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.