From the coal beds of Indonesia to oil and gas fields throughout Europe, Sam Wahab of the London-based investment firm Seymour Pierce is a master at spotting investment opportunities in the topsy-turvy world of fluctuating energy prices. In this interview with The Energy Report, he deftly defines the structural problems affecting gas and coal markets, while identifying some plays that demonstrate the savvy to come out on top.
The Energy Report: Sam, with natural gas production stalling in North America, where can investors find good deals in the junior exploration space?
Sam Wahab: Gas exploration in the U.S., especially of the unconventional type, has resulted in diminishing Henry Hub spot prices. Nevertheless, gas exploration on a global scale remains strong. The key reason is that gas prices in Europe and Asia are underpinned by robust consumer demand and the need for energy security.
A clear example is in Central and Eastern Europe, where Gazprom (OTC:OGZRY) has a strong monopoly on gas supply despite a plethora of untapped resources. Many of the governments in these countries [Poland, Romania, Ukraine, etc.] are now incentivizing junior domestic players through undemanding fiscal terms to prove up these resources to secure energy self-sufficiency. In return, these junior companies enjoy gas prices far in excess of the Henry Hub, which is about $3 per thousand cubic feet [Mcf].
The Romanian gas market is slated to deregulate its gas prices next year. That should bring it inside the European average of $8-13/Mcf. We have a Buy recommendation on Hawkley Oil & Gas Ltd., an Australia-listed company that owns and operates Ukrainian assets. It was getting $11.80/Mcf, which is a fourfold multiple to the Henry Hub. Our target price for Hawkley is $0.72/share. Other beneficiaries of this type of price movement in Europe include Zeta Petroleum Plc, Aurelian Oil & Gas Plc (OTC:AROGF) and San Leon Energy Plc (OTC:SLGYF), which is merging into Aurelian.
Another interesting proposition for investors, in my view, is the growing interest in the supply of regassified liquid natural gas [LNG] to gas-starved West African markets. To clarify, LNG is natural gas that has been converted to liquid form for ease of storage or transport. Regasification is the process of returning the LNG to natural gas prior to distribution.
London-listed Gasol Plc (OTC:GASOF) is looking to service this growing demand by securing sales agreements with LNG suppliers and national governments for fixed periods. LNG cargoes will be delivered to a floating LNG regasification facility, which will then either pipe gas to nearby industry or power generation facilities.
TER: Are the explorers that you cover focused on finding and developing gas-producing properties that they can hold onto as income producers, or are they typically more interested in selling their properties to a major corporation once the resources are proved out?
SW: That's a very good question and the answer will strongly depend on the individual management team, their strategy and the diversification of the company's asset portfolio. It is extremely difficult for a junior gas explorer to prove up and commercialize an asset alone, given the significant financial and technical resource base necessary to do so. We often see juniors acquire an asset, shoot seismic and potentially drill one or two exploration wells, at which point they have sufficiently derisked the acreage to attract a partner to assist in bringing the asset through field development.
TER: Indonesia is a microcosm of East Asian energy development. It is balancing its domestic needs against export demands and it enters into production-sharing contracts between the government and the CBM explorers that bear the burden of derisking the gas fields. Where is the margin in this type of public-private venture?
SW: The country's natural gas market is characterized by a declining supply of conventional gas and a rapidly growing domestic market with a large export segment. A clear margin exists where the domestic gas price is between $5-11/Mcf, whereas the export prices go as high as $15/Mcf.
It turns out that 50% of Indonesia's gas is exported to North Asian markets in the form of LNG-down from 62% during the past decade. So a declining conventional gas production combined with driving domestic gas consumption is crimping Indonesia's ability to meet its own LNG export obligations and its ability to capitalize on the high gas prices in North Asia. Meanwhile, domestic consumption has risen over 100% during the last 10 years. That's largely a function of Indonesia's strong economic growth, which is headed toward a gross domestic product of $1 trillion this year.
Looming shortage of supply is causing the Indonesian government to support public-private CBM development projects with incentivized production-sharing contracts [PSCs]. The terms allow contractors to take 40-45% on an after-tax basis-higher than the industry average. The capital requirements for CBM exploration, which is classed as unconventional, are low-between $2.5-3 million [$2.5-3M] to acquire a production-sharing agreement and up to $4-6M to complete the exploration phase. The risk and costs are low with the potential for high returns. The situation has set off a bit of a land grab in Indonesia.
TER: What other companies are focused on CBM exploration?
SW: Companies active in CBM exploration in Indonesia include BP Plc (NYSE:BP), Dart Energy Ltd. (OTC:DEGEF), Exxon Mobil Corp. (NYSE:XOM), Santos (OTCPK:STOSF) and Total. Whilst in our view Dart Energy has the most compelling investment case at the moment, we would expect more entrants into this particular market given the low cost of drilling and access to existing infrastructure.
The Australian CBM industry is mature. Between 2003 and 2011, Australia's CBM industry consolidated through 33 mergers of small, independent operators with a value of over 30 billion Aussie dollars. I believe a similar consolidation could occur in Indonesia as acquirers of Australian CBM assets such as Total and Santos, which are active in Indonesia, look to pick up small companies.
TER: Let's talk about CBM drilling for a moment. How does it differ from conventional gas drilling?
SW: Coal bed methane is a byproduct of the coal formation process. It's chemically identical to other sources of natural gas, but it's cleaner than hydrogen sulphide. In the reservoirs, the methane is absorbed into the coal surface-held tightly in place by a layer of water. Drilling a production well releases the water pressure in the coal stream, allowing the gas to float to the surface following the water. The wells are shallow, less than 1,000 meters down to the gas-rich stream. Remarkably, such a well can be drilled and completed in less than 48 hours.
TER: When a major is looking at CBM juniors, what metrics do they require?
SW: The effects of the U.S. shale boom on the Henry Hub have led many majors to deploy their technical resource base in extracting unconventional resources in high spot-price environments. They are constantly on the lookout for sufficiently derisked assets, made through a combination of seismic and drilling activity. They want to take a significant equity portion, and they want the asset to be located in geopolitically stable regions with a strong demand or sufficient infrastructure in place so that they can easily export the hydrocarbons. If most of these boxes are checked, there is a good chance that a major will show interest in a junior oil and gas company.
Recently, BP divested many of its non-operating gas interests in the North Sea, while increasing its presence in West Africa. It has just farmed in to Chariot Oil & Gas Ltd. (OTCPK:OIGLF) block. Exxon exited many of its Polish shale concessions in favor of the reported interests in onshore United Kingdom shale by Egdon Resources Plc. The U.K. government has lifted a suspension on fracking in the U.K. Now Exxon is interested in some of the onshore U.K. assets. Egdon Resources could be a key benefactor.
TER: Nonetheless, share prices for many gas explorers are not very robust. Why?
SW: Historically, gas prices have been linked to oil prices. Starting with the U.S. shale boom, we have seen a divergence-oil prices have remained strong, while gas prices have generally fallen. However, contract prices for drilling infrastructure such as rig equipment and personnel continue to be linked to oil prices. The upshot is that gas exploration has become increasingly less viable.
There have also been a number of micro-economic events that affected individual companies and regions. The difficulty in employing extraction methods in Central Europe using similar techniques as those in North America arises from the significant differences in the geological makeup. This has led to disappointing exploration performance.
TER: Are there limits to the supply of natural gas that can be profitably brought to market?
SW: The movement of the gas market is largely randomized on a macro level. Shifts in supply and demand are being dictated by economic growth in emerging economies and continued productivity from existing and untapped resources. It's fairly unpredictable.
But in the near term, gas prices will be dictated by the aggressive use of gas in China and India from their growing economies, which will push prices on a global scale. As will the discovery and utilization of gas resources in Latin America-an up-and-coming region with a huge, untapped potential for natural gas. There is a move away from nuclear power in Japan and some European countries in response to the nuclear incident in Fukushima. And Europe is continuing to process policies requiring greenhouse gas emissions reductions. That could hinder direct gas exploration there.
In Russia, however, people are slowly chipping away at Gazprom's monopoly. In response, it is looking to regasify the Far Eastern region, which could also push prices. Generally, the ongoing search for shale and other unconventional gas will dictate the global gas price regime. In the U.S., though, the low Henry Hub price could result in a lot less drilling for gas and more of a focus toward oil production, which could drive gas prices back up.
TER: Thanks very much, Sam.
SW: Many thanks, Peter.
Sam Wahab began his career at PricewaterhouseCoopers (NYSEARCA:PWC), where he qualified as a prize-winning chartered accountant. On PwC's energy team, he specialized in assurance and transaction advisory. His clients including Royal Dutch Shell and JKX Oil & Gas. Following a spell in the oil and gas research team at Arbuthnot Securities, Wahab joined Seymour Pierce in 2011. He heads up oil and gas equity research at the firm. His coverage includes companies with global operations on multiple stock exchanges.
1) Peter Byrne of The Energy Report conducted this interview. He personally and/or his family own shares of the following companies mentioned in this interview: None.
2) The following companies mentioned in the interview are sponsors of The Energy Report: None. Interviews are edited for clarity.
3) Sam Wahab: I personally and/or my family own shares of the following companies mentioned in this interview: None. I personally and/or my family am paid by the following companies mentioned in this interview: None. I was not paid by Streetwise Reports for participating in this interview.
Disclosure: I have no positions in any stocks mentioned, and no plans to initiate any positions within the next 72 hours. I wrote this article myself, and it expresses my own opinions. I am not receiving compensation for it. I have no business relationship with any company whose stock is mentioned in this article.