Big Oil’s painful offshore wind pivot
Big Oil’s painful offshore wind pivot
DEEP-DIVE: European oil majors throw caution to the wind by embracing razor-thin margins
European oil majors are jostling to become offshore wind heavyweights. Building capital-intensive projects at scale in familiar offshore environments, underpinned by guaranteed returns, has proved alluring. But cost inflation and aggressive bidding at cut-throat ‘subsidy-free’ auctions have eviscerated margins. Energy Flux takes a critical look at new research into the sketchy economics of offshore wind for the likes of Equinor, Shell, BP and ENI.
Offshore wind is the new darling of the European oil industry. The biggest names in petroleum have amassed gigawatt-scale development pipelines and frequently scrap it out for seabed acreage in premium markets in western Europe and North America. Several are also entering emerging Asian markets via local joint ventures.
Barely a week goes by without some sort of announcement from a European oil major about its deepening involvement in the sector. They all hope to emulate the metamorphosis of Denmark’s state oil company DONG Energy into Ørsted, an offshore wind pioneer. Shell sees its ~6 GW pipeline as a “key growth area”. BP says wind will play a “vital role” in achieving its 2050 ‘net zero’ target. TotalEnergies and ENI are similarly zealous.
Equinor is leading the pack. The Norwegian oil major expects offshore wind to account for two-thirds of its 12-16 GW renewables capacity by 2030, and is “determined to be a global offshore wind energy major”.
That determination to scale up quickly is driving European IOCs into a tight corner. Once-cautious companies that weighed high risk, high-return global investments on cold-blooded financial metrics appear to be making exuberant ‘green’ bets that could land them in hot water.
Competition for prime acreage is rife, resulting in some questionable bids. BP faced accusations that it overpaid in the UK’s latest leasing round. There is a similar scramble to secure 15-year fixed returns enshrined in a Contract for Difference (CfD) or similarly bankable support instrument. Revenues are under pressure.
CfD auctions frequently clear at the minimum price, as occurred at a recent 1 GW Danish tender that saw companies draw lots in a tie-break. This result was hailed as historic, which it undoubtedly is, since the (un)lucky winner – RWE – will pay the Danish state DKK 2.8 billion (€376 million) by 2028 and pick up the tab for export cables and grid connection. Supply chain margins must be under immense pressure to keep the project economics in the black.
With clearing prices falling more rapidly than costs, major turbine supplier Siemens-Gamesa recently warned that margins have been squeezed “too far”, hobbling reinvestment in factories and technology improvements. These can’t be deferred forever, which means turbine costs can’t keep falling forever either. Materials inflation and labour constraints are an aggravating factor.
Throwing caution to the wind
As Energy Flux asserted more than a year ago, any attempt to emulate oil-sized profits from renewables is destined to fail. European majors now tacitly admit this by imposing less stringent investment metrics on offshore wind projects than oil.
Shell says future upstream projects must be profitable at $30/barrel, deliver an internal rate of return (IRR) of 20-25% and pay back capital within seven years. Integrated gas projects must deliver IRRs of 14-18%. As global oil and gas demand returns to pre-pandemic levels, investments made on this basis have a big safety margin.
The bar is set much lower in the renewables segment, where Shell is investing $2-3 billion each year. The company is targeting an “unlevered” IRR (i.e. pure equity, no debt) of “more than 10%”, which it says is made possible by its integrated business model. Conventional wisdom holds that leveraging up the asset with cheap debt improves returns (more on this below).
A higher margin requirement for oil investments reflects exploration risk and crude demand uncertainty stemming from decarbonisation policies. Wind might not carry these risks, but much lower margins mean investments carry less ‘fat’ to absorb contingencies. Shell’s twin-track approach, which is not unique, raises some questions:
Can renewable investments reliably generate double-digit returns?
Will returns come quickly enough to support a high rate of reinvestment in new projects and sustain dividends at levels sufficient to compete in capital markets?
Can IOCs release value by spinning off their ‘green’ investments into stand-alone listed companies?
New research by academics in Norway suggests the answer to all of the above will be a resounding nei. This might not matter while wind accounts for a tiny proportion of IOC capital expenditure, but that is set to change: Equinor expects renewables to account for 50% of its capital expenditure by 2030. Big wind could drain Big Oil of liquidity.
The decarbonisation megatrend has skewed the investment thesis in favour of strategic objectives. The calculus seems to be that taking on projects with poor economics is a price worth paying for polluting companies desperate to burnish their ESG credentials and renew their social licence to operate.
An alternative theory holds that the move into low-rent clean power production is a strategic hedge against ‘green’ hydrogen — produced from renewables via electrolysis — outcompeting the gas-derived blue variety to become a significant energy vector in the UK and Europe. Big Oil’s intense pro-hydrogen lobbying gives credence to this view.
Massaging the numbers
Researchers from the University of Stavanger ran the rule over Equinor’s investment in the 3.6 GW Dogger Bank wind farm in the UK’s southern North Sea. Dogger Bank is the world’s largest offshore wind farm, an order of magnitude greater than the 317 MW Sheringham Shoal and 402 MW Dudgeon projects that Equinor tackled previously.
The site is so big it is being developed, financed and built in three separate 1.2 GW special purpose vehicles – Dogger Bank A, B and C – that will be co-owned by Equinor (40%), SSE Renewables (40%) and Italy’s ENI (20%). Each phase will cost a cool £3 billion.
Phases A and B achieved financial close a year ago after securing senior and ancillary debt facilities of £5.5 billion, with gearing of 65-70% on the generation assets and 90% on transmission infrastructure. Phase C reached this milestone yesterday on similar terms with many of the same lenders.
Equinor executive vice president of renewables Pål Eitrheim said the project will achieve a “nominal equity return” of 12-16%. This figure includes profits from the sale of 10% project equity to ENI. Speaking at Equinor’s capital markets day in June, Eitrheim said:
“[W]e expect [wind] project-based returns between 4% and 8%… these are unlevered real-life cycle returns, excluding farm-downs. Add 2% for inflation and you get to the expected nominal return range… Farm-downs would typically add 1 to 2 percentage points to the unlevered project IRRs.
“We expect significantly higher nominal equity returns when we are using project finance. If you look at our projects in the US and the UK that are secured offtake, they have nominal equity returns between 12% and 16%. These returns reflect a business with a very different risk profile than our legacy oil and gas business: no exploration risk, no oil price volatility exposure nor production decline rates, stable revenues.”
Big wind = big unknowns
Eitrheim’s figures paint a much rosier picture than the Stavanger researchers, who said Equinor can expect an IRR of 5.6% after tax in their “best estimate” central case for Dogger Bank. On a net present value (NPV) basis, the wind farm comes in at negative £907 million – meaning the investment is not worth making for Equinor.
“Our estimation, based on the project economics of the Dogger Bank project, is that this activity will be cash negative for a very long time,” say researchers Petter Osmundsen, Magne Emhjellen-Stendal and Sindre Lorentzen.
Osmundsen told Energy Flux the figures are not comparable because Equinor is referring to its entire portfolio, while his study considers Dogger Bank in isolation. Also, he challenges the notion that leveraging up a project squeezes more value from the equity portion:
“By gearing up a project you may have higher expected return, but at the same time higher risk and thereby higher rate of return requirement, so the value of your project does not change. This is confirmed by sensitivity calculations we have done for the project. By increasing the debt to 70%, you get a high variability in equity return.” — Petter Osmundsen, via email
Osmundsen’s study assessed key economic inputs such as Equinor’s cost of capital, capital and operational costs (capex/opex) of each phase, operations and maintenance (O&M) costs, plant capacity factor, asset lifespan, future power prices and many other variables. Some of these are difficult to pin down.
Dogger Bank is anomalous in that it is much bigger and further from shore than any wind farm in operation today – 130-190 km – but the site lies in relatively shallow waters. Distance from shore increases installation and O&M costs, cabling costs and plant downtime, since it might not make economic sense to journey out to fix individual turbine outages. Transmission losses also rise with distance.
These downsides are (partially) offset by the lower capital cost of building and installing turbine foundations in shallower waters, the economies of scale achievable in a multi-gigawatt development, and the stronger and steadier wind speeds to be harvested further out to sea.
Dogger Bank will boast 190 GE Haliade-X wind turbines each rated at 13 MW in its first two phases. The use of a smaller number of larger turbines improves power yield while decreasing unit costs since fewer blades, towers, nacelles and foundations will need to be manufactured, installed and maintained at the remote site.
Equinor’s equity will be tied up in Dogger Bank for 16 or 17 years before it is paid off by electricity revenues. This is a year or two after the CfD’s fixed revenue support period ends, and much longer than the average of six years for Norwegian oil investments. The research paper claims lenders will require loans be paid off during the 15-year CfD, not after — a view not shared by everyone in the wind industry.
Flawed assumptions?
The assumptions used in the financial modelling deserve scrutiny. There is a lot of uncertainty around the overall economic life of the asset, and the price risk it will face after the 15-year CfD expires. Osmundsen et al assume lots of price cannibalisation and low/negative wholesale prices after a rapid ramp-up of UK wind power generation in the 2030s. They also assume the turbines will be dismantled after 25 years.
There is reason for caution here. Energy Flux understands that Dogger Bank is being developed as a 30-year asset, and sources in the offshore wind industry say 35 years is starting to be viewed as the norm as technologies improve. The extra O&M costs of keeping ageing offshore turbines spinning for another five years will be vastly outweighed by the additional revenue from a fully amortised asset, wind advocates say. That holds true regardless of price volatility in a wind-dominated power market, some claim.
The Norwegian researchers modelled one scenario for Dogger Bank as a 30-year asset. With three decades of revenue the IRR rises to 7.3%, while optimistic sensitivities modelled around costs (-15%) and prices (+20%) could boost that figure as high as 8.5%.
Another five years of operations might conceivably nose the IRR into low double digits, but we can’t be sure unless the financial model is re-run over 35 years. (Osmundsen declined to do this. A spokesperson for Equinor did not respond by the time of publication.)
Turbulent headwinds
Does this mean Equinor’s wind pivot will be plain sailing? Far from it. Government officials in Oslo will need to get comfortable with their national energy champion spending more on wind projects in overseas jurisdictions and less at home. This has negative implications for Norway’s fiscal revenue and supply chain investment.
There is also the question of “hard money”, as a source close to Equinor put it to Energy Flux. Oil investments are made in US dollars and produce a globally traded commodity to repay those dollars and cover taxes, royalties and dividends. Further upside can be gleaned from trading equity volumes and leveraging Equinor’s global footprint.
Oil companies book wind investments in US dollars but revenues and taxes are paid in local currency because electricity markets are localised. Arbitrage opportunities, and hence upside, are limited by transmission infrastructure. This is a structural challenge that green hydrogen/ammonia might one day resolve — but don’t hold your breath.
In the meantime, Equinor’s balance sheet could deteriorate. Dogger Bank’s total capital outlay of £9 billion will be 70% debt-funded. Equinor’s 40% project share, minus the £276.4 million farm-out payment from ENI, implies an equity commitment of £800 million for 1.44 GW. This equates to $555 million per gigawatt installed.
If we take that as a rough benchmark, Equinor’s target of 12-16 GW installed capacity this decade implies an equity outlay of £6.7-8.9 billion. This capital won’t be recouped for well over a decade, so there won’t be much free cash flow to cover dividends or invest in new growth opportunities without hefty farm-outs.
Aggressively selling down large chunks of project equity pre- and post-construction might keep Equinor’s renewables investments above water, but those buying in face dismal returns. ENI’s two Dogger Bank farm-in deals (see here and here) will achieve IRRs of just 2.7% and 2.9%, according to the Stavanger researchers. Equinor and SSE will enjoy higher overall margins at ENI’s expense, which the paper describes as a “zero-sum game”:
“Newspapers have commented that this means that the project and offshore wind in general has become more profitable. This is not the case. ENI have been willing to [accept] a lower rate [of] return … to learn the business and to move against their target of offshore wind production of 25 GW by 2035. The transaction is merely a redistribution of profit among private companies, a zero-sum game. The socio-economic value of the project has not changed. The expected NPV of the project is the same, irrespective of equity transaction.”
As Energy Flux readers will recall, ENI harbours ambitions to spin off its green arm to release unrealised value and alleviate the renewables investment burden on current shareholders. ENI believes capital markets are discounting renewables investments and opportunities on its balance sheet. But if those investments yield such low returns, who in their right mind will buy in?
The bottom line
There is only so much economic value to go around from investments in ‘cheap’ offshore wind. Spectacular reductions in auction prices have spawned a misleading narrative that this sector is becoming an attractive investment proposition for oil companies scrambling for a means to reduce emissions, remain relevant and keep ESG investors onside.
Moving early pays off. Sadly, the macro conditions that led to Ørsted’s successful green reincarnation no longer exist. Equinor is a laggard by comparison but arrived just in time to cream off value from initial UK investments via its farm-outs to ENI.
If Dogger Bank is representative of its plans to squeeze shareholder value from wind, the Italian oil company faces big problems. The same might hold true for Shell, BP and TotalEnergies; time will tell. For now, their collective push into offshore wind is still gathering steam. Don’t be surprised if a few big projects are quietly erased from portfolios along the way.
Seb Kennedy | Energy Flux | 3rd December 2021
