More and more Liquified Natural Gas (LNG) expansion is progressing across North America. Also, a new gas pipeline has been proposed for Prince Rupert, British Columbia, with a pipeline branch coming down a different inlet from the narrow, delicate Skeena River valley. This is thought to enhance the prospects for environmental clearance, as well as speedier construction.
A new oil refining and export plant for Kitimat is also proposed. Refining the oil into gasoline and diesel and jet fuel will reduce damage a spill could cause in the tricky passages out to open water. The total project may cost CAD$25 billion (USD$24.5 billion), or even more, if it goes ahead.
Meanwhile, the gas pipelines to nearby Kitimat, and the LNG facilities they entail, are being called into question on costs and margins, as it seems that Australian and Russian competition may put a ceiling on what prices the product may command in Korean and Japanese markets, let alone in China, which has a wide array of competitive choices, from Myanmar, Central Asia, Australia and Russia.
East of the Rocky Mountains, the Alberta provincial government’s revenues are plummeting as royalties plunge, with the discount of Alberta bitumen widening to record levels against light oil and more centrally sourced Bakken product. The urgency of having the Keystone XL pipeline built is greater than ever for Alberta conventional and oil sands producers. New projects are being delayed or cancelled, and existing ones are getting cost-cutting attention.
The Enbridge oil line to Kitimat will take several more years to get built, if it is approved at all. Native organizations, or ‘First Nations,’ are getting more hardened in their anti-development resolve. The reversal of Enbridge and TransCanada lines to eastern Canada will not require much (if any) environmental review, but, it turns out, will require many more quarters of work before they become fully functional.
Update on the Keystone and Bakken Lines
The U.S. State department has given conditional approval to the Keystone XL line, having found that there are no significant environmental impediments to its construction, and also that the oil it would transport would be produced and shipped whether the line is built or not. That has not satisfied environmental activists, who hope to influence President Obama to either disapprove it or place onerous restrictions on it. In any case, it will not be finished for years, and the build-up of Canadian and Bakken crude may bring more pain to producers.
In efforts to get Bakken and Canadian oil moving, railroad companies are stepping up their shipments of oil. Hundreds of railcars are being ordered, delivered, and deployed, with shipments by rail west and east by Canadian National and Canadian Pacific jumping dramatically in recent months, as have shipments by those companies to the U.S., and by several U.S. railroads in all directions.
The advantages of rail shipment are fast movement of products, quick ramp-up of capacity, and avoidance of environmental review. Nearly all pipelines in North America are at capacity, and only those with existing approved line are able to easily gain approval to expand that capacity. As a result of the rail factor, and some incremental pipeline expansion, the recent big discount of Alberta bitumen to light and U.S. oil has narrowed, but not dramatically.
In Bakken developments, some explorers are now experimenting with closer, denser spacing of drilling of wells, which appears to be netting them higher recoveries of oil. As a result, some very high figures are being bandied about for potential total recoverable reserves, just in the Bakken formation, and the one called Three Forks, which lies below it: nearly 900 billion barrels. Even ten per cent of that number would be impressive, added to all the other shale formations in North America, whose potential and economically viable reserves could also be expanded.
It looks like there could indeed be trillions of barrels of oil in the shale of North America, and much more natural gas, too. Since China is thought to have even more than North America, that, along with coal bed methane, brings the total potential nonconventional reserves of oil and gas to more than that of all conventional sources, such as those in the Persian Gulf. That does not even count the oil sands of Alberta and Venezuela, very heavy oil deposits in California, or the kerogen (what used to be called shale oil, in the 1980’s) formations in Wyoming, Colorado, Israel and Jordan.
What remains unclear is what the long-term depletion rates and ongoing fracking costs of these types of shale wells are. However, with some history in older Barnett and Bakken plays, the depletion appears to be manageable.
Developments Down Under and Elsewhere
In Australia, a company called Linc Energy has found what it claims could be a 200 billion barrel or more reservoir onshore South Australia. This could be wishful thinking, or a miscalculation. However, if even a small fraction of that is proved up, Australia’s onshore oil potential could be huge. Also, this is a brand-new province; there could be more reserves adjacent, and offshore, too.
China’s shale development has been slow, owing to difficult geological structures, and water shortages. However, Shell is producing and sending gas into a local distribution system in Sichuan province. Turkey is exploring aggressively on and offshore, with some success.
Cyprus, Lebanon and Israel all have natural gas in their offshore realms, with Israel now close to commercial sales, awaiting only completion of a relatively short pipeline to the mainland. However, there are some maritime border disputes.
Argentina’s development has been cut short by political and economic turmoil, and maltreatment of foreign investors. Chevron, for instance, was on the brink of investing in a large joint venture in shale oil there, but a dubious Ecuadorian court judgment against the firm was validated as a claim by Argentinian courts, causing the company to withdraw to forestall any risk of payment.
Saudi Arabia announced its intention to begin shale oil and gas development, with potential reserves of each roughly equal to its current conventional resources. However, as water is a major input in hydraulic fracturing, unless a way can be found to use sea water or cheaply partly-desalinated sea water, the desert kingdom is unlikely to be able to develop this resource quickly or substantially.
Such a method may be imminent, as graphene (carbon in a unique form), in a one-molecule-thick layer, is capable of straining out sodium chloride, or salt, and letting through dihydrogen oxide, or (pure) water, one hundred to one thousand times more efficiently than current reverse osmosis desalination systems. Graphene is still expensive, and not being manufactured in mass quantities, so this could take some time to benefit either Saudi Arabia or China, in shale gas or oil exploitation (let alone other regions in irrigation or drinking water production).
In Europe, the news from Polish shale efforts continues to disappoint, but there are indications from Ukraine that they are eager to attract considerable foreign investment and involvement in potentially huge shale formations there. The nation is in a protracted, perennial contract and market dispute with Russia over natural gas transit and payment for supply, and would like to diversify its supplier base, if not become energy-independent entirely, eventually.
Venezuela Minus Chavez, and Closer to Home
With the death of its long-time populist authoritarian, socialist president, Hugo Chavez, it may seem that Venezuela might become more open to foreign investment and development of its conventional and heavy oil resources. The government has been using the nationalized oil company, PDVSA, as a cash cow, taking nearly all its free cash flow, starving it of capital needed to reinvest in operations to offset depletion. However, its government, to this point, looks set to maintain current anti-capitalist and anti-foreign policies, and foreign investors remain wary of the country, which has stolen assets from them and reneged on contracts and licenses in recent years.
Mexico’s president, however, appears to be making some slow progress in making his country’s monopoly oil company, Pemex, open to outside contractors and joint ventures, which could arrest liquids decline and conceivably could lead to a reversal of its net import of natural gas. Mexico has extensive unexploited shale formations, too, but those seem to be a low investment priority given all the work required on remediation of conventional reservoirs.
U.S. energy production continues to hit new records. Both oil and natural gas production are rising, continuing to push out imports, improve the balance of payments, boost the dollar, and lower prices for consumers and businesses. Gas prices remained relatively strong over the winter, giving hope to producers, who have been cautious in drilling plans, thus far, this year.
Drilling is slowing down, but well productivity and total reserves keep rising. The firing and retirement of CEO’s at a number of aggressive explorers has led to reduced spending, and a focus on high potential targets, and more liquids rather than gas. Total gas inventories are well below what they were at this time last year, but still above the five-year average.
Coal, Nat Gas and LNG
Coal displaced by the surging gas supply is being sent to Europe, where it is filling in for when government-mandated solar and wind electric power does not meet market demand. U.S. production has risen to the point where it is having an effect on world export patterns. It is displacing some Middle Eastern and African crude, which is now having to be diverted to European and Asian markets, putting pressure on world prices, which would otherwise be rising with demand growth, and on OPEC, where some countries are now having to trim production.
Meanwhile, a number of North American companies are plunging into LNG as a transport fuel. Several are testing it in Canada and the U.S., and some major fleet owners are prepared to convert to LNG use if current price differentials to diesel prices stay about the same in the future. Some big delivery and trucking companies are involved, but are still at an early stage. It now appears that LNG has the edge over compressed natural gas, ‘CNG,’ systems.
Burlington Northern Santa Fe, a unit of Berkshire Hathaway (BRK.B), is experimenting with LNG-burning locomotives. While the cost of converting a diesel locomotive to LNG is currently estimated at over $25,000, the potential savings in fuel could be as much as 70%. There remain the difficulties of establishing LNG refueling depots along rail lines, but this could be overcome.
U.S. LNG export plans are getting more credibility, and are beginning to crystallize. The earliest one, by Cheniere Energy (LNG), on the Gulf of Mexico, is nearly certain to begin commercial sales in 2015, with full capacity production in 2018. Contracts with foreign buyers are already signed. No West Coast facilities have been announced, as yet, but if difficulties persist in Canada, it is conceivable that new LNG export terminals could be announced in Washington state or Oregon.
In more esoteric news, Japan has conducted experiments designed to develop commercial capture of seabed methane hydrates. Apparently, the results were at least technically successful. Japan has a very extensive continental shelf within its maritime boundaries, so, should natural gas prices in their market remain elevated, even without the premium they get above all other markets around the world, this could conceivably be a viable and substantial new domestic source of supply, but not anytime very soon.
This is additional validation of the potential of this worldwide ubiquitous resource, which earlier had a technically successful test by U.S. researchers in Alaskan waters. While it is not entirely clear, it seems likely that exploitation of this resource is much less environmentally risky or contentious than shale development, and subsea gathering systems and pipelines would be much less controversial than that of oil wells and systems.
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