In the following, information-packed interview with Rick Rule, founder of Global Resource Investments, Ltd., Mr. Rule discusses conventional oil and gas, oil shale, shale gas, oil sands, heavy crude, peak oil and alternative energy, with particular emphasis on geothermal power.
Rule has dedicated his entire life to all aspects of the natural resource industry. His contacts and knowledge of this market are unmatched. At Global Resource Investments, Rick leads a team featuring professionals trained in resource related disciplines, including geology and engineering, to evaluate investment opportunities.
Rick began his career in the securities business in 1974, and has been principally involved in natural resource security investments ever since. He is a leading American retail broker specializing in mining, energy, water utilities, forest products and agriculture. His research and brokerage capabilities are frequently recommended by distinguished financial newsletter writers such as Bob Bishop, Jim Blanchard, Doug Casey, Adrian Day, Richard Maybury, Paul van Eeden, Mark Skousen, Jack Pugsley, Ron Hera and others.
Hera Research Newsletter (HRN): Thank you for speaking with us today. How do you see the conventional oil and gas market developing in light of alternative energy?
Rule: From an investor’s point of view, conventional oil and gas will always be a pretty good business because it’s a reasonably high margin business and it’s also a very large business but it’s a cyclical business, which means that it goes on sale reasonably often.
The most important theme that people need to understand with regard to conventional oil is that most conventional oil that is produced in the world and sold for export is not produced by companies like Shell or Exxon or Total, in other words it’s not produced by major oil companies. It’s produced by national oil companies, where the shareholders aren’t public shareholders but rather sovereign governments, and that’s important to understand. It’s important for investors because most of the national oil companies have been, for some period of time, diverting substantial amounts of the cashflow from their domestic oil industries into other domestic spending programs that aren’t oil related, thereby starving their domestic oil industry of sustaining capital. I think this has gone on for so long that several of these national oil companies have production decline curves that are irreversible for the next decade. The consequence of that is that several countries, particularly Mexico, Venezuela, Peru, Indonesia and perhaps Iran, will cease to be oil exporters within 5 years, even if they start spending now, which they aren’t able to do. The impact of that is that as much as 20% of world export crude will come off of export markets and that could lead to a truly precipitous increase in price. The only hope that oil import countries have is that sustaining capital investments have increased in Saudi Arabia, the United Arab Emirates and Kuwait. These three countries, with the help of a resurgent Iraq (if it does resurge), are the importing countries’ only hope for moderated oil prices in the next 5 years. It’s my belief that production declines as a consequence of a lack of reinvestment will be greater than the production adds and I suspect we will see sharply higher world oil prices in the next 5 years.
HRN: Do you think that increased domestic oil consumption by oil exporting countries is a significant factor?
Rule: One of the things that oil exporting countries like Iran, Indonesia, Mexico and Venezuela do with the cashflow from oil exports is subsidize domestic energy production. At the same time that they increase supply, they constrain demand, which is not a sustainable set of circumstances over time. I think it will correct but it will not correct in time to prevent an oil price shock.
HRN: How does your outlook for conventional oil differ from natural gas?
Rule: Natural gas is not yet a global market, although with increasing traffic in liquefied natural gas (NYSEMKT:LNG), it is becoming a global market. It is rather a series of regional markets. Some markets are in substantial oversupply, North America being one. North America benefits from very favorable geology and extraordinary infrastructure. The United States has transmission and underground storage infrastructure, as well as LNG receiving infrastructure, that are the envy of the world. The United States has access to ample supplies of gas from Canada’s Western sedimentary basin and huge quantities of shale gas that has become newly economic as a consequence of several different types of extraction technology. Additionally, the United States has six LNG receiving facilities and the storage capacity to take cargoes at a moment’s notice and store them. Paradoxically, although the United States is an oversupplied natural gas market, it is also a market that takes surplus LNG cargoes that cannot be sold elsewhere. For the next while, at least, the North American natural gas market is in a state of oversupply. This has caused North American dry gas prices to fall and the prices of gas producers to fall.
HRN: How will the BP catastrophe in the Gulf of Mexico affect the US oil and gas market?
Rule: What interests me—the fly in the ointment—about the blowout in the Gulf of Mexico Is that the Gulf of Mexico supplies 30% of US domestic oil and gas. Gas wells in the Gulf, in particular, have very high decline curves, meaning that gas wells drilled this year will likely be played out in 2012 or 2014. Without sustained drilling in the Gulf of Mexico, we can expect very rapid declines in overall US gas production, which may or may not lead to increasing domestic prices at a time when most commentators are calling for decreasing domestic prices.
HRN: Do you think shale gas will keep US prices low?
Rule: I expect the supply of shale gas to be extremely volatile and the volatility will be a delta between the leveraged finding cost of gas producers and the forward strip. It would appear that the median North American shale—a combination of the Marcellus, Barnett, Eagle Fort and Woodford shale systems—involves finding costs and capital costs in the $4 to $5 per million British Thermal Unit (BTU) range. To the extent that a forward strip market exists, in the futures market, above $5.50 per million BTU, meaning that producers can hedge by selling forward enough gas production to pay off a well, drilling will be fairly active. Producers can drill these gas wells because they have no exploration risk for a while. If they can produce gas for $4.00 to $4.50 per million BTU and sell it for $5.00 to $5.50 per million BTU, because of the very high initial production of these wells, they have the ability to drill a well and pay the well off on a guaranteed basis by selling into the forward strip. When high drilling activity puts enough fresh production into the system to drive gas prices down and the forward strip goes below $4.00 or $4.50 per million BTU we’ll see a relatively rapid stacking of rigs and, because of the very, very high depletion of gas shale wells, 18 to 24 months out we’ll see gas supplies tight enough to drive the spot and the strip market higher, and the situation will repeat itself.
HRN: What’s the best way for investors to capitalize on cyclicality in the North American gas market?
Rule: The interesting thing about the North American natural gas market is that it is going to be extremely volatile. Speculators are going to have to buy in terms of low gas prices, when rigs are stacked and production is declining, and sell during periods of high gas prices when producer cash flows are soaring. It’s going to be counterintuitive but very, very rewarding. Normally, these cycles take place in 10 years or 12 years but we’re going to see these cycles taking place in 2 years, which is a situation we’ve not seen before.
HRN: Can you comment on the global market for gas?
Rule: The global gas market is very different. It’s a series of smaller markets, in actuality. In far eastern markets, LNG is increasingly seen as a cheap substitute for oil in many of oil’s functions, such as power generation and petrochemical feedstocks (used in the manufacture of chemicals, synthetic rubber and plastics) in particular. We’re seeing the development of a vast LNG infrastructure to move gas from places where it’s in abundance, like the Australian shelf and parts of Indonesia, to places that appear to be perpetually hydrocarbon starved, like China, Taiwan, Korea and Japan. Europe, similarly, has fairly high gas prices and has developed what the Europeans believe to be a dangerous reliance on Russian supplies. There are moves afoot to lessen European dependence on Russian gas, like moving Iranian or Azerbaijani gas through Turkey into Europe, and moving North African gas into Europe. Over time, I suspect, a way will be found to provide energy security for Europe where the Russians have a big share of the market but will not dominate the market.
HRN: Do you expect natural gas to be more widely used as a motor fuel in the future?
Rule: What’s interesting is that natural gas prices are substantially cheaper than oil prices as a consequence of oil’s dominance as a motor fuel. I think we are finally in an era where natural gas will achieve prominence as a motor fuel. I suspect that the country that leads that charge will be the United States, as a consequence of its reliance on export crude and of our unique national highway system. It’s always been a chicken or egg problem. If we convert cars before having the ability to distribute LNG we’ll have stranded vehicles, but if we convert gas stations before converting cars we have stranded capital. The answer to that in the near term is to convert 2% of the gasoline stations along long haul trucking routes and convert the trucking fleet before converting cars. This would save a tremendous amount of cash because LNG is significantly cheaper as a motor fuel.
HRN: Isn’t that part of the Pickens Plan?
Rule: Yes, it is, but the Pickens Plan, somewhat disingenuously, would rely on federal subsidies. I don’t think we need any federal subsidies. The savings that would be generated by converting the long haul trucking fleet to LNG would be such that federal subsidies wouldn’t be needed. It’s also interesting that there are rapidly developing technologies that would allow service stations to compress the gas themselves from utility supply rather than having to distribute LNG in the same fashion that gasoline or diesel are distributed. I also think the US is headed, in the near term, for some type of carbon tax—whether or not it’s a good idea is a different question—and I think the carbon tax would make gasoline and diesel even less competitive relative to natural gas. In the next 5 years we’ll see substantial strides towards the conversion of the long haul trucking fleet from diesel to LNG. There have been discussions that Wal-Mart or Costco, partially for public relations reasons, might lead the charge by making conversions across the country by converting their own, high-volume operations. Having that critical mass of availability of LNG will encourage the conversion of the nation’s automobile fleet.
HRN: I read that there has been a build-out of capacity to refine heavy sour crude oil.
Rule: Heavy oil is doing well and I think it will continue to do well for a couple of paradoxical reasons. There used to be a very large spread between heavy sour crude prices and sweet light crude because heavy oil required upgrading. The spread was so large that upgrading heavy oil was extremely profitable and, as a consequence, enormous capital investments were made over the past 10 years or so both in Canada and in the United States in heavy oil upgrading. What’s happened is that our capacity to upgrade heavy sour crude has begun to outstrip supplies, particularly from Mexico and Venezuela. Because of the oversupply of upgrading capacity and the relative undersupply of heavy crude oil, the spreads between heavy crude and light crude have declined to the point where producing heavy crude has become a very profitable activity.
HRN: What is your view on oil sands?
Rule: North American speculators who are under-weighted in oil should probably take a position in the larger oil sands companies, just as they would buy car insurance or life insurance. In addition to the supply disruptions that I see from the lack of investment in conventional export crude, geopolitical instability in the Persian Gulf region, particularly where Iran is concerned, could disrupt supply. If the Iranians had cause to shut down the Strait of Hormuz for any period of time, we would see a tremendous escalation in oil prices and we would see the geopolitical benefit of the Athabasca oil sands, which is an enormous, producing bitumen region of Northern Alberta, Canada. I see oil sands as an absolute cornerstone in a North American energy investor’s portfolio because of its extraordinary size, the amount of capital that has already been expended and because of its particular importance to US consumers.
HRN: What’s the status of technology to recover oil from oil sands?
Rule: Steam assisted gravity drainage (OTCPK:SAGD) is a technology that’s useful where the oil is heavy and doesn’t flow very well but where there is porosity and permeability. What we do is drill two horizontal legs into the reservoir. One leg pumps steam into the reservoir while the other leg pumps out the fluid produced as a consequence of the injection of energy and steam.
HRN: With the energy inputs, is it economic or energy positive to produce oil from oil sands?
Rule: In an ideal world, one would build about 2 GW of nuclear capacity at the Athabasca oil sands in Northern Alberta, which is the largest oil sands basin in the world, because the byproduct of a nuclear power plant is steam. The steam from 2 GW of nuclear capacity would be worth about a quarter of a billion dollars annually. In other words, you would sell your waste product for a quarter of a billion dollars and the cash flow from the waste (steam) would amortize most of the construction cost of the power plant and the power that would be generated would back out all of the natural gas fired power used in the province of Alberta, freeing all of that gas for export or other uses (other than generating steam for the oil sands). Unfortunately, that set of circumstances isn’t politically appropriate. Right now, what happens in the oil sands business is that, because oil commands a higher premium as a consequence of its easy conversion into a motor fuel compared with natural gas, the process involves an arbitrage between high oil prices and low gas prices. Enormous amounts of energy are consumed to produce energy.
HRN: Is there an environmental impact?
Rule: A challenge facing the oil sands industry is that it alters, negatively, large quantities of water. Water supply and water treatment issues will come to the fore in the oil sands business. I’m not a knee-jerk environmentalist but I am a real environmentalist. The industry has to address the fact that it has improperly treated water for a long period of time and it consumes much more water at lower input prices than it ought to. The industry is going to have to deal with recycling processed water back into process and with cleaning up process water before putting it back into the environment. In oil mining operations, the industry is also going to have to deal with the water that builds up in the pit as oil that hasn’t been mined desorbs from the rocks in the pit and is ultimately released into the environment. There are costs associated with oil sands that aren’t being factored into the cost of the oil that’s being sold and society is going to demand solutions to those problems and that will increase the production cost.
HRN: That’s fascinating, can you comment on oil shale as well?
Rule: The technologies that have been brought to bear on gas rich shales, particularly those that have a lot of liquids in them, can probably be brought to bear on some of the oil rich shales, in particular, the thermally mature oil shales. We know that some of these basins are like organic kitchens, cooking their organic content into oil, but they have neither the porosity nor the permeability to be produced economically. What we’ve done in the gas rich shales, because they have poor reservoir properties, is that we’ve effectively manufactured our own reservoirs. We drill into the gas shales horizontally rather than vertically, exposing more of the reservoir to our extractive mechanism, that is, our well. Because the shale is very tight we pump in water or sand or ceramic, in a procedure called fracturing, keeping the reservoir open. In other words we are manufacturing a reservoir in rock that has oil and gas in place but that didn’t have a reservoir previously. That technology will probably work in certain applications for oil shales. It may be that a combination of technologies, fracturing and SAGD, can be used in oil shales. The tremendous advance of technology we’ve enjoyed in the last 30 years and the tens of billions of barrels of oil that are known to exist, suggests that we may see the same type of technological breakthrough in the oil shales that we have in the gas shales. In the oil sands, the billions of dollars invested are beginning to pay off in spades, both in terms of cash flows and in terms of the security of the supply.
HRN: What do you think about the Peak Oil theory?
Rule: Peak oil is more an economic and political phenomenon than it is a geological phenomenon. I think we’re past $40 peak oil but I don’t think we’re past $200 peak oil. There are technologies, as an example, miscible CO2 flooding to recover oil from allegedly depleted oil fields. There are new basins, albeit remote, frontier basins. There are new technologies that allow dry gas or LNG to be substituted for liquid oil. It’s an economic function because these technologies and substitutions require higher energy prices. At $200 oil, we’ve got lots of oil.
Disclosure: Long Ram Power Corp. (TSX:RPG) and Magma Energy Corp. (TSX:MXY). The author is personally a client of Global Resource Investments, Ltd.