Welcome to the Connacher Oil and Gas Hub on AGORACOM
Connacher is a growing exploration, development and production company with a focus on producing bitumen and expanding its in-situ oil sands projects located near Fort McMurray, Alberta
Message: Interesting article (+ for CLL)
well, i am just sick of this slide and sell off in the stock.
but holding on... on the bright side i found this nice positive article on CLL. GLTA.
http://www.oilsandsreview.com/articl...
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Dec 2007 |
| Source: Oilsands Review |
| The magic formula |
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Based on innovative company strategies, Connacher Oil and Gas and EnCana tie in voting for 2007 Producer of the Year |
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Andrea W. Lorenz |
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| In a surprise result of Oilsands Review’s first-ever Producer of the Year competition, EnCana and Connacher Oil and Gas won in a tie. The two companies represent the second wave of oilsands producers: those producing from reservoirs too deep to mine with evolving technology based on the technique of steam assisted gravity drainage (SAGD). They present a fascinating contrast: EnCana is one of the largest and oldest SAGD producers; Connacher one of the smallest and newest. Yet they have adopted a similar model—it is based on the principle of hedging for price volatility by becoming an integrated company. What makes their stories compelling is that they both make a process fraught with complications look easy. Despite their differences in size and age EnCana and Connacher both recently closed deals giving them ownership of refineries. Both have benefited from foresight, good fortune and location. And—in an ironic coincidence that their peers will appreciate—both benefited in different ways from the fallout from the 2003 gas-over-bitumen debate. Connacher Oil and Gas: a minnow making waves in a big fish’s world With justifiable pride, Connacher Oil and Gas chief operating officer Pete Sametz calls his company a “mini-integrated producer.” Having worked in the heavy oil business long before it became the commodity to invest in, when differentials barely justified producing it and refineries would only pay good money for it during the summer paving season, Sametz and company founder, president and chief executive officer Dick Gusella knew that a small company could quickly be eaten up by the bigger players. If they were to survive in the oilsands business, they would have to design a new model, one that contained multiple shock absorbers. Sametz explains the strategy: “We’re trying to physically hedge lockstep downstream with what we’re doing upstream.” Thus, even before the company starts producing, it has cushioned both sides of the equation—on the upstream side with natural gas production and on the downstream side with refining capacity. “What’s driving [our strategy] is we’re producing a very tough barrel, and it’s hard to make money on it,” Sametz explains. The refinery During a working breakfast around Christmas 2004, financiers at Mustang Capital broached the idea of purchasing the Montana Refining Company to Gusella and his team. The latter had already been mulling the possibility of buying a refinery. “We knew we had to deal with wide differentials caused by [events like] Hurricane Katrina and $14 to$15 gas,” Gusella explains. The small refinery in Great Falls is one of four in Montana. ExxonMobil, ConocoPhillips, and Cenex own the other three. Built in the early 1930s, its most recent owner was Holly Corporation, which was trying to sell it. Timing played into Connacher’s hands. “The refiner had a bust deal,” Gusella says. “It was also before refining margins exploded.” The refinery currently produces just less than 10,000 barrels per day from a feedstock of 22°API Bow River crude. The end product is approximately one-third asphalt, one-third middle distillates including diesel and jet fuel, and one-third gasoline. “This is perhaps the most complex small refinery in the U.S.,” says Sametz. “It’s the closest U.S. refinery to the oilsands in Alberta.” He explains how the financial hedge works: “Our molecules don’t have to go to the refinery, but we’re mitigating returns. If there are wild swings in performance, it smoothes out [the effect of] swings in price. If the price of bitumen goes up, we make more money on the upstream but less at the refinery. But if the demand for gas and diesel go up, we make money from the refinery. We hope to have less than a three-year payout. It was an excellent deal.” The natural gas In March 2006, Connacher purchased Luke Energy, acquiring natural gas producing properties in the Marten Creek and Three Hills areas of Alberta. It currently produces about nine million cubic feet of natural gas per day. “We bought Luke because it fit into our strategy of mitigating risk, and there is also room to expand,” Sametz told Oilsands Review in 2006. The bitumen Connacher’s oilsands leases lie south of Fort McMurray along Highway 63, just south of neighbouring Japan Canada Oil Sands (JACOS). They comprise 95,000 acres in what they call “the main fairway,” where the deposits lie at a depth of 30 to 60 metres. It was in 2003, at the height of the gas over bitumen controversy, that Gusella’s team seized the opportunity and posted these lands, which belonged to a small, private gas producer whose name he would not reveal. In 2004, when the price of oil was languishing between $30 and $35, Connacher bought the leases for $1.3 million—or $20 per acre. The price today for the same property would run between $4,000 and $5,000 per acre. Not only was the timing right, but also the leases’ location close to the highway made the logistics of building the production facility relatively simple. In June 2006, Connacher received regulatory approval for its 10,000-barrel-per-day Great Divide SAGD project. After just 300 days of construction, the facility was ready to go “hot” in August 2007. The first Great Divide bitumen has now been sold, and production is ramping up to capacity of 10,000 barrels per day. At the same time it was preparing the Great Divide project to go operational, Connacher also advanced the next phase of its oilsands developments: Algar, which is also known as Pod 2. The EUB application for this next 10,000-barrel-per-day installation was submitted in June 2007. Production start is slated for 2009. As with EnCana and every SAGD producer, maintaining the lowest steam to oil ratio (SOR) is critical to keeping a lid on operating costs. Connacher expects its SOR will land at a competitive 2.7:1. Once it starts its normal operating phase, the project’s operating costs should “drop to $12 to $14 a day,” Sametz says, adding, “The cost of natural gas is the biggest determinant of operating costs—about 66 to 75 per cent.” How will Connacher’s bitumen get to market? “In the short term, it will be trucked to the best market.” When it begins to pipeline its product south, the company will use a one-third cut of diluent. Naphtha from its Montana refinery will provide a portion of this. “We’re negotiating with all the pipelines,” says Sametz. “We have no business arrangement yet. There’s a bit of a wait and see on the pipeline companies’ project. As we prove up our volumes and as they see us move forward on the Algar project, they will see our capability.” Neighbouring JACOS, which produces approximately 9,000 barrels per day, also trucks its product to market. Has Connacher discussed partnering with JACOS to build a pipeline? “We’ve talked with potential partners on pipeline construction,” Sametz acknowledged. “JACOS is an obvious one.” Connacher now has 40,000 shareholders, most of whom are Canadian, and a capital expenditure of $250 million. Upstream, it plans to expand SAGD operations to its Algar properties, and downstream it plans to increase the capacity of its Montana refinery. Connacher may yet face growing pains, but so far it has managed to grow just enough not to burst out of its britches. EnCana: a natural gas giant sets its sights on integration Taking the leap of becoming an integrated producer is akin to doing a high dive for the first time. Once taken, it forever changes the identity of a company. It also affects the company’s entire peer group by inducing a realignment of the hierarchy. In EnCana’s case the company moved from the independent producer group to the integrated group. In EnCana’s view, the move was so significant that it created a brand new integrated oilsands division, appointing John Brannan president, and Harbir Chhina vice-president of upstream operations. In an October interview, both described to Oilsands Review what makes the new division a success. There is no question that EnCana’s Foster Creek project in the Cold Lake air weapons range is a leader in the SAGD arena. It was the first commercial-scale SAGD project in the world. Since 2004, its production has grown significantly—though perhaps not quite as fast as its managers had predicted. In March 2004, the project was producing 27,000 barrels of bitumen per day, and Chhina said at the time that subsequent phases could likely bring production to 100,000 barrels per day by 2007. This October, Chhina said, “Today we are producing 54,000 barrels a day, and we’re working to 60,000.” He and Brannan now hope to achieve 120,000 barrels per day by 2009. EnCana’s oilsands properties at Foster Creek, Christina Lake, and recently announced Borealis contain an estimated development potential of 33 billion barrels of bitumen. Evolving SAGD technology Although companies have been trying the technique of SAGD since the 1970s, real breakthroughs have only been achieved in the last five years. For Chhina, the most significant recent technological improvement has been the introduction of electric submersible pumps. “Before, we used to use gas. We didn’t have enough pressure downhole.” According to Schlumberger’s oilfield glossary, an ESP is a downhole pump especially designed “with vane and fin configurations” that alleviate frictional losses due to bitumen or heavy oil’s high viscosity. For EnCana, ESPs provide a key benefit: they help lower its SOR. As Chhina says, “Our goal in all of these [innovations] is to reduce our steam-to-oil ratio because that has the biggest impact on capital costs and our operating costs.” The pumps’ design allows EnCana to “turn our wells on and off, and we can operate at lower pressure, which is better for lowering our steam-to-oil ratio,” Chhina explains. The company now claims an SOR of 2.5 barrels of steam to one barrel of oil, a ratio it has maintained since before 2003. Today, 72 ESPs are at work at Foster Creek. Brannan and Chhina are intent on pushing the SOR to 1.4—a rate they believe they can achieve with their newest technological innovation: “solvent-assisted process” or SAP. The process, which involves using butane as a solvent, is close to commercialization, Chhina says. “By next year, we’ll be shutting off a lot of steam in our wells. We’ll recover a lot of our oil—the last 20 to 25 per cent—without injecting any steam. That will drop our steam [to] oil ratio to 2:0. With SAP, we expect to get around 1:4.” Operating costs at EnCana’s oilsands operations range between $12 and $14 per barrel, depending upon the cost of natural gas. Currently, it takes 1,000 cubic feet of gas to produce a barrel of oil. “Over the next seven years, our target is 0.6 [thousand cubic feet] per barrel,” says Chhina, adding the “Status quo is unacceptable for us.” Battling the gas over bitumen issue EnCana is trying to prove that in reservoirs where gas and bitumen exist together, both can be produced. The argument over whether or not this was technically possible was at the crux of a debate that pitted natural gas producers against bitumen producers in 2003. In the end, the Alberta Energy and Utilities Board (EUB) decided to order the shut-in of 900 gas wells in the Athabasca area to prevent pressure from dropping, which would have rendered it impossible to produce the estimated 100 billion barrels of bitumen in the region. Meanwhile, EnCana continued to insist that a technology was just within reach that would allow it to produce the gas without jeopardizing the bitumen. First it had to persuade the gas producers to allow it to pilot test the method. “We said, ‘Look guys, we both have gas. We both have bitumen. Why don’t you produce your gas as fast as you can. We can show the world we can work together, even though we own different commodities,” recalls Chhina. “So the deal we made with them was to accelerate producer gas. After that, we said, ‘Give us the wellbores. Give us the pipeline so that we can repressure up with air.” Devon Energy, which had previously been producing gas at Christina Lake, agreed to allow EnCana to experiment, and EUB regulators gave EnCana permission to run a pilot project. It required starting combustion in the gas cap. “There’s always a little bit of oil in the gas cap,” explains Chhina. “Air does the combustion. CO2 and nitrogen are produced and they displace the methane. So for every molecule of air you were producing, you get a molecule of methane. So the reservoir pressure doesn’t change, but you end up producing the gas and you end up heating the reservoir.” With characteristic enthusiasm he adds, “That part is working like a charm.” In return for the right to produce the bitumen, EnCana gave Devon right to use the new wells. “We started to give them some of the wells, and we repressured back up with air,” said Chhina. Despite EnCana’s success and that of other similar pilots, the results have yet to convince the EUB to reverse its decision. Becoming an integrated player Effective January 2007, EnCana attained the status of an integrated player—a significant makeover in the rapidly reconfiguring oilsands world. Six years ago, in a foresighted 2001 piece titled The Canadian Heavy Oil Business: The Plot Thickens, FirstEnergy analysts John Mawdsley and Steven Paget wrote, “The integrated companies are in the best position at this time because they can capture the full value chain of the bitumen resource.” In an interview at the time, Paget told Oilweek, “EnCana at Foster Creek doesn’t have an official alliance that allows them to place any new bitumen they produce…EnCana is probably trying to find an alliance.” One of the challenges bitumen producers face is the large discount the lower-grade product is sold at as compared to lighter oils. EnCana chose a well-suited partner in ConocoPhillips. The two negotiated what is known as a swap, in which each owns 50 per cent of the other’s key asset. EnCana now owns half of two refineries, one in Wood River, Illinois, and the other in Borger, Texas. Although the partners’ bitumen production now exceeds their refining capacity, they plan expansions to accommodate their increased production by 2015. For ConocoPhillips, securing the partnership with EnCana was a coup. CPC President Kevin Meyers brimmed with enthusiasm when he told Oilweek in a recent interview, “The EnCana [joint venture] has significant growth plans. Over the next 10 years, our joint goal is to see production grow to 400,000 barrels a day.” |
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