Independence Day

Now that America's presidential race is decided, Canada's need to seek energy markets beyond the U.S. has never been more urgent.

 This article appears in the January, 2013 issue of Oilweek; photo from here

By Peter McKenzie-Brown

The day after America’s presidential election, the Calgary-based Canadian Defence and Foreign Affairs Institute (CDFAI) hosted a panel discussion on the political and economic significance of President Obama’s second term.

Some of the most interesting observations came from Jonathan Baron, an American lobbyist with a primarily Republican clientele. “What you need to know about Republicans and Democrats is that they hear different things when they hear the word energy. Say ‘energy’ to a Republican, and he will think about increasing energy production. Say ‘energy’ to a Democrat, and she will think about mitigating environmental impacts. It’s like another world.”

Now he was on a roll. “When a Republican thinks about Canada’s energy resources,” he added, “they really do think that these resources belong to America. There isn’t a strong sense that they are a sovereign asset for Canadians. For Republicans, the idea of North American energy security is a no-brainer.”

The irony is that the International Energy Agency issued its annual report a few days after this panel discussion – a report which seemed to put the cat among the pigeons. According to the IEA, “The global energy map is changing, with potentially far-reaching consequences for energy markets and trade. It is being redrawn by the resurgence in oil and gas production in the United States and could be further reshaped by a retreat from nuclear power in some countries, continued rapid growth in the use of wind and solar technologies and by the global spread of unconventional gas production.” According to this respected agency, the US will become the world’s top oil producer by 2017, and could be nearing energy self-sufficiency two decades later.

A bearish outlook for Canada’s oil producers, is this report worth long-term worry? Probably not. Since the 1972 publication of The Limits to Growth, a book which forecast shortages of virtually every commodity by the end of the 20^th Century, a good rule of thumb has been that long-term natural resource forecasts are always wrong.

To a large extent, this is because major forecasts are political. IEA member governments and some oil companies vet them before they go public. In the highly likely case that the United States reviewed the IEA forecast before it hit the streets, they would have wanted the agency’s report to justify fracking, Keystone, perhaps, and the West’s embargo of Iranian oil. As one commentator observed, “Forecasters test scenarios – they assess economic and energy trends to produce numbers. Among the enormous range of possibilities, one forecast is chosen for public purposes.” Also, of course, since Adam Smith published The Wealth of Nations in the 18^th century, economies have shown repeatedly that markets eventually equilibrate.

If you focus instead on the near-term implications of the recent US election, there is a lot of good news.

·         Before campaigning began, global warming environmentalists developed traction by opposing Keystone. Notwithstanding their public protests, sources Oilweek spoke to believe the project has a good likelihood of getting State Department approval. An okay would increase the integration of Canadian oil and bitumen production into US markets and provide tidewater access to overseas buyers.

·         On the gas side, this commodity will expand its market for power generation, and Canadians will perhaps gain an advantage in the export of this commodity overseas.

Keystone

President Obama’s re-election was a near-term good news story for Canada’s oil patch. If approved, he Keystone Pipeline will move bitumen to the 7.6 million barrel-per-day Gulf Coast market. It is worth remembering that the Department of State originally deferred its decision on the pipeline as a political gesture, so as not to alienate environmentalists during the election. The reason given was concern about a proposed segment of the pipeline route through environmentally sensitive sand hills in Nebraska.

According to Maryscot (“Scotty”) Greenwood, a left-leaning Democrat, “There is awareness in the United States about the importance of energy from Canada and I believe that awareness was heightened during the campaign. There is a renewed appreciation of the importance of North American energy independence.” She is reasonably confident the project will go ahead, using TCPL’s revised route. In a separate interview, AJM Deloitte’s geoscience director Dave Russum enumerated the reasons the State Department might stand behind Keystone: “Job creation, economy boost in the US, secure supply.”

For Canada, the benefits are different. Keystone would provide Canadian oil sands producers with direct access to America’s single biggest oil market. Thus that pipeline’s throughput would not be subject to the price differentials that have become chronic – especially for the oilsands sector. More importantly, the project would provide Canadian producers with access to tidewater. This would mean overseas markets and international prices. Meanwhile “we are in for a rocky time in the Canadian industry regardless of who is in the White House,” according to Russum. “When oil prices were more than $100, many projects looked pretty attractive, but current prices in the $85 range make the economics much less robust.”

Carbon emissions kept coming up during the CDFAI forum, and Greenwood stressed the political importance of the environmental constituency. “During the second term of the Obama administration (president Obama) has an imperative to deal with some new legislation which covers coal ash, soot and other environment-related questions. This will affect core constituencies. However, there is not necessarily a conflict between these two. You can look after these regulatory issues, and also do Keystone.”

Right-leaning Jonathon Baron disagreed. “The environmental community feels frustrated, so (their protests) have moved down to the state level. The president is going to have to do quite an interesting balancing act to deal with fracturing and Keystone.”

A master of Realpolitik, Baron offered hope for crude oil prices – but hope with a bitter taste. “There’s going to be more instability in the Middle East during an Obama presidency,” he said; after all, the president campaigned on having ended “a decade of war.” If the president is not willing to use American might in response to Iran’s apparent nuclear build-up, Baron argued, there will be mischief in the Middle East. “That volatility means high prices going forward. That has important implications in American markets for Canadian oil sands and natural gas.”

Gas Prices and Markets

Canada’s gas industry is likely to benefit from President Obama’s next term through the conversion of its power industry to natural gas. According to Scotty Greenwood, who served for two terms as a staffer in the Clinton White House, suggested that he “is looking for ways to regulate more stringently, to pivot to natural gas because it’s a cleaner burning fuel than coal. He does have a desire to build demand for natural gas and to clean up the coal industry.” Since it’s his second term, the president will find America’s powerful coal lobbies less daunting.

“During the election campaign Obama virtually did say ‘I hate coal!’” Baron told the CDFAI audience. “Cheap natural gas has given the president an opportunity that didn’t exist before. Because the United States knows that it is not going to be able to implement a carbon tax, it will instead increase the price of coal through regulation, making coal less competitive.”

North American gas markets are likely to expand at the expense of coal. In itself, this may not be cause for much celebration in Canada, since the United States is nearing self-sufficiency in this commodity, and its production and transportation costs are lower. However, Greenwood noted another area where the US political environment could unwittingly favour Canadian natural gas.

In the American political system, Congressional committees have plenty of muscle, and it matters who serves as the chair. The incoming chair of the Senate’s powerful Energy and Natural Resource Committee is Democrat Ron Wyden. Wyden believes large-scale LNG exports would raise natural gas prices in the US, harming the economy. In the past he has argued that Washington should impose a “timeout” on new LNG export facilities, pending review. “That could be the end politically for (additional) natural gas exports from United States,” said Greenwood.

“There is a gigantic and very legitimate debate about whether we should be exporting natural gas,” she added. “My observation is that in the United States it will be politically very difficult to export (gas to other countries).…This could be a big opportunity for Canada, since the same political challenges do not exist here.” Baron concurred. “There are already a number of LNG export projects in the United States. LNG exports along with hydraulic fracturing will be major issues during the president’s second term.”

While the Americans dither, Canada could approve and construct facilities for overseas markets. Eastern Canada already imports about two billion cubic feet per day of gas from the US, and “this is a cheaper source than Western Canada. We are of course a net exporter to the US, but that role is shrinking. We need alternative exports” said AJM Deloitte’s Russum. He observes that Canada is ‘way behind Australia and other countries in developing or expanding LNG facilities. While the US already has gas export facilities in operation, Canada’s first plant won’t be ready until 2019.

“To me the problem is that Canada can’t compete with gas supplies that are abundant, cheaper, and closer to market in the US – for example, Marcellus, Fayetteville, Barnett and Eagleford,” he added. “Gas is still a fossil fuel, so while it is cleaner and more environmentally friendly than coal, it still has the fossil fuel stigma and the fracking stigma. I’m unclear whether it is a problem or a solution in the US. In any case, if prices rise the US has shown it is able to drill and bring on new volumes of shale gas very quickly, which would in turn dampen prices.” Russum added that “prices for natural gas need to be considerably higher to make the industry profitable here.”

The US/Canada Alliance

Prime Minister Brian Mulroney once famously said that “the relationships (between prime ministers and presidents) are absolutely indispensable. If you don’t have a friendly and constructive personal relationship with the president of the United States, nothing is going to happen.”

According to Greenwood, the Canada/US relationship is “hugely important, writ large. It’s much bigger and more integrated than any personality. It matters who is in the White House, but in the end the relationship will do well because it has to, and because of all the history between the two countries.” She added that “the US government does not want to prevent Canadian development in any way. We have very close relationships, and those relationships are of great value on both sides of the border. I think the United States, as Canada’s most important commercial partner, wants Canada to be commercially successful in every possible way.”

Colin Robinson, a Canadian diplomat who helped broker the Canada-US Free Trade Agreement and NAFTA, stressed the importance of international cooperation to help prevent trade disputes. “The first lumber dispute between Canada and the United States goes back to the time of George Washington,” he reminded the CDFAI audience. “These kinds of things do lead to protectionism. In a lot of cases, we have to put competition aside and think of things as North American.”

“Whenever (a diplomat has) to do something in the United States you have to do it through the White House,” according to Baron. The State Department is critical for international affairs, but other parts of government are in play. Formerly Canada’s ambassador to the US, Frank McKenna once said that “The president can love you to death, but that doesn’t mean you don’t have constant harassment from Congress….The tone at the top helps, but it’s not conclusive.”

As this article went to press, there was optimism that the United States would not fall over the “fiscal cliff.” For the sake of talking about the near-term future, this article assumes a compromise that won’t suffocate North America’s economies. If America remains a house divided, though, Canada needs to declare greater independence from US commodity markets. That truth is self-evident.

"We Were Canadians First"

With the news of former premier Peter Lougheed’s death on September 13, aged 84, an outpouring of grief began throughout Alberta – indeed, throughout Canada. Rarely has a politician ranked so high in the esteem of the people he or she has been chosen to lead. 

This article appears in the November issue of Oilsands Review 

By Peter McKenzie-Brown

The tributes and commentaries ranged from reflections by ordinary citizens to formal commentaries from the great and the good. One of Lougheed’s biographers, Alan Hustak, observed that he was “the architect of modern Alberta” who, among many other achievements, helped turn the province’s petroleum industry into a global powerhouse. Nothing you can say about this great man seems over the top.

Lougheed’s career in the provincial Legislature began in 1967 – coincidentally, the year the Great Canadian Oil Sands (Suncor) plant was commissioned. The convergence is compelling, since several of his greatest achievements were oilsands-related. Energy issues dominated his years in power (1971 to 1985), and he was a decisive figure in what became known as Canada’s energy wars.

Among governmental issues, oilsands remained a core interest to the end of his long life. As he said in an Oil Sands Oral History Project interview 18 months ago, “After I left government in ’85 I said to my successor, Don Getty, ‘Don, I will stay out of most things you’re doing… but the one thing I am going to stay involved in is the oilsands, because I am very interested in its evolution and its development.…’ Things happened so quickly [under] Premier Klein. I have stayed involved in the oilsands in a more public way and I have discussed it frequently with Premier Stelmach as well. Perhaps more than any other, that’s the one subject I have stayed involved in since I left government.”

The Energy Wars: Lougheed’s early political battles began with a shot across the bow from Prime Minister Pierre Trudeau.

Inflation had become a national problem, oil prices were rising, and on September 4, 1973, Trudeau asked the western provinces to agree to a voluntary freeze on oil prices. Nine days later, his government imposed a 40-cent tax on every barrel of exported Canadian oil. The tax equalled the difference between domestic and international oil prices, and the revenues were used to subsidize imports for eastern refiners. At a stroke, Ottawa began subsidizing eastern consumers while reducing the revenues available to producing provinces (mostly Alberta) and the petroleum industry.

This outraged Premier Lougheed, who understood how long and hard the province had fought for control of its natural resources; resource ownership had not been conferred upon the province until 1930. In response, Lougheed announced that his government would revise its royalty policy in favour of a system linked to international oil prices.

His timing was impeccable. Two days later, on October 6, 1973, the Yom Kippur War broke out – a nail-biting affair between Israel and its Arab neighbours. OPEC used the conflict to double the posted price for a barrel of Saudi Arabian light oil to US$5.14. The Saudis and the other Arab states then imposed embargoes on countries supporting Israel, and oil prices rose quickly to $12. These events aggravated tensions among provincial, federal and industry leaders.

The rest of the 1970s were marked by rapid-fire, escalating moves and counter-moves by Ottawa, the western provinces and even Newfoundland. From 1974 to 1985, Ottawa imposed an export tax on conventional crude oil – a move Lougheed called “the most discriminatory action taken by a federal government against a particular province in the entire history of Confederation.”

Lougheed strongly asserted and ultimately resolved, beyond question, Alberta’s ownership of most hydrocarbon and other mineral resources within its provincial borders, and he made it clear to industry itself that the government was in charge. “It was obvious that the oilsands were owned by the people of Alberta,” he explained in the Oral History interview. “We consistently and constantly made sure that the industry understood that the Government of Alberta was the owner, and we weren’t just there in a supervisory or regulatory way. We were extensively involved because we were the owners.”

Canada’s political conflicts over energy climaxed with the introduction of the National Energy Program (NEP) in 1980. Lougheed led negotiations on significant modifications a year later, mainly exempting “new oil,” but the contentious policy was not fully removed until 1986. As the policy collapsed due to severe recession and wrong assumptions about global oil prices, Lougheed played a key role in negotiating a new constitutional agreement for Canada, then retired from office.

Syncrude: One of the positive developments of the energy wars era was the rescue of Syncrude in 1975. The oilsands project’s costs had soared, and one of its partners had pulled out. To a certain extent, that rescue involved a different way of looking at royalties. Lougheed’s interest in petroleum royalties began early in his years in power, before the events of the early 1970s embargo drove oil prices to historically high levels. “We were in a fairly experimental period with the oilsands,” he said, “we had the Great Canadian Oil Sands [project] which was struggling. When Syncrude came along and we got into the negotiations, it was clear we could not approach [the owner’s share] from the perspective of gross revenue….We had inherited from [Ernest Manning’s] Social Credit Government, a good system of royalties for the conventional oil and gas system, which was a percentage of gross revenue. We modified it from time to time in government, but the conventional oil and gas business was based on a percentage of the gross revenue.”

The oilsands were a different kettle of fish. Lougheed continued, “Right from the start it was clear that it wasn’t really fair because of the risk element that came with being involved in such a new process. You know, a lot of people wondered, was it going to work? Would it be economic?” All of those questions led to a discussion between the owner – the Government of Alberta – and Syncrude. ‘What kind of royalty scheme should we have?’ [The discussion] evolved into the whole question of a net profits approach. It was completely different than [the policy used for] the conventional oil and gas industry.”

The 1975 Winnipeg Agreement, which saved the Syncrude project, was one of the few moments of cooperation among governments during the energy wars. Always a savvy negotiator, during those 12 hours of meetings on February 1st, Lougheed committed the province to take a 10 per cent interest in the project for the then-mind-numbing sum of $200 million (about $1 billion in 2012 dollars). Alberta would provide loans that the province could convert into equity, would construct no-risk utilities for the project, and would purchase an ownership interest for cash. This proved to be an extraordinary investment for the people of Alberta, “the owners of the resource.”

AOSTRA: Through the formation of a government agency, Peter Lougheed created a scientific and technical environment that unlocked the secrets of producing bitumen from the deposits too deep for mining, and fundamentally transformed the industry itself.

At the time, work on the deeply buried oilsands reservoirs, which represent about 90 per cent of the resource, had stalled. Imperial had made progress on the Cold Lake deposit, but there were no demonstrated technologies that could commercially unlock deep oil from the Peace River, Athabasca or Wabasca (now seen as an extension of Athabasca) deposits. At the time, there was little likelihood things would improve. Few companies were actively developing oilsands leases outside the mineable area.

Originally called “Project Energy Breakthrough,” the idea was to speed up the development of new in situ oilsands technologies. When legislated into existence in June 1974, the Alberta Oil Sands Technology Research Agency (AOSTRA) became one of the largest research and development programs ever launched in Canada. The act originally limited AOSTRA’s activities to oilsands, but an amendment to the legislation soon gave the agency the authority to fund heavy crude oil research. In 1979, the Crown corporation’s mandate was expanded again to include enhanced recovery of conventional crude. Over its lifetime, AOSTRA funded about $1 billion (1980 currency) in oilsands extraction research.

Initially, the Alberta government agreed to invest $100 million in this technology development fund. During the active life of the corporation, however, AOSTRA spurred the petroleum industry to undertake numerous demonstration projects, representing some $2 billion of research and development spending. In most cases, the authority essentially agreed to match the amount of money a company or industry partnership was willing to invest in oilsands projects.

During the AOSTRA years, the industry launched in-situ demonstration projects in all the major oilsands deposits. These included cyclic steam stimulation (CSS); steam flooding; forward combustion; reverse combustion; and combined forward combustion and water injection (COFCAW). However, AOSTRA’s crowning achievement occurred 25 years ago, when its Underground Test Facility proved the effectiveness of steam-assisted gravity drainage (SAGD.)

Premier Lougheed got excited when he talked about SAGD.  “I think SAGD…should be encouraged by the owner and is being encouraged by the owner. It’s the longer-term asset for the province. Surface mining has its limitations, and involves more environmental and water concerns. So, there is a clear and important distinction when you get into oilsands and that’s what the Alberta Oil Sands Technology and Research Authority had been focusing on….Throughout all of our discussions here, let’s make sure that we are drawing a distinction between SAGD and in situ [those words can be used interchangeably] and surface mining.” Lougheed served on the board of MEG Energy, which was one of the first companies to develop a commercial SAGD operation.

Ideal Model: AOSTRA spurred oilsands experimentation and development, although prospects for further development diminished in early 1986 when a precipitous collapse in oil prices, once again, threatened commercial development. While AOSTRA did not have a mandate to undertake projects on its own, in the 1980s it took a significant risk by constructing the now-legendary Underground Test Facility. The UTF proved steam-assisted gravity drainage (SAGD), which has since emerged as the most important system for developing deep underground oilsands reservoirs.

A noteworthy footnote to this discussion is that the 2009 Summit of the Americas held AOSTRA up as an ideal model for energy development. According to the Centre of International Governance Innovation (CIGI), which sponsored the summit, AOSTRA “engaged the private sector and the university research community in developing technology related to the oilsands, while the government retained the rights to the technology.” A government endowment allowed the organization “to function independently of the electoral cycle. A dedicated expert and respected seven-member board of directors helped secure the private sector’s buy-in.” In addition, “control by the government helped maintain continuity over downturns in the economic cycle.”

CIGI also noted with approval that, before AOSTRA determined its goals, “it conducted two years of extensive consultations with many stakeholders. Only after determining exactly where the technology gaps existed did AOSTRA put out a call for proposals.” Furthermore, “aside from successfully developing new technology, AOSTRA fostered and financed a new generation of academic and scholarly expertise in many aspects of oilsands development. The investment in human resources is often discounted, but has been fundamental for the sector’s success in Alberta.”

Afterword: Much has been said about Lougheed’s impact on the province of Alberta. However, out of the seemingly endless stream of tributes that followed his death came this from former Prime Minister Brian Mulroney, whose government finally dismantled the National Energy Program. “Peter built the modern Alberta: schools, universities, hospitals, highways and whole communities [like modern Fort McMurray]. He always defended Alberta’s interests brilliantly around the federal-provincial table. At the same time, he would be the first to say…‘We were Canadians first.’”

Where it All Began

Equipment in the Underground Test Facility proved the effectiveness of  SAGD 

A quarter-century after the first Canadian horizontal well was drilled, the technology is the cornerstone of today's industry.

This article appears in the June issue of Oilweek

By Peter McKenzie-Brown
The world of oil and gas was quite a different place a quarter century ago. Production mostly came straight up out of vertical holes. Though the Texans had drilled the first horizontal well in 1929, in Canada horizontal drilling was still mostly an esoteric, unproved and untested technology.

In 1987, all that began to change – so much so that, during the last 25 years, it simultaneously emerged as a standard production technique and revolutionized production. One result is that many petroleum resources have become technology-driven plays. Another is that reserves are way, way up.

In a sense, the most important uses of horizontal drilling technologies are reverse images of each other. “What makes horizontal drilling for nonconventional resources (like shale gas and tight oil) so attractive to the financial community is the very high initial rate of return. In the beginning, production rates are extremely high, although they quickly taper off. You have to remember that these applications enable you to get highly desirable hydrocarbons out of really poor reservoirs,” according to Dave Russum, who is director of geosciences at AJM Deloitte, a consultancy.

The oilsands represent the mirror image of this situation. “You are drilling into tremendous reservoir rocks – highly porous and very permeable, so there’s plenty of oil in there. But until you process the stuff it isn’t a particularly attractive commodity.”

The Bitumen Story

It’s true that in April 1978 Imperial Oil drilled Canada’s first horizontal well into the Clearwater formation at Cold Lake – a storied well overseen by Dr. Roger Butler in an early test of a system of oilsands production now known as steam-assisted gravity drainage (SAGD). After that test and a less interesting effort by Texaco a couple of years later, in Canada the technique mostly languished until 1987.

Then the advent of improved down-hole drilling motors and the invention of other necessary supporting equipment, materials, and technologies – particularly down-hole telemetry equipment, which enabled rigs to drill straight on target – led to an explosion of new applications for this technology. Producers and the drilling and service firms that support them found endless new uses for directional drilling – especially as it is used for horizontal wells.

Appropriately, in Canada the first horizontal wells drilled after Imperial’s early test were part of the Underground Test Facility (UTF), which celebrated its official opening on June 29^th, 1987. Developed by the Alberta Oil Sands Technology and Research Authority (AOSTRA), the UTF involved a pair of tunnels driven into limestone 15 metres below the reservoir.

Within those tunnels, AOSTRA constructed large well chambers. “Pairs of injection and production wells were drilled upwards from the well chambers at a 17⁰ slant,” according to the mining engineer behind the project, Gerry Stephenson, “and deflected horizontally into the base of the reservoir. The mobilized bitumen drained by gravity from the steam chamber in the reservoir to the well head in the tunnel and all of the production was pumped from a central location.” Those tests proved Butler’s theories about SAGD beyond any possible doubt.

Over its 15-year life, the UTF also evaluated other recovery strategies, but nothing compared to its SAGD results. “AOSTRA’s staff had estimated that the recovery might be somewhere between 30 percent and 45 percent of the bitumen in place” during the Phase A tests, according to Stephenson. “We actually got 65 percent recovery. The steam chambers formed by mobilization of the bitumen spread way beyond the area we’d expected….Over the 10-year life of the well pairs, Phase B got a steam/oil ratio, the most critical figure of all, of 2.3 to one.”

The tests at the UTF forever transformed Canada’s oilsands industry. Today, SAGD is responsible for more than half of Canada’s bitumen production.

Ironically, Sceptre Resources drilled the first horizontal well in Saskatchewan to test a SAGD-like system at Tangleflags, just as the UTF began its definitive tests. Drilled into the shallow (450-metre) Lloydminster sandstone, this primitive application of a form of SAGD illustrated the kinds of problems horizontal drilling could overcome. With an active aquifer below and a gas cap above, the reservoir’s pay thickness was about 27 metres. The oil was heavy: about 13^o API. Primary production from the field had been meagre (0.6% of the oil in place), and the use of cyclic steam stimulation, which uses vertical production wells, had flopped when they tapped the aquifer and started producing 99% water.

That was when the company decided to try SAGD – not the technique we use today, but the primitive version Imperial had tried out nine years earlier. Sceptre injected steam through four vertical wells near the gas-oil contact, draining the mobilized oil through a horizontal well. At the industry’s leading edge, the company found itself with a technical and economic success.

Fast Production from Tight Reservoirs

More than any other series of innovations, the technology-intensive processes that now surround directional drilling have enabled the industry to get production out of otherwise unproductive rock. In August of that same transformational year, Alberta Energy drilled the first horizontal well into the Glauconitic formation at Suffield. This was the first time a Canadian operator drilled horizontally into a conventional oilfield.

Things then quickly sped up. In February 1998 alone, three significant projects based on horizontal drilling took off. Amoco began a 10-well horizontal drilling program at Athabasca, into the Wabiskaw formation. Canadian Hunter drilled gas wells at Ansell (Alberta) into the Cardium formation and at Helmet (British Columbia) into the Jean Marie. A few months later, Shell Canada drilled for Mississippian oil in Saskatchewan, at Weyburn. This early application of the technology was meant to connect isolated small reservoirs or improving contact within heterogeneous rocks to enhance the sweep efficiency.

“In the 1990s the big push was to explore conventional carbonate rocks, especially from the Mississippian in Saskatchewan,” according to AJM Deloitte’s Russum. “The idea was to develop known reservoirs where the rock quality was variable, using horizontal wells to extract more oil from those formations…. Many different companies hopped on to the horizontal drilling band wagon in Saskatchewan with more than 500 wells drilled into the Mississippian in 1997 alone.  In that year more than 1300 horizontal oil wells were drilled across the basin – a tally that was not beaten until 2007.”

Horizontal drilling also began to tap the heavier oils in Saskatchewan and southeastern Alberta in the 1990s, and there was a lot of experimentation in other reservoirs. Also, of course, in that decade SAGD began to be developed in its modern form.

As horizontal drilling became more commonplace, the petroleum industry began combining it with innovations in both drilling and well completion technologies and ideas. The result has been like a snowball rolling downhill. Horizontal drilling has been enhanced by geo-steering, measurement-while-drilling, coil tubing, down-hole motors and new bit design, for example. Also, producers can now drill multilateral horizontal wells from a single drilling pad.

Perhaps the important recent development on the drilling side is the monobore. Monobore drilling involves running a casing string, then forcing a steel cone down the well to expand it in the hole. This process is repeated with identical casing strings. Thus, monobore completions have the revolutionary characteristic of installing a string with the same interior diameter from top to bottom. “These are making a huge difference,” said Russum. “In the past you had to drill a vertical well, then run the casing to the bottom and wait for the casing to set before you could begin to drill the horizontal leg. Monobores help reduce those time-consuming steps.”

Although technologies like microseismic are also making a difference, the most important developments on the completion side have involved the increasing power and sophistication of hydraulic fracturing. Better fracking has developed because of new packers, better pumping equipment and better treatment fluids and proppants. “It’s now easier to isolate horizontal wells and to put fractures into certain points of the formation,” according to Russum. “In the early days, each stage of multistage fracking would take a whole day. Each frack would have to be tested separately before you proceeded to the next one. Today it’s a continuous process.”

These clusters of technological breakthroughs first created the shale gas revolution. Pioneered by an American, George Mitchell, in the Barnett shale in Texas, tight gas reservoirs began yielding highly economic volumes of natural gas – and, not incidentally, drove down the price of gas. Some observers now describe natural gas as a low-value by-product encountered in shale reservoirs in the quest for natural gas liquids.

From a production perspective, the other great outcome from this cluster of technologies has been the development of tight oil from shale – what Russum prefers to call “conventional oil from more shaley, low-permeability reservoirs.” One outcome is that both western Canada and the US are experiencing growing light oil production for the first time in decades – much of it coming from the Bakken play in North Dakota and Montana. After decades of decline in Alberta, for example, light oil production has recently risen to ten year highs.

An Explosion of Uses

These new technologies are changing almost everything about Canada’s petroleum industry. For example, horizontal wells are now a huge part of gas storage. “You can store gas very quickly into those wells,” said Russum, “and you can extract it quickly, too. Then there is the whole area of trying to reduce surface impact. I think we’re going to see more and more of that. Surface owners are more and more reluctant to have pumpjacks and other surface equipment on their land, and horizontal wells are less likely to disturb natural habitat. There is also extended reach, so you can reach under lakes and towns and cities. You can use it to reduce water production in a thin reservoir located over an aquifer.”

The economics of the horizontal well are also greatly improved, especially when you are planning production from a narrow reservoir – ten metres thick, for example. Horizontal wells provide much greater contact with the reservoir per dollar of drilling than do their vertical kin. And when they are drilled in search of unconventional resources like shale gas and tight oil, the producer gets a quick payback because initial production rates are so high.

Still not convinced? Then let the numbers tell the tale. According to an AJM Deloitte study which is complete to late 2011, more than 30,000 horizontal wells have produced conventional oil or gas in Western Canada over the past twenty five years.  Of that tally, 4,300 were completed in 2011.  This set a record for horizontal oil drilling: nearly 3,500 wells (led by the Cardium, Viking and Bakken), and an additional 800 wells focused on gas – mainly attracted by the high liquids content in the Montney and Middle Mannville. Today, half of Western Canada’s wells are being drilled horizontally.

Is horizontal drilling helping bring about any other changes? Perhaps it is even changing the way corporations work. “Companies that fail to adequately research the geology are putting themselves at considerable risk if they assume all resource plays are alike and that more and larger fracks are the solution to economic production,” according to Russum. Even so, engineers are increasingly replacing geologists in the executive suite.

Traditional geologists who spent entire careers looking for conventional reservoirs are now more interested in minor variations in rock properties, in stress regimes and in proximity to source rock. In terms of traditional petro-geology this is a difficult concept to grasp, but to a large extent it is a response to the revolution spawned by horizontal drilling.

Oilsands companies in particular, but also other companies involved in modern resource plays are basing their business plans on step-by-step, decades-long development of vast and well-defined resources. This means traditional wheeling-and-dealing is at least partly on the decline – to a large extent replaced by courting cash-rich foreign companies with deep pockets and the desire to support these capital-intensive activities.

Where to Go?

Some say transportation should be a market grail for natural gas, while others aren't so sure

This article appears in the second volume of CSUG's Energy Evolution Guidebook & Directory

By Peter McKenzie Brown
In his best-selling 1958 book The Affluent Society, Canadian-born economist John Kenneth Galbraith popularized the concept of conventional wisdom. “It will be convenient to have a name for the ideas which are esteemed at any time for their acceptability, and it should be a term that emphasizes this predictability,” he wrote. “I shall refer to these ideas henceforth as the conventional wisdom.” The problem with conventional wisdom is that it isn’t always true. Contrarians are often right.

Price Bull
It’s worth keeping that truism in mind as we develop the case for building new natural gas markets in North America. In a recent comment, author and analyst Peter Tertzakian argued that the rapid decline in drilling for natural gas across North America raises the question of whether natural gas is likely to continue to be in a serious state of oversupply. Tertzakian notes that for the first time in 15 years half of the US drilling fleet is drilling for oil, compared to less than 20% of rigs for the last decade. Such a dramatic decline in drilling almost certainly suggests that production levels will decline, he suggests.

He then moves on to the killer argument: “Let’s say (gas) production starts retreating in earnest this year and natural gas prices rise back to some fictional level like six dollars per MCF. Notionally, the (conventional) wisdom goes that producers will dispatch more rigs to ramp up production and thus clobber prices again. There is a problem with this line of thinking: why would producers do that when more money is to be made elsewhere?” He suggests that as long as oil is valued at more than four times the value of gas (energy equivalency basis), there is little motivation for the industry to shift toward more gas drilling. The result? Declining supply and still higher gas prices until a cost-reward rebalance restores aggressive natural gas drilling.

Supply Bull
Since Tertzakian is such an unusual voice in the wilderness, the balance of this article assumes that the conventional wisdom is true. Gas supplies are likely to continue to be plentiful, and there will continue to be a need to develop new markets. One of the most interesting advocates of greater markets is the legendary oilman T. Boone Pickens, who says he has invested $70 million in developing and promoting The Pickens Plan.

An 83-year-old geologist who received his degree in geology in 1951, as a young man the Texas-born Pickens spent a decade in Calgary. In a broadcast interview, he said he opened an office in Calgary in 1959, and lived in the province with his family in the 1960s. After moving back to the United States, he made a multibillion-dollar fortune in exploration and development and, much more publicly, as a corporate raider. His current passion is to promote the Pickens Plan.

“For 40 years the United States has had no energy plan,” he explained. “We’ve just been drifting. Just drifting means you are just importing more oil from the Middle East, countries that the state department recommends we not visit.”

Pickens is adamant that the United States should reduce its dependency on overseas oil, and he believes that renewables like wind and solar aren’t viable anymore because of cheap gas.

“Natural gas is the only thing we have that can replace non-North American foreign oil. We import 5 million barrels from the Mid East. That’s the oil I want to replace with gas. If you had 8 million 18-wheelers (in the US trucking fleet fuelled with natural gas), that would cut OPEC imports in half.” He added, “If the US administration announced that from now on all new government vehicles would use domestic fuel that would be a powerful message to send to the world.”

“This is a security issue for me. I don’t want to be dependent on the enemy for energy,” he said. Until gas prices cratered, Pickens was a strong advocate of wind energy, and he was leading an effort to finance a multi-billion dollar wind farm in the Texas Panhandle. He uses this fact to support his green credentials. “Natural gas is 30% cleaner than diesel. We have the cleaner, cheaper, abundant fuel here, and it will replace the dirty fuel from the Mid-East.”

Pickens is also an advocate of continental fuel switching – in particular, substituting natural gas for coal in power generation facilities.

For many years most commentators have believed that the United States could never become self-sufficient in energy, Pickens said, but “things have changed. We have so much natural gas – the US has a 100 years supply, and the Canadians have a lot up in Horn River, for example, and the Canadians have a lot of oilsands (oil). Let’s use that to make North America energy self-sufficient.” He added, “When people say to me, ‘Hey, Pickens, I don’t like your plan!’ I say ‘Fine, what’s your plan? If you don’t have a plan your plan is to import more oil from the Middle East.’”

Not many oilmen are as colourful as T. Boone Pickens or as motivated by worries about enemies in the Middle East. However, there are a lot of other natural gas supply bulls.

Exxon-Mobil, for example, demonstrated its belief by plunking down $31 billion for gas-focused XTO Energy a year and a half ago. A company vice president, William Colton, recently told the New York Times that “If there is any kind of major trend, we think it’s going to be a shift toward more natural gas.” He added that “Natural gas is available. It’s the most efficient way to generate massive power. It’s affordable. We already have gas infrastructure in place. From a CO2 emissions standpoint, it’s 60 per cent cleaner than coal, and (the U.S. has) 100 years of supply.”

Agency Bull
America’s Energy Information Agency, whose job is to forecast supply and demand based on best-guess current trends, doesn’t appear to see much of a plan to promote greater use of natural gas anywhere in the future. According to the early-bird version of the 2011 forecast, “Non-hydro renewables and natural gas are the fastest growing fuels used to generate electricity, but coal remains the dominant energy source for electricity generation because of continued reliance on existing coal-fired plants” well into the foreseeable future.

According to the EIA, the agency has revised its methodology for gas prices “to better reflect a lessening of the influence of oil prices on natural gas prices, in part because of the increase in shale gas supply and improvements in natural gas extraction technologies.”

Of course, as Peter Tertzakian argues at the beginning of this article, it might be a mug’s game to discount energy equivalency too deeply when you are calculating the relative values of oil and gas.

Whatever methodology the organization uses, the EIA does forecast an increase in North America’s natural gas demand, but its estimates seem paltry compared to the aggressive development that T Boone Pickens, for example, is promoting.

The agency forecasts a strong near-term increasing demand because of a “strong recovery in near-term industrial production, growth in combined heat and power, and relatively low natural gas prices.” Look farther out into the future, however, and the agency’s forecasters are more circumspect than the gas supply bulls. “U.S. natural gas consumption rises 16 percent from 22.7 trillion cubic feet in 2009,” they intone, “to 26.5 trillion cubic feet in 2035.”

Such a small increase in forecast demand – 16% over 25 years – suggests that the EIA’s gas supply bulls aren’t as optimistic as Pickens; he might complain that they “don’t have a plan.” You could equally argue that there are contrarians among them.

The Road to Success

Canada's shale gas producers are paving the way to successful exploitation of a massive resource

This article appears in the second volume of CSUG's Energy Evolution Guidebook & Directory

By Peter McKenzie-Brown

The shale gas revolution has turned the natural gas business upside down at a pace no one could ever have imagined. There is now tough competition in North American gas markets and the legendary successes of junior oil companies in the province—a crowning achievement of western Canada’s way of doing business –is in decline. Juniors can’t be really small anymore because they now generally require a lot of start-up capital. Crashing gas prices have put some into receivership, forced many to merge and forced all to change.

Perhaps Winter Petroleum—a small, privately held company—typifies the situation for little gas producers. With operations in the northwest corner of Alberta, the company got its name because its properties can only be drilled during the winter, according to president Duncan McCowan, a geologist.

“Winter drilling requires a lot of equipment and it’s expensive,” he says, “and our production is remote from major markets. Because of cost structure and transportation, we’re finding it tough to compete in U.S. markets.”

His company hasn’t let any employees go, however. “We are still slightly profitable, but we can’t grow. We’ve cut back our capital spending completely and many of our operational items too. (Dry gas) activity in that part of the province is at a standstill.”

McCowan points to a decline in the number of junior companies, partly through bankruptcies like that of Drake Energy, which was a neighbour to his own gas company, Winter Pete.

“Today you need pretty serious money for a start-up. A few million dollars won’t go very far anymore, because the new technologies we’re using involve horizontal wells and multi-stage fraccing. It used to be you could drill a well for a couple hundred thousand dollars. Today it takes millions, and financing groups are putting together a fund of, say, $35 to $70 million and then putting an experienced management team in charge. There are fewer mom and pop petroleum companies around.”

Peter Tertzakian of ARC Financial Corp. says two other important trends favour consolidation and larger companies.

“Bulking up to get costs down helps you deal with lower prices. It gives you economies of scale. A related factor is that a lot of companies are migrating to horizontal drilling and completion strategies, but that’s very expensive.”

On average those wells cost $4.5 million, and there have been many wells that cost $8 million or more. “By drilling fewer wells that are more expensive each, you need more backbone – you need to be a bigger company.”

The companies most at risk are those that are heavily leveraged and biased to natural gas, but many of the smaller ones are successfully implementing what he calls “revitalization strategies: shifting their focus to liquids-rich gas, or even prospecting for oil. A small amount of liquids in the gas stream can make a big difference” since it often has a greater market value than oil.

Compare that situation to the one announced in February, when PetroChina made a huge counter-intuitive deal with EnCana Corp. While other major Asian investments in the Canadian petroleum industry have mostly gone into the oilsands, Petro-China put its money into shale gas. The two companies announced that they had inked a $5.4 billion deal by which they would become equal partners in EnCana’s Cutbank Ridge gas field in British Columbia. This investment, which surpasses Sinopec Corp.’s $4.65 billion acquisition of ConocoPhillips’ stake in Syncrude last year, is Asia’s largest single bet on North America’s energy sector.

According to EnCana spokesman Alan Boras, the focus of this effort is natural gas, not the associated gas liquids.

“We are always looking for ways to maximize the value of our assets, and natural gas liquids extraction is an important part of that process,” he says. “However, that is not our major focus.”

Since the company does not see natural gas prices above $6.63 per thousand cubic feet in the foreseeable future (2021), EnCana clearly is basing its business plan on something other than an upward move in North American gas prices.

One of those ideas is low-cost production. According to Boras, “In the Montney, where we have done the deal with PetroChina, our wellhead cost is about $3.15 (per thousand cubic feet).”

The deal will enable the Chinese to “get an early return on their investment, and then take the technology back to China to use it there. That certainly is part of what they’re thinking. The Chinese have recently talked openly about their need to increase domestic gas use.”

In addition to low-cost production, new pipe in a region already riddled with infrastructure could lower future transportation costs. This is the significance of the National Energy Board’s recent approval of TransCanada Corp.’s plan to build a $310 million pipeline to connect British Columbia’s Horn River shale gas region to its Alberta mainline system.

Ascendancy?
While the gas industry isn’t exactly in the ascendant, some trends suggest that ascendancy might not be far off. This isn’t readily apparent, since shale gas has backed Canadian producers out of traditional U.S. markets and driven down prices.

Low prices have made much of Canada’s conventional gas uneconomic in distant U.S. markets, and many producers are in trouble. In recent years the only major commodity to decline in price and stay there, natural gas has mostly defied winter demand for heat and summer demand for air conditioning.

The price collapse is forcing the industry to dramatically restructure, clouding the outlook. Such legacy assets as Canada’s Arctic gas fields look increasingly like white elephants: the likelihood of a pipeline from north to south is slipping ever farther into the future.

According to Robin Mann, president of AJM Petroleum Consulting, “Because of the development of shale gas formations like Montney and Horn River and others with great potential right next to infrastructure and pipelines, and with our existing conventional gas and our exports to the United States going down daily, we have more than enough (gas) for our own (use) so why is it important to build these pipelines? Why are we worrying about anything north of Alberta and B.C.?”

Consumers are happy with lower prices. Companies are not, however, and neither is the government of Alberta—now into its fifth consecutive year of deficit budgets.

One Alberta politician with ideas on the issue is Wildrose Alliance leader Danielle Smith, who doesn’t have to worry about balancing this year’s provincial budget. She sees the collapse in gas prices as an opportunity.

“There is so much we can do now to increase demand: fuel switching, the Pickens Plan (to increase gas use in automotive transport) in the United States, increasing use of gas for power generation.”

She even talks about installing modern-day gas-fired Stirling engines in our homes, to generate both heat and power. “If we do these things, consumers win. So does the environment and so do gas producers.”

In a way, those simple ideas describe a path that could bring the industry out of its funk. They are also consistent with much of what the industry is already doing in response to a rapidly changing business environment.

One industry response has been to reduce natural gas drilling--at this writing, at a one-year low. Companies are focusing instead on drilling for oil. According to ARC Financial’s Tertzakian, “this capital migration continues to be a positive leading indicator for natural gas price recovery.”

The industry is also responding to low prices with rapid adaptation of technology. It is cutting costs, seeking profitable niches and developing better markets. In addition, consumers are responding to the attractive price of natural gas, and policymakers are seeing it as a low-carbon alternative to other fuels.

And North America’s dominance in shale gas development makes it for the first time a potential large-scale manufacturer of liquids made from natural gas.

Gas-to-liquids
The gas-to-liquids concept is most evident in the billion-dollar deal Talisman Energy struck late last year with Sasol, the South African petrochemicals giant. The deal involved selling a 50 per cent interest in Talisman’s Farrell Creek shale gas properties in British Columbia. Eventually, the partnership could develop a plant using Sasol’s gas-to-liquids technology to turn the gas into a desirable liquid fuel. This is proven technology: Shell, for example, is constructing a $6 billion gas-to-liquids project in Qatar, the tiny Middle Eastern country with 15 per cent of the world’s proved natural gas reserves.

Another way to solve the stranded gas problem is to create liquefaction facilities for natural gas exports. When finished, the $3 billion Kitimat LNG project will become another face in the global LNG market—competing with, for example, Qatar.

According to Rosemary Boulton, the founding president of Kitimat LNG, “we’re experiencing a bigger gas bubble than we have seen in western Canada for 20 years, and this makes (LNG exports) a particularly viable proposition. We need to develop LNG to meet the needs of gas markets other than those in the U.S.”

Apache Corporation and EOG Resources obviously agree, since in December they bought out her start-up company—after it had received development approvals—and Canadian gas giant Encana Corp. came onboard with a 30 per cent interest this past March.

Countries like India and China will eventually begin developing their own shale gas resources but at present “Japan and Korea are the world’s biggest importers of natural gas,” says Boulton, “and they have no indigenous supply.”

She adds that “there are a number of ways you can write a price contract, and one of them is based on the price of WTI. That’s a pretty good price for exporters. For importers, it’s a lot better than a contract based on the price of Brent (North Sea) oil. Markets in Asia price natural gas relative to the price of oil, so that could be very attractive.”

Bill Gwozd, a vice president of Calgary-based Ziff Energy Services, agrees. “If you have an Asian market that’s prepared to pay (an LNG) price that’s linked to oil, we think (shale gas production) can surge.”

Boulton sees room for expansion of Canada’s international LNG business. “The Kitimat project is approved for five metric tonnes or 700 million cubic feet per day. The pipeline will be capable of supporting a much bigger project—doubling (project capacity) is certainly viable.”

She doesn’t see a lot of LNG shipments leaving from B.C.’s Lower Mainland, however. “Projects are all about location. I see a lot of objections to a project (there) because of the nature of some communities on the Left Coast.”

Stakeholder engagement
A year ago, American filmmaker Josh Fox released a film called Gasland, which purported to document the dangers of hydraulic fracturing for shale gas. One landowner after another talked about the dangers of shale gas to their health, and some spectacular footage showed a man setting water from his kitchen tap alight – the result, he said, of shale gas polluting his water well.

Ziff Energy’s Bill Gwozd is sceptical. While he acknowledges that the consumption of large amounts of water for fraccing can be an environmental problem in areas where water is in short supply, he’s sceptical about the rest. “Shale gas and ground water are peanut butter and oil,” he says. “They don’t touch each other.

There are a lot of people who want to talk about shale gas polluting groundwater but it just isn’t going to happen.”

He points out that the geological zones which hold groundwater and shale gas can be literally thousands of feet apart, and that dirt and rock under pressure are anything but porous. “So how could deep zones of shale gas pollute groundwater, which is maybe 1500 metres up?”

“You’ve got to believe that the answer is in the details,” he says. “A lot of people complain about shale gas development without bothering to understand the technical issue. When you get into that conversation, they have to come to the conclusion that there is no problem here.”

Well, not entirely. In March Québec’s environment minister, Pierre Arcand, said the government didn’t have enough scientific information about hydraulic fracturing to sanction its further use. Until his department completed its research into what had become a heated public issue, the government imposed a drilling moratorium on Québec’s promising Utica shales.

Ziff’s Gwozd has a kind of conspiracy theory respecting public concern about shale gas. “Who’s driving the environmental objections?” he asks, rhetorically, then offers his own answer: “Anybody (with an interest in) conventional gas, in LNG, in coal, in energy alternatives. If you complain about it, you make it an issue. (To say these worries are based on science) is like the fox telling the bird he doesn’t want to cook it for turkey day.”

Enter Lane Wells, the principal at head•stock, a public consultation firm which specializes in aboriginal communities. Wells describes effective stakeholder engagement as involving “thoughtful, non-adversarial and respectful exchanges of information. Listening to stakeholders is important. Responding to what you have heard is critical.” Stakeholder engagement is becoming increasingly crucial if you want public policies that give you the right just to develop shale gas.

Changing Policy
Public policy is becoming increasingly important in other ways, too. For example, the Obama administration is now behind a drive to make natural gas the fuel of choice in as many energy-consuming applications as possible, with an emphasis on switching coal-fired power plants to gas.

Senior Democrats in Congress are getting behind the stuff, portraying it as an alternative fuel for transportation that can serve as a stopgap until renewable sources of energy, like solar and wind power, become economical on a broad scale.

Reflecting this policy, last year Rahm Emanuel—a congressman and formerly President Barack Obama’s chief of staff—introduced legislation which would have offered tax credits to both gas producers and consumers. The legislation died with last fall’s election, which unceremoniously turfed Emanuel and other Democrats from the House.

The promotion of natural gas as a fuel is popular within the industry also. The New York Times cites William M. Colton, ExxonMobil’s vice president for corporate strategic planning, as a serious natural gas enthusiast.

“If there is any kind of major trend, we think it’s going to be a shift toward more natural gas. Natural gas is available. It’s the most efficient way to generate massive power. It’s affordable. We already have gas infrastructure in place. From a CO2 emissions standpoint, it’s 60 per cent cleaner than coal, and (the U.S. has) 100 years of supply.”

As these issues get resolved, a leaner and meaner industry using advanced technologies and far more capital is emerging. The industry is opening its collective eyes to a brave new world of natural gas—one in which surplus supplies are convulsing the sector in many ways.

“Our intent is to tough it out,” says Winter Petroleum’s Duncan McCowan. “So we’re doing creative things to cut costs—jointly handling gas with our neighbours, for example. We’re optimistic about our geology—the horizontal potential is huge, but we couldn’t justify (horizontal drilling) in this price environment. Sure, we’re pessimistic about gas prices, but we know they’re going to turn. We don’t know when, but when they do we think it’s going to be pretty quick.”

Dr. Sidney Ells

Consummate oilsands pioneer

This article appears in the 2011 Heavy Oil and Oilsands Guidebook

By Peter McKenzie-Brown
The first person with a technical background to devote his career to investigating the oilsands, Dr. Sydney Ells (1880?-1971) was the consummate oilsands pioneer. Until 1930, Ottawa held jurisdiction and ownership of Alberta’s mineral resources, and the federal Mines Department hired him in 1913 to investigate the resource potential of the oilsands. During more than 30 years with the department, he prepared 26 official oilsands reports and 15 maps of the region.

His 1913 report was the first government paper to stress that the oilsands in their own right had enormous economic potential. Previous investigators had proposed seeking light oil reservoirs near or underneath the sands. Working with the Parks Department, he then had 580 acres of prime oilsands property just outside the village of Fort McMurray designated the Horse River Reserve. It was on these lands that he conducted much of his research.

One notable experiment began in 1915. Ells shipped tons of oilsands by water, sleigh, and rail to Edmonton for a road-paving experiment. The stuff was used, without much need for repair, until the 1950s. Ells spent the last two years of the First World War in the armed forces. When the war was over, he returned to his work with the oilsands, soon becoming the federal government’s go-to guy on the oil sands.

Ells generally wintered in Ottawa, but spent summer months in the field. The trip from Edmonton to Fort McMurray in the early days was tremendously difficult. The first leg (145 km) was by wagon to Athabasca Landing. From there, he and his crew descended the river in a primitive scow. The return journey was worse, since it went against the current. Strong men used ropes to haul the scow to Athabasca Landing.

On one memorable occasion, Ells and his cocker spaniel actually walked the distance from Fort Mac to Athabasca Landing. So difficult were the conditions that he spent two days in hospital when he finally reached Edmonton.

In the 1920s Ells continued the paving material tests, with roads as far afield as Camrose, Jasper and Ottawa getting the oilsands treatment. He also arranged for test drilling – not for production purposes, but strictly to analyse the core. He invested a great deal of time and energy measuring geologic features, mapping terrain and cataloguing oilsands specifications. The oilsands got into Sidney Ells’ blood, and he stayed on top of research long after retirement in 1945.

Development efforts increased during the 1920s and 1930s – especially after the Alberta Research Council’s Dr. Karl Clark developed his game-changing hot-water separation process. After Alberta took ownership of the oilsands in 1930, however, Ells’ influence in the area went into decline.

His knowledge and enthusiasm had encouraged many business people and promoters to take an interest in the deposits, however, and his work helped create the cornerstone of today’s oilsands industry. Notably, in 1929 he went to Denver to meet with oil company executive Max Ball to discuss prospects for developing production from the Athabasca deposit. Having received Ells’ endorsement, Ball soon secured oilsands properties from the Dominion government – the last leases to be issued by the feds.

With encouragement from Ells that eventually overcame the discouraging economic conditions of the Great Depression, Ball began constructing the pioneering Abasand plant in 1936 but mining didn’t finally begin until 1941. In its first four months of operation, the plant processed 18,475 tonnes of oil sand to produce 17,000 barrels of oil then burned to the ground. The company rebuilt the plant and, in 1943, the federal government took it over as part of the war effort and experimented unsuccessfully with a cold-water process. Work at Abasand ended in 1945 when fire again destroyed the operation. That wasn’t the end of the Abasand legacy, though. In 1958 its leases became bedrock properties for Great Canadian Oil Sands (now Suncor).

Ells’ pioneering efforts were not rewarded with a truly commercial project during his working career. More than half a century after he began his pioneering investigations, he was a guest of honour at the official opening of the Great Canadian Oil Sands plant in 1967. After years of struggle, GCOS became the first truly commercial oilsands plant. However, Ells’ former colleague, friend and rival didn’t make the opening. Karl Clark had died nine months earlier of cancer.

Tell Your Banker to Buzz Off!

As lines of bank credit grow increasingly restrictive, royalty financing offers new options for operators. This article appears in the February issue of Oilweek

By Peter McKenzie-Brown and Richard Graham

Especially if you’re a natural gas producer, it can be tough to get credit these days. What are you going to do?

One possibility is to do what Compton Petroleum did last spring. Primarily a gas producer, the company sold a 5% royalty interest in 19,000 barrels of oil equivalent (BOEs) production per day, plus a 5% interest in 600,000 undeveloped acres to Caledonian Royalty Corporation, a company founded and managed by oil and gas financier Jim Kinnear.

In a way, royalty financing is filling a gap created by the elimination of energy trusts – at least, that’s what conventional wisdom would like you to think. However, as we researched this story, it became increasingly clear that royalty financing not only meets the needs of investors (especially heavy hitters), but it is also an excellent tool to meet the industry’s needs – natural gas companies like Compton Petroleum, for example, but other companies as well. While the industry traditionally associates the idea of royalties with government take, the new players in this area are promoting it as an effective alternative financing tool. While the jury is still out on whether it will be a preferred form of funding during the next boom, right now it has a lot of merit.

The Olden Days
Royalty funding is not new in Canada’s oil and gas sector, but the industry has to a large extent lost its collective memory of royalty financing. The founder of royalty financing in Canada was R.A. (Bob) Brown who, with his son – also named Bob Brown – later turned Home Oil into a major independent oil company.

During the Great Depression royalty financing played a critical role in the development of Turner Valley – at the time “the biggest oilfield in the British Empire.” On June 16, 1936, Brown senior’s Turner Valley Royalties #1 well began flowing 850 barrels of crude oil per day. Funded by royalty financing which guaranteed investors a percentage production from successful wells, Royalties #1 found Turner Valley’s oil formation two decades after earlier producers began stripping naphtha from wet gas discoveries there. This meant the first generation of producers had wasted much of the pressure needed to produce light oil from the reservoir.

Royalties financed 69 other wells in Turner Valley in the two years following Brown’s discovery. Since only two of those wells were dry, the primary constraint on new investment was the rapid saturation of local crude oil markets.

Royalties financing didn’t last, however. In 1938 the federal government decreed that income from oil production was taxable as profits in the hands of the producing company. In the investor’s hands it was taxed again as income, rather than return of capital. Although a producing company appealed this decision successfully, the incident shook confidence in the system. Indeed, in 1942 Ottawa amended the Income Tax Act to tax oil income from royalty trusts at wartime rates. Although the federal government repealed this provision in 1950, it was 70 years before petroleum royalties again became a significant alternative to traditional debt and equity.

Teams at Play
In recent years, at least four teams have suited up for the royalty game. Each team has its own style of play and a strategy that sounds like a winner. Brickburn Asset Management has the most passive style of play. Range Royalty Management is the brainchild of Clayton Woitas, founder of Renaissance Energy, and effectively combines royalty financing with E&P. Caledonian, founded and controlled by Jim Kinnear, is new while the fourth, Freehold Royalties Ltd. has roots going back to the creation of Canada.

Until it converted to a dividend-paying corporation at the beginning of 2011, Freehold was a publicly listed trust that issued distributions based on a large number of diverse royalty-generating properties (mineral rights and gross overriding royalties) and working interest properties. Its income comes from oil, gas, liquids and potash. Many of its properties are legacy assets – royalty rights which Ottawa granted to railroads and the Hudson’s Bay Company as part of the national effort to secure Western Canada. Freehold has interests in more than two million gross acres of land and 23,000 wells.

In a statement, the company’s president and chief executive officer, Bill Ingram, said that most “of our oil and gas production comes from mineral title lands and gross overriding royalties, which have no associated capital or operating costs; thus we have relatively low capital expenditure requirements. The strength of our royalties has allowed us to preserve a high payout ratio historically and should allow us to maintain a high dividend payout.”

The newest team is that of financier Jim Kinnear, who sees royalty financing as an extension of a common practice in Canada’s mining sector. When he started out in the securities business, says Kinnear, “we invested in small mining syndicates that had acquired claims – money returned plus a carried interest. I learned about returning capital to investors. People liked to see a return of cash or cash flow, and they still do.”

Last year, after retiring from Pengrowth Energy Trust – a business he founded and managed for over 20 years – Kinnear began applying this lesson in finance to oil and gas in an innovative way. So far he and his investors have placed $100 million in Caledonian Royalty Corporation. Their royalty investments – which represent registered interests in land and rank ahead of banks and other creditors – allow qualified investors to participate in cash flow based on production. Caledonian’s royalty interests include current production and potential future production from a large undeveloped land base in Alberta. At present, those assets are heavily weighted towards natural gas.

Range Royalty Management operates rather more like a traditional oil company, but also does financing through the issuance of royalties. The company was not willing to be interviewed for this story, but a source who asked to remain anonymous describes the firm as having “a great technical team. While they always want an overriding royalty, they get at it in a different way. They begin at the grassroots level” – by going to land sales, drilling and frequently operating oil and gas properties. Issuing royalties effectively gives the company financing that bears no interest, doesn’t need to be repaid and is free of commodity price risk.

The Problem with PUDs
Another newcomer to royalty financing is Bill Bonner, president of Brickburn Asset Management. Brickburn manages four partnership funds that invest in royalty interests under the WCSB brand name.

Although he has had a long career in oil and gas financing, Bonner only added royalty financing to his company’s portfolio in 2008. His system is both conservative and traditional. “We raise capital through prospectus,” he explains, “then make that capital available to experienced operators for the completion of development wells. In return, we earn a gross overriding royalty. One way to think about this is that we rent the operator’s wellbores. We are not concerned with any of the traditional costs, including the well’s ultimate abandonment.” He adds, “The sanctity of the royalty position is a very special place to get to.”

Bonner is adamant that royalty financing in its own right is an effective and robust form of finance rather than a replacement for the energy trust. When the oil industry goes into boom mode again, “we think there will still be opportunities for this kind of instrument, although candidly we don’t know for sure.”

He adds that “the main link between us and income trusts is that we pay out capital as we receive it. We provide a stream of income which the investor really likes. We are very much a distribution model as opposed to a model where you retain capital and grow. One of the advantages we have is that our investors get a tax write-off – a 30% Canadian Development Expense, which enables them to write off all of the money they have invested. It just takes time.”

He adds, “We have completed five partnerships totalling $82 million. We only take the money for three years. At that point our prospectuses say we will offer a ‘liquidity event’ to return the capital investment back to the investor. Our game plan is to somehow monetize the property after our investments have gone through a period of flush production – either by selling it outright or by somehow putting it into a going-concern business.”

Brickburn’s first royalty partnership came about in 2008. After the 2006 Halloween Massacre imposed a new tax on energy trusts, he says “it became increasingly difficult for smaller energy businesses to finance growth because for them the liquidation opportunity (selling their assets to energy trusts) had disappeared. So we moved in with this royalty instrument.” Complicating the tax problem was the financial crisis. Traditional sources of equity and debt financing for junior oil and gas companies seemed to have disappeared. Part of the solution was royalty financing.

Brickburn royalty partnerships have participated in more than 70 wells, 95% of which used horizontal multi-frac technology. “One of the reasons operators like us,” according to Bonner, “is that we extend their budgets. If we provide one and a half million dollars for a horizontal well, it frees up that much money for them to go do something else.” Royalties can add to the companies’ bottom lines in other ways, too. One of the main reasons is that operators tend to carry inventories of “proven undeveloped reserves,” or PUDs.

“The problem with PUDs,” says Bonner, “is that you get credit on your balance sheet for them as a proven resource, but now you have to throw a lot of money at them to turn them into developed resource. What we did was to come along and offer operators the opportunity to develop those PUDs in a way that was not dilutive to equity” since royalty interest investments equate to non-repayable loans. “Even though interest rates for the last couple of years have been close to zero, royalty financing is attractive because you don’t have to pay back the principle. When operators began to see this, they quickly realized that taking our capital was very accretive to the capital they had to spend themselves.”

Through its family of funds, Brickburn has acquired royalty interests through 11 operating companies, but is bound by agreement not to mention names. However, Delphi Energy and Bellatrix Exploration have both publically acknowledged that they use royalty financing from Brickburn.

Revolution Repeated

The Western Canada Sedimentary Basin. This article appears in the February issue of Oilweek.

By Peter McKenzie-Brown

First came the revolution in natural gas production – the shift to shale gas which, by bringing huge new stores of natural gas into the market drove prices down and made it necessary to fundamentally restructure Canada’s gas-prone petroleum sector. Now comes the revolution in the oilfield. Ironically, the same technologies that made shale gas possible are enabling the industry to begin the restructuring that the shift to shale gas made necessary.

“Oil doesn’t flow as well as gas,” Legacy Oil & Gas president Trent Yanko reminds us. “So in the oilfields of Alberta, especially, is a tremendous opportunity to recover unproduced oil. Original oil in place was in the billions of barrels, so if you can add only one, two, three percent to recovery there is quite an opportunity. You don’t have to be a wildcatter out in the jungle somewhere. All you have to do is better exploit what we already know is there.”

The technologies that made the shale gas revolution possible are beginning to have a similar impact in the light and conventional oil sector, which can now develop reservoirs that could not be exploited until energy prices and new technologies made production economic. For small companies in particular, this is presenting exceptional opportunities. From start-ups to mid-caps, companies like TriAxon and PetroBakken Energy are creating profitable enterprises from oilfields discovered 50 years ago. Already successful in similar enterprises, Legacy is taking on the big kahuna – the century-old field that put Canada’s petroleum headquarters on the map.
Juniors and the Treadmill

Since it became commonplace in the late 1980s, horizontal drilling has been enhanced by increased drilling efficiency. Much longer horizontal legs are now possible: many are two and three kilometres in length. This is possible because of improvements in bit design, the increasingly effective use of coil tubing and better down-hole motors. Other contributors include geo-steering and increasingly effective measurement-while-drilling (MWD) tools and techniques. Most important of all is multi-stage fracturing. The industry can now isolate many completion zones along lengthy horizontal wellbores: a two-kilometre horizontal leg can host up to 20 hydraulic fractures.

These technologies are making formations like the Bakken viable. Increasingly, the technologies that created the shale gas revolution – long horizontal wells and multistage fracturing – are being applied to aging light oil reservoirs in North America. This production phenomenon has also involved largely unacknowledged regulatory responses by the governments of Western Canada. These factors and other technologies are opening up important new opportunities for production from largely depleted reservoirs. For example, Gary Leach – executive director of SEPAC (the Small Explorers and Producers Association of Canada) – notes that “microseismic for the more precise design of frac jobs is a particularly important new technology.”

A year ago, TriAxon Resources represented a big success story among private junior oil companies. The company was created with what in 2006 was the novel idea of applying the cluster of new technologies to oil production. After screening available prospects, the company focused on the Bakken, Glauconite, Cardium, and Viking formations. The company raised $87 million in private financing; two and a half years later the partners sold out to Crescent Point Energy for $257 million.

Then, according to former president Jeff Saponja, he and his two partners – chief operating officer Colin Flanagan and operations vice president Rob Hari – took a two-week break before establishing TriAxon Oil Corp. – “TriAxon Two,” he calls it.

The opportunities come with a cost, of course. Saponja cautions that those technologies present unique challenges because they are so capital-intensive they. “Fifteen years ago, in the heyday of conventional oil exploration and production, you would put $150,000 to maybe $500,000 into the ground to get 200,000 barrels of oil,” according to Saponja. “Now you have to put maybe $4 million in the ground to get 200,000 barrels of oil, and you have a 50% to 80% initial rate of decline. To get these multistage frac wells to work you have to drill a lot of wells in these lower quality reservoirs.” This leads to what he calls the treadmill.

“To offset decline you have to be continually drilling, because the decline rate is so high. The main point of the equation is that these horizontal wells are very capital-intensive. Initially you get a very high rate of oil production but they will decline quite quickly. The economics are actually fairly marginal on a well to well basis, so you have to drill a lot of wells to benefit from scale. Except in the Bakken,” he says, “Most of these multistage frac wells really struggle if oil prices are below $60 or $70. For these wells to be really profitable, oil has to be over $80 a barrel.”

“You have to be continually drilling to offset decline. It’s called the treadmill. The main point of the equation is that these horizontal wells are very capital-intensive. Initially you get a very high rate of oil production but they will decline quite quickly. The economics are actually fairly marginal on a well-to-well basis, so you have to drill a lot of wells to benefit from scale. Except in the Bakken,” he says, “Most of these multistage frac wells really struggle if oil prices are below $60 or $70. For these wells to be really profitable, oil has to be over $80 a barrel.”

Does it make sense for private companies like TriAxon to stay public? According to Saponja, the economics of staying private are iffy. “These are very expensive wells. For a junior to stay on the treadmill becomes very difficult after you reach 3,000 or 4,000 barrels a day because you need a lot of capital to grow production and combat decline. The challenge that juniors face is that they have to either get their hands on more capital or be prepared to monetize their assets by selling them off. That’s the case for going public: it gives you access to low-cost capital. However, my partners and I are happy building basements, then selling them to the highest bidder.”

Midcaps in the Bakken
The highest bidder for TriAxon One was Crescent Point Energy – one of the two largest players in the Bakken, and the main competitor of PetroBakken, a midcap headed by Gregg Smith. “Our decline rates in the Bakken are about 60% in the first year, so we have to keep drilling to maintain production rates. You have to experiment a lot to be successful in plays like this. When you come into these plays your initial results are going to be mixed, but as you refine your drilling and production systems they improve.”

With considerable satisfaction, Smith notes his company’s success in drilling bilaterals from a single wellpad. “For PetroBakken to drill a single horizontal, the cost is $2.4 million. However, to drill two bilaterals from a single pad costs $3.6 million. It’s much more capital-effective, and it delivers an extra 50,000 barrels per well into the bargain.”

According to SEPAC’s Leach, the obviously improved economics of tighter spacing is generating “a regulatory response. The design of wellpads has to be different, and the new wellpads provide both environmental and economic benefits. Regulators are beginning to respond in all three western provinces.”

He adds, “The Cardium just began to take off in early 2009, and it was SEPAC companies – junior and midsized companies – that set the stage for this. Those sectors are looking to restructure because of the long-term poor prospects for natural gas, and this has played a role in that. It’s really turned around the fortunes of the industry, and generated a lot of investor interest.” With some satisfaction, he notes that multinational companies are coming back to North America to get back into the light and conventional oil resource plays. This involves a turnabout for some companies. for example, Talisman sold off a lot of its Alberta oil production just a few years ago.

PetroBakken’s Smith stresses that the situation in Canada is quite different than that in the United States. The Americans “are drilling shale oil plays. (By contrast) most of the horizontal wells with multistage fraccing in Canada are into reservoirs that were previously simply uneconomic or marginally economic (if you were trying to produce) oil from a vertical well.” This is all changing now, he says. “Now you’re seeing people try to tie up shale oil plays like the Alberta Bakken, the Duvernay and the Nordegg.”

Back to the Future
Of course, old hands in the oil industry are the first to tell you that technology has always been the key factor in expanding production. In fact, in this period of oilfield revolution the importance of technology is more obvious than ever before. According to Legacy president Trent Yanko, “Technology has always been an important part of oilfield development in Canada. I started out in Saskatchewan in 1980s, which was really Canada’s leader in horizontal drilling because of a major government incentive program.” After a few years the industry found itself drilling more horizontals in Saskatchewan than anywhere else in North America – “even the Austin Chalk” in Texas.

“Southeast Saskatchewan has been a classic case of the use of technology to extend the life of reservoirs,” Yanko continues. “Since the 1960s the industry has applied waterflood there, horizontal drilling, CO2 injection and other technologies, each of them extending the life of the province’s south-eastern petroleum reserves. As a result, in the late 1990s oil production matched what everybody thought had been the peak oil levels of 1966, and today the province is at record production.”

Almost all of the reservoirs now being developed with these technologies were discovered after 1947, when the Leduc discovery ushered in the industry’s modern age. Yanko, however, has plans to apply them in the petroleum industry’s birthplace. “Through the acquisition of a private company in July,” he says, “we acquired the Turner Valley oilfield. We control most of the production and all the facilities there.”

To understand Turner Valley’s significance, it’s worth noting that the field’s proximity to Calgary is the reason Canada’s petroleum sector is headquartered in the city. And, as SEPAC’s Gary Leach observes, Calgary now hosts the 45% of the world’s publicly traded oil and gas companies.

As he discusses this property, Trent Yanko becomes palpably excited. “There is still a lot of meat on the bone. There’s been less than 1% decline in (annual) oil production (from Turner Valley) over the last fifty years. The original oil in place was 1.3 billion barrels of 40° oil, and the historical recovery factor to date is only about 12%. So we think it has huge development potential. Before we acquired the property, the last vertical wells were drilled there in the 1940s. There was some horizontal drilling in the 1990s, but the field has been non-core for a long time.”

Although Legacy is proceeding cautiously, its president is thinking big. To begin with, Yanko believes Legacy has mapped a Cardium trend right on top of the field – “11 miles long and about 1½ miles wide,” with 10 metres gross maximum thickness. “In Turner Valley there’s a vertical well that just missed the Cardium and still produced more than 19,000 barrels. Otherwise, that trend hasn’t even been touched.”

“We believe the application of horizontal drilling and multi-stage frac technology can increase the recovery factor,” he adds. “So can infill drilling and reactivation of the waterflood. This property hits a lot of our hot buttons.” In the fall, the company drilled a number of vertical wells into the field. “We are going to frac them, and they will provide a great controlled environment to help us understand the horizons for future horizontal drilling. These wells will help us design that drilling program properly.”

When Turner Valley was first drilled in 1913, it was a wet gas field from which liquids were extracted and natural gas flared. A century later, with conventional gas again a marginally economic commodity, the prize sought in Turner Valley reservoirs is again its hydrocarbon liquids. The difference today is the toolkit.