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In previous articles, I discussed the ramifications of developments in the Shale Gas Revolution. The revolution continues, and is taking some important turns; some expected, some not entirely foreseen.
The price of natural gas, hovering around $3.50 per million British Thermal Units (MBTU), nearly exactly equivalent to $3.50 per GigaJoule (GJ) or Thousand Cubic Feet (mcf), has tested much lower levels, at around $1.90 in late April, when a warm winter and high gas production produced an enormous inventory surplus heading into the spring ‘shoulder season’ of low demand, and higher levels more recently.
Production, responding to lower prices, has slowed down, and excess inventory was consumed by electrical generation demand in air conditioning in the hot, dry conditions that prevailed in most of North America from late spring into the early autumn. The current shoulder season has not proved to be one with weaker pricing.
If the winter turns out to be close to normal, or even colder than average, the entire excess inventory should be consumed, and gas prices could, according to some traders of the commodity, reach over $4 per GJ, maybe over $5, although the sustainability of such a move is in some doubt.
One major change in behavior by producers has helped provide a lift to the gas price. As victims of their own success, that is, the great increase in gas production having lowered the prices they receive — they have curtailed their exploration plans in many cases, sold off some properties and re-oriented their focus to liquids-rich targets to take advantage of the higher prices those commodities get.
These liquids comprise normal petroleum, natural gas liquids (NGLs), and the similar liquefied petroleum gases. Natural gas liquids trade off the price of oil, and thus are not as vulnerable to decline as the price of natural gas itself. NGLs have ready markets to chemical firms and heavy oil and oil sands producers and shippers.
These explorers have largely been successful in this change of strategy, and they have rescued themselves from financial peril, at least so far. The increase in oil production in the United States, and even conventional production in Canada, has been impressive. However, there have been two important, negative side-effects of this success. The first is that, like the shale gas production growth, the increase in oil output is lowering the price that producers are getting in mid-continent markets.
West Texas Intermediate (WTI) continues to trade at a big discount to the globally-traded crudes represented by the revamped Brent oil price. Surging Bakken formation oil from North Dakota and Saskatchewan trades at a discount even to WTI, as pipelines to Cushing, Oklahoma are full, as are the ones to the port of Vancouver, and to Chicago and eastern North America. Oil is now being transported by Canadian and U.S. trains to the West Coast and elsewhere, instead of pipelines.
TransCanada’s (TRP) Keystone XL Express pipeline, a political football earlier in the U.S. election season, will, should it be finally constructed, not help prices greatly, as it will take yet more oil into Cushing, depressing prices, but it will help producers offload their production more easily. The fix of rerouting around the Sand Hills area in Nebraska seems to have mollified Keystone’s main opponents, but final approval, at state and federal level, will still have to wait until next year, at the earliest, and it will take a year or more to build. It will not be a crucial development, but it will, on the whole, be a positive one, for producers.
Kinder Morgan (KMP), which is well placed to benefit from either increases in gas, or oil production, by virtue of its large, extensive networks of both sorts of pipelines and gathering systems continent-wide, has proposed more than doubling the capacity of its Edmonton-to-Vancouver oil pipeline, to take expanding oil sands production from northern Alberta. This would be positive for the shale oil and gas producers, as it would redirect pipeline space demand from Enbridge’s (EEP) Alberta routes away from the mid-continent, making more capacity available to the Bakken and Niobara (in Colorado and vicinity) producers.
However, the Kinder proposal has run into opposition from environmental and other intervenors in British Columbia (B.C), where most of the Vancouver route runs through, and in the Vancouver area itself. Since the route is not a new one, nor is the pipeline, having been in place for decades, this should not be controversial, but it has become so. Kinder had a bad leak a few years ago, caused by a non-Kinder construction crew accidentally hitting the line. While not its fault, it still affects perceptions.
Even worse, though, is the fall-out from the opposition to Enbridge’s proposed Northern Gateway pipeline, going from Bruderheim, near Edmonton, generally following the northern branch of the Yellowhead Highway to Kitimat on the West Coast of British Columbia. There are three main issues: tanker dangers at Kitimat and in the passage through the islands and along the coast to that port; the hazards of spills on land and in water bodies in the interior of B.C.; and, finally, the less-than-stellar safety record of Enbridge itself.
The company did not respond quickly to a substantial spill into the Kalamazoo river in Michigan a few years ago, and there have been other apparently substandard incident responses documented by critics and regulators. Another complication is that Northern Gateway has become a B.C. provincial election campaign issue, with all major parties competing to be more strident in their skepticism and suspicion of the project. Gateway is not only crucial for northern Alberta oil sands producers to get their projected expansion of production to market, yet it also, indirectly, affects shale oil producers in not just Canada, but in the U.S., too.
If that expanded oil sands production does not find an outlet to the West Coast, it will go to the mid-continent, and keep WTI prices depressed, and reduce netbacks in North Dakota and Canada even more than today. The proposed changes in TransCanada’s gas pipeline to Eastern Canada and the U.S. to take oil east instead of gas will help somewhat, but current plans are not big enough in scale to remedy the situation completely. There are some lower capacity or shorter pipelines and pipeline extensions throughout North America that will aid in a more even, thorough distribution of both gas and oil that get little publicity, including several in the mid-West and the Appalachian regions, but these will take some time to have an impact.
Getting back to the shale explorers and producers, their refocus on liquids superficially would appear to help reduce gas production growth and oversupply, but there is another aspect to it that is an unpleasant side effect. Their search for oil has mostly been successful and production is climbing. However, it is impossible to produce shale oil without producing at least some gas, since the exploration is as much an art as a science.
As oil is the primary target, and, if the wells and attendant fracking produce sufficient quantities of it to justify the cost and risk, they do not care if they produce a little or a lot of associated gas, and, accordingly, do not care much what price they get for that gas, or that the price may decline; for many producers, it is not a significant factor in their planning.
Hence, there is, and will likely continue to be, a lot of gas produced, and even more as the liquids plays become more lucrative and production accelerates. The gas is a bonus, but not crucial. Therefore, the refocus of the explorers on liquids will not necessarily lower gas production or improve pricing, in the short or long term.
Meanwhile, more and more users of gas are betting on continued supply growth, and that prices will not escalate dramatically. Nearly all new planned electrical generating capacity in North America is natural gas fired. Not only is the fuel cheaper than coal, but the plants are less expensive, faster to build, and cleaner to operate. There will be nearly one hundred million more people in North America in the next forty years, and they will all need gas and electric service, assuring substantial demand growth.
There is another unusual development that could foster the use of natural gas for electricity: a new kind of fuel cell for buildings. It takes in natural gas and converts about half the energy to electric power. This is at least as efficient as natural gas generators, and also eliminates the losses in power from transmissions and substations, which can be as much as 50%, depending on the distance.
This technology is already commercial and being deployed in office buildings in the U.S. Innovative, nascent industries such as this one are hampered in some respects, being dependent as it is on gas utilities and distributors; by their rate-base regulated nature, there is little incentive for them to foster such development; their kindred regulated electric utilities may try to stop them entirely.
Meanwhile, the North American gas surplus has given confidence to oil and gas majors that there will be enough supply to ship to foreign markets and to support liquefied natural gas (LNG) facilities, which have a high capital cost. There are now at least five such facilities mooted for Kitimat to ship to Korea, Japan, and elsewhere across the Pacific, and several installations planned for the U.S. Gulf Coast. Curiously, the natural gas pipelines that would take Northern B.C. gas to Kitimat are attracting no opposition, despite the rancor directed at the oil lines.
There is some concern that the U.S. federal government may not give export permits to some or all exporters in the Gulf, but it seems unlikely that jobs and revenues that would be generated could be forsworn in the current stagnant, high unemployment economy.
Probably the biggest single event validating the gas story is the new push to build a trans-Alaska natural gas pipeline to take North Slope, and, later, Beaufort Sea gas to the south to the Gulf of Alaska, likely at Valdez, where the oil line terminates as well. This gas, too, will be destined for Asia. The cost will be staggering, and it will take a long time to build. That is a good thing, because, despite a lot of exploration, there is still not a lot of offshore gas developed in Alaska’s Arctic waters. The line is not dependent on successful exploration, but it would help fill its capacity as the onshore reserves deplete.
There has also been a considerable amount of natural gas proved up onshore in the Mackenzie Delta in nearby northern Canada, gas which had appeared to be stranded, as the long-proposed (since the 1970’s) pipeline to bring it south no longer makes sense with all the surplus gas in southern Canada and the lower forty-eight states of the U.S. Now, a relatively short lateral line could take all that stranded gas along the coastal plain to the Alaska pipeline, making both reservoirs even more valuable.
Outside North America, where gas prices only have indirect relation to oil prices, gas contracts for customers explicitly are tied to international oil prices. Thus, until recently, companies developing reserves in Russian, Central Asia, and offshore Australia for sale in Europe or South or East Asia were confident that they would get prices of over $10 per GJ, far higher than have been seen in North America for many years.
However, big buyers, generally electric or gas utilities, are now aware of the big fields coming onstream, and even more aware that they have choices, and can set sellers competing against each other. This global ‘gas-on-gas’ competition is just beginning; it has been prevalent in North America for decades, now. It will take some time for prices in the rest of the world to come down, and for them to rise in North America, as all these projects will take years to compete and become operational, while, at the same time, gas demand will continue to rise.
When it comes to international shale gas development, the only place with real progress has been China. In the past several months a number of new wells have been drilled, with, apparently, some success. So far, the amounts proved up have been kept secret, or may not be easily appraised. Given the tight control that Beijing has over the national industry, and the lack of commercial freedom, it would seem unlikely that production will take off the way it has in North America over the past decade. However, given all the technology that has been developed, which China can simply license or copy, they do not have to repeat all the mistakes and learning process that the producers in the West had to go through.
In other high-potential regions, progress is still slow. Argentina’s turmoil and anti-business stance, let alone its nationalization of YPF Repsol (YPF), has indefinitely delayed development of its still-hypothetical reserves. In Africa, some nations are attempting to retroactively change royalty, tax, and ownership regimes in their governments’ favor, retarding continued investment by foreign majors and independents. However, huge new reserves found offshore Mozambique look likely to be commercialized relatively soon.
In Israel, offshore gas and some liquids could make that nation energy independent within a few years’ time. There is also some progress on developing kerogen deposits. Potential reserves could be 250 billion barrels of oil equivalent. While there is little to no exploration risk, getting the stuff to flow is itself energy intensive, and requires current world oil prices to remain high for it to pay off. Onshore Australia, coal bed methane (CBM) and tight shale formations are adding to the offshore bonanza that is generating over $100 billion in LNG facilities to serve Asia. These will, as stated earlier, all take several years to come to full service and production.
When it comes to offshore exploration in the U.S., outside the Gulf of Mexico, it remains environmentally controversial, and will take a lot of time to fully assess, let alone successfully explore. Significant production is a long way off. Should it occur, despite environmental opposition, it will have little effect on oil prices in the U.S., as the offshore precincts are more closely integrated with world markets and pricing. The natural gas price could be affected, though, depending on the magnitude of any volumes discovered.
More near-term, in Mexico, the new administration which will take office in Mexico City on December 1st is determined to increase production from the properties the national oil monopoly, Pemex, controls. They plan to introduce legislation to make it much easier for foreign firms to apply their technology and get fully rewarded for it the more successfully it is applied. As many firms are already operating there under contract, results could be forthcoming relatively quickly. Mexico also has a number of attractive shale formations.
There are a number of ways to play the expansion of shale gas and liquids production and use. Probably the safest alternatives are to invest in the carriers, such as Kinder Morgan, TransCanada, and Enbridge. Mid-stream processors are also in a good situation; they will make money as volumes passing through continue to grow, along with the demand for feedstock from chemical and fertilizer producers.
The developers of LNG and other processing facilities should continue to do well for many years to come. They include Chicago Bridge and Iron (CBI), McDermott International (mdr), Fluor Corp. (FLR), Jacobs Engineering (JCI), Foster Wheeler (FWLT), and others.
When it comes to the actual producers, the picture is cloudier. As victims of their own success, they are on a treadmill of having to find more and more reserves as prices falter or even decline at times. The ones with the greatest exploration success, and the ability to keep free cash flow growing, even in depressed times, are the ones to examine carefully.
Among EOG Resources (EOG), Encana (ECA), Chesapeake (CHK), Forest Oil (FRO), Danbury (DNB), Range Resources (RRC), and others, look how they performed in the second quarter of this year, and watch the reports from Zacks to see which are primed to outperform their peers over a sustained period. It can be worth it to pay a premium for a proven survivor that can thrive in adversity.