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1、Q1 2012 oil but production from Latin America, the UK North Sea and Emerging Europe has also disappointed. Australia Oil Source: Historical, Energy Information Administration; Estimates/Forecasts, BMI In the UK, rising investment levels have not been able to stem a faster-than-expected decline in p
2、roduction, which fell below 1mn b/d in June 2011 for only the second time in 30 years. The effect has been magnified as the market has looked to the North Seas light sweet crude to replace lost light sweet volumes from Libya. In Azerbaijan, extended maintenance at BPs ACG oil field is likely to see
3、production to disappoint by around 100,000b/d relative to expected volumes. Moreover, Azeri authorities have warned that production is likely to remain lower into 2012. Production has also been worse than expected in Latin America. Disappointing production volumes in Brazil and Venezuela have led us
4、 to lower our 2011 output target for the region by around 200,000b/d. Supply tightness is expected to ease going into 2012, but the market is not expected to produce a surplus until 2013. We forecast a supply deficit of around 860,000b/d, which will persist into 2012, with the market finally going m
5、oving back into surplus in 2013. Libya, however, remains a wildcard. Our forecast is based on the assumption that limited oil supplies of around 300,000b/d - primarily from the Messla and Sarir fields in the southeast of the country will come back onstream before the end of 2011. The next stage of b
6、ringing production back onstream will likely see flows restart from the offshore Bouri field and the Eni -operated El Sharara field in the Murzuk Basin near the Algerian border. If those fields are successfully brought back onstream, we see potential for output rising to as much as 1mn b/d by the en
7、d of 2012. More challenging will be restarting production at Australia Oil Source: Historical, Energy Information Administration; Estimates/Forecasts, BMI Short-Term Demand Outlook According to the updated BMI model, 2011 global oil consumption will increase by 1.71% from the 2010 level. The 2011 fo
8、recast reflects slow Organisation for Economic Cooperation and Development (OECD) demand growth of 0.27%, and strong non-OECD consumption growth of 3.41%. Australia Oil stage two 2014; stage three 2016 Developing na na 18 Gas Offshore Montara Montara PTTEP AA* H211 Developing na na na Oil and gas Of
9、fshore Sunrise Troubadou r Woodside* (33%), ConocoPhilli ps (30%), Shell (27%), Osaka Gas (10%) 2013 Developing na na na Gas Offshore Van Gogh Van Gogh Apache* (52.5%), Inpex (47.5%) 2010 Producing 60,000 na na Oil Offshore Julimar- Brunello Balnaves Apache* (81.25%), KUFPEC na Developing na na na G
10、as Offshore Australia Oil Source: Historical, Energy Information Administration; Estimates/Forecasts, BMI Gas Supply And Demand We see rapid growth in both the production and export of gas as companies ramp up efforts to bring LNG projects on stream over the coming years. Australias gas consumption
11、is projected to grow twice as fast as the consumption of other energy sources in the next two decades and it is expected to account for 22% of total energy consumption by 2025. Our projections are for domestic demand to average about 3% growth per annum, suggesting that demand will reach about 37.6b
12、cm by 2016. However, if proposed LNG projects stick to their project timelines, production should have risen to as much as 90bcm by then, freeing up more than 52bcm of gas for export in the form of LNG, largely to Asian customers. Australia Oil Source: Historical, Energy Information Administration;
13、Estimates/Forecasts, BMI LNG The five-train 16.3mn tonne per annum (tpa) North West Shelf (NWS) LNG plant is the foundation stone of the Australian LNG export sector. The other main operating terminal is the 3mn tpa Wickham Point facility in NT, commonly known as Darwin LNG. Darwin began operating i
14、n 2006 using gas from the Bayu-Undan field and is contracted to supply 3mn tpa to Japanese customers for 17 years. Several major projects are in development offshore WA, including the Gorgon and Wheatstone projects led by Chevron, Woodside Petroleums Pluto LNG project and the Scarborough/Pilbara LNG
15、 project that is being planned by a joint venture (JV) between BHP Billiton and ExxonMobil. The two other major regions for LNG in Australia are the Timor Sea and the area around the port of Gladstone in Queensland. In the Timor Sea, Woodside is leading the Browse LNG project and Japans Inpex the Ic
16、hthys LNG scheme, with a terminal to be built onshore near Darwin. The final project in the area is the Woodside-led Greater Sunrise LNG project. Several other projects are in planning stages with the Origin Energy/ConocoPhillips Australia Pacific LNG project likely to be next in line for an FID. Wh
17、ile companies in Australia have highly ambitious growth plans we see a risk that as the myriad LNG projects progress simultaneously, competition could lead to skills, labour and materials shortages, threatening to raise costs and delay projects. Australia Oil however, we see it as effectively paving
18、 the way for those approvals, and we do not now expect any delays to Chevrons planned H211 final investment decision (FID). Browse LNG Further east along WAs coast, Woodside is leading a project off the remote Kimberley region as part of the consortium commonly known as the Browse JV. Woodside has a
19、 50% stake in three Browse Basin fields (Torosa, Brecknock and Calliance), which it has estimated holds 400bcm of gas and 370mn bbl of condensate reserves. BP and Chevron have 16.67% stakes each, while Shell and BHP each hold 8.33% interests in the seven retention leases comprising the fields. Woods
20、ide has been strongly championing a greenfield LNG terminal to commercialise the fields. After months of lobbying the remaining partners finally agreed to Woodsides plans in February 2010. Some companies in the consortium believed the new plant would be too costly and would have preferred to constru
21、ct an 800km pipeline to Karratha to use the existing terminal there once the NWS reserves start falling in around 2017. The project is estimated to cost around AUD30bn, though Shell has previously suggested that the figure could be as high as AUD50bn. Woodside rejects the higher figure and believes
22、the LNG plant at James Price Point is cost-competitive with other commercialisation options. The FEED is to be undertaken in 2011 and an FID is to be taken by mid-2012. According to Woodside CEO Don Voelte, first LNG is expected in 2016-2017 from a three-train terminal. The trains will have a capaci
23、ty of 4mn tpa each and are expected to come onstream at six-month intervals. In January 2010, PetroChina dealt a blow to the Browse project by deciding not to extend a preliminary deal to buy up to 3mn tpa of LNG from the development. The deal, expected to be worth AUD45bn Australia Oil Petronas and
24、 French major Total, which entered the project in September 2010, each hold a 27.5% stake; and Kogas holds a 15% interest. Queensland Curtis LNG British gas producer BG Group officially sanctioned its Curtis Island LNG project on October 31, becoming the first project developer to reach the importan
25、t milestone in the highly competitive race to supply LNG from Queensland to energy-hungry Asian markets. Australia Oil a 21-year 1.7mn tpa deal with Chiles Quintero LNG. In April 2008, it won a licence to import and sell regasified LNG in Singapore. It struggled, however, to sign up buyers during th
26、e global economic downturn in late 2008 and 2009 before striking two major agreements in March 2010. The first was a 20-year 3.6mn tpa sales and purchase agreement (SPA) agreement worth US$40bn with state-owned China National Offshore Oil Corporation (CNOOC). That was quickly followed by the announc
27、ement of a 20-year 1.2mn tpa deal with Japanese utility Tokyo Gas. In order to secure those agreements in March 2010, however, BG had to sweeten the deal by offering equity stakes in the project. As a result, CNOOC received a 10% stake in the first LNG train at the plant and a 5% stake in BGs upstre
28、am assets in the Surat Basin in central Queensland. CNOOC and BG will also team up to build two LNG ships in China that will be owned by the consortium. For its part, Tokyo Gas secured a 2.5% stake in the second LNG train at the facility and a 1.25% stake in certain upstream assets in the Surat Basi
29、n. Australia Pacific LNG In April 2009, ConocoPhillips and its partner Origin Energy announced their intention to spend some AUD35bn (US$24.6bn) over the next 10 years developing a CBM-to-LNG project in the Laird Point of Curtis Island. The Australia Pacific LNG project is designed as a four-train L
30、NG terminal. The partners said that the facility was expected to be able to produce as much as 14-16mn tpa of LNG or up to 22bcm of LNG, making it the largest CBM-fed LNG project proposed to date. The Australia Pacific LNG project has been granted significant project status by the state of Queenslan
31、d, ensuring it can be fast-tracked through the regulatory approval processes. Conoco and Origins investment is expected to cover the cost of developing the gas fields, building gas pipelines to the Queensland coast, and the four LNG trains. The partners said Australia Pacific LNG could come onstream
32、 in 2014, initially producing 3.5mn tpa (4.8bcm). An Origin spokesperson said the project would be developed in stages, with an FID on the construction of the first processing train expected by the end of 2010, though without a single SPA signed an FID was delayed until February 2011. FIDs on the re
33、maining two trains will be made after 2015. The partners said they were seeking long-term customers, most likely in China, South Korea and Japan. In January 2010, McConnell Dowell Constructors and Consolidated Contractors Australia JV were Australia Oil na = not available. Source: BMI Overview/State
34、 Role Australia boasts a fully liberalised and highly competitive energy sector, rivalling North America in terms of the speed and stability of the regulatory process. Australias upstream oil and gas scene has changed considerably over the years, with IOCs coming and going while independent explorat
35、ion companies are continually created and later absorbed by bigger players. The oil segment has been erratic in terms of prospectivity, while natural gas has generally proved to be a much bigger draw thanks to world-class export potential. In an effort to fire up fresh interest in the Australian ups
36、tream sector, many have called for an overhaul of the industry. It has been suggested that a new tax regime, with a defined legal structure and incentives for frontier and deepwater exploration, is crucial to encouraging more investment. The government has also made an effort in recent years to pass
37、 amendments to cut exploration costs, making a four-year, US$30mn commitment to fund AGSO-Geoscience Australia, an agency that provides companies with seismic and geological data. Australia Oil however, the tax in our view would be unlikely to threaten the economic viability of any projects. In our
38、view, the most significant threat to the LNG industry will continue to come from project delays and cost overruns, not the carbon tax. Those risks were highlighted in mid-June when Woodside Petroleum announced yet another setback at its Pluto LNG project. It was the second major delay and costs have
39、 now risen by 33% over the AUD11.2bn Woodside had estimated when it took a final investment decision (FID) on the project in July 2007. We see an increasing likelihood that Woodsides travails at Pluto are a sign of things to come in Australias booming LNG sector. If anything, the problem of delays a
40、nd cost overruns is likely to get worse over the coming years as more than a dozen projects compete for a dwindling pool of qualified labour and limited resources. A number of Australian companies, in addition to Woodside, have emerged as important players throughout the LNG boom, and these are the
41、companies that face the biggest risks due to their lack of diversification. Santos has taken an FID on a two-train 7.8mn tpa (10.76bcm) LNG export terminal in Gladstone. The company has estimated that the project will cost US$16bn. If Santos were to experience similar levels of cost inflation as Woo
42、dside has at Pluto, then that figure could rise to US$20bn, making the project far less economically attractive. Other companies that have already taken FIDs or are planning to approve LNG projects and will face cost pressures from the newly proposed carbon tax and the threat of cost overruns includ
43、e Britains BG Group, Australias LNG Ltd and Origin Energy, as well as majors Chevron, Royal Dutch Shell, Total and ConocoPhillips. Australia Oil na = not available/applicable. Source: Company data 2009 Australia Oil 1 excludes 74,000b/d Adelaide plant, currently mothballed; na = not available/applic
44、able. Source: BMI, Company data 2009 Australia Oil both are in Queensland and are some of Australias biggest onshore projects. Through to 2010 the total COP programme could see up to 1,000 wells drilled, targeting 60mn bbl of reserves net to Santos. Santos took an FID on its GLNG project in January
45、2011, making it the second to reach the milestone in the Gladstone CBM-to-LNG race. The FID calls for an investment of US$16bn through to 2015 to develop a two-train LNG plant with a total nameplate capacity of 7.8mn tpa, or 10bcm per annum, split evenly between the two trains. Exports from the plan
46、t are expected to begin in 2015, a year later than envisioned in the initial proposal. The facility is underpinned by probable (P2) reserves of an estimated 130bcm from Santoss Gladstone fields, as well as an additional 19bcm of reserves from Santos Cooper Basin acreage. Santos holds a 30% stake in
47、the project. In September 2010, Santos raised EUR300mn in a hybrid notes issue to fund its LNG projects. The issue brought the total issue of hybrid notes to EUR1bn. In July 2010, Santos executed an AUD2bn (US$1.76bn) bilateral bank loan facility to enhance its liquidity and refinance its existing A
48、UD700mn (US$617.34mn) of loans that will mature between 2011 and 2014. The loan will provide Santos with increased flexibility to fund its projects, including the Gladstone and Papua New Guinea LNG projects. In March 2010, Santos agreed to sell its 40% operating interest in the undeveloped Evans Sho
49、al gas field in the Bonaparte Basin of the Timor Sea to compatriot independent Magellan Petroleum for AUD200mn (US$182mn). In May 2009, Santos put its Timor Sea assets up for sale, hoping to raise US$500mn to fund its share of the Gladstone and PNG LNG projects. In addition to Evans Shoal, Santos was offering the wholly owned Petrel, Tern and Frigate fields in the southern part of the Bonaparte Basin, which were partially sold to French utility GDF Suez in August 2009 for US$370mn. Santos will keep 40% in the Bonaparte and