuels – see box nearby for a
case on Peru) and the capacity markets have been subject to gaming. Capacity requirements, on the other
hand, are most consistent with the old integrated resource planning approach, but some of the old
problems arise. For example, what is the right capacity margin? The industry used to be comfortable with
around 20% or more in 1990; but it is now satisfied with as low as 12% in some regions. The reserve
margin depends on generation stock, fuel prices, load shapes, demand elasticities of different customer
groups, all of which are difficult to estimate and may change over time. Another issue is the cost of
keeping excess capacity and its allocation among the market participants.
Gas and Power in Peru
Peru restructured its electricity sector in the early 1990s. But,
government’s desire to develop the country’s natural gas
reserves led to capacity payment schemes favorable to promote
gas-fired power at the expense of hydro and other thermal
units. These regulations distorted the market and led to
complaints by market participants. Resulting series of
modifications in regulations and political gaming associated
with the process damaged the attractiveness of the investment
environment. See our case study for details.
These are just some of the most pertinent issues in electricity markets; some are relevant regardless of the
level of openness in the market, others are issues faced by more competitive markets. The complexity of
issues multiplies as markets transition from regulated monopolies to competition. The promise of
competition in electricity depends on successful resolution of the problems to the satisfaction of a great
majority of the stakeholders across the electric power value chain.
Investment in the Electric Power Value Chain
Electricity is the key ingredient for economic growth. But currently, there are more than one billion
people around the world without reliable access, if any, to electricity. Average per capita electricity
consumption in the world is somewhere between 2,500 and 3,000 kWh as compared to 13,000 kWh in the
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
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Economics of the Energy Industries
U.S. and 6,000 to 8,000 kWh in OECD countries. Clearly, OECD countries are pulling the average
higher; most of the world does not consume anywhere near 2,500 kWh per person. For example, in
Bangladesh only 20% of a population of roughly 140 million people has access to electricity with an
average per capita consumption of just over 100 kWh. In Africa (excluding South Africa), the average
consumption for roughly 767 million people is about 300 kWh per person. Even after over a decade of
rapid economic growth, an average Chinese citizen consumes only about 1,000 kWh. An average Indian
consumes only half as much as a Chinese citizen.
Clearly, there is a need for large capital investment to expand the reach of electricity to a greater portion
of the world’s population. In its recent World Energy Investment Outlook, the International Energy
Agency (IEA) estimated that more than $4 trillion for new generation capacity, $1.6 trillion for new
transmission lines and several trillion dollars for distribution networks would be needed globally between
2001 and 2030. This amount is needed to meet expected demand increase of 2.4% per year, faster than
any other final energy source. Although demand growth is strongest in developing countries (4% per
year) and among residential users, this level of investment will not be sufficient to bring electricity to
everyone. Part of the investment is needed to replace aging infrastructure, mostly in OECD countries.
Only about $2 billion will be invested in building new generation in developing world. Almost 66% of
installed capacity in 2030 will have been built after 2000.
Natural gas has been the fuel of choice for power generation around the world. In resource-rich countries,
gas-fired power plants provide an opportunity to monetize stranded gas resources by creating local
demand. In most places, low cost of construction, higher efficiency and lower emissions of gas plants
increase their popularity. The liquefied natural gas (LNG) industry that has been cutting costs now makes
natural gas available to an increasing number of consumers around the world. Accordingly, more than
40% new generation capacity in the world is expected to be gas-fired. Almost half of this increase will
happen in OECD countries; there are significant uncertainties in most other countries regarding the ability
of attracting capital needed for infrastructure investments such as upstream development, pipelines, LNG
terminals and ships, and power facilities. Over the past decade, it has been very difficult for countries to
finance infrastructure projects through sovereign debt or development assistance, especially bilateral aid,
as donor countries examine more meticulously the results achieved in the past. Project financing has been
playing an important role but capital lenders are even more scrupulous than donor countries and past
problems with PPAs and distribution utility privatizations make lenders even more cautious (see the
Project Finance chapter for additional discussion).
The Link between Investment and Commercial Frameworks
Global Perspectives
In most countries, the electric power value chain has been developed through integrated, state owned
enterprises. Even in the U.S., privately owned utilities have been kept vertically integrated and regulated.
Several factors supported this vertically integrated organization:
•
The high degree of interdependency across the value chain segments;
•
The propensity toward integration;
•
The energy security aspects of electricity supply and delivery; and
•
The public interest/public service concepts embedded in infrastructure for both long distance
transmission and especially local distribution.
Since the 1980s, however, numerous jurisdictions have attempted significant electricity reform. In those
nations where electricity assets have been publicly owned, privatization and/or corporatization have been
a major element of reform. Many nations have also opened their doors to foreign investment in the
electric power industry for the first time. As a result, about $200 billion dollars were invested by the
private sector in developing countries, mostly in East Asia and Latin America, between 1990 and 2001.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
5 - 12
Economics of the Energy Industries
In East Asia, almost 70% of roughly $95 billion invested has been in green field projects while in Latin
America, almost 75% of approximately $80 billion has been invested in privatized state assets.
Unfortunately, after 1997, private investment
in developing country power sectors fell
significantly from $45-50 billion in 1997 to
less than $6 billion in 2002. Over the same
period, the number of transactions also
declined from about 125 to about 30. The
financial crises in Asia, Argentina, and
Turkey that led to currency devaluations and
macroeconomic instability rendered these
investments riskier.
Exposure of some
investors to these riskier countries as well as
problems experienced by some companies at
their home markets (e.g., some U.S.
companies suffered significantly following
the California crisis and the collapse of the
energy trading business) restricted the ability
to raise financing in international capital
markets. Moreover, many companies
overpaid based on optimistic estimates of
potential return or changes in markets.
Commercial frameworks for electricity offered by many countries left much to be desired and many
companies had bad experiences in certain markets. According to the World Bank survey13 of international
investors, the ability to collect payments, appropriateness of retail tariff levels, operational and
management freedom, and the presence of a legal framework defining investors’ rights and obligations as
well as adjudicating tariff adjustments and disputes fairly were the most important issues.
Project financing played an important role, but capital lenders are even more thorough than donor
countries when evaluating investment risks; past problems with PPAs and local distribution company
privatizations made lenders very cautious about financing projects not only in the countries where these
problems occurred but also in most other developing countries. Although the level of project financing
remains fairly high, developing countries have not been receiving as much as they did in the mid 1990s;
Europe and North America received significant amounts of capital between 1997 and 2000 while
financing in Asia and Latin America declined. In 2003, project financing in the power sector accounted
for $40 billion with 123 projects (a 66% increase from 2002); but the largest four projects worth roughly
$8 billion were in Italy, United Arab Emirates, Indonesia, and Malaysia.14 Except possibly for Indonesia,
these are not the countries most in need of investment. The Indonesia case involves a restructuring of the
Paiton plant which was originally financed before the 1997 financial crisis but became entangled in
disputes after the crisis.
Overall, capital seems to be available, but there is competition among countries and sectors. Developing
countries will have to address the problems experienced by power sector investors in the 1990s by
creating attractive commercial frameworks to re-channel the flow of international capital into their power
sectors. Companies need to be much more diligent about their market and risk evaluations and realistic
about their expectations. Finally, both governments and companies need a long-term focus.
The World Bank survey provides a fairly comprehensive list of commercial framework issues that need
the attention of governments. The survey was sent to 67 companies. Among the 48 companies that
13
14
Ibid.
Press information for Dealogic Global Project Finance Review 2003, January 14, 2004.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
5 - 13
Economics of the Energy Industries
responded, 83% are from North America and Western Europe. 26 of them invest only in generation
facilities. More than half are subsidiaries of utilities (i.e., merchant arms of the utilities). Most
respondents are relatively small in terms of capitalization. 21 of them seek returns higher than 16% with
another 17 looking for returns in the range of 12-16%. These high return expectations indicate the
perception of high risk in developing countries. Half of the companies are less interested in developing
country power sectors given their bad experiences but the other half remain interested, reflecting not only
differences across countries and commercial frameworks but also differences among company priorities.
The most desired characteristics in a market according to the responding companies were: the existence
of a legal framework defining their rights and obligations as foreign investors; the presence of payment
discipline; and the enforcement and availability of a guarantee from the government or a multilateral
agency. Presumably, guarantees can be lower in a country where rules and regulations are transparent
and consistent and cash flows are adequate and predictable. The adequacy of cash flows requires not only
the ability to collect payments but also the appropriateness of electricity prices for different customer
groups. Most of these companies employ project financing and cannot raise capital unless they can show
lenders the adequacy of their cash flows as well as their ability to manage other risks that may exist in a
given country.
The companies responding also desire a more responsive and administratively efficient government.
Investment timeframes for most companies are governed by tight budgetary deadlines and market
pressures. Processing delays caused by capriciousness or the lack of preparation on the part of the
government agencies increase the cost of doing business for investors. Once the investment is made,
respondents performed the best and were most satisfied with their experience in countries where the
governments did not interfere with operation and management of their assets. In this respect, investors
value highly the independence of regulation from political forces. The following table provides a ranking
of issues considered by the investors when evaluating a developing country. In addition to the four “dealbreaker” priorities discussed above, there is a host of major issues to evaluate before an investment
decision can be made.
Priorities when investing in a developing country
Minor
Legal framework defining the rights and obligations of private investors
Consumer payment discipline and enforcement
Availability of credit enhancement or guarantee from government and/or multilateral
agency
Independence of regulatory institution and processes from arbitrary government
interference
Administrative efficiency – lead time to get necessary approvals and licenses
Judicial independence – degree of perceived independence from government influence
Tenure and stability of elected officials in political process
Regulations that clearly define and allow exit for investors in infrastructure
Investment grade credit rating for long-term foreign exchange debt
Negative perceptions and resistance to private investment amongst members of civil
society (trade unions, press, NGOs)
Sector in transition to a competitive market structure
Country ranking in Transparency International’s Corruption Perception Index
Cost and available tenors to borrow in domestic banking market
Reliance on a competitive bidding process to select project investor/purchaser
Ability to vertically integrate with other segments of the energy chain (upstream
generation or downstream distribution; gas supplies; power exports; etc)
Major
Critical
Deal-Breaker
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Source: Figure 3.1 What International Investors Look for When Investing in Developing Countries: Results from a Survey of International
Investors in the Power Sector. Energy and Mining Sector Board Discussion Paper No. 6, The World Bank Group, May 2003.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
5 - 14
Economics of the Energy Industries
When respondents were satisfied with their investments, they attributed their satisfaction to several
factors which reflect adequate treatment of most of the issues listed above. In the order of importance, the
positive attributes that make an investment successful include the following:
1.
adequacy of retail prices and collection discipline to meet cash flow needs,
2.
ability to exercise effective operational and management control of the project,
3.
government meeting all commitments of state-enterprise performance and exchange conversion,
4.
enforcement of laws and contracts (e.g., disconnections, payment by counter-parties, etc.),
5.
availability of limited recourse financing,
6.
non-arbitrary adjudication of tariff adjustments and dispute resolution,
7.
no oversupply or capacity utilization problems (demand growth as projected),
8.
sustained regulatory commitment through long-term contracts,
9.
responsiveness of government to investor needs and timeframes,
10. existence of a competitive selection process,
11. presence of government guarantee of state-enterprise performance and revenue sufficiency, and
12. public-private partnership.
Note that except possibly for numbers 5 and 7, all of these factors represent elements of the commercial
framework the governments need to create to bring back investors to their countries. Respondents had
their worst project experiences when these elements were not present, ranking the most important
problems as follows:
•
government was unresponsive
•
retail prices were too low
•
collection discipline was absent
•
regulatory commitment could not be sustained
•
adjudication of disputes and tariff adjustments were arbitrary
•
laws and contracts were not enforced consistently
•
and government did not meet its commitments of state-enterprise performance and exchange
conversion.
Venezuela
Argentina
Colombia
India
Pakistan
Philippines
Thailand
China
Indonesia
8
Chile
12
4
Peru
Mexico
Yes
No
Brazil
Is this country still an investment prospect?
5
2
3
1
1
4
9
5
3
12
1
6
9
1
6
2
5
8
5
Source: Figure 2.7 What International Investors Look for When Investing in Developing Countries: Results from a Survey of International
Investors in the Power Sector. Energy and Mining Sector Board Discussion Paper No. 6, The World Bank Group, May 2003.
The survey results indicate that investors have been able to find adequate conditions all around the world
but more consistently in smaller systems such as Bolivia, Costa Rica, the Dominican Republic, El
Salvador, Guatemala, Jamaica, Kenya, Morocco, Nicaragua, Panama and Peru. On the other hand, 9 out
of 10 companies that invested in Argentina were very dissatisfied with their experience. Similarly, five
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
5 - 15
Economics of the Energy Industries
out of six in Colombia, 10 out of 15 in India, 6 out of 12 in Pakistan, and 11 out of 18 in China were very
dissatisfied. Accordingly, India, Pakistan, Argentina and Colombia did not fair well among investors as
future investment prospects.
Another World Bank study15 provides more or less the same conclusions, focusing on 10 East European
and Former Soviet Union countries – a group not covered in the World Bank survey summarized above.
According to this study’s results, the timing of restructuring or privatization efforts is crucial. It is usually
counterproductive and damaging in the long-run if structural changes are attempted during times of
economic, financial or political crisis or instability (however mild it may be perceived from outside).
Assuming that the country is generally stable, governments need to lay the foundation for private
investment to be able to sustain restructuring and competition. In particular, governments need to put in
place laws and regulations that enable companies to deny service to those who do not pay, to recover
unpaid bills quickly, and that define electricity theft as a criminal offence punishable by fines and jail
terms. In addition, governments should set retail prices to allow cost recovery and should reduce
(eliminate, if possible) internal cross subsidies. The correction of price distortions and future setting of
cost-reflective prices can probably be best achieved by independent regulatory bodies but they must have
adequate financial and personnel resources. A professional regulator will most likely divide the price into
its cost components of generation, transmission, distribution, and marketing and hence make the process
easier to monitor and more transparent.
Similar to the survey results, appropriateness of electricity prices and collection discipline are crucial
ingredients of the commercial frameworks that need to be created. One of the challenges, though, is the
inexperience of regulatory agencies that makes political pressure more difficult to handle. It may be
difficult for regulators to provide the right pricing and collection discipline in early years especially if
governments fail to resist the temptation to interfere with the regulator and set tariffs based on political
criteria.. One option currently explored by investors is the inclusion of price calculation formulas built
into privatization contracts, especially those for local distribution companies.16 PPAs usually include
international arbitration clauses that provide protection against future disputes. In Latin America, India,
and the U.S., Appellate Tribunals also provided adequate dispute resolution.
A recent World Bank study17 focuses on the importance of regulation: “regulation that provides a credible
commitment to safeguarding the interests of both investors and customers is crucial to attracting the longterm private capital needed to secure an adequate, reliable supply of infrastructure services.” As in other
studies, this study notes that regulatory agencies must be free of political influence and their processes
must encourage competition, be open and transparent. Perhaps most importantly, the regulatory agency
and its roles and responsibilities should be designed and put in place before restructuring is undertaken.
This study too acknowledges the absolute necessity of cost-reflective prices as an incentive to investors,
but also points out the importance of maintaining a balance between the need for investment in new
capacity and the socially desirable policies that provide safety nets and increased access to electricity.
The graphic below is the summary of a Deloitte Emerging Markets Group study.18 According to the
study, key success factors are:
•
Political leadership to drive through sector reforms and project agreements;
•
Good and tested project design balancing the risks and returns to the government and private
sponsor/lender;
15
Private Sector Participation in the Power Sector in Europe and Central Asia: Lessons from the Last Decade, Venkataraman Krishnaswamy
and Gary Struggins, World Bank Working Paper No. 8, 2003.
16
Regulation by Contract: A New Way to Privatize Electricity Distribution? by Tonci Bakovic, Bernard Tenenbaum and Fiona Woolf, Energy
and Mining Sector Board Discussion Paper, The World Bank Group, October 2003.
17
Reforming Infrastructure - Privatization, Regulation and Competition, by Ioannis N. Kessides, a World Bank Policy Research Report, 2004.
18
Sustainable Power Sector Reform in Emerging Markets – Financial Issues and Options by Deloitte Emerging Markets Group, Joint World
Bank/USAID Policy Paper, June 18, 2004.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
5 - 16
Economics of the Energy Industries
•
Good and tested market design, most success cases in vertically integrated and single buyer
markets;
•
Domestic capital role substantial from strategic and banking sector sources and potential to
generate self- financing;
•
Greenfield generation: (a) multilateral development bank support, (b) constrained power
expansion;
Sensible and Sustained Policies
•
tariff
Implement
Restructuring
Establish
Regulator
Corporatize
Power Entities
Prepare for
Privatization
Implement
Privatization
Assist postprivatization
?
?
Determine
Subsidies
covery
Cost re
Define Tariff
Rebalancing
Define Subsidy
Phase-out Plan
Finance Subsidy
B
w
elo
s
co
tariff
t
ry
ve
co
e
tr
target
iff
ar
Transition period
Cut utility from routine government budget support; Establish clear
accounting; Tariff rationalization; Separate business units by
function; Establish transparent transfer pricing; Institute clear audit
procedures; Compile clear inventory of assets and debts;
Professionalize billing, metering, and collections.
Existing distribution: (a) prior improved
collections & tariff levels, (b) public
participation.
Overall, this study confirms most of the findings
from the World Bank studies discussed earlier;
but it also clarifies the importance of political
leadership and support for successful reforms. In
addition, however, it brings to attention the
substantial role domestic private capital can play
in
financing
electricity
infrastructure
investments, provided that domestic financial
infrastructure is sufficiently sophisticated.
Commercial Framework Principles for the Electric Power Value Chain
Like with the natural gas industry, unbundling of the vertically integrated structure has been one of
central principles of electricity industry restructuring. Once unbundled, generation segment proved itself
to be fairly competitive as suspected. Merchant companies, growing in numbers and experience since the
early 1980s, were mostly up to the task of building generation facilities around the globe. For these
generators to compete, they needed to have fair and non-discriminatory access to the wires (i.e.,
transmission and distribution systems), which are kept as natural monopolies. This right to access is
known as open, or third party, access – another central principle of restructuring. As already discussed,
though, expansion of these systems remains a problem under regulated prices. For example, many
utilities in the U.S. have expressed a desire to see higher allowed rate of returns before they could justify
the risks involved with T&D investments.
Another issue concerns the allocation of fixed costs
associated with the T&D infrastructure. In many
regions, system maintenance and upgrade costs as well
Pricing Supply
The challenges:
as congestion management costs are distributed across
•Entry of new suppliers
•Managing common pools
all consumers, known as “socialization.”
Since
•Developing liquidity to establish
reliability
is
valued
by
almost
everyone,
this
practice
locational
basis
COMPETITIVE SALES
•Protecting market transparency
•Power generators
may sound reasonable. But there are instances where
•Dealing with third party
•Third party wholesalers
many criticized the “socialization” of these costs. For
wholesalers that are affiliated
for power
with regulated infrastructure
example, in Texas wind farms were built far away from
•Access for new supplies
the load centers although they knew that the
•Balancing short term cycles and
long term capital requirements
transmission capacity between their location and load
for resource development
centers was insufficient. A new transmission line is
being built primarily to make that wind capacity available but the cost of the line will be paid by all
consumers. Many find this unfair. Similarly, congestion costs can be included in T&D costs and paid by
all consumers. In nodal markets, however, it is possible to identify and bill those who cause the
congestion, which sounds fairer. These are just some of the issues associated with managing electricity
grids in a competitive environment.
Achieving Competitive Supply
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
5 - 17
Economics of the Energy Industries
On the retail side, large customers (industrial and
Regulated Infrastructure as the
commercial) seem to have benefited from having the
choice of electricity suppliers, including the option of
Conduit for Supply Competition
Pricing Transportation,
self-generation. In most regions, large users have been
The challenges:
Distribution
major proponents of competitive generation and have had
•Rate-making transitions
•Setting maximum allowable
choice from the beginning. On the other hand, smaller
rates with market transparency
•Pricing new capacity
customers (residential and small businesses) have been
RESERVATION (DEMAND)
•Dealing with access for
Fixed cost of investment
more reluctant to embrace retail choice where available.
new capacity
•Return on equity
•Determining contestable
•Taxes
Most successful examples include Texas and the UK
transportation markets
•Long term debt
•Dealing with market power
markets where residential switching rates are about 20%
•A&G, DA, O&M
•Balancing short term cycles and
COMMODITY (USAGE)
and 40%, respectively. Some of these switchers are back
long term capital requirements
Variable cost of operation
for delivery
•O&M
to incumbents. There are several problems with
marketing to small customers. It costs more to market to
small users on a per kWh basis. It is difficult to differentiate from other providers; except for some
“green” electricity products, customers do not seem to care what “color” their electrons are. As long as
the price is the dominant marketing feature, it is
Achieving Competitive Demand
difficult to show large enough savings to overcome the
Pricing Consumption
inertia of most users.
The challenges:
•Political will to allow wholesale
price fluctuations to flow to retail
users
Margin
•Price discovery and
transparency
Retail Cost •Market structure (unbundling)
•Market power
•Market oversight
•Balancing short term cycles
Wholesale and long term capital
Cost
requirements for delivery
Market
Price
Not to scale
However, if all consumers are subjected to real time
prices that are more reflective of cost fluctuations
throughout the day as well as across seasons, it may be
possible to see a larger demand side response even
from smaller users. This could not only provide
marketers to develop new services and products but
also help maintain system reliability during peak
hours. Yet, subjecting residential consumers to price
volatility is a politically difficult proposition.
In most of the world, though, the immediate challenge remains the development of generation capacity
and T&D infrastructure in order to increase the number of people with access to electricity. This
challenge requires the creation of the right commercial framework by governments to attract and keep
investors, and encourage competition and consumer choice. Gradual removal of subsidies, reduction of
system losses (technical and theft-related), and respect for contracts are among the improvements that are
needed as part of the commercial framework conducive to investors.
Relevant Case Studies:
Brazil Power Market Crisis
Electricity Restructuring in California
Gas and Power in Peru
Power Marketization in Turkey
Results of Electricity Restructuring in Argentina
Results of Electricity Restructuring in Chile
Results of Electricity Restructuring in Peru
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
5 - 18
Economics of the Energy Industries
CHAPTER 6 –ROLE OF GOVERNMENT
Governments, Economic Organization and Energy
Energy is essential for economic development. As a consequence, nation states and their societies have
often taken a direct hand in the development of and access to energy products and services. At this time
in human history, however, there is considerable debate about the proper role for governments in their
energy sectors, just as there is debate about government intervention in national economies overall. A
wide array of models for energy sector organization currently is in existence around the world, but there is
also a marked trend toward reducing government intervention and increasing “market-based solutions”
for energy development, transportation and distribution. By market-based solutions we mean the reliance
on the objective interactions between buyers and sellers, with price discovery and transparency and
minimal interference, to exchange energy goods and services.
The extent to which energy is perceived to be a strategic material as opposed to a commodity is often the
major factor dictating the extent of government involvement in a nation’s energy sector. The idea that
energy fuels are commodities like any other (non-fuel metals or agricultural products, for example) is
relatively new and emerged out of the disruptions in world energy markets during the 1970s and 1980s.
Extreme fluctuations in the prices of energy fuels and changing world market conditions for energy, with
growing fuel competition as well as the shift toward market-based economic reforms overall, led to the
increased perception that energy fuels could be
managed like commodities. The emergence of
Drivers for Government Policy
spot and futures markets for energy fuels, as
described in Chapter 1, provided both energy
Tendency Toward Energy
customers and suppliers with instruments for the
Sector Reform
HIGH
LOW
management of both price and supply risk. As
Energy products are
Energy products are
suppliers and customers become more comfortable
commodities
strategic materials
with the notion of energy fuels as commodities,
Small resource base
Large resource base
there is less of a need for government intervention
Strong imperatives
Weak imperatives
as method of managing these risks. This level of
Strong institutional
Weak institutional
comfort and the linkage to government policy is
setting
setting
often related to other factors, as shown in the chart
at left. Size of resource base, the financial balance
sheet of the country, level of institutional development are some of the prominent factors that can drive
government policy toward or away from energy sector restructure. Finally, the extent of government
involvement tends to be directly linked to how national economies are organized. These simple
relationships can be generalized as shown in the table that follows.
Economic and Government Organization of Energy Sectors: Possible Solutions
Tendency toward
centrally-planned
economies.
Tendency toward
market-based economies.
Energy is a strategic
material.
Energy is a
commodity.
A
B
High
Moderate to Low
C
D
Moderate to Low
High
Government-based
solutions for energy.
Market-based
solutions for energy.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
6-1
Economics of the Energy Industries
The table above suggests that in countries that tend toward centrally-planned economies and where
energy is considered to be a strategic material, government-based solutions for energy are more
frequently observed (solution A). Good examples are Mexico and the People’s Republic of China. In
countries that tend toward market-based economies and where energy is generally regarded to be a
commodity like any other, market-based solutions are more frequently observed (solution D). Examples
of this situation at this time are the U.S. (strong) and Canada (less strong), which have been moving in
this direction for some time.
The interesting exceptions are solutions B and C. No good examples of solution B exist for a nation as a
whole, because the perception of energy fuels as commodities are most compatible with existence of
market-based economies. However, the hypothetical solution B does provide an interesting explanation
for some aspects of energy sector management in countries like the U.S. and Canada. Both retain strong
government intervention when it comes to energy fuels for military defense purposes in spite of the
treatment of energy fuels as commodities and the shift toward market-based solutions for energy when it
comes to private transactions. Solution C is the most dynamic situation and is in evidence in many parts
of the world. The U.S. and, to some extent, Canada displayed many characteristics that might be
associated with solution C during the latter half of this century. In countries that are moving toward
market-based economies, market-based solutions for energy are more prevalent. These countries are
moving toward solution C from solution A. Parts of Western Europe and India are good illustrations of
this trend. As the idea grows that energy fuels are commodities for which security and price risk can be
managed, these countries will be able to move more strongly toward market-based solutions for energy
(toward solution D from solution C).
¾ Countries are making positive shifts away from the institutional arrangement of state-owned or
regulated monopoly toward competition to take advantage of a mature infrastructure.
¾ The fundamental philosophical question is how to provide for infrastructure development while also
facilitating competition.
Marketization can achieve a great deal. Although not energy industry specific, the following chart19 is
informative of the negative correlation that exists between regulation and economic growth. In particular,
the growth in Ireland and Britain was twice as
high as the growth in Greece. The authors
compared the 11 EU economies in terms of
market regulation and output growth and
ranked them. Under market regulation, they
considered both product and labor markets.
For the labor market, they included
information on the regulation of normal work
time, flexibility of irregular work time,
temporary employment, dismissal protection
and minimum wages. For product markets,
they constructed an indicator incorporating
information
on
business
regulation,
competition policy, public ownership, sectoral
and firm specific support to manufacturing
companies, regulation of shop opening hours,
and the implementation at the national level of
the European Single Market program. This simple correlation ignores other variables such as initial
human capital, initial real per capita GDP, share of government consumption in GDP, and measures of
19
Koedijk and Kremers, 1996, “Market Opening, Regulation and Growth in Europe,” Economic Policy (October); The Economist, October
12th, 1996
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
6-2
Economics of the Energy Industries
political stability, which could also impact growth. As the authors claim, however, these are not likely to
be significant given the common past of the EU members.
The Koedijk and Kremers study is one of the many economic studies on the relationship between
economic performance and the level of government involvement either through direct ownership or
regulation of key industries. Perhaps not surprisingly, the results are similar. The reform efforts around
the world in almost all sectors of the economy from agriculture to telecommunications to railroads and to
energy are based on the premise of breaking out of this negative correlation and spur development by
increased private investment.
But, regulation has its appeal, especially in network industries such as energy industry. The U.S.
accomplished a great deal with regulated private franchise monopoly for both natural gas and electric
power industries. The following chart shows the growth in the U.S. natural gas market. While
competitive producers have been able to increase production, albeit under price controls after 1954,
regulated utilities expanded the transmission and distribution grids to connect those supplies to
consumers. But inconsistencies among wellhead price controls, transmission tariffs and regional markets
eventually constrained production. In reaction, the industry was deregulated starting in 1978.
5.0
Gas Production
4.5
Transm ission
4.0
Distribution
3.5
3.0
2.5
2.0
1.5
95
93
91
89
87
85
83
81
79
77
75
73
71
69
67
65
63
61
59
57
55
53
51
49
47
1.0
The Goals of Governments
Clearly, governments may have many different goals when it comes to energy depending upon the mix of
macroeconomic organization, perceptions about energy fuels and the resulting approaches. Where
government-based solutions for energy are in evidence, countries may exhibit such goals as securing
energy supplies for their citizenry (if they are large net consumers) or increasing revenues from energy
exports (if they are net producers). Many governments also have goals to improve the efficiency of their
policies or to introduce some aspects of market-based solutions. State-owned enterprises (SOEs), which
produce and provide energy products and services in many countries are often considered to be inefficient
and a political medium for lowering unemployment. As a result, many governments have sought
solutions to improve the performance of their SOEs or, in several instances, have chosen to privatize their
SOEs in order to instill the performance incentives associated with competition. For countries where
market-based solutions are prevalent, many governments may have goals to “protect” the market from
anticompetitive practices, to improve transparency, or to minimize the impact of government policies like
taxation.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
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Economics of the Energy Industries
When it comes to introducing or expanding market-based solutions, governments have many options.
Since the late 1970s, competitive advantage and corporate viability have become more critical than ever
before for most countries. To cope with these new realities, the U.S., Canada and Western Europe have
significantly relaxed government control of several industries including many sectors of the energy
industry. A similar, albeit relatively partial movement towards freer and more open markets is under way
in Latin America and Central and Eastern Europe (CEE) as well as the Asia/Pacific region.
Governments have opted to restructure their national energy sectors in order to create more competitive
markets, especially in industries, like energy utilities, that traditionally have been treated as natural
monopolies. However, restructuring can take many forms. Where state ownership has been prevalent,
privatization and commercialization are the common approaches. Where private ownership has been
prevalent but with government control, deregulation, "re-regulation" or liberalization are typical
strategies. All of these concepts involve price, entry, exit and vertical or horizontal business integration.
In more mature industries and where the pace of technological change is rapid, "contestability" or
potential competition may yield benefits similar to what could be achieved with full competition, further
reducing the role of government or need for regulation.
Since the late 1980s, privatization and commercialization have become the twin pillars of economic
engagement in the emerging market economies (EMEs). In terms of international practices, privatization
refers to a reduction in state ownership. As a result, the state-owned enterprises (SOEs) in a majority of
developing countries have become private enterprises, the equity of which is at least partially owned by
the public. This is also known as "denationalization." The rationale for privatization is that firms and
assets owned and operated by the private sector will generally be more efficient and more responsive to
the needs of the public than those owned and operated by the state. Many countries have already reaped
the benefits of privatization. In the longer run, commercialization proves to be a bridge between
privatization and liberalization or deregulation. This connection, however, requires effective regulatory
reform in the majority of EMEs. In most cases, this reform entails creation of relatively independent
regulatory commissions and regulatory rules in order to prevent monopoly activity by private owners and
operators. The following graph reflects the relationships among these programs.
Hypothetical Marketization Pathway
Increasing Private Control
Decreasing Government Role
Commercialization:
•Delegate management
•Face competition
PH
ES
AS
OF
Liberalization:
•Relaxation of newly privatized or strong
state controlled sectors
•Decontrol of pricing/planning
E
PM
LO
VE
DE
Regulation:
•Establish legislation
•Identify regulatory function
•Establish regulatory rules
Full Deregulation:
•Complete removal of government control
Privatization:
•Increasing private ownership
NT
Deregulation/Re-regulation:
•Reduce or alter regulatory role
•Change regulatory rules to increase
competition
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
6-4
Economics of the Energy Industries
The entire process, from privatization of state owned assets to deregulation of privately operated assets
can be termed "marketization." Increasing reliance on private market transactions requires not only
reducing the role of the state, but also establishment of institutions, rules and norms to facilitate private
transactions. These include sound legal systems and adherence of the rule of law, sanctity of contracts
and property rights, creation or strengthening of financial institutions and exchanges, and so on.
Importantly, how the building blocks in the marketization process are arranged can vary widely across
countries. In some countries, national energy companies are forced to commercialize in advance of, or in
lieu of, full privatization while other countries may choose a "cold shower" strategy of full privatization.
Where countries have multiple SOEs engaged in energy production and delivery, energy sector reform
may be more similar to deregulation in industrialized countries like Canada or the U.S., with an easing of
government rules regarding investment, trade, the proportion of net revenue SOEs may reinvest in their
operations, and perhaps private participation in the nation's energy sector.
A Case Study of Upstream
When a sample of countries is compared using the relationship between their resource endowments and
institutional frameworks they provide, a definitive pattern emerges, as shown in the chart below.20 This
pattern suggests that a fundamental change must occur in the motivation of governments to achieve
policies toward private (and direct foreign) participation in oil and gas exploration and production given a
country’s or region’s position with respect to reserves and, consequently, operational risk (geological,
geophysical and engineering).
Upstream Country Frameworks and
Risk/Reserve Position
(An Inverse Relationship for Private
Investment)
Favorable
Non-attainment area of
high risk/reserve
position and
favorable policies.
U.S. GOM Deep
Government
Policies
(Commercial
Frameworks)
E. Canada
Norway
Angola
Colombia
Brazil
China
Venezuela
India
Worldwide
risk capital
“equilibrium”:
Capital will flow
to high
risk/policy
constrained
locations but
only with
substantial risk
premiums
FSU
Mexico
Saudi Arabia
Favorable
Risk/Reserve Position
Source: Michot Foss, et. al., 1999. Approximation, only.
At the time of writing we have several anecdotal “tests” of this hypothesis. In the case of Saudi Arabia,
the desire to maintain market share and assert domination on the world oil market scene, as well as to
realize the value of natural gas resources, may provide sufficient motivation for a return to more open
policies with regard to foreign participation. If this is true, the Saudis could move into the non-attainment
area where currently no country is represented: the temptation for such a major reserve holder to control
its petroleum and gas wealth, and the importance of controlling their oil export revenues for political
objectives, otherwise is simply too powerful. On the other hand, Angola, for example, appears to be
20
From UH IELE, Best Practices in Energy Sector Reform, 1999.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
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Economics of the Energy Industries
moving the other way. Prolific offshore discoveries appear to be triggering a reconsideration of the
favorable fiscal terms Angola had been offering. If so, Angola will decline in attractiveness for private,
foreign direct investment upstream. China and Brazil are transitioning toward market-based policies for
energy. Both are faced with growing demand, inadequate domestic resources, and environmental
imperatives. Russia and other new independent republics, especially the resource-rich countries of the
Caspian region, are attractive to international energy companies, at least based on resource potential; but,
investment conditions are poor with inadequate frameworks for private capital inflows and risk
management. Importantly, political risk and uncertainty can impinge on any country’s relative position
and comparative advantage.
The approximate relationship of risk/reserve positions and government policies bears striking
resemblance to the distribution of producing countries when reserves are correlated with production (see
chart below). The prevailing conclusion is that for countries less well endowed to attract global capital
flows for upstream development, government policies (commercial frameworks for upstream, primarily
fiscal terms for access to prospective areas for exploration and production) must be that much more
attractive. These relationships are not static, and experience and learning heavily impacts both investor
and host government positions.
OPEC, Non-OPEC Risk/Reserve Positions
Combining Upstream, Midstream and Downstream – the Natural Gas and Power Case
A similar approach can be used to approximate the relative relationships and distribution of best practices
for the combined natural gas and electric power value chains. One such example is shown below. Here,
the illustration links private investment access across the value chains for upstream natural gas,
midstream pipelines, downstream power generation, wholesale natural gas and electric power, and retail
natural gas and electric power. The objective is to assess, in a very broad way, “quality” of commercial
frameworks to facilitate gas/power marketization in countries and regions where host governments have
indicated some interest in fostering more open, liberalized treatment of these industries. Many exceptions
exist to the very general relationships expressed in this chart. For example, and notably, while much of
the Middle Eastern countries within the “Petroleum Heartland” are not easily accessible, some countries
have moved to provide at least elementary platforms for external investment flows (Qatar being such a
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
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Economics of the Energy Industries
case in point). Within West Africa, considerable progress has been made in countries like Côte d’Ivoire
and Ghana. Political risk throughout the Petroleum Heartland (West Africa into the Commonwealth of
Independent States or CIS, the former Soviet Union republics) complicates the best intentions within
governments. Even within established markets like the highly integrated Canada/U.S. system issues in
both the quality of commercial frameworks as well as consistent applications of best practices across
multiple jurisdictions and levels of jurisdictions can impede energy value chain development. Across all
countries examined, a key issue is price transparency and political support for efforts by regulators and
other market facilitators to establish market based approaches to end user pricing.
World Trends:
Gas/Power
“Marketization”
In general, where options for private
investment upstream are limited,
midstream/downstream marketization is
also limited
England
Rest of Russia and Other CIS
W. Europe
9 9 9 99
Canada/U.S.
Uncertain
regulatory
response on
price reporting
is inhibiting
investment
99
China
C/E Europe
Petroleum Heartland
999
Mexico
9
99
9
Colombia
Venezuela
Brazil
Peru
Argentina
W. Africa
9
99
Southeast
Asia
Northeast
Asia
99
99
S. Africa
99
99
Chile
999
India
99
9 No real progress toward marketization
99 Progress made, but weak institutions
Australia
999
999
New Zealand
and/or tendency to backtrack; political risk
9 9 9 Strongest progress toward markets
Relevant Case Studies:
Almost all New Era cases contain perspectives on the role of government; but the following are most
direct representations of government involvement.
Apertura in Venezuela
Brazil’s Restructuring of the Oil & Gas Industry
Electricity Restructuring in California
Gas and Power in Peru
Natural Gas Marketization in North America
Nigerian National Petroleum Company
Power Marketization in Turkey
Small Refiner Bias
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
6-7
Economics of the Energy Industries
APPENDIX 1
Commercial Frameworks for National Oil Companies1
Working Paper
OVERVIEW OF CEE RESEARCH EFFORT
This working paper represents the first publication from a long term research effort at CEE to understand
sovereign or national oil companies (NOCs), their imperatives, constraints and strategies into the future.
Our research effort is linked to CEE’s elite annual international energy sector capacity building and
research program, New Era in Oil, Gas & Power Value Creation, and our energy sector development
assistance initiatives.2 As part of these and through other sponsored research grants and contracts and our
custom training programs, CEE has been privileged to observe how NOCs have evolved and continue to
re-shape themselves to meet energy development challenges in their home countries as well as to respond
to drivers emanating from the global energy markets and energy value chain operations.
During the early 1990s, and as part of a widespread push for freer markets and energy sector reforms
across broad swaths of the globe, a number of full and partial privatizations of NOCs took place. This
activity was triggered by a number of factors:
• Lower prices for oil and gas commodities;
• Revenue needs among the governments engaging in restructuring programs;
• Pressure from international capital markets; and, in some cases,
• Internal shifts in public preferences with regard to market organization and the roles of government
and government owned or controlled enterprises in core activities such as oil and gas exploration and
commercialization.
Today, the tables have largely turned. Higher commodity prices, flush treasuries, availability of
technologies from oil and gas service providers, friendlier international capital markets and other factors,
not excluding political drivers, have essentially reversed the situation. Consequently, it is important to
understand modern NOC organizations; their roles and emerging commercial strategies; and the various
internal and external pressures (economic development, local content, community benefits) directed
toward NOCs and their operations.
Several viewpoints must be considered.
• In contrast to many opinions and expectations, NOCs are likely to remain a strong energy sector
feature for countries that remain net exporters of hydrocarbons, at least for the foreseeable future. Of
interest are those countries that face diminishing futures as net exporters and that may, as a result,
restructure their NOCs to meet other goals and objectives than those with which the NOC may have
been historically charged. However, even governments of net consuming countries may retain the
NOC model for various reasons. For instance, the NOC model may be retained in net
1
This paper was prepared by Ms. Miranda Ferrell Wainberg, Senior Researcher, and Dr. Michelle Michot Foss,
Chief Energy Economist and CEE Head, with assistance from Mr. Dmitry, Energy Analyst; Dr. Mariano Gurfinkel,
Project Manager and CEE Assistant Head; Dr. Gürcan Gülen, Senior Energy Economist. Considerable review and
input was provided by CEE international advisors and donors. The “commercial framework” concept was
developed by Dr. Michot Foss and her research team in 1998.
2
For information on CEE’s New Era program, go to: http://www.beg.utexas.edu/energyecon/new-era/. For
information on CEE’s international energy partnerships and development assistance projects, including CEE’s Smart
Development Initiative supported by the U.S. Agency for International Development (USAID) go to:
http://www.beg.utexas.edu/energyecon/about.php and http://www.beg.utexas.edu/energyecon/IDA/.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
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Economics of the Energy Industries
•
•
•
•
•
importing/consuming countries where government organization remains strongly centered around
sovereign interests (more on this point later).
Distinct differences exist among NOCs and their performance in achieving both commercial and noncommercial objectives. NOC performance has significant implications for world energy supplies
given International Energy Agency projections that upwards of 90 percent of new primary energy
production through 2030 will come from developing countries, many of whose energy sectors are
NOC controlled. The IEA’s projection represents a sharp jump from 60 percent in the previous three
decades.3 Thus, it is crucial to understand the factors that drive differential NOC performance.
Yet, how should NOC performance be measured? What are the right metrics for these types of
organizations? Comparisons between NOCs and IOCs (international, generally publicly traded, oil
companies) are not useful given the current deviations in goals and objectives. NOC/IOC goals and
objectives may converge over time as NOCs become increasingly commercial and IOCs are
increasingly pressured to broaden their social and economic participation in developing countries.
Moreover, NOCs are interested in being benchmarked against other, similarly situated NOCs, a
reflection of how managers in these organizations view themselves and their competitive landscape,
and as a more joint ventures are formed among NOCs.
NOC-IOC relationships are changing. NOCs clearly are trying to position as preferred partners
and/or operators; some NOCs have comparative advantages that can be competitive in global energy
businesses. NOCs have the access to energy resources and believe that their experience with social
and economic development issues makes them a preferred partner for other NOCs and, in many
instances, preferred partners or operators for IOCs. Potential fruitful areas for future NOC/IOC
collaboration may be in the arenas of asset swaps (upstream access traded for downstream access) and
corporate citizenship/host country social and economic development.
It is in the arena of non-commercial issues such as social and economic development, as well as with
concerns about transparency, environmental protection and so on, that NOCs are most vulnerable to
critique. As NOCs take more prominent roles as operators and/or seek to integrate commercial goals,
objectives and performance measures into their protocols, they also become targets for scrutiny by the
legions of nongovernmental organizations (NGOs) that have long sought to impact IOC operations in
various countries and regions. Indigenous civil society NGOs have also become more contentious
with respect to NOCs, as NOC governance and the role of NOCs in the political organization and
fabric of their countries increasingly are linked.
A key strategic issue for NOCs and for any attempt to understand NOCs is the challenge of balancing
NOC commercialization (development of their hydrocarbon sectors) with national political, social
and economic development objectives.
INTRODUCTION
There has been surprisingly little systematic research on NOCs notwithstanding their significant presence
in and influence on the international oil and gas industry (McPherson, 2003). Nine of the top ten global
companies in terms of oil reserves are NOCs, and all ten of the top ten global companies in terms of
natural gas reserves are NOCs (PIW, 2005).4 These resource-rich NOCs are primarily resident in
developing countries and, as discussed below, we expect that the NOC model in those countries will
3
International Energy Agency, World Energy Outlook, 2002.
Top 10 companies based on oil reserves: Saudi Aramco, National Iranian Oil Company (NIOC), Iraq National Oil
Company (INOC), Kuwait Petroleum Corporation (KPC), Petroleos de Venezuela (PdVSA), Abu Dhabi National
Oil Company (Adnoc), Libya National Oil Company (Libya NOC), Nigerian National Petroleum Company
(NNPC), Petroleos Mexicanos (Pemex) and Lukoil. The top 10 companies based on natural gas reserves: Gazprom,
NIOC, Qatar Petroleum (QP), Saudi Aramco, Sonatrach, PdVSA, Rosneft, Adnoc, INOC and NNPC (Petroleum
Intelligence Weekly, 2005).
4
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
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Economics of the Energy Industries
continue at least for the foreseeable future. As a result, “getting it right” with respect to NOCs can be
expected to have major political, social and developmental consequences (McPherson, 2003).
In order to understand the role of NOCs and their impact on energy sector governance, it is necessary to
understand NOC performance within the context of their objectives as well as the key factors influencing
NOC “success” or lack thereof. We are concerned with the “commercial frameworks” for NOCs, that is,
the policy and regulatory settings in which NOCs function and that influences their performance. The
most frequently cited optimal economic structure for the oil and gas sector is that of private companies
operating in a regulated environment.5 However, for many countries, this structure is not necessarily a
viable option within a discernable time frame. In this project, we seek to define “best” commercial
frameworks as well as “best” NOC practices and performance within existing political and economic
constraints.
We propose using the business analysis approaches described in this paper for the evaluation of NOC
performance and the identification of the key performance drivers. There has been limited work to date
on the development of a robust performance evaluation system for NOCs even though many researchers
have acknowledged the need for one.6 In addition, NOCs want to be benchmarked with respect to other
NOCs. In her recent book on Middle Eastern NOCs7, Valerie Marcel noted that the NOCs in her study
were in the process of redefining themselves and attempting to find an appropriate balance in their
relations with the state. One reason that the five Middle Eastern NOCs participated in her study was their
desire to be benchmarked. These NOCs felt that they knew very little about how other NOCs operated
and how they dealt with common challenges. These NOCs “showed a great deal of interest in and
curiosity about NOCs outside the region.”
Our performance evaluation analysis will require consideration of related issues in the NOC commercial
framework, such as the political environments surrounding the NOCs and the relationship between NOCs
and regulatory bodies that are created to facilitate investment in energy sectors where NOCs are present.
We are also concerned with data availability, quality and comparability and international efforts to
encourage improved quality of the data reported by NOCs. Our working paper is part of a long term
research effort for which the objective is to define “best practices” in NOC organization, management and
commercial operations based on performance evaluation and the key commercial frameworks that lead to
these “best” NOC practices.
The authors and our colleagues are increasingly engaged in interactions with NOCs, especially through
our annual capacity building program (New Era in Oil, Gas and Power Value Creation), custom training
and through our international energy sector development assistance grants and activities. Undertaking a
long term research effort on NOCs and a comparable effort on national hydrocarbon regulators will
enable our team to both utilize information that is required for and incorporated into our other activities
(research and training) as well as to develop new analytical tools for capacity building worldwide.
5
Some countries lack the competitive marketplace, private capital and effective legal and regulatory system needed
to make this structure work (Stevens, 2003; Wong, 2004).
6
Ramamurti, Ravi and R. Vernon, eds., Privatization and Control of State-Owned Enterprises, The World Bank,
Washington, D.C., 1991; Valerie Marcel, “Good Governance of the National Oil Company,” Chatham House,
February 2005; Helena Inniss, “Measuring the Efficiency of State Owned Enterprises: Examples from the Energy
Sector, Petroleum Economics; “National Oil Company Case Study Research Protocol,” Baker Institute for Public
Policy, Rice University, May 2005.
7
Marcel, Valerie, Oil Titans: National Oil Companies in the Middle East, Chatham House, London, 2006. The
companies studied included Saudi Aramco, Kuwait Petroleum, National Iranian Oil, Sonatrach and Abu Dhabi
National Oil Company.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
6 - 10
Economics of the Energy Industries
The output of our long term project should be of interest to NOC stakeholders including governments,
international donor and financing organizations, and international oil companies (IOCs), as well as the
NOCs themselves. IOCs would like more clarity in their relations with NOCs and their governments to
improve the chances that mutually beneficial business arrangements can be concluded.8 NOCs
themselves have called for a reexamination of the record and future role of NOCs in their home countries
and worldwide.9
BACKGROUND
Why were national oil companies formed, and when?
Many NOCs came into being during a period of relatively large scale state intervention in their countries’
economies, a process which only began to reverse in the 1980’s and 1990’s (Stevens, 2003). Many
economists in these times thought that the “normal” operation of market forces would not be sufficient to
propel developing countries out of poverty. Only the state could marshal the resources required for
economic development. Thus the stage was set for government intervention in the oil and gas sector.
Within this general context favoring government intervention in the economic system, additional reasons
have been cited for the creation of NOCs including: (1) the emergence of natural resource nationalism and
the reduction of the state’s dependence on international oil companies; (2) the “strategic” nature of oil; (3)
the inability of the private sector to deal with the commercially risky and technologically complex oil and
gas sectors; (4) lack of institutional frameworks to support a regulated private sector, and (5) the
economic development role envisioned for the NOCs (Stevens, 2003; Heller, 1980; Foss, 2005; Grayson,
1981; Mommer, 2002). These reasons are discussed further below.
The driver for national sovereignty over natural resources in developing countries reflected “a collectively
bad experience with the international oil companies” (Stevens, 2003). Nationalizations occurred not
because these companies were privately owned but because they were foreign (Hartshorne, 1993).
Foreign oil companies were seen as having international interests which often did not coincide with
national interests. In addition, politically and financially powerful foreign oil companies brought with
them the specter of foreign government interference with national objectives.
Oil was viewed as “strategic” in that oil revenues were usually the main source of hard currency inflows
to national treasuries (Foss, 2005). The movement toward permanent sovereignty over natural resources
combined with the “strategic” nature of oil concept together provided the key rationale for state
involvement in the sector. If permanent sovereignty over oil and gas resources implies nationalization of
foreign operations it also implies the creation of NOCs: some entity must be created by the government to
replace the incumbent (foreign) operator to take over the oil operations (Olorunfemi, 1991).
At the times of foreign oil company nationalizations in developing countries, it was commonly thought
that development of a country’s oil sector could not be achieved by private companies operating in a
regulated environment (Stevens, 2003). First, the oil sector was seen as simply too large a commercial
risk for the small and relatively undeveloped private sectors in these countries and foreign private
companies were politically unacceptable. The rationale for direct state participation in the oil sector was
that it could secure crucial national interests more effectively than market forces and private initiative
(Noreng, 1997). Second, regulatory institutions and expertise were virtually non-existent in these
countries. Third, private companies would not accept the heavy fiscal burden and the development role of
the NOCs which were considered crucial for a country’s economic development (Boué, 2003).
8
“New Recipe Needed for IOC-NOC Mix,” Petroleum Intelligence Weekly, April 4, 2005.
Ali Al-Naimi, Saudi Arabia Minister of Petroleum and Mineral Resources, Speech at the OPEC International
Seminar, Vienna, Austria, September 16, 2004.
9
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
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Economics of the Energy Industries
Finally, the oil sector was often seen as a leading development sector or “locomotive” for overall
economic development in developing countries through establishing linkages with other industrial sectors
(Auty, 1990). Given the limited capacity of the private sector, NOCs were seen as the engines to develop
these physical and fiscal linkages (Stevens, 2003).
With respect to timing, the first NOC in a developing country was created in Argentina in 1922, as shown
in Table 1. Post World War II, the trend toward the creation of NOCs achieved an overwhelming
momentum as former colonies became independent (Baum, 1980). Although several OPEC country
NOCs were created in the 1950’s and 1960’s, it was not until the 1970’s that these NOCs achieved
complete control over their countries’ oil and gas sectors (Heller, 1980).
Table 1. Selected NOCs and Year Established
Country
National Oil Company Date of Creation
Argentina
YPFA
1922
Chile
ENAP
1926
Russia
Various
1934*
Peru
PetroPeru
1934
Bolivia
YPFB
1936
Mexico
Pemex
1938
China
PetroChina
Early 1950s
Colombia
Ecopetrol
1951
Iran
NIOC
1951
Brazil
Petrobras
1954
India
ONGC
1956
Iraq
INOC
1961
Saudi Arabia Petromin
1962
Algeria
Sonatrach
1965
Indonesia
Pertamina
1968
Libya
Libya NOC
1968
Norway
Statoil
1982
Ecuador
Petroecuador
1973
Malaysia
Petronas
1974
Kuwait
KPC
1975
Venezuela
PdVSA
1976
China
CNOOC
1982
Source: UNCNRET, State Petroleum Enterprises in Developing Countries, 1980; company reports.
*Russia nationalized its oil industry in 1918 but the industry was not consolidated into NOCs until 1934.
What led to the criticism of the NOC model and the privatization of many NOCs in the 1990’s and
early 2000’s?
In the late 1970’s and 1980’s government intervention in the economy in general came under attack.
Supply side and “monetarist” economic analysis attacked much of the Keynesian basis for state economic
intervention (Stevens, 2003). Developing country economies failed to perform well in many cases and
this failure was attributed to inefficient, ineffective and often corrupt government intervention. The
collapse of the Soviet Union was the final indictment of state controlled economies. “The result was
privatization, deregulation and general liberalization. State owned enterprises became viewed as
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
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Economics of the Energy Industries
dinosaurs requiring a helping hand into extinction. It seemed that removing state intervention from all
but a minimal role was now an undisputed requirement” (Stevens, 2003).
In addition to the renewed credibility of market forces, NOC “dinosaurs” were subjected to other
criticisms. Many governments, economists and industry stakeholders thought that conflicting objectives
(development of the oil sector vs. fiscal funding of the government) led to NOC operational paralysis (El
Mallakh, Noreng and Poulson, 1984). Politicians frequently deprived NOCs of sufficient investment
capital to achieve their commercial goals in order to fund other state activities (Hartshorne, 1993).
Subsidized prices for oil and gas products in many countries also saddled the NOC with losses (Philips,
1982; Khan, 1994).
On the other hand, NOCs were also criticized for becoming too powerful in the context of domestic
politics especially when there were few countervailing powers. Information asymmetries and agency
issues in the technically complex oil industry allowed the NOC to pursue rent for their own purposes.
Pemex and PdVSA have been accused of behaving in such a way (Philip, 1982; Boué, 1993; Mommer,
2002).
A no-win dichotomy was believed to exist: Excessive government interference impaired the NOCs
commercial effectiveness while insufficient control led to NOC disinterest in its non-commercial
objectives and behavior similar to that of any private oil multinational corporation (Grayson, 1981).
NOCs were monopolies operating in a highly protected business environment (Grayson, 1981). Private
investment was prohibited or if permitted, the NOC was often able to create significant barriers to entry
by manipulating the regulatory environment to its advantage. Lack of competition and transparency led
to inefficiency, incompetence and corruption (Madelin, 1974; Van der Linde, 2000). NOCs fell behind
technologically and managerially and were frequently used as vehicles to lower unemployment (AlMazeedi, 1992) or achieve other social and political imperatives.10 As a result of these problems and the
general movement globally away from centrally-planned economies toward market-based economies,
there was a wave of NOC privatizations in the 1990’s and early 21st century, as shown in Table 2. The
goal of these privatizations was to eliminate conflicts of interest resulting from state ownership (political
vs. economic objectives) and to promote efficiency gains by introducing competition (Aegis, 2002). It is
interesting to note that most of the privatizations, and the more extensive privatizations, occurred in
developed countries or the Russian transition economy. Several reasons could be attributed for this
pattern, including the relative maturity or lack of hydrocarbon resources in some locations (such as
France, Norway, onshore China and Argentina) and socioeconomic and political transformations in
developed countries that were broadly impacting energy sector regimes (such as Britain). The Russian
transition economy privatizations could be considered an outlier; a resource rich federation, the Russian
companies were established during a time of chaotic upheaval following the collapse of the Soviet Union.
The current stance of the Russian government is much more akin to that of governments in resource rich
nations (such as the Middle East) and perhaps more typical of what should be expected or even of what
might have occurred otherwise.
Table 2. Full or Partial Privatizations of National Oil Companies
Company
YPF-Argentina
YPFB-Bolivia
Date of Privatization % of State Ownership Sold
1993, 1999
58%, 100%
1996
50%
10
It is well known that NOCs are often the conduits for carrying out an array of activities, from road building to
health care. These “non-core” activities have often been blamed for hindering NOC efficiencies in their “core”
activities, production and delivery of hydrocarbon resources. The ability of NOCs to re-invest in their core activities
also has been hindered by revenue capture by their host governments.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
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Economics of the Energy Industries
Company
Date of Privatization % of State Ownership Sold
PetroCanada
1995, 2002
81%
Sinopec
1998
45%
PetroChina
1998
10%
CNOOC-China
1998
29%
Elf-France
1992, 1994
49%, 100%
Total-France
1992, 1998
30%, 100%
ENI-Italy
1995, 2001
15%, 70%
Yukos-Russia*
1994
100%*
Statoil-Norway
2001
20%
Gazprom-Russia
1994
61%
Repsol-Spain
1989-1997
80%
BP-UK
1979-1995
100%
Petrobras-Brazil
1995
49%
Lukoil-Russia
1994
92%
Source: Aegis Energy Advisors Corp., November 2002 and Petroleum Intelligence Weekly, April 2005
*Rosneft acquired a Yukos unit representing about 60% of its crude oil production in 2004.
What is the situation of NOCs today?
Five of PIW’s top ten world oil companies are NOCs: Saudi Aramco, NIOC, PdVSA and PetroChina. As
can be seen below, nine of the top ten oil companies in terms of oil reserve endowment are 100 percent
state-owned, dominate their countries’ economies (with the exception of Mexico) and are the primary
sources of export revenues and government fiscal revenues. In these countries, oil continues to be viewed
as “strategic.”
Table 3. 100% State-Owned National Oil Companies, 2003
Company
Saudi Aramco
NIOC-Iran
INOC-Iraq
KPC-Kuwait
PdVSA-Venezuela
Adnoc-UAE
Libya NOC
NNPC-Nigeria
Pemex-Mexico
Qatar Petroleum
Sonatrach-Algeria
Petronas-Malaysia
PertaminaIndonesia
Petroecuador
Socar-Azerbaijan
Rosneft-Russia
Sonangol-Angola
SPC-Syria
Oil/Gas % Export
Revenues
90%
80%
87%
Oil/Gas % of Gov’t
Fiscal Revenue
70-80%
40-50%
90%
50%
80%
70%
75%
80%
35%
70%
75%
29%
96%
11%
95%
4%
21%
Oil/Gas %
GDP
40%
80%
40-50%
30%
30%
8%
40%
7-19%
40%
85%
66%
90%
67%
40%
50%
World Ranking By
Oil Reserves
1
2
3
4
5
6
7
8
9
11
16
22
26
12%
25%
50%
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
6 - 14
28
33
34
38
39
Economics of the Energy Industries
Company
Oil/Gas % Export
Revenues
Oil/Gas % of Gov’t
Fiscal Revenue
Oil/Gas %
GDP
World Ranking By
Oil Reserves
41
43
EGPC-Egypt
Ecopetrol28%
5%
7%
Colombia
Kazmunaigas60%
55%
35
Kazakhstan
Sources: PIW April 2005, World Bank Country Data at a Glance, EIA Country Profiles, Economist
Intelligence Unit, EIA OPEC Revenues, Country Details, January 2005.
A second group of NOCs is significant in terms of resource endowment and majority ownership by their
governments. The reduction in state ownership from 100 percent came about through the partial
privatizations discussed previously. In these countries, the oil and gas sector plays an important but not
necessarily a dominant economic role and several of the countries are net importers of hydrocarbons.
These NOCs are shown in Table 4.
Table 4. Majority Owned National Oil Companies 2003
Company
PetroChina
PetrobrasBrazil
SinopecChina
StatoilNorway
ONGC-India
CNOOCChina
PDO-Oman
% State
Oil/Gas % Export
Ownership
Revenues
88% Importer11
56% Importer12
Oil/Gas %
GDP
World Ranking by Oil
Reserves
15
18
55% Importer
31
80%
47%
21%13
29-Gas
10%
26-Gas
44
84% Importer14
71% Importer
60%
75%
40%
Sources: Same as 100% State-Owned NOCs 2003 in the table above.
32
Finally, a third group of NOCs exists which have minority ownership by their governments, as shown in
Table 5.
Table 5. Minority Owned National Oil Companies 2003
Company
ENI-Italy
Lukoil-Russia
Gazprom-Russia
PetroCanada
% State
Ownership
30%
7.6%
38%*
19%
Oil/Gas % Export
Revenues
66%
66%
World Ranking by Oil
Reserves
29
10
1-Gas
52
11
In China 34 percent of domestic oil consumption is provided by imports. U.S. EIA Country Analysis, China.
Brazil achieved oil self-sufficiency in 2006, e.g. the country’s oil production equaled demand. However, due to
the configuration of Brazil’s refineries, the country still has to import lighter crudes.
13
In Norway the oil and gas sector accounts for 28% of the state’s fiscal revenue.
14
In India, fuel and energy imports account for 26% of total imports. World Bank, India Financial Profile.
12
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
6 - 15
Economics of the Energy Industries
Company
% State
Ownership
44%
Oil/Gas % Export
Revenues
World Ranking by Oil
Reserves
37-Gas
Norsk HydroNorway
Tatneft-Russia
31%**
66%
24
Sources: Same as 100% State-Owned NOCs 2003 in the table above. *The government increased its
ownership to 51% in 2005. **Owned by provincial not the federal government.
Harsh fiscal regimes for both NOCs and private investors (if permitted to enter) appear to be
characteristic of countries with large resource endowments and a high degree of dependency on oil and/or
natural gas for export revenues and government funding. Some anomalies exist – Mexico and India, for
example, have traditionally restricted their oil and gas upstream policies far beyond what is warranted by
their comparative advantage in risked reserves (proven with typically a ninety percent probability) (Foss,
2005, and shown in Figure 1 below). In addition, the Mexican and Indian economies are relatively welldiversified with far less dependence on oil and gas for export earnings and government funding than
many other oil-producing countries.
Figure 1. Country Hydrocarbon Resource Endowments and Distribution of Upstream
Fiscal Regimes (Foss, 2005)
Note that the worldwide risk capital “equilibrium” is
dynamic. At time of first writing (May 2005) higher
commodity prices were inducing host governments to
revise fiscal regimes in ways that enable capture of
“windfall” profits and accelerate a trend of increasing
government “take” relative to IOC profit margins.
The recent upsurge in oil and gas prices has revived perceptions of “resource nationalism”. In many
producing countries, NOCs are still seen as crucial to economic development (Boué, 2003). Control of
oil revenue, in particular, is often a mechanism for political control of government (Foss, 2004). Russia
has nationalized Yukos and now controls 51 percent of Gazprom. Putin’s government has asserted that
various foreign oil and gas companies are in arrears on income taxes (see previous remarks on Russia’s
transition economy and NOC privatizations) and has limited foreign company participation in major oil
and gas projects. Kazakhstan is considering changing the fiscal regime for foreign investors. Venezuela
has tightened the fiscal regime for oil and increased state participation in oil projects. Venezuela is also
alleging that foreign operators owe back taxes. Mexico’s upstream sector remains largely off-limits for
private investment and the issue of foreign participation continues to be a controversial political issue.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
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Economics of the Energy Industries
Bolivia’s president, Evo Morales, renationalized the oil and gas industry in 2006. In Trinidad and
Tobago, the state is seeking increased participation in the country’s LNG projects. Even Argentina, an
oft-cited “model” for privatized energy sectors, established a new state-owned energy company, Enarsa,
in 2004 which “will become involved in all aspects of the energy sector.”15 While relatively high
commodity prices persist it is unlikely that state participation in the oil and gas sectors in developing
countries will decrease and fiscal regimes most likely will favor the state.
In a similar vein, NOC/IOC commercial arrangements will likely remain difficult to negotiate and
implement. Limited upstream opportunities lead cash-rich IOCs to seek partnership or joint venture
relationships with resource-rich NOCs. IOCs have investment capital (a continual problem for many
NOCs) and technology and project management expertise which they feel would be beneficial for NOCs.
However, it has been difficult to achieve these arrangements in practice in the most predominant
resource-rich countries.
COMMERCIAL FRAMEWORK ANALYSIS
Given the importance of energy for economic development and the probable continuation of the NOC
“model” for some time to come our objective is to identify “best practices” in NOC organization,
management and commercial operations by using business analysis approaches to evaluate the
performance of NOCs. In addition, we will identify the commercial frameworks, often the key drivers,
influencing NOC performance and address non-commercial challenges.
The NOC Commercial Framework
Foss, et.al. (1998) suggested that energy sector efficiency could be defined by the prevailing style of
organization, as shown in Figure 2.
Figure 2. Generalized Energy Sector Organization
Source: Foss et.al. (1998).
Further work by Foss, et.al. (1999) defined a matrix to explain key outcomes in energy sector
organization as a function of both economic organization of the host country and host government
viewpoints with respect to strategic control of their energy sectors. This matrix is shown in Figure 3.
Figure 3 suggests that in countries that tend toward centrally-planned economies and where energy is
considered to be a strategic material, government-based solutions for energy are more frequently
observed. Good examples are Mexico and Venezuela. In countries that tend toward market-based
economies and where energy is generally regarded to be a commodity like any other, market-based
solutions are more frequently observed. Examples of this situation at this time are the U.S. (strong) and
Canada (less strong), which have been moving in this direction for some time. In essence, in those
situations in which host governments view energy as “too important to be left to the market” government
intervention will be strongest. If the country is a hydrocarbon producer, a net hydrocarbon exporter, and
15
U.S. EIA, Country Analysis Brief - Argentina, January 2005.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
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Economics of the Energy Industries
hydrocarbons are the patrimony of the state, the probability of the NOC form of organization being
utilized will be strongest.
Figure 3. Energy Sector Organization and Presence of NOCs
Source: As published in Foss, et.al, “Hydrocarbon Regulation and Cross-border Trade in the Western Hemisphere”,
Chapter 16 in Energy Cooperation in the Western Hemisphere: Benefits and Impediments, Center for Strategic and
International Studies, 2007, http://www.csisbookstore.org/index.asp?PageAction=VIEWPROD&ProdID=163. First
published in Michelle Michot Foss et al., Best Practices in Energy Sector Reform, Final Technical Report, Energy
Institute, University of Houston, 1999 (available from Center for Energy Economics [CEE],
www.beg.utexas.edu/energyecon).
A specific addition to the NOC commercial framework in recent years is the hydrocarbon regulator. The
U.S. has long had regulators at both the national and state levels (examples are the U.S. Minerals
Management Service, which oversees federal interests offshore, and the Texas Railroad Commission, the
oldest hydrocarbon regulator in existence). In the U.S., hydrocarbon regulators have authority over entry
and exit on public lands (with private lands being left to market forces), implement conservation practices
(to ensure efficient and optimum resource exploitation), and oversee health, safety and environment
(HSE) requirements (although numerous other regulatory entities exist in domains such as air and water
quality). Outside of the U.S., government ownership over hydrocarbon resources is dominant and tends
to be at the national level (albeit with provincial crown ownership in Canada). In countries with
government control of hydrocarbon resources, and especially where NOCs exist, the hydrocarbon
regulator is typically viewed as providing the mechanism for private capital flows and especially foreign
capital flows to enter the energy sector. This approach nearly always pits the regulator against the NOC.
A typical model is shown in Figure 4.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
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Economics of the Energy Industries
Figure 4. The Role of Hydrocarbon Regulator
Source: As published in Foss, et.al, “Hydrocarbon Regulation and Cross-border Trade in the Western Hemisphere”,
Chapter 16 in Energy Cooperation in the Western Hemisphere: Benefits and Impediments, Center for Strategic and
International Studies, 2007, http://www.csisbookstore.org/index.asp?PageAction=VIEWPROD&ProdID=163. First
published in Michelle Michot Foss et al., Best Practices in Energy Sector Reform, Final Technical Report, Energy
Institute, University of Houston, 1999 (available from Center for Energy Economics [CEE],
www.beg.utexas.edu/energyecon).
The commercial framework for a typical NOC thus can be summarized as shown below. NOCs today
exist in both domestic and international environments. Any of the prevailing forces within these
environments can overwhelm a NOC’s own management structure, decision making processes, and
performance outcomes. These forces may be mutually exclusive, or interact strongly.
Table 6. NOC Commercial Framework and Critical Forces
Internal (Domestic) Factors
Impacting NOC
Internal energy and materials
requirements
Political organization and “golden
share”
Labor unions and labor politics
NOC
Revenue priorities for host
government
Emerging regulatory framework and
conditions for access
Domestic civil society groups and
other nongovernmental
organizations (NGOs)
External (International) Factors
Impacting NOC
Export strategies for regional,
global markets
Global supply-demand balances
and commodity prices
Goals, objectives of investors
(foreign and domestic)
Minimum requirements of global
capital markets
Interactions between investors and
regulator
International civil society groups
and other NGOs
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
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Economics of the Energy Industries
NOC Objectives
In order to evaluate NOC performance, NOC objectives must first be defined in order to determine what
NOC success looks like. The literature on oil and gas producing country NOCs generally places their
objectives in one of two categories: (1) Effective development of the country’s hydrocarbon sector,16 and
(2) Contribution to the overall social and economic development of the country (Zakariya, 1980;
Megateli, 1980). The literature also acknowledges the often conflicting nature of NOC objectives
(Megateli, 1980; Grayson, 1981; UNCNRET, 1978). In its 2003 Annual Review Saudi Aramco speaks of
“honing the company’s dual role as a commercial enterprise that continually strives to maximize its
financial performance and to contribute to the national interests.” This conflict is well-articulated by
Petrobras in its 2005 20-F filing with the U.S. Securities and Exchange Commission:
“The Brazilian government has pursued, and may pursue in the future, certain of its
macroeconomic and social objectives through us…As a result, we may engage in
activities that give preference to the objectives of the Brazilian government rather than to
our own economic and business objectives…Accordingly, we may continue to make
investments, incur costs and engage in sales on terms that may have an adverse effect on
our results of operations and financial condition.”17
Examples of goals in the first category include efficient finding and development, production and
marketing of hydrocarbons as well as meeting targeted profitability measures. Examples of goals in the
second category include capital formation by generating profit and foreign exchange earnings from
hydrocarbon sector operations and making this capital available to the state in order for the non-oil sector
to grow as well as provision of adequate affordable energy to its citizens (Al-Naimi, 2004; Ecopetrol
annual report, 2003).
Previous studies advocate that NOCs should be evaluated in light of their own objectives given the
multidimensional differences in the history, resource endowment, organization, and the financial,
economic and even political conditions of the petroleum industries in their countries. These could include
the objectives assigned to it by the government and/or the specific corporate goals and targets specified in
operational and financial terms during the evolution of the NOC (Megateli, 1980). Scholars as well as
NOCs warn against comparing NOCs with IOCs given the dual objectives of the NOCs (Megateli, 1980;
Al-Naimi, 2004).
Many NOCs are now explicitly stating their objectives. Examples of stated NOC objectives based on
public disclosures can be seen below.
Category 1. Effective Development of the Country’s Hydrocarbon Sector
• Increase production while replenishing/increasing reserves (Pemex, Petrobras, Ecopetrol, Saudi
Aramco);
• Attain/maintain oil and/or gas self-sufficiency (Petrobras, Ecopetrol, Pemex);
• Modernize productive infrastructure and operations (Pemex);
• Increase upstream investments (Pemex);
• Improve operating margin, EBITDA and return on operating assets (Ecopetrol);
• Reduce lifting costs and meet targeted return on capital employed of 15% for 2010 (Petrobras);
• Use advanced business practices to improve operating efficiency (Saudi Aramco);
• Rationalize labor expense (Ecopetrol);
16
For oil importing country NOCs, this first goal category becomes assuring affordable and reliable hydrocarbon
supplies (Grayson, 1981).
17
Petrobras Form 20-F, 12/31/03, pg. 24.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
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Economics of the Energy Industries
•
•
•
Operate successfully and transparently in a deregulated market (Petrobras);
Achieve internationally competitive business and technical expertise levels (Qatar Petroleum, Saudi
Aramco, Ecopetrol);
Improve health, safety and environmental performance (Pemex, Petrobras, Ecopetrol, Saudi Aramco,
and Qatar Petroleum).
Category 2. Contribute to the Overall Social and Economic Development of the Country
• Make a significant fiscal contribution to the state (Ecopetrol);
• Provide the state with a reliable cash flow, of maximum value, from diversified business interests
(Qatar Petroleum);
• Maximize the benefits from operations and place those benefits at the service of the country (Saudi
Aramco);
• Leverage oil and gas resources to expand/diversify the economy (Saudi Aramco);
• Maximize the creation of economic value (Pemex);
• Maximize employment (Saudi Aramco, Qatar Petroleum);
• Contribute to social, cultural and economic programs (Ecopetrol);
• Contribute to the country’s overall development (Petrobras).
NOC Performance Evaluation Analysis
NOC Selection
We selected five NOCs to illustrate our performance evaluation analysis: Pemex, PetroChina, CNOOC,
Petrobras and Statoil. All five companies provide easily accessed, good quality and comparable data in
their annual filings of the U.S. Securities and Exchange Commission’s (SEC) Form 20F. The SEC
standards are considered to be quite good relative to other international reporting standards. All of the
companies have filed the Form 20F over a time period sufficient to permit longitudinal analysis. With
respect to accounting standards, CNOOC, Petrobras and Statoil use U.S. generally accepted accounting
principles (U.S. GAAP). Pemex uses Mexico generally accepted accounting principles (MAAP) and
PetroChina uses International financial reporting standards (IFRS): both companies provide
reconciliations to U.S. GAAP and over the time period of our analysis there was not a material difference
between their standards and U.S. GAAP with respect to our performance metrics. Four of the companies
(PetroChina, CNOOC, Petrobras and Statoil) use the “successful efforts” (SE) accounting methodology
for reporting the results of upstream operations. Pemex does not explicitly claim to use the SE
methodology but their disclosed methodology is practically identical to SE. All five NOCs have stated
goals and objectives.
All five companies report results of upstream operations in accordance with U.S. accounting standard
FAS 69. Upstream domestic and international operating results are disclosed separately. We have chosen
to focus on domestic upstream operations given their importance to the five countries. (However, we
expect the international upstream operations of these NOCs to become increasingly important to the
companies and their governments given the increasing recognition that domestic energy security is
dependent on sufficient worldwide oil and gas supplies.) The proved oil and gas reserves of all five
companies are audited by third party independent and recognized petroleum engineering consulting firms.
With the exception of CNOOC, which operates solely in the upstream oil and gas sector, the other four
companies are integrated firms with significant operations in the midstream (processing, storage and
transportation) and downstream (refining, petrochemicals and retail marketing of hydrocarbon products)
sectors of the oil and gas industry.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
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Economics of the Energy Industries
In addition to good data quality and comparability, these five NOCs have been repeatedly identified by
other NOCs as companies having commercial results and governance frameworks that could be worthy of
emulation. The managements of Middle Eastern NOCs in Marcel’s 2006 study wanted to know more
about Statoil, Petronas18 and Petrobras. Pemex in its reports has mentioned these three companies as well
as PetroChina as companies with superior operating and financial performance. Colombia’s NOC,
Ecopetrol, is explicitly modeling its reforms on the Petrobras model in Brazil.
Finally, these five NOCs span the spectrums of commercial frameworks and country economic reliance
on the hydrocarbon sector. At one end of the commercial frameworks spectrum is Pemex which has a
complete upstream monopoly and a dominant midstream and downstream position. At the other end of
the spectrum, there is Statoil which must compete with other public and private (including foreign)
companies on a relatively level upstream playing field. In addition, as discussed later in this paper, Statoil
no longer dominates the midstream sector of the hydrocarbons industry and the downstream sector is
slated to become increasingly competitive. As a result, Statoil accounts for 15 percent of Norway’s
proved reserves whereas Pemex accounts for 100 percent of Mexico’s proved reserves. Interestingly, the
governments of Norway and Mexico are also the most reliant on hydrocarbon export revenues for funding
of the public budget but have evolved almost diametrically opposed commercial frameworks.
China permits public and private (including foreign) companies to participate in the upstream sector but
has specific upstream policies favoring its own NOCs as discussed in more detail in the commercial
frameworks section of this paper. The Chinese NOCs also dominate the midstream and downstream
sectors of the oil and gas industry which can discourage upstream competition. PetroChina still controls
66 percent of the country’s reserves. Competition is allowed in Brazil’s upstream sector but Petrobras
continues to dominate the upstream in part due to its superior knowledge of Brazil’s exploration prospects
and accounts for 77 percent of the country’s reserves. Like the Chinese NOCs, Brazil dominates the
midstream and downstream oil and gas sectors. China and Brazil are net hydrocarbon importers with
large domestic markets for energy.
These spectrums of commercial frameworks and country economic structures will allow us to assess the
impact of country economic structure on oil and gas sector commercial frameworks as well as the impact
of commercial policies, practices and regulation on NOC performance.
Domestic Resource Endowment
It is important to note that the composition (oil/gas), quality (sour heavy oil vs. sweet light oil), quantity
(size of proved reserves), diversification (number of geographic areas and geological basins), location
(onshore/offshore, deep/shallow, remote/near markets) and maturity (proved undeveloped or PUD vs.
proved developed reserves) of a country’s oil and gas resource endowment will affect NOC performance.
The NOC does not have control over these factors: it is the hand the NOC has been dealt by nature.
However, the characterization of hydrocarbon endowments has performance-related consequences. Large
resource endowments that are not overly complex for production and/or treatment generally translate into
greater financial resources, liquidity and economies of scale. Resource composition, quality, quantity and
location can affect realized prices and costs, monetization strategies and value enhancement. Highly
mature reserve bases can result in higher costs and decreasing production. Lack of diversification can
lead to operating disruptions with negative financial consequences.
These differences in resource endowment could make inter-NOC comparisons difficult if the differences
are wide. Nevertheless, a NOC can be measured against itself over time.
18
We did not include Petronas, an otherwise much discussed example, in this paper because it does not file a Form
20F.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
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Economics of the Energy Industries
The 2005 domestic resource endowment profile of the five NOCs researched for this paper can be seen in
Table 7 below. MMBOE refers to million barrels of oil equivalent.
Table 7. 2005 Domestic Resource Endowment Profile
Company/Metric
Proved Reserves
(MMBOE)
% Oil/Gas
% PUD Oil/Gas
Revenue/BOE
Production
(MMBOE)
Oil Prod. (MMB)
Gas Prod. (BCF)
% Prod. Oil/Gas
Production
Concentration
Weight Pemex
PetroChina
CNOOC
Petrobras
Statoil
0.15
16,470
19,556
2,113
10,479
3,462
% Prod.
Onshore/Offshore
0.075
0.075
0.125
0.15
83/17
30/39
$41
1,605
59/41
20/71
$39
1,053
62/38
53/55
$43
141
86/14
55/56
$39
673
33/67
31/28
$41
360
0.075
1354
829
122
585
205
0.075
1305
1344
108
496
869
0.075
84/16
79/21
87/13
87/13
57/43
49% oil from
83% oil from
49% oil from
0.075 61% oil and 41% oil from
15% gas
from
Cantarell
complex
0.10 17/83-Oil0.025 Shallow
66/34-Gas
Daqing region
Bohai Bay;
68% gas from
West South
China Sea
Campos basin
Tampen
NCS;70%
gas from
Troll NCS
90/10 -Oil
90/10 -Gas
0/100- OilShallow
0/100- Gas
18/82-OilDeep
18/82-Gas19
0/100-OilHarsh
0/100-Gas
For each metric, similar companies’ results are highlighted in the same color for emphasis. For example,
Pemex, PetroChina and Petrobras are similar in terms of proved reserves as are CNOOC and Statoil; these
data are highlighted in yellow. Outliers (e.g., a company’s results are not shared by any other company)
are highlighted in red. Statoil stands out as a natural gas company in terms of proved reserves and
production composition where the other four are oil dominant. CNOOC has the smallest gas production
by far of the five companies. PetroChina is an onshore oil producer where the other four are primarily
offshore oil producers.
Greater weightings are given to the size metrics (proved reserve volumes and production volumes) as a
high degree of correlation has been observed among larger results on these metrics and other positive
characteristics such as asset diversification, financial resources and liquidity, cash flow durability,
operating success and longevity. Companies that have similar size metrics tend to share these other
characteristics. Revenue/BOE (reflects resource composition, quality, and location) and percentage of
production onshore vs. offshore have similar impacts on realized prices and production costs. Companies
with similar results tend to share revenue and cost profiles. With respect to production onshore vs.
offshore, greater weight is given to resource with greater production. As there is no more than a 10
percent variance in revenue/BOE, all the companies share similar results on this metric.
Table 8. Domestic Resource Endowment Comparability among NOCs
Company
Pemex
PetroChina
CNOOC
19
Pemex
100%
75%
30%
PetroChina
75%
100%
27.5%
CNOOC
30%
27.5%
100%
Petrobras
57.5%
42.5%
30%
Statoil
20%
20%
45%
75% of gas production is from associated gas.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
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Economics of the Energy Industries
Company
Petrobras
Statoil
Pemex
57.5%
20%
PetroChina
42.5%
20%
CNOOC
30%
45%
Petrobras
100%
32.5%
Statoil
32.5%
100%
Pemex is most comparable with PetroChina. To a lesser extent, Pemex and PetroChina are comparable to
Petrobras. CNOOC and Statoil approach 50 percent comparability with respect to the resource
endowment metrics. Although the comparability among the companies is less than 50 percent in many
cases, this does not preclude companies learning from each other in the areas where there is
comparability.
Performance Evaluation Methodologies
The objectives of the five NOCs in our study generally fall into two categories: commercial and noncommercial. Commercial goals typically address the effective development of the country’s hydrocarbon
sector while non-commercial goals pertain to the overall social and economic development of the country.
Commercial Objectives. With respect to determining whether or not a NOC effectively develops its
country’s hydrocarbon resources, we undertake the following analysis:
1. We focus on the upstream sector (oil and gas exploration and development) since it is critical to
all subsequent oil and gas value chain components and typically is the most politically sensitive part
of the industry. One part of the analysis will focus on the NOC’s ability to find and develop
hydrocarbons in a cost effective manner. It can be argued that performance in this arena is critical:
an upstream company’s sustainability is threatened if it cannot replace production cost-effectively.
According to Moody’s Investors Service “To survive a company must reinvest substantial capital
consistently and successfully over a long period of time to find new reserves and replace and grow its
production.”20 Otherwise reserves and production will decrease and the company will eventually
liquidate.
2. The second part of the upstream sector analysis will concentrate on the NOC’s ability to profitably
produce hydrocarbons. The ability of the five NOCs to sustain themselves and the development of
their countries’ hydrocarbon sectors is an important objective.
Performance metrics are defined in Table 9 and Table 10; unless otherwise specified all data is sourced
from the SEC Form 20F. Most of these performance metrics are within the control of the NOC. Items
not within NOC control include the fiscal regime (tax burden); any government imposed limitations on
capital available for investment; any government/labor union requirement to provide employment and/or
“out-of-market” compensation levels; provision of price subsidies. Recognizing that a NOC may not be
totally responsible for performance on these metrics, it is still useful from a policy analysis perspective to
know which government policies are influencing NOC performance and to what degree.
Table 9. Metrics for NOC’s Ability to Find and Develop Hydrocarbons Cost Effectively
Performance Metric
Exploration Success
Rate
Development Success
Rate
3 Yr. Ave. All Source
Reserve Replacement
20
Definition
Number successful exploration wells/total exploration wells
drilled in time period
Number successful development wells/total development wells
drilled in time period
Total costs incurred per FAS 69
(acquisition+exploration+development)/reserve additions
Attribute Measured
Exploration competence; ability
to replace reserves
Development competence; ability
to produce reserves
Project selection; capital &
project management &
“Global Integrated Oil & Gas Industry Rating Methodology,” Moody’s Investor Service, October, 2005.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
6 - 24
Economics of the Energy Industries
Performance Metric
Cost (RRC) (BOE)
3 Yr. All Source
Production
Replacement Ratio
(PRC) (BOE)
(Cash Margin/BOE)/3
Yr. Ave. Reserve
Replacement Cost
/BOE
Upstream Op. Cash
Flow/Upstream Cap.
Ex.
Production and
Reserve Growth
Rates
Definition
(extensions & discoveries, improved recovery, net
purchases)/(sales+net reserve revisions)
Reserve additions (as defined above)+net reserve
revisions/production
Attribute Measured
Effectiveness. Competitiveness
and sustainability
Drilling/operating success
FAS 69 upstream revenue-(production and exploration
expenses)/3 Yr. Ave. RRC/BOE
Level of embedded production
and reserve replacement costs
relative to the operating cash
margin; ability to generate cash
for investment
Ability to generate sufficient
investment capital from upstream
operations
Technical competence;
sustainability; capital adequacy
FAS 69 upstream earnings after tax+depreciation/upstream
capital expenditures
Current period production or reserve level/prior period
production or reserves level
Table 10. Metrics for NOC’s Ability to Produce Hydrocarbons Profitably
Performance Metric
Upstream Operating Results/BOE
EBTDA/BOE
Upstream After Tax
Earnings/Upstream Long Term Assets
Definition
FAS 69 upstream results of operations
((revenue-(production and exploration
expenses+depreciation+taxes))/annual
BOE production
FAS 69 ((revenue-production and
exploration expenses)/annual BOE
production
FAS 69 upstream earnings after tax/
upstream long term assets as reported in
Form 20F segment information
Attribute Measured
Operating efficiency and
competitiveness; impact of the fiscal
regime on NOC sustainability
Operating efficiency and
competitiveness
Capital management effectiveness;
profitability
3. The third part of the analysis will concentrate on the consolidated operating and financial
performance of the NOC. This is done more for diagnostic than comparative purposes as the
business models (integrated oil companies vs. upstream only companies vs. primarily natural gas
companies) and resource endowments vary considerably across NOCs. The main purpose of this part
of the analysis is to identify any “red flags” in the overall corporate profile that could influence
upstream performance such as: high corporate debt levels and/or tax burdens and/or poor interest
coverage ratios that could limit access to capital; unusually high levels of non-financial non-operating
expenses; ability to generate investment capital from operations; competing capital requirements of
the non-upstream sectors, and overall NOC profitability.
Performance metrics are defined in Table 11; unless otherwise specified all data is sourced from the SEC
Form 20F. The same issues surrounding NOC control of factors that could influence performance
discussed above should also be considered here.
Table 11. Metrics for Consolidated NOC Operating and Financial Performance
Performance Metric
EBITDA/Revenues
FFO/Capital Expenditures
Definition
Earnings before interest, taxes and
depreciation/Revenues
Earnings before interest and taxes/Net
Interest
Funds from operations/ cap. exp.
Net Income/Average Total Capital
Employed (ATCE)
Net Income/(average of two year short
and long term debt minority interest
EBIT/Net Interest
Attribute Measured
Cash margin from operations;
competitiveness, sustainability
Ability to pay interest; financial strength
Ability to generate sufficient investment
capital from operations
Profitability, competitiveness, capital
management effectiveness
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
6 - 25
Economics of the Energy Industries
Performance Metric
Definition
deferred taxes operating leases equity)
Short and long term debt operating
leases/( average of two year short and
long term debt minority interest deferred
taxes operating leases equity)
Short and long term debt operating
leases/total proved reserves
Gross Debt/ATCE
Gross Debt/Total Proved Reserves
Attribute Measured
Ability to service debt; financial strength
Ability to generate future revenues from
current asset base to service debt
Five Company Performance Evaluations
The company profiles in Table 12 provide context for the performance evaluations and aid in results
interpretation in Table 13.
Table 12. Company Profiles
Company
Country
Type Company
Non-NOC
Participants in
Upstream
NOC %
Country’s
Reserves
Upstream Assets
($MM)
Significant
International
Upstream Assets
Pemex
Mexico
Integrated
No
100%
PetroChina
China
Integrated
Yes but specific
policies favor
NOCs.
66%
CNOOC
China
Upstream Only
Yes but specific
policies favor
NOCs.
7%
$78,326
$57,102
$11,505
No
No
Yes
Petrobras
Brazil
Integrated
Yes but NOC is
dominant.
Statoil
Norway
Integrated
Yes-Most level
playing field.
77%
15%
$25,869
$12,809
Yes
Yes
Table 13. Performance Metrics re: Ability to Find and Develop Hydrocarbons Cost Effectively
Company/Metric
3 Yr. Average
Exploration
Success 2005 vs.
2003 (05-03)
3 Yr. Ave.
Development
Success, 05-03
Extensions,
Discoveries,
Improved
Recovery & Net
Revisions, 02-05
3 Yr. Ave. All
Source RRC
($/BOE), 05-03
3 Yr. Ave. All
Source RRC
($/BOE), 04-02
Upstream Capital
Costs Incurred
2005/2002
Cash
Margin/BOE
Pemex
PetroChina
CNOOC
Petrobras
Statoil
51%
49%
53%
46%
69%
92%
98%
100%
97%
100%
Oil-135 MMB
Gas-3,084 Buff
Oil-3,296 MMB
Gas-3,162 Buff
Oil-441 MMB
Gas-1,339 Buff
Oil-3,556 MMB
Gas-3,656 Buff
Oil-656 MMB
Gas-2,973
MMboe-890
MMboe-5,866
MMboe-663
MMboe-4,163
MMboe-1,175
$19.42
$5.90
$7.62
$6.61
$8.66
$41.29
$4.72
$6.24
$3.35
$7.83
192%
217%
237%
194%
191%
176%
519%
465%
508%
423%
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
6 - 26
Economics of the Energy Industries
Company/Metric
3 Yr. All Source
PRC (%), 05-03
Production
Growth (BOE)
2005/2002
Proved Reserve
Growth (BOE)
2005/2001
Upstream
Operating Cash
Flow/Upstream
Capital Expense
Pemex
PetroChina
CNOOC
Petrobras
Statoil
25%
152%
176%
140%
82%
106%
111%
129%
111%
101%
-25%
119%
116%
119%
-6%
35%
235%
206%
369%
181%
Note: Outliers highlighted in yellow.
Findings
•
•
•
•
•
21
22
With the exception of Statoil’s high exploratory success rate, all five companies have had comparable
drilling success in their exploration and development programs. Statoil is exploring in a very mature
area, the Norwegian Continental Shelf (NCS), where the probability of success is relatively high. In
addition, Statoil has 30 years of exploration experience on the NCS: the geology is well understood
and the infrastructure is well developed. The high success rate, however, is offset by smaller sized
discoveries as borne out by Statoil’s relatively smaller reserve additions and its recent inability to
replace production.
With respect to adding oil reserves through the drill-bit (extensions plus discoveries plus improved
recovery, net of revisions), Pemex has had a dismal record especially when compared with similar
companies PetroChina and Petrobras. Excluding revisions, Pemex’s oil reserve additions remain very
low at 310 MMB (million barrels) over the period. Pemex sees three alternatives for increasing oil
reserve additions and production (Chicontepec development, mature field development, and deep
water development) but all three alternatives require new technical solutions, new technical
applications for enhanced recovery, intensive drilling and execution capacity and a high degree of
efficiency.21 However, Pemex has limited access to new technology and best practices in project
management and are calling for “strategic alliances” in deepwater exploration and production.22
Pemex’s gas reserve additions are comparable with those of the other four companies. However, the
poor oil drilling performance has resulted in failure to replace 75 percent of its production since 2002
leading to a 25 percent decrease in proved reserves. Moody’s considers Pemex’s performance on the
RRC and PRC metrics as sub-investment grade (Caa). The other four companies’ performance on the
RRC and PRC metrics is investment grade (Statoil-Baa; PetroChina, Petrobras, CNOOC-A-Aaa).
Mexico is the only country in this group which prohibits non-Pemex entities from participation in the
upstream sector. As a result, Pemex has not had the same access to knowledge transfer from highly
competent foreign companies nor the incentives to improve performance that come from competition.
All five companies have seen their capital costs double since 2002 due to high commodity prices and
increased exploration and development activity. As a result, reserve replacement costs have increased
for every company except Pemex. Pemex’s RRC improved between 2004 ($23.27) and 2005
($19.57) as net oil revisions went from -109 MMB to +197 MMB. However, the absolute level of
Pemex’s RRC is by far the highest of the five, attributable to poor oil drilling performance. Similarly,
Pemex’s cash margin/BOE is much lower than those of the other four companies. This indicates that
Pemex’s level of embedded production and reserve replacement costs is high which impairs its ability
to generate cash for future investment. As a result, upstream sustainability is threatened.
Pemex presentation, October 13, 2006.
Ibid.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
6 - 27
Economics of the Energy Industries
•
•
Statoil’s production is flat over 2002-2005; Mexico’s increased 6 percent showing that Pemex can
produce what it currently has; PetroChina’s production and proved reserves increased 11 percent and
19 percent, respectively, despite the maturity of its major three producing areas and the production
and proved reserve increases of CNOOC and Petrobras reflect the relative immaturity of their reserve
bases.
All companies except Pemex can fund their capital expenditures comfortably from operating cash
flow (Table 14). Pemex needed outside financing to fund about 65 percent of its upstream capital
expenditures in 2004 and 2005. As will be seen in the following section, this results in an extremely
high debt level for Pemex that would be rated sub-investment grade (Caa) if not for “the
extraordinary implicit support of the Mexican government” (Moody’s, 2005).23
Table 14. NOC’s Ability to Produce Hydrocarbons Profitably
Company/Metric
2005 Upstream
Operating
Results/BOE24
Revenue/BOE
Production
Costs/BOE
Prod. Costs &
Exploration Exp.
EBTDA/BOE
DDA/BOE
EBT/BOE
Taxes/BOE
After-tax
income/BOE
Taxes/EBT
After-tax
income/Long
Term Assets
Pemex
PetroChina
CNOOC
Petrobras
Statoil
$41.44
6.93
$38.58
6.11
$42.87
6.24
$41.41
6.46
$41.09
3.34
7.23
7.95
7.45
7.80
4.45
34.20
2.17
32.04
31.90
0.13
30.63
3.04
27.59
7.63
19.96
35.42
4.71
30.71
9.21
21.49
33.61
2.35
31.26
16.50
14.75
36.64
4.93
31.71
24.49
7.21
99%
0.2%
28%
37%
30%
26%
53%%
38%
77%
20%
Findings
•
•
•
Statoil is the most efficient producer of the group; Pemex has the lowest production costs plus
exploration expenses of the other four companies.
Earnings before taxes and depreciation expense/BOE are comparable among the five companies.
Statoil is the best performer, benefiting from its low operating costs. As a producing company,
Pemex is as efficient as PetroChina, CNOOC and Petrobras. It should be noted that the Chinese
companies may have an advantage due to the circumstances of their privatization processes. Many of
the general administrative functions of the companies, including education, health, research and
development and downsizing compensation either remained at the parent holding company level or
were transferred to local governments.
The largest difference among the companies is the tax burden imposed by their governments.
Pemex’s tax regime is punitive at 99 percent of earnings before taxes. It deprives the company of
needed investment capital and contributes to the company’s high leverage position. The lack of
capital becomes a bottleneck for reserve and production growth. Statoil’s tax burden is also high at
77 percent of earnings before taxes and puts it at the lower end of the return on long term assets
23
See Footnote 20.
Authors’ calculations based on information contained in the 2005 Form 20Fs, Notes to Financial Statements,
Supplemental Information on Oil and Gas Producing Activities (FAS 69) filed by the companies in this study.
Available on the company websites and www.sec.gov.
24
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
6 - 28
Economics of the Energy Industries
spectrum. The tax burden may become a problem for Statoil as it extends its operations into frontier
and international areas and its capital needs increase. The Petrobras tax burden is high by U.S.
standards, but the company is showing the best return on long term assets in the group. As an
importing country, China’s tax policies are not onerous as the country wants its NOCs to have the
capital available to grow reserves and production.
Table 15. Consolidated NOC Operating and Financial Performance
Company/Metric
EBITDA/Revenues
EBIT/Net Interest
FFO/Cap. Exp.
Net Income/ATCE
Gross Debt/ATCE
Gross Debt/Proved
Reserves
Pemex
PetroChina
60%
23X
46%
-14%
99%
304%
CNOOC
44%
229X
171%
20%
25%
110%
Petrobras
61%
487X
184%
28%
21%
99%
Statoil
35%
35X
146%
19%
40%
207%
30%
27X
122%
17%
27%
178%
Findings:
•
•
Pemex and CNOOC generate the most cash margin before interest, depreciation and taxes. CNOOC
is not burdened with lower cash margin non-upstream business segments and Pemex’s non-upstream
business segments are not large in relation to the exploration and production segment. The lower
cash margins of PetroChina, Petrobras and Statoil reflect the impact of non-upstream business
segments.
For the reasons discussed above, Pemex’s tax burden renders it unable to fund 54 percent of its
capital requirements from operations and has led to negative returns on average total capital
employed and very high debt levels.
Performance versus 2005 Company Upstream Commercial Goals
Table 16 provides a comparison of NOC performance relative to the companies’ stated or implied
commercial goals.
Table 16. Commercial Goals and Performance
Company and Goals
Pemex
Increase BOE Production
Increase Operating Efficiency
Improve Production Replacement Ratio
Reduce Accident Frequency Rate
Performance
Flat ‘05/’04; Increased 6% 2002-2005
BOE Op. costs increased each year 2002-2005
26% ’05; 23% ’04; 26% ‘03
Decreased 29% from ‘04
PetroChina
Contain Operating Cost Increases
Accelerate Oil Production Growth
Significantly Grow Gas Production
Grow Proved Reserves
20% Inc. 05/04; 9% 04/03; 11% 03/02
1% Inc. 05/04; 1% Inc. 04/04; 5% Inc. 03/02
26% Inc. 05/04; 17% Inc. 04/03; 15% 03/02
Proved reserves increased each year 2001-2005
for a 19% increase over the period
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
6 - 29
Economics of the Energy Industries
Company and Goals
CNOOC
150% Production Replacement
19% Production Increase
Production Costs in Top Quartile Peers
Performance
3 Yr. Ave. 176%
14% ’05; 14% ’03; Flat ‘03
$6.24 versus $5.71 average for other 4
companies
Gross Debt/Total Capital did not exceed 25%
Maintain Capital Discipline
Petrobras
Increase Production and Reserves
Minimum reserve/production life of 15 years
Strengthen deep water expertise
BOE prod. Up 12% ’05 & 11% 2002-2005
15.5 ’05; 17 ’04; 17% ‘03
37 operating wells in depths more than 1,000
meters; drilled 400 wells in depths over 1,000
meters
4% Inc. ’05; 5% ’04; 2% ‘03
BOE Op. Cost at high end of the 5 companies
38% ’05; 31% ’04. High end of group.
Accelerate gas production
Operational excellence
Improve Return on Total Capital
Statoil
Maintain NCS production at 1 MMBOE/D
beyond 2010
Reduce Production Costs
Replace Production
Maintain Proved Reserves
Improve Return on Total Capital
Strict Capital Discipline
Note: Goals achieved are highlighted in yellow
Production flat at 986 MMBOE/D ’04 and ‘05
Production costs flat 2005/2004
PRR 114% 2005
2% Increase in 2005
20% ’05; 15% ’04. Low end of group.
Gross Debt/ATCE down from 30% to 27%
Findings
•
•
•
Petrobras and Statoil had the best performance relative to their stated goals. The two companies also
had the most formalized and robust performance evaluation systems in place.
The Chinese NOCs achieved half of their goals. CNOOC’s performance evaluation system was more
sophisticated than PetroChina’s.
Given the magnitude of its problems, it is not surprising that Pemex had the weakest performance
evaluation process and failed to achieve most of its goals. As discussed previously, this failure is
largely due to the government’s commercial frameworks for the upstream hydrocarbon sector.
Non-commercial Goals and Implications for Performance
The non-commercial goals of NOCs may be the most controversial issue with respect to these companies.
One school of thought contends that the social and economic development objectives of NOCs erodes
their commercial efficiency and makes it less likely that they will successfully deliver the fuels to meet
the world’s energy demand over the next twenty years.25 Many industry observers claim that the social
25
Some researchers contend that NOCs are only 35-65 percent as efficient as the privately held (publicly traded)
international oil majors, a consequence of NOC non-commercial objectives, especially domestic fuel price subsidies.
See The Changing Role of NOCs in International Energy Markets: Introduction and Summary Conclusions,”
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
6 - 30
Economics of the Energy Industries
and economic development objectives outlined in Table 17 are the responsibility of governments and
international aid and development agencies. However, this latter claim ignores the considerable evidence
that governments and aid agencies in developing countries have not been able to effectively address these
issues due to lack of capacity, corruption, poorly designed programs, and so on. In many developing
countries, the NOC has greater resources and management capacity than their host governments.
Table 17. Measuring NOC Contribution to Social and Economic Development
Related Sub-objective/Goal
NOC as “engine” to develop
other economic sectors
Performance Metric
Development of refining,
petrochemical and other related
industries
Capital Formation
NOC fiscal contribution to state as %
of oil/gas revenues;
NOC fiscal contribution to state/BOE
Establishment of research
institutes/training programs;
Awards/Recognition;
Joint ventures with technical experts.
% unemployed; number of employees;
labor expense
Oil % GDP, export revenues, public
budget
Price subsidies; % population served.
Technology
Development/Training
Full Employment
Reduction of State Dependence
on Oil Revenues
Provision of affordable energy
products to citizens
Spending on social and
environmental programs
Dollars spent by NOC and partners;
number and type of programs
Cite
Stevens, 2003;
Taher, 1980;
Grayson, 1981; Mommer,
2002; Saudi Aramco, 2003.
Mommer, 2002;
Boué, 2003;
Saudi Aramco, 2003.
Al-Naimi, 2004;
Zanoyan, 2002;
Alleyne, 1980;
Sastri, 1980.
Megateli, 1980,
Saudi Aramco, 2003.
Zanoyan, 2002.
Megateli, 1980;
UNCNRET, 1980.
Ecopetrol, 2003,
The failures of government and international agencies have prompted a push for increased, not decreased,
private corporate involvement in social and economic development.26 The appropriate types and levels of
this involvement depend on specific country conditions and this subject continues to generate substantial
debate. Over the last fifteen years, however, there seems to be a growing consensus that there is a role for
extractive industries’ corporate involvement in the social and economic issues of the developing countries
where they operate even though the definition of that role is still evolving.
In the future, IOCs may well find that access to a country’s resources may depend on assuming a more
active role in that country’s social and economic development. This could be a fruitful area for NOC/IOC
Presentation, 3/1/07, Baker Institute of Public Policy at Rice University, Houston, Texas. Available at
www.rice.edu\energy.
26
There is considerable literature on this subject including, but not limited to: “Corporate social responsibility and
transnational companies from developing and transition economies,” World Investment Report 2006; Corporate
Social Responsibility and International Development, Michael Hopkins, Earthscan, Sterling, Virginia , 2007; “The
Virtue Matrix: Calculating the Return on Corporate Responsibility,” Roger L. Martin, Harvard Business Review on
Corporate Responsibility, Harvard Business School Press, 2003; Extractive Industries and Sustainable
Development, World Bank , Washington, D.C. 2005; Charles O. Holliday, Jr. et. al., Walking the Talk: The Business
Case for Sustainable Development, Berrett-Koehler, San Francisco, 2002. Also see Graham Davis and John Tilton,
Colorado School of Mines, 2002, Should Developing Countries Renounce Mining? A Perspective on the Debate for
a lucid and rigorous analysis of socioeconomic costs and benefits associated with extractive industry operations.
See http://www.mines.edu/academic/econbus/pdf/Davis/Davis%20and%20Tilton%202002.pdf.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
6 - 31
Economics of the Energy Industries
cooperation. IOC management practices and resources coupled with NOC experience and insights into
these issues could yield a better result for all parties.27 NOCs could act as “strategic bridging”
organizations that aid collaboration between IOCs, governments, non-government agencies and local
communities.28
Table 18 summarizes the contributions of NOCs (and non-NOCs where appropriate) to the social and
economic development of the four countries in our study.
Table 18. NOC Socioeconomic Contributions – Company and Country Levels
Country
Company
Country Prod. MMBOE
NOC Production as % of Total
Mexico
Pemex
1,620
99%
Brazil
Petrobras
699
96%
Norway
Statoil
360
23%
Norway
N Hydro
506
32%
Norway
Total
1,575
55%
China
CNOOC
140
9%
China
PetroChina
1,053
64%
China
Sinopec
317
19%
China
Total
1,639
92%
Upstream Taxes, $MM
Other Taxes
Dividends
Signature Bonuses
NOC Direct Payments
Over-Employment
Price Subsidies (Cost)
Domestic Social Development
Sub-Total
51,205
397
987
0
52,589
WIP
2,458
109
2,567
11,106
0
1,178
214
12,498
WIP
1,440
194
1,634
8,817
0
1,256
0
10,073
WIP
0
0
0
4,463
0
350
0
4,813
WIP
0
0
0
13,280
378
1,606
0
15,264
WIP
0
0
0
1,299
427
636
0
2,362
WIP
0
0
0
8,032
0
5,852
0
13,884
WIP
2,421
2,387
202
1,191
0
3,780
WIP
428
11,718
629
7,679
0
20,026
WIP
2,849
2,421
428
2,849
Total NOC Contribution, $MM
State Direct HC Interests
Total State Contribution
55,156
NA
55,156
14,132
NA
14,132
10,073
4,813
4,813
2,362
NA
2,362
16,305
NA
16,305
4,208
NA
4,208
22,875
10,073
15,264
17,375
32,639
NA
NA
NA
NA
NM
286
NM
286
55,156
34.05
14,418
20.62
Non-NOC Upstream Taxes, $MM
Non-NOC Signature Bonuses
Non-NOC Other Taxes
Total Non-NOC Contribution
Total Sector Contribution, $MM
Total Sector Contribution/BOE Prod
11,610
NA
310
11,920
10,073
4,813
44,559
28.28
NM
11
NM
11
11
11
2,373
16,305
4,208
NM=Not meaningful
NA=Not applicable
27
In five Middle Eastern countries, Valerie Marcel found that NOC professionals “felt that IOCs develop expensive
programs that NOCs and states could carry out more cheaply…..and considered that IOCs, unlike national
institutions, do not understand domestic needs. There is great pride in many NOCs for having hitherto responded to
the needs of the nation.” Further IOC efforts in this regard “must be coordinated with existing programs handled by
the relevant ministries and put in place by the NOCs.” Such IOC/NOC collaboration could help address the trust
issue, e.g. “The crucial issue for NOCs is trust and the lack of it is a serious obstacle to IOC-NOC
partnerships…IOCs should not underestimate the knowledge of NOCs,” Valerie Marcel, Oil Titans: National Oil
Companies in the Middle East, Chatham House, London, 2006, pages 215-217.
28
For a description of strategic bridging see “Building Corporate Citizenship through Strategic Bridging in the Oil
and Gas Industry in Latin America,” Percy Garcia and Harrie Vredenburg, University of Calgary, Canada, JCC 10,
Greenleaf Publishing, Summer 2003.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
6 - 32
22,875
22,886
13.96
Economics of the Energy Industries
Findings
•
•
•
•
The analysis above suggests that a robustly competitive upstream sector like Norway’s produces an
acceptably performing NOC structure with a fiscal contribution to the country, in total and on a BOE
of production basis, which approaches Mexico’s. Norway’s model produces this result in spite of
sovereign control of just over half of Norwegian output, while Norwegian total production nearly
equaled Mexico’s for 2005. (The above analysis does not include additional investment income
generated by oil funds and Norway’s is currently valued at $300 billion.) The crucial difference
between the structures of the hydrocarbon sectors in Mexico and Norway is that the current structure
in Mexico appears to be unsustainable while Norway’s is widely considered to be sustainable.
Increasing non-NOC participation in Brazil and China’s hydrocarbon sectors to levels like that in
Norway could benefit total sector contribution (on a $/BOE basis) to their economies.
The countries with significant domestic fuel price subsidies (Brazil, Mexico and China) are also
importers of refined oil products. The price subsidies charged against their NOCs both encumber
NOC performance and reduce incentives for investment in domestic refining capacity.
Pemex, Petrobras, Statoil and CNOOC provide the most detailed information on their social and
economic development contributions in separate reports available on their web sites. Petrobras,
CNOOC and Statoil provide these contributions outside their home countries as well. Petrobras and
Statoil are acknowledged as industry leaders in this regard.
Commercial Frameworks: Identifying Key Factors Driving NOC Performance
In order to gain deeper insight into how and why NOCs with similar upstream endowments, objectives
and priorities perform differently, we define the independent variables that influence NOC performance
on the metrics previously discussed. The literature on state-owned enterprises in general and on NOCs in
particular suggests that the following factors have significant impact on NOC performance.
Public Sector Governance
• The presence of a well-defined national hydrocarbon policy addressing oil and natural gas issues as
well as the roles for permitted participants in the sector (Bacon, 1999; Khelil, 2002);
• Clearly defined and publicly stated objectives ranked by priority for NOCs (Wong, 2004);
• Clear objectives and management separation among oil and gas policymaking (executive branch
function); regulation (a separate and autonomous executive branch function) and commercial
operations (NOC) ( Khelil, 2002; McPherson, 2003; Zanoyan, 2002; Al-Naimi, 2004; Ecopetrol
2003);
• Non-commercial objectives (including price subsidies) that are publicly disclosed as well as
associated costs and sources of funding. These activities are reported and measured separately from
the NOC’s commercial activities (Wong, 2004);
• The fiscal regime (royalties, taxes, dividends, cost sharing, profit sharing, etc.) is clearly defined for
all sector participants (Al-Naimi, 2004; Ecopetrol, 2003).
Corporate Governance
• Only one government entity is the NOC “owner” and entitled to exercise shareholder rights; other
government agencies interact with the NOC on an arm’s length basis (Wong, 2004);
• The NOC has an independent Board of Directors selected by merit and professional expertise which
approves and oversees the NOC’s business plan, capital budget and strategies (Al-Naimi, 2004;
Wong, 2004);
• Merit and performance guides NOC manpower recruitment, placement and development (Al-Naimi,
2004);
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
6 - 33
Economics of the Energy Industries
•
•
The NOC has an independent financial structure with audited financial results (Al-Naimi, 2004;
McPherson, 2003; Wong, 2004);
The NOC possesses strong internal financial oversight and controls as well as a strong corporate
planning function (Al-Naimi, 2004; Wong, 2004).
Fiscal Regimes
• The fiscal regime for the NOC allows for net cash flow retention adequate to meet its objectives and
plan over a reasonable time horizon (Al-Naimi, 2004; McPherson, 2003);
• The fiscal regime permits the NOC to obtain a credit rating sufficient to attract the appropriate
amount of external financing (Wong, 2004);
• The fiscal regime for non-NOC participants in the upstream sector, if permitted, attracts the level of
investment and operating results established by the government (Sultan, 2003).
Commercialization
• Non-NOC participants are permitted in the upstream sector in order to provide the performance
incentives associated with competition (Bacon, 1999; McPherson, 2003; Wong, 2004);
• Joint ventures and/or other alliances exist between the NOC and third parties domestically and/or
internationally in order to promote efficiency and new technology assimilation (Al-Naimi, 2004;
Zanoyan, 2002; McPherson, 2003);
• The NOC contains profit-oriented business units that are adequately capitalized and accountable for
results (McPherson, 2003).
Regulation
Separate work is being undertaken to assess the key goals and objectives of energy sector regulators and
to determine and evaluate best practices.29 An independent and transparent agency exists to:
• Compel NOCs to adopt practices that would render results similar to those in competitive markets
with respect to prices, access to and quality of energy services (Australia, 1999);
• Assure market transparency, especially the availability of good quality, unbiased data and information
(Foss, 2005);
• Resolve disputes and conflicts and address public concerns about development of and access to oil
and gas resources and infrastructure (Foss, 2005).
Table 18 provides our subjective rankings of commercial framework variables for each NOC and for their
host countries overall.
Table 18. Country Hydrocarbon Sector Commercial Frameworks Evaluation
Company/Commercial
Framework
Public Sector
Governance
Well defined nat’l
hydrocarbon policy
Clear NOC goals
Separation among
policy, regulatory &
commercial functions
Weight
Mexico
China
Brazil
Norway
15%
7.3%
8.85%
10.95%
12.75%
3.75
1.8%
1.8%
1.8%
3.75%
3.75
3.75
1%
1.5%
3.75%
1.8%
3.75%
2.4%
3.75%
3.25%
29
See the separate working paper prepared by Dr. Gürcan Gülen on our research team (not yet published; contact
CEE for more information, [email protected]).
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
6 - 34
Economics of the Energy Industries
Company/Commercial
Framework
Full disclosure of NOC
non-commercial goals
Corporate Governance
Independent BOD
Merit & Performance
Based Personnel
Policies
Audited Financials
Audited Reserves
Strong internal financial
oversight & planning
Fiscal Regimes
Allows for sufficient
capital investment
Permits good credit
rating
Attracts desired level of
non-NOC investments
NOC budget process
predictable and separate
from gov’t
Weight
Mexico
3.75
15%
3.0
3.0
China
3%
Brazil
Norway
1.5%
3%
2%
Pemex
PetroChina/CNOOC
7%
13%
0%
1%
1%
3%
Petrobras
13.3%
1.3%
3%
Statoil
14%
2%
3%
3%
3%
3%
3%
3%
3%
3%
3%
3%
18.5%
6.25%
Brazil
18.5%
6.25%
Norway
23.75%
6.25%
3.0
3.0
3.0
3%
2%
1%
Mexico
25% 6%/18.75%
6.25
2%
China
6.25
3%
6.25%
6.25%
6.25%
6.25
NA
3%
3%
6.25%
6.25
1%
3%
3%
5%
Commercialization
Upstream Competition
NOC/Non-NOC JVs,
alliances
Midstream Competition
Partial Privatization
30%
10.0
5.0
2%
0%
1%
10.7%
2.7%
2%
14%
2%
4%
26%
10%
5%
5.0
10.0
1%
0%
1%
5%
1%
7%
4%
7%
Regulation
Effectively limits NOC
market power upstream
Limits NOC market
power midstream
Provision of good
quality, unbiased data
to all participants
Resolve disputes &
conflicts
OVERALL
15%
4.5
3%/10%
NA
3%
1%
6%
1%
15%
4.5%
4.5
2%
1%
2%
4.5%
3.0
1.5%
.5%
1.5%
3.0%
3.0
1.5%
.5%
1.5%
3.0
100%
28%
54.05%
62.75%
91.5%
Weightings Rationale
Based on the performance evaluations of the five NOCs in our study group and NOC statements in
presentations and other public documents, it appears to us that the commercial frameworks with respect to
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
6 - 35
Economics of the Energy Industries
fiscal regimes and commercialization have the greatest impact on NOC performance. Accordingly, we
have given them greater weight. The remaining weights were assigned based on NOC statements and
other industry analysis.
Findings
Public Sector Governance
•
•
•
•
•
Only Norway has a well-defined hydrocarbon policy addressing all sectors (upstream, mid-stream and
downstream) as well as the roles for permitted participants in the sector. Brazil and China have welldefined policies for the upstream sector but lack a coherent policies for the mid and downstream
natural gas sectors. Mexico has well-defined policies for the mid and downstream sectors but they
don’t fit well with the current upstream sector organization.
The three NOCs with partial private ownership (Statoil, PetroChina, CNOOC and Petrobras) have
clearly defined and publicly stated objectives; disclose performance versus those goals; and have
performance evaluation systems to hold management accountable to those goals. Mexico has
publicly stated goals but lacks the management performance evaluation systems.
In Norway’s upstream, the policy and regulatory functions are the responsibility of the Ministry of
Petroleum and, at times, the Norwegian Congress (the Storting). There is not an independent
upstream regulator. Statoil is responsible for commercial operations. However, Norway has required
Statoil to market the Norwegian’s state’s directly held oil and gas interests together with its own as a
single economic unit. This coordinated marketing strategy means that Statoil may not be able to fully
pursue its own commercial interests as it must ensure “an equitable distribution of the total value
creation between the state and Statoil.” In the midstream, the policy and regulatory functions reside
with the Ministry of Petroleum and Energy and commercial operations reside in a producer-owned
gas pipeline system which is operated by wholly-owned Norwegian state company Gassco SA.
Statoil provides technical operating services to Gassco on a cost basis. Gassco holds no ownership in
the gas pipelines or gas production. The pipeline ownership interests and transportation access of
Statoil and the other producers were not affected. Statoil owns approximately 21% of Norway’s gas
pipeline and terminals system. The Ministry of Petroleum and Energy sets tariffs based on operating
costs and a return on capital to the producers who made the investments. There is no independent
midstream regulator.
In Brazil’s upstream, the policy functions belong to Ministry of Mines and Energy and the regulatory
functions belong to an independent agency, the ANP. Commercial functions are the responsibility of
Petrobras and other exploration and production companies. In the midstream sector, Petrobras
controls the oil and gas pipeline infrastructure. There is independent regulation of the gas pipelines
with respect to access and tariffs.
In China’s upstream, policy functions are decentralized and highly fragmented. As a result, there has
been inadequate development of national institutions responsible for policy and regulations. Even
though upstream governance lies officially with the National Development and Reform Commission,
local governments and the companies themselves frequently assume the policy/regulatory functions.
In addition, the role of the Communist Party in both national institutions and the companies
themselves adds additional opaqueness to an already complicated governance situation.30 Access to
resources for non-NOC upstream participants is the responsibility of the 100 percent state-owned
administrative companies China National Petroleum Corp. and CNOOC. These administrative
companies own varying majority interests in the partially privatized commercial companies
PetroChina Limited and CNOOC Ltd. All of the exploration and production assets and operations are
controlled by the commercial companies. The administrative companies provide some services to the
commercial companies and are responsible for negotiating production sharing agreements with non-
30
Jin Zhang, Catch-up and Competitiveness in China: The case of large firms in the oil industry, London:
Routledge-Curzon, 2004.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
6 - 36
Economics of the Energy Industries
•
•
NOC participants, at times with input from the commercial companies. Once established, the PSAs
are transferred to the commercial companies. In the mid-stream PetroChina controls almost all gas
transportation infrastructure. Similar to the upstream, midstream policy and regulatory functions are
fragmented over a large number of entities, impeding the development of infrastructure and rendering
the sector opaque for non-NOC participants.
In Mexico, upstream policy and regulatory responsibilities are the responsibility of the President and
various Cabinet-level ministries which creates myriad “bosses” and sometimes conflicting mandates
for Pemex. Commercial upstream operations are not clearly separated from the government as Pemex
is a decentralized public entity of the government. In the natural gas midstream, policy belongs to the
energy ministry, Secretaría de Energía or SENER; regulation belongs to CRE (which reports to
SENER) and commercial operations belong to Pemex and other non-NOC participants.
With respect to full disclosure of non-NOC goals, Mexico and Brazil provide the fullest disclosures.
Corporate Governance
• Following is the independent composition of the Board of Directors of Pemex, PetroChina, CNOOC,
Petrobras and Statoil, respectively: 0 percent, 23 percent, 42 percent, and 67 percent.
• Pemex provides its audited reserves one year in arrears, e.g., the 2005 audited reserves will be
provided in 2006.
• According to Pemex, it complies with only 48 percent of the best practices described in the Code of
Best Practices in Corporate Governance of the Mexican Stock Exchange. It has no audit committee
and the BOD does not participate in decisions like management nomination and compensation and
strategic planning.
Fiscal Regimes
• The tax burdens and capital investment resources of the five companies have been discussed
previously.
• All of the companies have investment grade credit ratings. Pemex’s lower score is due to the fact that
it would approach a sub-investment grade rating based on its own metrics. Its investment grade rating
is due to the extraordinary implicit support of the Mexican government.
• The capital budgets of Pemex and Petrobras must be approved by their legislatures. The Storting’s
approval must be obtained for certain Statoil investments. The wholly state-owned parent companies
of the Chinese NOCs must approve their capital investments.
• In China, CNOOC has the right to back in for a 51 percent interest in any commercial discovery made
by a non-NOC upstream participant without paying any portion of the exploration costs. This could
discourage non-NOC investment. In Brazil, Petrobras has used its superior knowledge of Brazil’s
exploratory prospects to either “cherry pick” the best blocks or to negotiate joint ventures with nonNOC participants that favor Petrobras.
Commercialization
• Upstream competition matters. The Norwegian government attributes Statoil’s success and the
overall success of Norway’s hydrocarbons sector to having competent non-NOC participants in the
sector. First, there was an initial strong element of knowledge transfer from foreign oil companies
and supply/service companies. Second, the coordination and competition among commercial players
often yields the best results in activities that include many complicated decisions of a commercial and
technical nature. These elements exist in China and Brazil as well, although to a lesser extent.
• There is no upstream competition in Mexico. In China, PetroChina and CNOOC still control over 70
percent of China’s reserves. In Brazil Petrobras has a 98 percent market share in oil production and
controls over 80 percent of the country’s reserves. In Norway, non-NOC participants account for the
majority of oil and gas production and reserves.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
6 - 37
Economics of the Energy Industries
•
•
•
In Mexico, China and Brazil, the NOCs control over 90 percent of oil and gas mid-stream assets. In
Norway, Statoil’s percentage is lower at 21 percent.
NOC control of midstream assets can discourage investment in the upstream sector if companies
perceive that the NOCs can block third party access or cross-subsidize their marketing and
transportation activities.
The four companies that have non-government shareholders all point to the following benefits from
partial privatization: (1) Opportunity to divest less productive assets; (2) Implementation of
management accountability systems; (3) Opportunity to align compensation systems with
performance; (4) The requirement to have clearly stated goals and strategies with disclosure of
performance; (5) Equity share price and equity analyst coverage allows the company to measure
performance over time and to measure performance against other hydrocarbon companies and
provides incentives for reasonable tax, investment and debt policies.
Regulation
• Understanding the role of hydrocarbon regulation needs further work. Our ratings are subjective
based on anecdotal information and country observation, and more research is required on the
structure and effectiveness of the Chinese system.
NEXT STEPS IN CEE-UT RESEARCH
We have attempted in this working paper to put forth a synopsis of work in progress as well as raise
questions and challenges for how NOCs are viewed today and going forward. Our research agenda going
forward will include the major items outlined below.
•
•
•
•
•
Complete analysis of the fiscal contribution of the hydrocarbons sectors to each of the five countries;
Conduct additional research on regulatory effectiveness in the four countries, especially China;
Evaluate the effectiveness of NOC social and economic development measures as well as the factors
that drive performance in this area;
Make recommendations on the steps the NOCs in our study group can take to improve performance
and better manage social development issues (where applicable);
Analyze the impact of the performance evaluations on NOC/IOC and NOC/NOC collaboration and
identify areas for future collaboration.
CEE is actively exchanging information with certain NOC organizations, and monitoring analysis of
NOC’s by other research groups. We encourage questions and comments on this working paper. The
authors and CEE research team can be contacted at [email protected].
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
6 - 38
Economics of the Energy Industries
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© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
6 - 41
Economics of the Energy Industries
APPENDIX 2
Energy Sector Regulatory Oversight
The following table provides a summary of regulatory oversight responsibilities of various government
agencies (from ministries to independent regulatory bodies) across the oil, natural gas and electric power
value chains in 32 countries. This summary is a snapshot in time and reflects the status in late 2005 and
early 2006. Energy sector regulation is dynamic. We will continue to incorporate changes and add more
countries to this table.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
6 - 42
Energy Sector Regulatory Oversight
National Oil Government
Company
Ownership
Argentina
Energia
Argentina
(Enarsa)
Bolivia
None at
N.A.
present but
proposed
under 5/17/05
Hydrocarbon
s Law. YPFB
Brazil
Petroleo
Brasileiro
(Petrobras)
Colombia
Empresa
Colombiana
de Petroleos
(Ecopetrol)
Minerals
Under
National
Lands
Upstream
Upstream
Licensing
65% Ministry of
N.A.
Economy,
Public Works
and ServicesSecretaria de
Energia
(SdE);
OffshoreEnarsa
YPFB ,
YPFB
Ministry of
Hydrocarbon
s and Energy
(MHE),
Superintende
ncy de
Hidrocarburo
s (SH)
56% Agencia
Nacional do
Petroleo
(ANP)
ANP
ANH
100% Agencia
Nacional de
Hidrocarburo
s (ANH)
NOC
Storage and
Upstream Processing
Participation
Oil
Pipelines,
Tankers,
Barges
Natural Gas Pipelines
Downstream
Refining & Downstream
NOC
Intrastate/Int Interstate/Int
Gas
Oil Product Licensing Downstream raprovincial erprovincial Distribution
Distribution
Participation
Enarsa has Oil-SdE; Gas- SdE
no operating Ente
assets as yet. Nacional
Repsol-YPF Regulador
controls 39% del Gas
(Enargas)
of oil
production
and 33% of
gas
production;
Total Austral
controls 19%
of gas
production.
SdE
Hydrocarbon
s
Superintende
nt
Transition
Transredes
from SH to
Petrobolivia,
a new
regulatory
entity
Petrobras
ANP
remains
responsible
for almost all
oil & gas
production.
ANP
Ecopetrol
controls
about 50% of
total oil
production.
Private
companies
control most
gas
production.
ANH
ANP
MME;
Ministry of
Mines and
Ecopetrol
Energy
(MME)/Ecope
trol
Exports/Imports
Pipelines
LNG
Repsol-YPF Enargas
accounts for
about 50% of
total refining
capacity. Gas
pipelines and
distribution
companies
are privately
owned with
large foreign
participation.
Enargas
Enargas
Oil-SdE; Gas- N.A.
Enargas
Transition
YPFB
from SH to
Petrobolivia,
a new
regulatory
entity
Hydrocarbon Transredes
s
Superintende
nt
Transredes
Transredes
Transredes
ANP
ANP
Petrobras
ANP
controls most
storage,
marine
terminals,
tankers and
pipelines. It
has minority
stakes in 17
gas
distributors.
ANP/MEM &
Min of
Finance (fuel
prices)
ANP
MME;
Ecopetrol
ANH
CREG
Ecopetrol
controls most
refining
assets, oil
and gas
pipelines and
oil and gas
marketing
and
distribution
activities.
ANH
CREG
N.A.
Price Controls/Subsidies
Oil
Gas
Oil Products Natural gas
prices for
residential
users are
controlled.
Electricity
Generation Transmissio
IntraInterDistribution Tariffs/Subsi Exports/Imp
n:
provincial or provincial or
dies
orts
intrastate
interstate
Power
Compania
Compania
Compania
The
Prices set by n/a
generates sell Nacional de Nacional de Nacional de distribution
the market.
Price cap
their
Transporte
Transporte
Transporte
sector is
electricity in a Energetica en Energetica en Energetica en more heavily system to
wholesale
Alta Tension Alta Tension Alta Tension regulated and encourage
market
efficiency in
(Transener) (Transener) (Transener) less
operated by owns and
owns and
owns and
competitive, distribution,
the
operates the operates the operates the with three
wheeling and
Compania
national
national
national
primary
transmission.
Administrador electricity
electricity
electricity
distribution
Reduction in
a del
transmission transmission transmission companies
subsidies.
Mercado
grid under a grid under a grid under a (Edenor,
Mayorista
long-term
long-term
long-term
Edesur and
Electrico
agreement
agreement
agreement
Edelap)
(CAMMESA). with the
with the
with the
controlling the
market.
Argentine
Argentine
Argentine
government. government. government.
MHE/SH/Petr MHE/SH/Petr MHE/SH/Petr
obolivia?
obolivia?
obolivia
Gasoline,
diesel
Unbundled.
Superintende
nt of
Electricity
(SE)
State Energy ANP
Secretariats
ANP
None
Dominated by Operado
state-owned Nacional do
entities;
Sistema
Agência
Electrica
Nacional de (ONS)
Energia
Elétrica ANEEL
CREG
N.A.
Gasoline,
diesel
N.A.
On some gas
sold for
electric
generation
and domestic
gas-MME
Unbundled.
Superintende
nt of
Electricity
(SE)
Unbundled.
Superintende
nt of
Electricity
(SE)
Unbundled.
Superintende
nt of
Electricity
(SE)
Unbundled.
Superintende
nt of
Electricity
(SE)
Cross
subsidies still
exist but are
expected to
be eliminated
Unbundled.
Superintende
nt of
Electricity
(SE)
Agência
Nacional de
Energia
Elétrica ANEEL
Agência
Nacional de
Energia
Elétrica ANEEL
Agência
Nacional de
Energia
Elétrica ANEEL
Yes
Agência
Nacional de
Energia
Elétrica ANEEL
Restructured; Restructured; Restructured; Restructured; Restructured; Elimination of Restructured;
CREG
CREG
CREG
CREG
CREG
CREG
cross
subsidies by
2002.
Subsidies will
be applied to
low-income
residential
customers
and will be
granted
entirely by the
government
Ecuador
Petroecuador
100% Special
Ministry
Committee
for Biddings
(CEL),
Petroecuador
Petroecuador MEM
controls
about 50% of
oil production.
Ministry/Petro
ecuador
MEM
Peru
PetroPeru
100% PeruPetro
PetroPeru
None
?
Trinidad &
Tobago
N.A.
The Ministry
of Energy
and Energy
Industries
The Ministry
of Energy
and Energy
Industries
The Ministry
of Energy
and Energy
Industries
Venezuela
Petroleos de
Venezuela
(PdVSA)
Canada
None
Mexico
Pemex
N.A.
The Ministry
of Energy
and Energy
Industries
100% Ministry of
Energy and
Oil (MEO)
N.A.
N.A. (Federal EUBs
agencies are
coordinating
with provincial
governments
for Eastern
Canada
offshore
projects)
100% Petroleos
Mexicanos or
PEMEX (selfregulated)
with a
committee of
ministries,
including
Secretaría de
Energía or
SENER
(chair) and
Hacienda
(finance);
Presidential
authority for
planning
Petroecuador N.A.
controls all
downstream
activities with
the exception
of one oil
pipeline.
Ministry
N.A.
N.A.
MEM
N.A.
Gasoline,
diesel
MEM/PetroP MEM/PetroP PetroPeru
eru
eru
N.A.
PetroPeru
controls the
only crude oil
pipeline, most
of the
refineries and
a majority of
the retail oil
products
market.
N.A.
N.A.
MEM
MEM?
None
The Ministry
of Energy
and Energy
Industries
The Ministry
of Energy
and Energy
Industries
The Ministry
of Energy
and Energy
Industries
The Ministry
of Energy
and Energy
Industries
The Ministry
of Energy
and Energy
Industries
The Ministry
of Energy
and Energy
Industries
The Ministry
of Energy
and Energy
Industries
The Ministry Gasoline,
of Energy
diesel
and Energy
Industries
MEO
MEO
Ministry/Gove Excluding the MEO/Ente
MEO/Enagas MEO/Enagas MEO
Nacional del
rnment
heavy oil
Gas (Enagas)
upgraders,
PdVSA
controls all
Venezuelan
refining. It
also controls
oil and gas
transportation
and
distribution
networks.
Ministry/Gove
rnment
MEO
Province
ministries
Province
ministries
Province
ministries
EUBs
NEB and
EUBs
Pemex
Pemex
Pemex
Pemex but
Ministry/Cong Comisión
CRE
Ministry/Cong ress
Reguladora
ress is final
de Energía
authority
(CRE),
except where
excluded
MEO
Struggle btw PdVSA
Ministry and controls
PdVSA
about twothirds of total
oil production
and over 90%
of gas
production.
Struggle btw
Ministry and
PdVSA
None
Pemex but
Pemex
Ministry/Cong
ress is final
authority
MEM
Ministry
None
The Ministry
of Energy
and Energy
Industries
EUBs, NEB
National
Energy
Board,
Canada
(NEB)
EUBs
NEB for
pipelines;
CRE
PEMEX with CRE
CRE
regulation for
first hand
sales
Restructuring. Restructuring. Restructuring. Restructuring. Restructuring. Electricity
Restructuring.
CONELEC, CONELEC, CONELEC, CONELEC, CONELEC, prices for end-CONELEC,
in charge of in charge of in charge of in charge of in charge of users barely in charge of
enforcing
enforcing
enforcing
enforcing
enforcing
cover 50% of enforcing
regulation.
regulation.
regulation.
regulation.
regulation.
costs.
regulation.
CENACE, in
charge of the
administration
of the
wholesale
electricity
market.
None
OSINERG, in
charge of
enforcing
regulation
OSINERG, in
charge of
enforcing
regulation;
COES, which
is the
independent
system
operator
OSINERG, in
charge of
enforcing
regulation
OSINERG, in
charge of
enforcing
regulation
OSINERG, in
charge of
enforcing
regulation
None. CTE,
in charge of
setting
electricity
prices
N.A.
Trinidad &
Tobago
Electricity
Commission
Trinidad &
Tobago
Electricity
Commission
Trinidad &
Tobago
Electricity
Commission
Trinidad &
Tobago
Electricity
Commission
Trinidad &
Tobago
Electricity
Commission
Rates and
n/a
Tariffs are set
by the
Regulated
Industries
Commission
(the RIC)
Oil Products Natural gas
prices for
residential
users are
controlled.
Oficina de
Operacion de
Sistema
Interconectad
os (OPSIS)
Oficina de
Oficina de
Oficina de
Oficina de
Operacion de Operacion de Operacion de Operacion de
Sistema
Sistema
Sistema
Sistema
Interconectad Interconectad Interconectad Interconectad
os (OPSIS) is os (OPSIS) is os (OPSIS) is os (OPSIS)
responsible responsible responsible
for managing for managing for managing
and operating and operating and operating
national
national
national
transmission transmission transmission
grid.
grid.
grid.
None
None
EUBs (for
utilities only).
Provinceowned utility
companies
dominate
generation,
transmission,
and
distribution
activities.
Provinceowned utility
companies
dominate
generation,
transmission,
and
distribution
activities.
Gasoline,
diesel
Price cap
N.A.
CFE (selfregulated)
with a
committee of
ministries,
including
SENER
(chair) and
Hacienda
(finance), and
Presidential
authority for
planning;
CRE (new
plants with
private
participation
only)
EUBs;
reliability
councils.
Provinceowned utility
companies
dominate
generation,
transmission,
and
distribution
activities.
NEB;
participation
in reliability
councils.
Provinceowned utility
companies
dominate
generation,
transmission,
and
distribution
activities.
CFE
CFE and Luz CFE
y Fuerza del
Centro or
LFC, in
Mexico City
(D.F.)
OSINERG, in
charge of
enforcing
regulation
Last price
Oficina de
adjustments Operacion de
in 1999 and Sistema
2000 were
Interconectad
oriented to
os (OPSIS)
reduce cross
subsidies and
to reflect the
cost of the
service, but
electricity
prices are still
controlled by
the
government.
EUBs.
Price caps on EUBs
Provinceresidential
owned utility utility rates.
companies
dominate
generation,
transmission,
and
distribution
activities.
Subsidies to CFE
domestic and
agricultural
rate payers.
One of the
utilities has
profits after
recovering
subsidies
from the
federal
government.
The other has
losses.
United
States
None
N.A.
Federal
agencies with
specific
authority
Onshore –
Bureau of
Land
Management,
2 Forest
Service3
Offshore –
Minerals
Management
Service2
Algeria
Sonatrach
100% Sonatrach,
HRA
ALNAFT
(Sonatrach
presently)
ALNAFT
(Sonatrach
presently)
Angola
Sonangol
100% Sonangol
MINPET
(Ministry of
Petroleum)/S
onangol
Egypt
EGPC
100% Egyptian
Ministry of
Petroleum
EGPC
Libya
LNOC
100% LNOC
Nigeria
NNPC
Iran
NIOC
None
None
State public
utility
commissions
(PUCs)
Federal
PUCs
Energy
Regulatory
Commission
(FERC)
State-owned Sonatrach
Sonelgaz retail;
Sonatrach
controls
wholesale
distribution
Sonatrach
Sonatrach,
HRA
Naftec, a
subsidiary of
Sonatrach;
HRA
Hydrocarbon
s regulation
Authority
(Sonatrach
presently)
Hydrocarbon Sonatrach
s regulation
Authority
(Sonatrach
presently)
MINPET
Sonangol
(Ministry of
Petroleum)/S
onangol
Sonangol
Sonangol
MINPET
(Ministry of
Petroleum)/S
onangol
MINPET
The Ministry The Ministry The Ministry The Ministry Sonangol
(Ministry of
of Industry
of Industry
of Industry
of Industry
Petroleum)/S
onangol
EGPC
Egyptian
Ministry of
Petroleum
Egyptian
Ministry of
Petroleum
Egyptian
Ministry of
Petroleum
EGPC
EGPC
Secretariat of LNOC
Energy,
LNOC
LNOC
LNOC
LNOC
Secretariat of LNOC
Energy,
LNOC
100% NNPC
Ministry =
NNPC
Ministry =
NNPC
NNPC
Pipelines and
Products
Marketing
Company
(PPMC)
NNPC's
Ministry =
Pipelines and NNPC
Products
Marketing
Company
(PPMC)
100% Ministry of
Petroleum
Ministry =
NIOC
Ministry =
NIOC
Ministry of
Ministry of
Petroleum
Petroleum
(MoP), NIOC (MoP),
National
Iranian Oil
Refining and
Distribution
Company
(NIORDC),
NIOC,
National
Iranian
Tanker
Company
(NITC)
Ministry of
Ministry =
Petroleum
NIOC
(MoP),
National
Iranian Oil
Refining and
Distribution
Company
(NIORDC),
NIOC
Sonatrach,
HRA
Sonatrach
FERC for
FERC,
None
infrastructure; MARAD,
U.S.
Coast Guard,
Department U.S.
of Energy
Department
(DOE)
of Energy
(DOE)
PUCs (for
utilities only)
PUCs;
reliability
councils4
FERC;
participation
in reliability
councils
PUCs
None
FERC/DOE
(Presidential
certificate for
DC ties)
Gasoline,
diesel
Yes
State-owned State-owned State-owned State-owned State-owned Electricity and Algerian
Sonelgaz - to Sonelgaz - to Sonelgaz - to Sonelgaz
Gas
Energy
Sonelgaz,
be devided
be devided
be devided
(formally
Company
Electricity and Regulatory
into separate into separate into separate JSC);
Commission (AEC) - JV of
Gas
transmission, transmission, transmission, Electricity and Regulatory
(CREG)
Sonelgaz and
distribution
Sonothrach;
distribution
distribution
Gas
Commission
andgeneratio andgeneratio andgeneratio Regulatory
Electricity and
(CREG)
n
n
n
Commission
Gas
commpanies commpanies commpanies (CREG)
Regulatory
in 2006;
in 2006;
in 2006;
Commission
Electricity and Electricity and Electricity and
(CREG)
Gas
Gas
Gas
Regulatory
Regulatory
Regulatory
Commission Commission Commission
(CREG)
(CREG)
(CREG)
Gasoline,
diesel
n/a
Directorate
Nacional
Electricidade
(DNE);
Instituto
Regulador de
Sector
Eléctrico
(IRSE)
Directorate
Nacional
Electricidade
(DNE);
Instituto
Regulador de
Sector
Eléctrico
(IRSE)
Directorate
Nacional
Electricidade
(DNE);Institut
o
Regulador de
Sector
Eléctrico
(IRSE)
Directorate
Nacional
Electricidade
(DNE);Institut
o
Regulador de
Sector
Eléctrico
(IRSE)
Directorate
The Ministry
Nacional
of Finance
Electricidade
(DNE);Institut
o
Regulador de
Sector
Eléctrico
(IRSE)
Directorate
Nacional
Electricidade
(DNE);Institut
o
Regulador de
Sector
Eléctrico
(IRSE)
Egyptian
Natural Gas
Holding
Company
(EGAS)
Egyptian
Natural Gas
Holding
Company
(EGAS)
Egyptian
Natural Gas
Holding
Company
(EGAS)
Egyptian
Natural Gas
Holding
Company
(EGAS)
Egyptian
Natural Gas
Holding
Company
(EGAS)
Gasoline,
diesel
Ceiling and
floor prices
Egyptian
Electricity
Authority
(EEA)
Egyptian
Electricity
Holding
Company
(EGELEC)
Egyptian
Electricity
Holding
Company
(EGELEC)
Egyptian
Electricity
Holding
Company
(EGELEC)
Egyptian
Electricity
Holding
Company
(EGELEC)
Egyptian
Electricity
Holding
Company
(EGELEC)
Egyptian
Electricity
Holding
Company
(EGELEC)
LNOC
LNOC
LNOC
LNOC
LNOC
Gasoline,
diesel
Yes
State-owned
General
Electricity
Company
(GECOL)
State-owned
General
Electricity
Company
(GECOL)
State-owned
General
Electricity
Company
(GECOL)
State-owned
General
Electricity
Company
(GECOL)
State-owned
General
Electricity
Company
(GECOL)
State-owned
General
Electricity
Company
(GECOL)
State-owned
General
Electricity
Company
(GECOL)
Ministry =
NNPC
NNPC's
Pipelines and
Products
Marketing
Company
(PPMC)
NNPC's
Pipelines and
Products
Marketing
Company
(PPMC)
NNPC's
Pipelines and
Products
Marketing
Company
(PPMC)
NNPC's
Pipelines and
Products
Marketing
Company
(PPMC)
NNPC holds Gasoline,
49% in the
diesel
Nigeria
Liquefied
Natural Gas
(NLNG)
Company
Yes
Power
Power
Power
Power
Power
Yes- planned
Company
Company
Company
Company
Company
to be
Holding of
Holding of
Holding of
Holding of
eliminated
Holding of
Nigeria
Nigeria
Nigeria
Nigeria
Nigeria
(PHCN).
(PHCN).
(PHCN).
(PHCN).
(PHCN).
Privatization Privatization Privatization Privatization Privatization
and functional and functional and functional and functional and functional
division is
division is
division is
division is
division is
planned for planned for planned for planned for planned for
2006
2006
2006
2006
2006
Power
Company
Holding of
Nigeria
(PHCN).
Privatization
and functional
division is
planned for
2006
Ministry =
NIOC
Ministry of
Petroleum
(MoP),
National
Iranian Gas
Company
(NIGC)
Ministry of
Petroleum
(MoP),
National
Iranian Gas
Company
(NIGC)
Ministry of
Petroleum
(MoP)
National
Iranian Gas
Export Co.
(NIGEC)
National
Iranian Gas
Export Co.
(NIGEC)
Yes
Statecontrolled
Tavanir
Statecontrolled
Tavanir
Gasoline,
diesel
Statecontrolled
Tavanir
Statecontrolled
Tavanir
Statecontrolled
Tavanir
Statecontrolled
Tavanir
Yes
Iraq
INOC
100% Oil Ministry
SOGC,
Ministry=
INOC
Oil Ministry
Oil Ministry
State Oil
Ministry
Marketing
Organization
(SOMO)
Kuwait
KPC
100% KPC
SPC,
SPC,
Kuwait
Ministry, KPC Ministry, KPC National
Petroleum
Company
(KNPC) KPC
subsidiary;
Kuwait
National
Petroleum
Company
(KNPC) KPC
subsidiary;
Kuwait Oil
Tanker
Corporation
(KOTC)
Kuwait
National
Petroleum
Company
(KNPC) KPC
subsidiary
Oman
OOC
100% OPD
Ministry =
OOC
Ministry =
OOC
Ministry =
OOC
State-owned Ministry =
OOC
Oman
Refinery
Company
(ORC)
Qatar
Qatar
Petroleum
100% Qatar
Petroleum
Ministry, QP QP
Qatar
Petroleum
Qatar
Petroleum
QP Refinery Ministry, QP QP
Qatar
Petroleum
Qatar
Petroleum
Qatar
Petroleum
Qatar
Petroleum
100% SCPM,
Ministry
SCPM,
Ministry
SEC, SCPM, Saudi
Saudi
Aramco
Aramco
Aramco's
shipping
subsidiary
Vela
Saudi
Aramco
SCPM,
Samarec,
Petramin
Saudi
Aramco
Saudi
Aramco
Saudi
Aramco
Saudi
Aramco
Saudi Arabia Saudi
Aramco
Ministry=
INOC
Ministry =
OOC
Ministry
North Gas
Company
(NGC) and
South Gas
Company
(SGC)
SPC,
SPC,
Kuwait Oil
Ministry, KPC Ministry, KPC Company
(KOC) - KPC
subsidiary
SCPM,
Ministry
Ministry =
OOC
North Gas
Company
(NGC) and
South Gas
Company
(SGC)
North Gas
Company
(NGC) and
South Gas
Company
(SGC)
North Gas
Company
(NGC) and
South Gas
Company
(SGC)
N.A.
Gasoline,
diesel
Yes
Electricity
Ministry
Electricity
Ministry
Kuwait Oil
Company
(KOC) - KPC
subsidiary
Kuwait Oil
Company
(KOC) - KPC
subsidiary
Kuwait Oil
Company
(KOC) - KPC
subsidiary
Kuwait Oil
Gasoline,
Company
diesel
(KOC) - KPC
subsidiary
Yes
Energy
Ministry
Energy
Ministry
Yes
The Ministry
of Electricity
and Water
(MEW)/Trans
mission and
Distribution
Company
(TRANSCO)
when
established
The Ministry
of Electricity
and Water
(MEW)/Trans
mission and
Distribution
Company
(TRANSCO)
when
established
Qatar
Gasoline,
Petroleum as diesel
Joint
Ventures'
participant
Qatar
Petroleum
Qatar
Qatar
Qatar
Qatar
Qatar
Payment
General
General
General
General
General
required for
Electricity and Electricity and Electricity and Electricity and Electricity and consumption
Water
Water
Water
Water
Water
above a set
Corporation Corporation Corporation Corporation Corporation threshold
(QEWC) (QEWC) (QEWC) (QEWC) (QEWC) since 1999
43%
43%
43%
43%
43%
controlled by controlled by controlled by controlled by controlled by
the
the
the
the
the
government government government government government
N.A.
Gasoline,
diesel by
Royal
Decrees
Yes
Industry and
Electricity
Ministry;
Electricity
Services
Regulatory
Authority
(ESRA) independent
agency
Industry and
Electricity
Ministry;
Electricity
Services
Regulatory
Authority
(ESRA) independent
agency
Industry and
Electricity
Ministry;
Electricity
Services
Regulatory
Authority
(ESRA) independent
agency
Industry and
Electricity
Ministry;
Electricity
Services
Regulatory
Authority
(ESRA) independent
agency
Industry and Yes
Electricity
Ministry;
Electricity
Services
Regulatory
Authority
(ESRA) independent
agency
Industry and
Electricity
Ministry;
Electricity
Services
Regulatory
Authority
(ESRA) independent
agency
Ministry of
Electricity
State-owned State-owned State-owned State-owned Ministry =
OOC
Oman Gas
Oman Gas
Oman Gas
Oman Gas
Company
Company
Company
Company
(OGC).
(OGC).
(OGC).
(OGC).
Canada's
Canada's
Canada's
Canada's
Enbridge and Enbridge and Enbridge and Enbridge and
Terasen won Terasen won Terasen won Terasen won
a contract to a contract to a contract to a contract to
operate the operate the operate the operate the
country's
country's
country's
country's
natural gas natural gas natural gas natural gas
transportation transportation transportation transportation
and
and
and
and
distribution
distribution
distribution
distribution
infrastructure infrastructure infrastructure infrastructure
till mid-2006, till mid-2006, till mid-2006, till mid-2006,
after which
after which
after which
after which
OGC will
OGC will
OGC will
OGC will
regain
regain
regain
regain
operating
operating
operating
operating
control
control
control
control
Gasoline,
diesel
Electricity
Ministry
Electricity
Ministry
Yes
Energy
Ministry
Energy
Ministry
Energy
Ministry
Yes - lowest Energy
prices for
Ministry
power in the
world
The Ministry
of Electricity
and Water
(MEW)/Trans
mission and
Distribution
Company
(TRANSCO)
when
established
The Ministry
of Electricity
and Water
(MEW)/Trans
mission and
Distribution
Company
(TRANSCO)
when
established
The Ministry
of Electricity
and Water
(MEW)/Trans
mission and
Distribution
Company
(TRANSCO)
when
established
The Ministry n/a
of Electricity
and Water
(MEW)
Syria
SPC
100% Oil and
Mineral
Resources
Ministry
Oil and
Mineral
Resources
Ministry, SPC
Oil and
Mineral
Resources
Ministry, SPC
State-owned
Syrian
Company for
Oil Transport
State-owned
Syrian
Company for
Oil Transport
SPC
Syrian
Company for
the Storage
and
Distribution of
Oil Products
(SADCOP)
SPC
Syrian Gas
Company
Syrian Gas
Company
Syrian
Company for
Gas
Distribution
Syrian Gas N.A.
Company,
Syrian
Company for
Gas
Distribution
Gasoline,
diesel
Yes
Ministry of
Electricity
Ministry of
Electricity
Ministry of
Electricity
Ministry of
Electricity
Ministry of
Electricity
UAE
ADNOC
100% N.A.
SPC
SPC,
ADNOC
Abu Dhabi
National Oil
Company
(ADNOC),
Emirates
National Oil
Company
(ENOC)
Abu Dhabi
National Oil
Company
(ADNOC),
Emirates
National Oil
Company
(ENOC)
Abu Dhabi
National Oil
Company
(ADNOC),
Emirates
National Oil
Company
(ENOC) +
private
SPC,
ADNOC
SPC,
ADNOC
UAE Offsets
Group
(UOG),
ADNOC
UAE Offsets
Group
(UOG),
ADNOC
UAE Offsets
Group
(UOG),
ADNOC
UAE Offsets N.A.
Group
(UOG),
ADNOC
Gasoline,
diesel
Yes
Abu Dhabi
Water and
Electricity
Authority
(ADWEA)
Abu Dhabi
Water and
Electricity
Authority
(ADWEA)
Abu Dhabi
Water and
Electricity
Authority
(ADWEA)
Abu Dhabi
Water and
Electricity
Authority
(ADWEA)
Abu Dhabi
Water and
Electricity
Authority
(ADWEA)
Azerbaijan
Socar
100% Socar
Ministries,
SOCAR
Ministries,
SOCAR
Socar
Socar
Socar
Ministries,
SOCAR
SOCAR
AzeriGaz
AzeriGaz
AzeriGaz
AzeriGaz
Oil products
Azerigaz
Azerenerji
Azerenerji
Azerenerji
Azerenerji
Azerenerji
n/a
Yes
Electricity
Ministry
Qatar
General
Electricity and
Water
Corporation
(QEWC) 43%
controlled by
the
government
Abu Dhabi
Water and
Electricity
Authority
(ADWEA)
Kazakhstan Kazmunaigaz
100% Ministry of
Energy and
Natural
Resources
Ministry of
Energy and
Natural
Resources
Ministry,
Ministry of
Kazmunaigaz Energy and
Natural
Resources
KazTransOil Ministry of
Energy and
Natural
Resources
Ministry,
Kazmunaigaz Kazmunaigaz Kazmunaigaz Kazmunaigaz Kazmunaigaz n/a
Kazmunaigaz
Agency of the Agency of the Ministry of
Republic of Republic of Energy and
Kazakhstan Kazakhstan Natural
for
for
Resources
Regulation of Regulation of
Natural
Natural
Monopolies, Monopolies,
Protection
Protection
of Competitio of Competitio
n (ANMR). n (ANMR
Oil products
Kazakhstan
Electricity
Grid
Operating
Company
(KEGOC)
Kazakhstan
Electricity
Grid
Operating
Company
(KEGOC)
Kazakhstan
Electricity
Grid
Operating
Company
(KEGOC)
Kazakhstan
Electricity
Grid
Operating
Company
(KEGOC)
Agency of the Ministry of
Republic of Energy and
Kazakhstan Natural
for
Resources
Regulation of
Natural
Monopolies,
Protection
of Competitio
n (ANMR
Federal Tariff Unified
Service of the Energy
Russian
System of
Federation
Russia (UES)
(FTS)
Russia
Rosneft
100%
Ministry of
(Rosneft only) Energy
IPO is
planned in
2006
Multiple
Multiple
Ministry of
Ministries and Ministries and Energy
Agencies
Agencies
Pipelines Ministry of
Transneft Energy
100%
government
owned;
various
ministries and
agencies
Multiple
Multiple
Gazprom
Ministries and Ministries and
Agencies
Agencies,
Transneft,
Gazprom
Gazprom
Gazprom
Gazprom
Gazprom
Federal Tariff Federal Tariff Unified
Service of the Service of the Energy
Russian
Russian
System of
Federation
Federation
Russia (UES)
(FTS). Oil
(FTS)
products
Unified
Energy
System of
Russia (UES)
Unified
Energy
System of
Russia (UES)
Unified
Energy
System of
Russia (UES)
Unified
Energy
System of
Russia (UES)
China
CNPC,
CNOOC,
Sinopec,
Petrochina
CNPC –
100%
CNOOC –
71%,
Sinopec –
55%,
Petrochina –
90%
State
State
State Energy
Administratio Administratio Administratio
n of
n of
n (SEA),
Petroleum
Petroleum
Sinopec
and Chemical and Chemical
Industries;
Industries;
State Energy State Energy
Administratio Administratio
n (SEA)
n (SEA)
State Energy
Administratio
n (SEA),
PetroChina 79%
State Energy
Administratio
n (SEA),
Sinopec
State
Petrochina State
Administratio Administratio 95%
n of
n of
Petroleum
Petroleum
and Chemical and Chemical
Industries;
Industries;
State Energy State Energy
Administratio Administratio
n (SEA)
n (SEA)
Petrochina
Petrochina
Petrochina
n/a
State Energy
Administratio
n (SEA). Oil
products
Set by
distributors,
must be
approved by
the
government.
State
Electricity
Regulatory
Commission
of
China
(SERC).
State Grid
Corporation
of China
(SG), China
Southern
Power Grid
Co Ltd
State
Electricity
Regulatory
Commission
of
China
(SERC)
State
Electricity
Regulatory
Commission
of
China
(SERC)
State
Yes
Electricity
Regulatory
Commission
of
China
(SERC)
State
Electricity
Regulatory
Commission
of
China
(SERC)
India
Oil India
ONGC –
n/a
Limited (OIL) 84%,
IOC – 100%
OIL- 100%
MoPNG/DGH MoPNG/Petr
Directorate
oleum
General of
Regulatory
Hydrocarbon
Board when
s (under
Ministry of
established
Petroleum
and Natural
Gas)
MoPNG/Petr
oleum
Regulatory
Board when
established
MoPNG/Petr MoPNG/DGH MoPNG/DGH GAIL/Petrole
um
oleum
Regulatory
Regulatory
Board when
Board when
established
established
GAIL/Petrole Petroleum
um
Regulatory
Regulatory
Board when
Board when established
established.
The draft
natural gas
pipeline policy
covering
transmission
pipelines and
local or city
gas
distribution
networks is
under
formulation
OGL/Petroleu OGL/Petroleu Oficially MoPNG/Tarif Ministry of
Ministry of
m Regulatory m Regulatory none since
f Commission Power/State Power/State
Board when Board when 2002, but
electricity
electricity
established established substantial
boards
boards
government
(SEB's)/unbu (SEB's)/unbu
control on the
ndling of SEB ndling of SEB
sector
assets into
assets into
prevails.
generation, generation,
Tariff
transmission, transmission,
Commission
and
and
distribution
distribution
companies, companies,
and the
and the
eventual
eventual
privatization privatization
of these
of these
assets
assets
Ministry of
Power/State
electricity
boards
(SEB's)/unbu
ndling of SEB
assets into
generation,
transmission,
and
distribution
companies,
and the
eventual
privatization
of these
assets
Ministry of
Power/State
electricity
boards
(SEB's)/unbu
ndling of SEB
assets into
generation,
transmission,
and
distribution
companies,
and the
eventual
privatization
of these
assets
Ministry of
Yes
Power/State
electricity
boards
(SEB's)/unbu
ndling of SEB
assets into
generation,
transmission,
and
distribution
companies,
and the
eventual
privatization
of these
assets
Ministry of
Power
Indonesia
Pertamina
BPMIGAS/Mi BPMIGAS
nistry
BP Migas
Pertamina
Perum Gas
Negara
(PGN)
Perum Gas
Negara
(PGN)
Ministry of
Land and
Resources
(MLR)
100% Ministry
BP Migas
BATUR/Minis BATUR
try
Perum Gas
Negara
(PGN)
Perum Gas
Negara
(PGN)
Perum Gas
Negara
(PGN)
Gasoline,
diesel
State
Yes. Local
regulations. Electricity
The Chinese Regulatory
government Commission
is in the
of
process of
China
drafting a
(SERC). Five
National
new legal
framework
Generation
for the natural Groups:
gas sector
Huaneng
Group
Datang
Group
Huadian
Group
Guodian
Group
China Power
Investment
Corporation
(CPI)
Yes
State-utility State-utility State-utility State-utility State-utility Yes. StatePerusahaan Perusahaan Perusahaan Perusahaan Perusahaan owned PLN
Listrik Negara Listrik Negara Listrik Negara Listrik Negara Listrik Negara receives
(PLN)
(PLN)
(PLN)
(PLN)
(PLN)
direct
subsidies
from the
government
State-utility
Perusahaan
Listrik Negara
(PLN)
Malaysia
Petronas
Norway
Statoil
100% Petronas
>50%
NPD
Petronas
Petronas
Petronas
Petronas
Petronas
Ministry
NPD
NPD
Most
NPD
pipelines are
operated by
44% stateowned Norsk
Hydro. NPD
Ministry of
International
Trade and
Industry
PM’s
Economic
Planning Unit
(gas prices);
Ministry of
Domestic
Trade &
Consumer
Affairs
(product
prices)
Ministry (?)
Ministry/NPD State-owned State-owned State-owned State-owned Ministry
Gassco
Gassco
Gassco
Gassled
Petronas Gas Petronas Gas Petronas Gas Petronas Gas Petronas
Bhd.;
Bhd.;
Bhd.;
Bhd.;
Department Department Department Department
of Electricity of Electricity of Electricity of Electricity
and Gas
and Gas
and Gas
and Gas
Supply
Supply
Supply
Supply
Gasoline,
diesel
Yes
Three state- Three state- Three state- Three state- Three state- Yes. Natural
owned utilities owned utilities owned utilities owned utilities owned utilities gas is
dominate
dominate
dominate
dominate
dominate
provided at
power
power
power
power
power
25% of the
generation
generation
generation
generation
generation
commercial
and
and
and
and
and
price to the
distribution; distribution; distribution; distribution; distribution; power sector
Department Department Department Department Department
of Electricity of Electricity of Electricity of Electricity of Electricity
and Gas
and Gas
and Gas
and Gas
and Gas
Supply
Supply
Supply
Supply
Supply
Department
of Electricity
and Gas
Supply
None
None
Water
State-owned State-owned State-owned Water
No
Resources & Statnett
Statnett
Statnett
Resources &
Energy
Energy
Directorate
Directorate
Water
Resources &
Energy
Directorate;
Economics of the Energy Industries
CHAPTER 7 - PROJECT EVALUATION AND CAPITAL BUDGETING
The Time Value of Money
An Example
Most of the time, a company does not have necessary resources to undertake all the projects with positive
cash inflow. This is especially the case in the oil and gas business where risks and initial investment are
usually quite high. Companies are often in a position to evaluate different investment opportunities in
order to choose the one(s) that would yield the highest return. Consider the following investment
opportunities. Each require an initial investment of $100, but have different income streams for the fouryear life of the operation.
Year
0
1
2
3
4
A
-100
50
50
50
50
100
B
-100
20
40
60
80
100
C
-100
80
70
20
20
90
D
-100
60
40
60
40
100
E
-100
10
20
70
110
110
Project E appears to offer the highest return to the initial investment of $100, and Project C offers the
least. Projects A, B and D provide equal returns. However, money has a time value. An amount of
money received today is worth more than the same dollar amount received a year from now. Similarly, a
payment of a certain amount is worth less if it is paid a year from now. The main reason for why this is
the case is that one dollar today can be invested to earn a rate of return. When one considers this
opportunity of earning interest, the ranking of the five projects changes. Project E is not as attractive
anymore as the company would have to wait until the last year of the operation to receive the majority of
its income. Similarly, Project C is not necessarily the worst option any longer, because the company
receives most of the cash the first two years of operations and can earn interest on this income over the
next two years of the operation. Projects A, B and D are not equivalent either. The sooner the company
receives most of its income and the higher the interest that can be earned from this cash, the higher its
value will be. Accordingly, Project D looks better than both Projects A and B.
Present Value and Future Value Concepts
Project managers make constant use of the time value of money. As we discussed above, any decisions
involving investing or financing where cash flows occur at different points in time require an
understanding of the time value of money. In borrowing or lending money, the amount due can be
calculated using either simple interest or compound interest. The principal is the amount of money
borrowed or invested, the term of a loan is the length of time or number of periods the loan is outstanding,
and the rate of interest is the percentage of the principal the borrower pays the lender per time period.
Simple interest is the interest paid on the principal sum only.
I = PV0 x i x n
where I = simple interest in dollars, PV0 = principal amount at time 0,
i =interest rate per time period, and n = number of time periods.
For simple interest, the present value of the loan is
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
7-1
Economics of the Energy Industries
PV0 = I / (I x n).
The future value (amount due at time n) using simple interest is
FVn = PV0 + I, or
FVn = PV0 + (PV0 x i x n) = PV0 [1 + (i x n)].
Compound interest is due not only on the principal but on prior interest which has not been paid
(or withdrawn). The amount of interest due each period is the interest rate times the principal amount at
the beginning of the period.
For one period, the future (compound) value is
FV1 = PV0 (1 + i)
and for two periods, the future value is
FV2= FV1(1 + i), or
FV2 = PV0 (1 + i)(1 + i) = PV0 (1 + i)2.
Year
0
1
2
PV0
FV1
FV2
In general, the future value at the end of year n for a sum compounded at interest rate i is
FVn = PV0 (1 + i)n
Present value calculations find the amount at time zero, or the present value (PV0) today, that is
equivalent to some future amount FVn. The present value of a future amount received in n years or time
periods discounted at interest rate i is:
PV0 = FVn/(1 + i)n
Year
0
1
2
n-2
n-1
n
FVn
PV0
When i appears in the numerator, the interest rate is referred to as the compound interest rate or
the growth rate. On the other hand, when i appears in the denominator, the interest rate is called the
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
7-2
Economics of the Energy Industries
discount rate.
Major Steps in Evaluating Capital Investment Projects
Capital Budgeting
Capital investment decisions can be the most complex decisions facing a company’s management.
Capital budgeting is the process of planning for purchases of assets whose returns are expected to
continue beyond one year. A capital expenditure is a cash outlay, which is expected to generate a flow of
future cash benefits. Normally, a capital project is one with a life of more than one year. Capital
budgeting models are used to evaluate a wide variety of capital expenditure decisions, including the
following.
1. Investments in assets to expand an existing product line or to enter a new line of business.
2. Replacement of an existing capital asset.
3. Expenditures for research and development.
4. Investments in permanent increases in inventory or receivables levels.
5. Investments in education and training.
6. Leasing decisions.
The company's cost of capital is the overall cost of funds, which are supplied to the company. The cost of
capital is also called the investors' required rate of return, because it is the minimum rate of return, which
must be earned on the capital invested in the company. The required rate of return helps provide a basis
for evaluating capital investment projects.
Projects under consideration may be independent of each other or have some types of interdependencies.
1. An independent project is one whose acceptance or rejection has no effect on other projects under
consideration.
2. Two projects are mutually exclusive if one or the other can be accepted, but not both.
3. A contingent project is one whose acceptance is contingent upon the adoption of one or more other
projects.
4. One additional complication is capital rationing, which occurs when the company has a limited total
amount of dollars available for investment and the outlay for profitable investments exceeds this
limit. On the other hand, when the company has sufficient funds available to invest in all profitable
projects, we say the company is operating without a funds constraint.
The basic framework for capital budgeting is widely employed. Economic theory demonstrates that the
company should expand its output until marginal revenue equals marginal cost. In capital budgeting, the
company should invest in its most profitable projects first and should continue accepting projects as long
as the last project's rate of return exceeds the marginal cost of funds to the company. Some practical
problems are encountered when using this capital budgeting model.
1. All capital projects may not be known to the company at one time. Changing markets, technology,
and corporate strategies can make some current proposals obsolete and make new ones profitable.
2. Estimates of future costs and revenues can be made subject to varying degrees of uncertainty.
The capital budgeting process can be broken into four steps.
1. Generating capital investment project proposals.
2. Estimating cash flows.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
7-3
Economics of the Energy Industries
3. Evaluating alternatives and selecting projects to be implemented.
4. Reviewing or post-auditing prior investment decisions.
The initial step in the capital budgeting process is generating capital investment project proposals. The
process of soliciting and evaluating investment proposals varies greatly among companies. Investment
projects can be classified as:
1. projects generated by growth opportunities in existing product lines or new lines,
2. projects generated by cost reduction opportunities, and
3. projects required to meet legal requirements and health and safety standards.
The size of an investment proposal frequently determines who has authority to approve the project. A
very large outlay might require approval of the corporation president or board of directors and lower and
lower levels of management can authorize successively smaller outlays. If an investment decision is
critical and must be made fast, a lower level manager can approve it or it can bypass the normal timeconsuming review process to reach the appropriate responsible manager as fast as possible.
Capital Budgeting Criteria
Net cash flow (NCF) is the foundation of all investment decisions. It converts technical estimates into a
common unit - money. Only cash can be used to acquire assets and to make profit distributions to
investors. Negative cash flows over an extended period of time reduce an organization’s ability to satisfy
its financial obligations. This is why the decision criteria we will see in this chapter are based on the cash
flow, rather than revenues or profit. We will study two capital budgeting criteria. These are the net
present value (NPV) and internal rate of return (IRR).
Net Present Value
The net present value (NPV) of an investment project is defined as the present value of a stream of future
net cash flows from a project minus the project's net investment.
The net present value is:
NPV = PVNCF - INV, or
n NCF
t − INV
t
t=1(1 + k )
NPV = ∑
where:
NPV = net present value
NCFt = expected net cash flow in period t
n = expected project life
k = cost of capital
INV = initial investment.
The NPV decision rule is to accept a project when the NPV is greater than zero (because, in this case, the
present value of the project's net cash flows exceeds the project's net investment outlay) and to reject a
project when its NPV is less than zero (the present value of the net cash flows is less than the outlay).
What causes some projects to have positive or negative NPV's? When product and factor markets are not
perfectly competitive, it is possible for a company to earn above-normal profits and invest in positive
NPV projects. Some examples of conditions that allow above normal profits include:
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
7-4
Economics of the Energy Industries
a. buyer preferences for established brand names,
b. ownership or control of favored distribution systems,
c. patent control of superior product designs or production techniques,
d. exclusive ownership of superior natural resource deposits,
e.
inability of new companies to acquire necessary factors of production (management, labor,
equipment),
f.
superior access to financial resources at lower costs (economies of scale in attracting capital),
g. economies of large-scale production and distribution arising from capital intensive production
processes and high initial start-up costs, and
h. access to superior labor or managerial talents at cost which are not fully reflective of their value.
Example:
Let us revisit our example in Section I, and calculate the net present value of each project. First, assume
that the company requires a 10% after tax rate of return, that is, k = 0.1.
NPV(A) = 50/(1+0.1) + 50/(1+0.1)2 + 50/(1+0.1)3 + 50/(1+0.1)4 - 100 = 58.49
NPV(B) = 20/(1+0.1) + 40/(1+0.1)2 + 60/(1+0.1)3 + 80/(1+0.1)4 - 100 = 50.96
NPV(C) = 80/(1+0.1) + 70/(1+0.1)2 + 20/(1+0.1)3 + 20/(1+0.1)4 - 100 = 59.27
NPV(D) = 60/(1+0.1) + 40/(1+0.1)2 + 60/(1+0.1)3 + 40/(1+0.1)4 - 100 = 60.00
NPV(E) = 10/(1+0.1) + 20/(1+0.1)2 + 70/(1+0.1)3 + 110/(1+0.1)4 - 100 = 53.34
According to the net present value calculations, Project D is the best option and Project C is the second
best. Project E is the second worst alternative despite the largest straight sum of cash flows ($110) it
provides. Overall, projects are ranked from best to worst as follows: D, C, A, E and B. This ranking
may change if the company requires a higher rate of return, say 20%.
NPV(A) = 50/(1+0.2) + 50/(1+0.2)2 + 50/(1+0.2)3 + 50/(1+0.2)4 - 100 = 29.44
NPV(B) = 20/(1+0.2) + 40/(1+0.2)2 + 60/(1+0.2)3 + 80/(1+0.2)4 - 100 = 17.75
NPV(C) = 80/(1+0.2) + 70/(1+0.2)2 + 20/(1+0.2)3 + 20/(1+0.2)4 - 100 = 36.50
NPV(D) = 60/(1+0.2) + 40/(1+0.2)2 + 60/(1+0.2)3 + 40/(1+0.2)4 - 100 = 31.79
NPV(E) = 10/(1+0.2) + 20/(1+0.2)2 + 70/(1+0.2)3 + 110/(1+0.2)4 - 100 = 15.78
When the company discounts the future returns more, that is, the returns further in the future are less
valuable to the firm, Project E becomes the worst option whereas Project C becomes the best investment
opportunity despite the lowest straight sum of cash flows ($90) it provides. Now, the projects are ranked
from best to worst as follows: C, D, A, B and E. The following chart provides a visual representation of
the rankings and demonstrates how the ranking and project NPVs change as we change the discount rate.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
7-5
Economics of the Energy Industries
Comparison of Projects
70
60
50
40
10%
20%
NPV in30$
20
10
0
A
B
C
D
E
In practice, NPV calculations take into account the many complexities of capital budgets. These include
variations in timing of expenditures and revenues; complex tax rules; and depreciation, amortization and
depletion allowances.
Internal Rate of Return
One of the most common methods used to calculate the return on investment for a capital expenditure
project is the internal rate of return (IRR) method, or discounted cash flow (DCF) method, as it is often
called. The internal rate of return (IRR) is defined as the rate of discount that equates the present value
of net cash flows of a project with the present value of the net investment. In other words, the IRR is the
discount rate which makes a project’s NPV equal zero. The algebraic definition of the IRR is:
n NCF
t = INV
t
t =1(1+ r )
∑
where r = IRR.
The IRR decision rule is to accept a project when its IRR exceeds the cost of capital (k), for example, the
interest rate on borrowed money, and to reject a project when its IRR is less than k. Like the NPV, the
IRR takes account of the magnitude and timing of a project's net cash flows over its entire life. One
occasional difficulty with the IRR is that an unusual cash flow pattern (cash flows switching signs from
positive to negative and vice versa) can result in multiple rates of return.
When two or more mutually exclusive projects are acceptable using the IRR and NPV criteria, and if the
two criteria disagree on which is best, the NPV criterion is generally preferred. Both the NPV and IRR
criteria will always agree on accept/reject decisions (i.e., if NPV > 0, then IRR > k; and if NPV < 0, then
IRR < k), even if the NPV and IRR do not rank the projects the same. Different rankings result from the
implicit reinvestment rate assumptions of the two techniques: the NPV assumes that cash flows over the
project's life may be reinvested at the cost of capital k while the IRR assumes that cash flows may be
reinvested at the IRR.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
7-6
Economics of the Energy Industries
Example:
Using our example from Section I, let us calculate IRR for each investment project.
50/(1+rA) + 50/(1+ rA)2 + 50/(1+ rA)3 + 50/(1+ rA)4 = 100
20/(1+ rB) + 40/(1+ rB)2 + 60/(1+ rB)3 + 80/(1+rB)4 = 100
80/(1+ rC) + 70/(1+ rC)2 + 20/(1+ rC)3 + 20/(1+rC)4 = 100
60/(1+ rD) + 40/(1+ rD)2 + 60/(1+ rD)3 + 40/(1+rD)4 = 100
10/(1+ rE) + 20/(1+ rE)2 + 70/(1+ rE)3 + 110/(1+rE)4 = 100
Spreadsheet programs and financial calculators can calculate IRR very easily once you provide the net
cash flows and the initial investment. All they do, however, is to solve for r in above equations. In our
example, we obtain the following values for internal rate of return of each project:
rA = 35%;
rB = 27%;
rC = 45%;
rD = 37%;
rE = 26%.
These results rank the projects from best to worst as follows: C, D, A, B and E. High values of IRR
indicate that the company discounts future returns significantly. Since, in Project C, the most of the cash
inflows are received during the first two years of operations, the company would have to discount the next
year’s dollar at a rate of 45% for sum of the discounted net cash flows to equal the initial investment.
Remember that the company is trying to recover the cost of capital. The cost of capital, k, is less likely to
be in the 40% range than in the 20% range.
Risk and Return Concepts
Risk refers to the potential variability of returns from a project. A project is considered risk-free if the
monetary returns from a project are known with certainty. Probability distributions are the probabilities
of every particular outcome. These probability distributions may be objectively or subjectively
determined. The expected return is a weighted average of the individual possible returns,
∧
n
r = ∑ r jp j
j=1
∧
r
where
= expected return
rj = return for the jth case, where there are n possible outcomes
pj = probability of occurrence of the jth outcome.
The standard deviation is an absolute measure of risk. It is defined as the square root of the weighted
average of the squared deviations of individual observations from the expected value.
σ=
n
∧
∑ (r j − r )2 p j
j=1
If the outcomes are normally distributed (on a plot they would take the shape of a bell curve with the
expected value at the top of the curve) the actual outcome should be between ± 1 standard deviation of the
expected value 68.26% of the time, and between ± 2 standard deviations of the expected value 95.44% of
the time. The number of standard deviations, z, that a particular value of r is from the expected value of r
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
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Economics of the Energy Industries
is computed with the relationship
∧
r−r
z=
σ
Risk is an increasing function of time with early returns being less risky than distant returns.
One of the key variables in capital budgeting decisions is the cost of capital. The cost of capital can be
thought of as what the company must pay for capital (interest rates on borrowing) or the return required
by investors in the company's securities. Risk can also be thought of as the minimum rate of return
required on new investments undertaken by the company. The cost of capital is determined in the capital
markets and depends on the risk associated with the company's activities.
The weighted cost of capital is the discount rate used when computing the net present value of a project of
average risk. Similarly, the weighted cost of capital is the hurdle rate used in conjunction with the internal
rate of return. The weighted cost of capital is based on the after-tax cost of capital where the cost of the
next (marginal) sources of capital are weighted by the proportions of the capital components in the
company's long-range target capital structure. The weighted, or overall, cost of capital is obtained from
the weighted costs of the individual components. The weights are equal to the proportion of each of the
components in the target capital structure.
The general expression for calculating the weighted cost of capital, ka, is:
ka = (equity fraction)(cost of equity) + (debt fraction)(cost of debt)
ka =
E
(k e ) + B (k d )(1 − T)
B+E
B+ E
ka =
E
(k e ) + B (k i )
B+E
B+ E
where B = amount of debt and E = amount of equity.
The appropriate component costs to use in determining ka are the marginal costs or the costs associated
with the next dollar of capital to be raised. These may differ from the historical costs of capital raised in
the past. The required return, k, on any security may be thought of as consisting of a risk-free rate of
return plus a premium for the risk inherent in the security, or
Required return = Risk-Free return + Risk premium.
The risk-free rate of return is usually measured by the rate of return on risk-free securities such as short
term government securities. The risk-free rate increases with expectations of future inflation. The riskfree rate depends on the overall supply and demand for funds in the economy.
There are five major risk components, which determine the risk premium on a security.
1. Business risk arises from the variability of the company's operating income and is determined by the
variability of sales revenues & expenses and by the amount of operating leverage the company uses.
2. Financial risk arises from the additional variability of the net earnings associated with the use of
financial leverage together with the increased risk of bankruptcy associated with the use of debt.
3. Marketability risk refers to the ability to quickly buy and sell the securities. Securities that are widely
traded have less marketability risk than those, which are less actively traded.
4. Interest rate risk refers to the variability in returns on securities arising from changes in interest rates.
Increases in interest rates reduce the market price of the security. Decreases in interest rates reduce
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
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Economics of the Energy Industries
the rate at which intermediate interest payments can be reinvested.
5. Seniority risk is the risk due to the priority of a security's claim in a company's capital structure.
The cost of funds may increase with the amount of financing required. The cost of funds obtained from a
particular type of security increases the lower the security ranks in its claims on the company. The cost of
common equity is higher than that for preferred stock, which has preference over common stock in the
event of corporate liquidation. The return required on preferred stock is higher than that for unsecured
debt, which is higher than that for secured debt. The cost of capital is equal to the equilibrium rate of
return demanded by investors in the capital markets for securities of that degree of risk.
Regardless of the specific source of financing used at a particular time, a weighted cost of capital
dependent on the component costs and the proportions of the components in the target capital structure is
used for capital budgeting decisions.
With respect to oil and gas operations, there are specific aspects of risk within the broad categories
described above.
1. Geologic risk. For both the exploration and production (upstream) businesses, there is considerable
geologic risk associated with the occurrence of oil & gas. Any number of factors contributes to risk -whether oil & gas occur in “commercial” quantities (relative to commodity prices and costs of
extraction), the quality of the reservoir, success of any reservoir treatment, and so on.
2. Engineering risk. For the upstream and downstream (processing, refining, transportation, chemicals,
marketing) businesses, there is risk associated with engineering design of infrastructure requirements.
3. Market risk. For the oil and gas industries, this source of risk is tied to supply and demand conditions
in specific regions and worldwide.
4. Commodity price risk. There is risk inherent in the prices for oil & gas both locally and worldwide.
Trading and speculation may contribute to risk while serving as strategies for managing price risk.
5. Financial risk. The cost of financing (interest rates, terms & conditions) is a large source of risk.
Incremental Cash Flow Analysis
The capital budgeting process is concerned primarily with the estimation of the cash flows associated with
a project, not just the project's contribution to accounting profits. Typically, a capital expenditure
requires an initial cash outflow, termed the initial investment. Thus, it is important to measure a project's
performance in terms of the net (operating) cash flows it is expected to generate over a number of future
years. The chart in the following page represents a typical cash flow diagram.
Estimating the cash flows associated with investment projects is crucial to the capital budgeting process.
The cash flows associated with a project are the basis for evaluation rather than the project's accounting
profits. There are several rules concerning the estimation of cash flows:
1. Cash flows should be measured on an incremental basis. The cash flow stream for a project is the
difference between the cash flows to the company with the project compared to the cash flows to the
company without adopting the project.
2. Cash flows should be measured on an after-tax basis.
3. All the indirect effects of a project should be included in the cash flow estimates. For example,
increases in cash balances, receivables, and inventory necessitated by a capital project should be
included in the project's net investment.
4. Sunk costs should not be considered. Since they result from previous decisions, sunk costs are not
truly incremental costs.
5. Resources should be measured in terms of their opportunity costs. The opportunity costs of resources
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
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Economics of the Energy Industries
are the cash flows they would generate if investment were made in an alternative opportunity rather
than in the project under consideration.
Cash Flow Diagram
Dividends to Stockholders
Income from Patents, Engineering, R&D, etc.
R&D
Borrowed Capital
Equity Capital
Outside Investments
CORPORATION
CASH
Cash Flow
WORKING
CAPITAL
Sales Revenue
DIRECT
INVESTMENTS
Operating
Costs
OPERATIONS
Gross
Profit
DEPRECIATION
AMORTIZATION
DEPLETION
DEFERRED DEDUCTIONS
Taxable Income
NET PROFIT
INCOME TAX
Source: Stermole, F. Economic Analysis and Investment Decision Making, 1983.
Estimating the Initial Investment
The initial investment is the initial cash outlay for a project (usually at time zero). A four-step procedure
for estimating the net investment can be summarized as follows:
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
7 - 10
Economics of the Energy Industries
Step 1.
The new project cost plus any installation and shipping costs
associated with acquiring the asset and putting it into service,
PLUS
Step 2.
Any increases in net working capital initially required as a
result of the new investment,
PLUS
Step 3.
The net proceeds from the sale of existing assets when the
investment is a replacement decision,
PLUS or MINUS
Step 4.
The taxes associated with the sale of the existing asset
and/or the purchase of a new one,
EQUALS
The initial investment.
Some projects involve outlays for more than a year. The net investment for a multiple-period investment
is the present value of the series of outlays discounted at the company's cost of capital. Reviewing or
post-auditing is a final step to review the performance of investment projects after they have been
implemented. While projected cash flows are uncertain and one should not expect actual values to agree
with predicted values, the analysis should attempt to find systematic biases or errors by individuals,
departments, plants, or divisions and attempt to identify reasons for these errors. Another reason to audit
project performance is to decide whether to abandon or continue projects that have done poorly.
Inflation is easily incorporated into the basic capital budgeting criteria. Make sure the cost of capital
takes account of inflationary expectations. Make sure that future cash flow estimates also include
expected price and cost increases. If these are done, the capital budgeting techniques outlined in this
chapter serve the financial decision maker reasonably well.
If a project generates additional revenues and the company extends credit to its customers, an additional
initial investment in accounts receivable is required. Moreover, if additional inventories are necessary to
generate the increased revenues, then an additional initial investment in inventory is required, too. This
increase in initial working capital -- that is, cash, accounts receivable, and inventories -- should be
calculated net of any automatic increases in current liabilities, such as accounts payable or wages and
taxes payable that occur because of the project. As a general rule, replacement projects require little or no
net working capital increase. Expansion projects, on the other hand, normally require investments in
additional net working capital.
Estimating the Annual Operating Cash Flows
The expected future net operating cash flows (NCF) are easily computed. The after-tax net operating
cash flow is:
NCF = ∆OEAT + ∆Dep - ∆NWC,
where
∆OEAT (change in earnings after tax) = ∆OEBT(1 - T)
∆Dep = change in depreciation
∆NWC = increase in the net working capital investment
∆OEBT = change in earnings before tax
T = tax rate,
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
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Economics of the Energy Industries
and
∆OEBT = ∆R - ∆O - ∆Dep,
where
∆R = RW - RWO (revenues with project - revenues without project)
∆O = OW - OWO (operating costs with project - operating costs without
project)
∆Dep = DepW - DepWO (depreciation with project - depreciation without
project).
Based on these definitions, two useful expanded versions of the basic NCF equation are
NCF = (∆R - ∆O - ∆Dep)(1 - T) + ∆Dep - ∆NWC
NCF = [(RW - RWO)-(OW - OWO)-(DepW - DepWO)] (1 -T) + (DepW - DepWO) - ∆NWC
Estimating the Terminal Year Cash Flows
There are two potential cash flows at the end of a project's life. First, cash inflow due to incremental
salvage must be included at the end of the project. Incremental salvage is the difference between salvage
with the project and without the project. There will be taxes due or saved when an asset is sold for more
or less than book value. Book value is the installed cost of the asset less accumulated depreciation. There
are four possible tax situations.
Case 1: Sale of an asset for book value. No tax consequences.
Case 2: Sale of an asset for less than book value. The loss is treated as an operating loss to offset
operating income. The tax saving is the marginal tax rate times the amount of the loss.
Case 3: Sale of an asset for more than book value but less than original cost. The gain is taxed as
operating income, with taxes due equal to the marginal tax rate times the amount of the gain.
Case 4: Sale of an asset for more than original cost. The part of the gain that represents a recapture of
depreciation is treated as an operating gain and the gain in excess of original cost is treated as a
capital gain.
Don't forget that the recovery of book value is tax-free. Only gains and losses from book value result in
tax savings or obligations. Also, recovery of net working capital can be a cash inflow. There are no tax
consequences of liquidating working capital.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
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Economics of the Energy Industries
CHAPTER 8 - PROJECT FINANCE
Introduction
Before the 1970s, most energy projects were financed by internal cash generation of international oil
companies. When in the 1970s, governments got involved in the energy sector to ensure better control of
their reserves, the financing of oil and gas projects by governments and official borrowings increased. In
the past twenty years there has been a wave of global interest in project finance as a tool for investment.
In the early 1990s, most governments have limited their involvement in the sector to promote private
participation. Thus, the financing became more complex, involving public and private investors and
financiers.
Project finance helps finance new investment projects by structuring the financing based on the project's
own operating cash flow and assets, without additional sponsor guarantees. The use of project finance
tends to reduce investment risk and raise capital at a relatively low cost, to the benefit of sponsor and
investor alike.
The change in attitude toward project finance can be attributed to a number of factors. Primarily, most
countries today rely on market mechanisms to guide their economic activity and on the private sector to
supply investment. Greater focus on the private sector has necessitated major regulatory reforms, which in
turn have created new markets in areas previously seen as the preserve of government activity. These
trends are particularly true for the energy sector, especially in power generation. For example, in 2003,
project financing in the power sector ranked first, accounting for $40 billion with 123 projects (a 66%
increase from 2002). Oil and gas investments ranked third with 40 deals worth $16 billion and nine
petrochemicals deals worth $8 billion came fourth. Total value of project financings in 2003 was $108
billion as compared to $79 billion in 2002.
Types of Project Finance
Project finance is tailored to meet the needs of a specific project. Repayment of the financing relies on the
cash flow and the assets of the project itself. The risks (and returns) are borne by different classes of
investors (equity holders, debt providers, quasi-equity investors). Because risks are shared, one criterion
of a project's suitability for financing is whether it is able to stand alone as a distinct legal and economic
entity. Project assets, project-related contracts, and project cash flows need to be separated from those of
the sponsor. See Appendix 1 for a typical deal structure for a project-financed project, and Appendix 2
for a list of top 10 project finance deals in 2003 (amounting to almost $25 billion).
Corporate financing is when the borrowing is carried out by a utility as a whole rather than by an entity
created specifically to hold ownership of the new facility. Although the funds may be invested into a
particular project, lenders in a corporate financing arrangement look at the cash flow and assets of the
entire company to service the debt and to provide security.
There are two basic types of project finance: non-recourse project finance and limited-recourse project
finance.
Non-recourse project finance is an arrangement under which investors and creditors financing the project
do not have any direct recourse to the sponsors, as might traditionally be expected (for example, through
loan guarantees). Although creditors' security will include the assets being financed, lenders rely on the
operating cash flow generated from those assets for repayment. Before it can attract financing, then, the
project must be carefully structured and provide comfort to its financiers that it is economically,
technically, and environmentally feasible, and that it is capable of servicing debt and generating financial
returns commensurate with its risk profile.
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Limited-recourse project finance permits creditors and investors some recourse to the sponsors.
Investments into the project are viewed as assets of the project company. This frequently takes the form
of a pre-completion guarantee during a project's construction period, or other assurances of some form of
support for the project. Creditors and investors, however, still look to the success of the project as their
primary source of repayment. In most developing market projects and in other projects with significant
construction risk, project finance is generally of the limited-recourse type.
Funds for a project come in the form of equity or debt (see previous chapter on project evaluation). The
equity is provided by owners, shareholders, and sponsors that receive payments dividends and capital
gains based on the company’s net profit. For oil and gas projects, mean leverage ratio is around 65%, and
for power projects, it is around 70%.55 The possible sources of equity include sponsor’s own capital,
investment funds, multilateral institutions, international equity markets, and local capital markets.
Project debt refers to funds lent by financiers such as commercial banks, financial institutions, and other
funds. These loans are secured by the project’s underlying assets. Lenders receive payments for principal
and interest on these loans according to a predetermined rate, regardless of whether the company makes
or loses money. However, prospective lenders examine the company’s projected cash flow very carefully
to ensure that there is sufficient financial capacity for debt repayment. Debt makes up to 60-80% of the
project cost and is provided through institutional investors, international commercial banks, the
International Financial Corporation (IFC), international bond markets, suppliers’ credits and special
energy funds, as well as governments.
Advantages of Project Finance
Project finance has two important advantages over traditional corporate finance; it can
• increase the availability of funds, and
• reduce the overall risk for major project participants down to an acceptable level.
In order to attract such financing, though, a project needs to ensure that all the parties' obligations are
negotiated and are contractually binding. Financial and legal advisers and other experts may have to
spend considerable time and effort on this structuring, and on a detailed appraisal of the project. These
steps will add to the cost of the project and may delay its implementation. Moreover, the sharing of risks
and benefits brings unrelated parties into a close and long relationship. A sponsor must consider the
implications of its actions on the other parties associated with the project (and must treat them fairly) if
the relationship is to remain harmonious over the long term.
Under project finance, there are several major benefits and advantages for stakeholders:
Control benefits include the owners’ discretion to reinvest free cash flow in projects of their own choice,
ability to pay themselves high salaries and bonuses, and their freedom in decision-making for their own
interests at the expense of lenders or shareholders.56
Non-recourse benefit. The typical project financing involves a loan that is completely "non-recourse" to
the sponsor, i.e., the sponsor has no obligation to make payments on the project loan if revenues
generated by the project are insufficient to cover the principal and interest payments on the loan. In order
to minimize the risks associated with a non-recourse loan, a lender typically will require indirect credit
supports in the form of guarantees, warranties and other covenants from the sponsor, its affiliates and
other third parties involved with the project.
Benefits of leverage maximization. The sponsor typically seeks to finance the costs of development and
construction of the project on a highly leveraged basis. Frequently, such costs are financed using 80 to
55
Esty, Benjamin C. Modern Project Finance, John Wiley & Sons, 2004. p.41 (for the period of 1997-2001).
"Optimal Incorporation, Structure of Debt Contracts, and Limited-Recourse Project Financing" (with K. John), Journal of Financial
Intermediation, October 1996.
56
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
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100 percent debt. High leverage in a non-recourse project financing permits a sponsor to put less in funds
at risk, permits a sponsor to finance the project without diluting its equity investment in the project and, in
certain circumstances, also may permit reductions in the cost of capital by substituting lower-cost, taxdeductible interest for higher-cost, taxable returns on equity.
Off-Balance-Sheet treatment benefit. Depending upon the structure of a project financing, the project
sponsor may not be required to report any of the project debt on its balance sheet because such debt is
non-recourse or of limited recourse to the sponsor. Off-balance-sheet treatment can have the added
practical benefit of helping the sponsor comply with covenants and restrictions relating to borrowing
funds contained in other indentures and credit agreements to which the sponsor is a party.
Maximization of tax benefits. Project financings should be structured to maximize tax benefits and to
assure that all available tax benefits are used by the sponsor or transferred, to the extent permissible, to
another party through a partnership, lease or other vehicle.57
Benefit of capturing an economic rent. The sponsors of the project can monetize the economic rent by
entering into long-term purchase contracts that can be used to secure project borrowings to finance the
project. Such contracts could also generate the cash flow to service project debt and provide equity
investors the return of and return on their investment.
Achieving economies of scale. Two or more producers can benefit from joining together to build a single
facility when there are economies of scale in production. For example, the firms in a densely
industrialized area might decide to cooperate in a single cogeneration facility, with each firm agreeing to
buy steam to meet its own needs for heat and the group selling all the excess electricity to the local
electric utility.
Risk sharing. If a project’s capital cost is large in relation to sponsor’s capitalization or financial
capabilities of the host country, to reduce their own risk exposure they can enlist one or more jointventure partners.
Lower overall costs of funds. If the output purchaser’s credit standing is higher than that of the project
sponsors, the project will be able to borrow funds more cheaply than the project sponsors could on their
own. Also, to the extent the project entity can achieve a higher degree of leverage than the sponsors can
comfortably maintain on their own, the project’s cost of capital will benefit from the substitution of
lower-cost debt for equity.
Reduced cost of resolving financial distress. A project entity’s capital structure typically has just one class
of debt, and the number of other potential claimants is likely to be small. The entity with such capital
structure tends to emerge from financial distress more easily.
Reduced legal or regulatory costs. Certain types of projects, such as cogeneration projects, involve legal
or regulatory costs that an experienced project sponsor can bear more cheaply than an inexperienced
operator can.
Disadvantages of Project Finance
Because the risks assumed by lenders may be greater in a non-recourse project financing than in a more
traditional financing, the cost of capital may be greater than with traditional financing.
Complexity of project financing. Project financings are extremely complex. It may take a much longer
period of time to structure, negotiate and document a project financing than a traditional financing, and
the legal fees and related costs associated with a project financing can be very high.
57
Thelen Reid & Priest LLP report at
http://www.constructionweblinks.com/Resources/Industry_Reports__Newsletters/June_3_2002/project_finance.htm
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
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Indirect credit support. The cost of debt is typically higher in a project financing because of the indirect
nature of the credit support. Lenders to a project will naturally be concerned that the contractual
commitments might somehow fail to provide an uninterrupted flow of debt service, and as a result they
typically require a higher yield premium to compensate that risk, that is generally between 50 and 100
basis points (could be up to 400 basis points), depending on purchase contract negotiated (under any
circumstances contract provides a greater degree of credit support).
Higher transaction costs. Higher transaction costs reflect the legal expense involved in designing the
project structure, researching and dealing with project-related tax and legal issues, and preparation of
necessary project ownership, loan documentation and other contracts.58
Limited managerial decision-making. Extensive contracting restricts managerial decision-making.
Disclosure of strategic information. Project finance requires greater disclosure of proprietary information
and strategic deals.
Project Risks
Since project finance structuring hinges on the strength of the project itself, the technical, financial,
environmental, and economic viability of the project is a big concern. Anything that could weaken the
project is also likely to weaken the financial returns of investors and creditors. Therefore, an essential step
of the procedure is to identify and analyze the project's risks, then to allocate and mitigate them, usually
by entering into guarantee and contractual arrangements.
The various risks that concern energy project lenders can include the following:
Construction: Will the project be on time? Will the project be on budget? Is the contractor capable of
delivering what he's agreed to? Does he have sufficient assets in the event he does not deliver? Will some
act of God, force majeure or other physical loss impede or otherwise upset the project?
Operations: Will the project be properly maintained? Is the O&M contractor qualified and experienced?
Will the project perform efficiently and at predicted capacity levels? Will there be labor difficulties,
unplanned outages, physical losses and income losses caused by acts of God?
Equipment: Is the chosen equipment suitable for the project? Will it be delivered on time? Will
replacement parts be readily available? Is there a technology risk? What is the stability of the
manufacturer? Does it have sufficient assets in case of a fleet wide failure?
Economic: Will there be unexpected costs, problems with currency conversion, repatriation of funds, tax
changes, and/or policy changes? Will sinking funds and government agreements be sufficient or reliable?
Market Availability: Will the project have the ability to sell power/gas/liquids at sufficient rates to assure
debt service and project health? Is the credit rating of the purchase agreements (e.g., PPAs), if any,
sufficient? What is the ability of the government to back these agreements? What is the value of the
country's sovereign guarantee?
Political: A number of political or cross border risks may need to be addressed such as private ownership,
power sales, taxes, fuel use, emissions, currency, contract repudiation, expropriation, nationalization,
insurrection.
Fuel Supply Resource Reliability: Depending on the technology being used, different fuel reliability
issues arise such as long term supply contracts or agreements, the fluctuation in fuel prices, reliability of
resource studies, weather risk such as a lack of sufficient wind speeds or hours of sunshine for wind and
solar projects.
58
John D. Finnerty. Project Financing. Wiley & Sons. 1996. pp.24-33
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
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Clearly, project risks are many and varied. These risks are related to events that could endanger the
project during development, construction, and operation. Some may relate to a specific sub-sector, others
to the country and policy environment, and still others to more general factors. But, in general, financing
projects in the developing world is considered more risky than in developed world primarily due to: (1)
deficiencies in institutional and organizational structures, (2) lack of clear and transparent legislative and
regulatory systems, (3) economic and political insecurity, (4) market/price risk for the commodity to be
produced, (5) financial risks, (6) currency risks (risks of devaluation of cash flows nominated on local
currency), and (7) increased force majeure risk. These risks endanger the viability and sustainability of
the project through (1) excessive construction and operation costs, (2) shortfall in revenue or the margin
caused by price and market risks, and (3) uncertainty about safety and transferability of investments and
returns.
The project risks are usually borne by project sponsors. Accordingly, identification, analysis, mitigation,
and allocation of project risks are essential to structuring project finance deals. Although it may be costly
and time-consuming, detailed risk appraisal is absolutely necessary to assure other parties, including
passive lenders and investors, that the project makes sound economic and commercial sense. Similarly,
lenders and investors must be kept abreast of the project's operational performance as it progresses. This
risk assessment and mitigation process is one of the reasons for higher transaction costs associated with
project financing.
Project Financing Across the Energy Value Chain
Upstream
From the financing of oil and gas rigs to oil refineries and pipelines, oil and gas companies are
increasingly using project financing as a method of reducing corporate debt by taking heavy capital
investment off balance sheet. Large international oil companies (IOCs) usually finance the upstream oil
and gas projects by internal cash generation and corporate borrowings. Smaller IOCs borrow funds on
non-recourse or limited recourse basis.
One of the oil projects financed by the project finance is the Azerbaijani International Oil Consortium
(AIOC), consisting of 11 members. In 1999, the AIOC completed the early oil project, producing 100,000
barrels of crude oil per day. The early oil project included the refurbishment of the Chirag-1 platform, the
construction of a new onshore terminal at Sangachal and a 230-km subsea pipeline system, and the
rehabilitation of two existing export pipelines to transport early oil to the Black Sea, via two routes: one
through Russia to Novorossiysk and the other through Georgia to Supsa.
The AIOC was organized as an unincorporated joint venture between subsidiaries from each company.
Each of them was responsible for financing its share. So, each partner had a choice in how to finance its
share of $1.9 billion for the project. Six members with combined interests of 48.2% chose to use internal
funds. For example, BP contributed around $325 million to cover its share (17.1% of $1.9 billion). The
other five members of the AIOC formed a Mutual Interest Group (MIG) for the purpose of obtaining
project loan from the International Finance Corporation (IFC), and the EBRD. These multilateral agencies
gave these companies access to long-term funds that banks were not willing to provide. In February
1999, the IFC, EBRD and MIG closed a $400 million, limited recourse project financing, with the
effective interest rate of less than 10%. Traditionally, the multilateral agencies funded projects in one of
three ways: direct lending (“A loans”), indirect lending as agent for a syndicated bank loan (“B loan”), or
equity contributions. In this case the financing was structured as ten A loans and ten B loans – agency
made an A and a B loan to special purpose subsidiaries at each of the five MIG partners.
Another example of the project-finance in the upstream sector is Petrolera Zuato, Petrozuata C.A., a $2.5
billion joint-venture of Conoco (50.1%) and state-owned Petroleos de Venezuela, S.A. (PDVSA)
(49.9%), oil-field development project in Venezuela. Petrozuata’s sponsors made a series of commitments
in order to ensure successful implementation of the project. They agreed to provide funds to Petrozuata to
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
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Economics of the Energy Industries
pay project expenses, including any unexpected costs overrun, prior to project’s completion. The parent
corporations of the sponsors guaranteed these obligations in the amount of $1.4 billion. The guarantee
structure was unique considering difference in ratings between the companies (Du Pont – AA-, PDVSA –
B). The completion guarantee included severe penalties for failing to meet obligations, and incentives to
cover the other party’s shortfall. The construction budget also contained a $38-million contingency for
upstream facilities, a $139-million contingency for downstream facilities and enough funds to pay
premiums on a construction all-risk insurance policy covering up to $1.5 billion of physical loss or
damage.
Once Petrozuata completed construction, the sponsors’ guarantees would end, and project debt would
become non-recourse to the sponsors. If Petrozuata would not complete the project by December 2001, all
debt would have immediately become due and payable. On the 15th of March, 2002 Petrozuata announced
that all performance requirements associated with the project financing have successfully been met, and
the institutional debt becomes non-recourse to Petrozuata's shareholders.
Pipelines
In the U.S. a few natural gas pipelines have been financed through project finance. Examples are the Kern
River and Mojave Pipelines in the early 1990’s and two of the Canadian import projects. An example of
that is the U.S.-Canadian Alliance Pipeline capable of transporting 1.325 billion cubic feet of natural gas
daily from northeastern British Columbia to the Chicago-area market for distribution throughout North
America. Alliance partners are Coastal Corporation (14.4%), Duke Energy Corporation (9.8%), Fort
Chicago Energy Partners LP (26%), IPL Energy Inc. (21.4%), Unocal Corporation (9.1%), Westcoast
Energy Inc. (14.5%) and Williams Companies Inc. (4.8%). The Cost of the pipeline was $3.1 billion
which made it one of the biggest projects financed in North America. The debt and equity structure of the
pipeline financing was 70%-30%. The U.S. side of the pipeline construction received a debt of $961.5
million, and the Canadian side received $1.6 billion, with debts financed by Bank of Montreal, The Bank
of Nova Scotia, the Chase Manhattan Bank, and Royal Bank of Scotland, and maturing in December
2008.
Internationally, there are two recent examples: Bolivia-to-Brazil natural gas pipeline and Chad-Cameroon
oil pipeline. The Chad-Cameroon pipeline will carry oil produced from the fields at Doba in southern
Chad over 1,070 km to offshore oil-loading facilities on Cameroon’s Atlantic coast. The field
development will cost $1.5 billion and the pipeline will cost $2.2 billion. The project’s private sponsors
(led by ExxonMobil, the operator, Petronas, and Chevron) are financing about $3.0 billion or 81% of the
project costs from their own resources including 100% of the field facilities. About $600 million in debt
financing for the export system has been obtained by the sponsors from export credit agencies and
commercial banks. Other project stakeholders include the World Bank, IFC, governments of Chad and
Cameroon, and even local communities and NGO’s. A major concern of the project participants and
stakeholders was the distribution and use of the newfound oil wealth for the good of the majority in Chad,
and, in particular, local communities that host the project. In response, the World Bank, with the
collaboration of other stakeholders implemented a revolutionary Revenue Management Plan, isolating
Chad’s project revenues and targeting them to social development programs (see the Chad-Cameroon
Pipeline case study for details on project financing and revenue management plan)
Bolivia – to - Brazil Pipeline, which is the longest pipeline built in Latin America at a cost of $2.2 billion,
was financed by the World Bank, the Brazilian National Development Bank (BNDES), the InterAmerican Development Bank (IADB), the European Investment Bank (EIB) and Corporación Andina de
Fomento (CAF). The project was financed from loans (debt) and equity with the 63%-37% ratio. In 1997,
the IADB and the World Bank approved loans to finance a significant portion of the Bolivia-Brazil gas
pipeline. The IADB ($240 million) and the World Bank ($310 million) loans went to finance Petrobras,
the Brazilian state-owned energy company, the principal investor and operator of the pipeline in Brazil.
The owner of the pipeline in Brazil is TGB, whose investors include Petrobras, Transredes, Enron, Shell
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
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Economics of the Energy Industries
and BTB. Gas Transboliviano, a consortium comprised of Transredes, Enron, Shell, Petrobras and others,
owns the Bolivia side of the pipeline. The Bolivian side ($84 million) was financed by the Andean
Development Corporation. While the borrower and the guarantor were a Brazilian firm and the
government of Brazil, the legal documents provided coverage for the commitments for execution of the
environmental and social management program in Bolivia.
A combination of multilateral lending, export credits, and partial credit guarantees offered the only
prospect to obtain financing with maturities long enough to achieve a gas price which would allow gas to
penetrate the existing energy market. For this reason, the Brazilian government indicated early in the
appraisal process that it would be prepared to provide the necessary guarantees for such financing
package. However, multilateral financing and partial credit guarantees were not an option for the Bolivian
side since the transportation company was structured as a fully private venture for which sovereign
guarantees, required from the Bolivian Government for multilateral support, were not available.
Nevertheless, the new owners of the transportation company in Bolivia were not coming up with the
required financing and seemed not to attach the same urgency as Petrobras to close the pipeline financing
and start the construction. It became clear to Petrobras that the Bolivian segment of the pipeline,
amounting to about 20% of overall construction costs, was impeding the realization of the entire project.
Petrobras, which had also been contracted to oversee pipeline construction in Bolivia, then decided to
mobilize financing for this portion of the project as well (see Bolivia-to-Brazil pipeline case for details).
Electric Power
As some electricity markets are liberalized and government monopolies are unbundled and privatized,
private sector companies are playing a pivotal role in building new generation capacity; they usually
employ project finance with off-take agreements guaranteeing electricity sales. In emerging countries,
expansion of electricity is imperative to economic growth and raising the standard of living. In the
absence of sufficient government financing, project financing plays an important role in attracting private
investors to these countries, where investment risks are usually higher. Accordingly, coal, oil and gasfired power plants, hydroelectric, combined heat and power and renewable energy plants are being
successfully delivered on a project finance basis around the world.
There are numerous methods available for the financing of power projects in developing countries. These
methods allow for various levels of participation and control by private (and sometimes foreign)
investors.
•
Management and operation contracts involve an outside private entity managing but not owning a
public entity - often for a specified period of time. They involve the state ceding the least amount of
control to private enterprise.
•
Greenfield projects involve the construction of new power plants by private investors or by publicprivate ventures. They may be build-own-operate (BOO), build-operate-transfer (BOT), or buildlease-own (BLO) agreements.
•
Divestitures allow the private firm to take a substantial equity stake in what was a domestic (and
sometimes publicly owned) enterprise.
In terms of financing power projects, debt usually consists of commercial bank loans or bond issuances.
Equity, on the other hand, usually consists of taking stock or ownership in the project or company. One
instrument that blends the qualities of debt and equity is a subordinated loan, which is given repayment
priority over equity capital, but not over commercial loans or other senior debt.
The selected project financing technique depends heavily on the creditworthiness of the country where the
investment is taking place. Legal systems, economic and financial environments, and political stability are
some of the factors that determine a nation’s creditworthiness. The most obvious method for repayment
of the costs of a power plant would be through the cash flow from the operations of the plant. However,
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
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Economics of the Energy Industries
many developing countries are plagued by theft of electricity or tariff rates that cannot support the cost of
the plant. For riskier power projects, state Export Credit Agencies (ECAs) often play a role in providing
loans, making guarantees to financiers of the project, or acting as an insurance facility. Developing
countries are also recipients of major funding packages from multilateral and bilateral agencies or credit
facilities, which have a function similar to that of ECAs.
Across the world, Americas and Pacific Asia stood out as major targets of project finance lending in the
energy sector between1998 and 2002. Over this period, $101 billion in the power sector and $20 billion in
the oil & gas sector was financed in North and South America; the corresponding numbers in Pacific Asia
were $20 billion and $13 billion.
One of the most recent and interesting deals is the Umm al-Nar IWPP project in the United Arab Emirates
(UAE) combined elements of long-term foreign investment, conventional debt financing and Islamic
financing in challenging market conditions. The project included the financing of the acquisition of an
existing 850-MW and 162 million imperial gallons per day (MIGD) power and desalination plant,
construction of 1,550 MW and 25 MIGD of new capacity, decommissioning of certain existing assets and
operation of a combined new facility on Umm Al Nar Island in the Emirate of Abu Dhabi. The purchaser
was a new equity joint venture, Arabian Power Company, owned 40 percent jointly by wholly owned
subsidiaries of International Power plc, the Tokyo Electric Power Company and Mitsui Co., Ltd., and
60% by a new holding company wholly owned by ADWEA. Capacity and output will be sold to the Abu
Dhabi Water and Electricity Company, an affiliate of ADWEA and the "single buyer" for Abu Dhabi’s
privatized water and electricity sector, under a 20-year power and water purchase agreement.
The financing package included two non-recourse loans, a $1.1 billion 20-year term loan and a $230
million five-year term loan, in addition to a $440 million five-year equity bridge loan. The lead-arranging
group was comprised of 14 international, regional and local financial institutions, with Bank of TokyoMitsubishi acting as global coordinator and Abu Dhabi Islamic Bank as lead arranger for the Islamic
facility.
The developing Asian countries typically have chosen to rely more on Independent Power Producers
(IPPs). In Asia, 72% of $93 billion in private investment between 1990 and 1999 was directed to
greenfield projects. Private sector involvement generally has been limited to generation while
transmission and distribution continued to remain in the hands of the government. This has sometimes led
to serious problems, however, as the highly politicized issue of determining fair tariff rates discourages
the ability to raise enough revenue to support the cost of generation without the aid of government
subsidies. Recent controversial private electricity investments such as the Dabhol arrangement in India,
and PT Paiton Energy in Indonesia have led to some debate about the most suitable forms of privatization
and financing for various regions.
The Dabhol project started promisingly enough. By June 1992, Enron had selected Dabhol as the site for
a project, and, with General Electric, Enron entered a memorandum of understanding with the
Maharashtra State Electricity Board (MSEB) to build the Dabhol project. The operating entity was the
Dabhol Power Company (DPC), which is a joint venture. During most of the project development period,
Enron owned 80% of the project, while General Electric and Bechtel each owned 10%. The parties
negotiated the project terms over an 18-month period, which culminated in the DPC and MSEB signing a
power purchase agreement in December 1993. Enron also obtained the necessary approvals for the project
from the Indian government during this period. Over the next year, Enron developed the project
financing, obtaining $635 million in financing, insurance, and loan guarantees from Bank of America,
ABN Amro, a group of Indian banks, the U.S. Export-Import Bank, and the Overseas Private Investment
Corporation (OPIC). In addition, in 1997, the Indian government approved Enron’s request to expand a
portion of the project, the Dabhol liquified natural gas terminal, to allow it to process five million metric
tons annually.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
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Economics of the Energy Industries
But, problems started in April 1993, when the World Bank found that the project was too large for base
load operation in Maharashtra. The Bank also found that the plant’s power, which would be produced
from LNG, would cost much more than power from coal. Under the proposed deal, the plant’s power
would displace lower cost power, raising power costs overall for the state. The conclusion was that the
project was not economically viable, and thus could not be financed by the Bank.
The Indian government also commissioned an official report on the project in 1995. The report critiqued
both the process by which the project had been developed and the terms of the deal. It found that the
initial memorandum of understanding was rushed and “one-sided” (citing a letter from the World Bank),
condemned the absence of competitive bids and lack of transparency in the process, critiqued subsequent
changes to the project design as addressing “only the concerns of Enron,” and found that Enron was given
undue favors and concessions. The report also found that the capital costs of the project were inflated, that
the rates for the power would be much higher than justified, in part because the contract was based on
U.S. dollars (placing the risk of currency fluctuations on the state), that there were outstanding
environmental questions, and that the project would adversely affect the state of Maharashtra.
Based on this evaluation, in August 1995, the state decided to halt construction and cancel the project. In
response to the state’s action, Enron sought $300 million in compensation, while attempting to convince
the Indian government to reverse its decision. In November 1995 negotiations resumed between Enron
and the state. On January 8, 1996, the state announced it would accept a revised agreement, and the terms
were finalized on February 23, 1996. As the MSEB was still committed to buying 90% of the plant’s
output and covering the risk of currency fluctuations, the project’s expansion increased the financial risk
to the state under the revised agreement. In addition, while the state announced that Enron had reduced
the capital costs of the project, critics charged that the reductions were largely the products of external
factors, not accommodations by Enron.
The price of the power from Dabhol turned out to be far beyond what consumers in the area will pay or
the state can afford. The financial problems began to appear in the winter of 2000. Phase I of the project
runs on naptha (a derivative of crude petroleum), but oil prices have apparently been higher than
projected, and demand has been substantially lower. In addition, the deal was structured to peg the costs
of power to the dollar, so the state bore the risk of currency fluctuations. The state was contracted to buy
the full output of the plant, but was purchasing only 10%-20% of the plant’s output from Phase I. The
state was obligated nonetheless to pay the plant’s full fixed costs, which further increased the rates. In
2001, power from Dabhol was four times more expensive than that from domestic power producers. The
payments due for the power from Dabhol alone would be more than Maharashtra’s entire budget for
primary and secondary education. These financial problems were expected to dramatically worsen after
Phase II came on line, as it would add an additional 1,444 megawatts of power and the entire project
would be converted to run off imported LNG, which could also raise the cost.
The state of Maharashtra did not pay its $ December 2000 bill, which was for $22 million. The state then
sought to cancel the PPA. Enron began arbitration proceedings in April 2001, ceased operation of the
Phase I portion of the plant in May 2001, and halted construction on the 90% completed Phase II portion
of the plant in June 2001. Enron claimed that the state owed it $64 million in unpaid bills.
In June 2001 MSEB terminated PPA with DPC, citing high power tariff. Six months later IDBI invited
EoIs for DPC sale. BSES, Tata Power, BG, Shell submitted their EoIs. Enron, GE and Bechtel targeted
$500 million as minimum bid, and in March 2002 the private players dropped out. In April 2003 DPC's
foreign lenders initiated arbitration process in London. Since then BG, BP and Tata Power have submitted
proposals to Indian Ministry of Finance to take over the company, but without results.
The Dabhol project is an example of a project financing deal that failed to appreciate the level of market
and political risk in host country. PPA and arbitration were not sufficient to protect the company when
the price differentials were unpopular. At the same time, the project demonstrates a fundamental
challenge in most emerging countries where investment in electricity is desperately needed to fuel and
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
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Economics of the Energy Industries
support economic growth: unless consumer prices can be brought to a level to reflect cost of investment,
it will be very difficult to successfully develop projects.
PT Paiton Energy project was the first IPP to be financed in Indonesia, and one of the largest to have
closed to date anywhere. Although the project's revenue stream was based on a local currency PPA
without a sovereign guarantee, commercial lenders agreed to provide a high level of limited recourse debt
after less than a year of negotiations. A combination of bilateral agency cover, a government provided
"comfort letter" supporting the state electricity firm, PLN, payment terms and rupiah/dollar conversion
mechanism indexed to prevailing exchange rates, fixed price turnkey construction contract, and the
strength of the project persuaded the lenders that the rewards of making the loans outweighed the
accompanying risks.
Asian financial crisis in late 1997 struck Indonesia hard, and by January 1998 the Indonesian government
had indefinitely postponed or canceled many of the IPPs. The Indonesian economy collapsed amid
massive unemployment and depreciation of the rupiah to a range of 12,000-16,000 rupiah/U.S. dollar.
This economic disaster, coupled with allegations of corruption, political instability, and renewed
resistance to privatizations, overwhelmed efforts to find a mutually acceptable solution to the problems of
the IPPs. Paiton continued throughout this period to seek a negotiated solution with PLN and the
Indonesian government. As the year progressed, though, the project sponsors and the Indonesian side
remained very far apart on terms of an acceptable settlement. The Paiton PPA obligated PLN to make
tariff payments in Indonesian rupiah, not U.S. dollars. However, under the PPA the amount of the rupiah
payment was adjusted to assure to Paiton the appropriate amount of U.S. dollars at then-current exchange
rates. Critically, the PPA also provided that, if the project company was unable to obtain spot foreignexchange contracts to promptly convert the rupiah payments into U.S. dollars, then PLN instead was
obligated to obtain the foreign-exchange contracts for the benefit of the project company. The Ministry of
Finance Support Letter covered all of the PLN obligations. Thus, the ultimate risk of foreign-exchange
availability, convertibility, and fluctuation was allocated to PLN and the Republic of Indonesia.
The Paiton project also benefited from approximately $1.8 billion in direct loans and debt insurance
provided by the U.S. and Japanese governments as export credit financing. Such large exposure assured
that the U.S. and Japan would pay close attention to the project. Moreover, U.S. Eximbank and other
export credit agencies have a policy of insisting that sponsors pledge their stock in the project company as
collateral security for export credits. That pledge significantly limits the value of equity political risk
insurance, since OPIC and many other insurers require the stock of the project company to be transferred
to the insurer free of liens as a condition to honoring expropriation claims. The Paiton sponsors could not,
therefore, recover on equity insurance to the exclusion of the project lenders.
Construction of the Paiton facility was close to completion when the financial crisis struck Indonesia.
Responding to the severe currency crisis, PLN unilaterally limited its tariff payments to Paiton by an
exchange rate of 2,450 rupiah/U.S. dollar and refused to accept energy from Paiton. Those
announcements led immediately to a financial crisis for Paiton. The project sponsors raised the prospect
of (but did not commence) arbitration against PLN and the Republic. In addition, the project sought the
political assistance of the U.S. and Japanese governments. This time, PLN struck first in October 1999
and filed a lawsuit against the project in the Central Jakarta District Court. In its filings, PLN argued inter
alia that the project documents were unenforceable by reason of force majeure, fraud, corruption, and
illegality. When the project company in turn commenced arbitration proceedings in Stockholm under the
project documents, the Jakarta court issued an anti-arbitration injunction backed by the threat of a U.S.
$600 million penalty for non-compliance. These litigation steps imperiled relations between the
Indonesian government and the U.S. and Japanese governments at exactly the same time Indonesia was
seeking international financial assistance to stem its economic crisis. Intense political and commercial
discussions resulted in a December 1999 decision by Indonesia's then--President Abdurrahman Wahid to
order a halt to PLN's litigation strategy. Instead, Wahid instructed PLN to agree to an interim settlement
requiring both sides to pursue negotiations rather than litigation. Senior officers of PLN resigned to
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
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Economics of the Energy Industries
protest Wahid's decision, but the President's order remained effective. Terms of a final settlement eluded
the project, however, until July 2002--almost five years from commencement of the dispute. Importantly,
at no time during the dispute did the project sponsors explicitly threaten to walk away from the project. In
July 2002, Paiton and PLN agreed to an amended PPA, and the stakeholders took active steps to project’s
debt restructuring. The deal was sealed in March 2003. As part of it, the Export Import Bank of the
United States (EXIMBANK) would provide a US$381 million direct loan to Paiton's power project.
EXIMBANK, along with the Japanese Bank for International Cooperation, Nippon Export and
Investment Insurance of Japan and the U.S, OPIC, were the major lenders to the project. In addition,
commercial banks from the U.S., Europe, Japan, Australia and other Asian countries and bond holders
also contributed to the project.
Sources of Funds
There are a few major agencies providing project financing in the energy sector. The main players could
be divided into two categories: development financial institutions (DFIs) and export credit agencies
(ECAs). DFIs try to foster economic development, and include the World Bank and its International
Finance Corporation (IFC) and Multilateral Investment Guarantee Agency (MIGA), European Bank for
Reconstruction and Development (EBRD), European Investment Bank (EIB), Asian Development Bank
(ADB) and others. ECAs try to help domestic firms export their goods and services into international
markets, and operate on a country basis, such as the Overseas Private Investment Corporation (OPIC) and
Export Import Bank of the U.S. (EXIMBANK), Japan Bank for International Cooperation (JBIC), Export
Development Corporation (EDC) in Canada, Export Credits Guarantee Department (ECGD) in United
Kingdom, Servizi Assicurativi del Commercio Estero (SACE) in Italy, Coface in France, Euler Hermes
Kreditversicherungs-AG (HERMES) in Germany, etc.
These institutions are the catalysts for a large number of projects in different nations in which
privatization of state energy operations and an increasing tendency for producing nations to enter the
downstream market are encouraging private projects. Furthermore, barriers to foreign investment in
domestic petroleum sectors are falling and oil and gas law reforms are under way especially in the
developing world.
World Bank’s International Finance Corporation (IFC) (http://www.ifc.org/) offers a range of financing
and advisory services that allow it to play a unique role in supporting private sector development of oil
and gas, and mineral reserves in its developing member countries. IFC has extensive experience in
financing oil, gas and mining projects in the developing world, and holds loan or equity investments in
more than 50 projects in 30 countries. In 1992, IFC created an Oil, Gas & Mining (OGM) Department to
handle its growing business in these sectors. IFC does not invest in pure exploration ventures, it is able to
invest in all other facets of the oil and gas business, including the funding of further exploration in areas
with fields in production, investments designed to appraise field reserves and bring a known reservoir into
production, and, where appropriate, in oil service companies.
Although IFC is primarily a financier of private sector projects, it may provide finance for a company
with some government ownership, provided that there is private sector participation and the venture is run
on a commercial basis. It can finance companies that are wholly locally owned as well as joint ventures
between foreign and local shareholders.
To ensure the participation of investors and lenders from the private sector, IFC limits the total amount of
own-account debt and equity financing it will provide for any single project. For new projects the
maximum is 25% of the total estimated project costs, or, on an exceptional basis, up 35% for small
projects. For expansion projects IFC may provide up to 50% of the project cost, provided its investments
do not exceed 25% of the total capitalization of the project company. On average, for every $1 of IFC
financing, other investors and lenders provide over $5.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
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Economics of the Energy Industries
An IFC investment typically ranges from $1 million to $100 million. Its funds may be used for permanent
working capital or for foreign or local expenditures in any IBRD member country to acquire fixed assets.
IFC’s gross loans and equity investments at the end of 2003 financial year were $9,242 million and
$2,760 million respectively, in addition to $1.1 billion in signed guarantees. Power sector accounted for
$2.4 billion. This amount is significantly lower than lending of $17,250.6 million in fiscal year 2001, out
of which $824.4 million went to electric power and other energy industries and $81.6 million went to the
oil and gas industry.
Multilateral Investment Guarantee Agency (MIGA) (http://www.miga.org/) was established on April 12,
1998. Its purpose is to encourage the flow of foreign direct investment to its developing member countries
for economic development. Its primary means of facilitating investment is through the provision of
investment guarantees against the risks of currency transfer, expropriation, breach of contract, and war
and civil disturbance (political risks).
MIGA offers long term (up to 15, sometimes 20, years) political risk insurance coverage to eligible
investors for qualified investments in developing member countries. MIGA can insure new-cross border
investments originating in any MIGA member country, destined for any developing member country.
An eligible investor is a national of a MIGA member country other than the country in which the
investment is to be made. However, under certain conditions, investments made by nationals of the host
country are also eligible. A corporation is eligible for coverage if it is either incorporated, and has its
principal place of business, in a member country or if it is majority-owned by nationals of member
countries.
Projected Level and Composition of Financing Energy Operations
Source: EBRD
European Bank for Reconstruction and Development (EBRD) (http://www.ebrd.com/) was established in
1991. It exists to foster the transition towards open market-oriented economies and to promote private and
entrepreneurial initiative in the countries of central and Eastern Europe and the Commonwealth of
Independent States (CIS). Through its investments it promotes private sector activity, the strengthening of
financial institutions and legal systems, and the development of the infrastructure needed to support the
private sector. The EBRD provides project-specific direct financing for private sector activities,
restructuring and privatization, or financing of infrastructure that supports these activities. Joint ventures
have been major beneficiaries of Bank lending, particularly those with foreign sponsors. The EBRD
offers several alternatives to provide direct funding to small and medium-sized enterprises (SMEs) such
as: loans, equity, guarantees and financing through intermediaries.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
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Economics of the Energy Industries
In 2000, EBRD financed 228 million euro into natural resources sector (9% of total financing activities by
the bank), 17 million euro into energy efficiency projects (1%), and 267 euro (10%) into power and
energy infrastructure projects.
The Overseas Private Investment Corporation (OPIC) (http://www.opic.gov/) is an independent U.S.
Government agency that sells investment services to assist U.S. companies investing in some 140
emerging economies around the world. OPIC provides financing through direct loans and loan guaranties
that provide medium- to long-term funding to ventures involving significant equity and/or management
participation by U.S. businesses.
OPIC can provide financing on a project finance or a corporate finance basis. As repayments of loans
depend on the cash flows generated by projects, OPIC carefully analyzes the economic, technical,
marketing and financial soundness of each project. There must be an adequate cash flow to pay all
operational costs, service all debt, and provide the owners or sponsors with an adequate return on their
investments.
OPIC can provide medium- and long-term financing in countries where conventional financial institutions
often are reluctant or unable to lend on such a basis. Since its programs support private sector investments
in financially viable projects, OPIC does not offer concessionary terms usually associated with
government-to-government lending, nor does it typically offer financing of export sales unrelated to longterm investments in overseas business. OPIC will not participate in projects that can secure adequate
financing from commercial sources.
OPIC provides loan guaranties, which are typically used for larger projects, and direct loans, which are
reserved for projects sponsored by or substantially involving U.S. small businesses and cooperatives.
OPIC can normally guarantee or lend up to $200 million per project.
Export-Import Bank of the United States (http://www.exim.gov/). The Bank offers limited recourse
project finance support to assist U.S. exporters competing in international growth industries such as the
development of private power and other infrastructure. This financing structure has been used
successfully for oil and gas, mining, and power projects, as well as telecommunications, transportation
and other sectors. Ex-Im Bank does not compete with private sector lenders but provides export financing
products that fill gaps in trade financing. It assumes credit and country risks that the private sector is
unable or unwilling to accept and also helps to level the playing field for U.S. exporters by matching the
financing that other governments provide to their exporters. Ex-Im Bank provides working capital
guarantees (pre-export financing); export credit insurance (post-export financing); and loan guarantees
and direct loans (buyer financing).
Japan Bank for International Cooperation (JBIC) (http://www.jbic.go.jp/english/index.php). JBIC 's
financial activities focus on projects in developing countries where local private financial institutions
cannot cover financing on their own, due to such factors as unstable economic conditions and the
necessities of long-term financing. As JBIC's mandate is the support of internationalization for Japanese
companies, its loans can be distinguished from Official Development Assistance (ODA), which aims at
the economic development and improved well-being of developing countries. JBIC operates on two fronts
in undertaking Japan's external economic policy and economic cooperation. On one front it conducts
International Financial Operations, which include export loans, import loans, overseas investment loans,
untied loans and equity participation in overseas projects of Japanese corporations. The other component
of the operations of JBIC is the Overseas Economic Cooperation Operations which provide financial
assistance including ODA loans. The basic tenet of these operations is to provide concessionary longterm, low-interest funds needed for the self-help efforts of developing countries, including social
infrastructure development and economic stabilization. More specifically, JBIC provides ODA loans in
various forms attuned to the existing needs, Private-Sector Investment Finance Supporting business
activities in developing countries, and development-related research.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
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Economics of the Energy Industries
Export Development Corporation (EDC) (http://www.edc.ca/index_e.htm) is focused on supporting
export and project financing for Canadian goods or services. EDC financing services extend beyond
countries in which EDC has established lines of credit. EDC helps Canadian exporters and investors
assess the long-term potential and manage the increased complexity and risk. In 2003, Canadian business
concluded $45.4 billion in export and domestic sales and investments in markets using EDC trade
financing services, up 13 per cent over the previous year. Financial services of EDC include credit
insurance, bonding and guarantees, political risk insurance, direct loans to buyers and lines of credit in
other countries to encourage buyers to “buy Canadian.” The Corporation also provides limited recourse
financing arrangements, and joint ventures for projects involving long-term leasing arrangements and
equity participation.
Export Credits Guarantee Department (ECGD) (http://www.ecgd.gov.uk/). ECGD was originally set up
in 1919 to help British exporters re-establish their trading positions following the disruption caused by the
Great War. This assistance largely took the form of providing insurance against the commercial and
political risks of not being paid by overseas buyers after goods were exported. In 1991, the arm of ECGD
which dealt with exporters who traded on short terms of credit (i.e. up to two years) was sold to NCM
Credit Insurance Ltd. Exporters of this type of goods, e.g. consumable items, can now obtain credit
insurance from a number of companies in the private market. ECGD still provide exporters of British
capital goods and services with finance and insurance packages to help them win valuable overseas
orders. ECGD can also insure British companies who invest abroad against the political risks of a nonreturn on their investments. ECGD issue around £3.5 billion of guarantees a year to cover a variety of
exports ranging, for instance, from textile machinery to Uzbekistan to multi-million pound power stations
in China. 55% of ECGD’s portfolio covers support for overseas civil projects, 24% is for defense-related
equipment and 21% is for civil aircraft (mostly Airbus). ECGD is also insuring over £800 million of
overseas investments (e.g., an office building in Morocco).
SACE S.p.a., Servizi Assicurativi del Commercio Estero (http://www.isace.it/portale/home.asp?l=eng) is
the Italian export credit agency. SACE S.p.a.’s capital is fully owned by the Ministry of Economy and
Finance, which appoints the members of the Board in agreement with the relevant ministries. SACE S.p.a.
provides support for the internationalization of the Italian economy by ensuring and reinsuring political,
economic and commercial risks to which Italian operators may be exposed in the process of their
international transactions. The Agency is authorised to enter into insurance, re-insurance and co-insurance
agreements covering risks of a political, catastrophic, economic and commercial nature and those inherent
in exchange rate fluctuations to which Italian entrepreneurs may be exposed in their transactions abroad
and, more generally, to promote the internationalisation of Italian economic undertakings.
With close to 60 years experience, Coface (http://www.coface.com/) facilitates transactions between
companies throughout the world. It offers businesses an array of solutions to manage, finance and protect
their commercial transactions, while giving them the option to outsource all or part of their trade
receivables management. Two core businesses are at the disposition of Coface's 83,000 customers
(domestic/export credit insurance and credit management services, including credit information, the
@rating Solution and trade receivables management and collection) alongside three complementary
activities (guarantee insurance, BtoB marketing and trade receivables financing). Coface has a direct
presence in 56 countries and through the CreditAlliance credit insurance network and the InfoAlliance
credit information network, its geographic reach spans 91 countries. These two networks are built around
an integrated product and service offer: the @rating Solution and a shared risk management system
(Common Risk System). Coface is one of the world leaders in credit insurance and credit management
services.
Euler Hermes Kreditversicherungs-AG (HERMES) (http://www.hermes-kredit.com/ger/en/index.html) is
the worldwide leader in credit insurance, the leading European group in factoring and one of the leaders
in bonding and guarantees. With 6,000 employees in 36 countries, Euler Hermes has a share of 36% of
the global credit insurance market and offers a complete range of services for the management of
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
8 - 14
Economics of the Energy Industries
customer receivables. A member of the Allianz group and subsidiary of AGF, Euler Hermes is listed on
the Premier Marché of Euronext Paris. Standard & Poor’s rates the Group and its principal credit
insurance subsidiaries A+.
Relevant Case Studies:
The Bolivia-to-Brazil Pipeline
The Chad-Cameroon Pipeline
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
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Economics of the Energy Industries
Appendix 1. Diagram of a Typical Project-Financed Deal
Source: http://www.constructionweblinks.com/Resources/Industry_Reports__Newsletters/June_3_2002/project_finance.htm
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
8 - 16
Economics of the Energy Industries
Appendix 2. Top 10 global project finance deals 2003
1
2
Borrower
Metronet
Project
Metronet London
Underground
Nanhai Petrochemical
Project
Eurogen Refinancing
Country
UK
Sector
Urban railway
Amount
($ million)
4,871.92
China
Petrochemicals
4,300.00
Italy
Power
2,733.54.00
3
CNOOC Shell
Petrochemical
Edipower
4
J-COM Finance
J-COM Refinacing &
Expansion
Japan
Telecom
2,400.00
5
Paradigm Secure
Communications
Empresa Nacional de
Autopistas (ENA)
Skynet 5
UK
Defence
2,073.87
ENA Privatization
Spain
Road
1,865.89
6
7
Arabian Power
Umm al-Nar IWPP
UAE
Power
1,777.50
8
PT Paiton Energy
Indonesia
Power
1,729.50
9
Aluminium Bahrain
Paiton I Debt
Restructuring
Alba Aluminiunm
Smelter Expansion
Bahrain
Processing
plant
1,700.00
10
SKS Power
Power
1,532.60
Tanjung Bin Power
Malaysia
Project
Source: Dealogic via Euromoney Institutional Investor PLC.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
8 - 17
Economics of the Energy Industries
SECTION 3 – ENERGY VALUE CHAIN SEGMENTS
UPSTREAM:
CHAPTER 9 – EXPLORATION AND PRODUCTION
MIDSTREAM:
CHAPTER 10 – PIPELINES
CHAPTER 11 – NATURAL GAS PROCESSING
CHAPTER 12 – LIQUEFIED NATURAL GAS
DOWNSTREAM:
CHAPTER 13 – REFINING AND MARKETING
CHAPTER 14 – ELECTRIC POWER GENERATION
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
Economics of the Energy Industries
CHAPTER 9 - EXPLORATION AND PRODUCTION
Economics of Exhaustible Resources
Fossil fuels (coal, oil and natural gas) have been the major sources of energy in the world for a long time.
They are considered nonrenewable (or exhaustible) since it takes millions of years for these fuels to form
in the earth’s crust. The fact that the store of oil and gas is ultimately exhaustible has been a cause for
concern, depending upon perceptions about how large that store is. For example, there were predictions
that the production of oil in the U.S. would end within the 20th century, but additions to reserves proved
those predictions wrong. Advances in technology, due in part to the oil price shocks of the 1970s, have
helped to extend the ultimate life of the U.S. reserve base. The combination of higher oil prices and
technology advances also resulted in additions to the world’s resource base of oil and gas.
Nevertheless, it is a geological fact that oil and gas resources are not infinite (at least based on current
knowledge). However, it may be more important to consider the “economic life” of the resource rather
than the “geologic life.” For some oil and gas producing basins, the cost of extraction may increase faster
than the increase in the price of oil or gas. That is, the resources in the basin are being depleted at a faster
rate (or reserves are being added at a slower rate) than the general rise in oil and gas prices associated
with gradual depletion of the worldwide resource base. In this example, the economic life of the resource
is shorter than the geologic life. Importantly, the economic life of a basin, or its commercial viability, is
always subject to change given technology development and disruptions in oil and gas prices, as well as
the attractiveness of competing investment opportunities.
A critical question is whether oil and gas resources are being depleted too rapidly (for instance, by
inadequate conservation practices) or too slowly (for instance, by a cartel limiting its production in order
to raise prices). In either situation, we are most concerned with the optimal rate of production. This rate
is likely to differ between companies (or countries) as well as under different market conditions. Most
probably, all of these situations will be different from the “socially optimal” rate. The latter, which is
qualitatively equivalent to competitive outcome, is the case we will demonstrate.
Optimal Depletion
The objective of the resource owner (a company or a country) is to allocate the resource over time in such
a way to maximize its value (profit or social welfare) if we assume a “fixed” amount of the resource.
There are several imperfections affecting the solution to this problem:
- exercise of market power by a group of producers,
- environmental concerns about the production and consumption of fossil fuels,
- uncertainty of discovery,
- long-lasting effects of current decisions about their use,
- uncertainty of future demand conditions.
However, we will use a very simple approach, which is sufficient to demonstrate the basic principles of
economics of exhaustible resources. Most of the issues listed above will be addressed in more detail in
later chapters, as they are fairly relevant factors during the phase of project evaluation.
With exhaustible resources, production of a unit today involves an opportunity cost: the foregone value
of producing that unit at a later date. This opportunity cost must be taken into account in determining
how to allocate the resource over time. In particular, instead of the usual efficiency condition (or
competitive equilibrium condition),
Price = Marginal Cost,
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
9–1
Economics of the Energy Industries
we have
Price = Marginal Cost + Opportunity Cost.
The difference between the price and the marginal cost is also known as “user cost,” “royalty” or “rent”
(Hotelling rent). Therefore, the optimal depletion of exhaustible resources leads to a higher price and a
lower level of production than competitive equilibrium would dictate for any other commodity. The Price
= Marginal Cost rule would lead to (Pe,Qe) as equilibrium (see graph below). However, the opportunity
cost of exhausting a unit today, which is equal to the difference between points A and B (or P*-Pe), raises
the actual price to P* and lowers the actual output to Q*.
Opportunity Cost for an Exhaustible Resource
Price
A
P*
Pe
B
Marginal Cost
Demand
Q*
Qe
Quantity
The behavior of this rent over time is important. After all, there will be a royalty tomorrow if the
production of one barrel of oil is postponed until tomorrow. When is it, then, most beneficial for the
producer to extract that barrel? To answer this question, let us work through a simple example. Suppose
there are only 10 barrels of oil in the ground in total and that the marginal cost of production is constant at
$2 per barrel. Also, assume that the demand in period t is given by the following equation: Pt = 10 - Qt.
Let us set the discount rate to 10%, r = 0.1. Finally, let us also assume, for simplicity, that the field will
be exhausted after two periods.
For an efficient outcome in each period, the objective is to maximize the net benefit, which is usually
defined as the difference between what consumers are willing to pay and what it costs to produce. In
Figure 1.1, this is the area below the Demand curve and above the Marginal Cost curve up to Q*. Given a
time horizon of two periods, the objective is to choose a level of production in each period in order to
maximize the sum of the net benefits over two periods (naturally, the second period’s benefits are
discounted to obtain a present value for them). The constraint is that the total ultimate production is
limited to 10 barrels.
Without going into details, we can examine the simple results. Optimal levels of output for this problem
turn out to be 5.14 barrels in the first period and 4.86 barrels in the second period. When we put these
values into our demand function, we obtain $4.86 and $5.14 as the price of a barrel in the first and second
periods, respectively. Given that marginal cost is $2 per barrel, the rent is equal to $2.86 in the first
period and $3.14 in the second. Notice that, with discounting, $3.14 is equal to $2.86 (=3.14/(1+0.1)).
This is an important result since it implies that the undiscounted rent must rise at the rate of interest. This
is known as the r% (or Hotelling) rule. Note that even if the assumption of constant marginal cost is
replaced by the more realistic assumption of increasing marginal cost, the rule still applies.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
9-2
Economics of the Energy Industries
Unlike capital assets, like factory equipment, there are no dividends or depreciation for exhaustible
resources and therefore the return must come entirely as a rise in the value of the asset. The value of
exhaustible resources is the rent. Ideally, production is distributed over time in such a way that the rent
rises at the rate of interest. This also implies that the price of a barrel of oil will also increase
continuously, because price equals marginal cost plus rent. However, this is not possible. In our simple
example, the demand equation tells us that when the price reaches $10 a barrel, the quantity demanded
will fall to 0. If price rises enough, people will have an incentive to develop substitute fuels or
technologies which can replace oil. For example, renewable technologies, that are currently not
commercially viable relative to oil, may replace oil as a source of energy if the price of the latter reaches a
level where it would be economically feasible to switch to renewables from oil.
Accordingly, the r% rule also implies a decreasing output over time. Of course, demand for oil and gas
may rise over time, technological improvements may increase productivity or lead to additions to existing
reserves and some other factors may impact the smooth pattern of extraction depicted in our figure. The
r% rule itself is not sacred. If one allows for decreasing quality of oil extracted, for example, the rent will
increase at a rate less than the interest rate. However, this only affects the degree of extraction and
therefore the time horizon over which the resource will be exhausted, but not the downward trend of
output.
Time Path of Price & Output for an Exhaustible Resource
Price,
Output
Backstop
Technologies
Price
Output
Time
Historically, price and output of oil and gas have not followed the smooth patterns our model predicts.
Instead, they have fluctuated. The assumptions of our simple model about fixed marginal cost and fixed
known amount of resource can be changed. This would lead to less smooth patterns for the price and
extraction; but, overall, price will rise and output will decline as exhaustion approaches.
The world price of crude oil slightly declined from the early 1950s until the early 1970s, but has become
quite volatile and unpredictable since then (see chart below). The discrepancy between forecasts (those of
the U.S. Department of Energy are presented) and actual prices shows that it is very difficult to accurately
predict future prices. As we addressed above, the historical data do not concur with the theory of
exhaustible resources. This is partially due to some of the assumptions of the theory that are not
consistent with the practice in the industry. Two of these assumptions are discussed further in the
following section.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
9–3
Economics of the Energy Industries
Historical Price of Crude Oil and Price Forecasts
Source: “Forecasting Oil Supply: Theory and Practice” by Michael C. Lynch, July 2001.
OIL AND GAS RESERVE TERMINOLOGY
Recoverable Resources
(Society of Petroleum Engineers)
Shortcomings of the Theory
Reserve Additions
Total Oil and Gas
Resource
Discovered
Nonrecoverabl
e
Resources
Undiscovered
Recoverable
Resources
Reserves
Proved
Reserves
Cumulative
Production
Unproved
Reserves
Probable
Reserves
Possible
Reserves
Two critical assumptions that underlie the economics of
exhaustible resources and models of the oil and gas resource
base are flawed. One is the idea that there is a known and
fixed amount of oil and gas in any given basin at the
beginning of operations. Recall that the cost of extraction in
a basin may increase at a slower rate than the general rise in
oil and gas prices, and that the slow increase in extraction
costs is due to reserve additions. Technology improvements
and the general rise in oil and gas prices may combine to
extend the geologic life of a basin far beyond what economic
theory would suggest or assume. In fact, reserve additions
(see chart at left for basic reserve categories) that extend the
geologic life of a producing area have been some of the most
important factors in the significant upward revisions of oil
and gas resources around the world. This is true particularly
in mature provinces like the U.S. and the North Sea.
Upward revisions in estimates of the world’s oil and gas
resources are also the main reason for why forecasts of oil
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
9-4
Economics of the Energy Industries
and gas supply and prices are usually wrong.
The following chart presents the historical data on the worldwide additions to oil reserves. The values
represented in the chart are calculated as the reserves in year t+1 minus reserves in year t plus production
in year t. Except for three years in the 1970s, it appears that oil producing countries and companies have
been able to add to the proved reserves. Also, one cannot determine a trend, downward or upward, in
additions to reserves looking at this data, which seems to support that more discoveries are made, more
resources are proved in existing fields as the market price for oil is high enough to justify necessary
investments.
Worldwide Reserves Additions (billion barrels)
200
150
Reserve Additions
100
50
0
1960
1965
1970
1975
1980
1985
1990
1995
2000
-50
Source: Calculated based on Oil & Gas Journal data
Common Pool Problem
The second flawed assumption in the economics of exhaustible resources is that free competition among
producers lead to optimal rates of production. If a number of producers are extracting oil and gas from a
common pool, they each have an incentive to extract as much as they can in order to maximize their
revenue and profit. We call this a “common pool problem” and it exists for all natural resources, like
timber, fisheries and non-fuel minerals. A solution is to establish rules that lead to more efficient
resource extraction, what we typically refer to as “conservation practices.” The most important feature of
conservation practices is shared information among producers and a third party, usually the government.
There are many examples of the common pool problem for oil and gas, but perhaps the most famous is
the situation in Texas at the turn of the century, when the giant East Texas and Yates fields were
discovered. Intense competition among producers resulted in waste and extensive reservoir damage, and
caused the price of oil to collapse. The Texas Railroad Commission was given the authority in 1928 to
regulate oil and gas production and, through its conservation practices, effectively controlled the world
price of oil until OPEC’s first embargo in 1973.
A more recent example is the dispute between Qatar and Iran over the gas in the Persian Gulf. Two
countries differ significantly in their estimates of how much gas each side has. Qatar already started
production from several offshore platforms near the Iranian border. Iran complains that Qatar is
producing from Iranian reservoirs. As a result, although the country does not need the output from this
field, Iran decided to develop fields on its side of the border before Qatar extracts more than its “fair”
share.
Exploration and Production
As we have seen in the previous chapter, companies study in detail every single project before they
actually go ahead with it. Net Present Value (NPV) and Internal Rate of Return (IRR) are two of the
decision criteria employed by companies to evaluate different projects. Since there is considerable
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
9–5
Economics of the Energy Industries
uncertainty about the future values of variables used in calculating these criteria, the evaluation process
needs to include some kind of likelihood (or probability) analysis. Decision trees, sensitivity analysis and
simulation (also known as Monte Carlo simulation) are some of the tools available to professionals.
Decision trees and simulation involve assigning probabilities to different values of crucial variables of the
model. In order to be able to do this, considerable amount of data is required. Sensitivity analysis, on the
other hand, studies the effect of a change in one (or more) variables on the NPV (or IRR) of the project.
For example, managers may want to know how the NPV of the project would change if the price is 10%
less than what was initially assumed.
Petroleum exploration and production (E&P) projects are fairly complicated as they contain several stages
each containing quite a few crucial variables. From the beginning, the inability to determine with
certainty the geological characteristics of a project area indicates the necessity of probability analysis.
Political factors, although not always built into the cash flow calculations, also have significant bearing
on the outcome. In order to predict future values of crucial variables as accurately as possible, a
considerable amount of data needs to be collected and analyzed. In the following sections, we will
discuss these aspects of E&P in more detail.
Geological Characteristics
Petroleum is formed under the earth’s crust after the hydrocarbon-bearing matter, coming mostly from
marine organisms deposited in marine sediments, has been exposed to high temperatures over a long
period of time. Heat and pressure cause complex kerogen molecules to break down into simpler
hydrocarbon molecules. This is known as the thermal cracking process. When “synthetic” oil and gas are
manufactured from coal and oil shale, we are simply completing a process of nature, for coal and oil shale
have not been buried deep enough or long enough for oil and gas to form.
Petroleum can be produced only from rock formations that possess “porosity,” void spaces in the rock and
can only move through a rock possessing some “permeability,” passages connecting the pores. Both are
needed for oil to migrate and then be recovered from its trap when found. There are different kinds of
traps where oil and gas can be found. Some are easier to detect by geological studies than others.
Water occupies some of total pore space in a rock formation. The fraction of water is called “water
saturation.” The higher the level of water saturation, the lower will be the amount of oil and gas that can
be extracted as water will move up the well bores along with oil and gas. In the beginning, the amount of
water extracted may be low, but as production continues, the water saturation in the reservoir will
increase as well as the amount of water extracted. Naturally, this will reduce the value of production as
the same effort and expense provides less oil and more water.
All of these geological aspects of oil have some bearing on exploration and production operations since
they help determine the amount of oil and gas that occurs and that can be produced. Eventually, geologic
factors impact the question of commercial viability of a project. Despite developing technology,
geophysical, geographical and topographical studies cannot provide anything better than an estimate
about the size of the reservoir or production conditions. This uncertainty creates the risk a company
needs to evaluate before it starts the exploratory drilling.
Economic Factors
Exploration is a time intensive activity and the rewards cannot be reaped until geological studies are
completed and exploratory wells determine the existence of commercial quantities of oil and gas. This
situation creates the problem of time inconsistency, when initial estimates of crucial variables diverge
from actual values when the project is completed. A prime example is the price of oil. Uncertainty about
the price of oil has been a fact of life since the turbulent 1970s. The estimate used in the beginning to
evaluate a project may be much different than the actual value at the end. Similarly, operating costs may
turn out higher than initially estimated.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
9-6
Economics of the Energy Industries
Economic conditions in the country where a project is going to take place are also relevant. The
uncertainty about the rate of inflation and tax rates, among other things, creates potentially risky
situations for international investors. Some of these factors are complicated even further by the political
situation in the host country.
Political Aspects
The major energy companies have always been involved in exploration and production projects all over
the world. The political and legal environment of the country where a project is to take place has
significant bearing on the cash flow analysis of the project as it affects the returns to the company through
taxes, royalties, production sharing agreements, and so on. When evaluating a capital expenditure to be
made in another country, the parent firm must be concerned with the cash flows that can be expected to be
received by the parent and not the overseas subsidiary as the host country may block the subsidiary from
remitting funds back to the parent (repatriation). It is also possible that the host government can take the
parent’s assets in the subsidiary with inadequate or no compensation. Exchange rates between the
country’s currency and that of the parent company can create risk as well. A host country’s geographic
location and its relationship with its neighbors are also important as these may impact solutions to the
problem of getting oil/gas to the market from the producing field.
Most of the time, companies operational in different countries diversify their risks, in much the same way
as individuals manage their investment portfolios; by mixing low risk projects with high risk but high
return projects in different parts of the world.
Occasionally, international politics can play a role as well. After the Gulf Crisis in 1990-91, Iraq was
banned from selling oil and foreign companies were not allowed to invest in Iraq due to U.N. sanctions.
Also, the U.S. sanctions on countries such as Libya and Iran prevents U.S. companies from investing in
these countries. Conoco, Chevron, Amoco and others invested considerable sums in countries where later
restrictions prevented them from operating. These examples show that international as well as home
country politics may present issues to consider for companies during project evaluation.
Technical Aspects of E&P Operations
Exploration is the riskiest undertaking of the oil and gas business, as it requires large amounts of capital
investment before the existence, volume and quality of hydrocarbons are known. The quality of oil and
gas, once found, may be lower than expected. For example, oil and gas may contain high proportions of
sulfur and other contaminants, requiring expensive treatment before they can be transported from the
field. Instead of more valuable light crude oil, a heavier type can be found. More exploratory wells may
be needed which would increase the capital costs of a project eventually lowering the net present value of
cash flows even if everything else goes as estimated. In order to get a better understanding of what is
involved in E&P operations and sources of risk, let us take a closer look at the costs involved.
Exploration costs include the following.
-
Topographical, geographical and geophysical (G&G) studies, rights of access to properties to conduct
these studies and salaries and other expenses of people involved in these studies.
-
Costs of carrying and retaining undeveloped properties, such as rentals, taxes, legal costs and
maintenance of the land and lease records.
-
Dry hole contributions and bottom hole contributions.
-
Costs of drilling and equipping exploratory wells.
-
Costs of drilling exploratory-type stratigraphic test wells.
The first two items are incurred before finding any commercial sources and can be substantial depending
on the length of these analyses. G&G studies locate an area under which significant amounts of oil and
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
9–7
Economics of the Energy Industries
gas may be trapped. Then, the first exploratory well needs to be drilled in order to actually establish the
existence and size of the reservoir. The first well provides additional data on:
-
initial reservoir pressure and temperature,
-
formation properties,
-
fluid properties,
-
short-term flow tests to estimate the potential rate and reservoir extent,
-
geological sample data and depth reference points for modification of pre-drilling data.
Despite all these data and analysis, a reserve number is just an estimate, not an absolute quantity. And
once production starts, reservoir conditions may change and production rates may fall. There are natural
factors that help push oil and gas out of the well bores.
-
If the pressure in the formation is higher than the pressure in the well, it will push the oil and gas up
the well bores.
-
An aquifer, which expands in size as production continues, will act as a piston and push the fluids up.
-
A gas cap, which expands as production continues can push the oil out of the pores toward the well.
-
If the reservoir has enough vertical permeability, gas rises and oil falls because of density differences.
This separation of oil and gas enhances oil recovery.
On the other hand, there are some natural forces that resist the upward flow of oil.
-
Significant capillary forces in tight sections of the formation, where permeability and porosity are
low, reduce the flow of oil and gas.
-
Low permeability and porosity mean that the rock is tight and cannot produce at commercial rates.
-
Limitedness of the area of flow around the well bore can also lower the rate of production. The
thicker the producing strata, the greater should be the rate of extraction, other things being equal.
-
If oil is high in viscosity, it will not flow as easily.
-
The farther oil needs to flow to reach the well, that is, the deeper the objective, the greater will be the
resistance to flow.
If the resistance to flow overwhelms natural driving forces or production declines rapidly after completion
due to certain unfavorable formation conditions, some techniques to enhance oil and gas recovery may be
needed. A few examples are listed below.
-
Water flooding is sometimes used to increase pressure, in a process called “secondary recovery.”
This involves injection of water under pressure to push oil to the producing wells. Sometimes
chemical solutions (detergents), carbon dioxide or other substances may be used, in a process called
“tertiary recovery.”
-
Associated gas produced along with oil may be reinjected into the reservoir to push oil reserves up.
-
When oil is high in viscosity, a steam flood may reduce viscosity and hence increase the rate of flow.
-
Part of the oil can be burned in the reservoir to lower viscosity and help produce the rest of oil.
-
Gas often occurs in low quality reservoirs. “Nonconventional gas” produced from coal (coalbed
methane), from shales or from tight sands generally requires that the formation be fractured.
“Fracing” involves pumping fluids into the producing zones under extremely high pressures in order
to increase, widen and connect the naturally occurring fracture system.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
9-8
Economics of the Energy Industries
There are other options as well. However, all are fairly expensive. The decision to employ these methods
depends on the expected increase in production rate. Unfortunately, it is difficult to accurately estimate
enhanced recovery performance of each method. Also, the success of each method changes from field to
field. A careful evaluation of options in each individual situation is necessary.
As we have seen, E&P operations involve quite a few stages each presenting challenges to decision
makers. In considering an E&P project, a company is trying to maximize the net present value of the
future streams of after-tax cash flows over a horizon of usually 30 to 40 years. Ideally, the decision
makers would like to be able to predict all the variables as accurately as possible. But, beginning with the
price of oil, there are many factors that will change over the course of the operation. The more
uncertainty there is, the higher is the risk and the higher the rate of return a company will require to
undertake a certain project.
E&P projects are expensive in that they require large sums of initial investment. Many companies and
host countries are not able or willing to meet these requirements. On the other hand, international capital
markets are becoming more and more competitive as emerging economies need more capital to finance
their economic development. Therefore, both companies and host governments need to deal with the
lenders who usually prefer lower risk projects. With the level of competition for funds that exists today,
lenders have the luxury of being selective.
Models of E&P Investment
The table at the end of the chapter represents cash flow calculations used in evaluating E&P projects for a
typical production sharing contract (PSC). It does not include everything discussed in the previous
section, but the most crucial variables such as reserve size, bonuses, royalty share, and so on are analyzed
(see appendix to this chapter for details on petroleum fiscal systems). Naturally, the price of oil is also
considered as one of the most volatile and significant variables for oil projects. Two decision criteria, net
present value (NPV) of cash flows (at different discount rates) and the corresponding internal rate of
return (IRR) as introduced in Chapter 3, are also presented. In our example, annual cash flow is
calculated as follows.
Cash Flow = Net Revenues – Intangible Expenses – Tangible Expenses – O&M Expenses –
Bonuses – Total Profit Oil + Contractor’s Profit Oil – Income Tax
Where
Net Revenues = Gross Revenues – Royalties = Price x Production – Royalty Rate x Gross
Revenues = (1-Royalty Rate) x Gross Revenues
Tangible Expenses are based on the costs associated with exploratory and development wells and
other infrastructure that needs to be developed before production can start. Exploration usually
takes place first. So, in this example, we have $5 million in Year 1 for G&G expenditures, $25
million for two exploratory wells in Year 2, $125 million in Year 3 for development drilling and
$160 million in Year 4 to complete the infrastructure in the production site.
Intangible Expenses are calculated as a portion of Tangible Expenses but are non-depreciable.
Usually, these costs are rolled in Tangible Expenses with PSCs as part of the cost recovery
process.
O&M Expenses are simply calculated as the product of oil production times per barrel O&M
costs (usually these can be estimated based on the data package on the field, G&G analysis and
information about historical cost in the same region).
Bonuses are usually paid at contract signing or when the production starts or at both times. Note
that if the field was acquired after an auction round, the bid paid as a result of the auction would
also have to be considered as an upfront expense similar to bonuses.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
9–9
Economics of the Energy Industries
Total Profit Oil = Net Revenues – Cost Oil if this difference is positive, otherwise 0. Cost Oil is
the portion of costs that the contractor is allowed to recover under the terms of the PSC contract.
For this calculation, costs = Intangible Expenses + O&M Expenses + DDA (Depletion,
Depreciation & Amortization). As long as these costs are less than the cost recovery amount
(=cost recovery percent agreed in the PSC x Gross Revenues), they can all be considered in Total
Profit Oil calculation as Cost Oil.
Contractor’s Profit Oil = Total Profit Oil x Contractor’s Profit Share
Income Tax is basically equal to the taxes paid out of Contractor’s Profit Oil based on the tax
rate. Tax Loss Carry Forward is used to account for tax reimbursements for taxes paid before
production and, hence, revenues start.
Some of the key input variables that are usually set during the bidding stage or through negotiations with
the government entities are provided in the table below. Production profile is consistent with estimated
reserves of 319 million barrels for a 30-year project.
Some Key Input Variables
O&M cost per barrel, cost recovery limit (usually
between 80% and 100%), contractor profit share, income
Reserves (million bbls)
319
tax, royalty rate and bonuses that are used in above cash
O&M Cost ($/bbl)
$2
flow calculations are provided as inputs in this table. In
Fiscal Terms
addition, price is set as $25 per barrel.
Royalty Rate
Signing Bonus (million $)
Contractor Profit Share
Cost Recovery Limit (80-100%)
Income Tax Rate
Oil Price ($/bbl)
Discount Rate
12.5%
$50
65%
80%
30%
$25
10%
Our calculations show that, over 30 years, this project
yields an NPV of $596 million at a 10% discount rate
with an IRR of 32%. At 15% discount rate, the NPV
goes down to $317 million. The project looks good
under these criteria.
There are two other criteria that are used to assess
upstream projects: present worth payout (PWP) and
present worth index (PWI). PWP is the time it takes to
recover an investment in terms of present value dollars.
It represents the elapsed time (expressed in years) that it
takes for the present value of the net cash inflows to equal the present value of the net cash outflows. It is
measured from the initial outflow of funds. PWI is the ratio of the present value of cash inflows to the
present value of the cash outflows. PWI measures the relative attractiveness of projects per dollar of
investment. For the project reviewed in this section, PWP is equal to 7.3 years and PWI is equal to 3.33
(see cash flow table at the end of the chapter for calculations). The project promises to allow recovery of
upfront investment in about 7 years with overall inflows more than three times the initial outflows. A
comparison of these four evaluation criteria follows.
Production Profile
No. of Producing Wells
Plateau Rate (bbls/day)
Annual Plateau Production (million bbls)
Project Life
Decline Rate (3-7%)
Measure
NPV
25
50,000
18.3
30
7%
Comparison of Project Evaluation Criteria
Strength / Purpose
Weakness / Drawback
Measures the economic value expected to be
Does not consider time length to achieve that
generated by the project at the time of
value. Is dependent on cost of capital used.
investment. It represents the value being added to
the Company by making the investment.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
9 - 10
Economics of the Energy Industries
Measure
IRR
PWP
PWI
Comparison of Project Evaluation Criteria
Strength / Purpose
Weakness / Drawback
Measures the efficiency of the project in
There are many reasons why an investment with
producing value without reference to any
a lower IRR could be preferred to one with a
predetermined cost of capital. When compared to higher one. IRR assumes that project cash flows
the cost of capital IRR can be an indication of
are reinvested at the same rate of return as the
how effective a particular project is in adding
project generates. Favors projects with a quick
value.
payout or short-term in nature. It is a useful
indicator when considered with the other three
criteria for comparing projects.
Measures the time that the net investment will be Only measures the project result up to the time of
at risk. The longer the payout period, the more
payback. Disregards any cash flow received after
chance for some unfavorable circumstance to
payback. Is dependent on cost of capital used. Is
occur. Is also a value indicator. If a project that is not a measure of risk, only of time.
expected to last 10 years has a three year payout,
then 30% of the project's life is committed to
recouping investment and 70% is devoted to
creating value for the company.
Measures the efficiency of invested capital. For
Is dependent on cost of capital used. If cost of
every dollar invested, how efficient is it in
capital is over or underestimated could result in
producing value. Best measure for comparing
selection of wrong project.
and deciding between mutually exclusive
projects.
Production path and annual cash flow for the lifetime of the project are depicted below. Note that
production does not start until the fifth year of the project (including Year 0 when signing bonus was
paid). During the first four years, the contractor invest heavily in G&G analysis, drilling exploratory and
development wells and, if the field is promising, the development of the rest of the production
infrastructure. Also note that production peaks fairly rapidly in the first few years of production, reaching
a plateau that is sustained for several years and then follows a smooth decline curve. In the absence of
reserve additions, this is one of the results of the exhaustible resource model. Upstream operations after
reaching the plateau are very much directed towards sustaining higher levels of output and restraining the
pace of the decline. Naturally, cash flows reflect the upfront investment requirements (significant cash
outflows in first 4-5 years and follow a pattern almost identical to that of production, with cash inflows
peaking together with production, once oil starts to follow.
million barrels a year
20
Production & Cash Flow
$ million
250
18
200
16
150
14
12
100
10
50
8
6
Production
Cash Flow
0
-50
4
-100
2
0
-150
0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
9 – 11
Economics of the Energy Industries
For this project, NPV is greater than 0 and IRR is greater than 10%, supporting a “go” decision on the
project. PWP and PWI also indicate a “go” decision. But, this single observation cannot be taken as
granted since our assumptions about certain variables may not hold in the future, impacting the projected
cash flows. Usually, decision makers would like to learn about different scenarios. For example, they
may be interested in following scenarios.
•
What if the price of oil is $20 instead of $25? New NPV = $421 million and new IRR =27%. Note
that the price of oil is never stable. Our simplifying average price assumption can be very misleading.
For example, if the price of oil collapses when the field’s production is peaking, the project will
definitely feel the damage. The longer the price stays low in this period, the worse it will be for the
contractor. See an example of price fluctuations below.
•
What if O&M costs per barrel doubles to $4? New NPV = $516 million and new IRR =30%.
•
What if only 150 million barrels could be recovered from the reserves? New NPV = $405 million and
new IRR =31%. Note that, in this case, the contractor can also make adjustments to number of wells
drilled to either extend the life of the reserves or quickly produce and recover its costs.
•
What if the contractor was awarded this field as a result of an auction following a $100 million bid?
New NPV = $496 million and new IRR =23%.
•
What if all of these four conditions occur for the project? New NPV = $111 million and new IRR =
14%. Although still a positively assessed opportunity, the project looks much less attractive.
Naturally, there are many other things that can go wrong, as discussed earlier in this chapter, including
some non-economic factors. Many are not reflected in our simple model. But, even with more variables,
this type of sensitivity analysis, although useful, does not cover all possibilities with enough scrutiny.
A more sophisticated approach called simulation analysis (Monte Carlo simulation) is more widely used.
Computers have made it both feasible and relatively inexpensive to apply simulation techniques to capital
budgeting decisions. The simulation approach generally is more appropriate for analyzing larger projects.
A simulation is a financial planning tool that models some event. When simulation is used in capital
budgeting, it requires that estimates be made of the probability distribution of each cash flow element
(reserves, price of oil, O&M costs, and so on). These probability distributions then are entered into the
simulation model to compute the project's net present value probability distribution.
The simulation approach is a powerful one because it explicitly recognizes all of the interactions among
the variables that influence a project's net present value. It provides both a mean net present value and a
standard deviation that can help the decision maker analyze trade-offs between risk and expected return.
Unfortunately, it can take considerable time and effort to gather the historical data necessary for each of
the input variables and to correctly formulate the probability distributions. Also, crucial variables such as
the price of crude oil have been very volatile and cannot be easily represented by normal, bell-shaped
probability distributions. This limits the feasibility of simulation to very large projects. In addition, the
scenario examples illustrated above assume that the values of the input variables are independent of one
another. If this is not true, then this interaction must be incorporated into the Monte Carlo model,
introducing even more complexity.
Oil Price Shocks
Finally, we analyze the effects of price shocks on the returns of the project. We consider two very simple
scenarios of identical price shocks but with different timing.
For the first scenario, we assume that the price of crude oil falls to $10 per barrel from $25 per barrel
during the second year of production, and stays at that level for five years before rising to first $15 for
four years, then to $20 for four years and then to $25. Despite subsequent increases, the crash in oil
prices causes the project NPV to fall to $230 million from $596 million. Accordingly, the project IRR is
now 19% as opposed to 32% we obtained from our original model.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
9 - 12
Economics of the Energy Industries
For the second scenario, we push the same price cycle to five years later. Although lower than original,
the NPV is now $406 million and the IRR is 29%. The same price shocks coming five years later in the
life of this project makes a significant difference.
The following chart shows the fluctuations in the cash flow of the project that are due to price shocks
under the two scenarios. Clearly, in the first scenario, the contractor can postpone some of the production
anticipating the eventual rise of the price again (historically this has been the case; besides OPEC can
always play a role if price is too low), but this will probably be costly. In addition, the contractor may be
bound contractually to sustain production at certain level. Nevertheless, it is also clear that the first
scenario can be detrimental for many projects.
$ million
250
Cash flows under two price shock scenarios
200
First
150
Second
100
50
30
28
26
24
22
20
18
16
14
12
10
8
6
4
-50
2
0
0
-100
-150
Relevant Case Studies:
Apertura in Venezuela
Brazil’s Restructuring of the Oil & Gas Industry
Chad Cameroon Pipeline
Deepwater Developments in Angola
Deepwater Developments in Brazil
Energy Inc. Deepwater Project
North Atlantic Canada
Oil Monetization in Azerbaijan
Soviet Legacy on Russian Petroleum Industry
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
9 – 13
Sample Production Sharing Contract Cash Flow Projection
Oil
Year
Oil
Production
Price
(mmbbls)
($/bbl)
Gross
Net
Intangible Tangible Operating
Revenues Royalty Revenues
($MM)
($MM)
Contractor
($MM)
Cap Ex
Cap Ex
Expense
($MM)
($MM)
($MM)
80%
Bonus DD&A
Cumulative
Total
Contractor
Government
Cost
Profit
Profit
Profit
Tax
Oil
Oil
Oil
Oil
Loss C/F
Tax
Flow
Flow
Flow
($MM)
($MM)
($MM)
($MM)
($MM)
($MM)
($MM)
($MM) ($MM) ($MM) ($MM)
Income
Net
PV Net
Net
Cash
Cash
Cash
20%
0
0.00
25.00
0
0
0
0
(50)
(50)
1
0.00
25.00
0
0
0
5
50
0
(5)
(5)
(50)
(55)
2
0.00
25.00
0
0
0
25
0
(25)
(21)
(80)
3
0.00
25.00
0
0
0
125
4
3.65
25.00
91
11
80
160
5
12.78
25.00
319
40
6
18.25
25.00
456
7
18.25
25.00
8
18.25
9
18.25
10
0
0
0
0
0
0
(125)
(94)
(205)
7.30
1
8
72
47
25
14
(126)
(86)
(331)
279
25.55
6
32
248
161
87
48
119
74
(213)
57
399
36.50
31
68
332
216
116
65
182
103
(31)
456
57
399
36.50
63
100
300
195
105
58
199
102
169
25.00
456
57
399
36.50
63
100
300
195
105
58
199
93
368
25.00
456
57
399
36.50
62
99
301
195
105
59
199
84
567
17.02
25.00
425
53
372
34.03
57
91
281
183
98
55
185
71
752
11
15.87
25.00
397
50
347
31.73
32
64
283
184
99
55
161
56
913
12
14.79
25.00
370
46
324
29.59
0
30
294
191
103
57
134
43
1046
13
13.79
25.00
345
43
302
27.59
0
28
274
178
96
53
125
36
1171
14
12.86
25.00
322
40
281
25.72
0
26
256
166
89
50
116
31
1288
15
11.99
25.00
300
37
262
23.98
0
24
238
155
83
46
108
26
1396
16
11.18
25.00
280
35
245
22.36
22
222
144
78
43
101
22
1497
17
10.42
25.00
261
33
228
20.85
21
207
135
73
40
94
19
1591
18
9.72
25.00
243
30
213
19.44
19
193
126
68
38
88
16
1679
19
9.06
25.00
227
28
198
18.13
18
180
117
63
35
82
13
1761
20
8.45
25.00
211
26
185
16.90
17
168
109
59
33
76
11
1838
21
7.88
25.00
197
25
172
15.76
16
157
102
55
31
71
10
1909
22
7.35
25.00
184
23
161
14.69
15
146
95
51
28
66
8
1975
23
6.85
25.00
171
21
150
13.70
14
136
88
48
27
62
7
2037
24
6.39
25.00
160
20
140
12.77
13
127
83
44
25
58
6
2095
25
5.95
25.00
149
19
130
11.91
12
118
77
41
23
54
5
2149
26
5.55
25.00
139
17
121
11.10
11
110
72
39
22
50
4
2199
27
5.18
25.00
129
16
113
10.35
10
103
67
36
20
47
4
2246
28
4.83
25.00
121
15
106
9.65
10
96
62
34
19
44
3
2289
29
4.50
25.00
113
14
98
9.00
9
89
58
31
17
41
3
2330
30
4.20
25.00
105
13
92
8.39
8
83
54
29
16
38
2
2368
NPV @
5%
1147
NPV @
12%
463
NPV @
15%
317
NPV @
10%
IRR
596
32.25%
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
PWI
PWP
3.33
7.3
Economics of the Energy Industries
APPENDIX
Fiscal Terms for Upstream Projects – An Overview
Fiscal terms for upstream investment refer to the agreement between a local government and an oil and
gas exploration company to explore, develop and produce hydrocarbons. The objective of a host
government is to maximize wealth from its natural resources by encouraging appropriate levels of
exploration and development activity. In order to accomplish this, governments must design fiscal
systems. The objectives of the oil companies are to build equity and maximize wealth by finding and
producing oil and gas reserves at the lowest possible cost and highest possible profit margin.
In a competitive world, areas with the least favorable geology, the highest costs, and the lowest prices at
the wellhead would offer the best fiscal terms, while areas with the best geology, the lowest costs, and the
highest prices at the wellhead would offer the toughest fiscal terms.
The objective of the host government is to design a fiscal system where exploration and development
rights are acquired by those companies who place the highest value on these rights. In an efficient
market, competitive bidding can help achieve this objective. The hallmark of an efficient market is
availability of information. Yet exploration is dominated by numerous unknowns and uncertainty. With
sufficient competition the industry will help determine what the market can bear, and profit will be
allocated accordingly. In the absence of competition, efficiency must be designed into the fiscal terms.
This is not easy to do.
Introduction
Regardless of what fiscal system is used, the bottom line is the financial issue of how costs are recovered
and profits divided. In order to accomplish this, governments must design fiscal systems that
•
Provide a fair return to the state and to the industry.
•
Avoid undue speculation.
•
Limit undue administrative burden.
•
Provide flexibility.
•
Create healthy competition and market efficiency.
The design of an efficient fiscal system must take into consideration the political and geological risks as
well as the potential rewards.
Detailed economic modeling using cash flow analysis is the best way to evaluate division of profits.
Factors that limit a company’s profits in a contract, such as cost recovery allowance, a government’s right
to back-in for an extra share of production, or an additional tax, can be modeled for the purposes of
contract negotiation or project evaluation. Division of profits is commonly referred as contractor take
and government take.
There are two main types of petroleum fiscal arrangements: concessionary systems and contractual
systems. In concessionary systems private ownership is allowed whereas in contractual systems the state
retains ownership. In contractual systems companies have the right to receive a share of production or
revenues from the sale of oil or gas in accordance with a production sharing contract (PSC) or a service
contract.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
9 - 15
Economics of the Energy Industries
Petroleum Fiscal Arrangement
Concessionary Systems
Contractual Systems
Production Sharing Contract
PSC
Service Contracts
SC
Concessionary Systems
To calculate the contractor take, the first item to be deducted from the gross revenues from oil and gas
production are the royalties. Gross revenues less royalty equals net revenue. The next item are
deductions, which include operating costs, depreciation, and amortization; and intangible drilling costs.
These are deducted from net revenue to arrive at taxable income. The third item is taxation. Revenue
remaining after royalty and deductions is called taxable income. Taxable income might be taxed in two
layers: provincial and federal. The remaining revenue after taxation is the contractors take.
Concessionary contracts are a relatively simple and are not as widely used as the more complex
production sharing contracts.
High Royalties
Contractor’s Take
Taxable
Income
Net
Revenue
Gross
Revenue
Low Royalties
Contractor’s Take
Taxable
Income
Taxes
Taxes
Net
Revenue
Gross
Revenue
DD&A
DD&A
Royalties
Royalties
Royalties are regressive because they are levied on gross revenues. For less profitable ventures, the
relative percentage of royalty increases. The further from gross revenues that taxes are levied, the more
progressive the system becomes.
Production Sharing Contracts
In most contractual systems, the facilities put in place by the contractor within the host government
domain become the property of the state either the moment they are landed in the country or upon startup
or commissioning. Sometimes, the title to the assets or facilities does not pass to the government until the
attendant costs have been recovered. Contractual systems are divided into service contracts and
production sharing contracts. The difference between them depends on whether or not the contractor
receives compensation in cash or in kind (crude). The distribution of how gross revenues are distributed
from a barrel of oil under a PSC.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
9 - 16
Economics of the Energy Industries
A Barrel of oil in a Production Sharing Contract
Contractor’s Take
Taxable
Income
Gross
Revenue
Net
Revenue
Profits
Oil/Gas
Taxes Contr. Profit
State’s Profit Share
Cost Recovery
(Limited)
Royalties <= 15%
Basic features of production sharing contracts:
•
The title of the hydrocarbons remains with the state.
•
The State maintains management control and the contractor is responsible for the execution of
petroleum operations in accordance to the terms of the contract.
•
The contractor is required to submit annual work programs and budgets for scrutiny and approval the
State Company.
•
The contract is based on production sharing and not profit-sharing basis.
•
The contractor provides all financing and technology required for the operations and bore the risks.
•
During the term of the contract, after allowance for up to a specified percentage of annual production
for recovery of costs, the remaining production is split between the contractor and State.
•
Equipment purchased and imported by the contractor become property of the State. Service company
equipment and leased equipment are exempt.
Deductions stages
1. Royalty. Royalties are the first deduction.
2. Cost Recovery. Before sharing of production, the contractor is allowed to recover costs out of net
revenues. Most PSCs place a limit on cost recovery. If operating costs and DD&A amounts to more than
the allowed limit, the balance would be carried forward and recovered later. From the mechanical point
of view, the cost recovery limit is the only true distinction between concessionary systems and PSCs.
3. Profit Oil Split. Revenues remaining after royalty and cost recovery are referred to as profit oil or profit
gas. The analog in a concessionary system would be taxable income. The contractor share of profit oil or
gas is a specified percentage. If this were a service agreement, the contractor's share would be called
service fee-not profit oil.
4. Taxes. The contractor's share of profit oil and gas is subject to taxation.
Basic Elements
The basic elements of a production sharing system are categorized in the following table. These elements
are also found in concessionary systems with the exception of the cost recovery limit and production
sharing. Many aspects of the government/contractor relationship may be negotiated but some are
normally determined by legislation. Those elements not determined by legislation must be negotiated.
Usually, it is better to have more aspects that are subject to negotiation. This is true for the government
agency responsible for negotiations as well as for the oil companies. Flexibility is required to offset
differences between basins, regions, and license areas within a country.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
9 - 17
Economics of the Energy Industries
Production Sharing Fiscal/Contractual Structure
Operational Aspects
Revenue or Production
Sharing Elements
National Legislation
Government participation
Ownership transfer
Arbitration
Insurance
Royalties
Taxation
Depreciation rates
Investment credits
Domestic obligation
Ringfencing
Contract Negotiation
Work commitment
Relinquishment
Commerciality
Bonus payments
Cost recovery limits
Production sharing
Work Commitment. The work commitment refers to the obligations an exploration company incurs once
a PSC is formalized. Work commitments are generally measured in kilometers of seismic data and the
number of wells to be drilled in the exploration phase.
Bonus Payments. Cash bonuses are lump sums paid by the contractor to acquire a particular license.
These cash bonuses are the main element in bidding rounds of very prospective acreage. Production
bonuses are paid when production from a given contract area or field reaches a specified level.
Royalties. Royalties are taken right off the gross revenues. Royalties range as high as 15%, although
many PSCs do not have a royalty. A specific rate royalty is relatively rare, but it may also go by another
name, such as “export tariff’, like in the former Soviet Union or the War Tax levy in Colombia.
Another aspect of royalties that contributes to their lack of popularity with the industry is that they can
cause production to become uneconomic prematurely. This works to the disadvantage of both the
industry and government. One remedy that has become popular is to scale royalties and other fiscal
elements to accommodate marginal situations.
Sliding Scales. A feature found in many petroleum fiscal systems is the sliding scale used for royalties,
taxes and various other items. The most common approach is an incremental sliding scale based on
average daily production. A sample sliding scale royalty is provided below.
Average
First Tranche
Second Tranche
Third Tranche
Daily Production
Up to 10,000 BOPD
10,001-20,000 BOPD
Above 20,000 BOPD
Royalty
5%
10%
15%
Cost Recovery. Cost recovery is the means by which the contractor recoups costs of exploration,
development, and operations out of gross revenues. Most PSCs have a limit to the amount of revenues
the contractor may claim for cost recovery but will allow unrecovered costs to be carried forward and
recovered in succeeding years. Cost recovery limits or cost recovery ceilings, as they are also known, if
they exist typically range from 30% to 60%.
Sometimes the hierarchy of cost recovery can make a difference in cash flow calculations. This is
particularly the case if certain cost recovery items are taxable. Cost recovery of cost oil normally includes
the following items listed in this order:
1.
Unrecovered costs carried over from previous years.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
9 - 18
Economics of the Energy Industries
2.
Operating costs.
3.
Expensed capital costs.
4.
Current year DD&A.
5.
Interest on financing (usually with limitations).
6.
Investment credit (uplift).
7.
Abandonment cost recovery fund.
In most respects, cost recovery is similar to deductions in calculating taxable income under a
concessionary system. There are some exceptions. For example, some PSCs have no limit to cost
recovery and some have no cost recovery.
Tangible vs Intangible Capital Costs. Sometimes a distinction is made between depreciation of fixed
capital assets and amortization of intangible capital costs. Under some concession agreements, intangible
exploration and development costs are not amortized. They are expensed in the year they are incurred
and treated as ordinary operating expenses. Those rare cases where intangible capital costs are written off
immediately can be an important financial incentive. Most systems will force intangible systems to be
amortized. Therefore, recovery of these costs takes longer, with more revenues subject to taxation in the
early stages of production.
Interest Cost Recovery. Sometimes interest expense is allowed as a deduction. Some systems limit the
amount of interest expense by using a theoretical capitalization structure such as a maximum 70% debt.
General and Administrative Costs. Many systems allow the contractor to recover some office
administrative and overhead expenses. Non operators are normally not allowed to recover such costs.
Unrecovered Costs Carried Forward. Most unrecovered costs are carried forward and are available for
recovery in subsequent periods. The same is true for unused deductions. The term “sunk cost” is applied
to past costs that have not been recovered. There are four classes of sunk cost: tax loss carry forward,
unrecovered depreciation balance, unrecovered amortization balance and cost recovery carry forward.
These items are typically held in abeyance (inactive) prior to the beginning of production. Many PSCs do
not allow pre-production costs to begin depreciation or amortization prior to the beginning of production.
Exploration sunk costs can have a significant impact on field development economics and can strongly
affect the development decision. The importance of sunk costs and development feasibility centers on an
important concept called commerciality.
The financial impact of a sunk cost position on the development position can be easily determined with
discounted cash flow analysis. The field development cash flow projection should be run once with sunk
costs and one without.
Abandonment Costs. Under most PSCs the contractor cedes ownership rights to the government for
equipment, platforms, pipelines and facilities upon commissioning or startup. The government as owner
is theoretically responsible for the cost of abandonment. Anticipated cost of abandonment is accumulated
through a sinking fund that matures at the time of abandonment. The costs are recovered prior to
abandonment so that funds are available when needed.
Profit Oil Split Taxation. Profit oil and gas is split between the contractor and the government, according
to the terms of the PSC. Sometimes it is negotiable. The contractor's share is usually subject to taxation.
Commerciality. Commerciality deals with who determines whether or not a discovery is economically
feasible and should be developed. Some regimes allow the contractor to decide whether or not to
commence development operations. Other systems have a commerciality requirement where the
contractor has to prove that the development of a discovery is economically beneficial for both the
contractor and the government. The benchmark for obtaining commercial status for a discovery cannot be
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
9 - 19
Economics of the Energy Industries
developed unless it is granted commercial status by the host government. The grant of the commercial
status marks the end of the exploration phase and the beginning of the development phase of a contract.
Government Participation (Joint Ventures). Many systems provide an option for the national oil company
to participate in development projects. Under most government participation arrangements, the contractor
bears the cost and risk of exploration. If there is a discovery, the government backs-in for a percentage,
the government is carried through exploration. The key aspects of government participation are:
•
What percentage participation? (most range from 10% to 51%)
•
When does the government back in? (usually once a discoveries made)
•
How much participation in management? (large range of degree of participation)
•
What costs will the government bear? (usually only their prorated share of development costs)
•
How does government fund its portion of costs? (often out of production)
The financial effect of a government partner is similar to that of any working-interest partner with a few
exceptions:
1. The government is usually carried through the exploration phase, and may or may not reimburse the
contractor for past exploration costs.
2. The government's contribution to capital and operating costs is normally paid out of production.
3. The government is seldom a silent partner.
Contractors prefer no government participation. This stems from a desire for efficiency as well as
economy. Joint operations of any sort, especially between diverse cultures, can have a negative impact on
operational efficiency. This is particularly true when the interests of government and an oil company can
be so polarized.
Investment Credits and Uplifts. Uplift allows the contractor to recover an additional percentage of capital
costs through cost recovery. For example, an uplift of 20% on capital expenditures of $100 million would
allow the contractor to recover $120 million. Uplifts can create incentives for the industry. Uplifts are
the key of rate of return contracts.
Domestic Obligation. Many contracts specify that a certain percentage of the contractor's profit oil be sold
to the government. The sales price to the government is usually at a discount to world prices.
Ring fencing. Ordinarily all costs associated with a given block or license must be recovered from
revenues generated within that block. The block is ring fenced. This element of a system can have a huge
impact on the recovery costs of exploration and development. From the government perspective, any
consideration for costs to cross a ring fence means that the government may in effect subsidize
unsuccessful operations. However, allowing exploration costs to cross the fence can be a strong financial
incentive for the industry.
Reinvestment Obligations. Some contracts require the contractor to set aside a specified percentage of
income for further exploratory work within the license.
Tax and Royalty Holidays. The purpose of tax and royalty holidays is to attract additional investment.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
9 - 20
Economics of the Energy Industries
Risk Service Contracts
In service contracts the contractor provides all capital associated with exploration and development of
petroleum resources. In return, if exploration efforts are successful, the government allows the contractor
to recover costs through sale of the oil or gas and pays the contractor a fee based on a percentage of the
remaining revenues. The fee is often subject to taxes. The net importing countries are the ones most
likely to use this approach. The distinction between PSCs and risk service contracts is minute. The
nature of the payment of the contractor's services is the point of distinction
Rate of Return Contracts
Contracts with flexible terms are becoming standard. There are many advantages for both the host
government and the contractor with contracts that encompass a range of economic conditions. The most
common method used for creating a flexible system is with sliding scale terms. Most sliding-scale
systems trigger on production rates. As production rates increase, government take increases. This
theoretically allows equitable terms for development of both large and small fields. Some contracts will
provide flexibility through a progressive tax rate, others will tie more than one variable to a sliding scale
such as cost recovery, profit oil split and royalty.
The most common contract terms subject to sliding scale are profit oil split, royalty and bonuses. Less
common are cost recovery limits and taxes. The most common factors and conditions used to trigger
sliding scales are production rates, water depth, cumulative production, oil prices, age or depth of the
reservoir, onshore vs offshore, R factors and the remoteness of locations. Less common are oil vs gas,
crude quality, time period (history), distance from shore and rate of return.
The objective with sliding scale systems is to create an environment where the government take flexes
upward as with increased profitability. The result of most fiscal structures is that project profitability is a
function of government take. In general, it is better for both parties when government take is a function
of profitability.
Some countries have developed progressive taxes or sharing arrangements based on project rate of return
(ROR). The effective government take increases as the project ROR increases. In order to be truly
progressive, the sliding-scale taxes and other attempts at flexibility should be based on profitability, not
production rates.
Some contracts use what is called an R factor. The R factor = Accrued net earnings / Accrued total
expenditures. R factors deal with all variables that affect project economics. Contractor potential upside
from price increase is diminished, but the downside is also protected.
Technical Assistance Contracts (TACs)
TACs are often referred to as rehabilitation, redevelopment or enhanced oil recovery projects. They are
associated with existing fields of production and sometimes, but to a lesser extent, abandoned fields. The
contractor takes over operations including equipment and personnel if applicable. The assistance that
includes capital provided by the contractor is principally based on special know-how such as steam or
water flood expertise.
Fiscal Terms for Gas
Only a few nations specifically support gas development through the fiscal system. However, most
nations that provide support have seen a strong development of the natural gas sector.
Since most gas projects will typically have a relatively low rate of return compared with oil, ROR-based
scales typically favor gas development. The higher the ROR benchmark, the more gas is being favored.
The same applies to contracts that have R-factor sliding scales being used in production sharing, royalties
or taxes. R-factor scales help gas economics because gas requires more investment and results often in
lower prices at the wellhead on an energy basis. This means lower R factors. Jurisdictions that make use
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
9 - 21
Economics of the Energy Industries
of uplifts or depletion allowances in calculations that apply to oil and gas usually also favor gas with a
few percentage points government take (Van Meurs & Seck, 1997).
Sources:
World Fiscal Systems for Gas, Barrows Inc., New York.
Van Meurs, Pedro. Governments Cut Takes to Compete as World Acreage Demand Falls, The Oil & Gas
Journal, April 24, 1995.
Van Meurs, Pedro and Andrew Seck. Government Takes Decline as Nations Diversify Terms to Attract
Investment, The Oil & Gas Journal, May 26, 1997.
Van Meurs, Pedro and Andrew Seck. Fiscal Terms for Gas Need Improvement in Many Countries, The
Oil & Gas Journal, August 11, 1997.
Derman, Andrew and Daniel Johnston. Bonuses Enhance Upstream Fiscal System Analysis, The Oil &
Gas Journal, February 8, 1999.
Johnston, Daniel. Different fiscal systems complicate reserve values, The Oil & Gas Journal, May 29,
1995, pp. 39-42.
Johnston, Daniel. Global petroleum fiscal systems compared by contractor take, The Oil & Gas Journal,
December 12, 1994, pp. 47-50.
Johnston, Daniel. International Petroleum Fiscal Systems and Production-Sharing Contracts, PennWell,
Tulsa, 1994.
Johnston, Daniel. Maturing Planet, Tougher Terms Change Upstream Landscape, The Oil & Gas Journal,
December 13 1999.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
9 - 22
Economics of the Energy Industries
CHAPTER 10 - PIPELINES
Introduction
Crude oil and natural gas need to be transported from producing fields to refineries and processing plants,
and products need to be transported to the markets. Land and sea tankers along with pipelines have long
served this purpose well for oil. Tankers are still quite indispensable as large volumes of oil need to be
shipped long distances, for instance from the Persian Gulf to the U.S. or to Japan. Geographical and
economic, sometimes combined with political, barriers do not allow pipeline construction in some cases.
In other circumstances, however, pipelines offer a cheaper and efficient alternative to tankers in
transporting oil. This is especially true in the case of natural gas which needs to be “liquefied” through an
expensive process in order to be shipped in tankers and then “regasified” in order to be consumed by endusers in as flexible manner as piped gas. Accordingly, in most cases, pipelines are clearly the better
choice for transporting natural gas.
Worldwide Pipeline Construction (miles)
30,000
25,000
20,000
15,000
10,000
5,000
0
1996
1997
Source: Oil & Gas Journal
1998
1999
Crude
2000
Gas
2001
Products
In total, there were about 45,000 miles
(72,450 km) of pipelines under
consideration in 1996, 64% of which
were gas pipelines. In 1999, only
20,000 miles (32,200 km) of pipelines
were considered, but a greater
percentage (81%) was intended to
transport gas. Except these two
extreme years, more than 30,000 miles
of pipelines were considered in each
of the other years, again mostly for gas
transportation (60-70%).
In the period from 1996 to 1999, the
decrease in oil and natural gas prices resulted in a decrease in production. This reduction in production
created a dampening effect on pipeline construction plans, which reached its lowest in 1999 when the
price of oil and natural gas dropped to an all time low. However, long-term, worldwide plans for oil and
natural gas pipelines picked up again in 2000 mostly in response to unexpectedly strong prices since mid1999.
Overall, natural gas pipelines dominated construction and engineering work in the late 1990s. Demand
for gas is being driven mostly by growing worldwide demand for gas-fired electric power generation and
to a lesser extent by growing industrial, commercial and residential demand. On the supply side, the need
and desire to monetize stranded and flared gas assets are also supporting this trend. In 1996, more than
29,000 miles (46,690 km) of gas pipelines were under consideration, especially in Latin America and the
U.S. However, as prices dropped, some of the planned projects were reduced in size, postponed or
cancelled. Prices bounced back in 2000, which is also witnessed by the increase in gas pipeline mileage
to almost 25,000 miles (40,250 km) from 16,000 miles (25,760 km) in 1999. Most analysts expect prices
to remain strong as the U.S. and global economy recovers. As a result, there is pressure on operators to
add infrastructure sooner rather than later. In 2001, actual construction mileage was 10,916 miles (17,564
km). This represents a 15% increase from 2000 when 9,456 miles (15,214 km) were under construction.
The increase is mostly due to projects in Europe and the Former Soviet Union (FSU), the Caspian region,
Latin America, the Far East and the South Pacific.
The following table illustrates the length of planned or under construction pipelines across different parts
of the world. In 2001, about 18% of these pipelines was planned to be built in the Asia-Pacific region and
18% in the FSU region. The U.S., with 19% of pipeline construction plans, continues to add significant
miles to the world’s largest web of pipelines. Latin America accounts for about 12% of the total. Both
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
10 – 1
Economics of the Energy Industries
Canada (9%) and Europe (9%) will construct about 3,000 miles of pipelines each, the former to ship its
natural gas and oil mostly to the U.S. market, and the latter to meet its increasing demand for natural gas
from diversified sources. The Middle East also constitutes 9% of the pipeline construction plans.
Pipeline Construction by Region
1996 *
REGION
1997 **
P
C
G
1998 ***
C
G
P
C
AFRICA
1,291
1,228
-
2,375
156
180
2,375
ASIA-PACIFIC
2,858
5,114
3,562
2,951
2,934
1,945
219
CANADA
852
4,530
120
605
2,945
343
1,244
EUROPE
109
3,611
191
134
3,421
2
91
G
1999
P
C
153
180
3,751
458
1,927
3,237
†
2000
C
††
G
P
G
373
-
-
653
500
20
2,613
71
271
8,582
262
275
2,337
195
351
102
-
1,733
100
706
2001
P
C
-
†††
G
P
1,173
500
675
627
4,269
750
-
855
-
536
2,351
-
1,573
-
563
2,369
31
FSU
156
54
-
1,796
-
-
1,796
-
-
940
1,620
-
4,367
3,634
290
2,522
2,611
450
LATINAMERICA
973
8,224
2,374
1,302
4,843
1,638
397
4,608
1,723
207
3,464
1,106
519
2,376
1,617
1,154
1,367
1,274
MIDDLEEAST
317
1,000
1,425
429
719
506
-
1,089
221
-
U.S.
616
5,371
852
500
6,501
836
626
4,806
891
275
8,523 10,091 21,519
5,450
6,747 19,571
3,837
7,172 29,132
Source:
*
Oil &Gas Journal, September 30, 1996
-
-
2,482
150
149
2,454
150
3,722
615
250
294
4,702
859
503
4,374
1,169
2,090 16,103
1,722
7,161 24,704
3,591
7,227 20,296
3,824
Oil &Gas Journal, October 11, 1999
†
**
Oil &Gas Journal, October 13, 1997
††
Oil &Gas Journal, October 30, 2000
***
Oil &Gas Journal, October 5, 1998
†††
Oil &Gas Journal, October 29, 2001
FSU’s shares in pipeline construction has increased significantly since 1996 from less than 1% to 18% in
2001, mostly at the expense of Latin America whose share declined from 26% in 1996 to 12% in 2001.
Asia-Pacific also reduced the investments in pipelines, especially during the Asian crisis of 1998-99.
Nevertheless, FSU seems to be the key region for expansion of pipeline capacity in the near future
whereas Latin America appears saturated especially given current economic problems of the region.
In 2001, 65% of pipelines were intended for gas transportation, 23% for crude oil and the rest for
products. Most regions, except for Africa where more than two-thirds of pipelines were for shipping
crude oil, are expected to build gas pipelines. Clearly crude oil pipelines have been a priority for Africa
during the late 1990s. FSU and Latin America also intended to construct significant miles of crude oil and
products pipelines. 45% of FSU pipelines were for crude oil, almost equivalent the share of gas pipelines.
Note, however, that gas pipelines increased their share significantly only in 2000 and 2001.
Asymmetrically, gas pipelines attracted most of the investment in Latin America in the late 1990s in
addition to a fairly stable expansion of products lines in the range of 1,000 to 2,000 miles a year. For all
other regions (including the Middle
East), for the most part, there has been
Pipeline Construction in Africa (miles)
significantly more investment in gas
2,500
pipelines than either in crude or products
2,000
since 1996.
1,500
Africa
1,000
Operators in Africa are moving forward
with plans to build long-distance
500
pipelines designed to move oil and gas
0
to distant markets. In 1997 and 1998 an
1996
1997
1998
1999
2000
2001
increase in crude pipeline construction
Source: Oil & Gas Journal
Crude
Gas
Products
was observed, most of which was
concentrated in Sudan and Zambia.
About 2,400 miles of crude lines were under consideration in each year – 7% and 9% of total world crude
oil pipelines, respectively. After a very inactive 1999, there is an increasing number of both oil and gas
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
10 - 2
Economics of the Energy Industries
projects. The planned mileage for oil pipelines increased from 373 miles in 1999 to 1,173 miles in 2001
while 500 miles of gas pipeline were under consideration in 2000 and 2001 as compared to none in 1999.
Most of the recent larger proposed or planned projects in Africa involve regional pipelines, designed to
deliver gas or crude to African or European markets. Some of the more notable projects include the
$510-million, 620-mile, 24-inch West African Gas Pipeline project, designed to move Nigerian natural
gas to markets in Benin, Togo and Ghana. In February 2000, the four nations signed an InterGovernmental Agreement (IGA) which established the framework for realizing the project. The project
has received administrative support from the Economic Community of West African States Secretariat
and technical assistance from the U.S. Agency for International Development. The project is being
developed by a consortium of Chevron, Shell, Nigerian National Petroleum Corp., Volta River Authority,
Societe Beninoise de Gaz (SoBeGaz) and Societe Togolaise de Gaz (SoToGaz).
Work on the $3.5-billion Chad to Cameroon crude oil pipeline was scheduled to begin in October of
2001. The project involves building a 665-mile, 30-inch line to transport crude oil from the Doba fields in
Chad to a terminal on the Cameroon Coast. The project is being developed by Exxon Mobil Corp.,
Petronas, and Chevron. A May 2003 completion is planned.
The governments of South Africa and Mozambique have signed an agreement that facilitates construction
of a $580-million pipeline. The project involves building a 540-mile, 26-inch line that will deliver gas
from Mozambique’s Pande and Temane gas fields in northern Inhambane province to Ressano Garcia,
and from there to Secunda in South Africa’s eastern Mpumalanga Province. There, it will serve as a
feedstock to synthetic fuels and chemicals plants, as well as emerging South African gas distribution
markets. A spur to Maputo may also be built. A joint-venture company owned by Sasol and the
governments of Mozambique and South Africa is to build, own and operate the pipeline. A secondquarter 2004 completion is expected.
Asia-Pacific
Expected
long-term
economic
growth in this geographically
Pipeline Construction in Asia-Pacific (miles)
10,000
expansive
region
(China
in
particular)
is
boosting
demand
for
8,000
some large pipeline projects, mostly
6,000
for natural gas. Especially since
1998, almost all of the investment
4,000
was directed towards gas pipelines.
2,000
Continuing expansion of Australia’s
0
gas transmission and distribution
1996
1997
1998
1999
2000
2001
grid, extension of natural gas service
Source: Oil & Gas Journal
Crude Gas Products
to Tasmania and development
initiatives to exploit gas reserves in
Papua New Guinea as well as China’s increasing demand for gas are the reasons behind this trend.
Although there has been significant activity in expanding the gas pipeline network in the region since
1996, averaging 3,600 miles a year between 1996 and 1999, a surge was observed in 2000 when almost
8,600 miles of gas pipelines (a 300% increase from 1999) were under consideration. In 2001, the trend
continues with more than 4,200 miles of gas pipelines planned or under construction.
Canada
There has been considerable progress in recent years on gas interconnections between Canada and the
U.S. Oil and products pipeline activity were relatively minor between 1999 and 2001 after averaging
more than 1,100 miles a year between 1996 and 1998. Note, however, that gas pipelines represented
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
10 – 3
Economics of the Energy Industries
more than 70% of pipeline activity in Canada except for 1998 when they accounted only for 56% of the
total.
The Northern Border Pipeline, an
extension of the Nova Pipeline,
came on stream in late 1999 and
4000
connects to Chicago through the
upper Midwest. The Maritimes and
3000
Northeast Pipeline came on stream
2000
in January 2000, running from Sable
Island to New England. The Alliance
1000
Pipeline is a $2.5-billion, 1,875-mile
0
pipeline, the longest ever built in
1996
1997
1998
1999
2000
2001
North America, and is designed to
Source: Oil & Gas Journal
Crude Gas
Products
carry about 1.3 billion cubic feet per
day (bcf/d) of gas from western Canada to the Chicago area. The pipeline began commercial service on
December 1, 2000. The Millennium Pipeline remains in the regulatory approval stage of development; it
is slated to connect Canadian sources to southern New York and Pennsylvania. Crude oil pipeline
construction in Canada is targeted to deliver oil to eastern provinces and to the U.S.
Pipeline Construction in Canada (miles)
5000
Europe
Europe’s gas pipeline construction projects have been and will continue to be consistently high as
European countries increase their transmission and local distribution gas pipeline systems and replace old
distribution systems with new lines to meet increasing demand for natural gas. Although the pace has
slowed down from more than 3,000 miles a year during the period of 1996-1998, in 2001 there were
almost 2,500 miles of gas pipelines under construction and/or planned. Even in 2000, more than 1,500
miles of gas lines were under
consideration.
Pipeline Construction in Europe (miles)
In 2000 and 2001, oil pipeline activity
also picked up. The $1.13-billion, 563mile oil pipeline to be built across the
Balkans to connect the Black Sea to the
Adriatic Sea is mainly responsible for this
increase. As proposed, the line would run
from the Bulgarian Black Sea port of
Burgas, through Macedonia, to Albania’s
Adriatic port of Vlora. It is designed to
1996
1997
1998
1999
2000
2001
Source: Oil & Gas Journal
Crude Gas Products
provide
a
cheaper
transportation
alternative for oil coming from Russia,
Azerbaijan, and Kazakhstan to markets in northwest Europe and along the Adriatic Coast. A feasibility
study has been completed. Original plans called for the project to have a four-year construction
timeframe, and a 2005 completion. Construction was delayed due to the unrest along the route of the
pipeline.
4000
3500
3000
2500
2000
1500
1000
500
0
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
10 - 4
Economics of the Energy Industries
Former Soviet Union (FSU)
Russia’s new energy strategy, named “Energy
Strategy to 2020,” emphasizes gas
5000
transportation as an area of concern. Due to a
proposed increase in gas production in
4000
Eastern Siberia and the Far East, the strategy
3000
calls for a pipeline from Kovykta to Irkutsk,
2000
possibly continuing into China. Within two
decades, the plan is to construct 16,800 miles
1000
of new lines and replace 14,300 miles of
0
existing lines due to corrosion. In addition,
1996
1997
1998
1999
2000
2001
the need of Caspian states such as
Source: Oil & Gas Journal
Crude Gas Products
Turkmenistan and Azerbaijan to export their
gas caused an increased interest in gas export
pipelines from the region. As a result, the mileage of gas pipeline under consideration jumped to 1,620
miles in 1999 and then to 3,634 miles in 2000 from almost none between 1996 and 1998. However, when
the proposed TransCaspian gas pipeline from Turkmenistan to Turkey was removed from the proposed
projects due to geopolitical reasons, the mileage fell to 2,611 in 2001.
Pipeline Construction in FSU (miles)
FSU countries, especially in the Caspian region, also focused heavily on oil pipeline projects to gain
access to the world market. In the late 1990s, regional pipelines were built including the one to connect
Baku, Azerbaijan to Supsa, Georgia to start the early oil flow. In 2000, more projects (more than 4,000
miles) were proposed and others were later completed. One of the main proposed projects is the
construction of the 1,075-mile Baku-Ceyhan pipeline project, which will be the main export route for
Azeri oil. The construction is expected to start in 2002. The Caspian Pipeline Consortium (CPC)
pipeline that connects Kazakhstan’s Tengiz field to Russia’s Black Sea port of Novorossiysk is another
project which has been successfully completed and is currently in use.
Latin America
There has been a constant decline
in the mileage of pipelines that
10000
were either under construction or
8000
planned since 1996, especially for
natural gas. There were more
6000
than 8,000 miles of natural gas
4000
pipelines in the books in 1996 as
compared to only about 1,400
2000
miles in 2001. The decline has
0
been continuous. On the other
1996
1997
1998
1999
2000
2001
hand, there was a fairly stable
Source: Oil & Gas Journal
Crude Gas Products
interest in products lines, which
averaged about 1,600 miles a year between 1996 and 2001. Recently, there is an increasing interest in
crude oil pipelines, with more than 1,100 miles in 2001 as compared to only 200 in 1999. Nevertheless,
the late 1990s were dominated by gas pipelines such as the 2,000-mile Bolivia to Brazil pipeline and
others in Argentina and Mexico. The gas pipeline construction numbers in 2001 consist of the 1,188-mile
planned gas distribution projects in Brazil and the 135-mile gas transmission line from the U.S. to
Mexico. As for crude oil pipeline projects, Mexico has just completed its 635-mile crude oil pipeline and
the rest of the projects are proposed oil pipelines that include the 312-mile pipeline in Ecuador and the
207-mile planned pipeline in Brazil.
Pipeline Construction in Latin America (miles)
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
10 – 5
Economics of the Energy Industries
Currently, there are plans for expanding the gas transmission and distribution systems in Mexico in order
to establish gas as a fuel of choice and help develop the country’s gas resources. At the same time, there
are at least three projects that are aimed at delivering U.S. natural gas and related products to Mexican
markets. Meanwhile, the governments of Mexico and Guatemala continue to study the feasibility of
building a 347-mile pipeline to deliver Mexican natural gas to markets in Central America. The
development of the Camisea field in Peru is also expected to add several hundred miles of gas pipelines
within the next few years.
The Middle East
As in other regions, except for 1996 natural gas pipelines constitute the bulk of projects in the Middle
East region with Oman, Qatar, Saudi Arabia and Syria as the countries hosting most of the pipeline
construction activity. In particular, there has been a significant increase in 2000 and 2001 in the mileage
of gas pipelines under construction and/or that were announced. In each year, almost 2,500 miles of gas
pipelines were under consideration as compared to an average of about 800 miles between 1996 and
1999. Since 1997, there has not been much interest in crude oil and products pipelines. In contrast, with
almost 1,500 miles, products pipelines accounted for the largest share of investments in 1996.
In 2000 and 2001, Qatar expanded
its pipeline projects as it secured
major contracts with neighboring
2500
countries such as the UAE,
2000
Bahrain and possibly Oman to
1500
supply natural gas to meet the
1000
needs of those countries. Another
500
line from the North field of Qatar
to Pakistan is being promoted. The
0
proposal envisions a 995-mile
1996
1997
1998
1999
2000
2001
Source: Oil & Gas Journal
Crude Gas Products
(1,601-km), 48-inch line to
Pakistan. Saudi Arabia also saw a
rise in its gas pipeline construction activity in 2000 and 2001, and currently has 932 miles of gas
transmission pipeline projects that are either under construction or being planned. The pipelines are part
of the Hawiyah gas development project, which will connect those fields to the delivery systems in
Riyadh. Oman has two major pipelines proposed; the first pipeline being currently constructed is from
central Oman to Sohar, which the government is promoting as an industrial city, and the second would
transport gas to the southern city of Salalah, where a private power plant is planned. A 155-mile (250km) pipeline in Syria was completed in September 2001. The new pipeline connects the natural gas
delivery system that serves western Syria (including Damascus) with producing regions located some 280
miles (450 km) northeast of Damascus.
Pipeline Construction in Middle East (miles)
3000
Pipeline Construction in the U.S. (miles)
7000
The U.S.
6000
During the past decade, interstate natural
gas pipeline capacity has increased
4000
substantially. From January 1996 through
3000
August 1998 alone, at least 78 projects
2000
were completed adding approximately
1000
11.7 bcf/d of capacity, and much more
0
will be needed in coming years. There
1996
1997
1998
1999
2000
2001
has been constant investment in
Source: Oil & Gas Journal
Crude Gas
Products
expanding the gas pipeline network in the
U.S. at an average rate of almost 5,000
miles a year between 1996 and 2001, with a peak of 6,500 miles in 1997 and a trough of 3,722 miles in
5000
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
10 - 6
Economics of the Energy Industries
1999. There has also been constant activity in crude oil and products pipelines as well, albeit at a much
smaller scale. An average of 470 miles of crude oil and 810 miles of products pipelines were considered
between 1996 and 2001.
Growing U.S. demand for Canadian natural gas has been a dominant factor underlying many of the
pipeline expansion projects. The U.S. and Canadian natural gas grids are highly interconnected and
Canadian natural gas has become an increasingly important component of the total natural gas supply for
the United States. This is especially true for certain U.S. regions such as the Northeast, Midwest, and
Pacific Coast, which depend on Canadian natural gas for significant amounts of their supply.
The U.S. demand is expected to grow as a result of mostly increasing capacity of gas-fired generation and
the rise in industrial demand. As the U.S. continues to deplete its current producing areas, in order to
meet the increasing demand, more gas will be needed from Canada and/or Mexico and new regions in the
U.S. such as the Eastern Gulf of Mexico or federal lands in the West may be developed. These
developments will necessitate the construction of new pipelines. As witnessed during the California’s
energy crisis in 2001, there are already bottlenecks in the system.
Pipeline Economics
Costs associated with pipeline construction depend on many factors. For example, the cost per mile
increases with the nominal pipe size. Construction on land using a 12-inch pipeline costs about $300,000
per mile while using a 42-inch pipeline costs almost $1.5 million per mile. For a given diameter, pipeline
construction costs increases if the pipeline goes through residential areas, or there are roads, highways
and rivers on the way. Overall, construction costs are dependent on location, terrain, population density,
or other factors (for instance, different labor and tax laws in different countries).
It is difficult to gather detailed information about all these factors. However, the U.S. has by far the
largest pipeline network of all types, across all type of terrains and new pipelines are constantly being
built. As a result, the U.S. average pipeline cost estimates, which are also the most commonly available
and reliable estimates, are provided in this section. Adjustments can be made for other countries mostly
by considering differences in labor and material costs.
In the U.S., there are approximately 152,005 miles of liquids pipelines. Largest 10 owners of pipeline
mileage account for about 45% of the total. In 2000, total trunkline traffic of top 10 interstate oil pipeline
companies was 2,114 billion barrel-miles for crude oil (60% of total traffic). These companies generated
$1.3 billion in revenues (49% of total revenues).
Also, there are 237,079 miles of gas pipelines (194,673 miles of long distance transmission lines, 37,339
miles of field lines and 5,067 miles of storage lines). Largest 10 owners of pipeline mileage account for
about 54% of the total. After deregulation of the industry, pipelines gradually increased transmission of
other companies’ gas, acting like contract carriers. In 2000, pipeline companies moved nearly 32 trillion
cubic feet (tcf) of other companies’ gas and sold less than 800 bcf from their own systems. Top 10
interstate gas pipeline companies moved about 16 tcf (49% of total volume) and generated $1.4 billion in
net income (49% of total revenues).
Pipeline construction costs include several factors, the most important of which are material and labor
costs which make up 70 to 80% of the total construction cost both onshore and offshore. Surveying,
engineering, supervision, administration and overhead, telecommunications equipment, freight, taxes,
regulatory filing fees, interest, contingencies (all covered under Miscellaneous), right-of-way (R.O.W.)
and damages make up the rest. The following two tables are based on a 1995-1996 survey of 62 land and
2 offshore projects and a 2000-2001 survey of 49 land and 2 offshore projects by the Oil & Gas Journal.
Total construction costs increased by 38% between 1995 and 2000 for onshore pipelines, mostly due to
significant increases in labor and especially in miscellaneous items. The unavailability of experienced
labor may help explain the increase in that category. Miscellaneous costs increased mostly due to an
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
10 – 7
Economics of the Energy Industries
increase for specialized services such as surveying and engineering. Specialized service companies
became able to ask for higher prices. The biggest variation (151%) was in the R.O.W. and Damages
category. As longer pipes that extend across different boundaries and territories are being designed and
built at increasing rates, governments saw an opportunity to benefit from these projects by charging
pipeline companies different and higher fees. Material costs remained fairly constant.
Estimated Pipeline Construction Costs per Mile and % of Total (Onshore)
1995-1996
2000-2001
% Change
$274,210 (31%)
$279,565 (21%)
2%
Material
$422,610 (47%)
$571,719 (44%)
35%
Labor
$154,012 (17%)
$344,273 (26%)
124%
Miscellaneous
$48,075 (5%)
$120,607 (9%)
151%
R.O.W. and Damages
Total
$898,907
$1,316,164
38%
Source: Oil & Gas Journal, Pipeline Economics Survey, various issues.
Although there are only two offshore projects in both survey periods and hence the costs estimates may
not be as robust, it clearly costs more to build pipelines offshore, especially due to increases in material
and labor costs. As for the trends between 1995 and 2000, similar patterns are observed for offshore
pipelines: overall costs increased by 60%, mostly due to increases in labor and miscellaneous items.
Although there is a very significant increase in R.O.W and Damages category, its share in total is still
only 4%.
Estimated Pipeline Construction Costs per Mile and % of Total (Offshore)
1995-1996
2000-2001
% Change
$684,604 (42%)
$413,995 (16%)
-40%
Material
$527,619 (33%)
$1,537,249 (60%)
191%
Labor
$396,394 (25%)
$510,271 (20%)
29%
Miscellaneous
$3,201 (0%)
$116,898 (4%)
3,552%
R.O.W. and Damages
60%
Total
$1,611,818
$2,578,413
Source: Oil & Gas Journal, Pipeline Economics Survey, various issues.
Investors and project planners should consider the trends in the cost categories as guidelines whenever
they try to estimate the cost of any pipeline project. The reason for that is as more pipelines are being
designed and constructed, the variation between actual incurred costs to the estimated costs widens. In
order to accurately determine the financial value of any pipeline project, this variation should be
quantified and minimized by a better prediction of the movement of each cost category and its relation
with the number of projects being designed and built.
A Model of Pipeline Investment
We provide two examples of pipeline investment decision analysis, one for an oil pipeline and another for
a gas pipeline. Cash flow calculations for a 42-inch, 800-mile oil pipeline are summarized at the end of
the chapter. The model is set up to allow for project financing, with investors deciding on the debt-toequity ratio. As a result, principal and interest service of the loan are included. Cash flow (the last
column) is calculated as follows:
Cash Flow = Revenues – Principle – Interest – O&M Cost – Transit Fees – Tax – Capital Expenditure +
Depreciation
where
Revenues = Sales x Tariff. Sales are based on the needs of the producing region and the consumption
centers. The pipeline is assumed to reach contracted capacity in four years after the flow starts. Tariff is
negotiated and basically determines whether the operator will invest in the pipeline or not.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
10 - 8
Economics of the Energy Industries
Principle and Interest are calculated based on the loan structure (loan amount, interest rate, loan period) if
a loan is taken. Equity-loan ratio is an input. We also include an upfront fee for the loan and calculate
interest cost during the construction period (i.e., before payments start along with revenues).
O&M Cost is computed for you based on fixed and variable costs involved during operations and
maintenance. For example, we use $23 million fixed and $2.3 per ton for this example (see table below).
We also allow for contingencies in O&M costs that may be associated with lack of skilled labor, poor
infrastructure, bureaucratic changes and the like that commonly delay projects and increase costs,
especially in emerging markets.
Transit Fees are paid if the pipeline passes through a third country and based on the transit fee that
country charges (sales x transit fee). The model allows for multiple transit countries.
Tax is calculated based on the taxable income, which is equal to revenues – depreciation - interest.
Input Data for the Oil Pipeline
Length
Onshore portion (%)
Cost per mile (onshore)
Cost per mile (offshore)
Cost of the pipeline
Equity (%)
O&M costs
Fixed cost
Variable cost
Tax rate
Tariff rate
Transit fee
No of transit countries
Discount rate
800
100%
1.4
2.6
1344
30%
miles
23
2.3
35%
22
2.5
0
10%
$MM
$/ton
$MM
$MM
$MM
Year 1
25%
Investment Outlay
Year 2
Year 3
50%
25%
Add. Capital Contingency
20%
Add. O&M Contingency
20%
Loan Structure
Loan amount
941
Loan rate
15%
Loan period
10
Loan+interest
1250
IDC
0.6%
Upfront fee
2.5%
Principle
1144
Sales
$MM
First Year
Peak Flow
4 MT/yr
20 MT/yr
years
$MM
15.6%
$MM
$/ton
$/ton
Given the input values, this pipeline yields an NPV of $676 million and an IRR of 18%. It would be
useful to analyze sensitivities of the project to some key variables.
If the pipeline were not able to carry 20 million tons (MT) a year at its peak but only 18 MT, due to
problems either at production end or consumption end or both, NPV would go down to $535 million and
IRR to 16%.
If the loan rate was 18% instead of 15%, NPV would be $535 million and IRR would be 16%. The
situation could be worsened if equity was not available and full cost would have to be met through
financing at 18%. NPV would be further reduced to $325 million although IRR would remain at 14%.
If the pipeline were to be re-routed in the middle of construction, due to environmental, social or
historical reasons, an additional 50 miles may be needed. In that case, an NPV of $632 million and IRR
of 17% would be obtained.
If all of these calamities occur at the same time, NPV would be $91 million and IRR would fall to 11%.
There are other considerations such as the number of transit countries, transit fees to be negotiated with
each, and fluctuations in O&M costs. But, the sensitivity analyses provided above should be sufficient to
demonstrate risks associated with an oil pipeline.
A similar model of a gas pipeline is also provided at the end of the chapter. It is a 1,250-mile pipeline,
using 42-inch pipes with three compressor stations. Cash flow is calculated using the same formula and
definitions as the oil pipeline. The following table provides the input data. Note that the pipeline needs
to go under water for about 10% of its length.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
10 – 9
Economics of the Energy Industries
Input Data for the Gas Pipeline
Length
Onshore portion (%)
Cost per mile (onshore)
Cost per mile (offshore)
Cost of the pipeline
Equity (%)
O&M costs
Fixed cost
Variable cost
Tax rate
Tariff rate
Transit fee
No of transit countries
Discount rate
1250
90%
1.4
2.6
2280
75%
miles
39
2.6
35%
40
5
1
10%
$MM
$/1000cm
$MM
$MM
$MM
Year 1
25%
Investment Outlay
Year 2
Year 3
50%
25%
Add. Capital Contingency
20%
Add. O&M Contingency
20%
Loan Structure
Loan amount
570
Loan rate
12%
Loan period
10
Loan+interest
717
IDC
0.6%
Upfront fee
2.5%
Principle
615
$MM
First Year
Peak Flow
Sales
5 bcm/yr
15 bcm/yr
years
$MM
12.6%
$MM
($/1000cm)
($/1000cm)
Given the input values, this pipeline yields an NPV of roughly $724 million and an IRR of 15%. Again,
it would be useful to analyze sensitivities of the project to some key variables.
If the pipeline were not able to carry 15 billion cubic meters (bcm) a year at its peak but only 13 bcm, due
to problems either at production end or consumption end or both, NPV would go down to $516 million
and IRR to 13%.
If the loan rate was 15% instead of 12%, NPV would be $659 million and IRR would be 14%. The
situation could be worsened if equity was not available and full cost would have to be met through
financing at 15%. NPV would be further reduced to $204 million.
If the pipeline were to be re-routed in the middle of construction, due to environmental, social or
historical reasons, an additional 100 miles may be needed. In that case, an NPV of $658 million and IRR
of 14% would be obtained.
If all of these calamities occur at the same time, NPV would be negative. Although the probability of all
going wrong is low, this example demonstrates risks associated with an international gas pipeline.
Relevant Case Studies:
Bolivia-to-Brazil Pipeline
Chad Cameroon Pipeline
Trans-Caspian Gas Pipeline
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
10 - 10
Economics of the Energy Industries
Project Economics for an 800-mile Oil Pipeline
Year
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
Investor Share Capital Exp
$MM
$MM
107
356
226
754
147
490
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Principle
$MM
Interest
$MM
0
0
0
-56
-65
-74
-86
-99
-113
-130
-150
-172
-198
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-172
-163
-153
-142
-129
-115
-98
-78
-56
-30
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
O&M Cost
$MM
0
0
0
39
50
61
72
83
83
83
83
83
83
83
83
83
83
83
83
83
83
83
83
83
83
83
83
83
83
83
Transit fees Depreciation
$MM
$MM
0
0
0
0
0
0
0
107
0
107
0
107
0
107
0
107
0
107
0
107
0
107
0
107
0
107
0
107
0
107
0
107
0
107
0
107
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Sales
MT
Revenues
$MM
0
0
0
4
8
12
16
20
20
20
20
20
20
20
20
20
20
20
20
20
20
20
20
20
20
20
20
20
20
20
Tax
$MM
0
0
0
88
176
264
352
440
440
440
440
440
440
440
440
440
440
440
440
440
440
440
440
440
440
440
440
440
440
440
0
0
0
0
0
0
11
42
48
54
60
68
77
88
88
88
88
88
125
125
125
125
125
125
125
125
125
125
125
125
Cashflow
$MM
-107
-226
-375
-72
5
82
148
194
188
182
176
168
387
376
376
376
376
376
232
232
232
232
232
232
232
232
232
232
232
232
$676
18%
0
0
0
0
0
34
68
102
105
107
110
113
117
121
121
121
121
121
177
177
177
177
177
177
177
177
177
177
177
177
Cashflow
$MM
-435
-885
-591
164
244
289
335
380
378
375
373
369
474
470
470
470
470
470
254
254
254
254
254
254
254
254
254
254
254
254
$724
15%
NPV
IRR
Project Economics for an 1,250-mile Gas Pipeline
Year
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
Investor share Capital Exp
$MM
$MM
435
580
885
1179
482
643
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Principle
$MM
0
0
0
-35
-39
-44
-49
-55
-62
-69
-77
-87
-97
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Interest
$MM
0
0
0
-74
-70
-65
-60
-54
-47
-40
-31
-22
-12
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
O&M Cost
$MM
0
0
0
62
70
78
86
94
94
94
94
94
94
94
94
94
94
94
94
94
94
94
94
94
94
94
94
94
94
94
Transit fees Depreciation
$MM
$MM
0
0
0
0
0
0
25
160
38
160
50
160
63
160
75
160
75
160
75
160
75
160
75
160
75
160
75
160
75
160
75
160
75
160
75
160
75
0
75
0
75
0
75
0
75
0
75
0
75
0
75
0
75
0
75
0
75
0
75
0
Sales
bcm
0
0
0
5
7.5
10
12.5
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
Revenues
$MM
Tax
$MM
0
0
0
200
300
400
500
600
600
600
600
600
600
600
600
600
600
600
600
600
600
600
600
600
600
600
600
600
600
600
NPV
IRR
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
10 – 11
Appendix
Contracting and Rate Design: Reference Materials
This document contains a list of reference materials that demonstrate how rate (tariff) design changes
with market conditions. The examples are for the United States, and are focused on natural gas and
electric power, but have applicability to other locations where restructuring of these industries is
underway or being contemplated. Rate design has implications for both infrastructure investment and the
energy fuel markets. This is because rate designs that place too much risk on investors relative to depth
of the marketplace will discourage investment in critical infrastructure needed to transport energy
(pipelines for natural gas, wires for electric power). Two resources suggested for your review.
Chapter 22, Principles of Rate Design, in Volume 6, Utility Rates, Public Utilities Reports Guide, 1996,
by PUR, Inc. The Guide was revised and printed in 2004 and can be purchased at
http://www.pur.com/books/12.cfm
This chapter illustrates various issues in rate design once the revenue requirement for a regulated entity
is established. The revenue requirement is operating costs, plus taxes, plus depreciation allowance, plus
the allowed rate of return times the rate base. The rate base is the amount invested in facilities needed in
order to provide service.
RR = O + T + D + r(RB)
A key concepts in establishing revenue requirement is “just and reasonable” pricing, subject to certain
tests.
Chapter 4, Impact of Recent Rate Design Changes, in Natural Gas 1992: Issues and Trends, U.S. Energy
Information Administration.
The natural gas sector in the U.S., in particular, has undergone an array of changes that impact how
pipelines operate. This chapter captures shifts in pipeline rate design during a critical period in U.S.
natural gas history. Along with pipeline rate design, the method of contracting for natural gas supplies
also changed significantly. For both pipeline rates and natural gas contracts, the trend was toward greater
flexibility (with increased risk and thus risk management), as the table below on natural gas contracting
demonstrates.
Evolution of Natural Gas Contract Terms
Contract Terms
Price
Purchase/Delivery
Obligation
Pre-1983
Fixed price, fixed
escalators, favored
nations
Total wellhead
production
% take or pay; dedication
of reserves
Delivery Point(s)
Wellhead delivery
Quality Measurement
& Tests
Detailed provisions for
measurement and quality
specs
Life of reserves
Quantity
Length
1983-1989
30-day spot market price
“Up to…”
Best efforts, fully
interruptible by both
parties
Into the mainline of the
transporting pipeline of
city gate
Per measurement and
specs of the transporting
pipeline
30-day evergreen, subject
to termination
1989-1990s
Spot market indexed pricing; fixed
pricing for 6-12 month terms;
seasonal pricing
Specified quantity; winter/summer
or other seasonal differentials
Corporate warranty of
deliverability
Headstations or pooling points;
city gate
Per measurement and specs of the
transporting pipeline
One year, five years, ten years
Source: John Herbert, NGC, 1993
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
10-12
Economics of the Energy Industries
CHAPTER 11 - NATURAL GAS PROCESSING
Introduction
Natural gas processing plants liquefy the heavier molecules that occur in the gas stream in order to make
the production more marketable and to increase profits from the lease. Natural gas, produced from
formations, differs from “town gas” which is manufactured from coal. The most important consideration
in evaluating a processing plant is deciding which liquids to recover. Normally, natural gas consists of
about 97% methane (one carbon and four hydrogen molecules), 1.5% ethane with the remainder formed
by butanes, propane, and larger hydrocarbon molecules. “Wet” gas contains a higher proportion of larger
molecules as well as oil condensate as opposed to ”dry” gas, which contains little or none. Processing
plant design is contingent on the composition of the gas stream. Recovery of all molecules is possible but
raises both the initial cost of plant and operating costs considerably. The value of the liquids produced
should be high enough to cover the costs. However, during the stage of evaluating the project it is
difficult to get a reliable estimate of their value. Liquids prices have been volatile in the past and market
conditions are in constant change.
Another consideration is the location and the size of the plant to be built. A site near producing fields
would lower the cost of transportation of natural gas, while a plant located near consumption centers
would make it easier to market the products. The size depends on the volume of gas expected to be
processed, which in turn depends on estimates of the field based on geological studies and exploratory
drilling. If the actual production falls short of estimates, the company can end up with an oversized plant.
Naturally, the initial investment on this plant would also turn out more than necessary lowering the cash
flow of the operation.
Some types of processing technology available are as follows.
•
Mechanical Refrigeration System. This system recovers 30 to 50% of propane and 80 to 90% of
butanes at -20 degrees Fahrenheit.
•
Turbo Expander. These type of plants recover up to 99% of propanes and between 50 to 90% of
ethane.
•
Short-cycle Unit (LTX Expansion System). This is mainly used for lean gas systems and
recovers 20% of butanes and 80% of gasolines.
The choice of plant technology depends on the mix of liquids desired as discussed above. However, the
output of liquids changes according to market conditions. At any given time, the plant operator may only
wish to recover certain liquids and not others. This type of flexibility is, however, expensive.
A Model of Natural Gas Processing Plant Investment
Our model is for a small plant with a processing capacity of 100 million cubic feet (mcf) a day and a 10year life. We assume an initial investment of $10 million will be sufficient for this plant. We further
assume following recovery rates: 94.5% methane, 5% of liquids without specifying which molecules, and
0.5% of loss (gas consumed in the process as fuel). Profit margins are set to 10 cents per cubic feet for
gas and 20 cents per cubic feet for liquids. Under these assumptions, the project's after-tax cash flows
yield a net present value of $5.93 million with an internal rate of return of 24%.
If, for example, the plant is not able to receive 100 mcf a day to process but only 75 mcf, the NPV falls to
$2.73 million and the IRR falls to 17%. This example shows the importance of location of the plant in
terms of consistently having the necessary supplies in order to fully utilize the plant’s capacity. Product
margins, as in the case of petroleum refineries, can also create significant risk. If the profit margin for gas
falls to 7 cents per cubic feet from 10 cents as we initially assumed, the project NPV falls to $2.46
million, and the new IRR is 16%. If lower margins and lower sales occur at the same time, the NPV now
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
11 – 1
Economics of the Energy Industries
barely stays positive at $130,000 and the IRR falls to 10%. These new values seriously question the
viability of the project.
Further “what if?” scenarios can be considered, including fluctuations in the profit margins of liquids.
However, these will be less important, because liquids account only for a small percentage of the output.
Given the assumption that the plant is designed to yield specified percentages, significant fluctuations in
shares of gas and liquids in total output are not expected. As we have discussed in previous chapters, a
full scale simulation model will incorporate all this information.
A Model for Gas Processing Plant Investment
Volume=
Gas margin=
Strip margin=
Share of gas=
Share of strip=
Discount rate=
Depreciation=
Tax rate=
100000 1000 cf
0.1 $/1000 cf
0.2 $/1000 cf
94.5%
5.0%
10.0%
10.0%
40.0%
Year
0
1
2
3
4
5
6
7
8
9
10
$ million
$ million
Investment Depreciation
10
0
0
1.00
0
1.00
0
1.00
0
1.00
0
1.00
0
1.00
0
1.00
0
1.00
0
1.00
0
1.00
1000 cf
Volume
0
100000
100000
100000
100000
100000
100000
100000
100000
100000
100000
$ million
$ million
Net Revenue After-tax Inc.
0
0
3.81
1.69
3.81
1.69
3.81
1.69
3.81
1.69
3.81
1.69
3.81
1.69
3.81
1.69
3.81
1.69
3.81
1.69
3.81
1.69
$ million
Cash Flow
-10
2.69
2.69
2.69
2.69
2.69
2.69
2.69
2.69
2.69
2.69
$5.93
24%
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
11 - 2
Economics of the Energy Industries
CHAPTER 12 – LIQUEFIED NATURAL GAS
What is LNG?
Liquefied natural gas (LNG) is natural gas that has been cooled to the point that it condenses to a liquid,
which occurs at a temperature of approximately -256oF (-161oC) and at atmospheric pressure.
Liquefaction reduces the volume by approximately 600 times thus making it more economical to transport
between continents in specially designed ocean vessels, whereas traditional pipeline transportation
systems would be less economically attractive and could be technically or politically infeasible.
Thus, LNG technology makes natural gas available throughout the world. LNG trade originally started in
1964 around the Atlantic Basin, the emphasis shifted to the Pacific when the American market failed to
live up to expectations. Japan, and later other Far East countries, lacking indigenous energy resources
and isolated from potential sources of pipeline gas, found LNG to be attractive and created rapidly
growing markets.
Reduction of Gas Flaring
Of particular interest is the role that exporting gas in the form of LNG might play to help reduce natural
gas flaring, for both environmental benefits and to capture this premium commodity. There are large
reserves of natural gas in areas for which there is no significant market. Such hydrocarbon reserves are
stranded in North Africa, West Africa, South America, Caribbean, the Middle East, Indonesia, Malaysia,
Northwestern Australia and Alaska. Some of the gas that would otherwise be flared is instead converted
to LNG. This reduces the environmental impact of continuous flaring of large quantities of natural gas.
About 2.5 tcf of natural gas is flared annually out of a total of 112 tcf of gas produced but not marketed
globally. The balance is re-injected into the reservoir due to lack of markets.1
To end flaring is a goal for producing countries and companies, environmental groups and institutions
like the World Bank. These initiatives have contributed to increased interest in LNG as a means of
utilizing valuable natural gas resources and contributing toward sustainable development.
Natural Gas Trends
Natural gas provided 24% of the world average energy primary needs in 2004 and is expected to increase
to 25% in 2030 (see chart below).2 Consumption of natural gas continues to increase worldwide (see
Chapter
1
for
details).
This
World Primary Energy Consumption by Fuel in 2004
increasing demand is
mainly due to the
fact that natural gas
6%
6%
is one of the cleaner
Oil
and most efficient
37%
Natural Gas
energy
sources,
Coal
especially when used
27%
in power generation.
Nuclear Energy
As a result, most of
Hydro electric
the
increase
in
24%
natural
gas
consumption
has
Source: BP Global Statistical Review of World Energy June 2005
come from and is
expected to come from the electric power sector. Market reforms in many countries have been fueling the
1
EIA, International Energy Annual 2003, http://www.eia.doe.gov/pub/international/iea2003/table41.xls
Key World Energy Statistics 2005, International Energy Agency (IEA), 2005.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
2
12 – 1
Economics of the Energy Industries
development of merchant generation facilities. Although many of these investments failed to generate
desired revenues and faced a variety of problems (e.g., failure to dispatch), natural gas remains the fuel of
choice for large scale power generation.
The rate of increase is faster in the Asia
Pacific Region than elsewhere, although
relative consumption in this region still
lags behind the traditional markets of
Europe and North America. In 2004, the
U.S., Russia, U.K., Germany, Canada
and Japan made up about 52 percent of
total worldwide natural gas consumption
(see chart to the right).
Natural Gas Consumption by Country in 2004
24%
48%
15%
3% 3% 3% 4%
U.S.
Russian Federation U.K.
The largest increments in gas use are
Germany
Canada
Japan
expected in Central and South America
Others
and in developing Asia, and the Source: BP Global Statistical Review of World Energy June 2005
developing countries as a whole are
expected to add a larger increment to gas use by 2030 than are the industrialized countries. The largest
natural gas usage in 2030 are expected to still be North America (mostly the U.S.) and Western Europe
and Russia.
The growth in demand for natural gas worldwide is outpacing the demand for any other hydrocarbon fuel.
This is due to a number of factors, including price, environmentally benign characteristics of natural gas,
fuel diversification needs of consumers, energy security concerns, deregulation of both natural gas and
electricity markets, and overall economic growth. Accordingly, natural gas use is projected to double, to
147 trillion cubic feet (tcf) or 397 billion cubic feet (bcf/d) in 2025 from 96 tcf or 260 bcf/d in 2004 (see
next chart).3
450.0
400.0
350.0
300.0
250.0
200.0
150.0
100.0
50.0
0.0
19
70
19
72
19
74
19
76
19
78
19
80
19
82
19
84
19
86
19
88
19
90
19
92
19
94
19
96
19
98
20
00
20
02
20
04
20
15
20
25
Bcf/d
World Natural Gas Consumption
Source: BP Global Stat istical Review of World Energy June 2005, Key World Energy St atist ics 2005, Int ernat ional Energy
05
Agency (IEA), 2005
Role of LNG in Global Natural Gas Trade
A global gas market has evolved to satisfy increasing demand for natural gas. Natural gas has been
delivered from producing regions to consumption centers either by pipelines, or by ships in the form of
3
BP Global Statistical Review of World Energy June 2005; Key World Energy Statistics 2005, International Energy Agency
(IEA), 2005
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
12 - 2
Economics of the Energy Industries
liquefied natural gas, or LNG. In 2004, 26% of global natural gas was transported as LNG in specially
designed tankers.
The global LNG business and trade have grown at an average rate of 6% per annum between 1992 and
2002. 12 countries produced a total of around 6.6 tcf of LNG in 2004 to 14 importing countries. In
February 2003, the Dominican Republic received its first shipment of LNG while in October 2003,
Portugal's new LNG terminal, Sines, processed its first cargo. India imported its first cargo of LNG in
January 2004, while the UK joined the club of LNG importers in July 2005 when the Isle of Grain
terminal was put in operation.
7,000
6,000
6% per year growth (1992 - 2004)
bcf
5,000
4,000
3,000
2,000
1,000
1970 1975 1980 1985 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004
Indonesia
Australia
UAE
Trinidad & Tobago
Malaysia
Brunei
USA
Nigeria
Qatar
Oman
Algeria
Libya
Source: BP Statistical Review of World Energy June 2005
The growth in LNG demand has been particularly strong since the first cargoes were delivered in the
1964 from Algeria to the UK and France, and gas from Alaska to Japan. It expanded in the 1970s with
shipments from Libya to Spain and Italy, from Algeria to the U.S., and most importantly, from Indonesia,
Brunei and the Middle East to Japan. During the 1980s, LNG trade contracted along with a U.S. gas price
collapse and expanded pipeline gas supplies in Europe.
Pacific Basin
South Korea
17%
Atlantic Basin
France
4%
Spain
10%
Taiwan
5%
Other
34%
Japan
45%
Portugal
1%
USA
11%
Italy
3%
Turkey
Greece 2%
0%
Belgium
2%
During the 1990s, while there was
some growth in the U.S. and
European LNG imports, imports to
Japan and South Korea grew
tremendously. Qatar became a
significant supplier in the late
1990s. The worldwide LNG
demand grew by about 5% in
2001, 2002 and 2004, and hefty
13% in 2003. The demand growth
rate between 1992 and 2004
averaged about 6% per annum.
This trend is expected to continue.
According to the International
Source: Cedigaz, BP Statistical Review of World Energy June 2005
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
12 – 3
Economics of the Energy Industries
Energy Agency (IEA),4 inter-regional LNG trade is expected to increase six fold, from 6.6 tcf in 2004 to
about 25 tcf by 2030, becoming as important as pipeline trade by 2030.
The LNG trade can be conveniently divided into two regions the Pacific-Indian Basin and the AtlanticMediterranean Basin. Today, the Pacific Basin accounts for most of the LNG volumes traded, led by
Japan and South Korea. However, most of the increase in LNG trade will be in the Atlantic basin, which
is expected to overtake the Pacific basin in volume. European countries but increasingly the U.S. and
Mexico are in need of LNG supplies. The 2004 global trade movement data are provided in the appendix.
Pacific Basin
Australia
7%
Brunei
5%
Oman
5%
Atlantic Basin
UAE
4% USA
1%
Algeria
14%
Qatar
14%
Trinidad &
Tobago
8%
Nigeria
7%
Libya
0%
Malaysia
16%
Indonesia
19%
Other
30%
Source: BP Statistical Review of World Energy June 2005
Similar to the consumption
picture, most of the LNG
suppliers are located near
and serve the Pacific Basin.
Indonesia, Malaysia and
Qatar are the largest
suppliers in the region. The
region is home to most of
the 19 liquefaction facilities
operating worldwide. Qatar
LNG recently overtook the
eight-train, 22-mtpa, (1.07
Tcf per year) Indonesian
facility at Bontang on the
eastern Kalimantan coast
with a 25-mtpa facility as
the largest in the world.
Algeria is the only supplier
in the Atlantic Basin that is
comparable in size.
As of April 2006, there were 202 LNG carriers operating with another 148 under construction. Nearly all
of these carriers are being built in Japan and South Korea, which together control over 70 percent of the
market.5 But, shipbuilders in China, France and Spain have orders for five, three and one ship respectively
and could potentially emerge as serious competitors to Asian LNG shipbuilders. At the other end of the
LNG chain are the regasification terminals, of which there are 49 operating worldwide. The largest of
these is the Sodegaura terminal operated by Tokyo Gas, with a storage capacity of 2.66 million cubic
meters (94 MMcf).
New LNG Supplies
A number of plants are currently being expanded, and many new LNG trains have been announced,
mostly in the Atlantic Basin.
Atlantic Basin
In the Atlantic Basin, LNG is currently being produced by Algeria, Libya, Nigeria and Trinidad and
Tobago. Egypt has recently put in operation two terminals in the Mediterranean with an associated overall
liquefaction capacity of 400 bcf per year. All these countries have substantial expansion capacity, some of
which is already in the planning process or committed. In addition, countries like, Angola and various
others in West Africa have announced new projects. Although more expensive, some of the Middle East
countries augment the LNG supply into the Atlantic Basin. The largest portion of Algeria’s LNG goes to
4
World Energy Outlook 2004, International Energy Agency (IEA), 2004.
http://times.hankooki.com/lpage/biz/200604/kt2006040621202811910.htm
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
5
12 - 4
Economics of the Energy Industries
France and Spain. Trinidad & Tobago is the primary supplier to the U.S., destination for about 5% of the
world’s LNG imports. Nigeria supplies several countries in Europe, as well as the U.S.
Atlantic Basin Suppliers
Supply Location
Algeria – Arzew. Repsol YPF/Gas
Natural/Sonatrach
Size (mtpa)
Startup
5.2
2009
Algeria – Skikda. Sonatrach
Angola – Soyo.
Chevron/BP/ExxonMobil/Total
Libiya – Marsa Al-Brega expansion.
BP/NOC
Equatorial Guinea – Bioko Island.
Marathon Oil
4.5
2010
5.0
2006
3.2
2008
3.4
2008
Nigeria – NLNG Plus
Nigeria – Brass LNG.
NNPC/ConocoPhilips/Chevron/ENI
Nigeria – Olokola LNG.
NNPC/BG/Chevron/Shell
20.0
2007-10
10.0
2009
20.0
2010
Norway – Snohvit
4.0
2006
Trinidad 5-6
Venezuela – Gran Mariscal de
Ayacucho
6.0
2009-10
4.7
2010
Venezuela - Jose
2.1
2007
Russia – Yamal Peninsula
7.5
2010
Total
95.6
Pacific Basin Suppliers
Australia – Gordon LNG.
Chevron/ExxonMobil/Shell
5.0
2009
Australia – Woodside Energy 5
4.2
2008
Russia – Sakhalin II
9.6
2008
Indonesia – Tangguh. BP
7.6
2008
Qatar – QatarGas 2-4
31.2
2009-10
Qatar – RasGas 2-3
12.5
2007-08
Peru – Pampa Melchorita
4.4
2009
In the Atlantic Basin area, five countries
produced around 2 tcf (43 million tonnes) in
2004 which is about 30 percent of total
worldwide LNG production. LNG production
would more than triple by 2010 with both
green-field and expansion projects totaling 4.4
tcf (95.6 million tonnes) of capacity under
construction. If announced projects proceed as
planned, Venezuela, Angola, Equatorial
Guinea, Russia and Norway could join the
group of LNG exporters in the Atlantic Basin
by 2010.
Pacific Basin
The Pacific Basin imports 66% of LNG
produced worldwide. Japan is the leading
importer of LNG in the Pacific Basin (and
worldwide), followed by South Korea. Japan
imports about 45% of the world’s LNG.
Indonesia alone supplied 19 percent and
Malaysia, 16 percent; most of whose LNG goes
to Japan. In the Pacific Basin area, eight
countries produced around 5 tcf (109 million
tonnes) in 2004. New LNG trains are under
construction which will increase the supply by
75%. Core demand for LNG is still expected to
come from the established markets in Japan,
Korea and Taiwan, but new emerging markets
in India and China.
LNG Value Chain
On the question of cost and price, the LNG
value
chain
represents
investment
commitments for the parties involved.
However, the cost estimates for importing
LNG are considerably less than when the LNG industry was launched roughly 40 years ago. Substantial
savings have been achieved for both liquefaction and shipbuilding, and, importantly, the life spans of
LNG tankers have been extended. The LNG value chain today encompasses significant technology
improvements for cost reductions as well as safety and environmental enhancements and protections.
Overall, the average costs for liquefaction, shipping and regasification have declined.
Yemen – Bal Haf. Total
6.2
Total
Source: EIA, Media Announcements
80.7
2009
Typical LNG Value Chain Costs
EXPLORATION &
PRODUCTION
$1.0-$2.5 billion
$0.5-$1.0/MMBtu
REGASIFICATION &
LIQUEFACTION
SHIPPING
STORAGE
$1.5-$2.0 billion
$0.8-$2.6 billion
$0.5-$1.0 billion
$0.8-$1.2/MMBtu
$0.4-$1.7/MMBtu
$0.3-$0.5/MMBtu
TOTAL = $3.7 - $8.1 billion or $2.0 -$4.4/MMBtu
Greatest variability is in upstream feedstock for liquefaction.
Source: Industry
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
12 – 5
Economics of the Energy Industries
Representative LNG costs are shown above. Variation in the cost for natural gas feedstock (production)
hinges on terms that governments offer for E&P activity. Shipping costs will vary based upon shipping
distance.
Natural gas price forecast and cost of LNG ($/MMBTU)
$5.00
$4.50
$4.00
S/mmbtu
$3.50
$3.00
$2.50
$2.00
$1.50
$1.00
$0.50
LNG Cost Band $2.00 - $3.70
$0.00
2004
2008
Price Forecast
2012
2016
2020
2024
Source: EIA and Industry
The chart above compares the EIA forecast of natural gas in North America with the range of delivered
cost of LNG. Clearly, LNG projects can be commercially viable and provide cost-competitive natural gas
supplies to the U.S. market. It is also useful to keep in mind that the benchmark, Henry Hub natural gas
price has been above $3.50 per MMBTU since early 2000 and with expectations going forward of prices
above $4.00 for some time to come.
LNG project cost is dropping
800
$ /tonne of c apac ity
700
600
500
400
300
200
100
0
mid 1990
Source : IEA
2002
2010
Liquefaction Shipping
Shipping
2030
Regasification and Storage
In recent years, competition among builders has been driving down costs for both green-field plants and
vessels. Technology development and improvements in refrigeration and liquefaction techniques have
reduced the capital costs of LNG processing and shipping, allowing more LNG projects to achieve
commercial viability. The result has been a proliferation of LNG sales in both the Asian and Atlantic
Basin markets. Today, LNG competes with pipeline gas in the North American and European markets
and will soon compete in additional markets. The overall capital cost of LNG supply chains are expected
to continue to fall. Total capacity requirement have fallen from around $700 per tonne in the mid-1990s
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
12 - 6
Economics of the Energy Industries
to around $500 per tonne in 2003. Costs are projected to fall to $420 per tonne by 2010 and $320 per
tonne by 2030. This assumed a shipping distance of about 4,000km.
Liquefaction
Nominal liquefaction capital cost had fallen from $550 per tonne of LNG capacity on average in 1990 to
$195 in 20056. According to IEA, recent liquefaction plants being built can process up to 7 mtpa, up from
2 mtpa in the early 1990’s. Economies of scale are achieved by sharing common facilities, such as utility
infrastructure and storage tanks. As a result, unit cost of a second train is typically much lower than that
of the first train. Integrating terminals with power plants have also helped to reduce costs. On the average
liquefaction costs plants are projected to drop to $200/tpa by 2010 and $150/tpa by 2030. The following
chart shows that the unit capital cost of five green-field projects built in the latter half of the 90’s
averaged $280 per tpy7
LNG Greenfield Liquefaction Costs
500
Source: BP
$/tpy
400
300
200
100
0
1
1996
Qatargas
Source: OGJ, Industry
1
1999
Nigeria
LNG
1
1999
Atlantic
LNG
1
1999
Rasgas,
Qatar
2000
Oman
LNG
2
2005
Idku,
Egypt
The main cost-cutting measures put into effect include improvements in the design efficiency of LNG
plant, improvements in liquefaction technology, and improved economies of scale. The improvements in
liquefaction technology have included optimization of air and water-cooling, and a reduction in design
redundancy.
Transport
The cost of building LNG carriers has fallen from an average of $250 million to $170 million, more than
30%, between 1992 and 2002. However, due to increased demand and costs of materials (especially
steel), this trend has slowed even having tanker costs drift higher. Larger tankers and cargoes, coupled
with expanded terminals to handle the bigger vessels, and enhanced tanker efficiencies have both lowered
shipping costs substantially. In March 2006, ConocoPhillips signed a contract with Samsung for three
270,000 cubic meters LNG tankers for delivery in 2009. Ships will use the membrane cargo containment
technology. Currently, the biggest LNG ship can carry almost 150,000 cubic meters. The trend for larger
LNG tankers continues. LNG tankers twice that size - over 300,000 cm are already being designed. By
2010, LNG carriers with 320,000 to 350,000 cubic meters of capacity may be possible.
6
Idku terminal in Egypt went online in May 2005 with $195/ton of capacity.
Yost, Chuck & DiNapoli, Robert; Benchmarking study compares LNG plant costs, Oil & Gas Journal, April. 14, 2003
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
7
12 – 7
Economics of the Energy Industries
Transportation costs are one of the expenses in LNG chain. Applying economies of scale by increasing
the size of the vessel’s cargo, a saving on the unit transportation costs can be made. So far, the vessels
constructed have been restricted by terminal design. It may be possible that new terminals coming on line
will have the flexibility to accommodate larger vessels. All the yards involve in LNG already have plans
in hand for the construction of Very Large LNG Carriers (VLLNGC). The ability of fixed receiving
terminals to handle very large ships may limit the ultimate volume they will transport. Offshore
regasification terminals will likely not have this constraint.
Tanker Cost are Dropping
LNG carrier (125-138,000 cu.m) newbuilding prices
$M
300
250
200
150
100
50
0
19901991199219931994199519961997199819992001200220032004 JanAug
Source: LNGOneWorld 2001©, CEE
2005
New designs of vessels are being developed in addition to the increases in size mentioned before. Firstly,
tankers that incorporate regasification facilities onboard have been built and are in operation. This allows
for the direct offloading of natural gas into existing natural gas infrastructure thus avoiding LNG handling
at terminals. Secondly, with the recent development of LNG liquefaction plants in severe Arctic
conditions new carriers are being designed and built to serve Snohvit and Shtockman terminals.
As tankers return empty after offloading their LNG cargo, finding other cargoes for the return trip could
help defray those costs though dual purpose tankers have not been developed to date.
Regasification
$/tonne
Average unit regasification terminal costs are currently around $86 million per bcm per year capacity,
accounting for 20% of the total cost of an LNG
chain, not including upstream development. On
140
average regasification cost are projected to fall by
120
the IEA, mainly due to economies of scale to $77
million by 2010 and $65 million by 2030 (see chart
100
to the left).
80
On arrival at the receiving terminal in its liquid
state, LNG is pumped first to a double-walled
40
storage tank, similar to those used in the
liquefaction plant, then it is pumped at high
20
pressure through various terminal components
0
where it is warmed in a controlled environment.
m id 1990
2002
2010
2030
The vaporized gas is then regulated for pressure
and enters the U.S. natural gas pipeline system.
Regasification and Storage
Finally, residential and commercial consumers
receive natural gas for daily use from local gas utilities or in the form of electricity.
60
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
12 - 8
Economics of the Energy Industries
LNG Pricing Mechanisms
International gas pricing structures have evolved over time. The LNG pricing had traditionally been
indexed on competing fuels. There have been three distinct and relatively independent markets for LNG.
In the U.S., the competing fuel is pipeline natural gas, and the index price is Henry Hub price for short
term sales. The LNG transactions in the U.S. are therefore subject to a high degree of price volatility. The
Trinidad LNG contracts are based on Henry Hub. In Europe, LNG prices are related to competing fuels
such as low-sulfur residual fuel oil. There have been recent linkages to natural gas spot market and
futures prices. In Asia, prices are linked to imported crude oil. The price of is proportional to that of
crude oil plus an adjustment factor calculated based on the rate of inflation.
The destination of the LNG cargo has also an impact on the determination of the price. For example,
Algerian imports to Europe and Japan are priced based on crude and/or product prices in respective
regions. The oil indexing base could differ widely from contract to contract. Prices can also be tied to the
price of alternative fuels, such as coal in the case of power plants. This way, power plant managers will
be able to see that using LNG is comparable to using coal in generating electricity. Eventually, as the
market for LNG increases in volume and more buyers and sellers interact, spot and futures market may be
developed. The Asian prices are generally higher than prices elsewhere.
LNG Prices versus Henry Hub and Brent
12
10
$/mmbtu
8
6
4
2
1975
1976
1977
1978
1979
1980
1981
1982
1983
1984
1985
1986
1987
1988
1989
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
0
LNG (cif Japan)
US Henry Hub
Europe Gas cif
Oil (Brent)
Source: BP Gas and Power
Greater interactions between swing suppliers to both markets will likely cause prices to converge over
time. In the future, the LNG market may become more like the oil market of today, in which substantial
sales and purchases are made on the spot market, and firms invest in infrastructure without first arranging
long-term contracts with specific trading partners. A global LNG market could use the New York
Mercantile Exchange (NYMEX) as its primary pricing point, with other trading centers emerging in
Belgium, Tokyo, and other locations, all indexed off NYMEX. This would operate in much the same
way as the oil markets with West Texas Intermediate, Brent Blend, and Dubai serving as benchmarks.
Project Ownership and Financing
Because of the large sums and risks involved, financing arrangements are crucial to the LNG project
development process. Almost all projects that have been developed have been on the basis of long-term
contracts between the different parties along the supply chain i.e., the gas producer, the liquefaction
project sponsors, the LNG buyer and large final consumers.
Until now, no liquefaction plant or receiving terminal has been built without long-term contracts covering
the bulk of the capacity. Although long-term contracts will probably remain the backbone of the LNG
industry, they will become shorter and take-or-pay commitments may become less onerous.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
12 – 9
Economics of the Energy Industries
The upstream facilities and LNG liquefaction plant are structurally separate, although the partners in both
may be the same. The LNG buyer is normally responsible for financing the construction of the import
terminal. Either the upstream/liquefaction project developer or the buyer is responsible for arranging
financing for the ships, on a separate basis from both the liquefaction and receiving terminal projects.
Different players are involved in different parts of the LNG chain. In 2001, more than 60% of the equity
in global LNG liquefaction capacity was owned by state companies, in some cases in a joint venture with
a major oil and gas company.
Ownership of LNG Liquefaction Capacity
Source: IEA WEO 2005
Since the start of commercial sales over 40 years ago, the LNG industry has grown based on fixed trade
routes and long-term contracts. Typically, the new LNG projects have a build-up period or ‘wedge’ as
buyers increase commitments to full contracted volumes. In addition, the LNG projects typically have
some margin engineered into them resulting in spare capacity. Often this spare capacity is increased
through minor upgrading or de-bottlenecking, once performance has been established. Whereas the
existing buyers have usually committed to these incremental volumes over time, in 1986 Kogas started
LNG imports into Korea based purely on this surplus capacity from projects developed to supply
Japanese power and gas utilities.
Technology-driven cost reductions such as those cited earlier has made it possible for developers to
obtain financing to build plants without long term contracts. Newer plants are also being designed to
have excess capacity that can be used to supply a growing short-term or spot market for LNG. Buyers in
the Atlantic Basin in particular (Puerto Rico, Dominican Republic, Greece) are finding that this spot
market based on excess capacity is reliable. This is a change from the long-term, inflexible contracts of
the past.
New, more flexible, commercial arrangements are supporting these new market dynamics. Nontraditional buyers are emerging who require a less traditional contracting approach, as evidenced by the
increasing number of short-term LNG trades over the last few years. Customers are seeking to manage
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
12 - 10
Economics of the Energy Industries
seasonality and load variation with more innovative contracting strategies that do not always involve
additional investments in LNG storage tanks and ships.
Evolution of LNG Contracts
Market
Original Liquefaction Facility
Sold through
Contract Terms
Yielding
1980’s
Japan
1990’s
U.S.
2000’s
Spain
High CAPEX
Low CAPEX
Low CAPEX
Oil-indexed pricing
Gas-Gas competition
Spot Cargoes
Long Term
Long/Short Term
Cargo
Low risk/Low return
High risk/High return
High risk/High return
Potential for LNG Spot Trade
The commodity potential of LNG is greater than that of other energy products. There are several reasons
for this:
•
Cargoes of LNG have a narrow range of quality (BTU value), much less than crude oil’s thus
reducing the possible market segmentation.
•
Most ships are of a similar size range and have similar configurations: A ship starting from any
Atlantic source location could sail for any import terminal in the Atlantic Basin.
Trinidad & Tobago has replaced Algeria as the primary source of supply for the U.S., with cargoes
coming also from Qatar, Nigeria, Australia, and Oman. Although the long-term contracts with the
primary suppliers are still important, spot market sales are becoming much more common.
In 2006, the main limitation to the growth of spot trading is the lack of uncommitted shipping capacity,
whereas in the mid 1990s there were several vessels available for term and voyage charter - the first
phases of the Atlantic and Nigeria LNG projects absorbed much of this capacity in order to minimize the
initial project investment requirements.
Access to regasification terminals and pipelines present a greater challenge. Much of the transportation
capacity within Europe remains tied up with existing long-term take-or-pay contracts thus restricting
access for new volumes. For this situation to change, the regulation underway will need to effectively
address all areas of network codes and rules of operation at LNG terminals. This would allow fair access
and fair tariffs for new entrants. Many of the existing LNG import terminals in Europe could be easily
expanded.
Challenges to Building LNG Infrastructure in the U.S.
Although importation of LNG from around the world was an important component of North America’s
plans to restore energy security in the 1970s, there has not been any new LNG import facilities developed
on the continent for the past 20 years. In order to accommodate an increase in imported LNG, the number
of receiving and regasification terminal capacity must be increased. Some of this capacity increase will
be attained through expansion projects at the existing facilities. In addition, new facilities will need to be
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
12 – 11
Economics of the Energy Industries
built, and a number of new marine import terminals have been proposed not only in the U.S. but also in
Canada and Mexico.
Bcf
US LNG Supply
700
Algeria
Australia
Brunei
600
Indonesia
Malaysia
Nigeria
500
Oman
Qatar
Trinidad
UAE
Other
400
300
200
100
19
73
19
75
19
77
19
79
19
81
19
83
19
85
19
87
19
89
19
91
19
93
19
95
19
97
19
99
20
01
20
03
20
05
0
Sources: EIA
North America LNG Supply Forecast (bcfd)
Of note are proposals to build LNG import facilities in Canada and Mexico. Canada’s Atlantic coast,
once thought to be highly prospective for natural gas, could provide a key entry point for LNG cargos
destined for use in both eastern Canada and the northeastern U.S. Two terminals of 1 Bcf per day sendout capacity have already been approved, while six more have been proposed. Mexico has three approved
LNG terminals with 3.1 Bcf per day total capacity, Currently, five more regasification terminal have been
suggested to be built mainly on Mexico’s Pacific coast, which would be capable of supplying at least 3.8
Bcf a day. Proposed LNG receiving terminals in the Baja region could export surplus natural gas to
California and provide critical incremental supplies to balance western natural gas markets. Additional
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
12 - 12
Economics of the Energy Industries
proposed terminals further south on Mexico’s Pacific coast and in the Yucatán would provide indirect
support to North American natural gas balances by serving growing natural gas demand elsewhere in
Mexico.
Clearly, not all of these projects will be built, as there is no demand for all of the capacity (see chart
above). The EIA forecast8 indicated that 11.9 bcfd or 4.4 tcf per year of LNG would be required by 2030.
This means about four to five new terminals averaging one bcfd capacity each might be needed in
addition to the planned expansion of the existing terminals and from only one or two new terminals would
be needed by 2010.
A number of risks will impact prospective LNG import capacity development. For example, natural gas
market dynamics (shifts in supply, demand and thus price) could occur that would alter the outlook for
increased imports. In contrast, difficulties in siting and permitting new import terminals could delay
growth in LNG imports, possibly contributing to higher prices and related disruptions.
The challenges facing the development of new LNG infrastructure in the U.S. include permitting and
siting issues, (Local acceptance, safety and security, federal and state and local approvals), natural gas
transmission system issues (location of demand for natural gas, take away capacity, natural gas
interchangeability), and natural gas market issues.
Relevant Case Studies:
Gas Monetization in Bangladesh
Gas Monetization in Bolivia
Gas Monetization in Nigeria
Natural Gas Marketization in North America
Trinidad LNG Project
8
EIA – Annual Energy Outlook 2006, http://www.eia.doe.gov/oiaf/aeo/
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
12 – 13
Economics of the Energy Industries
APPENDIX
World LNG Imports by Origin, 2004 (Billion Cubic Feet)
EXPORTERS
United
States
Trinidad &
Tobago
Algeria
Libya
Nigeria
IMPORTERS
United States
462.10
120.34
11.82
1
0.37
Mexico
Puerto Rico
24.01
Dominican
6.36
Republic
Belgium
108.84
France
237.32
29.31
Greece
16.56
Italy
42.17
18.47
154.79
Portugal
48.88
Spain
232.37
22.25
169.87
Turkey
110.11
35.84
India
Japan
62.10
5.40
5.65
South Korea
10.59
8.48
Taiwan
2.83
Apparent Exports
62.47
497.88
878.31
40.72
467.45
1
Imports to Mexico from the United States are delivered by truck.
Sources: Energy Information Administration
Qatar
United Arab
Emirates
11.85
Oman
Australia
9.41
14.99
Brunei
Indonesia
Malaysia
Other
20.00
1.50
2.83
138.08
92.88
334.29
281.11
858.21
7.06
42.38
252.47
2.83
2.86
265.22
54.60
211.89
2.86
323.96
6.36
425.79
19.42
314.30
42.73
460.21
357.03
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
12 - 14
768.60
257.80
192.61
1,219.00
650.36
213.66
131.30
1,021.67
Total
Imports
652.02
0.37
24.01
6.36
108.84
269.45
16.56
215.42
48.88
618.37
145.96
2,873.56
1,048.50
332.46
6,453.64
Economics of the Energy Industries
CHAPTER 13 - REFINING AND MARKETING
Refining
Crude oil is not useful in its pure form as extracted from the ground; it needs to be refined into products
such as gasoline, fuel oil, and so on. Demand for crude oil is a derived demand, that is, it depends on the
demand for petroleum products. For example, demand for crude oil increases during the winter months of
the northern hemisphere as demand for heating oil increases in North America and Europe. Similarly,
during summer months, increased demand for gasoline and jet fuel along with increased traveling causes
the demand for crude oil to surge. In the early years of the oil industry, producing companies realized
that extending their operations to downstream such as refining and marketing would make it much easier
for them to market their crude oil and increase revenues. Also, high transactions costs involved in selling
crude oil could be avoided. Vertically integrated companies enjoyed the benefits of low transaction costs
and ready markets for their products for a long time.
However, following the oil shocks of the 1970s changing market conditions caused people to think that
the separation of upstream and downstream operations may be a good thing. This is because crude oil has
become much easier to sell at very high prices. Increasing world demand allowed these companies to sell
all they could produce by offering prices slightly below official OPEC prices. Given high and fairly
secure revenues from selling their crude oil, companies did not need their downstream businesses any
longer, especially in a time where downstream operations started to become highly competitive.
Before the first oil shock, in addition to transportation crude oil and its products were used for residential
heating as well as power generation in the U.S. and Europe, creating a significant demand for fuel oil
especially. Increasing traveling by citizens of these developed countries also created demand for gasoline
and jet fuel. But, higher crude oil prices led to conservation, increased efficiency and fuel substitution.
Coal, natural gas and nuclear power have become significant alternatives for fuel oil in power generation.
In the U.S., the share of coal in electricity generation has been more than 50% for decades, and the
nuclear power is the second largest source of electricity with roughly 20%. The amount of electricity
generated by coal more than doubled since the first oil shock. Before the early 1970s, there were
practically no nuclear power plants in the world. Natural gas became a significant option for fueling
power plants as well as for residential heating.
As a result of declining demand for refinery products even in most affluent markets, product margins
started to shrink. Also, the belief that the price of oil would stay high forever caused major oil companies
to invest heavily in building export refineries in the Middle East so that the cost of crude oil inputs could
be minimized. Increasing competition from these refineries put considerable pressure on the refineries in
other parts of the world. Competition pulled down prices to such low levels that older plants were not
able to produce what was called “the incremental barrel” because, without fixed costs, product prices
were below the minimum average total cost of production. On the other hand, newer plants with their
initial investment still not fully recovered continued production, because prices were still high enough to
recover their fixed costs. If product prices fell below variable costs, even new plants would have to shut
down.
Between 1965 and 1970, there has been a significant surge in new refineries, increasing capacity from
34.5 million b/d to 51.4 million b/d, or a rise of 49% (see table next page). Most of the increase occurred
in North America and Europe. These regions continued to expend capacity along with the FSU and Asia
regions in the 1970s, adding another 30 million b/d by 1980 – almost 60% increase. Some of the capacity
increase observed in the U.S. during the late 1970s can be explained by the entitlement programs (see the
case study on Small Refiner Bias).
However, after 1980, refining capacity in developing regions such as Asia expanded significantly while
European and North American refining stalled with surplus capacity. One can also observe that the
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
13 – 1
Economics of the Energy Industries
Middle East has been another region where there has been significant investment in refining capacity.
High oil prices and depressed demand before 1986 kept refining capacity declining, but lower prices since
then combined with increasing worldwide demand for petroleum products fueled the capacity expansion.
The world refining capacity in 2000 was back to its 1980 level at 82 million b/d after falling to 73 million
b/d in the mid-1980s. Note, however, that about 8 million b/d of capacity was added in Asia, including
China between 1980 and 2000 and another 2.6 million b/d in the Middle East. North America lost about
2 million b/d despite increases in the late 1990s and Europe lost more than 6 million b/d of refining
capacity since 1980.
Refining Capacity 1965-2000 (million b/d)
North America
South & Central America
Europe
FSU
Middle East
Africa
China
Other Asia
Total
1965
11.9
3.6
8.7
4.5
1.7
0.6
0.2
3.4
34.5
1970
14.8
4.8
15.9
6.1
2.5
0.7
0.6
6.0
51.4
1975
18.1
6.9
22.1
8.4
3.1
1.2
1.2
9.6
70.7
1980
22.0
7.4
22.7
11.4
3.8
2.0
1.8
10.6
81.6
1985
18.6
5.8
17.1
12.3
4.3
2.4
2.2
10.4
73.1
1990
19.2
6.0
16.4
12.3
5.0
2.7
2.9
10.4
74.8
1995
18.6
6.2
16.2
10.3
5.7
2.8
4.0
13.1
76.9
2000
19.9
6.5
16.4
9.0
6.4
3.0
5.4
15.4
82.0
Source: BP Statistical Review of World Energy 2001.
Most refineries meet their "local" demand first, with exports providing a temporary flow for balancing
supply and demand. There have historically been a few exceptions to this local focus. A refining center in
the Caribbean, for instance, supplied heavy fuel oil to the U.S. East Coast where it was used for power,
heat, and electric generation. As the demand for this heavy fuel oil, or residual fuel oil, waned, so did
those dedicated refineries. While the Caribbean refineries, as well as refineries in the Middle East and in
Singapore, were built for product export, they are the exception.
Increasingly competitive nature of the downstream business led most companies to separate their
upstream and downstream operations, that is, abandon vertical integration. With the high cost of
environmental protection and competition from new refining capacity, refining margins in the U.S. and
Western Europe have steadily declined in recent years. The resulting competitive pressure is revealed in
a new trend, where companies are merging their downstream operations. Prime examples are those
mergers between BP and Mobil in Europe and between Shell and Texaco in the U.S. Many of these
mergers include retail marketing as well which, as we explain in Chapter 8, is extremely competitive.
Nevertheless, vertical integration stays a viable option for national oil companies which are not fully
exposed to global competition and are expected to provide their respective countries’ product needs
through their operations. Essentially, these companies (or countries) are in the same position as large
multinationals were before oil shocks of the 1970s. Since there is fierce competition in crude oil market,
refining their own crude oil and marketing products benefit these companies. Also, vertical integration
makes it easier for OPEC members to cheat on their quotas.
In 1981, the U.S. refining industry was dominated by 189 companies that owned 324 refineries; in 2002,
63 companies own 150 U.S. refineries as small independent refiners and gasoline marketers have
dwindled. While the number of refineries has shrunk, the capacity of remaining refineries has increased
to keep up with the increasing demand for gasoline in the U.S. (over 40% of world’s demand). Because
capacity increase has not been quite as large as demand growth, supplies are tighter. Meanwhile, many
independents have disappeared along with spot markets for unbranded gasoline. Both developments were
probably caused by market forces that tended to push prices down. In the late 1990s, gasoline prices were
about 45% lower, adjusted for inflation, than record high prices registered in 1981. During the 1990's the
role of independent refiners has grown again, largely as the result of refinery purchases from integrated
companies seeking to streamline and realign their positions. Furthermore, the independent refiners, like
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
13 - 2
Economics of the Energy Industries
the majors, are in a period of consolidation; the mergers and acquisitions are having a significant impact
on refinery ownership (although not overall refined product supply).
Changing market conditions is one of the factors managers need to consider when evaluating a refinery
project. The proposed refinery should be configured to increase the output of the most marketable
product. For example, in the U.S. gasoline constitutes
about 42-43% of the product mix whereas in Europe
diesel is still heavily used in cars and accounts for 35%
of the product mix (see graphic above). Therefore, a
refinery to be built in the U.S. needs different
specifications than a refinery in Europe. Refineries built
before the 1970s were designed to yield significant
amounts of fuel oil, but as we discussed high oil prices
lowered the demand for fuel oil. Refineries needed to be
upgraded to yield more of other products for which
demand conditions were better than those for fuel oil.
Increasing environmental regulations on sulfur
emissions caused refineries to prefer sweet crude oil
(sulfur content less than 0.5%) to sour crude oil (sulfur
content more than 1%) and/or to invest in technology to extract more of the sulfur out of their products.
The initial investment also depends on the location of the proposed refinery. Being near a pipeline or a
port is preferred as it lowers transportation costs. If there are petrochemical plants in the immediate area,
this can increase margins and guarantee a market for future products. Product prices pose even a bigger
challenge when it comes to forecasting. There are no systematic forecasts for international product prices
and the relationship between the price of crude oil and product prices has been unstable over time and
across countries and markets. Nevertheless, the major concern is whether refining and selling products
generates a higher netback value than simply selling crude oil or not. The spread between the product and
crude prices determines the answer to this question.
The following chart presents the fluctuations in product margins for gasoline, jet fuel, No. 2 distillate fuel
oil, residual fuel oil and a composite product (aviation gasoline, kerosene-type jet fuel, kerosene, motor
gasoline, distillate fuel nos. 1, 2, and 4, and residual fuel) in the U.S. for the 1978-2000 period. Refinery
margin is the difference between the composite refiner acquisition price of crude oil and the product price
to resellers. Obviously, the refiners need to make up what they lose in residual on other products.
Depending on the product (except for residual oil), the margin has been in the range of ¢11 and ¢25 per
gallon for the most of the 1990s, with gasoline as the most valuable product.
Refinery Margins in the U.S. (cents per gallon)
35
25
Gasoline
15
Jet Fuel
No. 2 Distillate
5
Residual
-5 1978
1980
1982
1984
1986
1988
1990
1992
1994
1996
1998
2000
2002
Composite
-15
-25
Source: Annual Energy Review, EIA
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
13 – 3
Economics of the Energy Industries
The uncertainty about the future demand for each product used to create some problems for refineries.
However, global markets are fairly developed and well connected so that product prices are fairly in
equilibrium around the world. Development of spot and futures markets expedited the globalization of
the product market. New York Mercantile Exchange (NYMEX) has 24-hour electronic trading which
connects Asian markets in real time regardless of time differences. Refineries almost anywhere in the
world can market any surplus product they may have in these markets. For example, the U.S. East Coast
has the option of receiving its heating oil supplies from the Gulf Coast or Rotterdam markets. Japan is in
the enviable position of trading with the U.S. West Coast, Singapore or the Persian Gulf. Similarly, the
Mediterranean region has several alternatives in Russia, Persian Gulf or Rotterdam for its product
supplies. These regions also serve Western Europe.
Refining Technology
The core refining process is simple distillation (see graphic below). Because crude oil is made up of a
mixture of hydrocarbons, this first and basic refining process is aimed at separating the crude oil into its
"fractions," the broad categories of its component hydrocarbons. Crude oil is heated and put into a still -a distillation column -- and different
products boil off and can be recovered
at different temperatures. The lighter
products -- liquid petroleum gases
(LPG), naphtha, and gasoline -- are
recovered at the lowest temperatures.
Middle distillates -- jet fuel, kerosene,
distillates (such as home heating oil
and diesel fuel) -- come next. Finally,
the heaviest products (residual fuel
oil) are recovered, sometimes at
temperatures over 1000 degrees F.
The simplest refineries stop at this
point.
Additional processing follows crude
distillation, "downstream" (or closer
to the refinery gate and the consumer)
of the distillation process. Downstream processing encompasses a variety of highly complex units
designed for very different upgrading processes. Some change the molecular structure of the input with
chemical reactions, some in the presence of a catalyst, and some with thermal reactions.
In general, these processes are designed to take heavy, low-valued feedstock -- often itself the output from
an earlier process -- and change it into lighter, higher-valued output. A catalytic cracker, for instance,
uses the gas oil (heavy distillate) output from crude distillation as its feedstock and produces additional
finished distillates (heating oil and diesel) and gasoline. Sulfur removal is accomplished in a
hydrotreater. A reforming unit produces higher octane components for gasoline from lower octane
feedstock that was recovered in the distillation process. A coker uses the heaviest output of distillation,
the residue or residuum, to produce a lighter feedstock for further processing, as well as petroleum coke.
A Model of Refining Investment
The simple model presented in this chapter is for a plant capable of processing 50,000 b/d (see tables at
the end). We assume that our company plans to buy this plant for $100 million. The product mix is set
such that 100 barrels of crude oil yield 25 barrels of light oil (gasoline, LPG, and so on), 40 barrels of
middle distillate (kerosene, diesel, and the like) and 31 barrels of heavy oil (fuel oil, various grades of
residual or “resid”) when refined. Product prices are tied to the price of crude oil. A barrel of light oil is
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
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Economics of the Energy Industries
priced 35% more, a barrel of middle distillate is 32% more and a barrel of heavy oil is 15% less than the
price of a barrel of crude oil. Operating and maintenance (O&M) costs are $1.20 per barrel.
In order to evaluate the project, we need to estimate cash flows over the expected lifetime of the refinery
(20 years in this case). The annual cash flow is defined as follows.
Cash Flow
= After-tax Income - Initial Investment + DDA
= (1-Tax rate)Taxable Income - Initial Investment + DDA
= (1-Tax rate)(Revenue - DDA) - Initial Investment + DDA
= (1-Tax rate)[(weighted product price - price of crude oil - O&M
cost)Volume - DDA] - Initial Investment + DDA,
3
∑ s jp j
where DDA stands for depreciation, depletion and amortization, and weighted product price =
j=1
sj is the share of jth product described above (25% light oil, 40% middle distillate and 31% heavy oil) and
pj is the price of the jth product relative to the price of crude oil.
As one can see from the spreadsheet, the above assumptions lead to an NPV equal to $60.28 million that
corresponds to an IRR of 21%. Once this base case (most likely) scenario is established, managers or
executives, who will decide on whether to go ahead with the project or not, may be interested in other
outcomes and their probabilities. After all, as we discussed there are uncertainties about the product
margins, O&M costs, and so on. For example, what would happen to the project’s returns if light oil
cannot be sold at a price 35% higher than the price of oil, but only 30% higher. Our recalculations show
that the project NPV falls to $36.61 million and the project IRR is down to 17%. If, instead, the market
for middle distillate is tight and the refiner cannot get a price more than 27% higher than the price of oil
(instead of 32% higher), the NPV falls to $22.40 million and the IRR falls to 14%. The second example
is comparable to the case of decreasing
fuel oil demand we discussed in the
40
Cash Flows
previous section.
20
0
-20
0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20
-40
-60
-80
-100
Coker
Original Refinery
-120
-140
-160
There are other scenarios that may be
of interest to decision makers. They
may want to learn what would happen
to returns if the refinery ends up
processing only 45,000 b/d instead of
50,000 barrels as originally expected.
In this case, NPV falls to $47.22
million and the IRR is now 19%. On
the other hand, an increase in O&M
costs from $1.2 per barrel to $1.5 per
barrel causes NPV to fall almost 50%
to $31.87 million, corresponding to an
IRR of 16%.
These kinds of sensitivity analyses can
be done for as many values as possible. It can also be carried out simultaneously for different values of
more than one variable. For example, if we consider lower prices for both light products and middle
distillate we discussed above, the project NPV becomes negative and the IRR becomes 10%. Under these
circumstances, the project becomes unacceptable. The company may decide to upgrade the refinery by
installing a coker to get rid of heavy oil and obtain more of lighter products instead. The NPV of this
incremental project (the coker) would be $20.29 million corresponding to an IRR of 12% despite the
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
13 – 5
Economics of the Energy Industries
initial investment of $160 million. Below a comparison of cash flows from the original refinery project
and the coker project is presented. Despite high initial investment, net cash flows from the coker surpass
those from the refinery throughout the 20-year life of these two projects (see tables at the end). The share
of heavy oil and its price are taken from the original refinery model discussed earlier. We assumed that,
out of 100 barrels of fuel oil, the coker can refine 32 barrels of light products, 47 barrels of middle
distillate and 18 barrels of petroleum coke. Prices of light oil and middle distillate are respectively 35%
and 32% higher than the price of crude oil (as we assumed in the previous case). The petroleum coke can
be sold for a price roughly equivalent to 25% of the price of crude oil.
Again, it is a worthwhile exercise to analyze how changes in crucial variables impact the project returns.
Revisiting some of the examples from the original refinery model, we can test the effect of a decline in
the price of light products from 35% higher than that of crude oil to 30% higher. In this case, the NPV
falls to $11.88 million and the IRR falls to 11%. If, instead, a similar decline in the price of middle
distillates is analyzed, the project NPV falls to $7.94 million and the project IRR falls to 11%.
As seen in the previous chapter, a simulation model is able to provide more accurate evaluations with
probabilities assigned to each possible outcome. It would actually enable the executives making
decisions to calculate the probability of this refinery project yielding a negative net present value. Then it
would be a question of whether this probability is acceptable or not. The only drawback is gathering
considerable amount of data about variables of interest so that one can create the distributions that most
realistically represent the behavior of these variables. As discussed earlier, the price of crude oil as well
as product prices creates a challenge, as their historical data does not fit standard bell curve distributions
very well. While it is difficult to analyze historical data on crude oil and product prices, the general
historical relationships among crude oil and product prices and demand are well established.
It is important to note that a more complex simulation model would also account for impacts on demand
of changing feedstock costs and product prices. A drop in fuel oil feedstock costs would initially cause
refining profit margins to fall. Rising demand with lower prices on petroleum products would eventually
cause refining margins to improve. Conversely, an increase in feedstock costs would initially trigger an
increase in refining margins. However, demand for petroleum products would eventually diminish in
response to higher product prices, causing those prices to soften and refining margins to suffer.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
13 - 6
Economics of the Energy Industries
A Model for Refinery Investment
Processing capacity =
Depreciation rate =
Tax rate =
Inflation rate =
Discount rate =
O&M cost =
Price of Crude Oil =
Light oil =
Middle Distillate =
Heavy oil =
50000
0.1
0.4
0
0.1
1.2
20
share/b price coef.
0.25
1.35
0.4
1.32
0.31
0.85
Year
0
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
$ million
Investment
100.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.3375
0.528
0.2635
22.58
$ million
DDA
10.00
9.00
8.10
7.29
6.56
5.90
5.31
4.78
4.30
3.87
3.49
3.14
3.14
3.14
3.14
3.14
3.14
3.14
3.14
3.14
3.14
100.00
b/d
Vol. of oil
50000.00
50000.00
50000.00
50000.00
50000.00
50000.00
50000.00
50000.00
50000.00
50000.00
50000.00
50000.00
50000.00
50000.00
50000.00
50000.00
50000.00
50000.00
50000.00
50000.00
50000.00
$/b
$ million $ million $ million
$ million
$ million
$ million
$ million
$ million
Price
Revenue
O&M
Cost of oil Net Revenue Taxable Inc.
Tax
After-tax Inc. Cash flow
20.00
412.09
21.90
365.00
25.19
15.19
6.07
9.11
-80.89
20.00
412.09
21.90
365.00
25.19
16.19
6.47
9.71
18.71
20.00
412.09
21.90
365.00
25.19
17.09
6.83
10.25
18.35
20.00
412.09
21.90
365.00
25.19
17.90
7.16
10.74
18.03
20.00
412.09
21.90
365.00
25.19
18.62
7.45
11.17
17.74
20.00
412.09
21.90
365.00
25.19
19.28
7.71
11.57
17.47
20.00
412.09
21.90
365.00
25.19
19.87
7.95
11.92
17.24
20.00
412.09
21.90
365.00
25.19
20.40
8.16
12.24
17.02
20.00
412.09
21.90
365.00
25.19
20.88
8.35
12.53
16.83
20.00
412.09
21.90
365.00
25.19
21.31
8.52
12.79
16.66
20.00
412.09
21.90
365.00
25.19
21.70
8.68
13.02
16.51
20.00
412.09
21.90
365.00
25.19
22.05
8.82
13.23
16.37
20.00
412.09
21.90
365.00
25.19
22.05
8.82
13.23
16.37
20.00
412.09
21.90
365.00
25.19
22.05
8.82
13.23
16.37
20.00
412.09
21.90
365.00
25.19
22.05
8.82
13.23
16.37
20.00
412.09
21.90
365.00
25.19
22.05
8.82
13.23
16.37
20.00
412.09
21.90
365.00
25.19
22.05
8.82
13.23
16.37
20.00
412.09
21.90
365.00
25.19
22.05
8.82
13.23
16.37
20.00
412.09
21.90
365.00
25.19
22.05
8.82
13.23
16.37
20.00
412.09
21.90
365.00
25.19
22.05
8.82
13.23
16.37
20.00
412.09
21.90
365.00
25.19
22.05
8.82
13.23
16.37
NPV=
$60.28
IRR=
21%
Increm ental Refinery Project - Coker
Processing capacity =
Share of fuel oil=
C ost of fuel oil=
D epreciation rate =
T ax rate =
D iscount rate =
Price of crude oil=
Light oil =
M iddle Distillate=
Petroleum coke=
Year
0
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
50000
0.31
17
0.1
0.4
0.1
20
share/b
price coef.
0.32
1.35
0.47
1.32
0.18
0.25
0.432
0.6204
0.045
21.948
$ m illion
$ m illion
b/d
$/b
$ m illion
$ m illion
Investm ent D epreciation Vol. of Fuel O il C ost of Fuel O il R evenue T axable Inc. After-tax Inc.
160.00
0.00
0.00
17.00
0.00
0.00
0.00
0.00
16.00
15500.00
17.00
27.99
11.99
7.20
0.00
16.00
15500.00
17.00
27.99
11.99
7.20
0.00
16.00
15500.00
17.00
27.99
11.99
7.20
0.00
16.00
15500.00
17.00
27.99
11.99
7.20
0.00
16.00
15500.00
17.00
27.99
11.99
7.20
0.00
16.00
15500.00
17.00
27.99
11.99
7.20
0.00
16.00
15500.00
17.00
27.99
11.99
7.20
0.00
16.00
15500.00
17.00
27.99
11.99
7.20
0.00
16.00
15500.00
17.00
27.99
11.99
7.20
0.00
16.00
15500.00
17.00
27.99
11.99
7.20
0.00
0.00
15500.00
17.00
27.99
27.99
16.80
0.00
0.00
15500.00
17.00
27.99
27.99
16.80
0.00
0.00
15500.00
17.00
27.99
27.99
16.80
0.00
0.00
15500.00
17.00
27.99
27.99
16.80
0.00
0.00
15500.00
17.00
27.99
27.99
16.80
0.00
0.00
15500.00
17.00
27.99
27.99
16.80
0.00
0.00
15500.00
17.00
27.99
27.99
16.80
0.00
0.00
15500.00
17.00
27.99
27.99
16.80
0.00
0.00
15500.00
17.00
27.99
27.99
16.80
0.00
0.00
15500.00
17.00
27.99
27.99
16.80
N PV=
IR R =
$ m illion
C ash Flow
-160.00
23.20
23.20
23.20
23.20
23.20
23.20
23.20
23.20
23.20
23.20
16.80
16.80
16.80
16.80
16.80
16.80
16.80
16.80
16.80
16.80
$20.29
12%
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
13 – 7
Economics of the Energy Industries
Marketing
Marketing petroleum products, especially gasoline, is a risky business because of the highly competitive
nature of many markets as well as the uncertain nature of demand and supply conditions. In countries
where competition in retail marketing exists, it is difficult to pass on increases in the price of crude oil to
customers. The market is affected by seasonal fluctuations as well as by developments in the global or
local crude oil markets. Despite the risks involved, opening a gasoline station usually requires a small
initial investment, especially when compared to E&P and refining operations we considered in previous
chapters. If a company decides to open a chain of stations at the same time, a considerable amount of
capital may be necessary. However, most gas stations are operated as franchises by individual investors.
In the U.S., competition is quite fierce in marketing and one can observe the level of competition at any
major road intersection where each corner is occupied by a gasoline station. Traveling around a city, one
will also notice that prices tend to be higher at gasoline stations, which are either the only stations in a
neighborhood or in more well-to-do neighborhoods. On the other hand, sales volume may be much lower
in these areas as compared to major intersections where four gasoline stations compete with each other
usually by lowering their prices. Creating a brand loyalty has also been a strategy used by major oil
companies.
Gasoline stations underwent significant changes over the last twenty to thirty years. Especially after the
crash of world oil prices in 1986, cost-cutting measures such as switching to self-service from full-service
have become even more popular in the U.S. A general trend is for service station operators to diversify
their sources of revenue by offering other services such as convenience store shopping. Another strategy
that has become widespread is co-branding gasoline stations with big name fast food restaurants.
In Europe, the level of competition has been lower because of the extent of government intervention in
product pricing through high taxes and price controls. This situation not only creates higher profit
margins, but also lowers working capital needs as marketers are allowed to delay their tax payments for
up to 45 days. Nevertheless, downstream operations are still fiercely competitive. Actually, the tightness
of margins in marketing has forced two of the largest oil companies, Mobil and BP to merge their refining
and marketing operations in Europe in the late 1990s. This merger, which was initially fueled by
competition from supermarket chains offering gasoline to their customers, is considered the first example
of a general trend in the industry, which needs to find a way to deal with low profit margins and
overcapacity. Star (a joint venture between Kuwait and Texaco) and Shell proceeded with a similar
merger in the U.S., and Texaco and Shell pursued a union of their downstream operations. Other big
companies and independent refiners and marketers are expected to follow this trend. Shell-Texaco
alliance drew considerable criticism from independent marketers that sold about 50% of gasoline in the
U.S., but were concerned that such mergers would lower their share in the future. Both Shell and Texaco
had large marketing share as well as brand recognition. Antitrust regulators scrutinized these and other
mergers that followed (in particular those involving major brand names: BP-Amoco-Arco, Exxon-Mobil,
Chevron-Texaco, and Conoco-Phillips) and required necessary divestitures to prevent any one company
acquiring a dominant position in any regional market.
Nevertheless, these mergers further challenge the ability of independent marketers to access and to choose
among suppliers. Smaller marketers may not be able to meet minimum volume requirements or comply
with franchise agreements. Moreover, the competition in marketing is expected to increase further as
supermarkets and mega stores such as Walmart, Costco and Sam’s Club in the U.S. enter the gasoline
marketing business as similar entities did in Europe. The biggest threat to independent marketers is the
fact that these supermarkets consider gasoline sales as a way of attracting customers to their stores (a
form of advertisement), and therefore can afford offering lower prices. Another challenge facing smaller
independents is the compliance with environmental regulations, such as upgrading underground storage
tanks, which increases operating costs of marketers.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
13 - 8
Economics of the Energy Industries
As a result of these developments, a smaller number of independent marketers are expected to survive in
the future, and those that remain are expected to be larger than the average marketer today because of
mergers and acquisitions. However, competition will probably be as fierce as it is today, forcing
marketers to look for ways to diversify their revenue sources. This analysis is not unique to the U.S. and
Western Europe where product markets are developed. Companies are facing same kind of competition
in emerging markets. One of the innovative approaches to differentiate itself from competitors is
originated by Agip SPA of Italy in Russia, where the company started to use a mobile gasoline station for
delivering fuel to remote areas.
The Case of Gasoline in the U.S.
Gasoline, one of the main products refined from crude oil, accounts for about 16 percent of the energy
consumed in the U.S. While gasoline is produced year-round, extra volumes are made in time for the
summer driving season. Gasoline is delivered from oil refineries mainly through pipelines to a massive
distribution chain. There are three main grades of gasoline: regular, mid-grade, and premium. Each grade
has a different octane level. Price levels vary by grade, but the price differential between grades is
generally constant.
The cost to produce and deliver gasoline to consumers includes the cost of crude oil to refiners, refinery
processing costs, marketing and distribution costs, and finally the retail station costs and taxes. The prices
paid by consumers at the pump reflect these costs, as well as the profits (and sometimes losses) of
refiners, marketers, distributors, and retail station owners.
Federal, State, and local taxes are a large
component of the retail price of
gasoline. Taxes (not including county
and
local
taxes)
account
for
approximately 31% of the cost of a
gallon of gasoline. Within this national
average, Federal excise taxes are 18.4
cents per gallon and State excise taxes
average about 20 cents per gallon. Also,
eleven States levy additional State sales
and other taxes, some of which are
applied to the Federal and State excise
taxes. Additional local county and city
taxes can have a significant impact on
the price of gasoline.
Refining costs and profits comprise
about 13% of the retail price of gasoline. This component varies from region to region due to the different
formulations required in different parts of the country.
Distribution, marketing and retail dealer costs and profits combined make up 13% of the cost of a gallon
of gasoline. From the refinery, most gasoline is shipped first by pipeline to terminals near consuming
areas, and then loaded into trucks for delivery to individual stations. Some retail outlets are owned and
operated by refiners, while others are independent businesses that purchase gasoline for resale to the
public. The price on the pump reflects both the retailer's purchase cost for the product and the other costs
of operating the service station. It also reflects local market conditions and factors, such as the desirability
of the location and the marketing strategy of the owner.
Even when crude oil prices are stable, gasoline prices normally fluctuate due to factors such as
seasonality and local retail station competition. Additionally, gasoline prices can change rapidly due to
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
13 – 9
Economics of the Energy Industries
crude oil supply disruptions stemming from world events, or domestic problems such as refinery or
pipeline outages.
The main underlying challenge facing the U.S. gasoline market is the persistent lack of sufficient gasoline
producing capacity. This is the result of the decline in the number of U.S. refineries in the last two
decades. U.S. refining capacity, as measured by daily processing capacity of crude oil distillation units
alone, has appeared relatively stable in recent years, at about 16 million b/d of operable capacity. The
first refineries that were shut down as demand fell in the early 1980's were those that had little
downstream processing capability. Existing refineries have expanded, with particular emphasis on
upgrading capacity. But there is a limit to refinery extensions. As a result, U.S. refineries have not been
able to produce sufficient gasoline to totally meet domestic needs.
A Model for Marketing Investment
A simple model is presented at the end of the chapter. As one can see from the first column, an initial
investment of $250,000 is sufficient for a gasoline station with a maximum sales volume of 500,000
gallons a year. We assume a profit margin of 10 cents per gallon (with the price of gasoline $1.00 a
gallon and O&M cost 90 cents a gallon). We also assume that the land the station is built on appreciates
by 2% a year. This is important, because the value of the land will be salvaged when sold at the end of
the economic life of the station, and added to the cash flow, which is calculated as follows.
Cash Flow = After-tax Income - Initial Investment + Depreciation - Working Capital
= (1-Tax rate)[(Price-O&M)Volume - Depreciation] - Initial Investment +
Depreciation - Working Capital
For the last year we need to add the value of the land and total working capital assumed to be liquidated
and returned to the company as cash at the end of project's life (20 years). When we use the values
described above the NPV of after-tax
cash flows over twenty years equals
250
Cash Flows
$53,160 with an IRR of 13%.
200
Our
example
represents
quite
effectively
the
tightness
of
margins
and
150
sensitivity of revenues to fluctuations
100
in profit margins. Consider a one-cent
50
increase in O&M costs from 90 cents
per gallon to 91 cents per gallon. As a
0
result, NPV falls almost 45% to
0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20
-50
$30,110. The project IRR remains
fairly constant at 12%. A decrease in
-100
sales volume from 500,000 gallons a
-150
Station
Foodmart
year to 450,000 gallons a year has a
-200
similar impact: the NPV falls to
$31,150, and the IRR declines to 12%.
-250
Decreasing sales volume is a natural
outcome of increased competition by new gasoline stations being opened across the street. If we consider
the combined impact of higher O&M costs and lower sales volume, the project yields an IRR of 11% and
a NPV of $10,410. Obviously, any further decline in sales volume and/or increase in O&M costs will
render the project less attractive.
When we evaluate cash flows to be generated by adding a convenience store to the station, we obtain the
model presented in the second table below. We assumed that the foodmart is able to sell 80-cent worth of
goods for each gallon of gasoline sold. All other variables have the same value as in the original model.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
13 - 10
Economics of the Energy Industries
Addition of foodmart increases the NPV value of the station to $237,520 from $53,160. The new IRR is
a much more respectable 23% as opposed to 13% the original gasoline station project provided. This
simple example supports our discussion about how competitive the marketing business is and the
importance of adding value to the station’s operations by providing additional services.
If we repeat our scenario analysis for the gasoline station with foodmart, we obtain following results. A
one-cent increase in O&M costs does not affect the returns to project significantly as the IRR falls slightly
to 21% and the NPV remains fairly high at $214,480. Lower sales volume (450,000 gallons instead of
500,000) has a more significant impact: the project NPV is down to $197,070 and the IRR is now 20%.
Taken together, higher costs and lower sales lower the IRR to 19% and the NPV to $176,330.
Nevertheless, the gasoline station with a foodmart is a better project than a conventional gasoline station.
Clearly foodmart generates significantly larger cash inflows throughout the 20-year life of the gasoline
station, and accordingly raises the viability of the project.
Relevant Case Studies:
Brazil’s Restructuring of the Oil & Gas Industry
Deer Park Refinery
LPG Subsidies in India
Refining Sector in Kazakhstan
Small Refiner Bias
Soviet Legacy on Russian Petroleum Industry
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
13 – 11
Economics of the Energy Industries
A Model for Gasoline Station
Value of land=
Max Sales Volume =
Price of gasoline =
Tax rate =
O&M costs =
Appreciation of land =
Depreciation rate =
Discount rate =
Working capital =
100
500
1
0.4
0.9
0.02
0.1
0.1
1.1
Year
0
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
$1,000
$1,000
$1,000 1000 gal.
$1,000
$1,000
$1,000
$1,000
$1,000
$1,000
$1,000
Investment Depreciation Working Cap. Sales
Revenue O&M cost Net Revenue Taxable Inc. Tax
After-tax Inc. Cash flow
250.00
15.00
4.52
150.00
150.00
135.00
15.00
0.00
0.00
0.00 -239.52
0.00
13.50
4.52
300.00
300.00
270.00
30.00
16.50
6.60
9.90
18.88
0.00
12.15
6.03
500.00
500.00
450.00
50.00
37.85
15.14
22.71
28.83
0.00
10.94
0.00
500.00
500.00
450.00
50.00
39.07
15.63
23.44
34.37
0.00
9.84
0.00
500.00
500.00
450.00
50.00
40.16
16.06
24.10
33.94
0.00
8.86
0.00
500.00
500.00
450.00
50.00
41.14
16.46
24.69
33.54
0.00
7.97
0.00
500.00
500.00
450.00
50.00
42.03
16.81
25.22
33.19
0.00
7.17
0.00
500.00
500.00
450.00
50.00
42.83
17.13
25.70
32.87
0.00
6.46
0.00
500.00
500.00
450.00
50.00
43.54
17.42
26.13
32.58
0.00
5.81
0.00
500.00
500.00
450.00
50.00
44.19
17.68
26.51
32.32
0.00
13.85
0.00
500.00
500.00
450.00
50.00
36.15
14.46
21.69
35.54
0.00
13.85
0.00
500.00
500.00
450.00
50.00
36.15
14.46
21.69
35.54
0.00
13.85
0.00
500.00
500.00
450.00
50.00
36.15
14.46
21.69
35.54
0.00
13.85
0.00
500.00
500.00
450.00
50.00
36.15
14.46
21.69
35.54
0.00
13.85
0.00
500.00
500.00
450.00
50.00
36.15
14.46
21.69
35.54
0.00
13.85
0.00
500.00
500.00
450.00
50.00
36.15
14.46
21.69
35.54
0.00
13.85
0.00
500.00
500.00
450.00
50.00
36.15
14.46
21.69
35.54
0.00
13.85
0.00
500.00
500.00
450.00
50.00
36.15
14.46
21.69
35.54
0.00
13.85
0.00
500.00
500.00
450.00
50.00
36.15
14.46
21.69
35.54
0.00
13.85
0.00
500.00
500.00
450.00
50.00
36.15
14.46
21.69
35.54
0.00
13.85
0.00
500.00
500.00
450.00
50.00
36.15
14.46
21.69
202.17
250.00
NPV=
$ 53.16
IRR=
13%
A Model for Gasoline Station with Foodmart
Gasoline Sales Max =
Price of gasoline =
Foodmart margin=
Foodmart sales=
Tax rate =
O&M costs =
Appreciation of land =
Depreciation rate =
Discount rate =
Working capital =
Year
0
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
500
1
0.1
0.8 we assume that for every gallon of gasoline sold, the foodmart sells 80-cent worth of goods
0.4
0.9
0.02
0.1
0.1
1.1
$1,000
$1,000
$1,000
$1,000
Investment Depreciation Land apprec. Working Cap.
250.00
15.00
102.00
4.52
0.00
13.50
104.04
4.52
0.00
12.15
106.12
6.03
0.00
10.94
108.24
0.00
0.00
9.84
110.41
0.00
0.00
8.86
112.62
0.00
0.00
7.97
114.87
0.00
0.00
7.17
117.17
0.00
0.00
6.46
119.51
0.00
0.00
5.81
121.90
0.00
0.00
13.85
124.34
0.00
0.00
13.85
126.82
0.00
0.00
13.85
129.36
0.00
0.00
13.85
131.95
0.00
0.00
13.85
134.59
0.00
0.00
13.85
137.28
0.00
0.00
13.85
140.02
0.00
0.00
13.85
142.82
0.00
0.00
13.85
145.68
0.00
0.00
13.85
148.59
0.00
0.00
13.85
151.57
0.00
250.00
1000 gal.
$1,000
$1,000
Sales
Gasoline Rev. Foodmart Rev.
150.00
150.00
12.00
300.00
300.00
24.00
500.00
500.00
40.00
500.00
500.00
40.00
500.00
500.00
40.00
500.00
500.00
40.00
500.00
500.00
40.00
500.00
500.00
40.00
500.00
500.00
40.00
500.00
500.00
40.00
500.00
500.00
40.00
500.00
500.00
40.00
500.00
500.00
40.00
500.00
500.00
40.00
500.00
500.00
40.00
500.00
500.00
40.00
500.00
500.00
40.00
500.00
500.00
40.00
500.00
500.00
40.00
500.00
500.00
40.00
500.00
500.00
40.00
$1,000
$1,000
$1,000
O&M cost Net Revenue Taxable Inc.
135.00
27.00
12.00
270.00
54.00
40.50
450.00
90.00
77.85
450.00
90.00
79.07
450.00
90.00
80.16
450.00
90.00
81.14
450.00
90.00
82.03
450.00
90.00
82.83
450.00
90.00
83.54
450.00
90.00
84.19
450.00
90.00
76.15
450.00
90.00
76.15
450.00
90.00
76.15
450.00
90.00
76.15
450.00
90.00
76.15
450.00
90.00
76.15
450.00
90.00
76.15
450.00
90.00
76.15
450.00
90.00
76.15
450.00
90.00
76.15
450.00
90.00
76.15
$1,000
$1,000
Tax
After-tax Inc.
4.80
7.20
16.20
24.30
31.14
46.71
31.63
47.44
32.06
48.10
32.46
48.69
32.81
49.22
33.13
49.70
33.42
50.13
33.68
50.51
30.46
45.69
30.46
45.69
30.46
45.69
30.46
45.69
30.46
45.69
30.46
45.69
30.46
45.69
30.46
45.69
30.46
45.69
30.46
45.69
30.46
45.69
NPV=
IRR=
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
13 - 12
Economics of the Energy Industries
CHAPTER 14 – POWER PLANT INVESTMENT
Introduction
The EIA projects the worldwide electricity consumption to increase at an average annual rate of 2.7%
from 1999 to 2020. The most rapid growth in electricity use is projected for the developing world,
particularly developing Asia, where electricity consumption is expected to increase by 4.5% per year.
Similarly, the expected growth rate for electricity use in Central and South America is 3.9% per year.
Electricity consumption in the industrialized world is expected to grow at a more modest pace than in the
developing world, at 1.9% per year.
Coal is projected to continue to retain the largest market share of electricity generation, but its importance
is expected to be diminished somewhat by the rise in natural gas use. The role of nuclear power in the
world’s electricity markets is projected to lessen as reactors in industrialized nations reach the end of their
lifespans and few new reactors are expected to replace them. Generation from hydropower and other
renewable energy sources is projected to grow by more than 50%, but their share of total electricity
generation is projected to remain near the current level of 20 percent. Electricity markets of the future are
expected to rely increasingly on natural-gas-fired generation. This trend is evident throughout the world,
as industrialized nations are intent on using combined-cycle gas turbines, which generally are cheaper to
construct and more efficient to operate than other fossil-fuel-fired generation technologies. Natural gas is
also seen as a cleaner fuel than other fossil fuels. Worldwide, natural gas use for electricity generation is
projected to double by 2020, as technologies for gas-fired generation continue to improve and ample gas
reserves are exploited.
To meet the increasing demand, the industry will have to invest billions of dollars. There have been two
important developments in the electricity sector in recent years that may affect the way the industry meets
these investment requirements, both from financial and technological perspectives (which may also affect
the fuel portfolio projections provided above).
The first is electricity industry restructuring. Many countries have implemented reforms to unbundle
generation, transmission and distribution (T&D), and marketing functions of vertically integrated electric
utilities. Then they provided open access to T&D (which remained a natural monopoly) to allow for
competition to flourish in the generation and marketing (both wholesale and retail) ends of the industry.
A second important development, which mainly resulted from the first, is the increasing role of foreign
direct investment in the developing regions of the world. Greater access to foreign investment in the
electricity sector has allowed developing nations to construct the infrastructure needed for substantial
increases in access to electricity, a particular problem for many developing nations.
Power Plant Economics
Key Considerations
Investment in plants is a complex decision process that is governed by many variables which are not
mutually exclusive and several decision iterations are needed to reach an economically and
environmentally viable investment decision. Failing to accurately quantify each of these variables may
result in adverse effects on the overall outcome of the project. Therefore, it is imperative to identify each
of the variables, how they interact with each other and how they can be integrated to produce a profitable
project that provides investors with the right risk-return ratio.
Fuel prices, expected load curve, the level of competition (laws & regulations), construction and
operational (especially fuel) costs, environmental regulations, economical conditions and, in many parts
of the world, political conditions are some of the variables that need to be estimated. They may all have
significant impact on project NPV and IRR.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
14 – 1
Economics of the Energy Industries
Electricity industry restructuring has created new opportunities for merchant power plant construction.
Independent power producers (IPPs) have invested billions of dollars all around the world (see Chapter 1
for an overview) replacing traditional integrated utilities. At the same time, higher competition causes
new challenges for profitable investment. A better understanding of the present and future load curves, a
thorough knowledge of political, economical and environmental factors, and, perhaps most importantly,
the ability to keep up with and commercialize technological advances appear to be key requirements for
success in this new environment.
In a regulated market, selectivity and optionality concepts in power generation projects are not applied. In
the regulated environment or in places where state monopolies dominated, large scale investments on
hydro, coal and/or nuclear facilities were preferred and sometimes easily financed either through
regulated rates or through state funds. In the competitive environment, however, power plants need to be
evaluated based on traditional project finance methods.
As discussed in Chapter 1, the technological developments in gas turbines allowed gas-fired power plants
to become the choice of investors. These plants can be built in relatively smaller sizes, which lowers the
cost and the construction time. One can also run these units only during peak hours as they are easy and
cheap to turn on and off unlike coal or nuclear plants that are better suited for base load. Accordingly,
optionality is very important for gas-fired plants.
Costs
Electricity demand fluctuates throughout the day as well as across seasons. Nevertheless, there is a
constant amount of load at all times to power commercial and industrial equipment as well as home
appliances that are always on. This is called the base load.
Then, throughout the day, the load fluctuates depending on the need for lighting, heating, cooling and so
on. Typically, during winter, there will be an increase in load in the morning when people get up and turn
the lights and the heat on to get ready for work and/or school. There will be another increase in the early
evening hours when people return home, cook, dine, watch TV, and so on. The further north it is and the
greater the percentage of electric heating, the larger the increase will be. These increases are known as
peak load, or peak demand. In summer, peaks will coincide with afternoons and early evenings when the
need for air conditioning would be largest.
These variations in the daily load curve are crucial for running power plants. Some power plants are
better suited for meeting the base load and others are very efficient as peaking units, i.e., plants to be run
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
14 - 2
Economics of the Energy Industries
when the load peaks. In general, high capital cost plants such as coal and nuclear-fired facilities are built
in larger sizes and cannot be turned on and off easily, or economically. So, they are ideal for running all
the time to meet the base load.
On the other hand, cheaper, more modular gas-fired units that can be built faster and at lower cost, and,
more importantly, can be turned on and off within 15 minutes notice, are well suited for meeting the peak
demand.
In restructured markets, where the price of electricity is allowed to fluctuate along with the load curve,
peaking plants offer opportunities for IPPs as well as marketers. Accordingly, gas-fired facilities are
more in demand in these markets than traditional base load plants.
Nevertheless, as population and/or economy grow in any region, the base load as well as the peak load
will increase (despite our best efforts to conserve). There will hence be a need for all kinds of generation
facilities (unless scenarios about distributed generation, grid-independent generation and alternative
technologies become a reality much sooner than many think). It is therefore useful to consider the costs
of generation technologies.
The capital costs associated with building generation capacity for a wide range of technologies from
conventional thermal to alternative technologies such as wind, solar and biomass can be seen in the chart
below. Clearly, the alternative technologies, except for wind, are significantly more expensive than
conventional technologies. For example, MSW costs more than ten times per kW as conventional
combined-cycle, and more than three times as nuclear capacity, which is among the costliest of traditional
technologies.
Capital Costs ($1996 per kW)
6,000
5,289
Source: Kyoto Report - 1998 Energy Information Administration (EIA)
5,000
4,000
3,185
3,000
2,025 1,910
2,000
1,550 1,476 1,440
1,206 1,079
1,000
991
965
440
400
325
320
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Lowest capital costs are associated with advanced combustion turbine technology (gas-fired) at $320 per
kW, followed by other gas-fired technologies such as advanced combined-cycle, conventional combinedcycle and conventional combustion turbine. Note that all of these cost less than half of next cheapest
technologies, which are wind and oil/gas steam. Coal-fired plants, though not as expensive as nuclear
plants, cost up to four times as much per kW as most gas-fired plants.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
14 – 3
Economics of the Energy Industries
Fixed and Variable O&M Costs
120
5.4
Variable Cost
5.2
5
Fixed Cost
5
5
100
4
80
3.25
3
60
2
1.87
2
1
2
40
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0.5
0.4
0
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Fixed O&M (1996 Dollars per kW)
Variable O&M (1996 Mills per kWh)
6
In addition to capital costs, investors need to consider operation and maintenance (O&M) costs as well
(see chart above). Unlike the capital costs, conventional technologies have much larger variable O&M
costs than the alternative technologies (for more on these comparisons, see Chapter 16).
Although two alternative technologies, biomass and MSW, have the highest variable O&M costs with 5.2
and 5.4 mills per kWh respectively, combustion turbine technologies also have a variable cost of 5 mills
per kWh (note that $1=1,000 mills). Note, however, that these variable costs can fluctuate with the cost
of fuel, which is a more significant problem with natural gas than it is with coal, uranium, biomass, or
MSW. The U.S. natural gas price spikes during the winter of 2000-01, which were almost immediately
reflected in power prices, demonstrated this vulnerability of dependence on gas-fired peaking units.
In terms of fixed O&M, geothermal, nuclear, solar thermal, biomass and oil/gas steam rank high with
more than $30 per kW (as high as $100 per kW for geothermal). Other than nuclear ($55 per kW), most
other conventional technologies have fixed O&M costs less than $25 per kW, and less than $15 for gasfired facilities.
In addition to cost and capacity considerations, using the most efficient equipment is important.
Efficiency is measured by the heat rate, which is the ratio of amount of heat energy (measured in Btu’s) in
fuel used to generate one kWh of electricity. Clearly, the lower the heat rate, the more efficient is the
plant as this means less fuel is needed to generate power and hence costs less. The advanced combinedcycle gas-fired power plant is the most efficient type while the conventional combustion turbine is the
least efficient among the conventional technologies. As we will see later in this Chapter, heat rate (and
the associated concept of spark spread) is a very crucial concept in competitive electricity markets.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
14 - 4
Economics of the Energy Industries
Heat Rate
35,000
32,391
Source: Kyoto Report - 1998 Energy Information Administration (EIA)
30,000
(Btu per kWh)
25,000
20,000
16,000
15,000
10,000
11,900
10,400 9,700 9,585
9,500 8,911
8,470 8,030
6,985
6,000
5,000
So
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Although the costs of alternative technologies have fallen (see Chapter 16), they still are not widely
competitive with fossil fuel technologies. As a result, the most economical options available to electricity
suppliers for meeting the demand for electricity over the next 20 years are existing coal plants and new
natural gas plants.
In 1995, the average operating cost of coal-fired power plants was 1.8 ¢ per kWh. Only 66% of their
maximum potential output was needed to meet the 1996 level of demand. Over the next 20 years, as the
demand for electricity grows, the utilization of coal-fired plants is expected to approach 80%. For new
capacity additions, the low capital costs and high operating efficiencies of natural-gas-fired combinedcycle plants make them the most economical choice for most uses.
A factor that may change the role of coal in the future and enhance the increasing share of gas-fired
power is the debate about emissions and, in particular, CO2, which is generally accepted to be the main
culprit for global warming. Electricity suppliers have a variety of options available for reducing their
carbon emissions. The degree to which each of the options is employed will depend on the level of
reduction required and the time frame for this reduction to be achieved (i.e., regulations). If a carbon tax
strategy and strict time table is pursued by the international agreements and/or local governments, coalfired generation may suffer.
On the other hand, a market-based solution such as emissions trading, which has been successfully used
in the U.S. to reduce SO2 emissions, can buy some time for these plants. In either case, gas-fired
generation will likely benefit from environmental regulations as it emits less carbon than coal and other
fossil fuels.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
14 – 5
Economics of the Energy Industries
Carbon Emissions
6 00
5 19
5 00
(Pounds per MWh)
417
4 00
330
29 6
3 00
2 50
249
19 8
2 00
1 67
1 00
0
0
0
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0
Merchant Power Plants
Electricity restructuring has done more than just bring competition to the U.S. retail electricity markets. It
has also made wholesale power prices more volatile. That volatility is most evident when there are shortterm dislocations of supply. The resulting price spikes lead to substantial "risk premiums" in forward
power markets.
In the past, traditional utilities typically considered their power plants mere collections of brick and
mortar. But today, a merchant plant operator increasingly views his facility as a stack of conversion
options or options on the available spark spread. But whether the merchant plant operator is a utility or an
IPP, competition requires that it makes every possible effort to extract maximum value from the
generation portfolio, and that means using sophisticated tools to manage market risk.
These risk-management tools are designed to cope with the uncertainties of the new business model that
deregulation has ushered in - the Forward Risk Premiums model. As was the case under the old Economic
Dispatch model, some portion of forward power prices is still determined by marginal generation
economics. Now, however, whenever one or more links in the electricity delivery chain are stressed, the
market adds a risk premium to power prices to reflect the uncertainties of forward delivery. Exploiting the
existence of that risk premium is the objective of a new concept for managing merchant plant operations
called Total Btu Management.
The Components of Generation Value
The base values that accrue to electricity generation and the effect that these value components have on
wholesale power prices are a subject that requires a modified mind set to understand. In the traditional
paradigm, where generation and transmission were merely guarantors of reliable service, these value
components were largely ignored or not understood at all. In the competitive marketplace, electricity
generation has three main components of value: commodity, optionality, and deliverability.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
14 - 6
Economics of the Energy Industries
Components of Electricity Generation Value
Commodity
Conversion of fuel to electricity
Principal value in regulated
environment
Optionality
Electricity values vary by time
and duration of delivery
Operating characteristics: ramp
rates, turndown capability, fuel
switching, peaking
Deliverability
Greater value by packaging,
time, flexibility
Major feature in deregulated
markets
Not important in regulated
environments as market is known
Generally speaking, the commodity aspect is the only value that is attached to generation in a regulated
environment. The commodity component refers to the ability of a power plant to convert one form of
energy - be it fossil or nuclear fuel, wind, water, or sunlight - to another: electricity. The value of this
conversion capability is embedded in the economics.
With the introduction of competition, the optionality that accrues to a form of electricity generation has
become a significant value component. The economies of scale that were the rage in the 1970s and early
1980s have yielded the premium value perched to the generating capacity that has the most opportunity to
run at peak periods, and not run at periods of low demand. Rapid ramp rates, complete turndown
capability, storage capacity, and other forms of enhanced optionality add tremendous value to the
generation proposition.
The third component – deliverability - is in some ways another form of optionality. The value of the
deliverability of power depends on its ability to be packaged in intermittent delivery blocks and for very
short periods of time. The other aspect of deliverability is its flexibility in reaching multiple transmission
points and multiple markets with equal ease. Plants with easy access to multiple markets are more
valuable because they are capable of delivering their output to premium markets on short notice as market
conditions change.
The price of natural gas fuel is likely to be the most volatile number--next to power prices - to which a
merchant generator will be exposed. Therefore, it is critical that IPPs keep close tabs on the prevailing
market price of gas, in addition to performing rigorous fundamental supply/ demand balance analyses for
informing their fuel-purchase decisions. The level of analytical sophistication and trading acumen should
be a function of the company's desired trading activity levels.
Gas and Power Prices and Optionality
In the U.S. there are several price indexes for both electricity and natural gas; Henry Hub (HH) natural
gas and Palo Verde (PV) electricity futures (the latter does not trade any longer) are used here to illustrate
the relationship between gas and electricity prices (see chart below). Due to electricity market
restructuring, electricity prices are becoming more sensitive to the short-term spot price changes in
natural gas and the volatility associated with it. Clearly, electricity and gas prices are positively
correlated (correlation coefficient is 0.70).
However, due to natural gas storage and hedging effects, this correlation is delayed. These effects
prevented an instantaneous increase in the electricity price when natural gas price climbed to a maximum
of $8.65/Mcf in December 2000. However, an increase in the price of natural gas stored today may affect
the price of electricity that uses this stored natural gas capacity several months down the road. Electricity
prices in May 2001 spiked to a maximum of $340.29/MWh. Increase in electricity demand due to
weather conditions, shortages in natural gas supply and transmission congestions are also major
contributors to this electricity price spike.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
14 – 7
Economics of the Energy Industries
Natural Gas and Electric Power Prices
400
10
Source : New York Mercentile Exchange (NYMEX)
9
350
8
300
7
6
200
5
Henry Hub Natural Gas Price ($/Mcf)
($/Mcf)
($/MWh)
250
4
150
3
100
2
50
Palo Verde Electricity Price ($/MWh)
0
Apr-96
1
0
Apr-97
Apr-98
Apr-99
Apr-00
Apr-01
Gas-fired generation falls into one of three broad categories: (1) existing, mid-merit, simple-cycle
generation; (2) high-efficiency combined-cycle; and (3) peaking plants. Plant characteristics - such as heat
rate curves, ramp rates, turndown maximums, startup costs, location, and market load shape - must be
considered here. In many cases, existing, long-dated transactions must also be taken into account.
Decisions about long-term indexed transactions or short-term spot activity should be largely influenced
by the financial requirements of earnings levels and variability control. In many cases, financing
arrangements require that some portion of a facility be committed to long-term agreements. Upon
determining the mix of transaction terms that is appropriate, the facility marketing plan must take into
account trade construction.
Virtually all gas-fired plants have some level of load-following optionality that is accompanied by
substantial short-term price premiums. The IPP must accurately quantify the options value and be
compensated for it accordingly. This can be done either by entering into contracts with sizable options
premiums embedded in the price formula or by keeping a portion of the unit's output uncommitted and
then selling it hourly as market prices dictate. Where a portfolio of different generation types is involved,
a total portfolio approach is adopted to take advantage of the combined flexibility of the generation fleet.
Within this element, decisions to run or not run a plant are made. When natural gas prices are extremely
volatile, very often shutting down a facility and selling its fuel into the market makes better economic
sense than keeping the plant running. During the spring and fall, when generating plant economics are
marginal, intermittent operation of facilities based upon daily swings in profitability are most crucial. In
addition, basis and pipeline economics of natural gas delivery may dictate operating a less efficient
facility to exploit fuel economics on the front end of generation. For example, an older, less efficient
facility that is located near a liquidity hub might be substituted for a more efficient plant located up the
distribution chain to resell the transportation for a profit.
Example on Optionality
The following example illustrates the economics of natural gas-fired power plants and how a decision is
reached to operate (or not) each power plant based on calculating the spark spread for each plant in each
period and based on comparing the market heat rate to that of each power plant. In addition to the data
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
14 - 8
Economics of the Energy Industries
listed in table below, PV and HH prices charted above as well as futures contract prices for five electricity
contracts and HH futures contracts from October 2001 for months covering the range from November
2001 to October 2002 are used.
Sample Power Plants as Peaking Units
Conventional Combined-Cycle
Advanced Combined-Cycle
Conventional Combustion Turbine
Advanced Combustion Turbine
Size
(MW)
250
400
160
120
Variable O&M
(Mills per kWh)
2.0
2.0
5.0
5.0
Monthly
Fixed O&M
($ per kW)
1.25
1.15
0.33
0.48
Heat Rate
(Btu per kWh)
7,000
6,350
10,600
8,000
From the data, the spark spread is calculated for each plant to determine the operational periods. Then
based on the future contract prices the market heat rate is calculated for all months to determine what
markets appear to be most attractive in the future for each of the plants.
Spark spread for each plant in each period is calculated using the following equation:
Spark Spread ($/MWh) = Power Price – [Plant Heat Rate x Gas Price] – O&M Cost
Algebraically, the spark spread increases as power price increases and/or the heat rate decreases or gas
price or the O&M cost decrease. Clearly, the main drivers are the prices of power and natural gas. The
higher the price of power (such as during peak periods), the more likely it is for a given plant to run
unless the natural gas price is also high in proportion to the power price.
Any of the power plants will operate only if the spark spread is greater than zero and should not run when
the spark spread is negative. The calculated spark spreads for each power plant for the period between
April 1996 and October 2001 are provided below. Note that there are many months during the 1996-99
period where the spark spread has been negative for most of the plants, especially conventional
combustion turbine plant (Plant 3), which is the least efficient plant (highest heat rate).
There are many months where Plant 3 has been the only plant with a negative spark spread (e.g., July
1996, September 1998-May 1999, etc.). Since May 2000, the beginning of California crisis, all plants
have become profitable to run. Note, however, that we used monthly average prices; in any given day,
prices (in particular, power prices) will fluctuate and the spark spread can become negative certain times
of any given day for any of these plants.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
14 – 9
Economics of the Energy Industries
Spark Spreads
Spark Spread for the Plants ($/MWh)
Month
Plant 1
Plant 2
Plant 3
Spark Spread for the Plants ($/MWh)
Plant 4
Month
Plant 1
Plant 2
Plant 3
Plant 4
Apr-96
-9.434
-7.657
-18.180
-12.601
Feb-99
3.153
4.576
-3.631
0.531
May-96
-7.793
-6.035
-16.440
-10.933
Mar-99
3.109
4.558
-3.819
0.447
Jun-96
-3.610
-1.678
-13.215
-7.016
Apr-99
3.973
5.656
-4.254
0.950
Jul-96
3.593
5.510
-5.931
0.210
May-99
6.794
8.541
-1.784
3.674
18.378
Aug-96
1.423
3.033
-6.401
-1.488
Jun-99
21.568
23.359
12.740
Sep-96
-2.661
-1.126
-10.064
-5.455
Jul-99
32.418
34.195
23.668
29.250
Oct-96
-4.420
-2.530
-13.797
-7.763
Aug-99
14.094
16.193
3.562
10.431
Nov-96
-2.439
-0.196
-13.768
-6.324
Sep-99
7.867
9.859
-2.069
4.369
Dec-96
-18.557
-15.909
-32.127
-23.064
Oct-99
5.886
8.038
-4.939
2.142
2.261
Jan-97
-10.950
-8.679
-22.438
-14.879
Nov-99
5.672
7.607
-3.951
Feb-97
-6.541
-4.921
-14.422
-9.468
Dec-99
6.424
8.280
-2.762
3.135
Mar-97
-4.131
-2.619
-11.414
-6.892
Jan-00
6.123
7.952
-2.908
2.877
3.608
Apr-97
-2.778
-1.197
-10.444
-5.645
Feb-00
7.083
9.060
-2.773
May-97
3.852
5.601
-4.741
0.727
Mar-00
9.823
11.940
-0.803
6.134
Jun-97
9.767
11.450
1.538
6.744
Apr-00
9.250
11.496
-2.099
5.360
24.588
Jul-97
14.179
15.844
6.051
11.184
May-00
29.046
31.661
15.653
Aug-97
7.225
9.116
-2.152
3.883
Jun-00
83.190
86.265
67.253
78.025
Sep-97
2.811
4.956
-7.978
-0.924
Jul-00
131.407
134.267
116.663
126.574
Oct-97
-3.427
-1.041
-15.550
-7.532
Aug-00
104.563
107.740
88.059
99.241
Nov-97
-1.342
0.934
-12.855
-5.278
Sep-00
61.932
65.549
42.988
55.932
Dec-97
1.354
3.195
-7.753
-1.914
Oct-00
34.640
38.220
15.908
28.699
Jan-98
2.066
3.709
-5.943
-0.897
Nov-00
47.344
51.353
26.234
40.742
Feb-98
-1.212
0.537
-9.805
-4.336
Dec-00
75.720
81.621
44.131
66.207
Mar-98
0.879
2.617
-7.657
-2.230
Jan-01
132.835
138.199
104.217
124.148
Apr-98
2.424
4.307
-6.911
-0.907
Feb-01
184.139
188.128
163.137
177.567
May-98
8.588
10.270
0.367
5.567
Mar-01
239.019
242.687
219.799
232.942
Jun-98
16.809
18.496
8.557
13.779
Apr-01
283.804
287.461
264.645
277.744
Jul-98
32.607
34.281
24.430
29.598
May-01
305.162
308.191
289.479
300.068
Aug-98
21.735
23.219
14.610
19.018
Jun-01
132.134
134.874
118.051
127.484
Sep-98
6.955
8.556
-0.820
4.057
Jul-01
72.365
74.701
60.523
68.338
Oct-98
6.751
8.468
-1.664
3.676
Aug-01
38.288
40.538
26.920
34.393
Nov-98
6.732
8.517
-2.061
3.552
Sep-01
12.028
13.931
2.583
8.667
Dec-98
6.440
7.971
-0.945
3.651
Oct-01
13.528
15.756
2.283
9.667
Jan-99
5.671
7.138
-1.362
2.980
The following table compares the market heat rate to the heat rate of each of the power plant in each
period. The market heat rate is calculated as the ratio of the power price to the natural gas price. So, the
higher the power price is relative to the price of natural gas (which also means that the spark spread will
be larger), the higher the heat rate will be and the more likely it is for a plant to run. Note that the values
provided below are in Btu per MWh as compared to Btu per kWh values used to describe the plants
above.
Highlighted numbers are the periods in which the heat rate of the plant is less than the market heat rate.
Roughly speaking, a plant will be profitable if the market heat rate exceeds its own. Note, however, that
the decisions based on the market heat rate may yield different results (and may not be as accurate) than
the decisions based on the spark spread because it ignores the O&M cost for the plant.
For example, Plant 3 (the least efficient) should not have run between September 1998 and May 1999 as
shown with a negative spark spread above. However, based on the market heat rate, which ranged
between 11 and 14 Btu per MWh during that period, Plant 3’s heat rate of 10.6 indicates that the plant
could be run. Clearly, when the market heat rate and plant heat rate are this close, O&M costs require
closer inspection.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
14 - 10
Economics of the Energy Industries
Market Heat Rate
Market
Heat Rate
Plant 1
Plant 2
Plant 3
Market Heat
Rate
Plant 4
Month
Apr-96
May-96
Jun-96
Jul-96
Aug-96
Sep-96
Oct-96
Nov-96
Dec-96
Jan-97
Feb-97
Mar-97
Apr-97
May-97
Jun-97
Jul-97
Aug-97
Sep-97
Oct-97
Nov-97
Dec-97
Jan-98
Feb-98
Mar-98
Apr-98
May-98
Jun-98
Jul-98
Aug-98
Sep-98
Oct-98
Nov-98
Dec-98
Jan-99
Plant 1
Plant 2
Plant 3
Plant 4
Month
5.282
5.981
7.732
10.594
10.364
8.455
7.424
8.003
3.411
5.214
6.482
7.706
8.343
11.119
14.047
16.208
12.117
9.883
7.630
8.343
9.837
10.588
8.882
9.826
10.197
13.509
17.273
24.728
21.663
13.103
12.521
12.262
13.179
13.089
0
0
7
7
7
7
7
7
0
0
0
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
0
0
6.35
6.35
6.35
6.35
6.35
6.35
0
0
6.35
6.35
6.35
6.35
6.35
6.35
6.35
6.35
6.35
6.35
6.35
6.35
6.35
6.35
6.35
6.35
6.35
6.35
6.35
6.35
6.35
6.35
6.35
6.35
0
0
0
0
0
0
0
0
0
0
0
0
0
10.6
10.6
10.6
10.6
0
0
0
0
0
0
0
0
10.6
10.6
10.6
10.6
10.6
10.6
10.6
10.6
10.6
0
0
0
8
8
8
0
8
0
0
0
0
8
8
8
8
8
8
0
8
8
8
8
8
8
8
8
8
8
8
8
8
8
8
Feb-99
Mar-99
Apr-99
May-99
Jun-99
Jul-99
Aug-99
Sep-99
Oct-99
Nov-99
Dec-99
Jan-00
Feb-00
Mar-00
Apr-00
May-00
Jun-00
Jul-00
Aug-00
Sep-00
Oct-00
Nov-00
Dec-00
Jan-01
Feb-01
Mar-01
Apr-01
May-01
Jun-01
Jul-01
Aug-01
Sep-01
Oct-01
11.898
11.765
11.369
12.429
18.611
23.424
13.983
12.059
10.939
11.371
11.899
11.861
11.803
12.408
11.861
16.597
27.603
41.460
31.667
20.117
14.896
16.201
16.385
24.673
40.206
53.877
62.645
80.388
43.323
31.585
21.422
14.000
13.333
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
6.35
6.35
6.35
6.35
6.35
6.35
6.35
6.35
6.35
6.35
6.35
6.35
6.35
6.35
6.35
6.35
6.35
6.35
6.35
6.35
6.35
6.35
6.35
6.35
6.35
6.35
6.35
6.35
6.35
6.35
6.35
6.35
6.35
10.6
10.6
10.6
10.6
10.6
10.6
10.6
10.6
10.6
10.6
10.6
10.6
10.6
10.6
10.6
10.6
10.6
10.6
10.6
10.6
10.6
10.6
10.6
10.6
10.6
10.6
10.6
10.6
10.6
10.6
10.6
10.6
10.6
A similar analysis can be carried out looking into the future when reliable data on the forward price curve
can be obtained. Below, Entergy and Cinergy markets were not expected to have high power prices
relative to the price of natural gas and hence Plant 3 and 4 were not expected to run much except for
summer months. On the other California markets, COB and PV were projected to have high prices and
hence most plants were expected to run. Again, remember that the market heat rate ignores O&M costs
and that daily price fluctuations may also impact the decision of when to run a plant.
Market Heat Rate in the Future
M o n th
N o v -0
D e c -0
J a n -0
F e b -0
M a r-0
A p r-0
M a y -0
J u n -0
J u l- 0
A u g -0
S e p -0
O c t-0
1
1
2
2
2
2
2
2
2
2
2
2
C O
1
1
1
1
1
1
1
1
1
1
1
B
1 .3
3 .2
2 .7
1 .6
0 .4
0 .1
9 .7
0 .2
3 .5
5 .2
4 .6
1 .7
4
8
6
6
9
9
7
8
3
4
3
8
9
6
4
7
4
1
9
0
8
4
4
2
E n te rg y
8 .0 4
7 .9 2
7 .9 9
8 .0 1
7 .7 9
8 .0 4
8 .3 6
1 1 .1 5
1 3 .8 4
1 3 .7 2
7 .5 1
7 .8 5
3
5
1
5
3
1
0
3
6
0
5
5
C in e r g y
8 .5 0
8 .5 3
8 .9 4
8 .9 7
8 .5 4
8 .8 2
9 .3 8
1 2 .3 8
1 5 .6 1
1 5 .4 7
8 .4 6
8 .5 0
3
8
3
0
9
2
5
3
5
3
0
5
P JM
9
9
10
10
9
10
11
14
17
17
9
9
.4
.4
.6
.6
.7
.0
.2
.3
.7
.6
.5
.4
0
6
1
5
8
9
6
3
6
0
1
4
8
5
9
2
4
6
2
0
9
7
2
1
P a lo V e r d e
1 0 .6 0 9
1 1 .3 2 1
1 1 .0 2 7
1 0 .4 5 5
1 0 .4 9 4
1 0 .6 6 9
1 1 .8 3 0
1 4 .0 1 9
1 6 .3 0 8
1 8 .9 0 2
1 5 .5 4 9
1 1 .7 8 2
P la n t 1 , 2 , 3 & 4
P la n t 1 , 2 & 4
P la n t 1 & 2
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
14 – 11
8
8
8
8
8
8
8
8
8
8
8
8
8
8
8
8
8
8
8
8
8
8
8
8
8
8
8
8
8
8
8
8
8
Economics of the Energy Industries
A Model of Power Plant Investment
In this section, we present a typical, albeit simplified, DCF analysis for building a gas-fired power plant.
The model is based on project financing. Capital cost, fixed and variable O&M costs as well as efficiency
ratio (which is related to the heat rate concept discussed earlier) are key variables. Load factor (LF)
shows what percentage of the capacity the plant will be able to generate during any period of time. This
may be a function of the spark spread and/or market heat rate analysis we carried out above, but it is also
a function of technical requirements of the equipment. In general, a power plant with nameplate capacity
of 400 MW will not be able to generate 400x24x365 MWh of electricity in a year. Finally, as we have
seen with the spark spread analysis, gas and power prices are most important to decide whether the plant
is economical or not.
The annual cash flow is calculated as follows:
Cash Flow = (1 – Tax Rate) x (Revenue – Depreciation – Opex – Gas Cost – Interest) + Depreciation –
Investor’s share of Capex – Principle
Where
Revenue = Generation x Power Price
Generation = Capacity x 24 x 365 x LF
Opex = Fixed O&M x Capacity + Variable O&M x Generation
Gas Consumption = (Generation x 3,412)/Efficiency
Gas Cost = Gas Consumption x Gas Price
There are 3,412 Btus in a kWh and efficiency measures how many MMBtus of gas the plant needs to
generate one kWh of electricity. Efficiency is related to the concept of heat rate. For example, a plant
with 7,000 Btu/kWh heat rate (e.g., a combined cycle gas turbine plant) would have 3,412/7,000 = 48.7%
efficiency. The following table provides assumptions for a CCGT plant (note that by changing the value
of cost variables, efficiency, load factor and fuel costs, almost any type of plant can be analyzed with this
model).
The loan structure includes financing terms including an interest payment during the construction period
as well as an upfront fee typical of these kinds of projects. Most infrastructure projects tend to cost more
than originally estimated and may also take longer to complete and operate. This is especially true for
developing countries where lack of skilled labor, international trade constraints, sub-par conditions of
existing infrastructure such as roads as well as bureaucratic changes are likely to introduce unforeseen
cost surges. Accordingly, we also allow for contingencies for both capital and O&M costs.
Combined Cycle Gas Turbine Economics
Capital Cost ($/kW)
Cost of the Plant ($MM)
Equity (%)
450
216
40%
Capacity (MW)
Efficiency
Load Factor
400
49%
65%
Fixed O&M ($/kW)
Variable O&M ($/kWh)
Discount Rate
Tax Rate
15
0.002
10%
35%
Fuel Cost ($/MMBtu)
Power Price ($/KWh)
Add. Capital Contingency
Add. O&M Contingency
2.1
0.041
20%
20%
Year 1
30%
Investment Outlay
Year 2
45%
Year 3
25%
Loan amount
Loan rate
Loan Structure
130 $MM
12%
Loan period
Interest Const.
Up-Front Fee
Principle
10 years
0.6%
12.6%
2.5%
150 $MM
Given this model and the input values summarized in table above, the plant will generate an NPV of $47
million over 22 years with an IRR of 15% (see table below). Naturally, these values are very sensitive to
gas and power prices. For example, if the gas cost rises to $2.9/MMBtu or the power price is down to
$.036/kWh, the NPV becomes negative. If both of these events occur simultaneously, the results will
naturally be worse. This clearly shows the importance of long-term gas contracts and power purchase
agreements the IPPs usually ask for, especially in markets where price forecasts and/or supply and
demand conditions for either power or gas or both are not dependable. On the other hand, increasing load
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
14 - 12
Economics of the Energy Industries
factor or efficiency by 4-5%, or a combination of 2-3% increases in both would overcome the increase in
the cost of natural gas or the decrease in power prices.
For comparison, if we look at a conventional combustion turbine for which the capital cost is $325/kW,
the fixed O&M cost is only $5/kW, variable O&M cost is $0.005/kWh and the efficiency is only 32%
(heat rate of 10,600 Btu/kWh). Even with mostly lower cost, significantly lower efficiency causes the
NPV to be almost zero. If this plant had the same efficiency as our first plant (i.e., 49%), the lower costs
would have resulted in an NPV of $74 million and an IRR of 21% (under the same gas and power prices).
Combined Cycle Gas Turbine Economics
Investor Capex Incl.
Year Share ($MM) Int. ($MM)
1
27
67
2
43
107
3
28
71
4
0
5
0
6
0
7
0
8
0
9
0
10
0
11
0
12
0
13
0
14
0
15
0
16
0
17
0
18
0
19
0
20
0
21
0
22
0
23
0
Total
98
245
Principle
($MM)
0
0
0
-9
-10
-11
-12
-13
-15
-17
-19
-21
-24
0
0
0
0
0
0
0
0
0
0
-150
Interest
($MM)
0
0
0
-18
-17
-16
-15
-13
-11
-10
-8
-5
-3
0
0
0
0
0
0
0
0
0
0
-116
Deprec.
($MM)
0
0
0
16
16
16
16
16
16
16
16
16
16
16
16
16
16
16
0
0
0
0
0
245
O&M Costs
Fuel Cons.
($MM)
(10^12 Btu)
0
0.00
0
0.00
0
0.00
12.67
15.86
12.67
15.86
12.67
15.86
12.67
15.86
12.67
15.86
12.67
15.86
12.67
15.86
12.67
15.86
12.67
15.86
12.67
15.86
12.67
15.86
12.67
15.86
12.67
15.86
12.67
15.86
12.67
15.86
12.67
15.86
12.67
15.86
12.67
15.86
12.67
15.86
12.67
15.86
Gas Cost
($MM)
0.00
0.00
0.00
33.31
33.31
33.31
33.31
33.31
33.31
33.31
33.31
33.31
33.31
33.31
33.31
33.31
33.31
33.31
33.31
33.31
33.31
33.31
33.31
Generation
(MM kWh)
0
0
0
2277.6
2277.6
2277.6
2277.6
2277.6
2277.6
2277.6
2277.6
2277.6
2277.6
2277.6
2277.6
2277.6
2277.6
2277.6
2277.6
2277.6
2277.6
2277.6
2277.6
Revenue
($MM)
0.00
0.00
0.00
93.38
93.38
93.38
93.38
93.38
93.38
93.38
93.38
93.38
93.38
93.38
93.38
93.38
93.38
93.38
93.38
93.38
93.38
93.38
93.38
After-tax
Income
Cash Flow
($MM)
($MM)
0.00
-26.96
0.00
-42.66
0.00
-28.28
8.50
16.27
9.17
15.91
9.92
15.51
10.75
15.06
11.69
14.55
12.74
13.99
13.92
13.35
15.23
12.64
16.71
11.85
18.36
10.96
20.21
36.53
20.21
36.53
20.21
36.53
20.21
36.53
20.21
36.53
30.82
30.82
30.82
30.82
30.82
30.82
30.82
30.82
30.82
30.82
NPV
IRR
$46.82
15%
Relevant Case Studies:
Brazil Power Market Crisis
Convergence Merger
Electricity Restructuring in California
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
14 – 13
Economics of the Energy Industries
SECTION 4 – TRADING, MARKETING, AND RISK
MANAGEMENT
CHAPTER 15 – ENERGY TRADING & RISK MANAGEMENT: A STORY OF
EVOLUTION
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
Economics of the Energy Industries
CHAPTER 15 – ENERGY TRADING & RISK MANAGEMENT: A STORY OF
EVOLUTION1
Introduction
The phrase “energy marketing,” by its very nature, involves the rationalization and evaluation of all
energy sources by various parties (the electric utility, natural gas utility, independent power producer,
cogenerator, end user, etc.) to determine the best overall fit in attending to customer needs. The
commodity itself – energy – is basically becoming a secondary concern to most stakeholders as needs
themselves become primary in the choice of which type or types of energy will be utilized. The market
itself, in many instances, will help to determine the source from which energy is produced.
Energy customers, once thought of as a captive audience due to the monopoly position of their energy
supplier, can no longer be held captive. Most customers have come to appreciate the opportunity to
choose their energy suppliers. The larger a customer is, the more likely it is that s/he will benefit from
having a choice. Not only do energy customers desire the opportunity to make choices about their
providers, but also they are requiring their supplier or suppliers to assist them in addressing their energy
needs. Again, this is particularly the case for large industrial and commercial consumers of energy.
However sometime in the future, residential consumers also may be seeking help in addressing their
energy needs.
This spells out the need for energy marketers to be solution providers and not just merely a provider that
offers the best prices.
Evolution in the Energy Industry
Like most all other industries, the energy industry in its current state is the product of evolution – a
gradual, yet continual state of advancement brought about through various events. Evolution by its very
nature, context, and definition, is ongoing. It never ends. It is constant. A series of historical events has
actually caused the industry to evolve and to change into something else. Outside forces, including
regulatory policy and, in no lesser part, the economy are direct agents in causing the power industry
change. We provided details of the evolution in each of the oil, natural gas and electric power value
chains in chapters 3-5. Here we revisit natural gas and electric power restructuring efforts in the U.S.,
which set the stage for energy marketing, trading and risk management to mature.
The evolution of the natural gas industry
Natural gas industry restructuring began in 1978, with the passage of the Natural Gas Policy Act (NGPA),
which started the deregulation of wellhead price controls. Federal Energy Regulatory Commission
(FERC) issued Order 436 in 1985 to help address and control the apparent discriminatory access to
pipeline transportation. The courts later would not completely disagree with the purpose of the order, but
would, however, have some differences of opinion on how to address the discriminatory access dilemma.
The second major step was the passage of FERC Order 451, which effectively removed vintage price tiers
that had been set out under the NGPA. With this order, FERC raised ceilings of vintage gas categories to
market levels and established procedures that encouraged procedures and pipelines to renegotiate
associated contracts.
Due to some legal challenges that faced FERC Order 436, it was reentered as FERC Order 500. This rule
would later be finalized and be renamed FERC Order 636, which became the gas industry’s ticket to
competition.
1
Based on a paper prepared by Haluk Noyin, Energy Institute Research Assistant, 2000.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
15 – 1
Economics of the Energy Industries
The evolution of the electric utility industry
Regulators in the United States are playing a central role in the movement towards a competitive electric
power generation market. Driven by the desire to reduce energy prices and to substitute competition for
regulation, FERC and several state commissions have taken the lead in developing competitive market
structures at both the wholesale and retail levels. The main tasks for the regulators are to:
•
Mesh competitive electricity-generation markets with the existing regulated monopolies in
transmission and distribution; and
•
Provide an equitable and effective transition between the industry’s traditional monopoly style
regulation and the more limited regulation envisaged for the future.
Regulators are still in charge of setting the rules of the game and the competitive opportunities for market
participants remain very much in affected by their choices.
The regulatory structure
Investor-owned electricity utilities are subject to economic regulation by the U.S. federal government and
by state governments. FERC regulates the rates, terms, and conditions of wholesale sales and
transmission of electricity by investor-owned utilities pursuant to the Federal Power Act (FPA). Under
the FPA, such rates, terms, and conditions must be “just and reasonable” and not “unduly discriminatory
or preferential.” Historically, regulation has been based on the principle of “cost-of-service” – i.e., it was
designed to allow the industry to recover its costs plus a fair rate of return (see information on rate
making at the end of this workbook).
FERC also regulates certain corporate activities of public utilities, such as mergers between, and
acquisitions of, public utilities and the issuance of securities by certain public utilities. According to
FPA, FERC must find that a merger or consolidation of public utilities or the disposition of public utility
facilities is consistent with the public interest before authorizing the transaction. FPA also requires public
utilities whose securities are not regulated under state law or by the Securities and Exchange Commission
(SEC) to obtain authorization from FERC for the issuance of any security or for the assumption of any
obligations as a guarantor of securities.
The FPA also requires that any person who wishes to export electricity from the U.S. should obtain an
order from FERC. This power has been delegated to the Department of Energy (DOE), which until
recently only granted export authorization for specified transactions if it had been shown that they would
not impair the reliability of the affected utilities. In 1996, however, DOE began granting blanket export
authorizations for power marketers. Such authorizations require that all necessary contractual approvals
be obtained for the use of cross-border transmission facilities and that deliveries using such facilities do
not exceed authorized levels.
PUHCA
The Public Utility Holding Company Act or PUHCA came into being in 1935 when Congress decided
that it was time to restrain the activities and dealings of large holding companies in both the natural gas
industry and in the electric power industry.
The goal of PUHCA was to simplify and regulate the organization of holding companies and to limit the
geographic size of utilities. The act gives the Securities and Exchange Commission (SEC) authority over
those who hold interests in utilities and restricts the operations of registered public utility holding
companies. Under PUHCA, the SEC scrutinizes virtually every significant transaction undertaken by
registered holding companies, as well as their accounting practices and corporate structures. In fact, SEC
oversees all the corporate entities in a given public utility holding company system. To avoid regulation
under PUHCA, holding companies must obtain an exemption under one of five categories, the most
significant being the exemptions for holding companies that operate predominantly in one state and for
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
15 – 2
Economics of the Energy Industries
holding companies that are predominantly utility companies operating in their state of organization and
contiguous states. To bring themselves within these exemptions, most utilities in the U.S. are organized
and operate in limited and contiguous geographical areas. This accounts for much of the current
organization of the industry. Although the SEC has attempted to liberalize the Act's regulations and has
recommended its repeal, PUHCA remains a significant constraint and its amendment or repeal is an
important part of the legislative agenda.
PURPA
Enacted by Congress in 1978, the Public Utility Regulatory Policies Act encourages the use of renewables
to generate electricity. The goal of the act, passed at the height of an energy crisis, was to help the U.S.
decrease its dependence on foreign oil.
PURPA encourages private investors to build small electric power production facilities using renewable
energy sources. Also, PURPA encourages plants to cogenerate electricity by using excess steam from
various manufacturing processes. Electricity utilities are required to purchase power wholesale from
certain types of independent power producers, namely independent power plants that produce electricity
with renewable resources (e.g. hydroelectric, geothermal, solar, wind, biomass), or which “cogenerate”
(i.e. produce both electricity and another useful form of energy such as steam). The rates for utility
purchases from such entities are determined by state regulatory agencies, but are to be no more than the
“avoided cost” of energy and capacity incurred by the purchasing utilities (i.e. the costs that the
purchasing utility would have incurred in order to build or acquire the energy and capacity itself). The
Act brought scores of new participants into wholesale power markets and utilities had to deal with
independent, third party power suppliers for the first time. In the wake of PURPA, state regulatory
commissions also began developing and expanding competitive procurement policies for electricity
utilities, resulting in more extensive integrated resource plan requirements.
The underlying principle of PURPA was that utilities would pay no more for the power than their
opportunity cost, but to facilitate the financing of new power plants, state commissions required utilities
to enter into long-term power contracts, frequently at fixed rates. As the market has developed, the rates
that were established in these contracts have turned out to be far above current market prices and are one
of the major sources of “stranded costs” in the industry (i.e., costs that would not be recoverable in a
competitive market). Ironically, PURPA both set in motion the movement toward a competitive market
and helped create one of the major problems in effecting that change.
EPAct
Seen as a turning point by many in the evolution of the electric power industry was Congress’ passage of
the National Energy Policy Act of 1992. Significant alterations were made to PUHCA with the passage
of EPAct. The most important change was aimed at loosening the tight grip PUHCA had on registered
public utility holding companies. EPAct allowed registered public utility holding companies to diversify
into such areas as independent power production as well as others.
The passage of EPAct would set the stage for competition in the electric utility industry. Its purpose was
to promote economic development and energy conservation, but it had a major goal of encouraging
competition. EPAct began what has become a tidal wave of changes in national policies and regulations
that have, in the past, defined the place of utilities in the generation, transmission, and sale of electricity.
Under the sections added to the FPA, FERC can order a “transmitting utility” (a category that includes
municipal utilities and electric cooperatives in addition to investor-owned utilities) to provide
transmission service to others. In a series of orders implementing these provisions, FERC has established
a procedure whereby a customer seeking transmission service must first make a “good faith request” to
the transmitting utility for such service. If such request is not granted, the customer can file a complaint
with FERC seeking an order compelling transmission service. If FERC finds merit in such a complaint, it
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
15 – 3
Economics of the Energy Industries
will order the parties to negotiate and, if such negotiations fail, to file briefs with the Commission. The
Commission will then decide whether to order such services and their rates, terms, and conditions.
Prior to the EPA, FERC had never required a utility to provide “network” transmission service. Rather,
FERC had held that “point-to-point” transmission service was adequate under the FPA. However, in
1994, FERC issued an order requiring a utility to provide network transmission service. Such service was
to be priced on the basis of the customer’s “load ratio share” of the transmitting utility’s transmission
system costs. In 1994, FERC also made an important conceptual shift and began making its approvals
conditional upon the requirement that utility tariffs offer a service that is “comparable” to the
transmission owners’ own uses of its transmission system.
Processing individual requests for access was a slow and cumbersome process, generally taking well over
a year from the time of the initial request for service to final FERC disposition. To avoid these burdens
and to accelerate the process of providing access FERC proposed and then approved a rule requiring all
public utilities to provide open access. This rule – the watershed Order 888 – proved to be the critical
step in establishing the framework for competitive wholesale markets. It also laid the foundations for
reform at state level intended to bring about a competitive retail service.
FERC issues historic final rules
On April 24, 1996, FERC issued a set of final rules, known as FERC Order No. 888 and FERC Order No.
889, pertaining to electric utility industry restructuring. Order 888 opened wholesale power sales to
competition. Public utilities that own, control, or operate transmission lines are now required to file nondiscriminatory open access tariffs that offer others the same transmission service they provide themselves.
Rates for such transmission services (and for associated ancillary services) are to be determined in
individual proceedings before FERC on the basis of the supplying utility’s cost of service.
Order 889 is known as the Open Access Same-time Information System (OASIS) rule. An OASIS is an
electronic information system accessible through the Internet. An OASIS system should provide market
participants with all the information about a utility’s transmission system that they need to make use of a
utility’s tariff. OASIS will ensure that transmission owners and their affiliates do not have an unfair
competitive advantage in using transmission to sell power. Order 889 also requires utilities to adopt
standards of conduct that prohibit the exchange of transmission function and the employees y working in
the power marketing function. The Order 889 standards are intended to ensure that third-party power
suppliers and the power marketing arms of utilities have equal access to information about transmission.
Under Orders 888 and 889, a utility must “functionally unbundle” all wholesale sales and purchases of
electricity. Such functional unbundling requires that rates for generation, transmission and ancillary
services be separately stated, that the utility use its own transmission tariff (just as a third party would) in
order to transmit power across its own transmission system, and that the utility’s marketing arm and third
parties have equal access to transmission information through OASIS.
Under Order 888, public utilities that are members of a tight power pool were required to file a joint poolwide open access tariff by December 31, 1996, and must take service under that tariff for all pool
transactions. The reformed power pool agreements should establish open, non-discriminatory
membership provisions (including establishment of an independent system operator or ISO for
transmission system operation, if that is a pool’s preferred method of remedying undue discrimination)
and modify any provisions that are unduly discriminatory or preferential. Any bulk power market
participant must be allowed to join the pool, regardless of the type of the entity, affiliation, or geographic
location.
In adopting Order 888, the Commission recognized that open access could lead to the “stranding” of
generation and other costs incurred by utilities under the prior regulatory regime, and the order provided
for the full recovery from wholesale customers of “legitimate, prudent and verifiable” stranded costs.
Order 888 concludes that direct assignment of stranded costs to a departing wholesale generation
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
15 – 4
Economics of the Energy Industries
customer through either an exit fee or a surcharge on transmission is the appropriate method for recovery
of such costs. Stranded costs at the wholesale level, the level regulated by FERC, are estimated to be only
10% to 15% of the total potential stranded costs in the industry. The remaining costs are subject to state
regulation, but at an early stage FERC, along with California at the state level, articulated a basis for
permitting 100% recovery of these costs. This profoundly influenced subsequent thinking and has no
doubt contributed to the wide acceptance of Order 888 by the industry.
The demands of competition
The passage of the Public Utility Regulatory Policies Act (PURPA) of 1978 unleashed the forces for
change in the electric power industry. The advent of enterprises that generated and sold electricity, but
were not integrated utilities, introduced new stakeholders, new ideas and new demands. The first power
sales transaction to be crafted by a non-traditional utility was executed in 1986 by Citizens Energy
Corporation. Increasingly, electric power was sold using market-based pricing rather than the traditional
cost-based pricing. In 1989, FERC approved the application of the first industrial power marketing
company, Citizens Power & Light Corporation, to sell electric power at market-based prices.
Pressure for more competitive markets continued to mount, and the Energy Policy Act of 1992
established federal guidelines for opening electricity markets to competition. The ranks of the electricity
marketers swelled to more than 250 companies. Inevitably, non-discriminatory access to the electric
power transmission service became a key issue, which FERC addressed with Orders 888 and 889.
Relationships between utilities and new entities: The restructured market
The relationships between utilities that existed under traditional regulation were replaced with more
complex transmission-related interactions. There are three broad categories of interactions. First of all,
marketing interactions between the sellers and buyers of power give rise to the need for a transmission
service. The merchant then sets in motion the transmission service interactions by querying the OASIS
data system to determine whether transmission services are available and reserve the necessary
transmission to support the proposed transaction. The transmission providers refresh the data on the
OASIS and take the transmission reservations over the OASIS. As the hour of delivery approaches,
schedules for energy deliveries using the transmission reservations are filed with the transmission
provider. This give rise to control interactions between generators, loads (i.e., power takers) and other
transmission providers, to allow each party to make the deliveries within the constraints of the system.
The traditional utility will continue, in the near term, to serve the loads within its franchise area.
However, its generation, transmission, and load enterprises will be “unbundled” into their various
functions as the utility responds to the FERC unbundling requirements. Generation enterprises and the
load enterprises will eventually need marketers with different sets of skills to sell energy and capacity
from generating assets and to buy energy and capacity for serving the loads. Many traditional utilities
have already created affiliated power marketer enterprises to arrange power transactions beyond their
franchise area. In these cases, the affiliated power marketers are obliged by Order 889 to query the same
OASIS data as the other merchants to review transmission availability and make reservations.
Transmission-dependent utilities continue to serve their native loads, but have a vastly increased
opportunity to purchase power from multiple sources.
Many of these opportunities arise from the new market participants. Independent power producers (IPPs)
and power marketers are active in the marketplace. Load aggregators and independent transmission
enterprises do not yet have a substantial presence, but may evolve as retail competition becomes a reality
and independent entities build and operate transmission assets. Independent system operators (ISOs) are
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
15 – 5
Economics of the Energy Industries
being formed to provide independent operation of the transmission grid. In the end, the ISO in a region
will probably maintain the OASIS on behalf of transmission providers.2
Another new entrant to the power market is the power exchange (PX). In reality, several power
exchanges may eventually operate in the marketplace, some trading futures products, some trading
physical products, while others are yet to be conceived. To the extent that trading generating transmission
requirements, either the PX or its participants must arrange transmission services. The New York
Mercantile Exchange (NYMEX) initiated two futures power exchange contracts at the Western
Interconnection, one at the California-Oregon Border (COB) hub and the other at the Palo Verde hub in
the late 1990s but both contracts were cancelled along with Cinergy contract due to lack of interest and
California crisis. As any exchange-based contracts, they were very well defined in terms of quantity, time
periods, and the like. As it turned out, this standardization that worked fine for oil, products and natural
gas contracts was not desirable for electricity. Many players developed their own products and traded
them over the counter.
The final new entrants in the marketplace are the security coordinators (SC), formed in 1997 by North
American Electric Reliability Council (NERC) to coordinate the secure and reliable operation of the
North American transmission grid. The ISOs and the separate utility control centers will provide
standardized interconnection information to the NERC Inter-Regional Security Network (ISN), and
receive coordinating instructions from the security coordinators when the transmission networks are under
serious loading stress. The security coordinators will be able to invoke standard line-loading relief
procedures to relieve the stressed facilities.
Managing Risk in a Competitive Environment
As restructuring of natural gas and electricity markets took effect, prices for these commodities started to
become more volatile. Commodity prices are known to fluctuate in response to seasonality in demand or
supply, unexpected developments in production cycles or demand conditions, and the like. Natural gas
and in particular electricity proved to be much more volatile than most other commodities. Price
volatility increases risk for both producers considering their investment plans and consumers planning
their energy budgets. Like any other risk, energy price volatility risk needs to be managed.
Risk Management Goals & Strategies
The first step in devising a risk-management policy is to understand that risk management can be different
things to different people. There are different kinds of trading strategies, which achieve very different
kinds of risk-and-return goals. Not only can the same firm be following different goals, the firm may
actually be practicing strategies that do not necessarily fit the desired goals.
There are many different approaches to trading strategies, but they can be broke down into four distinct
groups:
•
•
•
•
Speculation
Arbitrage
Market Maker
Treasury
While not mutually exclusive, each strategy represents a different balance of risk and return that requires
very different types of business processes and management. A manager would be wise to evaluate her
own operation, understand how it could be categorized as one or more of the distinct strategies, and
perhaps begin the process of separating functions in order to evaluate them.
2
Since FERC’s Order 2000 issued at the end of 1999, Regional Transmission Organization, or RTO, is the more
common term used to describe independent system operators.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
15 – 6
Economics of the Energy Industries
The figure below plots the four strategies across risk and return. Speculation, arbitrage, and market
making are profit-generating strategies, while the treasury strategy is a pure risk-reducing strategy.
Strategy
Risk
Reward
Term
Liquidity
Speculation
Arbitrage
Market maker
Treasury
High
Low
Low
Reducing
High
Low
Low
Negative
Short
Short-medium
As required
As required
High
High
As available
As available
Speculation
A speculative trading strategy is typically a large-return-for-large-risk strategy. It is typically very shortterm, in terms of how long the positions are held as well as how far out the traded contracts tend to go.
This type of strategy benefits from a great deal of liquidity for greater deal turnover and hence more
opportunity. Nonetheless, it can also be seen in illiquid markets, where the deals are held for longer
periods of time. The traders asked to generate value in such a strategy are primarily market-driven, as
they try to guess the short-term market moves.
Arbitrage
An arbitrage strategy involves “beating” the marketplace with one’s ability to value and hedge derivative
products. Sometimes this can be pure arbitrage, where value is captured through a zero-risk pure
arbitrage market opportunity. Sometimes this can be “statistical arbitrage,” where value is captured by
exploiting a market opportunity over a period of time and by doing many trades. The pure arbitrage case
is a perfectly hedged value-added
Return
deal. An example can be buying
a futures contract at the Chicago
Speculative
Board
of
Trade
and
simultaneously selling the exact
same contract on the Philadelphia
Market Maker
exchange but at a higher price
than what it was bought for.
Obviously,
pure
arbitrage
Arbitrage
opportunities carrying no risk are
hard to find, and when they are
found they do not last for very
Treasury
long.
Statistical arbitrage involves
capturing market mispricing,
which is obvious only to the players who know something about the market or about product pricing. A
good example of such statistical arbitrage occurs when the market is using too low a volatility in pricing
options. The risk is typically much smaller than in the case of the speculative strategy. Arbitrage
strategies can primarily be found in relatively new and fairly illiquid markets, as these typically provide
mispricing opportunities.
Risk
Market Maker
Being a risk-management service provider, or market maker, is in theory a zero-risk strategy that captures
the bid-ask spread in the marketplace. A market maker is willing to quote a price on almost any deal
within a well-defined market-place to its customer. When a customer enters into a deal, the service
provider looks for the best hedges for the deal. If the market is liquid and mature, the service provider
can hedge off all the first-order risks. When the hedging is assumed continuous, as the first-order risks
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
15 – 7
Economics of the Energy Industries
change due to the market underlying prices and volatilities changing, the service provider immediately
rehedged. In such a way, all the risks are brought down to a minimum at all times.
However, the reality is that even in highly liquid markets hedging is not continuous, and hence the service
provider is generally left with some small daily risks. Similarly, the hedging costs may be high enough
that the risk manager decides that she is better off keeping some risks on the books rather than paying for
the hedges. In the case of an illiquid market, not only is the hedging very far from being continuous, it
may also be impossible to hedge off certain types of risk. Hence, in both the liquid and the illiquid
markets, being a service provider carries a certain amount of risk. One piece of good news is that the
greater the illiquidity in a market place, the greater are bid-ask spreads.
Treasury
The treasury strategy means providing risk-management service only in-house in order to achieve a
particular risk/return combination for the company. This is a one-way strategy, typically consisting of
buying certain derivative products to be used as insurance to offset risks. The interest rate derivative
products have developed into a huge market because there are so many companies that carry interest rate
risks through their loan-based capital that they have a need to manage this risk. The electricity market
could also become a large market post restructuring for this same reason – there are enough users to
generate a need for managing the electricity price risk.
The Role of Marketers and Brokers
With the restructuring of the natural gas and electricity industries a group of niche players who offer
specialized services came on the scene. From power marketers or arbitrageurs buying and selling
electricity as a commodity to the new marketing divisions of unbundled utilities to retail-level distribution
companies, these companies developed and reshaped the market.
There are two different types of marketers: affiliated and independent. Under FERC guidelines,
affiliated marketers are comprised of any group that has more than a five-percent or ten-percent
ownership by an electric utility, qualified facility, or independent power producer. In the late 1990s, there
were 365 independent power marketers, 112 power marketers affiliated with utilities and 89 power
marketers associated with other power generators.
It must be noted that brokers also carry a significant amount of weight in arranging bulk power
transactions. There are at least two main differences between a marketer and a broker. First, brokers do
not assume financial risk. The role of the broker is to bring together a willing seller and a willing buyer
without actually taking title to the power. Marketers actually take title to the power, thus their
attractiveness in reducing a utility’s financial risk. Secondly, brokers differ from marketers in that they
currently are not regulated by FERC.
The ranks of marketers and the total trading volume grew at a fast pace between 1996 and 1998 and
remained high until about 2000. The rise in the number of marketers and their transactions at the
wholesale level were largely due to their unique ability to offer services that utilities traditionally have not
developed. Marketers were able to unbundle and then rebundle differentiated products to meet the needs
of a vastly changing market. Through this unbundling and rebundling activity, marketers were able to
provide high-impact and high-demand services. In the physical market, marketers were able to provide
the following services: system firming, shaping, dispatchability, displaceability, and storage. In the
financial area, marketers were able to offer the following: flexible contracts, flexible pricing, and various
financial instruments, such as futures.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
15 – 8
Economics of the Energy Industries
Top North American Gas Marketers (Bcf/d)
Company
2003
BP
Sempra
Coral
ConocoPhillips
Cinergy
ChevronTexaco
Tenaska
ExxonMobil
Nexen
Williams
EnCana
Oneok
Devon
Entergy-Koch
Amerada Hess
Sequent
Burlington
Anadarko
Western Gas
Enserco
Dominion
Apache
Total
Volume
2003
20.20
13.20
9.20
8.70
4.06
3.87
3.50
3.19
3.03
2.70
2.57
2.53
2.34
2.30
2.00
1.75
1.73
1.37
1.36
1.21
1.09
0.98
81.38
Company
1999
Enron
Duke
Aquila
Coral
Dynegy
PG&E
ExxonMobil*
Reliant
El Paso**
TransCanada
Sempra
Engage
Koch
BP Amoco
Southern
Oneok***
Texaco
Williams
Conoco
TXU
Volume
1999
13.10
11.00
10.40
9.80
8.80
8.40
7.80
7.00
6.70
6.60
5.80
5.60
5.50
5.40
5.40
4.50
3.40
3.40
3.20
3.00
134.80
* Includes net interest in Duke Energy partnership's sales
**Includes Sonat
***Includes former Kinder Morgan and KN Energy operations
Source: Intelligence Press, Inc
These attributes particular to marketers made them
highly attractive to utilities that generate electricity
and were looking for new, innovative ways to
market the power they produce.
Utilities that once found themselves having to enter
into long-term power purchase contracts were
finding that they could go with short-term contracts
when they employ the use of marketers. This
implied two things: that the contracts were viewed
by utilities as safer and second that utilities liked
the idea of sharing or relinquishing altogether their
financial risk through shifting it to the marketer.
Most of these qualities are still true but California
and Enron crises and following meltdown in the
energy trading business changed the face of the
industry. In the table to the left, one can see that
volume of natural gas marketed fell by almost 40%
between 1999 and 2003. Once high flying trading
companies, such as Enron, Aquila, Dynegy, and
Duke are not even in the list for 2003. The list is
now dominated by companies with real assets and
production, such as BP, Sempra, ConocoPhillips,
and ChevronTexaco. The picture is similar in the
electricity market as well (see table next page).
Although the volume fell only by 14%, the
composition of traders changed. Again, Enron and
Aquila and others like them are replaced by
companies with real assets. Part of the decrease in
volumes marketed can be explained by the
roundtrip trades some of these companies
employed before the collapse in 2001-2002.
Financial market advancements: NYMEX and others
The three major energy futures exchanges are the NYMEX, IPE, and SIMEX (Singapore International
Monetary Exchange). For electricity and natural gas, only NYMEX and IPE will be significant.
Since starting with heating oil futures in 1978, energy futures and options markets on the New York
Mercantile Exchange have grown and profoundly changed energy marketing. Contracts traded on the
NYMEX include light sweet crude oil, unleaded gasoline, New York Harbor #2 heating oil, Henry Hub
natural gas, propane, coal and PJM electricity. The sour crude and Gulf Coast gasoline are not actively
traded at this time. A residual fuel oil contract is no longer listed. Recently, NYMEX introduced Brent
crude oil contract that competes with the well established Brent contract at IPE, which also trades gasoil,
and unleaded gasoline futures contracts. The SIMEX trades residual fuel oil (relaunched in April 1997)
and has an inactive gasoil futures contract which may be relaunched in the future. In 1995, the SIMEX
listed the IPE’s Brent crude oil futures contract as a mutual offset contract for the Far East, where it trades
much smaller volumes compared to London-based Brent trading.
All three established energy futures exchanges have indicated they will continue to launch futures
contracts that conceptually hedge the entire barrel of crude oil as it makes its way from the ground to the
consumer, as well as natural gas, electricity, and coal contracts. However, most refiners and end users are
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
15 – 9
Economics of the Energy Industries
more comfortable using other over-the-counter financial instruments to hedge less liquid products such as
residual fuel oil, jet fuel, naphtha, and diesel fuel.
North American Power Sales by Top Companies
(million kWh)
Company
2003
Entergy Commodities
Sempra Energy Trading
Exelon Generation
Williams Energy
Reliant Wholesale
Cinergy Commercial
TXU North America
FirstEnergy Corp
Calpine
Dominion Generation
Reliant Retail Energy
PP&L Energy Supply
DTE Power Generation
Texas Genco Holdings
Avista Trading
Dynegy Generation
Mirant Corp.
Entergy Nuclear
Pinnacle West
Duke Energy N. America
CMS Enterprises
Duke International
Total
Volume
2003
445,980
312,300
217,362
165,908
159,666
147,460
117,284
106,125
83,568
75,407
67,187
60,339
52,520
47,365
41,579
37,100
36,900
32,383
28,380
24,126
20,000
18,631
2,297,570
Company
1999
Enron
AEP
Aquila
PG&E
Southern
Avista
Reliant
Duke
Entergy
PPL
Williams
Citizens
Bonneville
El Paso***
Dynegy
Constellation
PECO
Tractebel
Koch
Cinergy
Volume
1999
380,500
306,600
236,500
224,700
219,300
135,000
112,000
109,600
106,800
96,000
90,700
90,100
90,000
79,400
79,300
69,800
66,600
61,400
56,200
48,100
2,658,700
***Includes Sonat
Source: Intelligence Press, Inc
The NYMEX trades options on crude oil,
New York Harbor unleaded gasoline, #2
heating oil, and natural gas, providing
additional tools to manage price risk. The
NYMEX natural gas futures contract,
launched on April 3, 1990, has rapidly
established itself as an effective instrument
for natural gas price discovery in North
America. NYMEX launched natural gas
options in October 1992, adding another
tool to manage risk in that volatile market.
A second natural gas futures contract was
launched on August 1, 1995, by the Kansas
City Board of Trade, which is oriented to
the western U.S. market.
In February 1990, the NYMEX initiated
long-dated options for the crude oil
contract. These options trade 12 months
out. Long-dated options were a direct
response to the growth of off-exchange
markets. They allow users to lock in a
fixed price or price range and are useful for
refiners and end users entering into long
term supply contracts where crude oil
prices are likely to be variable. Since that
time, NYMEX has extended the crude oil
contract out seven years and its Henry Hub
natural gas contract out three years
forward. The IPE has been particularly
successful with its Brent crude oil options
and also a gasoil options contract.
New Systems in Risk Management
Commodity trading systems play a key role in the successful development of these organizations.
Regardless of the specific needs of each sector, the ability to identify and manage risks associated with
the underlying commodity is essential. Electric utilities have the most to gain. As they move forward
into the unbundling process, these traditionally vertically integrated companies are going through
organizational metamorphoses. The generation, transmission, marketing and distribution functions of the
organization are quickly evolving as standalone business units, with horizontal business structures for
each functional area.
The power industry is presenting a number of challenges to systems developers that are not apparent in
other energy commodities. Electricity, in fact, is considered the most challenging commodity to manage.
Price volatility is as extreme as it is in other emerging markets. The actual underlying physical
commodity offers unique trading properties.
In the natural gas industry, the use of storage and pipeline imbalances offers traders flexibility to manage
their books. This type of flexibility is not available to power traders, since the commodity is consumed as
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
15 – 10
Economics of the Energy Industries
it is generated. Embedded options, therefore, are a significant component of physical trades, providing
the ability to shift on receipt and delivery alternatives.
Another property that differentiates the electricity industry is the physical receipt and delivery of power,
which is managed in hourly increments. The level of resolution will likely become even finer as market
niches develop. The hourly increments in the power market mean that the sheer volume of components
for each trade is significantly larger than in other energy commodities. As a result of rapidly changing
intra-day levels of demand, the price of power varies, resulting in higher prices during peak hours.
What are some of the new needs of power marketers or arbitrageurs and marketing arms of utilities with
generation and transmission assets? The power marketer or arbitrageur acts as an intermediary between
parties who want to buy and sell power. The
goal, as with all traders, is to make a profit by
working off the opportunities to arbitrage prices.
Because power marketers have limited access to
generation and transmission assets, physical
delivery of trades they execute may be as low as
20 percent. In addition, transactions are limited
to grid locations where trading volumes are
significant enough to provide liquidity to lay off
open positions. Hence the number of trading
locations in the portfolio is smaller.
Power marketers’ portfolios primarily consist of standardized products such as on-peak, off-peak and
round-the-clock. In a typical trade, a power marketer might agree to sell power in on-peak five-by-16
blocks (five days a week, 16 hours a day) at 100 megawatts per hour for $25 per hour at a specific grid
location. Before the actual delivery of the commodity, however, the power trader will attempt to bookout of the trade by executing a corresponding purchase transaction, eliminating the requirement to
physically deliver the commodity.
In order to meet the needs of power marketers or arbitrageurs, a commodity trading system may be
adequate if it aggregates physical and financial positions from a standard product perspective for the
forward months, with the ability to query non-standard positions. For spot month trading, however, the
power marketer requires the commodity trading system to support physical and financial position
management on an hourly basis. With this level of resolution, traders can assess the impact of standard
and non-standard product positions with schedulers completing physical receipt and delivery transactions.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
15 – 11
Economics of the Energy Industries
Relevant Case Studies
Electricity Restructuring in California
Natural Gas Marketization in North America
References
Fusaro, Peter C., 1998, Energy Risk Management, McGraw Hill
Gellings, Clark W., 1998, Effective Power Marketing, PennWell Publishing Company
Joskow, Paul L., 1998, “Electricity Sectors in Transition,” The Energy Journal, Vol. 19, No.2
Moorhouse, John C., 1986, Electric Power Deregulation and Public Interest, Pacific Research Institute
for Public Policy
Pilipovic, Dragana, 1998, Energy Risk, McGraw Hill
Stewart, Sally, 1998, “New Trading Systems for the Power Industry,” Derivatives Strategy
Warkentin, Denise, 1996, Energy Marketing Handbook, PennWell Publishing Company
Williams, Dan R. and Good, Larry, 1994, Guide to the Energy Policy Act of 1992, The Fairmont Press
http://interactive4.wsj.com/public/current/articles/SB905354608899343000.htm,
Wild,” The Wall Street Journal Interactive Edition
1998,
“Young
and
http://www.eei.org/issues/comp_reg/5explosi.htm, 1999, “The Explosive Growth of Non-Utility Electric
Generation Sources,” Edison Electric Institute
http://www.eei.org/issues/comp_reg/6riseofp.htm, 1999, “The Rise of the Power Marketer,” Edison
Electric Institute
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
15 – 12
Economics of the Energy Industries
SECTION 5 – ALTERNATIVES
CHAPTER 16 - ALTERNATIVE SOURCES OF ENERGY
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
Economics of the Energy Industries
CHAPTER 16 - ALTERNATIVE SOURCES OF ENERGY
Introduction
In the last few decades, growing energy demand, increasing environmental problems, and concerns about
exhaustibility of fossil fuel resources made the world look to alternative energy options. For many,
securing environmentally sound sources of energy is one of the most important global challenges for the
future. Governments around the world unilaterally and via international agreements support development
of efficient and clean technologies and put their efforts into creating a stable framework for commercial
decision-making that will provide further motivation for technological development in order to stimulate
environment-friendly choices in the marketplace. Many believe that supplying new technologies can
transform fixing environmental problems into development opportunities that will foster economic
growth and provide energy security.
The alternative (or emerging) technologies listed above serve by either:
•
•
•
•
Prominently increasing energy supplies, thereby increasing energy security (technologies include
frontier hydrocarbon technologies such as gasification, including hydrogen production; gas-toliquids; tar sands, oil sands, and other heavy crude extractive and processing technologies);
Providing additional non-hydrocarbon supply options (ethanol1, biodiesel, wind and solar);
Moving towards globalizing a regionally limited natural-gas market to reduce risks associated
with supply and price (LNG); or
Reducing emissions of greenhouse gases (new emission-free supplies such as nuclear, wind,
solar; more efficient end-use technologies such as hydrogen fuel cells and advanced technology
vehicles; reduced emissions from hydrocarbon usage such as coal gasification, cogeneration and
deployment of CO2 capture and sequestration technologies and strategies).
1
It should be noted that significant amounts of fossil fuel are required to produce corn-based ethanol, both in growing the corn
and in producing the ethanol.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
16 – 1
Economics of the Energy Industries
To meet projected U.S. energy demand growth of 34% in the next two decades, U.S. oil and gas
companies invested $98 billion from 2000 through 2005 on emerging energy technologies. This
expenditure is 73% of the estimated total of $135 billion spent by U.S. companies and the Federal
government. Of the industry investments, $86 billion (or 88% of the $98 billion total) were directed
toward frontier hydrocarbons. In addition, the industry invested $11 billion (or 11% of the $98 billion
total) for advanced end-use technologies, mostly for efficiency improvements through combined heat and
power (cogeneration) and for advanced-technology vehicles using fuel-cell technology. Significantly,
this $11 billion investment in end-use technologies represents 35% of the estimated total amount ($31
billion) spent by U.S. companies and the Federal government in this area.
In addition to the U.S. oil and gas industry, other significant emerging technology investments were made
by the motor-vehicle industry, agricultural industry, electric utilities, renewable-fuel industry, and the
Federal government. These other private industries are estimated to have invested $32 billion (or 23% of
the $135 billion total) from 2000 to 2005. Of the $32 billion, $20 billion (62%) is associated with enduse technologies, $12 billion (37%) with non-hydrocarbons, and $0.3 billion (1%) with frontier
hydrocarbons.
The five leading technologies for private and public sector investment (see figure below), as measured by
expenditure, are gas-to-liquids (30%); tar and oil sands (25%); advanced technology vehicles (19%);
liquefied natural gas, or LNG2 (7%); and wind power (4%).
2
We have included only investments in domestic LNG regasification facilities. The global LNG market would also include ships
and liquefaction facilities in foreign locations, which are estimated to be valued at nearly $200 billion. Roughly $30 billion of this
total could be allocated to the U.S. market.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
16 - 2
Economics of the Energy Industries
There are two main areas for new energy sources and technologies to play a significant role: electric
power generation and transportation.
Electric Power Generation
Renewable energy sources, including water, wind, solar, geothermal, and some combustible materials,
such as landfill gas, municipal solid waste (MSW), and other forms of biomass, offer a great opportunity
for meeting a larger share of the need for electric power. In the U.S. and Europe, policies have supported
the development of renewable energy technologies in order to develop a sustainable energy future, reduce
dependence on foreign oil and gas, and reduce the environmental impacts of fossil-fueled electricity
generation. Recently Europe, however, has surpassed the U.S., especially in the use of wind power.
Worldwide, electricity generation from renewable sources increased from 1.7 quadrillion Btus (quads) in
1990 to 3.8 quads in 2003, or almost 125% (see table below).
Total Renewables Used to Generate Electricity (Quadrillion Btu)
United States
1985
1990
1995
1996
1997
1998
1999
2000
2001
2002
2003
0.213
0.872
0.947
0.973
0.983
0.982
1.013
1.027
1.001
1.100
1.113
Canada
0.017
0.038
0.054
0.057
0.060
0.064
0.076
0.077
0.083
0.086
0.087
Mexico
0.035
0.103
0.113
0.114
0.109
0.116
0.118
0.123
0.117
0.113
0.125
Japan
0.147
0.197
0.255
0.269
0.288
0.283
0.292
0.292
0.306
0.318
0.315
Western Europe
0.174
0.238
0.431
0.460
0.543
0.641
0.696
0.829
0.914
1.063
1.201
Australia
0.005
0.006
0.007
0.010
0.010
0.011
0.011
0.011
0.015
0.027
0.028
New Zealand
0.031
0.050
0.050
0.050
0.053
0.060
0.067
0.071
0.069
0.069
0.068
Industrialized Countries
Eastern Europe
0.621
0.005
1.503
0.003
1.857
0.009
1.933
0.009
2.046
0.009
2.157
0.009
2.272
0.009
2.430
0.009
2.505
0.009
2.776
0.009
2.937
0.009
Former Soviet Union
0
0.001
0.020
0.020
0.021
0.022
0.030
0.033
0.037
0.038
0.040
Total EE/FSU
China
0.005
0
0.004
0
0.029
0.028
0.028
0.014
0.029
0.025
0.031
0.023
0.039
0.023
0.042
0.023
0.046
0.024
0.046
0.024
0.048
0.024
India
0
0.001
0.005
0.009
0.010
0.010
0.023
0.029
0.040
0.042
0.043
Other Asia
0.111
0.132
0.204
0.206
0.245
0.299
0.349
0.401
0.407
0.422
0.430
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
16 – 3
Economics of the Energy Industries
Developing Asia
0.111
0.132
0.237
0.229
0.28
0.332
0.395
0.453
0.471
0.488
Middle East
0
0.001
0.001
0.0011
0.001
0.001
0.001
0.001
0.001
0.001
0.001
Africa
0.008
0.008
0.009
0.009
0.009
0.010
0.010
0.014
0.017
0.015
0.014
Central & South America
Brazil
0.078
0.040
0.094
0.051
0.129
0.076
0.146
0.088
0.157
0.098
0.158
0.099
0.179
0.112
0.197
0.120
0.232
0.137
0.253
0.148
0.288
0.166
Developing Countries
Total World
Source: EIA
0.497
0.202
0.240
0.404
0.412
0.475
0.531
0.623
0.706
0.766
0.802
0.847
0.823
1.741
2.261
2.345
2.521
2.688
2.895
3.136
3.271
3.578
3.784
Hydroelectric power generation, which has been around for decades, is included within renewables in this
section. Currently, hydropower accounts for 97% of total renewable generation in the world although this
percentage may differ across different regions (see table below). The world consumption of renewables
has increased by 30% from 24 quads in 1990 to 31.1 quads in 2000 while the total generation increased
only 20% from 127.1 quads to 152.5 quads over the same period. As a result, the share of renewables in
total generation increased from 18.8% to 20.1%. Most of the increase in renewables occurred in
developing regions from 8 quads to 12.1 quads, or more than 50%, while the industrialized countries also
added 2.8 quads, or 21%.
Electricity Generation, by Region and Fuel (Quadrillion Btu)
Industrialized Countries
Oil
Natural Gas
Coal
Nuclear
Renewables
Total Industrialized Countries
EE/FSU Countries
Oil
Natural Gas
Coal
Nuclear
Renewables
Total EE/FSU Countries
Developing Countries
Oil
Natural Gas
Coal
Nuclear
Renewables
Total Developing Countries
Total World
Oil
Natural Gas
Coal
Nuclear
Renewables
Total World
Source: BP, EIA
1990
1995
1996
1997
1998
1999
2000
2001
2002
2010
2025
5.9
5.9
27.2
16.3
13.1
68.4
5.7
9.7
27.7
19.4
14.7
77.1
5.9
9.8
28.4
19.8
15.1
79.0
5.9
10.3
29.4
19.5
15.5
80.8
6.7
10.9
29.8
20.0
15.3
82.7
6.5
11.6
29.5
20.6
15.6
83.8
6.3
12.5
29.9
20.8
15.9
85.4
5.1
14.4
32.1
21.0
16.4
89.0
4.8
12.3
32.0
21.2
13.8
84.0
4.5
16.5
35.1
22.1
16.0
94.1
5.4
23.6
40.3
21.8
20.2
111.3
3.8
10.8
10.9
2.9
2.8
31.2
2.8
10.6
7.4
2.5
3.1
26.4
2.5
10.7
6.3
2.8
2.9
25.2
2.5
10.1
6.2
2.8
2.9
24.4
2.4
10.2
5.6
2.7
3.0
23.9
2.4
10.3
5.4
2.7
3.0
23.8
2.6
10.3
5.5
2.9
3.1
24.4
0.9
8.1
6.8
3.0
3.1
21.9
1.1
8.3
6.3
3.4
3.1
22.0
1.1
13.0
7.3
3.8
3.3
28.5
1.2
17.3
7.2
5.4
3.5
34.7
4.4
3.1
10.8
1.1
8.0
27.5
5.1
4.8
16.8
1.4
10.1
38.1
5.3
5.1
17.2
1.5
10.4
39.6
5.5
5.5
16.9
1.6
10.8
40.3
5.6
5.7
16.6
1.7
11.1
40.8
5.7
6.0
15.8
1.9
11.5
40.9
5.8
6.4
16.5
2.0
12.1
42.7
6.1
7.1
22.2
2.2
12.0
49.6
6.5
8.8
25.5
2.2
12.2
55.7
10.0
11.1
37.4
4.2
17.3
79.9
12.4
21.5
49.5
7.2
21.1
111.5
14.1
19.8
48.9
20.4
24.0
127.1
13.6
25.1
51.9
23.3
27.9
141.7
13.8
25.6
51.9
24.1
28.3
143.7
14.0
26.0
52.5
23.9
29.2
145.5
14.7
26.8
52.0
24.4
29.4
147.3
14.6
27.9
50.7
25.3
30.0
148.4
14.8
29.1
51.8
25.7
31.1
152.5
12.2
29.6
61.1
26.2
31.5
160.5
12.4
29.4
63.8
26.8
29.1
161.7
15.6
40.6
79.8
30.1
36.6
202.5
19
62.4
97
34.4
44.8
257.5
In the future, restructuring of electricity markets will lead to a reevaluation of renewable energy policies
as competition will encourage utilities to become more efficient and reduce costs in order to lower
electricity prices. Renewable energy sources will be challenged to continue penetrating the generation
portfolio because they are generally higher-cost options for producing electricity. Supporters of renewable
energy fear that renewables may be an inadvertent casualty in the transition to a competitive market.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
16 - 4
Economics of the Energy Industries
Transportation
Worldwide, on roads today, over 5 million cars, trucks and buses run on something other than gasoline or
diesel fuel. A substantial majority (over11 million) run on liquefied petroleum gas (LPG), a mixture of
propane and butane that emits fewer pollutants than gasoline. About 5 million use natural gas in a form of
compressed natural gas (CNG) or liquefied natural gas (LNG), around 4 million use ethanol or methanol
and about 200,000 are electric cars.
Increasingly, hybrid cars, which use a combination of electric battery and internal combustion engine
(ICE), are entering the market. Although they use mostly gasoline and not an alternative fuel, these cars
mainly depend on the electric battery and increase the gas mileage to 50 to 60 miles per gallon (mpg) as
compared to 25-30 mpg in a typical ICE car.
Some alternatives fuels can be largely produced domestically, and may come from renewable energy
sources and are not heavy polluters. Stumbling blocks to wider alternative fuel use are a lack of stations
that carry the fuels and the added costs associated with alternative-fuel vehicles. For example, only about
600 gas stations in the US sell ethanol, out of existing 170,000, and ethanol gets fewer miles to the gallon
than gasoline.
Challenges
Despite all their promises, renewable and alternative technologies have certain drawbacks. Renewables
for electricity production are often located remotely from electricity demand centers. They are also often
available only intermittently; and some renewables tend to be available in approximate coincidence with
electricity demand (peak coincidence). The remote locations increase the cost of transmitting power
under distance-based pricing schemes. Intermittent availability either increases the cost of providing
electricity or increases the risk that transmission capacity will not be available whenever renewable
generation is. The inability to store electricity in a commercially viable manner intensifies the problem
of intermittency. The peak coincidence of some renewables (e.g., solar, wind, photovoltaic) with
electricity demand could raise transmission costs under congestion pricing schemes, but the price
received for peak electricity may well offset or exceed the higher costs.
Alternative fuel vehicles also have drawbacks for the consumers, including shorter driving ranges, less
cargo space (because of extra fuel tanks or batteries), and fewer refueling outlets. Only electricity has a
suitable fueling infrastructure in place; however, in many respects, electricity is the alternative fuel most
in need of technological improvements in order to be a practical transportation fuel.
Alternative Generation Technologies
The most commonly used types of alternative sources of energy include wind, solar, biomass, hydro, and
geothermal. Sections below will describe the characteristics of each type, consider advantages and
disadvantages of the use of such resources, as well as the economics of each type.
Hydro
Hydro is the leading source of renewable energy. It provides more than 88% of all electricity generated by
renewable sources. Hydroelectric power is an emissions-free, renewable, and mostly reliable source of
energy. Hydropower plants take advantage of a virtually infinite source of power. About 20% of all
electricity is generated by hydropower worldwide. Hydropower converts kinetic energy from falling
water into electricity. By generating carbon-free electricity, hydropower avoids burning fossil fuels and
releasing significant amounts of carbon dioxide. Hydropower turbines are capable of converting 90% of
available energy into electricity, which makes hydropower more efficient than any other form of
generation. Even the best fossil fuel power plant is only about 60% efficient.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
16 – 5
Economics of the Energy Industries
Net Hydroelectric Power Consumption, 2003
Billion Kilowatthours
3,000.00
2,500.00
2,000.00
1,500.00
1,000.00
500.00
0.00
Source: EIA
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ite
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Although Canada and the U.S. are the two largest producers, Brazil, the third largest, depends on
hydropower to generate more than 93% of its electricity, while the U.S gets about 7% and Canada gets
about 60% of their electricity from their hydro facilities. Norway produces more than 99% of its
electricity from hydropower. New Zealand uses hydropower for 56% of its electricity. Hydroelectric
generation increased by 2% in 2003, reflecting rapid growth in Africa, South America and Asia, partially
offset by a 0.6% fall in North America and 3.0% decline in Europe.
Wind
Wind power has become the world's fastest growing electricity generating technology. The world wind
energy generating capacity has grown from almost 0 in 1980 to 59,000 MW in 2005, yet still accounting
for less than 1% of total world capacity. The increase has been most rapid after 1997.
Global Wind Generation Capacity, 1995-2005
The greatest advantage of wind power is its potential for large-scale electricity generation without
emissions of any kind. Recent improvements in technology and better reliability have lowered costs. In
addition, government support around the world has been very strong. Wind power plants can be built in
small, modular units (less than a megawatt each) within a relatively short time frame, offering power
suppliers great flexibility. Capacity factor serves as the most common measure of a wind turbine's
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
16 - 6
Economics of the Energy Industries
productivity. Estimates of capacity factor of wind farms range from 20% to 40%, as compared to 70-90%
for coal and 60-100% for nuclear and 60% for combined cycle gas plant.
The U.S. possessed 95% of the world’s installed capacity in the early 1980s. But by 1990, Denmark,
Germany, the Netherlands, and India had also developed significant wind capacity, and the U.S. share
dropped to 75%. By 2005, Germany was the leading country in generation of wind power. In 2005, the
U.S. share was about 16%.
But, there have been significant additions in 2005 mainly in Texas and few other states. In many states in
the U.S. and elsewhere in the world, electricity restructuring legislation usually calls for the expansion of
alternative, or renewable, generation capacity, and wind technology, given its relatively advanced stage
and lower costs, benefited the most from these requirements.
Half of the capacity added in 2005 was concentrated in the top three countries: Germany added 1,808
MW, Spain 1,764 MW and the U.S. more than 2,400 MW. For the U.S., this translates into a growth in
generating capacity of more than 36% in 2005.
Top Wind Energy Markets (by installed capacity, in MW)
Germany
Spain
US
India
Denmark
2004
Additions
2.037
2.065
372
875
9
2004 Year
End Total
16,629
8,263
6,725
3,000
3,083
2005 Additions
1,808
1,764
2,431
1,430
39
2005 Year
End Total
18,428
10,027
9,149
4,430
3,122
%
of Total
31.2
17.0
15.5
7.5
5.3
Source: GWEC, American Wind Energy Association
Solar
Solar power provided around 2,400 MW worldwide by the end of 2003, a negligible share of total world
capacity. Solar power is used in two forms - thermal and photovoltaic (PV). The first concentrates
sunlight, converts it into heat, and applies it to a steam generator or engine to be converted into electricity
and used for heating, and electricity generation. Electricity is generated when the heated fluid drives
turbines or other machinery. The second form of solar power produces electricity directly without moving
parts. Today's PV system is composed of cells made of silicon, the second most abundant element in the
earth's crust. Viable solar thermal resources are limited to where water availability (for solar thermal
utilizing steam turbines) limits power generation potential. Most places are suitable for producing
electricity using solar PV during daylight, and PV generating facilities can be installed at the point of
demand making PV electricity the renewable generating technology least likely to be affected by
transmission pricing policies.
The solar industry has made major progress in the areas of performance, reliability, and costs, as well as
consumer acceptance. With the deregulation of generation, the solar industry will have to emphasize its
niche market applications and newly derived opportunities in order to continue its cost-reducing
technological developments.
The major advantages of PV solar power are that it is clean and renewable, requires little maintenance and
no supervision, and has a long life with low running costs. Remote areas can easily produce their own
supply of electricity by constructing as small or as large of a system as needed.
PV power even has advantages over wind power, hydropower, and solar thermal power. The latter three
require turbines with moving parts that are noisy and require maintenance. It is much more practical and
cheaper than the extension of expensive power lines into remote areas. Also, with small scale
applications, batteries can be used as storage devices. There are two primary disadvantages to using solar
power - amount of sunlight (i.e., intermittency and unreliability of sunlight) and high cost of equipment.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
16 – 7
Economics of the Energy Industries
Biomass
The world’s energy markets rely heavily on fossil fuels, coal, oil and natural gas - the resources that
require millions of years to form, are finite and are subject to depletion as they are consumed. The only
other naturally occurring hydrocarbon resource that can be substituted for fossil fuels is biomass. There
are four primary classes of biomass power systems: direct-fired, co-fired, gasification, and modular
systems. Biomass includes all organic material stemming from plants, trees and crops (including wood
waste), and all waste biomass such as municipal solid waste (MSW), municipal biosolids, animal waste,
and certain types of industrial wastes. Unlike fossil fuels, biomass is renewable in the sense that it takes a
short period of time to replace it. Although, there is a belief that biomass contributes some to atmospheric
CO2 built-up, the use of biomass results in less emissions than other fossil fuels.
There is an estimated 14,000 MW (less than 0.5% of world total capacity) of installed biomass generation
capacity in the world. Currently, the U.S. is the largest biomass power generator at 7,000 MW. The
majority of biomass energy is produced from wood and wood wastes (64%), followed by MSW (26%),
agricultural waste (5%) and landfill gases (5%). Initially, biomass was primarily used to provide heat for
cooking and comfort. Technologies have now been developed which can generate electricity from the
energy in biomass fuels.
Biomass energy is unique among renewable resources in that the fuel is not freely available. Collecting
biomass fuel has always been a costly and labor-intensive process. The benefits derived from biomass
power plants extend well beyond the production of clean electricity, as they reduce the amount of solid
waste in crowded landfills, thereby extending the life of difficult-to-site landfills.
Biomass technology is already fairly advanced so that conversion to liquid biofuels, ethanol and biodiesel,
can be as good as 75% efficient, through fast pyrolysis technology (still under development). Co-firing
with biomass, or biomass-only electricity generation, has been demonstrated, and proposed feedstocks
include pulp and paper byproducts. The best estimates for the future are that 10 to 20% of base load
energy could be supplied by biomass, and the results from current research suggest that hydrogen
production from biomass may be feasible but it is unknown if it could be a significant hydrogen source by
2030.
Geothermal Energy
Geothermal energy is the fraction of the Earth’s heat that is or could be utilized by man. It derives from
the decay of radioactive isotopes within the crust and mantle. It is the energy that moves the large
lithospheric places, which are made up of the crust and the uppermost part of the mantle, by a few
centimeters each year. Geothermal energy is produced by harvesting the heat from magma that is
relatively close to the surface of the earth, usually in areas that are seismically or volcanically active.
In order to utilize the heat contained in deep rocks, it has to be brought to the surface, where it may
emerge naturally in thermal springs, or through a well. The medium that brings it to the surface is the
geothermal fluid, consisting of water or steam. In order to absorb the heat, the geothermal fluid has to
circulate within hot, permeable rocks and, in what is called the geothermal reservoir. Geothermal
electricity involves a mature technology and a three year timeline between which a site is confirmed with
sufficient, high temperature water to drive a turbine, and the time a facility can produce electricity.
Geothermal energy is a clean energy source. The CO2 emissions from high-temperature geothermal fields
used for electricity production worldwide is lower comparing to other sources. Geothermal generation
emits 13 to 380 G/kWh as compared to 453 G/kWh emitted by natural gas, 906 G/kWh by oil and 1,042
G/kWh by coal.
As compared to other alternative and/or renewable sources, geothermal is independent of climate and/or
seasons, and can be used 24 hours a day. It can be converted to electric energy, or its heat can be used
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
16 - 8
Economics of the Energy Industries
directly. Electricity generation mainly takes place in conventional steam turbines and binary plants,
depending on the characteristics of the geothermal resource.
The world's largest geothermal resource region is The Geysers, located about 90 miles northeast of San
Francisco in Sonoma and Lake Counties, that has been in operation since 1960, and generates over 1,000
MW, the equivalent of a large nuclear reactor. Currently, geothermal resources are found in 25 countries
where around 8,400 MW installed capacity generated about 53 TWh of electricity in 2003 (see table
below).
El Salvador, Nicaragua and Iceland generate about 15% of their electric power from geothermal
resources. Although the U.S. is by far the largest in geothermal generation with more than 15 TWh
followed by the Philippines at nine TWh and Mexico with almost six TWh, the share of geothermal
generation in total is only 0.25% in the U.S. and 2% in Mexico. Another Central American country, Costa
Rica generates almost 8% of its electricity from geothermal facilities and Kenya receives more than 5% of
its electricity from its geothermal resources.
Cumulative Installed Geothermal Power Capacity at year-end* (Megawatts)
Argentina
Austria
Australia
China
Costa Rica
El Salvador
Ethiopia
France (Guadeloupe)
Germany
Guatemala
Iceland
Indonesia
Italy
Japan
Kenya
Mexico
New Zealand
Nicaragua
Papua New Guinea
Philippines
Portugal (The Azores)
Russia (Kamchatka)
Thailand
Turkey
USA
TOTAL WORLD
1990
1995
2000
2003
0.7
0.0
0.2
19.2
0.0
95.0
0.0
4.2
0.0
0.0
44.6
144.8
545.0
214.6
45.0
700.0
283.2
35.0
0.0
891.0
3.0
11.0
0.3
20.6
2774.6
5832.0
0.7
0.0
0.2
28.8
55.0
105.0
0.0
4.2
0.0
0.0
50.0
309.8
631.7
413.7
45.0
753.0
286.0
70.0
0.0
1227.0
5.0
11.0
0.3
20.4
2816.7
6833.4
0.0
0.0
0.2
29.2
142.5
161.0
7.0
4.2
0.0
33.4
170.0
589.5
785.0
546.9
45.0
755.0
437.0
70.0
0.0
1909.0
16.0
23.0
0.3
20.4
2228.0
7972.6
0.0
1.3
0.2
28.2
162.5
161.0
7.0
15.0
0.2
29.0
200.0
807.0
790.5
560.9
121.0
953.0
421.3
77.5
6.0
1931.0
16.0
73.0
0.3
20.4
2020.0
8402.3
Change
2002-03
n/a
n/a
0.0%
–1.1%
4.5%
0.0%
0.0%
52.9%
n/a
–4.6%
5.6%
11.0%
0.2%
0.8%
39.1%
8.1%
–1.2%
3.5%
n/a
0.4%
0.0%
47.0%
0.0%
0.0%
–3.2%
1.8%
2003 share of total
0.0%
0.0%
0.0%
0.3%
1.9%
1.9%
0.1%
0.2%
0.0%
0.3%
2.4%
9.6%
9.4%
6.7%
1.4%
11.3%
5.0%
0.9%
0.1%
23.0%
0.2%
0.9%
0.0%
0.2%
24.0%
100.0%
Source: BP, International Geothermal Association.
Alternative Transportation Technologies and Fuels
There are alternative fuels that are being used today for transportation purposes, in place of gasoline and
diesel fuel derived from crude oil. The major types of these "alternative fuels" are: liquefied petroleum
gas (LPG) and propane, natural gas, ethanol, methanol, electricity, hydrogen, biodiesel, and p-series fuels.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
16 – 9
Economics of the Energy Industries
Alternative fuels have two non-economic advantages - they produce lower emissions and can help reduce
dependence of on imported petroleum.
LPG (or Propane). When speaking of alternative fuels, the terms LPG and propane are often used
interchangeably. LPG for vehicular use is a mixture containing at least 90% propane, 2.5% butane and
higher hydrocarbons, and a balance of ethane and propylene. Propane is a by-product of natural gas
processing or petroleum refining. It is a gas at room temperature but turns to liquid when compressed.
Liquid propane is stored in special tanks that keep it under pressure (about 200 psi). Although stored
onboard vehicles as a liquid, propane is returned to a gaseous form before being burned in the engine.
Of all the alternative fuel types, propane has the largest percentage of converted vehicles. In addition,
vehicle manufacturers are committed to producing some new propane vehicles. These factors point to
steady, but slow, growth in the use of propane vehicles. Propane was introduced in the early 1900s. It is
now a leading alternative vehicle fuel and is used in over four million over-the-road vehicles around the
world. The U.S. is the largest LPG producer in the world. Over 95% of consumed propane in the U.S. is
produced domestically.
Compressed Natural Gas (CNG). CNG is natural gas that is stored in pressurized tanks and used as
vehicle fuel. CNG releases one-tenth as much of the pollutants such as CO and NOX as does gasoline. In
the U.S., state and city governments began encouraging public and private bus and truck fleets to switch
to CNG from diesel in the early 1990s. Thus far, CNG's use has been limited to larger vehicles because it
must be stored in bulky tanks. Cars that run on CNG cost about $3,000 more than gasoline-powered cars.
In 2001, about 1,250 U.S. service stations sold the fuel as compared to 900 in 1994.
Natural Gas Vehicles (2005)
Country
Argentina
Brazil
Pakistan
Italy
India
USA
China
Iran
Ukraine
Egypt
Colombia
Bolivia
Bangladesh
Venezuela
Russia
Armenia
Germany
Japan
Canada
Malaysia
Tajikistan
Ireland
Thailand
S. Korea
France
Sweden
Indonesia
Bielorussia
Chile
Moldova
Bulgaria
Trinidad & Tobago
Myanmar (Burma)
Mexico
Consumption
(MTOE)***
34
17
23
66
29
582
35
78
64
23
6
12
25
362
77
65
81
30
4
26
28
40
1
30
17
7
Production
(MTOE)***
40
10
21
12
27
489
37
77
17
24
6
8
12
25
530
15
165
49
18
66
3
43
25
7
33
Vehicles*
Refueling Stations
VRA**
1,459,236
1,035,348
870,000
382,000
248,000
130,000
97,200
91,314
67,000
63,135
60,000
45,000
44,534
44,146
41,780
38,100
33,000
25,000
20,505
14,900
10,600
9,780
9,000
8,619
7,400
6,709
6,600
5,500
5,500
4,500
4,177
4,000
4,343
3,037
1,400
1176
828
509
198
1,340
355
120
147
95
90
63
106
149
213
60
647
289
222
39
53
10
44
170
105
86
17
24
12
8
9
13
14
6
32
3,331
8
15
779
686
3,258
1
6
209
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
16 - 10
Economics of the Energy Industries
Switzerland
3
1,346
56
Australia
22
32
895
12
Spain
25
797
28
Poland
12
4
771
28
United Kingdom
88
86
543
31
Austria
9
500
68
New Zealand
3
3
471
12
Turkey
20
400
5
Czech Republic
8
390
16
Netherlands
39
62
348
8
Latvia
310
4
Belgium
300
5
Slovakia
6
250
7
Portugal
3
242
5
Hungary
12
202
13
Norway
4
71
147
4
Algeria
19
74
125
3
Croatia
100
1
Serbia & Montenergro
92
2
Finland
4
84
3
Yugoslavia
81
1
Nigeria
19
60
2
Iceland
45
1
Cuba
45
1
Greece
2
40
United Arab Emirates
36
41
35
Macedonia
32
1
Luxembourg
32
3
Liechtenstein
26
1
South Africa
22
1
Uraguay
20
Philippines
2
12
1
Singapore
7
7
1
Denmark
5
9
5
1
Taiwan
9
4
1
North Korea
4
1
Bosnia and Herzegovina
1
TOTALS
4,908,474
8,944
* Includes both OEM and converted NGVs
** VRA = Number of Vehicle Refuelling Appliances
*** - Data for 2004
Sources: BP Statistical Review of World Energy 2005 and International Association for Natural Gas Vehicles
89
55
21
18
115
58
6
394
5
60
4
4
3
1
9,158
Ethanol. Ethanol is ethyl alcohol, a grain alcohol mixed with gasoline and sold in a blend called gasohol.
Certain crops, such as corn and sugar cane, are fermented to make ethanol. Some studies have shown that
ethanol emits less CO and fewer hydrocarbons than pure gasoline.
Methanol. Methanol can be manufactured from a variety of carbon-based feedstock such as natural gas,
coal, and biomass (e.g., wood). Methanol is produced from natural gas in production plants with 60%
total energy efficiency. The use of methanol diversifies the fuel supply and reduces dependence on
imported petroleum. Methanol is transferred from import terminals or production facilities by barges, rail
or trucks. Methanol is predominantly produced by steam reforming of natural gas to create a synthesis
gas, which is then fed into a reactor vessel in the presence of a catalyst to produce methanol and water
vapor. Although a variety of feedstock other than natural gas can and have been used, today's economics
favor natural gas.
Electricity. Electricity is unique among the alternative fuels in that mechanical power is derived directly
from it, whereas the other alternative fuels release stored chemical energy through combustion to provide
mechanical power. Motive power is produced from electricity by an electric motor. Electricity used to
power vehicles is commonly provided by batteries, but fuel cells are also being explored. But unlike
batteries, which are storage devices, fuel cells convert chemical energy to electricity.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
16 – 11
Economics of the Energy Industries
Electric cars have been on the U.S. roads since the late 1800s, but they became largely extinct when gaspowered cars became the norm because of cost considerations. The primary attraction of electric cars is
that they do not emit pollutants. Their main problems, however, are power storage and vehicle range.
Electric cars must recharge their batteries every 90 miles or so. Also, in addition to paying a sticker price
up to three times that of a conventional car, electric car owners must buy a recharging system for between
$3,000 and $5,000.
In December 1996, General Motors Corp. introduced the first mass-produced electric car, the EV1, in
California and Arizona, which failed to establish a market for itself. Great Britain has the most electric
cars on its roads - about 25,000. Hybrid cars, however, are more readily accepted by the public. They
also depend mostly on electricity to run but since they are also equipped with an ICE, the problems
associated with pure electric vehicles such as the limited travel distance between each charge and low
performance in tougher road conditions are overcome.
Hydrogen. Although hydrogen can fuel an engine directly, or serve as a fuel additive, the current
emphasis is on the use of hydrogen to supply fuel cells, which power electric vehicles. Hydrogen has also
been blended with methane to form a fuel called Hythane.
Biodiesel. Biodiesel is another alternative fuel which contains no petroleum but can be blended to any
level with petroleum diesel to create a biodiesel blend. Biodiesel can be used in diesel engines with no
major modifications.
P-Series. Pure Energy Corporation's P-series fuels are blends of ethanol, methyltetrahydrofuran (MTHF),
and pentanes plus, with butane added for blends that would be used in severe cold-weather conditions to
meet cold start requirements. It is anticipated that both the ethanol and the MTHF will be derived from
renewable resources, such as waste cellulose biomass that can be derived from waste paper, agricultural
waste and urban/industrial wood waste.
Solar. Solar energy technologies use sunlight to produce heat and electricity. Electricity produced by
solar energy through photovoltaic technologies can be used in conventional electric vehicles. In order to
collect this energy and use it to fuel a vehicle, photovoltaic cells are used. Pure solar energy is 100%
renewable and a vehicle run on this fuel emits no emissions. Solar vehicles are not available to the
general public. Using solar energy directly to power vehicles has been investigated primarily for
competition and demonstration vehicles.
Economics of Alternative Generation Technologies
Renewable energy sources and technologies making use of them are very diverse. However, their
common tendency is to cost more than conventional technologies but to offer some attractive
characteristics, especially in terms of the environmental impact. The balance between relative costs and
desired attributes defines the place of each renewable in the portfolio of energy options. All forms of
alternative energy are always affected economically by oil prices. When oil prices are low, the alternative
energy becomes less desired and as oil prices increase, they become more viable and attractive. During
the 1970's oil embargo, the industrialized world encouraged alternative technologies and fuels. As a
result, solar power plants flourished and many new hydroelectric, wind, and nuclear plants were built.
Alternative technologies are generally characterized by relatively high capital costs and low operation and
maintenance costs, making them attractive in the long run, but less so in a competitive setting where the
premium is on near-term cost minimization. Advances in technologies continue to lower their cost and
increase their efficiency, but outside of small niche markets, they still are not economically competitive
compared to conventional sources of power.
A comparison of cost and performance of most advanced alternative technologies, including emissions
and efficiency (heat rate), to more conventional technologies of power generation is provided below. The
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
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Economics of the Energy Industries
cheapest of the alternative technologies in terms of capital cost is wind with $965 per kW capacity. Note,
however, that this level is reached after some economies of scale are established in the production of wind
turbines. This capital cost is fairly competitive with coal and nuclear plants, but it is significantly larger
(more than twice as expensive) than the cost of most modern gas-fired plants, which is the biggest
challenge for all alternative technologies. Natural gas resources all around the world is best utilized in
power generation. Low cost of gas-fired generation and relatively low level of emissions from these
plants are increasing the attractiveness of gas-fired plants (see Chapters 1 and 9 for details).
2002 Overnight Capital Cost (including Contingencies) and Performance Characteristics of
Different Generating Technologies
Technology
Capital Costs*
(2001$/Kwhr)
2002 Heat
Rates (Btu/Kwhr)
Online
Year**
Advanced Combustion Turbine
460
8,550
2004
Conventional Combustion Turbine
409
10,450
2004
Advanced Gas/Oil Combined Cycle
608
7,000
2005
Conventional Gas/Oil Combined Cycle
536
7,500
2005
Scrubbed Coal New
1,154
9,000
2006
Integrated Gas Combined Cycle
1,367
8,000
2006
Fuel Cells
2,137
7,500
2005
Advanced Nuclear
2,117
10,400
2007
Biomass
1,763
8,911
2006
Solar Thermal
2,594
10,280
2005
Solar Photovoltaic
3,915
10,280
2004
Wind
1,003
10,280
2005
*Overnight capital cost includes contingency factors, and exclude regional multipliers and learning effects. Interest
charges are also excluded. These represent costs of new projects initiated in 2002.
**Online year represents the first year that a new unit could be completed, given an order date of 2002.
Source: EIA Annual Energy Outlook 2003
Capital costs associated with other alternative technologies are very high, ranging from $1,763 per kW for
biomass (which is barely competitive with nuclear) to $5,289 for Solar Photovoltaic. Although fuel is
free for most of these technologies and hence the variable O&M is mostly negligible, fixed O&M costs
can also be very high. Even with wind fixed O&M costs reduces the competitiveness of this technology
against almost all of the conventional technologies.
When determining the fuel source for a new generation plant, it is important to study the "levelized" cost
to determine which technology and energy source will be the least costly. Levelized costing considers all
capital (capital costs are amortized over the expected power output for the life of the plant), fuel, and
operating and maintenance costs. Public authorities and energy planners tend to assess different energy
sources on the basis of the levelized cost. These calculations do not depend upon variables such as
inflation or taxation system. However, the perspective of private investors or utilities is different, and
takes into account the variables introduced by government policy and shifts in financial and foreign
exchange markets. These investors make decisions on project cash flows and payback time.
Hydro
Unlike other renewable resource options, hydropower, in particular large-scale facilities constructed
decades ago and whose initial cost have been paid off, is often the cheapest power source on the system.
Small-scale hydroelectric plant costs are equal to fossil alternatives. Modern hydro turbines can convert
as much as 90% of the available energy into electricity. The best fossil fuel plants are only about 60%
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
16 – 13
Economics of the Energy Industries
efficient. Hydropower does not experience rising or unstable fuel costs. From 1985 to 1990 the cost of
operating a hydropower plant grew at less than the rate of inflation.
Up to 20MW (small hydro) is suitable for small and/or remote communities, and, where implemented,
avoids emissions associated with fossil fuel fired technologies. Off-peak power from hydro is a resource,
and it is important to support engineering of the systems to combine it with other renewables so that this
resource is captured and stored, e.g., as hydrogen. Turbines, turbine generators, and turbine control
systems, which are now under development, represent a step toward the efficient models to be used in
2030.
The key factors relevant to the economics of a hydro development are:
•
initial capital outlay
•
long lifetime for the scheme
•
high reliability and availability
•
low running costs
•
no annual fuel costs
The cost of generation by existing large-scale schemes is estimated to be ¢0.75-0.90/kWh, calculated on
an historic costing basis. For small-scale schemes, in general the initial costs are lowest for sites with high
hydraulic heads. These costs increase as the hydraulic head decreases, while scheme viability decreases as
generating capacity decreases. The initial costs are, though, very dependent on the details of a particular
scheme. Land prices and rents vary according to local circumstances. If existing engineering structures
are used, capital costs can be considerably reduced.
Wind
There are two main influences which affect the cost of electricity generated from the wind, and therefore
its final price: technical factors, such as wind speed and the nature of the turbines (the windiness of the
site, wind turbine availability, and the way the turbines arranged so that they do not interfere with each
other), and the financial perspective of those that commission the projects, e.g. what rate of return is
required on the capital, and the length of time over which the capital is repaid. Annual electricity
production will vary enormously depending on the amount of wind on the turbine site. Therefore, there is
not a single price for wind energy, but a range of prices, depending on wind speeds.
Wind power is currently a viable technology under ideal site conditions, and rapid advancements in
technology will enable the growth and deployment of wind power to more marginal geographical areas,
using significantly less land resources. Wind energy generation is expected to increase in efficiency and
become a significant source of power by 2030. The technological focus will be turbines and systems.
With wind energy, and many other renewables, the fuel is free. Therefore once the project has been paid
for, the only costs are operation and maintenance and fixed costs, such as land rental. The capital cost is
high, between 75% and 90% of the total.
Public authorities and energy planners require the capital to be paid off over the technical lifetime of the
wind turbine, i.e. 20 years, whereas the private investor would have to recover the cost of the turbines
sooner or during the length of the bank loan. The interest rates used by public authorities and energy
planners would typically be lower than those used by private investors.
The economics of wind energy are already strong, despite the relative youth of the industry. Although the
cost varies between different countries, the trend everywhere is the same - wind energy is getting cheaper.
Power production costs for wind turbines have dropped 80% since the early 1980s and now costs of
generating electricity from the wind falls somewhere between ¢4-6 per kWh. Prices are projected to drop
another 20 to 40% over the next ten years. The cost is coming down for various reasons. The turbines
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
16 - 14
Economics of the Energy Industries
themselves are getting cheaper as technology improves and the components can be made more
economically. The productivity of these newer designs is also better, so more electricity is produced from
more cost-effective turbines. There is also a trend towards larger machines. This reduces infrastructure
costs, as fewer turbines are needed for the same output.
Capital Cost of Wind Power
Source: The British Wind Energy Association
The cost of financing such capital intensive energy as wind energy is also falling as lenders gain
confidence in the technology that have steadily progressed to a higher reliability level. However, capital
costs remain high compared to natural gas-based technologies. Combined with problems of intermittency,
lack of storage, cost of connecting to the grid and so on, these high costs makes financing of wind
projects a challenge without some kind of public sector support.
Nevertheless, the global wind energy market is expanding
rapidly, creating opportunities for employment through the
export of wind energy goods and services. It is estimated
that 950,000 MW of wind energy capacity will be installed
in the next 15 years supplying 12% of the electricity
worldwide.
Another way to calculate the economics of wind power is
by income to land owners. Each turbine represents about
Source: AIM PowerGen Corporation
$1,500 in additional income for a farmer that can still
continue the traditional agricultural practices on the 95%
of remaining land that is not impacted by dispersed wind turbines. For example, a 250-acre farm would
average about $40 per acre or a total of $10,000 annually from wind farming.
Solar
Solar power suffers from a high initial investment need. As solar cell efficiency increases, it will be more
cost effective to use the technology even in areas of low sunlight. PV electricity is currently expensive in
comparison to grid electricity; nevertheless it will be extremely valuable as an electricity source for
remote locations away from the grid. Especially in the developing world, where electricity grid is not well
developed and a greater percentage of the population live in rural areas, grid-independent generation
technologies can provide electricity faster to a greater number of people.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
16 – 15
Economics of the Energy Industries
By 2030, solar technology costs are expected to be competitive and by 2050, solar cell module prices are
expected to fall by half. Storage methodologies, expected to be fully developed by 2030, and parallel
connections to a grid will narrow the intermittence of the PV source. A key portion of the development
work will be on thin film semiconductors, the goals being increased efficiency of conversion and lifetime.
Geothermal
The EIA estimates that geothermal energy appears to be the least costly of the alternative technologies,
but there is very limited capacity available for development. Geothermal energy development of high
temperature (>180oC) for power generation typically involves some risk in the initial investigations to
prove the geothermal resource. Investment is required for exploration, drilling wells and installation of
plant, but operating costs are very low because of the free fuel. In comparison, fossil fuel station capital
costs are usually significantly cheaper than geothermal power stations, but fuel costs are very much
higher. Diesel powered generation plant capital costs for example are typically less than 50% of the cost
of geothermal plants.
Due to many influencing factors, geothermal power development project capital costs are very much site
and project specific. However, in general, geothermal power plants can produce electricity as cheaply as
some conventional power plants at ¢4.5-7 per kWh (a decrease from ¢8-10 per kWh in 1980). In
comparison, new coal-fired plants produce electricity at about ¢4 per kWh. About 40% of the cost of a
geothermal plant comes up-front in hardware; operations and maintenance costs are extremely low, and
the average life expectancy of a geothermal plant is about 30 years. Initial construction costs for
geothermal power plants are high because geothermal wells and power plants must be constructed at the
same time. But the cost of producing electricity over time is lower because the price and availability of
the fuel is stable and predictable.
Biomass
Although the technology used to generate electricity from biomass has become more efficient and cleaner
over time, not much can be done to lower the labor costs involved in the fuel collection process. The cost
of electricity from a new biomass power plant in the early 1980s was ¢10 per kWh, while today the costs
would be just under ¢5 per kWh.
The levelized cost of biomass power is about double that of wind and gas combustion turbines. The
biomass power cost, however, does not include any credit for waste disposal costs that might be otherwise
incurred. The cost to generate electricity from biomass varies depending on the type of technology used,
the size of the power plant, and the cost of the biomass fuel supply. Biomass power systems range in size
from a few kW for on-site generation units, up to 80 MW for power plants.
Limitations on locally available biomass resources generally make it uneconomical to exceed 100 MW in
size. Once advanced biomass power systems (gasification combined-cycles) become commercially
available, larger generation units will be more feasible. Today, co-firing (co-firing biomass with coal in
traditional coal-fired boilers) offers power plant managers a relatively low cost and low risk route to add
biomass capacity. These projects require small capital investments per unit of power generation capacity.
When low cost biomass fuels are used, co-firing systems can result in payback periods as low as two
years.
A typical existing coal-fueled power plant produces power for about 4 ¢/kWh. Co-firing inexpensive
biomass fuels can reduce this cost to 2.1 ¢/kWh. In today’s direct-fired biomass power plants, generation
costs are about 9 ¢/kWh. In the future, advanced technologies such as gasification-based systems could
generate power for as little as 5 ¢/kWh. For comparison, a new combined-cycle power plant using natural
gas can generate electricity for about 4 to 5 ¢/kWh.
For biomass to be economical as a power plant fuel, transportation distances from the resource supply to
the power generation point must be minimized, with the maximum economically feasible distance being
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
16 - 16
Economics of the Energy Industries
less than 100 miles. The most economical conditions exist when the energy use is located at the site
where the biomass residue is generated (i.e., at a paper mill, sawmill, or sugar mill). Modular BioPower
generation technologies under development by the U.S. Department of Energy and industry partners will
minimize fuel transportation distances by locating small-scale power plants at biomass supply sites.
Economics of Alternative Transportation Technologies and Fuels
There is a cost premium for each alternative transportation technologies over the ICE. In the case of
ethanol, the fuel is also more expensive. In terms of mileage, only LPG and electricity offer more miles
per gallon. Although maintenance costs can be lower for some (e.g., CNG and LPG), none of the fuels
appear to offer an absolute advantage over the ICE and gasoline when all of the factors in the table are
considered.
Comparison of Alternative Vehicle Fuels
CNG
LPG
Ethanol
Electricity
Biodiesel
Range (compared to
gasoline)
<20-50%
equal or greater
<10-30%
Power (compared to
gasoline)
equal or greater
equal
equal
slower
acceleration
equal to diesel
<10-30%
<10-20%
>20-70%
< 10-50%
depends upon
electric rates
> 20-40%
Fuel cost (compared to
gasoline)
Vehicle Maintenance &
life
Slightly longer
engine life
Vehicle conversion cost
$2,700 - 6,000
>100% (up to 80
equal to diesel
miles)
Special
Batteries changed
lubricants
every 30,000
Potentially
Slightly longer
required; more
miles; no oil
longer engine
engine life
life
frequent engine changes or tuneoverhauls
up
200-500% more
$1,000 - 2,500
$0 - $1000
than a standard None required
vehicle
Source: Platts Global Energy
LPG/Propane
Vehicle and fuel costs remain barriers to propane's widespread use as an alternative fuel. Many propane
vehicles are conversions, with conversion costs typically ranging between $1,000-$2,000. Propane retail
prices were consistent with unleaded gasoline prices during the 1990s, and future propane prices are
expected to be less than gasoline. Since propane prices tend to move along with oil prices, however,
propane prices can greatly fluctuate.
In 2005, there were an estimated 350,000 on-road propane vehicles in use in the United States. Although
that is the largest number among all alternative fuel types, propane vehicles experienced the slowest
growth between 1992 and 1998. As a result, propane has lost some of its market share. The greatest
concentration of propane vehicles is in the South, where large numbers are operated in the oil-producing
States of Oklahoma and Texas.
LPG retail prices are, on average, similar to that of unleaded gasoline prices. Cost averaged $2.56 across
the US in September 2005. LPG/propane is used in several different sectors, which makes direct
comparison to gasoline at the pump difficult.
Ethanol
Ethanol prices are closely tied to commodity prices for agricultural crops. In the U.S., where ethanol is
used as an alternative fuel (or as an additive to gasoline to create gasohol), retail prices of ethanol ranged
from $2.36-2.83/gallon in late 2005. Ethanol production is more costly on a per volume basis than some
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
16 – 17
Economics of the Energy Industries
other alternative fuels, although government tax incentives of about 54¢/gallon in the U.S., for example,
have kept prices comparatively low. Ethanol has lower energy content than gasoline; consequently, more
fuel is consumed per distance traveled. The price of ethanol is constrained because of corn feedstock,
which is closely tied to commodity prices for agricultural crops. For example, severe flooding of the
Mississippi River in 1993 directly impacted the corn crop in the Mississippi basin. This flooding resulted
in a short-term increase in the regional ethanol fuel price.
Methanol
While methanol contains just one-half the energy of gasoline, because the methanol fuel cell car has a
calculated fuel economy 1.74-times greater than a gasoline equivalent, the actual cost to the consumer to
fuel a methanol fuel cell vehicle is between 77-94¢ per gasoline-equivalent-gallon. At this price,
methanol is able to compete quite well with gasoline, and provides a significant return on investment to
retailers converting pumps to methanol operation.
In the last few decades, methanol prices, like gasoline, have experienced highs and lows, but on average,
methanol is substantially cheaper per gallon than gasoline. Since 1975, the average U.S. wholesale spot
price for methanol has been 46¢/gallon on a non-inflation-adjusted basis. The average retail costs are
about $1.20/gallon. Since it takes roughly 1.65 gallons of M-85 to provide equivalent energy content or
range as a gallon of gasoline, the effective cost to the consumer would be $1.87 per gallon. Given current
U.S. gasoline prices well about $3.00 per gallon, this is certainly an attractive price point. The cost of
methanol has been decreasing in real terms due to economies of scale achieved through the construction
of larger, more efficient plants and the distribution of methanol in much larger sea vessels.
The repair and maintenance costs of methanol vehicles are similar to gasoline vehicles, with the exception
of oil changes except for a special lubricant that is needed. Because the special oil is produced in limited
quantities, it is more expensive than regular oil.
CNG and LNG
Natural gas can be stored as either compressed (CNG) or liquid form (LNG). Although some vehicle
tests have been done using LNG, the development of CNG vehicles is far more advanced. Most of the
light-duty CNG vehicles in operation are gasoline vehicles that have been converted to operate on either
natural gas or gasoline. Converting a car or light truck for bi-fuel operation can cost anywhere from
$2,600 to $3,400 depending on the sophistication of the technology used to meter the natural gas and the
number and size of fuel storage tanks.
On an energy-equivalent basis, the price of LNG can be higher or lower than gasoline or diesel fuel. The
price is very much dependent on geographic location, purity, transportation and quantity. As a substantial
market for the fuel develops, LNG prices can be expected to decline. This would secure a more
affordable LNG refueling infrastructure and could enable economic use of large liquefaction plants.
In 1997, the U.S. federal government revised the excise tax on LNG to approximately $0.12 per LNG
gallon, the energy equivalent of gasoline at about $0.18/gallon. Previously federal excise taxation for
LNG was at the same rate per gallon as gasoline, with no recognition of LNG's lower energy density.
Heavy fuel consuming vehicles over 12,000 lb can pay a flat rate of $168 per year. Without this flat rate
incentive, a typical LNG truck using 33,333 gallons of LNG to travel 100,000 miles (at 3 miles per LNG
gallon) would pay as much as $2,000 in California State fuel excise taxes for example.
Vehicle maintenance costs are reduced as oil changes are required less frequently and spark plugs last
longer. Costs for a "slow fill" system or "quick fill" system to handle public or private fleets can cost
$250,000 or as much as $3 million for a bus fleet. A compressor station typically costs $2,000 to $4,000
per vehicle served.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
16 - 18
Economics of the Energy Industries
Costs for a compressor for use with a single vehicle in private homes averages about $3,500. Individual
home compressors use a slow-fill system for overnight refueling. These would usually be located in a
home's garage area and would be connected directly to the natural gas supply in the house.
Hydrogen
Currently, the cost of hydrogen derived from natural gas is approx $1.2/kg. Hydrogen costs about 50%
more than diesel fuel, on a cost per mile basis. When examining the cost of fuel cells, it is necessary to
address the vehicle fuel economy. Compared with conventional vehicles, fuel cell powered vehicles have
a better fuel economy, achieving as much as 80 miles per gallon. These improvements in fuel economy
are attributed to the fuel cell power systems. Vehicles equipped with methanol steam reformers are more
efficient.
Electricity
The operating cost of a vehicle run by electricity depends on vehicle efficiency and the available electric
rates. Fueling costs would also be lower especially if off-peak rates are taken advantage of. Recharging
an electric vehicle at $0.05 per kilowatt hour (kWh) equates to about $0.015 per mile on average
Maintenance costs like oil changes are virtually eliminated. Once the relatively high initial capital cost is
made, operation costs are much lower in the long term as these vehicles have fewer moving parts to
service and replace.
There is a significant savings in cost when an electric vehicle is leased rather than bought as all
maintenance and repair costs are covered by the lease agreement. As technology improves, buying an
electric vehicle may not be as feasible as the owner may find the technology obsolete after a couple of
years, whereas a lease period does not exceed the estimated life of the current technology.
P-Series fuel
At commercial scale production, Pure Energy Corporation claims that the price is competitive with that of
gasoline. However, commercial production of P-Series fuel is not expected until after 2001, according to
Pure Energy Corporation.
Biodiesel
The cost of biodiesel is largely dependent on the feedstock, which include soybeans and vegetable oil. A
study completed in 2001 by the U.S. Department of Agriculture found that an average annual increase of
the equivalent of 200 million gallons of soy-based biodiesel demand would boost total crop cash receipts
by $5.2 billion cumulatively by 2010, resulting in an average net farm income increase of $300 million
per year. The price for a bushel of soybeans is likely to increase by an average of 17¢ annually during the
ten-year period.
Solar
Sunlight is free. The cost involved in using solar energy comes from the cells and the design of systems
to make use of energy from these cells. To date, the commercial market for solar powered vehicles is
very limited and no solar-powered vehicles have been manufactured with a commercial intent.
Relevant Case Studies
Brazil Power Market Crisis
Hospital Power in Congo
LPG Subsidies in India
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
16 – 19
Economics of the Energy Industries
GLOSSARY
After-tax cash flow (ATCF) - Earnings after tax plus non-cash charges, such as depreciation and
deferred taxes.
Amortization - The systematic allocation of the of an intangible asset over its expected economic life or
some other period of time for financial reporting purposes, tax purposes, or both. (see
depreciation)
Business risk - The variability in a company’s operating earnings (EBIT).
Capital budgeting - The process of planning for purchases of assets whose cash flows are expected to
continue beyond one year.
Capital expenditure - The amount of money spent to purchase a long-term asset, such as a piece of
equipment. This cash outlay generally is expected to result in a flow of future cash benefits
extending beyond one year in time.
Capital markets - Financial markets in which long-term securities are bought and sold.
Capital rationing - The process of limiting the number of capital expenditure projects because of
insufficient funds to finance all projects that otherwise meet the firm’s criteria for acceptability
or because of a lack of sufficient managerial resources to undertake all otherwise acceptable
projects.
Cash flow - The actual amount of cash collected and paid out by a company.
Common pool problem - If a number of producers are extracting oil and gas from a common pool, they
each have an incentive to extract as much as they can in order to maximize their revenues.
Common stock - Shares in the ownership of a company. Common stock represents a residual form of
ownership in that dividends are paid out only after more senior financial obligations, such as
interest on debt, are fulfilled.
Compound interest - Interest that is paid not only on the principal but also on any interest earned but not
withdrawn during earlier periods.
Contingent project - A project whose acceptance depends on the adoption of one or more other projects.
Cost of capital - The equilibrium rate of return demanded by investors in the securities issued by a firm.
Depreciation - The systematic allocation of the cost of a tangible asset over its expected economic life or
some other period of time for financial reporting purposes, tax purposes, or both. (See
amortization)
Discount rate - The rate of interest used in the process of finding present values (discounting).
Dividend - The amount of money paid to the owner of stock in a company.
Economic life of natural resources - The amount of resources that can be extracted without raising costs
so as to justify the development of alternative resources (also see Geologic Life of Natural
Resources).
Expected return - The benefits (price appreciation and distributions) an individual anticipates receiving
from an investment.
Expected value - A statistical measure of the mean or average value of the possible outcomes.
Operationally, it is defined as the weighted average of the possible outcomes with the weights
being the probability of occurrence.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
Glossary - 1
Economics of the Energy Industries
Financial analysis - The utilization of a group of analytical techniques, including financial ratio analysis,
to determine the strengths, weaknesses, and direction of a company’s performance.
Financial forecasting - The projection and estimation of a company’s future financial statements.
Fixed costs - Costs that do not vary as the level of a firm’s output changes.
Future (terminal) value - The value at some future point in time of a present payment (or a series of
payments) evaluated at the appropriate interest (growth) rate.
Geologic life of natural resources - Amount of natural resources that is known to exist in the nature and
that can be extracted with no consideration of cost (also see Economic Life of Natural
Resources).
Hotelling rule - The undiscounted rent of exhaustible resources must rise at the rate of interest (also
known as r% rule).
Hurdle rate - The minimum acceptable rate of return from a project. For projects of average risk it is
usually equal to the company’s cost of capital.
Initial investment - The initial cash outlay required at the beginning of an investment project.
Interest - The return earned by or the amount paid to an individual who forgoes current consumption or
alternative investments and “rents” money to a business, bank, the government, some other form
of institution, or another individual.
Internal rate of return (IRR) - The discount rate that equates the present value of net cash flows from a
project with the present value of the net investment. It is the discount rate that gives the project a
net present value equal to zero. The IRR is used to evaluate, rank, and select from among various
investment projects.
Marginal cost of production - The cost of producing one additional unit of output.
Marginal cost of capital - The weight after-tax cost of the next dollar of capital a company expects to
raise to finance a new investment project.
Marketability risk - The ability of an investor to buy and sell an asset (security) quickly and without a
significant loss of value.
Market value - The price at which a stock trades in the financial marketplace.
Multinational corporation - A company with direct investments in more than one country.
Net present value (NPV) - The present value of the stream of net cash flows resulting from a project,
discounted at the firm’s cost of capital, minus the project’s net investment. It is used to evaluate,
rank, and select from among various investment projects.
Net working capital - The difference between a company’s current assets and current liabilities. The
term net working capital is used interchangeably with working capital.
Nominal interest rate - A market rate of interest stated in current, not real terms. Nominal interest rates
reflect expected inflation rates.
Opportunity cost - The rate of return that can be earned on funds if they are invested in the next best
alternative investment.
Present value - The value today of a future payment (or a series of future payments) evaluated at the
appropriate discount rate.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
Glossary - 2
Economics of the Energy Industries
Rent - The difference between the price of a unit of exhaustible resource and the marginal cost of
extracting that extra unit - opportunity cost of producing that unit today instead of tomorrow (also
see royalty and user cost).
Required return - The return (yield) an individual demands from an investment as compensation for
postponing consumption and assuming risk. Required return is often used interchangeably with
the term “hurdle rate.”
Risk - The possibility that actual future returns will deviate from expected returns; the variability of
possible returns from a project.
Risk-adjusted discount rate - A discount rate that reflects the risk associated with a particular project.
In capital budgeting, a higher risk-adjusted rate is used to discount cash flows for riskier projects,
whereas a lower risk-adjusted rate is used to discount cash flows for less risky projects.
Risk-free rate of return - The return required by an investor in a security having no risk of default; equal
to the sum of the real rate of return and an inflation risk premium.
Risk premium - The difference between the required rate of return on a risky investment and the rate of
return on a risk-free asset, such as U.S. Treasury bills. Components include maturity risk, default
risk, seniority risk, and marketability risk
Royalty - The difference between the price of a unit of exhaustible resource and the marginal cost of
extracting that extra unit - opportunity cost of producing that unit today instead of tomorrow (also
see user cost and rent).
Sensitivity analysis - A procedure used to evaluate the change in some objective, such as net present
value, to changes in a variable influencing that objective, such as product price, one of the cash
flow elements.
Socially optimal rate of extraction - The rate of production that maximizes not only returns to the
producer but also consumer surplus.
Simulation - A financial planning tool that models some event, such as the cash flows from an
investment project, often for the purpose of assessing the risk associated with the project. It is
also called Monte Carlo Simulation.
Systematic risk - That portion of the variability of an individual security’s return that is caused by factors
affecting the market as a whole. This also is called nondiversifiable risk.
Term structure of interest rates - The pattern of interest rate yields for debt securities that are similar in
all respects except for their length of time to maturity. The term structure of interest rates usually
is represented by a graphic plot called a yield curve.
Unsystematic risk - Risk that is unique to a company. This also is called diversifiable risk.
User cost - The difference between the price of a unit of exhaustible resource and the marginal cost of
extracting that extra unit - opportunity cost of producing that unit today instead of tomorrow (also
see royalty and rent).
More definitions can be found at http://www.eia.doe.gov/glossary/glossary_main_page.htm.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
Glossary - 3
Economics of the Energy Industries
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
Glossary - 4
Economics of the Energy Industries
Conversion factors
To Convert
Crude Oil *
tonnes (metric)
kilolitres
barrels
From
US gallons
tonnes/ year
Multiply by
Tonnes (metric)
1
1.165
7.33
307.86
-
Kilolitres
0.8581
1
6.2898
264.17
-
Barrels
0.1364
0.159
1
42
-
US Gallons
0.00325
0.0038
0.0238
1
-
Barrels/day
-
-
-
-
49.8
*Based on worldwide average gravity.
From
Products
barrels to tonnes
tonnes to barrels
kilolitres to tonnes
tonnes to kilolitres
Multiply by
LPG
0.086
11.6
0.542
1.844
Gasoline
0.118
8.5
0.740
1.351
Kerosene
0.128
7.8
0.806
1.240
Gas oil / diesel
0.133
7.5
0.839
1.192
Fuel oil
0.149
6.7
0.939
1.065
To Convert
Natural Gas &
LNG
billion cubic
metres NG
billion cubic
feet NG
From
1 billion cubic
metres NG
million tonnes oil
equivalent
million
tonnes LNG
trillion British
thermal units
million barrels oil
equivalent
Multiply by
1
35.3
0.90
0.73
36
6.29
1 billion cubic feet
NG
0.028
1
0.026
0.021
1.03
0.18
1 million tonnes oil
equivalent
1.111
39.2
1
0.805
40.4
7.33
1 million tonnes
LNG
1.38
48.7
1.23
1
52.0
8.68
1 trillion British
thermal units
0.028
0.98
0.025
0.02
1
0.17
0.16
5.61
0.14
0.12
5.8
1
1 million barrels oil
equivalent
Units of Measure
1 metric tonne = 2204.62 lb.
= 1.1023 short tons
1 kilolitre = 6.2898 barrels
1 kilolitre = 1 cubic metre
1 kilocalorie (kcal) = 4.187 kJ = 3.968 Btu
1 kilojoule (kJ) = 0.239 kcal = 0.948 Btu
1 British thermal unit (Btu) = 0.252 kcal = 1.055 kJ
1 kilowatt-hour (kWh) = 860 kcal = 3600 kJ = 3412 Btu
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
Conversion Factors - 1
Economics of the Energy Industries
Calorific equivalents
One tonne of oil equivalent equals approximately:
Heat units
10 million kilocalories
42 gigajoules
40 million Btu
Solid fuels
1.5 tonnes of hard coal
3 tonnes of lignite
Gaseous fuels See natural gas and LNG table
Electricity
12 megawatt-hours
One million tonnes of oil produces about 4500 gigawatt-hours (=4.5 terawatt hours) of electricity in a modern power station.
Tonnes = metric tons
The conversion factors above are taken from BP Statistical Review of World Energy 2003, which is
available at http://www.bp.com/centres/energy/definitions/units.asp. At the same web site, there is also a
conversion calculator available for most common units for crude oil and natural gas.
© 2006 by Center for Energy Economics, Bureau of Economic Geology, University of Texas at Austin. All Rights reserved.
Conversion Factors - 2