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Valuation of Oil Companies Elearning Module
11/12/2012
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Valuation of Oil Companies
Content Learning Outcomes ........................................................................... 3 Duration ......................................................................................... 4 Introduction .................................................................................... 5
Your Contact EVALUESERVE Ashutosh Ojha
What is crude oil? ....................................................................... 5
[email protected]
Oil Price Dynamics...................................................................... 9
Tel: + 91 124 4622336
Crude Oil Price Benchmarks ....................................................... 12 Oil Industry – Overview ............................................................ 14
Fax: + 91 124 4063430 Location: Gurgaon, India
Industry Structure .................................................................... 15 Petroleum Fiscal Regime.................................................................. 16 What‘s so typical about oil companies? .............................................. 19 Classification of Oil Companies ................................................... 19 Valuation of Oil Companies .............................................................. 34
EVALUESERVE Rajiv Dalal
[email protected] Tel: + 91 124 4622345
Valuation Methodologies ............................................................ 34
Fax: + 91 124 4063430
Operating Performance Indicators ............................................... 36
Location: Gurgaon, India
Case Study: Valuation of an Upstream Oil Company - NPV ................... 38 Relative Valuation and Benchmark Indicators ............................... 42 Appendix ...................................................................................... 43 Glossary ....................................................................................... 45 References .................................................................................... 46 Authors......................................................................................... 47 Evalueserve Disclaimer ................................................................... 48
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Valuation of Oil Companies
Learning Outcomes After reading the module, the candidate should be able: •
Understand the basics of the global crude oil industry, position of crude oil in the global energy mix, global production and consumption pattern, major crude oil consumers and producers, and geographical distribution of crude oil reserves
•
Understand crude oil pricing dynamics as well as the factors influencing global crude oil prices, including supply, demand, and geopolitical issues
•
Understand the various oil price benchmarks, such as Brent and WTI; the difference between the Brent and WTI benchmarks; pricing of WTI and Brent; and the reasons behind WTI–Brent differential
•
Explain a brief history of the oil industry and classification of oil companies
•
Develop basic understanding of production sharing contracts (PSCs), types of PSCs, key elements of PSCs, revenue and profit-sharing mechanism in a PSC and the concept of government take (share) for oil
•
Understand the upstream business model, exploration and development of oil reserves, classification of oil and gas reserves
•
Explain the revenue and cost structure of upstream oil companies and their accounting treatment for exploration and production costs
•
Explain the basics of the oil refining industry, various refining processes, revenue and costs metrics of a refiner, the concept of gross refining margins, the Nelson complexity index, the factors affecting refinery performance, and single and multiple crack spreads
•
Gain basic understanding of oil marketing operations, marketing value chain, distribution channels, and sensitivity of marketing margins with crude oil prices
•
Explain the basics of the oil services industry, particularly rig providers, and summarize average daily rates and utilization rates across different rig types
•
Learn the absolute and relative valuation techniques to value oil and gas companies, the concept of net asset value (NAV) and discounted cash flow (DCF) and other commonly used relative valuation methods, and key operating performance indicators
•
Learn to apply the NAV method to value an upstream oil and gas asset
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Valuation of Oil Companies
Duration The course should take 5 hours to complete.
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Valuation of Oil Companies
Introduction What is crude oil? Crude oil is a naturally occurring flammable liquid that has a complex mixture of hydrocarbons of various molecular weights and other liquid organic compounds found in geologic formations beneath the earth‘s surface. This fossil fuel is formed when large quantities of dead organisms are buried under sedimentary rocks and undergo transformation due to intense heat and pressure. Crude oil composition varies significantly from one oil source to another; four different types of hydrocarbon molecules appear in crude oil, and their percentages vary in different crude oil forms. Crude oil, which is usually found with natural gas, is recovered through oil drilling. Crude oil is refined and separated at the boiling point into a number of products, ranging from petrol (or gasoline) and kerosene to asphalt and chemical reagents used to make plastics and pharmaceuticals. The process through which crude oil is separated into its various by-products is known as cracking. Oil refinery cracking processes enable production of ―light‖ products such as liquefied petroleum gas (LPG) and gasoline from heavier crude oil distillation fractions such as gas oils and residues. Fluid catalytic cracking produces a high yield of gasoline and LPG, while hydro cracking is a major source of jet fuel, diesel, naphtha, and LPG. Thermal cracking is currently used to ―upgrade‖ very heavy fractions or produce light fractions or distillates, burner fuel, and petroleum coke. Crude oil is used to manufacture a wide variety of materials. The world consumes about 88 million barrels of oil per day (MMbbl/d). Oil – Key Element of Global Energy Mix Global energy consumption is divided into the following five segments: liquids (majorly oil), natural gas, coal, nuclear energy, and others (including hydro, wind, and solar). Oil accounts for one-third of the world‘s energy consumption and is expected to grow at a compound annual growth rate (CAGR) of 1% between 2011 and 2035, with strong growth expected from emerging markets. By 2035, the share of oil is expected to decline to 29%, due to strong growth in nuclear energy and other non-conventional sources of energy. However, oil will continue to account for a sizeable portion of the global energy mix, as there are challenges associated with producing other energy sources. For example, hydro power, wind power, and solar power cannot be produced everywhere. Further, while some energy sources (e.g., fuel cells) are yet to take off, others (e.g., coal reserves) are not present everywhere. There have been increasing concerns about nuclear power, especially after the 2011 tsunami, which led to incidents of nuclear radiation from the Fukushima power plant in Japan.
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Valuation of Oil Companies
Figure 1: Global Energy Demand, 2005 – 35(E)
1000
Figure 2: Global Energy Composition, 2011
Projections
Actual
Nuclear 6%
Other 11%
800 600
Liquids 33%
400 Natural Gas 22%
200 2005 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025 2027 2029 2031 2033 2035
0
Other
Nuclear
Natural Gas
Coal
Coal 28%
Liquids
Source: BP statistical review
Source: BP statistical review
Largest Oil Producer: Middle East Global crude oil production grew at a CAGR of 2.1% over 1965–11, with particularly strong growth in the Asia-Pacific region (4.9%), followed by Africa (3.0%), the Middle East (2.6%), Europe and Eurasia (2.5%), South and Central America (1.2 %), and North America (0.7%). In 2011, global crude oil production was 83.6 MMbbl/d, of which the Organization of the Petroleum Exporting Countries (OPEC) produced 35.8 MMbbl/d. By region, the Middle East is the largest producer of oil (33%), followed by Europe and Eurasia (21%), North America (17%), Africa (10%), Asia-Pacific (10%), and Central and South America (9%). By country, Saudi Arabia was the largest producer in 2011, with 11.2 MMbbl/d, followed by Russia (10.3 MMbbl/d) and the US (7.8 MMbbl/d). Largest Oil Consumer: Asia-Pacific The increase in global crude oil consumption was driven by strong demand in Asia-Pacific (4.8%), the Middle East (4.8%), Africa (4.1%), and South and Central America (3.0%). This growth in consumption was also driven by the increasing pace of development in emerging markets. In 2011, global petroleum consumption was 88.03 MMbbl/d, of which OECD alone consumed 45.9 MMbbl/d, or 52%. By region, Asia-Pacific is the largest consumer of oil (32%), followed by North America (26%), Europe and Eurasia (22%), the Middle East (9%), Central and South America (7%), and Africa (4%). By country, the three largest consumers are the US (18.8 MMbbl/d), China (9.8 MMbbl/d), and Japan (4.4 MMbbl/d). Figures 3 to 10 show the production and demand patterns in the evolution of the oil industry, including the current scenario. Figure 3: Global Oil Production (MMbbl/Day)
Figure 4: Global Oil Consumption (MMbbl/Day)
90
Source: BP statistical review
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Source: BP statistical review
2010
2007
2004
2001
1998
1995
1992
1989
2010
2007
2004
2001
1998
1995
1992
1989
1986
1983
1980
1977
1974
1971
1968
1965
0
1986
10
1983
20
1980
30
1977
40
1974
50
1971
60
1968
70
1965
100 90 80 70 60 50 40 30 20 10 0
80
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Valuation of Oil Companies
Figure 5: Global Oil Production by Region, 2011
C. & S. America 9% Asia Pacific 10%
Figure 6: Global Oil Consumption by Region, 2011
C. & S. Africa America 4% 7%
Middle East 33%
Middle East 9%
Africa 10%
Europe & Eurasia 22%
Europe & Eurasia 21%
North America 17% Source: BP statistical review
Figure 7: Top 10 (MMbbl/Day), 2011
Asia Pacific 32%
North America 26%
Source: BP statistical review
Oil
Producing
Countries Figure 8: Top 10 (MMbbl/Day), 2011
12 10 8 6 4 2 0
Oil
Consuming
Countries
20 16 12 8 4
Germany
South Korea
Brazil
Saudi Arabia
Russia
India
Japan
China
US
Iraq
Kuwait
Mexico
UAE
Canada
China
Iran
US
Russia
Saudi Arabia
0
Source: BP statistical review
Source: BP statistical review
Figure 9: Oil Consumption by Product Group, 1965
Figure 10: Oil Consumption by Product Group, 2011
Others 16%
Others 22%
Light distillates 30%
Light distillates 32%
Fuel oil 10%
Fuel oil 26% Middle distillates 28% Source: BP statistical review
Middle distillates 36% Source: BP statistical review
Top Five Countries Account for 45% of Global Oil Production In 2011, the world‘s five largest producers – Saudi Arabia, Russia, the US, Iran, and China – represented nearly 45% of global oil production. Figure 11 provides global production statistics by country for the year 2011. During the year, global oil production increased 1 MMbbl/d (1.3% y-o-y), with OPEC countries recording majority growth, offsetting weak production from Libya. Output from countries such as Saudi Arabia, the UAE, and Qatar reached a record high in 2011, while that from non-OPEC countries was broadly flat. Among non-OPEC countries, production increased in the US (reaching its highest level since
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Valuation of Oil Companies
1998), Canada, Russia, and Colombia. But the increase in production was broadly offset by a decline in production in the UK and Norway as well as unexpected outages in some other countries. While global oil consumption increased 0.6 MMbbl/d in 2011, this was one of the weakest growth rates among fossil fuels. China recorded maximum consumption growth in 2011, although the growth rate was below its 10-year average. Figure 11: Global Oil Production by Country, 2011 Rank
Oil Production
Thousand
Rank
Oil Production
Barrels/Day
Thousand Barrels/Day
1
Saudi Arabia
11,161
26
Argentina
607
2
Russian Federation
10,280
27
Malaysia
573
3
US
7,841
28
Ecuador
509
4
Iran
4,321
29
Australia
484
5
China
4,090
30
Libya
479
6
Canada
3,522
31
Sudan
453
7
United
3,322
32
Thailand
345
Arab Emirates 8
Mexico
2,938
33
Syria
332
9
Kuwait
2,865
34
Vietnam
328
Iraq
2,798
35
Republic
295
10
of Congo (Brazzaville) 11
Venezuela
2,720
36
Equatorial Guinea
252
12
Nigeria
2,457
37
Gabon
245
13
Brazil
2,193
38
Yemen
228
14
Norway
2,039
39
Denmark
224
15
Kazakhstan
1,841
40
Turkmenistan
216
16
Angola
1,746
41
Brunei
166
17
Algeria
1,729
42
Peru
153
18
Qatar
1,723
43
Trinidad and Tobago
136
19
United Kingdom
1,100
44
Other South and
134
Central America 20
Indonesia
942
45
Chad
114
21
Azerbaijan
931
46
Italy
110
22
Colombia
930
47
Romania
88
23
Oman
891
48
Uzbekistan
86
24
India
858
49
Tunisia
78
25
Egypt
735
Source: BP Statistical review
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Valuation of Oil Companies
Middle East Accounted for 48% of Global Oil Reserves in 2011 An oil reservoir includes both producible and non-producible oil, which together are referred to as oil in place. Due to limitations in petroleum extraction technologies and reservoir characteristics, only a fraction of this oil in place can be brought to the surface. This producible fraction is called the ―reserve‖. These reserves are broadly classified into two categories – proven and unproven. Proven reserves are those from which oil can be recovered using existing technology and under the current economic and political environment. The remaining reserves are termed as unproven reserves. Unproven reserves are further classified as probable and possible reserves. Probable reserves have a known accumulation of oil and a 50% chance of recovery, while possible reserves are those with less possibilities of recovery. Since 1980, the world‘s proved oil reserves have increased by more than 100%, with particularly strong bases in South and Central America, followed by Africa and the Middle East. Over the past decade, there has been a strong movement in the percentage of global proved reserves from the Middle East to South and Central America, led by a few major findings in Venezuela. In 2011, total proved reserves amounted to 1,652.6 billion barrels, of which nearly 48% were in the Middle East, followed by South and Central America (20%) and North America (13%). Figures 12–14 provide statistics on the current global oil reserve scenario. Figure 12: Global Oil Reserves, 2000–11 (Million Figure 13: Global Oil Reserves by Region, 2011 Barrels)
1800 1600 1400 1200 1000 800 600 400 200 0
Africa Asia Pacific Europe & 8% 2% Eurasia 9% Middle East 48%
Asia Pacific Europe & Eurasia South and Central America
2011
2010
2009
2008
2007
2006
2005
2004
2003
2002
2001
2000
Nort America 13%
South and Central America 20%
Africa North America Middle East
Source: BP statistical review
Source: BP statistical review
Source: BP statistical review Figure 14: Global Proved Oil Reserves by Region, 2000–11 (%)
Asia Pacific Africa Europe & Eurasia North America South and Central America Middle East Total proved reserves
2000 3% 7% 8% 18% 8% 55% 1257.9
2001 3% 8% 8% 18% 8% 55% 1267.4
2002 3% 8% 8% 17% 8% 56% 1321.9
2003 3% 8% 9% 17% 7% 56% 1340.0
2004 3% 8% 9% 17% 8% 56% 1346.2
2005 3% 9% 9% 17% 8% 56% 1357.0
2006 3% 9% 8% 16% 8% 55% 1364.5
2007 3% 9% 10% 16% 9% 54% 1404.5
2008 3% 9% 9% 15% 13% 51% 1475.4
2009 3% 9% 9% 14% 16% 50% 1518.2
2010 3% 8% 9% 13% 20% 47% 1622.1
2011 2% 8% 9% 13% 20% 48% 1652.6
Source: BP statistical review
Oil Price Dynamics How Crude Oil Prices are Determined Global oil demand and supply patterns significantly influence the oil market, along with a number of other geo-political factors. Prices of petroleum products such as gasoline, diesel, heating oil, jet fuel and lubricants are relative to crude oil prices.
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Valuation of Oil Companies
Demand Side The world is divided into two major categories on the basis of the demand for oil – OECD and non-OECD. The OECD bloc consists of the US, a major part of Europe, and other developed countries. These large economies consume more than 50% of global oil (45.9 MMbbl/d in 2011); however, their rate of consumption growth is very low. The transportation sector in OECD countries accounts for the majority of oil consumption. As a result, any economic instability and changes in policies that affect the transportation sector have a significant impact on oil consumption in these countries. The developing countries that are not part of the OECD are collectively known as non-OECD. These countries utilize a greater proportion of their economic activity in manufacturing industries, which are more energy-intensive than service industries. Although oil consumption by the transportation sector in these countries is usually lower than in OECD countries, it is rapidly increasing, in line with their economic growth. In other words, non-OECD countries have a high rate of consumption growth. Oil consumption in OECD countries fell from 63% in 2000 to 52% in 2011, whereas in the non-OECD bloc, it increased from 37% in 2000 to 48% in 2011, led by China, India, and Saudi Arabia. Due to relatively slower economic growth and a more mature transportation sector, the impact of prices on the consumption of OECD countries is more evident than it is on the consumption in non-OECD countries. Supply Side Changes in crude oil production by OPEC countries can have a significant impact on oil prices. The organization consists of countries such as Saudi Arabia, Iran, Iraq, Kuwait, Libya, the UAE, Nigeria, Algeria, Angola, Ecuador, Qatar, and Venezuela. OPEC member countries produce c.40% of the world's crude oil. Also, OPEC's oil exports represent c.57% of the total petroleum traded internationally. The organization possesses about two-thirds of the world‘s estimated crude oil reserves and has a significant spare oil production capacity. It influences oil production and, consequently, oil prices, by setting limits on production by member countries. Historically, multiple reductions in the OPEC production targets have led to an increase in oil prices. Non-OPEC members such as North America, regions of the former Soviet Union, and the North Sea collectively account for 60% of the world production, taking independent decisions about oil production. Production activities in the non-OPEC bloc are carried out by international or investor-owned oil companies (IOCs), unlike OPEC, where oil production is controlled by national oil companies (NOCs). Producers in non-OPEC countries are generally price takers, as they respond to market prices rather than attempting to influence prices by managing production. As a result, non-OPEC countries tend to produce at or near full capacity and therefore have little spare capacity.
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Valuation of Oil Companies
Figure 15: Global Oil Production (OPEC and Non- Figure 16: Global Oil Consumption (OECD and NonOPEC), 2011 OECD), 2011
OPEC 43%
Non-OECD 48% OECD 52%
Non-OPEC 57%
Source: BP statistical review
Source: BP statistical review
Other Factors Other factors that influence oil prices are the inventory balance of countries, natural disasters, political instability in oil producing countries (e.g., the recent political uprising in Libya and the Iran–US conflict or historically the Gulf War in the 1990s influenced crude oil prices) and seasonal demand and supply changes (refer to Figure 17, which shows the impact of geo-political issues on crude prices). Historical Price Trend In the short term, demand and supply of oil is inelastic to changes in oil prices. Therefore, any event that may lead to disruption or create uncertainty in the supply or demand of oil, such as political unrest or natural disasters, can greatly impact oil prices. Figure 17 shows the fluctuations in oil prices due to 12 major global events over the past 40 years. The most notable disruptions were caused by the Iran–Iraq war in the early 1980s; Iraq‘s invasion of Kuwait in 1990; the global financial crisis in 2008–09; and most recently, the political unrest in Nigeria, Venezuela, Iraq, Iran, and Libya. WTI (a light crude oil) prices increased five-fold from $25/bbl in the 1990s to more than $125/bbl in 2008. However, during the global recession in 2008–09, oil prices fell from an all-time high of $145/bbl to a low of $35/bbl. The steep decline in oil prices was due to decreasing oil demand and uncertainty in global economic growth. However, with recovery in economic growth, oil prices began to improve, averaging at $95/bbl in 2011.
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Valuation of Oil Companies
Figure 17: Movement of Crude Prices due to Geopolitical and Economic Events
Source: EIA, 1: US spare capacity exhausted, 2: Arab Oil Embargo, 3: Iranian Revolution, 4: Iran-Iraq War, 5: Saudi’s abandon swing producer role, 6: Iraq invades Kuwait, 7: Asian financial crisis, 8: OPEC cuts production targets 1.7 MMbbl/d, 9: 9/11 attacks, 10: Low spare capacity, 11: Global financial collapse, 12: OPEC cuts production targets 4.2 MMbbl/d
Current Price Trend Though oil prices averaged at more than $100/bbl in Q1 2012, they declined to below $100 in Q2 2012 because of market concerns related to global economic growth. In Q3 2012, crude prices rebounded and averaged at about $110, led by the seasonal tightening of oil markets and continuing unexpected production outages. Figure 18: Crude Oil Price Movement, 2012
130 120 110
100 90 80 Jan-12 Feb-12 Mar-12 Apr-12 May-12 Jun-12 Jul-12 Aug-12 Sep-12 Oct-12 Source: Bloomberg finance LP
Crude Oil Price Benchmarks Crude oil is differentiated and priced on the basis of internal characteristics such as American Petroleum Institute (API) gravity and sulfur content, as well as the geographic location of its production. Lowdensity (high API) and low-sulfur content (sweet) crude oil is priced at a premium as it can be used more cost effectively to derive high-value refined products.
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Valuation of Oil Companies
Globally, more than 300 different types of crude oil are produced, each with different characteristics. The two primary benchmarks are West Texas Intermediate (WTI) and Brent Blend. Variants of crude are priced by assigning a benchmark oil price (such as WTI or Brent) and then making adjustments to account for the differences in quality, location, proximity to refineries, transportation costs, etc. WTI WTI is a light crude oil with API gravity of 39.6 and specific gravity of 0.827. It is described as light because of its relatively low density, and sweet because of its low sulfur content (0.24%). WTI is used as a benchmark in oil pricing and is the underlying commodity of Chicago Mercantile Exchange (CME)‘s oil futures contracts. WTI is refined mostly in the Midwest and Gulf Coast regions of the US and is listed as WTI, Cushing, Oklahoma. WTI Pricing The pricing mechanism used for WTI is simple. Due to the lack of significant forward market, the physical spot price for WTI is solely based on the NYMEX light sweet oil futures front-month contract. The futures contract has a contract size of 1,000 barrels, and the delivery point is Cushing, Oklahoma. Most futures contracts are just financial transactions which are settled before their expiry. A small percentage of contracts are physically settled. On the expiry date, the reported WTI price includes the new front-month futures price and the cash costs of rolling the futures contract. Brent Brent crude is a light crude oil with an API gravity of 38.06 and a specific gravity of 0.835. It contains 0.37% of sulfur and is classified as sweet crude, but it is not as sweet as WTI. Brent is suitable for production of petrol and middle distillates. It is also an acronym for the formation layers of an oil field: Broom, Rannoch, Etieve, Ness, and Tarbat. It is sourced from the North Sea and is typically refined in Northwest Europe. It is used as a benchmark for petroleum production from Europe, Africa, and the Middle East. It is used to price two-thirds of the internationally traded crude oil supplies. To enhance the trade volumes on exchanges, three additional North Sea crudes have been added to Brent: Forties, Oseberg, and Ekofisk. Brent Pricing Brent pricing is more complex than WTI pricing and depends on the liquidity in the derivatives market. The key step is the assessment of the spot price (delivery for 10–25 days forward) for the physical delivery of Brent, commonly known as ‗Dated Brent‘, and is taken as the reference point. When the forward markets are liquid, Dated Brent prices are derived from 25-day Brent Forwards, which represent physically deliverable OTC contracts. Brent futures are used to price Dated Brent when the forward markets lack sufficient liquidity. ICE (Intercontinental Exchange) Brent futures prices are combined with exchange of futures for physicals (EFPs) values to derive synthetic Brent forward prices, which are then used to calculate Dated Brent prices. Forward Dated Brent Curve for up to eight weeks ahead is constructed using contract-for-difference (CFD) prices. CFD prices are short-term swaps between floating prices and fixed Dated Brent forward prices. Implied Dated Brent prices for 10–25 days forward can be calculated using this curve. Prices of the four categories (i.e., Brent, Forties, Oseberg, and Ekofisk) are calculated on the basis of implied
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Valuation of Oil Companies
Dated Brent and grade differentials. The published Brent price is the lowest price of the four variants, which is generally Forties, as it is the lowest in quality. WTI–Brent Differential The prices of many crude oil streams produced globally tend to move closely together, although there are persistent differentials between light-weight, low-sulfur (light-sweet) grades and heavier, higher-sulfur (heavy-sour) crudes that are lower in quality. Historically, oil prices of various benchmarks across the world have traded closely to avoid any arbitrary profits. However, in 2011, a temporary shortage of refining capacity led to a large stockpile of oil at the Cushing, Oklahoma storage. This stockpile caused WTI prices to be artificially depressed against other benchmarks such as Brent. While Brent prices increased because of civil unrest in the Middle East, WTI prices declined as the stockpile at Cushing could not be transported to the Gulf Coast for export. During the period, WTI prices averaged at $95/bbl, while Brent was priced at $111/bbl. As a result of the price differential, WTI temporarily lost its status as a barometer of world oil prices. The price differential between WTI and Brent still continues, but the gap is expected to decrease gradually, as additional pipeline capacities, such as the Seaway expansion and the southern leg of Keystone XL, come on stream. Figure 19: WTI Brent Price Differential
Source: EIA
Oil Industry – Overview Oil and gas play a very critical role in driving the global economy. The origin of the modern oil industry dates back to the late 19th century. The invention of the kerosene lamp in the mid-1850s led to the establishment of the first US oil company, the Pennsylvania Rock Oil Company of Connecticut. The company started its drilling operations in 1859 at Titusville; additional discoveries near these wells led to the creation of a number of oil companies and rapid growth in the oil industry. Oil replaced most of the other existing fuels for motorized transport, and the global automotive industry adopted oil as its primary source of energy.
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Valuation of Oil Companies
Some of the major oil companies founded in the 19th century include the following: •
Standard Oil Company: Founded in 1870
•
Gulf Oil: Founded in 1890
•
Texaco: Founded in 1901
•
Royal Dutch Shell: Founded in 1907
•
Anglo-Persian Oil Company: Founded in 1909
•
Turkish Petroleum Company: Founded in 1910
Standard Oil of New Jersey became Exxon, Standard Oil of New York became Mobil, and Standard Oil of California is now known as Chevron. These oil giants, along with Royal Dutch Shell, Texaco, Gulf, and BP, are known as the ―seven sisters.‖ At the beginning of the 20th century, oil production was dominated by three regions: the US, Russia, and the Dutch East Indies (Indonesia). During the first decade of the 20th century, major efforts were made to explore, develop and produce oil in the Middle East region. Oil exploration began in Iran, followed by Turkey, Kuwait, and Saudi Arabia. Industry Structure The oil and gas industry is divided into the following four sub-segments: •
Upstream (exploration, development and production of crude oil or natural gas)
•
Refining (oil tankers, refiners, retailers, and consumers)
•
Marketing
•
Services
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Valuation of Oil Companies
Petroleum Fiscal Regime The petroleum fiscal regime is basically the contract or the system that decides the ownership of oil assets, the percentage share of production and the government mechanism of taxing the production from a commercial discovery. While there are numerous types of contracts, the following two types are more common: 1. Concessions or Royalty/Tax System: A concession is an agreement between the host government or one of its agencies such as a national oil company (NOC) and a contractor (an oil exploration company or a consortium) that grants the contractor exclusive rights to produce hydrocarbons from designated oil field/block for a specified period. In return, the contractor pays a signature bonus or license fee to the government. Once the commercial discovery is established, the contractor also pays royalties/taxes, as per the terms of the contract. In such contracts, the ownership of hydrocarbons occurs at the wellhead, and there are typically no costrecovery limits. This system is used in a number of countries, including the US, the UK, Norway, France, Russia, Australia, New Zealand, Argentina, and South Africa. 2. Production sharing contracts (PSC): This is an agreement between the government or one of its agencies, such as an NOC, and a contractor (an oil exploration company or a consortium) that gives the contractor exclusive rights to explore hydrocarbons from a designated block, over a specified period. The contract states the share each party will receive from the commercial production of hydrocarbons from the designated field. Typically, in these contracts, the oil company bears the exploration, production, and development costs in return for its stipulated share of production. The contractor can recover these expenses (known as cost oil) in case of a commercial discovery. The amount left after deducting cost oil is called profit oil, and is split between the government and the contractor (i.e., 85% government share and 15% contractor share), as per the terms of the PSC. If stipulated in the PSC, the share of the contractor may vary with international oil prices or the production rate. The contractor bears the exploration costs in case commercial recovery is not feasible from the designated field. The concept of PSCs originated in Indonesia in the 1960s. These contracts are very popular in the Middle East and Central Asia. They act as a guiding document for defining responsibilities, resource-sharing mechanism, and liabilities of the parties to the agreement. These contracts can help countries that lack the resources (technical and/or financial) to develop oil resources. Key Elements of PSC: The key components in most PSCs are highlighted in the following figure. The terms and provisions of the contracts may vary case to case.
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Valuation of Oil Companies
Figure 20: Key Elements of PSC
Initial license area
Work obligation
Contract Term
Measurement and valuation of
Allocation of production
Royalties
Cost oil
Profit oil
Signature bonus
Other bonuses*
Tax rates
Export duty
Dispute resolution mechanism
Training and technology transfers
Health safety and environment
hydrocarbons
(arbitration)
clauses
* Depending on the establishment of commercial discovery, production start-up or achievement of a certain production threshold
Division of Revenue and Profits in PSC: The division of profits is the key element of a PSC. Profit refers to economic profits, i.e., gross revenue less costs for obtaining that revenue. The government may get its share of profits in one or all of the following ways: •
Signature bonus or other bonuses
•
Royalties
•
Profit-based split
•
Income tax
Figure 21 explains the division of profits with an example, including some of the elements mentioned above. In this example, we have assumed 15% royalty (paid by the contractor to the government) on gross production to arrive at net production. From net production, the contractor is allowed to deduct the various costs incurred in developing the oil field. These costs include capital expenditure (capex) and operating expenditure (opex), and are referred to as cost recovery or cost oil (in our example, we have assumed cost recovery as 30% of gross production). Most of the PSCs have cost-recovery limits, which (along with royalties) guarantee minimum payout to the government, regardless of whether or not economic profits are generated. The deduction of cost recovery from net production gives profit oil (also known as equity oil). Profit oil is the share of production available to all the stakeholders in the field. The government‘s share is deducted from profit oil to calculate the contractor‘s share. The contractor also pays corporate taxes on his share of profit oil. Thus, the government‘s share includes royalties (15%), share of profit oil (33%), and corporate taxes (7.7%), while the contractor‘s share includes cost recovery (30%) and post-tax share of profit oil (14.3%). In this example, the government‘s total share is 55.7% (15%+33%+7.7%), while the contractor‘s share is 44.3% (30%+14.3%) of the gross production. Figure 21: Division of Revenue/Production Accounting Hierarchy PSC Terminology Gross Production
100.0
Royalty (15%)
-15.0
Net Production
85.0
Cost Recovery (30% of gross production)
-30.0
Profit Oil
55.0
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Valuation of Oil Companies
PSC Terminology Govt. Share of Profit Oil (60%)
-33.0
Contractor Share of Profit Oil (40%)
22.0
Income Tax (35%) Contractor Share (Net of Taxes)
7.7 14.3
Source: Evalueserve
Risk Service Contract (RSC): This is an agreement between the government and a contractor (generally an oil exploration company) that performs the oil exploration on a designated block for a specified fee, over a stated period of time. The principal difference between an RSC and a PSC is the ownership of assets (oil blocks). In case of an RSC, the ownership remains with the government, and the contractor is paid for its services with no right to the hydrocarbons produced from the designated block. Practically, pure RSCs are rare, with the only notable example being the Iranian oil buy-backs. (In these contracts, foreign companies are allowed to make the initial investment in oil projects in Iran, and these companies subsequently recover the initial investment through the exploitation of the projects‘ final product: crude, gas, or refined products). Government Take (Share) for Oil: Figure 22 illustrates the petroleum fiscal systems adopted in different countries. The government take varies from 30% to 90% in different countries; the trend has been towards a higher take in the production of hydrocarbons. The government take is the highest in the Middle East, Africa, and Venezuela and the lowest in Ireland, Peru, and Morocco. Figure 22: Government Take for Oil
Source: Journal of World Energy Law and Business (JWELB), Independent Petroleum Association of America
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Valuation of Oil Companies
What‘s so typical about oil companies? Classification of Oil Companies Upstream Companies Upstream oil companies are engaged in the exploration of a potential natural resource field (oil and gas), development of the field after successful discoveries, and commercial production of oil/gas from the developed natural resource field. The process of survey, exploration, development, and commercial production takes 3–4 years at each stage. The life cycle of an oil field is explained in Figure 23. Figure 23: Oil Field Life Cycle
Source: Petroleumonline
Exploration The exploration phase of an offshore field generally takes 3–5 years and involves the following steps: 1. Design a seismic plan 2. Submit the plan to the government authority for approval 3. Move seismic vessels into the survey field after obtaining approval and deploy steamers to obtain a 3D seismic survey of the area 4. Set the motor of the vessel to fire air-guns at regular intervals (every 10–20 seconds) 5. Detect the echo from the sedimentary layer below the sea bed using hydrophones and store the data in magnetic tapes for further analysis 6. Analyze the data to create a sonic graphic image of the area under survey; the pattern of contour lines are used by geologists to determine the location suitable for the drilling of oil or gas Development of Reserves Development involves drilling production wells and constructing infrastructure such as platforms, processing plant pipelines, and export terminals. This stage involves major capital expenditure outlays. The selection of drilling platforms depends on circumstances, from shallow waters to deep seas. It also depends on the depth at which the oil/gas is explored.
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Valuation of Oil Companies
The following are different types of drilling platforms: 1. Fixed platforms 2. Compliant tower 3. Sea star 4. Floating production systems 5. Tension leg platform 6. Sub-sea systems
7. SPAR platform Figure 24 provides a classification of drilling platforms, based on depth for deepwater systems. Figure 24: Types of Offshore Drilling Platform, Based on Depth of Field
Source: U.S. Minerals Management Service
A fixed platform (FP) is feasible for water depths of up to 1,650 feet and is supported by piles driven into the seabed. A compliant tower (CT) is a narrow, flexible tower that can operate in water depths of up to 3,000 feet. The sea star, or a floating mini-tension leg structure, is suitable for smaller reservoirs and operates in water depths of up to 3,500 feet. The floating production system (FPS) is anchored in place and can be dynamically positioned, using rotating thrusters. Connected to wellheads on the ocean floor, this system can be used in water depths of up to 6,000 feet. Subsea systems (SS), connected to nearby platforms, can operate at great depths. However, the drilling and completion cost penalties of subsea systems make these arrangements less preferable than floating structures.
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Valuation of Oil Companies
Classification of Oil and Gas Reserves Reserves are the major assets of upstream oil companies. Figure 25 provides a broad classification of reserves. Figure 25: Resource Classification System
Source: Society of Petroleum Engineers
Reserves are broadly classified into the following two categories: 1. Recoverable reserves (discovered commercial and discovered sub-commercial) 2. Unrecoverable reserves (undiscovered) Recoverable reserves are further classified into the following sub-categories: •
Proved Reserves (1P): The term refers to estimated quantities of oil and gas that are reasonably certain to be recovered from a reservoir under favorable economic conditions, i.e., prices and costs. Reserves are classified under 1P if it is considered economically viable to extract oil from them. The area of the reservoir that is outlined for drilling, along with adjoining regions analyzed through geological and engineering data, is considered as proved reserves. It is also referred to as P90, i.e., having 90% certainty of being produced.
•
Proved plus Probable Reserve (2P): These reserves include proven reserves as well as reserves that are not yet proven but have more than a 50% chance of being economically and technologically productive.
•
Proved plus Probable plus Possible Reserves (3P): These reserves include proven reserves as well as reserves that are not yet proven and reserves that cannot be categorized as proven reserves and have less than a 50% chance of being economically and technologically productive.
Undiscovered Reserves: These include reserves that are yet to be discovered. Monte Carlo simulation techniques are used to determine the lower and upper bound of such reserves. In the absence of other significant information about such reserves, the lower bound is considered as their estimated value.
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Valuation of Oil Companies
Oil and Gas Accounting Metrics Revenue Metrics Revenues of upstream companies are highly dependent on the quantum of oil produced and industry price levels. Production, in case of upstream companies, mainly comprises crude oil, natural gas, and natural gas liquids. Oil prices across the industry are dependent on the global demand and supply of oil, economic conditions, production quotas imposed by OPEC, and supply interventions. The price of natural gas is closely aligned with the demand and supply condition in respective regional markets. Cost Structure The following are some of the major costs associated with an upstream oil company: •
Acquisition Cost: This refers to the cost incurred in the course of acquiring the rights to explore, develop, and produce oil or natural gas. It includes expenses related to either the purchase or leasing of the right to extract oil and gas from a property not owned by the company. Also included in acquisition costs are any lease bonus payments paid to the property owner, along with legal expenses, and title search, broker, and recording costs.
•
Exploration Cost: This refers to the costs incurred for the purpose of determining the existence, location, extent, quality, or economic potential of a mineral deposit. It also includes costs associated with drilling a well, and are considered as intangible or tangible. Intangible costs are usually those incurred before the installation of drilling equipment, whereas tangible drilling costs are those incurred while installing and operating the equipment.
•
Development Cost: This refers to the costs incurred in the preparation of discovered reserves for production, such as the construction or improvement of roads to access a well site, with additional drilling or well-completion work, and installing other needed infrastructure to extract (e.g., pumps), gather (pipelines), and store (tanks) the oil or natural gas from reserves.
•
Production Cost: This refers to the costs incurred while extracting oil or natural gas from reserves. It includes wages for workers and electricity for operating well pumps.
Accounting for Costs Successful Efforts Method The successful efforts (SE) method allows a company to capitalize only those expenses that are associated with successfully locating new oil and natural gas reserves. For unsuccessful results, the associated operating costs are immediately charged against revenue for that period. This method assumes that the ultimate objective of an oil and gas company is to produce oil or natural gas from reserves that it locates and develops, so that only those costs relating to successful efforts get capitalized. On the contrary, as there is no change in productive assets with unsuccessful results and therefore costs incurred with this effort should be expensed. Full Cost Method The full cost (FC) method allows all operating expenses relating to locating new oil and gas reserves— regardless of the outcome—to be capitalized. This method conveys that the dominant activity of an oil
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23
Valuation of Oil Companies
and gas company is the exploration and development of oil and gas reserves. Therefore, all costs incurred in pursuit of that activity should first be capitalized and then written off over the course of a full operating cycle. Refining Introduction Refiners separate derivative products from crude oil. Major global refining players include Koch Industries, Exxon, BP Plc, Royal Dutch/Shell, Chevron Texaco, and Conoco Philips. However, the refining business has been dominated by major integrated oil players such as Exxon, ConocoPhillips, Shell, and BP, with their combined distillation capacity of ~25% of the total supply. Historically, Europe and the US have been the dominant regions in the refining industry, with a majority of the capacity in these regions. However, over the past two decades, most Greenfield projects and capacity additions have been happening in developing regions, particularly China. The advantages of high volume growth, coupled with easy access to raw materials (especially in the Middle East), have resulted in sharp capacity growth in Asia. China now controls 12% of global refining capacity, and the remaining Asian countries contribute 20%. The US still remains the global refining capacity leader, with 19% of capacity. Figure 26: Global Refining Capacity by Region, Figure 27: Global Refining Capacity by Region, 2011 1965–11 Mbd 35
China 12%
30
US 19%
25 20
Asia ex China 20%
15
Rest of America 11%
10 5
Africa 3%
US Middle East
Rest of America Africa
2011
2009
2007
2005
2003
2001
1999
1997
1995
1993
1991
1989
1987
1985
1983
1981
1979
1977
1975
1973
1971
1969
1967
1965
0
Middle East 9%
Europe Asia ex China
Source: BP statistical review
Europe 26%
Source: BP statistical review
Refining: Capital-Intensive and Low-Margin Business Refining, the least preferred business of oil companies, is characterized by high capital, low margins (34%), low growth, environmental issues, and political sensitivity. However, if managed efficiently with limited capital, the refinery business can generate strong cash flows and decent returns on invested capital. Throughout the past century, oil demand has been pretty strong, thereby generating handsome returns from the refining business. However, there have been times when demand has dropped, resulting in low operating rates and pressure on profitability – most recently during the 2008–09 financial crisis, when demand declined by 1.14 Mbd and operating rates slumped to ~80%.
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Valuation of Oil Companies
Figure 28: Refining Demand, Capacity, and Operating Rates Mbd 100
% 88%
95
86%
90
84%
85
82%
80
80%
75 78%
70
76%
65
74%
55
72%
50
70%
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 2006 2007 2008 2009 2010 2011
60
Consumption (LHS)
Refinery Capacity (LHS)
Operating rate (RHS)
Source: BP statistical review
Refining Process Refining is the process of converting crude oil into usable products such as LPG, gasoline, kerosene, diesel, lubricating oil, and petroleum coke. The function of an oil refinery is to convert crude oil into products with more commercial value. Different refiners, depending on the location and configuration of a refinery and the type of crude, follow different procedures.
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Valuation of Oil Companies
Figure 29: Summary of Major Refining Processes Process name
Action
Method
Purpose
Feedstock (s)
Product (s)
Fractionation Processes Atmospheric distillation
Separation
Thermal
Separate fractions
Desalted crude oil
Vacuum distilation
Separation
Thermal
Separate w/o cracking
Atmospheric tower residual
Gas, gas oil, distillate, residual Gas oil, lube stock, residual
Conversion Processes - Decomposition Catalyst cracking Alteration
Catalytic
Upgrade gasoline
Gas oil, coke distillate
Gasoline, petrochemical feedstock
Coking
Polymerize
Thermal
Convert vacuum residuals
Gas oil, coke distillate
Gasoline, petrochemical feedstock
Hydro- cracking
Hydrogenate
Catalytic
Convert to lighter HC's
Hydrogen steam reforming
Decompose
Catalytic/Thermal
Produce hydrogen
Lighter, higher quality products Hydrogen, CO, Co2
Steam cracking
Decompose
Thermal
Crack large molecules
Visbreaking
Decompose
Thermal
reduce viscosity
Gas oil, cracked oil, residual Desulfurized gas, O2, steam Atm tower heavy fuel/ distillate Atmospheric tower residual
Upgrade low-octane naphtha Convert straight chain to branch
Coker/ hydro-cracker naphtha Butane, pentane, hexane
High oct. Reformate/ aromatic Isobutane/ pentane/ hexane
Sour gas, HCs w/CO2 & H2S Crude oil Liq Hcs, LPG, alky feedstk Cycle oils & lube feedstocks High-sulfur residual/ gas oil Residuals, cracked HC's Lube oil base stocks
Acid free gases & liquid HCs
Vac. tower residual, propane Vac. tower lube oils
Heavy lube oil, asphalt
Gas oil, reformate, distillate Untreated distillate/gasoline
High-octane gasoline
Conversion Processes - Alteration or Rearrangement Catalytic reforming Alteration/ Catalytic dehydration Isomerization Rearrange Catalytic Treatment Processes Amine treating
Treatment
Absorption
Desalting Drying & sweetening
Dehydration Treatment
Absorption Absorption/ Thermal
Furfural extraction
Solvent extr.
Absorption
Hydrodesulfurization
Treatment
Catalytic
Hydrotreating
Hydrogenation
Catalytic
Phenol extraction
Solvent extr.
Absorption/ Thermal
Remove acidic contaminants Remove contaminants Remove H2O & sulfur cmpds Upgrade mid distillate & lubes Remove sulfur, contaminants Remove impurities, saturate HC's Improve visc. index, color
Solvent deasphalting
Treatment
Absorption
Remove asphalt
Solvent dewaxing
Treatment
Cool/ filter
Solvent extraction
Solvent extr.
Absorption/ precip.
Remove wax from lube stocks Separate unsat. oils
Sweetening
Treatment
Catalytic
Remv H2S, convert mercaptan
Cracked naphtha, coke, residual Distillate, tar
Desalted crude oil Sweet & dry hydrocarbons High quality diesel & lube oil Desulfurized olefins Cracker feed, distillate, lube High quality lube oils
Dewaxed lube basestock
High-quality distillate/gasoline
Source: United States Dept. Of Labor
Oil Refinery Fractional Distillation Process Distillation is the process of separating crude into different hydrocarbon groups of different boiling points. Crude oil is heated and products are separated based on their boiling points. The following are the two types of distillation that are normally performed: 1. Atmospheric Distillation: Crude oil is heated at a temperature of 350–400°C. Lighter products such as LPG, naphtha, and gasoline are derived at the lowest temperature, followed by kerosene and diesel. Heavy products are recovered at a temperature of about 350°C. 2. Vacuum Distillation: Residue is further transferred to a second distillation column to recover additional heavy distillates. Hydrocarbons with boiling points close to 450°C are separated without partially breaking them into unwanted products such as coke and gas.
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Valuation of Oil Companies
Figure 30: Oil Refinery Crude Distillation Process
Source: http://www.bbc.co.uk/schools/gcsebitesize/science/aqa_pre_2011/rocks/fuelsrev3.shtml
Conversion Conversion or upgrading alters the chemical structure of hydrocarbons to match the requirements of the market. For example, if the output from crude includes 30% gasoline and 40% residue, a more sophisticated refinery using conversion can alter the product slate to 65% gasoline and 5% residue. Treatment Process After refining, various treatment methods are used to remove non-hydrocarbons, impurities and other constituents in order to improve the efficiency of the conversion process as well as the quality and properties of gasoline. Revenue Sources of Refiners Refining companies primarily derive their revenue from the following services: •
Refinery services: Companies may enter into refining operations, which involves removing sulfur from natural gas and hydrocarbon stream.
•
Pipeline transportation: Pipeline transportation includes the transportation of crude oil, natural gas, and carbon dioxide for a fee, all of which require a different set of pipelines.
•
Industrial gases: Companies may also supply carbon dioxide to industrial customers.
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Valuation of Oil Companies
•
Supply and logistics: Companies often provide terminaling, blending, storing, marketing, gathering, and transporting of oil, and other supply and logistics services to third parties.
Earnings of refining oil companies are closely tied with the fee they charge for transportation of crude oil, which is regulated by the government. Pipeline revenues are a function of the level of throughput, the particular point where crude oil was injected into the pipeline, and the delivery point. Cost Structure A refiner incurs costs specific to its operations. These costs include the following: •
Pipeline operating costs
•
Transportation costs
•
Development costs
Gross Refining Margin: Key Profitability Indicator Gross refining margin (GRM) is an indicator of the profitability and margin trend of a downstream company. It shows the incremental revenue that can be earned by converting crude oil into end products and is calculated by subtracting crude price from the price of refined products. Gross margins of a refinery are influenced by various factors, including crude oil composition and prices and complexity of refinery. Different refined products have different market values. Gasoline and diesel typically sell at a premium to heavy fuel oils. At times of rising crude prices, transport fuel prices move up due to lack of substitutes. But in the case of heavy fuels, the upside is limited due to the availability of alternatives (coal and natural gas). As a result, refineries equipped to convert lower-value products into higher-value products enjoy extra benefits and higher GRMs. Ideally, differences in the composition of crude should reflect in the prices of different crude oils. For example, light crude trades at a premium to heavy crude, as it contains products with higher commercial value. However, not all refineries are equipped to process heavier, sour blends; therefore, during times of tight supply of light, sweet oil, refiners that can process heavy, sour crude will have an edge over others. Factors Affecting Refinery Performance Although all refineries convert crude oil into petroleum products, profitability of one refinery may differ from another. As discussed, refiners can modify their processes to alter output slate. Refinery complexity plays a major role in determining margins, followed by other factors such as the type of crude oil, location of refinery, method of crude delivery, and the overall efficiency of the refinery. •
Refinery Configuration: While a simple refinery has more rigid product yield and is focused only on crude oil distillation, a complex refinery is equipped with catalyst crackers, hydrocrackers, and fluid cokers that can change the product output slate. A complex refinery has the flexibility to shift toward a more commercially valuable output slate by producing more highvalue products. Complex refineries also have the flexibility of using lower-priced crude. However, complex refineries are more capital-intensive and may not necessarily match the returns on capital of a simple refinery.
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27
Valuation of Oil Companies
•
Nelson Complexity Factor: Developed by Wilbur L Nelson in 1960–61, the Nelson Complexity Factor is the most recognized and commonly used measure of refinery complexity. It describes the proportion of secondary conversion unit capacities relative to primary distillation. A factor of one is assigned to the primary distillation unit, and all other units are rated in terms of their cost and complexity relative to the primary unit. The complexity of a refinery is calculated by adding the complexity of each piece of refinery equipment – ―complexity factor x unit capacity/crude distillation capacity‖.
•
Crude Choice: The second most important factor affecting the profitability of a refinery is the type of crude available. Lighter crude contains more commercially valuable products, such as gasoline and naphtha, than heavy crude. Sweet crude has less sulfur content, making it more cost-effective, as sour crude attracts extra cost to eliminate sulfur. As light, sweet crude has an advantage over heavy, sour crude, the refining industry is more inclined toward processing light, sweet crude such as Brent and WTI over Russian Urals and Mexican Maya. Therefore, in a tight demand-and-supply market (high demand or less light, sweet crude supply), refiners equipped to process heavy, sour crude find themselves in an advantageous position over simple refiners, which experience sharp rise in costs and low margins due to their inability to process heavy crude.
•
Location: There is a major difference between coastal and inland plants. Coastal refiners have the advantage of low crude supply costs and better access to export markets, whereas inland refiners are generally closely located to high-demand areas and may be specifically configured to cater to that market. Moreover, location affects freight, product dispatch, labor, and environmental compliance costs.
Crack Spreads GRMs per barrel for a refinery are commonly referred to as crack spreads. These spreads are an important indicator of the profitability of a particular market or region, as they are calculated using global oil and local end-product prices. Crack spread calculation depends on the configuration of the plant and can be calculated using either a single product or multiple products. •
Single-Product Crack Spread: A single-product crack spread is the difference in the price of a barrel of crude oil and a single refined product. The most common single product spread is the gasoline crack spread.
Figure 31 compares the crack spread for Singapore naphtha, gasoline, jet kero, and diesel with Dubai Fateh crude prices.
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29
Valuation of Oil Companies
Figure 31: Singapore Product Crack Spreads vs. Dubai Fateh Crude Prices 20
USD/bbl
15 10
5 0 -5 -10
Naphtha
Gasoline
Jet Kero
Q1FY13
Q4FY12
Q3FY12
Q2FY12
Q1FY12
Q4FY11
Q3FY11
Q2FY11
Q1FY11
Q4FY10
Q3FY10
Q2FY10
Q1FY10
-15
Diesel
Source: Bloomberg
•
Multiple Product Crack Spread: It is the difference between the value of the weighted average of multiple refined products and a barrel of crude oil. The most commonly quoted multiple product crack spread is the 3:2:1 crack spread, which compares three barrels of crude oil with two barrels of gasoline and one barrel of distillate.
2004–08: Golden Period of Refining Profitability The 2004–08 periods is referred to as the golden period for refining profitability. Continued strong demand growth, coupled with higher utilization rates, led to higher margins and returns from refining. However, the global financial crisis of 2008–09 brought an early end to the dream run, with refining margins dropping to pre-2004 levels. Demand declined after two-and-a-half decades, and operating rates also dropped sharply. Supply of bio fuels for blending and NGL production further added to the downward pressure on margins. Since 2008, utilization rates have remained low, and with many refiners closing down units, there has been a slight recovery in margins. Figure 32: Refining Margins by Region, 2000-11 $/ bbl 25 20 15 10 5 0
2000
2001
2002
USGC
2003
2004
NEW
Source: BP statistical review
Marketing Marketing: Stable Low-Margin Business
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2005
2006
2007
2008
2009
2010
Singapore Medium Sour Hydrocracking
3Q11
1Q11
3Q10
1Q10
3Q09
1Q09
3Q08
1Q08
3Q07
1Q07
3Q06
1Q06
3Q05
1Q05
3Q04
1Q04
3Q03
1Q03
3Q02
1Q02
3Q01
1Q01
3Q00
1Q00
-5
2011
30
Valuation of Oil Companies
Marketing refers to distribution and sale of refined crude oil products to retail and wholesale customers beyond the refinery gate. The marketing operation is the public face of an oil company, as people working in this function directly interact with the general public on a day-to-day basis. The key role of marketing is to secure the end markets for products from refining operations. The main players in the marketing value chain include the marketing company, wholesalers, retailers, industrial/commercial customers, and retail customers. Marketing companies generally sell their products directly or through dealer-owned franchisee networks. •
Direct Selling: Under this model, the company may sell its products directly to customers through a chain of company-owned and -operated retail outlets. The advantage of this sales model is that the company gets to deal directly with customers. But this model requires large investment in retail outlets, which should be located in the right places to attract volumes.
•
Franchise Network: Under this model, a company selects a dealer, who invests in setting up retail outlets and sells the company‘s product, following strict guidelines.
The distribution channel may also be classified based on whether the product is sold directly to the end customer or to wholesalers and retailers, who then sell it to end customers. Figure 33: Marketing Value Chain
Pump prices
Crude Oil
Refiners Gross Refining Margins
Wholesalers Wholesaler Margins
Retailers
End customer
Retailer Margins
Total Marketing Margin: Wholesaler margin + Retailer margin
Source: Evalueserve
Volumes: Key to Success in Marketing Business Marketing is a large-volume, but low-margin business. Marketing margins typically range from 1% to 2%. Given the low margins, volumes are the key to success in this business. This highlights the importance of having well-located retail outlets. Marketing Margins Impacted by Crude Oil Prices, but not as much as Refining Margins Marketing margins are affected by changes in crude oil prices. Margins are negatively affected when crude prices increase as it takes time to pass on the cost to customers, while crude prices are adjusted immediately, thus increasing the input cost. In some cases, retail prices may be regulated by the government (e.g., diesel prices in India). This implies that there can be significant delay in passing on this cost to customers. Conversely, marketing companies make good margins in a declining oil price scenario, as benefits (lower costs) are often passed on with a delay. Marketing margins are normally stable on an annual basis, although there could be significant volatility in the short term, due to changes in the prices of refinery output (e.g., run-up in the prices of refined products ahead of the driving season
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Valuation of Oil Companies
in the US). However, the overall volatility in marketing margins is lower than the volatility in refining margins. Oil services Introduction The oil service industry is the backbone of upstream oil companies. It provides rigs to integrated oil companies and exploration and production (E&P) integrated companies on a contractual basis. Some of the other services provided by the oil service industry include seismic testing, transport services, and directional services. The revenue stream of the oil service industry depends on the revenues, profits, and capital spending of independent and integrated oil companies and E&P companies whose revenues and profits are closely interlinked with customer needs. The capital investment in exploration, seismic activity, drilling activity, and construction generally increases in periods of economic expansion, when the demand for oil and its various derivatives increase. Factors that contribute to increased capital spending in the oil and gas exploration industry include current and estimated hydrocarbon prices, oil and gas demand expectations, upstream cash flow, and reservoir depletion rates. Figure 34 shows the expected increase in global E&P spending in 2012 (vs. 2011A), with all regions increasing their E&P spending. Some of the major oil services companies are Schlumberger Ltd, Halliburton, and Baker Hughes Inc (BHI). Figure 34: Worldwide E&P Capital Spending by Region, 2011–12 ($ Billion)
$140 $116
$126
$120
$102
$101 $92
$100
$87 $75
$80
$64
$60 $38
$40
$38
$43
$38 $41
$48
$26 $28
$23 $26
$20 $23
$20
$9 $7 Others
NA independents
India, Asia & Australia
2012E
Russia
Europe
2011A
Middle East
Africa
LatAM
Supermajors (Int'l Spending)
Canada
United States
$0
Source: Barclays
Activity Numbers The health of the global oil and gas industry is determined by the utilization numbers of rigs, of the total rig fleet. BHI, one of the major service oil and gas companies, provides rigs to oil and gas operators around the world. The company also provides ample data on its rigs contracted and rigs fleet, and percentage utilization by region. Rigs are utilized based on the topography of the exploration area and are classified into the following two broad categories: •
Onshore rigs
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Valuation of Oil Companies
•
Offshore rigs
Onshore rigs are used to explore oil and gas below the land surface, while offshore rigs are generally used to explore oil and gas beneath the sea bed. Rigzone provides and manages data on rig fleet by region and type, as well as the average daily rates for contracting a particular type of offshore rig. Figures 35 and 36 provide information on offshore rig fleet by region and type for CY2012. Figure 35 provides information on the utilization levels worldwide in CY2012 (the ratio of rigs contracted to rig fleet)—highest in Europe (90%) and lowest in North America (41%). Figure 36 shows the highest utilization for semi-submersible rigs and the lowest for submersible and inland barge. Figure 36: Offshore Rig Fleet by Rig Type 100%
600
80%
500
41%
100
40% 20%
Rigs Contracted
Rig Fleet
S America
N America
M. East
Europe
Australia
Asia
0%
Africa
0
% Utilization
Source: Rigzone
63%
76%
58%
56%
57%
60%
46%
300
80%
40%
200
0%
100
20%
18%
0
0%
Rigs Contracted
Rig Fleet
Tender
60%
47%
400
Submersible
64%
Semisub
200
70%
69%
Platform Rig
75%
Jackup
300
100%
Inland Barge
90%
Drill Barge
400
Drillship
Figure 35: Offshore Rig Fleet by Region
% Utilization
Source: Rigzone
Rigs are contracted by various operators, depending on the type of rig and the depth at which the operator is required to carry out the extraction of oil/gas. Figure 37 and 38 classify rig fleet and rigs contracted by operators and the average rate for each rig type, depending on the depth and type of rig, for CY2012. The highest average daily rate in the drillship and semisubmersible category is $449K for drillship type rigs (at 4,000 feet water depth [WD]).
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33
Valuation of Oil Companies
Figure 37: Drillship and Semisubmersible Rigs
120
Figure 38: Average Day Rate for Drillship and Semisubmersible Rigs 111
$409,000
67
61
60
$289,000
$300,000
$260,000 $229,000
40 20
$449,000
$400,000
75
80
$500,000
93
92
100
6
9
8
$200,000
15
0
$100,000
Drillship
