North Sea-focused Ithaca Energy has issued a cautious guidance statement for 2013 after producing a robust performance in the final quarter of last year.
The oil and gas junior's production figure of 6,631 barrels of oil equivalent per day (boepd) for 4Q 2012 was in line with forecasts, according to analysts at Cenkos Securities and RBC Europe, in spite of the firm suffering lengthy production outages at its Anglia
Ithaca said that production during 4Q 2012 benefited from a strong performance from the Athena
field, where it is operator. Athena continues to produce "dry" oil at a stable gross daily rate of between 10,000 and 11,000 boepd – with between 2,250 and 2,475 of this going to Ithaca.
For 2013, Ithaca expects export production to be similar to that for the final quarter of 2012 at between 6,000 and 6,700 boepd. Approximately 80-percent of the firm's total net production is anticipated to be derived from the firm's Cook, Athena and Beatrice/Jacky fields.
Ithaca added that this production guidance reflects anticipated water breakthrough at the Athena field during 2013 as well as the impact of planned maintenance shutdowns.
Meanwhile, Ithaca expects to spend a total of $360 million in 2013, with almost all of this being focused on the company's execution of the Greater Stella Area
development that is scheduled for the latter part of the current quarter.
Analysts at RBC Europe pointed out that investment in the Greater Stella Area project is "set to deliver dramatic production growth through 2014-15".
DUBAI: The Gulf Cooperation Council (GCC) countries will award a little over $50 billion worth of contracts in the market in 2013, almost double the $27 billion expected to be awarded this year, a report has said.
According to 'MEED Insight', two huge projects scheduled to get underway in Kuwait and Oman next year will help spur a major increase in the value of contracts awarded in the GCC's oil, gas and petrochemical projects market in 2013.
The pick-up in activity will be good news to contractors which have suffered from a slowdown in activity since the market saw a record $ 52 billion worth of contracts awarded in 2009, said the report.
Since then, contract award levels have dropped as national oil companies evaluated their project plans; in 2010, some $ 40 billion worth of contracts were awarded, while this slipped to just $ 25 billion in 2011, it said.
However, while the market is expected to rebound next year, it will be dependent on two major projects proceeding. "The forecast is predicated around the assumption that the $ 14 billion fourth refinery in Kuwait and BP's $ 15 billion Khazzan tight gas scheme in Oman will go ahead," said Ed James, Head of MEED Insight.
Developments in Kuwait and Oman are also likely to determine whether the $ 50 billion forecast for 2014 is met as the total includes awards on Kuwait's $ 18 billion clean fuels program and the proposed $ 6 billion Duqm refinery in the sultanate.
Nonetheless, there will still be a host of other major projects awarded over the next two years, including further contracts on Saudi Aramco's Jizan refinery, major work offshore Abu Dhabi, and new world-scale petrochemical complexes in Qatar, the report said.
France's Total made its first venture into Papua New Guinea on Tuesday, signing a deal with Australia's Oil Search to acquire five licensing agreements in the onshore and offshore Gulf of Papua region.
Oil Search, which has operated in Papua New Guinea for decades, and Total will hold equal interests in the five licenses, Oil Search said in statement released on Tuesday.
"The farm-in... is in line with our strategy to strengthen our presence in the Asia Pacific, particularly in the gas and LNG sectors," said Jean-Marie Guillermou, senior vice president of Total exploration and production in Asia-Pacific.
Total has been recently expanding its portfolio in Asia and in January made a final investment decision, along with joint venture partner Inpex, on Australia's $34 billion Ichthys liquefied natural gas (LNG) project in Darwin.
A drilling program on the offshore licenses will begin in the first quarter of 2013, Oil Search said.
"In the event of exploration and appraisal success that leads to an LNG project, Total would develop and operate the downstream facilities of any development," said Peter Botten, Oil Search's managing director.
Papua New Guinea has several LNG projects already under way, including Exxon's $15.7 billion PNG LNG project, which is expected to come online in 2014.
InterOil Corp has also been planning a $6 billion LNG project, but is still finalising the specifications of the project with the government.
A specialized oil and gas free zone will be build on a 11 million square meter land at Khor Al-Zubair area in Basra in a joint venture agreement between Iraq General Commission of Free Zones and BIOGH Basra International Oil and Gas Hub
. The zone will be serving as a mixed-use site for manufacturing, storage and servicing of the expanding requirements of Iraq’s oil and gas sector as it is adjacent to Iraq’s strategic energy port.
Administrative functions will be single handedly be overseen by the Iraq General Commission of Free Zones but it will join hands with other collaborators in facilitating on-site customs clearance and the provision of work permits. Basra International Oil and Gas Hub (BIOGH) will be the developer of the project with responsibility for the construction and design, infrastructure, project financing, marketing and management of the special free zone.
When completed, users of the zone will be handed long term agreements and a fast track process for regulatory approvals by BIOGH. Dr Sabah Al-Qaisi, the director general of the Iraq General Commission of Free Zones hailed the creation of the BIOGH free zone “as the most significant investment contract entered into by the Commission.”
The free zone will be the second largest oil and gas free zone in the world. It will immensely help in boosting the economy of Iraq by attracting significant foreign direct investment.
The facilities will be equipped with modern technology and will also be independent when it comes to power generation, water, and telecommunication, waste management processing and will be having permanent residential accommodation and recreation facilities.
Shell scrapped plans to drill for oil and gas off Alaska this year after a spill containment system crucial to the company’s efforts to explore in the icy Arctic waters was damaged during a test.
The company is pledging to continue to drill and cap the top portion of exploratory wells in both the Chukchi and Beaufort seas in order to try to hit the ground running next year.
Shell had successfully completed a series of tests of the first-ever Arctic Containment System, according to spokeswoman Kelly op de Weegh, but the containment dome onboard the company’s Arctic Challenger barge was damaged during a final test.
“The time required to repair the dome, along with steps we have taken to protect local whaling operations and to ensure the safety of operations from ice-flow movement, have led us to revise our plans for the 2012-2013 exploration program,” she wrote in an email.
As a result, Shell will “forgo drilling into hydrocarbon zones this year,” op de Weegh said, and instead drill “top holes” that allow it to attach equipment to the seabed before the company targets oil and gas reservoirs.
The accident is the latest setback for Shell’s long-delayed trailblazing quest to start Arctic oil-and-gas drilling off the Alaska coast this year, an effort that has been folded in with the larger politics over the Obama administration’s energy record before the election.
Sen. Lisa Murkowski (R-Alaska) was disappointed with the news, but said she believed “Shell has made the right decision, keeping safety paramount.” The ranking Republican on the Energy and Natural Resources Committee is a leading congressional advocate to expedite Shell’s exploration in the Arctic.
But one green group said the latest problem shows the company is ill-prepared to deal with the harsh Arctic climate
“If you can’t even test your safety systems in calm waters without damaging them, you’ve got no business drilling for oil in the Arctic,” Niel Lawrence, attorney at the Natural Resources Defense Council, said in a statement.
Falkland Oil and Gas (LON:FOGL), the exploration company focused on extensive licence areas to the South and East of the Falkland Islands, has confirmed that the Loligo exploration well is a gas discovery.
Loligo was the first of a two-well programme being undertaken by FOGL and the company is now planning to drill on the Scotia prospect. It said the latest well had proven a working hydrocarbon system in the northern part of the East Falkland basin and also demonstrated that Loligo is a viable stratigraphic trap.
FOGL said it was is clear from the initial well results that the main hydrocarbon phase within the T1 to T5 aged reservoir objectives was gas, but it had not been possible to determine whether this gas has any liquid content.
FOGL is the operator of the well, holding a 75% interest; its joint venture partner Edison International Spa holds the remaining 25% interest.
The well was drilled to a depth of 4,043 metres and penetrated six Tertiary aged reservoir objectives on prognosis. These comprise the T1, T1 deep, T2 (Trigg), T2 deep (Trigg deep), T3 (Three Bears) and T5 targets. These objectives had all been identified on the basis of their seismic amplitude responses.
Very strong gas shows (C1 to C5) were encountered whilst drilling through each of the horizons. Analysis of the wireline log data indicates that all six targets comprise fine grained sandstones, siltstones and claystones. FOGL interprets that these sediments have been deposited either outside, or at the distal (outer) end of the slope channel system.
Gas bearing zones were encountered over a 1,300 metre vertical interval from 2,420 to 3,720 metres. Petrophysical analysis of the T1 to T3 intervals inclusive (2,420 to 2,885 metres) indicated porosities ranging from 18% to 35% in the gas bearing zones. FOGL noted that due to the thin bedded nature of these sediments it was difficult to assess precisely both hydrocarbon saturation and the total net hydrocarbon bearing reservoir. Preliminary estimates however, suggest hydrocarbon saturations ranging from 40% to 60% and net hydrocarbon bearing reservoir of between 10 and 20 metres.
Within the T5 target two main hydrocarbon bearing zones were encountered (3,462 to 3,558 metres and 3,608 to 3,705 metres). The net hydrocarbon bearing reservoir in these two zones was 46 and 59 metres respectively. Porosities ranged between 23% and 30%, averaging 24% and hydrocarbon saturations between 40% and 75%.
FOGL said that attempts to obtain pressure data and collect fluid samples were unsuccessful, probably due to the fine grained nature of sediments in the gas bearing zone and also, not having access to the specialised test equipment appropriate for this type of formation.
Further detailed evaluation of all the well data, together with the existing seismic is now required in order to better define reservoir distribution and more precisely map the channel systems.
FOGL now intends to plug and abandon the well, which is expected to take approximately 10 days. FOGL and Edison believe that it would be premature to drill a second well on Loligo at the current approved location (Loligo north-west) before having undertaken detailed analysis of the current well results. Accordingly the decision has been taken that the next well will be on the Scotia prospect in the Mid Cretaceous fan play. On the basis that Scotia is also drilled within budget, it is estimated that the company’s cash balance post the 2012 exploration campaign will not be less than US$200m.
Tim Bushell, the chief executive of FOGL, said: “The initial results of the Loligo well are encouraging. They have demonstrated that hydrocarbons have migrated into the Tertiary Channel Play. It is also clear that Loligo is a valid trap that contains multiple gas bearing zones, with over 100 metres of hydrocarbon bearing reservoir. We now need to focus on reservoir distribution within Loligo in order to find the sweet spots. A work programme will be undertaken to achieve this, assess the resource potential and commercial viability of this discovery.”
He added: “We now have a positive result from one of our major exploration prospects. This, together with the results from our next well, will help determine the priorities for our future exploration efforts. With our partners Noble Energy and Edison, we have the technical resources and funding in place to carry out substantial 3D surveys, followed by further drilling in 2014.”
Oil traded near the lowest price in two days in New York after stockpiles unexpectedly rose in the U.S., the world’s biggest crude user.
Futures were little changed after dropping for the first time in six days yesterday. Inventories rose 1.99 million barrels last week, the Energy Department said yesterday. They were forecast to fall by 2.9 million barrels, according to the median estimate of 11 analysts in a Bloomberg News survey. The Federal Open Market Committee may announce additional stimulus measures for the economy at the end of a two-day meeting today.
“The oil market couldn’t go higher because of the bearish impact of the inventory data,” said Ken Hasegawa, a derivative sales manager at Newedge Group in Tokyo who expects West Texas Intermediate crude to trade below $98.29 a barrel, the Aug. 23 intraday high that marked the peak of a rally since June. “The lower side will be limited ahead of the FOMC meeting. It’s a big event.”
Crude for October delivery was at $96.92 a barrel, down 9 cents, in electronic trading on the New York Mercantile Exchange at 3 p.m. Singapore time. WTI slipped 16 cents to $97.01 a barrel yesterday, the lowest close since Sept. 10. Front-month prices are down 1.9 percent this year.
Brent oil for October settlement fell 1 cent to $115.95 a barrel on the London-based ICE Futures Europe exchange. The European benchmark grade’s premium to WTI was at $19.03, from $18.95 yesterday.
Gasoline StockpilesOil in New York has technical resistance along the upper Bollinger Band on the daily chart, at around $99.20 a barrel today, according to data compiled by Bloomberg. Futures have halted advances near this indicator since July. Sell orders tend to be clustered near chart-resistance levels.
U.S. gasoline inventories fell 1.18 million barrels last week, the Energy Department report showed. They were forecast to decline by 1.7 million, according to the survey. Distillate supplies, a category that includes heating oil and diesel, rose 1.48 million barrels, compared with a projected decline of 500,000.
The FOMC will probably announce a third round of bond purchases after its meeting and extend the duration of its zero- interest-rate policy into 2015, according to two-thirds of the economists surveyed by Bloomberg.
Global oil inventories have become “more comfortable,” the International Energy Agency said in a report yesterday. Daily output by the Organization of Petroleum Exporting Countries increased by 45,000 barrels last month to 31.55 million, or about 450,000 more than required this quarter and 950,000 more than next quarter, the Paris-based IEA said.
Emergency ReservesThe agency didn’t specify whether members should release emergency reserves to tame prices, a move discussed last month by leaders in the U.S., U.K. and France.
“We’ve got effectively an implied stockpile-build in the fourth quarter, so we don’t see a need for an emergency stock release,” said Alan Gelder, the head of downstream research at Wood Mackenzie Ltd. in London. “That supply’s mainly coming out of non-OPEC. There’s some supply growth in the former Soviet Union in the third and fourth quarters, and Europe coming off North Sea maintenance.”
Iran’s oil exports rebounded to 1.1 million barrels a day in August from a record-low 930,000 in July, the IEA said. Shipments to Turkey and Malaysia increased the most. Sales by Iran, which is facing sanctions on its energy and financial industries because of its nuclear program, may rise again this month as nations including China, South Korea and India boost loadings, according to the report.
Older North Sea oil and gas fields are to benefit from a new UK tax break designed to stimulate investment, the Chancellor George Osborne has announced.
The measure is designed to support new investment in older oil and gas fields in the North Sea, with a view to increasing tax revenues from the industry. Under the change, certain mature fields, known as brown fields, will be able to shield a portion of their income from the Supplementary Charge.
The Supplementary Charge on North Sea activity is paid in addition to corporation tax. Osborne hiked the levy by 12% in last year's Budget, taking it from 20% to 32%. The government received sustained criticism for this decision, with industry bodies and related companies warning that the huge tax burden makes investment in North Sea oil and gas projects uneconomical.
The new Brown Field Allowance will now shield up to GBP250m (USD400m) of income in qualifying brown field projects, or GBP500m for projects in fields paying Petroleum Revenue Tax, from the 32% Supplementary Charge rate. This, the government claims, will provide tax relief of up to GBP80m or GBP160m respectively.
Announcing the news, Osborne said: “[The] tax allowance is more good news for the North Sea, good news for jobs and good news for the broader economy. It will give companies the incentive to get the most out of older fields, creating jobs and delivering more revenue for taxpayers."
China National Offshore Oil Corporation's (CNOOC) successful appraisal of two offshore wells in the Bohai Sea is a "major positive" development for the company, Nomura Equity Research Analyst Ding Hanzhi told Rigzone in a telephone interview Thursday.
"This discovery is significant for CNOOC considering the fact that oil production in the Bohai Sea has been declining," Ding explained.
Ding was referring to a published statement by CNOOC on its website on Tuesday, which noted that the company's successful appraisal took place in the Qinhuangdao 29-2 structure, sited in the central and northern part of the Bohai Sea. Qinhuangdao 29-2 lies 89 feet (27 meters) beneath waters.
One of the wells, Qinhuangdao 29-2E-4, encountered oil pay zones 717 feet (218 meters) thick, including a 439-feet (134-meter) thick single oil pay zone. Qinhuangdao 29-2E-4 was tested to produce around 6,600 barrels of oil and 4.5 million cubic feet of natural gas per day, creating the highest capacity of clastic rocks in the Bohai Sea.
There was no mention of the other appraised well.
"I believe that Qinhuangdao 29-2 will provide firm support to the company's reserve and production growth in the near future," CNOOC's CEO Li Fanrong said in the company's issued statement.
- Total oil production averaged more than 155,000 barrels per day (bbls/d), a 28% increase compared with the same period a year earlier.
- Oil sands production at Foster Creek and Christina Lake averaged more than 80,000 bbls/d in the second quarter, a 38% increase compared with 2011.
- Cenovus began injecting steam at Christina Lake phase D, with production anticipated in the third quarter.
- Refining operations generated $344 million in operating cash flow, up $22 million from the second quarter in 2011.
- Cash flow was $925 million in the second quarter, a slight decrease compared with the same period a year earlier due to weaker commodity prices during the quarter.
- Capital investment in the quarter increased 39% to $660 million compared with the same period in 2011 as the company continued to expand the development of its oil assets.
- Cenovus received regulatory approval for its Narrows Lake oil sands development, which is expected to have a gross production capacity of 130,000 bbls/d.
“Cenovus has a clearly defined 10-year growth plan, which is expected to deliver predictable, reliable performance,” said Brian Ferguson, Cenovus President & Chief Executive Officer. “We’re consistently growing oil production while maintaining our focus on low-cost operations and continuing to demonstrate the value of our integrated approach with strong refining margins.”
Cenovus Energy Inc. (TSX, NYSE: CVE) delivered strong performance during the second quarter, led by significant increases in oil production and favourable refining results. The company increased capital spending in the quarter and remained focused on expanding the development of its oil sands properties, as well as investing in the growth of its conventional oil assets in Alberta and Saskatchewan.
Combined production in the second quarter from Foster Creek and Christina Lake was more than 80,000 bbls/d net (160,000 bbls/d gross), a 38% increase compared with the same quarter in 2011. Christina Lake averaged more than 28,000 bbls/d net (57,000 bbls/d gross), more than tripling production from the same period a year earlier due to the industry-leading start-up of phase C. The company also achieved a new daily gross production high at Christina Lake of 64,000 bbls/d, 10% higher than its current gross capacity of 58,000 bbls/d. Cenovus began injecting steam at phase D in the second quarter and anticipates first production in the third quarter, approximately three months ahead of schedule. Once phase D is fully commissioned, it is expected to bring the gross production capacity at Christina Lake to 98,000 bbls/d.
Production from Foster Creek increased 3% to almost 52,000 bbls/d (nearly 104,000 bbls/d gross) in the second quarter, which included a scheduled turnaround. The full plant turnaround was completed safely, on time and within budget. The plant continues to demonstrate excellent performance and produced more than 126,000 bbls/d gross on several days in the quarter, exceeding its current capacity of 120,000 bbls/d gross. There are currently five phases producing at Foster Creek, with three more under construction. Cenovus has also started conducting public consultation for an additional phase that is planned to produce 50,000 bbls/d gross. In total, Cenovus plans to have nine phases at Foster Creek eventually producing 295,000 bbls/d gross and expects that, with optimization, the total gross production capacity at Foster Creek will be as much as 310,000 bbls/d.
“It’s important to have the right people working on the right resources,” Ferguson said. “The expansion of our oil sands assets is going well, thanks to the dedication of our teams and the quality of our assets. We’re striving to find innovative ways to bring these expansion phases on even more efficiently and we’re seeing strong results.”
The company is beginning to see production increases at its Pelican Lake heavy oil operation, due to the infill drilling program to expand the polymer flood. Production averaged more than 22,000 bbls/d in the second quarter, a 15% increase from the same period in 2011 when wild fires in the Slave Lake region curtailed production by approximately 2,100 bbls/d. The production increase continues to be partially offset by reduced operating pressures and shut-ins that are temporarily required to complete infill drilling between existing wells. Cenovus plans to drill between 1,200 and 1,300 production and injection wells in the next five to seven years to expand the polymer flood, with production expected to reach 55,000 bbls/d.
Cenovus also saw growth in its conventional oil assets in Alberta and Saskatchewan in the second quarter, partly due to better operating conditions after poor weather limited access to locations in both areas in the second quarter of 2011. Oil production in Alberta increased 14% to more than 29,000 bbls/d in the quarter as the company continued to focus on developing new tight oil plays on its existing lands in southern Alberta. Average oil production from the Lower Shaunavon and Bakken tight oil plays more than tripled compared with the same period last year to about 6,200 bbls/d due to a successful drilling program, although production continues to be impacted by delays in facility construction. Cenovus completed battery construction for the Bakken area in the second quarter, while construction continues on facilities to support the Lower Shaunavon. These are scheduled to be complete in the third quarter of 2012 and are expected to reduce trucking needs.
Cash flow in the second quarter was $925 million, a slight decrease from $939 million in 2011. Weaker commodity prices for both oil and natural gas were somewhat offset by the company’s significant increase in oil production. In addition, Cenovus’s refining business contributed $344 million to operating cash flow, an increase of $22 million compared with the same period a year earlier. This increase is primarily due to strong refining margins, as well as higher throughput and increased heavy oil processing associated with the start-up of the coker at the Coker and Refinery Expansion (CORE) project at the Wood River Refinery.
Operating earnings in the second quarter were $283 million, a 28% decrease from the same period a year earlier partly due to the company recognizing an exploration expense of $68 million. This is primarily attributed to a decision not to carry out further work at a small exploration play called Roncott, an area outside of Cenovus’s core Bakken area. Operating earnings were also impacted by higher depreciation, depletion & amortization (DD&A) costs due to higher production volumes and CORE capital costs now being subject to depreciation.
Investing in oil development
Capital investment in the second quarter totaled $660 million, a 39% increase from the same period in 2011, as the company continued to advance development of its oil opportunities. Cenovus invested $307 million to develop expansion phases at Foster Creek and Christina Lake, a 55% increase compared with the same period a year earlier, and continues to pursue ways to achieve industry-leading capital efficiencies at its oil sands operations. The company expects to build expansion phases at Foster Creek and Christina Lake in the range of $22,000 to $25,000 per flowing barrel.
Cenovus continues to work on growing conventional oil production with capital investment at its conventional assets, excluding Pelican Lake, reaching $122 million in the second quarter, an 85% increase from the same period in 2011. The increase is mainly due to facility and infrastructure construction in the company’s Lower Shaunavon and Bakken operations, as well as drilling and completions across Saskatchewan and Alberta. Cenovus continues to explore oil opportunities on its existing fee lands in Alberta.
Capital investment at Pelican Lake more than tripled to $104 million in the second quarter from the same period in 2011. Spending was primarily related to infill drilling activities to advance the polymer flood, as well as minor facility expansions and pipeline construction to support higher volumes.
Benefit of integration and low supply costs
Heavy oil differentials between Western Canadian Select (WCS) and West Texas Intermediate (WTI) increased in the quarter. Cenovus’s strategy of integrating its oil sands production with its refining assets continued to prove valuable in this environment, as wider heavy oil differentials and increased volumes of heavy oil processed resulted in lower cost feedstock for the company’s refining operations, which influenced refining margins. The strength of the refining business also helped to provide stable cash flow as oil prices decreased in the quarter.
In addition to its integration strategy, Cenovus continues to focus on achieving low supply costs at its oil sands operations to offer stability in a low-price environment. Supply costs are calculated as the long-term average WTI price required to achieve a 9% after-tax return after all capital, operating and maintenance costs are considered. Supply costs are approximately US$35 to $45 per barrel at both Foster Creek and Christina Lake.
“One of Cenovus’s key strengths is that we can generate positive returns at lower prices,” said Ferguson. “We anticipate fluctuations in commodity prices and we have the financial stability to deal with those. Our integrated strategy, strong balance sheet and position as a low-cost operator mean we can generate shareholder value in a variety of price environments.”
Continuing to advance Telephone Lake
Cenovus has concluded its process to identify a potential strategic partner for its Telephone Lake oil sands project. The goal of the process was to identify an arrangement that would provide strategic benefit to Cenovus and bring forward the value of the project, which is not included in the company’s 10-year plan.
“We only wanted a deal if it would add compelling value for our shareholders,” said Ferguson. “There was never a financial need to do a transaction. Our drilling results indicate that Telephone Lake is a world-class resource and has the potential to be a cornerstone project like Foster Creek or Christina Lake. We look forward to developing the asset on our own.”
Cenovus continues to advance the dewatering pilot project at Telephone Lake, which is designed to test the efficiency of removing the non-potable water sitting on top of the bitumen in the reservoir. Removing this water is expected to reduce the steam to oil ratio (SOR) and operating costs for the commercial project. The company commissioned the pilot facilities in the second quarter and expects to start water production and air injection in the next couple of months.
Regulatory approval for Narrows Lake
Cenovus received approval from the Alberta Energy Resources Conservation Board for its Narrows Lake development in the second quarter. The approval included the option to use a combination of steam-assisted gravity drainage (SAGD) and solvent aided process (SAP). SAP involves the addition of a solvent to the steam injected into the reservoir to help thin the oil and allow it to flow more freely to the producing well. This would be the industry’s first use of SAP with butane on a commercial scale.
The project is anticipated to have a gross production capacity of 130,000 bbls/d and be developed in three phases. Narrows Lake is located just north of the company’s Christina Lake property and is jointly owned with ConocoPhillips. Project sanctioning from Cenovus and ConocoPhillips is expected by the end of this year, with ground work for the initial phase of 45,000 bbls/d gross expected to begin this fall.
“Receiving regulatory approval for Narrows Lake was a significant achievement,” said Ferguson. “This is an important milestone along the path to developing our next major oil sands project, which will be the first to use our solvent aided process on a commercial scale. We’re excited about this technology, as it has the potential to significantly improve recovery while continuing to reduce the environmental impact.”
From Financial Post