Source: Tom Armistead of The Energy Report (12/12/13)
http://www.theenergyreport.com/pub/na/has-shale-broken-opecs-grip-peter-dupont-names-powerhouses-of-the-future
The Shale Age is the age of the nimble junior, and exploration has revealed oil and gas resources that could forever alter the global production profile. Peter Dupont, oil and gas analyst for Edison Investment Research, tells The Energy Report how companies in North and South America, Australia, Africa and the U.K. are upending the oil and gas order and creating a whole new energy investment landscape. 
The Energy Report: The price of Brent is holding steady above $100/barrel ($100/bbl) while West Texas Intermediate’s (WTI) price is slipping back into the $90s. How are these prices and the spread between them affecting exploration and production of oil and gas?
Peter Dupont: Over $100/bbl for Brent is still a pretty good price in terms of potential profitability for most companies. If the price of WTI should drop significantly below $90/bbl, then a question mark begins to arise over drilling activity.
Bear in mind, though, that the price structure in North America for other onshore grades at the moment is discounted to WTI. The Bakken price has recently been $15/bbl less than WTI. It’s beginning to move into an area where many people think low prices could, at some stage, trigger a decline in drilling activity. I don’t think we’re there yet; I think the decline has to be sustained for a period of time. Prices north of $80/bbl for Bakken and $90-plus for WTI are still really attractive for developers.
TER: Are these spreads caused by transportation challenges? Do you foresee the spread increasing or do you think it will level off as producers find ways to move more oil to consumers?
PD: A few months back, most people thought the U.S. supply/demand issue had been brought into equilibrium because the differential between WTI and Brent dropped to $4/bbl or less. On some days in Q3/13, there was almost no differential. Lately, the spread has widened. One factor has been a decline in refiner demand for crude. That’s partly seasonal, of course, and related to maintenance activities. I would expect the refinery utilization rate to rise; it already has from the low point.
Oil production is still very buoyant in the U.S. and I expect that trend to continue. Near term, we’re looking at a spread that might be a bit larger than we expected a few months ago. On average for next year, I’d expect a Brent/WTI differential somewhere in the high single digits, assuming there are no big weather factors or major unplanned refinery outages. Those would be the wild cards.
Also interesting is the big spread that has opened up on the Gulf Coast between Brent and Louisiana Light Sweet crude (LLS). LLS has moved from an historical premium of a dollar or so per barrel to a discount of about $10/bbl. It reflects the fact that surplus oil is being shifted to the coast now that the Cushing bottleneck has been alleviated. The U.S. oil price on the coast is now substantially below international levels.
TER: What are some companies that are taking advantage of the shifts we’re seeing today?
PD: The big advantage is for refiners because they’re getting oil that is very competitively priced from a global perspective.
TER: What are some of the refineries that you’ve been watching?
PD: They’re all well-known companies. HollyFrontier Corp. (HFC:NYSE) is one of the big inland refineries. The Tesoro Corp. (TSO:NYSE) refinery in North Dakota also has a pretty big advantage. I’m beginning to see an advantage for coastal refineries as well, because with the big discount now opening up for domestic crude, they are receiving internationally competitive crude net of transportation costs. Competitively priced oil is beginning to come into West Coast refineries and Atlantic Coast refineries. The refineries that are really benefiting, however, are those in the Midwest and Mid-Continent. That would include the refining complexes in the Chicago, St Louis and Detroit areas and increasingly along the Gulf Coast.
TER: So, is this a good time to be looking outside the U.S. at companies that are leveraged overseas?
PD: There has been a drop in international oil prices as well. Until late November, we were looking at light crude prices significantly below $110/barrel. However, with light crude prices over $100/bbl, producing oil is still a pretty profitable business in most cases.
If you’re an oil producer, you’re a price taker. The big argument becomes whether the price starts to drop toward what’s called the long-run marginal cost, which includes all the capital costs in addition to operating costs, royalties and taxes.
If the price in the U.S. drops south of $80/bbl, and particularly south of $70/bbl, then drilling may be affected because the icing will have been taken off the cake, so to speak. Also, remember that quite a few companies in the U.S., particularly the smaller ones, use debt to finance development activity. Banks always require hedging, and depending on the shape of the forward curve, this can hurt margins.
A sustained drop in price below $75/bbl for several months would in all likelihood have an adverse impact on drilling activity in the U.S. In Canada, there is a particular issue surrounding heavy oil. The price of West Canada Select (WCS), a heavy grade, stands at a discount of $40/bbl or so to WTI. It’s the cheapest oil in the world for practical purposes. If the price of WCS is depressed significantly south of $50/bbl, it would have the potential to adversely impact production by choking off sources of finance. Marginal oil sands heavy oil producers with above-average operating and transport costs would be the most vulnerable.
TER: Let’s talk about the producers. Are the large, international oil companies or the small producers better positioned right now?
PD: For onshore production and development activity, the big international oil companies have not been leading the pack; the great innovators have been a series of medium-size producers.
Probably the most renowned of the Bakken producers and the largest in terms of acreage is Continental Resources Group Inc. (CRGC:OTCBB). You’ve got others like EOG Resources Inc. (EOG:NYSE) and Marathon Petroleum Corp. (MPC:NYSE). They are quite big companies in terms of market capitalization, but they’re not household names. They’re not the Royal Dutch Shell Plc (RDS.A:NYSE; RDS.B:NYSE), Exxon Mobils (XOM:NYSE) and BPs (BP:NYSE; BP:LSE) of this world, which have all been late to the game.
TER: Are the small and mid-size producers good investments right now?
PD: I believe the shale revolution is probably at a very early stage. It’s got quite a few years to run. These companies have the engineering expertise to unlock the Holy Grail. I think they will probably continue to lead the field, but investors have to be patient. Obviously these companies have their ups and down, but they remain interesting investment opportunities.
You also have to remember, particularly in the case of Continental, that production is trending strongly upward. This reflects the scale of its acreage in the Bakken and Oklahoma, innovative technology, a sizeable resource base and the aggressive drill program. Continental continues to look interesting from an investment perspective.
TER: How about outside North America? Any companies that could do well based on Far Eastern growth?
PD: CBM Asia Development Corp. (TCF:TSX.V) is an Indonesia-focused coal bed methane (CBM) outfit. The company’s key issue at the moment is to get development activity up and running. Unfortunately, the company has had a major constraint in raising capital and hasn’t been able to undertake the development activity that was expected for this year. It remains to be seen how quickly it can resurrect the situation. That’s really dependent on the company’s ability to renegotiate a joint venture agreement with Exxon Mobil. CBM has indicated that it is attempting to renegotiate certain aspects of the joint venture. There’s been no news on progress but according to the company, an announcement is expected in the near future. If CBM does manage to renegotiate the joint venture so Exxon Mobil carries more of the financing, this would transform the outlook for the company and potentially provide a major boost to the stock.
TER: What about the national oil companies? What are the prospects for those names getting more involved?
PD: The Brazilian government has tried to establish closer control over Petrobras (PBR:NYSE; PETR3:BOVESPA) over the last few years. It has insisted that all the pre-salt development activity be undertaken by Petrobras itself. As a result, it’s become a much more difficult situation for non-Petrobras players to be involved in Brazil. They can participate as investors, but it’s impossible for anyone other than Petrobras to be involved as an operator. You’ve got a tightening of the state’s grip there.
Whether that will continue is possibly a bit more of an open question now because of very heavy development costs. Hitting 5 million barrels a day (5 MMbbl/d) by 2020 will be a costly task and will require a lot of technical and operational resources. Bringing the production onstream along with expanding the refining infrastructure is placing a huge burden on Petrobras. There is no doubt about the existence of the oil. The problems relate to extraction and logistics given the deepwater location, distance from the coast and the technical challenges of drilling through a very thick layer of salt. I have no doubt Petrobras will succeed in due course, but there are a lot of technical and financial hurdles to be overcome.
The other place in South America where you’ve had a tightening state grip of late is Argentina. Here the largest domestic oil and gas producer and former Repsol unit , Yacimientos Petrolíferos Fiscales (YPF:NYSE), was partly nationalized in April 2012. The government there is also increasingly involved in LNG imports. Argentina, however, is a very interesting place given its geology and particularly the quality of its tight shale formations. Argentina is not a newcomer to oil and gas production. Oil, in fact, has been produced there for 100 years and there is well-developed midstream/downstream infrastructure. The country is well served by oilfield service companies, there’s plenty of engineering know-how and Argentina is host to Tenaris (TS:NYSE), the world’s largest producer of seamless tube. There have also been three big shale oil and gas joint venture announcements in the Neuquén Basin in recent months between YPF and Chevron Corp. (CVX:NYSE),YPF and Dow Chemical Co. (DOW:NYSE) and Gas y Petroleo (Neuquén provincial government) and Wintershall Holding GmbH (a subsidiary of BASF Corp. [EUR53.17:XETRA]).
Arguably, the prospects for further shale oil and gas projects have been greatly enhanced in recent weeks following the tentative agreement between the Argentine government and Repsol on compensation terms for YPF. It should also be noted that the business environment has been improving of late in Argentina. This reflects such factors as commodity pricing reforms, the accelerated depreciation of the peso, more business friendly statements emanating from government and a less confrontational government stance vis-à-vis international bodies. Significantly, the Buenos Aires Stock Exchange Merval Index is up about 3X over the past year, driven in large part by expectations of a change of government in October 2015.
There are a couple of particularly interesting Canadian juniors operating in Argentina: Americas Petrogas Inc. (BOE:TSX.V) and Madalena Energy Inc. (MVN:TSX.V). Both have large acreages in the Vaca Muerta shale oil and gas zone in the Neuquén Basin. Several medium to large U.S. and European players also have interests in Argentina, including Exxon, Chevron, Apache Corp. (APA:NYSE), EOG, BP, Shell, Total S.A. (TOT:NYSE) and Wintershall. BP is active through its 60% stake in the closely held Buenos Aires company and second largest domestic oil and gas producer, Pan American Energy (CNOOC and the Bulgheroni family are the other shareholders). Presently the excitement surrounding Argentina mainly relates to Vaca Muerta in Neuquén. There is, however, another potentially large shale play called D-129 in the San Jorge Basin in Chubut province. Reflecting its dominant position in the Basin, Pan American and by implication BP could potentially be beneficiaries of D-129.
Vaca Muerta could be as big as the Bakken. It may hold as much as 25 billion barrels of oil equivalent (25 Bboe) in recoverable reserves, which is a very substantial number. Neuquén and nearby provinces also boast well-developed oil and gas infrastructure including refining and petrochemical facilities.
One of the key points of differentiation in Argentina compared with the U.S. is the ownership of the mineral rights. In the U.S., mineral rights are generally owned privately unless land is federally or state owned. By comparison, in Argentina and in fact in most other parts of the world, mineral rights are not owned by private individuals/concerns. They’re owned by the state, in one form or another. In Argentina mineral rights are the property of the provinces.
Shale oil and gas development has considerable support both at the federal level and the provincial level in Argentina. The federal authorities are interested in increasing the domestic supply of hydrocarbons due to a sizeable import bill for oil and gas of over $10 billion per year. The provinces, by contrast, are interested in oil and gas royalties, which are, in fact, the major source of income (excluding transfers from the federal government) in some provinces, including Chubut, Neuquén and Santa Cruz.
TER: You mentioned the role of the Canada-based juniors operating in Argentina. Are those long-term investment plays?
PD: Some of these companies have first-mover advantage. Madalena and Americas Petrogas are the most obvious examples. As is often the case, the junior outfits saw the opportunity in the Vaca Muerta early on or were willing to take the risk before the majors, but big bucks are required for development activity. At some stage the juniors will probably look at selling a stake in the projects or selling the whole company. There are some companies, of course, that may wish to go through the whole process from conceptualization to development—the proverbial company-maker concept.
TER: Which model do you think Madalena and Americas Petrogas are following? Are they looking to be bought out or do they want to go all the way to production?
PD: Both companies already have producing assets in Argentina. Production is running at about 2,250 barrels of oil equivalent per day (2,250 boe/d) for Americas and 200 boe/d for Madalena. Americas has modest 2P reserve of 10.4 MMboe/d but the interesting angle is the potential upside reflected by the substantial unrisked recoverable resource position of 8.3 billion barrels of oil (8.3 Bboe). Americas’ pilot projects at the moment are relatively small scale. The company is in joint ventures with Exxon and Apache. I suspect, given the lead times involved, the company is planning to find a buyer or to sell down the stake. Indeed, Americas has commissioned Jefferies to undertake a strategic review of the business. If Vaca Muerta and the other tight formations in the Neuquén Basin do indeed look like they are hosting the best part of 25 Bboe in recoverable resources, then the Americas shareholders could be off to the races. Although selling down stakes in some of the Vaca Muerta plays may make sense from a project finance perspective, disposal of the whole company could be premature at this stage if the recoverable resource position is as large as appears to be the case.
Madalena has working interests ranging between 35–90% in three blocks in the Neuquén Basin comprising a sizeable 135,000 net acres. Contingent and prospective recoverable resources are estimated by Madalena at 2.9 Bboe, of which 45% are oil and natural gas liquids (NGLs). There is a mixture of conventional and unconventional plays. Small quantities of oil are presently obtained from the conventional Sierras Blancas formation in the Coiron Amargo Block, where horizontal drilling technology is being applied. Madalena’s key focus presently is to secure a joint venture partner for the appraisal and development of the Vaca Muerta and Agrio shale formations. Securing a partner or partners would be a critical catalyst for the stock.
TER: It sounds like you see a lot of opportunity in South America.
PD: I think the most interesting developments and opportunities in oil and gas are in the Americas, both North and South. In addition to the relatively well-known opportunities in Argentina and Brazil, I believe that Paraguay and maybe onshore and offshore Uruguay could emerge as new frontier oil and gas provinces over the next few years. Governments are supportive of oil and gas exploration and development in both jurisdictions. Currently, Paraguay and Uruguay import virtually all their oil and gas needs.
TER: Is there a company in Paraguay or Uruguay that you like?
PD: The key company in Paraguay is an AIM-listed junior called, President Energy Plc (PPC:LSE). It also has interests in Argentina. President has shot seismic in Paraguay’s sector of the Chaco Basin, apparently with very positive results. The company has referred to ‘giant’ field potential. Drilling is scheduled to commence in Q2/14. A contract has been signed with Schlumberger Ltd. (SLB:NYSE) for project management and drilling services. The Argentine zone of the Chaco Basin has been a significant producer. Another AIM-listed junior, Amerisur Resources Plc (AMER:LSE), also has some early-stage exploration interests in Paraguay. Amerisur has had a very successful exploration/development program in Colombia.
Recent drilling activity in northern Uruguay by state-owned ANCAP and the ASX-listed junior Petrel Energy Plc (PRL:ASX) has yielded positive results with evidence of a working petroleum system. The most significant offshore event of late has been Shell’s acquisition of Petrobras’ interests. Several other majors and mid-tier concerns are also present offshore Uruguay. The theory is that Brazil’s pre-salt reservoirs could extend a long way to the south. Interestingly, a major gas discovery has recently been made by a Total/Pan American Energy (PAEYE:NASDAQ)/Wintershall consortium offshore Tierra del Fuego.
TER: Does all the production in North and South America leave OPEC in a less powerful position?
PD: Clearly, yes, because you’ve got a lot of supply coming online outside of OPEC. There will be about 1.7 MMbbl/d in 2013 and probably a similar amount in 2014. Within OPEC, Iraq (not subject to quota restrictions) is planning to boost output by approaching 1 MMbbl/d in 2014 as new terminal and refurbished oilfield capacity comes onstream. Libya and Iran would also like to substantially increase production during 2014. On the demand side of the equation, global growth is considerably slower than in the mid 2000s. Growth is now running at 0.8-1.0 MMbbl/d—less than 1% a year. With demand growth likely to lag potential gains in supply, OPEC members other than Iraq and Iran may need to cut production significantly over the next year or two to avoid downward pressure on prices. Saudi Arabia would have to carry the burden of the adjustment.
In 2013, OPEC crude production will be down about 1 MMbbl/d to 30.5 MMbbl/d while NGL output could be up 0.1 MMbbl/d to 6.4 MMbbl/d. From a recent historical perspective, OPEC production has remained at a high level. The key negatives for OPEC output in 2013 have been the impact of sanctions on Iran and ongoing civil unrest and strikes in Libya. Iranian output has dropped by about 1 MMbbl/d, while Libyan production has fallen from about 1.4 MMbbl/d in early 2013 to 0.3 MMbbl/d of late. The void has to a large degree been filled by Saudi Arabia and to a lesser extent the UAE and Kuwait.
Late in Q3/13 and into Q4/13, Iraq’s production also dropped. This is principally because the country is updating major terminal facilities in the Persian Gulf. That will enable Iraq to increase exporting capacity, but it has temporarily adversely impacted production. Additionally, northern Iraq has been plagued by terrorist activity that has interrupted flow on the Kirkuk-Ceyhan export pipeline. If not for the disruptions to output in Iraq and civil unrest in Libya, we would probably have been looking at a much lower Brent price in Q4/13.
TER: Are there any other superstar companies or geographical regions that we didn’t touch on?
PD: The Bowland Basin in northwest U.K. is looking interesting as a shale gas play. Some drilling activity is expected to start next year. Russia arguably offers major shale oil potential and there are major conventional exploration and development opportunities in Eastern Siberia. Tax incentives may be offered in Russia to encourage shale oil and gas development. China is another interesting area, both for shale oil and gas. You could see drilling activity accelerate here considerably in the next few years, driven by official policy to develop domestic energy supplies and reduce dependence on imports. North Africa is also attracting conceptual interest as a potential shale province. A lot of highly successful exploration activity has been undertaken onshore and offshore East Africa in recent years. Following discoveries made by Tullow Oil Plc (TLW:LSE) and Africa Oil Corp. (AOI:TSX.V), Kenya looks like it’s emerging as an important new oil province. Somalia and Ethiopia continue to offer frontier rift play potential. Last, central Australia is a very large unexplored area for oil and gas and offers both conventional and unconventional potential in the Mesozoic and Paleozoic basins that characterize the zone.
TER: Are there companies you like in Australia?
PD: This is a little outside my orbit. However, Santos Ltd. (STO:ASX) is a major player in central Australia with midstream and downstream interests and pioneered the development of the Cooper Basin 40-50 years ago. Other smaller players active in central Australia are Beach Energy Ltd. (BPT:ASX), Central Petroleum Ltd. (CTP:ASX), Drillsearch Energy Ltd. (DLS:ASX), Norwest Energy (NWE:ASX) and Senex Energy Ltd. (SXY:ASX). Arguably Central Petroleum looks particularly interesting on the basis of its recent Sunshine discovery, its massive acreage and its two large-scale exploration joint ventures with Santos and Total. Interestingly, Central Petroleum is to a large extent carried in the early stages of these joint ventures.
TER: It sounds like there are a lot of opportunities, particularly for people who have a long-term view on investing in oil and gas.
PD: Oil and gas is a long-term business requiring big bucks. Companies not only need technical resources, but access to capital and a strong balance sheet. Investors need to have a solid understanding of the technical and economic background to oil and gas projects and, as in other areas of investment, strong nerves and confidence.
TER: Thank you for taking the time to update us on the world of oil and gas investing.
PD: Thank you for having me.
Peter Dupont has been involved in investment research for 30 years in the industrial and resource sectors. Between 1983 and 1998, he worked for Union Bank of Switzerland (UBS) in London covering engineering and metals stocks. In early 1998, Dupont moved to Commerzbank to head its research activity in the European and UK metals and natural resources sector. Between 2005 and 2009, he worked as a consultant analyst for a London-based boutique investment bank, Libertas Capital. Since 2009, Dupont has worked for Edison Investment Research covering the oil and gas sector. Dupont produces regular macro oil and gas studies and covers developments in the “unconventionals” field. He has a Bachelor of Science from the London School of Economics.
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