Rosneft sells stake to Indian oil companies for its Taas Yuryakh project

Oil India, Indian Oil Corporation and Bharat PetroResources signed a deal to acquire a 29.9 percent stake in Rosneft’s Taas-Yuryakh oil project.

A group of Indian state-run energy firms  announced a string of deals with Russian giant Rosneft for stakes in Siberian oil fields, as the two countries seek to step up energy cooperation.

India’s oil and gas minister Dharmendra Pradhan met Igor Sechin, the head of state-owned Rosneft who is considered a close ally of Vladimir Putin, for the signing of the agreements.

The deals are worth an estimated $4.2 billion, Press Trust of India said, citing unnamed officials.

“The signed documents literally mark the turning of a new leaf in the cooperation between Russia and India in the energy sector,” Sechin said in a statement.

India imports around 80 percent of its oil needs and is keen to take advantage of low crude prices by signing overseas deals that will help secure supplies, to meet its growing demand.

Russia has been hit badly by recession, exacerbated by the steep drop in oil prices and Western sanctions against Moscow over the Ukraine crisis, and sees India as an attractive market.

An Indian group comprising Oil India, Indian Oil Corporation and Bharat PetroResources signed a deal to acquire a 29.9 percent stake in Rosneft’s Taas-Yuryakh oil project.

The consortium also signed an initial, non-binding Heads of Agreement for a 23.9 percent share in Vankorneft, a Rosneft subsidiary that runs its huge Vankor field in Siberia.

And the overseas arm of India’s Oil and Natural Gas Corp (ONGC), which earlier agreed a deal for a 15 percent share in Vankorneft, signed a memorandum of understanding to raise that stake to 26 percent.

Indian oil minister Pradhan said the agreements were “a remarkable achievement”.

“It is of prime importance that the cooperation is of a long-term nature and it will deliver significant multiplicative effect for the economies of both countries,” he said in a statement.

India is also looking to develop its domestic hydrocarbon resources and has outlined policy changes to boost investment in gas and oil exploration in recent weeks.

Oil minister Pradhan told the Financial Times this week in an interview that the changes would unlock $40 billion in hydrocarbons and attract some $25 billion in investment.

Chinese Geo-Jade acquires Bankers Petroleum Albania oil exploitation rights

Gazprom operations in Serbia and SEE region negatively impacted by EU sanctions against Russia

NIS Serbia owned by Gazprom, Sberbank and VTB Bank are under EU sanctions and suffering from it. Gazprom controlled Oil Industry of Serbia NIS may be facing difficulties in financing its SEE regional projects in oil exploration in Romania and other business activities. It could be softly explained that NIS Gazprom is competing with MOL INA regional market expansion as Gazprom has ongoing asset swap talks with OMV.

are suffering The 24-pages document is branded as a government paper, although its authors work for NIS, Serbia’s largest energy company, majority-owned by Russia’s Gazprom, and in which the Serbian government also has a stake.

Serbia believes that the EU sanctions against Russia unfairly impact candidate countries, and have an adverse effect on its own accession process, says a document obtained by EurActiv.com.

Serbia, a candidate country since 2012, claims that its companies are disadvantaged in comparison to EU firms when dealing with Russian entities targeted by the EU sanctions. Candidate countries are not legally obliged to align with the sanctions regime imposed on Russia as a response of the destabilisation of Ukraine. But, Montenegro and Albania, both candidates, have adopted the sanctions.

Serbia considers itself the candidate country most affected by the European Union’s sanctions against Russia, although Belgrade has refused to implement them.

The 24-pages document is branded as a government paper, although its authors work for NIS, Serbia’s largest energy company, majority-owned by Russia’s Gazprom, and in which the Serbian government also has a stake.

According to the authors, Belgrade believes that the adverse effects of the EU financial restrictive measures regime on Serbia were not foreseen at the time of drafting of the sanctions rules, most likely because EU candidate countries were not sufficiently consulted or considered during the discussions and drafting of the text of the EU Regulation of 31 July 2014.

Since their imposition in August and September 2014, the EU sanctions impacted NIS jsc, and 2 Serbian banks, Sberbank Serbia and VTB Serbia, which are in fact subsidiaries of Russian banks Sberbank and VTB (Vneshtorgbank), which are subject to sanctions.

The paper explains that the possibility of NIS securing credit and financing has been adversely affected by the sanctions.

“This indirect effect of EU sanctions causes irreparable damage to NIS and places it at an unfairly disadvantageous position in comparison to any of its competitors in the EU, including those who are controlled by listed entities. Indeed, subsidiaries of listed entities within the EU are not subject to such restrictions”, the paper says.

Another argument contends that destabilising the Serbian economy is contrary to the EU’s commitment of cooperation to achieve reform under the EU-Serbia Stabilisation and Association Agreement.

By not allowing companies based in Serbia to have the same treatment as the EU-based subsidiaries of the sanctioned entities, the EU unintentionally destabilises the Serbian economy and goes against this commitment of cooperation to achieve economic reform, as enshrined in the Stabilisation and Association Agreement, the paper says.

One more argument used is that Serbia will not be able to meet the obligations arising from the Energy Community Treaty and the EU Accession Process.

“If Serbia’s largest energy company is unable to meet its EU obligations in good time, which would require a total investment of around €550 million, accession plans in the field of energy and environment might be derailed,” says the document.

Serbia proposes that any exemption that applies to the EU-registered subsidiary companies of the Russian entities listed in the sanctions legal texts should be extended to the subsidiary companies registered in candidate countries as well.

In the absence of such an agreement, the papers proposes as an alternative that the EU would allow certain specific authorisations to be granted by the member state competent authorities, in order to permit companies such as NIS to raise funding within the EU capital markets.

EurActiv asked the Commission to comment. The brief answer it gave is that decisions regarding restrictive measures (meaning sanctions) are taken by the member states by unanimity. This implies that candidate countries are not consulted in the process.

Shale gas potential in Turkey important for energy security

Shale gas potential could play a crucial part in terms of Turkey’s energy security.

While continuing its rise among the world markets, shale gas is turning the balance and prices of various markets upside down, and it also has a huge part to play in the U.S.’s economy. The World Energy Council and its project partner Accenture Strategy discloses with a report titled “Shale gas is a global phenomenon” how shale gas affects the world’s energy sector and what part it will play in the future. The report focuses on its pace of progress in different countries. The study also indicates that Turkey, Mexico, Saudi Arabia, South Africa and Poland have promising shale gas potential.

According to the report, despite price instability, its growth potential and speed are not just affecting the U.S., but also China, Argentina and Algeria, which have potential close to the U.S.’s regarding shale gas production.

World Energy Council Secretary General Christoph Frei stresses that shale gas will cause changes within the natural gas market dynamics that will last decades. According to Frei, the shale gas spreading fast around the world has accessible prices for consumers, and their concerns regarding the safety of the resources have decreased. “So far, the surprising resistance of the U.S. shale gas market has caused a burst in terms of its production. Even though other countries do not have the unique qualities of the United States, they will learn Liquefied Natural Gas [LNG] production and export, and this will change the global dynamics of the energy market,” Frei added.

World Energy Council Turkish National Committee Chair Murat Mercan indicated that Turkey still does not have the necessary technical equipment to search for shale gas, but they had works in progress regarding the issue. He also stressed that the shale gas potential, which would be unearthed after the necessary research, could play a crucial part in terms of Turkey’s energy security.

The “Shale gas is a global phenomenon” report indicates three global trends: First, because of the current price instability, the shareholders lead to more flexible and short-term investments rather that the deep drillings in the U.S. The second tendency shows the international growth of shale gas operators. By realizing the global opportunities, operators from all around the world lead markets such as China, Australia and Argentina, whose effect will reveal itself by 2020. The third and last tendency reveals the situations in the connected markets. Surplus in some countries has caused prices to stabilize, and also structural changes that cover the three regional centers of Asia, Europe and North America make them more global and transparent. The decrease in oil prices and Asia’s demand has caused a decrease in the price margin between Japanese LNG and British markets in 2016. Additionally, because of the developing domestic resources, the prices in the U.S. have also followed a low level.

GBC Oil takes over TransAtlantic Albania oil assets

TransAtlantic Holdings announced the completion of its divestiture of its Albanian oil assets, a summary of year-end 2015 reserves and its entry into a new master services agreement. Company entered into and closed a share purchase agreement with GBC Oil Company Ltd. (“GBC Oil”) for the sale of its Albanian oil assets.

On February 29, 2016, TransAtlantic Holdings, B.C. (“TAT Holdings”), a subsidiary of the Company, entered into and closed a Share Purchase Agreement (the “Purchase Agreement”) with GBC Oil.  Pursuant to the Purchase Agreement, TAT Holdings sold all of the equity interests in Stream Oil & Gas Ltd. (“Stream”), a subsidiary of TAT Holdings, to GBC Oil in exchange for (i) the future payment of $2.3 million to Raiffeisen Sh.A (“Raiffeisen”) to pay down a term loan facility (the “Term Loan Facility”) dated as of September 17, 2014 between Stream’s subsidiary, TransAtlantic Albania Ltd. (“TransAtlantic Albania”), and Raiffeisen, and (ii) the assumption of $29.2 million of liabilities owed by Stream, consisting of $23.1 million of accounts payable and accrued liabilities and $6.1 million of debt. In addition, GBC Oil issued a warrant to TAT Holdings pursuant to which TAT Holdings has the right to acquire up to 25% of the fully diluted equity interests in TransAtlantic Albania for nominal consideration at any time on or before March 1, 2019.

The Purchase Agreement contains representations, warranties, covenants and indemnification provisions customary for transactions of this type. In addition, TAT Holdings has indemnified GBC Oil and Stream for approximately $12.9 million of liabilities related to the Delvina gas operations, which may be assumed by a subsidiary of the Company as described below.

Pursuant to the Purchase Agreement, TransAtlantic Albania executed an assignment and assumption agreement pursuant to which TransAtlantic Albania will assign its Delvina gas assets and approximately $12.9 million of associated liabilities (the “Delvina Assets and Liabilities”) to Delvina Gas Company Ltd. (“DelvinaCo”), a newly formed, wholly-owned subsidiary of the Company, to be effective immediately upon receipt of required contractual and governmental consents and the expiration of required notice periods.  TAT Holdings and GBC Oil have agreed to use commercially reasonable efforts to obtain the required contractual and governmental consents for the assignment of the Delvina Assets and Liabilities.  There is no assurance that TAT Holdings will be able to obtain the required contractual and governmental consents.

The Company is currently negotiating a joint venture with a third party for the purchase of a portion of DelvinaCo.  There is no assurance that the Company will be able to complete a joint venture for the purchase of a portion of DelvinaCo.

Petroceltic reduces CAPEX in its Bulgaria exploration oil blocks

Petroceltic initiated a reduction in capital investment programmes in Bulgaria, and adjustments to reserves. Worldview Capital Management may takeover Petroceltic.

Petroceltic International PLC Monday it has been granted another debt repayment extension until later this month.

The latest extension runs until February 19, but the company reiterated its lenders have indicated they are willing to consider other waivers in the future whilst it conducts its strategic review.

Petroceltic initiated a formal strategic review of the business and its assets back in December as the company continued to struggle to make repayments under its senior bank facility due to a drop in oil prices, reduction in capital investment programmes in Egypt and Bulgaria, and adjustments to reserves.

A substantial shareholder in the company, Worldview Capital Management Ltd, said it was considering making a takeover bid for the company in January after campaigning aggressively for change at the top of the company.

Romania oil-gas concessions operated by OMV, MOL, Chevron, Lukoil

There are 463 concession agreements in Romania. Most of the perimeters are operated by Austria’s OMV Petrom and stateowned gas producer Romgaz. The state tendered 30 perimeters five years ago and Hungary’s MOL, US-based Chevron and Russia’s Lukoil were able to secure exploration and exploitation licenses for 20 fields. In the meantime, the government is looking Romania seeking new oil and gas investments.

With the current oil and gas reserves set to be depleted in the coming decades, Romania is looking to attract big oil majors that could unearth new deposits. However, this could prove to be challenging given the tumbling oil prices, which fell below USD 30 per barrel at the start of 2016.

Exploring the Black Sea

At present, the Ministry of Energy led by Victor Grigorescu is working on a new energy strategy for the 2016-2035 period. The government is looking to update the figures from a draft strategy published in 2014.
That document stated the energy sector needs around EUR 100 billion worth of investments by 2035. This money would be used for the construction of new production and distribution networks, as well for the overhaul of current energy-producing assets.

The draft strategy published two years ago stated that current oil reserves could be consumed in 23 years. For gas, reserves are set to be depleted in 14 years. The government has acknowledged that most of the proven oil reserves are located in onshore deposits, while just 4 percent are offshore.

With the country already grappling with falling production, oil majors have to take riskier investments to find new deposits. Specialists have warned that in a low oil price environment, new projects could be abandoned. Some oil majors have ventured into the Black Sea in search of new oil and gas re-sources, with several companies announcing initial discoveries of deposits, although it is still too early to say if they will be commercially viable.

Russia’s Lukoil, US-based PanAtlantic and Romgaz had all announced in the last quarter of 2015 that they found a Romanian gas deposit offshore. The initial estimates put the discovery at over 30 billion
bcm of gas, roughly enough to cover Romania’s domestic consumption for three years. More than three years earlier a consortium comprising of OMV Petrom and ExxonMobil said they had found a gas deposit of around 42 to 84 bcm in the Black Sea . The companies aim to invest up to USD 1 billion in offshore explorations.

New bidding round for oil fields remains uncertain

The last time Romania put up oil fields for tender concessions was in 2010. Since then investors have been waiting for the 11th bidding round, but nothing has happened in so far, although the National Agency for Mineral Resources, which is tasked with organizing the tender, had announced in early 2015 that new fields would be brought on the market .

At present, there are 463 concession agreements in Romania, according to data published by the Romanian Petroleum Exploration and Production Companies Association (ROPEPCA). Most of the perimeters are operated by Austria’s OMV Petrom and stateowned gas producer Romgaz. The state tendered 30 perimeters five years ago and Hungary’s MOL, US-based Chevron and Russia’s Lukoil were able to secure exploration and exploitation licenses for 20 fields. In the meantime, the government is looking Romania seeking new oil and gas investments.

With the current oil and gas reserves set to be depleted in the coming decades, Romania is looking to attract big oil majors that could unearth new deposits. However, this could prove to be challenging given the tumbling oil prices, which fell below USD 30 per barrel at the start of 2016.

Gazprom & Bank of China deal, first bilateral loan facility agreement with a Chinese bank

Gazprom is not the only large state-run company that has recently closed a multi-billion dollar loan from a Chinese bank; Petrobras, (ticker: PBR) the world’s most in-debt oil company, announced a $10 billion loan from the China Development Bank to help pay down its debt this year earlier this week. In exchange for the assistance in helping pay down debt, Petrobras will supply oil to Chinese companies.

Bank of China has agreed to loan Russian state-owned gas giant Gazprom (ticker: OGZPY) €2 billion ($2.17 billion). In the company’s press release, Gazprom said the loan was the largest deal in terms of the amount of financing attracted directly from one financial institution and the first bilateral loan facility agreement with a Chinese bank.

The deal is the latest in a string of agreements between Russia and China for more energy flowing east, as relations between Russia and the West continue to deteriorate over Ukraine. U.S. sanctions against Russia have cut its energy sector off from investment, forcing Russian oil and gas producers to increasingly turn their focus towards Asia.

The timing of the release, which followed news that the U.S. would extend sanctions against Russia, is also a public-relations message, Natalia Orlova, chief economist at Alfa Bank in Moscow, told The Wall Street Journal.

“Still, one shouldn’t expect that Chinese banks will replace the global capital market,” said Orlova.

Gazprom did not disclose the terms of the loan, which will likely be used for refinancing and is not huge for a company with an investment program around 10 times the size of the loan announced this week.

Russian companies, particularly Novatek, whose Yamal LNG project has been on hold while the company negotiates financing, have increasingly had to turn to China for money to help continue capital-intensive exploration. The loan given to Gazprom could be part of a larger plan to gain leverage over Russia for more favorable energy supplies as the Russia looks for funding outside of Western markets.

“China is sitting in an ambush waiting for Russian companies to get into a predicament and then save them on their own terms,” said Mikhail Krutikhin, partner at RusEnergy consulting firm.

Gazprom is not the only large state-run company that has recently closed a multi-billion dollar loan from a Chinese bank; Petrobras, (ticker: PBR) the world’s most in-debt oil company, announced a $10 billion loan from the China Development Bank to help pay down its debt this year earlier this week. In exchange for the assistance in helping pay down debt, Petrobras will supply oil to Chinese companies.

China has been lending to distressed companies in Latin America that are shut out of private debt markets. The loans appear to help China secure energy requirements on good terms.

Poland Baltic Gas project

The Baltic Gas Project involves the development of the B4 and B6 gas fields located in Poland’s exclusive economic zone in the Southern Baltic Sea. The fields are being developed by Baltic Gas Sp. z o.o. i Wspólnicy Spólka Komandytowa (Baltic Gas).

Baltic Gas is a special purpose vehicle formed by a joint venture comprising LOTOS Petrobaltic (51%) and CalEnergy Resources (49%). The joint venture was formed on 30 October 2012 in Gdansk and was approved on 9 April 2013. The offshore project received environmental approval on 16 May 2014 from the regional director for environmental protection.

The project is currently in the pre-final investment decision (FID) study phase with FID approval expected in the second half of 2016. First production from the development is planned for 2017 at a rate of 250 million cubic metres (mcm) a year.

B4 and B6 fields location

Located in the Baltic Sea, the B4 and B6 natural gas fields lie in the eastern part of the Polish exclusive economic zone. The B4 reservoir is situated at a depth of 1,100m below the sea level and is approximately 90km from the coastline. The B6 reservoir lies 1,450m below the sea level and is roughly 75km from the coastline.

Discovery and reserves

The two reservoirs were discovered in 1981-1982 during the exploration operations conducted by the International ‘Petrobaltic’ Joint Organisation for Oil Exploration. The B4 reservoir was discovered by drilling three boreholes, while the B6 reservoir was identified by drilling two boreholes.

The combined recoverable reserves of the fields are estimated to be 4bcm (149bcf). The recoverable reserves of B4 are estimated to be 1,972.4mcm and that of B6 are estimated to be 1,792.85mcm.

Baltic Gas project development details

The project includes reservoir drilling and borehole production of natural gas, construction of gas pipeline, and transporting the extracted gas first into the production system on the production rig and then to the hydrocarbon conversion system at the Wladyslawowo combined heat and power plant owned by Energobaltic.

The project will be developed in two phases with phase one consisting of the B6 field development. It will include the drilling of up to four production boreholes and setting the foundations for an unmanned production rig. A subsea gas pipeline will also be constructed to connect to the Wladyslawowo plant.

Phase two of the development will feature the B4 field involving the drilling of up to four production boreholes and installing an unmanned rig. An undersea gas pipeline will also be constructed to connect to the main production rig located on the B6 field where the extracted gas will be blended. The second phase is expected to start between 2022 and 2027.

Drilling operations

A total of four boreholes are planned to be drilled in each of the two fields that will include both vertical and horizontal boreholes. The maximum length of the vertical and horizontal sections is expected to be 3,000m for the B4 field and 3,100m for B6 field. The drilling will be performed by the Lotos Petrobaltic jack-up rig owned by Lotos Petrobaltic.

Subsea connection

An 85km-long DN250 subsea pipeline will be laid between the B6 field and the onshore plant, during the first phase of the development. A 33km-long DN150 pipeline will be laid in the second phase, to connect the B4 and B6 fields.

The pipelines will be installed in excavation made at the sea bottom and will be covered with sediments. The thickness of the protective layer will vary from 1m in the high seas to 3m while approaching land.

Contractors involved with the Baltic Gas project

A contract was awarded to Jacobs Engineering Group in February 2016 to conduct a pre-FID study for an onshore gas treatment plant for the project. The scope of work also includes preparing a cost estimate based on vendor quotations for the project to aid in the FID.

Subsea Engineering Associates was contracted in January 2016 for detailed design, procurement and construction management. The scope of work includes subsea pipelines, horizontal directional drilling (HDD) shore crossing, pre-lay and post-lay trenching, risers and platform tie-ins, as well as system engineering including reservoir to gas plant flow assurance.

Part of the Petrofac group, SPD entered a master services agreement in November 2014 to provide front-end engineering design (FEED) for the project.

Poland oil shale exploration, reality check for energy firms

Poland’s shale formations have attracted the most attention within the region. The nation depends heavily on coal, and what natural gas it does use comes almost exclusively from Russia. In the mid-2000s, the burgeoning US shale boom prompted Poland’s government to offer shale exploration licences that went to local companies as well as major international energy firms, including the US companies ExxonMobil and Chevron, and the French firm Total. Poland’s foreign minister, Radosław Sikorski, said in 2010 that Poland would become “a second Norway” — referring to Europe’s second-largest natural-gas producer, after Russia.

Over the past few years, fracking fever has swept through several European nations, including Denmark, Lithuania, Romania and especially Poland, which has seen more shale exploration than any other nation on the continent. Fracking might help to boost gas production in Europe at a time when it is facing a sharp decline. Older gas fields in the North Sea are running out, as are deposits in Germany, Italy and Romania. The disappointing output has increased Europe’s dependence on imported gas, mainly from Russia. European leaders have grown wary of relying on that source, especially after diplomatic relations chilled when Russia invaded Ukraine in 2014. But Europe’s appetite for gas could increase as it tries to cut greenhouse-gas emissions — which will probably require reducing coal consumption (see ‘Looming gas crunch?’). The European Commission says that “gas will be critical for the transformation of the energy system”.

This means that countries such as the United Kingdom have invested an immense amount of hope in shale gas. But a close examination of the industry suggests that any fracking boom in Europe is a long way off — and some experts say that it may never arrive.

Despite several years of exploratory drilling, there are currently no commercial shale-gas wells in Europe. Tests of the region’s shale potential have been limited, and the results so far have been generally disappointing, say geologists and energy experts. It remains highly uncertain how much gas would be recoverable with today’s technologies, and even more difficult to forecast how much would be profitable to extract.

All that leads to big questions about Europe’s shale hopes, says Jonathan Stern, a natural-gas expert at the Oxford Institute for Energy Studies in Oxford, UK. “There has been an enormous amount of ridiculous hype about shale gas in Europe.

A decade ago, the United States was facing a similarly dismal outlook for natural gas. Production from conventional fields was petering out, and geologists did not expect that alternative sources of gas could compensate for the shortfall. But within a few years, the picture suddenly brightened owing to improved drilling and fracking technologies, which tapped previously inaccessible gas reserves and unleashed a boom dubbed the shale revolution. Shale is almost impermeable to oil and gas, so companies must fracture the rock to liberate those hydrocarbons.

The idea that a similar wealth of untapped energy could be lurking in the rocks below Europe is economically appealing. But geologists know relatively little about the potential of shale-rock formations in Europe because there has been less onshore drilling than in the United States. European companies have sometimes drilled through shale to reach other rock formations, but they have rarely taken detailed measurements or collected samples of the shale layers.

So far, Poland’s shale formations have attracted the most attention within the region. The nation depends heavily on coal, and what natural gas it does use comes almost exclusively from Russia. In the mid-2000s, the burgeoning US shale boom prompted Poland’s government to offer shale exploration licences that went to local companies as well as major international energy firms, including the US companies ExxonMobil and Chevron, and the French firm Total. Poland’s foreign minister, Radosław Sikorski, said in 2010 that Poland would become “a second Norway” — referring to Europe’s second-largest natural-gas producer, after Russia.

The excitement was bolstered in 2011 by an assessment from Advanced Resources International (ARI), a consultancy in Washington DC that was commissioned by the US Department of Energy to study shale-gas resources worldwide. That study estimated the quantity of shale rock and other parameters such as the total organic content of the rock, which is the source of oil and gas. ARI also estimated parameters to represent the risk that some shale zones, or plays, might not prove promising or that only a portion of them might be amenable to drilling. Given these assumptions, ARI calculated that Poland’s shale-gas plays hold about 5,295 billion cubic metres (bcm) of technically recoverable gas, the most shale gas of any nation in Europe. If all of that gas could be extracted, it would be equivalent to 325 years of Poland’s current gas consumption¹.

While companies began drilling dozens of test wells in Poland, the Polish Geological Institute (PGI) in Warsaw made its own estimate in March 2012. Taking the considerable uncertainty over the data into account, the PGI calculated that Poland has 346–768 bcm of recoverable shale gas onshore — about one-tenth of ARI’s figure.

hen in July 2012, the US Geological Survey (USGS) released another study of Poland’s shale-gas resources. The agency assumed that individual wells would yield about half as much gas as the PGI assumed and that the area that is likely to contain recoverable gas is only about one-third of the size. So the USGS wound up with an estimate even smaller than the other two, with a mean result of just 38 bcm of recoverable gas, and a huge range of uncertainty, from 0 to 116 bcm. The mean was about one-tenth that of the PGI’s estimate, and about one-hundredth of ARI’s.

“One report — huge potential. A year later — nothing,” says PGI geologist Hubert Kiersnowski. “The scale of uncertainty is so big.”

Meanwhile, results started coming in from test wells. Of the 72 wells drilled by the end of 2015, 25 were successfully fracked to release gas. However, these wells yielded only about one-third to one-tenth of the flow that would be required to turn a profit, says petroleum geologist Paweł Poprawa of AGH University of Science and Technology in Krakow, Poland, and formerly of the PGI. None of the wells has become a commercial producer.

At the peak of interest in early 2013, companies held shale-drilling licences covering about one-third of Poland. But throughout 2013 and 2014, the major international energy firms gave up their shale-exploration licences and left the country, often citing disappointing results. The last to leave was Texas-based ConocoPhillips in June 2015 — now Poland’s shale drilling is almost at a standstill.

One major hurdle to development is that Poland’s shale is expensive to drill because it is buried around 3–5 kilometres down, compared with around 1–2 kilometres for most successful US plays. Some of Poland’s shale also has a high clay content, which makes the rock harder to fracture. And exploratory holes into one of Poland’s most promising shale formations — in the north, near the Baltic Sea — showed that it held a geological barrier that would limit how much gas could be tapped by individual wells, says Poprawa. The drilling results suggest that ARI “overestimated the acreage, the thickness, and the quality of the shale”, he says.

The PGI says that its previous lower estimates are reinforced by its latest, as-yet-unpublished assessment, which draws on recent shale-drilling tests. PGI spokesperson Andrzej Rudnicki calls ARI’s much higher estimates “enthusiastic, but geologically unrealistic”.

The results in Poland to date indeed have been disappointing,” concedes geologist Scott Stevens of ARI. He says that the main reason for the unproductive wells was “extremely high” stresses in the rock, which makes fracking less effective. “There was no way that the exploration companies could know that in advance,” he notes. Nonetheless, he argues, “It is too soon to dismiss Poland’s extensive shale potential.” Given the limited available data, he does not see a reason to revise ARI’s estimate.

Even the PGI’s lower estimates suggest that there is a still a substantial amount of gas trapped in Poland’s shale. However, it is uncertain whether any of that gas will be profitable to extract. “I am still hopeful,” Poprawa says. “But the initial hopes were not realistic.”

Although companies raced to grab concessions in Poland, activity in the United Kingdom has been subdued. In 2011, Cuadrilla Resources fracked the United Kingdom’s first shale well near Blackpool in northern England, but this triggered two small earthquakes, which led the government to place a year-long moratorium on further fracking. After the moratorium lifted, companies slowly began vying to tap UK shale.

According to a 2013 assessment by ARI, UK shale holds 17,600 bcm of gas. Only 728 bcm of this is judged to be technically recoverable: if that could be profitably extracted, it would satisfy the United Kingdom’s gas needs for about a decade⁴.

The British Geological Survey (BGS) has assessed the shale-gas resources in the United Kingdom’s three major plays by constructing a 3D model of the subsurface using drilling records and seismic surveys, which has allowed it to roughly estimate the volume of shale rock. But geologist Ian Andrews of the BGS insists that this estimate is just a first pass based on the seismic information available, “which is sparse, and fairly poor”.

By testing old rock cores stored by the government, the BGS was also able to measure some of the properties of UK shale, such as the total organic carbon (TOC) content. Successful shale plays in the United States typically have TOC values greater than 2%. Although TOC measurements for the United Kingdom are scant, the available data suggest that there are large volumes of rock above the 2% threshold. But data are lacking for other key parameters, such as the rock porosity, which adds greatly to the uncertainty of these projections.

The BGS estimated that the three shale plays it has assessed so far hold around 39,900 bcm of gas, with an uncertainty range of 24,700–68,400 bcm. This is more than the ARI estimate, but that study only considered the most promising rock. The BGS did not attempt to estimate how much of that gas would be technically recoverable. “How much we can get out of the ground, I don’t think anybody knows yet, because the drilling hasn’t happened to test it,” says Andrews.

Although the BGS’s studies used US shale plays as analogues for crucial parameters, the two nations have different geological histories. The United States has large deposits of shale that are not too thick and have been folded little over time. The shale in the United Kingdom is more complicated, says petroleum geoscientist Andrew Aplin of the University of Durham, UK. “It’s been screwed around with more”, creating more folds and faults.

That greater complexity could pose challenges. One risk is that pumping fluid into rock can trigger earthquakes if the wells are near faults or large natural fractures. “It’s better to stay away from them, especially when they’re located near densely populated areas,” says natural-gas expert Rene Peters of the Netherlands Organisation for Applied Scientific Research (TNO) in the Hague. But there has been relatively little high-resolution seismic imaging in Europe, he says, so “not all these fractures are known”. Small faults can pose another challenge. If the fracking fluid leaks into a fault, the pressure on the rock is reduced and the fracking is less effective. Given the geological hurdles and the United Kingdom’s dense population, it may prove difficult to find many promising, acceptable places to drill.

nature.com