Tuesday, 3 October 2017

Revealing Big Oil hurdle rates

Our analysis on cost of capital tends to focus on small/mid cap E&Ps as these are companies we traditionally model and where the deals are material enough to investors that get good visibility on deal metrics. The analysis indicates that costs of capital (as implied by buyers' IRRs) are perhaps higher than many would expect - in the range of 15-20%.

These deals are often characterised by a capital-constrained seller and therefore often a buyer' market. How the deals stack up when deals are made with other large companies or NOCs are probably different and should illustrate the lower end of returns that the buyers are willing to accept.

In this vein, the farm-outs by Pemex to majors should be a good guide to how majors bid in a competitive process for attractive assets with low technical risk. With a farm-out of Maximino in progress, we look back at the last deal executed.

We therefore model the returns expected by the farm-out deal of Trion - won by BHP (BP was the only other bidder and bid almost exactly the same terms as BHP) and find that on our price deck ($70/bbl in 2022), the 2017 IRR is 11.5%. This is significantly lower than most other farm-out deals we have reviewed.

The analysis seems to confirm the lowest returns majors are willing to accept are around 11-12% on our price deck (although these move materially as different oil prices are used).

Thus, our implied cost of capital chart is updated. If we apply long term oil prices used by BHP and BP in their impairment testing (which we believe are high vs analyst consensus expectations), the IRRs are 13.1% and 14.8% - taking them closer towards the trend. Applying the Dec 2016 forward curve gives 8.6%.




Thursday, 17 August 2017

Made a discovery? What are the odds of another?

By Will Forbes

Companies exploring in frontier basins frequently include maps and tables with all the prospects and leads in the acreage in marketing information, often adding the prospects sizes to give an unrisked block resources estimate. There is a risk that these representations are misunderstood by investors.

We agree that managements are right to give investors an idea of the depth of prospectivity in their assets/acreage - more, larger and lower risk prospects give exploration teams the luxury to choose the best chance of drilling a valuable well especially in the case where exploration is mandated by licence commitments. You can therefore understand that a company would want to demonstrate it is drilling from a position of strength.

However, we continue to see dangers in this approach for investors who do not appreciate the complexities in oil exploration. The modern reality is that investors should not use this apparently large resource base as a metric to value the block/company. Companies rarely drill a second wildcat well if the first is a failure. Using Norwegian Petroleum Directorate data, companies have only drilled a licence/block a second time 10% of the time if the first was dry in the last five years or so (see chart below). Frontier exploration failures with no follow-ups are common (just looking at West Africa in the last five years throws up many wells in Morocco, Namibia and elsewhere). 

But is this data indicative of other, more frontier, areas? We think so; from 2011-2015, West African dry wells had a follow up in the same block only 7% of the time.









We have therefore long been advocates of only valuing the first well in a block (unless a campaign is already committed to and more wells are definitely going to be drilled). Managements should be more clear to reduce the possibility that (less informed) investors will attribute value to the cumulative gross block resource estimates.

What about the play opening argument?
Investors and managements have made the argument that if a discovery is made, it significantly de-risks further prospects. This would mean that we should include some value for this de-risking before the first well.

We again look at the NPD for some quantification, but with many caveats. The North Sea was de-risked by UK drilling before widespread exploration/development occurred in Norway and explorers in the basin had higher levels of confidence in the various elements (source, migration etc) before drilling. Commercial quantities of oil are typically much lower in Norway that they may be for more frontier areas offshore (perhaps 50mmbboe for Norway vs 200mmboe for offshore Africa). Every basin is different, so we give this analysis with a pinch or more of salt.

However, looking at blocks in Norway, the chances of a block containing two or more fields given that it already has one is around 40% (where a block is of type 1/3 or 10/11) - see chart below. These blocks are much smaller than those typically seen in Africa. Scaling up to a collection of blocks which are roughly equivalent to Cairn's Deep Offshore block (containing the SNE field) in area, this chance increases to over 55%.


This is for Norwegian blocks, that are substantially smaller than typically frontier offshore blocks

Resulting probability tree
And assuming a 30% CoS (roughly the commercial chance of success for a wildcat in Norway), we can produce a rough interpretation routes to success/failure. Here we also use the observation that if the first well is unsuccessful, the chance of success for the second well falls to 15-20%. For information, if two are unsuccessful, the chance of a third being a success has been 13% (and 6% for a fourth well). Given only 10% of initial unsuccessful wells are followed up, the impact of these CoS on subsequent wells is vanishing small.


Note: We use a 50% chance after a first success here as a simplification of the 40-55% chance of finding more than one field given one has already been discovered (where 40% is over a block in Norway and 55% is for a collection of Norwegian blocks roughly the size of the SNE block in Senegal)


Overall, going from NPD data, the chance of two (or more) successes is 15%, the chance of a first well being successful with no further successes is 15%. The chances of a failed campaign (either because a second well is not drilled or a second is unsuccessful) is 69%. The chance of a first failure is followed up by a success is 1%.

Conclusion
Going from this data, there is therefore a case for including value for play-opening discoveries. For every discovery, further discoveries are have a c.50% chance of occurring, though many more wells may need to be drilled to make another discovery - the implied individual CoS rises by perhaps 15%. 

However, we remain cautious. Investors have to take account of the time to appraise and develop discoveries. When are subsequent wells going to be drilled to enable possible discoveries, are all going to be co-developed or will others be tied-back after first oil or have a longer term phased development?  

In the case of small oil companies, the effect of financing (dealt with in many previous blogs) and possible farm-downs/delays should also be accounted for. Given a failure is far more likely than a success, we are happy to continue to examine only the value of a drill until a result is known. This analysis then gives a possible framework for how an investor (and shares) may then react after a result.





Tuesday, 8 August 2017

Kosmos searching for more investors

by Will Forbes

On 2 August, Kosmos announced that it will be seeking a main-market listing in London during the third quarter in order to access European investors. According to Reuters, the company indicates "There are a number of European investment funds and specialist international oil and gas investors that are currently unable to hold Kosmos' shares due to their listing outside of a European regulated market"

We also believe it is a function of the differing attitudes the investor bases have towards exploration. Given the multitude of onshore producers, US investors typically place more emphasis on near-term cashflows and production. Especially since the advent of shale fracking, exploration risk is smaller and a greater attention is given to cashflows and financial leverage. 

European exchanges tend to see more international explorers focussing on frontier areas, leading to a greater understanding of international exploration and willingness to value it.  European exchanges are more used to taking a risked approach to longer term value ideas such as 2P/3P reserves and exploration. 
This may explain why European analysts have higher target prices given Kosmos' mix of production/ development/exploration assets.

Given these differences it makes sense for Kosmos to list in London. Of the companies operating (or those that had recent drilling) in the West African coast, many of them are European listed. The majors are joined by Tullow, Cairn, Ophir , GALP, Genel, Seplat and many small and micro-cap peers. While recent years have seen the London market paying less attention to exploration, we believe it is a more natural home for Kosmos, which will be exploring for more resource in 2017-2018 than any other E&P (according to the company). 

For European investors interested in exploration, Kosmos may be an attractive prospect.

In 2017-2018 it is targeting six material wells. In Africa four targets represent large opportunities (pre-drill estimates of gross unrisked resources are Yakaar 833mmboe, Requin 833mmboe, Lamarin 833mmboe, Requin Tigre 2.5bn boe). Of these, Yakaar has been a successful discovery which, added to Teranga, opens up 20tcf of pMean gas resource and a large LNG development in Senegal. With partner BP, Kosmos is targeting a 2018 FID and 2023 first LNG. Given the LNG environment at the moment, we would not be surprised to see dates slip slightly, but Kosmos is well placed to monetise these resources.

In South America, Kosmos holds interests in two blocks close to the existing Liza and Payara discoveries made by Exxon. Anapai and Aurora could each hold 300mmboe according to the company.



Additionally, it has production cashflows from Jubilee and TEN, which will be well known to Tullow's base. In May 2017, its presentation indicated around $260m of FCF could be generated at $50/bbl oil (including farm-out proceeds).

Other observations US vs Euro listed E&Ps




If the analysts are a guide to investors' attitudes, it's possible that greater European investor shareholdings could contribute to an increase in the share price, as existing European-focussed analysts for the company have markedly higher average target prices than their US-focussed counterparts.



Source: Bloomberg. Black dot is Kosmos, green dots are European E&Ps


In fact, if we apply only the target prices for European analysts and assume that Kosmos moves towards the trend line in EV vs discount to target price seen in the chart above, it could lead to more than a 20% increase in share price.

Given the relative paucity of European E&Ps (vs US), it is very possible the listing of a $3.5bn EV company on London exchange will attract more investors and interest - only Tullow will be bigger. More analysts are likely to cover the company (Kosmos has 15 at the moment, Ophir 18 and Tullow 27).















Wednesday, 26 July 2017

Killing the goose that laid the golden eggs

By Charlie Gibson


In London, the shares of Acacia Mining (formerly African Barrick Gold, the 62%-owned, listed subsidiary of Barrick Corp) have fallen by almost half in the last 24 hours, after the Tanzania Revenue Authority demanded $190bn ($40bn in alleged back taxes, with the rest in interest and penalty charges).

It is difficult to pinpoint the exact origin of the dispute between Acacia and the government and, arguably, it goes back to Barrick’s first major investment in the country in the late 1990’s. Then, the price of gold had fallen to a 20 year low of US$250/oz and Barrick, which had had some good exploration success in the Lake Victoria goldfield negotiated some very keen fiscal terms with the government to develop its new mine, Bulyanhulu. Had the price of gold stayed where it was, perhaps the current dispute would never have arisen. However, as the gold price rose to US$1,250/oz (via a record high of US$1,900/oz in 2013), Barrick’s tax breaks (duly enshrined into Tanzanian law) became – if you will excuse the pun – a gold mine, effectively shielding its assets from actually paying cash taxes for years, if not decades. As the old saying goes however, wealth begets envy and, while Acacia (as it had been renamed) trumpeted its attractions to western investors, the Tanzanian government looked on ever more covetously as its natural wealth (as it saw it) was shipped overseas. If that was the environment, then it only took a spark to set the plains ablaze. In this case, that spark was provided by the election of a populist Presidential candidate in 2015, John Magufuli, who was easily able to incite lingering anti-colonial resentment to paint a picture of rapacious western investors cynically depriving Tanzania of its natural wealth.

The first Acacia knew of it was when the government passed a law banning the export of metalliferous concentrate in February 2017 under the guise of wanting to develop a domestic smelting industry. That was rapidly followed by the reports of two Presidential committees in the following four months that alleged that Acacia had been under reporting its gold exports in concentrate form by a factor of ten. That is to say, when Acacia declared 100oz of exports, the committees accused them of selling 1,000oz. The implication of the committee’s findings is that Bulyanhulu and Buzwagi each produce more than 1.5 million ounces of gold per year and are the two largest gold producers in the world, that Acacia is the world’s third largest gold producer and that it produces more gold from its three mines than AngloGold Ashanti from 19 mines, Goldcorp from 11 mines and Kinross from nine mines. Suffice it to say that Acacia is a publicly listed company and that its financial, production and gold reserve records are audited to international standards and that it must comply with government oversight agencies in Tanzania, the UK, Canada, and the USA that have the right to impose heavy penalties on companies that do not report their production and financial results accurately. Despite requesting it, Acacia has yet to be given a copies of the reports, nor has it been provided with details of the sampling protocols followed by the committees.

At the same time as the Tanzania Revenue Authority (TRA) ceased providing Acacia with VAT refunds, parliament then passed the Natural Wealth & Resources Contracts (Review & Re-Negotiation of Unconscionable Terms) Act and the Natural Wealth & Resources (Permanent Sovereignty) Act. The former allows the government to dissolve existing contracts deemed prejudicial to the interests of Tanzanians, while the latter prohibits the involvement of foreign courts or tribunals in disputes between the government and investors and compels companies to process minerals within the country rather than exporting them as raw materials. New laws have also increased the royalty rate applicable to metallic minerals by 2% as well as imposing a 1% clearing fee on exports, while President Magufuli has ordered the Energy & Minerals Ministry to neither issue new mining licenses nor renew expired ones.

With the dispute apparently escalating, earlier this week, Acacia announced that it had received a series of Notices of Adjusted Assessment from the TRA for historical corporate income tax, covering the period from 2000 to 2017, which assert that it owes the Tanzanian government approximately US$40bn of alleged unpaid taxes and approximately a further US$150bn in penalties and interest. To put that in context, the GDP of Tanzania is only about US$50bn! At the same time, local regulations now require miners to list operating assets locally and to achieve a 30% minimum local shareholding by 23 August. Finally, as if to add insult to injury, the Tanzania government appears to be deliberately sidelining the company by insisting on negotiating solely with its parent, Barrick, rather than with it, directly.

Resource nationalism has a long and bleak history, from the Russian Revolution in 1917 through the tribulations of British Coal from the 1940’s to the 1980’s and, latterly, all manner of government taxation initiatives and interference from countries as far afield on the political spectrum as Australia and Guinea. Almost none has been blessed with any success and almost all have consigned their mining industries to years, if not decades, of underperformance, inefficiency and underinvestment, with the result that governments have rarely (if ever) reaped the benefits for either themselves or for their populations that they had envisaged. Hitherto, Tanzania had been one of the relative success stories in Africa of a country that had created a stable and trustworthy environment for international mining investors. It would be a shame if it became the most recent candidate to mistakenly (and unnecessarily) kill the goose that laid the golden egg.

Friday, 14 July 2017

Oil and share prices for mid-cap E&Ps

By Will Forbes

With the tribulations of the London-listed E&Ps with the oil price slide, investors have seen large moves in the share prices. 

What has been the  relationship between moves of oil price (in GBP) and shares? Since January 2015, cairn has been materially less volatile than the others. This is not surprising given its cash balance, lack of debt and exposure to immediate oil prices through production. This will change as more and more of its value is dictated by production.
How tight is the relationship?

Friday, 30 June 2017

AIMing high: London listings more liquid than Australia and Canada

By Will Forbes

Companies often ask us our opinion on listing whether they should consider listing on other exchanges to boost liquidity and move their shares closer towards their perceived fair value. The answer is a complex one, market timing, industry and peer group as well as overall market sentiment and always have an impact on the answer. However, the chart below indicate the added liquidity that companies see in London (vs Australia and Canada).

Source: Bloomberg, Edison Investment Research
Of the 35 examples we found (the vast majority in the oils and mining spaces), only ten saw higher share values traded in the two non-London exchanges examined. In all other, London trading dominates the shares. Below is the ratio of value of shares traded (30 moving average) between London and Australian/Canadian listings. In many cases, it may be better to ask why list on any other exchange at all?




Thursday, 25 May 2017

Conservative Energy Policy - 2017 manifesto - shale gas and oil rig decommissioning

Given the current polls (with the Conservatives leading Labour by 47% to 33%), we assume that the Conservatives form the next government and therefore take a look at what (if anything) we May glean from Theresa's manifesto.

Full excerpts from the manifesto are at the bottom, but unsurprisingly perhaps, there are few specifics. Shale gas takes top billing, with an assertion that it could play an important role in "re-balancing our economy". 

To enable this, the manifesto proposes a change in planning laws for shale drilling. "Non-fracking drilling will be treated as permitted development, expert planning functions will be established to support local councils, and, when necessary, major shale planning decisions will be made the responsibility of the National Planning Regime." 
We interpret this as suggesting that initial exploratory drilling will be able to progress much faster and may be made at the national level (aided by a new Shale Environmental Regulator), rather than the current emphasis on local decision making. This may be because of a number of local decisions not to allow drilling (for example in Lancashire in 2016). 

Initial exploration wells (that can prove up the existence of shales, take cores and provide greater insight on resources), would have to be followed up by fracking wells to more definitively gauge the flow rates of any shales discovered. From the manifesto, it is not clear at this point how local objections/councils would be involved in these decisions. 

However, it seems clear that if these proposals go through, it will be potentially easier and quicker to drill wells targeting shale gas deposits. If so, it should benefit existing players in the area (Egdon Resources*, Cuadrilla Resources, IGas, Third Energy, Ineos and Total)

Decommissioning
The government expects the North Sea to be the first major basin to decommission, and the manifesto promises support to a decommission industry, a multi-use yard and the UK first ultra deep water port to aid in this growth. If the UK can build world leading decommissioning expertise, we would expect material contracts to flow over coming decades as massive offshore structures are decommissioned in Europe, Africa and America. We would imagine that this capability will be fiercely changed by existing shipyards and deep water ports around the world (particularly in Asia for example).


Full text relating to oil and gas in the 2017 manifesto
"The discovery and extraction of shale gas in the United States has been a revolution. Gas prices have fallen, driving growth in the American economy and pushing down prices for consumers. The US has become less reliant on imported foreign energy and is more secure as a result. And because shale is cleaner than coal, it can also help reduce carbon emissions. We believe that shale energy has the potential to do the same thing in Britain, and could play a crucial role in rebalancing our economy.

We will therefore develop the shale industry in Britain. We will only be able to do so if we maintain public confidence in the process, if we uphold our rigorous environmental protections, and if we ensure the proceeds of the wealth generated by shale energy are shared with the communities affected.

We will legislate to change planning law for shale applications. Non-fracking drilling will be treated as permitted development, expert planning functions will be established to support local councils, and, when necessary, major shale planning decisions will be made the responsibility of the National Planning Regime.

We will set up a new Shale Environmental Regulator, which will assume the relevant functions of the Health and Safety Executive, the Environment Agency and the Department for Business, Energy and Industrial Strategy. This will provide clear governance and accountability, become a source of expertise, and allow decisions to be made fairly but swiftly.

Finally, we will change the proposed Shale Wealth Fund so a greater percentage of the tax revenues from shale gas directly benefit the communities that host the extraction sites. Where communities decide that it is right for them, we will allow payments to be made directly to local people themselves. A significant share of the remaining tax revenues will be invested for the benefit of the country at large."

Supporting industries to succeed section
"Other industries, like the oil and gas sector, are transforming. The North Sea has provided more than £300 billion in tax revenue to the UK economy and supports thousands of highly-skilled jobs across Britain. We will ensure that the sector continues to play a critical role in our economy and domestic energy supply, supporting further investment in the UK’s natural resources. We will continue to support the industry and build on the unprecedented support already provided to the oil and gas sector. While there are very significant reserves still in the North Sea, it is expected to be the first major oil and gas basin in the world to decommission fully, and we will take advantage of that to support the development of a world-leading decommissioning industry. We will work with the industry to create a multi-use yard and the UK’s first ultra-deep water port to support this industry."

Comparison - text on energy in the 2015 document
"We will continue to support the safe development of shale gas, and ensure that local communities share the proceeds through generous community benefit packages. We will create a Sovereign Wealth Fund for the North of England, so that the shale gas resources of the North are used to invest in the future of the North. We will continue to support development of North Sea oil and gas. We will provide start-up funding for promising new renewable technologies and research, but will only give significant support to those that clearly represent value for money."

*Note: Egdon Resources is a client of Edison Investment Research

Monday, 10 April 2017

E&P industry funding cost still high

By Will Forbes

Cairn's recent deal with Flowstream gives us another data point to examine cost of capital in the industry.

From Cairn's preliminary announcement
"On 2 March 2017, the Group secured funding of US$75m from FlowStream in exchange for the proceeds from 4.5% of Kraken production. FlowStream’s entitlement to Kraken production reduces to 1.35% if FlowStream achieves a 10% return and reduces to 0.675% after FlowStream achieves a 15% return. An additional tranche of US$125m in return for a further proceeds from production across Kraken and Catcher is available, subject to mutual consent, at Cairn’s option. FlowStream’s sole recourse for the funding is to its production from the assets. The agreement is subject to approval from the UK Oil and Gas Authority."

So what return does Flowstream achieve from this investment?
Given the terms of the deal, the return is simply a function of the production (we assume the profile below) and prevailing oil prices.
We assume Kraken production comes online in  H2 2017, although the rate is 40mbbld. Production therefore average 20mbbld

Calculating the IRRs for Flowstream under different oil prices scenarios gives us the following chart. This implies that Flowstream is likely to make an IRR over the life of the field of 20-30%. One would have to be fairly pessimistic on both oil prices and production for an IRR to be much lower than 20% over the project lifetime. The forward curve in March of $56/bbl in 2023 produces a 25% IRR. 


This produces an additional data point for our E&P funding path. Points from this small but growing dataset indicate that industry funding is not getting any cheaper.



This seems like a hefty price for Cairn to sacrifice, and on the surface it is. However, it is worth bearing in mind that it paid very little for the additional 4.5% interest in 2016 and therefore the unlevered cashflows from this additional interest suggest returns of more than 50%. Within this frame, a deal that implying a cost of capital/funding of 25% (for a very small portion of the overall project funding) is very palatable. The deal is also not particularly tax-efficient (at least as we understand it) as it is not tax deductable.

It is worth noting that Cairn has $350-400m of RBL (undrawn), where the interest rate is likely to be less than 10%, and it has significant cash resources, so we are not sure why it sought such an expensive financing solution.

Tuesday, 21 March 2017

Wells to watch in 2017

by Elaine Reynolds

Since the oil price crash of 2014, exploration has been particularly badly hit as companies looked to trim expenditure. Wood Mackenzie estimates that 2017 exploration will account for 8% of upstream expenditure, down from historic norms of 14%. In this more difficult environment, any surviving exploration has tended to be led by majors, for example ExxonMobil's giant Liza discovery offshore Guyana in 2015. In our most recent Exploration Watch, we highlight wells due to spud in 2017 that involve independent companies, with resources estimates greater than 100mmboe. Our exception is the much anticipated multi-billion barrel potential Korpfjell prospect in the Barents Sea offshore Norway, which is operated by Statoil and partnered by major companies.

Concentrated across underexplored basins

The majority of the seven wells that we have chosen to highlight here are located in underexplored basins where success either nearby or in an analogous basin has focused attention on the region. These wells include the Araku prospect offshore Suriname and to the east of Liza, and the Druid/Drombeg well in the Porcupine Basin, which is an area attracting interest following success in the analogous Flemish Pass Basin. Similarly, the Ayame well offshore Côte d’Ivoire is looking to replicate the success in Jubilee, 600km to the east. Other wells are in areas only recently opened up for exploration. Korpfjell sits in the Barents Sea but in a licence close to the Russian maritime border that was offered for the first time in the Norwegian 23rd round in 2016, while the Zama prospect offshore Mexico was awarded in 2015 after the country opened up its upstream sector to private investment for the first time in 75 years. However, two of the wells are located in the mature UK North Sea, where both Partridge and Verbier are targeting over 100mmbbls in a region where the average discovery size is 20mmbbls.

To read the full report click here , or to see a short discussion on our Bitesize briefing, click here

Wednesday, 1 March 2017

Misunderestimations - how accurate are production forecasts from industry and analysts?

By Will Forbes

Looking at the accuracy of production forecasts for major oil companies (by the companies and by covering equity analysts)
Sources to all charts are company websites (production and guidance), Bloomberg (production and forecasts) and Edison Investment Research (necessary adjustments)


Oil exploration and development is an enormously difficult process. To successfully find oil or gas, companies have to undertake complex geological groundwork, including acquiring expensive seismic data. Experienced and highly trained staff have to interpret that data, processed by supercomputers, to try to understand what rocks thousands of metres below the surface and laid down tens of millions of years ago, may contain.

Rigs then have to be contracted (some costing hundreds of thousands of dollars a day to hire) that are powerful and accurate enough to end up within metres of the intended target after drilling more than two kilometres of rock.

If found, the oil than has to be developed and produced, which will often take a decade from discovery to first production, and costs billions of dollars and millions of man hours. Under these conditions it is not surprising that difficulties arise and delays result.

Having said that, these are difficulties inherent in the industry and ones that you would imagine would be at some level improvable over time. So why is it that forecasts of future production by many major oil companies are so consistently over optimistic, and why do the market believe the forecasts this year?

As can be seen below, the forecasts of production (grey lines) for many of the majors have overplayed the actual production over time (dark green), and for many this has been consistent. Perhaps more puzzling is why the analysts covering the companies  are comfortable forecasting that production rises so strongly (in line with company forecasts), given the historical suggestion that this seems unlikely.

Below is the production over time split for major oil companies (BG (now subsumed by Shell), BP, Chevron, ENI, Exxon, OMV, Repsol, Shell, Statoil, Total) compared to the forecasts given by these companies over time. It is clear that over the time period examined, companies did over estimate their production markedly. 

Factors that affect production that can't be predicted/divulged to the market include planned acquisitions/divestments (particularly important for BP's production through the period following the GoM incident), oil/gas prices affecting PSC terms, OPEC requirements and entitlement volumes and these will have played a part in the overestimation. Of these divestments and acquisition are the easiest in theory to normalise for, though in reality production for assets in any year after the acquisition is harder, while for large companies, not every sale is fully documented for investors. The dotted green line represents current analyst forecasts of production (see section later).

We note that the companies' websites restrict the historical presentations we have been able to access. ENI and Total go back the furthest while Statoil only goes back to 2012. This may make the predictive accuracy of the companies with the most lines look the worst, when this may not be the case. We would like to go back further to test how the accuracy was from 2000 or earlier, but that is not practical at this time.

We would note that the analyses below is almost certainly true for most industries and is a feature of human nature and the reality of business pressures. We are therefore not explicitly criticising the companies directly, but rather trying to point out for investors a common theme that they may seek to take account of, particularly as strategy season continues.
















Interestingly, virtually all companies continued to forecast growth through multiple periods even when oil production fell by 1.5% per year between 2006-2014. The trend seems now to be resolutely up, with a combined growth rate of 2.7% out to 2020, but these figures seem to indicate that investors may be wise to re-visit these broad assertions. There is no reason to disbelieve that many companies will grow at the rates that they forecast, but as a whole, we would be surprised (given the historical trend only) if this actually holds for the group.

Accuracy of market analysts
Companies are the first source of data for analysts on production targets and growth assumptions - without information provided by the companies, analysts would have less visibility on which projects will come online when. It is therefore right that analysts rely heavily on these estimates. It is also fair, given what we have seen, that analysts should be cautious of using these numbers as a baseline, given that companies (in the period 2010 onwards anyway) routinely missed their growth targets and instead shrank production by 1.5%. Missed production targets mean less cashflow which means worse financial positions and reduced ability to fund debt, capex, dividends and buybacks.

Below are the analyst revisions for production estimates for the majors from 2010 onwards. This shows material downgrades across the board. As can be seen in the charts above, the consensus going forward is generally in line with company forecasts, and this meant that analysts were much too optimistic in forecasts two years forward (by an average of 8% 2011-2016) but the estimates were unsurprisingly more reliable on the 1st January of the year in question (at 2.3% too optimistic). 



































Wednesday, 15 February 2017

Filicudi discovery - positive start to 2017 Barents exploration

by Elaine Reynolds

Lundin's Filicudi discovery is a successful start to exploration drilling in 2017 for the Barents Sea. The prospect holds an estimated 35 - 100mmboe and encountered 63m of oil and 66m of gas in high quality Jurassic and Triassic sandstones. Filicudi is on trend with Johan Castberg around 40km to the north east and the discovery has derisked the adjacent 218mmboe Hurri prospect together with the 285mmboe Hufsa. As a result, both prospects now carry a 25% CoS, and Lundin and licence partners AkerBP and Dea are considering drilling one or both of these later this year. 

Meanwhile, attention in the Barents will now turn to the ENI operated Boné/Dazzler* well, with partner Faroe indicating that results can be expected around the end of February. Although the prospect sits 90km to the north of Johan Castberg, it is targeting similar Jurassic and Triassic targets encountered both there and in Filicudi.

Source: Faroe Petroleum

Johan Castberg and Filicudi sit on the Loppa High, while 
Boné/Dazzler is located on the southern flank of the Stappen High and separated from the Loppa High by the Bjørnøya Basin, however it is located in a structural setting that is similar to that found in Johan Castberg. To date, the bulk of exploration across the area has taken place in the Loppa High and the closest discovery to Boné/Dazzler, Pingvin, was a technical gas discovery, although traces of oil were found.



Source: NPD

The high impact Boné/Dazzler target is a large horst structure with key risks around reservoir and seal. This is due to the significant uplift and erosion that has typically occurred across the area, and has resulted in a CoS for the prospect of 15%.The well is targeting 232mmboe prospective resources and if successful would high grade three further prospects for Faroe, Dazzler East, South and West, that are currently independently estimated to hold combined best prospective resources of 388mmboe. At Faroe's recent operational update,Boné/Dazzler was described during the call by COO Helge Hammer as a Johan Castberg lookalike that could hold up to 700mmboe.

Beyond the Southern Barents, drilling will commence for the first time in the Southeastern Barents in the second half of 2017 when Statoil is due to spud its Korpfjell* exploration well. Located in the most sought after acreage in the recent 23rd round, Korpfjell is estimated by partner Lundin to have a multi billion barrel potential. 

*Boné/Dazzler: Operator ENI 30%, Partners Faroe 20%, Bayerngas Norge 20%, Petoro 20%, Point Resources 10%

*Korpfjell: Operator Statoil 30%, Partners Chevron 20%, Lundin 15%, ConocoPhillips 15%, Petoro 20%


Thursday, 9 February 2017

Tullow dipping a toe back into exploration

By Will Forbes

It is not surprising to see the markets continue to concentrate on the near-term financial health of the company given the material impacts that the TEN start-up and recent issues with Jubilee will have in 2017. Tullow rightly acknowledge the company's current financial situation and are focussing on production cashflows to enable the steady de-leveraging of the balance sheet. Exploration and appraisal spend remains at very limited levels vs history.
Tullow E&A spend as forecast by TLW in advance vs actual spend

However, it is notable that Tullow is signalling that the company is sensibly looking beyond these near term issues to plan for future growth, fuelled by its core business of exploration. It is still well below the levels seen as recently as 2014 and only $100m is forecast to be spent in 2017 (vs over $1bn at peak). However, E&A spend is set to increase in 2017.

This spend is sensibly still focussed on near-field step outs (in the case of Ghana and Kenya), but is also moving towards key wildcats including the Aruka well, described by the exploration director Angus McCoss as one of the best prospects they've seen in a decade.

G&G elsewhere is continuing with an eye to moving assets in Mauritania (3D seismic in 2017) and Namibia (further work being performed) towards drill-ready status.


Source: Tullow, Edison estimates. Prior to 2012 Tullow gave gross upside estimates. From 2012 onwards these were altered to pMean. The exact relationship between P10 and mean varies - we have assumed that P10 is twice that of pMean based on a rough polling of other listed E&P CPRs. Includes Exploration and appraisal wells as estimated for the year ahead by Tullow in its annual factbook. In some cases, where WI or voluems are not given we have made conservative assumptions

Simple, low cost exploration with an eye to development

Falling well costs are a large part of Tullow's ability to start to move back towards exploration. Kenyan onshore wells that may have cost $25m a few years ago can now be drilled for $10m (also helped by performance inflation and efficiency gains from drilling 12 wells so far), while the Araku well in Guyana/Suriname region is likely to cost $40-45m, substantially down from an estimated $100m at peak.

This is not the only move in Tullow's renewed exploration approach. It is a key facet that the exploration targets also take development into consideration - Angus McCoss stressed that shallow water prospects reduce exploration drilling cost and development cost. Another target in Guyana/Suriname assets (Amalia) lies updip of Liza in just 100m of water (vs 2,000m at Liza). Many of the Namibia leads are in water around 500m deep.
Simpler, cheaper wells also reduce the likelihood of substantial cost increases, 


Araku-1, Suriname in H217
XOM's success at Liza-1 de-risked  the Guyana Basin in which Araku lies (albeit over 150km away) and Tullow believes its acreage located around the "catchers mitt" encompasses "game changing low-cost prospects with multiple follow up potential". Araku is a four-way  structural prospect with an estimated 500mmboe with good seismic amplitude support in 1,000m water depth that will be drilling in H217. At around $14m net to Tullow, drilling costs are low.

In the Guyana side of the basin, Exxon's subsequent mixed success in Payara and Skipjack could be seen as good for Tullow's shallower prospects (which would benefit from charging from these leaked targets). 

Monday, 6 February 2017

Diversified Gas and Oil - quick thoughts

Friday 3rd February was the first day of dealing for Diversified Gas and Oil, a conventional onshore US producer with assets in the Appalachian basin (in Ohio, Pennsylvania and West Virginia). The company raised c. US$50m (c.£40m) pre-expenses through a placing of 61m shares at 65p/share (indicating a market value of £69m or $86m). This blog is a summary of parts of the admission document and our reflections on it based on initial and basic analysis.

As hinted at by its name, DGOC is heavily gas oriented, with 2.29mmbbls of 1P oil and  153.7 bcf of gas (or 27.9mmboe in total), with current production of 26,000mcfd and 475 bbls/d. The CPR includes no estimate for 2P reserves.
The production comes from 7,500 wells in onshore basins and has grown, acquiring conventional assets across shale basins. According to management, shale companies are offloading the conventional portions of the acreage to concentrate on shale, relying on the conventional to lock in the acreage ("Held by Production"). 43% of the 2017 gas production is hedged (and 62% of oil). Average opex is $9.5/boe according to the company.

The company plan to continue to invest in the assets, with wells costing $200-300k apiece. It has already drilled 150 producing wells with no dry holes. According to the company, wells could last at least 50 years, exhibiting high initial hyperbolic decline, followed by a long exponential tail.
Hatfield-2 well, Ashtabula County, Ohio  (1985-2015)

The company used the majority of the proceeds to pay down debt, leaving the company's cashflows to be available for reinvestment and a promise to pay at least 40% of cashflow from operations to shareholders.

Value
The company listed at 65p/share, indicating a market value of £69m (or $86m). The accompanying CPR (by Wright and company) indicates an NPV10 of the proved reserves of $104m (post tax), though we note that this assumes prices that vary from the current forward curve. CPR prices for oil are below ($52.93/bbl from 2022 onwards vs forward curve of $59/bbl in 2022), but gas prices are above (HH of $3.3/mcf in 2022 vs forward curve of $2.9/mcf). We also note that depreciation/taxes are modelled differently in the CPR to how we would expect.

Using inputs from the CPR on production, costs and commodity prices (but using our own modelling on depreciation and taxes), getting an NPV10 of $90m. Interestingly, if we mechanically move from the CPR assumptions on prices to forward curves numbers the NPV10 moves to $86m on an unrisked basis. Using this analysis (and looking at asset value only), the current market cap would be justified by the asset cashflows ending in 2030 (although production is likely to continue well after this date).

If we look instead at a dividend discount model, assuming that 40% of CFO-capex is paid in dividends, the value at the CPR oil/gas price forecasts becomes $30m, leaving investors requiring further growth in production and cashflows to justify the share price. 

These numbers are explicitly not our valuation of the company - we have to investigate the reasons behind the differences between our modelling and the CPR, as well as many other factors such as oil prices vs benchmarks, capex/opex and the production characteristics - checking our back of the envelope calculations at all times. We use 10% as a discount rate for comparability purposes rather than as an applied WACC. These asset values importantly do not include cash/debt in the business nor G&A expenses over time. Given that the business is US-based, US-run we are curious as to why it has chosen to list in London. We would also look to get a further view on upside to the disclosed CPR reserves - most London-listed companies are examined on a 2P basis, rather than 1P, investors may be therefore be comparing apples and oranges on a headline level.



Monday, 30 January 2017

SDX Energy's acquisition of Circle's Moroccan assets - summary

By Will Forbes

SDX Energy’s accretive $30m acquisition of the Egyptian and Moroccan assets from Circle Oil is a major step to increase the company’s footprint and is in line with its stated ambition to grow (in)organically. The Moroccan gas production in particular is a step-out from its existing base, but provides strong cash flow generation, quick effective payback and the possibility of future high-value development and exploration. The increased working interest in NW Gemsa should boost SDX’s share in FCF in Egypt, and further contribute to costs for the upcoming waterflood programme. We increase our core NAV from 39p/share to 42p/share (RENAV moves from 68p/share to 57p/share) even after some (unrelated) modelling adjustments. Despite a recent increase in the shares, this suggests further upside for investors in a larger company with greater ability to invest in high-value projects in North Africa.

Accretive acquisition

The acquisition should be accretive to shareholder value, despite the share dilution connected with the announced $40m capital raising. The associated working capital connected to the acquisition (as well as not taking on any of Circle’s debt) reduces the effective (core) metrics to $3.5/boe (compared to SDX’s pre-deal metric of $4.6/boe pre-acquisition at 30p/share). We value the acquired assets at $70m (on a core basis), implying that SDX obtained them at a c.60% discount.

Acquisition increases SDX footprint

SDX has always been actively looking to grow inorganically and the US$30m purchase of a 40% stake in NW Gemsa (Egypt) and 75% in Sebou (Morocco) production (including approximately US$18m in working capital) is a strong first move. The new assets are strongly cash generative and could add around $20m of cash flow in 2017 and 2018 (each year, including working capital movements) and with an effective IRR of over 50% and a 1.5 year payback on the acquisition price.

Valuation: Accretive deal increases core NAV to 42p

We have folded the new assets into the existing portfolio, which increases our indicative core NAV to 42p/share (from 39p), while our indicative full NAV (including a risked 7p valuation for the South Disouq exploration well and possible upside from Meseda waterflood) is now 57p/share. SDX is now a larger company with strongly positive cash flows in the near term, and can use these to further explore in Morocco, develop a discovery at South Disouq or to grow further inorganically. It retains the ambition to grow in North Africa towards a production rate of 25-30mboed.

The full note is available here

Friday, 27 January 2017

EnQuest acquisition: ability to extract net economics (NAV) will be demonstrated over time

By Sanjeev Bahl

EnQuest’s agreement to take over operatorship of Magnus, SVT and associated infrastructure is a material operational undertaking, especially when considered in parallel with commissioning and ramp-up of production at Kraken. The transaction will involve EnQuest taking on several hundred onshore and offshore staff and contractors. With this in mind EnQuest’s stage approach which involves taking on just 25% of Magnus and an additional 3% of SVT at the out-set appears to be sensible. The combination of deferred consideration payments, a ‘call’ option on additional equity in the transaction assets and downside protection mechanisms suggest that EnQuest is backing its ability to maximise value from late life assets without exposing shareholders to potential downsides. EnQuest has until 15 January 2019 in order to exercise its option over an additional 75% of Magnus and related transaction assets giving it time to understand the operational complexities as well as study decommissioning options before taking on risk. 
The net economics of the transaction (and net NAV impact) will be largely driven by EnQuest’s ability to reduce opex costs from current levels (we estimate that these may currently be around current spot oil prices)  by increasing oil production and production efficiency, increasing oil recovery (significant potential exists in the Kimmeride Clay where current oil recovery is just 30%) and through deferring and reducing decommissioning costs. From an opex perspective there is a material opportunity to reduce Magnus onshore costs and overheads as well to leverage logistical synergies (supply vessels and helicopters) in order to bring down costs closer to group levels (c.25$/bbl).
  
Given the size of the Magnus platform (over 70ktonnes), decommissioning is likely to be an important consideration when it comes to deal value. Prior to exercising its option, EnQuest’s liability is restricted to the maximum of 7.5% of BP’s actual post-tax decommissioning cost and cumulative positive cashflows from the transaction assets. On exercising its option, it’s exposure is uncapped on the additional 75% it would acquire of Magnus. 
The deal does come at a price. In the event of option exercise whereby EnQuest acquires 100% of Magnus, 9.1% in SVT, 27% in the NLGP and 11.5% in NPS, BP will receive 100% of net cash flows from the transaction assets until the non-cash consideration of $285m is recovered. This is followed by a BP cash-sweep of 37.5% of net cashflows until a further $1bn is recovered. Shareholders will need to be aware that whilst the anticipated step-up in production from Kraken in H217 will drive a corresponding step-up in cashflow from operations, EnQuest expect it will take around 2 years (at current oil prices and assuming a 3 well programme on Magnus) to see a cash benefit from the transaction assets.  Depending on the tax structure of the deal it does sound like BP is benefiting from EnQuest’s fortunate tax position (we do not expect EnQuest to pay cash tax on Magnus) - BP is divesting of an asset whilst still receiving a significant percentage of transaction asset cashflows in the early years that are protected from cash tax through EnQuest’s historic tax shield.
The transaction highlights EnQuest’s confidence in its ability to drive the recommendations of the Wood Review, maximizing economic recovery from late life assets, and the use of innovative transaction structures in order to facilitate the transfer of mature assets from the hands of the majors to ‘leaner’ operators. EnQuest analyst NAV upgrades are understandable, but we expect there to be significant uncertainty over the pace of opex reductions as well and the timing / cost of decommissioning (we believe the gross decommissioning cost for Magnus and the transaction assets could be well over $700m) which will ultimately drive net economics. With EnQuest now on the verge of producing over 50kboed we expect management focus to shift from growth to operational execution in order to extract maximum value from its expansive asset/resource base.