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Northern British Columbia and Alberta's Oil and Gas Industry Vol. 2 Issue 10 • dist: 18,000 SEPTEMBER/October • 2012

h t r No

• Free

in this issue:

• DAWSON CREEK ENERGY CONFERENCE • FORT NELSON ENERGY EXPO • WASTE WATER NOT WASTED - DAWSON CREEK RECLAIMED WATER PROJECT • CANUCK WISDOM - TREVOR LINDEN TALKS LEADERSHIP 32530

SHELL CANADA KIDS HELP OUT UNITED AWAY AT FORT ST. JOHN FIRE TRUCK PULL - JAMES WATERMAN PHOTO


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• PIPELINE NEWS NORTH

SEPTEMBER 2012

The Fort St. John Petroleum Association is continuing to support the community by sponsoring sports teams and offering scholarships for postsecondary education. A fairly new initiative for the club is its sponsorship of Fort St. John Minor Lacrosse. “We sponsor a variety of youth team sports such as the new lacrosse league,” said Petroleum Association president Tyler Kosick. “We feel it is important to keep the young ones active for health reasons along with improving their social skills at the same time.” The scholarship program helping a pair of young Fort St. John residents achieve their goals. Randi Whitford and Forest Pimm, who will be studying chemistry at the University of Victoria, received the awards this year. “We as a club feel it is important to provide assistance to the youth of our community,” said Kosick. “Our scholarship program is geared towards graduating individuals seeking formal education in a petroleum related field or a field that will allow them to return to Fort St John and contribute back to the community in a positive way.”

PETROLEUM ASSOCIATION - HAPPENINGS


industry news

STAYING PUT Encana renews Events Centre sponsorship

james waterman Pipeline News North Community was the word of the day as Encana announced that they would be continuing their sponsorship of the Encana Events Centre in Dawson Creek on Wednesday, Sept. 19. The Canadian natural gas company will be lending its name to the facility for an additional five years as part of a new $600,000 commitment to Global Spectrum Facility Management. “The Encana Events Centre is a catalyst for economic development and provides diverse recreational and entertainment opportunities [that] increase the quality of life [of] the citizens of Dawson Creek and [the] surrounding region,” said Ryan MacIvor, general manager of the Encana Events Centre. “This is another defining moment for the venue.” “This is great for the City of Dawson Creek and obviously for the facility,” said Dawson Creek Mayor Mike Bernier. “The last five years, it’s been the Encana Events Centre,” he continued. “It’s going to be great to keep that name recognition for another five years. “It’s great to have Encana come forward.” “Renewing our sponsorship for five more years is just another show of our commitment to the community over the long term,” said Michael Forgo, vice president of business services and stakeholder relations with Encana’s Canadian Division. “Our community relations and investment program means that we want to participate and give back to the community,” he added. “So, this is just one way of doing that.” In recognition of their support, Encana was presented with a pair of acoustic guitars signed by country music stars Gord Bamford and Miranda Lambert, as well as their set lists from shows at the Encana Events Centre. A plaque thanking Encana and 28231

their Cutbank Ridge partner Mitsubishi Corporation for their support was also unveiled during the event, which was attended by Max Oda, president and CEO of Mitsubishi Canada and Shinya Miyazaki, CEO of Cutbank Dawson Gas Resources, a subsidiary of Mitsubishi. “I’m very happy to have a chance to visit here,” said Miyazaki “And we are enjoying very good support from the community and the province and the country itself,” he added, noting that Mitsubishi is working on other ventures in British Columbia as well. Mitsubishi is one of three Asianbased partners, along with Korea Gas Corporation (KOGAS) and PetroChina Company, participating in the LNG Canada liquefied natural gas (LNG) project led by Shell Canada. “Trying to get more and more involved in gas industry here,” said Miyazaki. Miyazaki remarked that they don’t have the same opportunity to interact with the Dawson Creek community as their partner because Encana is the operator of the Cutbank Ridge project. “But we do like to have more and more opportunity to visit and see many people here,” he said. “I visited here in the winter and the summer as well,” he continued. “And we see it’s a very lovely, beautiful place, both in winter and summer.” “They are very interested in learning more about the community, being part of the investment program this partnership brings to the areas in which we operate and really happy to be here today,” Forgo said of Mitsubishi. Bernier was thrilled that the Mitsubishi representatives could take part in the sponsorship announcement. “It’s great to have people from Mitsubishi who have come all the way to Dawson Creek,” he said. “They’ve obviously had a huge investment in the Cutbank Ridge play. But, more importantly, their comment to me is

that investment also means [impacts to] the community. And they want to be part of this announcement today to make sure that they’re part of everything that goes on. “Even though it’s going to be, technically, Encana’s name, this is a partnership with Mitsubishi as well. They have said that they want to be involved in the growing of Dawson Creek.” “I think it’s important,” added Peace River South MLA Blair Lekstrom. “Obviously, Encana is a major player in our area,” he continued. “From day one, when they came in, it wasn’t just about the resource. It was about saying, ‘We want to work with the community in the region. We want to make sure that as we extract this resource, we can maintain the quality of life. We can actually contribute back to the social well being of the region and the community.’ Lekstrom reiterated the importance of natural gas projects such as Cutbank Ridge to the provincial economy, but also noted that those economic benefits should never trump the health of the community. “The partnership they’ve developed with Mitsubishi is one… where we all share the same thing,” he said. “The resource is important to us. We’re a resource rich province. It’s what drives our economy. But it’s never more important than actually maintaining our environment or the sustainability of our communities. So, a huge thank you. “I’ve had the opportunity to work with Encana now going back to when I served as mayor of Dawson Creek. I think they do a tremendous job for us. And every day we’re always trying to find out what we can do better. “And I know that’s their motto as well.” Of course, even businessmen aren’t all business all the time. Miyazaki added,“Very much looking forward to playing golf.”

SEPTEMBER 28, 2012

PIPELINE NEWS NORTH •

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special feature 14 The tie that binds - oil sands and natural gas 18 Good company - industry and community together 26 Canuck wisdom - Trevor Linden talks leadership

community 12 Pulling their weight - Fort St. John’s fire truck pull

industry news 4 CERI studies NGLs

5 Different strokes - Fort Nelson Enery Expo 10 BG and Spectra join LNG game

environment 6 8 24

Dawson Creek Reclaimed Water Project Roadmap to reclamation Caribou face uphill climb

careers & training 29 Old challenges and new opportunities


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SEPTEMBER 28, 2012

North

industry news

all about pentanes plus

CERI takes a hard look at NGL marketplace William Julian Regional Manager 250-785-5631

Alison McMeans Managing Editor 250-785-5631

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Published Monthly by Glacier Ventures International Corp. The Pipeline News North is politically independent and a member of the B.C. Press Council. The Pipeline News North retains sole copyright of advertising, news stories and photography produced by staff. Reproduction is prohibited without written consent of the editor.

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james waterman Pipeline News North

Too much propane and butane; not enough pentanes plus. That is the story being told by a new Canadian Energy Research Institute (CERI) study that examines the natural gas liquids (NGL) market in North America between the present day and 2035. Although a new focus on liquidsrich plays and advances in hydraulic fracturing and horizontal drilling are creating a glut of NGL such as propane and butane in the United States and western Canada, there may still be a shortage of pentanes plus and condensate, diluents that are necessary for transporting oil sands bitumen by pipeline. CERI predicts that pentanes plus and condensate amounting to about 1.4 million barrels per day will be required for oil export projects such as Enbridge’s Northern Gateway and Kinder Morgan’s Trans Mountain Expansion (TMX) by 2035, volumes that can’t be supplied by western Canadian resources. “We are under-supplied with domestic production right now,” said CERI president and CEO Peter Howard, noting that domestic production is presently about 130,000 barrels per day. Imports will have to pick up the slack. “We’re bringing condensate in from the west coast by rail into Edmonton,” said Howard, adding that a pair of pipelines is also now bringing diluent into Alberta from the United States. One of those projects, Enbridge’s Southern Lights pipeline, ships pentanes plus from the Chicago area to Edmonton. The other project is the Cochin pipeline, which had previously been used to ship products such as propane and butane between western Canada and eastern Canada. “That pipeline was bought by Kinder Morgan,” said Howard, “and will be reversed to bring condensate from the North Dakota area back into Alberta. “That will be used to get bitumen out of the province,” he added. Howard remarked that Cochin could be an important piece of the diluent puzzle, particularly if heavy

oil projects such as TMX and TransCanada’s Keystone XL pipeline – which would transport Alberta oil to Gulf Coast refineries – gain approval, but Northern Gateway is left on the sidelines. Northern Gateway is the only one of the pending heavy oil transport projects that includes plans for a pipeline that will bring imported condensate into Alberta. “And that’s kind of where the Cochin pipeline partially fills the bill, because it does bring condensate back into the province,” said Howard. “It’s probably simply stated that if we can get a pipeline out of here to take the bitumen to market, we will be able to figure out how to get it there,” he continued. “Whether it actually means we use imported condensate or in fact we actually can fall back and use synthetic crude oil – SCO – as the diluent. That’s possible too.” The primary source of pentanes plus in western Canada is natural gas production, which is declining because of current low prices for dry natural gas. “The vast majority of the pentanes plus that are domestically produced in the system right now come from the old gas fields,” said Howard. “The economics of those fields is, basically, as long as the market price is above the variable operating cost, then they’ll produce it.” That conventional production will eventually be replaced by production in the liquids-rich plays of what Howard calls the Rockies Trend. “This would be west of Edmonton, west of Calgary and just south of Grande Prairie,” said Howard. “The producers are migrating over to the NGL primarily to enhance the economics of drilling wells,” he continued. “And here in Canada – especially in western Canada – it is just so blatantly obvious that they’ve abandoned all dry, conventional resources and have moved up against the mountains into the liquids plays.” NGL prices are closely aligned to oil prices compared to dry natural gas prices. Howard noted that about 95 per cent of the 723 gas wells licensed in western Canada by September 9, 2012 were along the Rockies Trend. “That’s where the NGL plays are,” he said.

Interestingly, the study really began with an interest in ethane, which is converted into ethylene at ethylene crackers, primarily for manufacturing chemicals such as plastics. “Two significant events have taken place in the last two years, which – plus or minus – contribute to that question,” said Howard. “First of all, the gas streams are declining quite significantly. And that’s more to do with markets than anything else. And the question is: is there the potential of a resurgence, rebound, growth, flatlining, whatever?” The second of those significant events is the Williams pipeline that moves off-gases, including ethane, from the Alberta oil sands to the petrochemical industry in that province. “Here in Alberta, we have three world-scale ethylene crackers,” said Howard, noting that NOVA Chemicals is also adding a third polypropylene cracker. “What it means is if you actually capture and recover ethane, there is a market for it here,” he added. While the domestic ethane supply may be low enough to necessitate imports from the Bakken tight oil play in North Dakota to satisfy the Alberta market, the situation is quite different when it comes to propane and butane. “When you look at propanes and butanes,” said Howard, “I think, in its simplest form, the industry basically drilled the heavy liquids plays looking to capture the economic rent from the liquids market, but not recognizing the potential to over-supply that market. And that is now starting to materialize. “It’s not just forecasting anymore,” he continued. “Even some of the actuals is starting to suggest that the market – North American market – will become over-supplied in propanes and butanes. With the relief from that being primarily exports.” There is also potential for using propane and butane as solvents in oil sands operations. “That’s a positive,” said Howard. “That would require those streams to be directed towards the oil sands as opposed to being directed outside of the province in the export market.”


SEPTEMBER 28, 2012

PIPELINE NEWS NORTH •

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DIFFERENT STROKES Variety is the spice of life at Fort Nelson Energy Expo

Rachael D’Silva from Employment Connections in Fort St. John talks oil and gas with Art Jarvis, executive director south for Energy Services BC, during the Fort Nelson Energy Expo.

JAMES WATERMAN photO

james waterman Pipeline News North A lesson to be learned from the most recent Fort Nelson Energy Expo is that no trade show is the same to all its participants. Energy Services BC (ESBC), the organizer of the oil and gas industry event that took place at the Northern Rockies Regional Recreation Centre on September 14-15, had very clear goals for the expo, but they didn’t match the goals of all the guests and exhibitors. “My goals for this expo and every expo we put on is to ensure that there’s a seamless communication opportunity between the service sector and the producers,” said Art Jarvis, executive director south with ESBC. The purpose is to show the natural gas producers operating in the region what they can expect to find in the Fort Nelson area as far as services and equipment. “And, of course, from the service sector side, the type of jobs that they can expect to see in the near future or that are currently going on,” Jarvis added. In those terms, the show was a modest success, which isn’t entirely surprising considering the low natural gas prices that have slowed activity in the nearby Horn River Basin shale gas play of northeast British Columbia. “There’s uncertainty about what’s going to happen this winter,” said Jarvis. Still, ESBC isn’t satisfied. “I’m quite sure that we’ll be going to the Horn River [Basin] Producers Group – going to their next meeting – and requesting an improved attendance, for them to take a more serious look at the investment that all of our service people have getting into this, and the fact that they need to be viewed by the right people from Calgary,” said Jarvis. The Energy Expo was a different story for Rachael D’Silva, who was attending on behalf of Employment Connections in Fort St. John to promote the Targeted Skills Shortage Program. “Which is aimed for small employers, small organizations or entrepreneurs in the North Peace region,” said D’Silva.

The program focuses on five sectors: natural gas, transportation, manufacturing, health care and social services, and clean technology and green economy. “There was a pilot program last year, but it didn’t cover all these sectors,” D’Silva continued. “This year it’s been expanded to include the oil and gas and the clean technology and green economy sector.” The program offers as much as $1,500 per employee and $7,500 per employer to pay for tuition and other materials associated with training and education. “Basically, if an employee does not possess a high school diploma, or he has a high school diploma but doesn’t have any recognized certification, than he could be eligible” said D’Silva. “Fund any kind of safety tickets he needs, any kind of training he requires,” she added. The program has expanded to include the oil and gas industry largely because of the number of people gravitating toward that sector in the region, including those new to the area.

D’Silva feels that participating in the program could be a smart move for employers. “By training your employees, you’re really demonstrating your interest in your employee’s professional development and enhancing their skills,” she explained. “It’s also a way of retaining your employees and reducing employee turnover.” D’Silva met with a number of companies during the trade show. “They’re very, very interested in the program,” she said. “Though I’ve tried to market this program and sent out tons of emails to quite a few of them, it really helps to meet them face to face, because I get a much better feedback from them,” she added. However, D’Silva had other reasons for attending the Energy Expo as well. “For me, it’s a learning in the oil and gas industry, because I don’t know enough,” she admitted. Enbridge is a company that knows plenty about the oil and gas industry. They were attending the Energy Expo to make sure that the Fort Nelson community knows a thing or two about them. “January 1, we’re taking over ownership from Encana of the Cabin Gas Plant,” said community relations advisor Craig Matwick. “So, this is the first time that we wanted to come out to the Expo and just start to meet people and shake hands and explain a bit about Enbridge and who we are and where we come from, what our core business is, and then what we’re planning to do as far as the transition to take over on January 1.” Enbridge is a big player in the natural gas midstream business in other regions such as Texas, but taking over the natural gas processing plant is their first foray into that sector in northeast B.C. “We’ve been doing it for years down there,” said Matwick. “We’re going to try it in Canada. We got into the Cabin Gas Plant here and there’s a lot of opportunity for growth and expansion in the area.” Matwick remarked that Enbridge was hoping to “get an idea of what makes the community tick” and address local concerns about their activities out in the remote part of the Horn River Basin where the Cabin Gas Plant is located. “There’s nothing worse than not knowing what’s going on,” he said. “It’s definitely always best to just be open and transparent about what is going on, what our plans are, and this is our first opportunity in town to really get that message out there and start answering questions and making contacts and building a long term relationship. “If anybody has questions, they know who to contact.”

Northern Rockies Regional Municipality Mayor Bill Streeper gets to know the folks from Enbridge, who will be taking over the Cabin Gas Plant from Encana in January. The plant is located in the Horn River Basin shale gas play near Fort Nelson.

JAMES WATERMAN photO


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environment

WASTE WATER not WASTED Shell and Dawson Creek work together to save a precious resource james waterman Pipeline News North The City of Dawson Creek celebrated the end of one of the driest South Peace summers on record with the promise of a future full of lush sports fields, vibrant flowers and environmentally sustainable hydraulic fracturing operations in the Montney natural gas play of the region. That promise was made on the morning of Friday, September 7 with the unveiling of the Dawson Creek Reclaimed Water Project, a collaborative effort between the City and Shell Canada to divert sewage wastewater usually destined for Dawson Creek to Shell’s Groundbirch natural gas operation 48 kilometres west of town. “The City of Dawson Creek has actually applied for a secondary permit on this facility,” said Mayor Mike Bernier, pointing out that hydraulic fracturing won’t be the only use of the reclaimed water. The City has been issued a permit to discharge that reclaimed water for use by Shell, but is presently awaiting approval from the provincial Ministry of Environment for an additional permit to use the water for municipal purposes. “And to sell to other people in the community for nonpotable, bulk uses,” said Bernier.

That could include use by other natural gas producers in their hydraulic fracturing operations. “We’re pretty confident that it’s not far away,” Bernier said of the second permit. “And then we basically will be able to start using it for all of the other plans that we have in place – sports fields, watering our planters and washing down the streets. Things that, right now, we have to use potable water for.” Bernier’s optimism was given a measure of validity by presence of Peace River South MLA Blair Lekstrom at the grand opening of the plant. “This is just the beginning,” said Lekstrom, adding that the reclaimed water could have “so many uses beyond fracking.” The project also received a glowing review from Minister of Energy and Mines Rich Coleman. “The use of treated waste water is an excellent step forward by Shell and the City of Dawson Creek to improve resource demands and operations, and is an example of a green project that has already resulted in positive change,” Coleman said in a news release issued by Shell. “The Government of British Columbia applauds the work and commitment that has resulted in this fine facility, which is a model we hope other industry players and

local governments will strive to replicate,” he added. Additionally, Lekstrom praised Shell for their role in the project, remarking that the company is “ahead of government in many ways.” Shell hasn’t yet begun to use the reclaimed water, however, as they are still in the process of filling the ponds at their Groundbirch site. “It varies,” said Rej Tetrault, operations manager for Groundbirch, discussing the volumes of water Shell will be using from the reclaimed water plant. “And it will vary on a daily basis,” he continued. “Some days, like today, we’re not using any water because we’re making due with what we have. And so it will be very cyclical. And it’s those cycles that will present the opportunity to seek other users to [take] those other volumes.” Previously, Shell had been working with water from the nearby river and adjacent ponds that also provide water for cattle, as well as recycling and reusing as much as 75 per cent of the produced water from their natural gas wells. Their goal is to eliminate as much as possible the use of freshwater for drilling and completions at Groundbirch, a goal that aligned with the City of Dawson Creek’s desire to better manage its own water use as well as

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SEPTEMBER 28, 2012

reduce the amount of water being used by the natural gas producers in the area. “The water was being wasted,” said Bernier. “It was serendipitous,” Tetrault said of how the project began. “And maybe that merge might not have happened as quickly as it did. It could have been maybe several months until we would have found out. So, I think it just speaks to the need to make sure that we’re constantly engaging with various stakeholders to find innovative ways to meet our needs. “Whenever you are developing a project or thinking about a project, whether it be the City or ourselves, the first thing that you need to do is you need to reach out to as many stakeholders as you can to actually seek information [and] ideas,” he added. The result in this case is a water treatment facility capable of producing 4,000 cubic metres of useable water per day from sewage, which is especially significant considering the water woes the South Peace – and the natural gas industry – has experienced this summer. The City had decided to implement Stage 4 water restrictions just two days prior to the grand opening of the reclaimed water facility. The restrictions prohibit non-essential household water use and limits industrial water use. Additionally, the dry conditions prompted the BC Oil and Gas Commission (OGC) to suspend water withdrawals by natural gas producers from several waterways in the northeast corner of the province, including the Kiskatinaw River, which is the water source for Dawson Creek. OGC hydrologist Alan Chapman explained that the South Peace is experiencing a one-in-twenty-years dry spell this year, but he also put the summer of 2010 in that same category. “When you look at the fact that we’re in a drought situation again in the South Peace region here, it really highlights

the importance of a facility like this,” said Bernier, noting the hope that this initiative will mean never again resorting to Stage 4 water restrictions. “This is starting to become a norm,” he continued, discussing the historically significant drought. “And so this facility is perfectly timed to recognize the fact that we need to do everything we can to save our potable water and to reduce the amount we withdraw from the Kiskatinaw River. It also highlights the need for the City to make sure that we have more storage so, going forward, we don’t have issues like this where we have to go to any kind of … restrictions.” “It certainly puts it under a magnifying glass,” added Tetrault. “When you’re looking at a summer like this one being so dry,” he said. “And this presents an opportunity as well to be able to get this facility such that you can actually water fields, water planters, find other uses for this water, because, as you’ve seen today, it’s a very clean water.” Bernier also pointed out that there is always effluent that can be treated regardless of the amount of potable water available due to dry conditions. That means that there will always be a source of non-potable use water for the industry and the municipality even when surface sources are running dry. “It’s very beneficial for Shell and for [other] companies because, now with this facility, even though there’s water restrictions by the OGC, companies like Shell can continue fracking, continue operating, because they’re using reclaimed water,” he said. “That in itself shows how it’s a win-win for everybody.” Although water conservation was top of mind during the opening of the plant, Tetrault remarked that the initiative also addresses another common concern among those who live near natural gas

PIPELINE NEWS NORTH •

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Dawson Creek Mayor Mike Bernier shows off the quality of the water that has been treated at the new Dawson Creek Reclaimed Water Project by comparing it to a beaker of fresh drinking water. The reclaimed water isn’t quite potable, but is suitable for watering sports fields and industry use in hydraulic fracturing.

JAMES WATERMAN photO

operations: truck traffic. “Certainly, any initiative to reduce the amount of truck traffic on the roads is a very positive one,” said Tetrault. “It certainly removes the amount of road use, wear and tear on the roads, dust. And then, of course, road safety as well. “It reduces our risk of having someone hurt on the roads.” Ultimately, Tetrault and Bernier were simply thrilled to finally show off the fruits of the two-year partnership between Shell and the City of Dawson Creek that built the reclaimed water plant. “I’m extremely excited to be part of this,” said Tetrault. “Proud of Shell. It’s one of those days where I come to work and I look to see what we accomplished with all of our stakeholders and feel an extreme sense of joy that we’ve done

some real good in the world today.” “This is a great opportunity,” said Bernier. “It wouldn’t have happened without our partnership with Shell. It was way beyond something that a city, I think, could do by themselves. So, again, really have to thank Shell and all of the people we’ve worked with there to be able to get to do this point. “Something we can showcase as one of a kind.” The significance of the event and the value of the reclaimed water project were highlighted by the fact that Shell’s executive vice president of onshore gas Russ Ford traveled all the way from Houston, Texas to address the attending dignitaries and other invited guests. Ford added, “This is a good day in my job life.”

Enbridge conducts training exercise on North Saskatchewan River james waterman Pipeline News North

About sixty men in the typical garb of the oil and gas industry descended on Capilano Park in Edmonton on Wednesday, September 12, but not because there had been an actual oil leak into the North Saskatchewan River. It was just a routine training exercise for thirty pipeline integrity, operations, emergency response, liquid pipelines, regulatory, environmental management and facilities personnel from Enbridge Pipelines, and thirty additional personnel from Pembina Pipeline Corporation. “Several times a year, according to regulatory requirements,” said Enbridge spokesperson Graham White, discussing how often such training exercises are conducted by the company. The only difference this time around was that they partnered with their peers from Pembina to run this session. “It is vital not just for regulatory reasons,” Graham

continued, explaining the value of the exercies, “but to ensure our level of preparedness and response is adequate, coordinated, effective and efficient for any incident. We need to be able to provide assurance to ourselves, regulators and the public that we are capable of fulfilling our very serious commitment to public safety and to mitigating any environmental impacts. “And this is just this type of exercise for this region. We conduct many other exercises in all the regions in which we operate.” Enbridge chose that section of the North Saskatchewan River not because they have pipelines crossing the water in that area, but because it is similar to other locations across North America where they do have water crossings. “Also,” said Graham, “this site allows us to consolidate resources and equipment from several different areas and partners – Pembina, for example – to ensure we have what we need in the event of an actual incident and that everything works together effectively and efficiently.”

Regulatory requirements dictate that Enbridge regularly perform emergency response training like the exercises conducted in the North Saskatchewan River in Edmonton this September.

photO COURTESY OF ENBRIDGE


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SEPTEMBER 28, 2012

environment

ROADMAP TO RECLAMATION Oil industry improving tailings ponds technologies

Suncor Energy’s Wapisiw Lookout, formerly known as Pond 1, is the first oil sands tailings pond site now capable of supporting vegetation. It will soon be home to 220 hectares of mixed forest and a wetland. The Tailings Technology Roadmap and Action Plan will help other companies successfully reclaim their tailings ponds, too.

photO COURTESY OF SUNCOR ENERGY

james waterman Pipeline News North Tailings ponds are a fact of life in the Alberta oil sands, but that doesn’t mean the industry is becoming complacent about the reclamation of those sites. A group of oil sands producers with surface mining operations – Suncor Energy, Syncrude Canada, Shell Canada, Canadian Natural Resources (CNRL), Imperial Oil, Total E&P Canada and Teck Resources – were brought together about two years ago under the banner of a Tailings Technology Roadmap and Action Plan project to share the technologies they use in their tailings reclamation efforts, all in the interest of improving tailings management in the oil sands. The results were released at the end of August. “Tailings is an environmental issue that’s been around for a fair bit of time,” said Dr. Eddy Isaacs, CEO of Alberta Innovates-Energy and Environmental Solutions (AI-EES), which partnered with the Oil Sands Tailings Consortium (OSTC) to lead the project. Alberta Energy and Alberta Environment and Sustainable Resource Development (ESRD) also participated, along with the Alberta’s oil and gas industry regulator, the Energy Resources Conservation Board (ERCB), and Natural Resources Canada (NRCan). “Different companies have been working together – separately and together – on a number of technologies to try to solve the problems, reclaim the land, and so on,” Isaacs continued. “And, of course, some reclamation has already taken place. Actually, a fair bit of reclamation has.” The goal of the project was to review all existing and developing technologies in one place in order to determine all the potential pathways for reclaiming oil sands tailings ponds. “In some cases, they have been collaborating, but it’s been one-on-one as opposed to the entire industry,” said Isaacs. “Syncrude and Suncor have been working on this

problem for a long time and so they have a lot of very like centrifuges, which Syncrude has adopted to some good information that they can make available,” he degree. continued. “And so part of the deal was that companies “There are no silver bullets,” he continued. “Different would start to share all of the past information, but also companies have different ore bodies, they have different future information.” licenses for their settling areas. Some of them don’t It is a legal requirement that companies reclaim their have as much room to use for tailings ponds.” tailings ponds, which can be a long and tricky process The pathways also identify innovations that could imbecause of the oil and organic substances associated prove tailings reclamation from an economic perspective. with the water. “But the key aspects of these is how can these pathWater in a tailings pond is also used for oil extraction ways be accelerated and what are the missing links to throughout the life of the associated mine. technologies that can do that,” said Isaacs. “When the water separates, it’s used in the process “We also want to deal with the water issue,” he added. itself,” said Isaacs, noting that about 85 per cent of that “Just because the clays get settled, we still have to water is recycled. clean up the water. And so some of the technologies “But, in the meantime, you do have fine clays that deal with that as well.” have not settled and take a long The pathways were develtime to settle,” he continued. “So, oped with the help of nine in order to reclaim these ponds, consulting and engineering and in order to re-vegetate the soil companies that work with oil “There are no silver and so on, you need to resettle sands producers. these clays. And so a large part “Really critical to this projbullets.” of what was looked at with this ect’s success,” said Isaacs. roadmap was to look at what are Overall, the team assessed – Eddy Isaacs, the key technologies to be able to over 500 technologies used in do that from a practical perspectailings ponds reclamations. Alberta Innovates tive – an economic and technical “The beauty is that all of this perspective – and what [does] the is in one place as opposed consolidation look like if this is to being scattered in different done properly. places,” said Isaacs. “And what are the gaps that there are that need to be “The team we have within our own organization … is to filled so that reclamation can be done and advance the now go through these and start to prioritize the work that rate at which reclamation can be done.” needs to be done to firm up some of these pathways to The project identified nine pathways for tailings reclamake sure that the technologies that are already being mation, each featuring a set of technologies specific to demonstrated are being shared,” he continued. the characteristics of the operation. “And to know where the gaps are. The roadmap itself “Some of them really require a lot more finesse and has identified these gaps. And so the question is to folwork in parts of it,” Isaacs explained. “So, a pathway low up and make sure we actually start to address the could consist of a number of different technologies. The gaps and to implement the roadmap.” key technologies will remain the use of polymers for Demonstrations of these pathways are expected to quicker settlement of the ponds [and] the use of things begin in early 2013.


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industry news

NEW PLAYERS IN THE LNG GAME

BG and Spectra join forces on gas export project james waterman Pipeline News North

Spectra Energy is the latest company bidding to join the liquefied natural gas (LNG) export game in British Columbia. The midstream outfit announced on September 10 that they are working with international natural gas heavyweight BG Group to develop a system to transport natural gas from northeast B.C. to a proposed LNG export hub in Prince Rupert. If it goes forward, the equal ownership venture would see Spectra take responsibility for construction and operation of the pipeline, while BG Group would contract the natural gas for transport. “That was a very easy decision,” said Steve Sawffield, acting president of BG Group in B.C., explaining why his company has chosen to work with Spectra. “Spectra have a great North American footprint,” he added. “And their position in western Canada is unsurpassed. They’ve had over 50 years of experience in the midstream. And it was a logical fit with them.” Spectra had similar praise for BG Group. “We’ve got to know them pretty well now over the last year or so that we’ve worked with them,” said Doug Bloom, president of Spectra Energy Transmission West. “And I have to say that we really like working with them. “They’re a big player, obviously. They’re a global player. A very significant LNG player and a very significant natural gas company that operates in 25 countries around the world. So, they bring a lot to the table.” That includes access to an Asian market coveted by natural gas producers in western Canada. “They’re a very significant player,” Bloom continued. “We’ve been impressed, frankly, at how well they’ve done their homework in British Columbia,” he said. “They’ve done a lot of work on the pipeline side themselves to try and make sure they were really knowledgeable as they went into the process of selecting with whom they’d work. So, they’re thorough and they’re a big player and so far we’ve found the cultures very compatible between us. So, we’re looking forward to working with them for the long term.” The plan involves constructing an 850-kilometre pipeline beginning at point in the Cypress area, just over 100 kilometres northwest of Fort St. John. The pipeline will likely follow the Fort Nelson Mainline right-of-way south to a compressor station near Chetwynd, then turn west toward Prince Rupert along a brand new pipeline corridor. “Capacity is targeted at 4.2 billion cubic feet (bcf) a day,” said Bloom, adding that the current plan is for a 48-inch diameter pipe.

At this point, capital cost of the project is estimated at between $6 billion and $8 billion, but that number isn’t yet set in stone. “This is very much feasibility,” said Swaffield. “We’re in the early stages of the project. We wouldn’t be making a final investment decision until the middle of the decade. And the first gas exports would be right at the end of the decade.” “We have been working for about a year as a team and announced previously that we’ve selected Ridley Island as our potential export location,” he continued. “And that’s a site that benefits from road and rail access. And its coastal location and deepwater port is what we were looking for on the coast of B.C.” “We’ve got plenty of work to do to confirm the corridor or adjust it as needed,” said Bloom. “Go through all the permitting and regulatory process, work with the First Nations who are affected along the way, and then, of course, do substantially more technical work – engineering and technical analysis – that can give us a more firm estimate of the cost, all of which we plan to do in the next couple of years until we get to our final investment decision date.” BG Group is presently discussing the project with natural gas producers in northeast B.C. that may wish to take advantage of this avenue to export their product. “It’s probably gas that we and others would process,” said Bloom. “We think it’s going to create a lot of opportunity for a company like ours that is a very large gas processor up in northeastern B.C. That’s not to say that we would get all of it, but we think it does create a big opportunity for players like us in gathering and processing the gas. And even the pipeline connections into the system that we are planning to build with BG.” Spectra likely had a leg up on the competition for this opportunity to work with BG Group thanks to past experience in the challenging terrain of northwest B.C. “We owned all the voting shares of PNG (Pacific Northern Gas) and we used to do a lot of the engineering work for them,” said Bloom. “And, in fact, engineers that worked at one time for Spectra designed and built that PNG system. So, throughout the company there’s a reasonable amount of institutional memory about PNG and what aspects of the geography we really need to pay attention to out there. And to avoid areas that are unstable either because of slope or water flow.” Bloom believes that history played a significant role in BG Group’s decision. “I think they really understand that, because we’ve owned and operated pipelines in British Columbia for 55 years, we’ve built up a fair bit of experience with the geography,” he continued.

Spectra Energy has entered into a development agreement with BG Group to build an 850-kilometre pipeline for transporting as much as 4.2 billion cubic feet of natural gas per day from northeast British Columbia to a proposed liquefied natural gas export hub at Prince Rupert.

photO COURTESY OF spectra energy

“We cross all of the mountain ranges already. We’ve done a lot of work up in that northwest part of British Columbia that again leverages off the experience we’ve had everywhere else in British Columbia. So, I think all of that probably played an important factor. “We’ve got a pretty good reputation in the communities that we operate in,” he added. “And we work very hard to be a good neighbour and to be part of the fabric of the communities that we deal with. I think all of those things were relevant to BG as they were deciding who

to work with.” Spectra’s knowledge of the challenges of building and operating a pipeline in northwest B.C. may inspire some new ideas this time around. “One of the most important things we’re focused on is altitude,” said Bloom, noting that it is preferable to stay below about 600 metres above sea level rather than venture into areas well over 1000 metres above sea level. “Altitude is going to create weather issues, is going to create access issues, is going to create hazards that could


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lead to safety incidents or delays or other challenges in construction,” Bloom continued. “We’ve designed an initial corridor that keeps the pipeline at what we think is a manageable altitude,” he said. Another significant issue is slope stability in a mountainous region where landslides are fairly common. “We’ve got a lot of experience with slopes and how to distinguish slopes that we think we’ll be able to keep stable versus slopes that will be inherently unstable and could put a lot of strain and pressure on the pipeline,” said Bloom. The major economic question concerns whether or not there is room for this project in terms of B.C. gas supply and foreign market demand when at least three other LNG projects could be up and running before the BG Group project is online. “We believe there’s room for several projects,” said Swaffield. “The world LNG needs will grow faster than the [natural gas production] growth in western Canada and faster than the growth in North America,” said Bill Gwozd, vice president of gas services with Ziff Energy Group. The shift from coal and other sources

of power to natural gas is expected to be a significant aspect of that trend. “Even in 2020, will the demand for LNG continue to grow?” said Gwozd. “We believe the answer is yes. So, even by 2025, 2030, 2035, 2040 there’s incremental growth of gas markets. And so, as a result, you’re going to need incremental supply sources. So, I do not view BG as being late. “I don’t know view Apache as being early,” he added, referring to the Kitimat LNG project led by Apache and also involving EOG Resources and Encana. “I just believe that they’re all sequenced into a broader scheme where they can all dovetail into the LNG requirement matrix.” However, there could be a problem around finding the necessary labour to build and operate the pipelines and export facilities. “Labour is one of the biggest challenges, not just for the energy industry, but across the west in all kinds of industries,” said Canadian Association of Petroleum Producers (CAPP) spokesperson Travis Davies. “It will be a part of the consideration, whether you’re looking at cost of labour or even just simply availability of labour. And it’s a chronic problem.

“We’ve got demographics that are shifting,” he continued. “We’ve got, obviously, a lot of projects and growth potential that, in order to meet, we’re going to need to find the labour.” One option is to import that labour. “When you do labour pool analyses, you have to make assumptions on workload – existing workload – in many sectors,” said Gwozd. “In the future,” he continued, “you have to have estimates of the activity, not labour. Estimates of the activity in order to determine how much labour you require.” Gwozd feels that many of the companies that conduct labour pool analysis make mistakes when they forecast activity. “I’m not convinced that the forecasters that are forecasting … labour are really that astute in the activity levels and the clear understanding of the relationships between energy prices and activity and what’s realistic in the future,” he said. “I’m curious how they can actually forecast labour if they don’t have a clear understanding of the fundamentals that surround that,” he added. Gwozd foresees a decrease in natural

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gas activity and a fairly stable picture for the oil industry until it also dips down in the distant future. Pipeline and plant construction are the areas where labour demand is likely to grow. “You can use Houston labour for engineering design,” said Gwozd. “You can use India labour for engineering design. And then it’s just simply the welders and the pipefitters and the actual physical builders of these plants. “And I’m not a believer that a big labour issue is looming.” Many in the oil and gas industry would certainly hope that is true considering the opportunity that exists with LNG. “The LNG opportunity is huge for British Columbia,” said Bloom. “The United States has probably more natural gas than even we have in Canada,” he continued, discussing the dynamics of the export market. “And we’re sitting on an enormous amount of it. And in British Columbia we’re sitting on an enormous proportion of that. It becomes pretty obvious that we’ve really got to diversify markets. “It’s going to be necessary in order to maintain and grow production and growth of this industry.”

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community PULLING THEIR WEIGHT Energy sector rises to the challenge for United Way

The United Way’s Niki Hedges counts the seconds as the winning team from Shell Canada pulls a 31,000 pound fire truck across the Pomeroy Sports Centre parking lot. The event brought in $25,000 for the United Way.

JAMES WATERMAN photO

james waterman Pipeline News North Bragging rights were on the line on Saturday, September 22 as the United Way of northern British Columbia held their second annual fire truck pull in Fort St. John. The fundraising event to launch the 2012 United Way Campaign pitted firefighters against police officers and energy sector companies against each other in a bit of friendly competition that brought in $25,000 for initiatives such as an outreach program with the Fort St. John Women’s Resource Society, an early learning program in Dawson Creek and a seniors transportation program in Fort Nelson. “Today was an amazing success,” said Niki Hedges, United Way’s community development and campaign officer for northeast B.C. “Last year, we did really well and the atmosphere down here was just electric,” she continued. “But this year, it just increased, and the spirit of the different teams here was phenomenal.” The first fire truck pull brought in $8,000, an amount that was more than tripled this year thanks in part to the

new participation of Progress Energy, who raised the most money of all teams with $7,700, and the continued support of Shell Canada, who had two regional teams that contributed over $14,400 collectively. “I think it’s key,” said Rej Tetrault, operations manager for Shell’s Groundbirch operation in the Montney tight gas play, discussing the importance of that friendly competition between the energy sector companies, as well as within his own organization. “We all have a bit of a competitive spirit,” he added. “And if you can leverage that competitive spirit to help raise money for great charities, for the United Way, than let’s go. Let’s do that.” Tetrault’s team was not the best Shell had to offer that day, as the other Shell team won the competition by pulling the 31,000 pound fire truck the necessary distance in just 14.7 seconds. Second place went to the Fort St. John Fire Department, who completed the task in just over 15 seconds. The RCMP team came in just behind the firefighters. “It’s great, especially for us with the police,” said firefighter and team captain Craig Faulkner. “We always see them on scene and deal with them

like that,” he continued. “And away from the job, it’s nice to have a relationship, especially when it’s friendly competition. Last year they ended up beating us. So, this year, it was our goal to make sure we beat the cops. “That friendly competition is always good for an event.” The Spectra Energy team, led by world-class speed skater Jay Morrison, failed to live up to expectations and finished with a disappointing time of about 22 seconds. “My sport isn’t specifically tailored to the fire truck pull, necessarily, but I feel like there is some crossover in strength,” Morrison joked. Luckily, Spectra was able to redeem themselves by taking home the prize for most spirited team. “I’m always happy to support fun events that raise money for a good cause,” said Morrison. “Fort St. John’s a really good community,” he continued, contemplating the ten teams who took part in the event and the tremendous crowd that came out to watch the competition. “We’re a young community, a growing community, and people are vibrant. And the community is vibrant because of it. I think people are willing to participate in a lot of the things that we have going on. And


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Although the Spectra Energy team featured speed skater Jay Morrison, they had one of the worst times of the day, while still helping United Way raise funds for their programs.

JAMES WATERMAN photO

there is a lot going on in the community.” “I think it’s great when the community gets out and supports United Way,” added Morrison’s Spectra colleague Rod Locke. Of course, the true goal of the event wasn’t winning the race, but supporting a good cause. “At the end of the day, everybody’s down here for United Way Northern BC,” said Hedges. “And we’re raising really important funds that will be invested into the community. Really crucial funds that go into programs and services where there is a critical need and where we will help

to impact the most amount of people.” Hedges is hoping to bring the fire truck pull to other northeast B.C. communities from Tumbler Ridge to Fort Nelson, a dream that the oil and gas industry will likely help her accomplish. “It’s very important,” she said of the energy sector support. “Company-wide, in western Canada, we’re a big supporter of the United Way,” said Locke. Shell is another big supporter. “We invited the United Way to come in and give us a presentation on what the United Way is because we do have new

employees that aren’t maybe aware of what the United Way is and what they do,” said Tetrault, explaining how Shell’s Fort St. John office began their involvement in the 2012 United Way Campaign. “We also brought a local charity that the United Way supports,” he added.

Even the kids are taking part in the fundraising efforts this year. “Many of the Shell children got together and raised money on their own and put together their own fire truck pull team,” said Tetrault. “They pulled a golf cart. And together just the children raised $880.”

STAFF REPORTER Pipeline News North Already enjoying a front row seat for the debut of a British Columbian liquefied natural gas (LNG) industry that is growing around their Kitimat community, the Haisla First Nation are now working toward developing an LNG export facility of their own. That was the story told in a September 14 announcement from the Haisla and the B.C. government discussing the signing of a framework agreement between the two parties, the ultimate goal of which is to develop an natural gas liquefaction plant and marine export terminal on the Douglas Channel. The agreement will facilitate the purchase or lease of a suitable parcel of land by the Haisla for the purpose of constructing such a facility with an industry partner. “This agreement allows the Haisla to look at the land on the west side of the Douglas Channel in a different light,” said Haisla Nation chief councilor Ellis Ross. “This gives the Haisla and associated projects the certainty needed for the LNG proposals and other projects coming forward for our territory. If we are able to do this, the Haisla people will benefit, as will all British Columbians and Canadians.” “Our government is working with First Nations like the Haisla to create new jobs and opportunities throughout British Columbia,” added Ida Chong, Minister of

Aboriginal Relations and Conciliation. “This agreement builds on our strong partnership with the Haisla Nation and it is the key to unlocking the vast potential of a whole new natural gas export industry in British Columbia, which will provide longterm stability for families and communities.” It will also help the government achieve its goal of having three LNG terminals up and running by 2020. Numerous other LNG proposals are in various stages of development, including the Kitimat LNG project led by Apache, EOG Resources and Encana, which is expected to be online in 2017. BG Group has announced plans to develop an LNG facility in Prince Rupert, while Shell Canada is moving forward on another plant in Kitimat with their LNG Canada partners Korea Gas Corporation (KOGAS), Mitsubishi Corporation and PetroChina Company. The BC LNG Export Co-operative is also in the mix. The government expects the LNG industry to create 1,400 jobs and $600 billion in economic activity in the province over the next thirty years. “The Province of British Columbia continues to build on the foundation of the BC Jobs Plan to create jobs and support businesses,” said Minister of Energy and Mines Rich Coleman. “Today’s framework agreement is another step toward our goal of developing a liquefied natural gas industry which will create economic opportunities for our entire province.”

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THE TIE THAT BINDS

The links between heavy oil and natural gas james waterman Pipeline News North

It is clear to Ziff Energy that the future of the Alberta oil sands depends heavily on new pipeline capacity to transport bitumen from that province to markets in the United States and Asia. The oil and gas industry consulting firm released a new report titled Implications of Growing Western Canadian Oil Production on August 31 in which they analyze oil sands supply and demand dynamics, as well as export potential for the resource and the pipeline capacity necessary to ship western Canadian oil to refineries in the U.S. and beyond. Ziff Energy projects that oil production in western Canada will exceed 5.5 million barrels by 2020, conventional oil accounting for 1.5 billion barrels and oil sands mining and in situ projects accounting for approximately 2.0 million barrels each. “Alberta oil sands mining and in situ projects are contributing to the strong growth forecast and, in order for this to be realized, new pipeline capacity is required,” said Ziff Energy gas analyst Julia Sagidova. That could also impact the natural gas industry in British Columbia. “By 2020,” said Sagidova, “one bcf (billion cubic feet) of forecast gas demand for oil sands projects is at risk if proposed pipeline projects do not proceed as planned.” Ziff Energy forecasts that oil sands demand for natural gas will reach 3.0 bcf per day by 2020 if the necessary pipeline capacity to move the bitumen exists. If that capacity isn’t available, oil sands demand for natural gas will only be 2.0 bcf per day by 2020. Chief among the oil pipeline projects in question is Enbridge’s embattled Northern Gateway pipeline that would ship oil sands bitumen to an export hub at Kitimat, Kinder Morgan’s Trans Mountain Expansion (TMX) project that would also deliver Alberta oil to the Pacific Coast and TransCanada’s Keystone XL pipeline that

would transport Alberta oil to Gulf Coast refineries in the U.S. “If there’s no oil transportation legs in place, you can’t transport the oil,” said Bill Gwozd, vice president of gas services with Ziff Energy. “Therefore, you won’t need the natural gas supply for it. That’s the issue that we have to address: will we have the pipelines in place?” Gwozd suggested that Ziff Energy is realistic rather than optimistic, yet he seems confident that the necessary pipelines will be ready in the near future. He expects Enbridge’s Alberta Clipper pipeline to move oil from Hardisty, Alberta to Superior, Wisconsin will be online by 2014 and Keystone XL will be online by 2015. “Then there’s the TMX and the Enbridge Gateway, which should be up and running by about 2017,” he said. “As we stack these projects up,” he continued, “if they come to [fruition], the gas demand for the oil sands will proceed.” If the pipelines don’t materialize, oil sands production will slow – or stop – unless viable alternatives are found. “They could put it in rail cars, for example, and transport it out,” said Gwozd. “You could go back to the other oil transporters and ask if they could squeeze it out. You could find new markets for it.” Instead of trying to push the oil south and west, the industry could look to the north and the east, which is the idea that TransCanada is exploring with a plan to convert one of their natural gas pipelines to oil service to eastern Canada. “[If] the stars don’t align, then the natural gas demand for the oil sands could tilt down,” said Gwozd. The issue for B.C. natural gas producers is what the impact on their business could be if the oil sands industry demand for their product is lower than anticipated. “It’s one of the closest and fastest growing markets there is in Canada for natural gas,” said Greg Stringham, vice president of markets and oil sands with the Canadian Association of Petroleum Producers (CAPP).

“If there is a slowdown in oil sands development, that means there’ll be a slowdown in the need for natural gas,” he added, noting that natural gas currently used by oil sands operators includes resources from the Horn River Basin shale gas play of northeast B.C. Stringham suggested that the oil sands industry needs access to Asian markets through the West Coast, American refineries in the U.S. Gulf Coast and eastern Canadian markets that could be supplied by TransCanada in order to maintain the pace of development. He also indicated that would be positive for the B.C. natural gas industry in terms of continuing development of the Horn River Basin and unlocking the nearby Liard Basin and Cordova Embayment. “We need all three of those markets,” said Stringham. “And all three of those are good for the development of the Horn River and other northern B.C. basins. Because they are already pipeline connected and would be big suppliers into that oil sands market.” A common refrain in B.C. is that the natural gas sector – and the affiliated liquefied natural gas (LNG) export business – is good for the province, but heavy oil pipelines such as Northern Gateway and TMX should not be welcome within its borders, even though there is that link between the natural gas and oil sands industries. “I think they’re both equally important,” said Stringham. “LNG gives us an opportunity to get to the international market,” he continued. “But the advantage of the oil sands is it’s already connected and piped, in particular, to the Horn River area, which, again, is dry gas. It doesn’t have the liquids push that’s getting the Montney activity going on right now.” Gwozd offered his own take on the natural gas versus oil sands debate in B.C. “A lot of people in B.C. are just not knowledgeable,” said Gwozd. “Including the government,” he contin-

ued. “Just overall lack of leadership, lack of depth, lack of insight.” That problem is exemplified in Gwozd’s mind by the September 13 announcement from the Ministry of Finance that low natural gas prices should shoulder the blame for the projected $1.14 billion deficit that British Columbia is facing in 2012-13. Although land sales for natural gas exploration and production are also down, the main cause of the bulging deficit, according to the Ministry of Finance, is a natural gas price that is predicted to average just $1.41 per thousand cubic feet (mmcf) in 2013, not the $2.52 per mmcf noted in the original forecast or the $2.12 per mmcf mentioned in private sector forecasts. Low natural gas prices are causing a decline in exploration and production activity in the province, translating to a royalty revenue shortfall expected to amount to $1.1 billion of a total $1.4 billion lost revenue from the natural resource sector over the next three years. “Flaws in their policies,” said Gwozd, suggesting that the blame for the impending financial woes should actually fall on the shoulders of the provincial government. “They have uniformly cut royalties across all [natural gas plays] in northeast B.C. from the plains to the deep foothills to the tight gas to the shale gas,” he added. The idea behind reducing royalty rates is to encourage activity, but Gwozd isn’t impressed with the B.C. government approach, which is actually a price-sensitive system where royalty rates change according to the price of natural gas. Gwozd noted that Ziff Energy offered a dozen recommendations for improving natural gas exploration and production activity in northeast B.C. in a publicly available report that was released almost ten years ago. “For the past half dozen years,” said Gwozd, “the B.C. government has been tinkering with the specific royalty credits. Some wells that are long and horizontal

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Although oil sands mining such as this Suncor Energy operation doesn’t use natural gas to the same degree as in situ operations, natural gas is still a high demand fuel for the oil sands industry. Strong links between the oil sands and natural gas industries in Canada could last for generations.

photO COURTESY OF SUNCOR ENERGY

get a specific credit, whereas others with a certain depth get a credit. “It was an administrative change based on all regions are equal, though each region is not,” he added. “Some regions in northeast B.C. are more expensive.” The negative example that Gwozd cites is deep foothills gas where the full-cycle cost is as much as $14.00 per mmcf. “Trimming the royalty by fifty cents or a dollar will only reduce the full cycle cost from $14.00 to $13.00,” said Gwozd. “Since the gas price is only $2.00 or $3.00, that’s not going to spur any activity.” It doesn’t benefit the provincial coffers either. “One-size policy does not work,” said Gwozd. “And the British Columbia leadership has shot themselves in their foot. Had they sought… expert advisors, the expert advisors would have quickly shown them that there’s different cost structures in the different areas. And, yes, their concept of spurring more development is technically correct, but you have to do it in different wedges. “The Montney may need a little bit of assistance,” he continued. “The Horn River [Basin] needs more. But the deep foothills is a lost cause. Wash your hands and give up. Activity’s going to go down.” Gwozd suggested that the government should have trained their eye to the bright future for natural gas in the province instead of focusing on the immediate troubles caused by low prices. “[B.C.] is going to have more natural gas flowing than the province of Alberta,” he said. “So, this gets into long-term strategy development for the province of B.C. “The current leadership that [is] giving these types of directions to the energy

groups have the wrong vision. The British Columbia vision should be: we are going to grow and we want to position ourselves to have the right staff to do the right analyses.” Royalty rates aren’t the only issue, however. Gwozd also points to a failure to promote “orderly development of infrastructure” in the natural gas producing regions of the province. “Look at the broad picture. How big should the pipes be? How big should the plants be?” said Gwozd. “The B.C. government has a clear financial interest in that activity because they have what’s called a B.C. Gas Cost Allowance (GCA),” he added. “When producers spend lots of money on facilities and process the gas, they’re not processing the B.C. gas portion for free – the royalty portion.” The producers are given a credit by the government when they process that gas. “But if there’s too many plants or plants that are too underutilized, the producers are capturing an incremental benefit that the B.C. government could get back if they were to manage it properly,” said Gwozd, remarking that better analysis of industry conditions could have allowed the Province to increase revenues simply by altering energy policies. “But they do not have adequate staff or staff with the depth of knowledge,” he continued. “Because these ideas are new to them and they’re just growing into this area. “In my professional opinion,” he said, “they need to hire key advisors that understand that area from a cost structure [perspective] and develop appropriate policies that industry would be receptive to, with the aim to increase the overall revenue that the B.C. government gets.

“Increase revenue rather than cut costs.” However, the Ministry of Finance has indicated that they intend to make up the $241 million shortfall in 2012-13, the $389 million shortfall in 2013-14 and the $483 million shortfall in 2014-15 by cutting discretionary spending, freezing salaries for public sector management and freezing public service hiring. “We are committed to delivering a balanced budget,” said Finance Minister Michael de Jong in a September 13 news release. “That’s why we are taking additional steps to exercise greater fiscal restraint. This government respects taxpayers and we will not spend more of their money than we receive. We are looking for savings inside government, while protecting the programs and services B.C. families rely on.” “They’re doing it with the wrong strategy,” said Gwozd. It all comes down to a misinterpretation of supply and demand dynamics, not to mention a lingering uncertainty that surrounds the LNG industry just as it surrounds the heavy oil pipeline proposals, although not to the same degree. “Western Canada in the future will be dominated with natural gas production out of British Columbia, not out of Alberta,” said Gwozd. Predicting a daily natural gas production of 13.0 bcf in B.C. in 2020, Gwozd noted that British Columbians would be correct to say the province doesn’t need oil sands projects if LNG export projects consume as much as 9.0 bcf per day, which is a possibility. The question, however, is concerning the other possibility that LNG projects could only consume as much as 3.0 bcf per day. “What’s going to happen to the other five or six or seven bcf of gas?” Gwozd wondered. Still, Gwozd doesn’t mean to suggest that oil sands demand for natural gas is necessarily vital to the future of the natural gas industry in B.C. “The natural gas demand in North America is about 80 bcf a day and our models have it growing to about 90 bcf by 2020,” said Gwozd. If oil pipelines such as Northern Gateway and Keystone XL weren’t constructed, the natural gas industry would only be losing 1.0 bcf per day of a 90 bcf per day natural gas demand across North America. “It’s not a big amount of gas demand,” Gwozd continued. The problem is that northeast B.C. natural gas – particularly the resource coming from the Horn River Basin – is far from other domestic markets such as eastern Canada. Eastern U.S. natural gas can be transported to eastern Canada at a lower cost than northeast B.C. natural gas, which is an issue for the producers in the region. “Any local markets would be viewed as a benefit for western Canada producers,” said Gwozd. “It’s all kind of convenient,” he added. The inconvenience is a tight labour pool that could cause difficulties as petroleum companies try to simultaneously launch their oil pipelines and LNG

PIPELINE NEWS NORTH •

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export facilities over the next ten years. Adding to the issue is that the oil and gas industry could be competing for skilled labour with coal and mineral mines, not to mention BC Hydro’s Site C project. Other industries are also taking part in that competition. Rio Tinto Alcan started an aggressive recruiting campaign on September 7 to attract skilled workers from across western Canada to complete the expansion of their Kitimat smelter. The company requires 1,500 workers for the job. “The oil sands projects are going to go full steam of head, the LNG projects are going to go full steam ahead, northern projects going to go full steam ahead, all this tight oil and tight gas is going to go full steam ahead – who is going to do all the work?” said Gwozd, citing concerns previously noted by the Petroleum Human Resources Council. “The linkage, in my mind, between oil sands projects and northeast B.C. could be the same labour issue,” he continued. “If you need to build pipes out of northeast B.C. and you need to build pipes for the oil systems, who gets who first?” Gwozd joked that it could turn into a rendition of the Abbot and Costello’s famous “Who’s on first?” routine. “If the oil sands get Who first, then the LNG projects will get Somebody second,” he said. “And therefore there could be a delay just due to labour issues.” However, Gwozd isn’t as concerned about the labour issue as others seem to be, largely because of the declining number of wells drilled in western Canada. “The natural gas industry used to drill 18,000 wells a year,” said Gwozd. “This year, maybe they drilled 2,000. People say, ‘Well, I know, but they’re still maintaining production.’ I know, but for 2,000 wells, you need less road clearing crews, you need less gas gathering crews, because you just put it in one gas gathering system rather than seven. We generally have less activity. Less activity frees up staff. “As long as you’re bilingual in work duties, you’re okay,” he continued, alluding to the transferability of skills that allows labour mobility. “You can switch between jobs just as effectively as a farmer can switch from growing wheat to growing corn,” he added. Ultimately, the potential for oil and gas production in western Canada is immense. “We have a very strong resource base for both oil,” said Stringham. “And when I say oil, I mean both tight oil and oil sands that are poised to grow into the future. “We also have lots of natural gas,” he continued. “A very strong resource base in British Columbia in particular that is looking for a market. And a key market growth that we see for natural gas is being used [in the] oil sands… to generate the steam that’s required there. And, potentially, could be used in other things like power generation and natural gas transportation. “But those are far more distant and still are competing with other fuels, where, in the oil sands, it’s really just the demand growth that’s being satisfied.”


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SEPTEMBER 28, 2012

special feature

FRACKING EARTHQUAKES

No risk to public or environment from seismic activity caused by hydraulic fracturing says OGC james waterman Pipeline News North

the surface. “I think it’s actually really helpful, positive information,” said Pryce. “Because A link exists between hydraulic fracturwhat it essentially says is that… of the ing and seismic activity in the Horn River 8,000 frack jobs that we’ve done, 272… Basin shale gas play of northeast British show some correlation. But the correlaColumbia, but the magnitude of the astion speaks to very low magnitude events. sociated earthquakes doesn’t pose a risk So, everything is below 3.8. Almost to the public or the environment. everything is below much lower numbers That was the conclusion of a BC Oil than that.” and Gas Commission (OGC) investiga“None of the events caused any threat tion to examine the causes of 272 seismic or hazard to public safety or the environevents that were recorded in that region ment, which we wanted to ensure as the between April, 2009 and December, 2011. regulator,” said Paulson, emphasizing “We initiated the investigation when that all the anomalous seismic events in NRCan (Natural Resources Canada) con- question took place in a small and remote tacted us to let us know there was a clussection of the Horn River Basin. ter of anomalous seismic events in a part “They haven’t been detected anywhere of the Horn River Basin that was normally else in northeastern B.C. where we have without any seismicity,” said Ken Paulson, multiple activities going on continuously,” chief operating officer at the OGC. he continued. “So, there’s a combination “So, we wanted to take a look at that,” of unique factors at this particular location he continued, explaining that the motivathat seem to be contributing to the intion was to determine if there was a link duced seismicity that we have up there.” between natural gas industry operations The link between fracturing and seismic in the area and seismic activity. activity was determined through a review “And we wanted to make sure that our of fracturing and completions in the Etsho regulatory framework adequately proarea where the majority of the events tected public safety and the environment,” occurred, additional information from six he added. operators working in the area provided NRCan recorded 38 of the tremors through formal information requests in the region with their seismograph and a survey of relevant literature about stations. A dense seismograph array induced seismic events in oil and natural deployed by a natural gas producer in the gas producing regions in Ohio, Oklahoma Etsho area detected 216 events and 18 and England. events were recorded by a similar array It was learned that 27 of the events in in the Kiwigana area. It was determined the Etsho area occurred within a 10-kilothrough the study that all the events were metre radius that was also home to seven induced quakes resulting from the movedrilling pads. Similarly, the seven seismic ment of pre-existing faults in the rock and events recorded in the Tattoo area northcaused by fluid injection during hydraulic west of Etsho occurred within the same fracturing operations. 10-kilometre radius as a pair of drilling “We’ve been looking forward to the repads. Fracturing was underway at one of lease of this report those pads at a for quite a while,” time when seismic said David Pryce, activity took place. vice president of “There’s a lot “We wanted to make operations with of evidence out the Canadian there that points Association of Pe- sure that our regulatory to a possible troleum Producers linkage between framework adequately fluid injection and (CAPP). “And the imporinduced seismictant message… in protected public safety ity,” said Paulson, the report is that, noting that the of those events, has usually and the environment.” focus there’s been no been injection into harm to people, disposal wells. no harm to strucInjection of – Ken Paulson, OGC tures, there’s no fluids into disdamage to the posal wells has environment,” he been linked to added. seismic events in Ohio, but that was All events included in the study had not the case with the series of events in magnitudes between 2.2 and 3.8 on the the Horn River Basin, according to the Richter scale. According to NRCan data, OGC, even though there were three opthe 3.8 magnitude quake of May 19, 2011 erating disposal wells at Etsho and one was the only one of those tremors felt at operating disposal well at Tattoo during

the study period. is based on data provided by industry.” “To date, there haven’t really been any “With any investigation,” said Paulstudies that draw definitive links between son, discussing material provided by fluid injection during hydraulic fracturing the natural gas producers through the and induced seismicity at low levels,” OGC’s information requests, “what we’re added Paulson. always looking for is information that Although the OGC study has promight help us to better understand what vided a degree of clarity on that matter, happened, understand what the effects uncertainty still exists concerning which of what happened are or were or may factor is the greatest contributing factor to have been, and also lead us to drawing induced seismiciconclusions and ty: proximity of the making recomnatural gas well mendations… as “We need to have a to the pre-existing to what we might fault or the rate at do going forward if which fluids are better understanding there is a probbeing injected into lem. And how we the formation. mitigate it of where and when the might “There was no and effectively conclusive findit, ensurearthquakes can occur.” manage ing there,” said ing protection of Paulson. the public and “There’s indicaprotection of the – Amanda Bustin, UBC tions that… where environment going you’re starting to forward. So, those see induced seismicity, if you lower the information requests are a normal part of pump rate, then you’ll lower the activity,” every investigation that we do. he continued, noting that that isn’t true for “We became aware of the events,” he every location where seismicity has been continued. “We went out to industry with recorded. the information requests to get all the “There were faults where there was information we could for the reasons I active hydraulic fracturing taking place already said. And industry was very forthwhere there was no induced seismicity,” coming with providing us with the data, added Paulson. “So, there’s a combinamaterials, some proprietary information. tion of factors… that contribute to when “Hydraulic fracturing – the whole you’re going to have some induced purpose is to induce these micro-seismic seismicity.” events and create these small cracks and The results of the study were subject to fissures in the shale formation so that peer review by a pair of researchers from you can get the gas out of it. So, microthe University of British Columbia, Marc seismic monitoring data shows us lots of and Amanda Bustin, who are actively things, including where there may be any investigating links between hydraulic movement relative to the fracking operafracturing and induced seismicity. tion. In this case, it was very useful to us in “We’re doing a research project on inshowing that the fractures associated with duced seismicity in the Horn River Basin,” these events that we studied in the Horn said Marc. were contained to the target formation. Amanda is an engineer with a back“There is very obvious containment withground in tectonics, while Marc is a in the target formation of the fractures.” geologist who was involved in investiMarc suggested that one of the most gating the links between fracturing and important results of the study is showing earthquakes in England, one of the cases to the public that fracturing does induce studied by the OGC. seismicity, but that the resulting tremors “The big thing is the public percepare very minor. tion,” said Marc, discussing the value of “Technical people know that, when we independent third party participation in fracture rocks, in fact, we’re breaking such a study. the rocks and we create seismicity,” he “Oil companies aren’t always seen in said. “It’s at a very micro-scale. And, of the best light,” he continued. “Unfairly, in course, we use that information routinemy opinion, but that surely is the case. ly to monitor what we’re actually doing And university people, rightly or wrongly, in the rocks. We do that because we are thought to be a little bit more indeneed to understand which rocks we’re pendent thinkers or unbiased in their fracturing.” opinions. Public knowledge and public perception “[But] that report wouldn’t have been also played a role in Questerre Energy’s possible if industry hadn’t… undertaken a decision to publish a fact sheet on hystudy, which they didn’t have to underdraulic fracturing and earthquakes, which take, and [did] it because they felt it was was released on August 30, the same day necessary. So, even that study, of course, the OGC issued their report.


SEPTEMBER 28, 2012

“It’s one of the arguments … that the opponents [to hydraulic fracturing] in Quebec always bring up,” said Jovette Jolicoeur, technical assistant to the vice president of engineering at Questerre. “It’s just to show that we’re very aware of things that could happen,” she continued. “And we have looked at the area. We have done our research. We have looked around at other people’s research. This is what we’ve found. “It’s just to support the fact that it’s a good thing to [produce] shale gas in Quebec.” Jovette also noted that there aren’t many similarities between Quebec and B.C. when it comes to seismic potential. “In Quebec, it’s a lot older,” she said. “So, there’s very little seismic activity. And the faults are really, really old and there’s not a whole lot of movement. “In Quebec, it’s very stable,” she concluded. Among the recommendations published in the OGC report was increasing and improving monitoring of seismic activity in the Horn River Basin. “We need to have a better understanding of where and when the earthquakes can occur,” said Amanda. “I think that requires some modeling,” she continued. “And we need some specific data in order to do that modeling. And that allows us to have a better understanding of what’s happening and being to able to mitigate wells that are in areas that have the potential to induce seismicity, so we know to avoid those areas, as well as having better ideas on the injection rates and volumes that are permissible in different areas.” “From a practical perspective and from, obviously, a public perception perspective, there’s two things we want to do,” Marc added. “We want to prevent seismicity that could potentially be a hazard. If we are fracking wells in an area where there’s potential for seismicity and some seismicity occurs, how do we mitigate the seismicity so it doesn’t become a seismic hazard. Although it has never, ever happened to date, there’s certainly… the public perception that… you may end up injecting fluids into aquifers.” “By looking at the microseismic data, they were able to conclusively state that we’re not fracturing into the upper-lying layers, which provides good proof that we’re not affecting the aquifers at all,” said Amanda. Paulson noted that the improved monitoring could also benefit the producers when it comes to their exploration and production activities. “I think it again gives us a better knowledge of the geological structures that we’re targeting,” said Paulson. “Where the shales are.” Additionally, it may not be ideal to perform fracturing where seismicity is likely to occur from a natural gas production standpoint, particularly if quakes are related to the horizontal wellbore deformation noted in a few of the wells in the study. There is no proven link between seismicity and wellbore deformation, however.

“Some of these faults were at what we call close to critical stress,” said Paulson. “And that means they’re close to being moving. And these are very small, isolated faults. And when they move, there could be minor movement of the casing as well in the horizontal portion. And if you have horizontal deformation, then you could have a potential cost [for] repair.” Pryce remarked that CAPP will be watching the wellbore deformation problem very carefully to see if there is a link to seismicity. “The issue for us will be that’s the part of the casing where the production actually occurs and so we need to make sure that we’re able to flow the fluids through that part of the wellbore,” said Pryce. “That sort of pressure on the casing happens down in the production zone,” he continued. “It doesn’t happen in the upper wellbore. And so the important thing for us is that demonstrates that that particular part of the wellbore – the upper part – has its integrity. Because that’s the wellbore part that is intended to isolate the whole … production reservoir from the upper aquifer areas where the freshwater occurs. “I think that gives us comfort that we still have the integrity there.” CAPP is using the results of the study to design a set of operating guidelines for natural gas producers concerning fracturing and seismicity that they plan to release this fall. “Key opportunities, as we see it, is doing our work upfront, doing our geological assessment, identifying where there’s pre-existing faults so that we understand where they are,” said Pryce. “That can help us in the planning of our program designs, our well site selections. And the other thing that I think is probably going to be relevant is: what can we do with respect to pumping pressures that manage the potential risks? “When we look at some of the learnings from the report, it appears that if we are going to be operating in pre-existing fault circumstances, we will want to look at [it] closely and watch our pumping pressures.” CAPP is participating in the new monitoring program as well, partly by providing $500,000, which is being matched by Geoscience BC, for six new seismograph stations to be installed in northeast B.C. this fall that will collect data for the next five years. The Ministry of Energy and Mines will also be involved, while much of the technical work will be donated by NRCan and the OGC. “They’re state of the art,” Carlos Salas, vice president of oil and gas with Geoscience BC, said of the seismograph stations. “We collect the data and we put it up on our webpage,” he continued. “And then everybody can take that data and make the conclusions they think is correct.” The goal is to establish a baseline for seismic activity in the northeast. “Make sure we understand where it’s occurring and why it’s occurring,” said Salas.

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Map of Horn River Basin earthquakes included in the OGC study that determined a link exists between seismic activity and hydraulic fracturing.

IMAGE COURTESY OF BC OIL AND GAS COMMISSION

“The first thing is we have to make sure we understand the baseline of seismicity,” he continued. “Like how many of these events are occurring and where are they occurring and why.” The hope is that the monitoring will also help answer some of the bigger questions, including whether or not fracturing is altering the geology of the region in such a way that it could lead to more severe quakes in the future. “This is what we’re trying to figure out,” said Salas. “What we need is to get that data to actually make sure that we understand. Because, for example, one of the areas around that Tattoo-Maxhamish area… did have those higher seismicity events.” The program could also put an end to the proximity versus pump rate debate, as well as provide a map of spots to avoid fracturing, if possible. “We’re probably leading the charge here in the world, really, because not too many people have started doing this,” said Salas. “There’s a very important component called the geomechanics of the rock physics,” he added. It deals with a phenomenon known as effective stress. “In certain parts of the earth, what happens is you get higher effective stresses,” said Salas. “And in other places, you get less effective stress. So, if it’s a high ef-

fective stress, what happens is, if you try to crack the rock there, it takes a lot more energy to crack the rock. So, when you do crack the rock, you’re more likely to cause some kind of seismicity, whereas if the rock is low stress, it’s easier. It’s like cutting butter.” “I think that the most important recommendation that came out of it is to be proactive,” said Marc. “Have the industry provide the OGC with data so they can look at it. They’re not necessarily going to release it to the public, but at least they’re going to be able to monitor what’s going on closely by requesting the industry turnover, for example, the microseismic data from the frack operations. “The OGC’s being very proactive in saying, ‘Okay, we recognize there’s currently no problem, but we want to stay on top of it to make sure there is no problem.’” Indeed, there could be no problem at all. “British Columbia is an active province for shale gas production,” said Paulson. “We have an awful lot of completions operations and hydraulic fracturing operations going on. And have had for a number of years now. We’ve only seen this induced seismicity at a measurable level in this one area in the Horn River Basin. “We haven’t seen it anywhere else.”


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special feature

good company

Energy Conference brings industry-community relationship into focus

Dawson Creek Mayor Mike Bernier raises a glass of drinking water to Shell Canada for their part in making the Dawson Creek Reclaimed Water Project a reality. That partnership was the sort of industry-community relationship being highlighted during the 2012 Dawson Creek Energy Conference.

JAMES WATERMAN photO

james waterman Pipeline News North Water reclamation plants and natural gas vehicles (NGVs) may not seem to have much in common, but they were sharing the stage on the last day of the 2012 Dawson Creek Energy Conference on Friday, September 21. The theme of the discussion was the relationship between energy sector companies and the communities where they work, the promise of which was demonstrated by a plan to bring NGVs to Dawson Creek and an explanation of the partnership between the City and Shell Canada that has resulted in the new Dawson Creek Reclaimed Water Project. “This is not a new thing,” said Matthew MacWilliam, the energy manager for the City of Dawson Creek, adding that there are presently over 15 million NGVs in over 30 countries across the world. MacWilliam suggested that compressed natural gas (CNG) or liquefied natural gas (LNG) as transportation fuel could be a good fit for a Dawson Creek municipal vehicle fleet that generated 530,000 tonnes of carbon dioxide (CO2) emissions by burning 225,000 litres of gasoline and diesel at a cost of over $200,000 in 2010 alone, particularly when the city is surrounded by natural gas in the prolific Montney tight gas play. Forecasts suggest that natural gas, which is currently priced quite low, will continue to be much less expensive than oil over the next fifteen to twenty years. “It’s a cleaner burning fuel,” said MacWilliam, noting that there are also “benefits for the actual engines.” Heavier vehicles are leading the way for conversion to natural gas and Waste Management is one of those pioneering companies, presently using over a thousand vehicles across their operations. MacWilliam believes there is potential for Waste Management to convert to natural gas in Dawson Creek as well.

“Is this the future?” he said. “It’s starting to look that way.” However, there are significant obstacles to large-scale adoption in terms of the lack of refueling infrastructure in many locations and the considerable cost of converting gasoline or diesel vehicles to natural gas. Conversion of a truck can cost between $10,000 and $12,000, but a study conducted in Saskatchewan has shown that that cost can be recovered in just 40,000 to 50,000 kilometres because of the fuel cost savings. Pacific Northern Gas (PNG) is trying to alleviate the difficulties associated with conversion to NGVs with a plan to build natural gas cardlock stations in one or two communities in B.C. “A new business for PNG,” said manager of financial planning and business development Peter Schriber. The company is working on a pilot project that should see a new CNG fuelling station in Dawson Creek in early 2013 and a second station in Fort St. John by the end of the same year. PNG would be looking for an interested third party to eventually take over those operations. “We don’t necessarily want to be in the business of running gas stations,” said Schriber. The discussion of companies and communities began not with the consumption of natural gas, but with one of the big issues related to how it is extracted from the ground in the Dawson Creek area: the use of water for hydraulic fracturing. Water has been an interesting topic in Dawson Creek in recent years. Mayor Mike Bernier pointed out that the community went from a one-in-40 year drought in 2010 to a one-in-100 year flood last summer. This summer has been another one-in-40 year drought. “At the same time, we’re seeing unprecedented growth,” said Bernier, referring to natural gas exploration and production in the region, as well as the associated rise in fracturing activity. City council has adopted a policy whereby the oil and

gas industry is the last of all users to have their potable water supply shut off in the event that a water shortage is severe enough to necessitate imposing restrictions on potable water use, primarily because of the positive economic impacts the oil and gas industry brings to the region. So, the municipal government was looking for a way to allow industry to continue to use water for their operations, as well as let the City use water for dust suppression on roads and watering flower baskets and sports fields, if a drought it so extreme as to cause Stage 4 water restrictions, as was the case this summer. During Stage 4 restrictions, even industry is prohibited from using potable water from the city reservoir. According to Bernier, it was only a “tongue in cheek” suggestion to have industry use the city’s sewage for fracturing, but the idea quickly took flight. “We think this will work, but we need somebody else to work with us,” said Bernier, remembering the early days of the plan. The City issued a Request for Proposal (RFP) and Shell Canada stepped forward. “It actually exceeded, as a council, what we were hoping to see,” Bernier said of the Shell proposal. The end result is a sewage treatment system that produces water about ten times cleaner than Dawson Creek’s potable water source, the Kiskatinaw River. As a reward for building the water plant, Shell is able to take up to 3,400 cubic metres of water per day for their Groundbirch natural gas operations. The City holds onto about 800 cubic metres per day, which they will be using for their own purposes when the permits are in place. “The City actually doesn’t use a lot of water,” said Bernier, adding that there is a plan on the table to build pipelines from the water treatment facility to the nearby sports fields for watering that grass. Dawson Creek can also generate up to $2 million per year in revenue by selling portions of that water to other industry players, although the price of that water is yet to be determined. “One of my proudest days at Shell,” said Groundbirch operations manager Rej Tetrault, speaking of the day the plant was finally unveiled. Shell has been in Groundbirch for about five years and is currently producing about 200 million cubic feet (mmcf) of natural gas from 300 wells. They expect to be active at that location for over 40 years. “They’ll continue producing for a very long time,” Tetrault said of those wells. That requires water. “These wells will not flow if you don’t hydraulic fracture them,” he added, noting that fracturing requires about 7000 cubic metres of water per well. However, not all of that water must be met by outside sources such as surface water or the reclaimed water from the treatment facility. About 30 to 40 per cent of the water used for fracturing flows back to the surface within the first few months. Additional water returns to surface after that point. Shell already recycled a considerable amount of that water prior to building the water plant. The reclaimed water only ensures that they will not have to look to surface water or potable water to meet any of their fracturing needs in the future. “We generate a water supply and demand forecast,” said Tetrault, explaining how they can predict when the reclaimed water will be necessary to meet shortfalls in recycled water supply. “Now we actually have a team of people that do noth-


SEPTEMBER 28, 2012

ing but forecast water,” he added. By scheduling fracturing efficiently, Shell is also able to minimize the amount of reclaimed water they need to use, which can benefit Dawson Creek in terms of what they have available for their own use and for sale. Maximizing those benefits will require the construction of storage facilities so that surplus water isn’t simply dumped into the creek. After the presentation, Bernier suggested that events such as the energy conference can help foster the sorts of relationships between companies and communities that can yield such positive impacts for both parties.

“We need to continue in this region working with our companies and having those partnerships because they’re here,” he said. “The resource is here. And, as citizens, we want to make sure that we engage with the companies as best as possible… to make sure that any concerns that we have are addressed to the companies. “They want to be able to communicate back with us,” he added. Bernier noted that he conference was also a good opportunity to learn about the companies and how they are coping with low natural gas prices. “Sometimes, we forget how busy it really is here,” said Bernier. “Right now,

it’s seems it’s a little slower with $2.00 gas. So, it’s really interesting to hear from most of the companies how important it is that they are still here in this area. “With the liquids in the gas, they’re still working here in the Montney play and the Dawson Creek area,” he continued. “It’s still… one of the biggest assets.” Bernier also learned a thing or two about his community, including the fact that many residents of the area still have lingering concerns about the industry. “How do we work better with the companies?” he asked rhetorically. “And we’re always trying to strive for that. So, again, it’s trying to have everybody in the same room so we can talk about it.”

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After all, the industry is going to be part of Dawson Creek life for decades to come. “It’s not just a boom right now,” said Bernier. “Everything we’ve heard through this conference is they’re going to be here drilling and working for quite a few decades. From a community perspective, we have to take that into consideration when we’re doing our planning, when we’re making decisions at city hall for the community when it comes to building infrastructure to sustain the industry and sustain the growth of the community. “We haven’t reached a plateau yet, so we have to continue planning.”

Coleman announces new round of royalty credits for B.C. industry

Minister of Energy, Mines and Natural Gas Rich Coleman announced $120 million in royalty reductions for infrastructure projects at the Dawson Creek Energy Conference on Thursday, September 20.

PHOTO BY JAMES WATERMAN

STAFF REPORTER Pipeline News North Rich Coleman didn’t simply drop by the 2012 Dawson Creek Energy Conference on Thursday, September 20 to grab lunch, say a few kind words about the petroleum sector and proclaim Oil and Gas Week in British Columbia. The Minister of Energy, Mines and Natural Gas also had money on his mind, announcing the eleventh installment of the Infrastructure Royalty Credit Program,

which consists of $120 million in royalty relief to encourage new infrastructure projects in the northeast corner of the province. “Our Infrastructure Royalty Credit Program will result in new roads to help industry access areas while also supporting pipeline construction to move B.C.’s natural gas out of the field and to the marketplace,” said Coleman. Eleven companies have been awarded royalty reductions to support 21 projects near Fort Nelson, Fort St. John and

Dawson Creek, which are expected to aid the development of the liquid natural gas (LNG) industry in B.C., as well as create over 1,600 jobs. “The Infrastructure Royalty Program will create service sector opportunities and support long-term road and pipeline needs for job creation,” said Peace River North MLA Pat Pimm. The Province expects that these royalty reductions will mean $300 million in royalty revenues over the next five years. Coleman also announced a new $1

million investment by BC Hydro for trades training programs at Northern Lights College (NLC). “Our Jobs Plan is focused on creating family-supporting jobs across the province,” said Coleman, “and skills training is a key element.” “We know there are going to be a lot of jobs to fill in the coming years,” added Pimm, “and these are just the type of initiatives we need.” “For anyone looking to enroll in a college program, the related costs are always a significant consideration,” said NLC’s president and CEO Laurie Rancourt. “We know this funding from BC Hydro will help make postsecondary education and training a viable alternative for more students in northern B.C.,” she added. The funding will actually go to the Northern Lights College Foundation for student bursaries. Half of that amount will be devoted to bursaries for Aboriginal students. “Funding to support those students who might not otherwise have access to postsecondary education is just another example of how BC Hydro is supporting local communities,” said Pimm. “We have a major presence in the Peace region,” added Susan Yurkovich, executive vice president for BC Hydro’s Site C project. “And we understand the need for a skilled workforce. Our funding is intended to increase participation in trades training, which benefits students, industry and local and Aboriginal communities.”

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special feature

VISION QUEST

Energy Conference crowd asked to offer their view of a sustainable future james waterman Pipeline News North Just as 2012 Dawson Creek Energy Conference delegates were preparing talk about the achievements of their recent past on the morning of September 19, they were suddenly given the task of considering the future. Following a speech in which she discussed her lifetime of globetrotting adventures and the associated lessons in sustainability, Tina Olivero, the found and publisher of Oil and Gas Magazine, asked the audience to create vision boards to present their hopes and dreams for the future. “We’ve been working with vision boards in our company for the last two years,” Olivero told Pipeline News North. “And everybody in our company has a vision and intention for themselves, not just at work, but also at home. So, what we do is we operate vision boards and that becomes like our goal-setting strategy. But it’s with images. So, it’s visual.” Olivero and her staff then map that vision back to the present day to determine the actions that must be taken now. “It’s a matter of designing and implementing it. And it works. It’s very powerful,” she said. Olivero believes that environment, whether that be the home or the workplace, is a function of intentions. “Architect your sustainable environment,” she told the energy conference crowd, emphasizing the role of creativity in achieving a sustainable future, not just settling for the status quo. “What we tolerate is what we get every time,” she said. Rej Tetrault, operations manager for Shell Canada’s Groundbirch natural gas project near Dawson Creek, believes that their new offices in Fort St. John are an example of what Olivero calls “mastering your environment.” “It helps us layout a bit of a culture … on what we expect and how we expect to work,” said Tetrault. “A culture of fitness, because we want our employees to be fit. We want a clean environment. That would be air or clean carpets. So, we want a clean, healthy environment so that we can encourage our employees to

Andy Ackerman of Myriad Consulting and Jay Morrison of Spectra Energy help each other out during the vision board exercise.

JAMES WATERMAN photO

Shell Canada’s Rej Tetrault hard at work creating his vision for a sustainable future during a sustainability presentation given by Oil and Gas Magazine founder Tina Olivero at the Dawson Creek Energy Conference.

JAMES WATERMAN photO

be healthy and fit, which is why we also have the fitness facility down on the main floor.” Tetrault also believes the building itself is a positive step toward a sustainable future. “When I think about our office, I look to LEED (Leadership in Energy and Environmental Design) certification,” he said. “It’s a LEED Silver building, which means that it utilizes very little energy by definition. And our employees feel proud that they’re part of an office environment that, for instance, in the wintertime, uses very little energy to heat the building, because it’s got very good insulation value.” Such concerns and initiatives are what Tetrault had in mind when he introduced Olivero to the conference crowd, indicating that the entrepreneur shares many of Shell’s values. “I think we align along two points,” said Tetrault. “She really believes that we need to be thinking about what our energy mix is,” he explained. “Is it one energy source? Is it multiple energy sources? And what are they? And what do we need to do to set ourselves up to get there? “The other piece where we align is around sustainably focusing on developing our energy resources. And that’s one where I think we’re quite proud, for instance, of our Dawson Creek Reclaimed Water Project. … She used the words innovative and creative. And that fits the bill when you’re looking for some innovative projects. “We need to foster an environment that encourages our people, whether it’s my children or the folks that I work with, to be innovative and creative and help encourage more of these ideas.” Tetrault didn’t focus on work with his own vision board, but chose to look toward his family and his community. “It’s more along the lines of getting back to our roots,” he said, adding that it is important to him to teach his children about the origins of the energy they

use every day. “It’s similar to foods,” he continued. “My boys don’t know where their meat comes from. They just know that it comes from a grocery store. And we all know that’s not where your meat comes from. “And I want to do the same for energy. Where does the energy come from? Do you have a really good respect and appreciation? I think we take it for granted being that we’re in a very fortunate situation here to be living in Canada, which is a very, very good country. It affords us these particular luxuries – I define them as luxuries. And I think we take that for granted.” Tetrault looks to Olivero’s idea of combining the old world and the new world to create a better world. “It really struck a chord to me that my role is to actually do more teaching on the old,” he said. “We’re not concentrating enough [on] that. I think we’re always constantly looking for the new. “The other piece on my vision board is I still think that we’re too wasteful,” he continued. “I still go to cities at night and I see office buildings… lit up. And I know that not all of those lights need to be on. “She asked [us to] reflect on what do you tolerate. I think we’re still tolerating waste. And we need to cut that out.” Those comments would likely be music to Olivero’s ears. “My intention was to plant seeds for sustainability because we tend to talk about sustainability as a concept,” she said. “Everybody has the opportunity to actually create a sustainable solution,” she continued. “Until we take it back to the individual as opposed to the leadership, we limit ourselves by only having the leadership involved. But when everybody’s involved, then we have a sustainable, creative force working towards sustainability. “That’s the difference.”


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Most incidents occur on old pipelines Daily Oil Bulletin

Canada had 1,200 pipeline incidents since the 1950s, but most occurred before 1971, a conference heard on Monday, September 24. A pipeline incident is defined as a failure such as a leak or rupture. “The data [in the archives of the National Energy Board, which was formed in 1959] wasn’t great, but about 275 of those 1,200 were related to seam welds,” said Joe Paviglianiti, an engineering technical leader on the NEB’s integrity management team. Of the 275 seam-weld-related incidents, 185 happened during pipeline operations and 59 during commissioning tests, Paviglianiti told a session of the

2012 International Pipeline Conference in Calgary. He said it was unclear from the archived data whether the rest occurred during operations or during hydro testing. Since 1987 -- when the data quality has been much better -- there were 30 seam weld incidents involving leaks or ruptures. More than three-quarters of those occurred in pre-1970 pipe, Paviglianiti said. Since 1991 Canada had 37 pipeline ruptures -- six of which were related to seam welds. Five of those six seamweld-related ruptures occurred on pipe manufactured before 1970, according to NEB figures. Of the seam weld incidents that occurred since 1987, 70 per cent were due

to cracking and 30 per cent were attributed to pinholes. The NEB requires pipeline operators to have a pipeline integrity management program to prevent such incidents. “It doesn’t single out seam welds. [But] it does say you have to manage all your hazards -- and we would consider seam welds as one hazard,” Paviglianiti said. “So you have to look at all potential hazards [such as those associated with pre-1970s pipe] and monitor and mitigate any of those hazards.” The NEB conducts inspections and audits to verify pipeline operators are complying with those requirements. As a regulator, the NEB expects companies to “anticipate, prevent, manage and mitigate potentially dangerous condi-

tions. ... We hold companies accountable for the integrity of their pipelines -- regardless of vintage,” Paviglianiti noted. He said that with proper maintenance older pipelines can be as safe as newer ones. “Basically we expect companies to manage all their pipelines to reduce the probability of leaks and ruptures regardless of vintage.” Scott Ironside, manager of facilities integrity and operational risk management at Enbridge Pipelines Inc., concurred. “Utilization of the appropriate technologies really does allow the safe operation of pre-1970s pipelines,” Ironside told the conference. “And continued improvement in the reliability of these technologies will ensure that the current trend of reduced failures across the industry can continue.”

‘Hardwiring’ along LNG value chain attractive to Asian buyers Daily Oil Bulletin LNG buyers in Asia are more comfortable with the structure of proposed export plants in Western Canada whose value chains include upstream and midstream development than with the United States Gulf model in which they simply acquire export capacity, a natural gas conference heard Thursday. There are a growing number of export proposals in North America designed to take advantage of the pricing arbitrage in both Prince Rupert and Kitimat on the British Columbia North Coast and in Oregon, as well as along the United States Gulf Coast. “There’s a huge contrast between the Gulf Coast LNG projects and the Western Canadian LNG projects,” Edward Kelly, vice-president, North American gas consulting with IHS Global Consulting, told an Insight Info northeast B.C. natural gas summit. Western Canada’s proposed LNG export plants are ‘hardwired’ along the entire value chain: from the producing area to the pipe and into the liquefaction facility. The LNG is then shipped to Asia. “It’s all built new; the wells are new, the pipes are new, the liquefaction facilities are new,” Kelly said. “As extensive as that is, that is much more familiar and that’s a much more comfortable structure to the Asian buyers than is going to a U.S. Gulf Coast LNG facility and simply taking a

position in the export capacity. “There are trading oriented Asian buyers that are taking positions in U.S. Gulf Coast LNG facilities,” he added. “The main advantage is the U.S. Gulf Coast can happen earlier. “[Buyers] can get their gas earlier at a lower initial cost and lower all-in capital costs, or they can hardwire an entire value chain, know that it’s there [but with] more expensive all-in costs, more than likely, out of Western Canada,” Kelly said. “It’ll be interesting to see [what happens].” Other factors are at play as well. For example, in the LNG marketplace, Canada is considered a lower political risk country compared to the U.S. “The U.S. is in a pool of countries that is considered moderate political risk,” Kelly said. “In the global LNG marketplace, Australia and Canada are considered low political risk countries. Again, that’s another factor that goes into the equation from an LNG buyers’ perspective.” In the Gulf, Cheniere Energy’s Sabine Pass project in Louisiana announced the sale to its fourth major customer, Korea Gas, in January following announced sales to BG, GAIL and Gas Natural Fenosa. Blackstone has invested US$2 billion in equity in Sabine, making it likely to be the first U.S. LNG export project online around 2015/16. The Kitimat LNG project proposed by Apache Canada Ltd., Encana Corpora-

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tion and EOG Resources Inc. is expected to come online sometime around 2017. “Our call is two to three U.S. Gulf Coast facilities and one Western Canadian facility, but that’s a moving target,” Kelly said. Meanwhile, the Obama administration this week once again delayed the release of a report on expanding LNG exports, likely pushing beyond the election a decision on the potentially contentious issue of sending U.S. gas abroad. Commissioned by the Energy Department to examine the economic impact of LNG exports, the report by an unidentified third-party contractor is now expected to be completed by the end of the year. Rob Spitzer, vice-president, Canada exploration, new ventures with Apache Canada, pointed out that Horn River drilling activity will be challenged in 2013 at current gas prices. “Unfortunately, Horn is dry, there’s not any liquids in the Horn, and that causes some significant challenges,” he said. “What you’ll see in 2013, likely, is that the activity is going to be lower. “There’s really only two possible areas to get better value for your gas. One is that you cross your fingers and the North American gas price goes up,” he said. “The other is to basically have an LNG price that is indexed to oil and ship it to Asia. “If you look at the Horn, this activity ... won’t go up in the near-term without

some assistance from either one of those two sources.” Apache said recently that the company and its partners in the planned Kitimat LNG export project are looking to sell about 20 per cent of their stake to large investors. Kitimat LNG is widely considered to be the front runner of the proposed developments along the North Coast. Meanwhile, Spectra Energy Corp. earlier this month signed a project development agreement with BG Group plc to jointly develop plans for a new natural gas transportation system from northeast B.C. to serve BG Group’s potential LNG export facility in Prince Rupert. The pipeline will be capable of transporting 4.2 bcf per day of gas and could cost in the order of $6 billion to $8 billion. Bob Duncan, general manager, engineering services with Spectra, said the company sees a huge opportunity for natural gas in B.C. “Our expanding infrastructure will be done to meet market needs and will be designed after we’ve worked with local communities, First Nations and other key players,” he told the conference. “The final investment decision is right now scheduled to be in 2015 and then after that we would go to construction and the in-service date is expected to be in 2019. That’s scheduled to coincide with completion of the LNG terminal in Prince Rupert.”

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industry news CAPP pitches for more competitive TransCanada Mainline Daily Oil Bulletin The National Energy Board needs to make it clear to TransCanada Corporation that it is responsible for dealing with the issue of underutilization on its Mainline and that it needs to make changes to better compete in the marketplace, industry officials said Monday. “I think this is absolutely essential that TransCanada understands that it is their asset and their investment to manage for success,” Real Cusson, senior vicepresident of marketing at Canadian Natural Resources Limited, told the board, which is hearing TransCanada’s restructuring and 2012-2013 tolls application. “It is not for the National Energy Board to provide daddy’s money to bail out the kids every weekend.” The Canadian Association of Petroleum Producers (CAPP), in an opening statement filed with the board, said it believes that the current method of regulation “with its virtual guarantee of cash flow certainty,” lacks accountability for day-to-day decisions. Cusson, who was part of the CAPP panel, said he’s totally confident that if TransCanada employees were required to become more responsive to market forces they would succeed. “They’re very smart people and they know the markets extremely well,” he said. Murray Edwards, chairman of CNRL, and Randy Eresman, president and chief executive officer of Encana Corporation, also made unprecedented appearances before the board, along with David Collyer, CAPP president, David Thorn, vice-president of Canadian gas marketing for Encana, and Barry Jardine, CAPP’s manager of regulated transportation. Cusson and Thorn also are members of CAPP’s markets and transportation group. Flows on the Mainline are about one-half what they were a decade ago. Long-haul firm service transportation out of Western Canada is shifting to short term service and in the east, short-haul contracts are increasing, resulting in higher and more volatile Mainline tolls. TransCanada’s response has been the proposed restructuring, which includes the Alberta System Extension (ASE) to the Saskatchewan/Manitoba border which CAPP argues inappropriately allocates costs from the Mainline and the Foothills system to NOVA Gas Transmission Ltd., a wholly owned TransCanada subsidiary. Long-haul shippers would benefit from reductions in illustrative tolls of between 31 per cent and 49 per cent compared to the status quo, says TransCanada. For example, the total cost of transportation between NIT (NOVA Inventory Transfer) and Dawn, Ontario, would be $1.39 per gigajoule under the restructuring proposal compared to $2.43 per gigajoule under the status quo, a saving of $1.04 per gigajoule, or 43 per cent, it says.

However, that key element of the restructuring is unacceptable to CAPP, which has come up with its own proposal. The idea of the ASE “turns business on its head,” said Edwards. “When we contract with NGTL, we understand we are at risk for NGTL costs and for what we contract for,” he said. “As part of such a contract, we do not assume responsibility for Mainline costs.” CAPP views the ASE proposal as a “significant and unjustified violation” of the regulatory compact, Collyer told the board. “It violates the standalone principle which is a cornerstone of regulation.” NGTL and the Mainline are separate businesses and are regulated as such, he said. “The treatment of costs of mainline underutilization is a matter for the NEB to determine within the bounds of the Mainline as a standalone business entity.” The regulatory uncertainty introduced by the TransCanada proposal increases the risk of doing business with NGTL and could potentially affect the willingness of overseas investors to put their capital at risk, said Eresman. “We’re at a time in our industry in Western Canada where we have the opportunity to attract a lot of thirdparty investment,” he said. “A lot of that investment is potentially going to come from overseas. And things like these changes could negatively affect their desire to want to invest in Western Canada.” The ASE proposal would result in an increase of more than 30 per cent in the NGTL revenue requirement at a time when the western Canadian gas industry already is challenged, said Edwards. If the NEB were to approve it, the markets would react with potentially less capital invested in Western Canada with reduced activity, which could ultimately result in less gas for the Mainline, he warned. TransCanada has always taken the position that under the traditional regulatory model it is entitled to recover its revenue requirement from firm shippers and does not bear the cost of unutilized capacity. Under cross-examination from Kemm Yates, counsel for TransCanada, CAPP panelists insisted they had not changed their position that the cost and risk of underutilization rests with the shippers. “Shippers when they make contractual arrangements understand that they have the risk of bearing the cost of underutilized capacity based on the toll established by the board,” said Collyer. The problem is that there are very few shippers left on TransCanada -- and that’s TransCanada’s job to manage, he said. “We’d love to see them go out and provide an offering that would attract new volumes to the system,” and those shippers would be responsible for paying for those

costs, said Thorn. “There are plenty of opportunities to compete, not strictly on the gas side of the business,” added Cusson, noting that he had been involved in TransCanada’s proposal to convert an underused gas pipeline to oil service for the initial Keystone pipeline. Responding to a question from Yates, Encana’s Thorn said CAPP still views the Mainline as any other market outlet from Western Canada and considers any access to any market as important -- providing it is competitive. In its statement, CAPP said that a threshold question when developing its position was whether or not the Mainline has “stranded investment,” which it defined as investment that cannot be recovered in tolls over the economic life of the line. However, based on the throughput information provided by TransCanada and with the advice of its experts, the association said it concluded the Mainline is not yet a stranded investment case although it may be in the future. In concluding that it was premature to consider the Mainline a stranded investment, Collyer said the association considered TransCanada’s belief that it has upside and can win back long-haul volumes with tolls at the levels proposed in the restructuring and that it believes the pipeline should be given the opportunity to do so. “If they’re unsuccessful in doing so, we’ll have to have another discussion about what the options are to deal with the issue that will be in front of industry and in front of the board at that time,” he told Yates in cross-examination. While not ruling out a write-down of TransCanada assets, Collyer said CAPP is not advocating that or any other specific action at this time. Association members have not yet reached any consensus as to what option they would prefer or what the complete range of options would be, he said. In explaining why it is not yet prepared to consider the Mainline a stranded investment case, CAPP said that it also recognizes the uncertainty in the natural gas marketplace and the difficulty in predicting how pipeline flows may evolve, although “we would certainly acknowledge that market conditions are such that resolution of the mainline issue appears to be very challenging.” The CAPP proposal provides for the deferral of tolls, which would be repaid when future markets could support the future period’s cost plus the deferred amounts. TransCanada’s opportunity to earn its cost through deferrals is dependent in part on a stronger market and how supply develops but also, importantly, on the competitiveness of the service offering, Collyer said in response to a question from Parvez Khan, NEB counsel.

Nexen shareholders approve CNOOC takeover bid Daily Oil Bulletin Nexen Inc. shareholders overwhelmingly approved the oil producer’s takeover by China’s CNOOC Ltd. on Thursday but the stock weakened as public opposition to a state-owned enterprise absorbing $15.1 billion of Canadianowned assets appeared to grow. Shareholder blessing of the deal had been seen as a formality, given the rich 61 per cent premium that CNOOC offered on the price of Nexen’s shares. But the shares remain well below the $27.50 bid price due to uncertainty over the chances of the Canadian government giving the transaction the green light. Prime Minister Stephen Harper has actively wooed Chinese investment to help develop the country’s energy

resources, but recently even members of his government have broken ranks to publicly express discomfort with China taking such a large position, especially in the Alberta oil sands, one of the world’s biggest deposits of crude oil. The government has launched a review of the deal to determine whether it meets a murky “net benefit to Canada” test. “I think that’s healthy to have a good debate on whether this is in the best interest of Canada, so I’m not surprised we’re getting all of those different views coming out,” Kevin Reinhart, Nexen’s interim chief executive, said following the vote. “In terms of how the transaction unfolds, I’m not going to comment on that. The decision will be made behind closed doors, not in the public forum, hence we’ve stayed out of those conversations and will work

with the regulators to make their decision.” Holders of Nexen’s common shares voted 99 per cent in favor of the deal, and preferred shareholders voted 87 per cent in favor. Nexen shares were down nine cents at $25.23 on the New York Stock Exchange on Thursday and were unchanged at C$24.67 in Toronto. A CNOOC spokesman said the company welcomed the results. It has promised several items aimed at making the deal palatable in Canada, including moving its Western Hemisphere headquarters to Calgary, maintaining all of Nexen’s staff, and listing its shares on the Toronto Stock Exchange. CNOOC plans to keep the Nexen name, Reinhart told the meeting. “This tells me they understand who we are

what we stand for,” he said. “The Nexen brand has been a huge contributor to our success around the world and has provided us with a significant competitive advantage.” In addition, CNOOC has committed to carry on Nexen’s social responsibility programs in Canada and in all the other communities in which it operates, said Reinhart. “This is a clear recognition of the value that this creates for all of our stakeholders.” However, a poll appeared to show public support weakening. A Sun News-Abacus survey showed 69 per cent of Canadians say Ottawa should not approve the takeover, up 12 percentage points from a similar poll conducted in August. The survey was conducted online with 1,208 participants between Sept. 14 and 18.


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Apache says Kitimat LNG group looking to sell 20 per cent equity Daily Oil Bulletin Apache Corp. and its partners in Canada’s Kitimat liquefied natural gas export project are looking to sell about 20 percent of their stake to large investors, a company executive said Wednesday. Kitimat LNG is widely considered to be the front runner among five proposed LNG export developments in Canada. Apache’s partners are Encana Corporation and EOG Resources Inc. “In total, we’ve probably got about 20 per cent we can offer,” Doug Adams, vice-president of Apache LNG, told reporters on the sidelines of an industry gathering in Singapore, adding that the current partners would decrease their stakes proportionally in order to offer the 20 per cent equity. “There’s a lot of interest. A lot of buyers want equity, but we are offering equity to substantial off-takers or major foundation buyers, not to everyone,” Adams said. Apache and its partners plan to make a final investment decision on the development in the first quarter of 2013 and it is expected to come online in 2017. Most of the buyer interest for Kitimat LNG has come from North Asia, Adams said. Long-term contracts offered to those buyers will have prices indexed to oil, he added. That may disappoint North Asian investors who have been drawn to North American projects in the hope that prices will not be oil-indexed, as many of their other long-term contracts in Asia are. North American gas prices, especially in the United States, have plummeted in recent years due to a boom in shale gas, with U.S. natural gas prices under $3 per mmBtu compared with around $13 per mmBtu for spot LNG supplies in Asia.

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environment

A LONG WAY TO GO

Natural gas industry helping caribou on road back to stability

Ministry of Environment wildlife biologist Dale Seip talks caribou during a presentation in Fort St. John on September 23. Seip explained that caribou are disappearing from northeast B.C.

JAMES WATERMAN photO

james waterman Pipeline News North Wolf predation and human disturbance to the landscape could mean the end of the caribou in northeast British Columbia in the coming decades, but the oil and gas industry is striving to prevent that fate. That was the message being delivered by provincial Ministry of Environment (MOE) wildlife biologists Dale Seip and Conrad Thiessen during their Sunday, September 23 presentation in Fort St. John. The discussion was part of A Night of Caribou, an unofficial kickoff to the North American Caribou Workshop that also included a screening of the documentary Being Caribou, the tale of one couple following the Porcupine caribou herd migration on foot. “Caribou have disappeared from large portions of their historic range,” said Seip, whose presentation focused on the caribou living in the area south of Chetwynd and Dawson Creek, and east of the Rocky Mountains. Those populations have been studied since 2002. The results of that work haven’t been promising. “Decline, decline, decline,” Seip said of those populations, adding that the Burnt Pine herd is down to just one adult female. The Quintette herd is a stable population of about 173 to 218 individuals, but the Bearhole-Redwillow and Moberly

herds are also declining, both with fewer than 30 individuals at this point. The Graham herd would appear to be doing well based on its current population of approximately 700 caribou, but Seip also noted that just the southern portion of that herd had 1800 individuals as recently as 1988. That segment of the population has declined to just 300 animals at this point. Thiessen painted a similar picture for the caribou residing in the northeast corner of the province in the Fort Nelson area. Little was known about those populations prior to 2000, said Thiessen, but the MOE is now fairly confident that 1,300 caribou live in that region. That is a relatively small number of animals roaming across a vast landscape. “They actually exist at very low densities,” said Thiessen, suggesting that the northeast B.C. caribou are very difficult to count. “No statistical confidence in those numbers,” he added. Seip and Thiessen both point their fingers at one culprit when they explain the declining caribou populations in B.C. “Excessive wolf predation,” said Seip. Indeed, wolf predation now accounts for about 75 per cent of adult mortality among caribou in the South Peace. “We expect wolves are often killing calves as well,” he added. The peculiar piece of this puzzle, however, is that wolves and caribou have coexisted in the region – where their ranges

frequently overlap – for generations, but this associated decline in caribou populations is a recent phenomenon. Part of that problem could be the growing numbers and expanding ranges of preferred wolf prey such as moose, deer and beavers, which are contributing to growing wolf populations in addition as bringing the carnivores in contact with caribou more often than was common in the past. Thiessen noted that in one area of significant caribou decline near Fort Nelson the beaver numbers are very high. It is also an area where wolves have been found with their front teeth missing, likely kicked out by moose. “It’s not an easy life being a wolf,” said Thiessen. The wolves have survived in the area by preying on beaver, an easier food source than moose, but one that doesn’t compare to the amount of sustenance provided by large ungulates. Those wolves are likely supplementing their diets with caribou. When it comes to assigning blame for the growing numbers and expanding ranges of prey species preferred by wolves, particularly moose and deer, the pointing fingers turn towards human impacts. Activities such as logging have created roadways for prey and predators, as well as conditions that provide plenty of food for moose and deer. “A lot more wolves,” said Seip. Thiessen said that a study conducted in Alberta has shown that land disturbance amounting to greater than 61 per cent of the land base in a caribou range will cause a decline in their numbers. In northeast B.C., 71 per cent of the Calendar range has been impacted, 79 per cent of the Chinchaga range has been impacted and 84 per cent of the SnakeSahtahneh range has been impacted. Caribou are facing extirpation in all those areas. One area where the caribou population is stable is the Maxhamish range, but that region is also approaching the 61 per cent disturbance threshold at 57 per cent. Much of the disturbance in the Fort Nelson area is a result of oil and gas industry activity in the Horn River Basin shale gas play that creates linear features such as roads, pipeline right-of-ways and seismic lines. Those linear features offer predators easier access to caribou. Thiessen noted that the oil and gas industry has also begun to fund research that will hopefully help reverse the trend of declining caribou populations, particularly through $2 million per year in levies that go to a Science and Community Environmental Knowledge Fund (SCEK) administered by the BC Oil and Gas Commission (OGC), the Canadian Association of Petroleum Producers (CAPP) and the Small Explorers and Producers

Association of Canada (SEPAC). SCEK is currently contributing a study into caribou calving and predation being led by University of Alberta research Craig Demars. Thiessen has also been participating in that study. The burning question is what should be done about the wolves. Culling techniques have been employed in Alberta, but that hasn’t actually resulted in a reduction in wolf numbers, according to Thiessen. There is also a great deal of debate over the morality of killing one animal to save another. “Do we want caribou? Do we want wolves?” said Thiessen. The pair of biologists hope that they can help foster the conversation around caribou conservation issues by delivering these types of presentations to the general public. “It’s not clear that caribou are in trouble in some places,” said Thiessen. “Hopefully, people can take this into their daily life and how they make decisions,” he continued, “But, also, we live in a democracy and they can let their representatives know what they want to see on the land.” “People could live here for a long time and not really see any caribou,” said Seip. “And I think a lot of people just aren’t aware that there’s caribou here. They’ve been here a long time, but if the current trends continue, we may well see the caribou disappear from the east side of the Rockies over the next few decades.”

A caribou spotted near Muncho Lake in northeast B.C. this summer. Caribou are often seen in that area, which can give a false impression of their population health.

KATELIN DEAN photO


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Meet mitsubishi Encana’s Cutbank Ridge partner gets to know Dawson Creek

TOP: Shinya Miyazaki, CEO of Cutbank Dawson Gas Resources, had a busy lunch break on Wednesday, September 19. Miyazaki and is colleague Max Oda, president and CEO of Mitsubishi Canada, were in Dawson Creek to meet a few of the local dignitaries, including Peace River South MLA Blair Lekstrom (left) and Pouce Coupe Mayor Larry Fynn (right), as well as help their new partner Encana announce their renewed sponsorship of the Encana Events Centre. Mitsubishi is working with Encana on their Cutbank Ridge natural gas operations in the area. BOTTOM: Shinya Miyazaki, CEO of Cutbank Dawson Gas Resources; Ryan MacIvor, Encana Events Centre general manager; Michael Forgo, vice president of business services and stakeholder relations with Encana’s Canadian division; and City of Dawson Creek Mayor Mike Bernier. Encana presented Global Spectrum Facility Management with the first $120,000 installment of a five-year, $600,000 sponsorship to hold the naming rights of the facility on Wednesday, September 19.

JAMES WATERMAN photOS 28392


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special feature

CANUCK WISDOM Hockey great talks leadership at Energy Expo

Vancouver Canucks great Trevor Linden visited the Fort Nelson Energy Expo on Friday, September 14 to talk leadership and tell stories from his days in the National Hockey League.

JAMES WATERMAN photO

james waterman Pipeline News North Trevor Linden was in his last days as a National Hockey League player. The All Star and Olympian who had led his Vancouver Canucks to a seventh and deciding game against the eventual Stanley Cup Champion New York Rangers during the height of his captaincy in the spring of 1994 had gone the way of other elder statesmen of the game with still enough jump in their legs and passion for the sport to play both ends of the rink as a third line winger night after night. He wasn’t one of the young stars anymore. He was the Old Warrior. The

Grizzled Veteran. The Greybeard. But that was just the hockey world. “I was still a young man,” Linden told the Fort Nelson Energy Expo crowd during dinner at the Northern Rockies Regional Recreation Centre on Friday, September 14, recalling his rebirth as an ordinary citizen of the world, no longer an NHL player, but a newcomer to the workforce with a lifetime in front of him. Linden brought these stories of hockey stardom and his inevitable retirement from the NHL to the men and women who toil in the oil and gas industry of northeast British Columbia as part of a meditation on the lessons of the game and the true nature of leadership.

“I think of people that show courage,” Linden told Pipeline News North. “Because I think that being a leader is difficult. It’s not always popular. And you have to make some difficult decisions. “I think of people with courage. I think sometimes it’s really lonely to be a leader. And it’s not always the glorified place that people think.” Leadership is also about exhibiting integrity and earning respect. “Integrity means doing the right thing even though it’s maybe the unpopular thing,” said Linden. “And that says a lot about someone. And I think we all strive in our lives to display that trait. It’s not easy.” It isn’t easy to earn respect either. “When I think about professional hockey or the locker room, every guy in that room earns their respect,” he continued. “And that’s the truest sense of earning it. And you earn it in different ways. You earn it in your actions. You earn it in your words. But, most of all, I think you earn it with how you act and how you respond in difficult situations.” One of the courageous men of integrity in Linden’s hockey life was Detroit Red Wings great Steve Yzerman, who was still a young man – and a young team captain – when he took Linden under his wing at his first NHL All Star Game. “People that are able to put themselves in someone else’s shoes and helps them out,” Linden said of those brave players who lent him a hand in his early years. “Guys like Ray Bourque or Joe Sakic or Steve Yzerman,” he added. “Just very down to earth, quality people. That’s a unique and great quality.” Linden recognizes those same qualities in a pair of former teammates in Vancouver, Henrik and Daniel Sedin. “Incredible integrity,” said Linden. “Quality people. Hardest working guys on the team. Great players. And they lead by example. Those guys are really special people. “I think there’s lots of quality people in the game,” he continued. “And I think it’s

a better story when you talk about the not so quality people, but there’s lots of good ones.” Linden suggested that leadership often begins with childhood lessons for most of the great Canadian leaders in the league. “I think most Canadian kids come from pretty humble beginnings,” he explained. “My mom was awesome and I love her to bits because she made it happen for us kids. She found us equipment. She went to garage sales. She bought second hand equipment for us. But we always had equipment.” His glimpse of the business world since retiring from hockey has shown Linden that there are great similarities between team captains and the titans of industry. “When I think about what goes on in an NHL locker room,” he said, “it’s so transferable to anything from as simple as small business to your family to bigger boardroom type settings. There are very many similarities.” Linden tries to pass along the lessons of his NHL experiences to those who might be able to use those tales to help them in their careers and businesses when he attends events such as the Energy Expo. “I obviously try to pass on some entertainment,” he said, “but also try to weave in some stories that they maybe take back to their homes, their workplace, the places where they feel that they want to make a difference and change the culture of what they may be doing.” That is one of the rewards of a hockey career. “Having the great ability through playing hockey of being able to make a small difference in people’s lives,” said Linden. “I’ve had the great privilege of visiting some of these communities over the last two or three years – since I’ve been retired – and it’s just a really unique experience to come to the northern part of B.C. “And just such great people and big hockey fans,” he concluded. “So, it’s a lot of fun.”

Painted Pony updates Montney well operations Daily Oil Bulletin In an operations update of the company’s Montney gas project in northeastern British Columbia, Painted Pony Petroleum Ltd. reports it recently completed four (1.4 net) new Montney gas wells in the Daiber/Kobes area that are undergoing production testing. All four wells were drilled earlier in 2012. The Daiber d-A44-C/94-B-16 (50 per cent working interest; operated) lower Montney well is currently testing in-line through the company’s Daiber facility. During the past 12 days, this well has flowed at an average wellhead rate of 10.2 mmcf per day over 277 hours. The 24-hour peak rate averaged 13.1 mmcf a day and the most

recent 24-hour rate was 9.3 mmcf a day at a current flowing casing pressure of 1,039 psi. The Daiber d-B44-C/94-B-16 (50 per cent working interest; operated) middle Montney well is currently flowing back on initial cleanup. In addition to the middle Montney completion, this well was perforated and simulated across one stage in the upper Montney. During the past three days, this well flowed at an average wellhead rate of 3.2 mmcf a day over 65 hours. Additional test data from this well are expected within the next several weeks following the installation of production tubing. The Kobes c-75-J/94-B-09 (20 per cent working interest; non-operated) lower Montney well is currently testing in-line through the non-operated Gundy facility. During the past six

days, this well flowed at an average wellhead rate of 5.6 mmcf per day over 131 hours. The latest 24-hour test rate was 5.3 mmcf a day at a current flowing tubing pressure of 570 psi. A second lower Montney well on the Kobes pad, the c-A75-J/94-B-09 location (20 per cent working interest; nonoperated), is also producing on test through the Gundy facility. During the past six days, this well flowed at an average wellhead rate of eight mmcf a day over 133 hours. The latest 24-hour test rate was 9.7 mmcf per day at a flowing tubing pressure of 966 psi. On the Blair block, Painted Pony has recently spud the first of two wells (100 per cent working interest), which are planned to be drilled, completed and tested prior to year-end. 11-F/94-B-16 pad.


SEPTEMBER 28, 2012

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community JUST FOR THE FUN OF IT Encana gets Fort Nelson running again james waterman Pipeline News North

There was something for athletes of all ages and abilities at the Trail Mix Half Marathon and Fun Run in Fort Nelson on Saturday, September 22. The event, organized by Encana and the Northern Rockies Recreation Department (NRRM), featured a half marathon, a 10-kilometre run, a 5-kilometre run, a 5-kilometre walk, a 1-kilometre run for those between the ages of 8 and 15 and a 500-metre run for kids seven years of age and under. “The race went very well this year,” said Angela White of Encana, noting that they had 20 more participants than last year for a total of 108 runners and walkers, not to mention over 20 dogs. Eight brave souls tackled the half marathon. “The most grueling race, as they have to run the trail twice and there is a very

long section of uphill,” said White. “The weather was absolutely perfect again,” she added. White explained that the run is part of Encana’s community investment program. “We focus on funding three priorities: environment, education and community life,” she said. “This run is an opportunity for community members to participate in a community event that promotes health, community spirit and celebrates the beautiful community trail.” “The NRRM was thrilled to once again work with Encana to put on this annual fun run, which really caters to all ages and abilities,” said Danielle Morine, recreation program manager with the NRRM. “We look forward to offering this community event for years to come.” White remarked that the community spirit aspect of the run is important, but she also emphasized the value of promoting personal fitness.

“Fort Nelson has so many amazing people living here and I’ve only seen community spirit grow. To have so many volunteers step up to help is huge and tells me that people want to help make events successful,” she White. “I have seen people training for months for this event,” she continued, “and there are even running clinics that culminate just prior to this race so people can demonstrate their fitness at this event. “The race is fun, but it is also an opportunity for people to challenge themselves and set goals. There was one runner who set a goal several months ago to run the 10-kilometre and when she crossed the finish line you could just see how happy she was to have achieved her goal. “I also talked to one boy who ran the 5-kilometre. He was so proud to have ran the distance entirely, as it was the first time he had ever ran that far. “These stories make it all worthwhile.”

The Trail Mix Half Marathon and Fun Run included a 500-metre race for kids seven years of age and under.

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industry news Too early to tell if Duvernay can match Eagle Ford Daily Oil Bulletin

While the Duvernay shale play in Alberta has drawn parallels to the Eagle Ford shale in Texas in terms of oil and liquids production potential, there’s simply not enough information to know for certain at this point if the two are comparable. Some view the Eagle Ford as the premier liquidsrich resource play in North America, and there is hope that the Duvernay will be similar. But there hasn’t been enough drilling in the Duvernay to know for sure. “At the state we’re at in the Duvernay, we’re very much in the exploration phase,” Gary McMurren, director of light oil with Athabasca Oil Corporation, told the Peters & Co. Limited 2012 Energy Conference. “Will the Duvernay be the next Eagle Ford shale? With certainty, I can tell you that no one can answer that question ... with any certainty.” The Duvernay shales have been credited as the source rock for many of the large Devonian oil and gas pools in Alberta, including the Leduc field discovery in 1947. In central Alberta, the Duvernay shale basin spans roughly 50,000 square miles, much of which is within the thermally mature or “wet” gas window, according to a report from BMO Capital Markets. An estimated 7,500 square miles is thought to be in the liquids-rich gas window where reported liquids recoveries range from 75 to 150 bbls per mmcf. Since late 2009 to now, producers have spent billions at Crown land sales amassing acreage positions. The Kaybob area was the first to see land sale activity thought to be associated with the Duvernay and is the area that is most mature in the overall development of the play. McMurren said that unlike the Eagle Ford where there are hundreds of wells drilled, completed and on produc-

tion with a lot of data, there’s a fraction of that in the Duvernay. “[There are] older wells, Cretateous gas wells, that have been on production for a number of years, and a lot of the facilities right now are set up as sweet gathering systems,” he said. “To date, the Duvernay has been a sweet gas zone. There have been tests of sour product from it and it does sit in the Devonian age around zones like the Beaverhill Lake that are very sour in the area. “It might stand to reason that it may be sour one day.” The company is setting up the infrastructure needed to handle high-pressure liquids-rich gas. “We have constructed a 63-kilometre pipeline ... essentially from the town of Fox Creek all the way over to the Simonette Keyera gas plant,” McMurren said. Three batteries are planned for Saxon, Kaybob West and Kaybob East and expected to be onstream this year to handle both oil and gas. Greg Niebergall, exploration manager with Yoho Resources Inc., noted that the company was an earlymover at Kaybob, picking up its initial lands at less than $30 an acre. “We now have 54 gross sections, or 21 net to Yoho, and five successful horizontal wells spread across our lands,” he said. “We can support over 145 development locations, and those are net to Yoho.” The company focused on the Kaybob area because it has the thickest section of high-porosity Duvernay shale and it’s also located in a prime liquids-rich window. “The Duvernay section at Kaybob is very thick; in places it’s over 50 metres and the high-quality organicrich shale is continuous from top to bottom,” Niebergall added. “The Duvernay is very overpressured. In fact, we’re seeing pressure gradients between 18 and 19 kpa per metre versus nine to 10 in the conventional reser-

voirs in the Kaybob area. “It has very high quartz and low clays and that makes it suitable for achieving big fracture networks, which is very important in our completions.” Jim Riddell, chief executive officer of Trilogy Energy Corp., noted that industry has spent $1.7 billion on Duvernay rights in the Kaybob area since December 2009, adding that 65 wells have been drilled/or are drilling to date and 18 horizontal wells licensed. Roughly close to $1 billion has been put into the play in terms of drilling. “It is fairly well understood where the shales are. We slowly have started to understand what the burial history of those shales has been and where would be the areas that were subjected to the highest heat and maybe a little less heat,” he said. “That’s determined how much the organic matter within the shales has been cooked and what it has done to generate the hydrocarbons. The hotter, deeper, higher pressure burial history has generated dry gas and the less is an oilier part.” The Duvernay can be as much as 60 or 70 metres thick. “We go from the southwest corner, an area we have interpreted to be a drier gas, a liquids-rich gas in the middle and then an oilier area to the north,” Riddell added. The company has around 100 sections of land in the oilier, still-to-be-proven area and another 100 sections in the liquids-rich area, “which we think is pretty close to being declared as commercial.” He cited the 3-13-60-20W5 well, which the company put onstream last April. It started at three or four mmcf per day and it’s got a hyperbolic decline that’s flattened right out at about one mmcf per day now. “It also is producing 80 or 90 bbls a million of free condensate, plus additional liquids that we recover at the plants,” Riddell said.

Horizontal drilling continues to surge across Canada Daily Oil Bulletin

A record 4,626 horizontal wells were drilled across Canada to the end of August, representing an 11.55 per cent increase from 4,147 horizontal wells rig released during the first eight months of 2011. This year’s eight-month rig release count for horizontal wells is up 54.5 per cent from 2,994 such wells only two years ago. Year-over-year, the horizontal well count is up in all four western provinces except for British Columbia, where drilling counts are off significantly from last year due to slumping gas prices. To the end of August, operators have drilled 7,043 wells across Canada, off almost

D000703854

10 per cent from 7,802 wells rig released during the comparable period last year. Of the wells drilled, 917 still have no final status (oil, gas, dry or service). Of those with a status designation, 77.33 per cent were reported as an oil well and only 12.53 per cent were listed as a gas well. This year’s eight-month rig release count for oil wells of 4,745 is off from 5,230 oil wells rig released a year ago. While the number of rig releases declined year-over-year to the end of August, total metres drilled rose to 14.17 million metres from 14.01 million metres in January-toAugust 2011. Alberta rig released 4,360 wells over the first eight months, off 12.4 per cent

from 4,977 a year ago, but total metres drilled lifted to 9.1 million metres from 8.79 million metres to the end of August last year. In Saskatchewan, eight-month rig releases were off 7.22 per cent to 1,952 from 2,104 a year ago. Metres drilled declined to 3.09 million metres from 3.20 million metres over the first eight months of 2011. The rig release tally in B.C. declined 26.35 per cent to 313 after eight months, compared to 425 last year, while operators in the province drilled 1.19 million metres versus 1.49 million metres to the end of August 2011. Manitoba’s rig release count after eight months lifted 51.31 per cent to 404 com-

pared to 267 a year ago. A total of 750,340 metres were drilled to the end of August compared to 486,688 metres in January-to-August 2011. Operators across Canada rig released 1,098 wells in August, off almost 21 per cent from 1,388 wells drilled a year ago In Alberta, operators drilled 631 wells last month compared to 823 in August 2011 (off 23.33 per cent). Saskatchewan operators rig released 344 wells, off 25.54 per cent from 462 wells in the year-prior period. B.C. operators drilled 37 wells in August compared to 48 a year ago. Manitoba was the only province that reported a year-over-year increase in rig releases during August.


SEPTEMBER 28, 2012

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OLD CHALLENGES & NEW OPPORTUNITIES Hectic day at Energy Conference covers all the bases

Steve Troyer of Energy Services BC discussed the challenges of recruiting and training new workers during a roundtable discussion on workforce issues at the Dawson Creek Energy Conference on Thursday, September 20.

James Waterman photO

james waterman Pipeline News North Workplace safety, labour shortages and renewable sources of energy were just a few of the topics of interest during a busy day at the 2012 Dawson Creek Energy Conference on Thursday, September 20. The second – and biggest – day of the event saw representatives from the oil and gas industry, the service sector, educational institutions, crown corporations and the government participate in six discussions of significant energy sector subjects both as speakers and attentive listeners. The day began with a focus on labour issues both in terms of the seemingly constant struggle to find the necessary workers and how women are starting to play a bigger role in the energy industry. “We don’t have an equal number of women in the energy industry,” said Tina Olivero, founder and publisher of Oil and Gas Magazine, as well as facilitator of the women in industry roundtable. “There is a huge opportunity there,” she added. “Women are still sorely underrepresented in the trades,” said Kevin Evans, CEO of the Industry Training Authority (ITA), during a simultaneous discussion on how the industry can meet the challenge of a labour shortage. Evans described the labour situation in terms of the billions of dollars to be invested in energy sector projects ranging from oil pipelines to liquefied natural gas (LNG) export facilities over the next ten years and the lack of “human capital” that could adversely impact those developments. The ITA predicts a need to fill 2,910 trades jobs in British Columbia by 2020. That includes 1,710 workers to replace those who will be retiring and 1,200 new positions due to industry expansion. “This is a very conservative outlook,” said Evans, noting that the most recently announced projects aren’t

included in that forecast. The labour picture for northeast B.C. as described by Evans is a complex one where there is simultaneously an aging workforce whose experience and mentorship will be lost to retirement and a declining youth population. The result is a relatively small workforce of just 41,000 people that has been hard to grow due to negative perceptions of the region and the oil and gas industry in other parts of the province and the country. For example, Evans noted that 20 per cent of first year welders in the Lower Mainland are choosing unemployment over relocating to the northeast. Steve Troyer of Energy Services BC (ESBC) told the labour roundtable that the way to correct that problem is to try to attract families, not just workers, and that begins with affordable housing and improved roads so that workers are spending less time in camps. It also involves creating a comfortable workplace environment for those individuals who haven’t traditionally been part of the oil and gas industry workforce in northeast B.C., a demographic that includes women as well as new Canadians who may have trouble communicating with those unfamiliar with their languages and accents. “You see mostly white guys,” Troyer said of the oil patch of northeast B.C. “We must make our communities welcoming to a more diverse population,” he added. Olivero doesn’t believe the workplace culture of the oil and gas industry should be a barrier to women joining the sector, however. “I don’t think that there’s anything really stopping women. I think there’s a lot of preconceived limitations that aren’t true,” she said. “I started working in the industry when there was only three women in it,” she continued. “Myself included. And the rest were men. “I could have gone either way with that. I could have

thought, ‘This is great. I get to hang out with the guys all the time, have fun and do whatever I want.’ Or I could have been intimidated. And it’s a choice. “There is no room for intimidation. There is no room for thinking that you’re inferior. And that’s where inequality comes from. It doesn’t come from the actual environment. It comes from people thinking that for some reason they don’t fit in. And that is not the truth.” Adequate training is another key concern, said Evans, who noted that there are measures in the BC Jobs Plan to help improve industry training through programs such as $17 million to upgrade equipment used for training purposes. “This is a critical need,” said Evans, emphasizing the importance of “training our young people in equipment they’ll be using in the field.” There is also the problem of too many apprentices who have been unsuccessful in finding employers despite the labour shortage. Evans remarked that it could be a case of insufficient training. “Let’s identify where the gaps are,” he said. “And then let’s train to the gaps.” Evans admitted that the lingering effects of the recent recession may be deterring employers from sponsoring apprentices, but he hopes they will reconsider that stance. “There is a very solid business case to taking on an apprentice,” said Evans. “Poaching is no longer an option for recruiting,” he added. The problem is significant, according to Evans, because there are currently only 401 sponsors for 1036 registered apprentices in northeast B.C. “This is not going to be sufficient,” he said. The gap between the number of apprentices and the number of sponsors might suggest that the industry is continued pg 30


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Conference crowd given glimpse of green energy

cont’d from pg 29

for managers so that they can make contact with potential employees. “The key is working together to solve our own problem,” said Troyer. Another key conversation during that hectic day at the energy conference involved discussions of new technologies and green and renewable energy. “Some of the bigger companies like AltaGas… have a variety of projects on the go, such as wind and micro-

MacWilliam. “It’s not necessarily the green versus the oil and gas as much anymore. We’re starting to see attracting plenty of young people to fill the roles they more synergies. require. However, Peter Nunoda, vice president of “It will become more common in the future.” academic and research at Northern Lights College MacWilliam also believes the oil and gas industry is (NLC), said that the college recently lost its geomatics starting to recognize the opportunities to use renewable program not because geomatics professionals aren’t energy for their own operations, such as using solar ena hot commodity, but because there were insufficient ergy when they don’t have access to the electricity grid. students to continue the program. “It’s an alternative to using diesel no matter where you “The issue is not the programming,” he are,” he said. said. “It might not be as cheap as grid electricity,” “It’s not necessarily the green versus “We can’t get the students that we need.” he added, “but they don’t have grid electricity.” Nunoda indicated a need to reach Links between producing oil and gas and the oil and gas as much anymore. We’re students at a younger age to make them producing other forms of energy also exist. aware of their options and push them in “There’s going to be more and more opstarting to see more synergies.” the right direction, but Troyer suggested portunities to create energy when you’re that part of the problem is simply how the already creating energy,” said MacWilliam, industry relates to young people. citing geothermal as an example. – Matthew MacWilliam, City of Dawson Creek At his own company, Troyer faces the “What they’re talking about is a very similar challenge of recruiting non-skilled workers, technology to oil and gas,” he continued. which often means selling those individuals “Oil and gas is extracting the oil, but, in the on a job they may not have considered previously. process, 95 per cent of what’s coming out of that hole, hydro,” said Matthew MacWilliam, energy manager for “Good people that can get the job done,” he said of for the most part, is hot water. Hot water can be used to the City of Dawson Creek, who facilitated two sessions his workforce needs. create steam electricity. So, you’re already kind of doing on green energy and renewable energy. Troyer’s target demographic is people between the MacWilliam thinks the inclusion of those initiatives the same thing. You’re just not aware of it. age of 25 and 35, a group that is unlikely to look for a “There’s going to be more and more opportunities in the energy conference discussion is a recognition job in the newspaper, but would prefer to search and ap- that there is a need for all available forms of energy to for oil companies to expand their appetite to look at ply for jobs via Facebook. Facebook has been blocked other opportunities to create energy beyond just oil satisfy demand in a sustainable manner. at his company, but Troyer is now reversing that policy and gas.” “We’re looking at energy more holistically now,” said R001113627

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