Please help me with this case study attached ''Forecasting earnings and earnings growth in the European oil and gas industry'' to answer to the 4 questions:

1.What are the European oil and gas companies? drivers of profitability? What are their key risks?

2.Using the supplemental information summarized in Exhibit 2, analysts can produce several ratios that provide insight into the efficiency of the companies? exploration, development, and production activities as well as their growth opportunities. Develop asset of ratios that provide such insights. How efficient are the three oil and gas companies in exploration and production?

3.Exhibit 3 summarizes analysts? one-year-horizon (2006), two-year-horizon (2007), and three-year-horizon (2008) forecasts of sales growth and profit margins. For each of the three oil and gas companies, provide arguments justifying the most pessimistic scenarios as well as arguments justifying the most optimistic scenarios.

4.Given your answers to the previous questions, what are your forecasts of the oil and gas companies? net profits for fiscal year 2006? What are your expectations about each of the companies? long-term earnings growth (i.e., growth in 2007 and 2008)?

see Home/Nanyang Technological University/ACC ACC 3103/ch6tn_oil_gas there is the answer but i cant see.

Forecasting earnings and earnings growth in the European oil and gas industry Industry overview I n 2011 the largest companies operating in the European oil exploration and production industry all tended to operate on a global scale. They were typically categorized as ''price takers'' because they had little control over the prices that they could ask from their customers. One reason for this small influence on prices was that the 12 oil-producing developing countries that coordinated their production activities through the OPEC organization had a strong influence on the worldwide oil supply and crude oil prices. Although the OPEC countries possessed close to 80 percent of the worldwide proved oil reserves, they supplied only 42 percent of the worldwide oil production to stabilize prices at higher levels. National taxes also influenced local prices and demand for oil. For example, in Europe fuel prices were, on average, three times as large as fuel prices in the US, tempering the demand in Europe. During the 2000s, crude oil prices soared to record levels. While at the end of 1999 the price for a barrel of crude oil was close to $25, the crude oil price approached $110 per barrel by the end of 2011. There were several potential reasons for this strong increase in the oil price.1 The increasing demand for oil from emerging economies such as China had led to a situation in which the amount of oil demanded had approached the maximum production capacity. While the OPEC countries had increased their production to record levels, they had invested insufficiently in new capacity and were unable to further increase oil supply. Oil supply had also come under pressure because of the low interest rates, which made it less expensive for oil producers to carry inventories and strategically limit production. Further, oil prices were strongly affected by speculative trading in the commodity markets in response to the political instability in the Middle East and oil-producing African countries. Exhibit 1 shows the (Brent) crude oil price between January 2005 and December 2011 as well as the prices of oil futures during the first half of 2012. Because oil and gas companies were price takers, their success critically depended on (1) their ability to grow and (2) the efficiency of their exploration and production activities. Although the growth of the energy markets typically followed the growth in gross domestic product, oil and gas companies could grow at a faster or slower rate than the economy average for the following reasons. First, some companies were able to open up new markets, primarily in the emerging countries. The most important emerging market during the 2000s was China, which contributed almost one-third to the total worldwide increase in oil consumption. Second, although the demand for energy tended to follow the growth of the economy, the supply of oil and gas was limited by the natural availability of the energy sources. By the end of the 2000s, many industry analysts feared that oil and gas companies' proved developed oil and gas reserves would reduce in the near future. Third, companies could diversify into other segments of the energy market. For example, oil and natural gas companies produced or started to produce coal, nuclear energy, or hydroelectric energy. The increasing oil price tended to have a positive impact on oil and gas companies' profits in the 2000s. Nonetheless, various other developments put pressure on the companies' profit margins. First, because oil was traded in US dollars, the weak dollar implied that it was expensive for oil companies to buy resources in other currencies. Second, steel prices were also rising, making oil and gas companies' capital investments more expensive. Third, and most importantly, during the first half of the 2000s exploration costs per barrel of oil equivalent (BOE) had risen sharply. 2 Oil and gas companies that had operations in developing countries were also subject to a substantial degree of country risk. Many companies were extending their operations to developing countries in, for example, West Africa or around the Caspian Sea, because they were running out of reserves in the developed countries. Operations in such developing countries could, however, be disrupted by political crises, acts of war, and expropriation or nationalization of reserves and production facilities by governments. For example, in 2006 Bolivia announced plans to nationalize its oil and gas fields, which were then owned by several international oil and gas producers. Similarly, early 2012 Argentina decided to take back control of YPF, the Argentinian operating branch of Spain-based oil producer Repsol. Oil and gas companies' accounting and disclosure As argued, because oil and gas companies are price takers, their future profitability depends primarily on (1) the quantity and quality of their current oil and gas reserves, (2) their ability to efficiently extract and produce oil and gas, and (3) their ability to replace extracted reserves. Some inherent characteristics of oil and gas companies' exploration and development activities, however, make accounting for these activities a difficult exercise. Particularly, because the future economic benefits of current exploration and development expenditures are hard to establish, deciding on which expenditures must be capitalized as assets and which expenditures must be categorized as ''unsuccessful'' and immediately written-off can be problematic. Most oil and gas companies use the ''successful efforts method'' of accounting for exploration and development activities. Under this method, the key financial reporting estimate is for proved oil and gas reserves. Accounting standards consider oil and gas reserves to be proved when the company has government and regulatory approval for the extraction of reserves and is able to bring the reserves quickly to the market in a commercially viable manner. Companies make these estimates using geological information about each reservoir, reservoir production histories, and reservoir pressure histories. The distinction between proved and unproved reserves is important because only exploration expenditures that are associated with proved reserves are capitalized as assets. Specifically, under the successful efforts method, companies capitalize their exploration expenditures for a short period, after which they choose between continued capitalization and immediate amortization based on whether the exploration has successfully led to the booking of proved reserves. In addition, oil companies' depreciation, depletion, and amortization of production plants are typically calculated using the unit-of-production method, where the expected production capacity is derived from the proved reserves. The following paragraphs from BP plc's 2011 Annual Report describe how BP accounts for exploration and development expenditures and illustrates the basic idea underlying the successful efforts method: Exploration license and leasehold property acquisition costs are capitalized within intangible assets and are reviewed at each reporting date to confirm that there is no indication that the carrying amount exceeds the recoverable amount. This review includes confirming that exploration drilling is still under way or firmly planned or that it has been determined, or work is under way to determine, that the discovery is economically viable based on a range of technical and commercial considerations and sufficient progress is being made on establishing development plans and timing. If no future activity is planned, the remaining balance of the license and property acquisition costs is written off. [...] Geological and geophysical exploration costs are charged against income as incurred. Costs directly associated with an exploration well are initially capitalized as an intangible asset until the drilling of the well is complete and the results have been evaluated. These costs include employee remuneration, materials and fuel used, rig costs, and payments made to contractors. If potentially commercial quantities of hydrocarbons are not found, the exploration well is written off as a dry hole. If hydrocarbons are found and, subject to further appraisal activity, are likely to be capable of commercial development, the costs continue to be carried as an asset. [...] When proved reserves of oil and natural gas are determined and development is approved by management, the relevant expenditure is transferred to property, plant, and equipment. [...] Expenditure on the construction, installation, and completion of infrastructure facilities such as platforms, pipelines, and the drilling of development wells, including service and unsuccessful development or delineation wells, is capitalized within property, plant, and equipment and is depreciated from the commencement of production as described below in the accounting policy for property, plant, and equipment. [...] Oil and natural gas properties, including related pipelines, are depreciated using a unit-ofproduction method. The cost of producing wells is amortized over proved developed reserves. License acquisition, common facilities, and future decommissioning costs are amortized over total proved reserves. The method that BP uses to account for its exploration and development expenditures is similar to the method used by many other oil and gas companies, including Royal Dutch Shell and Statoil. Most oil and gas companies also provide supplemental disclosures about their oil and gas reserves. These disclosures typically show (1) the exploration and development costs that the company incurred during the year, (2) the exploration and development costs that the company capitalized over the years, (3) the results of the company's oil and gas exploration and development activities, and (4) the movements in the company's proved and unproved oil and gas reserves during the year. Exhibit 2 summarizes the supplemental information that BP, Royal Dutch Shell, and Statoil provided in annual reports for the fiscal year ended on December 31, 2011. A description of three European oil and gas companies Following are the descriptions of three European companies that operated in the oil and gas industry in 2011: BP, Royal Dutch Shell, and Statoil. BP At the end of the 2000s, BP was one the world's largest publicly listed oil and gas company's in terms of revenues. The company had upstream (oil exploration and production) and downstream (sales and distribution) operations in more than 30 countries, in which it employed approximately 83,000 people. Between December 31, 2004 and December 31, 2011, BP's share price decreased by 9.3 percent, which in combination with an average annualized dividend yield of 3.2 percent yielded an average annual return of 2.0 percent. By the end of 2011, BP's market value was close to 88 billion. BP's shares were widely held. In 2011, the company's largest shareholder owned less than 6 percent of BP's ordinary shares outstanding. Like many other oil and gas companies, during the 2000s BP had excess cash that it returned to its shareholders through share repurchases and dividends. Between 2000 and 2008, the company repurchased ordinary shares for an amount of 51.1 billion; however, BP halted its buy-back program in 2009. BP was a financially healthy company, evidenced by the fact that Standard and Poor's had rated BP's public debt at A. Although BP's primary activities were the exploration, development, and production of oil and natural gas, the company also operated in other product segments. However, in 2011 less than 1 percent of the company's revenues came from its alternative energy business. BP's primary geographical segment was the US and Europe, where it generated 35 percent of its revenues, followed by the UK (20 percent of its revenues). Fiscal years 2010 and 2011 had been a turbulent period for BP. In the first half of 2010 an oil spill caused by an explosion at one of BP's operations had caused significant environmental damage in the Gulf of Mexico. Following the oil spill, BP had committed to an extensive clean up, to supporting the economic restoration of the area affected by the oil spill, and to creating a $20 billion Deepwater Horizon Oil Spill Trust from which individual claims and settlements could be funded. BP's income statement for fiscal 2010 included a pre-tax charge of $40.8 billion resulting from its oil spill-related commitments; the company's 2011 income statement included an oil spill-related pre-tax gain (reversal) of $3.8 billion. BP's capital expenditures in the exploration and production segment totaled $25.5 billion in 2011. 3 The company's proved developed and undeveloped reserves increased by 411 million barrels of oil equivalent (BOE) because of discoveries and improvements in recovery techniques. BP's daily production in 2011 was approximately 2.1 million BOEs. Royal Dutch Shell By the beginning of 2012, Royal Dutch Shell plc was, like BP, one of the world's largest publicly listed energy and petrochemical group and larger than BP in terms of revenues and market capitalization. The company employed around 90,000 people in more than 80 countries. The shares of Royal Dutch Shell were widely held. The company's largest shareholder held less than 5 percent of the company's ordinary share capital. Royal Dutch Shell's core activities were the production, development, and retailing of oil and natural gas. Forty percent of Royal Dutch Shell's revenues in 2011 came from its European operations, 20 percent of its revenues came from its US operations, and 32 percent of its sales was made in nonEuropean countries from the eastern hemisphere. In the period from 2005 to 2011, Royal Dutch Shell's returns on its equity ranged from 9.2 percent to 28.6 percent. During this period, the company realized an average total share return of 0.7 percent, reaching a market capitalization of E174 billion on December 31, 2011. Rating agency Standard and Poor's had rated Royal Dutch Shell's debt at AA. In 2004, Royal Dutch Shell had surprised investors with the announcement that its proved oil and gas reserves were about 20 percent smaller than it had previously disclosed. Specifically, the company reclassified 2.7 billion barrels of oil and natural gas liquids as well as 7.2 trillion standard cubic feet of natural gas as ''probable but not proved.'' The estimated value of the reclassified reserves was close to E6 billion. To restore credibility after the restatements of its oil and gas reserves, Royal Dutch Shell undertook several steps. The company improved its internal control systems, replaced some of its directors, abandoned its practice of evaluating business unit's performance and calculating managers' bonuses based on reserve bookings, and changed its governance structure. In 2011, Royal Dutch Shell reported a return on operating assets of 15.3 percent, up by 4.3 percentage points compared to 2010, partly because of higher oil prices and asset sales and despite lower refining margins. In that year, the company's share price increased by close to 15 percent. Royal Dutch Shell's capital expenditures in the exploration and production segments were $19.1 billion in 2011, when its daily oil and gas production level had declined from 2.4 million to 2.3 million BOEs. Management planned to raise capital investments by close to 25 percent in 2012, anticipating a 25 percent increase in production between 2011 and 2017-2018. Statoil Of the three described European oil and gas companies - BP, Royal Dutch Shell, and Statoil - Statoil was a smallest. In 2011, the company operated in more than 41 countries, employing approximately 21,000 people. Between 2005 and 2011, Statoil's return on equity ranged from 9 to 37 percent. During these years, the company's share price had increased by an average of 12.1 percent (including dividends), to reach a market value of NOK488.2 billion (E62.8 billion) on December 31, 2011. Statoil had one large shareholder, the government of Norway, who held close to 67 percent of the company's ordinary share capital. In 2011, Statoil's dividends totaled NOK20.7 billion; the company had not repurchased ordinary shares. Standard and Poor's rated Statoil's public debt at AA. Statoil's operating activities were focused on exploring for, producing, and retailing oil and natural gas. The company had most of its operations located in Norway and North America and was less geographically diversified than BP and Royal Dutch Shell. Specifically, it had 49 percent of its non-current assets located in Norway, 25 percent in the US and Canada, and 17 percent in Angola, Brazil, and Azerbaijan. Fiscal year 2011 had been a profitable year for Statoil. The company's profitability had benefited from the rising oil prices, gains on the sale of assets and unrealized gains on derivatives. For the years 2012, Statoil's management targeted a 3 percent growth in production. In 2011, the company made capital expenditures of NOK85.1 billion, up by 24 percent compared to 2010, and anticipated a further increase in capital spending by 20 percent in the next year. In its 2011 Annual Report, the company identified as one of its primary ambitions to remain in the top quartile of its peer group for unit of production cost. Questions 1 What are the European oil and gas companies' drivers of profitability? What are their key risks? 2 Using the supplemental information summarized in Exhibit 2, analysts can produce several ratios that provide insight into the efficiency of the companies' exploration, development, and production activities as well as their growth opportunities. Develop a set of ratios that provide such insights. How efficient are the three oil and gas companies in exploration and production? 3 Exhibit 3 summarizes analysts' one-year-horizon (2012), two-year-horizon (2013), and three-year-horizon (2014) forecasts of sales growth and profit margins. For each of the three oil and gas companies, provide arguments justifying the most pessimistic scenarios as well as arguments justifying the most optimistic scenarios. 4 Given your answers to the previous questions, what are your forecasts of the oil and gas companies' net profits for fiscal year 2012? What are your expectations about each of the companies' longterm earnings growth (i.e., growth in 2013 and 2014)