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Northern British Columbia and Alberta's Oil and Gas Industry Vol. 3 Issue 7 • dist: 16,000

jULY/august • 2013

h t r o N

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in this issue:

• HOME ON THE RANGE - FORAGE ASSOCIATION TACKLES LEASE SITE RE-VEGETATION • THE LNG MAN COMETH - KRISH SUTHANTHIRAN’S JOURNEY FROM INDIA TO KITSAULT • SAFE AND SOUND - MARINE OIL TRANSPORT

ACCESS PIPELINE TESTING LOW IMPACT PIPELINE CONSTRUCTION TECHNIQUES IN ALBERTA - ALBERTA ENVIRONMENT AND SUSTAINABLE RESOURCE DEVELOPMENT PHOTO

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• PIPELINE NEWS NORTH

JULY 12, 2013

industry news CODE OF CONDUCT Working Energy Commitment inspires conversation about fracturing

special feature 24 Access Pipeline looking to reduce their impact

james waterman Pipeline News North

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“They would just like a better line of communication about what all is going on, who’s in the area, what are you doing, how long are you going to be here,” he conFollowing through on Working Energy Commitment tinued. “ And then just treat our community with promises around communicating with communities respect – simple little things like don’t wear your coverand developing a hydraulic fracturing code of con- alls into the coffee shop.” duct, Petroleum Services Association of Canada Salkeld said the conversations were fairly consistent (PSAC) member companies and their oil and gas throughout the four stops, but also noted a greater industry peers have been holding public engage- environmental awareness in Dawson Creek, seemingment sessions throughout western Canada this ly inspired by documentaries with a bias against spring and summer. hydraulic fracturing. The sessions began in Drayton Valley, Alberta on Salkeld believes the landowners asking questions May 8, followed by stops in Lethbridge, Alberta on based on the content of those films might be more May 28, Grande Prairie, Alberta on June 19 and skeptical of those documentaries now. Dawson Creek, British Columbia on June 20. “Because we had informed, respectable people in Planned visits to Red Deer and Medicine Hat, our group,” he said. “Representation from the producAlberta have been delayed because of the flooding ers and from our member companies who live in in the Calgary area, as reprethese communities and work in sentatives of member compathese communities.” “We had subject nies have been preoccupied Alberta Environment and with matters related to that Sustainable Resource matter experts that natural disaster. Development (ESRD) and oil The final two stops will be and gas industry regulators rescheduled. Additional visits to openly and honestly were also present. B.C. communities such as “We had subject matter Prince George, Kamloops and experts that openly and honestanswered questions.” ly answered Vancouver, as well as stops in their questions and New Brunswick and just gave them basic facts Newfoundland and Labrador, about what we do,” said – Mark Salkeld, PSAC may also be on the horizon. Salkeld. “It boiled down to a “The most pleasing outcome really good conversation in all is the thank you from all the groups that we’ve met four locations so far.” with just for the simple reason of coming out and talkThat has put PSAC ahead of the curve in terms of ing to them,” said Mark Salkeld, president and chief developing their code of conduct. executive officer of PSAC. “Answering their questions “We’ve had enough information and enough feedabout hydraulic fracturing. Giving them a little bit of an back, and really good conversation and dialogue with explanation on what it’s all about and how long we’ve the four groups, that we’re already beginning to draft been doing it.” an outline,” said Salkeld. “And we’ll be taking that with Water has been a prevalent topic of conversation so us [to] the next sessions if it’s ready.” far, particularly around concerns about potential conThe final draft should be ready in the near future tamination of drinking water and how much water as well. industry is using for fracturing operation “We’re hoping to have it done by the end of the “For the most part, the group knows that we need oil year,” said Salkeld. and gas,” Salkeld said of the engagement session par“And actually go back to the communities that we ticipants that range from local landowners to municipal visited with a final draft just to let them know what government representatives. we’ve developed.”

PIPELINE NEWS NORTH •

industry news 16 Alberta Energy Regulator up

and running

profiles 18 Krish Suthanthiran’s journey from India to Kitsault

environment 12 Forage Association looks at lease site re-vegetation

community 8 Energy sector helping with Calgary flood relief

careers 8

Alberta aims to keep its foreign workers

• PIPELINE NEWS NORTH

JULY 12, 2013

industry news

North ALWAYS IN THREES NEB receives trio of new LNG export applications james waterman Pipeline News North

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The British Columbia government was all smiles on Friday, July 5 with the news that Pacific NorthWest LNG had submitted an application to the National Energy Board (NEB) to export liquefied natural gas (LNG) from the B.C. coast to global markets. It is the sixth such application submitted to the NEB and the third since June 17 of this year. The first LNG export license was given to Kitimat LNG – which consists of Apache and Chevron Canada – in October, 2011. Douglas Channel Energy was subsequently granted an export license in February, 2012, followed by the LNG Canada project led by Shell Canada in February, 2013. BG Group submitted an application for Prince Rupert LNG on June 17 and a partnership between ExxonMobil Canada and Imperial Oil followed suit later that week. “Pacific NorthWest LNG’s export application marks another positive development in our goal to provide clean natural gas to growing markets in Asia,” said Premier Christy Clark. “By increasing the demand and reach of our natural gas sector, we will create jobs, strengthen our economy and put British Columbia on a prosperous path to a debt-free future.” “British Columbia has an unprecedented opportunity to create lasting benefits for the entire province with the world’s cleanest-burning fossil fuel,” said Rich Coleman, provincial minister of natural gas development. “The Pacific NorthWest LNG export application is great news, representing the latest milestone in our commitment to develop a new export industry that will put us on a path to new prosperity.” Pacific NorthWest LNG, a Petronas company, is hoping to export almost 20 million tonnes of LNG per year over 25 years from an export point on Lelu Island in the District of Port Edward, not far from Prince Rupert. The source of natural gas would be assets belonging to Progress Energy – another Petronas company – in the Montney formation of northeast B.C. “The recent submission of our NEB export licence application represents another important step in bringing our LNG project to reality,” said Greg Kist, president of Pacific NorthWest LNG. “We are encouraged by Premier Clark’s commitment to creating and maintaining a positive environment for investment in the LNG business and believe that a successful LNG industry will have a significant positive economic and social impact on the province for decades to come.” The BG Group project – Prince Rupert LNG – has asked for a 25-year license to export almost 22 million tonnes of LNG per year from Ridley Island, which is also near Prince Rupert. The project led proposed by ExxonMobil and Imperial – known as WCC LNG – is also seeking a 25-year license, but for a total volume of 30 million tonnes per year. Imperial spokesperson Pius Rolheiser explained that WCC – which stands for West Coast Canada – LNG is an equal partnership between the two oil and gas companies “ExxonMobil Corporation has extensive experience operation LNG projects in other parts of the world,” said Rolheiser. That includes operations in Qatar, Australia and Papua New Guinea. ExxonMobil has a share greater than 25 per cent in the four projects with which they are involved in those countries. The combined LNG

production capacity of those projects was about 65 million tonnes last year. “In addition,” Rolheiser continued, “we are able to leverage the experience and capabilities of ExxonMobil’s subsidiary, XTO Energy, which is a leading unconventional oil and gas producer in North America.” Imperial doesn’t seem too concerned about the competition considering their project is just one of three proposals to submit export license applications to the NEB in just a couple of weeks. “All LNG projects must compete in global energy markets,” said Rolhesier. “Competition will be not only from other LNG projects, but development of new unconventional resources. “Natural gas currently meets over 20 percent of the world’s energy needs and is expected to be one of the world’s fastest growing sources of fuel in the coming decades,” he added, beginning to cite projections from ExxonMobil’s annual Energy Outlook. “Demand for natural gas will increase by about 65 percent through 2040 and a large variety of sources will be needed to meet growing demand.” Imperial is also confident that the supply of natural gas is sufficient to fuel six – or more – LNG projects even though current annual natural gas production in Canada is far below the volumes that would be exported annually as LNG if even just a few of those proposals succeed. “Studies prepared by Ziff Energy Group and Roland Priddle concluded that North American and Canadian gas resources are large enough to meet growing Canadian demand, as well as provide supplies for LNG export,” said Rolheiser, adding that Imperial and ExxonMobil are “committed to protecting the land and environment, as well as the cultures of Aboriginal people and local residents” as they increase production to supply their LNG train. WCC LNG intends to export Canadian natural gas, starting with resources found in their assets in the Horn River Basin of northeast B.C., where they began producing in 2012. “The companies,” said Rolheiser, “also hold major acreage positions in the Montney and Duvernay resources.”

Imperial Oil and ExxonMobil would use natural gas from their assets in the Horn River Basin of northeast B.C. to supply their liquefied natural gas project. The partnership is one of six groups to apply for licenses to export that product from B.C.

IMPERIAL OIL PHOTO

JULY 12, 2013

PIPELINE NEWS NORTH •

industry news

BALANCING ACT

B.C. government pins economic future on young LNG export industry GAVEN CRITES Pipeline News North

Saskatchewan,” she said. “I think we’re talking too much about the fiscal deficit and not enough about the environmental and social deficits that will hurt British Columbians over the long run.” Jarvis said he advises the government continue to maintain a good working relationship with energy producers and continue to show fiscal restraint, but not when it comes to spending in the North. “I don’t mean cuts in the North end of the province,” he said. “In the future, the North is going to support the rest of the province with the revenues the pro-

vincial government is going to be receiving. But, right now, that’s a long ways out and they have to be very careful they don’t upset these gas producers… Every government has to keep in mind it’s a business relationship that has to be two-sided. It has to be good to the producer. I know there’s an attitude out there people feel producers are making too much money, but that’s what enables them to invest in years of research and development before they get a return. That has to go on. It can’t stop.”

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The B.C. government is looking at liquid natural gas (LNG) development to help eliminate the growing provincial debt and balance future budgets. “The opportunity of LNG development in B.C. is to create new investment, new jobs and new revenues to the provincial government over the medium to longer term,” said a spokesperson for the Ministry of Natural Gas Development. “A key priority in the near term will be the work to establish a BC Prosperity Fund, which will secure wealth from tomorrow’s LNG development and protect if for future generations.” According to the Ministry, forecasts show revenues to the Fund could be in excess of $100 billion over the next 30 years. However, that’s only when new LNG plants become operational. Following the release of the 2013 Budget on June 27, Iglika Ivanova, an economist and public interest researcher at the Canadian Centre for Policy Alternatives, said it’s unfortunate more people aren’t talking about the impact of LNG development on B.C.’s economy. “Pinning your hopes on royalties from future LNG development in order to pay off the debt – which is what (the Liberals) campaigned on – is wishful thinking,” she said. “It really isn’t planning as much as hoping.” It will be awhile before the government sees any revenue from LNG plants, which are still years away from being operational, said Art Jarvis, executive director of Energy Services BC, who represent the province’s oil and gas services sector. “It’s a great idea to balance the budget by the additional taxation or levies they’re going to put on natural gas, but in reality, there won’t be any revenue from it until there’s some market and some sales,” Jarvis said. “That’s the only way they can measure how they’re going to get there money is how much is being sold. “There have been a lot of wells that have been drilled and capped simply because there is no market for it right now and that’s where the pressure is to get this to the coast and liquefy it and then you have the world market.” Despite a drop in projected economic growth compared with the pre-election budget tabled in February, the government forecasts a $153 million surplus in 2013-2014. According to the government, “an improved forecast for natural gas prices (and) bonus bids for natural

gas tenures” will partly offset reductions in government revenue. In 2012, lower than expected natural gas prices cost the government over $1 billion in expected revenue. Jarvis said diminishing natural gas revenues should sound loud warning bells to the government. “It will be five to eight years before we see any exportation of natural gas,” he said. “It’s going to take that long to lay the pipeline, build the plants. Some of these oil companies don’t have a market in place yet. We all know Asia needs it; you still have to develop the contract.” A spokesperson for the Ministry of Natural Gas Development said the B.C. government uses a prudent approach when forecasting natural gas prices. “The current natural gas price forecast is $2.25 (CDN) per gigajoule for 2013/2014, and $2.51 (CDN) per gigajoule for 2014/15. This is higher than the forecast contained in February’s budget. The current price forecasts were raised due to rising market prices, higher private sector forecast prices, and other positive developments in the natural gas markets in North America since 2013.” Throughout the election campaign in May, the Liberals promised to balance the budget this fiscal year, and with the selling off of government assets and continued spending restraints, the government predicts budget surpluses of $154 million in 2014-15 and $446 million in 2015-16. But, Ivanova said there’s no reason to balance budgets and look for “razor thin” surpluses in the near term if it means comprising public services. “The way they’re handling it is asking for further spending cuts of $130 million over three years, which is unclear where it’s coming from at this point,” she said. “What I’m concerned about is at whose expense is this budget going to be balanced? There eventually comes a point where you can’t cut anymore without compromising services. There is no question incurring excessive debt imposes an unfair burden on future generations, but that’s also true of inadequate investments in infrastructure, education and environment. Allowing public services to crumble is also going to put burdens on future generations.” Regarding the B.C. government’s total debt – close to $57 billion – Ivanova said it’s a big number, but it’s a manageable one when considering the size of the province’s economy. ”Our debt is about 18 per cent of our GDP, which is the third lowest in the country behind Alberta and

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• PIPELINE NEWS NORTH

JULY 12, 2013

industry news DON’T KNOCK THE DILBIT

Canadian heavy oil doesn’t pose extra risk to pipelines james waterman Pipeline News North TransCanada and Enbridge were both quick to respond to a report by the National Research Council in the United States on Tuesday, June 25 that states that heavy oil produced in the Alberta oil sands doesn’t pose a greater risk to pipeline integrity than other crude oils. The report addressed concerns raised by opponents of TransCanada’s Keystone XL proposal to move Alberta oil to Texas refineries that the mixture of diluents and bitumen – dilbit – required to transport the heavy oil by pipeline is particularly corrosive due to high acid and mineral content. “Diluted bitumen does not have unique or extreme properties that make it more likely than other crude oils to cause internal damage to transmission pipelines from corrosion or erosion,” the report said. TransCanada and Enbridge – their Northern Gateway project would ship oil sands bitumen to the

British Columbia coast for export to foreign markets if approved – immediately took to the web to comment on the report via their company blogs. “The public has been bombarded with misinformation about the oil that will go through the Keystone XL Pipeline, but this latest study by the highly credible National Academy of Sciences has confirmed that oil is oil and the pipelines we build will safely move different blends — as we have been doing for decades,” said Vern Meier, TransCanada’s vice president of pipeline safety and compliance, in a blog post titled Diluted Bitumen – Manufactured Myth Deconstructed. The Enbridge blog noted opponents of the oil sands and associated pipeline proposals have “wrongly claimed” that bitumen has to be heated to flow through pipelines and has higher sediment and organic acid levels than other oils in addition to being denser and more viscous. “The [National Research Council] study debunked those claims completely,” read the blog.

The report stated that dilbit is chemically and physically similar to other crude oils and so can be transported at similar pressures and temperatures as those other products. Importantly, the study also found that no pipeline failure has ever been specifically attributable to the chemical and physical properties of dilbit, nor is that likely to occur in the future. “The public needs to have confidence in what our industry does and the steps that companies like TransCanada take to make sure that the products we transport are handled carefully and safely, and this latest study shows that we are,” Meier said on the TransCanada blog. “We make significant investments to make sure our energy infrastructure network is operating as safely as possible,” he continued. “In 2012 alone, TransCanada invested more than $1 billion in pipeline integrity and proactive inspection and maintenance programs to protect our pipelines and energy facilities. “We plan to spend an additional $1.2 billion this year.” R001424274

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Life’s brighter under the sun Tel 250-785-7575 Fax 250-785-1677 fci@sunlife.com 9519 - 100th Avenue Fort St. John, BC V1J 1Y1 The advisors at First Choice Insurance & Investment Services Inc. are contracted with Sun Life Financial Distributers (Canada) Inc. a member of the Sun Life Financial group of companies. © Sun Life Assurance Company of Canada, 2011.

Seven reasons to love living in Canada By Kevin Press, BrighterLife.ca

A study published yesterday by the Organization for Economic Co-operation and Development (OECD) found that “Canada performs exceptionally well in measures of well-being,” according to an online report. On a range of measures — housing, income, health and safety — Canada scored among the world’s bestperforming countries. The study scored 36 nations, including 34 OECD members, Russia and Brazil. No overall ranking is reported. The findings will surprise some, given our 7.2% national unemployment rate, 14.5% youth unemployment rate and economic growth projections that remain soft in the short term. Here are seven highlights from the OECD report: Income: The average household earns US$28,194 each year after taxes. That’s more than US$5,000 above the OECD average. There is disparity at both ends of the earnings spectrum though, not surprisingly. The top 20% takes home US$55,718, while the bottom 20% earns US$10,526. We ranked seventh on R001424347

household wealth and ninth on income. Community: Canadians spend two minutes a day volunteering; that’s about half the OECD average. On the other hand, 64% said they’d helped a stranger in the last month. (The OECD average is 48%.) And 94% know someone they could count on if needed. We ranked seventh on support network. Housing: Nine in 10 Canadians are satisfied with their housing. The average home in this country provides 2.6 rooms per occupant, more than any other country. And 99.8% of Canadians live in a home with a private washroom that has an indoor, flushing toilet. (The OECD average is 97.8%.) We ranked 24th on the ratio of housing costs to income, eighth on basic facilities and first on number of rooms per person. Environment: We’re better than average on both air pollution and water quality measures. We ranked 14th on pollution and 12th on water quality. Health: Our life expectancy at birth is 81, a full year above the OECD average. And 88% of Canadians say

they are in good health. Health spending in this country makes up 11.4% of gross domestic product. (The OECD average is 9.5% of gross domestic product.) We ranked third in health and 17th in life expectancy. Safety: Just 1.3% of Canadians said they were assaulted over the one-year period leading up to the survey. That’s well below the OECD average of 4%. Our homicide rate is less impressive. It’s 1.6%, only marginally below the average rate of 2.2%. We ranked first on assault rate and 23rd on homicide rate. Work-life balance: Canadians work an average 1,702 hours per year. That’s 74 hours below the OECD average. When asked if they work more than 50 hours a week, 4% said yes. (The OECD average is 9%.) We ranked ninth on working long hours. The full index is made up of 11 categories. Canada ranked 27th on job security, fourth on student skills, fourth on government transparency and eighth on life satisfaction.

Submitted by: First Choice Insurance & Investment Services Inc. © Sun Life Assurance Company of Canada, 2011

industry news

JULY 12, 2013

PIPELINE NEWS NORTH •

PETRONAS IS PROGRESS

LNG heavyweight investing big in British Columbia Northeast British Columbia will see a “substantial increase” in the amount of drilling associated with the emerging liquefied natural gas (LNG) industry as a result of Petronas’ $16 billion investment in the province’s energy industry. While specific numbers are not being released to the media yet, Tessa Gill, manager for stakeholder relations for Progress Energy, which is owned by Petronas, was able to confirm that the Peace Region will see a large share of this investment. “There will be a substantial investment in that play (Montney Shale Play),” said Gill, referring to the Montney formation that surrounds Dawson Creek and Fort St. John. The Montney Shale Play area covers more than 2.6 million hectares in the Peace Region and contains an estimated 8 trillion cubic feet (tcf) of natural gas. “There is going to be a substantial increase in LNG drilling operations in [northeast] B.C.,” said Gill. “We are pleased to be a part of this exciting project.” “I believe that you haven’t see anything yet,” said Fort St. John city councillor Larry Evans. “With this announcement, things in

the Peace’s oil patch will only get better. This investment will change the landscape of the [region].” Kathleen Connolly, director of the Dawson Creek Chamber of Commerce, said, “Any and all development is great. Anything to help pull product out of the ground and get it to international exports is good. We’re 100 per cent good with that. This will help the investment climate in the Peace and any increase in revenue for the LNG market for the area will get more people working.” Local companies are also excited by the news, which is expected to pump more revenue into the Peace Region. “It’s very positive news,” said Bill Birch of Bill Birch Oilfield Consulting, based in Dawson Creek. He said his company has contracts with Progress Energy and handles fluid hauling for many of their well sites, including those used for hydraulic fracturing. Birch said he is “looking forward to it” after one of his employees told him of the recent news of Petronas’ huge investment in the LNG industry. “It looks like they’re committed to the shale gas play and all that land locked gas and that will help domestic gas prices,” he said of Petronas. “This is nothing but positive news.” Dwayne Taylor, director of operations for CorrPro, which has an office

CEPA on board with new pipeline rules Daily Oil Bulletin The Canadian Energy Pipeline Association (CEPA) says it supports the proposed changes to enhance pipeline safety and performance, as announced by Joe Oliver, the federal minister of Natural Resources. The changes align with the pipeline industry’s commitment to improve its ongoing performance, says a press release issued the following day. “The pipeline industry is an important component of Canada’s critical infrastructure,” Brenda Kenny, CEPA president and CEO, said in the release. “We encourage strong, independent regulatory oversight of our industry, which will provide further assurance to Canadians that our member companies are committed to continually improving pipeline safety.” Some of the announced changes include the commitment to the polluter-pay principle, new penalties and fines for non-compliance, strengthening of emergency response management, a better definition of safety zones to protect pipeline assets, and clarification of jurisdictional responsibility for abandoned pipelines. “Our industry is particularly glad to see that the government has clarified the jurisdictional issues regarding abandoned pipelines, but one thing is for sure -- landowners will not be responsible for abandoned pipelines,” said Kenny. According to Natural Resource Canada’s backgrounder, Strengthening Canada’s Pipeline Safety Regime, even after a pipeline is abandoned in-place without being removed, the National Energy Board will continue to have jurisdiction over the abandoned pipeline, and can take steps to prevent, mitigate and remediate any post-abandonment impacts. Pipeline operators will remain responsible for any costs and damages from an abandoned pipeline, so long as the pipeline remains in the ground.

in Fort St. John, said the investment news will “definitely improve our own bottom line.” “We do corrosion protection for Progress Energy in their pipelines,” said Taylor. “Our company will definitely benefit from Petronas’ investment. It might be a while, but we’ll still get some of that pie.” The investment announcement came at the same time as an announcement by Rich Coleman, provincial minister of natural gas development, who said that Petronas is “dead serious” about investing in B.C.’s LNG industry. Greg Kist, president of Pacific Northwest LNG, noted that Petronas and Progress would finalize their investment numbers for northeast B.C. in 2014. “We hope to reach a final investment

decision by late 2014,” Kist said. “This announcement will go a long ways in establishing investor confidence in the B.C. economy,” said John Winter, president of the BC Chamber of Commerce. “I think there are some skeptics and doubters about the potential of the LNG market on the whole, but this announcement sends a strong signal that Petronas has a lot of confidence in our economy and the LNG market in B.C.” Winter said that the province had created a “Legacy Fund” for helping to pay down the provincial debt from the proceeds from the LNG market and this investment will “open those doors.” He added, “Many of these kinds of investments will be needed to establish us as a world player.”

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carl B.R. johnson Pipeline News North

• PIPELINE NEWS NORTH

JULY 12, 2013

community

AFTER THE RAIN Energy sector helping out with Alberta flood recovery james waterman Pipeline News North “Back to business as usual.” Encana’s Doug McIntyre said those words on July 2, the first day that he and all his colleagues were able to return to their Calgary offices in about two weeks, after being driven away by rains and rising rivers that left their indelible mark on nearby communities such as Canmore and High River and sent hundreds of Calgarians – including the residents of the local zoo – fleeing from flooding streets and power outages. “The buildings were dry,” McIntyre continued. “They did not experience any flooding. Of course, there were city-wide power restrictions. And because of the flooding in downtown Calgary, for safety reasons, we certainly had to follow the instructions of the first responders and the mayor, who wanted to keep downtown Calgary ... a bit of a no-go zone until such time as they had power fully restored and streets cleaned up. “It certainly looks much different than it did a week ago. They’ve done great work.” The previous week, the company had 3,000 employees working remotely in order to keep their operations running as smoothly as possible. “The biggest challenge faced was just being able to have people able to work remotely,” said McIntyre, adding that they received support from the Denver, Colorado and Plano, Texas offices to proceed with business critical functions. “We were all able to stay quite connected,” he continued. “Having other offices in many locations actually turns into a bit of an advantage in that sense because you’re able to keep a lot of these functions running. “In terms of operating in the field, it’s still early to assess the full impact in operations, but, at this point, we believe that the flood had pretty minimal impact. And, to our knowledge, there are only about two shallow gas well sites southeast of Calgary that were impacted at all.” Cenovus spokesperson Jessica Wilkinson said the flood didn’t have any impact on their southern Alberta operations. “We have prepared for this type of incident and our business continuity plan was activated,” said Wilkinson, noting that staff weren’t able to work in their downtown Calgary offices during the height of the flood because of the power outages. “All business critical work was done from an office location outside the downtown core,” she continued. “This includes functions such as marketing, payroll and treasury. In addition, staff were able to access email and can work remotely from home if requested by a supervisor. All but one of our buildings has now had power restored, including the Bow tower, which houses most of our Calgary staff.” “The flooding in southern Alberta had minimal impact on Imperial’s operations and we maintained all essential services and operations,” said Imperial Oil spokesperson Pius Rolheiser, explaining that a pair of natural gas operations in the area were temporarily shut down only as a precaution, but all their major oil operations were safe in the northern part of the province. “Our refineries and major distribution network for fuels were largely unaffected,” he continued, adding that a few gas stations in Calgary were also shut down, also only as a precaution.

Encana employee Doug McIntyre took these photographs with his cell phone at the height of the flooding in Calgary this June. The site is Fish Creek Provincial Park, which is located in the southeast of the city. McIntyre said roads and bicycle paths are deep under this water. A nearby pedestrian bridge was destroyed by the flood.

DOUG MCINTYRE PHOTOS

Imperial’s Calgary office was only closed from June 21 to June 25. “We maintained our computer networks and many employees were able to work from remote locations,” said Rolheiser. “Our research centre at the University of Calgary campus was unaffected,” he added. Natural gas transmission company Spectra Energy, which operates pipelines and processing plants throughout western Canada, also managed to work through the flood without any major disruptions. “The flood had very little impact on our operations in western Canada,” said Spectra spokesperson Peter Murchland. “However, we did have several hundred employees that could not access the downtown Calgary offices for several days during the flood. In many cases, employees continued to work from their homes until there was improved, and safe, access to the downtown core – as directed by City and emergency officials. “Our main concern during the flood was the health and safety of our employees in the Calgary area,” he continued. “All our employees remained

safe. However, several of them had to be evacuated from their homes for several days during the flood. Some of our employees also sustained water damage to their homes, but the vast majority were not adversely impacted.” “We have quite a few staff who were personally affected and had to be evacuated [and] may be dealing with some property concerns as a result of the flooding,” said McIntyre. ”Since this event happened,” he continued, “we’ve certainly encouraged people that have concerns with property to take care, first and foremost, of what’s important. And that’s property and family. Certainly, that’s being accommodated. “We’ve been very fortunate [that] nobody will have lost their home as a result of the flooding, but [we will] certainly make every effort to accommodate staff that may need that extra time to take care of some of those concerns.” Imperial is helping their employees cope with the flood by offering the severely affected interest-free loans and flexible work schedules. “Our major goal through the flood situation was to

JULY 12, 2013

ensure all our employees were safe and supported, and we maintained good communication with our employees via our e-mail network, social media and other means,” said Rolheiser. “Not surprisingly, a number of our employees were personally affected by the floods,” he added. Calgary is returning to normal, but many residents have suffered property damage and may still be displaced from their homes. There are other issues as well. For example, it was reported on July 5 that the Bow River has tested positive for high levels of lethal E. Coli bacteria after the flooding caused sewage to pour into that waterway. That could be a serious problem for any individual who comes into contact with that water. The energy sector has been doing its best to help with the recovery efforts. Husky Energy promised $1 million to the cause, while Suncor Energy has contributed $1.5 million. “While it is devastating to see the damage as a result of the unprecedented flooding, it is heartwarming to see the community rally together,” said Steve Williams, Suncor president and chief executive officer. “Many of our employees have been volunteering to help with the clean-up efforts and, as a company, we will help. That’s why we’ve developed a comprehensive flood relief program that will deliver dollars to organizations that have expertise in getting funds to those who need it the most.” Shell Canada is donating about $550,000 to help rebuild communities hardest hit by the flood, including a $150,000 donation to the Canadian Red Cross. “The floods devastated many communities where Shell employees live and work. We are grateful to the hard work and professionalism of our emergency services in their quick response to keep people safe. Now our thoughts turn to colleagues, neighbours and friends who lost so much and how we can help clean-up and rebuild homes and communities,” said Lorraine Mitchelmore, Shell Canada president and country chair. “This continues to be a difficult time for many communities, but Albertans are resilient and we will work together to get through this as a community.” Devon Energy offered $750,000 to the recovery, including $250,000 to both the Canadian Red Cross and the United Way. “The floods have had a substantial impact on our communities and the social service fabric that supports them,” said Chris Seasons, president of Devon Canada.“We understand how important it is for business to step-up and help support the immediate emergency efforts as well as the longer-term community recovery efforts. We hope that our funding will help fulfil both those needs.” “I want to express my deepest sympathy and support for those in these affected areas,” said Kevin Reinhart, Nexen’s chief executive officer, announcing a $250,000 donation to the Canadian Red Cross. “We know many of our staff and their families have been impacted, along with thousands of others in the province whose homes and property have been destroyed in these unprecedented floods,” he continued. “Our priority remains keeping people safe and caring for our communities.” “The floods affected many areas where our people live and work and the focus now is on the cleanup and rebuilding homes and communities,” said Tim Sullivan, president of Apache Canada. “Albertans are a resilient bunch and we continue to see countless examples of people pitching in to help. Thousands of people are doing their part, and Apache is proud to be able to support this important work.” Apache’s support features a $250,000 donation to the Calgary Foundation and an additional $250,000 spread across a handful of other organizations, includ-

ing the Town of High River. “The health and safety of our Apache people remains our number one concern as floodwaters begin to recede and the massive cleanup and remediation efforts continue in and around Calgary,” said Sullivan. “We announced on June 22 that we’re donating $500,000 to assist with flood relief efforts in southern Alberta,” McIntyre said of Encana’s contribution, which includes $250,000 to the Canadian Red Cross. “Our thoughts are with those that have been impacted by the floods and we want to commend the emergency professionals and volunteers who have done an amazing job of responding to assist those in need,” Wilkinson said on behalf of Cenovus. “We’re donating $1 million toward flood relief efforts and are working with our community partners to determine what volunteer opportunities are available for our staff,” she added. “We also have a matching gift program in place. If employees choose to donate money to a registered charity, Cenovus will match up to $25,000 per employee. “We want all communities where we live and work to be better off as a result of us being there. Helping those in need is just the right thing to do.” The very first day of flooding in Calgary saw Imperial donate $100,000 to the Canadian Red Cross. “Continuing to assess the situation to determine what other direct financial support might be appropriate,” said Rolheiser. “In addition,” he continued, “the company is actively organizing and facilitating employee involvement in volunteer community activities to support and help those people and communities hardest hit by the flood. For example, on Saturday, June 29, groups of Imperial employees volunteered at a number of Calgary neighborhood clean up and recovery efforts, including the Mission community, which was among

PIPELINE NEWS NORTH •

the hardest hit.” Spectra donated $100,000 to the Canadian Red Cross, but also launched a matching gift program by where they will match any employee donation to the Canadian Red Cross between $50 and $7,500. “During the flood, several of our employees reached out to one another to provide volunteer support,” Murchland said of Spectra’s efforts. “Additionally, employees offered support to residents and various community organizations in several affected communities. The company also extended its Helping Hands in Action annual employee volunteer program to ensure flood-related needs of the community were being met.” The energy sector has been impressed and inspired by the character shown by Calgarians and Albertans during this trying time. “What’s really been inspiring to see amidst all this is the amount of hard work that’s been done, certainly, by relief agencies and emergency services personnel, who have all done just a fantastic job,” said McIntyre. “But what’s also been quite inspiring to see is how many people have volunteered their efforts and pitched in to help, not only their neighbours, but complete strangers who may have lost a lot of belongings and sustained quite a bit of property damage. “I think that really reflects well to a strong sense of community in Calgary.” “I think the unofficial slogan ‘Alberta Strong’ sums it up well,” added Wilkinson. “We will rebuild. The floodwaters have been replaced by a flood of generosity – from volunteers helping with clean up to those donating food and clothes and offering shelter to people who have been – and still are – unable to access their homes. “It’s amazing to watch. And definitely makes us even more proud to be a Canadian company.”

Spectra Energy employees doing their part to aid the flood relief efforts in Calgary by volunteering at a donation warehouse known as Neighbourlink. It is only one aspect of how the company and its employees have tried to help the city recover from the natural disaster.

SPECTRA ENERGY PHOTO

â&#x20AC;˘ PIPELINE NEWS NORTH

JULY 12, 2013

Government bonus revenue down in first half of 2013 Daily Oil Bulletin

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Land sale spending during the first half of the year in Canada was down by about 30 per cent from the previous year, with a dip in Alberta accounting for the lionâ&#x20AC;&#x2122;s share of the overall decline. During the first six months of 2013, industry spent $569.35 million tying up 1.36 million hectares at an average price of $418.55. During the same six-month stretch ending June 30, 2012, governments in Canada received $797.67 million in bonus bids on 1.64 million hectares at an average of $485.26 per hectare. The $411.48 million spent in Alberta from January to June 2013 accounted for just over 72 per cent of the overall bonus spent in Canada. Industry acquired 1.24 million hectares in Alberta during the first six months of the year at an average price of $331.88 per hectare. That was down sharply from the $647.56 million spent during the same period last year on 1.45 million hectares at an average price of $446.43. It was the opposite story in British Columbia where the provinceâ&#x20AC;&#x2122;s bonus revenue rebounded after a weak 2012. The provincial government attracted $127.45 million during the first six sales of the year on 68,248 hectares at an average of $1,867.44 per hectare. To the same point last year, the province had brought in $83.65 million for 66,934 hectares at an average price of $1,249.70. Meanwhile, Saskatchewan saw its land sale revenue dip during the first half of the year. At its three sales held during the period, the government attracted $29.26 million in bonus bids on 49,593 hectares at an average of $589.97. At the same point in 2012, Saskatchewan had $55.64 million in its land sale coffers as industry had acquired 99,545 hectares at an average of $558.92. In Manitoba, two sales were held during the first six months of the year. The province collected $1.16 million in bonus bids on 2,607.62 hectares at an average price of $444.99 per hectare. To the same point in 2012, the government had collected $10.56 million in bonus revenue on 15,310.85 hectares at an average of $689.93.

industry news

JULY 12, 2013

PIPELINE NEWS NORTH •

GOOD SERVICE

Service sector helps Calgary recover from the flood Daily Oil Bulletin A straw poll of Calgary-based oilfield service companies suggests most are coping well with fallout from the city’s flooding, in some cases despite being kept out of their downtown offices. Floodwaters in Calgary’s Bow and Elbow Rivers began receding in late June and city work crews have since cleared tons of mud, water and debris, making roads and sidewalks passable again. Repairs to roads and twisted C-train tracks are a longer-term endeavour. Noting Calgary Mayor Naheed Nenshi’s earlier call to stay out of downtown, some companies asked employees to work from home, while others set up temporary offices in other parts of town. By noon on Tuesday, June 25, Calgary media were reporting that power was restored to about half of downtown, a figure that had risen to 60 per cent the following morning. Realizing it might be a few days before buildings were open, some companies encouraged staff to join the many volunteers that went to work in flood-affected neighbourhoods. That was true for Calfrac Well Services, which made its trucks, pressure-pumping units and crews available in recent days. Calfrac’s downtown headquarters did not lose power and was not flooded. On most days, the company has 120 employees at its head office. Except for a small group sent in to do payroll, the bulk of those stayed away. “We encouraged staff to work from home and to talk to [the city’s emergency management] to see where they could help,” said Doug Ramsay, Calfrac’s president and chief executive, noting many staff volunteered in Calgary and around the province. “We had a big take-up on that. There’s only so much you could do from home, and a lot of our work is customer contact.” In northeast Calgary, the company’s Trades, Training and Technology Centre (TTC) normally houses about 40 employees, but another 50 work spaces were added to accommodate displaced downtown staff. As the week began, and water levels fell, many Calgarians came home to flooded basements, and Calfrac was one of several companies that made its vehicles and crews available to those in need. “We have a small fleet of light-duty pickup trucks, and 50 or 60 people manning them around the community, picking up [things] for whomever and helping out,” said Ramsay. “I’m expecting we’ll have over 50 or 60 per cent participation by our people [in volunteering].”

A few of Calfrac’s pumping trucks went to work clearing flooded parkades on the weekend. Yet, no invoices will be sent, either to Calgarians who benefited from the company’s efforts or to those in Red Deer, where a large Calfrac crew spent hours sandbagging the Red Deer River. For Trican Well Service, the picture was similar. The company’s offices in downtown Calgary’s west end suffered no water damage, but getting employees to work amidst traffic that’s snarled daily proved to be the main issue, according to Dale Dusterhoft, Trican’s chief executive officer. “The other issue is helping out people who had water damage or flooding,” he said. “I’ve been really impressed with our people who were clamouring to help in any way they could. We put work teams together to help employees with serious damage to their homes. We’re also doing things in the community with the same intent. A number of staff are out every day in groups of six to ten, doing just that.” Trican’s crew are using smaller pumps to drain basements, and are helping tear out carpets and drywall, and similar tasks. “We’ve offered pumping equipment to all the cities and towns affected, but it isn’t perfectly suited to suction. They’re really looking for vacuum trucks more than pressure-pumpers,” he said, noting the company did some pumping in Medicine Hat, and has a standing offer of equipment to the town of High River. In the meantime, getting employees to work in postdiluvian Calgary, despite road closures and train derailments, is the biggest challenge. Trican’s downtown office normally has about 400 staff in it. “The transit issues are the biggest ones, trying to get people in within a reasonable amount of time,” said Dusterhoft. “We’re arranging car pools, trying to get people in that way. We’ve also flexed our schedules, so some staff are coming in at 6:00 am, and others at 9:00, to ease the rush hour burden.” Smaller oilfield service firms, like CWC Well Services, are also affected. CWC has a sales team in downtown’s Bow Valley Square, and, like staff at other oilfield service companies, often keeps in touch with colleagues and customers by using smart phones and laptops. “It’s business as usual for us, as far as ensuring our customers are serviced for their oilfield service needs,” said CWC president and chief executive, Duncan Au, when the company was still coping with the flooding.

“As for the number of CWC people affected, only three – myself included – had to be evacuated from their homes,” he told theBulletin. “None of our equipment was damaged by flooding, although we’ll be affected by the heavy rains, as far as getting equipment into the field.” Other service firms echoed Au’s comments, noting that frequent rain around Alberta has made field conditions muddier across the board, slowing the movement of vehicles and rigs. For CWC employees, the combined wet weather and flooding also had other consequences. “We were scheduled to have an Employee Appreciation Day at Kananaskis, but that’s no longer going to happen,” said Au. “Instead, our employees generously donated those funds to the Canadian Red Cross, so the less fortunate will be able to cope with these difficult times,” he said. Au says the company was fortunate, all things considered, since no employees lost their lives in the flooding, nor was any equipment damaged or lost. “We’ve been very lucky,” he said. “The only inconvenience for us is our downtown Calgary office, where employees [could not] access the building.” For Enerflex, whose Calgary office is on Mcleod Trail, not far from the Elbow River, near the Stampede grounds, the flood situation was a lot closer to home. “Our head office was hit pretty hard,” said Craig Stewart, Enerflex’s vice president and chief information officer. “But on Friday, we put together a contingency plan and divided our staff up to [work at] our four other Calgary offices.” The upshot was that all Enerflex head office staff, including finance, communications and legal teams, migrated to the company’s 47 Street SW office, resuming work there. Meanwhile, the Enerflex sales staff was moved to the company’s manufacturing facility at the Calgary airport, and worked through the weekend. By Monday morning, all teams were fully operating, albeit at different venues, he said. The flood’s real impact has been on Calgary’s roads, highways and transit, he said. “We’re really dependent on the public infrastructure,” Stewart said. Looking back, Stewart said he was struck by just how rapidly the flooding hit. “It just shows you can never fully anticipate what might come your way.”

Development drilling in Canada continues at record pace Daily Oil Bulletin Operators have drilled a record 7.8 million metres of development hole in Western and Northern Canada to the end of May, surpassing the previous high of 7.54 million metres last year. Exploratory metres declined slightly from last year, however, to 1.21 million metres rig released in the first five months of the year compared to 1.35 million metres a year ago. The average length of a well in Western/ Northern Canada has increased to 2,069 metres in the January-to-May period versus 2,045 metres in the comparable

period a year ago. Operators rig released 315 wells in May, a decrease of almost 17 per cent from 379 wells drilled in the comparable period a year ago. Industry has drilled 4,356 wells through the first five months of the year, up 1.6 per cent from 4,291 wells rig released over the January-to-May period in 2012. Those 4,356 wells translated into a total of 9.02 million metres of hole, up 1.5 per cent from 8.88 million metres to the end of May last year. In Alberta, 248 wells were rig released in May, up 6.9 per cent from 233 wells drilled in the year-prior period. Through

the first five months of the year, the count has climbed about four per cent to 2,847 wells rig released compared to 2,739 in January-May 2012. Saskatchewan operators drilled 35 wells last month compared to 113 in May 2012 (off 69 per cent). The five-month tally is down 5.8 per cent, to 1,040 wells drilled versus 1,104 wells rig released in the first five months of 2012. British Columbia’s 31 rig releases in May were up 34.8 per cent from 23 a year ago, while the five-month tally is flat with 235 wells drilled in January-May 2013 – the same count as a year ago. Only one well was drilled in Manitoba

last month compared to seven in the year-prior period. Over the first five months of the year, 224 wells have been rig released in the province compared to 201 in the January-toMay period last year. To the end of May, 1,982 of the wells drilled in Alberta had oil or bitumen as an objective compared to 1,832 wells last year, while 452 were approved for natural gas or CBM (coalbed methane) targets compared to 539 in the first five months of 2012. In Saskatchewan, only one well with a gas objective has been rig released over the January-May period, while 995 have chased oil.

• PIPELINE NEWS NORTH

JULY 12, 2013

environment

HOME ON THE RANGE Forage Association tour offers glimpse of lease site re-vegetation study james waterman Pipeline News North

It only makes sense that the Society for Range Management Pacific Northwest (SRM PNW) summer tour featured discussions of issues ranging from soil and water conservation to managing invasive weeds and cattle grazing pastures in the Peace Region. After all, the two day event is largely a gathering of individuals representing agriculture, forestry and conservation groups such as Ducks Unlimited. However, the tour that took place in the Dawson Creek area this June also included a visit to an oil and gas industry lease site. “We just went to the edge of a lease site,” said Jennifer Critcher, a vegetation advisor for natural gas producer Encana. Critcher is responsible for weed management throughout the company’s operations in an area that extends from Grande Cache, Alberta in the south to Fort Nelson, British Columbia in the north. “They were able to look at the different re-vegetation trials that we have set up on an Encana site,” she continued. The seeding on that site was conducted by the Peace River Forage Association, which is also monitoring the progress of those plants. “It’s basically just to see what plants establish better under the conditions that are on an oil and gas lease site, where they strip back the topsoil and then they strip back the subsoil, so you have essentially two different soil types in piles on the edge of the lease site,” added Critcher. Bill Wilson of the Forage Association explained that the study dates back to conversations between natural gas producers in northeast B.C. and Julie

Robinson, a regional agrologist with the provincial Ministry of Agriculture in Fort St. John. The companies were looking for seed mixes that would result in grass growing as quickly as possible on disturbed sites such as leases and pipeline right-of-ways. “We’ve got these berms,” Wilson said of those piles of topsoil and subsoil along the edges of lease sites that were mentioned by Critcher. “They’re trying to get something to grow on really, really poor soil,” he continued, discussing efforts to grow vegetation on those berms that are a mix of organic soil from the top layer and mineral soil from the subsurface. “When you dig down four feet, there’s no organic matter,” he added. “We saw this as an opportunity to reevaluate some of things that have been going on for a long time.” That includes questioning the composition of typically used seed mixes. Wilson noted that many companies have typically left the berms as mounds of dirt, spraying them for weeds on a regular basis. However, producers began to recognize that purposefully growing vegetation on the berms reduced the spread of weeds and prevented soil erosion. “So, we set up these tests to evaluate different species on the berms,” he said. The Forage Association has been working with both Encana and Shell Canada on the project. “There’s a lot more to it than just species,” said Wilson, discussing the factors that determine successful re-vegetation of those sites. Soil fertility and the construction of the berms are also important. “The berms have to be constructed in such a way that, mechanically, they can be seeded,” he explained. “If it’s really steep, than you can’t run your quad or your seeding system on it.”

The three-year project began with the first seeding last spring, followed by subsequent seeding last fall and this spring. Observations will continue to the end of next summer, but Wilson is hoping that new funding will allow the project to proceed beyond that point. “Because there will be things that we’ve learned that need more evaluation,” said Wilson. “We’re hoping to carry it on, but, right now, we don’t have the funding in place.” Early results have shown that metal brome grass and alfalfa have fared very well on the berms, including on areas of poor mineral soil in the case of alfalfa. Wilson attributes the success of the metal brome grass to its large root system. A native species of wheatgrass has also thrived on the site, but timothy and a pair of fescue species have struggled in comparison “A native called fowl bluegrass has done really,really poorly,” said Wilson. “It’s kind of the real disappointment.” The initial application of the results of the study will be re-vegetating pipelineright-of ways and Wilson expects that to offer benefits as far as invasive weed management. “If you’ve got grass growing there, than weeds aren’t going to have that competitive advantage,” he explained. “If you’ve got a good stand of grass, than the weeds just aren’t going to be able to grow.” Wilson said the tour-goers were “quite impressed” with the study and particularly interested in the considerable differences between the success rates of the various species. “A lot of the people on the tour, especially the ones from [southern B.C.] and from the [United] States, were just quite fascinated by the whole oil industry thing,” he continued, adding that sites such as multi-well pads are unknown

phenomena to many people in the SRM PNW, particularly those from southern B.C. and regions of the northwest U.S. such as Washington. Illustrating that fact, Wilson told of a visit to a lease site after the tour with a woman from southern B.C. who writes about the agricultural sector. “She said, ‘Well, how big would this be so I can compare this to something people can understand?’ And we kind of figured out it would be about two football fields. ... She said, ‘That’s interesting. Where I live, there are farms that are this size.’” The lease site re-vegetation project wasn’t the only learning opportunity on the tour. The better part of the two-day journey was spent examining methods of controlling aspen on land where the common boreal tree species is a nuisance for those individuals requiring forage for their cattle. “The tour started at Bear Mountain,” said Wilson. Bear Mountain, just southwest of Dawson Creek, is the site of a community pasture on Crown land that is used by local cattle ranchers. “They get aspen re-growth in it all the time,” added Wilson. The solution at that site has been removing the trees and seeding with forage species, a vastly different method than the one employed at the farm belonging to Glenn Hogberg, another stop during the first morning of the tour. “What he was doing was, after logging, he went in with livestock and grazed them really, really heavy so that the actual cows were walking on and killing the trees, and eating the leaves,” Wilson said of Hogberg. “And did that for a number of years,” he added. However, Hogberg hasn’t had sufficient cattle to use that technique on

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Seeding the north berm of an Encana lease site near Dawson Creek, B.C. last spring. The natural gas producer is working with the Peace River Forage Association to study the growth of forage plants such as alfalfa on the sorts of land disturbances common in the oil and gas industry. The results of the project could change how companies seed areas such as pipeline right-of-ways on pastures.

PEACE RIVER FORAGE ASSOCIATION PHOTOS

larger areas. Instead, he began feeding his cattle on the range during the winter, causing winter damage to the young aspen from the cattle walking through the snow and hay bales left on top of the snow. “That puts manure out there and that helps the grass production as well,” Wilson continued, adding that the results of this method have been better than the results of using heavy equipment to remove the trees and re-seed with grass at Bear Mountain. Tour-goers also had a look at a project known as Holy Cow. “The Holy Cow Project was a project that happened a long time ago,” Wilson said of a study that took place south of Dawson Creek about twenty years ago. “They were grazing cattle in aspen growth,” he explained. “Bigger trees. And what they were trying to do was evaluate if the cattle actually did damage to that aspen growth. “They found that it really didn’t make any difference. The trees did well.” Wilson said the project was a significant undertaking at the time. Including that site on the tour was simply to point out that the initial conclusions of the study still hold true today. “They were just showing people that this area had cattle and this one didn’t, and the aspen growth is very, very similar.” The value of the tour in Wilson’s eyes is bringing stakeholders together from across the natural resource sectors to learn about these different ideas and projects. “I think it gives everybody an opportunity to see what the other industries [are] doing.” Wilson was particularly interested in the work of Richard Kabzems, a research silviculturist with the Ministry of Forests, Lands and Natural Resource Operations (FLNRO), who is studying conditions under which poplar is successful. “And the other part of it from the forestry end is that

the people that want to grow trees have a better understanding of what’s in it for the livestock producer who wants to grow grass where he can graze his cows,” said Wilson. “I think it just gives everybody a better understanding of the other person’s point of view.” Wilson also sees the value in people who work in the field in the oil and gas industry understanding the methods and the goals of farmers and foresters. “I think that the [agriculture] producers have devel-

oped an appreciation for the oil industry, some of the challenges that they have,” he added. “As a producer, you think, ‘Well, that can’t be that hard. We’ll just go out and seed the berms.’ But now I have a lot better understanding of some of the things that happen out there and realize it’s not quite that simple. “It’s got everybody talking about stuff like that. And I think that’s absolutely super.” “It’s always good to educate people,” said Critcher. “And there are so many different, interesting projects.”

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industry news CHANGE IS IN THE AER

Alberta introduces new energy sector regulator

Jim Ellis is the first chief executive officer of the new Alberta Energy Regulator.

ALBERTA ENERGY REGULATOR PHOTO

james waterman Pipeline News North The ink was barely dry on the proclamation that the new Alberta Energy Regulator (AER) was finally up and running when the heavens let loose a deluge of torrential rains that left Calgary and its neighbouring communities underwater. The AER was officially operational on June 17, but floodwaters in Calgary forced its staff out of their head office almost immediately. “The question: were we ready when the proclamation of the bill occurred and the new regulator was launched on June 17?” said AER spokesperson Bob Curran. “I think the answer is in the ... capacity we demonstrated while the flood occurred and our head office was shut down for over a week. “Of course, we have other options, because we have offices across Alberta.” Curran also noted that the AER was able to adequately respond to incidents that did occur in the field while its offices were closed due to the flood. “The industry that we regulate” he

said, “they were probably slowed a bit by the head office closures as well, because most of Calgary’s downtown was closed. And you might have seen an effect on our ability to process applications, for example, but all of the critical stuff that has to happen to ensure that public safety is protected and the environment is protected, all of those functions continued uninterrupted and unaffected.” AER staff who have lost property or had their homes damaged by the floodwaters will be given time to address those issues. “They’re going to be given whatever support is necessary to ensure that they can manage that, because, of course, it can be devastating, the impact on individuals,” said Curran. “There are a lot of people affected in Calgary and the surrounding area, and we have staff that live outside of Calgary, too, in some of those areas,” he continued. “Whatever support they need, they’re going to get to ensure that they can [have] the time to deal with it. “The provincial government is step-

ping in [to provide] direct assistance to people that are impacted.” The Calgary office was back to business as usual on Tuesday, July 2. “We probably could have been in on Monday if it wasn’t a holiday,” said Curran. “But everything returned to normal on Tuesday. And you wouldn’t even have know there was a problem. “The building really wasn’t affected,” he added. “It was just within that quadrant that was shut down. There was no more power for several days. Almost a week there was no power downtown. We just worked remotely. And we have pretty good remote capacity for our staff to access our system. Any of the critical work that needed to be done was all being done fairly easily.” The AER has replaced the old Energy Resources Conservation Board (ERCB) and the biggest difference between the two entities is structural. “We’ve shifted from our old model,” said Curran, noting that model was a board with several members led by a chair. “And they were involved in all aspects of the organization – operational, regulatory and adjudicative – and they were the leadership of the organization,” he continued. “The new structure splits up those functions.” AER has a new part-time board of directors led by chair Gerry Protti. “That board is responsible for governance of our organization,” said Curran. “High level strategic work. They’ve got specific duties that they’re overseeing and giving advice to the organization on. But they’re not involved in the day-to-day operations and they’re not involved with the adjudicative process at all.

The adjudicative process has been separated out from the operations as well. We have now a chief hearing commissioner and we have hearing commissioners whose role is strictly to work on hearings. And again they’re not involved in the operational side of the business.” The operations are led by new chief executive officer Jim Ellis, who has taken over many of the responsibilities previously held by the chair of the old ERCB. “The operational side of the business, the decision-making, the day-to-day regulatory affairs, the rules that we have in place that companies are required to follow,” Curran explained. “It’s just to ensure that there’s a clear division between the regulatory function, adjudicative function and that governance,” he added. Another brand new feature is a policy management office within government that can address policy issues brought to them by the AER. Previously, when certain issues arose, and they were more policy issues than regulatory issues, we often just put regulations in place to deal with them,” said Curran. “And it worked to a point. But, functionally, some of those things should be flipped over to government. And the policy management office is going to provide that liaison between us and government. And they’re going to assess a lot of these issues. “If there’s a policy issue, they’ll take it to government. And if it’s regulatory, it will remain with us.” Again, it is about ensuring a clear division of roles and responsibilities.

Alberta’s energy minister Ken Hughes and his colleagues in government did the heavy lifting putting the new provincial oil and gas industry regulator together.

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“That keeps us focused on just strictly the regulatory side of things in Alberta,” said Curran. “And it keeps government focused on the policy side of things, which is the way it’s supposed to work.” A lot of the heavy lifting when it comes to creating a new regulatory body is done by the government, which obviously has to do the work of drafting the legislation. “And there are still further changes to come,” said Curran. “There are new regulations that are going to be put in place. Because this is a phased-in change over to the full authority that’s going to be bestowed upon the Alberta Energy Regulator. That won’t fully occur until next year about this time.” When it comes to the work that must be done by the AER staff, the devil is in the details. “When we’re given direction by the

government, then we put things in motion,” said Curran. “So, it’s a lot of little things that, put together, add up to quite a bit of work.” That includes everything from business cards to logos on truck and signs on office buildings, as well as all the computer work that goes well beyond simply changing a name on a website. “We have a lot of web-based applications,” said Curran. “Just our website alone is enormous,” he added. “And to go through and get every last reference to the ERCB changed to the Alberta Energy Regulator [is] an enormous undertaking just on its own.” Part of the reason for the shift to a single window regulator was improving efficiency in terms of applications, reviews, accessing information and addressing stakeholder concerns. “That’s the phased-in part,” said Curran.

“A lot of the functionality that resides currently with Environment and Sustainable Resource Development that pertains directly to upstream oil and gas activities will be shifted over to the Alberta Energy Regulator in a phased approach,” he explained. “The legislation that created the Alberta Energy Regulator is basically a framework and the regulations build that capacity within the framework for those changes to occur. That’s going to happen over time. And we’re going to see some changes here this fall, and then the remainder will occur by this time next year. “[It will mean] landowners, other stakeholders, municipalities and industry all having a single point of contact for a lot more of the issues ... rather than multiple points of contact.” Curran said the AER is being proactive in spreading the news about what

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all stakeholders need to know about the new government agency. “We’re going out across the province to re-launch all of our offices and meet with people in those local communities,” he said. AER will also reach out to environmental groups and other political parties to ensure that they are well informed about the new regulator. “And, of course, we’ll have a lot of information available, as we always have, on our website,” Curran added. The reaction to the AER has been mixed so far, which, according to Curran, is fairly typical of announcements concerning the new regulator and its predecessor. “There’s always question marks when you’re making a change like that as to how things are going to go,” said Curran. “It came together pretty well.”

Questerre releases resource assessment of Montney lands Daily Oil Bulletin Questerre Energy Corporation said on July 4 it has prospective resources of 100 million barrelsl of oil equivalent (boe) and economic contingent resources of 32 million boe on its Montney acreage in the Kakwa-Resthaven area. Prospective resources are quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations through future development projects. Questerre said the assessment by McDaniel & Associates Consultants Ltd. includes: discovered and undiscovered petroleum initially in place (PIIP); prospective resources (PR), a subset of undiscovered PIIP; and economic contingent resources (ECR), a subset of discovered PIIP. “We are very pleased that the report puts a significant value on the dense resource we have captured in the Kakwa-Resthaven area over the last year,” said Michael Binnion, president of Questerre. In a press release, he said economic contingent resources were assigned to just over 15 per cent of

the company’s total acreage based on proximity to tested or producing Montney wells. “We expect that as additional wells are drilled and tested on and adjacent to our lands, the majority of the prospective resources will be reclassified as economically contingent resources and ultimately reserves.” The McDaniel report assessed the resource on 12,800 net acres or about 44 per cent of Questerre’s total acreage in the area. No assessment was done of the company’s 16,000 net acres held in the Wapiti area. The report estimates PR net to Questerre to range between a low of 291 bcfe (49 million boe) and a high of 774 bcfe (129 million boe), with a best estimate of 598 bcfe (100 million boe) that includes over 40 per cent condensate. In addition, ECR, attributed to only 15 per cent of the company’s 28,800 net acres, have been assigned a best estimate of 190 bcfe (32 million boe), with a range from a low of 95 bcfe (16 million boe) to a high of 245 bcfe (41 million boe). About 50 per cent of this best estimate, or 16 million boe, is natural gas liquids with condensate accounting

for over 83 per cent of this amount. The PR and ECR are in addition to the proved and probable reserves of 26 bcfe (four million boe) at yearend 2012. The evaluation conducted by McDaniel included detailed geological and petrophysical analysis of Questerre and adjacent industry Montney wells. It focused on the Upper and Middle Montney intervals. McDaniel assumed a Montney development plan based on an average of eight wells per section (four wells for each of the Upper and Middle Montney intervals). Total PIIP on average was estimated at about 60 bcf per section with recovery factors estimated to range from 20 per cent to 55 per cent with a best estimate of about 40 per cent. The recoveries of NGL estimated by the resource assessment are based on the company securing shallow-cut processing capacity. Questerre said it is currently in negotiations to secure processing, transportation and fractionating capacity for its production in the area. Contingent resources were assigned to the company’s acreage within a three mile radius of a tested or producing Montney well.

New PennWest CEO sees greater concentration on Cardium Daily Oil Bulletin David Roberts, the new president and chief executive officer of embattled Penn West Petroleum, says that the operator needs to reshape the size and scope of its portfolio. There’s been much upheaval at the company this year. Roberts began his new role just a couple of weeks ago. He replaced Murray Nunns. Also, Allan Markin stepped down from Penn West’s board. Despite the turbulence, Roberts appeared confident the company can right the ship. “This is a company that everything that we need to do is within our control; we need to be much better operators in terms of how we actually execute our program,” he said. “We need to be much better deciders of where our capital goes in terms

of what creates the most opportunity. “If we do those things, a lot of the things that will happen in the company will fall out naturally. Our portfolio needs to be reshaped in size and scope; the organization needs to be reshaped.” Roberts said the Cardium is the heart of the company. Penn West holds 600,000 net acres there with roughly 500 million boe of contingent resources. The 2013 program includes selective primary development drilling at Alder Flats and waterflood initiation in three areas. “We have a vast acreage position in what I think is one of the more interesting assets in North America, if not the world,” he said. “It’s not sexy, as you might say... but it is an asset that you can put a lot of money to work in through just good oilfield practice along with some secondary recovery techniques.

“I do not think that we have focused appropriately on this asset and it’s one of the things that we’ll be doing much more of in the coming years as we move forward.” The company also plans to invest more in the Viking in Saskatchewan, he added. Meanwhile, Roberts noted that the company is doing a full-scale review of all its assets. The Duvernay, for example, is “not really relevant” to a portfolio of a company Penn West’s size. “This is going to be big dollars in terms of how this is ultimately going to be developed; great geology, it looks very similar to some of things I’ve seen south of the border, but it just may be a bridge just too far for us,” he said. “We need to start performing. This is a company that has not been able to deliver on its expectations. That delivery model will change. We will start making prom-

ises and actually [meet] them. “We will drive the business to improve our capital efficiency relative to the type of asset base that we have. There is dramatic room for improvement in our cost structure. We recognize that we’re not cents but dollars out of range with some of our capital and overhead structures and we will be taking significant action to address that.” Penn West has a balance sheet that does not allow for much flexibility, Roberts said. “We’ve done some repair there by having to take the very difficult step of reducing a very large dividend to one that is still very attractive in terms of a yield basis but we’ve got to do more to get our balance sheet back under control so we can be in a less risky position,” he said.

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profiles THE LNG MAN COMETH Krish Suthanthiran’s journey from India to Kitsault james waterman Pipeline News North If Krish Suthanthiran has taken an unconventional path into the Canadian oil and gas industry, perhaps it is only because he was meant to be closely tied to its unconventional resources. With British Columbia and Alberta sitting atop a wealth of shale gas waiting to be unlocked by methods known as horizontal drilling and hydraulic fracturing, industry and government are scrambling to take advantage of high natural gas prices in Asian markets by building pipelines and facilities that would allow the export of western Canadian natural gas to those countries as liquefied natural gas (LNG). Although Suthanthiran isn’t an experienced oil and gas player, he recognizes the opportunity that exists with LNG, which is why he has purchased the industry ghost town of Kitsault, B.C. with the intention of partnering with energy sector companies to turn the coastal village into an LNG export hub. “My life from childhood had many twists and turns,” said Suthanthiran. Born in India, the young Suthanthiran was a bright child who eventually felt drawn to the universities of North America – despite lacking the financial wherewithal to make that leap – because of the example set by a friend and classmate who had traveled to the United States to study at the University of California in Berkeley. “Having watched him for a couple of months, I decided to try my luck, but I had no money,” said Suthanthiran, adding that “money was not a problem” for his friend, as he had come from a wealthy family. Suthanthiran’s friend had also studied at an English school and his family conversed in English at home. “He was very smart,” said Suthanthiran. “And much more fluent in

English than most in our class. My English was not that good.” Suthanthiran’s fortunes began to change with newfound connections to Carleton University in Ottawa, Ontario during his college days. A classmate had relatives who were studying at that school and he also met one of its professors at his own school in 1968. That inspired him to apply to the mechanical and aerospace engineering program at Carleton. Suthanthiran was accepted into the program, but without a scholarship that future was still in doubt. Although he was able to get a student visa, he didn’t have the airfare to fly from India to Ottawa, let alone the necessary funds to pay his tuition. So, he took his story – and his exemplary school and college records – to a local bank manager who offered a loan of 10,000 Indian Rupees, which was about $1,250 Canadian at the time. Suthanthiran was soon on his way to Canada. “I arrived around September 7, 1969,” he said, recalling that it was cool and rainy that day. Suthanthiran was able to rent a room near the university, barely managing to scrape by with his loan and the earnings from a dishwashing job at a cafeteria. “One dollar an hour.” H o w e v e r, i t w a s n ’ t l o n g u n t i l Suthanthiran secured a position as a research assistant under Richard Kind. “He and his wife were very kind to me,” he said. “I am still in touch with them. And his son is working for me in our Vancouver office.” Suthanthiran has also established a scholarship in Kind’s name at Carleton University, as well as two other scholarships in honour of chairmen of the mechanical and aerospace engineering department who were an important part of his life during his university days. “I am still in touch with the university and its president,” said Suthanthiran,

Krish Suthanthiran is the brains behind a plan to turn the abandoned mining town of Kitsault, B.C. into a liquefied natural gas export hub. Suthanthiran purchased the village in 2005.

kitsault energy PHOTO

who has also contributed to purchasing new equipment for his old department. Still, it was a difficult transition to Canadian life for Suthanthiran. “A rough beginning,” he said. “I was trying to understand the English language [and] the Canadian slang. Extremely cold winters. Lots of snow.” It was something of a culture shock,

but one made easier through the summer months by the fact that so much of the Carleton campus is connected by underground walkways. “Slowly,” he continued, “I got used to drinking coffee multiple times a day. Drinking beer. Eating pizza. ... For nearly 18 months, every day, my dinner was cheese pizza with banana peppers R001424176

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delivered to the campus.” His early days in Canada offered a few embarrassing moments, too. “One day,” he recalled, “I went to the library.” Trying to ask the librarian when the book should be returned, his still poor English caused him to make an unfortunate mistake. “I said, ‘Can I have a date?’ And she freaked out and decided to call security. And I was a nervous wreck , worried they were going to kick me out of the university.” Suthanthiran survived those early troubles to complete the course requirements of his program in December of 1979 and finish his thesis in 1971. “I began to search for work,” he said, noting that Canada and the United States were suffering a recession at the time and unemployment was high. “Professor Kind gave me a six month assignment at $500 per month, which expired at the end of June or July 1971, and I still did not have a job,” he added. “Having lost my father to cancer, I began to think about medical school and was attracted to McMaster University.” Suthanthiran began enrolling in the required biology and chemistry courses at the University of Toronto to pave the way for admission to McMaster, but, as a lifelong vegetarian, he found it difficult to perform the dissections that were necessary to complete the biology classes. He was looking for opportunities again. During the winter of 1972, he spent time with a friend who was a doctoral student in computer science at the University of Waterloo. He grew to like the campus and so chose to pursue a doctorate in mechanical engineering at that university beginning in the fall of 1972. Before beginning those studies, however, Suthanthiran took his first journey into the United States with stops in Detroit, Cleveland, Pittsburgh and Washington, D.C., arriving at that final destination just days after the Watergate burglary. “I began my sightseeing tours and fell in love with the beauty [and] historical and global significance of D.C .” His original plan was to spend two days in the U.S. capital before moving on to New York, but he soon decided to prolong his stay in order to look for a job. “One of the oncologists in a local hospital was looking for an engineer to design instruments for cancer treatment and research,” said Suthanthiran. “I got the job and began my career in Washington D.C.” His home for the first few months was a bunk bed at a hostel just a few blocks from the White House. “Walked to work every day and had no car for almost a year,” he said. That was the end of his plan to study at the University of Waterloo, but the beginning of his career in the oncology field. Sunthanthiran has tried his hand at a few business ventures outside of that arena – even restaurants – since starting as an engineer at that Washington, D.C.

hospital in 1972, but the only real success to date has been Best Medical International, which he launched in 1977, just prior to leaving the hospital in 1978. As the company really started to thrive in the eighties, he also began investing in real estate. “Since I never had much luck with the stock market,” he said. The ups and downs experienced by the company over the years, along with the constant technological changes in t h e m e d i c a l i n d u s t r y, i n s p i r e d Suthanthiran to diversify. “I began to contemplate expanding in 2004 and started to purchase other companies,” he said. He bought Kitsault in January of 2005. “Sight unseen,” he said. It all began during a conference Suthanthiran attended in Halifax, Nova Scotia in September of 2004. During his trip to the east coast, he just happened to pick up a newspaper on a Monday morning to see a front page story about Kitsault. “And it was for sale,” he said. His first visit to Kitsault was in February of 2005. “It snowed heavily. It was a beautiful sight,” he said. “In spite of the heavy snow,” he continued, “it did not feel very cold. And it was pleasant outside when the snow stopped.” Kitsault was purposefully built as a mining town and it was home to about 1,200 employees at the peak of operations. “Many still contact us and express their fondness for the town, including the kids who grew up there. Kitsault brings many fond memories to all of them,” said Suthanthiran. “Since I purchased Kitsault in 2005,” he added, “it has gathered a great deal of publicity, interest and excitement. In India, every, daily, weekly [and] monthly journal, newspaper, and magazine, in every language, has written it up. ... I probably get a few emails from those interested in buying a home or moving to work there every week. Prior to my purchase, no one knew [much] about it.” Suthanthiran’s goal from the beginning has been to bring economic activity back to Kitsault. An idea began to emerge last fall when he was looking at the growing natural gas exploration and production activity in northeast B.C. and the Kitimat Clean plan to construct an oil refinery in Kitimat. “During the Christmas break,” he recalled, “one of [my] staff contacted me about the news about the LNG plans for northwest B.C. I requested [that he] send me all the news articles about it.” Suthanthiran was in Atlanta, Georgia on a business trip at the time. “As I began to read,” he continued, “I got very interested and wanted to read everything about it.” He even spent a rainy New Year’s Eve in his hotel room learning all he could about B.C. natural gas and the burgeoning LNG industry. “As I read the articles, the one about Spectra Energy stuck with me,”

said Suthanthiran. It was because their proposed pipeline to Prince Rupert as part of their LNG-based partnership with BG Group was likely to pass Kitsault. If that pipeline was expected to exist regardless, it could potentially cut the cost of establishing an LNG export terminal at Kitsault. “I began to contemplate the use of Kitsault as an energy hub and [creating] a dedicated energy corridor and export terminal,” he continued. “So, I talked to my legal team about forming Kitsault Energy as a company in Canada and issued the first press release on January 8 from Ottawa. And had a press conference in Ottawa on the same day. “Everyone at the press conference was very excited and thought it makes a lot of sense.” Suthanthiran and his team – which would eventually include Dave Pernarowski, mayor of Terrace – has been promoting the concept at conferences throughout North America, as well as discussing the possibilities with governments, potential investors and major oil and gas industry players. “Three months ago,” he said, “we began to lay out a multiphase plan that may cost as little as $5 billion for phase one [and up] to $35 billion for all of the phases, taking three to seven years to complete.” The first phase is a pipeline and a floating LNG facility. “We could complete this phase in three years,” he added, noting that the export capacity of the first phase could be up to 5 million tonnes of LNG per year. Subsequent phases would include construction of a land-based liquefaction and export facility. “What does all this mean to Canada, B.C., Alberta and Saskatchewan?”

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Suthanthiran asked. “[This] is a huge opportunity to export the natural gas from these provinces, create nearly a million new jobs by the end of the next decade, balance the budget, improve education, healthcare and job training, and help the First Nations enjoy the benefits.” Suthanthiran believes Canada needs to experience those rewards. “Majority of the provinces in Canada and the federal government are [experiencing] a deficit budget,” he explained. “And the cumulative budget deficits of some provinces are approaching 200 percent of GDP. Canadian manufacturing is declining. Just last month, Canada lost almost six per cent of jobs in manufacturing, while it had robust growth in the service sector, construction and real estate. “Canada, the provinces and the energy industries are losing, on the average, $35 bIllion in annual revenue ... because they are selling the oil at a discounted price [and] do not have the pipeline capacity to export. Also, Canada’s export of natural gas to the U.S. has declined by 50 per cent during the past five years. And, in a few years, the U.S. will not need any Canadian oil or natural gas for domestic use.” Suthanthiran predicts a 25 per cent decline in manufacturing jobs in Canada by the end of the decade, noting that automotive industry jobs have already declined by 50,000 since 2008, while investment in that sector has also been reduced significantly. “However, during the next three decades, B.C. will add nearly one million or more new jobs and a $1 trillion investment in the economy, spurred by the natural gas industry, and along with the growth of Alberta oil production. “This is great for B.C.,” he said. “And Kitsault.”

The coastal village of Kitsault that Suthanthiran purchased in 2005. Suthanthiran had no intentions of transforming the site into a centre for natural gas liquefaction and export at the time, but began to seriously consider the possibility after reading about the emerging liquefied natural gas industry just last year.

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special feature

SAFE AND SOUND

Marine oil transport has come a long way in 25 years james waterman Pipeline News North

Opponents of Enbridge’s Northern Gateway plan to ship Alberta oil sands bitumen to world markets via pipeline to the British Columbia coast and via oil tankers to destinations along the Pacific Rim often cite the cause and effect of the infamous Exxon Valdez oil spill of 1989 as a reason to abandon the project. However, a recent report published by IHS CERA as part of their Oil Sands Dialogue program not only shows that the world of marine oil transport is vastly different today, but also that Canada has been safely and successfully moving oil across the ocean for years. “It’s part of why our header in our press release was that Canada already does this on the east coast,” said Jackie Forrest, who leads the Oil Sands Dialogue efforts for IHS CERA as part of her role as senior director of their North American oil division. “We had a workshop in Vancouver and had a wide group of stakeholders there,” she added, referring to the March 21 focus group that was part of the study – along with considerable research and analysis by IHS CERA staff – that informed the report titled Assessing Marine Transport for Canada’s Oil Sands on Canada’s West Coast. “Their perception is this is all new for Canada – we don’t have a lot in place,” Forrest continued. “One of the key things we found through our research is there is already an existing regulatory framework that does look a lot like a lot of other countries. Now the application of that is going to have to change as we scale up the activity on the west coast. But there is an existing framework there that Canada uses and it’s what actually most other countries use as well.”

Forrest believes the research conducted by IHS CERA indicates that Canada’s ability to manage marine oil transport isn’t well understood by many Canadians. “Canada actually moves a lot of oil,” she said. “Nothing like the United States or China, who are really dependent on imports, but similar to Australia and Norway already. “I don’t think it’s well understood .” The report suggests that Canada already has an impressive set of measures and regulations in terms of preventing marine oil spills and responding to such events if they should happen. The first measures noted by the report concern the competency of crew members and ship design, an area that has seen significant improvements since Exxon Valdez. “The double hulls,” said Forrest. “The fact that now they’re segregated vessels so that, if you were to puncture a hole into the vessel, but a part of the entire volume of the vessel could be emptied. “Things have changed a lot.” Owen McHugh, manager of emergency response for Enbridge Northern Gateway, said that his company would only accept the best tanker design for their project. “We talk to our experts,” said McHugh. “And we commit to things such as cargo tanks that don’t span the entire width of the tanker. And what that does is it limits the potential volume that could flow out in the event of an incident there, just by selecting a tanker that has an appropriate tank design. “There might be a few ships that still have that old standard,” he added, “but, as a project, we wouldn’t be able to accept that.” The report noted that Canada performs over 1,300 foreign ship inspections per year, the results of which can include warnings, fines, vessel detention and prosecution if problems exist. The Department of Fisheries and Oceans (DFO) and Environment Canada

also have a variety of navigation tools for ships entering Canadian ports. Additionally, all international vessels larger than 300 metric tonnes traveling through Pacific coast waters must use Automatic Identification Systems (AIS). That tool broadcasts information about the ship that ranges from its name to its speed. The report states: “Services like AIS aid in vessel navigation around ships and other obstacles.” Ships are typically required to be escorted by tugs, as well as being piloted by individuals with a wealth of local experience in the case of sensitive waters or particularly challenging conditions, which may describe the Douglas Channel route into Kitimat, the endpoint of the proposed Northern Gateway pipeline. “Many of the precautions that are used today just didn’t exist in that time,” said Forrest, referring to the Exxon Valdez spill again. “They didn’t have pilots onboard looking over their shoulders with local knowledge of the area. They didn’t have tugs on the boat. “It’s practice, but it’s also technology.” The report notes that marine oil terminals frequently have their own pilots and other personnel who supervise the process as well. Furthermore, coastal waters are patrolled by Canada’s National Aerial Surveillance Program, which can deter illegal activities such as purposefully discharging oil or waste products, as well as allow the authorities to detect an oil spill early. That is only the tip of the iceberg as far as Canada’s preparedness for marine oil transport, but even that seems to far exceed the knowledge of most Canadians in that respect. “Oil sands needs new markets,” said Forrest, “and access to the west coast is a key question in terms of what a potential new market could be. And so we wanted to get some facts and data out

there. Because there is obviously a debate going on, but there’s sometimes a void of information. “We thought we could add some value by researching some of the questions that were coming up around potential tanker movements from Canada’s west coast.” It is why all Oil Sands Dialogue reports are available to the public. “We do think it’s important,” said Forrest. “That’s why I value talking to [the media]. Because I think the articles that [they] write are going to be more widely read than a 30 page document on our website. “And I think people need to have facts and data. And what we try to do is involve a whole bunch of stakeholders. And this report was informed by a workshop, as well as many people reviewing the paper, and all sorts of different groups. We had [non-governmental organizations] review it. We had [the United States] Coast Guard. We had people from the shipping industry. Oil industry. “Our goal is to have it very balanced and factual, and hopefully inform people of some of these aspects associated with maritime shipping.” “If you look at the participants list on the bottom, it’s actually quite extensive,” McHugh said of the report. “If you get that many people all together to talk about these types of issues, it’s quite important. And I think this is a fairly good summary of what’s happening in Canada.” McHugh suggested that the Canadian public is “fairly unaware” of the activity that already occurs in Canada, even in ports such as Vancouver – where Kinder Morgan is hoping to increase marine oil transport to foreign markets by twinning their Trans Mountain pipeline – and Kitimat. “Really, what a lot of the public sees is the newspaper articles,” he added, continued pg 27

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Pipeline companies to keep $1 billion available for emergencies Daily Oil Bulletin Major crude oil pipelines are expected to have at least $1 billion on hand to respond to any incident and remedy damage, according to new federal government rules announced on June 26. Joe Oliver, the federal minister of natural resources, called it the latest step in government’s plan to further enhance Canada’s pipeline system and to support jobs. Oliver also announced new, modern safety rules for pipelines and new financial penalties that will soon come into force for individuals and companies that violate environmental laws. Some of these additional measures include new fines designed to address contraventions quickly so that larger issues do not arise in the future. The penalties to companies and individuals for a variety of infractions can range from $25,000 to a maximum of $100,000. In addition, the government will require companies to appoint a senior officer whose duty is to ensure their management systems and programs are in compliance. The requirements will apply to all major pipelines, whether they are existing or proposed. Companies’ emergency and environmental plans will have to be transparent and easily available to the public, and the “polluter pays” principle will be explicitly enshrined in law whereas currently it is only implicit, says a government press release. Asked why the government considers the current insurance for pipelines to be insufficient, a Natural Resources spokesperson said pipeline operators

are subject to unlimited liability when they are at fault or negligent. The minimum financial capacity requirement for all major crude oil pipelines of $1 billion will help ensure that pipeline operators have the resources necessary to respond to incidents, wrote spokesman Paul Duchesne. He was also asked how these changes will result in job creation. “New pipelines will create jobs by allowing for improved market access for Canadian oil and gas,” Duchesne wrote in response. “Canadian oil and natural gas production is expected to grow, and this additional production will require access to new markets, particularly as our main market, the United States, sees increases in its own oil and natural gas production. We have stated that we will not allow new pipelines to proceed unless public health, safety, and the environment are protected. These changes will make pipelines safer, and so will help to support new pipeline infrastructure.” Enbridge is reviewing the announced measures, and said it is fully aligned with the overall objective of strengthening pipeline safety. “We agree that the public must have confidence that companies have the capability to fully respond to a pipeline spill. There is no financial limit on that responsibility. Northern Gateway and Enbridge will take full financial responsibility in the event of a spill,” said Todd Nogier, spokesperson. “We look forward to getting a better understanding of what the federal government has announced on this one measure.” The company already subscribes to some of the new measures, said Nogier.

For example, Enbridge announced earlier this year a vice-president position dedicated strictly to ensuring that safety and integrity operations permeate through the organization, he told the Daily Oil Bulletin. Nogier said every pipeline company carries insurance to cover damages but this announcement appears to go beyond that. TransCanada said it is required by law to pay the costs of a spill and “keep landowners whole. If there are legislative or regulatory changes that the Government of Canada is considering putting in place to provide additional protection for Canadians, we will wait to see what those proposals are and how they can be achieved.” The company supports in principle having strong, robust pipeline safety regulations in place to help improve public confidence and measures that demonstrate its ability to operate its energy infrastructure networks safely and reliably, spokesperson Shawn Howard wrote in an email. Charlie Fischer, former president and chief executive officer of Nexen, recently suggested that the creation of an insurance “superfund” would indemnify all Canadian pipelines that provide access to world markets. Pipeline companies, producers and governments would benefit if the fund helped to ease citizen concerns about pipelines’ safety, said Fischer. Oliver said the measures announced yesterday strengthen Canada’s already strong pipeline system even further. “Through our government’s plan for Responsible Resource Development, we are undertaking aggressive measures to increase oil and gas pipeline

inspections, double comprehensive audits of pipelines, implement new safety measures for oil tankers to ensure the safe and reliable transport of energy resources through our waterways,” wrote Oliver in a press release. British Columbia’s government is conducting its own review of pipeline safety, with help from the federal government. The National Energy Board (NEB) has the authority to prosecute for certain violations of the National Energy Board Act, with fines ranging from $100,000 to $1 million and imprisonment from one to five years. The federal government has provided $13.5 million over two years to the NEB to increase the number of oil and gas pipeline inspections by 50 per cent annually. It also doubles, to six from three, the number of annual comprehensive audits to identify potential issues and prevent incidents from occurring. The NEB has the authority to impose administrative monetary penalties that can be cumulative should infractions not be addressed. In the event of a pipeline rupture or spill, the company is liable for all cleanup and remediation costs. Companies can also be prosecuted and, if found guilty, fined. Violators may also be subject to prosecution and fines under other federal and provincial legislation should the environment, species and wildlife, or waterways be affected. There are an estimated 825,000 kilometres of transmission, gathering, and distribution lines in Canada. Approximately 73,000 kilometres of pipelines are federally regulated and transport over $100 billion of oil, gas, and petroleum products each year.

Infrastructure opportunites have never been better: TransCanada Daily Oil Bulletin Incidents such as the recent train derailment in Lac-Megantic, Quebec, shake public confidence and colour politicians’ and regulators’ views of the energy industry, but the fact remains: oil is needed, so stricter regulations and better company performance are required, an energy conference heard Tuesday, July 9. “Make no mistake, the world needs this stuff. North America needs this stuff to cook their food, to start their vehicles every day, and most people understand that,” said Russ Girling, president and chief executive officer of TransCanada. “We’ll eventually get through this; we’ll see greater emphasis on pipeline safety, greater emphasis on worker safety, greater emphasis on stakeholder relations, community development, environmental sensitivities, and that’s a good thing but we do need the infrastructure. “I think everybody knows that and eventually these [approvals] will get made and I think that’s true not just for the Keystone pipeline but [for] projects

like Gateway and other major construction projects that the marketplace needs. We just have to do them safely and regain public confidence,” he said in the keynote speech to the TD Securities Calgary Energy Conference. The opportunities for building infrastructure right now -- the quality and volume of the projects -- are unprecedented thanks to a changing energy landscape, but getting the facilities built has never been more challenging, said Girling. TransCanada has invested about $38 billion into its core businesses over the past 10 years and it expects to invest even more than that over the next decade. “Today the world is in need of substantial new energy infrastructure development and I think it may come as somewhat of a surprise to most of you that the region of the world that needs that infrastructure the most is North America,” he said. Changing North America’s energy situation and driving the need for new infrastructure are new technologies such as horizontal drilling and multistage fracturing, oil sands production

growth and increased tight oil supplies, and the trend toward a less-carbon intensive future, he said. Girling pointed to the International Energy Agency’s 2012 forecast that $8 trillion in energy infrastructure is needed for North America. “It’s in oil, it’s in gas and it’s in power; it’s replacing the aging infrastructure that exists today and to connect new supply to the market,” said Girling. TransCanada has about $26 billion worth of commercially secured projects underway, the conference heard. It has more than $12.8 billion slated to be in service by the end of 2015and another $13.2 billion in secured projects to be in service post-2015. That figure does not include the proposed Energy East conversion project or a few other projects on its slate, he noted. For its part, Enbridge Inc. has $28 billion in commercially secured projects between 2012 and 2016, Richard Bird, the company’s executive vice-president and chief financial officer, said in another session. The figure includes $17 bil-

lion in pipelines on the Mainline system and market access extensions/expansions that will open up new continental markets for 1.7 million bbls per day. Pointing to the Canadian Association of Petroleum Producers’ prediction of an increase of two million bbls per day of oil production from the Western Canadian Sedimentary Basin by the end of this decade, Girling said the equivalent of four original Keystone pipelines will need to be built. Another 500,000 bbls of oil per day from the Bakken requires transportation to markets, he added. The growing oil supply has allowed TransCanada to capture about $3.5 billion in expansion opportunities in Alberta, most of which is currently under development, said Girling. He told the conference there are three themes to North America’s changing energy landscape: abundant natural gas supply, a growing oil supply and a shift away from coal-fired power generation. TransCanada is well positioned to take advantage of all three.

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environment

THE ELECTRIC CHAIR Amit Kumar takes charge of new energy and environment research program

University of Alberta mechanical engineering professor Amit Kumar was named the head of a research program looking at energy and the environment on June 17.

UNIVERSITY OF ALBERTa PHOTO

james waterman Pipeline News North One day a modest University of Alberta mechanical engineering professor conducting important research into the use of biomass as an energy source; next day the chair of a $4.4 million research program focusing on energy and the environment. That is the story of Amit Kumar. After a June 17 announcement that the Natural Sciences and Engineering Research Council of Canada (NSERC), Cenovus Energy, Alberta Innovates Bio Solutions and Alberta Innovates

Energy and Environment Solutions would be collectively contributing that $4.4 million in funding to support work that could lead to important decisions around energy production, water conservation and greenhouse gas (GHG) emissions reductions, Kumar found himself the new NSERC/Cenovus/Alberta Innovates Associate Industrial Research Chair in Energy and Environmental Systems Engineering and the first ever Cenovus Energy Endowed Chair in Environmental Engineering. “This is quite a big honour for me,” said Kumar. Kumar’s relationship with Alberta Innovates – which is contributing $500,000 of the $4.4 million in funding,

split evenly between the Bio Solutions and Energy and Environment Solutions groups – began about seven years ago, shortly after Kumar joined the University of Alberta engineering faculty in 2005. “Our core business is to position Alberta to achieve superior environmental performance,” said Eddy Isaacs, chief executive officer of Alberta Innovates Energy and Environment Solutions. “We helped Dr. Kumar launch his research on energy and environmental systems modeling several years ago because we recognized the need for an Albertaspecific model and the need for building the innovation capacity in this area. Dr. Kumar’s work has helped inform the Government of Alberta strategy on energy efficiency and our strategy and focus on innovation to support the Government of Alberta’s climate change plan.” “At that time, one of the projects was to study the energy flow diagram for Alberta,” Kumar said of the early days of that partnership, adding that questions of interest included what the various energy sources might be and what sources of energy are used by what energy consumers. That was just the beginning for projects in that general topic area, a list that would eventually feature a project with Cenovus looking at the cost of converting biomass into charcoal. “Over the last two years,” said Kumar, “we have been discussing [starting a] research program that looks at all the energy systems in a holistic way and trying to assess them in terms of their environmental footprint and cost.” That is how the partners involved in this research program were brought together. “The overall mandate is to basically assess the different types of energy systems,” said Kumar. The program includes research in three key areas, the first of which is long-term energy and environmental modeling. “Basically, we develop computer models which have detailed data on the energy demand sector, energy supply sector and the energy resource sector,” said Kumar. The energy demand sector is essentially all ener-

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gy consumers from residential and commercial buildings to transportation and industry. The models for that sector not only look at energy requirements for items such as lighting, cooking and space heating, but also look at the types of technologies used for all of those purposes. “This model has details on how [many units] of energy are actually used per household per year,” said Kumar. “What it helps us in assessing is, if there is any improvement in, say, efficiency of these furnaces, than what is the impact in terms of GHG,” he added. That work can be useful to scientists and engineers who develop the technologies as well as those in government who set policies. “Dr. Kumar’s new industrial research program will help private sector industries, investors and government policy-makers make informed decisions about long-term energy planning in Alberta’s agriculture and forest sectors,” said Stan Blade, chief executive officer of Alberta Innovates Bio Solutions. “The program’s modeling tools can assess all stages of the supply and demand chain and provide solid information for Alberta’s bio-industries to become more competitive and environmentally sustainable.” “We have built in details of each and every power plant that we have in Alberta,” Kumar continued, turning his attention to the energy supply sector. “You’re looking at the whole system of demand and supply in a holistic way.” Kumar and his team can look at differences in potential future GHG emissions depending on the percentage of power generated by methods such as wind, high efficiency coal power plants and power plants making use of biomass energy. “We have other models that look at water footprints – how much water is required to produce a unit of energy using a certain pathway?” he added. “And we are also looking at land footprint – how many square kilometres would be required to produce

a unit of energy?” Another team studies the full lifecycle GHG emissions of a unit of energy from a specific source, as well as the energy return on investment. “How much energy you put into producing a unit of energy from a certain source,” said Kumar, adding that they look at both renewable and non-renewable energy resources. “You’re looking at conventional systems like coal, oil and gas, but you’re also looking at the renewable energy systems like wind, biomass, geothermal,” he continued. A third team looks at the cost of producing energy. “There are people who are working on a specific technology and a specific resource, but you will find very few people are working on the whole system, taking all the different types of energy ... in a comprehensive way, and looking at the options and assessing the different technologies,” said Kumar. “The impact of energy resource systems on our environment is of vital importance to Canada,” said Janet Walden, chief operating officer at NSERC, which is contributing $925,000 to the program. “[This] research will help governments and businesses better assess the costs and environmental impacts of various energy technologies, and ultimately help shape the future of energy production in Canada,” she continued. “We’re excited to be able to support Dr. Kumar’s valuable research into efficient energy systems,” added Brian Ferguson, president and chief executive officer of Cenovus, the biggest contributor to the program with their $3 million investment. “We expect the work this team is doing will lead to new tools that will help us do an even better job of unlocking the tremendous value of Alberta’s oil sands in a responsible and environmentally friendly way,” he said. “This will help us look at the whole spectrum of energy technologies for Canada and Alberta and

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beyond,” said Kumar. “We talk about [how] in Alberta we have this many megatonnes of GHG we have to mitigate,” he continued. “Now what are the options? You can mitigate it by [improving] the efficiency. You can mitigate it by going to renewable energy. ... Or you can also mitigate it through carbon sequestration.” The program will assess all these options in terms of GHG mitigation over the long-term. “And what gives you the best bang for the buck – dollar per tonne of CO2 mitigated,” said Kumar. The program isn’t only about shaping the future of energy production and consumption, but it is also about shaping the futures of graduate students who could be responsible for making the necessary technological changes in their careers. “The students will be trained in this area and will have a special skill set where they can look at these energy systems in a holistic way,” said Kumar. “If you look at a cross-section of my group, almost all of them are engineers,” he continued. “They have different backgrounds. They come from mechanical, chemical, agricultural. But these Chair programs will train the students in energy systems research where they would be able to look at these energy systems and assess these energy systems, which is kind of a critical area for a country like Canada where natural resources is such a big factor.” David Lynch, the University of Alberta’s dean of engineering, appears to share Kumar’s views. “Partnerships between the public and private sector have a real impact – by providing the basic research foundation, we can promote the development and upgrading of Alberta’s natural resources in an environmentally responsible manner,” said Lynch. ”At the same time,” he added, “we are giving our students a truly world class education. And they, in turn, will bring their knowledge and expertise to industry and government as engineering professionals to solve future challenges.”

Local industry reps unhappy with proposed water use bylaw in Dawson Creek WILLIAM STODALKA Pipeline News North

the facts.” “The industry’s being targeted because of the large volumes that they’re using for the new technology of fracking,” he said. “A lot of times industry gets targeted because a non-industry related person doesn’t get all the facts. ... You have to have a knowledgeable conversation about what industry is doing with water.” Jarvis said that industry is aware of how their water consumption impacts communities. He said that industry is re-using water from previous fracks more than in the past. “It’s not just the major users that need to conserve,” he said. “Everyone has to consider conservation of all resources.” Jarvis also said that people should not “let the hose run in the driveway.” A representative from Encana, Doug McIntyre, said in an email that “we can’t speculate at this point on how they could potentially impact our operations.”

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A new bylaw set to be debated by city council in Dawson Creek, British Columbia will hurt the natural gas industry, according to the provincial organization representing the oil and gas industry service sector. On Monday, June 15, council asked city staff to draft a policy that would prohibit oil and gas companies from using the city’s water at an earlier stage of water restrictions than was previously the case. The move came after a survey commissioned by the City showed that residents did not want industry to be able to wait until Stage 4 water restrictions to have their water cut off. Instead, if the new bylaw passes as it is now proposed, the industry would have to be cut off at Stage 2, when most residents would not be allowed to water their lawns or do other duties. “That will affect jobs, time schedules, and activity in the area,” said Art Jarvis, executive director of Energy Services BC (ESBC). “If they have to stop operations for a given period, that may halt several employees from going to work. “Clamping down will have an impact.” Jarvis also said that oil companies could be forced to Avis car and truck rental. go on longer trips for water, increasing traffic and Long and short term truck rentals available. stress on highway infrastructure if these new bylaws Fort St. John airport location 250 785-5515 go through. Grande Prairie airport location 780 539-4101 Jarvis said that part of this highlight on the water used ©2013 Aviscar Inc. All Rights Reserved. by oil companies was because people “did not have all ®Avis is a registered trademark licensed to Aviscar, Inc. for use in Canada.

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JULY 12, 2013

special feature ACCESSING INNOVATION Pipeline company digging for social license gold

Access Pipeline personnel are carefully studying every aspect of nine test cells the company has built on their land in northern Alberta. Access is conducting research to determine if they can use the low impact pipeline construction techniques developed at the Evergreen Centre for Resource Excellence and Innovation in Grande Prairie to build a 300-kilometre, 42-inch pipeline. The techniques have only been used to build small diameter pipelines to date.

ALBERTA ENVIRONMENT AND SUSTAINABLE RESOURCE DEVELOPMENT PHOTO

james waterman Pipeline News North IPS – Innovative Pipeline Strategies. It is a set of low impact pipeline construction techniques pioneered at the Evergreen Centre For Resource Excellence and Innovation in Grande Prairie, Alberta by the likes of Randy Galbreath of Stratus Pipelines, Marc LaBerge of Devon Canada and Doug Kulba of Alberta Environment and Sustainable Resource Development (ESRD). The focus of IPS so far has been pipeline ditch construction and soil management when building small diameter pipelines, but for the first time those methods are being put to the test with respect to building a much larger 42-inch pipeline in a research study being conducted by Access Pipeline this summer. “Our company’s owned 50 per cent by Devon Energy and 50 per cent by MEG Energy,” said Samin Aminzadah, an intern with Access who recently completed a graduate science degree in sustainable energy development. “They’re both around the Conklin area and our lines tie-in to their production facilities. And it’s about 300 kilometres from their facilities all the way to our terminal in the Fort Saskatchewan area.” Access is in the early stages of building a 42-inch

pipeline between Conklin and that terminal. “The [research] project came about from some commitments we made to two landowners,” he added. “These landowners,” said Aminzadah, “they had pipelines on their properties before.” A number of those pipelines belong to other companies, but the list also includes the Access mainline that was constructed in 2007. “They just wanted something different,” he continued. “They had seen some of the issues that some of the pipelines had on their properties – not all of them. And they had learned about [the] IPS process. So, they came to us and said, ‘Okay, look, we will sign off on this project if you guys can commit [to adopting] some of these IPS aspects.’ And we said, ‘Absolutely. However, the IPS process is based around small inch diameter pipeline. And big inch pipe is just a different beast altogether.’” For example, the narrow buckets used to reduce the amount of soil removed from the ditch when constructing small diameter pipelines – thereby reducing the risk of sunken pipeline ditches that can cause significant problems for farmers and their equipment – are narrower than the 42-inch pipe. “The biggest issue with a 42-inch is you’re going to need more of an area – work area – and the displacement factor,” said Aminzadah.

“You’re displacing much more soil,” he explained. “The volume of soil that you’re handling is much greater.” Rather than simply dismiss IPS as inapplicable to large diameter pipeline construction, Access opted to design a research project to test those techniques using a pair of quarter sections of land around their terminal. “We did most of our testing on one of the quarters,” said Aminzadah. “We laid out nine different plots. And we essentially tried nine different methods of soil management and compaction techniques.” Access didn’t want to test the methods on an existing pipe or during construction of a real pipeline project because of the risk of damaging infrastructure that the company would want to be useful and relatively problem-free for decades. “We have a prime contractor,” said Aminzadah, beginning to discuss those concerns. “And that prime contractor is responsible for the site and they’re responsible for the pipe. So, if we go and say, ‘Hey, look, you need to do this,’ and we hadn’t told them prior to, and they go and they damage the pipe, well, they’re on the hook for that.” Another issue is the risk of damaging the pipe when trying new soil compaction techniques, particularly when that damage may not be apparent until it springs a leak years down the road. “Safety is paramount for all pipeline companies,” said Aminzadah. “For us, it made a lot of sense to test out some of these techniques on our land that we own around our terminal.” One soil compaction technique tested at the site is brand new. It is a dual wheel system that actually straddles the pipe to improve compaction around the pipe. “The idea of that tool was to compact the haunches, get more of the material underneath the haunches alongside the pipe, which is something that we normally don’t get an opportunity to do,” explained Kulba, who has been involved with the project, as well as the demonstration of the methods being studied at the Access site that took place in late June. “And what that does,” he continued, “is it provides structural support for the pipe with that soil. So, when you put a vertical load overtop of the pipe [there is] no damage or ovalling [of the pipe].” “One of the issues that we have right now is, in certain soil types, it’s difficult to get all the material back into the trench, not only because of the displacement of the pipe, but also because the soil bulks when you move it,” added Aminzadah. “What happens is you have excess of soil leftover.” The amount of bulking depends on the soil, but Aminzadah said that it can range from zero per cent to as much as 40 per cent. “When you put everything back,” he continued, “not only are you dealing with the displacement factor, which, for our pipe, is about 27 per cent, but also with the bulking as well. So, now you have quite a bit of soil leftover. And, traditionally, what happens is you sort of just spread it around your right-of-way. And we thought that, maybe, at the very least, we could minimize the bulking and get the soil back into its in situ density.” Access is also experimenting with different types of pipeline ditches, including the typically straight wall and flat bottom ditches, as well as v-shaped ditches. IPS pioneer Galbreath has been offering his experience and expertise from day one. “Access came up with the idea,” said Galbreath. “I basically took care of the men and the equipment, and added whatever knowledge I had from the previ-

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ous stuff that I had done as far as the low impact stuff.” It has been a learning experience for Galbreath as well, since he and his company only deal with small diameter pipe, not the sort of large 42-inch pipe being built by Access. “It’s a different world than my small diameter world,” he said. However, the individuals involved all agree that the value of the demonstration aspect of the project goes well beyond the lessons learned by the likes of Aminzadah and Galbreath. “I think it’s something that the oil patch needs to do a lot of,” said Galbreath. “We need to start showing the people that we actually are interested in trying some new things. And if we have been doing some things in the past that can be upgraded, we’re prepared to do that. “Publicity-wise – could be worth a great deal.” Aminzadah also suggested that the physical demonstration of such techniques is necessary for proving the possibilities and the benefits to people in the industry. “If you tell a pipeliner who has been doing this for 30 years, he just won’t buy it. They need to see that,” said Aminzadah. “We had a lot of government folks that came out,” he continued. “And I think it’s very important for them to see, not only the partnership between industry and government, and the fruitfulness of that, but also for them to learn and make policies accordingly. “Obviously, industry has to take a lead, but ... government also has to play a vital role. The policy makers really need to understand what the issues are and what industry thinks are some of the solutions.” “It demonstrates to the global community that the oil and gas industry is doing things in a different way,” Kulba said of the Access project and demonstration. “It’s an acknowledgement that we don’t have all the answers, but we’re working together. And I think one of the biggest things is that it’s industry, government and community coming together with ideas. “What was interesting out there [was] when people actually saw what we were doing, they all had some input. They started to get ideas. So, it inspires innovation and creativity. “It challenges our thinking about how we do things.” Galbreath said there was a great deal of skepticism among the participants at first, but that was quickly replaced by enthusiasm for the project – and excitement about the possibilities. “That’s the thing that always kind of amazes me,” he said. “They’ll kick and scream before they have to do it, then once they’re doing it, they all have new ideas.” Enbridge spokesperson Ivan Geisbrecht said that the company representative who attended the demonstration appreciated the invitation. “We are grateful for these opportunities,” he added, “as they allow us to learn about new techniques and

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how they might be able to assist in our planning and because of the accuracy of the grain count and the engineering efforts.” GPS units.” Richard Dixon, the executive director of the Centre for It is an example of how low impact pipeline conApplied Business Research in Energy and the struction can help pipeline companies save money that Environment (CABREE), part of the Alberta School of could be spent dealing with conflicts with landowners. Business at the University of Alberta, was interested in the “You’re mitigating future costs,” said Dixon. project and demonstration in terms of the sort of applied “Pipelines put in the ground, they’re there for 40 business research that is at the heart of CABREE. years. They want to get it right.” “We’re looking at a variety of applicable technoloGalbreath would be pleased to see this study prove gies and [asking], from an applied the cost benefits of IPS. business point of view, ‘Does this “The perception that we’ve had “‘It’s nice to see make sense? And we’ll look at the all along the patch is that it’s a economics of it. We’ll look at the huge extra cost,” he said. “And a company that’s social license of it,” said Dixon. that’s not something that anybody “It was not a scientific study,” he prepared to look at. So, what grabbing the bull by was continued. “It’s a proof of concept I’m hoping is they’re going to realstudy. So, saying, ‘Here’s the ize that ... it may not be that huge the horns.” basic concept. Let’s run some varextra cost that they thought.” ious examples.’ I was glad to see Galbreath appreciates the opporit happening.” tunity to take part in this research. – Randy Galbreath, Dixon noted that CABREE is “It’s been a very good opportunity Stratus Pipelines hoping for the creation of a ... to show some things that I’ve Canadian Pipeline Institute. learned in a small diameter world “Right now, everything in energy and see if we can apply it in a big pipelines in Canada is focused on the engineering- diameter world,” he said. “And it’s nice to see that there’s a mechanical side,” he explained. “And the applied busi- company out there that’s grabbing the bull by the horns.” ness side has not been used as much. The kinds of Galbreath had similarly kind words for Kulba. tools that we could bring to bear – strategic scenarios, “He’s always very enthusiastic about these things,” financial analysis, economic analysis.” he said. The idea is that a Canadian Pipeline Institute would “I think it’s going to really elevate the Centre,” he encourage and support applied business research that continued. “Because we had some visitors here ... would help pipeline proponents answer the sort of social from other large transmission companies and they license questions that have been plaguing TransCanada can’t believe that they weren’t involved in this proand Enbridge as they struggle to build their Keystone XL gram. And they want to get involved in projects and Northern Gateway projects, respectively. down the road. So, I think it could be very good for “From a business perspective, it would change the the Centre.” strategies that they do to look at these problems in a Kulba hopes that the Centre will grow, too. very different light,” said Dixon. “The whole idea behind the Evergreen Centre is to Dixon also noted that the Access project specifically have satellite extensions to the Centre,” he said. could be especially important in terms of developing “[When people] see the government is actually in and perfecting low impact pipeline construction tech- this mode of innovation, and working with groups niques on agricultural land. and industry, I think it encourages others to do the “When you run a combine, you can now measure same,” he continued. “It comes down to leadership. the amount of grain that’s coming into the hopper with Really, it’s paving the way for the leadership that’s very, very precise measurements, coupled with GPS,” required in making change and doing these things in he explained. a different way.” “Now, farmers will know exactly what their yield is Access still has work to do to be certain how to proover any particular part of their field.” ceed with their pipeline and the IPS techniques. Consequently, farmers will know if there are prob“We’re going to do a data analysis and make some lems with the quantity and quality of their crops over recommendations internally for our company,” said pipeline right-of-ways that pass through their fields. Aminzadah. “And also release every piece of informa“They can go back to the oil companies and say, tion that we have to the public. The public and other ‘Here’s what your pipeline has done to my land. And organizations can do what they see fit with the info. here’s what it’s done to my crops. And I’ve got the “We’re also going back and ... monitor the site for stats to prove it.’ And those are going to be irrefutable,” about three years. said Dixon. “We have to look at the data afterwards and see “Companies are going to have a hard time with that how this pans out.”

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industry news New study examines net GHG impacts of storing CO2 through EOR Daily Oil Bulletin

If the use of carbon dioxide in enhanced oil recovery (EOR) could help get carbon capture and storage (CCS) projects “off the ground,” the impact in the development of such projects would be major, says the Integrated CO2 Network director of strategy and policy. “By being able to use the CO2 for something to actually get some revenue stream in, it has a tremendous benefit in actually trying to kick-start and get the industry moving,” ICO2N’s Eric Beynon told the Daily Oil Bulletin. However, he noted, there is a public debate as to whether CO2 should be used for the production of more hydrocarbons, or whether it is best simply to capture and store it. For this reason, his organization commissioned the Pembina Institute to prepare Net Greenhouse Gas Impact of Storing CO2 through Enhanced Oil Recovery (EOR). “There has been a big discussion around what is the net impact of using CO2 for enhanced oil recovery,

because you are producing more oil,” Beynon said, adding that many object to CO2 for EOR because they see it as merely resulting in more oil produced and thus adding to global carbon emissions, and therefore pure CCS is their preference. Meanwhile, “others say that oil will be produced anyway, so you’re still getting the net benefit of all the storage.” With its recently-published report, Beynon said the network aims to provide “solid numbers” to that ongoing discussion of EOR versus pure CCS. Analyzing on-site and downstream EOR-caused greenhouse gas (GHG) emissions in Western Canada, the report considered five different scenarios representing differing viewpoints and attempts to quantify these various perspectives with the scenarios presented such that they build upon each other. Beynon said: “I think those scenarios really fall into three buckets. There’s the one that just looks at the CO2 that’s stored. There’s the second one that looks at taking the CO2 content of the oil that’s produced and the CO2 that would be emitted from the consump-

Oil extraction isn’t always this easy. Occassionally, it requires a process of injecting carbon dioxide into the reservoir known as enhaned oil recovery. A new study commissioned by the Integrated CO2 Network examines the impact EOR could have on greenhouse gas emissions as the oil patch moves toward a future of carbon capture and storage.

JAMES WATERMAN PHOTO

tion of that oil. And then the third one, well, if you’re producing that oil in EOR you’re going to be displacing some other oil in the world, and therefore you can reduce that other oil.” The main conclusion of the analysis is that the impact of storing CO2 through EOR varies greatly depending on a particular perspective. In the first scenario, a tonne of CO2 arrives on-site and goes into straight geological storage. In the second scenario there is an analysis of on-site emissions of an EOR site. The report finds straight geologic storage of CO2 has more significant GHG benefits than using CO2 for EOR operations, given the energy required to produce crude oil from the EOR reservoir. As a third scenario, the full lifetime emissions for EOR is taken into account, including downstream emissions associated with oil produced through EOR. Scenarios four and five assume oil produced through EOR displaces other oil in the marketplace, done for both a bbl of oilsands crude and the average bbl in North American. In this step the study accounts for the full lifetime emissions of EOR plus the GHG savings of displacing oil in the marketplace. When assuming full displacement of competing sources of crude oil, the report finds EOR has a GHG benefit at 1.175 tonnes of CO2 equivalent (tco2e) reduced for an oilsands bbl and 0.834 tco2e for an average bbl. However, the report indicates the market’s dynamic nature makes it difficult to determine when one source displaces another. The report also finds the ratio of CO2 injected to bbls of oil produced has a large impact on overall GHG benefits from EOR with CO2 injection, as an increase in EOR production translates to less intensive per-bbl on-site energy requirements. Further, the report finds oil produced from EOR falls in between comparative crudes on a GHG comparative basis. According to Beynon, the study did not account for upstream emissions associated with producing and capturing the initial CO2 for these scenarios, because there is already a lot of research available into that topic and it is also very difficult to pinpoint all the CO2 sources. “You’ve got a whole array of different plants from which carbon capture could be put on, and on top of that you’ve got a whole array of different capture technologies, each with unique characteristics that create an individual picture of that merging of capture technology and capture facility.” According to Beynon, advancing CCS is “a tough nut to crack,” but Canada is certainly pursuing it “way more than its weight globally.” “Our hope is really this [study] can help provide some data to further inform the dialogue in this area.” The Integrated CO2 Network is a group of Canadian companies representing multiple industries, including coal and the oilsands, all of which have a strong interest in and a commitment to develop carbon capture and storage. Beynon said the audience for this study would largely be policymakers, the environmental community, business community, and others concerned with matters of carbon policy and global warming. “[The study] is more technical, so it is definitely for the people who are looking for a more technical analysis. When people are looking at CCS and assessing its role in society and the potential it has in helping reduce emissions, I think it is important to have information that leads into all that.”

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JULY 12, 2013

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Rate of marine oil spills has been declining cont’d from pg 20 noting that those articles tend to present a strong bias either for or against projects such as Northern Gateway. “This is more focused and ... balanced,” he said. Forrest said one of the biggest questions from the workshop concerned financial compensation if a marine oil spill should occur. “It’s higher than most other nations,” she said. “And if you look at the countries that are part of that international group that subscribe to the same compensation regime as Canada, they’ve never had a spill that has gone over that $1.3 billion in terms of its cost. “That excludes the United States, because the United States isn’t party to that.” The question is if that dollar figure is sufficient. “Probably not, if it was a very big spill,” said Forrest. “But if you look at history, that has been enough to cover all the spills [in all the] countries that signed up to the international regime.” Interestingly, Enbridge is planning their spill response for a “credible worst case discharge event.” The largest incident they are preparing for would include the volumes held by two very large crude carriers (VLCCs), which would likely only occur if there was a collision between those two vessels. “That’s different than saying we’ll meet the standards that are existing in Canada.” Opponents of projects along the lines of Northern Gateway suggest that a big part of the problem with a

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spill of diluted bitumen (dilbit) from the Alberta oil sands is that it would behave differently in a marine environment than other crude oils. It is thought that the diluents present in that mix could evaporate. The result would be that oil that is suddenly denser than the surrounding ocean water would sink, significantly reducing the chances of recovering the oil and potentially causing long-term harm to that ocean environment. It is an area of active research. A study performed by SL Ross as part of the Northern Gateway review process demonstrated that a bitumen blend from Alberta known as Cold Lake Blend – which is a dilbit – did increase in density over a twelve day period. Although it was denser than freshwater after that time, it was still less dense than ocean water, and so likely wouldn’t sink prior to recovery efforts. When bitumen blends spilled into the Kalamazoo River from an Enbridge pipeline in 2010, the oil did sink in that freshwater environment. However, the IHS CERA report also indicated that the rate of oil spills has been decreasing as practices and technologies improve. “The practices have changed a lot,” said Forrest, noting the decline in oil spills over the past two decades since the Exxon Valdez incident. “That’s really a reflection of all those changes in both operating practices and technology. They didn’t have satellite tracking systems back then.” she continued.

“People probably just don’t think about it. Think about what your life was like in 1989 and how you communicated and what technology you used. And the shipping industry has evolved just like every other aspect of our lives.” “They have done a pretty good job at categorizing what has changed since the Exxon Valdez spill,” said McHugh. “What Northern Gateway is committed to is above what’s in place in Canada, already getting pretty close to world class [in terms of] tanker inspection [and] tanker safety issues.” Northern Gateway is expected to bring an average of 71 condensate tankers and 149 oil tankers into Kitimat every year, which amounts to about 220 additional vessels. “It’s an increase, but, historically, there has been a lot of traffic to Kitimat as well,” said McHugh. “It actually kind of brings it back into line with what historically used to call at Kitimat. But there are obviously other project proposals as well.” An interesting aspect of that situation is how Kitimat and the rest of the B.C. coast might cope with an increase in oil tanker traffic along with the new traffic that could come with the liquefied natural gas (LNG ) export business. “One of the recent announcements is the government is planning to designate Kitimat a public port,” said McHugh. “And what that enables them to do is put in place measures to look at traffic control in the region in general. And put in place procedures around the port as well. That is being thought about. “They’re planning for that.”

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JULY 12, 2013

industry news B.C. government expecting higher natural gas royalties than original forecast

Premier Christy Clark learns the ins and outs of Spectra Energy’s new natural gas processing plant near Dawson Creek last summer. When her government tabled their budget in late June, they indicated that revenues from natural gas royalties would be higher over the coming fiscal year that predicted prior to the May election.

JAMES WATERMAN PHOTO

Daily Oil Bulletin The B.C. Liberal government, which was re-elected in May, tabled a revised provincial budget on Thursday, June 27, where it forecast higher natural gas royalties for 2013/2014 than what was predicted in the original February pre-election budget. The government’s original budget had estimated natural gas royalties of $282 million for 2013/2014, but yesterday that was raised to $397 million, which is also higher than the $169 million collected in fiscal 2012/2013 that ended on March 31, 2013. B.C. is now forecasting higher average prices and production for the fiscal year. The government now expects plant inlet prices for 2013/2014 to average C$2.25 per gigajoule on 39.1 billion cubic metres (about 1.38 tcf), up from February’s prediction of $1.85 on production of 38.7 billion cubic metres (about 1.37 tcf). Price estimates for the following two fiscal years are $2.51 and $2.89, respectively (originally forecast at $2.25 and 2.65 in

the February budget). A one per cent change in natural gas volumes means a $3 million impact on gas royalties. A 50-cent shift in natural gas prices equals a $117 million to $125 million impact. Sensitivities can vary significantly, especially at lower prices, the government warned. Natural gas royalty rates are based on a sliding scale linked to natural gas prices and are particularly sensitive to price changes within the $1.30 and $3 per gigajoule range. With the recent recovery in natural gas prices, the average gross royalty rate in 2013/2014 has increased 3.4 percentage points, resulting in an increase in natural gas royalty revenue. The forecast also includes the impact of measures introduced in the February 2013 budget, namely the introduction of a three per cent minimum royalty for all natural gas wells that qualify for the deep well royalty credit program and the termination of the summer drilling credit program. The government said it continues to provide royalty programs and

credits that foster industry investment in exploration and development. Meanwhile, petroleum royalties for 2013/2014 are forecast at $93 million, then $96 million and $92 million the following two fiscal years. The province reported a $1.15 billion deficit for 2012/2013 (it had projected a deficit of $1.23 billion in February). For 2013/2014, B.C. now expects a surplus of $153 million, lower than the originallybudgeted $197 million. Following an estimated increase of 1.8 per cent in 2012, the Ministry of Finance forecasts that B.C.’s economy will grow by 1.4 per cent in 2013, 2.2 per cent in 2014 and 2.5 per cent per year in the medium-term. The ministry’s outlook for B.C.’s real GDP growth is 0.2 percentage points lower in 2013 and 0.3 percentage points lower in 2014 than the outlook provided by the Economic Forecast Council. Carbon tax rates will not be increased, the government said. They will be maintained at $30 per tonne of CO2 equivalent. The carbon tax base

will not be expanded or broadened to include industrial process or other noncombustion emissions. While the carbon tax at current rates does not appear to have a significant impact on B.C.’s overall economic performance, a number of sectors have expressed concerns about the impact of the carbon tax on their competitiveness, budget documents noted. Increasing the carbon tax rates or expanding the base to include industrial process emissions would increase costs for B.C. businesses and increase competitiveness concerns, the government stated. “Climate change is a global issue and addressing it requires co-ordinated international action. Maintaining the current rates and base will help to ensure B.C. is not diverging in a substantial way from policies in competing jurisdictions,” the province stated. “When other jurisdictions, especially those within North America, introduce similar carbon taxes or carbon pricing, government may again review and consider changes to the carbon tax.”

JULY 12, 2013

careers

PIPELINE NEWS NORTH •

RESIDENCE TIME Temporary solution becoming permanent fix for Alberta

The list doesn’t include rig technicians or rig technician supervisors as those jobs fall under the rules of the Compulsory and Optional Trades Category. Workers applying through that program must have credentials along the lines of an Alberta Q u a l i f i c a t i o n C e r t i f i c a t e , R e c o g n i z e d Tr a d e Certificate or International Red Seal. The occupation itself is also a consideration. “It’s based on our short term employment forecast, which uses information about how many workers are there already, what is demand expected to be, what is supply expected to be, do we see a shortage coming,” Schroeder said of that list of eligible occupations in the Alberta Work Experience Category. The government is offering webinars to help those individuals who might qualify for permanent resident status navigate the application process. “You need your work permit, your certification paperwork, confirmation that you’ve been working in Alberta for a specific length of time,” said Schroeder. “And it will be two or three years depending on which job you have on that long list. Confirmation of your language ability, because that’s part of the federal requirements.” Schroeder suggested the changes could benefit employers as well. “Most employers would tell you that it’s expensive and time consuming to recruit somebody from overseas. And if you send them back, you have to start again with a new person and train them all over again,” she explained. “The nature of a temporary foreign worker program is that it’s for temporary work,” she continued. “The challenge is that we’ve had temporary foreign workers filling permanent jobs and they were needed for much longer than their original two-year permit.” Thomas Lukaszuk, who serves Albertans as both deputy premier and minister of enterprise and advanced education, announced in June that temporary foreign workers with sufficient work experience in certain professions can now apply to become permanent residents in Alberta .

aLBERTA GOVERNMENT PHOTO

james waterman Pipeline News North Aspiring Canadians and the oil and gas industry that has given them temporary jobs in the Alberta oil patch both had good reason to rejoice this June. The reason was a provincial government announcement that changes to the Alberta Immigrant Nominee Program (AINP) would allow qualified temporary foreign workers in certain professions to apply for permanent resident status independently, not just through their employers, which had been the case previously. “We have many skilled foreign workers already working here and contributing to our communities and our province,” said Thomas Lukaszuk, deputy premier and minister of enterprise and advanced education. “The Alberta Work Experience Category will have a positive effect on the lives of those workers, who will now be able to stay permanently,” he added. However, applications for permanent residence through the Alberta Work Experience Category are only being accepted until Nov. 28, 2013. “We have a number of occupations where the unemployment rate is consistently low,” said enterprise and advanced education spokesperson Janice Schroeder, explaining the change in regulations. “We have a number of programs in place to train Albertans for careers to help underrepresented groups get into the workforce in any different number of

ways,” she continued. “And, of course, to recruit workers from overseas and other provinces. But even if we do all those things, we’re still looking at facing significant shortages. And this is one of a number of steps to help us ensure that we have the people in place for the work that needs to be done.” The unemployment rate in Alberta has been below five per cent over the past year, while the provincial government is predicting a shortfall of 114,000 workers by 2014. Many of the high demand occupations listed in the Alberta Work Experience Category are important to the oil and gas industry, including geologists and geophysicists. R001551335

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careers Arne Nielsen set a great expample for the oil patch of the future to follow Daily Oil Bulletin A funeral service was held in Calgary on July 6 for one of the giants of the oilpatch in Western Canada and a role model for generations of geologists. Arne Nielsen, the geologist credited with leading the team that discovered the Pembina oilfield and the first Canadian president of Mobil Oil Canada, died July 2 in Calgary, five days short of his 88th birthday. Born on a farm near Standard, Alberta, of Danish settlers, Nielsen received bachelor and master’s degrees in geology from the University of Alberta after serving overseas in the Canadian Army. Upon graduation in 1950, he joined United Statesbased Socony-Vacuum Exploration – later Mobil Oil Canada – and over the next nine years worked his way up to chief geologist, where his teams were also credited with discoveries offshore the East Coast of Canada and in the Gulf of Mexico. Nielsen’s discovery of the Pembina field was a “geological tour de force,” Gordon Williams, a retired geology professor at the University of Alberta, said

in an interview. “He recognized the potential in the Cardium when most people didn’t.” In his 2012 book, We Gambled Everything, Nielsen wrote about how as district geologist for SoconyVacuum in the Edmonton field office, he had set out to explore the 100,000 acres of “rank wildcat acreage” in the Drayton Valley-Violet Grove area on which his company had farmed in. Following the Leduc discovery in 1949, companies were all looking for Devonian limestone reefs. Nielsen, though, through his study of well logs believed that the Cardium was a major sandstone body in the Western Canadian Sedimentary Basin – and when he saw the Cardium horizon in the logs he realized that he had found good conditions for a huge regional stratigraphic oil and gas trap. The discovery well at 4-16-48-8W5 near Violet Grove was drilled in 1953 and because of the tight formation tested at only 132 barrels per day of 37 degree API oil. Returning to Canada in 1966 as vice-president of R001424276

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exploration for Mobil Oil Canada, Nielsen became the company’s first Canadian president a year later. He also served as president and chief executive officer of Canadian Superior Oil from 1977 to1986 before returning to Mobil Oil Canada as chairman and chief executive officer in 1986 after it acquired Canadian Superior. Nielsen also served as chief executive officer of Poco Petroleums and Shiningbank Energy Trust, and was a director for various organizations including Toronto-Dominion Bank, Aetna Insurance, Vaalco, Rockwell International Canada, Phillips Cable and many small oil and gas corporations. He was chairman of the Canadian Petroleum Association on two occasions, including leading the industry response to the federal Liberal government’s National Energy Program. Nielsen was recognized during his long career with numerous lifetime memberships, admission into the Canadian Petroleum Hall of Fame in 1998, and an honorary doctorate from the University of Alberta.

JULY 12, 2013

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