Canada’s midstream operators face all of the current challenges as their brethren to the south—and then some. The oil and gas industry has active drilling and development programs under way in multiple unconventional shale plays, such as the Montney and Duvernay, that lie beneath western Canada.

Think Eagle Ford or maybe Marcellus— the comparisons come easily. And Canada and the U.S. share at least one unconventional play, the Bakken. It lies below Saskatchewan and Manitoba, the same play that has made North Dakota to the south into a world-class oil producer as it keeps Montana’s drillers busy.

Those shale plays have greatly increased Canada’s crude oil, natural gas and natural gas liquids (NGL) production, filling pipelines and other midstream infrastructure and creating a debate over liquefied natural gas (LNG) exports.

It should all sound very familiar to U.S. midstream operators.

There’s more: On top of all the unconventional shale plays and LNG, Canada’s midstream must accommodate a totally different unconventional play unique to the nation: the oil sands.

‘Go to Canada’

Add all of that up, and it’s easy to see why many executives in the worldwide energy business are thinking “maybe we should go to Canada,” says Bill Gwozd, senior vice president, gas services, for Ziff Energy Services Group, a Calgary, Alberta-based consulting group.

He tells Midstream Business U.S. investment north of the border is nothing new but Canada’s booming energy industry has drawn increasing investor attention outside North America, particularly from Asia. Since the end of 2010, Canadian energy firms have teamed up in joint ventures, mergers and acquisitions in deals worth billions, most focused on developing unconventional plays.

One of the biggest deals closed earlier this year when China’s CNOOC Ltd. purchased Calgary-based Nexen. That purchase alone was worth C$15.1 billion. The trend parallels foreign companies buying into U.S. shale plays. Firms want in on the North American action as much to learn the science behind developing and producing unconventional targets as for investment opportunities.

Other new players in Canada include Japan’s Mitsubishi, PetroChina and China National Petroleum Corp. The investments give life to projects that otherwise would sit on the shelf, Richard Dunn, vice president, regulatory and government relations, for Encana Corp., told Hart Energy’s DUG Canada conference in Calgary earlier this year. “The importance of foreign investment in the Canadian natural gas industry has a key role in commercializing the world-class natural gas resource we have in this country,” Dunn told conference attendees.

That capital will be needed. Estimates from the conference placed the nation’s need for midstream investment in the billions during the next decade.

Roger Ihne, principal with Deloitte Consulting LLP, seconds the observation about Canada by Gwozd.

“It’s an extremely dynamic market,” Ihne says of Canada’s energy business in general and midstream in particular in an interview with Midstream Business. “People don't realize it, but two of the four major (North American) midstream companies are Canadian-based—Enbridge and TransCanada.”

An emerging midstream

Canada offers a different business setting than the Lower 48 states. It has a land mass of 3.9 million square miles, the second- largest nation behind Russia. But its population of 33.5 million is smaller than California’s. Distances can be long and end markets small.

That land mass contains tremendous resources. The Canadian Association of Petroleum Producers (CAPP) pegs Canada’s oil reserves at 174 billion barrels (bbl.), third-highest in the world behind Saudi Arabia and Venezuela. It also has substantial natural gas reserves of nearly 25 trillion cubic meters, placing it ahead of such major gas producers as Norway and Algeria.

The bulk of Canada’s oil and gas production comes from the west with less than 10% of production coming from operations offshore Newfoundland and the Maritime provinces.

The challenges Canada’s midstream players face are as sprawling as the country itself. Exports are a given—unlike the U.S.—due to the comparatively small domestic market.

“Obviously, the challenges you have are both physical and economic—developing, transporting and directing resource development,” Ihne adds.

Business methods also differ, says Kevin Cumming, president and chief executive of Calgary-based, private-equity backed KANATA Energy Group, a midstream start up. He tells Midstream Business, “We see a lot of movement to midstream service providers but there still are some (upstream) companies reluctant to give up control of their infrastructure for various reasons. Some feel they will get better value in a sale process, they don’t believe they will get the same service and availability as when they control the assets and that— with control of infrastructure—they can maintain control of an area and encourage other operators to sell.”

Cumming adds, “The key challenge for Canada’s midstream providers will be to convince the producer sector that it makes better use of their capital to invest in upstream activities and that control may be accomplished with the structuring of contractual arrangements. The midstream industry must find a way to align itself with the upstream industry so that the lowest capital cost and operating costs are achieved and that midstream facilities operate at the highest availability.”

Canada doesn’t offer the master limited partnership business structure that has been key to the U.S. buildout of a separate midstream industry. Private equity by ARC Financial Corp., Energy Spectrum Capital and Teachers’ Private Capital funded KANATA’s entry into the business earlier this year.

Political environment

But the trading partners and neighbors have similarities. “We’re faced with the same political issues. I think Canada, as well as the U.S., is involved in a lot of political and regulatory debates and decisions that impact the overall economics going forward,” Ihne adds.

While Canada may go its own way in developing its rich energy resources, the North American neighbors remain firmly joined at the energy hip. Production and midstream trends in the U.S. impact Canada, and Canadian energy trends in turn impact business south of the border.

The U.S. is “the natural customer” for Canadian production, Ihne points out, and there must be midstream infrastructure to support that move south. But political debates on both sides can complicate things, witness the U.S. indecision concerning TransCanada’s proposed Keystone XL crude pipeline, intended to move Canadian heavy oil south to the Cushing, Oklahoma, hub and Gulf Coast refineries.

The shale plays

Alberta’s Duvernay, sometimes called “the Eagle Ford of Canada,” may be the best known of Canada’s shale prospects. Its geology mirrors the Eagle Ford’s three-play dry gas/condensate/crude oil geology. Duvernay reserve estimates are in the 2 billion bbl. range, according to Hart Energy’s North American Shale Quarterly (NASQ). Growing production has spurred the necessary midstream development. Encana, one of the biggest upstream operators in the resource play, has announced plans to shift its Duvernay drilling program to seek out more liquids-rich production as gas prices have sagged.

To the north lies the Montney, a comparatively shallow, tight sand play that spreads westward into British Columbia. Originally thought of as a gas play, Montney operators—as with other unconventional plays—now emphasize zones with high-liquids content.

The play has comparatively well-established midstream infrastructure linking producers to markets. But with increasing oil sands production in the province, most pipelines are running at near capacity. Any progress in LNG terminal development will be a net positive to gas demand.

If the Duvernay mirrors the Eagle Ford then the nearby Cardium resembles the Permian basin—a successful conventional play with a new life. Cardium production began in the early 1950s and includes the Pembina—Canada’s largest onshore field.

Pembina’s conventional production peaked 40 years ago at nearly 200,000 bbl. per day, then slowly declined to around 50,000 bbl. per day in 2008, according to NASQ. But a familiar thing happened: Producers started horizontal drilling and multi-stage fracturing, making the Cardium a hot property again. Since 2009, more than 1,200 wells have been put into production, which has significantly offset decreased conventional production while making use of much of the area’s existing midstream infrastructure.

“Existing infrastructure provides the Pembina field of the Cardium with a significant advantage. It has well-established pipelines, oil treating and gas handling facilities that allows for production to be brought on-stream quickly. The Cardium is known as a brownfield development where operators have historical data to work with—unlike those engaged in emerging Alberta plays such as the Alberta Bakken and the Duvernay,” NASQ’s first-quarter 2013 report says.

Ziff Energy’s Simon Mauger, director of gas supply and economics, agrees. “There’s a lot of existing infrastructure for the Duvernay and the Montney. You’re in an area that has been developed for natural gas and oil for over 40 years, 50 years. So there’s a huge amount of infrastructure, and some of it underutilized,” he tells Midstream Business.

Western Canada has other unconventional shale plays, notably the Horn River in British Columbia’s far north. Encana discovered the field in 2003, but its dry gas production is attractive only “in the correct price environment,” according to NASQ reports, similar to the Barnett and Haynesville shales in the U.S. that have had a drilling drop-off with the steep decline in North American gas prices during the last five years.

Where to send the gas

Conventional plays have produced a steady stream of gas to fuel Canada’s domestic needs for years and also created significant production for export to U.S. customers. Swelling resource- play production, coupled with flat domestic demand and a shrinking U.S. market—thank surging U.S. domestic shale production—have left Canadian producers dealing with low prices.

“The Canadian natural gas industry is feeling the effect of the supply/demand imbalance for both gas and natural gas liquids,” Cumming explains. “Both the upstream and midstream players are working on solutions to alleviate this imbalance and in the longer term liquefied natural gas plants and West Coast NGL terminals are the solutions that are somewhat within the control of the industry.

“Cleaner-burning natural gas power generation will also be a large factor but will likely need some political push, with the short-term solution being ensuring that the lowest-cost operations can be achieved to get the gas to market. The producer with the highest overall return on capital will achieve growth and success.” And achieving that goal is exactly what KANATA and midstream players can help accomplish, Cumming adds.

Ziff Energy’s Gwozd thinks Canada has a huge potential for LNG exports, telling Midstream Business “we actually believe that the Canadian LNG projects will account for twothirds of North America’s export potential.”

He continued, ticking off six reasons why the future is bright for Canadian LNG.

“The first reason, of course, is that nobody lives in Canada,” he says with a chuckle. “As a result, the price of gas is just cheaper. So the feedstock strategy is cheaper right now.” That draws the foreign interest. Second and third, British Columbia’s coast lies closer to prime Asian LNG markets than prospective U.S. liquefaction plants around the Gulf of Mexico, which in addition to greater distance, have the added cost of Panama Canal tolls to reach Asia. He goes on to mention Canada’s stronger contractual laws and the potential barrier of the U.S. Free Trade Act. Last but not least, he mentions population—or the lack of it—again.

Reliant Stadium

“I look at the location of the West Coast Canadian projects and, to be completely honest, nobody lives near the LNG projects. We’re talking fewer people up there than what Reliant Stadium will hold in Houston,” Gwozd says. The home of the National Football League’s Houston Texans seats 71,054 while Kitimat, British Columbia, the site for a major gas liquefaction plant and port, has a population of around 4,000.

“People will say, ‘Well Canada doesn’t have the gas’” due to recent gas output declines. “It’s actually tilted down. We used to produce 18 billion cubic feet (Bcf) per day. And now, Canada only produces 13 Bcf,” he adds.

The federal government’s Statistics Canada published numbers showing domestic gas sales averaged 321 million cubic meters (11.3 Bcf) per day in February.

“What I’m saying is because we have no markets, we have no place to put the gas. We reduced gas-directed drilling.” Provide markets for that gas and production will tick up again, he explains.

Seconding Gwozd’s comment about everyone going to Canada, Encana's Dunn says Asian demand is projected to more than double to 65 Bcf per day by 2020 with much of that growth occurring in China.

“It’s clear these days that market diversification through the export of LNG to a growing Asian market, along with accompanying Asian foreign-direct investments will be the keys to the continuing viability of the Canadian natural gas industry,” Dunn added.

The Kitimat LNG project gained important support earlier this year when Chevron Corp. closed the purchase of stakes in the project previously held by Encana Corp. and EOG Resources Canada. Chevron then sold 10% of its acquired interests to the remaining original project partner, Apache Corp. to equalize the firm’s 50/50 stake in the project. The first phase calls for liquefaction of 770 million cubic feet (MMcf) per day of gas, starting in 2017. Capacity could be doubled in a second phase to start up at a later date. The federal National Energy Board has approved a 20-year export license.

Getting that gas to new liquefaction plants on the British Columbia coast will be pricey, given that pipelines will need to cross some of the most rugged mountains in North America. TransCanada Corp. told attendees at its recent annual shareholder meeting that it is looking at a C$9-billion investment to build two gas pipelines across northern British Columbia.

Another natural gas/NGL market may be an emerging petrochemical industry in western Canada. It will complement the nation’s existing petrochemical hub at Sarnia, Ontario. The Williams Cos. recently announced what will be the region’s first large-scale petrochemical operation, fed by Montney-produced gas liquids processed by Williams’ existing gas processing operations at Redwater, Alberta. The C$900-million propane dehydrogenation plant will produce 1.1 million pounds per year of polypropylene and is scheduled to start up in 2016.

Crude considerations

But the gas and NGL issues get dwarfed alongside midstream’s challenge of moving Canada’s crude oil—which includes heavy bitumen from the sprawling oil sands. CAPP projects Canadian production will more than double from 3 million bbl. per day now to 6.2 million bbl. per day by 2030. More than half of the current figure is bitumen—and that share is expected to grow.

“Western Canada’s crude oil production outlook sounds very positive,” says a CAPP report. “But there's a major stumbling block—the need for more transportation infrastructure. (Existing) oil distribution pipelines are approaching capacity.” The crude glut and pipeline bottlenecks contribute to the wide price differentials for various North American crudes, which vary widely by type and producing region.

Oil sands bitumen is energy-intensive to produce, involving literal mining with heavy equipment or such in-situ heat injection techniques as steam-assisted gravity drainage. Steam injected into the producing formation thins the viscous, ultra-heavy crude enough to get it to flow to production wells.

Lighter-gravity crude, or diluent, must be mixed with the bitumen to move it to market. Yet all that work yields a refinery feedstock that brings a comparatively low price.

Deloitte’s Ihne points out the result: One of the most-expensive crudes to produce brings one of the lowest prices from customers. That makes for borderline economics “and I think a lot of producers are already there,” he says. New markets, wherever they may be, will be a tremendous help.

Pipeline ambitions

Where will the production go, and how will it get there?

The midstream in the neighboring nations faces tremendous growth opportunities in the foreseeable future, Ihne adds. “All of a sudden the midstream players, both in the U.S. and Canada, are doing quite well with the new projects that are needed, plus the overall flow of those resources. Midstream is basically volume-times-price, and volumes have been increasing and continue to increase from a macro perspective in both Canada and the U.S. The infrastructure clearly isn't there to be able to support the anticipated volumes.”

Midstream operators have multiple projects on the drawing board to move the oil and gas. An outlet for gas production includes that gas pipeline over the Rockies to Kitimat to feed one or more LNG plants. Pacific Trail Pipelines Ltd. would be a 288-mile, 42-inch pipeline linking Spectra Energy’s existing transmission system at Summit Lake, British Columbia, with the Apache-Chevron LNG plant. Capacity of the pipeline would be 1 Bcf per day.

Midstream projects to handle crude are many. Some of the most ambitious pipeline projects in the world right now aim to move oil sands production to market. Enbridge has proposed the twin-line, C$5.5 billion, 730-mile Northern Gateway project extending from outside Edmonton, Alberta, to Kitimat for an oil terminal. A 36-inch, 525,000-bbl.-perday line would move diluted bitumen west out of Alberta’s oil sands for loading aboard tankers. A parallel, 20-inch, 193,000-bbl.-per-day line would move diluent east from other tankers hauling the light oil in from foreign producers.

Kinder Morgan Canada proposes to loop its existing, 744- mile Trans Mountain Pipeline that links Edmonton with Burnaby, British Columbia, east of Vancouver, with a spur across the border to the refineries at Anacortes, Washington. Capacity would increase to 890,000 bbl. per day from 300,000- bbl.-per day and permit tanker loading for the first major crude exports via Vancouver.

An elaboration on the crude pipeline plans includes a C$25- billion pipeline, refinery and dock at Kitimat proposed by Canadian publisher and businessman David Black, backed by Swiss investors. It would enable Canada to garner greater value from its resources by exporting petroleum products rather than crude.

TransCanada recently proposed its Energy East project— a repurposing of an existing gas transmission line with certain newbuild sections that would move crude from Alberta and Saskatchewan to eastern Canada. The line would start at a new terminal to be built at the existing Hardisty, Alberta, crude hub outside Edmonton.

The 2,728-mile system would have a capacity of 500,000 to 850,000 bbl. per day. It would serve refineries in Quebec and New Brunswick, plus provide an option for tanker loading for trans-Atlantic export. TransCanada currently has an open season to gauge producer interest.

Rail’s role

As in the U.S., rail has a fast-growing slice of the midstream. Recent Canadian press reports noted that Canadian National Railway (CN) shipped zero crude in 2009. In 2012, it handled 19.2 million bbl. and this year it could handle 200,000 bbl. per day—or 73 million bbl.

CN notes it is unique in that it can provide one-line service from the oil-sands producing region to the U.S. Gulf Coast, including the St. James, Louisiana, crude hub and refineries on the Gulf Coast. CN owns the former Illinois Central Railroad that it purchased in the late 1990s, which links the Great Lakes and Gulf.

The competing Canadian Pacific Railway also has a growing crude business and serves as the No. 2 rail shipper, behind U.S.-based BNSF, in the Bakken play for producers on both sides of the border. Canadian Pacific says it handled 500 carloads of crude, total, in 2009. It’s forecasting 70,000 carloads in 2013.

There are other, far-reaching proposals for rail. One of the biggest is a plan by the Canadian firm Generating for Seven Generations Ltd. to build a 1,600-mile railroad line linking the end of track for North America’s existing rail network with the separate Alaska Railroad. Crude could then be shipped to tidewater at Seward, Alaska, or added to the Trans-Alaska Pipeline and moved to the oil terminal at Valdez, Alaska. The Alaska pipeline currently has excess capacity as North Slope crude production continues to slip.

The debate

With all those proposals, don’t forget about TransCanada’s Keystone XL. But, as is the case with Keystone XL in the U.S., the highest hurdle in Canada may not be the Rockies’ topography or financing—but politics.

British Columbia has an active environmental lobby and the proposed pipelines, liquefaction operations, terminals and refinery were a major issue in provincial elections held in May. Protests have been vocal and the Toronto-based Globe and Mail newspaper recently called the dispute centered on Northern Gateway in particular “incendiary.”

The debate spurred Deloitte Canada to publish a study, Gaining Ground in the Sands 2013: Ten Oil Sand Obstacles that Are Actually Opportunities, at the End of 2012. “We recognize that there are legitimate concerns on all sides of these issues,” Geoff Hill, oil and gas sector leader for Deloitte Canada says in the report’s opening. “But Canadians must understand that the oil sands are an indispensable economic asset that should be bringing the country together, not be driving it apart.”

Canada’s midstream lies in the center of the unsettled debate of what to do with Canada’s energy resources— and how to do it. The basic issue is “what kind of country we want to have in a rapidly evolving and frequently volatile global economy?” Deloitte’s Hill says in the firm’s report. “We believe it’s not only acceptable but also necessary to ask these tough questions.”

When answered, the likelihood is Canada’s midstream will be seen as a leader that has met and conquered very large obstacles of geography, technology, capital and politics. That expertise will serve Canada well as its works with its partner to the south and other energy markets throughout the world.

Comments