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November 18, 2015

by AEA

Assessing the performance of natural bitumen from Albania

The market for high modulus asphalt mixes has become very competitive in recent years, most notably in the segment for bitumen additives. Written by Edith Tartari, MSc Eng, electronics engineer with Selenice Bitumi in Albania.

The exploitation of natural asphalts as additives to modify the asphalt binders represents a growing challenge, especially in this moment when there is increasing demand for a more rational use of fossil fuels compatible with protection of the environment, ecosystems and the quality of human life.

Natural asphalts may represent a useful and economic alternative to the polymeric materials and other traditionally used modifiers of distillation bitumen, increasing the binder consistence, viscosity and stability. Their use allows superior performing asphalt pavements with higher values of stiffness and greater resistance to rutting and fatigue.

THE CHARACTER OF NATURAL BITUMEN

Research work was conducted by the University of Rome ‘’La Sapienza” on the characterisation of natural asphalts and their evaluation as modifiers, using rheological and thermal techniques. For the study, three of the most commonly used types of natural asphalt were selected: Gilsonite from Utah deposit (United States), Selenizza (Albania) and Trinidad Lake Asphalt (Central America).

To investigate the nature of the modification, 10% (in weight) of each natural asphalts was added to a standard penetration grade bitumen 80–100 and mixed at a minimum temperature of 150–180°C in order to guarantee the complete solubility.

Rheological analysis was carried out with a rotating rheometer under isochronal conditions, with temperature scanning. This was to assess viscoelastic behaviour in relatively high temperatures, as well as under isothermal conditions, with frequency scanning, for determining the characteristics in a low-temperature range. Trails were performed in the respective linear viscoelastic areas for each sample in order to apply the temperature-frequency equivalency principle and generate the master curves.

PENETRATION AND SOFTENING POINT

As expected, for the three cases, the resulting modified bitumen was characterised by higher softening point (R&B temperatures) and lower penetration values, compared to the original standard bitumen, due to the presence of high percentages of asphaltenes content in the natural asphalts.

Principal characteristics of the original bitumen and the modified products
Type of bitumen	Penetration at 25° (1/10 mm)	R&B Temp.	Asphaltenes content
Original bitumen	96	44	9.8
+ 10% Gilsonite	38	58	15.8
+ 10% Selenizza	67	52	13.0
+ 10% Trinidad	78	51	12.3

The table shows the principal characteristics of the original standard bitumen and the bitumen samples, modified with 10% of each type of natural asphalt. Furthermore, a proportional relationship was observed between the percentages of asphaltenes present in the modified samples of bitumen and the respective values of the softening point.

VISCOELASTIC PROPERTIES, HIGH TEMPERATURES
This correlation implies that the rheological behaviour for medium and high temperatures (50–160°C), whose softening point represents the lower limit, is not a function of the modifier quality and depends exclusively on the asphaltenes content.

Viscosity values of the modified bitumen for this temperature range increase. But even if the viscosity curves shift upwards, their shape and the slope remain unchanged and they remain parallel to one another, for all sample types. This means that the modifiers don’t affect the internal interactions between the asphaltene components in the modified bitumen, which is a typical phenomenon for the compatible additives. Thus, despite the significant increase of asphaltenes content (from 25% to 60%), the thermal susceptibility remains unaltered.

VISCOELASTIC PROPERTIES, LOW TEMPERATURES
For the low temperatures (10–60°C), the rheological modifications seem complex and are differentiated. The viscoelastic behaviour and the ductility of the modified samples, deduced from the master curves at 20°C and 60°C, are impacted by the quality of the natural bitumen (the bituminous component and the inorganic one, which, in this case, may perform the function of filler, decisive for the product performance). At T=20°, an inversion of the zero shear viscosity curves was observed.

During the modulated differential scanning calorimetry (MDSC) tests, the samples (7–10 mg), were subjected to a modulated heat flow, resulting from a sinusoidal temperature ripple overlaid on a linear temperature ramp, in the temperature range from -50°C to +160°C.

The system’s thermal response is composed of the reversing curve, inversely proportional to the heat capacity and the non-reversing curve, an undefined function of time and temperature. For the bitumen analysis, the reversible curve is more indicative as it highlights the various thermodynamic effects (glass transition, melting), while the non-reversing curve rather identifies the kinetic process.

The MDSC analysis, carried out with a calorimeter TA Instruments 2920, has shown that the rheological behaviour of the straight run bitumen has been modified by the addition of natural bitumen.

When comparing the softening temperatures obtained from different reversible curves of the original bitumen and the modified samples, it was observed that the addition of the natural asphalts Trinidad and Selenizza, affects the lower limit of the softening range of the straight-run bitumen.

Indeed, it was noticed that the total softening range of the original bitumen was composed of two different phases. The first one was due to the presence of the maltenic phase (lighter fraction) that melted at 55.8°C. The second one was due to the presence of the asphaltenic phase, melting at 67.8°C.

The maltenic phase of of both samples modified with Trinidad and Selenizza started to soften at lower temperature, for example about 45.9°C, due to the presence in the natural asphalts of different maltenic phases characterised by lower molar mass compared to the original bitumen. Meanwhile, the asphaltenic phases behaved independently. A dilution effect of the original bitumen was thus obtained.

In contrast, it was observed that the natural bitumen Gilsonite, does not act as a diluent. Its addition to the straight-run, bitumen had a negligible influence on the melting temperatures of different maltenic and aphaltenic phases of the original bitumen. But, on the other hand, it expands the softening range of the original bitumen to higher temperatures.

In conclusion, the study indicated that the modifications introduced by the addition of natural asphalts, operate in such a way as to increase the consistency, the viscosity and the stability of the original bitumen thus proving that the natural bitumen can represent an advantageous alternative to other additives for modifying the road pavement bitumen.

USE IN ROAD PROJECTS
Many examples of the implementation of road construction projects confirm the above-mentioned theoretical results.

During the construction of a 17.5km section of the A150 highway in France, the proposed project envisaged the implementation of a two-layer pavement structure consisting of a 6cm HMAC wearing course and a 12cm HMA binder course, over a PF3 sub-grade. With reference to the binder course, in order to meet the technical specifications according to the CE standard NF EN 13108-1, the project intended to use a recycled HMA base course EB 14 ASSISE 20/30 (EME 0/14 class 2). For the manufacture of the recycled hot-mix asphalt, two types of binders were analysed.

The basic HMA mix design contains 30% AE (asphalt aggregates) + 20/30 penetration grade bitumen. On the other hand, the alternative solution is composed of 30% AE (asphalt aggregates) + 50/70 grade bitumen + 1.5 % Selenizza. For comparison purposes, the two types of HMA had the same composition of materials in terms of particle size distribution curves and percentage of binder used.

The comparative study of the two different mix design types showed that both of them met the requested technical specifications and were in accordance with the standards. It should nevertheless be noted that on equal parameters of the obtained modified binder (penetration grade, softening point), the second approach, using natural bitumen, yields noticeably better results in terms of rheological and mechanical properties. There were higher results of stiffness (15 855MPa), better resistance to fatigue (137.1μm/m) and better resistance to rutting (3.3%).

These results validate the idea that the specific constituents of natural asphalts, shall be taken into consideration in the technicaleconomic choices.

Highway A150 in France. An implementation of a two-layer pavement structure consisting of a 6cm HMAC wearing course and a 12cm HMA binder course, over a PF3 sub-grade

A further example comes from the construction of the Fier–Tepelene highway in Albania, where the natural bitumen Selenizza was used as an additive for the production of bituminous mixtures of the flexible pavement.

It was used because of problems in finding the right bitumen locally that could meet the requirements of the technical specifications. But it was used also because natural bitumen could simultaneously contribute to reduce by 4cm the total thickness of asphalt layers, compared to the thickness provided for in the original project design.

The new road pavement structure consisted of three layers of continuously graded bituminous mixtures, the base course (9cm), the binder course (6cm) and the wearing course (4cm). For all bituminous mixtures, the natural bitumen Selenizza was used to a percentage of 8% by weight of the base bitumen. A study conducted by the Polytechnic University of Turin in Italy, on materials sampled from the production plant, as well as on a test session, evaluated the binder and pavement performance.

The analysis of compact issues, by referring to binder viscosity and the binder-related contribution to the occurrence of rutting, fatigue and thermal cracking as well as the assessment of mixture stiffness, led to the conclusion that the considered bituminous mixtures containing the natural asphalt Selenizza, were in compliance with the pavement construction standards and specifications.

One last example on the successful use of the natural bitumen Selenizza, is the Highway A8 Olimpia Odos construction project in Greece. It involved 375km of highway and was designed according to the prescription of French standards. The road structure consisted of a Dense Bitumen Macadam (DBM) base course, an anti-rutting binder course AC (5cm) and an anti-skid TAC (thin asphalt concrete) wearing course (2.5cm).

Several trial mix designs for the base and binder courses were tested using different kinds of binders such as bitumen 50/70, bitumen 50/70 + 8% Selenizza, bitumen 30/50 and PR PLAST modified bitumen. Laboratory tests on elastic modulus and fatigue showed that the binder with bitumen 50/70 + 8% Selenizza, had higher results of stiffness and fatigue compared to all the other tested binders, allowing it to produce an asphalt concrete that belongs to the higher project category DBM 4. This made it possible to reduce the road package thickness by at least 4cm.

NEUTRAL ASPHALT, ENVIRONMENTAL IMPACT
The recent worldwide economic crisis and the growing environmental awareness have created the need for bituminous binders that meet Life Cycle Assessment constraints. As a part of a common commitment to sustainable development, the University of Rome, in cooperation with the company Selenice Bitumi, carried out e research project, whose aim was to analyse and compare for the first time the production process of the Albanian natural asphalt (Selenizza). The project was also a chance to look at the steps necessary to produce conventional bitumen from crude oil, evaluating the energy consumption and CO2 emission for each kind of product. The study was based on the guidelines of the environmental assessments according to the European standard, such as Life Cycle Assessment (LCA) and Life Cycle Inventory (LCI), on the bitumen produced in crude oil refineries.

Highway A8 Olimpia Odos construction project in Greece uses the natural bitumen Selenizza

For conventional bitumen the energy consumption of each step has been calculated as well as the carbon dioxide emission, starting from oil extraction, up to vacuum distillation. It included the entire chain of bitumen production, beginning with the acquisition of raw materials, transport, manufacture, use and maintenance, recycling and final disposal.

The product cycle of natural asphalt Selenizza composed from four main phases – extraction, concentration, processing and storage. This is much simpler than the refinery cycle, with an immediate feedback in energy consumption and environmental impact. Moreover, transport stages are reduced to the minimum due to the close proximity of the quarry site to the processing unit.

For study purposes, all technical documentation about electrical equipment and vehicles operating at the mine of Selenice in Albania, together with geological and chemical analysis, were exploited to evaluate the energy consumption characterising each stage of the process.

Also, the value of the Italian-Albanian energy mix, determining the amount of CO2 emissions per kWh of electricity produced, was acquired from the International Energy Agency (IEA). The data on the calorific value of the fuels used during the production, that is, the amount of CO2 emissions per kg of burned fuel, were available from international literature and from ENI (Italian national hydrocarbons agency).

In the light of such an innovative analysis, it was concluded that the natural asphalt Selenizza allows substantial energy saving: 2,376MJ/t versus 4,71MJ/t, that is, about 50% of the value of the bitumen produced from crude oil. There was a significant reduction in CO2 emissions up to 44%: 127,3kg versus 226,2kg per tonne of conventional bitumen production.

A more efficient and smart use of natural resources at the dawn of the 21st century represents a challenge that we must all embrace. Indeed, the natural bitumen Selenizza, is an environmentally friendly product, available within the reach of every road construction company. It can also contribute to improving the quality of high modulus hot-mix asphalts. It offers a better resistance for the high-traffic stress roads, providing material savings by reducing layer thickness and ensuring increased pavement longevity.

Selenice Bitumi is a wholly owned subsidiary of French Company KLP Mines. The company owns the mine of Selenice, an open-pit natural bitumen reserve that constitutes the only deposit of natural bitumen in Europe.

The natural bitumen originating from these deposits is used as an additive and is mixed with refined bitumen, in different percentages, composing on average about 1% of the total mass of the binder.

Selenice Bitumi products are sold in France, Switzerland, Italy, Greece and Ukraine as well as in China, Canada and countries in North Africa, such as Tunisia and Morocco.

November 18, 2015

by AEA

Transatlantic Petroleum to sell Albanian assets

On November 16, 2015, the Company’s Board of Directors authorized the immediate launch of a marketing process for the sale of all of the Company’s oil and gas assets and operations in Albania.

While TransAtlantic pursues the marketing process, it will continue the execution of its current operational plan focusing on low cost, high return operations. TransAtlantic does not expect to comment further or update the market with further information on the marketing process unless and until the Board of Directors has approved a specific transaction or otherwise deems disclosure appropriate or necessary. There is no assurance that this marketing process will result in the Company pursuing a particular transaction or completing any such transaction.

Production Update

TransAtlantic’s current net production as of November 13, 2015 is approximately 6,500 BOEPD, and is comprised of approximately 5,800 BOEPD from Turkey and 700 BOPD from Albania.

About TransAtlantic Petroleum Ltd.

TransAtlantic Petroleum Ltd. is an international oil and natural gas company engaged in the acquisition, exploration, development and production of oil and natural gas. The Company holds interests in developed and undeveloped properties in Turkey, Albania and Bulgaria.

November 18, 2015

by AEA

China to host China-CEE leaders’ meeting for first time

The fourth leaders’ meeting of China and Central and Eastern European (CEE) countries will be held in east China’s Suzhou city from Nov.24 to 25, the first time for China to host the meeting.

LEADERS’ MEETING

Chinese Premier Li Keqiang and the leaders from the 16 CEE countries will attend the meeting in Suzhou, Chinese President Xi Jinping will meet the 16 countries’ leaders in Beijing, Chinese Vice Foreign Minister Wang Chao said.

Leaders’ meeting is the most important schedule under the framework of China-CEE cooperation this year, Wang said, noting it will lay a stronger foundation for future development.

The meeting in China this year will be meaningful to the sustained, balanced and in-depth relationship between China and Europe, Wang said.

Li will also attend a “16+1” round table meeting and an economic and trade forum.

The 16+1 meeting mechanism, launched in 2012, has helped to deepen traditional friendship, strengthen mutually beneficial cooperation and promote China-Europe relations, Wang said.

CEE countries that attended the meeting included Albania, Bosnia and Herzegovina, Bulgaria, Croatia, the Czech Republic, Estonia, Hungary, Latvia, Lithuania, Macedonia, Montenegro, Poland, Romania, Serbia, Slovakia and Slovenia.

NEW MILESTONE

China is willing to be a good host and make the meeting a new milestone to the development of China-CEE cooperation, Wang said.

The theme of the meeting this year is “New beginning, New fields, New vision” , Wang said.

It is the first time for China to host the China-CEE leaders’ meeting, Wang said, so the new beginning means it’s an important period to inherit the past and usher in the future.

The meeting will propose new measures and expand new fields for China-CEE cooperation, covering inter-connectivity, investment and trade, finance, agriculture, people-to-people exchanges and so forth, Wang said.

The leaders will also plan the new vision of development in the next five years, aiming to strengthen top-level design for the cooperation, Wang said, adding that some outcome documents will be released after the meeting.

Wang said China-CEE cooperation has expanded into new areas and produced greater results, thanks to the increasingly mature mechanism and emerging platforms.

TRADE AND INVESTMENT

Li will deliver a speech at the opening ceremony of a trade and investment forum in Suzhou, Vice Commerce Minister Gao Yan said, adding that about 1,000 China and CEE business leaders will participate in the forum.

In 2010, the trade volume between China and CEE countries was 43.9 billion U.S. dollars. The figure increased to 60.2 billion U.S. dollars in 2014.

China-CEE economic and trade cooperation faces new chances, Gao said, calling on the two sides to deepen cooperation in industrial capacity and equipment manufacturing.

According to Gao, at present, Chinese companies have invested more than 5 billion U.S. dollars in CEE countries and the 16 CEE countries have invested more than 1.2 billion U.S. dollars in China.

Gao said both sides are expanding investment areas and diversifying investment forms.

China and CEE countries are closely linked by the China-proposed Belt and Road initiative, Gao said, adding the two sides have huge potentials in energy and infrastructure cooperation.

November 18, 2015

by AEA

Ilham Aliyev: Energy security cannot be considered apart from national security

Azerbaijani President Ilham Aliyev addressed a working lunch as part of the G-20 Summit in Antalya on Nov.16.

The head of state noted that high-level relations between Azerbaijan and Turkey are developing and bilateral cooperation in the energy sector is going on successfully, APA reports.

Azerbaijan is successfully implementing major energy projects with Turkey, the president said.

“Azerbaijan is the first country where oil was extracted in the mid-nineteenth century. Afterwards in the mid-twentieth century oil extraction began in Absheron. And now, in the twenty first century, we are implementing the Southern Gas Corridor project, much of which has already been realized thanks to the active participation of Azerbaijan and Turkey. I’m talking about the project that links Azerbaijan and Turkey, and the Caspian and the Mediterranean. This is a historical event. I would also note the gas pipeline which connects Turkey with Azerbaijan. So we became not only an oil-rich country but also an oil exporter,” President Aliyev said.

The implementation of both projects began a decade ago, the president said, noting that their operation allows both countries to sell more oil and gas and our partners to use alternative energy sources.

As is known, the Caspian Sea does not have access to the ocean. Nevertheless, Azerbaijan is the only country that is able to deliver its resources to parts of the world, according to the head of state.

“We are glad that we began working with our partners in 1994 and this partnership is going on successfully now. The partnership between our countries and friends allowed us to implement these projects successfully,” he said, expressing hope for the successful implementation of the Southern Gas Corridor.

“I would like to express gratitude to President Erdogan for the support and jointly moving toward a same direction. We have good investors,” said the president.

President Aliyev, expressing gratitude to US President Barack Obama for the support the US provided in the implementation of the projects, noted that without this support, it would have been impossible to achieve success in the mid-1990s.

The president also thanked British Prime Minister Cameron. “The UK has been the largest investor in Azerbaijan for over 20 years and this enabled us to develop our partnership in investment and other fields,” he said.

Meanwhile, the head of state expressed gratitude to his friend Renzi, stressing that Italy will continue to be the largest importer of the gas. “This project will give us an opportunity to enter the markets of other countries through Italy”.

The president underlined that investments worth 45 billion dollars will allow to create a common gas network for the delivery of gas extracted in the Caspian Sea on-shore.

“The gas passing through Georgia and Turkey will be delivered to Greece, Bulgaria, and then Albania, and finally to Italy through the Adriatic Sea. This project requires the coordination of efforts of governments and companies of relevant countries and we are already foreseeing the results of this coordination and cooperation”, said President Aliyev.

Azerbaijan’s proven gas reserves are about 2.6 trillion cubic meters while its potential reserves are estimated at nearly 5 trillion cubic meters, the president said, noting that this volume is sufficient for us, our neighbors and European consumers at least 100 years.

President Aliyev said this is a project of energy security, stressing that today, the issue of energy security can not be considered apart from the country’s national security.

“This is a diversification project. In this case, this means not only the diversification of routes – although this is important – but also that of sources. In this respect, our route is new for Europe and it will fully change the energy map of Europe. Azerbaijan has already proved to be a reliable partner,” the head of state added.

“Of course, we must protect the interests of transit, consumer and producer countries,” the president said, noting that to achieve these goals, there is a need to create favorable conditions for all parties.

November 12, 2015

by AEA

TransAtlantic Petroleum Continues To Cut Costs

TransAtlantic Petroleum: OPEC Might Cut Production, But Company Continues To Cut Costs

Summary

The Albania Division is on the block for sale, or some definitive resolution and is in a company that is separate from the rest of the company.

The Turkish division is cash flow positive and profitable at current prices even without hedges.

The chairman and CEO is considering lifting the remainder of the hedges to pay down debt because he believes there is a good chance of an OPEC production cut.

The company has two wells to complete and return to production. Current production is up 900 BOED from the quarter not including two wells to be completed by year end.

Shareholders are purchasing stock in the company and hold a significant amount of the company’s debt.

Malone Mitchell, Chairman and CEO of TransAtlantic Petroleum (NYSEMKT:TAT) was characteristically blunt about the challenges facing the company. The company had purchased a division in Albania, a division that has been kept separate from the rest of the company (as a Cayman Island entity) since its acquisition. That company division needed work and had some minor cash flow. The company had done its due diligence and knew what it was getting into. However, since the acquisition the oil markets changed to the point where the division in Turkey was not generating the cash flow needed to turn around the division in Albania and meet covenant requirements. The company had tried and so far failed to find a substantial investor willing to put cash into the division without also wanting to run the division. Therefore the company has put the division up for sale and reported the Albania operation as a discontinued operation. The CEO still feels that the division has great prospects but he is assuming that low oil prices will continue through 2016 and therefore the rest of the company will not generate in the future the money needed to fully take advantage of this division and meet the inherited financial obligations.

The twenty percent decline in oil prices led to a $16 million impairment charge, $13 million of that charge was an impairment of the properties in Albania. The company also took a $22 million non-cash charge for the currency devaluation of the Turkish currency. The company wrote off $1.8 million of accounts receivable. None of these charges affected cash flow.

Finally, the company had stated that should oil prices decline to the point where the hedges were worth more than $40 million, then the company would consider cashing in the hedges and paying down some bank debt. The net proceeds of $25.8 million was used to pay down bank debt when the company unwound some hedges. Roughly half of the proceeds were received before quarter end and the rest after quarter end during the month of October. So while the company reported hedges worth more than $30 million at quarter end, approximately half that value has now been liquidated. The company did replace some of the hedges with new hedging at a lower price.

The company reported production costs of $9.68 per BOE for the latest period. While that was an increase from the second quarter, the total increase and more was due to the Albania division. In Turkey, the continuing operations segment, the LOE decrease from $4.6 million to $3.1 million for an annualized savings of roughly $6 million.

The company estimated in its release that the Turkey division was roughly responsible for 5200 BOED out of 5900 at quarter end. Using a 90 day quarter for estimation purposes that gives roughly. So if 700 BOED is subtracted from the 5000 BOED that was maintained during the quarter, then the production costs are estimated at $8.01 BOE, a very attractive figure for the Turkey division. So the company could realize some very tangible savings per BOE from ridding itself of the Albania division.

In addition, continuing general and administrative expense dropped to $4.6 million from $6.3 million from the previous year for a total savings of $7 million. So management has realized an annual savings of $13 million between the LOE decrease and the G&A decrease. The G&A expense is roughly $10 per BOE. While this is higher than several companies that I have covered so far, the combined figure of $18.01 for the Turkey division is very attractive at these prices, even if that figure climbs a little if the Albanian division is sold. This company is doing just fine at current oil prices with its continuing business and that is rare in the industry.

“The market for new credit or equity in energy markets is very expensive. IBERIABANK gave me a market study last week which showed the average high yield debt for all companies is now running at approximately 18.6% versus 6% a year ago. Debt cost in Turkey would probably be even higher if that were available.”

This quote from the conference call, indicates the predicament of the company. The production costs are excellent as the company gains much of its revenue in dollars and has many of its expenses in Turkish Lira. That enables the company to operate relatively cheaply. However, the conflict in Syria and Iraq has scared away creditors to the point where the company cannot obtain loans to develop its properties. Even the properties in Albania, which are further away are affected. What loans the company does have it intends to pay off. It has an $8 million loan that it intends to pay off by April, for example. It has already (through October) paid down $25 million in bank loans, and may well liquidate hedges to pay more loans. This is one of the big reasons for the change in plans with regard to the Albania division. With current oil price quotes in the forties the company is very hesitant to invest more than cash flow in its properties and would prefer to pay off its outside creditors first before investing in its properties.

The company has stated in the past that with oil prices below $50 it will work on its balance sheet, and this year has improved the balance sheet with a vengeance that few companies can match. If oil prices head over $60, then the company will expand its capital budget. The in between numbers the company intends to plan for sub-$50 oil however, it may vary from that plan depending upon the outlook of management.

Currently the company states it has $55 million convertible (from shareholders), $9 million loan and then another $29 million loan. Should the company decide to liquidate the rest of its hedges (and right now, that looks like the intention) then it will pay down another $15 million or so of these loans of $29 million and $8 million. No matter what the company has a priority of paying off the $8 million loan by April. Shareholders holding a hotel have pledged the hotel as security for some of these loans. It is successfully ridding itself of nervous creditors (that want to raise interest rates) through some very astute management of its hedging program.

“I do believe there is a chance of a production cut at the December 4th OPEC Meeting, not a probability but a chance. So I would tend to favor lifting our remaining hedge volumes ahead of that meeting if current information remains consistent.”

This quote merits consideration by any investor who has followed the company. This is the same CEO that previously rushed to purchase hedges ahead of the 20% price decline that occurred in the beginning of the third quarter. Those hedges have earned the company more than $25 million so far and will earn the company another $15 million (in cash) at least if this plan is carried out. Those hedges plus the ones already in place have enabled the company to remove a third of its long term debt ahead of schedule. That amount of money is a gold mine for a company of this size. This company is making quite a bit of money from the hedges and that offsets some of the other unfortunate things happening as well as making the continuing challenges easier to bear. This is a very significant turn around in attitude by that same CEO. It also indicates for the first time, that a CEO is relatively upbeat about the future of oil and gas prices. This CEO has been extremely accurate about the future of oil and gas prices, made a lot of money for his company in the process, and therefore his actions bear watching. He may be signaling that oil prices have finally hit bottom, at least for the time being and may be about to bounce upward.

Even in this market, the Turkish Division generated income of nearly $18.3 million before income taxes from continuing operations. The whole company showed income of nearly $200K before currency translation adjustments (a non-cash charge) of $22 million. So operations in Turkey are quite healthy and throwing off quite a bit of income. Cash flow for the nine months was $38 million, and therefore makes the debt level look quite comfortable were it not for the instability of the neighbors surrounding Turkey. Turkey itself appears quite stable, and seems to have more than adequate plans to deal with its neighbors, plus it has a long history of surviving quite adequately in a very unstable region. However, the perceptions of Turkey right now are not favorable and for that reason investors and investment money are hard to come by.

The current ratio is still fairly weak at approximately .66:1. However, much of the current accounts payable is for related parties and therefore could be put off for a little bit if the company needed more time. With the emphasis on paying off the bank debt, that appears to be exactly what is happening. Most of the convertible debt is due to shareholders of the company and that more than $50 million is in very stable and patient hands. The faith of the major shareholders in the company has clearly kept this company going and can be shown by the amounts owed to shareholders in long term debt as well as accounts payable amounts. It has allowed the company to pay off some nervous lenders and yet still be viable.

If the situation in Albania can come to a reasonable conclusion. There is an excellent possibility that this company will show some decent cash flow for its size with or without that division. The company showed production of 5000 BOE per day in the third quarter and states that was pretty flat with the previous year. However, the company shows 5900 BOE per day of current production with another 400 BOE per day shut in, and two wells that need to be completed for production in the fourth quarter. This company therefore should have a fairly significant revenue jump in the fourth quarter provided commodity prices don’t drop significantly again. Plus the production in the division is profitable production. The only reason that the company did not report profitability was the currency translation adjustment, a charge that is typically non-cash and does not affect anything. Operations results are extremely strong compared with the rest of the industry. This company should do very well when the Albanian division situation is resolved.

The larger shareholders banded together to purchase the $55 million in convertible notes from the company as noted in the previous article. That saved the company from a very dim future this year. As noted in the conference call, some of the major shareholders continue to purchase stock through open market transactions. The major shareholders have shown their faith in the company by purchasing convertible securities, lending, pledging collateral for loans, and doing business with the company (allowing for lenient repayment terms if needed), and purchasing stock on the open market. These owners have sent a loud and continuing signal that they consider the company a bargain and will do what is necessary to see the company survive.

The president himself stated that the next few months will be challenging, but he has outlined the challenges facing the company and has discussed publicly the plans that he has available to deal with those problems. Few management’s are this upfront about the challenges facing them, and when management faces challenges, they usually achieve their goals to the benefit of shareholders. The current stock price has a lot of negative news built into it, and in case the shareholders missed any news, the CEO summarized the challenges at the beginning of the conference call, and then stated how he intended to surmount those challenges. A shareholder could not ask for much more, and therefore could find this stock very rewarding in the future.

From the previous article, the 1P reserves are $18.63 a share. While that will take a hit with lower oil prices and to some extent the sale of the Albanian division, probably two-thirds of the value will survive even in the current low price environment. There is plenty of value still to this company and much of that value has been discarded by the current pessimism. The actions of the biggest shareholders have been ignored by the market, at some point that will change and the market will realize what the major shareholders have seen in the company all along. With the Albanian division kept separate, there is every reason to expect the company to survive without that division should that become necessary.

Disclaimer: I am not an investment advisor, and this article is not meant to be a recommendation of the purchase or sale of stock. Investors are advised to review all company documents, and press releases to see if the company fits their own investment qualifications.

Editor’s Note: This article covers one or more stocks trading at less than $1 per share and/or with less than a $100 million market cap. Please be aware of the risks associated with these stocks.

November 3, 2015

by AEA

Cashing In On Pieces Of The Caspian Jigsaw

The landlocked Caspian Sea is one of the oldest oil producing regions in the world and growing its reputation as a gas producer, but the region poses a unique set of challenges to companies looking to develop its reserves. Bordered by Kazakhstan, Russia, Azerbaijan, Iran and Turkmenistan, the Caspian Sea is the largest enclosed body of saltwater in the world.

Despite the logistical difficulties of access and infrastructure, however, a swathe of projects are underway offshore the main producing countries. With sanctions being lifted on Iran, activity also is expected to pick up there in the coming years.

In the Azeri sector of the Caspian, most oil production comes from the BP-operated Azeri-Chirag-Gunashli field complex, while Shah Deniz, Azerbaijan’s biggest gas field, is being developed by BP, Statoil, Azeri state energy company SOCAR and the South Caucasus Pipeline Co.

The project is in development of the second phase, which includes offshore drilling and completion of 26 subsea wells and construction of two bridge-linked platforms. And onshore there will be new processing and compression facilities at Sangachal.

About 16 Bcm/year (565 Bcf/year) of gas produced from the Shah Deniz Stage 2 project will be carried some 3,500 km (2,175 miles) to provide energy for millions of consumers in Georgia, Turkey, Greece, Bulgaria and Italy.

First gas is targeted for late 2018, with sales to Georgia and Turkey. First deliveries to Europe will follow about a year later.

Condensate production from the Shah Deniz Field is expected to increase to 120 Mbbl/d from current levels of about 55 Mbbl/d.

The final investment decision for the project was taken in 2014 and triggered plans to expand the South Caucasus Pipeline (SCP) through Azerbaijan and Georgia, to construct the Trans Anatolian Gas Pipeline (TANAP) across Turkey and to construct the Trans Adriatic Pipeline (TAP) across Greece and Albania and into Italy.

Together these projects will create a new Southern Gas Corridor to Europe. The total cost of the Shah Deniz Stage 2 and SCP expansion projects will be about $28 billion. Technip has been awarded a contract by TAP for the onshore part of the pipeline from Greece to Albania and in Italy.

The project scope includes an about 870-km-long (540-mile-long) pipeline, which will start from the tie-in with the TANAP portion of the Southern Gas Corridor project at the Greece/Turkey border.

The pipeline will then go through Greece and Albania to eventually cross subsea in the Adriatic Sea and end in Puglia, Italy, where it will connect to the Italian natural gas network.

TAP is designed to transport 10 Bcm/year (353 Bcf/year) with a potential future expansion to 20 Bcm/year (706 Bcf/year) as more gas becomes available.

FMC Technologies will supply subsea production systems for well clusters 3-5 of the Shah Deniz Stage 2 project in a deal worth $297 million.

Another $66 million contract for the second of three planned batches of subsea production trees and ancillaries required for the full-field development was awarded to OneSubsea. The delivery of equipment will take place from 2016 to 2021.

Shah Deniz is not the only major project underway in the Azeri sector of the Caspian, with Total teaming up with SOCAR to develop the Absheron gas field, which the French operator sees starting up in 2021.

Total and SOCAR formed a joint venture (JV) in 2009 to explore and develop the Absheron Field, which has estimated reserves of 350 Bcm (12 Tcf) of gas and 330 MMbbl of gas condensate.

Block Absheron lies under about 500 m (1,640 ft) of water in the Caspian Sea and is 100 km (62 miles) from Baku.

The field was discovered in 2011 and contains between 141 Bcm and 283 Bcm (5 Tcf and 10 Tcf) of gas resources.

Total and its partners have completed the FEED for the project.

The FEED process started in summer 2014 and was concluded in July 2015.

Various commercialization options for the natural gas have been studied. It could be transported via the SCP, in which Total holds a 10% equity stake.

“The final investment decision is expected to be made in the fourth quarter of 2017, and the first commercial drilling [is scheduled to] start in the fourth quarter of 2019,” Eric Meyer, Total’s planning development manager, said. “So the first gas will be produced in the fourth quarter of 2021.”

Four wells are expected to be drilled on the field by two rigs. The first of them will be drilled by a new semi-submersible floating drilling rig, which is now under construction by SOCAR.

Total and SOCAR both hold 40% stakes in the JV. French group GDF Suez, which joined the project later, owns 20%.

Limited rig access
One of the problems faced by companies operating in the Caspian is a lack of access to drilling rigs.

SOCAR is constructing the new Caspian Driller semisubmersible rig designed for drilling wells at depths up to 8,000 m (26,247 ft) and in water depths of 1,000 m (3,281 ft). The rig is expected to be completed in 2016.

The cost of the new-generation rig construction project in Azerbaijan is $1.116 billion.

The Caspian Drilling Co. (CDC), 92.44% of which is owned by SOCAR, will act as an operator of the rig.

Singapore’s Keppel FELS Ltd. became a construction contractor for the plant and signed an agreement on construction with CDC in June 2013.

The rig also will be used for drilling on other fields in the Azeri sector, including the Umid Field and the Babek, Karabakh and Ashrafi prospects. It is expected to start operations off Turkmenistan.

In a bid to overcome the limited rig supply in the Caspian, drilling contractor Eurasia Drilling Co. Ltd. (EDC) has used novel methods to get its rigs into the region.

It is now the largest offshore drilling contractor operating in the jackup market of the Russian, Kazakh and Turkmen sectors.

The company owns and operates three of the four jackups operating in these sectors: the Astra, Saturn and Neptune rigs. The company’s new Mercury jackup is completed and undergoing certification and licensing in the Turkmen sector before startup of operations.

The job of getting the Mercury rig from Sharjah where it was built to the Caspian was a complex one.

The rig was built as a Lego kit, fitted together and then sectioned out, enabling it to be shipped on the Volga Don Canal and then put back together at the CNRG shipyard in Astrakhan.

One of the main challenges was to fit the Volga-Don width restrictions. The central hull sections, for example (the largest single modules), cleared the canal by only 6 in. on either side.

The main hull for the Neptune, a LeTourneau Super 116E, was preassembled at the Lamprell yard in Sharjah in the United Arab Emirates (UAE) and then sectioned into seven pieces, including two central sections, two side sections and three leg well sections.

The legs for the rig were preassembled in the UAE as full rounds, with 13 sections per leg plus the spud can, which also included a small leg section.

The accommodation and rig package were then all shipped to the Caspian in kit form and assembled onsite with the exception of the cantilever, which was prebuilt in the UAE.

The helideck, upper pipe deck and a few other small items were built in the Caspian.

In addition to the Mercury newbuild rig there are another two jackups under construction in the Caspian, one of which is the Caspian Driller newbuild rig.

The second jackup is the Prime Exerter owned by Ezion Holdings. The 33-year-old Prime Exerter was dismantled in Holland so it could be shipped into the Caspian Sea through the Volga-Don Canal system. It has been reassembled in Baku.

EDC believes seven or eight jackups are required to keep up with drilling demand in the Caspian Sea due to the large number of exploration licenses yet to be drilled.

Further discoveries would lead to more development drilling on top of the already heavy workload EDC is seeing for its rigs.

During first-half 2015 the Astra jackup rig drilled a well for the N Operating Co. in Kazakhstan followed by a well for Lukoil in the Russian Sector.

The Saturn jackup was also busy, drilling two wells for Petronas in Turkmen waters, where the Neptune jackup also drilled three wells for Dragon Oil.

EDC also drilled and completed three wells on Lukoil’s Yuri Korchagin Field platform in the Russian sector before commencing coiled-tubing workover operations on a fourth well.

Russia eyes Caspian
With its vast oil and gas reserves, Russia has plenty of projects to choose from, but energy officials believe the Russian sector of the Caspian Sea could prove critical to its energy security.

Lukoil discovered six large oil and gas fields in the North Caspian between 1999 and 2005: Khvalynskoye, Yuri Korchagin, 170th Kilometer, Rakushechnoye, Sarmatskoye and Filanovsky.

The fields are thought to contain nearly 5 Bbbl of 3P (proven, probable and possible) reserves.

The Vladimir Filanovsky oil and gas field is the biggest by oil reserves discovered in Russia in the last 20 years, while another 10 prospective oil and gas structures have been identified in the North and Central Caspian.

The Vladimir Filanovsky Field was discovered in 2005 and contains 487 MMboe of proven reserves.

Development work is ongoing, and production from the field is scheduled to commence in late 2015 or early 2016 at a rate of 210,000 bbl/d.

Field facilities consist of an ice-resistant platform, a living quarters (LQ) platform and central processing platform.

The topside sections of the central processing platform and the LQ module were transported to the field in second-half 2014. The topsides for all four platforms and the catwalk bridges are currently being assembled.

Azat Shamsuarov, Lukoil’s senior vice president for oil and gas production, said, “The Vladimir Filanovsky Field development is being implemented in strict compliance with the schedule. Lukoil’s program for Caspian Sea development is a long-term one, and we are quite convinced that it will promote the development of shipbuilding and related industries in southern Russia.”

Another of Lukoil’s major producing fields is Yuri Korchagin, the country’s first offshore field in the Caspian Sea. Field infrastructure includes an ice-resistant fixed platform (LSP-1) built at the Astrakhansky Korabel shipyard and intended to drill and operate wells as well as collect and pretreat reservoir content.

The LSP-1 has a 560-mt rig capable of drilling up to 7,400-m (24,278-ft) wells.

Field construction will include 26 production wells, three water injectors and one gas injector.

Kashagan stalled

In the Kazakh sector of the Caspian Sea, the giant but troublesome Kashagan oil field is at the heart of development
plans.

Discovered in 2000, it is the largest oil field outside the Middle East. But development of the field has experienced significant delays and considerable cost overruns, with a $50 billion price tag now being put on the scheme.

The figures for oil-in-place range between 30 Bbbl and 50 Bbbl, with an average oil-in-place estimate of about 38 Bbbl. With a relatively low recovery factor of between 15% and 25% due to the complexity of the reservoir, the recoverable reserves figure is presently placed between 7 Bbbl and 13 Bbbl.

IP began in 2013 but just a few weeks later output had to be shut in because of leaks in the 28-in.-diameter pipelines transporting the sour gas 90 km (56 miles) to shore from the processing facilities installed on the artificial “Island D” hub, where the recovered liquid and gas are separated.

The highly corrosive gas has been blamed for the leaks, with the owners agreeing to completely replace the pipeline network (it is estimated to be about 200 km [124 miles] in total) with higher grade, more expensive materials.

Earlier this year Saipem, through its subsidiary ERSAI Caspian Contractor, was awarded a major new $1.8 billion engineering and construction contract for the Kashagan Field project.

Saipem will construct two 95-km (59-mile) pipelines that will connect Island D in the Caspian Sea to the Karabatan onshore plant in Kazakhstan.

The scope of work includes the engineering, welding materials, conversion and preparation of vessels, dredging, installation, burial and precommissioning of the two pipelines. The two pipelines, with a diameter of 28 in., are made of carbon steel internally cladded with a corrosion-resistant alloy layer. Construction will be completed by year-end 2016 and startup of the field is anticipated in 2017.

Eni has a 16.8% stake in the consortium developing the field. Other partners include Shell (16.81%), Total (16.81%), Exxon Mobil (16.81%), KazMunayGas (16.81%), China National Petroleum Corp. (8.4%) and Inpex (7.56%).

Until Kashagan starts up again, the largest source of oil production in Kazakhstan is the giant Tengiz oil field, discovered in 1979.

In Turkmenistan, most of the country’s oil reserves are located offshore or in the Garashyzlyk area west of the country.

The Cheleken project has been under development since the mid-1990s, with the UAE’s Dragon Oil acting as operator.

Proved and probable reserves in the contract area are about 3 MMbbl of oil and 84 Bcm (3 Tcf) of natural gas.

In 2014 Dragon Oil completed 14 development and appraisal wells: 13 in the Dzheitune (Lam) Field and one in the Dzhygalybeg (Zhdanov) Field. Four drilling rigs are operational in the Cheleken Contract Area.

The final piece of the Caspian jigsaw is Iran, where there is currently no significant production. Iran estimates, however, that there are 100 MMbbl of oil reserves in the Sardar Jangal Field discovered in 2011.

The Iranian Oil Ministry plans to establish a refinery on the Caspian coast and supply it with crude oil from the Sardar Jangal Field, although any development in this area is likely years away, according to the International Energy Agency.

What appetite Iran will have to produce Caspian oil now that sanctions are being removed remains to be seen.