Wendover’s Offshore Oil Verdict Confuses a Price Crash With a Profitability Test
On April 21, 2020, Wendover Productions published How Offshore Oil Rigs Work, an otherwise informative explanation of the enormous engineering and logistical costs of extracting petroleum beneath the ocean.
Its most consequential conclusion was this:
“There likely is not a single offshore oil platform in the world turning a profit at those prices.”
That is where the explanation stops being sufficiently rigorous.
The global oil-price collapse was real. Offshore investment was in serious trouble. Some installations genuinely could not justify continued production. But Wendover makes a much bigger claim: that virtually every offshore installation had become unprofitable.
It supplies no global platform-level financial data to establish that conclusion. More importantly, independent industry research and company filings reveal a substantially different picture.
The fundamental mistake is confusing the economics of building a new offshore project with the economics of operating an existing oilfield.
1. The video never defines what it means by profit
There are three different financial questions in offshore petroleum production:
- Operating profitability: Does the selling price cover the immediate costs of extracting and transporting the petroleum?
- Full-cycle profitability: Will the project recover exploration, construction, development, operating and eventual decommissioning costs, including an acceptable return on investment?
- Corporate profitability: Does the entire company generate an accounting profit after financing, depreciation, taxes, hedging and other expenses?
These measures can produce very different answers for the same oilfield.
The US Bureau of Ocean Energy Management explains this distinction in its 2018 technical study, Gulf of Mexico Decommissioning Trends and Operating Cost Estimation.
It distinguishes unit operating cost, calculated using annual operating expenditure and production, from life-cycle operating cost, calculated across the field's entire producing life. It also explains that major offshore capital expenditure occurs upfront, before production begins.
This distinction matters enormously during a price collapse.
A company that has already spent $1 billion building an offshore installation does not necessarily benefit from shutting it down when oil prices fall. Much of that original investment is already committed. The immediate decision depends on whether continuing production generates more cash than the additional costs of operating, shutting down and potentially restarting.
BOEM also warns that assessing profitability requires examining individual wells and structures, rather than relying on broad averages.
A platform is a physical structure, not necessarily an independent profit-and-loss account.
Wendover uses the enormous construction costs of offshore infrastructure to explain why the industry struggles at low prices. But it never properly separates those historical investments from the cost of producing the next barrel.
The distinction is not academic. It changes the verdict.
2. The North Sea contradicts the universal claim
The strongest counterevidence comes from Wood Mackenzie, an established energy research firm.
In an analysis published through Oilfield Technology on August 12, 2020, Wood Mackenzie examined the economics of existing North Sea production during the 2020 oil-price collapse.
Its findings were remarkably different from Wendover's conclusion.
At a Brent price of $25 per barrel:
- Only 370,000 barrels of oil equivalent per day, approximately 6% of North Sea production, failed to cover operating costs and the government's share.
- Approximately 94% of production covered those costs.
- The basin's weighted-average short-run marginal cost, including operating costs and taxes, was approximately $12 per barrel.
At $30 per barrel, 95% of North Sea production was economically viable on this operating-cost measure.
There was an important qualification: nearly one-quarter of individual fields could still operate at a loss at $30.
That distinction is precisely what Wendover misses.
A quarter of fields losing money does not mean a quarter of production is losing money. Large, productive fields can account for most of the region's output, while numerous smaller, mature fields contribute relatively little.
Wood Mackenzie's analysis therefore presents two simultaneous realities: some offshore fields were in serious financial difficulty, while the overwhelming majority of North Sea production could still cover its short-run operating costs at $25.
This does not establish that every producing field recovered its original development investment or earned an acceptable long-term return.
It does, however, directly undermine the claim that offshore production had universally become uneconomic.
3. Brazil demonstrates why offshore production cannot be treated as one business
The Brazilian offshore industry provides an even more revealing example.
Petrobras operates enormous deepwater and ultra-deepwater developments in the Santos Basin, including the Tupi and Búzios fields.
Its July 2020 financial filing with the US Securities and Exchange Commission provides actual production-cost figures from the second quarter of 2020.
During that quarter:
- Average Brent crude was $29.20 per barrel.
- Petrobras' average Brazilian crude sales price was $23.98 per barrel.
- Deep and ultra-deep post-salt lifting costs were $10.23 per barrel of oil equivalent, including platform leases but excluding production taxes.
- Pre-salt lifting costs were just $4.17 per barrel of oil equivalent, on the same basis.
- The company's overall Brazilian lifting cost, including production taxes and platform leases, was $10.56 per barrel of oil equivalent.
These are operating-cost figures, not complete project break-even calculations. Nevertheless, they demonstrate that substantial offshore production could continue operating at costs considerably below the prevailing oil price.
The company's subsequent 2020 annual report provides further evidence.
Approximately 66% of Petrobras' total production came from pre-salt fields, with an average reported lifting cost of just $2.50 per barrel of oil equivalent.
At the same time, Petrobras mothballed 63 oil platforms because of low productivity and high operating costs.
This is the important distinction: the company was retiring expensive installations while maintaining a substantial production base of highly productive offshore assets.
Brazil's government Energy Research Office provides additional detail. Its 2019/2020 industry report records the hibernation of 62 shallow-water platforms during the crisis.
Meanwhile, Brazil's pre-salt production continued to develop, and national oil and gas production recovered after reaching its low point in May 2020.
The industry was not simply shutting down. It was selecting which assets remained economically worthwhile.
Sources:\
Petrobras Q2 2020 SEC filing.
Brazilian Oil & Gas Report 2019/2020 — Energy Research Office.
4. The market price was not necessarily the price companies received
Another important omission is oil-price hedging.
Oil producers do not necessarily sell every barrel at the prevailing market price. Financial contracts can protect a portion of their production against sudden price collapses.
This was particularly relevant in April 2020.
On April 23, industry representative Oil & Gas UK estimated that smaller and medium-sized North Sea producers had hedged approximately half to two-thirds of their expected production for 2020.
The organisation also explained that restarting offshore facilities could be expensive and technically complicated, discouraging operators from shutting down installations simply because spot prices had collapsed.
Source: S&P Global, April 23, 2020.
Aker BP provides a concrete example.
The Norwegian Continental Shelf producer reported second-quarter 2020 production of approximately 209,800 barrels of oil equivalent per day.
Its average realized liquids price was $29.90 per barrel. However, $56 million in gains from oil-price hedging increased its effective realized liquids price to approximately $40.90.
The company reported production costs of $9.10 per barrel of oil equivalent and a net profit of $170 million for the quarter.
There were important qualifications: the result included a $136 million reversal of previous impairment charges and a $19 million tax credit. This was a company-wide quarterly result, not an individual platform's profit statement.
Nevertheless, the example demonstrates why comparing a single day's benchmark price with an industry's operating costs cannot establish whether its producers are making money.
5. Where Wendover's conclusion actually holds
There is a substantial part of the argument that survives investigation.
New offshore developments are extraordinarily capital-intensive. They require companies to commit enormous sums before receiving any production revenue.
The International Energy Agency estimated on April 1, 2020, that approximately five million barrels of worldwide daily production could not cover extraction costs at a Brent price of $25.
It also warned that companies might continue producing despite operating losses because shutting down and restarting installations could cost more than temporarily continuing production.
The IEA further reported that companies were initially reducing planned 2020 capital expenditure by approximately 20–35%.
International Energy Agency, April 1, 2020.
Wood Mackenzie similarly expected a 20% reduction in North Sea investment compared with its pre-crisis forecast, with most new investment decisions being postponed.
That is where the distinction becomes decisive.
An existing field with low operating costs and substantial infrastructure already installed might continue generating positive cash flow at $25 per barrel.
A company considering spending another billion dollars to develop a new offshore field faces an entirely different calculation.
It must justify the entire investment over many years, account for future operating costs and accept the risk that oil prices might remain depressed.
Wendover is right that the economics of new offshore investment deteriorated sharply. It is not justified in extending that conclusion to every existing offshore installation.
The verdict
Wendover presents offshore oil economics as though a single global price determines the fate of every installation.
The evidence shows something considerably more complicated.
The 2020 crisis created three different outcomes:
- Mature, expensive offshore assets were shut down or placed into hibernation.
- Productive, low-cost offshore fields continued operating and generating substantial cash.
- New developments faced collapsing investment prospects because their full-cycle economics no longer justified the required capital.
The North Sea, Brazil and Norway all demonstrate why these distinctions matter.
The video also correctly identifies the extraordinary environmental and financial risks associated with offshore accidents. Deepwater Horizon demonstrates that catastrophic losses are possible, but one disaster cannot establish the expected financial risk of every offshore development. Nor does a fall in BP's market value represent another cash expense equivalent to its cleanup and settlement spending.
The central failure is not the explanation of offshore engineering. It is the unsupported certainty of the financial conclusion.
Offshore oil did not become universally unprofitable in April 2020. Its economics became brutally selective.
That is a much more important story than declaring an entire industry financially dead.
Wendover had the information needed to explain that distinction. Its conclusion discarded it.
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