Sample of Writeup for The EIU


This page contains nine articles. All are copyrighted under

The high price of unlimited plans

April 3rd 2017

Intense competition in the over-saturated US telecoms market has led to services providers offering heavily discounted, integrated and unlimited plans. While the strategy has helped in adding and retaining customers in the short term, it has reduced average revenue per user for most telecoms services and stands to hurt profit margins over the longer haul. Moreover, increased data usage per customer at minimal to no extra charge, has placed a burden on the bandwidth of the telcos’ infrastructure. Competing on prices may also restrict US operators’ finances and put at risk investment in technological upgrading, possibly curbing income growth in the near future.

Precedents setting trend

The fact remains that the smaller players in the US market, such as T-Mobile US and Sprint, have gained from discounted offers. While T-Mobile added 2.1m net customers in the fourth quarter of 2016, Sprint recorded total net additions of 577,000 subscribers in the third quarter of the 2017 fiscal year ended December. That helped T-Mobile post a 31% year-on-year jump in quarterly net profit to US$390m, while Sprint narrowed its quarterly net loss by 43% to US$479m.

Meanwhile, market leader Verizon Communications posted a nearly 17% drop in its fourth-quarter net profit to US$4.6bn, while AT&T posted a 40% drop in net attributable profit to US$2.4bn. The firms cited continuing subscription losses, pricing pressure and higher expenses behind the downturn in performance. Following that, in early 2017, Verizon and AT&T announced that they would be selling unlimited plans in contrast to their earlier policy to not offer them to all of their customers.

What is on offer?

AT&T on February 16th expanded its unlimited plan for post-paid wireless customers to fend off competition. The new package contains unlimited talk-time (including to Canada and Mexico), text messages (to over 120 countries) and data on four lines for US$180. Subscribers can also avoid roaming charges in Canada and Mexico. AT&T’s previous unlimited plan of US$100/month for a single line was only for its DirecTV and U-Verse customers. The price of the unlimited plan was further cut by US$10 on February 27th.

The deal followed Verizon offering an unlimited data package on February 12th for mobile devices on its 4G LTE network. The introductory deal offered unlimited data, voice minutes and text for US$80/month for the first line and US$45 per line for four more connections. Verizon brought back the unlimited plan after five years. Previously, it had offered new devices to allow subscribers to carry forward unused data and avoid overage charges.

Right before Verizon launched its package, Sprint had offered an introductory unlimited data package for up to five lines for US$90. On February 13th T-Mobile said that it would offer HD video and 10-GB high-speed hotspot data per month to customers of its T-Mobile ONE unlimited plan at no extra charge, followed by unlimited 3G data. It also introduced a new offer of two lines for US$100.

Increased data usage per customer at close to no extra charge burdens the bandwidth of the telcos’ infrastructure, hurting overall services. For instance, AT&T has said that beyond 22 GB of data usage under its unlimited plan, speeds may slow during periods of network congestion.

What is at stake?

Telecoms is an industry that requires heavy investment, with the US mobile penetration rate forecast to rise to 143% by 2021, from around 128% in 2016, and companies in the sector will need to spend heavily in upgrading and expanding their networks. Picking up wireless spectrum remains expensive but crucial for telcos in order to survive in the long run. Competitive mobile plans therefore stand to restrict telcos’ finances and may threaten future investment.

Under pressure to offer services at lower prices, telcos have been cutting their expenses. While Verizon saw its capital expenditures drop by 4% to US$17.1bn in 2016, AT&T expects its capital budget to fall by 2% to US$22bn in 2017. Meanwhile, Sprint has reduced its spending forecast by as much as 33% to US$2bn for its fiscal 2017 ended March 31st by cutting services and operational expenses. T-Mobile is the only exception with its capital spending forecast of US$5.1bn for 2017 – a rise of up to 11% from last year.

Amid the competition, Verizon and AT&T have both targeted acquisitions to drive income growth. Last October, AT&T agreed to buy Time Warner Inc for US$85.4bn to gain access to the latter’s market-leading brands such as Home Box Office (HBO), CNN and DC Comics Inc. The deal will be backed by US$40bn in bridge loans. Last month, Verizon reduced its purchase price for Yahoo Inc’s core internet business by US$350m to US$4.5bn. With their purchases, Verizon and AT&T are aiming to expand their digital and mobile operations.

Having effective digital strategies will be crucial given that in the US average internet usage is expected to rise. Whereas an estimated 76 out of every 100 people used the internet in 2016, we forecast that 87 of every 100 will do so by 2021. Telcos also have the task of further expanding their 4G LTE networks in 2017. The US ranked tenth worldwide in 2016 in terms of the availability of 4G networks, according to OpenSignal, a wireless research firm, while in terms of speed of 4G services, the country stood in 68th place. Hence, heavy investment will be required to support the unlimited plans.

Investment in setting up 5G infrastructure is another priority for operators. Last month Verizon announced that it would start offering 5G connections as part of a “pre-commercial” rollout through its newly-built network to select customers in 11 US markets in the first half of 2017. 5G connections are expected to provide speeds up to 100 times faster than 4G technology. The other three main US players have unveiled plans to develop 5G networks and have already begun trials. Commercial rollout of 5G is expected by 2020.

Questions remain

The financial obligations of US telecoms firms raise questions about the sustainability of their discounting strategy. The viability of a telecoms business is often judged by its network and service quality, and not necessarily by its discount offers. The worry is that the craze for offering discounted and unlimited plans will end up hurting the speed and quality of the network, if they harm the ability of companies to pay for infrastructure upgrades.

Cost-cutting initiatives, including job cuts and operational restructuring, are likely to be on the table, especially since consolidation and acquisition plans typically face high regulatory hurdles. For instance, SoftBank is reportedly considering selling the majority of its mobile business, Sprint, in an attempt to overcome antitrust objections to it buying T-Mobile. Meanwhile, as part of a restructuring initiative, Verizon in January announced 155 job cuts at its go90 mobile video business.

Unlimited plans tend to limit revenue recognition from customers, especially those who consume a lot of data and other services. Given that data has become the largest revenue contributor for telecom companies, such heavily discounted plans can be counterproductive. On the flip side, consumers who use a lot of data or those who subscribe to group plans for families or packaged deals for a range of services can make the most of these unlimited and bundled plans.

It is unclear how long these companies can continue to offer discounted and unlimited deals, which help them to expand market share, but at such a high cost that the health of their businesses may eventually be at risk. For instance, although Verizon promised that its network was ready to support any volume of usage, the company has fewer spectrums per subscriber than smaller peers. Given the nature of the competitive environment, however, the unlimited plan is here to stay for now. It will remain a feature of the landscape for as long as smaller players continue aggressively expanding their customer bases.


Big players exit Canada’s oil sands

April 25th 2017

Canada’s oil sands region in the western province of Alberta contains the world’s third largest reserves of crude oil, but is also one that is expensive to develop. Some foreign energy firms have been exiting the region as part of their effort to reduce costs in a sustained lower oil price environment, enabling smaller domestic players to acquire unconventional upstream assets once held by their larger foreign counterparts. Indeed a host of global oil producers have divested assets or reduced their exposure to Canada’s oil sands. With the bigger global players looking elsewhere, such as the rebounding US shale patch, smaller domestic players in Canada have been moving in to acquire oil sands assets that the Majors have wanted to offload.

Oil firms leaving the sector as domestic players step in

There have been several big deals involving the sale of oil sands assets by the Majors to smaller domestic players. Shell sold nearly all of its oil sands operations in Canada, including the Athabasca Oil Sands Project (AOSP), for US$7.3bn to Canadian Natural Resources. The Anglo-Dutch firm said that it would prioritise other projects such as deepwater and petrochemical operations. US firm ConocoPhillips also announced a deal to sell Canadian oil and gas assets to Canada’s Cenovus Energy for US$13.3bn. The divested assets included a 50% stake in the Foster Creek Christina Lake oil sands project. Due to the Canadian divestments the US Major has cut its oil sands reserves estimate by nearly 50% to 1.2bn barrels at end-2016. Norway’s Statoil completed the sale of its Canadian oil sands operations, including the Kai Kos Dehseh (KKD) oil sands project for up to C$832m (US$626.3m), to Athabasca Oil. Meanwhile Chevron, the second largest US oil producer, is reportedly seeking to divest its 20% interest in the AOSP for around US$2.5bn, while CNOOC has shed some small assets in Canada as well. Overall, billions of dollars in oil sands assets have been shed over the last year by larger oil and gas companies as they focus on investment elsewhere. Finally, due to lower oil prices ExxonMobil has decreased its estimate of commercially available oil and gas reserves, including 3.5bn barrels of reserves from the Kearl project in Alberta.

The buyers of assets sold by the Majors are Canadian oil firms, such as Cenovus, Canadian Natural Resources and Suncor Energy, as well as some institutional investors. In December 2016 Cenovus revealed plans to raise its 2017 upstream investment to C$1.2bn-1.4bn (30% higher than 2016), including an expansion of the Christina Lake project. Suncor, Canada’s largest oil producer, is also raising output at Syncrude Canada, one of Canada’s largest oil sands projects. These Canadian firms expect to report better financial results in future, helped by higher heavy oil output brought about through fresh asset acquisitions.

The Majors, however, have not completely exited the oil sands, and still maintain a presence even though they have reduced their exposure to the region for now. Shell, after selling assets in the sector, will continue to control ancillary operations in Alberta; Statoil will also remain indirectly exposed to the oil sands through its 20% stake in Athabasca Oil; and ConocoPhillips continues to operate in the region through the Surmont joint venture with Total. Furthermore if oil prices rise some of the recent asset write downs could be reversed.

The road ahead

Last year investment in the oil sands sector plummeted, and it may take some time before there is a full recovery. Another challenge for the sector is limited infrastructure, which currently only permits oil sands to be exported to the US. The revival of the Keystone XL pipeline project by the Trump administration has raised hopes of expanded export capacity to the US, while the Trudeau government is considering other projects that would link the oil sands with eastern Canada, where oil is imported. Pipeline projects also exist to link the oil sands to the Canadian west coast, to enable exports to Asia, but these face tough opposition from environmental and indigenous groups. In the meantime, however, the future of the Canadian oil sands will be influenced by the industry’s ability to attract the investment necessary to maintain continued production growth. If oil prices recover interest in the oil sands from Major players may be re-ignited, with investment flooding back into the region. For now, however, local industry players have assumed a bigger role in oil sands developments as the Majors have divested, and this will contribute to maintaining the region as a key driver of Canada’s overall oil production growth in still difficult times.


Germany awards subsidy-free offshore wind contracts

May 15th 2017

In April 2017 Dong Energy AS and EnBW AG both won subsidy-free offshore wind contracts for projects in the North Sea off the coast of Germany. In successfully offering a bid price of zero euros per MWh for three projects, the two companies will not receive any government subsidy on top of wholesale power prices. This is the first time that offshore wind projects have been contracted without a subsidy, representing a landmark development for offshore wind in particular and renewable energy in general.

Dong Energy and EnBw the winners

Bundesnetzagentur, Germany’s federal electricity regulator, recently awarded three contracts in the first of two auctions for offshore wind capacity to the two European energy outfits. Two contracts were won by Dong Energy to construct two offshore wind projects – OWP West (240 MW) and Borkum Riffgrund West 2 (240 MW) – for a contract price of zero euros per MWh. Additionally, Dong will construct a third wind farm, Gode Wind 3 (110 MW), for a bid price of €60/MWh (US$65.20). Dong Energy hopes to make a final investment decision on all three projects in 2021, with the wind farms expected to come online by 2024. The company also aims to install offshore wind capacity of 11-12 GW globally by 2025.

EnBW, however, won the biggest contract of the auction, He Dreiht (a 900 MW project), also with a bid price of zero euros per MWh, to be commissioned in 2025. EnBW expects to achieve considerable synergies with He Dreiht, owing to its proximity with two other upcoming North Sea wind farm projects, Hohe See and Albatros. EnBW currently operates two offshore wind farms with a capacity of 336 MW in Germany, with another 1,510 MW expected by 2025 (Hohe See, Albatros and He Dreiht combined). Bundesnetzagentur offered 1,550 MW of capacity in total at this first auction, with Dong Energy and EnBW being the main successful bidders, accounting for 1490 MW, or 96%, of that amount.

Growing renewable energy market

The use of a subsidy-free contract has the potential to expand the use of cheaper offshore wind, which currently is a capital-intensive low carbon technology. As a result it represents a breakthrough for clean energy, not just in Europe but also worldwide. Support for renewables in countries such as Germany has been strong. However, policymakers’ concerns have also grown because of the costs of subsidising low carbon technologies to tackle climate change and reduce dependence on fossil fuels. But with technologies such as offshore wind becoming more cost competitive, the need for subsidies may fall substantially over time, enhancing a lower cost pathway towards the goal of de-carbonisation.


The unsubsidised offshore wind contracts can, however, prove risky for developers as they are largely based on the assumption of increasing wholesale power prices as thermal power capacity, such as coal and nuclear, is retired. The projects awarded in Germany could also prove to be more feasible compared to elsewhere because of conditions unique to the North Sea, such as the high density of existing wind projects and favourable climactic conditions. However, unsubsidised wind power could become more common globally over time as costs fall and countries increasingly seek lower carbon pathways to meet their electricity needs. The success of the offshore wind contracts in Germany may be a litmus test for the viability of lower cost renewable energy.


Oil price recovery and cost cuts drive rebound in oil sector

May 23rd 2017

A substantial recovery in global oil prices and cost cutting has helped the world’s largest oil and gas producers enjoy improved financial results for the first quarter of 2017 compared to the year ago period. The welcome financial recovery for many companies was mainly due to the rise in oil prices, while companies are also becoming more efficient in their operations and reaping the benefits of cost-cutting.

Companies leading the recovery brigade

Several companies improved their financial performance in the first quarter of 2017 compared to the year ago quarterly period. Exxon Mobil, the largest US oil producer, recorded a more than twofold rise in its attributable net profit, while Chevron moved to profit, recovering from a loss a year earlier. Across the Atlantic, UK’s BP moved to profit as well, compared with a year-earlier loss, while Anglo-Dutch Royal Dutch Shell posted a more than fourfold rise in its attributable profit. France’s Total reported a 77% rise in profit, and Norway’s Statoil posted a 74% jump in its net income.

Factors driving financial gains

In the first quarter all companies benefitted from higher crude oil prices, even though in some cases oil production dropped from the year ago period. Companies have also turned their attention towards less expensive regions for exploration, such as the Gulf of Mexico, offshore Egypt, Argentinian shale and offshore Mozambique, while exiting more expensive regions such as the Canadian oil sands. They have also cut costs widely through job reductions, asset sell-offs and restructuring. Companies have now increased their capital budget forecasts now that debt is becoming more manageable.

Challenges ahead

In order to become more efficient, energy companies have been prioritising their operations around upstream development. Indeed companies such as Shell, Exxon, BP and Chevron are exiting non-exploration businesses and concentrating instead on increasing upstream output. This strategy is essential as asset divestments have reduced potential for growth, while some oil companies have revised down booked reserves since the oil price collapse in 2014. Meanwhile oil prices remain under pressure despite efforts by OPEC to shore them up with output cutting. Times are better than the beginning of 2016 when prices were wallowing in the $25-30/bbl range, but the industry isn’t quite of the woods yet. Going forward oil companies will still need to adjust to the lower for longer oil price scenario.


The new giants of the Indian market

July 6th 2017

Indian smartphone brands, seeking a government curb on Chinese electronics products, must step up innovation to survive the onslaught from Chinese competitors.

Chinese smartphone makers are vigorously expanding their presence in India, pushing local competitors to the fringes. According to recent data from India Ratings & Research, a market researcher, the Indian market share of Chinese brands such as OPPO Electronics, Xiaomi, Vivo and Gionee has grown by more than three times, from 15% in the first quarter of 2016, to over 51% in the same period this year. Meanwhile in 2016 total smartphone shipments to the country grew by 15% year on year, to 29m units, according to Counterpoint, a research group. The trend will gain more strength in the near future, as Chinese companies prepare to launch new and improved products to gain income from the world’s fastest growing smartphone market.

A piece of the Indian pie

Amid the Chinese onslaught, the local market share of Indian companies such as Micromax Informatics, Intex Technologies, Lava International and Karbonn Mobiles shrank to below 14% in the quarter, from about 41% a year earlier. They have been beaten by the high-end specifications and competitive pricing of Chinese smartphones, particularly as demand has shifted away from sub-US$100 models to the higher US$100-200 price point. As a result, during the quarter ended in March, Oppo, Xiaomi and Vivo replaced Micromax, Lava and Karbonn in India’s top five ranking of smartphone brands. Increasing investment in research and development, as well as widespread marketing campaigns backed by a strong cash balance, has given Chinese companies an upper hand over Indian players that are lagging behind in terms of innovation.

In 2015 India overtook the US to become the world’s second-largest smartphone market by shipments after China. While the involvement of Chinese manufacturers has helped the Indian market to grow, Chinese competition has not only affected Indian companies, but also eaten into the markets of other foreign companies in India. Samsung continued to lead in the Indian market, with a 28% share in the first quarter of 2017, backed by its broad range of smartphone models. However, its highest-selling product in the fourth quarter of 2016, the Samsung Galaxy J2, was toppled by Xiaomi’s Redmi Note 4 to become the highest-shipped smartphone, according to International Data Corp, a market researcher. Apple has had even greater difficulty in the Indian market. According to CyberMedia Research’s quarterly mobile market review for India, Apple was the fifth-largest smartphone brand in India in the quarter, with around 9% market share, as its premium smartphones were challenged by Chinese brands such as OnePlus, a premium Chinese brand that offers cheaper products with market-leading specifications.

India is vital for the long-term income increase of global smartphone makers, with the market experiencing strong growth, as opposed to the plateauing of demand and intense competition in many major international markets. Mobile penetration in India is expected to reach 108 per 100 people by 2021, compared with 70 a decade earlier. The Economist Intelligence Unit expects the number of mobile phone users to rise at an annual average rate of 6% over the next five years to more than 1.5bn.

Tough road ahead 

Indian smartphone makers will face increasing competition in future as Chinese manufacturers spread their products portfolio, with new smartphones featuring curved screens, dual rear and front cameras, the latest Qualcomm Snapdragon 835 chipset and higher RAM specifications. Chinese products are typically more expensive than their Indian counterparts, but the former are still more popular, owing to better features and build quality. To restrain competition, Indian smartphone makers have sought anti-dumping duties on Chinese imports, similar to India’s restrictions on imports of certain low-priced chemical and steel products from China. Indian companies have also urged the government to impose levies on Chinese phones assembled in India.

However, such restrictions are unlikely to have an impact on the smartphone industry, after the government introduced a 10% duty on imported phones in its latest tax reform, the Goods and Services Tax, which became effective on July 1st. Under the GST, India also introduced a tax of 12% on all mobile phones, both imported and locally assembled. Still, although electronics consumer products have a significant impact on India’s trade balance, the sector is unlikely to attract trade curbs from the government, given the latter’s appetite to attract foreign investment. What’s more, in terms of the mobile phone industry, it accounts for 6.5% of GDP currently, although this is expected to grow to 8.2% by 2020.

Moreover, international smartphone makers, from Xiaomi to Apple, have set up manufacturing facilities in India to circumvent any possible trade curbs. Companies are also sourcing components locally to reduce cost. The strategy falls in line with the country’s “Make in India” campaign that is targeted at promoting foreign investment in India.

To compensate for their mobile market losses, Indian companies first expanded into making TVs, and have now moved into the manufacturing of home appliances, such as refrigerators, air conditioners and washing machines, among others. Micromax has also expanded into new markets such as the Middle East and North Africa, as well as Russia. Meanwhile, the Indian government has also been asked to extend financial assistance in the form of subsidies and incentives to strengthen the country’s mobile sector. But that assistance will need to be followed by Indian companies improving the quality of their products to put them on a par with Chinese competition.

All eyes on in India

Xiaomi, which is planning its third manufacturing site in India, recorded US$1bn of revenue from India in 2016 and expects to double it during the current year. Over 95% of its smartphones sold in India are made in the country. While its revenue increase has been boosted by online sales, Xiaomi last month opened up its first customer-facing operation in the Indian city of Bengaluru to improve brand building. It plans to open 100 more such outlets in the next two years.

OnePlus expects the Indian smartphone market to come close to China’s in terms of size over the next 3-5 years, rising to an annual volume of 400m units, from 120m this year, the company’s chief executive Pete Lau told The Times of India recently. In comparison, China’s market is expected to be around 450m strong over the same 3-5 year period. Meanwhile, Oppo and Vivo recorded sales increases of seven to nine times over the financial year 2017 ended March, respectively. India Ratings expects Vivo and Oppo’s smartphone sales to jump by around 40%-50% over the current financial year. Rapid progress in fast-speed mobile data consumption is touted as the main driver behind the income growth.

India is the new China is terms of smartphone growth and is crucial to manufacturers, owing to lower levels of competition compared with the Chinese market. During the first quarter of 2017, the average selling price of a smartphone in India increased by 18% to US$155, with almost two-thirds of smartphones sold by Chinese companies in the US$100-U$200+ price range. This was a considerable shift from the sub-US$100 range and showed the changing preferences of Indian consumers. As Chinese companies move upwards in terms of pricing brackets, Indian companies have retreated to the sub-US$100 and mid-range segments for income growth.

While Indian companies’ demand for trade restrictions on their Chinese peers comes across as counter-productive for the sake of innovation and industry growth, their complaints of unfair treatment are understandable. The Chinese technology sector, which has now spread worldwide, was backed by state subsidies and incentives in its nascent days. From that perspective, more support for the mobile sector from the Indian government is required, to both stimulate the manufacturing sector and allow more room for growth of the domestic smartphone makers, which are a key part of the local manufacturing sector. At the same time, such a strategy can also prove vital for India in maintaining its trade balance with China.


EVs present long term challenge to oil producers

August 14th 2017

Accelerated growth in electric vehicles sales will challenge the dominance of oil as the prime fuel for passenger vehicles.

Oil producers are showing signs of recovering from the oil price crash of 2014, with prices stabilising at around the $45-$50/bbl for most of this year and firms cutting costs to reflect the new low oil price environment. These improved circumstances have encouraged some firms in the industry to increase exploration and production budgets after a multi-year year lull. But as the oil industry is consolidating operations and looking for new exploration opportunities as they adjust to a “lower for longer” scenario, a longer term challenge to the industry looms on the horizon: the emergence of electric vehicles (EV). In addition to technological improvements and falling costs a number of countries have pledged to eliminate further sales of cars running on petrol and diesel by a certain year in the future, and some automakers have signalled they will shift from the internal combustion engine cars to EVs. The era of the petrol or diesel-fuelled car will not end tomorrow, but seismic shifts are underway that pose a longer term challenge to the primacy of oil as the source of energy for passenger vehicles.

The shift from oil to electricity

The 2020s will be a decade when EV sales pick up the pace, with automakers increasing their offerings of full and hybrid electric cars, plug-in versions of hybrids and fuel cell vehicles. The improving economics of EVs have encouraged automakers to increasingly embrace EV battery technology, especially among traditional carmakers wary of the rise of rival EV manufacturers such as Tesla. As a result some have decided to enter the EV market, given the sharp drop in manufacturing costs owing to innovation that is expected to make full-electric cars more competitive with fuel vehicles by as early as 2022, according to Bloomberg New Energy Finance (BNEF). Tesla—a US company that has been a benchmark for the EV industry—has priced its upcoming mass-market electric sedan, Model 3, at US$35,000, at least 60% cheaper than its sports utility EV, the Model X. EVs are likely to emerge from the fringes of the car market to being a core business strategy for many automakers in the future. Indeed, Volvo has committed to making only EVs from 2019 while Volkswagen is aiming to sell 1m pure electric cars annually by 2025.

Longer term impact on oil consumption

Oil and gas producers will still invest in exploration and production to meet rising global oil demand, which is still increasing annually by over than 1 million b/d. Transport accounts for about 50% of global oil consumption, but only half this share is taken up by demand from passenger vehicles. Thus fuel consumption from cars accounts for about 25% of global oil consumption overall. So while an acceleration of EV sales will not affect demand for oil from all parts of the transport sector, or demand for oil for non-transport uses, it will have some impact on slowing oil demand growth, or even contribute to it eventually peaking.

The requirement for oil will not totally go away but governments are already making moves to ban the sale of fuel vehicles. Norway already has a large fleet of EVs on the roads, while the Netherlands, UK and France plan to take all fuel vehicles off the road by 2040. ING Group forecasts that by 2035 all new cars sold in Europe will be EVs. Meanwhile in Asia, India has an ambitious plan to stop selling fuel vehicles by 2030, while China wants EVs to make up 11% of all car sales by as close as 2020. Several governments are also offering tax breaks and other financial incentives to encourage EV sales. EV sales are likely to grow very quickly over the next few decades, with the only question being what the level of penetration will be for EVs in the passenger vehicle market.

Facing long term reality

The EV market will expand but from a very low base, given that EVs represented less than 1% of total global passenger car sales last year. Major oil companies still pin their faith on oil consumption continuing to grow for a while, driven mainly by increasing demand from faster growing non-OECD economies. As a result they will continue to invest in developing hydrocarbons to meet growing consumption in the short to medium term. Yet the shift to EVs seems inevitable, however, and oil producers are increasingly considering the impact of electrification of the transport sector on global oil demand going forward.


US to get first nuclear plant expansion in decades

September 21st 2017

Southern Company, a US power utility, has decided to go ahead with the expansion of its Vogtle nuclear power plant. If successful, the project will mark the first addition to nuclear capacity, in terms of new units coming online, in nearly four decades. However, the go ahead for the project has come after much delay, and at a time when nuclear power is struggling to maintain its share of US power generation.

Georgia Power, a subsidiary of Southern company, on August 31st announced its intent to complete the long-delayed expansion of the Vogtle nuclear power plant in the US state of Georgia. The US$19bn project will add two new units to the facility, which currently has a total capacity of 2.4 GW from two operational units. These units, 1 and 2, run on pressurised water reactors manufactured by Westinghouse Electric, Toshiba’s US-based nuclear reactor business. This company is also contracted to deliver two new reactors – the advanced Westinghouse AP1000 water reactors – which will be units 3 and 4. Georgia Power had weighed the feasibility of the project in the light of difficult project economics, changing market dynamics in the electricity sector, and Westinghouse’s bankruptcy protection filing earlier this year. Nevertheless, it concluded that will go ahead with the plant expansion.

Georgia Power has filed a construction plan with the state authorities and expects units 3 and 4 to commence operation in late 2021 at the earliest, six years behind schedule. Faced with challenges in the past, it had discussed switching to a gas-fired operation or cancelling the project altogether. Georgia Power’s latest decision will, however, provide some relief to Westinghouse, which has slowly been wrapping up its reactor building business.

Future of nuclear power in the US

Expansion of the Vogtle plant comes as nuclear energy is competing to maintain its market share in the US, amid rising capacity from other energy sources such as natural gas and renewables, and relatively static levels of electricity consumption. The upfront costs of nuclear infrastructure have also discouraged investment. As of the end of 2016 the US had the largest nuclear-generating capacity in the world, with 99 nuclear reactors at 61 power plants and total capacity of about 100 GW. However, the US Energy Information Administration (EIA) forecasts nuclear’s share of the US electricity generation mix to drop to 11% by 2050, from 20% last year, as more capacity is retired than constructed and other sources expand their respective share. The expansion at Vogtle is, at this stage, the only new project on the horizon, with other capacity expansion coming from infrastructure upgrades at existing plants.

It is therefore unlikely that the Vogtle expansion will trigger new investor interest in the US nuclear sector, despite renewed support for nuclear energy from the Trump administration. Rick Perry, US energy secretary, had recently called for usage of smaller reactors and lower-cost technologies to drive growth in the nuclear sector, but it remains to be seen whether this will eventuate.


Gulf states push for solar power

November 6th 2017

The oil-rich states of the Persian Gulf region, led by Saudi Arabia and the United Arab Emirates (UAE) in particular, will see a rise in the number of new renewable energy projects entering service. The rationale from states in the region in building renewables capacity is to free up oil and gas for export while providing cleaner electricity to fast-growing domestic markets.

Upcoming projects to increase renewable capacity

In early October, Saudi Arabia awarded a contract to construct a 300 MW solar plant. Weeks before the UAE had announced a contract to expand capacity at a giant solar plant. Meanwhile Qatar, another oil and gas-rich state in the region, expects to bring online its first utility-scale solar project in 2018. Last year, Kuwait started operating its first solar plant and plans to build more capacity over the next five years. Solar has emerged as the preferred source of renewable energy among the Gulf states due to the region’s favourable climactic conditions.

Make power while the sun shines

Among the larger Gulf States renewable energy capacity will grow. This will be timely as the region’s power generation capacity will need to increase to keep up with growing domestic electricity consumption. Owing to its vast hydrocarbons reserves the region has not prioritised renewable energy investments in the past. However, the multi-year downturn in global oil prices has encouraged Gulf states to shift their economies away from too much reliance on fossil fuels. Furthermore, a steep drop in solar module prices and growing financial assistance from national governments have supported the establishment of photovoltaic capacity especially.

Bright future for renewables in the Middle East

Saudi Arabia is targeting capacity of 9.5 GW by 2023 with investment reaching US$50bn. Besides 300 MW of solar capacity, Saudi Arabia plans to set up 400 MW of wind capacity as well. This is to be followed up with tenders for additional wind and solar capacity of over 1 GW. In the UAE, solar capacity is primarily accounted for by Dubai’s Mohammed bin Rashid Al Maktoum solar park, with estimated capacity of 5 GW by 2030. The nation is also establishing a 1.2 GW solar plant near Abu Dhabi. The UAE will be investing US$160bn to ensure that by 2050 50% of the nation’s power consumption is supplied by renewable sources.

Meanwhile, Kuwait aims to produce 15% of its power from renewable sources by 2030 and plans to issue a tender for a 1 GW project early next year. In Qatar, solar power’s contribution to total generation capacity is estimated to rise to 6% by 2021. Projects have attracted the interest of foreign developers such as Électricité de France SA (EDF) and China’s Shanghai Electric Power Co Ltd, apart from local power utilities such as Saudi Arabia’s ACWA Power, Abu Dhabi Future Energy Co (Masdar).

Challenges ahead for clean energy

The Gulf states’ ambitious solar projects are still dependent on the region’s oil export income as a source of financing. Moreover, the success of solar projects in the region will depend on their connection to centralised power grids, which are also in urgent need of expansion. Sand and dust accumulation on panels has also been challenging for the efficiency of solar power usage in the region.

Renewables to get stronger in the oil-rich states

The Gulf states are trying to harness the region’s abundant solar resources to meet rising domestic energy demand. With the cost of solar panels and related infrastructure estimated to fall further, the economic viability of projects will increasingly lead to less reliance on fossil fuels for growing domestic energy consumption over time.


Oil recovery revives exploration interest in North Sea

Oil and gas producers from around the world are returning to drill in the resources-rich North Sea region, where until recently upstream activities have been on the decline. A multi-year downturn in global oil prices had dented the profitability of exploring the region, which is known for being capital intensive. However, a modest recovery in the oil market has led to new drilling expeditions as well as active acquisitions and investment activities. Companies, eager to find new hydrocarbon reserves, are relying on the existing infrastructure in the region to tackle high operations cost. Besides North Sea, the return has also targeted Barents Sea and Norwegian Sea.

Return to the North Sea 

The comeback is driven by promises of rich hydrocarbon reserves in the North Sea—estimated at around 2.2bn cu meters of oil equivalent at end-2016. Coming out of the downturn, oil and gas producers have rushed to strengthen their reserves holding, while taking advantage of a drop in asset valuations and industry service costs. In line with this, in August, French energy giant Total gained control of vast exploration acreages in the North Sea as part of its US$7.5bn takeover of the oil and gas business of AP Moller–Maersk, a Danish conglomerate. Meanwhile, in May, UK’s BP started production from the Schiehallion oilfield in North Sea—majorly owned by Royal Dutch Shell—following a nearly US$6bn redevelopment. The upgrade was aimed at revitalising the matured asset following its closure in 2013. BP is planning to double its UK North Sea output to 200,000 barrels of oil equivalent/day (boe/d) by 2020. The return is focussed not only in the North Sea, but across the Norwegian continental shelf (NCS), which includes the Barents Sea, Norwegian Sea and North Sea. Norway’s Statoil, Austria’s OMV, Italy’s Eni, Sweden’s Lundin Petroleum have announced oil and gas discoveries in the NCS region this year.

Factors behind renewed interest 

Apart from North Sea’s vast deposits, energy companies have rushed to claim stakes in Barents Sea’s reserves of around 241m cu meters oil equivalent as well as Norwegian Sea’s holding of around 574m cu meters oil equivalent, as of end-2016 respectively. In January, Statoil acquired 29 exploration licences in the NCS region, which is at the core of its upstream operations. Meanwhile, BP and Shell’s recent investment in Schiehallion and its adjacent oilfields is expected to release additional resources of around 450m barrels, extending the life of the oilfields to at least 2035. The region has produced nearly 400m barrels of oil since production started in 1998. BP and Shell have also set up new infrastructure to aid output growth. The return to the North Sea is further backed by a strategy to use the existing upstream infrastructure in the region in order to reduce exploration costs. For instance, Total, with its Maersk deal, expects to generate annual savings of more than US$400m, primarily from combination of assets. These factors have led to companies’ discovery of new oil and gas deposits in the Barents Sea, while identifying multiple additional prospects. The new assets will be core to reserve replacement as production drops from the old fields.

Challenges facing investment

The explorers’ return to North Sea, however, comes amid continuing uncertainties related to future reserve estimates as well as volatilities in the commodity market. This has kept a much larger number of oil and gas producers from investing in the capital-intensive region. Hydrocarbon reserves in the North Sea off the coast of the UK are estimated to dry out in the next decade. Meanwhile, Statoil’s several past oil expeditions in Barents Sea have led to only small gas discoveries, raising questions about the economic viability of drilling in the region. Moreover, increased exploration activities across the Americas as well as in offshore Asia-Pacific and Africa have kept the oil price recovery under check, thus limiting upstream investments. Operational hurdles in the region, known for adverse climatic condition, and related costs have also dented interests. The uncertainties have led to BP and Shell, among other companies, reducing their activities in the NCS region. Instead companies are focusing on up-and-coming high-margin acreages such as those in offshore Brazil, Mexico, Egypt and Australia. The shift-out is unlikely to slow down unless new hydrocarbon reserves are discovered in the North Sea in the coming years.

Future of exploration in North Sea

Despite the challenges, oil and gas companies are investing in the North Sea. A chunk of the activities is represented by independent oil and gas companies such as Chrysaor Holdings, Siccar Point Energy and Neptune Oil & Gas that have picked up assets from majors such as Shell, OMV and Engie, respectively, in the region. In June, BP merged its Norwegian operations with a local rival, Det Norske Oljeselskap, to improve income margin from the region. The merged entity, Aker BP plans to drill six to eight exploration wells in 2018, including four wells in the Barents Sea. The new company aims to discover 250m boe of reserves over 2016-20 from the NCS. Meanwhile, bigger regional rival, Statoil, is expected to start production from the giant Johan Sverdrup oilfield in the North Sea by end-2019. The Norwegian company said that its recent unsuccessful exploration campaigns in the Barents Sea showed cautious optimism for reserves in the neighbouring acreages. In line with the trend, Chevron recently approved an investment to increase output from its Captain oilfield in the North Sea.

North Sea to remain crucial 

Following a decade of weakness, North Sea has emerged as the second-most active hydrocarbon exploration spot in the world, behind the US shale. The majority of the deals struck in European energy space this year was focused on the North Sea.  Promises of new acreages as well as ageing assets that can potentially be reived with improved technologies and funds from private equity outfits are driving activities in the region. As a result of all the interest, this year North Sea is expected to record its highest annual output in a decade.

Leave a Reply

Fill in your details below or click an icon to log in: Logo

You are commenting using your account. Log Out /  Change )

Facebook photo

You are commenting using your Facebook account. Log Out /  Change )

Connecting to %s