Royal Dutch Shell & BG Group Kick off the Oil & Gas Mergers & Acquisitions Mega Season. Why Tanzania was so important in this deal and what could it mean for the massive Ruvuma onshore gas field & Solo Oil

“If you base the TCF valuation on the same benchmark as the Ophir-Pavilion deal where Pavilion paid $353 million per TCF for its 20% stake in Tanzania’s offshore blocks 1,3,4, then Ruvuma would be valued on an un-risked basis (1.17tcf) at $413 million minimum but on 2.3 tcf (AMINEX resource estimate for Ruvuma) of $811 million. Solo own 25% of the Ruvuma PSA. Accordingly the value attributable to Solo could be anywhere between $100 million to $200 million, and remember the Ntorya well in the Ruvuma PSA has pipeline infrastructure nearby and is an advanced project that can get into production very quickly.”

When BG Group announced in August 2014 that it had produced higher than expected flows of gas from their Mzia-3 test well off the southern part of Tanzania's coast, it was news that must have caught the eye of Royal Dutch Shell.

Mzia-3 was not only producing better than expected results, but it was reaching a flow rate of 101 million cubic feet per day, nearly double the flow rate measured at their Mzia-2 well that had test flowed a year earlier.

The impressive flow rates served to boost the financial viability of BG Groups planned Tanzanian LNG terminal and associated upstream production facilities and infrastructure, a factor that must have also interested Shell.

Shell’s decision to buy BG Group was one that focused on long-term asset building. It has enabled the company to get access to BG Groups significant advanced exploration portfolio. BG Group had sunk huge capital into the ground. This is where Shell clearly saw the long-term value in this mega deal.

However, we feel it is access to Tanzania that featured as a major factor in the purchase of BG Group, given Shell ended a £1.12bn cash offer for Cove Energy back in 2012 which was designed to give the company a foothold in east Africa’s gas sector, that attempt sadly failed.

Shell’s major African continent gas projects are located primarily in west Africa, not ideal in terms of shipping logistics to the Asia market. Shell were fully aware of the gas potential in Tanzania. In 2002, the company won a Tanzania Petroleum Development Corporation tender for four offshore blocks around Zanzibar island, but the deal got blocked by the Tanzania government. Shell holds at least four exploration licenses off Zanzibar and is working with Petroleo Brasileiro SA on two off Tanzania. But it is the legal process of essentially two jurisdictions, Zanzibar and Tanzania that has served to hold up Shell’s progress offshore. The deal with BG Group, essentially fast tracks the company’s foothold into Tanzania, which is set to become a huge future supplier of gas to Asia.

BG Group entered Tanzania in 2010 and is the operator of offshore Blocks 1, 3 and 4 in which it has a 60% interest. Around 15 tcf of total gross resource has been discovered and work is progressing to develop a joint LNG plant in collaboration with the Block 2 partners. Mzia was confirmed as second giant gas discovery, after Jodari, other highlights include

·      Taachui gas discovery secured in Block 1

·      LNG site MoU signed with the government

·      HoA signed with Block 2 partners: BG Group is lead developer for pre-FEED

·      Contracts for upstream and LNG plant pre-FEED have already been awarded.

Putting this into context

Why Ruvuma must now be a major acquisition interest.

Back in November 2013, Ophir Energy (LSE:OPHR) announced the sale of 20% interest in Tanzania blocks 1, 3 and 4 to Pavilion Energy for a staggering $1,288 million. The transaction with Pavilion a wholly owned subsidiary of Temasek, the Singapore investment company, served as one of the most important pricing benchmarks for Tanzania’s hydrocarbon sector.

With the most recent gas discovery on the Kamba-1 well in Block 4, the total discovered gross 2C resource to date is estimated at 17.1TCF across the three blocks, which is enough to underpin a two train LNG development.

So essentially Pavilion paid $1.2 billion USD for 3.4 TCF or $353 million per TCF

It was also a deal that showed the strategic importance Asia investors are placing on Tanzania in respect of its huge gas export potential.  Given that the season for mega deals is now underway and why Tanzania is featuring at the centre stage of mega deal making once again, I think it is time to remind investors about Tanzania’s massive Ruvuma gas field.

The Ruvuma PSA originally covered 12,360 square kilometres in the extreme south-east of Tanzania of which roughly 80% is onshore and 20% offshore. This is a licence development area that was awarded back in 2005. Ten years of work has been undertaken on Ruvuma.

Within the PSA are two specific, adjoining licence areas, known as Lindi and Mtwara. Following the first exploration period and an extension about 75% of the area was relinquished and the remaining PSA covers 3,447 square kilometres. Prior to the award of the current PSA 1153 kilometres of 2D seismic had been acquired in the area of the PSC between 1981 and 2002. No wells had been drilling within the boundaries of the PSA, but a well at Lukeledi-1 to the north had been drilled by Texaco in 1992 and the Mnazi Bay-1 well to the southeast had been drilled by Agip in 1982. Following award of the PSA Ndovu Resources, a subsidiary of Aminex, acquired 370 kilometres of offshore seismic in the Lindi Block and a further 430 kilometres of 2D seismic onshore in the Lindi and Mtwara Blocks.

The first well under the Ruvuma PSA was drilled in 2010 on the Likonde prospect. Likonde-1 is located in the Lindi Block and encountered thick sands with hydrocarbon shows. The well was drilled to a total depth of 3,647 metres and results of drilling, wireline logs and side-wall coring showed that the well intersected two sandstone intervals of over 250 metres (820 feet) combined thickness with evidence of residual oil and gas. Drilling had to be terminated in the deepest objectives due to the high rate influx of gas.

Based on the encouraging results of the Likonde-1 well the available 2D seismic was reprocessed and reinterpreted to select the location for a second exploration well, within the Mtwara Block. The chosen location, Ntorya-1, was intended to target the updip extent of the sands encountered in the Likonde-1 well.

On the 6 October 2011, prior to the drilling of Ntoya-1, Solo announced that it has increased its stake in the Ruvuma Basin PSA from 12.5% to 18.75% by assuming the additional obligations associated with the additional interest relinquished by Tullow Oil who reduced their over holding from 50 to 25%.

Ntorya-1 was spudded on the 22 December 2011 and intersected a gross 25 metre section of Mid-Cretaceous sandstones with gas. The upper 3.5 metres of the gas bearing zone were tested at a maximum rate of 20.1 mmscfd with 139 barrels oil per day of 53 deg API condensate through a 1” choke. The flow rate was considered to be of potential commercial interest and well has been suspended.

After intersecting the primary target, but prior to deepening to the eventual discovery level in the Ntorya-1 well Tullow Oil elected to transfer their remaining 25% interest to the partners, Ndovu and Solo in proportion to their existing interests in return for the assignees accepting future obligations in the second exploration period. As a result Solo increased its interest in the Ntorya-1 discovery and the Ruvuma Basin PSA to 25%.

A resource report has been prepared by ISIS Petroleum Consultants that attributes 5.75 tcf of potential gas-in-place resources to the Ruvuma PSA. ISIS calculates that Ntorya holds mean 1.17 tcf of unrisked gas in place of which 178 bcf are considered discovered, but recently increased its internal resources estimate of Ruvuma to 2.3 tcf.

“If you base the TCF valuation on the same benchmark as the Ophir-Pavilion deal where Pavilion paid $353 million per TCF for its 20% stake in Tanzania’s offshore blocks 1,3,4, then Ruvuma would be valued on an un-risked basis (1.17tcf) at $413 million minimum but on 2.3 tcf (AMINEX resource estimate for Ruvuma) of $811 million. Solo own 25% of the Ruvuma PSA. Accordingly the value attributable to Solo could be anywhere between $100 million to $200 million, and remember the Ntorya well in the Ruvuma PSA has pipeline infrastructure nearby and is an advanced project that can get into production very quickly.”

The Ntorya-1 discovery is now the subject to an application for an appraisal extension to the licence to carry out a two-year program of additional infill seismic and a further well. Elsewhere in the PSA an additional seismic program and two additional exploration wells are planned to follow-up the success of the first two wells. It is anticipated that a farm-in partner will be found to take up to a 50% interest in return for a substantial financial contribution to the remaining work program.

Essentially Ruvuma’s gas reserves equate to approximately 30% of BG Group’s stated Tanzania gas asset reserves. For Asia investors that want access to near term lower risk onshore gas production, then snapping up Ruvuma would be a very wise move.

Solo’s shares shot up last week on the back of the major oil reserve upgrade by the Horse Hill Development consortia, where they own 6.5% interest in the Horse Hill-1 well.

But we suspect the biggest value catalyst for Solo after their Kiliwani well enters production this year, will be Ruvuma. Watch this space.

Royal Dutch Shell Deal with BG Group: Portfolio Re-Balancing Now Underway

Royal Dutch Shell announced today that an agreement had been reached with BG Group that will see the company purchase BG Group in a deal that values the business at £47bn.
The  cash and shares offer which gives investors a 50% premium on BG Group's share price on 7 April.


So here is the deal. You are an international oil and gas company, operating in a market that is seeing the prices for your hydrocarbon commodities becoming increasingly depressed and priced at levels seen back in 2004. Yet your cost base has risen steeply in the last ten years. Your reaction to these low oil and gas prices is to make redundancies and cut exploration costs. Ideally you want to re-balance your portfolio, get access to lower cost onshore oil and gas production and hopefully ride the storm until the price of oil and gas heads north. But you also want more access to gas, the commodity that is not so aligned to automotive sector demand, where a revolution is underway, vehicles are becoming much more fuel efficient, electric vehicles and hybrids are now becoming commonplace, Cars in general are lighter, more fuel efficient, and so are heavy goods vehicles.

Gas demand is related to power, domestic cooking, Asia needs lots more gas, coal fired power stations are bing replaced by cleaner gas fired power stations, the gas market is more interesting longer term. 

What Royal Dutch Shell and BG Group have collectively decided to do is to shape their future together, it is a reaction to the current market conditions that has prompted this deal.

For Royal Dutch Shell's shareholders, they get access BG's diverse global production portfolio which includes some fantastic world-class gas assets particularly in markets that are gearing up to supply Asia and in lower cost operating jurisdictions such as Africa's Qatar i.e. Tanzania
Shell get access to Tanzania's offshore Blocks 1, 3 and 4 and around 15 tcf of total gross gas resource, where BG have a 60% interest. It also gives Shell a massive foothold in Australia's gas market where BG Group is developing a two-train 8.5 mtpa LNG plant supplied by coal seam gas (CSG). The Queensland Curtis LNG (QCLNG) plant is being built on a 270 hectare site on Curtis Island, Gladstone, on the Queensland coast. 
BG Group’s business in Australia comprises: Licences in four onshore areas of producing and potential gas supply covering a total of around 33 000 square kilometres. 

The project’s total reserves and resources at the end of 2013 were 22 tcf (net BG Group): Surat Basin CSG play: producing gas for the domestic market and will provide production into the LNG plant; Bowen Basin CSG play: exploration and appraisal ongoing; Bowen Basin tight gas sand play: exploration and appraisal ongoing; Cooper Basin tight gas sand and shale gas plays: exploration and appraisal ongoing; A 540 kilometre pipeline network comprising a 200 kilometre gas collection header and a 340 kilometre export pipeline; Major shareholdings in the two-train liquefaction facility, including 100% equity in common facilities such as the LNG storage tanks and jetty; and The 140 megawatt Condamine power station.

Shorting LGO Energy From Today’s News... It’s a Very Bad Idea...... Remember What Happened in May 2014

Shorting LGO Energy

From Today’s News It’s a Very Bad Idea

Remember What Happened in May 2014

But This Time LGO Energy is De Risked & Potential Takeover Target

Back on the 20^th May 2014 I wrote an article that shed some light on the shorting of oil and gas equities by using CFD’s. I made a point about the market cap threshold of £10 million and highlighted some points about the strategy in shorting oil and gas equities. I chose to analyse the case of Leni Gas & Oil (Now LGO Energy). I commented at that time that shorting LGO was a particularly bad idea, given the headwind of future news flow that was pent up in the company as a result of the commencement of the re-development of the Goudron oil field in Trinidad.

I was highly confident that LGO’s Goudron field would deliver positive results for LGO. My assessment was based on the proven geology and oil-bearing qualities of Goudron, it was as simple as that. LGO went on to produce some amazing results from the first seven wells.

On the 20^th May 2014 when I released the article, LGO’s shares closed at 1.08p. since that date the shares have never traded lower. As predicted, just like the positive news flow, there was positive oil flow.

Today LGO Energy released details of the planned 2015 Goudron development program where the first drawdown of funds from a US$25 million oil swap finance facility provided by BNP Paribas.

Like back in May 2014, I am predicting that shorting LGO Energy from today is again a bad idea. I base this view again on the fact that I am confident, like before that Goudron will again throw up some great results from this latest program. But this time its different, LGO Energy have behind them a significant oil production flow that is coming in from “Goudron Phase 1”. The flow rates of Goudron’s wells have been properly managed by LGO Energy to prevent flow rates from dropping off from the initial production flow.

There are a number of factors that will serve to seriously hurt shorters of LGO in 2015.

Potential Takeover Target: LGO Energy is de-risked, what I mean by that, is that LGO is an infrastructure supported sustainable producer of oil from the Goudron field, where the petroleum geological system is properly understood and reserves internationally classified and verified. Financing for development is in place.

For an oil company looking to add production inventory to its portfolio, particularly a US company, then investing in Trinidad and LGO’s proven production, would be a no brainer, particularly given the production upside and also the low onshore production costs. At the moment there are a number of oil companies that are looking to re-balance production away from costly offshore production to more lower cost onshore production. We can see that happening today in the UK North Sea market.

Newsflow:  Combined with potential suitors for LGO, which I suspect will begin to emerge this year, will be the news flow and it will be considerable. AIM stocks thrive on news flow. Under AIM reporting rules, the major activities surrounding well development from Goudron will have to be reported. From mobilization of rigs, movement of drill pads, drilling, spudding, flow rates etc, all activities that will contribute to deliver positive news flow, from a raft of wells that will be developed at Goudron in 2015. Neil Ritson has a very strong track record of transparent reporting of operational activities and they will be abundant in 2015 for LGO.

Financials: LGO Energy are paid to manage Goudron no matter what the oil price is, but the cost per barrel of production for these low cost onshore wells is sub circa $40 per barrel. So here is the deal. In May 2014, the price of Brent Crude was circa $105 per barrel, however by August 2014 LGO had begun producing oil from the first six wells of its phase 1 Goudron program where the oil sold would have been at a profitable margin.

It was not until November 2014 that the oil price had dropped to $80 a barrel.  I would estimate that LGO Energy enjoyed net oil price revenues of around $90 a barrel from production flowing from the first six wells of the phase 1 Goudron program. And so for the reporting period to December 2014, I would estimate LGO Energy will produce some pretty good financial results. Some evidence of this can be seen in the unaudited Interim results to the 30th June 2014

Revenue for period increased by 40%, to £3,230,000 (1H 2013 £2,308,000).

Gross profit for period increased by over 150% to £797,000 (1H 2013 £310,000). Pre-tax group loss for period of £2,489,000 (1H 2013 loss of £1,389,000).

Pre-tax group loss excluding exceptional legal costs, for the period was £1,242,000 (£1,304,000 in 1H 2013)

Summary

It would be really silly to short LGO Energy at the moment in the same way it was back in May 2014. I would expect a stream of really positive production and financial news flows over the course of 2015 that will catch out shorters in a very big way. Clearly BNP Paribas, who would have done considerable due diligence on LGO as part of the process of arranging the recent financing package for Goudron, like what they see in both the company and Goudron. Experience suggests going long on LGO from today may not be such a bad idea.

Cashflow Earnings from the Kiliwani North Gas KN-1 Well, Will Be A Major Value Catalyst for Solo Oil & Gas

Solo Oil plc (AIM:SOLO)

Patience Will Pay Off & Soon

Why the completed gas pipeline from the Songo Songo processing plant to the Kiliwani North Gas KN-1 well is such a significant value catalyst

Songo Songo Island sits 15 kilometres from Tanzania’s mainland. Gas was first discovered there in 1974 by the Italian oil company AGIP (now ENI). It took thirty years of huge investment by the government of Tanzania and its international financing partners including the World Bank, to help get the hydrocarbon processing, pipeline infrastructure, processing and power plant in place that laid the foundations to enable commercial gas production to start flowing in 2004 and served as a major catalyst in attracting a raft of international oil and gas companies to Tanzania.

Investment in Tanzania’s hydrocarbon processing and transportation infrastructure still continues to take place and at pace. The Chinese have recently completed the construction of a gas pipeline from Mtwara to Dar es Salaam, which will enable gas from the Mnazi Bay production area to be transported up to Dar es Salaam and where the large Ruvuma discoveries can now be monetised, given that the 36” diameter pipeline runs right through the onshore Ruvuma and Mtwara oil and gas fields.

This is good news for Solo Oil (AIM:SOLO) and AMINEX (LSE:AEX) who are the two partners in onshore Ruvuma and where the completed gas pipeline runs just 20 kilometres from the Ntorya-1 discovery well.  Ruvuma is the “BIG ONE” and it is just a matter of time to when the massive value of Ruvuma, with over 100 TCF in offshore discoveries to date, is unlocked.

But it is back on Songo Songo Island where Solo and AMINEX will begin to reap the rewards of over forty years of massive infrastructure investments by the government of Tanzania and its international financial partners. In just a matter of weeks, approximately 20 million cubic feet of gas per day will start flowing from the Kiliwani North KN-1 well to the Songo Songo gas processing plant. This is a facility that has a capacity to process between 1.98 MMcm/d (70 MMcf/d) and 2.97 MMcm/d (105 MMcf/d)

Gas from the KN-1 well, following processing, will flow through a 12 inch pipeline that runs 25 km (15 miles) from Songo Songo Island to the Somangafungu onshore processing facility where it is then transported another 207 km (129 miles) by a 36 inch pipeline to the Ubongu power plant in the Tanzanian capital, Dar es Salaam.

London listed AMINEX is the operator of the Kiliwani KN-1 well, Solo has a 6.5% interest but with an option to increase that interest by a further 6.5% to 13%.

For Solo, the company will initially be earning cash flow from sales of 39,000 MMBtu per month (39 million cubic feet of gas per month as part of their 6.5% stake) at a NYMEX price of 2.73$ MMBtu this would give Solo free cash flow of circa $106,470 per month. Should Solo exercise their option to increase their stake in Kiliwani to 13% (78,000 MMBtu per month) then this figure would double to $212,940 per month.

Solo will make the transition from explorer to producer in a matter of weeks and where these cash flows will have an immediate impact on the valuation of the company. For example if the option to increase their stake in Kiliwani is exercised by Solo, the cash flow earnings in the first year would increase the valuation of the company by at least 5.8% taking the market capitalisation to a figure closer to £32 million.

Clearly the markets are negative at the moment on oil and gas equities, but like the infrastructure in Tanzania, Solo and indeed AMINEX are as safe a bet as you can get. The current share price of Solo and AMINEX does not fully reflect the impending value increase from Kiliwani’s earnings and indeed the massive value of Ruvuma which like those early investors in Songo Songo, will at some point deliver alpha returns and where patience will eventually pay off.

Leni Gas & Oil, Latest Map Reveals Size & Scale of the Goudron Field & Trinidad Operations

Leni Gas & Oil, (LGO:AIM) the Trinidad focused oil company, today published a new map of their Trinidad operations. The map reveals the locations of the first five wells, spud as part of the 30 well redevelopment program plus the details of the locations of future wells that will be spud on the Goudron field.

In addition there is also a 3D diagram of the Gros Morne reservoir illustrating the pay zones in the Gros Morne and Lower Cruse structures.

The location of the Icacos oilfield and Trinity Innis oilfield are also shown. Leni Gas & Oil has an option to acquire 100% of Trinity Innis, which was announced to the market on the 16^th July 2014. Trinity Innis is a producing oilfield where production averages between 140-150 barrels of oil per day ("bopd") from approximately 25 active wells.

What is striking about this map is the size and scale of the Goudron acreage which is 3.5 kilometres by 2.5 kilometres 

It is a huge area that has massive production upside. It is clear from the map that Texaco did not really venture properly into the Goudron field as there are huge areas of unexplored acreage that clearly has the potential to be drilled.

The other really important point is that if LGO secure the option over Trinity Innis they will get game changing production output and almost certainly like Goudron have a field that has the potential for further exploration.

I think this map is a really great illustration 

Horse Hill Now Drilling. My guess is that this is now a major oil play

Drilling commences at Horse Hill

I have no doubt there is Oil and Gas in the Weald Basin. 

The geology is well known. All the ingredients are in place. Source Rock, Reservoir Rock, Seals, Traps and Maturation. Initially my assessment of Horse Hill led me to think this was a gas play, however after evaluation, I suspect the Kimmeridge clays are probably a major oil source.

This has to be one of the most exciting onshore exploration adventures for many years. There is a good technical team on the drill site. The Weald Basin is well known geologically and Horse Hill is not really an exploration story as such, its more of an evaluation story. The value in the Horse Hill well and for investors will be the technical outcomes. The contact data will be really useful.

If gas is found in the Weald Basin it must be sourced from either the older Triassic or deeper Palaeozoic strata and not the Liassic shales, which is the source for the oils. Horse Hill are at least targeting the correct structure (Triassic) Its pretty exciting and a very considered drill program from a technical perspective.

The Horse Hill-1 well is planned to be drilled to a Total Depth ("TD") of 2,646 metres (8,680 feet) and is designed to test for a number of conventional stacked oil targets in the Jurassic, as well as a deeper conventional gas target in the Triassic.

The operator, Horse Hill Developments Ltd ("HHDL"), is a special purpose company with a 65% operating interest in the PEDL 137 license in the Weald Basin to the north of Gatwick Airport in Surrey. UKOG has binding agreements in place to own a direct 20% interest in HHDL and an additional 2.4% interest by virtue of its 6% ownership in Angus Energy Limited ("Angus Energy"). Angus Energy owns 40% of HHDL.

The participants in the Horse Hill Prospect are HHDL (65%) and Magellan Petroleum Corporation (35%).

David Lenigas, the Company's Chairman, commented:

"This is an exciting time for UKOG as we embark on this well that will not only test a number of conventional oil formations, but will be one of the first wells drilled in this part of the Weald Basin to test for the potential for conventional gas in the deeper Triassic formations."

About Horse Hill:

The 99.29 km² (24,525 acre) Horse Hill Petroleum Exploration and Development Licence No. 137 (PEDL 137) ("Horse Hill") is located in Surrey, a few miles from Gatwick Airport.

The Horse Hill Prospect OOIP and OGIP and prospective resources, as announced by UKOG on 20 December 2013, are summarised in Table 1.

Table 1: Horse Hill Prospect estimated OOIP, OGIP and Prospective Resources.

Target Reservoir Oil	OOIP Upside Potential (MMSTB)	OOIP Mean (MMSTB)	Prospective Resources Mean (MMSTB )
Upper Portland Sandstone	116	57	17
Lower Portland Sandstone	284	147	44
Corallian Sandstone	67	33	10
Greater Oolite Limestone	204	104	16
Total Oil	671	341	87
Target Reservoir Gas	OGIP Upside Potential (Bcf)	OGIP Mean (Bcf)	Prospective Resources Mean (Bcf)
Triassic Sandstone	456	234	164