If there were a moment demanding a breakthrough in unconventional resource plays in Europe, recent events could scarcely have made the current time more opportune. Natural gas supplies to Ukraine have been halted by Russia amid conflicts along the Ukraine-Russia border. European-based manufacturers of chemicals, fertilizer, ceramics, glass and more are under extreme pressure from North American competitors that have access to gas supplies at half the price.

And there is no shortage of incentives in terms of self-interest. Having earlier led the land rush for unconventional resource acreage, Poland still relies on imported gas--mainly from Russia--for about two-thirds of its supplies. The U.K. now imports 50% or more of its natural gas, exacerbated by North Sea declines, and may be headed to 70% dependence on imports by 2020, according to Centrica, a U.K.-based diversified energy supplier.

Even as progress remains protracted, perhaps the best hopes of unlocking the unconventional resource base of Europe still lie with the U.K. and Poland. Some even speculate that if it were possible to demonstrate commercial gas flows in these two countries--at the western and eastern “bookends” of Europe--the development of unconventional resources in areas in between might be sparked, perhaps even in France, which currently restricts fracking.

But sentiment has been mixed. In the U.K. it has tracked higher--in some cases a lot higher--while Poland has strained for a catalyst after operators suffered lengthy delays and only of late have lined up key wells. Until recently, the challenges facing the industry left analysts far from upbeat. A report by Tudor Pickering Holt & Co. last November gave the U.K.’s Bowland Basin a “Hold” rating. Poland’s Baltic Basin was a “Sell,” according to the report, which noted that certain majors had exited Poland and some initial well results had disappointed.

More recently, however, consolidation in the U.K., as well as earlier farm-out announcements, have spurred optimism. In addition, the U.K. government is set to announce the 14th onshore licensing round, which some speculate may spark further interest from the majors.

Onshore independent IGas Energy Plc, London, announced in May that it agreed to acquire Australia-based Dart Energy Ltd., creating “a market-leading onshore U.K. oil and gas company with over one million net acres.” With its acquisition, due to close in late September, IGas jumped ahead of Cuadrilla Resources as the No. 1 holder of acreage prospective for shale gas in the U.K. Another consolidation in May involved the purchase by Egdon Resources Plc of the onshore shale gas assets and business of Alkane Energy Plc, resulting in a 90% increase in Egdon’s shale gas exploration acreage.

The two transactions followed a farm-out agreement struck this past January between French integrated Total SA and several of the independents pursuing unconventional resource plays. Terms called for a U.K. subsidiary of Total to fund a fully carried work program of up to $46.5 million, with a minimum commitment of $19.5 million. In return, Total would earn a 40% interest in two U.K. onshore petroleum exploration and development licenses, PEDL139 and PEDL140, bordering an existing field operated by IGas.

Work under the farm-out agreement includes shooting 3-D seismic; drilling and testing a vertical exploration well and associated well pad construction; and, subject to successful test results from the exploration well, the drilling of a horizontal appraisal well. Post-deal, those holding an interest in the two licenses are: Total, with 40%; subsidiaries of Dart Energy and IGas, with 17.5% and 15.5%, respectively; Egdon Resources, with 14.5%; and independent eCorp Oil & Gas U.K., with 13.5%. Clearly, the sector is gaining momentum, with other farm-in agreements having been negotiated earlier by France’s GDF Suez with Dart Energy, and by Centrica with Cuadrilla.

The fundamentals

What of the geology and other factors underpinning the U.K. unconventional resource base that helped bring this burst of business to the fore?

John Blaymires is COO of IGas, whose early roots as a company were in coalbed methane. At the announcement of the Dart acquisition, production by IGas was close to 3,000 barrels of oil equivalent per day (boe/d) solely from conventional assets. With IGas now focused equally on unconventional opportunities, it is the thickness of the target interval in the U.K. that Blaymire highlights as most noteworthy.

“The exciting aspect of the carboniferous Bowland-Hodder shales is the thickness of the shale, which can be in excess of 3,000 feet, coupled with good indications of gas and reasonable total organic carbon [TOC] values,” said Blaymires, referring to the shale potential in northern England. “However, we are only at the very early stages of understanding the play. Whether the full sequence of the shale is productive remains to be seen. The likelihood is that not all of the shale sequence will be brittle enough to go after.”

The U.K. industry’s first--and as yet only--Bowland Shale well to have been fracked was a vertical well, Preese Hall-1, drilled by Cuadrilla in Lancashire in northwest England. The well initially flowed more than 1 million cubic feet per day (MMcf/day), according to a presentation by a Cuadrilla shareholder, A.J. Lucas, even as only five of the planned 12 frack stages were operational. Operations were halted after some minor seismicity, or small earthquakes, were induced.

A recent report by Macquarie Capital (Europe) Ltd. said the flow rate exceeded its assumptions.

“Industry experts have discussed this result as encouraging considering that, looking at the U.S. shale plays, a horizontal well can achieve a flow rate of seven to 15 times higher, equivalent to an initial production [IP] rate for a fracked horizontal well of 7 to 15 million cubic feet per day, which compares to our IP range assumption used in our economic model scenarios of 5 to 8 million per day,” said the May report by Macquarie.

“For a vertical well, with a limited number of frack stages, I think that this was an encouraging result, particularly for the very first well to have been fracked,” commented Blaymires.

He is quick to acknowledge multiple challenges to developing the U.K.'s unconventional resource potential--not least, its denser population and more limited access to land. But he points to such potentially offsetting positives as a higher natural gas price, typically equivalent to $8 to $11/Mcf; the proximity to key markets by way of an existing infrastructure; and supportive government policies designed to at least “streamline” the regulatory framework and encourage shale development.

The key to successful development in the U.K., he said, lies in the greater “resource density” accompanying the thicker interval found in the Bowland Shale, for example. As compared to a typical U.S. estimate of gas-in-place (GIP) of around 200 to 250 Bcf per section, the Bowland GIP estimate should be “well north of that. I’ve seen figures cited of up to 1.4 trillion cubic feet [Tcf] per section,” he said.

Due to the thicker interval, “you have a higher resource density per square mile than in the U.S. In terms of development, you may not be able to drill as extensively and with as many pads as in the U.S., because of the U.K.’s denser population and limited access to land,” Blaymires said. “But from a single pad with multiple laterals you’re tapping into a much thicker resource density, and so the revenue and the economics of each pad are potentially enhanced as a result.”

Models developed

Models for several development options have been constructed using drilling in the Bowland Basin in Lancashire as an example. The Institute of Directors in the U.K., for example, has modeled a 10-well pad with each wellbore having four laterals--for a total of 40 laterals--due to the unusually thick productive interval anticipated in the Bowland Basin. Cost per lateral is estimated at 6 million pounds, or US$10.2 million at an exchange rate of $1.70, with facilities costs estimated at $50.1 million. Abandonment costs are estimated at $68 million.

Reserves produced over the lifespan of the single-pad development are put at 126 Bcf. Total costs (capex and operating expenses over project life) are estimated at $873.8 million.

A British Geological Survey report issued in June 2013 estimated a midcase scenario of total GIP for the Bowland Shale alone of 1,329 Tcf—or 130 Tcf assuming a 10% recovery factor. Does this mean all systems are go? Are the U.K. industry’s first horizontal wells imminent?

“With only a handful of shale wells drilled, we’re right at the early stages of understanding this,” said Blaymires. “The supply chain is at present limited,” with few rigs that meet European Union regulations and are suited to drilling horizontal shale wells. “And in terms of frack spreads, you can virtually count them on one hand. Currently, there is a limitation on how quickly you can ramp up.”

Preceding drilling, companies must apply for and observe a “very tight-writ regulatory regime,” as well as participate in a lengthy period of community engagement. “Ultimately, I think it is beneficial in terms of giving the public some reassurance. It’s vital to build and develop that trust. But the time scales to get things done can be drawn out as a consequence of the various consultations and processes we have to go through.”

This is an area that was highlighted as being ripe for streamlining, without reducing effective regulatory oversight, in a House of Lords Economic Affairs Committee report on the economic impact of shale on the U.K. energy policy, issued this past May.

Still, 2015 appears to be shaping up as an important year for both IGas and Cuadrilla.

Cuadrilla has submitted a planning application for its Preston New Road shale gas exploration site in the Bowland Shale, where it plans to drill four horizontal wells. Having begun the application process in mid-2013, and assuming no legal challenges, the company expects operations to begin sometime in 2015. Cuadrilla plans to apply for a second exploration site at Roseacre Wood, also in Lancashire.

"For IGas, our intent is to frack one or two wells next year, although it will all depend on securing all the relevant permitting,” said Blaymires. With that caveat, “there’s a reasonable chance that the wells to be drilled will be on either side of the Pennines,” he added, referring to the range of mountains running north and south that are called the “backbone of England.” This would also allow valuable geologic data to be gathered in more than a single basin, accelerating evaluation of the wider potential.

In the northwest of England, pro forma for the acquisition of Dart, IGas has estimated net GIP of some 125 Tcf, making this area in the Bowland Basin its largest in terms of potential reserves. In the East Midlands, where Total has farmed in to PEDL139 and PEDL140 in the Gainsborough Trough in Lincolnshire, IGas has pro forma net GIP of 25 Tcf. Importantly, IGas would benefit from whatever well data is obtained as a result of drilling under the Total farm-in.

“2015 will be an exciting year in terms of demonstrating the potential for commercial shale gas development in the U.K.,” Blaymires said.

Based in London, Hutton Energy, with activity in Poland, France, the Netherlands and Spain, has an international perspective on unconventional resource development. Its most significant assets are in Poland, where it holds approximately 1.7 million acres spanning the Baltic, Jurassic and Permian basins. Hutton is privately owned, with Macquarie Bank a significant shareholder.

“Our job as operators in Europe is to be conscious that we are operating in a global market, and that opportunities that we put up need to be competitive,” said managing director David Messina. “Europe is getting as close to being able to check those boxes as it probably has ever been. We’re hoping to start seeing some of that happen in Poland over the next six to 12 months."

Messina contrasts how events have unfolded in Poland compared to the U.K. In the latter, helped by an improved fiscal and regulatory environment--plus several farm-in agreements--sentiment has moved from “negative 18 months ago to positive now,” he said. Meanwhile, investor interest in Poland has been declining, in part because Poland received much of the early attention focused on the land rush around resource plays, especially the Baltic Basin shale play, and is now paying a price.

“Poland had a bit of a head start,” recalled Messina. “But with that head start comes some baggage. And, unfortunately, the baggage is that the early investors in those companies expected results in two to three years. And it’s not happened; it’s taking three to five years. And I think the U.K. companies are benefitting in that the companies coming in are slightly more informed than the initial investors coming into the Polish companies.”

Polish inflection point

However, the opportunity for an inflection point lies on the horizon, with results from three horizontal wells being drilled by different operators in the Baltic Basin due to be released in the second half of this year. They are 3Legs Resources’ LEP-1 sidetrack; BNK Petroleum’s Gapowo B-1, which has already been fracked; and a long lateral well by San Leon Energy at its Lewino location.

“The information from these three wells, certainly in the short term, will go a long way to giving us a glimpse into what the potential may be for the Baltic Basin play,” said Messina. “If you get a flow rate that at current drilling and completion costs and at current gas prices looks interesting, then I think we’ll see a lot of activity toward the end of this year with people looking to take positions alongside the existing companies. Whether that trigger point is 1, 2, 3 or 4 million per day is going to vary by company, depending on their appetite for risk.”

Messina said Hutton is having more discussions with U.S. independents about European opportunities than in the past several years. “They still need to gain conviction there is a development opportunity here, because that’s the key to getting the costs down,” he said. “But if any of these wells come in at a reasonable level, I would expect an asset reset almost overnight, and then a significant increase in farm-in activity as a result.”

While investor attention tends to focus on the Baltic Basin--an area where Hutton also has considerable exposure--Messina is quick to point out that Poland has a much broader, more complex opportunity than just the Baltic Basin. “When I look at Poland, I look at three or four different plays, and they all have their risk and reward profiles,” he said. “It has a lot more potential than perhaps people are giving it credit for, if they are just reading a headline ‘shale taking longer than expected.'"

Work on unconventional plays is having the added benefit of uncovering “multi-opportunity plays” comprised of both unconventional and conventional opportunities, according to Messina. In terms of short-term projects targeted for second-half 2014, Hutton plans further drilling at a gas prospect in the Permian, as well as drilling in two areas prospective for oil in the Jurassic Shale under an anticipated farm-in. Although conventional, both prospects require some stimulation.

For 3Legs Resources, which operates in Poland through a joint venture with ConocoPhillips called Lane Energy Poland, the third quarter of 2014 is of key importance in terms of wells results. Its Lublewo lateral well has been drilled, cased and cemented, and a stimulation program comprising 20 stages or more is scheduled to be completed in the third quarter. It is the third lateral well, and seventh overall well, drilled by Lane Energy in the Baltic Basin and marks the conclusion of the 2013 to 2014 programs.

“The key thing on our acreage is: ‘Can we flow gas from it at commercial rates?” said Kamlesh Parmar, CEO of 3Legs. Having earlier demonstrated gas-in-place on the acreage, and being able to flow gas at rates that are subcommercial, “that’s the only thing my investors are interested in now. They want to know:‘Can you produce enough gas to sell it? Is this a viable project?’ And that’s what we need to prove up now. ”

What rate would push through that commerciality threshold?

“I would argue we would need a 30-day rate in excess of 1.5 to 2 MMcf per day,” said Parmar, noting that this would mark a significant improvement from the company’s prior lateral well, Lebien LE-2H, which flowed at a 30-day rate of about 0.55 MMcf/d. “It’s going to be pretty critical for us.”

There are encouraging signs. The targeted Sasino Shale, with an estimated thickness of some 82 to 98 feet in 3Legs’ high-graded area, proved relatively consistent in terms of lithology and lack of faulting, and “strong gas shows” were seen throughout the lateral length of just over 4,921 feet. “We kept the well in zone,” said Parmar. “We had a nice quiet zone to work with; the zone did what we expected it to do.”

Assuming favorable well results, the next step would be an appraisal program with wells at multiple locations. “Working out the size of the play is important, because that will determine what you do,” said Parmar. In a three-block high-graded area, “do we have 300,000 acres in a good play, or do we have 3,000 acres? We think the former, but let’s see.”

Pending results--due at some point in the third quarter—3Legs’ stock reflects the extent to which the investment community has begun to question whether unconventional resources plays will work in Poland. As compared to three years ago, said Parmar, sentiment has overshot from “extreme optimism to now extreme bearishness.”

After backing out the net costs of the current work program, including the stimulation program at Leblewo, 3Legs’ remaining cash is estimated at 17 million pounds (some US$29 million), or about 20 pence (about 43 cents) per share. With 3Legs carrying no debt and the stock trading below 25 pence (about 43 cents) per share, “very little value is being ascribed to the acreage,” observed Parmar. In a success case, “I would expect a significant hike from where we are trading today. What that hike looks like is not something I can control.”

Wolf Regener, CEO of BNK Petroleum, echoed similar themes as the company, at press time, approached completing tests on its recently fracked Gapowo B-1. BNK holds 715,000 net acres in Poland, having relin- quished some acreage and focused its activity on three main blocks in the Baltic Basin. Of five vertical wells drilled by BNK in Poland, the Gapowo is the first to have a horizontal leg.

“Everyone from investors to potential joint venture partners are at the stage of ‘show me the gas,’” said Regener. “They all know the gas is in place, and they want to know what kind of flow we can get.”

BNK planned to initially frack about one-third of some 30 stages in the Gapowo well. Due to an issue in effectively stimulating the toe end of the well, BNK expanded the initial program to the entire lateral, with nine stages deemed to have been effectively stimulated. An initial flow rate--as measured by gas flow per frack stage--will serve as an indicator of well productivity, according to Regener.

What sort of production is needed to be commercial?

We believe we have to be somewhere in that 2.5 to 3 MMcf/d on a full lateral to be economic in the future,” said Regener, adding that much would depend on the as yet unknown decline curve of the well. It might be 3 MMcf/d for an IP rate or 2.5 MMcf/d for a 30-day rate, he noted, but it will depend on the decline curve. Using this guideline, and assuming 35 frack stages in a normal lateral, an IP of around 0.75 MMcf/d would be a target for a well with nine stages, such as the Gapowo, to hit.

“We do feel we’ve got a good stimulation on enough of the lateral to see what it will do,” said Regener.

“If we can get a good flow rate here, our plan would be to drill a few development wells over the next 18 months to prove up the areal extent of the play. The better the well, the better the potential for getting a favorable farmout agreement,” he said, adding that BNK would be looking for partners in its Bytow block, where the Gapowo well is located, as well as in the eastern part of its Trezbielino block.

In the meantime, according to Regener, investors “are not giving much credit for anything we’re doing in Europe.” A Macquarie report issued in late March on BNK carries a 12-month target price of CA$4 per share, based solely on its U.S. assets, while the stock has recently traded in Canada in a range of CA$1.50 to $1.75. Using strip pricing as of last March, BNK’s core net asset value for the company’s Oklahoma assets (proved plus probable reserves, plus net cash and warrant proceeds) is estimated at CA$1.25 per share, with risked exploration potential adding a further CA$2.75 per share. The report assumes no contribution from the company’s Polish assets in its CA$4 target.

“Not a lot of people are paying attention to what we’re doing in Europe,” said Regener. “But others see the value in the U.S. and say this is a ‘free option’ on what BNK is doing in Europe.”

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