ith crude oil hovering near US$100 per barrel and light oil reserves depleting, the oil sands and heavy oil in the WCSB have become increasingly attractive to the energy investor.
Heavy oil is, by definition, any oil having an API gravity of less than 22.3 degrees, making it highly viscous and difficult to extract using conventional methods. Some 97% of Canada's oil reserves are heavy, the bulk of which is trapped in the oil sands. Conventional heavy oil production forms a significant proportion of Canada's current oil output.
Oil sands comprise water-logged clay and sand laden with heavy oil. The oil sands of northern Alberta and western Saskatchewan are believed to be the result of oil seeping from southern Alberta, pushed by the same tectonic forces that created the Rockies. Estimated to contain between 1.7 and 2.5 trillion barrels of oil, the oil sands are the world's largest known agglomeration of oil.
The oil seeps to the surface at points and is often exposed in river banks. The oil sands were first discovered by the indigenous peoples of the Athabasca region. Later, early European travelers recorded the presence of unusual tar-like substances in the area. The challenge of finding a method to extract the oil from its burden was met relatively early. In the 1920s, Dr. Karl Clark invented the hot water separation method that still forms the basis of most modern extraction processes. But it took rising oil prices, further tinkering and substantial support from the Alberta government before the oil sands could be exploited for commercial gain.
The province's main oil sands reserves are found in three main areas: Athabasca, Cold Lake and Peace River. In total around 1.4 million barrels are produced each day, with production expected to grow to 3.5 million barrels a day by 2025.
The first oil sands operations employed open cast mining techniques to get at the prize, and it is these mines that have become, for better or worse, the poster image of the Canadian oil and gas sector.
In-situ: More than just mining
Today, just over half of oil sands production comes from these mines but, going forward, in-situ, or 'in place' extraction methods, will account for 80% of production. The belief that open cast mining is the oil sands underlines a common misperception surrounding the oil sands. As Richard Gusella, president and CEO of in-situ oil sands producer Connacher Oil and Gas, puts it: "Not all oil sands are created equally... In fact, within a given accumulation, every well is created differently and must be treated as such. It's like your kids."
"When oil is close to the surface, it's cheaper and more efficient to strip mine," explains Gusella. "You can also recover virtually 100% of the reserves. But when you're down below the surface and the depth precludes the application of mining, you have to look at other ways of getting oil out of the ground. That's where SAGD or other in-situ applications start to emerge."
"The trick with heavy oil is heating it to make it flow better," says John Wright, president and CEO of Petrobank Energy and Resources.
Steam Assisted Gravity Drainage (SAGD) is an enhanced recovery method to extract heavy oil using steam stimulation. The process involves drilling two horizontal wells at different depths. One well injects steam into the reservoir to reduce the viscosity of the heavy crude oil or bitumen. The air drives a process of combustion underground which separates the oil from its burden and evacuates the oil through the second well. The other, lower well, collects the oil and bitumen that flows out of the formation. SAGD is the newer, more effective version of regular steam flooding techniques and Cyclic Steam Stimulation (CSS).
The in-situ oil sands sector is characterized by a group of larger, often privately held, juniors, who develop proprietary technology to help them gain an advantage in the oil sands. Amongst them the race is on to improve upon SAGD.
"The heavy oil industry has been around for a long time and there have been many technological improvements since the 1970s and '80s," says Barry Lappin, president of the Canadian Heavy Oil Association. "We have international investors that are interested in bringing this technology to Asia that are coming here to learn."
Wright recognizes that "ours is a business of creative destruction and of technological advances...one of the reasons why there are huge accumulations of (heavy oil) is because it won't go anywhere unless you give it some energy to mobilize."
The principle with heavy oil and the oil sands has been that "you put a lot of energy into the ground and get a lot of oil out," in the words of Wright. "The pace of development has been fast in recent years: When we came along...SAGD…was just into its commercial phase and now they are planning to produce 1million BOE per day with it in Alberta."
Petrobank's proprietary THAI process offers its own benefits: "THAI removes the whole process of generating steam, so it is more efficient from an energy perspective. Another advantage is that, by duplicating some of the conditions in a refinery, we create a partial upgrading of the oil and it comes out of the ground at a much higher quality than its original, crude state," continues Wright.
"We are not burning natural gas, which lowers our operating costs and because of this our surface footprint is much smaller. Our extraction rate is higher because we can sweep the fire through the reservoir at a much higher temperature, which means that recovery rates are twice as much as you would get from other technology."
The THAI process produces less CO2 compared to SAGD, though Wright comments: "That wasn't our main goal. We wanted more oil out of the ground, for less cost and a higher sales price. It just so happens that we have lower CO2 emissions. The CO2 thing is a bit of a throw-in. It is an attractive thing for investors, but at the end of the day, it's like a tobacco producer saying his cigarettes cause less cancer."
Heat, typically generated by gas, represents the largest chunk of the cost that makes in-situ heavy oil more expensive to produce than light oil. Reducing energy consumption should therefore improve the economics of an operation as well as reducing GHG emissions. Laricina Energy, one of the largest privately held companies working the oil sands, is combing solvents with SAGD to further enhance recovery. "SC-SAGD has the elegance that you see in a hybrid car. It's a SAGD like any other, but with another 'engine'—in this case, propane," explains Laricina CEO Greg Schmidt. "Because of its characteristics, propane leaves less oil behind.
"SC-SAGD uses the same facilities, well pairs and pumping equipment, but it's an enhancement," adds Schmidt. "That's what allows the commercialization to proceed in a timely way... If I can get the same amount of oil using less steam and water, it's more efficient and my costs per barrel of production are lower.
"Because my wells also produce more oil and at greater rates, I end up with better economics...The enhancement of the solvents means that we can measure our carbon footprint very close to those of average oil imports (from outside North America)."
When it comes to extracting conventional heavy oil, the Canadians' lead in innovation and many of the techniques being developed for in-situ oil sands applications can be transferred across to extracting conventional crude, and vice-versa.
Connacher's early innovation was driven by a desire to improve production rates and drive down the amount of water being extracted along with the oil. "The reservoir was conventional heavy oil that would flow cold, about 13 API," explains Gusella. "The problem with cold production was that you had gas over oil over water, and water would produce preferentially, so the oil was assigned a very low recovery factor.
"We had to figure out how to get oil without water producing preferentially," he adds. "We initiated an experimental project, which was the first horizontal well into a conventional heavy oil basin. That turned out to be a great success. It was a significant precursor to what's going on in the oil sands right now and also in other aspects of the heavy oil business throughout Canada and the world. We thought that if we could be this successful in heavy oil then why not apply it to other areas as well?"
Connacher has continued to find new methods to tackle its assets, including being the first company in the world to install high-temperature down-hole pumps in a heavy oil well with the intention of further reducing the steam-to-oil ratio.
Using the Cold Heavy Oil Production with Sand method (CHOPS), Baytex Energy Corp. has been able to keep costs low. "It's low cost because there is no fracturing required," says Anthony Marino, CEO of Baytex, a heavy oil producer in Saskatchewan and Alberta. "It's mostly cold production, not even any steaming."
The company uses horizontal cold wells that don't require any mining or heating. "We've had a 100% success rate and successful wells," Marino continues. "The configuration is one of multi-lateral wells with very high efficiency. We have thermal recovery tested at two different levels. There are very low steam ratios and so we use less fuel and save costs there."
Adds CHOA's Lappin, "Through new technologies we are starting to see collaborations amongst producers to pool technology and ideas. There is a lot of research that is being done."
Developing the oil sands
Despite the widespread, successful use of SAGD over more than a decade, E&Ps must often educate both investors and the public about in-situ extraction in general, on top of their own, specific projects.
Alberta Oilsands Inc. owns 140 net sections of oil sands leases in the heart of the Athabasca oil sands, including land adjacent to the town of Fort McMurray. "Fort Mc," as it is affectionately known, is at the center of the oil sands industry and counts amongst the most pro-oil cities in the world.
Even in the heart of the Canadian oil patch, stakeholders need to be communicated with effectively. "There is a lot of confusion out there," states Shabir Premji, executive chairman of Alberta Oilsands Inc. "People do not understand SAGD technology, which has a tiny footprint compared to mining."
Alberta Oilsands Inc.'s most advanced project, Clear Water, is adjacent to the local airport and close to the city, so public recognition and understanding are fundamental for its progress.
The economics of the project look attractive, with a pay zone that is around 45m thick with very few laminations, no water and its own infrastructure. The project's first phase will produce 10,000 barrels per day (bbl/day) with a second phase potentially boosting production to the 25,000 bbl/day mark. The addition of solvent into the SAGD process should help lower the steam-to-water ratio substantially.
"When you look at our Clear Water asset, you can see that our pay zone vents into the Clear Water River because it has cut through the bitumen. However, we are steaming nowhere near the river and operating at low pressures. There is no way that the steam could travel that far. We are a shallow reservoir and Suncor has been producing from similar depths for 10 years. We are not drilling under the airport, we are adjacent to the airport and we were told that the project is a non-starter unless they were convinced that it could be operated safely."
Alberta Oilsands Inc. has taken a progressive approach to enfranchise key stakeholders. "Although we are going to be paying royalties to the government of Alberta, we have entered into a gross over-riding royalty agreement with the airport," explains Premji, who considers them a major stakeholder. Premji mentions the benefits for the airport, which "wants to expand their facilities, but do not have any direct funding. At $80 oil they will receive some $150 million in royalties over a 30-year period."
Interested parties are being won over by the commitments and procedures Alberta Oilsands Inc. has put in place to ensure safety at Clear Water. "The systems that we are bringing in are the most sophisticated systems to be found. The plant will be one of the greenest plants around and will provide employment for people who are able to stay at home and work instead of commuting for miles."
Oil sands are a longer-term play than most conventional oil and gas investment opportunities. While most resources are known, delineating a specific development can take many years and be extremely capital intensive.
"This is a great industry but, just like any other industry's megaprojects, it's not very good at cost control," says Gusella of Connacher. "We had to be very efficient with our use of capital."
All things being equal, netbacks on oil sands are lower than for conventional oil and until recently, it has taken considerable nerve for anyone other than the majors to expose themselves to this asset class. However, pioneers who got in early have been rewarded. As Harvest Energy CEO John Zahary, whose asset base includes 42,000 acres of oil sands leases in northwestern Alberta, puts it: "We got into it because everyone else got out of it! The safest thing [at the time] was to have a natural gas strategy but we decided not to go down that route."
Scalability is key with oil sands projects, and some juniors have managed to assemble large land positions to this end. Sunshine Oil Sands, a privately held junior, has managed to build a large portfolio in a matter of years. "Sunshine was formed in February 2007 and started off with four sections and has grown to over 1,800 sections today," relates co-CEO John Kowal.
"We have...almost 1.2 million acres," continues Kowal, "which represents about 7% of all of the leases that have been allocated in the Athabasca oil sands region. We have 100% ownership and operatorship of those lands and our latest independent resource report has allocated us 43.8 billion barrels of petroleum initially in place, 2.2 billion barrels of best case contingent and 54 billion barrels of 2P reserves."
Sunshine managed to assemble its land position the old-fashioned way, and Kowal explains: "All of our lands were purchased through land sales so there were no corporate deals or acquisitions...As more delineation was carried out in the area and resources assigned, companies realized the values inferred in our areas and subsequently numerous companies participated in a land rush."
"If you're looking for long-term, stable investments, the in-situ oil sands side of the equation is probably a good bet. Some 80% of the oil extracted from the oil sands will be extracted using in-situ processes and the oil sands represent 97% of Canada's 175 billion barrels of reserves," argues Pat Nelson, vice chair of the newly formed In Situ Oil Sands Alliance (IOSA). Nelson cautions, however, that the resource requires "patient capital."
Canada's controversy
Without doubt, the oil sands are Canada's most controversial resource. Disturbance caused by open pit mines and the assumption that oil sands oil has a high carbon foot print make this one of Canada's bug bears on the international stage. Canada is of course one of the few major hydrocarbon jurisdictions in the democratic world, and whatever the rights and wrongs, it's a lot easier to campaign against the Canadian oil sands than it is against Venezuela's heavy oil operations.
Working to reduce the environmental footprint of oil sands oil and doing a better job at educating the world about it are key challenges for the industry.
It takes about 1,200 cubic feet of natural gas to produce one barrel of bitumen from in-situ projects and about 700 cubic feet for integrated projects. Currently, the oil sands industry uses about 700 million cubic feet per day of purchased gas, or about 5% of the Western Canadian Sedimentary Basin's production.
"We are looking to reduce the impacts on water and reduce the costs so that companies will become more efficient," Lappin explains. "There are a lot of new technologies on the in-situ side and there are a lot of different approaches that are being commercialized, such as combustion technologies and electrical heating, all of which are being evaluated for their environmental impacts."
Environmentalist groups in Canada and abroad have long decried oil sands production and the resulting carbon emissions, something that has resonated with the average North American. "The public's opinion has been largely fueled by the media, which has been largely fueled by the more sensationalistic tactics employed by the environmentalist movement," says Marcel Coutou, president and CEO of Canadian Oil Sands (the largest shareholder in oil sands giant Syncrude) whose projects are based in the Athabasca region. "We have done a lot of polling, which suggests that support for the oil sands is much broader in Canada and the U.S. than you would expect.
"Oil sands only produce a million and a half BOE per day, or less than 2% of global production, and its contribution to CO2 globally is a mere fraction of the CO2 produced across the world. Why we became the icon [of the environmental movement] has more to do with the visual nature of our operations and the freedom to criticize in our democratic jurisdiction."
Chris Seasons, president of the Canadian division of Devon Energy and exiting chairman of the Canadian Association of Petroleum Producers (CAPP), notes: "We have a good track record on the environmental and social side of things and can stand up quite nicely against concerns regarding 'dirty oil.' With [their flagship in-situ project] Jackfish, we use no fresh water and we're between one-thirtieth and one-one-hundredth of the impact on the boreal forest, per barrel of oil produced, as compared to conventional oil.
"I am personally convinced that as a company we will get our greenhouse emissions down to being comparable to other alternative sources of energy in the not-too-distant future. First off, we wanted to make sure we could build a plant to be safe, environmentally friendly and efficient; secondly we wanted to be able to operate it; and now we are looking at how to enhance those operations to bring down emissions and increase our energy efficiency."
Devon is an in-situ operator with no open pit operations, but Seasons notes that "nobody likes to look at an image of an open pit mine. The difference in our industry is that our open pits have to be reclaimed. New technology has recently come about for tailing pond reduction and recovery and in 30 to 50 years you won't even notice these things existed. People in the industry are passionate about doing the right thing."
Tailings ponds are probably the second-most significant challenge facing the oil sands operators, after GHG emissions. Disposing of tailings, mining waste typically left to settle in large ponds, is tough. "There are large areas of land that haven't been reclaimed yet and a lot of that is tailing for which we do not yet have a quick reclamation solution. We worked with Suncor to help reclaim one of their ponds. It is a landmark project that has justified the concept," states Joe Aiello, managing director and president of energy and mining consultants Norwest Corp.
"The challenges are just beginning now as the regulators are saying that there needs to be a compressed time frame between the generation of tailings and final reclamation. But we're seeing a lot more cooperation between various operators because this isn't a competitive endeavor; it's in the interest of the sustainability of the industry."
"We've joined with six other companies to do some work on tailings innovation on behalf of the industry. It's a big issue that won't be solved over night and there won't be one single solution, but there is certainly a willingness to identify the alternatives and put them into practice. We can't just keep doing what we've been doing for the last 50 years."
"There's been a negative press index overriding this industry since we started to expand our involvement in 2006," says Gusella of Connacher. Combating it, he says, is an "evolutionary process."
Despite the negative images of the industry, bitumen is a sector in which Canadians are global leaders and those in the sector are proud of their expertise and position. "I don't think we as Canadians have to hang our head in any way, shape, or form," says Gusella.
"I have guys whose backgrounds are entirely in heavy oil and steam technologies and bitumen is the hardest thing we've had to deal with," he adds, speaking about the technological achievement that oil sands extraction represents."
In recent years, the industry has recognized that it needs to put its side of the story in front of the public if it is to stand any hope of dealing with the barrage of anti-oil sands propaganda in the general media.
"The misconception is an industry problem that we allowed to develop by not communicating properly with the public," believes Howard Lutley, CEO of the newly formed heavy oil junior, Silverbirch Energy. "In the last 18 months the industry has worked hard to change that perception. Headlines shouted that an area the size of Florida was being destroyed, but the reality is that the total disturbed area of the oil sands is one tenth the size of Toronto. The industry just chuckled about [these inaccuracies] but didn't say anything, and so the perceptions became real. Now we're finding that we are finally getting [a more accurate] message to opinion leaders."
Governmental and public attitudes toward heavy oil have the potential to impact investor sentiment. However, Lutley states: "There's a real understanding of the oil sands amongst investors and regulators of both the positive and negative aspects of the industry... I think that there's recognition amongst investors that the government has decided that oil sands operations have to go ahead one way or another."
Leadership on the environment
While the oil sands have been heavily criticized by many in North America, it's important to recognize the leadership position that Alberta, home of the oil sands, has taken on the environment. "One of the things that's unique about Alberta is that we're the only jurisdiction in North America that's recognized carbon and has a requirement for reduction," insists the IOSA's Nelson, a veteran of Alberta politics. "We have a tax on carbon. The money that's collected goes into a fund used to develop green technology... I don't think that it would be a stretch to say that Alberta has the most rigid and stringent regulatory regime in North America."
In Alberta, open cast oils sands operations fall under the jurisdiction of the province's mining laws. The industry seems to be comfortable with them in both principle and practice. "The mining regulatory process is quite predictable," reckons Silverbirch's Lutley. "No mine has been disallowed. Every year the regulatory requirements get tighter, which is the nature of the business. We sit on the committees that help draft regulations so we're familiar with what's coming. We're fortunate with our Frontier mine because it was designed after the new directive came, so we've gone directly to a new dry-tailings process, whereas other operators have had to retrofit or change their plans halfway through."
Dealing with the heavy discount
`Heavy oil commands a lower price in the market than its lighter cousin. The price differential is a result not just of the lower net value of the products that can be extracted from a typical barrel of heavy oil when compared to that of light oil, but also a reflection of the cost of refining and constraints in North America's heavy oil refining capability.
John Brannan, executive VP and COO of newly formed C$27-billion heavy oil company Cenovus, observes, "The development of heavy oil has traditionally been constrained by the light-heavy oil differential and the impact that this has on the economics. When we contemplated the developments at Foster Creek and Christina Lake, the light-heavy differential was running at 30% to 40% and there was a lot of volatility in the market.
"Our board of directors told us to find a downstream solution that takes the light-heavy differential out of the economical equation. The obvious route is to have exposure to both production and refining."
Three years ago, Encana (which spun out Cenovus) entered into a joint venture with Conoco Phillips to gain exposure to significant refinery capacity. Cenovus inherited the deal. The differential has narrowed, and Brannan says, "The heavy-light differential will stay low and gas prices will stay low, hence we will be in a strong position...we have no further investment planned in the downstream side, yet we are continuing to move forward on the upstream, so after 2012 we will conceptually be long bitumen."
With factions in the U.S. aligning to prevent the construction of new pipelines to ship Canadian bitumen to Gulf Coast heavy oil refineries and limited capacity to ship synthetic crude oil (upgraded from heavy oil and bitumen in Canada), the nation risks having its most significant natural resource land locked away from market. Expanding upgrading and refinery capacity in-country would allow Canada to produce high value products which are less reliant on U.S. transportation capacity.
A first step in this process will be North West Upgrading Inc.'s integrated 150,000-bbl/day upgrader and refinery. The NWU project will be the world's first integrated upgrader and refinery, another indication of the leadership position that Canada has achieved in the world of heavy oil. The project has the potential to revolutionize the image of Canadian oil since, as NWU chairman, Ian MacGregor, puts it, "You can go further on a ton of CO2 with fuel from our process than on any other oil in the world."
The NWU team decided to engineer for efficiency from the outset: "We want to have a minimum environmental footprint for this facility," states MacGregor. "At present, bitumen is heated for upgrading and then reheated for refining; by integrating the two stages we reduce the amount of energy required substantially. By going to fuels in one step we'll be able to reduce the environmental impact and have a much broader market access than synthetic."
Not satisfied with reducing its carbon footprint through integration alone, and conscious of the fact that Alberta is the only jurisdiction in North America to tax carbon, NWU has gone one step further. MacGregor explains: "We made the decision to configure the process to produce pure CO2, which is very unusual. We also started a business called Enhance Energy to develop an EOR project. Enhance is building the Alberta Carbon Trunk Line to take our CO2 and deliver it to their EOR site as well as to other clients."
Saskatchewan's sands
Until now, the oil sands have been intrinsically associated with Alberta; however, it has long been known that the formation extends into western Saskatchewan. Now, pioneer companies are starting to demonstrate that recovery across the border might be commercially viable.
"Initially, there was a lot of skepticism from investors about the Saskatchewan oil sands, largely because of the lack of infrastructure in the region in terms of roads, pipelines and power lines," says Garth Wong, president and CEO of Oilsands Quest, one of the first companies in the Saskatchewan oil sands. "But, as interest grows in the eastern edge of the oil sands basin, with other companies exploring and developing in the area, we have seen the market warming to us."
Oilsands Quest has drilled out and delineated three large reserves on either side of the Alberta/Saskatchewan border. "While Shell had drilled a few wells 30 to 40 years ago, the area was largely unexplored. We've found large, rich in-situ oil sands reservoirs with unusually large sand grains, which means good porosity and permeability. With five years of detailed technical work behind us, we now have three potential SAGD oil sands projects of 30,000 to 35,000 bbl/day each–Axe Lake, Wallace Creek and Raven Ridge."
Underlining the fact that oil sands developments are typically more complex than their conventional cousins, Wong notes: "Every in-situ oil sands reservoir is unique...We started testing at our first potential commercial oil sands site at Axe Lake in the fall of 2009.
"Axe Lake has an excellent reservoir, but the cap rock above the reservoir is different than oil sands projects further west. We ran lab tests on the cap rock to ensure that it can contain steam, which is essential for a SAGD project. Those results were very positive, and the next step is to run a SAGD pilot project to test the lab findings in the ground. Our surface facilities are in place for the pilot."
Across the border in Alberta, things are also progressing: "We just finished a five-well drilling program in Wallace Creek. The results are promising. We see a lot of synergies in terms of development opportunities in that region. In Raven Ridge, the southern of our two properties on the Alberta side, we require a bit more technological advancement to take full advantage of the opportunity. Our reservoir there looks much like Cenovus' potential Borealis project."
Light Oil
Despite light oil representing only 3% of Canada's oil reserves, CAPP predicts that it will represent 18% of production in 2011 (538,000 BOE per day). With netbacks for most light oil projects far higher than those seen in the oil sands, light oil production will represent a far higher share of the total profit generated by Canadian oil in 2011.
The WCSB's potential to produce exciting new light oil plays is often written off. This is a mature basin in which most of the initially recoverable reserves have been extracted, after all. However, while the basin's geology is well understood, the industry's constantly evolving capability to employ novel techniques to extract additional barrels is forcing analysts to look anew at many of the "old" plays.
If there is one play that demonstrates Canadian's ability to innovate, it is the Bakken. This play has come to symbolize a renaissance in Canada's light oil industry and helped place the province of Saskatchewan on the radar of the oil and gas investor.
The Bakken
The Bakken is a formation that has been known since the 1950s. What turned it into the hottest play in both Canada and the U.S. was the improvement in horizontal well drilling and capacity to pack ever more fracs into these wells.
On the Canadian side of the border, the Bakken rush started in Saskatchewan. Today, E&Ps are extending the play west into Alberta and east into Manitoba.
A man synonymous with the Bakken is Trent Yanko. Yanko helped pioneer the application of horizontal multistage fracs in the Bakken and built his last company, Mission Oil & Gas, to 7,000 BOE per day, primarily through the drillbit, in the play. Today he heads Legacy Oil & Gas, which works in the Bakken and other emerging plays.
"As a worldwide commodity, light oil is becoming scarce, so light oil will always be a premium product...," says Yanko. "The Canadian light oil story has been under appreciated. There's a large amount of potential in Canada for light oil as the Bakken has demonstrated."
It should be noted that while most Canadian Bakken production is light, on the Montana side of the boarder heavier API production is more common and there are an increasing number of cold Canadian Bakken producing wells.
Reliable Energy has secured 115 net sections in Saskatchewan and Manitoba. Understanding that "geology does not respect borders" (in the words of CEO Murray Swanson), Reliable has pursued the play back across the international line into Montana.
The margins from the Bakken's light and sweet oil are high. In April, Reliable announced its year-end results with 214% production growth through the drillbit to 333 BOE per day. At an average sale price of $77 per barrel, the company achieved a netback of $51.57 per barrel.
"We achieved a lot in 2010, it was without doubt our best year since we started operating in 2005," says Swanson. "This is despite the fact that the operating environment was tough, it was hard for everyone to get drills and fracs, and being in an emerging area, there are not as many drillers and fracers driving past us."
John Newman, VP finance and CFO at Reliable, adds, "The Manitoba government is very business friendly...The Manitoba royalty regime is great; it's a low cost environment in general. While in its early days, we think that the Bakken in Manitoba