Wentworth’s Gas Payment Security Agreement Gives Tanzania’s Gas Sector Players a Huge Boost

Players in Tanzania’s gas market that are relying on sales of gas to domestic customers through the Mnazi Bay-Dar es Salaam gas pipeline, received a huge boost last week when Wentworth (OSE: WRL) and AIM (AIM: WRL) announced they has secured a payment security agreement with Tanzania’s Petroleum Development Corporation (TPDC) enabling the company to make its first gas delivery from its Mnazi Bay gas project, a joint venture production sharing contract which also includes Maurel and Prom and TPDC.

As I have reported on in the past, the difficulty with securing gas sales agreements in Africa for sales of gas where the end customer is a domestic one, has always been the securing of a suitable financial guarantee. African utilities in particular have challenges when it comes to credit control. Let’s put it this way, it’s very difficult to collect cash from some customers.

On September 12, 2014, Wentworth and the Mnazi Bay partners signed a gas sales agreement with the Tanzanian government to deliver up to 130mmcf/day of natural gas from the Mnazi Bay concession, however, the agreement still required a financial guarantee.

Under the terms of the gas sales agreement, the sale price of the gas has been set at US$3.00 per million BTU, or around US$3.07 per thousand cubic feet, rising in line with the US CPI industrial index. The Partners have agreed payment security terms with TPDC, the buyer of the gas, and various other parties. Accordingly, the sales of natural gas will be settled in accordance with the agreed payment terms.

From my experience I think the agreement with involve typically a three month rolling letter of credit and probably some form of upfront payment, probably also three months. It is unlikely the World Bank would have supported TPDC with a Partial Risk Guarantee (PRG) and or a Multilateral Investment Guarantee Agency (MIGA), but I might be wrong,

Shares in Wentworth are up 13% today and the other two AIM players that will receive a huge value catalyst from this news are the two other Tanzania London listed Tanzania gas players who have a similar JV turn on gas project ready to go at Kiliwani North are AMINEX  (AEX) shares up 9% today and Solo Oil (SOLO) whose shares are also up 9%

I would expect AMINEX to secure its GSA for Kiliwani quite soon and this would mean a significant re-rating of its stock and that of Solo Oil, who can excerise an additional 6.5% stake in Kiliwani on the GSA being signed. At 13% (78,000 MMBtu per month) Solo would generate over $200,000 of free cash flow per month.

Tanzania Gas Sales Agreement Will Re-Rate AMINEX & SOLO

It’s hotting up in Tanzania for AMINEX and Solo Oil. The recent placing by AMINEX where they have raised £1.67m, provides some indication that investors believe the company will be successful in securing favorable terms for the Kiliwani North Gas Sales Agreement. Both AMINEX and SOLO will become cash generating companies this year when the gas sales agreement for Kiliwani can be secured. The pre-requisite infrastructure is in place.

It is in everyone’s interests for this agreement to be signed quickly. Tanzania needs the gas, its economy is booming, GDP growth is expected to be circa 7% in 2015. Only last week the World Bank Group, approved a $100 finance package to help Tanzania increase transparency and accountability in governance and improve public financial management, this is important intervention.

AMINEX will be looking to finalise the Kiliwani gas sales agreement that follows international oil and gas industry standards, sounds obvious, but these agreements can be complex and require the support and guarantees of external international financing agencies.

The last gas sales agreement I can recall being struck in Tanzania that is representative of the type of contract AMINEX will need was the Mnazi Bay GSA secured in September 2014 by Wentworth (OSE: WRL) & (AIM: WRL).

The Mnazi Bay GSA covers a 17 year term with net back price of gas agreed at US$3.00/MMBtu for the discovered gas and is non Brent linked. The Tanzania

government is responsible for transportation and processing costs. Importantly it is an 85% take or pay deal, however, as of yet I understand the financial guarantees have not yet been signed.

This is always a sticking point with these type of gas sales agreements for some Africa countries where the end customer is essentially the domestic market.

Yes the main utility customer of the gas such as Pan African/TPDC which is piloting bottling distributing natural gas in Tanzania will be credit worthy, however, they will need to secure reserve bank support, ie from the Bank of Tanzania, who in turn will need to secure international financial support, so the guarantees within these gas sales agreements are syndicated. But remember, the World Bank and a host of other international financial agencies are very active in Tanzania, which is why last weeks news of World Bank support for Tanzania is timely.

We have seen some evidence of the complexities involving gas sales agreements, particularly in Namibia with the Kudu gas project. The question was always Nampower, the parastatal power utility, and its ability to guarantee to take the Kudu gas production at a price that could support the economics to finance the gas to power project. Encouragingly the Kudu Gas GSA was signed in 2014 and has paved the way for Kudu to begin producing in 2017.

Credit risk is the reason why this is interesting. In Namibia for example Nampower sell their electricity to regional electricity distribution companies, (REDS) who in turn are responsible for collecting the revenue from their local domestic and business customers. Credit control and cash collection can be challenging, and often Nampower can suffer as a result. In Tanzania, TANESCO is the electricity utility and operates a vertically integrated a system that removes some of the risks Namibia has where Nampower is exposed to the ability of its REDS to collect cash.

The REDS in Namibia tend to be lenient and are not fond of cutting off electricity and Nampower is exposed to this more tactile system of cash collection. Customers of TANESCO, I think will not be treated so kindly, and I think the international funding partners understand that and so I think at least the credit risk in Tanzania is lower than other African countries. Given Shell’s recent purchase of British Gas Group who now join a raft of international oil and gas companies operating in Tanzania, the pressure to finalise a structure for gas sales agreements is clear.

On the demand side, Tanzania currently has five gas fired power stations, Ubungo I, Ubungo II, Tegeta, Mtwara and Songas. Coming on stream are Kinyerezi II Thermal Power Station (240MW) 2015, Mnazi Bay Gas Plant (300MW) 2016 and Kinyerezi III Gas Plant (300MW) 2016.  The demand for electricity in Tanzania is clear and so is the domestic demand for gas. These developments are helping lower credit risk.

The recent decision by the World Bank to support Tanzania in terms of the strengthening its financial management is saying to me that the syndication of international financial risk to support GSA’s is underway.

I would expect AMINEX to secure its GSA for Kiliwani quite soon and this would mean a significant re-rating of its stock and that of Solo Oil, who can excerise an additional 6.5% stake in Kiliwani on the GSA being signed.

Currently we are in perfect investment horizon for both of these stocks.

Schlumberger Report on Horse Hill Weald Basin

The news out this morning by UKOG is breathtaking. There is no other word to describe Horse Hill. This is Schlumberger we are talking about.

Schlumberger estimates an overall Oil in Place ("OIP") for the Jurassic section of the Horse Hill to be 271.4 million barrels of oil ("MMBO") per square mile. (NUTECH said there was 158 million) The total OIP comprises 16.2 MMBO per square mile for the conventional Upper Portland Sand reservoir discovery and 255.2 MMBO per square mile solely for the tight limestone and mudstone plays of the Kimmeridge, Oxford Clay and Lias. The OIP hydrocarbon volumes estimated should not be construed as recoverable resources or reserves.

Let’s remind ourselves of the facts.

It was a very simple deal, a consortia of oil company investors “Horse Hill Developments Ltd” including Angus Energy Ltd, Alba Minerals, Solo Oil Plc Doriemus Plc, Stellar Resources Plc, Magellan Petroleum Corporation, UK Oil & Gas Investments Plc came together to finance the drilling of a well in the Weald Basin…………WHY?

Because there was a pretty good chance oil was contained in the Weald Basin, simple as that.

Exploration began as far back as 1930 when a number of wells were drilled and where in 1964 oil was discovered when the Collendean Farm1 well was drilled.

The respected academics, Butler and Pullan published a paper in 1990 that provided pretty robust academic research on the Weald Basin that detailed the reservoir rock structures, detailed the seals, traps, generation, timing and migration of the Weald Basin oil play………..yes there was a fair chance oil was in the Weald Basin.

Remember, when drilling was done in the 1960’s there was no Windows software, there was no high powered geological, geophysical software available…….what did anyone know about tight oil or low permeability tight sandstone rock bearing oil back then………….not a lot?

But there was enough data to encourage Magellan to commission their own geological study on the Weald Basin with their consultants ENVOI. Let’s face it, conventional tight oil extraction was now commonplace in the US, Magellan, god bless them could see the potential in the Weald and so could others.

So the Horse Hill consortia came together, and it needed a leader, someone that could raise money, but also someone who could but a decent petroleum geological and geophysical team together to drill the Weald Basin.

But for the first time, drill it deep enough to access all of the main rock structures. The well would need to be drilled to over 8,500 feet, but just as importantly, the open hole electric logging would need to be undertaken properly.

David Lenigas, had rescued a failing AIM shell company and formed UKOG, with a simple idea to drill for conventional oil, UK onshore. No stranger to the oil business, Dave was founder of AIM listed Lenigas and Oil, (LGO Energy) and someone who had hands on and current experience in drilling for oil onshore. He stepped up, helped mobilise the consortia and raise the money to drill Horse Hill, it was as simple as that.

On the 3^rd September 2014, Horse Hill 1 was spudded.

This is when the game changed.

It really is pretty much after this point that the game changes when it comes to AIM rules for oil and gas companies and reporting of reserves and resources.

To its credit UKOG said, “OK we have drilled this well, lets get a competent person (CP), an external expert in tight oil plays to serve as an independent assessor that can tell the Horse Hill consortia what the results of the Horse Hill well actually are.”

That independent assessor was NUTECH, one of the world's leading companies in petrophysical analysis and reservoir Intelligence, who were appointed by UKOG on the 30th January 2015 to assess the Horse Hill 1 well data.

Now the significance of the appointment of NUTECH was not, in my view, properly picked up on by the press. I will come to that later and why today’s announcement is so important in that respect.

On the 9th of April, shares in UKOG surcharged at one point by 400% on the news that NUTECH, remember the independent CP, had provided the Horse Hill consortia with their assessment of the Horse Hill-1 well.

Horse Hill-1 had a total oil in place ("OIP") of 158 million barrels ("MMBO") per square mile, excluding the previously reported Upper Portland Sandstone oil discovery.

This led to huge media coverage and where some commentators who clearly did not have a clue about AIM rules on reporting, served to dish out what was clearly unjustified criticism of UKOG and the Horse Hill project without, in my view proper understanding of the way in which AIM works when it comes to the independent reporting of reserves and resources.

Now remember, NUTECH has their own reputation to consider. They are not in the business of misreporting, they have nothing to gain by that, there is no moral hazard here.

They just report what they see given their own extensive access to data and importantly up to date field knowledge of tight oil plays from their own extensive experience of working in the US Bakken oil formation.  No commentator ever gave any credit to NUTECH or indeed UKOG for hiring one of the best petroleum geoscience companies around. UKOG also hired Xodus Group, another highly respected team of petroleum geoscientists to report independently on the oil in place volumes contained within the Horse Hill conventional Portland Sandstones, again, I do not think enough credit was given to UKOG for that appointment either.

With criticism lingering, what did Dave Lenigas and UKOG do next? They approached Schlumberger, the world’s leading independent petroleum industry experts that specialise in providing governments, yes governments and the world’s major international oil companies with services such as seismic data processing, formation evaluation and petrophysical evaluations.

So now will the market give UKOG any credit for hiring Schlumberger?

Well if it doesn’t then we should all turn the lights off and go home.

The news today is so incredible on many levels.

For UKOG, by any standards a minnow oil company, to have secured the services of Schlumberger is in itself pretty incredible, but for Schlumberger to have allowed UKOG to released today’s Petrophysical Evaluation on Horse Hill is even more impressive.

What Dave Lenigas has said by hiring Schlumberger to conduct their independent assessment of Horse Hill, is,,,,,,,,,

“Look, I am highly confident of the technical reservoir assessment work undertaken by NUTECH and Xodus on Horse Hill, but it would be nice to get another opinion and I we would like Schlumberger to do that, not because we have any issue with NUTECH and Xodus but because of the magnitude of what we have here. This is potentially a major oil system, that has huge consequences for the British government and that they must take Horse Hill and the Weald Basin seriously and that the oil play itself is so interesting that it warrants investigation by Schlumberger’s Unconventional Resource Group and because Schlumberger is such a highly respected oil and gas petroleum geoscience company, and the Weald Basin-Horse Hill discovery is such an extremely interesting oil system, this combination justifies the highest level of professional attention and intervention by an expert such as Schlumberger.”

Summary

Later today I will write up an assessment of the Schlumberger report and what it means. But for now, anyone who is considering shorting UKOG and indeed any of the Horse Hill consortia, please think again, you would have to be certifiably insane to do so.

If Andy Samuel the CEO of OGA is reading this, then Andy, please pick up the phone to Dave Lenigas and open up a discussion…….. a proper discussion about the Weald Basin,,,,,,,,,,,,,he has bowled you a googly and you should work out how to play it.

Further, NUTECH this morning must feel vindicated in their early assessment of Horse Hill now that even Schlumberger confirm the volumes, which they say are even bigger!!!!!!!

And for those reporters that might want to have a go at Dave Lenigas, just have a think. This is an entrepreneur, someone that has got stuck in and made something happen, it is businessmen like this that have made Britain great and we need more of them and we need to encourage them and support them if we are to succeed as a nation.

The Weald Basin has the potential to generate billions of pounds of tax revenue to help fund schools, hospitals, create jobs and provide the UK with much needed energy security. We should remember that and we should also remember that this is a conventional oil play, a tight oil horizontal well recovery system technique to enable oil production, its not fracking.

The Weald Basin needs the support of the community, enabling its development could unlock huge wealth for the country and help fund many great positive environmental projects across our great land.

Andre Brand

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.