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"Hunting – sounding the horn for the recovery"

Hunting has had its ups and downs over the years, but Mark Watson-Mitchell reckons better times are ahead.

Although it has been in existence for over 140 years, I have only followed this group for the last four decades.

From its origins of shipowning, it ventured into oil tankers, and later it went into aircraft servicing and manufacturing, even owning an airline. Then in 1938, it started oil prospecting in Texas and later moved into Canada, before progressing into petroleum retailing, lubricants and specialised products.

It has reinvented and reorganised its operations several times in its history and always shown its ability to adapt to changing fortunes in its marketplace.

I can remember having several breakfast and lunchtime meetings in the company’s offices overlooking Nelson’s Column in Trafalgar Square, with Richard Hunting, the group’s former Chairman. I always enjoyed listening to him and his team describing the operations of their business.

It has had its ups and its downs over the years. However, I have always been impressed by the professionalism that its management has shown.

The gradual metamorphosis

Today Hunting (LON:HTG) is an international energy services provider to the world’s leading upstream oil and gas companies.

Irrespective of whether it is intended for oil, gas, onshore or offshore, conventional or unconventional, its broad range of products and associated services spans the lifecycle of the wellbore.

It manufactures the premium, high-end tools and components that are required to extract hydrocarbons across that lifecycle of an oil and gas well.

An impressive portfolio of intellectual property

Hunting’s substantial IP portfolio is a significant barrier to entry for competitors and allows it to defend margins and offer more operational flexibility, particularly in a downturn.

It has a truly global footprint, employing nearly 3,000 people operating in 11 countries with distribution and with the use of its products extending well beyond those countries.

Recent results

The group declared its final results for the 2020 year two weeks ago and its Report and Accounts are due to be published this coming Thursday (18).

The group’s AGM is due on 21 April, at which time we should get the latest trading update.

The reported finals showed that 2020 was not a good year for the group, which was understandable due to the massive reduction of activity in the global oil and gas marketplace.

Last year’s revenues fell from $960m to just $626m, while 2019’s $93.1m pre-tax profit was replaced with an underlying adjusted $19.4m loss.

Current estimates

But oil prices have moved significantly better in the last few months and better times are now being anticipated.

Estimates for the current year suggest similar revenues, with the loss falling to only $5.4m.

Going into 2022 sales could pick up sl

https://www.telegraph.co.uk/business/2021/03/13/ministers-considering-ban-north-sea-exploration-licences/

Ministers are considering declaring the beginning of the end for the North Sea oil industry with a ban on new exploration licences.

The radical move is on the table as part of a decisive shift away from fossil fuels and as part of preparations for the crucial climate summit the Government is due to host in Glasgow in the autumn.

Britain is already legally bound to deliver “net zero” carbon emissions by 2050. Options being consulted on are understood to include an end to issuing licences in 2040, and an immediate temporary pause in licences. No change to the licensing regime is also possible.

One industry source said a decision is close. A ban on new licences would begin the terminal decline of British exploration in the North Sea and would be particularly controversial in Scotland.

An estimated 39pc of the 270,000 total UK jobs supported by the oil industry are in Scotland – more than any other UK region – and the SNP has relied on forecasts of future North Sea tax revenues to claim that the nation could pay its way outside the Union.

Oil and gas reserves from the UK Continental Shelf are dwindling since their heyday in the 1970s and 1980s, but had been expected to play a significant role in its long-term energy needs, as well as in production of plastics and chemicals.

More than 30pc of the UK’s electricity in 2020 was generated by gas-fired power plants, while the offshore industry met about 45pc of its overall energy needs in 2019, according to industry figures.

Although that will change as wind turbines and electric cars come to the fore, any restrictions on licences are likely to trigger debate about whether the move would simply increase Britain’s reliance on imported gas and oil, potentially increasing emissions due to transportation requirements.

One industry source said: “We are going to still need oil and gas in this country. There is a lot of excitement around Cop26 and the imperative to be seen to do the right thing.”

The Government is keen to be on the front foot ahead of the United Nations Cop26 international climate change conference the UK is hosting in Glasgow in November. Last week, ministers overruled a local authority and launched a public inquiry into whether a new mine to produce coking coal for steelmaking should be built in Cumbria, following accusations the plans would damage the UK’s international reputation on environmental issues.

Drillers and explorers have been investing heavily to cut emissions from their own operations, including by cutting flaring. Oil and gas rigs in the UK are responsible for about 10m tons of CO2 per year, about 3pc of the total.

Some have also branched out into developing carbon capture systems and hydrogen, which the Government sees as key to its push to developing a greener energy system. Last year, Denmark, once a major Western European oil and gas

pt 6
The second permit acquired as part of the Schlumberger deal is Block IX – a vast licence, covering almost 2,000 sq km. The acreage is covered by relatively modern 2D seismic (including 454km of 2010 vintage data), and in 2013 two wells were drilled exhibiting both oil and gas shows without commercial success.

While Block IX therefore provides interesting exploration opportunities, we expect resources to be focussed on Block XIB and West Rustavi, and therefore Block IX will provide option value, should it be able to attract an industry farm in partner willing to spearhead exploration. Importantly, all work programme obligations have been satisfied by the previous operator, and the permits have some 14 years to expiry (plus further optional 5yr extensions).

2 PRODUCTION PROFILE & FINANCIAL FORECASTS
Our production profiles are based on underlying ‘base production’ of 450 boepd (average FY21), including the c.150-200 boepd recently acquired and a conservative estimate of c.250-300 boepd from the two existing West Rustavi wells (which are currently producing 740 boepd).

On top of this, we have assumed a total of c.627 boepd (again average full year) from the three wells to be brought onstream over the course of the year resulting in FY21 annual production of 1,184 boepd.

Due to the phasing effect, production grows in 2022, averaging 1,863 boepd on our numbers, building to 2,357 boepd in 2023 assuming a resumption of drilling. In terms of costs, operations in Georgia are particularly inexpensive, and costs are largely fixed (i.e. independent of production volumes).
We anticipate annual operating costs of c.US$3.0m, with a further c.US$1.8m of corporate G&A.

Based on our assumed oil price forecast of US$60/bbl in 2021-22, we estimate operating cash flow of around US$11m, rising above US$20m in 2022 driven by increased volumes. We have assumed that Block spends just over US$8m this year on its three new wells, which leaves around US$3m of free cash flow for the year. With Block starting the year with c.US$8m of net cash, this leaves plenty in the kitty for further development drilling through 2022.

We have built a DCF model covering Block’s assets. The licences are held under production sharing contracts (PSCs), which are very generous. Operating costs and capital costs can be recovered from 50% of licence revenue, with any unrecovered costs carried over in a cost recovery pool. Remaining ‘profit oil’ is split 50:50 between the contractor and the state, until ‘Payment Date’, which is defined as the time when cumulative revenues from Cost & Profit Oil exceed total sunk capex.

pt 5
The block contains four oil fields (Krtsanisi, Teleti, Patardzeuli and Samgori) which, combined, have produced in excess of 180 mmbbls of oil, predominantly from Middle Eocene horizons (the same horizon as Block’s West Rustavi field). Production from the fields peaked in the early 1980’s at 65,000 bopd (importantly without the benefit of horizontal wells and 3D seismic), however the collapsing Soviet Union resulted in sharp production decline (see profile in Figure 2), ultimately to negligible levels by the end of the century.

The production profile of the larger Patardzeuli field in particular clearly illustrates the impact of the Soviet Union’s demise (i.e. an unnatural decline curve). Over the past decade, only four new wells have been drilled on XIB, including Schlumberger’s 2019 deep gas appraisal well PAT-E1 The previous operator invested almost US$70m on the licence, including US$40m in calendar year 2018, predominantly on the drilling of a deep gas exploration well.

As well as the drilling of PAT-E1, Schlumberger’s investment also included significant seismic work, with comprehensive 2D and 3D seismic coverage recently reprocessed by WesternGeco. Importantly, this data, alongside the >200 well and production data, can be integrated into Block’s recently completed seismic programme at West Rustavi (which incidentally overlaps the neighbouring dataset), which should substantially improve regional understanding of the subsurface

. The level of historical investment in the permits is also expected to provide Block with a substantial, >US$130m cost recovery pool, which substantially improves returns to the contractor until these costs are recovered. Block, guided by the work of the previous owner, has identified 13 near term development targets on Block XIB, which we expect to become the company’s operational focus on completion of the West Rustavi drilling campaign.

Since these essentially serve as redevelopment of Patardzeuli, from a geological perspective they are particularly low risk, with plenty of behind pipe and infill opportunities. In addition to this low risk re-development, the deep gas potential, which originally attracted Schlumberger to the permit, has blue-sky potential.

The vertical PAT-E1 well encountered gas shows throughout the target reservoir, with an estimated discovered resource of around 600 Bcf. Schlumberger concluded however that additional work is required to establish the commerciality of the tight reservoir.

Given the higher risk/higher reward profile than the rest of Block’s portfolio, we expect the company to market the deeper gas horizon for farm out. Block will likely seek to divest a portion of its interest in return for drilling finance to fund a horizontal appraisal well on the discovery.

pt 4
In contrast to the majority of the previous wells in the area, the new wells will be drilled with substantial lateral sections. Block is planning far longer horizontal sections than its previous campaign, twice as long in some cases, which should maximise the intersection of small fractures within the reservoir, and in turn should maximise flow rates. The first well in Block’s 2021 programme (WR-BA) will be drilled on West Rustavi, in close proximity to Block’s successful WR-38Z well (see Figure 4, above).

The well will be drilled with a long horizontal section, with the planned c.1,100 metre section expected to be the longest horizontal section ever drilled in country. Water management will be key, particularly in later life, and accordingly the wells will be completed with external packers to provide water cut off capability.

The following wells in the campaign will depend somewhat on the results from WR-BA, however the likely to include JKT-1ST and WR-BB. JKT-1ST is a re-entry and sidetrack of a 2012 vertical exploration well (see Figure 4, above).

Despite its close proximity to the successful KRT-39 well (which has produced c.0.5 mmbbls to date), the vertical JKT-1 well failed to intersect sufficient levels of fracturing for flow.

With a long horizontal leg within an already proven reservoir, and the added benefit of new 3D seismic, we consider JKT-1ST to be geologically very low risk. WR-BB is situated close to Block’s successful WR-51 well, however its horizontal section will run in the opposite direction to WR-51 (see Figure 4). Block has identified a further four mature drilling targets which are likely to be added to the drilling programme in due course.

1.2BLOCK XIB (FORMER SCHLUMBERGER PERMIT)
Early last year, Block announced that it had reached an agreement with neighbour Schlumberger to acquire its two upstream licences in country, including Georgia’s most prolific licence, Block XIB. Schlumberger, a forced seller as a result of its closure of its upstream E&P business under which the assets were held (SPM), found itself marketing the asset during the peak of the first wave of the Coronavirus pandemic.

Accordingly, Block was able to acquire the assets for a hugely attractive price, with zero cash outlay and only a modest equity consideration (Schlumberger has a c.16% fully diluted equity position in Block).

Block also negotiated to include the former operator’s 30,000 bbls of crude inventory on the licence, with a market value in excess of US$1m at the time. Figure 5: Block XIB Source: Block XIB is considered the most significant block in the history of Georgian oil production.

pt3..
ASSET UPDATE AND NEAR TERM WORK PROGRAMME 1.1WEST RUSTAVI

Block’s West Rustavi field spent the bulk of 2020 shut-in, with the company taking the opportunity to install gas processing facilities while oil prices were particularly low. A 6-slot early production facility, with an expandable nameplate gas capacity of over 3 mmscf/d was installed, with wells WR-38Z and 16aZ hooked up and, since early this year producing into the grid.

The initiation of gas sales also allowed Block to reinstate oil production from the two wells. Given that the wells were shut in for the best part of a year, flow rates may take a while to stabilise.

Early indications however suggest that the two wells are performing particularly strongly at rates of 740 boepd – considerably higher than the c.300 boepd that the wells were producing at suspension. Late last year Block raised US6.5m of fresh equity for a new three well drilling campaign on West Rustavi.

The campaign is due to commence in early Q2, and will benefit from new 3D seismic, as well as the lessons learned during the last drilling campaign in 2019. To recap, the 2019 campaign yielded mixed results.

The re-entries of existing Soviet wells were cost effective, however the age of the wells and mismanagement by the original operators added risk. Well 16aZ was a case in point. Initial flow rates were highly encouraging, with flush production of over 1,000 boepd.

The wellbore however soon started producing water, which substantially inhibited oil and gas production. Well WR-38Z was more successful, flowing at a sustained rate of over 500 boepd, however the third well in the programme, WR-51, had to be abandoned due to wellbore integrity issues.

In addition to the drilling results, the subsequent 3D seismic has provided colour on the most effective drilling sites for future development wells.

The tight West Rustavi reservoir relies on natural fracturing in order to flow at commercial rates, and therefore it makes sense to target the regions which are most heavily fractured. However, should these fractures provide a conduit to the underlying groundwater, oil and gas zones could be bypassed in favour of the more mobile water (as with 16aZ).

Accordingly, Block will target the reservoir sweet spots, where fractures provide solid levels of hydrocarbon production but major faults do not provide the pathway for water production. The next wells to be drilled on West Rustavi have been selected with these factors in mind. They will be situated close to existing wells which have demonstrated moderate, but stable flow rates. This, supported by 3D data, suggests that there are not the more substantial faults

present which could cause the wells to water out prematurely.

Block EnergyOUT OF THE BLOCKS

Block Energy (BLOE LN) is a Georgian focused E&P, with a substantial portfolio of producing, redevelopment and exploration opportunities. Following last year’s acquisition of Schlumberger’s upstream assets in Georgia, Block now boasts some 66.5 mmbbls of 2P reserves across seven oil and gas fields.

Current production is in the order of c.900 boepd, however is set to increase strongly with a fully funded development drilling campaign which is due to commence in the coming weeks.

With inexpensive new development wells, workovers and infrastructure upgrades, the company sees a clear roadmap to 5,000 bopd and beyond.

Running parallel, Block plans to work up high impact appraisal opportunities, including the Lower Eocene gas play which originally attracted Schlumberger to the region.

With our 7.9p/shr target price offering 155% upside, we initiate coverage with a BUY recommendation. Upcoming multi well drilling programme:

Block expects the first of a minimum three well development drilling programme to commence in early May. Each well is drilled close to existing successful wells, and drilled based on the updated subsurface model, benefiting from new 3D seismic and drilling data.

As such the campaign, from a geological perspective, is low risk. The wells are each targeting initial rates of c.500 bopd, costing c.US$3m per well, and on an unrisked basis, are worth a combined c.11p/shr on our numbers.

Cash generative:Even without the impact of the new wells, at current production levels and commodity prices Block is strongly cash flow positive, generating in the region of US$6m/yr of free cash flow.

Each new well producing 500 boepd would add an incremental c.US$3m which, on top of existing free cash flow can be reinvested in new wells to grow production organically.

In a success case, our organic growth model estimates c.US$20m of EBITDA in 2022 rising to US$27m in 2023, with cash on the balance sheet growing above US$50m by the end of 2023.

Figure 1:
Summary financials 2021 2022 2023 Total production (boepd) 1,184 1,863 2,357 Sales (US$m) 16.0 25.2 31.9

Costs* (US$m) (4.8) (4.8) (4.8) EBITDA (US$m) 11.2 20.4 27.

1 EV/EBITDA** 1.4x (0.2x) (1.0x) Capex (US$m) (8.2) - (6.0) Free cash flow (US$m) 3.0 20.4 21.1 Net cash (debt) (US$m) 11.2 31.6 *OPEX plus G&A. **Fully diluted, at 3.1p/shr. Medium term development opportunities:

The Schlumberger acquisition added a host of brownfield redevelopment opportunities. As Figure 2 shows below, the assets were delivering over 70,000 bopd predominantly from the Samgori and Partardzeuli fields before the Soviet Union collapsed, prompting an abrupt decline in production levels.

identified a host of redevelopment opportunities, in particular on the Patardzeuli field, which on full redevelopment could sustain substantial levels of production. Figure 2: Samgori and Patardzeuli field production profile

pt1

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