You Just Made a Big Discovery. Now What?

This post provides a framework for understanding the timelines and trade offs that an explorer considers after a significant discovery. There are some necessary simplifications to avoid it being overly long but I welcome further discussion in the comments section to explore some of these themes with greater depth and nuance.

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TLDR shortcut

• The last two significant discoveries on the North Slope of Alaska have been the Willow complex and Pikka/Horseshoe. These are resources in the 500 million - 1 billion barrel range. First production is currently planned for 7-8 years from discovery.
• Unless a discovery is being tied in to available spare capacity in existing nearby infrastructure then lead times are a minimum of 5 years and can easily extend to 10 years from discovery.
• Globally, a basin opening discovery takes around 10 years on average to begin production with some examples talking longer. Generally offshore gas fields (eg Rovuma Basin in Mozambique) and onshore oil (eg Uganda onshore - 14 years and counting versus Kenya with 7 years) take longer than offshore oil fields (eg Pre-salt in Brazil early production system within 3 years with full field production building up over the following 10 years).
• Merlin (if confirmed as discovery) will need to build pipeline to Willow (closest planned infrastructure) but that will not have spare capacity until the end of the decade at the earliest. Alternative plans might include a shared facility with Pikka/Horseshoe through cooperation with Oil Search/Repsol allowing a start up by 2027/28.
• Given normal lead times, costs of appraisal post discovery and the acquirer’s return on capital requirements , the value on disposal is likely to be less than half the expected NPV10 of a notional development of the most likely recoverable resources immediately following discovery.

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It is no easy thing, despite how dismissive Redditors and StockTwits seem to be regarding exploration risks, to find a new field of commercial scale. For geoscientists, this may be the culmination of a decade or more of detective work but for engineers, their job is only just beginning. Key questions will include:

• Did we discover enough to cross the commerciality threshold?
• If we choose to sell the discovery before development, when should we do that and what portion of the NPV10 are we prepared to give up in a sale?
• What is our development concept?
• What will the plateau production rate be (the throughput capacity of the most constrained element of the production system)?
• How will I get my production to market and, if it is not going into an established market, who will buy it?
• How much further appraisal is necessary to de-risk the reserves to support the chosen development concept and the buyer’s confidence to sign a contract?
• Can we utilize an Early production System to de-risk full field development.
• What are the financing and regulatory requirements to get to FID (Final Investment Decision) in terms of FEED (Front End Engineering and Design)?
• How long does it take after FID to build roads, pipelines, production treatment, water injection, gas reinjection, drill and complete development and injection wells?

Let’s take some of these, broadly in order…

Commerciality? The critical question is whether the expected costs of development and production allow a rate of return that exceeds the cost of capital by more than the alternative use to which that capital might be applied. If an E&P company needs to earn more than 10% on its total invested capital then, to cover the costs of abortive exploration and other costs, by definition, it needs to earn more than 10% on its successful development projects. This means that threshold returns for development projects typically need to lie in the range 15-20% IRR or the company will not return its cost of capital overall.

If we imagine a development of 100 million barrels with costs estimated at $1 billion - $400 million to drill 20 wells and $600 million for facilities to produce at 50,000 bopd with water injection and gas reinfection facilities sized appropriately - then, at FID, this development would earn a rate of return of more than 75% at $60 per barrel and would have a breakeven of approx $30 per barrel. But this has no costs for roads and pipelines which are approximately $10 million per km in Alaska (NB these are order of magnitude figures i.e. >$1 million per km and <$100 million per km). If we have to go 70km to the nearest facilities, then the development costs around $1.7 billion and the IRR falls to 25% with a breakeven oil price of more than $45 per barrel. This explains why Umiat has sat undeveloped for so long despite having recoverable resources in the region of 100 million barrels and why it would suddenly become a lot more valuable if Merlin is a successful development that can underwrite the costs of connecting to infrastructure.

By contrast, the development of an estimated development of 76.5 million barrels at Alkaid (sitting under the TAPS line and the Dalton Highway) yields a 40% or higher IRR and a breakeven in the low $30’s per barrel. Location and size of resource are critical to the question of whether a discovery is commercial. The other key factor is the well deliverability. In Texas, a well producing 500 bopd is a great economic result but if we need 200 wells to get to our 50,000 bopd (100 producers and 100 injectors) then the costs of our notional 100 million barrel development rise by $3.6 billion at least and we just could not produce enough oil to cover that cost.

Appraisal? How much further appraisal is necessary to de-risk the reserves to support the chosen development concept? As a general rule, we need to have tested the limits of the accumulation. This will normally require a well at the crest of the trap or establishing where it pinches out or shales out if it is stratigraphic. It will be necessary to find the hydrocarbon water contact if one exists. The areal extent needs to be proven and the continuity of reservoir properties.

It is highly likely that a 500 million barrels discovery requires 4 appraisal wells after the discovery to reduce the range of uncertainty of the ultimate recovery volume so that we can be sure it is large enough to justify development and to know the maximum recoverable reserve to eliminate regrets that arise from investing in too small a facility. That is potentially a two year program given the seasonal window for exploration and appraisal drilling in Alaska (ie using ice roads for access).

Early production systems may be up and running within 2 years if permanent road access is already available. The production data gathered can significantly de-risk field appraisal - this is a reason that a long term production test is planned in the case of Pantheon’s Alkaid discovery.

Development concept? A key question is how much value are we prepared to sacrifice for early production and risk mitigation vs how much risk are we prepared to take to capture the maximum theoretical value?

An early production scheme is only really an option if there is a low cost tie-in to existing infrastructure nearby because the threshold costs to make it worthwhile to produce at an initial fraction of ultimate field deliverability are low enough not to destroy the economics. This can be an excellent way of gathering data on production performance and optimizing full field development. Similarly a staged development, building up in increments to full field production may mitigate risks and reduce the size of the negative cash sink but at the expense of carrying some costs ahead of their being needed (because we probably have to install the full pipeline capacity and other infrastructure on day one).

Financing and Pre-Development Activities? If the successful explorer decides to hold through development, what are the financing and regulatory requirements to get to FID (Final Investment Decision) in terms of FEED (Front End Engineering and Design) and what lead time does that impose? We already have a two year appraisal program for a material discovery and it may take a further year to complete concept selection, FEED and regulatory approvals to allow FID after the resource estimates have been firmed up. However, FID for a company that cannot fund development out of its own resources relies upon either a sale of part of the asset to fund the remaining share or a substantial debt and equity funding package being arranged. Even large companies that can self fund are likely to take a couple of years from the end of appraisal to get to FID while they try to optimize the development plan - because they have internal competition for capital.

There is even more scope for delay where a company has JV partners since it is rare for FID to occur without all partners approving so the development proceeds at the pace of the slowest or weakest.

Asset Sale? Pre-development sale of the asset must be weighed against a decision to hold through production. It is unlikely that a buyer will pay the NPV10 of the asset, even if a risked value. This is because the IRR of such a transaction would be 10% - not sufficient to cover their target returns on invested development capital. A more normal situation might be to pay a price equivalent to the level at which the overall IRR of acquisition and development would be 20%.

In our earlier example of the 100 million barrel field development based on a $1 billion cost, the NPV10 at FID would be $1.1 billion ($11/bbl) at $60 per barrel. The price that an acquirer could pay and still earn a 20% IRR would be $800 million ($8/bbl) at FID (the start of development). Note that these are illustrative numbers to show the discount to theoretical value that results from a “discover and sell” strategy versus a “hold through development”. However, to get to that point of the reserve being proved, the explorer would need to spend perhaps a further $100 million on appraisal so the value at discovery would be commensurately less. Furthermore, the time frame to get to FID from discovery would be two or perhaps three years. Based on the 10% cost of capital the value would be reduced to 75% of the FID headline value at the time of discovery - so a sale post discovery might only be expected to achieve a value of $5/bbl versus $8/bbl at FID. Theoretically, there is value to be captured by holding through appraisal but this needs to be traded off against the ability to redeploy the proceeds of disposal in new exploration projects.

Development Schedule? How long does it take after FID to build roads, pipelines, production treatment, water injection, gas reinjection, drill and complete development and injection wells?

Normal experience would suggest approximately 4 years to allow for seasonal activity from FID to first oil for a full field development. Schedules for Point Thomson, Alpine, Kuparuk River among others are broadly consistent with this estimate. Year 1 would likely involve sourcing and mining local aggregates (for roads and facilities pads) as this is cheaper than shipping in gravel to such a remote location. During this timeframe fabrication of process vessels can begin off site. However the field construction work, unlike exploration and appraisal drilling, is confined to summer and autumn months. Procurement of long lead time items (high grade steel and rotating equipment such as compressors, pumps and power systems) means that installation could be part of the summer in year three.

Welding and many other outdoors activities simply cannot be completed cost effectively in winter. Creating permanent roads and digging foundations are not activities for frozen ground. However, winterized rigs allow year round activity for development drilling. So well hook-up and commissioning could be expected during year 3 and into year 4.

An example of the development program for Willow https://static.conocophillips.com/files/resources/willow-fact-sheet-final.pdf based on the assumption of development beginning in 2020 supports the 4 year time frame. COP is among the most efficient operators on the North Slope so it is unlikely that smaller, less well resourced companies would beat that schedule.

The lead times for Pantheon’s discoveries at Alkaid and Talitha would potentially be similar to the 7-10 years to achieve full field production but, as a result of their location by the Dalton Highway and under the TAPS line, it is reasonable to expect early production within perhaps 2 years of discovery (indeed, even long term production test volumes during 2021 being trucked to Deadhorse). The same might apply to any discovery of oil on the Eastern portions of 88E’s Project IceWine acreage.

In remote oil basins, just as in real estate, it is “Location, Location, Location!”