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Shell will acquire German startup sonnen, staking a claim on the home energy storage market and further expanding its ever-increasing footprint in the clean energy industry.
Sonnen distinguished itself in the early home-storage market, with thousands of units deployed across Germany, and a notable presence elsewhere in Europe, the U.S. and Australia. Besides storing solar power for homeowners, sonnen aggregates its installations into controllable networks of grid resources.
It would be hard to overstate the opportunities that arise from teaming up with a global energy giant. Shell manages a full stack of energy services, including generation, trading and customer relationships. It could integrate energy storage with a number of other services.
The backing of Shell could propel sonnen to new scale and customer awareness as it competes with Tesla’s Powerwall and LG Chem’s Resu for customers that want to control their home energy.
“Our intention is to position the product so customers love it and buy it a lot,” said Brian Davis, VP of energy solutions at Shell, in an interview. “Whether it’s No. 1 or No. 2, that’s a matter for the market to decide.”
Flurry of investments
The acquisition escalates Shell’s involvement in futuristic grid startups. In just the last month, the company invested in a novel wind power venture called Makani and acquired Greenlots, a major U.S. electric vehicle charging company.
Shell first invested in sonnen in May 2018 as the leader of a $71 million round. That brought the sonnen’s total funding to about $180 million. The companies did not disclose the price paid for full acquisition.
The initial investment came with a “strategic cooperation agreement” with Shell New Energies, to develop “innovative integrated energy propositions, enhanced EV charging solutions and the provision of grid services that are based on sonnen's virtual battery pool.”
Since then, Shell learned more about sonnen, and liked what it saw, Davis said.
“They’ve got a really very good product and a great customer-centric innovation strategy,” Davis said. “What they’re trying to do and what we’re trying to do are very complementary.”
In particular, Davis liked that sonnen’s battery system comes in a single package with the necessary power electronics built in, making it easier to install. Additionally, it uses a lithium-ferrous-phosphate battery chemistry, which is considered safer and longer-lasting than the more energy-dense chemistries designed for car batteries and repackaged in boxes for homes.
The new corporate parent provides financial stability for sonnen as it continues to scale. That’s valuable, because the residential storage business is not an easy one to crack.
The rise of home solar, and intermittent renewables more broadly, spurred industry to find ways to store that power for use on demand. Still, the residential battery market remains minuscule compared to home solar, with few markets where the investment currently makes economic sense. The U.S. installs a few thousand residential batteries per quarter, and that’s after precipitous growth from where it was two years ago.
Tesla seized the popular imagination with its splashy Powerwall launch, but it remains more focused on making cars than proactively dominating the home battery business. LG Chem’s much less splashy Resu has found its way into homes, in part through a partnership with home solar installer Sunrun.
Numerous other storage vendors have run out of money while waiting for the market to arrive. Even well-known and well capitalised Mercedes-Benz, which once appeared like a viable contender to Tesla, pulled out of the business after reassessing the profit to be made.
Oil and gas supermajors are uniquely disposed to plan on a longer time horizon than many corporations. Home storage may not end up in every home, but it will be a lot bigger in the near future, Davis said.
“It will be a mass-market product in a lot sooner than 10 years,” he said. “The product is moving down a cost curve and will increasingly get more and more affordable for more and more people.”
By working together with sonnen, he added, “We can do a lot more, much faster.”
Now there’s a clear path to delivering the enhanced EV charging and grid services promised with Shell’s first investment in sonnen.
Greenlots, one of the major North American charging network companies, has become a corporate sibling to sonnen’s smart storage operation. Sonnen has remained focused on the residential space, so its product would need some tweaking to fit the needs of an electric vehicle charging station, but the technical expertise is there.
Similarly, sonnen’s efforts to aggregate power from thousands of homes and wield it as a grid resource could likely grow with the expertise of Shell’s trading desk.
The German regulatory regime allowed sonnen to build up its community and trade power on the grid with relative ease, but U.S. regulation has thwarted that approach. Instead, sonnen has partnered with homebuilders to put its battery systems in large new developments, with the intention to figure out grid services once constructed.
Shell could take that idea into deregulated markets, where regulated utilities don’t monopolize the delivery of electricity. Sunrun recently proved that could be done by winning a capacity contract in the New England wholesale market with a network of home solar and and battery systems.
Sonnen also delved into the world of high-end home automation with ecoLinx, which can manage a home's energy consumption in coordination with other appliances. The company promised to bring smart home-enabled battery systems to a more accessible price point, and can pursue that goal with Shell's help.
Taken as a whole, Shell New Energies’ spectrum of services overlaps considerably with what a traditional electric utility would do, besides maintaining the poles and wires.
“We’re not trying to replicate what others have done in the past — we want to offer customers what they want going forward,” Davis said. “In some sense, we’re trying to create the utility of the future.”
So far, that utility includes clean energy, electric vehicles and distributed energy storage, and there’s no reason to expect the drumbeat of investment will stop there.
A number of US law firms have announced investigations into Bristow Group on behalf of investors the move comes after the firm last week cast doubt on the validity of its own finances.
The company, which has a base in Aberdeen serving the oil and gas sector, saw its share price tumble last week after it reported “material weaknesses” in its financial reporting.
Several US legal firms have announced they are starting investigations into whether Bristow had violated federal securities laws or carried out any other unlawful business practices.
Those investigating include Glancy Prongay & Murray of Los Angeles, Block & Leviton of Boston and Levi & Korsinsky of New York.
Another, Kirby McInerney, issued a statement saying “this investigation concerns whether Bristow has violated federal securities laws and/or engaged in other unlawful business practices”.
Following last week’s announcement, Bristow’s share price dropped 40% from $3.00 to $1.80. A massive drop from its peak in 2018 of $18.72
The firm, which employs around 900 people in the UK, said there would be no impact on its UK operations.
In a press release issued yesterday, the firm said the “weaknesses” in its financial reporting related to the removal of certain helicopter engines from pledged or leased airframes.
The firm said it is “continuing to assess” the impact of the issue on Bristow’s balance sheet and is working to “develop a remediation plan”.
Yesterday, Bristow offered more specifics as to the “material weaknesses” in its internal controls it first revealed on February 11. The company said it is related to the fact that “certain pledged and leased helicopter engines were not matched to specific pledged or leased helicopter airframes or returned to such airframes within specified periods, as is required under certain of the secured financing and helicopter lease agreements.”
According to Bristow, removal and replacement was part of its normal and ongoing maintenance operations. However, “since certain of those helicopter engines and airframes are pledged to lenders or leased from lessors, the removal of a pledged or leased engine from a pledged or leased airframe can create issues of non-compliance with certain of the secured financing and helicopter lease agreements.”
Bristow said the issue affected a small number of its 385 helicopter engines subject to secured financing or helicopter leases, noting the issue was discovered and cured for all but nine engines related to three agreements before Dec. 31, 2018. Those engines were not returned to pledged airframes due to delays with certain maintenance service providers, Bristow said, adding that it had obtained non-compliance waivers under applicable agreements related to those engines.
The company said it needs to obtain waivers from secured equipment lenders and helicopter lessors related to non-compliance of non-financial covenants under related agreements as of Dec. 31, 2018 and prior periods. Without the waivers, certain debt balances would need to be reclassified from long-term to short-term under accounting rules.
Reclassifying the debt to short-term would require Bristow to insert a “going concern” warning in its current and applicable prior financial statements filed with the SEC. Certain equipment lending/lease covenants at Bristow require the filing of audited financial annual statements (Form 10-K) “without any going concern explanation or limitation.” If Bristow is forced to insert a “going concern” warning in prior financial statements, then a “going concern” waiver would need to be obtained from the appropriate lenders/lessors.
Bristow further said the delay in filing its latest quarterly report (Form 10-Q) could trigger a delisting warning from the New York Stock Exchange.
New Russia sanctions proposed by members of the U.S. Congress could hinder the development of some natural gas export pipelines, but otherwise do little to harm the country’s largest energy companies.
A bill was introduced this week to punish the Kremlin over allegations it interfered in U.S. elections and exerts a "malign influence" in countries including Ukraine. If passed into law, it would prohibit investments in Russian liquefied natural gas facilities outside the country, and the supply of capital, technology or equipment to future domestic oil fields.
A third measure in the bill, banning the financing of any global energy projects supported by the Russian government or state-run companies, is the most significant, according to analysts at Fitch Ratings and Aton. It could delay new export links such as Gazprom’s Nord Stream 2 and the European leg of TurkStream, said Aton energy analyst Alexander Kornilov.
Both pipelines, which state-run Gazprom is building in the face of opposition in the European Union and the U.S., will carry Russian gas to Europe, bypassing Ukraine. The Nord Stream 2 link under the Baltic Sea is jointly funded by Gazprom and five regional energy companies. The planned TurkStream leg from Turkey to the EU is set to receive financing from a 50-50 joint venture between Gazprom and its Turkish partner.
If adopted, the sanctions may force foreign investors to stop providing capital to the pipelines, Fitch Ratings oil and gas director Dmitry Marinchenko said. "Yet in the worst case, Gazprom can finance the pipelines on its own," he said.
Nord Stream 2 is set to cost $10.7 billion, and by the end of 2018 the project had received about 80% of the total financing, Gazprom CEO Alexey Miller said at the time. The Russian gas giant estimated its own spending on the TurkStream extension infrastructure this year at around $1.15 billion.
LNG on the Radar
The LNG sanctions listed in the new bill would not have an immediate impact because there are no such projects right now. The nation produces the fuel only within its borders, with Gazprom operating a plant on Sakhalin Island in Russia’s Far East, and Novatek PJSC running a new plant on the Yamal Peninsula in the Arctic region.
Those companies have no plans to construct LNG plants abroad and are focusing on new local projects. Novatek is preparing a final investment decision for a second Yamal plant and mulls a third facility on the peninsula, while Gazprom aims to expand the Sakhalin project and build a plant on the Baltic coast.
So, the sanctions would do nothing to curb Russia’s drive to raise its share of the global LNG market to as much as 20% by 2035, after doubling its share to 8% last year.
"The ban on non-existing Russian liquefied-gas projects abroad is a rather unpleasant signal" as it puts the nation’s LNG ambitions on the U.S. sanctions radar for the first time, Fitch’s Marinchenko said. "It is key for Russia that its future domestic LNG projects are not sanctioned eventually."
The proposed ban on financial, technology and equipment supplies to future Russian oil fields would also have little impact. Russia still relies mostly on projects launched back in Soviet times for the bulk of its crude output, with new major discoveries quite rare.
Still, in the long-run, the restrictions could hit Russia’s ability to maintain production, Marinchenko said. Overall, "the new sanctions package will hardly come as a shock for the Russian energy industry, yet it won’t go unnoticed either," he said.
Maersk Maker, the final vessel of Maersk Supply Service’s Starfish AHTS newbuilding series, was delivered yesterday from Kleven Yard. The vessel’s arrival completes Maersk Supply Service’s Fleet Renewal Program, with ten new-build vessels delivered and 23 vessels divested over the last three years.
The average age of Maersk Supply Service’s current 44-vessel fleet has been reduced to less than ten years. The composition of the renewed fleet – 30 AHTS vessels, 12 SSVs and 2 PSVs – supports Maersk Supply Service’s integrated solutions offerings for offshore projects in the areas of towing, mooring and installation; subsea construction; inspection, maintenance and repair; and light well intervention.
New-building program complete Ten new-build vessels have joined the Maersk Supply Service fleet since March 2017, including six M-class AHTS vessels of the Starfish series and four I-class SSVs of the Stingray series. Both vessel types have been designed to optimize reliability, energy efficiency, comfort, and safety.
“As some of the newest vessels operating in the offshore support vessel industry, they have proven their highly advanced capabilities from the moment of delivery. These vessels are building impressive track records within a range of services and we’ve received positive feedback from our customers around the world,” says CEO Steen S. Karstensen.
Vessel divestment program complete In 2016, Maersk Supply Service set out to reduce its fleet in response to the global over-supply of offshore support vessels. A total of 23 PSV and AHTS vessels have since left the fleet, with the final vessel divested in October 2018.
“It has been a priority for us to do our part in addressing the over-supply in the industry, as well as strengthening our asset base for project delivery. Here at the end of the renewal program, we have a more modern and competitive fleet to meet the needs of our customers,” says Steen S. Karstensen.
Oil majors increasingly are trying their hand at being alternative-energy minors.
Royal Dutch Shell Plc, which traces its roots back to the late 19th century, just bought Greenlots, a California software company serving the electric-vehicle charging sector. This follows other deals by Shell — along with the likes of BP Plc, Chevron Corp. and Total SA — to invest in renewable energy, retail power, batteries and other non-fossil fuel businesses.
For now, though, this is still pinky-toe dipping. Shell’s plan to invest $1-2 billion a year on “new energy” opportunities is a hefty check, but less than 10% of its capital expenditure budget. Besides anything else, there’s a straightforward reason for taking it slow: returns.
Oil majors have a testy relationship with investors these days. Shell’s stock is one of the better performers, but mainly because it has embraced a strategy centered on payouts: Its dividend yield scrapes 6%. A decade of high spending trashed return on capital across the industry.
Uncertainty around long-term oil and gas demand has compounded the erosion of trust when it comes to the majors’ spending plans. In a recent survey of institutional investors, the Oxford Institute for Energy Studies found hurdle rates required for new conventional oil projects have risen appreciably compared with historical rates of return, as investors price in risks around the energy transition.
In this context, alternative-energy investments can be justified on one level. A solar farm in the southwestern U.S. is a relatively low-risk project for a more risk-averse crowd. But they also raise a conundrum, especially if eventually done at a meaningful scale. As the chart suggests, investments in power-related infrastructure provide fundamentally different returns from what oil majors have offered historically. These companies have been built to take world-scale risks in the hope of generating high returns to match that.
French oil major Total provides a useful example here, because it has made some of the biggest investments in alternative energy businesses and, as a result, has come closest to actually splitting this business line out in its accounts. The “Gas, Renewables & Power,” or GPR, segment includes downstream natural gas activities, but it offers some insight to how these businesses compare with Total’s traditional operations:
While that chart shows what’s happened to returns, it doesn’t show relative scale. This chart shows average capital employed for each of Total’s divisions in 2015, when data for the GPR division begin, and 2018.
It’s hard to see there, but capital employed in the GPR business has risen by 18% a year, compounded, since 2015. In absolute-dollar terms, though, the upstream division has expanded by almost four times as much. The upshot is that a one-percentage-point improvement in return on average capital employed in the exploration and production business translates to $1.1 billion of adjusted operating income for Total — almost 16 times what a one-point improvement in the GPR business’ return would generate.
What complicates this further is the commodity cycle. Even if an oil major’s leadership has taken the view that oil demand is nearing a plateau, that doesn’t mean oil-price cycles are dead. And that can make a huge difference to returns in the traditional upstream and downstream bits of an integrated oil company. To get a sense of that, here is the annual change in adjusted operating profit by business line for Total over the past three years:
This may seem like a truism: Bigger divisions move the needle more. But this will continue to matter as oil majors discuss capital allocation with shareholders, who may well prefer to make their own decisions about allocating excess oil rents to new ventures rather than leave it to an oil CEO. Managers in dominant upstream divisions enjoying a commodity upswing may chafe at seeing budgets allocated to businesses that are ultimately antithetical to oil, even if they do fall under the rubric of “Big Energy.”
It can be argued that alternative-energy businesses may not necessarily provide the thrills of cyclical upswings, but they do generate steady returns. Certainly, renewable-power projects seem to do so. But these are still early days. John Abbott, who runs Shell’s downstream business and was in San Francisco last week for Bloomberg NEF’s summit on the future of mobility, told me and the audience quite candidly, “The reality is, in some of these value chains that we’ve been talking about, we don’t know exactly where the rent will sit.”
Hence, Shell is taking an integrated approach to power, electric-vehicle charging and the like, similar to its existing model in oil and gas, aimed at capturing margins on several levels. One critical question concerns whether or not value will move up and down the electrified value chain, the way it does with oil and gas. I think this will be less the case, with value tending to accrue at the customer-facing level, given that deflation in power generation is one of the primary drivers of greater electrification in the first place.
Proponents of oil majors pivoting to a brave new world can point to examples such as Ørsted ASA, the Danish oil and gas company that became an offshore wind-power giant. Two caveats, however: First, Ørsted’s target for annual return on capital employed through 2025 is 10% — about what you would expect for this sort of company but not an oil major. Second, getting investors comfortable with such a transformation is definitely a lot easier when you’re 50%-owned by the Kingdom of Denmark. For everyone else, the battle royal over what that incremental dollar goes toward — old energy, new energy, shareholders — is just getting going.
After decades of supplying itself and its European neighbors with natural gas, an era has officially come to an end for the Netherlands.
The country became a net importer for the first calendar year since it started production from the giant Groningen field in 1963. It joins European nations becoming increasingly reliant on sourcing fuel through pipelines from suppliers such as Norway and Russia or via tanker ships from the U.S., Qatar and elsewhere.
The shift was inevitable after the nation of 17 million vowed to close Groningen following earthquakes linked to extraction from the deposit in the north. Production from what’s left at the site will continue to earn billions for the Dutch state, Royal Dutch Shell and Exxon Mobil for a few more years at least.
The Netherlands gets about 40% of its energy from gas. GasTerra, a venture between the state and the two oil companies, on Friday said its sales rose 17% to $12.6 billion in 2018. More than a third of the fuel came from Groningen, for which it has the exclusive sales rights, with the rest mainly from smaller offshore fields as well as imports from Norway and Russia.
“Since the first molecules of natural gas flowed from Groningen, the Netherlands has been self-sufficient. No longer,” GasTerra CEO Annie Krist said. “Natural gas is still badly needed,” partly to meet increased demand in power generation to back up renewable sources and replace coal.
Wintershall was founded exactly 125 years ago, on Feb. 13, 1894. “A proud birthday only few companies get to experience,” says Mario Mehren, Wintershall’s CEO. Wintershall is now Germany’s largest internationally operating crude oil and natural gas producer. It was a long journey to achieve that: The company was originally founded to produce potash for use as a fertilizer. Here’s a brief look back at the company’s history:
How a chance event caused the company to change tack: from potash to crude oil
Heinrich Grimberg and Carl Julius Winter registered a joint drilling company for mining potash in February 1894. Its name was made up of the founder’s name “Winter” and the old Germanic word “Hall” for salt: hence Wintershall.
The company then took a completely new direction following a chance occurrence: an incursion of crude oil in a potash pit in 1930. That opened up a new field of business, since potash production had slumped as a result of the global economic crisis. This oil discovery and the proximity between the potash and crude oil were an opportunity Wintershall capitalized on. For example, Wintershall took a stake in two companies that had high-yielding oil sources near Hanover in 1931.
Wintershall is also taking a critical look at its own history in its anniversary year. For example, the Reich Drilling Program that was launched in the mid-1930s and in which Wintershall at the time participated. “We are tackling this part of our history head on,” says Mehren. “Openly and transparently.” Renowned historians are currently investigating the conduct of the German oil industry as a whole and Wintershall’s representatives back then. The results will be presented at a symposium held by the German Society for Corporate History in the second half of the year.
From crude oil to natural gas: The first pipeline in Germany is built
After the Second World War, natural gas production emerged as a new line of business for Wintershall. The company made its first gas discovery in 1951 at Bentheim in Lower Saxony and soon became a pioneer in natural gas production in West Germany – for instance with the first gas pipeline from Rehden to Marienhütte. However, it soon became clear that domestic oil and gas production alone could not cater for rising demand. Wintershall therefore began operations abroad – initially in Peru in 1954, then later in Libya, Canada and Oman.
Under the roof of BASF: expansion of international oil and gas production
In 1969, exactly half a century ago, Wintershall became a subsidiary of BASF. By taking over Wintershall, the chemical company secured its own supply of important natural resources. Conversely, Wintershall was able to expand its oil and gas business abroad as a result of the greater financial power behind it.
A milestone in the internationalization of Wintershall’s operations was an agreement concluded in 1990 with Russia’s Gazprom, the world’s largest producer of natural gas. What started as an agreement on marketing
Russian gas evolved over the next more than 25 years into close partnership: with joint gas production and infrastructure projects, like the Baltic Sea pipeline Nord Stream. As part of this close cooperation, the gas trading company WINGAS was established as a joint venture in 1993. In a large share swap in 2015, Wintershall relinquished its shares in WINGAS and in return was able to expand natural gas production with Gazprom in Siberia even further.
Whereas Wintershall has continuously increased oil and gas output since the 1970s, the Kassel-based firm has shed other business segments in the past decades. They include potash and rock salt business, which was hived off to the company Kali+Salz AG in 1970, and later the refinery business and service station chain NITAG/Deutsche Gasolin.
Besides Russia, the North Sea – and Norway in particular – is now a key pillar in Wintershall’s oil and gas production. Other major focus regions apart from Germany, the North Sea and Russia are South America, North Africa and the Middle East. “We are focusing on strategically selected regions,” states CEO Mehren: “Wherever we operate, we are one of the top companies. And in many cases even the leader.”
Wintershall and DEA have cooperated closely for decades and are now planning to merge
Wintershall is celebrating and commemorating its 125th birthday by publishing information and staging events in the anniversary year. They include an internal traveling exhibition, as well as special Internet sites and a school competition. A ceremony is also planned in Kassel’s documenta hall in November.
A look at Wintershall’s history also shows how far the cooperation with DEA Deutsche Erdöl AG, the other major German oil and gas producer, dates back. Wintershall conducted its first foreign project, in Peru, together with DEA. There were later joint projects in, for example, Libya, Norway and above Germany: Wintershall and DEA worked together to develop the two large German crude oil fields Schwedeneck in the Bay of Kiel and Mittelplate in the Wadden Sea in Schleswig-Holstein. The two companies are still producing oil together from Mittelplate. Yet the history of their cooperation also covers other fields: From the 1950s, Wintershall and DEA were involved in Deutsche Gasolin AG and later in Deminex GmbH, a joint venture of the German mineral industry that operated between 1969 and 1998.
Wintershall and the just five years younger DEA have therefore had close links with each other through numerous projects over the decades. Now the two German companies with their long and rich tradition are planning to merge. As Mario Mehren notes: “Wintershall and DEA have often worked side by side successfully. We now intend to move forward together: as Wintershall Dea. Two players who have already enjoyed long ties are now growing together.”
The merger between Wintershall and DEA will create Europe’s leading independent oil and gas company. “This merger is the right step at the right time to respond to the changes in our industry,” is the conviction of Wintershall’s CEO. “And so we’re doing precisely what has so often been the hallmark of Wintershall in its history: We’re tackling change and challenges – with the courage to adopt new approaches.”
Wintershall Holding GmbH, based in Kassel, Germany, is a wholly-owned subsidiary of BASF in Ludwigshafen. The company has been active in the extraction of natural resources for 125 years, and in the exploration and production of crude oil and natural gas for over 85 years. Wintershall focuses on selected core regions where the company has built up a high level of regional and technological expertise. These are Europe, Russia, North Africa, South America, and increasingly the Middle East region. The company wants to expand its business further with exploration and production, selected partnerships, innovation and technological competence. Wintershall employs about 2,000 staff worldwide from 50 nations and is now Germany’s largest, internationally active crude oil and natural gas producer.
At the end of September 2018, BASF and LetterOne signed a binding agreement to merge their respective oil and gas companies, Wintershall and DEA (Deutsche Erdöl AG). Subject to regulatory approvals, the transaction is expected to close in the first half of 2019. Wintershall DEA would become the leading independent oil and gas producer in Europe. BASF and LetterOne are planning an initial public offering (IPO) for Wintershall DEA in the medium term.
Equinor has awarded Kvaerner a front-end engineering design (FEED) contract for the planned Hywind Tampen wind power project in the Norwegian North Sea.
Kvaerner’s brief is to mature the design of concrete substructures for potentially 11 wind turbines based on Equinor’s floating offshore wind concept.
The scope includes identifying appropriate construction sites and putting together a plan for the construction and associated cost of the 11 floating concrete substructures.
Peder Christian Melleby, senior vice president Renewables at Kvaerner, said: “Another important part of the FEED contract is to establish an improvement agenda that targets cost and schedule drivers with the purpose of establishing the safest and most cost-efficient concept for project execution.”
Last August, Equinor revealed it was assessing the possibilities of supplying five platforms at the Gullfaks and Snorre fields in the North Sea with power from floating offshore wind.
According to Kvaerner, the oil and gas platforms could be the world’s first to be part-powered by floating wind turbines.
The Hywind’s 8 MW turbines would provide a combined capacity of 88 MW and could satisfy around 35% of the Snorre A and B, and Gullfaks A, B, and C facilities.
During periods of higher wind speed this percentage could be significantly higher.
Kvaerner will investigate how to bring down the serial production cost and execution time for the 11 concrete units.