Concern around long-dated hydrocarbons became particularly acute through the pandemic and into the early 2020s. Oil demand had collapsed, net-zero commitments were proliferating and investors were increasingly asking whether resources expected to produce into the 2030s and beyond would ever be developed, or whether they would become stranded before their capital had been recovered. Later-dated production was increasingly discounted more heavily, and in some cases effectively subjected to arbitrary cut-offs.
A barrel produced quickly was therefore worth more than one requiring billions of dollars of investment before generating cash many years into an uncertain energy transition. Resource duration, once an obvious source of value, had become something investors increasingly penalised.
That conversation has since evolved. The post-pandemic recovery, Russia’s invasion of Ukraine, repeated concerns around energy security and the resilience of global oil and gas demand have exposed how difficult it is to replace hydrocarbons quickly. Long-life resources have strategic value again, but the world has kept turning and the financial environment in which those resources have to be developed has moved in the opposite direction.
Resource duration may be back, but cheap capital is not. The Federal Reserve’s latest 25-basis-point increase is small in isolation. More important is the shift from a world in which the risk-free benchmark was effectively zero to one in which investors have been able to earn around 5% before taking meaningful corporate risk.
That has repriced capital across financial markets. If investors can earn a meaningful return without accepting corporate credit risk, lending to an E&P has to pay materially more, and equity sitting underneath that debt should demand more again. Long-duration resources may therefore be becoming strategically more valuable at exactly the same time that some of the companies holding them have become financially less capable of developing them.
Capital is no longer equal
For years in upstream, 10% was the familiar project discount rate. Everyone in the industry knew what an NPV10 meant, and projects were routinely compared on that basis. Debt capital markets today illustrate how far financing conditions have moved.
Kosmos Energy issued $350 million of senior secured bonds earlier this year carrying a fixed 11.25% coupon. Jadestone Energy followed with $200 million of senior secured bonds carrying a 12% coupon. Neither is a project-finance facility; they are observable prices at which those companies have been able to raise secured corporate debt.
Their significance is not simply the interest expense, but where those creditors sit in the capital structure. Kosmos and Jadestone are paying around 12% for senior secured capital that ranks ahead of shareholders, while equity retains the residual project, commodity, operating, liquidity and refinancing risk beneath that contractual claim.
The same upstream project can consequently look very different depending on who owns it. For a major, funding is typically much cheaper, corporate cash flows are diversified across assets and geographies, and a problem on one development is much less likely to become a financing problem for the company. The same cost overrun may be uncomfortable for a major but potentially devastating for the equity of a mid- or small-cap E&P.
A project model can tell a company whether a development creates value on a particular set of assumptions. It cannot by itself tell management or the board whether that company is the appropriate owner of the risk, or whether the prospective return is sufficient for the amount of corporate exposure being created.
The company evidence
Tullow Oil offers two contrasting examples. Uganda was one of the great exploration successes of the company’s history. Tullow accumulated the acreage, discovered a major new oil province and in 2012 sold two-thirds of its interests to Total and CNOOC for $2.9 billion. Tullow later described the proceeds as having made the company effectively debt-free.
The transaction did more than monetise part of the discovery. It moved a substantial portion of the future development burden onto two companies with much larger balance sheets while allowing Tullow to retain meaningful exposure to the resource. Exploration success had been converted into shareholder value without requiring Tullow to carry the full financial burden of the next stage.
TEN followed a different path. By late 2014 Tullow was planning on the basis that it would retain its full 47.18% interest through first oil. The development had an estimated gross cost of $4.9 billion, and although Tullow had sought a farm-down, it ultimately carried that large working interest into development.
TEN subsequently materially underperformed the expectations around which it had been sanctioned. Reservoir performance, well problems and lower production all contributed, while the oil-price collapse arrived at roughly the same time and Tullow was also funding a wider portfolio.
TEN did not single-handedly cause what subsequently happened to Tullow. Commodity prices, other operating issues, exploration outcomes, leverage and later strategic decisions all played roles. The relevant observation is that Tullow retained enough development exposure for project disappointment to feed directly into corporate financial pressure.
Uganda had demonstrated one way of converting exploration success into value while transferring much of the next stage of risk. TEN left far less room for the unexpected, and that difference becomes important when considering what shareholders were ultimately being asked to carry.
Kosmos provides another example because the original strategic decision was, in many respects, exactly what an exploration-led independent should have done. Kosmos opened a giant gas province offshore Mauritania and Senegal and then brought BP into the acreage. BP brought a much larger balance sheet, deepwater development capability and LNG experience, while Kosmos received cash, exploration and appraisal funding and a development carry capped at $533.4 million through first gas.
At the time, Kosmos explicitly said the transaction materially reduced its capital requirements and strengthened the balance sheet. It did. The structure reduced risk substantially, but it did not remove it.
Once the development carry was exhausted, Kosmos remained responsible for funding its retained share of additional expenditure. That became increasingly important as the project moved further away from its original timetable.
At FID in December 2018, project start-up was expected in the first half of 2022. The first commercial LNG cargo was eventually loaded on 17 April 2025. For an equity investor, that commercial milestone is more important than the moment gas first entered the facilities because it is much closer to the point at which the development began generating meaningful LNG sales.
The delay created a simple but painful mismatch: cash inflows moved to the right while cash outflows continued. Kosmos’s own segment reporting shows approximately $408 million of Mauritania/Senegal capital expenditure in 2022, $276 million in 2023, $325 million in 2024 and another $49 million in the first quarter of 2025.
More than $1.05 billion of capital was therefore invested in Mauritania and Senegal from the beginning of the year in which GTA had originally been expected to start producing through the quarter immediately preceding the first commercial LNG cargo. Not all of that $1.05 billion should be labelled a cost overrun, and not every dollar was necessarily GTA Phase 1, but it is a hard measure of the capital Kosmos was committing during a period when the original development timetable had anticipated the project being well into cash generation.
Kosmos separately quantified the deterioration in GTA economics. In 2021 it said COVID disruption, inflation and scope growth had increased expected gross Phase 1 cost by about 15%, adding roughly $100 million net to Kosmos to reach first gas.
The other side of the equation was revenue. GTA generated $117 million of Mauritania/Senegal oil and gas revenue for Kosmos during the 2025 ramp-up year and $144 million in the first half of 2026. On a simple run-rate basis, a start around the original timetable would have brought several hundred million dollars of revenue forward, with a reasonable estimate of around $700–800 million of gross revenue shifted into later years rather than permanently lost.
The economic damage is therefore not $1.05 billion plus $700–800 million. The capital built an asset that Kosmos still owns, and much of the revenue was deferred rather than destroyed. The revealing part is the balance-sheet exposure: Kosmos had to continue funding a capital-intensive development after the carry had been exhausted while the cash flows expected to support that investment kept moving further away.
Jadestone reached financial pressure by another route. Montara stopped producing cash while Akatara was absorbing capital and other portfolio commitments were being funded. Risks that might have been manageable independently arrived together, and the company subsequently raised equity and in 2026 refinanced through its $200 million, 12% secured bond.
BW Energy demonstrates another approach to the same broad problem. Maromba is a roughly $1.5 billion development and is very large relative to BW Energy, but the company has structured substantial elements of its financing around the project rather than requiring the corporate balance sheet to fund the entire pre-first-oil programme.
A $365 million Sinosure-backed project-finance facility covers roughly 80% of the FPSO project cost and is priced at SOFR plus 2.8%. A separate long-term lease finances $274 million of expenditure on the drilling and wellhead platform, with no lease payments due before first oil.
BW Energy has not eliminated Maromba risk. Reservoir performance, execution, cost, schedule and oil prices remain material. What it has done is change the way that risk reaches the corporate equity, reducing the amount of capital shareholders must provide before the development begins generating cash.
Energean provides another version. Energean Israel arranged a $750 million, ten-year senior secured term loan that can refinance existing Israeli debt and provide liquidity for Katlan. The facility is secured against the Israeli assets and is non-recourse to Energean plc, while Energean said the refinancing would leave its blended cost of debt around 7% and extend weighted-average debt life to around seven years.
The assets and companies are different, so the useful comparison is not between their geology or operating performance. It lies in how development risk is financed, contained or allowed to migrate back onto corporate equity.
What should the equity demand?
These examples change the way I think investors should look at hurdle rates. A project discount rate or IRR should obviously reflect the company’s cost of capital, but it should also reflect the amount of corporate risk that particular project imposes on the equity.
If I am investing in a smaller E&P undertaking a development large enough to expose a material part of the company, while senior secured creditors are demanding 11% or 12%, I am not interested in a stand-alone project IRR of 15% or even 20%. I would want to see the project stand up at around 30%, and if it cannot, the ownership, financing or development structure deserves much more scrutiny.
That is my hurdle, not a universal industry number. It is deliberately high not simply because smaller E&Ps face greater development risk, but because the conventional stand-alone project model does not capture the full economic burden imposed on the corporate equity.
Corporate overhead, financing expense, liquidity requirements and refinancing risk matter, as does the opportunity cost of tying up balance-sheet capacity that might otherwise have been deployed elsewhere. A company committed to one large development loses flexibility at exactly the time that flexibility may become most valuable.
The 30% hurdle is intended to compensate for those costs and risks rather than treating them as something to be considered separately after the project model has produced its answer. Leverage makes the payoff asymmetric because the project does not need to fail for shareholders to suffer badly: first production can move, capex can rise, another asset can unexpectedly stop producing or commodity prices can fall at the wrong time, while the creditors’ claim remains fixed and the equity absorbs the difference.
I would not demand the same 30% from an identical project inside a supermajor. The geology may be unchanged, but the corporate exposure is not. Cheaper financing, stronger liquidity and a much larger portfolio mean the same downside can be absorbed without forcing an equity issue, distressed asset sale or refinancing at punitive terms.
The required return should therefore reflect both the quality of the project and the financial condition of the owner. At shareholder level, I would think about the same exposure in money-on-money terms: if investors are being asked to carry concentrated development and financing risk for five years, I would want an outcome in the region of 3x the equity genuinely put at risk, equivalent to an annualised return of roughly 25% if the value is realised at the end of the period.
The project IRR and equity multiple are not interchangeable, but they are two ways of looking at the same underlying question: what compensation should shareholders require for concentrated risk? Structure that risk better and the hurdle should fall.
The equity proposition is the test
The starting point is not the project in isolation. It is the equity proposition, because investors provide capital on the basis that the potential reward justifies the risks they are taking.
Management’s job is to build and execute a strategy that makes that proposition as powerful as possible. The board is there to challenge it, understand where the risks sit and make sure shareholder capital is not being exposed to downside that overwhelms the potential reward.
That does not mean eliminating risk. Oil and gas is a risk business in which exploration can fail, reservoirs can disappoint, projects can run late and commodity prices can fall. The relevant questions are who owns those risks, how much of them the equity should carry, what can be done to reduce or transfer them, and whether the prospective reward justifies whatever remains.
A board cannot determine the oil price, but it can decide whether some of that exposure should be hedged. It cannot guarantee reservoir performance, but it can decide how much working interest shareholders should retain against that uncertainty. It cannot prevent every operational setback, but it can make sure one setback does not leave the company without enough liquidity to absorb it.
Where the risk cannot be understood with sufficient confidence, that is itself useful information. The appropriate response may be to own less, bring in another balance sheet, stage the commitment or demand a substantially higher return. Risk does not disappear because it is difficult to forecast; someone owns it, and the central task for management and the board is to decide whether that someone should be the shareholder and on what terms.
That is the framework through which the earlier company examples should be viewed. At its peak, Tullow had an equity value of roughly £14.5 billion and, following the Uganda farm-down, described itself as effectively debt-free. Today its market capitalisation is around £340 million, meaning barely 2.3% of that peak equity value remains.
No single project or decision explains a 97.7% decline. TEN certainly does not, and Tullow lived through oil-price collapses, operating problems, exploration disappointments, leverage and years of difficult portfolio decisions. But those are not reasons to remove management and boards from the analysis; they are precisely the kinds of risks they are employed to manage on behalf of shareholders.
Tullow had already shown in Uganda how exploration success could be converted into substantial value while much of the next stage of development risk was transferred to stronger balance sheets. Elsewhere, it retained substantially more exposure, and as operating, project and financial pressures accumulated, the room for error narrowed.
Almost all of Tullow’s peak equity value has since disappeared. That does not establish that every individual investment decision was wrong, but it does mean the outcome has to be part of any assessment of how successfully risk was managed on behalf of shareholders. The job was never simply to find resources, sanction developments and obtain financing; it was to construct an attractive risk-return proposition for the equity and preserve it as circumstances changed.
Kosmos presents the same question in a different form. Bringing BP into GTA was itself a sensible risk-management decision: Kosmos reduced its working interest, secured a supermajor partner and negotiated a development carry, but the carry was capped.
The project then moved almost three years beyond its original timetable for LNG sales. BP’s development carry had been capped at $533.4 million and was effectively exhausted before this later phase of spending, leaving Kosmos once again responsible for funding its retained share.
From the beginning of 2022, when GTA had originally been expected to start producing, through the quarter immediately preceding the first commercial LNG cargo, Kosmos invested more than $1 billion in Mauritania and Senegal. At the same time, some $750 million of gross revenue that might have arrived under the original timetable was pushed into later years.
Taken together, that represents a gross funding and timing burden of roughly $1.8 billion during the delayed period. It is not a measure of value destroyed: the capital built an asset Kosmos still owns and much of the revenue was deferred rather than lost. But both effects hit liquidity in the same direction; cash continued to leave the company while the cash expected to come back moved further away.
Kosmos today has an equity value of around $1.7 billion. The fact that the gross scale of that funding and timing burden was comparable with the entire current value of the equity today shows how large the residual exposure became, despite Kosmos holding a minority interest, having a supermajor partner and having negotiated what initially looked like a substantial development carry.
That is the kind of exposure management and boards need to understand before the downside arrives and begins dictating strategy for them. The test is not whether a development can be financed if everything broadly follows the plan; it is what happens to the equity when it does not. Once liquidity becomes constrained, strategy is no longer being chosen from a position of strength; refinancing needs, asset sales and equity issuance start choosing it for you.
If the oil price falls, what protects the cash flows? If development costs rise, who writes the cheque? If the schedule moves three years, who finances the intervening period? If the carry is exhausted, who owns the overrun? If another producing asset fails at the same time, how much liquidity remains?
If the answers lead quickly to distressed asset sales, deeply discounted equity issuance or borrowing at double-digit rates, then the investor proposition has changed materially from the one suggested by the original project economics. That is where the risk-return proposition can break down.
A project might show a respectable IRR under a conventional model, but if the upside available to shareholders is relatively constrained while the downside includes refinancing risk, concentrated development exposure and potentially severe dilution, the equity proposition has not been constructed well. Management and boards create shareholder value by choosing which risks the equity should own, structuring those risks intelligently and ensuring the expected reward is commensurate with the exposure.
Getting the project built is not enough. The test is what the shareholders earned for the risks their capital was required to carry.
Risk transfer has to be real
Farm-downs are an obvious part of the answer, but the structure matters as much as the percentage sold. A capped development carry can look extremely attractive when a transaction is announced because it can remove hundreds of millions of dollars of expected expenditure from the smaller company’s funding requirement and materially improve the economics of the retained interest.
The protection, however, ends at the cap. If the development follows the base case, that may be entirely adequate, but if costs rise or the schedule moves materially after the carry has been exhausted, the smaller partner can find itself exposed to exactly the part of the risk its balance sheet is least able to absorb.
The asymmetry between partners can be enormous. Another $100 million or $200 million of expenditure may be frustrating for a supermajor but readily financeable from operating cash flow or existing liquidity. For a small E&P, the same amount can become a corporate event requiring new debt at punitive rates, an equity issue after the share price has already fallen, or the sale of an asset that would otherwise have been retained.
The headline size of a carry therefore tells only part of the story. The more important question is who funds the downside once the development stops following the plan, and that should influence transaction design from the beginning.
A smaller retained working interest, a larger carry, protection against cost overruns, project finance, leasing structures, staged commitments or combinations of these can all move risk away from the corporate balance sheet. BW Energy’s financing of Maromba shows one approach, with a substantial part of the capital requirement structured around the FPSO and development infrastructure rather than simply loaded onto corporate equity before first oil.
Energean has taken another approach by placing long-term secured financing around its Israeli asset base while keeping that borrowing non-recourse to the listed parent. Neither structure makes the underlying development safe, nor should that be the objective; the objective is to prevent project risk from becoming corporate survival risk.
That feeds directly back into the return hurdle. If shareholders are protected from the most damaging tail outcomes, they should accept a lower required return, while shareholders underwriting the project, the balance sheet and the refinancing risk simultaneously should demand substantially more.
The optimal owner can change
There is no economic reason the company that discovers a resource should have to own the same percentage through exploration, appraisal, development and production. Different stages of the upstream cycle reward different capabilities, and ownership should be able to change with them.
Small E&Ps can be extraordinarily effective explorers. Focused technical teams can build deep knowledge of individual basins, move quickly and pursue geological ideas that might struggle to compete for attention and capital inside much larger organisations, while exploration success can create enormous value with relatively modest capital.
Development is different. As geological uncertainty falls, the amount of capital at risk rises dramatically and engineering execution, procurement, financing, construction, schedule management and the ability to absorb unexpected expenditure become increasingly important.
The optimal owner at discovery may therefore not be the optimal owner at development. For an exploration-led company, that should not be seen as a failure of ambition; it can be the business model: explore, discover, appraise, de-risk, farm down and recycle capital.
The timing matters because a farm-down completed while the company is financially strong and the asset is attracting competitive interest can monetise a substantial portion of the value created through exploration while deliberately transferring the next layer of risk. A farm-down attempted after costs have risen, the balance sheet has weakened and the market knows the company needs cash is a very different transaction.
One is strategic risk management; the other can become forced capital raising by another name. The distinction is not whether the company sells down, but when it does so and from what position of financial strength.
Larger companies can approach the same ecosystem from the opposite direction. Majors can and should retain strong internal exploration capabilities, but they do not need to rely exclusively on internal exploration or maintain equivalent exposure across every basin in the world.
Smaller explorers provide another source of resource. A major or large independent can allow smaller companies to take some of the earliest geological risk and then farm into or acquire discoveries once enough uncertainty has been removed for its own advantages to become more important.
That is not outsourcing exploration. It is choosing where on the risk curve to deploy capital, while continuing to explore internally where the company has a genuine technical advantage.
The same logic applies to mid-caps. Trying to explore everywhere in the name of diversification can dilute technical focus and spread management attention across too many basins, whereas maintaining strong internal capability where the company has an advantage and using farm-ins and acquisitions elsewhere can create a more disciplined resource pipeline.
Organic and inorganic resource additions then become parts of the same strategy. Internal exploration creates options, farm-ins acquire options created by others, acquisitions buy resources at later stages of de-risking, and farm-downs monetise part of successful exploration and recycle capital into the next opportunity.
The upstream ecosystem becomes a progression of risk between different owners rather than an assumption that every discovery should remain with the company that drilled the first successful well. That becomes increasingly important as resource duration returns and long-life oil and gas resources become strategically more valuable while remaining capital intensive and, for weaker credits, increasingly expensive to finance.
A company can therefore own an excellent resource and still be the wrong company to finance its development. A discovery can create enormous shareholder value without the discoverer retaining maximum working interest, while selling down can increase value rather than surrender it if doing so improves the risk-return proposition for the equity.
Conversely, a larger company with cheaper capital and greater financial capacity may create value by taking precisely the development exposure that is disproportionately expensive for a smaller company to carry. The same subsurface asset can therefore have different economics in different hands.
The return of resource duration does not mean every company should try to own as much resource as possible for as long as possible. It means management and boards should understand where in the resource life cycle their company genuinely creates the most value, how much risk the equity should carry and when ownership should change.
That brings the argument back to where it started. Resource duration is back, but cheap capital is not, and those two developments should be considered together.
For investors, executives and boards, the question is no longer simply which resources a company can discover or develop. It is whether the reward available to shareholders justifies the risks their capital is being asked to carry, and whether someone else may be better placed to own those risks at the next stage.