Has Shale Broken OPEC’s Grip? Peter Dupont Names Powerhouses of the Future

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Submitted by The Energy Report as part of our contributors program.

Has Shale Broken OPEC’s Grip? Peter Dupont Names Powerhouses of the Future


This interview was conducted by Tom Armistead of The Energy Report (12/12/13)

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.

 

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