Valuation of Oil Companies

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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

www.evalueserve.com | © 2013 Evalueserve. All Rights Reserved


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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Duration The course should take 5 hours to complete.


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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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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


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




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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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%


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



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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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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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 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


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.



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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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%



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.



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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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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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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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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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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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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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



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.


19


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.


20


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.


21


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


22

23


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


Europe 26%


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%.


24


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)


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.


25


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.



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.


26


•

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.


27


•

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.


28

29


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


Marketing Marketing: Stable Low-Margin Business


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


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


31


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


32


•

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]).


33


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 <4000' Drillship 4000' WD + WD

Semisub < 1500' WD

Rigs Working

Semisub 1500' Semisub 4000' + WD + WD

Drillship Drillship 4000' <4000' WD + WD

Total Rig Fleet

Semisub < Semisub 1500' Semisub 4000' 1500' WD + WD + WD

Average Day Rate

Source: Rigzone

Source: Rigzone

Jack-up rigs are classified into independent-leg cantilever rigs and mat-supported cantilever rigs. Figure 37 shows rig fleet and rigs contracted, based on the depth below sea level. Figure 38 shows the average daily rates for these rigs. The highest average daily rate is $152,000 for independent-leg cantilever rigs. Figure 39: Average Day Rate for Jack-up Rigs

$152,000

$160,000

$140,000 $120,000 $100,000

$84,000 $84,000 $89,000

$80,000

$75,000 $60,000

$60,000

$72,000

$70,000 $38,000

$40,000

$48,000

$20,000 $0

IC < 250' IC 250' WD WD

IC 300' IC IS 250' WD 300'+WD WD

IS 300' IS 300' + MC <200' MC 200' MS 200' WD WD WD +WD +WD

Average Day Rate Source: Rigzone



Valuation of Oil Companies The valuation of oil and gas companies is tricky as we do not assume the cash flows until perpetuity. We determine the resources and reserves (of various types) with different possibilities and probabilities. This section explains the different valuation methodologies for E&P companies. Valuation Methodologies The business of E&P companies depends on the prevailing market prices, as they are price takers. Production and capex decisions are based on the current and future price expectations of commodities. Typically, we do not use cash flow or income-based approaches to value E&P companies. The following are the two methodologies used for valuation: •

Absolute valuation

•

Relative valuation

Absolute Valuation Absolute valuation involves a fundamental analysis of the company in consideration. It requires information about the past performance and the prevailing economic and industry conditions to forecast revenue and cost structure. We use an NAV model instead of a DCF model to value companies. DCF is more suitable for valuing companies that are focused on refining, marketing and selling or cater to E&P companies as a services company. DCF is not an appropriate methodology to value E&P companies because their assets deplete and they are not expected to generate profits indefinitely. In addition, E&P companies have high capex requirements, which may sometimes result in negative free cash flows (FCF). NAV, which is an alternative to DCF, is more appropriate for valuing upstream oil companies. NAV The NAV model assumes that the company being analyzed operates and makes an economic profit from its existing reserves, which obviates the need for additional expansionary capex in the future. This model is typically built to value an asset with a finite life. We can obviously model different growth and degrowth assumptions (explained in more detail in the case study). All assets are valued separately and added to derive the value of a company. NAV considers the present value of post-tax cash flows from reserves (usually at a 10% discount) as well as the present value of cash flows from future exploration activity. The calculation is dependent on the company‘s undeveloped acreage and drilling prospects in that acreage, which calls for a careful study. The steps to value an oil or gas asset through this method are as follows: 1. We estimate reserves, production, oil price, and discount rates on the basis of information available in company filings or from specific databases such as Woodmac. Please refer to the case study on ABC Corp. presented in Figure 41 for assumptions. The case study shows that the life of the company‘s assets is until 2052, with growth until 2021, followed by a decline in the later years. One can also determine the asset life based on reserve life ratio (R/P ratio). We use the industry standard of a 10% discount rate. 2. We estimate commodity prices and map production by year. Reserves deplete due to production every year. The estimated realized price is multiplied by production to arrive at annual revenue


34


from different commodities. A sum total of various commodity revenue streams results in the combined revenue for each year over the life of the asset. 3. We estimate other expenses such as production and development expenses and tax rates. We exclude overhead expenses such as SG&A and expenses that fall into the corporate category. 4. Finally, all cash flows are discounted by the discount rate, using the Net Present Value (NPV) function. 5. All other assets are valued using the techniques applicable to that particular asset and summed up to arrive at the final enterprise value (EV). 6. We then add cash to the EV and subtract debt to calculate the equity value. DCF: A DCF analysis discounts FCF projections, generally at the weighted average cost of the capital (WACC), to derive current value, which is then used to evaluate the potential for investment. If the value arrived at through a DCF analysis is higher than the current cost of the investment, the opportunity is worth considering. The following adjustments are done when applying DCF to value midstream and downstream companies: •

Additional non-cash expenses, such as depreciation, depletion, and amortization (DD&A) and stock-based compensation are added to earings (EBIT) while calculating FCF. DD&A is an accounting method typically used for E&P companies.

•

For a terminal exit multiple, a daily production, EBITDA, or EBITDAX-based multiple is used instead of an FCF multiple. As we know at the onset that the asset is not a going concern and will not last for perpetuity, we do not have any formulae that incorporate perpetuity.

Midstream and downstream companies do not possess oil or natural gas reserves. They purchase oil from upstream companies and operate in the transportation and refining segments. The NAV methodology is not applicable to these companies because their earnings are dependent on their operations and not on assets as in the case of an E&P company. DCF and relative valuation can be effectively used to value companies that operate in the midstream and downstream segments. Relative Valuation Relative valuation refers to the comparison of an asset price with the market value of similar assets. In a relative valuation, the value of a company is determined in relation to how similar companies are priced in the market. It includes trading and transaction comparables. Commonly Used Valuation Multiples for Oil Companies •

EV/EBITDA or EV/EBITDAX: EBITDAX (rather than EBITDA) multiple is used to value E&P companies. EBITDAX is EBITDA before exploration costs for successful efforts. In addition, other non-cash expenses, such as impairments, accretion of asset retirement obligation, and deferred taxes, should be added back in the EBITDAX calculation. For full-cost firms, exploration costs are included in depreciation and depletion. EV/EBITDAX is the most popular valuation technique to determine the value of any oil and gas company.

•

EV/Barrels of Oil Equivalent per Day (EV/boe/d): This metric does not take into account the potential production from an undeveloped field. An undeveloped field obviously has a value, but if a company has a higher share of undeveloped fields, this multiple may not give the right picture.


35


•

EV/Proven plus Probable Reserves (EV/2P): The most commonly used metric is EV/2P or EV/Proven plus probable reserves. This and daily production (barrels of oil equivalent per day) are the two widely used criteria in cases where cash flows are not known with certainty.

•

EV/Debt-Adjusted Cash Flows (EV/DACF): EV/DACF is a proxy of EV/EBITDA after tax. This measure is not affected by a company‘s capital structure. It determines a business‘s value after paying off debt. EV/DACF is a multiple applicable to all oil companies, i.e., upstream, midstream, and downstream companies.

The value of a company, P, is estimated by multiplying the mid-cycle DACF with the mean/median multiple used for comparable companies (peer group), EV/DACF. Thus, Pi = (EV/DACF)*DACFi Where, DACF = NOPAT + Depreciation EV/DACF is an important multiple as it takes into consideration the after-tax value, which is important given that oil and gas is a sector that is generally taxed heavily. The above-mentioned metric is also independent of the impact of financial decisions and thus facilitates a fair comparison across the sector. Operating Performance Indicators The following are the two most common operating performance ratios used to assess the performance of oil companies: 1. Return on Average Capital Employed (RoACE) Return on capital employed is calculated as RoACE = Here, net income refers to the income after minority interest. Average capital employed is the sum of shareholders‘ fund and net interest bearing debt. It measures the capital return, which is an important input for valuation analysis. However, this ratio is not without drawbacks. For example, it measures only short-term accounting profitability. The ratio is not a true indicator of performance. When investment falls and capital assets depreciate, RoACE rises. 2. DACF DACF is generally after-tax cash flow from operations plus after-tax debt-service payments, where aftertax cash flow is the sum of net income, depreciation, exploration charge and other non-cash items.


36

37


DACF = Net operating profit after tax (NOPAT) plus Depreciation In addition to these two parameters, various other operating performance measures exist, depending on upstream, midstream, and downstream companies. Figure 40: Key Performance Indicators

Performance indicators Upstream Companies Exploratory Spending Undeveloped Acreage Number of wells drilled Extraction Rate Percentage of wells operated Cost per well Daily Production per well Reserves/ Production Replacement Ratio(Reserves Added/ Production) Unit Cost

What does it measure Allocation of Resources Exploratory Activity and Potential Exploratory and Development Activity Growth in production, efficiency in extraction and employment of infrastructural Degree of Control and capability Efficiency in exploration and drilling activities Efficiency in production Life of the Reserves Ability to replenish the portion of oil extracted. It includes the impact of acquisitions. Ideally it should be more than 100%. (Operating cost + capital consumption + Exploratory and development Cost)/ Number of units produced. Measures the efficiency and effectiveness in operations

Midstream Companies Pipeline Mileage Expense per Staff Expense per 1000 miles Expense per unit carried Expense per USD Revenue Revenue Per unit Transported Cash Flow per unit Transported

Capacity of Crude oil, Gas and Products Pipelines Efficiency of Resource allocation Efficiency of Resource allocation Efficiency of Resource allocation Efficiency of Resource allocation Level of tariffs received Operating Efficiency

Downstream Companies Number of Refineries Operated Capacity per refinery Average Refinery Complexity Revenues per barrel refined Operating Expenses per barrel Sales per Outlet Number of retail outlets Throughputs Operated

Capacity and ability to meet needs Capacity and efficiency Type of equipments used Sales value of products Nature of commitments, Allocation of resources, Efficiency in operations Size of the market and efficiency in distribution Access to the markets Capacity and Control

Source: Rigzone

It is essential for every oil and gas company to ensure an appropriate balance between the short-term goals of return on capital and the long-term goals of production growth and reserve replacement for sustainable operations.


38


Case Study: Valuation of an Upstream Oil Company - NPV ABC Corp. ABC Corp. is one of the world‘s largest E&P companies. Headquartered in Woodlands, Texas, ABC operates in some of the most prolific oil and gas basins in the world. Its major assets are located in the Gulf of Mexico, the Rocky Mountain region, Alaska, West Africa, Mozambique, and China. Being an E&P company, ABC‘s growth is driven by its proved reserves and the annual additions to its reserves. ABC classifies its proved reserves as proved developed and proved undeveloped reserves. Proved developed reserves are those wherein oil and gas can be extracted from existing wells, using the available technology and equipment. See Section 5.1 for a detailed description. Proved undeveloped reserves are those wherein the certainty of finding oil and gas has been established, but new wells need to be drilled for production or significant capex is required to sustain production at existing wells. ABC has successfully enhanced its reserve base and has ensured growth in its production rate. Figure 42 provides a summary of ABC‘s proved reserves, as on January 1, 2012. Note: As on January 1, 2011, the liquids 2P reserves were 850 MMBbl. Figure 41: Valuation-Related Assumptions

Figure 42: Remaining Reserves, as on January 1, 2012

Growth of oi l pri ce 2017 onwa rds Roya l ty ra te Increa s e i n no. of wel l s per yea r Ga s vol umes i ncrea s e NGL's Oi l Di s count ra te 1 BOE = Fi xed cos t per wel l ($) Opex per bbl ($) Roya l ty ra te Opex per mcf i n $

2% 14.50% 10% Li qui ds ( mmbbl ) Sa l es Ga s (bcf) 10% 17% 21% 10% 6ccf 7500 9 12.50% 1

Sta te ta xes (s evera nce+a dva l orem+i ncome)

12.00%

Corpora te ta x

35.00%

Source: Evalueserve

Proved devel oped 321 3,423

Proved + Proba bl e(2P) 890 10,870

Source: Evalueserve

We adopt the following approach/ steps to calculate asset NAVs: Step One: Forecasting Production Levels We estimate the assets will last until 2041. Error! Reference source not found. and Error!

Reference source not found. provide the production profile of oil and gas. Production peak sometime in 2021 and with reserve replacement going down the asset deplete (as it happens eventually with all oil and gas assets) completely in 2041.


39


Figure 43: Oil Production (‘000 bbl/d)

Figure 44: Gas Production (mmboe) 160 140 120 100 80 60 40 20 0

250 200 150 100

50 0

Gas in MMBOE

Oil and condensates Source: Evalueserve

Source: Evalueserve

Estimates of various commodities (until 2020) that are part of ABC‘s oil and gas assets are listed in Figure 45. (Refer to appendix for data up to 2041). As stated earlier, we have assumed that production rate initially increases as the reserves are getting replaced (please refer to reserves replacement ratio) at a slower rate. Based on this assumption, by 2041, production will reach its lowest point, after which the reserves are assumed to deplete. Figure 45: Production until 2020

Li qui ds 000b/d l i qui ds MMBOE Gas mmcfd Gas i n MMBOE NGLs Oil and condens ates Total MMBOE

2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 83 108 150 173 194 214 229 242 256 270 30 39 55 63 71 78 84 88 94 99 1,403 1,514 1,676 1,725 1,803 1,905 1,983 2,051 2,134 2,206 85 92 102 105 110 116 121 125 130 134 29 35 46 53 59 65 69 73 77 81 54 72 104 120 135 149 160 169 179 189 116 131 157 168 180 194 204 213 223 233

Source: Evalueserve

Step Two: Reserve Life and Reserve Replacement Ratio For any E&P company, the life of its reserves is the number of years the oil and gas reserves (1P) would last at the current rate of production, assuming zero additions in the future. For ABC, the life of its reserves at end-2011 was as follows: •

For oil, the reserve life is: Proved reserves/production during the year = 890/ (83*365/1000) = 29.27 years

•

For natural gas, the reserve life is = 10,870/1403 = 7.7 years

Figure 46: Life of Reserves

Commodity Oil and Natural Gas Condens ate Natural Gas Source: Evalueserve

Extraction rate = Production during the year/reserve base


years 29.27 years 7.7 years

40


The extraction rate is calculated on the opening balance of reserves to compute the percentage of reserves converted into production during 2011. Extraction rate for oil is = (83.30*365/1000)/890 =30/890 = 3.42% Extraction rate for gas = 1403/10870 = 12.9% Figure 47: Extraction Rate for 2011

Oil and Natural Gas Condensate Natural Gas

3.42% 12.90%

Source: Evalueserve

The growth of an E&P company also depends on its ability to replace its exhausting resources with newer finds. The idea is to avoid a decline in reserve life. The metric that describes this capability of an E&P company is called the reserve replacement ratio. A reserve replacement ratio of greater than one signifies greater additions to reserves than production growth. This suggests growth opportunities for the company. Reserve replacement ratio = addition to resources during the year/total production during the year In case actual reported reserves for 2010 were 850mmbl, the reserve replacement ratio for ABC at the end of 2011 was = (890-850)/30 = 1.33 As the ratio is greater than one, it signifies greater additions to reserves than production growth at ABC. The rate of production from a well follows a bell-shaped curve, also known as the Hubbert curve. Hubbert proposed that the production profile of an oil well follows a bell-shaped curve. Production increases exponentially, reaches a peak, and then starts to decline (see Figures 43 and 44). For oil wells, peak production may sustain for a very short period. On the other hand, natural gas wells sustain peak production for longer periods. In other words, instead of a peak for a short duration, natural gas wells exhibit a plateau-like production profile, where peak production continues for longer periods. Step Three: Forecasting Revenue We know ABC‘s production schedule until 2041. Therefore, we derive the revenue for each year by multiplying the production with the estimated commodity prices. All the related calculations are shown in Figure 48. Note that the data shown is only until 2025; the data from 2026 to 2041 is shown in the Appendix. Also, note that these are estimated numbers and are usually available in company filings or industry databases such as Woodmac. These production estimates generate sales revenue when multiplied with the expected sales price. The realized sales price for an oil company is generally different from benchmark prices; therefore, this differential should be incorporated when forecasting sales prices. This difference may arise due to company policies and hedging. The volume of oil or natural gas assumed to be realized at the contract price provides the hedged revenue. The portion of oil and natural gas produce that is not hedged is assumed to be sold at company prices, which are generally different from benchmark prices. This differential, along with the differential between company and average prices, should be adjusted while computing the realized price.


41


Revenue Calculation for 2011 The gross revenue of the firm is the sum of revenue from Natural Gas Liquids (NGLs), gas, and liquids. NGLs revenue = 29*43.43*365/1000 = 459 (in $ million) Gas revenue = 3.02*1403*365/1000 = 1547 (in $ million) Liquids revenue = 54*96.5*365/1000 = 1914 (in $ million) 54 is the difference between Liquids daily total production of 83 (in ‗000) minus NGLs daily production of 29 (‗000). Step Four: Determining NAV Figure 48: NAV Calculation Sheet for ABC Year Gross revenue (in USD m) Royalty Opex State taxes EBIDTA Dep EBIT Corporate tax PAT

2011 2012 2013 2014 2015 2016 3920 5213 6607 7605 8483 9421 568 756 958 1103 1230 1366 786 966 1150 1270 1401 1544 308 419 540 628 702 781 2258 3072 3960 4604 5149 5729 409 621 845 1066 1400 1723 1849 2451 3115 3538 3749 4007 647 858 1090 1238 1312 1402 1,202 1,593 2,025 2,300 2,437 2,604

2017 10180 1476 1663 845 6196 2008 4188 1466 2,722

2018 10894 1580 1773 905 6636 2381 4254 1489 2,765

2019 11695 1696 1899 972 7128 2790 4338 1518 2,820

2020 12487 1811 2023 1038 7615 3190 4425 1549 2,876

2021 13224 1917 2135 1101 8071 3601 4470 1564 2,905

2022 12212 1771 1977 1016 7449 1832 5616 1966 3,651

2023 10360 1502 1679 861 6317 1552 4766 1668 3,098

2024 9424 1367 1520 785 5753 1393 4360 1526 2,834

2025 8695 1261 1396 725 5313 1270 4043 1415 2,628

CAPEX

1,565

2,030

2,206

2,304

2,663

2,779

2,736

2,883

3,003

3,044

3,086

126

126

127

127

46

185

664

1,062

1,174

1,548

1,995

2,264

2,607

3,022

3,420

5,357

4,523

4,101

3,771

FCF

Source: Evalueserve

Assumptions •

Royalty (Figure 41) is 14.5% of revenue, which is $568 million for 2011. Opex is calculated separately for both gas and liquids, and summed up. For oil, opex is $9 per bbl produced, and for gas it is $1 per mcf produced. For 2011, opex is (9*83*1,000*365+ 1*1,403*365*1,000)/10^6 = $786m. We also assume an annual inflation of 2% on the rate.

•

Royalty and opex for further years is calculated similarly.

•

State taxes are calculated on revenues after the deduction of royalty and opex. Our assumption of a tax rate of 12% leads to a tax of $308 million for 2011. Capex is assumed to grow in the same way as the increase in production. This means that the expansionary capex will cease to increase in years when production starts declining (there will be maintenance capex though). In our estimates, we have taken the expansionary capex until 2021, syncing it with the production estimates, after which, maintenance capex is taken.

•

The accumulated depreciation is estimated to be same as the ratio of the (accumulated production until the year/end of life accumulated production). Please refer to the Appendix for the depreciation schedule. The corporate tax rate is assumed to be 35%, which, when applied to EBIT, results in a profit after tax (PAT) of $1,202 million.

•

On the FCF row, we apply the NPV function in MS-Excel to arrive at an EV of $19,683m.


42


Relative Valuation and Benchmark Indicators Figure 49, provides a comparison of ABC with the major players in the oil and gas industry that operate in the same country under similar tax structures and regulations. Figure 49: Valuation Multiples

EV (USD m) EBITDA (USDm) P/Sa l es EV/EBITDA P/Book P/Ca s h Fl ow EV/DACF EV/res erves

ABC Corp 19,683 3,072 0.58 6.4 2.3 16 8.5 1.8

X 9,777 611 2.1 2.6 4.1 4.5 18 0.5

Y 371,537 69,905 1.00 7.4 3.2 8 7.2 1.2

Z Average (X,Y,Z) 199,159 37,733 0.5 1.2 6.2 5.4 2 3.1 7.1 6.6 6 10.4 0.9 0.9

Source: Evalueserve

From the date in Figure 49, EV/EBITDA is higher for ABC Corp. than EV/EBITDA of peer average. When we analyze this, along with other important valuation multiple EV/reserves (EV/2P reserves), we find that the multiple is higher than the peer or group average. One of the reasons behind ABC multiples lying in the higher top quartile in the group could be a better reserves quality than its peers. It is also possible that ABC is able to extract more value out of their reserves. An analysis of the multiples presented above reveals that while ABC appears to be undervalued relative to its peers when compared on P/Sales, P/book, and EV/DACF. However it appears overvalued based on other valuation multiples such as P/Cash flow, EV/EVITDA and EV/reserves. Analysts may have different opinions but generally EV/EBITDA and EV/reserves are preferred ratios/multiples for valuing upstream companies. Benchmark Indicators We use key performance indicators to measure ABC‘s operating efficiency. Figure 50 compares the operating performance of ABC with three of its competitors. Figure 50: Valuation Multiples ABC Corp

X

Y

Z

Average (X,Y,Z)

7.7

13.55

40

27.17

26.9

1.33

4.65

5.04

2.48

4.1

11.37

3.59

9.77

15.45

9.6

RoACE

12%

2%

31%

22%

18%

Producti on growth

10%

7%

22%

9%

13%

R/P Res erve repl acement rati o (2012 vs 2011) Uni t cos t

Source: Evalueserve

The first two ratios—R/P (reserves/production) and reserve replacement—indicate the longevity of reserve life and how quickly the company can discover and develop new reserves. ABC‘s R/P ratio for oil and condensates is 29.3, and for gas it is 7.7. We can see that ABC‘s R/P and reserve replacement ratio is lower than that of its peers. At 10%, ABC‘s production growth lags behind that of its peer average. Even on relatively lower parameters, ABC appears to be overvalued on EV/EBITDA and EV/reserves multiple, signaling a mismatch. Compared with its peers, the value of ABC does not justify its reserves (growth and production levels); therefore, it should be associated with a sell recommendation.


43


Appendix Figure 51: Production, Price, and Revenue from Each Commodity, 2026–41 ($ Million) Li qui ds 000b/d l i qui ds MMBOE Ga s mmcfd Ga s i n MMBOE NGLs Oi l a nd condens a tes Total MMBOE NGLS pri ce Pri ce oi l $/Bbl s Ga s i n $/Mcf

2026 159 58 1,194 73 47 113 131

2027 146 53 1,066 65 41 105 118

2028 134 49 953 58 36 98 107

2029 123 45 853 52 32 92 97

2030 113 41 767 47 28 85 88

2031 104 38 691 42 25 80 80

2032 84 31 580 35 22 62 66

2033 76 28 522 32 19 57 60

2034 69 25 471 29 17 53 54

2035 63 23 424 26 15 48 49

2036 57 21 381 23 13 44 44

2037 51 19 335 20 11 40 39

2038 46 17 289 18 10 36 34

2039 40 15 246 15 9 32 30

2040 35 13 206 13 8 28 25

2041 31 11 167 10 7 24 21

49.28 50.27 51.27 52.30 53.34 54.41 55.50 56.61 57.74 58.90 60.07 61.28 62.50 63.75 65.03 66.33 109.51 111.70 113.94 116.22 118.54 120.91 123.33 125.80 128.31 130.88 133.50 136.17 138.89 141.67 144.50 147.39 6.27 6.39 6.52 6.65 6.78 6.92 7.06 7.20 7.34 7.49 7.64 7.79 7.95 8.11 8.27 8.43

Rev. from NGLs Rev. from Ga s Rev from l i qui ds

841 2,731 4,498

755 2,487 4,287

678 2,267 4,079

609 2,071 3,882

546 1,898 3,693

490 1,745 3,509

440 1,493 2,808

395 1,372 2,630

355 1,261 2,462

318 1,159 2,302

286 1,063 2,143

256 953 1,980

230 838 1,800

207 729 1,630

185 621 1,455

169 514 1,280

Gross revenue (in USD m)

8,070

7,529

7,023

6,561

6,137

5,745

4,741

4,398

4,078

3,779

3,492

3,189

2,869

2,565

2,261

1,964

Source: Evalueserve

Figure 52: NAV Calculation Sheet for ABC, 2026–41 ($ Million) Year

2026

2027

2028

2029

2030

2031

2032

2033

2034

2035

2036

2037

2038

2039

2040

2041

Gross revenue (in USD m)

8070

7529

7023

6561

6137

5745

4741

4398

4078

3779

3492

3189

2869

2565

2261

1964

Royalty

1170

1092

1018

951

890

833

687

638

591

548

506

462

416

372

328

285

Opex

1291

1194

1105

1024

950

884

739

683

630

582

536

487

436

388

340

294

673

629

588

550

516

483

398

369

343

318

294

269

242

217

191

166

EBIDTA

4936

4614

4312

4036

3781

3545

2916

2708

2514

2332

2156

1971

1775

1589

1402

1219

Dep

1165

1070

984

906

837

775

666

604

557

514

473

439

402

358

322

287

EBIT

3771

3544

3329

3130

2944

2769

2251

2104

1957

1818

1682

1532

1373

1231

1080

932

Corporate tax

1320

1240

1165

1095

1030

969

788

736

685

636

589

536

481

431

378

326

2,451

2,304

2,164

2,034

1,913

1,800

1,463

1,368

1,272

1,182

1,094

996

893

800

702

606

State taxes

PAT CAPEX FCF

128

128

127

126

126

124

128

114

112

109

107

112

114

107

106

104

3,488

3,246

3,020

2,814

2,625

2,451

2,000

1,857

1,717

1,586

1,460

1,323

1,180

1,052

918

789

2025

Source: Evalueserve

Figure 53: Depreciation Calculation Sheet for ABC, 2011–25 ($ Million) Depreciation

2011

2,012

2013

2,014

2,015

2,016

2,017

2,018

2019

2020

2021

2022

2023

2024

producti on i n the yea r

116

136

157

168

180

194

204

213

223

233

240

218

182

161

145

cumul a ti ve producti on unti l l the current yea r

650

786

943

1,111

1,291

1,485

1,690

1,903

2,126

2,359

2,599

2,818

3,000

3,161

3,306

14.95%

18.08%

21.68%

25.55%

29.70%

34.16%

38.85%

43.75%

48.89%

54.24%

59.77%

64.79%

68.98%

72.68%

76.01%

Gross Block

8137

10167

12372

14677

17339

20118

22854

25737

28739

31783

34869

34995

35121

35248

35375

Ca pex

1565

2030

2206

2304

2663

2779

2736

2883

3003

3044

3086

126

126

127

127

cumul a ti ve a s a % of tota l producti on

Acculmulated depreciation Dep for the year

1,217

1,838

2,683

3,749

5,149

6,872

8,880

11,261

14,051

17,241

20,841

22,674

24,225

25,619

26,888

409

621

845

1,066

1,400

1,723

2,008

2,381

2,790

3,190

3,601

1,832

1,552

1,393

1,270

Source: Evalueserve


44


Figure 54: Depreciation Calculation Sheet for ABC, 2026–41 Depreciation

2026

2027

2028

2029

2030

2031

2032

2033

2034

2035

2036

2037

2038

2039

2040

producti on i n the yea r

131

118

107

97

88

80

66

60

54

49

44

39

34

30

25

21

3,436

3,555

3,662

3,759

3,847

3,927

3,993

4,052

4,106

4,155

4,199

4,238

4,272

4,302

4,328

4,349

79.02%

81.74%

84.20%

86.42%

88.45%

90.29%

91.81%

93.18%

94.42%

95.54%

96.55%

97.45%

98.24%

98.92%

35503

35631

35758

35884

36010

36134

36262

36377

36488

36598

36704

36816

36930

37037

37143

37247

128

128

127

126

126

124

128

114

112

109

107

112

114

107

106

104

cumul a ti ve producti on unti l l the current yea r cumul a ti ve a s a % of tota l producti on Gross Block Ca pex Acculmulated depreciation Dep for the year

2041

99.51% 100.00%

28,053

29,123

30,106

31,013

31,850

32,625

33,291

33,895

34,452

34,966

35,439

35,878

36,280

36,638

36,960

37,247

1,165

1,070

984

906

837

775

666

604

557

514

473

439

402

358

322

287

Source: Evalueserve



Glossary Peak Oil: Peak oil refers to maximum level of production, in any area beyond which the rate of production of oil, being a natural resource is subject to decline. Decline Rate: This is solely associated with production and refers to the fall in production over time. Depletion Rate: Depletion rate refers to the rate which takes into account the amount of oil left in the reservoir. It is calculated by dividing the current year production by the amount of oil left at the start of the current year. Units Associated with Oil and Gas: •

Bbl: Barrel or barrels of oil

•

Bcf: Billion cubic feet of natural gas

•

Boe: Barrels of oil equivalent

•

Mbbl: Thousand barrels of oil

•

Mboe: Thousand barrels of oil equivalent

•

Mcf: Thousand cubic feet of natural gas

•

Mcfe: Thousand cubic feet of natural gas equivalent

•

MMbbl: Million barrels of oil

•

MMboe: Million barrels of oil equivalent

•

MMcf: Million cubic feet of natural gas


45


References •

International Petroleum Taxation for the Independent Petroleum Association of America by David Johnston, Daniel Johnston & Tony Rogers; Daniel Johnston & Co; Inc.| Hancock, New Hampshire July 4, 2008

•

BP Statistical Review of World Energy, June 2012

•

International Energy Outlook 2011, US Energy Information Administration, September 2011

•

World Oil and Gas review 2011, Eni S.p.A.

•

U.S. Energy Information Administration.

•

Thomson Reuters

•

Journal of World Energy Law and Business (JWELB), Independent Petroleum Association of America

•

Bloomberg Finance LP

•

United States Deptartment Of Labor

•

http://www.petroleumonline.com

•

http://www.naturalgas.org

•

http://www.sciencedirect.com

•

http://gis.bakerhughesdirect.com

•

http://www.rigzone.com

•

http://www.osha.gov

•

http://www.bbc.co.uk


46


Authors Anuj Bhatia Anuj Bhatia is a Senior Research Associate within the Financial Services division of Evalueserve. He is currently tracking the US Chemical sector for a global investment bank. Anuj provides support on investment projects relating to company valuations, financial modeling, industry analysis, thematic sector reports, company analysis and profiling. He has obtained a Post Graduate Diploma in Management from IIPM Delhi, and Bachelors in Economics from Delhi University. Abhishek Chawla Abhishek Chawla is Senior Research Associate within the Financial Services division of Evalueserve. He is currently tracking the US Chemical sector for a global investment bank. Abhishek provides support on investment projects relating to company valuations, financial modeling, industry analysis, thematic sector reports, company analysis and profiling. Prior to this, Abhishek has worked with Tata Consultancy Services (Mumbai, India). He is currently a CFA Level II candidate (CFA Institute, USA) and has obtained Post Graduate Diploma in Management from GIM Goa, and Bachelors in Engineering from NIT Jalandhar. Saurabh Mehndiratta Saurabh Mehndiratta is a Research Associate within the Financial Services division in Evalueserve. He is working in the investment research team covering European Basic Materials sector. Prior to this, Saurabh has worked with Ispat Industries ltd. in the Strategic Business Department looking at company financial strategies and preparing strategic roadmap for the organization. He is currently a CFA Level II candidate (CFA Institute, USA) and has obtained a post graduate diploma in Management in Finance from the BIMM, Pune. Ashutosh Ohjha Ashutosh Ojha is a Senior Research Associate within the Financial Services division of Evalueserve. Ashutosh has six years of experience in equity research, advisory and technology. Ashutosh provides support on thematic sector reports, financial modeling and initiation reports. He is currently tracking the MENA region petrochemicals, oil & gas services, metals & mining sectors for a global investment bank. Prior to this, he worked with Aranca, JP Morgan Chase and IBM. He is a FRM charter holder and has obtained a MBA from Asian Institute of Management, Philippines and Bachelor in Engineering from RVCE, Bangalore. Rajiv Dalal Rajiv Dalal is a Group Manager within the Financial Services division at Evalueserve. He has been providing equity research support to the European chemicals sector for more than seven years. He has also worked on the US technology (internet) sector. Prior to joining Evalueserve, Rajiv worked for the Community Development Scheme (CDS) under Ministry of Human Resource & Development (HRD), Government of India. He has obtained a Masters in Finance & Control from University of Delhi.


47


Evalueserve Disclaimer Although the information contained in this publication has been obtained from sources believed to be reliable, the author and Evalueserve disclaim all warranties as to the accuracy, completeness or adequacy of such information. Evalueserve shall have no liability for errors, omissions or inadequacies in the information contained herein or for interpretations thereof.


48

Valuation of Oil Companies

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