Efficient Markets? How Noise Drives Prices

By Peter McKenzie-Brown This week was remarkable. It began with the Americans twisting Saudi arms so they would increase oil production. Nervous that there might be spigots that could actually be opened, oil prices dropped off their lofty levels. Then a decline on global stock markets was greatly exacerbated by the squeeze forced on France’s Société Générale by a rogue trader.

The Martin Luther King holiday market closures compromised an orderly unwinding of those futures contracts, and the decline in the markets turned into a meltdown. Not knowing that the actions of a 31-year-old rogue had precipitated the collapse, the Fed’s Ben Bernanke flooded the world with cash by precipitously slashing key US interest rates. The markets were also flooded with rumours of a severe US recession impending – one that would take the world with it. Fearing a crash in demand, the price of West Texas Intermediate briefly dropped to its lowest level in three months. Then reality began to intrude: the Saudis don’t have a lot more oil they can produce, and geopolitics, rising demand and historically tight supply still govern the price of oil.

The chart illustrates two things. First, it shows the trading range of oil (the space between the red and green lines) during the last six years. Second, it shows an extended breach in that trading range – essentially, three months of trades above the red line. What used to be resistance has now become support. I consider it highly significant that oil prices popped up after touching their three-month low.

In the future, oil is likely to trade above the red line. One of the great things about technical analysis of this kind is that it is a way of imposing order (straight lines) on a market riven by noise (jagged lines.) However, technical analysis is not an excuse for not understanding what decisions help form the jagged lines of day-to-day trading. Oil prices are governed by a highly sophisticated market – one that can quickly balance innumerable pricing factors to establish appropriate prices for oil, but so doing creates endless charts of jagged lines. Herein I present my perception of how that market developed and of the major factors influencing it. As a Canuck, I will deal with the matter from a Canadian perspective.

The Background: As oil became a vital factor in western life during the twentieth century, exploration for the stuff – a new industry – found more than the world could consume. In response, big companies set prices for the oil they controlled overseas, while governments and regulators in the US helped create a parallel environment in which America’s huge domestic oil industry could prosper from higher prices. By 1970, these different policies had created a global pricing environment in which oil produced in the United States cost $3.18 (U.S.), while oil produced overseas only fetched $1.30 (U.S.)

This situation received a severe blow in 1973 when OPEC began to act as a cartel – an organization committed to keeping prices higher than the market would ordinarily allow. They were so successful that OPEC’s member states made price control the organization’s primary purpose, and for more than a decade a statement from OPEC was enough to give world energy markets the jitters. The energy crises of the period were possible because the world was no longer awash with oil. In particular, production in the United States (then the world’s largest producer) had begun to decline.

The Western world needed new supplies, and the volumes required were only available from OPEC members. This period culminated with the Iranian Revolution of 1979-80, which brought panic to oil markets. Dubai oil prices rose from about $2.00 (U.S.) per barrel in 1972 to $36 (U.S.) in 1980. All this was far more traumatic a generation ago than the rapid oil price increases of the last ten years. The reason is that – at least, in relative terms – oil then played a much larger role in the world economy.

Spot and Futures Prices: The market responded dramatically, and predictably, to these painful price increases. Consumers used less oil while producers pumped more. OPEC soon lost the ability to keep prices high. Then, in 1986, Saudi Arabia, an OPEC leader, flooded the market with oil in an effort to re-establish market share. As a result, prices plunged. Dubai oil dropped to $13, and fluctuated around that level for more than a decade. It did not move decisively upward again until 2000, when tight oil supplies began to squeeze prices higher. Aided by the convergence of computer and telecommunication technology and by increasing competition among global oil producers, the world’s response to these three “price shocks” – the price spikes of 1973 and 1980-1981 and the price collapse of 1986 – was to create a sophisticated global energy market.

After much turmoil, this market, which now accommodates innumerable buyers and sellers, imposed a laissez-faire discipline on the matter of global oil pricing. In this market, petroleum prices take the forms of “spot” and “futures” prices. Spot prices represent what traders charge for oil for immediate settlement – usually, delivery within two days. Futures prices are prices for delivery of oil at a certain date in the future – as soon as one month, as far into the future as nine years – at specified prices. Driven by a global network of traders working around the clock (except weekends and holidays), spot trades take into account the needs of refineries and a constant stream of geopolitical and economic data.

The markets are more strongly influenced by information about how much crude oil inventory is in America’s stockpiles than by OPEC statements about how much oil they are going to produce. News about hurricanes and other extreme weather events also figure into price calculations. So do rumours and worries about conditions in the world’s large economies. 

The world’s energy traders bring uncountable resources, facts, needs, expectations and beliefs about the future into their collective trading decisions. This interplay of intelligence and knowledge creates a group mind capable of processing extraordinary amounts of information as it establishes global prices. Charts of spot prices changing minute by minute can be found on numerous web sites.

Benchmark Pricing: Spot prices represent the business end of crude oil pricing, but futures contracts are the ones that truly set prices. As their name implies, futures contracts anticipate what prices will be in the future. Investors and speculators buy these contracts on major commodity exchanges, and spot traders use them as their main references as they negotiate prices.

Traders have developed many strategies using futures contracts. They are commonly used for financial speculation, but they also have practical business uses. Refiners can use them to secure the price they will pay for oil at certain points in the future, for example. To create futures markets, exchanges had to settle on particular kinds of oil to serve as benchmarks. The price of a barrel is highly dependent on both its grade (which is determined by factors such as its specific gravity and its sulfur content) and its point of delivery. In North America, the benchmark price on the New York Mercantile Exchange (NYMEX) is West Texas intermediate oil (WTI), delivered at Cushing, Oklahoma.

There are other benchmark crude oil contracts. Of these, the most important is Brent light, delivered at a port in the north of Scotland. Traded on the International Commodity Exchange in London, this oil contract essentially determines the price of oil in Europe and Africa. Oman oil, which is traded in Dubai, helps determine the cost of oil in the Middle East. The US government’s Energy Information Administration uses an entirely different approach to oil price calculations. It calculates the weighted average cost of oil imports (including oil from its biggest supplier, Canada) to determine the world oil price for the United States. Known as the Imported Refiner Acquisition Cost index, this is a lagging indicator. Instead of giving information about what prices are or will be, it describes what they have been.

Edmonton Par: Although Canada is a large and growing oil producer, we are a price taker rather than a price maker. Canadian prices are established by reference to the benchmarks of New York, especially, and of London. Those benchmarks are the price makers. The “real” price of oil is its spot price – the amount a buyer will pay for oil for real, immediate delivery. One important Canadian pricing standard is Edmonton light oil. How prices for that oil are established illustrates spot pricing in action. Initially, the price for Edmonton light is set by the companies – Imperial Oil, Petro-Canada, Shell and Suncor – with facilities at Refinery Row, near Alberta’s capital city.

Each morning they post the price they will pay for Edmonton light. Those prices closely track the most recent closing price for NYMEX futures contracts. The daily average of the prices offered by those four refiners is known as Edmonton Par, and it is the standard used for calculating oil prices in Western Canada. Foreign buyers (mostly located in Chicago) negotiate deals that take into account Edmonton Par, the futures price in New York, the spot price in Edmonton, the date the oil will be delivered, the difference in quality between Canadian light and WTI, the cost of transportation and the availability of competing supplies. As with other efficient markets, the price of Canadian oil reflects a balance of the needs and intelligence of many buyers and sellers.

Canada’s Split Personality: Global markets have had quite a big impact on the distribution of oil within Canada and across North America. In particular, they have helped determine which parts of North America use Canadian oil, and which use oil from the US and overseas. Refiners avoid the high transportation charges required to pipeline oil from Alberta to Toronto and points east. Instead, they buy oil from offshore Newfoundland or from international markets. That oil is delivered to ports in eastern Canada or to a pipeline terminal at the ice-free harbour in Portland, Maine. From those delivery points the oil is piped to major refining centres in Come-by-Chance, Nfld.; Saint John, NB; Montréal and St. Romauld, PQ; and Nanticoke, Ont.; and to smaller eastern refineries.

Oil from western Canada is another story. It is highly competitive from Vancouver to Sarnia, and in parts of the US West and Midwest. Many refiners in those areas have developed equipment designed to refine specific kinds of oil from Canadian producers. That specialized equipment is one part of the industrial infrastructure that has created secure markets for Canadian oil. Another is North America’s complex network of interconnected pipelines, which make delivery relatively easy.

In practice, Canada has a split personality in the matter of oil imports and exports, and this is mostly a function of our planet’s market pricing for oil. We are the seventh largest exporter of oil in the world, but also the seventh largest importer. In 2006, each day Canada exported 1,784,000 barrels of crude oil, mostly from the west. At the same time, however, we imported 849,000 per day into the east. Canada was thus a net exporter of 935,000 barrels of oil per day.

Because a great deal of our oil production is lower-quality heavy oil, in 2006 Canadian production on the whole sold for less than the $66 per barrel fetched by West Texas Intermediate. However, those net exports added more than $55 million per day to our trade balance with the world. The creation of a sophisticated global marketplace for crude oil coincided closely with the years in which Canada joined the big leagues of global oil producers and exporters. As we have seen, market pricing now suffuses the sector, and it has helped put the industry into its present form. An example is Canada’s decision to import oil for its eastern refineries while exporting oil from the west. In this instance and many others, efficient markets have helped create a cost-efficient industry.

Asia Ascending

This article appears in the January 2008 issue of Oilweek magazine.

Royal Dutch Shell traces its origins to Sumatra, and now Canadian companies are on the hunt for similar growth opportunities in Southeast Asia

By Peter McKenzie-Brown One hundred and twenty five years ago a Dutch planter, A. J. Zijlker, took cover from a tropical storm while travelling on the island of Sumatra. Sheltering in a tobacco shed, he saw a watchman light a fire from wet twigs using a bamboo torch. He asked what was fuelling the torch and the next day was taken to a small pond covered with a dark liquid. Soon after, Zijlker drilled the Telega Tila oil well near that pool. From his precarious derrick, Royal Dutch Shell's global empire eventually grew. This and other such ventures launched the petroleum industry in Southeast Asia and linked its resources to the energy markets of the world. As a result, Indonesia became a large-scale producer. The other regions of Southeast Asia, however, did not – at least not in the early days. Two world wars, the often bloody collapse of colonialism, political instability and the rise of autocratic government, endemic corruption – all these helped keep the petroleum industry out of the region. On the Southeast Asian mainland things were worse than in the archipelago. Not until after the Indochinese war did the area develop the stability needed for large-scale exploration and development programs.

Pan Orient: Fast forward to the present, and the Calgary offices of Pan Orient Energy. Everywhere you look there are Southeast Asian artefacts. The company’s offices are adorned with paintings of Buddha, a wooden sculpture of one of the ferocious demon-guardians that embellish Thai temples and many other fine pieces of traditional religious art. And so it should be.

One of few Canadian companies willing to risk operating in Southeast Asia, Pan Orient has achieved considerable success in Thailand. According to Pan Orient’s president, Jeff Chisholm, Southeast Asia is an ideal place to do business. The “real story” about the region, he says, is that smaller companies coming even into the heavily explored parts of Southeast Asia can succeed. “When the region was drilled in the ‘70s and ‘80s, the development threshold was a field of 50-100 million barrels” because prices were so much lower. Today, “we can make a lot of money on a 10-million-barrel field.”

 Although Pan Orient hasn’t done enough drilling to be able to calculate total reserves at its new onshore discovery in central Thailand, the first four wells tested between 1,200 and 1,900 barrels per day from multiple zones, and the company plans to complete another six wells. Chisholm, who has spent most of his career as an explorationist in South and Southeast Asia, is sanguine about drilling in the region.

Are there major political risks? He doesn’t think so. “The Asian economies are growing fast, so the governments need to keep the economy going. That means they need more (domestic) oil production.” Also, they learned from the 1997 currency crisis that they need to “keep their markets open, impose better financial controls and reduce corruption.”

In the region, only Indonesia has recently made changes to its fiscal regime. The country made its industry more attractive to foreign investors because the vast archipelago – formally a member of OPEC – has become an oil importer. Still poor, the government desperately wants to produce more oil. Chisholm says Thailand, with its open-bid system, is the most straightforward country to get into. The country has land auctions every two years. The government opens up areas of “deemed prospectivity,” and asks for bids.

To participate, you submit two envelopes to the Department of Natural Resources. The first describes your company’s credentials and financial information. If you get past that hurdle, departmental experts open the second envelope and review your proposed work program. To be awarded the contract, you must pass both tests, but it can take time.

 In the case of Pan Orient, the company worked with the elected government of Thaksin Shinawatra for more than a year to resolve some regulatory matters, with no success. The delays ended quickly after a military government took over in a bloodless coup, however. Chisholm offers this as evidence of the virtual irrelevance of political issues for explorers operating in Southeast Asia.

What about Burma (Myanmar)? “Burma’s about the only place you need to stay out of,” he says. “If the UN tells us it’s a bad place, we’ll take their word for it.” End of story, almost. As two Canadian companies discovered to their cost, you can pay public relations penalties for failing to heed Chisholm’s advice. Oracle Energy Group and CHC Helicopter Corporation both announced plans to conduct petroleum-related work in Myanmar, and both soon found themselves demonized on the Internet.

The Burma Campaign UK, a human rights organization opposed to the brutality of that country’s military regime, has posted the particulars of each company on its “Dirty List” of businesses that have signed contracts with the generals. There are numerous petroleum basins in Southeast Asia, many of them world-class. According to the United States Geological Service, 15 per cent of the world’s undiscovered oil and gas resources are in Southeast Asia. That prediction is an expert guess from an expert source, but proof can only come from the ultimate lie-detector, the drill bit. Another way to illustrate the region’s potential is to look at recent changes in production. 

The charts show oil (top chart) and gas production from the four largest Southeast Asian producers: Indonesia, Malaysia, Thailand and Vietnam. As they illustrate, growth in gas production since the early 70s has been rapid – indeed, this region has the world’s fastest-growing natural gas markets. In addition, growth in oil production outside the aging fields of Indonesia has also exhibited considerable strength. Most of the other countries of the region – Brunei, the Philippines, Papua New Guinea and blackballed Burma – also have exploration potential and expanding, lower-cost production.

Talisman: Though only a handful of Canadian companies are active in Southeast Asia, their experience has been positive. As we have seen, Thailand has been the key to success for Jeff Chisholm’s Pan Asian Energy. Two of Canada’s heavyweight producers – Talisman Energy and Husky Energy – also have interests in the region. Talisman is the larger and more experienced of the two.

According to vice president Jonathan Wright, the region has world-class production basins, low-cost operations and, because of the terms of the production sharing contracts his company has signed with the resource owners, rapid return of capital. For its part, the company has large and growing exploration acreage in the region, and existing production. The company got its foot in the door in the early 1990s when Talisman took over Bow Valley Energy, which had concessions in Indonesia.

The jewel in the company’s Indonesian crown is the Corridor property on the island of Sumatra, where the company has a huge gas field still being drilled, and still not fully understood. According to Wright, the reservoir is unusual in that it is not in sedimentary rock. “It is a basement granite structure. The reservoir is extremely porous and permeable, but the porosity exists mainly in fractures in the granite.” Some of those fractures are kilometres in length. With its 2001 takeover of a Swedish company, Lundin Oil, Talisman added properties in a border area between Malaysia and Vietnam to which both countries had previously laid claim.

The two countries reached an accord by agreeing to share production and called it the PM3 Commercial Arrangement Area, and Talisman is now partnering with national oil companies Petro-Vietnam and Petronas. Production is underway, and the three partners are investing more than $1 billion to expand production via the Northern Fields Project. They expect to nearly double production from its present daily rates – 40,000 barrels of oil and 175 million cubic feet of gas. Talisman’s share is 41 per cent. Southeast Asia already accounts for nearly 25 percent of Talisman’s total production. This is an especially impressive achievement when you consider that the company’s reserves have grown steadily and greatly since 1992, when the company became an independent entity. (Up to that time, it had been the Canadian subsidiary of BP.)

Talisman’s main production Southeast Asian production comes from Malaysia and Indonesia. The company has already announced exploration successes in Vietnam, however, and expects that country to be another good growth area. The company’s regional headquarters is in Kuala Lumpur, where Jonathan Wright hangs his hat. Few people are more enthusiastic about the region’s high potential than Wright. “Costs are rising here,” he says, “but they are still low compared to the rest of the world. And Vietnam and Malaysia are among the lowest-cost areas” per barrel for offshore exploration. “There are good hunting grounds here, but you have to be selective.”

In Malaysia the shallow basins have already been explored, “so you have to go (into) deeper (waters) or tie back smaller fields.” By contrast, Vietnam has not been as heavily explored, and the opportunities there are considerable. In one of its concessions, Talisman has been the beneficiary of two new-field discoveries. The first, which Talisman operated, may have 70-100 million barrels in place. The second is an industry discovery with perhaps 200-300 million barrels in place.

Unfortunately for Talisman, only a small portion of the field lies on the block it shares with its partners. “In our opinion (the contract area now being explored by Talisman) is the best block recently awarded in Vietnam,” says Wright. “It has basement granite as well as (more traditional sedimentary reservoir) potential. With luck, our Southeast Asia production could eventually rival our production from the North Sea.” Talisman is also pursuing exploration properties in Papua New Guinea, where it has already acquired natural gas acreage; in Thailand; and in the South China Sea offshore southern China. Technically the latter is not Southeast Asia but, says Wright, “geology knows no boundaries.”

Operations: Husky Energy must agree. The company has successfully secured exploration holdings off the coast of China, but the operator is a Chinese company, not Husky. The company has also negotiated a production sharing contract in the Madura Strait offshore Indonesia. Its contract area contains two prospects which, the company says, offer significant exploration promise.

The only large Canadian company besides Talisman now present in Southeast Asia, Husky describes its entry as part of a strategy to discover and develop conventional oil and gas outside North America. Do Canadian companies operate elsewhere in the world to the same high standards expected of them in Canada? According to Talisman’s Wright, the answer is a slightly qualified “Yes”. “Our environmental standards are the same (across the company) because we are one company,” he says. However, “the rules are different in different countries. We have to follow local regulations.” In Alberta virtually no natural gas can be flared. In the North Sea and Southeast Asia offshore, however, flaring is “permitted within certain limits, as there are sometimes no economically viable alternatives.”

With that qualification, Wright says, “our health, safety and environment umbrella is similar around the world. Our effluent standards for discharged water are the same in the North Sea and offshore Vietnam.” Is operating in Southeast Asia difficult from either a technical or a cultural perspective? Both Pan Orient’s Jeff Chisholm and Talisman’s Jonathan Wright say it isn’t so. According to Chisholm, “one key to successful operations is to incorporate as many locals into the work as you can.” Adds Wright, “you have to turn yourself to the national culture and setting. Beyond that, exploration challenges are similar around the world.”

Both Pan Orient and Talisman have demonstrated that developing a production base in Southeast Asia makes business sense. The pity is that other Canadian explorers haven’t yet taken that path.

Fiscal Issues in the Region
Southeast Asia is a region of vast diversity. Its countries host more than a thousand distinct languages and even more ethnic groups; a jumble of local customs, traditions and beliefs; and half a dozen major religions. The nations of this region have numerous forms of social organization, and they are ruled by governments ranging from monarchy through an assortment of democracies and socialist republics to Burma’s wicked military regime. For all their variety, these countries have one thing in common. In each case, the central government claims ownership of petroleum resources. Also, they have similar royalty regimes. Foreign companies gain the right to operate by signing technical assistance contracts (TAC) and production sharing contracts (PSC).

Technical Assistance: Technical assistance contracts are for marginal discovered fields that need technical help. One Canadian company that has secured such a contract is Vital Resources Corp. Vital’s technical assistance contract covers two properties – the Ramok and Senabing oilfields. The fields were discovered in the early 1900s but abandoned for decades until production was restored earlier this decade. According to the company’s Mike Whitehead, the TAC includes provisions that its costs will be paid out first from future production.

After payout, the company will receive 30 per cent of gross production. What is the potential for these fields? At present, they produce barely 100 barrels per day. If Vital is successful with its proposed $6 million enhanced oil recovery scheme, production could ramp up to as much as 2,500 barrels per day. For a micro-cap start-up like Vital, this contract could be the company-maker.

Production Sharing: Production sharing contracts are for areas that are prospective, but where there are no producing fields. While the specifics differ from country to country, the basic deal is the same. The country provides the contract area (prior to the 1970s, known as a “concession”) and may choose to put up some of the capital in return for an equity position in any discovery. The operator, however, develops the play and provides its own share of capital and the expertise needed to find and develop any hydrocarbons present.

Royalties vary, depending on whether capital investment has been recovered. Before the project has paid out, the royalty is based on “cost oil”, and it is small. Until the investors have received full payout, the company pays a royalty of, say, 10 per cent to the host government. This enables the investor to quickly recover the cost of successful drilling programs. After payout, production is known as “profit oil”, and the royalty increases. In the case of Pan Orient Energy, the company will pay the Thai government a production royalty of 15 per cent of profit oil, in cash. The company will also pay a 50 per cent tax on net income.

The Size of the Prize: In terms of economics, how does petroleum production in Southeast Asia compare to production in Canada? It’s hard to put the two side by side, but Talisman Energy vice president Jonathan Wright provides a ballpark estimate. “In Malaysia, the industry take (revenue share after expenses, royalties, and taxes) is 17 to 20 per cent (depending on the mix of oil and gas production). In Canada it averages about 25 per cent.” The gap between the two countries probably narrowed with Alberta’s recent royalty changes. Furthermore, he says, “The size of the prize is much greater here in Southeast Asia. Multi-hundred million barrel fields are still being found, in deeper horizons.” No such fields are likely to exist in Western Canada anymore.