Pipeline News North by Pipeline News North

Northern British Columbia and Alberta's Oil and Gas Industry Vol. 3 Issue 8 • dist: 16,000

august/september • 2013

h t r o N

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in this issue:

• LNG takes to the sea - BC FERRIES looks into the natural gas option • down on the farm - rural quebecers tour alberta oil patch • cross canada - full speEd ahead for pipeline

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• PIPELINE NEWS NORTH

AUGUST 16, 2013

industry news RAINY SEASON Wet weather hindering drilling activity james waterman Pipeline News North

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cent increase. “There’s lots of interest picking up and activity picking up in [Northeast B.C.],” said Salkeld, adding that British Columbia alone is bucking the trend as Progress Energy has increased its rig count for the soggy conditions put a damper on oil and gas drilling year by about a dozen rigs since it was acquired by activity across Western Canada. Petronas. The Petroleum Services Association of Canada “Just because there’s lots of positive talk about (PSAC) released its third update to the 2013 LNG (liquefied natural gas) in B.C. and the developCanadian Drilling Activity Forecast on Thursday, July ment there,” he continued. 25, indicating that the number of wells drilled this “So, you’ll see an uptick there for those players that year would dip slightly from the April forecast of can afford to play that long game.” 12,000 wells to 11,415 wells. At the same time, said Salkeld, the provincial and “It’s still an increase over the 2012 year,” said Mark federal governments are working hard to develop Salkeld, president and chief executive officer at overseas markets for Canadian oil and gas. PSAC. “And there’s confidence in that effort,” he continThe 2013 forecast suggests a three per cent ued. “From a business perspective, it only makes increase in wells drilled over 2012 numbers. good sense for Canada to be pursuing this both proSalkeld said PSAC was very optimistic about 2013 vincially and federally. in April, but that was before all the wet weather that “And I think the effort that the government at both even caused flooding in Southern Alberta. levels is putting in is being respected by industry. So, “Just with the wet weather there’s a certain level of confiand the break-up being a little that they are going to “With the wet weather dence bit longer than expected, it’s get wins.” hard for us to get equipment Still, B.C. is suffering from and the break-up back into the field. It’s put a bit the wet conditions this summer of a dent in our forecast,” he as well, just one summer being a little bit continued. removed from drought condi“We’re still optimistic. There’s tions that prompted the BC Oil lots of work to be done out longer than expected, and Gas Commission to susthere. It’s just waiting for the pend short-term water withroads to dry up and the weathit’s hard for us to get drawal licenses for certain er [to improve] so we can get waterways. equipment out there.” gas producers use equipment back into thatNatural PSAC is now predicting water for hydraulic fractur7,190 wells in Alberta, which is ing and other activities. the field.” a five per cent decline from the “Weather plays a big factor previous forecast of 7,563. The in this industry,” said Salkeld. numbers for Saskatchewan Salkeld believes the industry – Mark Salkeld, PSAC and Manitoba suggest a six per has adapted well to the curvecent decrease (3,081 wells) balls Mother Nature can throw and a nine percent decrease its way year after year, noting (613) wells, respectively. that multi-well pads and multiple-stage fracturing has “Oil is a good price and gas is not a good price,” changed that ballgame. said Salkeld. “Therefore, the equipment is still shifted “The bottom line is we’re not drilling as many wells toward [oil].” right now as we did in the past,” he explained. “The B.C. is the exception to all these rules, as PSAC overall well count or rigs released is important, but is predicting wells drilled to increase to 506 over we’re staying on the wells longer, we’re delivering the previous forecast of 457, marking an 11 per more productive wells, higher producing wells.”

PIPELINE NEWS NORTH •

special feature 18 Rural Quebecers tour Alberta oil patch

industry news 23 TransCanada pipeline goes

full speed ahead

interview 14 Binh Vu of Alberta Oilands talks investment

environment 19 Air quality study planned for Wood Buffalo

community 26 Encana races against hunger and everyone wins

careers 30 Oil and gas industry making lion’s share of new jobs

• PIPELINE NEWS NORTH

AUGUST 16, 2013

industry news

North William Julian Regional Manager 250-785-5631 wjulian@ pipelinenewsnorth.ca

Alison McMeans Managing Editor 250-782-4888 editor@ pipelinenewsnorth.ca

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The three fates

Site C review panelists selected william stodalka Pipeline News North

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Three people have been selected to decide the fate of the Site C project – and in the process, the economic and social future of the Peace Region as a whole. On Aug. 6, both B.C. and Federal regulatory authorities said that the amended environmental impact statement (EIS) for Site C was satisfactory, and have directed the proposal to the Joint Review Panel for further review. The chair members include a longtime environmental ministry insider, a professional engineer and a communications consultant with an anthropology background. The chair of the panel is Dr. Harry Swain, who holds a Ph.D. in economic geography. Swain served for 22 years in the federal government between 1971 and 1995, before eventually becoming a research associate at the University of Victoria. In 2012, he wrote an editorial questioning Enbridge’s proposed Northern Gateway pipeline, saying that there would be “some probabilities of environmental damage and some certainty of insult to aboriginal land titles.” The editorial concluded with Swain asking readers, “why Enbridge chose the less safe route, and whether we as taxpayers have to pay the premium for the risks the company has created.” Swain has also written a book about the Oka Crisis, a conflict where a First Nations protest arguing against a proposed golf course on disputed land turned into a 78-day standoff. (Swain was the Federal Minister of Aboriginal Affairs during that period.) The second member of the panel is James

Mattison, a professional engineer who at one point served as assistant deputy minister and comptroller of water rights with the Ministry of Environment. Mattison spent 25 years with the Ministry of Environment before retiring from government service in 2009. According to the provincial Ministry of Finance website, Mattison sits on both the Oil and Gas Appeal Tribunal and the Environmental Appeals Board. The third member of the panel is Jocelyne Beaudet, a communications consultant with two degrees in anthropology. She has also served as a member of a joint review panel for the new Darlington nuclear power plant project and the Eastmain 1-A/Rupert Hydroelectric Project. Fort St. John Mayor Lori Ackerman praised the panelists selected. “They look like their very knowledgeable people, and I look forward to meeting them and having a discussion with them about the dam,” she said. Area C Director Arthur Hadland said the panelists would have a few issues to look at, including recreational opportunities, agriculture, the dam’s economic impact in conjunction with the growing natural gas economy, and First Nations issues, among others. “I’m ever optimistic that honesty will prevail in a review process,” said Hadland, who has expressed opposition to the Site C dam in the past. “I’m hoping that they’ll give it a thorough, honest and transparent review.” The Site C project is expected to cost $7 billion, and bring in potentially thousands of jobs to the Peace Region. However, critics have questioned its necessity and environmental impacts, among other issues.

AUGUST 16, 2013

PIPELINE NEWS NORTH •

new beginning Woodfibre aims to resurrect old industrial site with LNG james waterman Pipeline News North

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Efforts to build a liquefied natural gas (LNG) industry in British Columbia continued to gain steam in late July with the fourth export license application submitted to the National Energy Board (NEB) this summer. Woodfibre Natural Gas is the seventh project overall to seek a license to export natural gas as LNG from the B.C. coast, joining a group that includes Pacific NorthWest LNG, Prince Rupert LNG and the ExxonMobil Canada-Imperial Oil partnership, all of which filed applications earlier in the season. Kitimat LNG, Douglas Channel Energy and LNG Canada had all been granted LNG export licenses previously. “We are currently undergoing baseline environmental studies to understand the area and its needs, as well as feasibility studies to determine which engineering and construction options would make the most sense for the project,” said Byng Giraud, vice president of corporate affairs with Woodfibre Natural Gas. An interesting facet of this project is that Woodfibre intends to use an existing waterfront industrial site, the former Western Forest Products pulp mill near Squamish. “Our purchase of the site is contingent on full environmental remediation of the site by the current owner, consistent with current regulatory standards,” said Giraud. “Revitalizing an existing but fallow industrial site means we are minimizing the impacts to the area environmentally and physically,” he contin-

ued, adding the site already has infrastructure to supply electricity and natural gas. Additionally, the facility is located on a deep water port. “We also look forward to working with the community to ensure that the project is an economic generator for the region … as well as collaborating on existing efforts to help improve the Howe Sound and Squamish area,” said Giraud. “It is still in the early stages of planning and remains subject to environmental review and approval, but does have the potential to create economic benefits for the local area in addition to returning the old industrial site to the District of Squamish tax base,” said Rich Coleman, minister of natural gas for the Province. “The B.C. Government remains committed to building the cleanest LNG industry in the world,” Giraud continued. “Industry will play an important role in this goal, and the repurposing of old industrial locations does help by minimizing the need to disturb other areas for development purposes.” Giraud isn’t concerned about access to feedstock for the Woodfibre project despite being the seventh proponent to announce their intentions to export LNG with an export license application. “The supply … in Western Canada is significant,” he said. Still, the feasibility study is an ongoing process. “We hope to have the results in the fall of this year,” said Giraud. “And proceeding with the … environmental review shortly afterwards.”

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• PIPELINE NEWS NORTH

AUGUST 16, 2013

industry news

closer together Western provinces set sights on energy export market james waterman Pipeline News North Although the two westernmost provinces have had their squabbles over Enbridge’s Northern Gateway plan to ship oil sands bitumen to an export point on the west coast, British Columbia and Alberta appear ready to work together on the issues around market access for energy resources such as oil and natural gas. Announced during the Premiers’ meeting in Niagara-On-The-Lake, Ontario on July 26, B.C. Premier Christy Clark and Alberta Premier Alison Redford have created a working group consisting of the top two energy officials from each province

to examine those issues and develop recommendations as to how to move forward by the end of this year. “Our two provinces have a common interest in the responsible development and export of our energy resources,” said Clark. “It’s critically important to work together to create jobs and strengthen the economy of our provinces.” “Premier Clark and I are working together to build new markets and get the highest price possible for the resources owned by the people of our two provinces,” added Redford. “I’m excited about the progress we’re making and the potential for Alberta and B.C. to continue driving

Canada’s economy.” Redford issues an additional statement the same day indicating the meetings had been quite successful from Alberta’s point of view, particularly in terms of energy issues. “We reached consensus on an issue I have been driving since day one – a Canadian Energy Strategy,” said Redford. Alberta presented a progress report on the development of a Canadian Energy Strategy during the meetings on July 25. The report touches on issues such as major pipeline projects, market access, regulatory reforms and greenhouse gas emissions. “We released a report detailing the

steps provinces are already taking to develop our resources responsibly, grow our economies and ensure we get the highest price possible for the resources we own. “BC Premier Christy Clark and I also announced a concrete step toward our goal of getting Alberta’s products to the coast - today we appointed our two top energy deputy ministers to work through some of the barriers that have existed between our two provinces. “Both the report and today’s working group announcement are a significant endorsement of Alberta’s efforts,” said Redford. “I’m proud of what we achieved, working together.”

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Life’s brighter under the sun

Employees consider health, wellness when choosing employer

By: Staff/June 12, 2013

Employees want a boss who cares about their health. A new U.S. survey of approximately 1,300 businesses and 10,000 employees found a strong link between the wellness and vitality of an organization and the health and wellness of its employees. The survey, conducted by Virgin HealthMiles Inc. found employees place a premium on the culture of wellness with 87% claiming that health and

wellness programs play a role in determining their employer of choice. However, quantifying the bottom-line impact of these programs continues to be a challenge for employers. Of the 1,300 businesses surveyed, 80% offer health and wellness benefits. Among that group, 47% have extended those health and wellness benefits to spouses of employees.

“Creating a culture-first mentality is a critical step for employers when it comes to building a highly engaged workforce,” said Chris Boyce, CEO of Virgin HealthMiles. “The trends outlined within this survey mirror what we’re seeing in the market: employees become much more motivated and productive when they know that their employer cares about their total quality of life, which goes beyond traditional wellness and includes physical, emotional, financial and social health.”

Key Survey Findings • Health and wellness programs are important to employees: approximately 87% of employees surveyed said they consider health and wellness offerings when choosing an employer and 80% of employees surveyed say that they believe their employer cares about their well being. • Health and wellness programs have a positive impact on an organization’s culture: 70% of employees say that wellness programs positively influence the culture at work. Survey respondents shared that their health and wellness habits are not just motivated by colleagues (58%) but also spouses/partners (53%), friends (41%) and children (32%). • Incentives matter: incentives also play a big role in the motivation of employees to participate in wellness programs, with 61% of employees

saying it is a key reason they participate and 78% claiming they are interested in participating in incentive-based programs while at work. The commonly-offered positive programs by employers today are: physical activity programs (58%), smoking cessation (50%) weight management (49%) and health risk assessments (47%). However, the programs that employees are most interested in varied a bit from what most employers are offering. • Communication is a concern: only 51% of employees surveyed said they have a good understanding of how to participate in health and wellness programs being offered by their employers. With 82% of organizations relying primarily on email as the main source of communication for these programs, there is a trend of companies moving to a more direct communication model of manager to employee, with 26% of organizations

reporting they are now using this method. • Measuring impact continues to be a challenge: while employees are confident in reporting how health and wellness programs have benefited them, employers still struggle with finding a tangible way to directly correlate these programs to bottom-line benefits – yet 67% are exploring the possible connections.

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AUGUST 16, 2013

PIPELINE NEWS NORTH •

how the west is one james waterman Pipeline News North Alberta oil was top of mind when a small contingent from the provincial government travelled to Las Vegas, Nevada for the annual meeting of the Council of State Governments-West (CSGWest) at the end of July. Minister of international and intergovernmental relations Cal Dallas led the delegation, which also included Strathcona-Sherwood Park MLA Dave Quest and Red Deer-North MLA Mary-Anne Joblonski, who now serves as co-chair of the CSG-West Canada Relations Committee. “This conference saw the inaugural Canada Relations Committee launched,” Dallas told Pipeline News North upon his return from the meeting on August 2, adding he saw an “enhanced hunger” from the Western United States to work with Alberta – and all of Canada – on various opportunities. “Whether that’s taking a look at best practices, sharing research, perhaps looking at investments from a policy perspective, supporting commercial enterprises, policies around economic development and the like – these are the kinds of things that we talk about,” said Dallas. CSG-West is comprised of Alaska, Arizona, California, Colorado, Hawaii, Idaho, Montana, Nevada, New Mexico, Oregon, Utah, Washington and Wyoming. Alberta and British Columbia are associate members, as are Guam, American Samoa and the Northern Marian Islands. “We’ve got a variety of messages about Alberta,” Dallas said of the conversation he and his colleagues took with them to Nevada. Opportunity was the key word, particularly in terms of the relationship between the CSG-West members and Canada. “Whether that’s energy-related, education, environment, agriculture,” he continued. “Pretty much every sector of our economy that we’re involved in, we see opportunities to work together with CSG members.” However, challenges also exist. One of those challenges concerns securing market access

for Alberta oil sands bitumen, an effort that involves TransCanada’s embattled Keystone XL pipeline that would ship crude to Texas refineries if approved by the federal government in the U.S. “Clearly, in Alberta, we’ve got a number of challenges that these state legislators and senators have a level of influence over, and that is to do with projects that involve moving energy back and forth across the border, Keystone being the highest profile of those,” said Dallas. That underscores the value of building relationships through mechanisms such as CSG-West. “It results in return visits,” he added. “Opportunities to show them what we’re doing in the oil sands. Show them our environmental commitments and the technologies that we’re deploying. “It’s all about relationships.” One of those newly developing relationships could help put minds at ease when it comes to projects along the lines of Keystone XL, as the latest CSG-West meetings featured the signing of an advanced technology memorandum of understanding (MOU) between Albert and Nevada, one that largely revolves around unmanned vehicle technologies. It all began when representatives from the Alberta government travelled to Nevada last year for the Association for Unmanned Vehicle Systems International (AUVSI) conference. “When we got chatting with the people from the State of Nevada and also with the Nevada companies, we realized that the investments that are happening in [research and development] and the actual development of products by Alberta companies really created a complementary opportunity to work with Nevada,” said Dallas. Unmanned vehicles can be used for land, air and underwater applications. “There’s a large scale federal procurement that’s in play that seeks to establish six sites in the United States for the testing and development of these types of products,” Dallas continued. “And, obviously, what is happening in Alberta could potentially enhance the State of

Nevada’s ability to perhaps be successful at that contract. If that were to evolve, than there would be opportunities for Alberta businesses that would go beyond where the status quo is today.” Dallas suggested there is equal enthusiasm from companies from both Alberta and Nevada around sharing information, best practices and technologies as the unmanned vehicle industry attempts to grow. “Alberta’s current contributions and emerging prominence have thrust it into a highly visible role that many are watching closely,” said Michael Hagood, director of program development for energy and environment science and technology at the Idaho National Laboratory. “Alberta’s position in North America and, in particular, western North America, is extremely important as the province addresses water resources, environment, energy, agriculture, transportation, trade and workforce development,” he added. There are obstacles to be overcome, however. “Up until today, the vast majority of the global applications are military, and we see a potential for the scope of that to change in that there’s many commercial applications,” Dallas explained. One obstacle is that unmanned aerial vehicles aren’t currently permitted to fly beyond the line of sight of the operator, which puts limits on their use. “If some of the hurdles around the air space and the safety issues associated with that can be managed,” said Dallas, “whether it’s agriculture, infrastructure, monitoring – pipelines are a great example, I think, of the potential of using these types of vehicles to ensure safety and reliability of our pipeline infrastructure.” Dallas can see a resolution to that problem coming in the not too distant future. “There’s an evolution of technology that potentially could mitigate some of the safety risks that are associated with that,” he said, adding that an important step now is establishing airspace – potentially in Southeastern Alberta – where unmanned aerial vehicles can be tested beyond line of site. Success is that area could

Alberta’s minister of international and intergovernmental relations Cal Dallas led a small provincial delegation to the CSG-West meetings in Las Vegas, Nevada at the end of July.

photo courtesy alberta government

be great news for proponents of pipeline projects such as Keystone XL and Northern Gateway. “The sophistication of the monitoring capability on this type of infrastructure has really advanced dramatically over the past number of years,” Dallas said of oil pipelines. “But further comfort could be provided by continuous air surveillance that would enhance further what’s already a very safe piece of infrastructure.” Dallas said the trip to Nevada was a productive one, at least in terms of raising awareness of the market challenges facing Alberta and its energy sector in particular. “We also had some very constructive meetings with the executive of CSG-West, talking about what the role for Alberta, and potentially other provinces, might be moving forward,” he continued, noting Alberta was able to host the meetings last year. “We’re still not a full-fledged member of the organization,” said Dallas. “There’s clearly a desire to have a conversation about how we can be more actively involved in some of the committee work that CSG-West is involved in. And, potentially, even the executive someday.” That can offer direct and indirect access to government at all levels throughout the United States. “It’s very important to continuously ensure that the mes-

sage about the opportunities … Alberta can offer are out there all the time,” he added. Dallas believes those issues suggest the need for not just a Canadian energy strategy, but a Western North American energy strategy, if not a strategy for all of North America. “There are certainly discussions … at the western governors level – discussions about a western energy strategy,” he said. “And the Province of Alberta has certainly submitted a presentation on our perspective of what that might look like and what the opportunities that would be presented are. Those conversations are ongoing and we have been working with a number of the state governors that are interested in advancing that. “That particular initiative was led by Governor [Gary] Herbert out of Utah. But … we’ve been in conservations with governors in other states and looking at those opportunities.” Dallas indicated that Alberta is keen on moving forward on that initiative and other issues with CSG-West. “Continuous engagement at every opportunity we get,” he said, discussing how to build on the work that had already been accomplished. “We invite these individuals to participate in tours in Alberta to look at not only our oil sands development, but the economic development activities that are happening more broadly.”

• PIPELINE NEWS NORTH

AUGUST 16, 2013

special feature LNG takes to the sea james waterman Pipeline News North

Over the next five years or so, British Columbia could see hundreds of seafaring vessels departing its shores with cargos of the fuel known as liquefied natural gas (LNG), but they may not all be destined for energy-hungry markets in Asia. Some of those ships may simply be embarking on return trips to its own islands. That is simply because BC Ferries announced on July 23 that BC Ferries Commissioner Gordon Macatee approved an application to build three new vessels and the fuel of choice for those ships is LNG. “With those three new vessels, we’re definitely considering going toward LNG,” said Deborah Marshall, BC Ferries’ director of media relations. The transportation company is still awaiting request for proposal (RFP) responses from the shipyards to understand what the cost of moving that direction might be. “And we also have to a bit more … technical analysis before a final decision,” Marshall added. “But we are quite bullish about LNG for the new build.” Indeed, the July 19 order from the BC Ferry Commission approving the new vessels states that “prior to signing a final contract with a shipyard for the design and build” of those new ferries, BC Ferries has to “obtain the commissioner’s approval to select diesel-fuelled vessels rather than LNG-fuelled vessels.” Such a request must also be accompanied by life cycle cost comparison of the lowest cost scenario for each option. Marshall explained that BC Ferries is leaning toward LNG largely due to the potential fuel cost savings. “Back in 2004, we were paying about $50 million for fuel per year. Last year we paid $121 million. So, it’s certainly a huge expense,” she said. BC Ferries uses almost 120 million litres of fuel per year. “With LNG right now,” Marshall continued, “the prices are about 50 to 60 per cent cheaper than diesel.” Three new vessels would only be a small fraction of 25-boat BC Ferries fleet, but Marshall insists the cost savings would still be felt by building those ships to run on LNG. “And we’re also looking at converting some ships to LNG,” she said. “But, of course, the financials have to be there as far as the life cycle cost of the new engines versus tearing out the old ones.” Marshall expects conversion could cost as much as $30 million per ship, but that varies by the size of the vessel. “We would be looking at LNG getting trucked in similar to how we get diesel fuel trucked in. So, it would be delivered overnight – when our ships are tied up overnight – to the terminals,” said Marshall, discussing the logistics of introducing LNG to the fleet. The LNG ferries would need to be refueled just two or three times per week, which is also about the same as the current situation with diesel. “We’re in the process of doing safety cases and risk assessments as far as how that [LNG] delivery would take place,” she continued. “But we would see it being delivered in pretty much the same manner as the regular conventional diesel fuel.” BC Ferries should be awarding a contract to design and build the new vessels by January, which means a decision on the LNG front should also

Public transit in British Columbia is gradually moving towards natural gas as a transportation fuel. BC Ferries just announced that they will be building three new vessels, hoping they will run on liquefied natural gas.

courtesy photo

come at that time. “Over the next 12 years, we need to build a total of 12 vessels. So, if not this go-round, we would certainly be considering for others,” said Marshall. “We could consider dual fuel,” she added. BC Ferries isn’t the only public transit system in the province with its eye on using natural gas as a transportation fuel for its fleets. “We’re going to launch our first ever CNG (compressed natural gas) fleet next spring,” said BC Transit spokesperson Meribeth Burton. That fleet will consist of 25 CNG buses in Nanaimo, just the first phase of a gradual shift toward natural gas that is expected to continue with a second community in 2015. BC Transit has been able to tackle this project with help from FortisBC and a program designed to encourage the use of natural gas as a transportation fuel. As part of that program, it was announced on March 1 that BC Transit would receive a $937,500 grant from FortisBC to aid the purchase of CNG vehicles by heavy duty fleet operators. The $104.9 million in funding for that program is part of the Greenhouse Gas Reduction regulation introduced by the provincial government in May of 2012. Other funding recipients this spring included School District 23 in Kelowna and the City of Vancouver. “That incentive helps offset the cost of switching fleets to natural gas. It helps fund training and upgrades to the facilities. The money can also go toward constructing …fueling stations,” said FortisBC spokesperson Michael Allison. “The cost to purchase a diesel bus is less than it would be to purchase a CNG bus,” said Burton. That differential is where the FortisBC funding comes into play. “When we’re talking about a $15 million fleet, that’s a significant chunk of money that’s coming from FortisBC,” she added. “BC Transit – we’re using taxpayer money. And anything we can do to offset something like this,

which is an innovative, new technology that we’re introducing, it just makes sense. … We’re delighted to be partnering with Fortis.” BC Transit has chosen Nanaimo as a starting point because it offers certain advantages that don’t exist everywhere in the province. “When you’re introducing CNG, you’re going to need a fuelling station. The cost of that is somewhere around $2 million,” said Burton. The transit system in Nanaimo is based where access to natural gas is readily available. “Those facilities were already in place and the cost of introducing a CNG fuelling station was more affordable,” Burton continued. “The cost of natural gas really fluctuates, too, depending where in … B.C. that you live, not just where in the world you live. And so … it’s more expensive in places like Whistler and it’s more affordable in certain places, including a large centre like Nanaimo. “We were also looking at what communities needed a large number of new buses.” A fleet typically undergoes a complete overhaul approximately every 14 years. “To make it more affordable, you’ll do two buses at a time and just do a slow roll out, but there are some communities in Nanaimo where many buses were retiring at the same time,” said Burton. All of those factors meant Nanaimo was the ideal choice for introducing a large fleet of CNG buses to the provincial transit system. “We just needed to do our research first,” Burton said of CNB buses that are not new to North America, but are certainly new to BC Transit. “And we’re delighted to be partnering with New Flyer, which has certainly been part of the BC Transit fleet,” she continued. “They make diesel buses as well. And we’re really familiar with New Flyer and their products. They’re going to build the buses for us out of Winnipeg. And we’re going to treat phase one as a learning period. “We’re going to take a year, assess it, what are the

AUGUST 16, 2013

PIPELINE NEWS NORTH •

the wheels on the bus are fueled by LNG costs – because maintenance costs can be up to 15 per cent higher than it would be on a diesel bus – and what kind of value are we getting environmentally. Because, obviously, sustainability is a BC Transit core value.” BC Transit will also be evaluating the return on taxpayer money and examining how the buses perform in different weather conditions, which can be more extreme in Nanaimo than other parts of Vancouver Island. “That’s what we’ll do before we decide on phase two,” said Burton. Fuel economy is another key concern. Despite challenges that may exist, Burton said natural gas is a good fit for BC Transit simply due to its abundance in the province. “It makes sense that we would use a fuel that’s readily available and that certainly supports industries in B.C.,” she explained. “It’s a cleaner product than what we’re using right now for the most part in our 1,030 bus fleet,” she continued, discussing the advantages of natural gas. “I think Nanaimo is ecstatic to be looking at a quieter technology – CNG buses tend to perform at lower noise levels than diesel buses. And, believe it or not, that is a complaint that we hear at BC Transit. “So, in terms of noise reduction, in terms of environmental impact, there were lots of great reasons why we chose natural gas.” FortisBC is obviously keen on natural gas as well. “The B.C. transportation industry … is responsible for about 36 per cent of provincial greenhouse gas emissions,” said Allison. “Converting fleets and vehicles – any vehicle for that matter – to natural gas helps the province meet its greenhouse gas reduction goals. It also helps improve air quality in the communities where they’re operating. “Natural gas burns cleaner than gasoline or diesel, which results in less pollution. The carbon dioxide emissions, which is usually what’s released from gas or diesel engines, is reduced by 20 to 30 per cent by natural gas vehicles. And there’s really no particulate matter from a natural gas vehicle. So, there would be no smog. “Hypothetically, if you had everyone running on natural gas, there wouldn’t be any smog build-up.” FortisBC wants to encourage using natural gas as

a transportation fuel because it is good for their business as a natural gas provider, but also because wider use of the product is good for existing customers in that space. “Just because it lowers the cost of maintaining the gas pipeline system,” said Allison. “Public transit’s one of the best early applications of the fuel because public transit has some of the best attributes that you need to be successful,” said Mike Most, an Encana vice president concerned with the commercial possibilities of natural gas. Encana has been working hard to encourage the use of natural gas for a variety of applications, largely by talking the talk and walking the walk. “We’ve been working in that space for a number of years,” said Most, noting that over 50 per cent of their drilling rigs and about a third of their company vehicles are running on natural gas. “We work with companies that truck materials to and from our sites on trucks that are fueled by natural gas,” he continued. “And we’ve been working with industry partners for years to make the engines available for others to use natural gas in their business. And we also produce LNG that we provide for people to use.” Most said the primary reason natural gas is good fit for public transit – including a system such as BC Ferries – is the high fuel usage in that sector. “Ferries are pretty hard to beat when it comes to fuel use, but bus systems are no different,” he said. Basically, if a company is burning large quantities of lower cost fuel, the cost savings are similarly large because they are seeing a cost savings benefit on every litre of fuel over thousands of litres of fuel. “Transit vehicles – ferries in particular – return to the same location every day,” Most continued. “In some cases, multiple times a day. So, your infrastructure that you need to invest in … to use the new fuel gets used that much more and you need to invest in that much less of it.” Conversely, the typical passenger vehicle uses less fuel and, although that vehicle does tend to stop at the same locations every day, the schedule is less predictable, fuelling requirements are less consistent and its home base is highly unlikely to contain refueling facilities.

“You just have a lot more infrastructure you got to build,” said Most. “Transit vehicles – ideal. And you’ve got the fact that those entities are looking for cost savings opportunities. LNG is just ideal in that it provides a low emission fuel that allows them to achieve their emissions and environmental goals in a way that’s very cost effective. “Perfect application.” Most said switching to natural gas is all a matter of becoming comfortable with the fuel. “Any time you’re using something new, you’ve got experience you need to develop with it so you can develop your comfort,” he explained. “So, starting small and building confidence, and then expanding from there has been essential for fleet managers to get comfortable with the fuel. “It does require slightly different handling than fuels they may use today. And logistics are a little different. And all of those things are worth getting some experience with, because the cost savings and the environmental attributes are so good. “Walking before you run is a key way to get folks comfortable.” Most mentioned three key selling points for convincing customers to convert to either LNG or CNG for their fleets. “The fuel has a cost advantage over diesel or marine fuel or gasoline,” he said. The environmental benefit is the second ingredient. “The abundance and the domestic nature of the fuel is a key selling point,” he continued. “But I think all of that’s led with the cost. The key selling point is that you can do all that and still save me money. And that’s what’s creating the momentum around this today.” Marshall indicated cost issues have been the main driver for BC Ferries. “Our number one issue from customers is cost,” she said. “If there’s anything that we can do to help mitigate potential fare increases in the future, that’s something that our customers certainly want us to look at. “It’s a cleaner burning fuel. So, that’s better for the environment,” she added. “We just have to make sure we’re getting the best value when we’re going to be building these new ships.”

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AUGUST 16, 2013

industry news Not Just a New Name AER field offices open their doors james waterman Pipeline News North

(Top) Former Energy Resources Conservation Board field offices across Alberta were re-opened in July as the new Alberta Energy Regulator. (Middle) Smiles all around as officials prepare to cut the ribbon. (Bottom) Like red rape, thsi ribbon is harder to tackle than it looks. alberta energy regulator photos

What was old is new again after field offices formerly sporting the name of the Energy Resources Conservation Board (ERCB) began opening their doors as the Alberta Energy Regulator (AER) in July. Following opening of the Calgary head office on July 28, which was delayed by the flooding that hit Southern Alberta earlier in the month, the AER spent about two weeks opening its field offices, starting with the Bonnyville Field Centre on July 9. “Albertans take seriously that development of our abundant energy resources must be done responsibly,” said energy minister Ken Hughes when the new regulator began opening its doors. “Nowhere is this more evident than in the dedicated work of our important field staff.” The AER also has offices in Edmonton, Red Deer, Fort McMurray, Grande Prairie, Drayton Valley, Medicine Hat, Midnapore, St. Albert, High Level and Wainwright, as well as a Core Research Centre, all of which were re-opened between July 9 and July 19. “It’s been around for a really long time,” Cara Tobin, AER spokesperson Cara Tobin, said of the Core Research Centre, adding that it has been storing samples and information for almost a century. “They store slivers, core and other geological data so that government, academia, industry can research it in order to better inform decision-making,” she said. Although the Calgary head office has been up and running since the end of June, the official re-opening of that branch won’t take place until September. “We’ll have a big soiree in September,” said Tobin. “We had all these things planned for the week that the floods happened in Calgary,” she added. “We had to reschedule at the last minute.” The opening of the Core Research Centre included tours of the facility. “Because it’s a little bit more interesting,” said Tobin. “The opening is just a celebration of the 75-year history that Alberta’s oil and gas regulator has in the province,” she continued. “And celebrating the new era of energy regulation moving forward under the Alberta Energy Regulator. “And certainly anybody is welcome to show up at any office at any time and learn more about what the regulator does.” Tobin said the AER definitely feels less like a concept than a reality now that the field offices are operating again. “It’s certainly … a celebration for staff … and we’re acknowledging all the work that’s been done to get us launched under the new regulator and under the new mandate of the regulator,” she continued. “We officially became the Alberta Energy Regulator on June 17. And then, obviously, with the floods, we were launched right into full bore new regulator mode and operating under the new mandate before we were able to celebrate this significant milestone.” Introducing the new name, governance structure and operational structure is just the first phase of launching the new regulator. The second phase will be introducing new regulations once they have been approved by the government. That includes the landowner registry. “The landowner registry is a mechanism for the Alberta Energy Regulator to enforce agreements between landowners and companies,” said Tobin. “The third phase would be introducing the public lands, environment and water functions that are currently with Alberta Environment and Sustainable Resource Development,” she added. “All the phases are supposed to be complete by spring 2014.”

AUGUST 16, 2013

PIPELINE NEWS NORTH •

A Quicksilver jump Quicksilver Resources Canada Inc. reported a big jump in its Canadian production in the second quarter (see table) due to the completion of an eight-well pad in the Horn River Basin in August and September 2012. Unless otherwise stated, all volumes are net of royalties and all dollar amounts are U.S. Quicksilver Canada is owned by Fort Worth, Texas-based Quicksilver Resources Inc., which is focused mainly on unconventional reservoirs in North America, including shale gas and coalbed methane. Total Canadian second quarter production of 103.5 mmcf a day was about 52 per cent higher than the corresponding 2012 period. Canadian production was 13 per cent lower than the first quarter of 2013 due to a planned outage in the Horn River shale gas play of northeast British Columbia. Horn River output returned to pre-outage levels last month. Second-quarter gross production in the Horn River was 68 mmcf a day, or 55 mmcf a day net, which is 20 per cent less than the previous quarter mainly due to a 14-day third-party plant turnaround, which reduced average output for the quarter by 13 mmcf a day. Production from the Horseshoe Canyon coalbed methane play in Alberta averaged 49 mmcf a day during the second quarter. Development activity continued to be limited in the second quarter, though the company expects to start a modest re-completion and tie-in program in the second half of 2013. In an earnings conference call today, company officials reiterated earlier comments that a regulatory decision (DOB, Jan. 30, 2013) against approval of NOVA Gas Transmission Ltd.’s proposed Komie North natural gas pipeline extension into the Horn River Basin is in Quicksilver’s interest. Quicksilver received written notice that NGTL is terminating the project and expenditure authorization (PEA) authorizing construction of a 75-mile pipeline connecting NGTL’s Alberta system to a meter station that would have been constructed on Quicksilver’s Horn River acreage and a related meter station. The unconventional gas producer said NGTL delivered the termination notice because it did not receive the certificate of public convenience and necessity required to develop the Komie North project as contemplated in the PEA. The 97-kilometre Komie North project, an extension to the Horn River mainline, would be built 110 kilometres north of Fort Nelson at an estimated cost of about $230 million for

the pipeline and the required Fortune Creek meter station. The PEA would have necessitated construction of a treating facility and required Quicksilver to provide financial guarantees to cover NGTL’s costs for the Komie North project. Quicksilver previously provided C$14 million in letters of credit to support this obligation. NGTL has indicated that it would release the letters of credit in connection with the payment by Quicksilver of costs incurred by NGTL, estimated at about $13 million. The commitment letter, which required Quicksilver to deliver gas to the Komie North project from its properties in the Horn River Basin, also terminated upon termination of the PEA. Quicksilver said it maintains the ability to sell all of its gas at the Station 2 and AECO hubs; its current production is served by existing treating facilities and pipelines. “The cancellation ... allows us to defer a substantial amount of capital that would have otherwise been spent in the basin,” John Regan, Quicksilver’s chief financial officer, told analysts after the company released its quarterly earnings today. The company is working to reduce its debt as it continues discussions with potential joint venture partners for its Horn River shale gas. Unlike many gas producers who switched to oil and natural gas liquids when North American gas prices collapsed, Quicksilver is focused on its long-term future as a gas producer. In the second quarter the company sold 25 per cent of its Barnett shale assets to a Tokyo Gas subsidiary for $485 million, securing long-term development partner in the Barnett. “The Komie North decision allowed for more time to methodically develop the [Horn River] assets. So that was of benefit to us in the sales [discussions], we believe. It’s certainly been conveyed that way to us from some of the potential buyers,” said Glenn Darden, Quicksilver’s chief executive officer. Quicksilver is bullish about the prospects for exporting LNG from Canada’s West Coast. “We have seen the country and the province really embrace ... the planning of exporting of natural gas. ... On the regulatory side we have not seen a lot of resistance. ... We’ve had good dialogue with regulators, with communities, et cetera,” Darden told analysts. “And it’s a good business environment to operate in.” In response to a question about whether there’s room for several West Coast LNG projects, Darden commented: “We believe a lot of gas is going to be exported because the government of Canada wants it, the province of British Columbia wants it

and it’s good for their country. They’re accustomed to exporting resources. We believe it’s going to happen on perhaps a bigger scale than in the U.S.” The Fort Worth-based company said it is running an integrated, competitive joint venture process in the Horn River with a select group of potential partners. The process is currently in the formal bidding stage. Quicksilver believes its 129,000 acres in the Horn River play holds a potential resource of up to 14 tcf of gas. The company said acreage is well served by existing pipelines and treating facilities and, based on the location and size of resource, could serve as feedstock for future LNG exports. Second quarter net earnings totalled $242.52 million, or $1.37 per diluted share, compared to a net loss of $802.02 million, or $4.72 per diluted

share, in the same period last year. Second quarter 2013 net income included several non-operational items, such as a $333-million gain related to the sale of 25 per cent of Quicksilver’s Barnett shale asset; $86 million in charges related to debt refinancing and acceleration of deferred financing fees; $84 million non-cash deferred tax valuation allowance; a $38 million non-cash, unrealized gain from commodity derivatives; and a $13-million non-cash charge in connection with the termination of the NGTL agreement to build the Komie North pipeline to the Horn River Basin. Excluding these non-operational items, adjusted net loss for the second quarter totalled $11 million, or six cents per diluted share, compared to a restated adjusted net loss of $7 million, or four cents per diluted share, in the prior-year quarter.

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pat roche Oil Bulletin

• PIPELINE NEWS NORTH

AUGUST 16, 2013

industry news

go deep!

Trinidad building big rig for Liard Basin james waterman Pipeline News North Making true the old adage that bigger is better, Trinidad Drilling is building the largest drilling rig in Canada to help an anonymous natural gas producer tackle the deep Liard Basin shale gas play of Northeast British Columbia. The company announced on Tuesday, July 30 that they would be constructing in their Nisku, Alberta manufacturing facility a 3,000 horsepower rig capable of drilling to a depth of 8,000 metres, just the equipment required to extract Liard Basin natural gas that is found deep below the surface. “The biggest challenge is how deep they’re drilling and the high pressure that we’re drilling at,” said Lisa Ciulka, vice president of investor relations with Trinidad, discussing the unique circumstances that exist in the Liard Basin, which is located west of the well known Horn River Basin, straddling the border with the Northwest Territories. “This is the deepest rig that we would have in our fleet,” she continued. “Currently, we have a rig that’s about 6,000 metres depth capacity. That’s working in the Horn River. But this one is 8,000 metres. It’s significantly deeper.” The new rig will also dwarf other rigs in their fleet in terms of hook load capacity. “This one has 1.25 million pound hook load capacity,” said Ciulka. “Typically, the rigs that we’re building for somewhere like the Duvernay in Canada or the Eagle Ford in the [United States] would have a 750,000 pound hook load capacity.” The increased hook load capacity is necessary due to the amount of drill pipe required to drill as deep as 8,000 metres. The rig has to be able to hold that amount of pipe as well as pull it up out of the ground. “And then we have a lot bigger pumps on this rig,” Ciulka added, noting the extra horsepower is essential to pumping drilling mud deep into the borehole. “We would normally have two 1,600 horsepower pumps, but, on this particular rig, we’ll have three

Trinidad Drilling’s Rig 37 has been operating in Alberta’s Duvernay shale gas play since the end of 2012. The company is building on their experience in deep formations such as the Duvernay and Horn River Basin to construct the largest drilling rig in Canada for the very deep Liard Basin in Northeast British Columbia.

trinidad drilling photo

2,300 horsepower pumps,” she continued. “It’s just a lot bigger all over compared to what we have building over the last little while.” Deep wells aren’t new to Trinidad. The Montney formation in the Dawson Creek and Fort St. John area is their shallowest area of operations in Western Canada. The emerging Duvernay shale gas play in Alberta is a bit deeper than the Montney and the Horn River Basin is deeper than the Duvernay. “And then even deeper still is the Liard,” said Ciulka. “It’s a matter of building what we have been build-

ing and scaling it up.” Trinidad already claims one of the biggest rigs in Canada, which is operating in the Horn River Basin currently. “We built that rig a couple of years ago for one of our customers and that’s been operating really well,” Ciulka said of the natural gas-powered rig. “I think part of the reason why we got awarded this contract is that we have built one of the largest rigs in Canada, and we’ve operated that rig, and it’s performed really well for the customer,” she said. Continued on page 22 R001424176

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tax investigation targets peace We pay our fair share, say local contractors

tractors are paid up with the (Worker’s Compensation Board),” he said. “That’s an easy one to detect … they could pay their taxes for them.” He added that those who do not follow this action may find themselves potentially blacklisted by other employers if they are found out. Dawson Creek’s Acting Mayor Shaely Wilbur also said the report “caught (her) a little off guard.”

william stodalka Pipeline News North The Canada Revenue Agency (CRA) has targeted oil and gas operators in the Peace Region as part of a federal probe into cash businesses, resulting in $2.5 million in additional taxes. More taxmen may be needed on the ground locally, as it has been reported that certain oil and gas service operators in the Peace Region are not paying their fair share of federal taxes. However, one woman who works for a Fort St. John pilot car service – one of the industries targeted by the agency – feels differently. “I deal with the CRA enough,” said a woman who worked at a pilot car service, but who did not give her name. “I pay my fair share of taxes ... if they want more, they can come and get it.” The Canadian Press learned about a pilot project targeting operators in B.C. that were being paid in cash and not reporting their income, through an official information request that became the basis of their report. The two-year probe resulted in $2.5 million in additional taxes and fines against certain local service contractors. These included pilot car drivers, who drive in front of wide-load carrying trucks, as well as mobile first aiders, who help provide some medical services to remote work sites, and “hot shots” – couriers who deliver materials quickly to remote locations. The report also seemed to surprise at least one local driver engaged in this type of work. A Fort St. John operator, Zane Willis, said that even though he did not currently do much pilot car work, the companies that he did work for sent out proper invoices. “Nobody really pays in cash,” he added. Willis also said that he did not know of other pilot car operators being paid in cash. “It’s not something people really talk about.” It was also reported that officials concluded that there needs to be further need for closer watch on the ground. The report seemed to surprise both a representative for an oil and gas contractor advocacy organization and municipal officials. Art Jarvis, who heads Energy Services B.C. – a Fort St. John-based organization that says it “provide(s) a united voice from the contractors and service firms located in Northeast B.C.” – said he was surprised that the CRA found so much in unpaid taxes. “Contractors need to ensure that their subcon-

“I feel that the CRA is doing a good job,” she said. “I think the CRA’s hit on a point.” Wilbur said that the CRA needed to continue to put more resources on the ground to ensure that these taxes are paid up. Calls to the CRA asking whether or not these further resources would continue to be in place beyond the pilot project were not returned as of press time.

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Manage employees and create a positive empl team-oriented environment through employee recruitment, development, engagement and motivation

Eﬀective leadership skills, independent thinking, organizational and planning abilities with strong initiative and ability to direct a team

Monitor material and labour costs of ongoing and completed work to project margins and to assist in quoting future work Responsible for budgeting, administration, scheduling and operations as well as reviewing ﬁnancial statements, sales and activity reports, and other performance data to measure productivity and goal achievement Responsible to be a leader in the corporate Safety and Quality programs Consult with relevant departments (Loss Prevention, Quality Assurance, Engineering, Human Resources) to meet Corporate and legislative requirements Work with Estimating in bid and contract review meetings regarding work scope, delivery timeframe, and pricing of projects

Ability to multi-task and oversee a variety of projects and personnel at one time Strong communication and interpersonal skills, including support, motivation, and guidance Excellent analytical and problem deﬁnition and solving skills Eﬃcient knowledge of word processing, kn spreadsheet, and e-mail software and use of the Internet Ability to delegate, set expectations and monitor progress of all direct reports Possess an aptitude in identifying measures of performance and actions needed to improve performance Experience with ERP systems is an asset

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AUGUST 16, 2013

interview on the hunt for oil discoveries An interview with Binh Vu, president of Alberta Oilsands

James Stafford: With the oil discoveries in Kenya and a lot of optimism over other rifts and lake systems including those present in Uganda, Zambia, Tanzania, etc. the East African Rift System has become an emerging oil hot spot. What we want to know is how to make money here without spending a ton of cash in exploration and drilling? What’s the smart way to stake a claim on the East African Rift Basin? AOS: That is a great question. The truth is that this area has become quite expensive as it has been found to be increasingly prolific. Major signing bonuses, deposits, and commitments are required in spots like Kenya, Tanzania, and Uganda. There is very little opportunity for the junior explorers to compete. We believe that Zambia is a fabulous jurisdiction because it shares the geology and rock age in certain large areas that have hosted the Lake Albert Discovery and the Block 10BB Kenya discovery. However, it is totally underexplored for hydrocarbons and thus provides much cheaper access to very prospective areas. Our company has successfully tied up ~18 million acres or what we believe covers about 33% of the attractive rift areas in Zambia which equates to oil and gas rights over about 8% of the country. James Stafford: How does an exploration company on a budget go about covering and “high-grading” targets over such a large area? AOS: Without a doubt that is a highly important question for any company engaged in the pursuit of elephant-sized targets in new frontiers. One of the things that we do is first is aim for concession agreements that don’t tie us to expensive immediate seismic commitments. Second we eschew large and expensive 2-D seismic programs in favor of a process of high grading using satellites, other remote sensing techniques, and ‘ground truthing’. We estimate that by using satellite data analysis over a number of criteria-gravity gradiometry, thermal emissivity analysis, geobotany analysis including vegetation anomalies and geo-microbial review over specific high-graded areas on our acreage--we can save millions of dollars and years of time. We then get to specific areas that are ready for

smaller, focused electroseismic surveys / 3-D surveys, and that can then be attacked as drillable targets either to take on ourselves, or to farm down to majors who are looking for the next major rift discovery. James Stafford: What does the playing field look like right now in Zambia? Who’s there, what are they doing, and how are you positioned to take advantage of all the money being spent there on exploration and drilling? AOS: There are a number of companies there and we have focused on two lakes as well as two dry rifts that show very promising gravity responses from the most up to date databases. Our number one focus is on Lake Tanganyika. This lake spans through Burundi, Tanzania, DRC, and Zambia. There are currently to our knowledge at least three major active seismic programs on Lake Tanganyika including one recently completed by Beach Energy, an Australian company with a $1.75 billion valuation. Beach is directly adjacent to AOS, on the Tanzania side of the Lake. It is likely that Lake Tanganyika will see at least 1 drill hole in 2014. We like Lake Tanganyika as the right spot for the next Lake Albert (3.5 billion barrels reserves) discovery because of the almost identical geological setting and rock age as well as the size of the Lake and the major indications of an existing petroleum system. Lake Tanganyika has multiple oil slicks and natural oil seeps including one that is believed to be the largest natural oil seep in the world. You can see it from Google Earth. James Stafford: You’ve also recently acquired acreage in Namibia, which just made its first-ever commercial oil discovery. What are the prospects here and what kind of timeframe are we looking at? AOS: I’m glad that you asked that. Namibia to us is a potentially direct analogue to all of the major offshore discoveries in Brazil (plate tectonics theory) and Angola to the north. Offshore Namibia has the identical age and rock type as the discoveries in offshore Angola. Combined, those two countries have nearly 30 billion barrels in reserves.

Alberta Oilsands had leases covering 106 sections in the northern Alberta area.

Alberta oil sands image

Namibia itself, however, remains highly underexplored with only 16 wells drilled in 20 years--seven on Kudu Gas Field alone--and the majority of the rest were shallow shelf wells. People are starting to get the idea and now. BP, Petrobras, Repsol, Galp Energia, HRT, are all there. HRT has had success there on their first well of this three-well campaign where they discovered light oil for the first time. Their second well was dry. The third well on which they will begin drilling in August in their PEL-24 block which borders directly on to AOS’ 2.5 million acre land package in the Orange Basin - blocks 2712A and 2812A. We are at ground zero. HRT rates their play chance there at 25 per cent and to my knowledge it is their biggest target--a 30 billion barrel monster. If that one works, I would think that there will be companies knocking down our door. We will know likely in late September, maybe the beginning of October. Regardless, there should be at least five more wells drilled and $500 million to $1 billion being spent offshore

Namibia over the next 12-18 months, so it really fits well with our strategy of being in highly active basins where majors and big independents are spending lots of money around us to prove up major discoveries. James Stafford: AOS’ new Africa portfolio is an ambitious diversification of its original assets in Alberta oil sands. Why the need for diversification here? AOS: It is indeed; however, I think that what shareholders need to understand (and many of ours do not) is that AOS has been traded for the last 24 months strictly on its balance sheet. It basically always trades at its cash per share. Why is that? Very simply there is or has been in recent times, very little capital market appetite or excitement for small companies developing SAGD oilsands plays. Athabasca Oil was one bright spot, but that was a marvel of financial engineering that caught a window. AOS has 500+ million barrels of oil sands resources which are getting no value. Combine a terrible junior market

AUGUST 16, 2013

with complete apathy for this asset class, and the result is a share price that declines almost in lockstep with the treasury, and a total lack of response or enthusiasm to basically just about any kind of positive news. We feel that while AOS is underpinned by its cash and by real assets on which the company has spent almost $65 million developing since 2007, it adds meaningfully to shareholder value by bringing into the fold, as cheaply as possible, blue sky scenarios with major lottery ticket potential and requiring little to no cost commitments over the next 12-18 months. Ultimately, as we gain approval at our flagship Clearwater project in Alberta, part of our plan as we examine our options to unlock value in two distinct plays could be to dividend out our African assets to shareholders into a new company on a 1 for 1 basis, such that shareholders retain 1 pure play share of Oilsands in Alberta (Clearwater, Grand Rapids, Algar Lake), and one pure play share of our 21 million acre and growing high-impact African exploration portfolio (Zambia, Namibia, DRC). James Stafford: Mainstream media reports generally put a price tag of $75 to produce a barrel of Canadian oil sands, but is this really reflective of the true price once you get past the start-up phase? AOS: Some of the junior oilsands development companies that have made the transition to SAGD have stumbled without a doubt. Connacher and Southern Pacific being two recent examples. I believe, however, that the economics are actually superlative once all problems are solved, and of course you can go on producing for a very, very long time. The margins of an operation in full-swing and after start-up/growing pains, are much better than the mainstream media is reporting. James Stafford: For how long will the US continue to need crude from Canada’s oil sands given current levels of production from US shale plays? What is the production price comparison here? Will it cost more to sustain production from wells in the Bakken and Permian Basins? AOS: This is an interesting question. My personal view is that whether it be the US or someone else, there will be no shortage of demand for what the Canadian oil sands can produce. Further, there is a lot more certainty in terms of consistency and longevity of the oil sands assets and their production profile, once they get going. James Stafford: What are your predictions for North American heavy oil economics over the next 2-3 years? Plenty of investors think this is the place to be with a lot of refineries coming out of turnaround and getting heavier and heavier despite all the light shale oil.

Will demand for heavy oil rise? AOS: I read analyst prognostications on this stuff every day. They can certainly have different complexions depending on who you are listening to. To me it’s pretty simple: I don’t believe that prices are going to go outside of a range (below, or above) where extremely healthy margins can be made by good operators, for their shareholders. We will be range-bound here at healthy levels is my overriding feeling on this. James Stafford: What can we expect from AOS in terms of Canadian oil sands development in the next 6-9 months; in the next 2-3 years? What drilling will occur across AOS’ oilsands acreage? AOS: Alberta Oilsands has four main projects domestically, and two of them are sleepers. For our flagship Clearwater asset with 373 million barrels of resources we hope to receive ERCB permits for production in Q4 of this year at an initial rate of up to 5,000 bopd, with a phase II of up to 40,000 bopd. This will be a game changer for us, and is the one thing that probably will move our market much higher immediately. Our Grand Rapids project has resources of 119 million barrels and we have just completed an EUR study that demonstrates its ability to produce as much as 30,000 barrels a day, for 40 years. This is highly encouraging and is totally overlooked by the market. Our third asset is a sleeper asset, in my opinion. AOS has taken on a partner to drill its Algar Lake project. We chose this partner because of its history of great exploration success. The team has, from scratch, made two separate billion+ barrel discoveries in Alberta and Saskatchewan and sold each to the majors. They want to turn their focus to Algar Lake now because it has the potential for cold flow production. Cold flow CAPEX is ~25% of SAGD CAPEX. On the OPEX side and on the operational complications side, it is basically the same story as well. Those are fundamental and major benefits. If I can find a couple hundred million barrels of cold flow today, I think that the world is at my door. The 5 well program this winter will be enough to tell us if we have the next Pelican Lake CNRL’s most profitable operating division per barrel, full stop.

bank, are underpinned by real assets with a real value, and also can provide the excitement and possibility of a geometric return on investment. James Stafford: And does AOS qualify for those criteria?

PIPELINE NEWS NORTH •

and realize that right now they get all of those potential outcomes for free while we sit trading at cash value, with 500 million barrels of oil booked, and 21 million acres of prime exploration ground with 100s of millions of dollars being spent right around it.

AOS: Not to toot our own horn here James Stafford: Thanks very much for James, but my view of the world is: AOS sharing your views with us on both the is trading at just above cash value. Our African landscape for exploration and combined PV10 between Clearwater discovery, as well as the outlook for and Grand Rapids is $823 million--or heavy oil prices and oil sands developabout 225X our market cap net of cash. ment in Canada. We have a very small burn rate. We have multiple catalysts that can take us James Stafford interviews for much higher in the next few months, Oilprice.com including: Success in Namibia by HRT in September; approval at Clearwater for producCERTIFIED tion in Q4; partners on ENFORM our vast African acreage, or other discoveries near EXTERNAL our rift acreage; demonAUDITOR stration of cold-flowing reservoirs at Algar Lake; and a strategic partner • BCCSA Auditor for Clearwater or Grand • Health and Safety Management Support Rapids. • Contractor Evaluation If any of these things • GAP Analysis come to fruition I think • Training that the market and our Stephen Davies CRSP, NCSO, RSO own shareholders will sit 403.392.6000 steve@safetysavvy.ca R001582474 up and take notice again The IUOE 115 represents over 11,000 skilled workers throughout British Columbia and the Yukon. We are part of North America’s largest, strongest, and most established trade unions.

The IUOE 115 plays a key role in placing trained workers on site, meeting the needs of Canada’s growing industrial economy, and securing those who build it.

The IUOE 115 Training Association operates a 40 acre training facility with recognised credentials in over 20 trades, keeping members competitive and employed.

James Stafford: It is no doubt a very difficult time right now for most junior oil and gas explorers and developers-whether with a domestic focus, or an international focus. What do you tell investors?

IUOE 115 membership means a professionally managed pension, health and life insurance benefits, access to our credit union, and the security of being represented by one of the most active and influential unions in Canada.

AOS: I would say that I don’t see that risk capital coming back for some time. It will be very opportunity specific and success driven. You want to look for companies that have the ability to survive for a while with the cash in the

The International Union of Operating Engineers Local 115 4333 Ledger Avenue, Burnaby, BC, Canada, V5G 3T3 1.888.486.3115 www.iuoe115.com

• PIPELINE NEWS NORTH

AUGUST 16, 2013

Operating days, metres decline in first half staff writer Daily Oil Bulletin

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Members of the Canadian Association of Oilwell Drilling Contractors booked 45,607 operating days in the first six months of 2013 in Western and Northern Canada, excluding experimental wells, off 11.6 per cent from 51,565 days booked in last year’s January-to-June period. Total metres drilled also declined during the period, decreasing about two per cent to 9.83 million metres in the first half of this year from 10.02 million metres to the end of June 2012. The average length/depth per well for CAODC members continued to be greater than 2,000 metres. In the first half of this year, it rose to 2,020 metres per well, up from 2,013 metres per well in the year-prior period. It took CAODC members an average of 9.40 days to drill a well over the first six months of 2013 compared to 10.4 days in the January-to-June interval last year. Including oilsands evaluation holes and experimental wells, the top contractor during the half was Precision Drilling. The contractor drilled 1,559 wells and finished 2.58 million metres of hole. Precision’s main customer during the half was Canadian Natural Resources Limited, which accounted for 315 of its wells (20.2 per cent). Cenovus Energy Inc. (142 wells, or 9.1 per cent) and Encana Corporation (117 wells, or 7.5 per

cent) were the following top customers. Excluding test wells, Precision’s share of the market increased to 29.29 per cent in the first half of 2013 from 25.85 per cent in 2012. Precision was the top contractor for horizontal wells during the half with 855 wells rig released and 2.05 million metres of hole (excluding test or experimental wells). Ensign was second with 462 horizontal wells (1.07 million metres), followed by Savanna with 327 horizontal wells (843,976 metres), Trinidad with 283 wells (797,426 metres) and Nabors with 268 wells (794,929 metres). Rig utilization during the second quarter for CAODC members stood at 16.01 per cent, down from 19.93 per cent in last year’s second quarter. For the first half, rig utilization declined to 31.41 per cent from 35.78 per cent a year ago. As usual, smaller contractors dominated rig utilization and most metres drilled per rig categories. Vortex Drilling Ltd.’s two rigs had a 65.75 per cent utilization rate during the half. Highkelly Drilling Ltd.’s 1.4 rigs booked a 59.05 per cent utilization rate, while AKITA’s 38.4 rigs had a 52.5 per cent utilization rate. Bonanza Drilling Inc. ranked first in metres drilled per rig (22,758 metres), followed by Vortex (20,778 metres) and Ironhand Drilling Inc. (20,201 metres). AKITA’s rig #32 drilled 43 wells to the end of June, the highest count for a rig.

AUGUST 16, 2013

PIPELINE NEWS NORTH •

industry news working out labour carter haydu Oil Bulletin

A new B.C. Natural Gas Workforce Strategy Committee action plan suggests the province will require as many as 60,000 workers during construction of projects, followed by more than 75,000 permanent skilled workers for its liquefied natural gas (LNG) plants. The plan assumes that five LNG plants are to be built and operational in northern British Columbia by 2021. However, Edward Kallio, director of gas consulting with Ziff Energy Group, told the Bulletin that building five multi-billion-dollar LNG plants in B.C. within the next eight years appears to be unrealistic. “I just think things are going to get a little tight. Obviously, you see the numbers they’re throwing out there ... that’s a lot of people, that’s a lot of rigs, and that’s a lot of steel pipe plants.” In an e-mail response to the DOB, a B.C. Ministry of Natural Gas Development spokesperson said the province’s timeline estimates for the construction of five LNG plants is based on analysis done by independent consultants using information collected by the provincial government, as well as the consultants’ own independent assumptions. The spokesperson said to date the National Energy Board has issued export licences to three LNG proponents, including the Douglas Channel Energy project, Kitimat LNG and LNG Canada. Another four proposals -Pacific NorthWest LNG, Prince Rupert LNG, Woodfibre LNG, and a proposal by Imperial Oil and ExxonMobil Canada -- have been submitted for export application review. Further, the spokesperson said, the province has approved the Kitimat LNG project and a provincial environmental assessment is underway for the LNG Canada and Prince Rupert LNG projects. Additionally, the B.C. Environmental Assessment Office has received a project description for the Pacific NorthWest LNG facility, which it is currently reviewing. The ministry spokesperson said the ministry is currently working with project proponents to complete negotiations and accelerate final investment decisions, and the prospect is that five facilities can be operational by 2021. According to the province’s action plan released this week, 21,600 jobs would be directly involved in the building of these LNG export facilities and associated pipelines during peak construction in 2016-17, while 41,900 jobs would be created in industries that supply goods and services at the peak of the construction phase. Tom Sigurdson, executive director of B.C. Building Trades Union said in an interview that if all the LNG projects assumed in the action plan report are to

proceed at or near the same time, then the impacts on his province could actually be rather negative. “If all of them go ahead, it’s going to be just terribly problematic. We’ve not had the skills training in B.C. to the degree we should have had over the last 10 years, and we will certainly not be able to put that many people onto the LNG projects in the timeframe they suggest all of this activity may take place.” Sigurdson said the B.C. government would have to make significant improvements to its apprenticeship program immediately in order to meet the demands associated with the construction of five simultaneous LNG projects. “You cannot just have jack-of-alltrades out on these projects. They need a very specific skills set that are going to be required.” The action plan also suggests there would be 2,400 permanent jobs in operating and maintaining the plants and pipelines on an ongoing basis, as well as 61,700 jobs to support LNG operations, including workers required to drill, produce, process and transport the natural gas required to feed the export facilities. Further, there would be another 11,100 jobs in industries benefitting from LNG workers spending their wages in the broader economy. In a news release, Shirley Bond, B.C. Minister of Jobs, Tourism and Skills Training and Minister Responsible for Labour, said it is critical the province look at all sectors, including LNG, and take action ensuring skills training is aligned with current and future workforce needs. “The largest employer in our province’s natural-gas industry, the oil- and gas-services sector, will create the most jobs in B.C. over the next decade, and it is crucial that we have a strategy in place to ensure we have skilled workers ready and trained for future growth.” However, Kallio said, creating so many jobs and developing infrastructure at the scale suggested in the action plan report would be similar to trying to create Fort McMurray in northern B.C. in less than a decade. “I just think the market is not going to take that much LNG that quickly. I think it’s probably going to build out a bit more slowly than they are assuming here.” According to Kallio, it is more feasible to expect a couple of LNG plants could be up and running by 2021, with a third plant complete by about 2025. “There’s only so much market out there, and everyone is chasing the same market,” he said, adding that it is difficult to find LNG investors and there are lots of cost pressures when it comes to such major projects. A Grant Thornton LLP impact review of B.C. LNG employment suggests capital expenditures during construction phase of the LNG plants would total approximately $98.4

billion. While sceptical of the timing suggested in the action plan, Kallio said it appears the province is building a policy around the most extreme case of LNG development. He said preparing for LNG growth is important, as the resource is vital to the energy sector. “The consequences of not doing it are dire for the Western Canadian oil and gas industry. Our basin is producing about 13 bcf per day right now, and without LNG, and without export pipe for oil and the resultant natural gas demand, our basin could be below 10 bcf per day by 2020. “But with LNG, we could be producing 16-20 bcf per day sometime in that 2020-to-2025 timeframe. So that is the swing, and it’s a big swing.” The B.C. workforce strategy committee was formed in March 2012 to develop an understanding of the workforce requirements to build and operate natural gas-related projects, as well as to conduct an environmental scan of the potential labour supply available to projects, building a workforce strategy and action plan to address labour supplyand-demand concerns. Labour is already at capacity in northeastern B.C., suggests the action plan report, and aside from the shortage of local workers to meet workforce requirements, the specific expertise necessary for certain LNG construction occupations is currently unavailable in the region. Further, LNG facility operations require highly skilled workers, and finding and keeping the technical workforce is also a challenge. The report states: “As it stands, northern B.C.’s labour force will simply not be able to meet the labour demand generated by the growth of the province’s natural gas industry.” The action plan calls for development strategies to inform local residents of the industry’s career opportunities and skill requirements, as well as the associated attractive pay and benefits. Many of these workers require skills training and upgrading, and while some capacity exists for expanding current apprenticeship training in northern B.C., the report suggests new approaches will be required, such as increasing high school graduation rates in northern B.C. and supporting the adoption and expansion of “school-to-work mechanisms.” According to the report, industry must actively recruit and train under-represented groups such as women and aboriginals, while the province must target immigration into its northern LNG industry, working with programs offered in conjunction with the federal government. Sigurdson said skilled temporary workers would undoubtedly come from across Canada and the United States to develop these LNG projects, as is regularly the case for such major develop-

ments. However, he said, if LNG projects result in lots of temporary workers coming from other countries in which trades qualifications might not be as guaranteed as in Canada and the U.S., it might be problematic. If the province wants to maximize the economic benefits of this bourgeoning industry, he said, then it needs to do what it can to ensure the regional population is able to profit from these projects. “This is a good news announcement, but the concern I have is that if all these projects proceed at roughly the same time, the news won’t be so good. We’ll be extracting raw resources for a market that’s not Canadian, and if we have to use non-Canadian workers to extract those resources, then some of that benefit is lost.” Workforce strategy committee chairman Geoff Stevens said over the past year the committee has met extensively with industry partners and First Nations to discuss the scope of LNG opportunities in B.C., identifying the need for skilled workers during the development and implementation phases of LNG projects. “The report outlines our key findings and provides government and its many partners with an overview that will help inform future decision making about LNG in our province.” B.C. Premier Christy Clark is to outline LNG opportunities for her province and lead a discussion on building a skilled workforce with other jurisdictions at this week’s Council of the Federation meeting at Niagara-on-the-Lake, Ont., where Canadian premiers will discuss skills training, jobs and the economy. “To make sure our province seizes the full opportunity of LNG, our first priority is building a strong and skilled B.C. workforce,” Clark said in the news release. “The committee’s report is a first step towards charting the course for LNG, and we will continue to work with all partners to make sure British Columbians remain first in line for the best opportunities.” Rich Coleman, B.C.’s minister of natural gas development, said LNG represents an “unprecedented opportunity” for the province, creating employment for future generations. “We have a vision of B.C. as a strong, prosperous and competitive economy and LNG will help us realize that vision for decades to come.” Greg Kist, president of Pacific NorthWest LNG, said this week’s announcement is a step toward meeting the provinces skilled-labour needs and acknowledges the emerging LNG industry is an opportunity for the whole country. “Skilled workers are the key to building and operating LNG facilities like the one that we are proposing in Port Edward.”

• PIPELINE NEWS NORTH

AUGUST 16, 2013

special feature

Down on the farm Rural Quebecers tour Alberta oil patch james waterman Pipeline News North Amidst the debate around shale gas development in Quebec that often pits landowners against industry, a group of Quebec farmers paid a visit to Alberta in early July to look at the interaction between agriculture and oil and gas. Joined by representatives from the Oil and Gas Services Association of Quebec (OGSAC) and the Petroleum Services Association of Canada (PSAC), the delegation made its first stop at the Bassano Dam, a century old project originally designed for irrigation purposes, before traveling to various farms around Brooks, Alberta, just southeast of Calgary. “The whole intent was to have the folks in this room meet up with their counterparts here in Alberta just to kind of show Alberta’s experience with respect to development of oil and gas,” said Mark Salkeld, president and chief executive officer of PSAC, during a July 17 press conference. “[PSAC] is committed to expanding the dialogue around our industry and how it functions,” he continued. “And we believe that through exchanges such as this – access to information – it will help more and more people understand how our industry works and how it works in conjunction with all the other activities that are necessary for the quality of life that we enjoy today.” It is the second such tour involving farmers from Quebec and the two oil and gas service sector trade associations. “Last year, we opened the channel of communication with Alberta,” said Mario Leveque, president of OGSAQ. “We bring people here and we want to show them, when we communicate with people and when we talk together, we can have a harmonious development. And I think that’s what we saw in the last couple of days,” he continued, adding that the group met with farmers’ advocates, surface rights groups and the new provincial oil and gas industry regulator, the Alberta Energy Regularo (AER), during the trip. “The way Alberta and Western Canada is doing business – that’s what we really, really need to implement in Quebec,” said Leveque. Leveque remarked that the message he has been hearing out of Western Canada concerning Quebec is that their provincial oil and gas industry is dead, largely because of the current moratorium on shale gas development, particularly hydraulic fracturing. “We are well alive and we’re moving forward. The oil development in Quebec is there to stay,” he said. Presently, the Province is conducting an environmental study around shale gas, the results of which should be released in November. “In the meantime, we have the chance to talk with our fellow citizens here and to build this [relationship that] is crucial for development,” said Leveque. “The best in the world offshore are the Norwegians. The best in the world onshore are people from Alberta. And we need to learn from the best. That’s the reason why we’re here.” That is why Leveque and his colleagues have opted against similar tours in the Marcellus shale gas play of the Northeastern United States, which is much closer to home. “It’s not about the formation,” he said.

A group of farmers from Quebec were joined by representatives of the Oil and Gas Services Association of Quebec and the Petroleum Services Association of Canada on a tour of Alberta farms in July. Quebec farmers are learning about the interaction between agriculture and oil and gas as their province studies the environmental impacts of shale gas.

Petroleum services association of Canada photo

“The best in the world are here,” he continued. “The best companies are here. The best workers. And I think the set of rules here – it’s one of the best ones to protect the people and the environment and everything around. “Why go where it’s less than the best?” Leveque suggests Alberta benefits from its long history with oil and gas development, which is prevalent across the province, but most Quebecers aren’t as familiar with the energy sector. “Here you have the knowledge and people understand the business. That’s the main difference,” he said, adding he hopes to bring that level of knowledge to Quebec. “We know it’s safe here,” he continued. “I’ve been in this industry for several years. When you use the best practices of the industry, it’s one of the safest ones … in the world. And energy – we need it. It’s the base of all economy. If you don’t have energy, you’re not going to have … any other kind of industry.” Leveque explained that Quebec is on the verge of adopting a new energy policy after the current policy expires in 2014.

“It’s our belief that a good mix of energy is the best way to go,” he said of OGSAQ. “We need to use hydrocarbons. We need to use electricity. And there’s a place for everything. “It’s impossible in this world only to live with electricity and it’s impossible to live only with oil. We need a good mix of energy.” Sabrina Caron, a Quebec farmer who had to use Leveque as her translator, represented the farmers who took part in the tour at the press conference. “She didn’t have any really big concerns because she’s really [critical] of what she reads in the paper and what she saw from the news,” she said. “One of the [biggest] fears for Quebec farmers [is] about the water,” she added, noting how measures such as well casing construction seen during the tour helped alleviate those fears. Caron was also impressed with the level of regulatory oversight in Alberta. “In Quebec right now,” said Leveque, “we have shale gas and we have oil, which people see as two different developments.” Continued on page 29

AUGUST 16, 2013

PIPELINE NEWS NORTH •

environment head in the clouds

Environmental field study in Wood Buffalo planned from August to mid-September staff writer Oil Bulletin A comprehensive environmental field study to gather information on air contaminants in the Wood Buffalo region will happen from August 12 to mid-September . The collaborative study between government, non-government, university and community partners will collect both airborne and ground-based measurements to determine how air pollutants are transformed and transported across the landscape. The intensive study is part of the Joint Canada/Alberta Implementation Plan for Oil Sands Monitoring (JOSM), announced in February 2012 (DOB, Feb 6, 2012). The three-year plan is designed to strengthen environmental monitoring programs for air, water, land and biodiversity in the oilsands region by bet-

ter understanding the state of the environment, cumulative effects and environmental change. The six-week field study will involve a large suite of ground-based measurements taken at two locations, including the Wood Buffalo Environmental Association’s (WBEA) Air Monitoring Station 13 -- established in 2000, and located five kilometres south of Fort McKay. The other monitoring site, which is provided by the Fort McKay First Nations, is set up for the next three years to support this year’s study as well as to also collect long-term measurements in the Fort McKay community. Both monitoring sites included in the study are near surface mining areas and allow for air pollutant mixtures from industry to the north and south to be studied separately. The ground portion of the study is designed to track air pollution levels

as close as possible to mining, upgrading, and other industrial and transportation processes. This will help determine the concentration and type of chemical compounds deposited on the ground over a wide area. In collaboration with the National Research Council of Canada (NRC), the study also includes measurements that will be conducted in the atmosphere using the NRC Convair-580 aircraft. The aircraft, equipped with air quality measurement instruments, will be used for flights over and downwind of the oilsands source region. Additionally, the aircraft will be flying at low-altitude to collect air quality data for evaluation and validation of emissions inventories and to test satellite monitoring of nitrogen dioxide and sulphur dioxide. Data collected through both the airborne and ground-based studies will

be used to evaluate high resolution air quality models for use in the oilsands region. Once the quality control process on the collected data has been completed, it will be made available through the Canada-Alberta Oil Sands data portal. More information on the Joint Canada/Alberta Implementation Plan for Oil Sands Monitoring is available at http://www.jointoilsandsmonitoring.ca. JOSM partners in the air monitoring summer project include: Environment Canada (EC), Alberta Environment and Sustainable Resource Development (AESRD), Fort McKay First Nations (FMFN), Wood Buffalo Environmental Association (WBEA) and National Research Council of Canada (NRC). Academic institutions include Dalhousie University, Carleton University, York University, University of Toronto, University of Calgary and the University of Alberta.

Soggy ground in a rainy summer The Peace Region’s average rainfall this summer has been twice the amount it normally receives from June to August, according to an analysis of Environment Canada historical data. For the month of July alone, Fort St. John received 95.4 millimetres of rain, following on from the 117.3 mm the city received in June. The combined average of 106.35 mm for the two months dwarfs the median rainfall of the past five years of just under 40 mm. Put another way: the total rainfall from June to August in four of the past five years has ranged between 95 and 140 mm. However, the city has already soaked up 212 mm this year, without even counting August. However, 2013 is still not the wettest year Fort St. John has experienced in recent memory. In 2011, the city averaged 111.6 mm of rain from June to August, a total of 334 mm or just over 13 inches – about as much as Vancouver gets during its

famously rainy springs. Local farmers have already started to feel the impact of the wet season. Rob Larson, the manager of Clover Farms near Fort St. John, said that the precipitation has “definitely affected” his business. “We’ve been getting showers every day,” he said. “There’s not enough time for the hay to dry off … it’d be nice to have a break.” Larson said that his business has seen some benefits from the rain, as there is more grass for his cattle to feed upon. He also said that over the past few years, many summers have been drier than he would have liked, so this has allowed some soil to get needed moisture. Those hot, dry summers hit Dawson Creek hard last year, when the region received the least rain since World War II. The area came closer to complete drought than at any time in recorded history, driving the city council to build a wastewater treatment plant to reclaim precious water supplies for residents, farm-

ers and industry. However, the fast reversal of that drought has also caused some problems for the Peace’s grain farmer, Larson said, because the extra moisture can bring new types of fungus into crops that the farmers need to fight.

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william stodalka Pipeline News North

• PIPELINE NEWS NORTH

AUGUST 16, 2013

special feature

It’s playtime Albert’s Wilrich gives B.C.’s Montney a run for the money Paul Wells Oil Bulletin The early promise of the Wilrich natural gas play in Alberta’s Deep Basin is coming to fruition as operators continue to ramp-up activity and well results remain encouraging. Jeremy McCrea, an analyst with AltaCorp Capital Inc., said that only a few years ago the Wilrich was “completely off the radar screen.” Now, with the continued advancement of horizontal drilling, multistage fracturing and completion techniques, the play is evolving at a strong pace. “In this last year it has really started to take off and Tourmaline [Oil Corp.] has been at the forefront of it and Peyto [Exploration & Development Corp.] is close behind,” he said, noting that industry heavyweights Encana Corporation, ConocoPhillips Canada Resources Corp., Husky Energy Inc. and Canadian Natural Resources Limited are also active in the Wilrich. “If you look at where the top Crown land sales have been recently, the $4,400 per hectare around the Minehead region is a top new area of focus for guys and the play that they’re chasing is the Wilrich.” “The Wilrich continues to rank as one of the most active and fastest growing plays in the Western Canadian Sedimentary Basin (WCSB),” said Peters & Co. Limited in a recent report on the play. According to Peters, about 40 Wilrich wells were added during the first quarter, bringing the total count to about 250 wells. The number of wells with more than one month of production increased 26 per cent to 205, giving the firm a broader sample size to work with in its analysis. The firm reported that results continue to be strong with total Wilrich natural gas volumes at approximately 0.42 bcf per day (March 2013), representing a 53 per cent increase year-over-year. “While it is certainly expanding, we continue to believe the development footprint of the Wilrich is relatively compact compared to the size of the prospective fairway and that the number of producing fields should continue to grow,” Peters stated.

mations horizontally -- the Cardium, the Notikewin “We continue to believe that the Wilrich play and the Wilrich,” president and chief executive offiranks as one of the most economic natural gas cer Mike Rose told the Bulletin. plays in North America with Peyto and Tourmaline ranking as our top picks for exposure to this play.” “So far, the horizontal Wilrich results have been According to the report, recent data shows that the best of the three and they’ve been stellar.” Wilrich wells at Edson/Nosehill have average Buoyed by initial results, Rose said that 30-day initial production (IP) rates of 3.8 mmcf per Tourmaline got after the Wilrich in earnest early in day with liquids yields of between 10 and 35 bbls the second half of 2012 and has since continued to per mmcf (40 per cent condensate). The first year ramp-up activity in the play. decline is about 60 per cent and the estimated ulti“In aggregate to date I think we’ve got 38 wells mate recovery (EUR) is 4.7 bcf equivalent (bcfe). drilled and probably 34 tested. We’ve got six rigs All-in costs for a typical well in this area are $5.2 focused on the Wilrich right now and for calendar million. 2013 the goal is to drill somewhere between 45 In the Kakwa/Resthaven region, IP30 rates averand 50 Wilrich wells and we’d like to get them age about eight mmcf per day with about 25 bbls of drilled, completed and the vast majority onstream,” liquids per mmcf (40 per cent condensate). First he said. year decline is 60 per cent, EUR is 9.1 bcfe and Rose noted that results to date have been ahead all-in well costs average about $8 million. of the company’s type curve. He said that 80-plus At Sundance, IP30 is estimated at 4.7 mmcf per per cent of the wells have exceeded internal proday with about 10 bbls of liquids per mmcf (40 per jections of an IP30 rate of five mmcf per day and a cent condensate). First year decline is about 70 first year average of 2.7 mmcf per day. per cent, EUR per well is 4.4 “That [type curve] will give bcfe and all-in well costs are in you a 4.5 to five bcf well and “Wilrich continues the $5.5 million range. we’re doing a little better than McCrea said that recent that. We’ll see how it plays out to rank as one of Wilrich wells drilled by industry over time,” he said. Rose added that liquids concontinue to impress but the most active and tent has been variable: “We’ve because the zone covers a vast expanse, results can vary got some sub-10 bbls per fastest growing greatly. mmcf and we’ve got some at “It’s still quite variable 30-plus bbls per mmcf,” he because the Wilrich channels said. plays in the extend all the way throughout Well costs are trending down the Deep Basin, so depending as the company gains experiWestern Canadian on where you are in the Deep ence and knowledge of the Basin, it does vary,” he said. play. Sedimentary Basin.” Tourmaline began opera“I think we are wearing tions just over four years ago [costs] down. I think we’re carand quickly began assembling rying an average of $5.25 mil– Peters & Co. a large position in the Deep lion per horizontal right now and we think we can take that Basin with the Wilrich being down further when we do more viewed as one of the company’s prime targets. pad drilling,” Rose said. Tourmaline’s first 38 Wilrich wells have been “Then we developed the Deep Basin vertically and horizontally and it looked like a good horizonbroadly positioned over an asset base that stretchtal candidate so we really just focused on three for- es about 250 kilometres from one end to the other.

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PIPELINE NEWS NORTH •

‘Wilrich is kind of a funny play’ Rose said that with six rigs now runtions in cost,” Robinson said. ning, optimization from pad drilling is “Overall, the Wilrich program has set to begin. been very consistent since inception “We’re going to do two- and threein terms of production performance. well Wilrich pads and we’ll frac two or Year-over-year average production three wells at a time and then you curves almost overlap without fail, start seeing some cost savings, on proving that there hasn’t been any your completions especially,” he said. overall deterioration in the perfor“We think we will probably ultimate- mance of the new wells we drill as ly get the costs down to between compared to the first wells back in $4.5 million and $4.75 million for a the beginning.” completed horizontal.” Robinson said that Peyto’s Wilrich Tourmaline’s land holdings in the wells typically have IP30 rates in the Deep Basin total more than 1,800 four mmcf per day range and after sections, though the company one year will decline to between 1.5 doesn’t own Wilrich rights on all of to two mmcf per day. At the beginning them. That said, it has an ample of spring breakup, the company was Wilrich drilling inventory of 1,520 producing about 60,000 boe per day locations. with 21,600 boe per day coming from “I think we have the largest land its Wilrich program. position in the Deep Basin so we’ll All-in well costs have decreased to get the largest capture of this play. between $4 million to $5 million as But there’s lots of room for other efficiencies continue to be gained. operators to drill good Wilrich wells, “We’ve seen drill times come down too, and we hope they do because it from about 25 days to sometimes in helps us understand our acreage bet- the mid-teens in terms of the number ter as well.” of days from spud to rig release,” Rose said that this year’s drilling Robinson said. Enerplus Corporation’s vice-presiprogram of 45 to 50 Wilrich wells is likely the company’s blueprint for dent of operations, Ray Daniels, said that the company has put appraisal Wilrich development going forward. “I think we would maintain the pace capital into the Wilrich during the last of this year unless prices collapse year and it’s now development ready and stayed low for an extended periand is considered one of the next od of time, but that’s not what we near-term growth catalysts for think is going to happen,” he said. Enerplus. Still in its early stages, Daniels said Peyto Exploration’s Wilrich program has been a vital component of the company has drilled five horizonits operational focus since the comtal wells into the Wilrich to date, “but pany turned to horizontal drilling in we’ve had some extraordinary” late 2009 and results. early 2010 and “One of our “Before horizontal wells tested at will remain so over 35 mmcf going forward. “In terms of drilling we didn’t think per day and the well count, if we IP30 was 17.4 were to look at there was much going mmcf per day,” the last several he said. “It’s a very exciting years of drilling, on there.” the Wilrich has play. We own been roughly infrastructure there [and] we one-third of the – Brad Hayes, president number of us growing Petrel Robertson Consulting see production to wells,” chief about 60 to 80 operating officer Scott Robinson mmcf per day.” said. Given current gas price forecasts, “This year we’re looking at a capital Daniels said the company will punch program that sees us drilling about two more Wilrich wells later this year, 100 wells in 2013 and roughly a third moving toward a full-fledged program of those will be Wilrich. It has been, in 2014. and continues to be, a very important “We also have a relatively long propart of our ongoing program.” gram ahead of us here with over 100 Peyto is focusing on the Wilrich in drilling locations that we’ve already its Sundance and Nosehill core got line of sight to,” he added. areas, which means there can be “The economics are robust [but] we slight variations in wells results and have to drive our costs down more -costs. we’re not hitting the $7 million [per “Each of these areas where we’re well] yet.” pursuing the Wilrich has this shoreDespite continued struggling gas face sand deposit and there might be prices, the Peters & Co. report noted a little different depth and a little difthat the Wilrich continues to be ecoferent pressure, so there are varianomic in “select areas” in the Deep

Basin because of strong IP rates and prospective and then over the years, liquids yields, abundant and accessias you move further south, for the ble infrastructure and relatively low most part in place of those shales decline rates. that are in the Wilrich in the north, “Based on our updated type curve you’ve got a bunch of sands and data and current strip prices, the before horizontal drilling, we didn’t Wilrich wells at Edson and Kakwa/ think there was much going on there.” Resthaven continue to rank as the Hayes said the Wilrich is a “complimost economic, with half-cycle break- cated unit” in that it is comprised of a even natural gas prices below $2 per number of different individual sand mcf,” the report said. packages. While it’s still somewhat early in “They’ve got different reservoir the evolution of the play, McCrea said compositions and different characterthat payback on a Wilrich well typical- istics in terms of the oil and gas that ly occurs between 12 and 14 months. they hold and the liquids richness in “Overall, quite frankly, this is lookdifferent areas. ‘Wilrich’ is a real ing to be a highly economic play and grab-bag term,” he said. “It’s really your liquids content helps “The economics are more a collecimprove some tion of plays of that payworking and look to and we’re really back,” he said. just starting to understand that. McCrea be better than the believes the Overall, the Wilrich has the resource potenMontney but you still tial is huge and potential to hold its own, and I think we’re need your gas price.” going to continperhaps exceed, the more develue to see it oped Montney grow as people – Jeremy McCrea play in northunderstand the AltaCorp Capital analyst eastern British variety of plays Columbia and better and betnorthwestern ter and they’re Alberta. better able to “The economics are working and target exactly where they are going.” look to be better than the Montney, To that end, Petrel Robertson is but you still need your gas price. The currently working on a major nonWilrich is drier than the Montney and exclusive study of the Wilrich for a you do need your gas prices to be number of industry clients, and Hayes said the main goal of the initiative is higher,” he said. “Notionally, Wilrich liquids range to “pick apart and understand the from 10 to 30 bbls per mmcf, so if geology” on a regional basis throughyou assume a $4 price at AECO, the out the Deep Basin. Wilrich will be a more economic play “Most companies will have a land base or a core area and they’ll decide than the Montney, I think.” Added Rose: “It’s economic at $3 to pursue the play in that area, they’ll [per mcf] gas ... they are very ecoget to know and understand to some nomic wells in a relatively low gas extent the geology in the area, but it’s price environment.” very difficult to be able to gain the Peyto’s Robinson said the combiperspective of what the geology is nation of low capital and operating doing regionally and what that means costs makes the economics of its in terms of reservoir,” Hayes said. “You might find that you can pursue Wilrich program “robust.” He said that even when gas prices dropped to the the specific sort of play -- the Wilrich $2 per gigajoule range for a period -- in other places, so the knowledge last year, rates of return for the comone company picks up in Resthaven pany’s Wilrich well were still in the might be transferable to another area mid-teens to just below 20 per cent. if you understand the geology well “But the recovery in gas prices enough.” brought these projects back up to Currently considered primarily a natural gas and liquids prone play, well into the 30-plus per cent rate of return on an individual project basis,” Hayes believes the Wilrich could Robinson said. become prospective for oil in some “The Wilrich is kind of a funny areas. play,” noted Brad Hayes, president of “We feel on the basis of our work Petrel Robertson Consulting Ltd. that there are a couple of areas “It was actually originally considwhere the Wilrich is actually producered to be a shale package that was ing oil,” he said. kind of sitting underneath the Falhers “Those are specific play areas, but and that in the Deep Basin in the 70s then again learning about those play and 80s,” he said. areas may allow us to prospect for oil “It really wasn’t seen as anything elsewhere in the Wilrich, too.”

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AUGUST 16, 2013

industry news ‘It’s the talk of the town’ Continued from page 12 “The new customer who’s contracted us to build this rig for the Liard has seen that ability. And so they feel comfortable that we are one of the companies within Canada that can create these kind of rigs and operate them well.” Ciulka noted that the Liard Basin has seen vertical drilling activity in the past, but producers are only now starting to apply the technologies developed in other shale gas plays to that reservoir. “It’s fine for us because we’ve got a lot of experience in drilling these kinds of wells,” she said. “Obviously, it’s a little deeper than what we typically drill, but we’re one of the main drillers in areas like Haynesville and the Eagle Ford in the U.S. where we’ve been doing shale gas wells for a long time. And also we’re one of the most active drillers in the Duvernay and the Montney as well. “We’ve been known in the market

ing in the Horn for probably a couple for drilling deep, technical wells.” years. And the Duvernay for one or Producers presently involved in the two years as well. It’s been really a Liard Basin include Apache Canada gradual growth in that drilling. and Chevron Canada, the two propo“What we’re starting to see now is nents of the Kitimat LNG plan to export B.C. natural gas to Asia-Pacific the capital commitment from some of these customers who are looking to markets as liquefied natural gas prove up reserves so that they can (LNG). get the … Trinidad’s new rig is tied “We’ve been known in the agreements that they to the emerging LNG market for drilling deep, need for their LNG plants,” industry in she continthe province. technical wells.” ued. “It’s really “We’ve the talk of – Lisa Ciulka been adding the town at the moment,” Vice president of investor relations rigs into both the Duvernay Ciulka said Trinidad and the of LNG, addMontney ing that over the last although the little while. And so we’re starting to Liard Basin is new to the company, see definitely an increase in demand activity associated with LNG is just for equipment in these plays.” part of the business these days. Ciulka said the problem the industry “We’ve been drilling in the Montney for … probably four or five years,” she is facing in Canada is that so many of the new rigs have been of the midexplained. “And then we’ve been drill-

sized variety. Those rigs are known as doubles because they hold two lengths of drill pipe. “They’re just not quite deep enough to drill some of these plays,” said Ciulka. “And so if you need a rig for somewhere like the Duvernay, the Horn or the Liard, you really need to have a triple.” A triple holds three lengths of drill pipe. “The customers are starting to demand more equipment and really a lot of that equipment just doesn’t exist,” she added. “So, there is some opportunity for additional new builds, either later on this year or … into 2014 and beyond.” Trinidad isn’t publicly stating a cost for the new rig, but it will be twice the size of rigs that cost the company about $20 million to build. “It’s probably going to take us about a year to build it,” said Ciulka. “This time next year, it would start being commissioned, and probably start moving … into the field then.”

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PIPELINE NEWS NORTH •

cross canada james waterman Pipeline News North A successful open season has not only convinced TransCanada to move forward with their Energy East Pipeline project, but has also inspired the company to expand the capacity of the pipeline from 850,000 barrels of oil per day to 1.1 million barrels of oil per day. The Energy East plan consists of converting about 3,000 kilometres of TransCanada’s underutilized Canadian Mainline natural gas transportation system to crude oil service so that Alberta oil sands bitumen and Saskatchewan light oil can find its way to refineries and export points in Quebec and New Brunswick. The project includes construction of about 1,400 kilometres of new pipeline in every province along the route, as well as a deep water marine terminal in Saint John, New Brunswick jointly owned by TransCanada and Irving Oil. “This is an historic day for TransCanada and an historic day for our country,” said Russ Girling, president and chief executive officer at TransCanada, during an August 1 press conference to announce the results of the open season that concluded on June 17. “Canada has a long tradition of forging important nation-building east-west ties across this country, like the Canadian Pacific Railway, the TransCanada Highway and our own TransCanada Mainline,” Girling continued. “This infrastructure was built to support the east-west trade of goods across our country, support economic development and promote national security. And these bold ventures were all tied to interprovincial commerce and the idea that Canadians across the country should share in the benefits of developing our nation’s resources. Each of these enterprises demanded innovative thinking and a strong belief that building critical infrastructure ties our country together, making it stronger and more in control of our own destiny.” The justification for the new 1.1 million barrel per day capacity is 900,000 barrels per day of 20-year shipping commitments with producers, refiners and international markets. “This response confirms the overwhelming industry support for innovative solutions to move crude oil to markets in Eastern Canada and to elsewhere in the safest, most efficient means possible, which is in a pipeline,” said Girling. “It also underscores the eastern Canadian refiners’ desire to have

TransCanada is moving forward with their Energy East plan to convert a portion of their Canadian Mainline from natural gas service to oil service after the open season process resulted in 900,000 barrels of oil per day of firm 20-year shipping commitments.

transcanada photo

access to stable and less expensive supply from western Canada,” he added, noting that Energy East could potentially replace all oil currently imported from foreign sources to feed those refineries in Eastern Canada. “TransCanada will proceed with the necessary regulatory applications for approvals to construct and operate

the Energy East pipeline system, and with the potential in-service date of late 2017 for deliveries into Quebec and 2018 for deliveries into New Brunswick,” said Girling. As much of the Energy East pipeline would travel along existing rightof-ways used for natural gas transmission, the potential impacts to the envi-

ronment and communities along the route are thought to be minimal. That could mean opposition to the project won’t be as great as the opposition to another TransCanada oil project, the Keystone XL pipeline to move Alberta oil to Texas refineries. Continued on page 24

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industry news $12 billion project is job-creator Continued from page 23 However, Girling stressed that Energy East isn’t a replacement for Keystone XL. “I would like to make it perfectly clear that the demand for Energy East is completely independent from our other outstanding long haul pipeline project, the Keystone XL pipeline, which is underpinned by its own 20-year contracts with Canadian and U.S. production companies, as well as U.S. refiners,” he said. “Those shippers remain committed to that project and bringing it in on time.” Girling also noted that while both pipelines are necessary keep pace with growing North American oil production, they serve different purposes in the marketplace. “In the case of Keystone XL,” he explained, “the refineries on the Gulf Coast want to access more reliable and less expensive supply of heavy oil from Canada and growing supplies from U.S. domestic crude producers, replacing oil in the United States that is currently

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imported from Venezuela, Mexico, West Africa and the Middle East. “In the case of Energy East, Eastern Canadian refineries are interested in accessing growing supplies of light oil as well as some heavy crude instead of continuing to import more than 700,000 barrels a day from overseas sources. “And, of course, Canadian production companies are very interested in accessing tidewater in order to reach international markets, including the U.S. Eastern Seaboard, which, by the way, imports over 800,000 barrels a day.” Girling said Canadian refiners also have their sights set on Europe and Asia. “India is actually closer from a shipping distance perspective to the east coast of Canada than it is to the west coast of Canada,” he added. “We’ve had interest from a number of international parties in the open season process.” The projected cost of the project it $12 billion, but Girling was unable to specify how that cost would be broken down apart from saying that much of the

capital would be spent on new pipeline in Alberta, Quebec and New Brunswick. “This $12 billion project will create thousands of jobs across our country and bring new revenues and business opportunities to local communities,” he said. “Gas pipelines move natural gas, which is compressible, and the motive force for moving the gas are compressors,” said Alex Pourbaix, president of energy and oil pipelines with TransCanada, discussing the logistics of the conversion from natural gas service to oil service. The compressors usually run on natural gas, but can be electric as well. “Oil is an incompressible liquid,” he continued. “Instead of using compressors, we’re not able to use that equipment, and we have to put in electric pumps to pump the oil.” TransCanada would have to install as many as 70 pump stations along the route for Energy East to operate. “Wherever possible, we’re going to build those pump stations on the existing compressor station footprint to mini-

mize our environmental impact,” he added. Pourbaix noted that some of the pipe has been in service for 20 to 30 years, but other sections of the pipe are not as old. “Throughout that period of time,” he continued, “it’s been regulated by the National Energy Board (NEB), which will be the regulatory agency that continues to regulate the oil pipeline. They have exhaustive information as to the condition and integrity of that pipe.” Still, TransCanada will conduct what they call “confirmatory digs” at various points along the pipeline to ensure it is in good shape. “The vast majority of that distance, we don’t have to dig up the pipe, we just have to change the motive force to move the product through the pipe,” said Pourbaix. “The pipe itself – it is of a type and quality and thickness of steel that is entirely appropriate both for transportation of gas and for oil.” Read about the environmental impact of the proposed pipeline on page 25.

AUGUST 16, 2013

PIPELINE NEWS NORTH •

environment

safer and greener Surprising advantages to pipeline running across Canada elsie ross Oil Bulletin

Pipeline is practical, and environmental solution, to transport across Canada.

safe and reliable pipeline infrastructure and are underpinned with binding, long-term agreements.” The project is expected to cost approximately $12 billion, excluding the transfer value of Canadian Mainline natural gas assets. It is anticipated to be in service by late-2017 for deliveries in Quebec and 2018 for deliveries to New Brunswick. It’s the single-largest capital project TransCanada has undertaken. In addition to crude transportation, Energy East will give new purpose to its underused natural gas Mainline, making it more competitive and attractive to natural gas customers. TransCanada is also committed to ensuring sufficient gas pipeline capacity to meet the growing demand and is working with its gas customers to understand their needs, he said. The Energy East pipeline project involves converting a portion of natural gas pipeline capacity in approximately 3,000 kilometres of TransCanada’s existing Canadian Mainline between Burstall, Saskatchewan, and Cornwall, Ontario, to crude oil service and constructing approximately 1,400 kilometres of new pipeline in Alberta, Saskatchewan, Manitoba, Ontario and New Brunswick. Terminals also will be built at Hardisty, Alberta, where the pipeline will start, and in southeast Saskatchewan, said Pourbaix, president of energy and oil pipelines. The pipeline will terminate at Canaport in Saint John, where TransCanada and Irving Oil have formed a joint venture to build, own and operate a new deep water marine terminal. The company intends to proceed with the necessary regulatory applications for approvals to construct and operate the pipeline project and terminal facilities in early 2014. “Our government welcomes the prospect of transporting Canadian crude oil from Western Canada to consumers and refineries in Eastern Canada and ultimately to new markets abroad,” Joe Oliver, federal Minister of Natural Resources, said in an issued statement. “Initiatives like this could allow Canadian refineries

Graphic courtesy daily oil bulletin

to process more potentially lower priced Canadian oil, enhancing Canada’s energy security and making our country less reliant on foreign oil.” In 2012, 83 per cent of crude oil deliveries to Atlantic Canadian refineries and 92 per cent of crude oil deliveries to refineries in Quebec were imported. Most comes from Saudi Arabia, Algeria and Libya and typically costs $30 to $40 more per bbl than domestic crude, said Pourbaix. The pipeline can eliminate eastern Canadian refineries’ reliance on imported crude oil and ensure Canadians receive greater value for their domestically-produced oil. There are 150 Metis and First Nation communities along the proposed route and TransCanada fully respects their legal and constitutional rights and they will be fully consulted, along with other stakeholders, about their insights and local knowledge, said Pourbaix. Alberta Premier Alison Redford said her government has “made a commitment to the project as part of our efforts to build new markets and get a fairer price for the oil resources Albertans own. “This is truly a nation-building project that will diversify our economy and create new jobs here in Alberta and across the country.”

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The proposed $12-billion Energy East pipeline project from Alberta to Saint John, New Brunswick, that will proceed based on binding, long-term contracts received from producers and refiners also offers environmental benefits, says TransCanada Corporation. The 1.1 million bbl per day project will convert an existing natural gas pipeline to crude service. “I think I can safely say that environmental concerns are going to top the list of priorities for a number of our stakeholders,” Alex Pourbaix, president of energy and oil pipelines, said in a conference call. “I am just as confident that the Energy East project will soon become known as a model of environmental responsibility within the energy sector.” That’s because 70 per cent of the pipeline is already in the ground and will not need to be dug up except for some digs to check the integrity of the pipeline and this fact alone greatly reduces the environmental footprint, he said. The pipeline will use existing rights-of-way and many pumping stations will be built at existing compressor stations. The conclusion of the successful open season confirmed strong market support for a pipeline with more than 900,000 bbls per day of firm, 20-year contracts to transport crude oil from Western Canada to refineries in Montreal, Quebec City and Saint John and to two export terminals, one in Quebec City and one in Saint John. The shippers include domestic producers, Canadian refiners and international marketers, Russ Girling, TransCanada’s president and chief executive officer, said in a conference call. TransCanada increased the size of the project after interest during the open season that closed in June exceeded the initial design capacity of 850,000 bbls per day. “This response confirms the overwhelming industry support to move crude oil to markets in Eastern Canada and elsewhere in the safest, most efficient means possible -- which is in a pipeline,” he said. “It also underscores the desire of Canadian refiners to have access to a stable and less expensive supply from Western Canada.” Eastern Canadian refiners are interested in accessing growing supplies of light oil as well as some heavy crude instead of continuing to import more than 700,000 bbls a day from overseas sources, he said. Western Canadian producers also are interested in reaching tidewater in order to reach international markets, including the U.S. Eastern Seaboard, which currently imports more than 800,000 bbls per day of oil from overseas. Tidewater would also provide access to markets in Europe, Asia and India, which is closer to the East Coast of Canada than the West Coast. “This is a historic opportunity to connect the oil resources of Western Canada to the consumers of Eastern Canada, creating jobs, tax revenue and energy security for all Canadians for decades to come,” Girling said in a press release. “Energy East is one solution for transporting crude oil but the industry also requires additional pipelines such as Keystone XL to transport growing supplies of Canadian and U.S. crude oil to existing North American markets,” he added. “Both pipelines are required to meet the need for

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AUGUST 16, 2013

PIPELINE NEWS NORTH •

as the sun hides

james waterman Pipeline News North

St. Mark’s Food Bank in Dawson Creek has received almost $7,000 and just over 600 pounds of food to help those in need thanks to Encana and the World Professional Chuckwagon Association. The funds and food were raised through the annual Race Against Hunger campaign led by the Canadian natural gas company and their friends in the WPCA. The tour makes stops in Grande Prairie, Ponoka, Strathmore, Rocky Mountain House and Calgary in Alberta, the lone British Columbia stop coinciding with Dawson Creek’s Fall Fair and Encana’s Community “Pardner” BBQ. “You’ll find … that donations are made at Christmas time, but the need is there year-round,” said Fiona Liebelt, a community relations advisor with Encana, explaining the reason for a summer food drive. Throughout the campaign, Encana matches cash donations dollar for dollar and chips in two dollars for every pound of food donated. WPCA members also help collect donations of food and cash through their “food driver of the year” competition that includes a grocery-bagging contest in Dawson Creek. The 2012 campaign contributed grand totals of 11,536 pounds of food and $103,246.49 to local food banks. Photos courtesy Encana unless otherwise indicated.

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AUGUST 16, 2013

industry news

doubling capacity ‘A large increase’: National Energy Board decision adds one bcf per day for TransCanada Corporation contracts elsie ross Oil Bulletin TransCanada Corporation has added about one bcf per day of new firm transportation contracts on its Mainline system since a National Energy Board decision in March on rates and tariffs, says a company executive. “That’s quite a large increase,” Karl Johannson, executive vice-president and president, Natural Gas Pipelines, said in a conference call as the company discussed second quarter 2013 results in which it posted improved net income, revenue and cash flow (DOB, July 26, 2013). Prior to the NEB decision (DOB, March 28, 2013), TransCanada had about 1.1 bcf of firm contracts as shippers in recent years have opted for short-term firm transportation (STFT) or interruptible service (IT) as more spare Mainline capacity became available. About 40 per cent of the new FT contracts have been since July 1 when the new rates took effect, he said. A lot of those contracts have been on the Empress to Emerson to Great Lakes or in that area, although there has been contracting right across the board from Alberta delivery points, analysts heard. The new contracts are for one to three years. The board in its decision gave TransCanada a broad range of flexibility for short-term (STFT) and interruptible (IT) services and the company’s goal is to maximize both throughput and revenue and is trying to price accordingly, said Johannson. In its ruling, the board said the bid floors for STFS must be set at 100 per cent of the corresponding FT (firm transportation) rate or higher. The NEB found that the previous pricing methodology for IT and STFT was not appropriate as shippers using those services to meet a firm operating requirement did not contribute sufficiently to the Mainline’s fixed costs. “Our tolling structure changed July 1 and what we are trying to do is understand what value people derive from it for different segments in different parts of our systems over different periods of time and make sure that we price accordingly to capture the value that people see in our pipeline,” added Russ Girling, president and chief executive officer.

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Mainline throughput volumes averaged 3.9 bcf per day (704 bcf in total) for the six months ended June 30, 2013, down from 4.4 bcf per day (804 bcf) for the comparable 2012 period. Physical receipts originating at the Alberta border and in Saskatchewan for the first half of this year averaged 2.2 bcf per day compared to 2.5 bcf per day the previous year. Field receipts on the NGTL system for the six months of 2013 were unchanged from 2012, averaging 10.2 bcf per day. In May, TransCanada filed an application for a review and variance of the NEB decision. The board dismissed the application but recognized that some proposed changes should be considered as a separate application through an oral hearing that will begin Sept. 3, 2013. TransCanada has submitted its tariff change application and will manage that through the hearing. The company has asked for some changes to the contracts and will likely have several of these going forward in the new pricing environment, he said. “We have to change some of our contracts to make them look less like the old world of cost service and more like the new world of merchants,” said Johannson. TransCanada at the September hearing will be looking at modifying the renewal options and eliminating diversion rights for shippers, he said. In its decision, the NEB also indicated that if TransCanada proceeds with an Energy East application to convert spare natural gas pipeline capacity to oil transportation it can go back to the board and ask it to look at how rates are determined on the system, he said. “I suspect at that time we would be back in front of the NEB looking for the impact of that transfer and looking for different rates,” said Johannson. Part of that will be dependent upon discussions and negotiations with the shippers on both sides (gas and oil), said Girling. “We are active in those discussions right now and are trying to find the place that works best for both parties.” Within the next two weeks, TransCanada expects to have an announcement on its proposed Energy East project, which would transport up to 850,000 bbls per day of crude oil from western receipt points to eastern Canadian markets as far east as Saint John, New Brunswick, said Alex Pourbaix, president of energy and oil pipelines. While the company will have binding shipping agreements, there also will be some cost sharing of development costs and capital cost risks once it is into the construction phase, said Girling. On the West Coast, TransCanada is extremely active in preliminary work in providing pipelines to transport natural gas to the PETRONAS-led Pacific NorthWest LNG Limited Partnership project to Prince Rupert, British Columbia, and the Royal Dutch Shell LNG project to Kitimat, said Girling. It is well underway with filing its project descriptions to the environmental agencies, has engaged in stakeholder consultation, and is working on engineering and route design, he said. “We hope to be in a position to receive regulatory approval for those projects by the time these projects receive

their sanctioning point.” Over the next 24 months, TransCanada expects to spend between $200 million to $300 million preparing for and participating in LNG regulatory processes, he said. In the second quarter, TransCanada also acquired the first of nine Ontario solar projects for $55 million. TransCanada has placed $700 million of new facilities into service in 2013 and has applied and received approval from the NEB for an additional $130 million of new facilities. So far this year, it has applied for an additional $145 million of facilities, which remain subject to NEB approval, and its planning regulatory applications for further expansion into B.C., which it estimates will cost between $1 billion and $1.5 billion, to connect and transport new gas supply that will be delivered to the Prince Rupert Gas Transmission Project as well as other markets served by the NGTL System. The B.C. Environmental Assessment Office has indicated that the Prince Rupert project is reviewable and requires an environmental assessment certificate. The Canadian Environmental Assessment Agency (CEAA) initiated the public comment period with respect to the project in June 2013. In the third quarter of this year, the company expects to begin an open season to provide delivery service through a transportation by others arrangement on Coastal GasLink to Vanderhoof, B.C. On the oil pipelines side in Alberta, TransCanada filed a permit application with the Alberta Energy Regulator for the proposed Northern Courier Pipeline after completing the required aboriginal and stakeholder engagement and associated field work. It continues to work with the Fort Hills Energy Limited Partnership on the development of the project. The company also has filed a permit application with the AER after completing the required aboriginal and stakeholder engagement and associated field work for the Grand Rapids pipeline system. It will be the first pipeline to connect the growing oilsands region west of the Athabasca River to the Edmonton/Heartland region and will be capable of moving up to 900,000 bbls per day of crude oil and 330,000 bbls per day of diluent. In addition, TransCanada has filed an application with the AER for the Heartland TC Terminals, which is expected to have storage capacity for up to 1.9 million bbls of oil. Later this year, the company expects to file an application for a crude oil pipeline that could transport up to 900,000 bbls per day from the Edmonton region to facilities in Hardisty, Alberta. The two projects have a combined cost estimated at $900 million and are expected to come into service during the second half of 2015. wIn the United States, construction on the $2.3 billion Gulf Coast Project, excluding the Houston Lateral, is now 85 per cent complete and should be in operation late this year. Construction of the 76-kilometre Houston Lateral is expected to be complete in 2014 at a cost of $300 million.

AUGUST 16, 2013

‘The best in the world are here’ Continued from page 18 The province currently as a moratorium on hydraulic fracturing until the environmental study is completed, but oil production is actively taking place about 500 miles east of Montreal and farther east toward the ocean. “More than 70 per cent of people want to see … the oil development. It’s a good starting point there,” said Leveque. Leveque believes the environmental study will persuade Quebecers of the merits of shale gas development, too. “I know it’s safe as a person from the industry,” he said. “And I know the scientists can prove that it can be done properly and safely. And Quebec really needs this energy. It’s not like it’s a surplus.

“It only makes sense for us to move forward.” Leveque said there are farmers in Quebec that are actually eager to move forward with shale gas simply because it is a fuel they can use for drying their grain, allowing them to save $60,000 per year if it can replace the propane they currently use. Mining, a big industry is Quebec, is also a big user of natural gas. “We’re going to need even more natural gas if we want to do it properly. We need more natural gas than bunker oil,” said Leveque. Shale gas also holds significant economic benefits for landowners. “There’s no crop that you can grow in the world [that] will make as much money [as] a lease pad.” R001424278

Working with industry to help eliminate work-related incidents and injuries Enform is the safety association for Canada’s upstream oil and gas industry. Established by industry for industry, Enform helps companies achieve their safety goals by promoting shared safety practices and by providing: » Effective training, including courses on general and operational safety programs and petroleum fundamentals » Expert audit services » Professional advice Our vision is no work-related incidents or injuries in the upstream oil and gas industry. Contact Enform today for more information.

Email bc@enform.ca Fort St. John 250.785.6009 Toll-free Toll-free 1.855.436.3676 (855.4ENFORM) Email bc@enform.ca Fort St. John 250.785.6009 1.800.667.5557 www.enformbc.ca www.enformbc.ca

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Most new jobs in oil and gas INDUSTRY Focus on ensuring skilled labour force is available william Stodalka Pipeline News North

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Workers totalling more than three times the population of Fort St. John will be needed in B.C. once certain liquefied natural gas (LNG) projects come online in the province, according to a new estimate put out by the province. The government released its new BC Natural Gas Workforce Strategy Committee report. It said that the province would need more than 75,000 permanent skilled workers over time, and during 2016-2017, 60,000 workers will be needed during peak construction. “The oil-and-gas services sector will create the most jobs in B.C. over the next decade, and it is crucial that we have a strategy in place to ensure we have skilled

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workers ready and trained for future growth,” said Labour Minister Shirley Bond. “It is critical to look at all sectors, including LNG, and take action to ensure that skills training is aligned with the jobs of today and tomorrow.” The report also stated that northern B.C.’s labour force won’t be able to meet this labour demand. The B.C. Natural Gas Workforce Strategy and Action Plan said more action is needed to retain talent from other regions and increase employment of local talent. Some steps identified in the plan include developing an enhanced apprenticeship model, developing occupational standards and assessment tools for labourers, and creating a post-secondary LNG operator training program. Another strategy would be to provide training to help regional businesses participate in procurement processes. The province also suggested conducting information R001573663

Roy Northern Land and Environmental, a leading Surface Land Broker in the north, is currently recruiting the following new positions in Fort St. John.

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sessions in regions with higher unemployment rates among in-demand occupations, including through southern B.C. Finally the province also suggested researching how best to bring in workers for permanent work, and offering work arrangements that support temporary relocation for short-term labour demand. In 2012, B.C.’s natural gas industry employed about Sun Bridge Windpower Project 13,000 workers, according to provincial estimates. The province estimates that during 2016-2017, more than 21,000 jobs will be needed to build LNG export facilities, and about 42,000 jobs will be created in goods and services industries for this construction. Once these plants are fully operational, 2,400 permanent jobs will maintain the plants, about 62,000 jobs will support LNG operations, and 11,000 jobs will be created from other industries that benefit from LNG workers spending their wages in the local economy.

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Join our staff of 25+ on large scale pipeline projects and drilling programs. Experience working with the OGC and 2-5 years experience in the industry would be considered an asset. If you are seeking a challenge, and would like to become part of a dynamic, aggressive team working with Industry Leading Clients, please apply to: HumanResources@RoyNorthern.com

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