Company starts producing oil from Christina Lake phase E
- Total oil production was more than 171,000 barrels of oil per day (bbls/d) net in the second quarter, a 10% increase when compared with the same period in 2012.
- Combined oil sands production at Foster Creek and Christina Lake averaged nearly 94,000 bbls/d net in the second quarter, up 17% from a year earlier. Production at Christina Lake climbed 35% to an average of more than 38,000 bbls/d net.
- Christina Lake phase E started steam injection in June, with first production achieved in mid-July.
- Operating cash flow increased 4% to $1.1 billion in the second quarter when compared with the same period a year earlier.
- Cash flow was $871 million in the quarter, a 6% decrease when compared with 2012, mainly due to a conventional oil pre-exploration expense and higher cash tax.
- Discovered bitumen initially-in-place increased 66% since 2009 to 93 billion barrels, reflecting the success of Cenovus's stratigraphic drilling program in converting undiscovered resource inventory to discovered.
- An agreement to sell Cenovus's Shaunavon tight oil asset for $240 million (plus closing adjustments) was announced in early June and closed in early July.
"At Cenovus, we continue to play to our strengths and deliver on our commitments," said Brian Ferguson, Cenovus President & Chief Executive Officer. "We have a track record of predictable and reliable development of our vast oil sands resources. In July, we started producing oil at our tenth expansion phase in the oil sands, Christina Lake phase E, and we expect to bring on a new phase of production in each of the next several years."
|Production & financial summary|
(for the period ended June 30)
Production (before royalties)
|Oil sands total (bbls/d)||93,797||80,317||17|
|Conventional oil1 (bbls/d)||77,330||75,249||3|
|Total oil (bbls/d)||171,127||155,566||10|
|Natural gas (MMcf/d)||536||596||-10|
($ millions, except per share amounts)
Per share diluted
|Per share diluted||0.34||0.37|
|Per share diluted||0.24||0.52|
1 Includes natural gas liquids (NGLs) and Pelican Lake production.
2 Cash flow and operating earnings are non-GAAP measures as defined in the Advisory. See also the earnings reconciliation summary in the operating earnings table.
CALGARY, July 24, 2013 /PRNewswire/ - Cenovus Energy Inc. (TSX, NYSE: CVE) delivered a solid operational quarter, buoyed by growing oil production from both its oil sands and conventional assets. Combined production from the company's oil sands projects, Christina Lake and Foster Creek, averaged nearly 94,000 bbls/d net in the quarter, a 17% increase from the same period a year earlier. This was primarily driven by the start-up of Christina Lake phase D in the third quarter of 2012 and subsequent ramp-up in the first half of 2013.
Average daily oil production at Christina Lake was more than 38,000 bbls/d net in the quarter, a 35% increase when compared with the same period in 2012. Volumes at Christina Lake were reduced during the quarter by the company's first full planned turnaround at the facility, which was completed successfully and safely. Cenovus started injecting steam for phase E in late June and achieved first production last week. The company expects the ramp-up to take place over the next six to nine months, similar to the ramp-up experienced at Christina Lake phase D.
Foster Creek production averaged more than 55,000 bbls/d net in the quarter, 7% higher than the year before. This increase is due to volumes being reduced in the second quarter of 2012 as the result of a full turnaround at the facility. The 2013 turnaround at Foster Creek is planned to start in late September.
Cenovus's conventional oil assets, including Pelican Lake, continued to deliver steady performance. Production averaged more than 77,000 bbls/d in the quarter, a slight increase from the same period in 2012 partly due to successful well performance related to the company's current drilling program to develop tight oil opportunities i n Alberta. Work to expand Cenovus's infill drilling and polymer flood program at Pelican Lake is ongoing, resulting in average production of nearly 24,000 bbls/d in the quarter, 7% higher than the same period a year earlier.
Demonstrating the value of integration
Operating cash flow was $1.1 billion in the quarter, an increase of 4% when compared with the same period a year earlier. Operating cash flow from the company's upstream assets benefited from the West Texas Intermediate (WTI) to Western Canadian Select (WCS) differential narrowing in the second quarter, to an average of US$19.16 per barrel (bbl), a 16% decrease from the same period in 2012. Climbing oil production and increased natural gas prices also contributed to higher operating cash flow. Those benefits were partially offset by higher operating costs, lower realized risk management gains and a decline in operating cash flow generated by the company's refining operations.
Operating cash flow from refining was $316 million in the second quarter, an 8% decrease when compared with the same period a year earlier. The narrowing WTI to WCS differential that benefited the company's upstream operations resulted in increased feedstock costs at Cenovus's refineries. Lower refined product output due to an unplanned hydrocracker outage at Wood River in June also contributed to the decline.
Cash flow in the second quarter was $871 million, a 6% decrease compared with the same period a year earlier. This is due to the same factors that affected operating cash flow, as well as a $63 million conventional oil pre-exploration expense and higher cash tax.
Operating earnings were $255 million in the quarter, a 10% decrease compared with the second quarter of 2012, mainly because of lower cash flow and increased depreciation, depletion and amortization (DD&A), which reflected an impairment of $57 million from the sale of the company's Shaunavon asset. Cenovus also incurred a $46 million exploration expense related to another tight oil play in Saskatchewan.
Cenovus's net earnings for the second quarter were $179 million compared with $397 million in the same period a year earlier, primarily as a result of lower unrealized risk management gains and higher unrealized foreign exchange losses in 2013, partially offset by a decline in deferred tax expense.
Cenovus has updated its 2013 full-year guidance to reflect actual results for the first half of the year and the company's outlook for the remainder of the year. Of note is a slight increase to the operating costs range at Foster Creek, Christina Lake and Pelican Lake based on actual costs for the first six months of the year, and expectations for the rest of 2013. Total cash flow remains unchanged. Updated guidance can be found at cenovus.com under "Invest in us."
Accessing new markets remains a priority
Cenovus continues to be rigorous in its efforts to identify new markets for its oil. During the second quarter, the company participated in the open season for TransCanada's Energy East pipeline project and is currently awaiting the results of that process.
"Our manufacturing approach to oil sands expansions has made us a low-cost producer," said Ferguson. "This same approach is also extremely valuable to our transportation strategy. We know we'll have significant new production coming on line every year for the next several years, so we can confidently make long term transportation commitments."
Cenovus plans to transport up to 50% of its oil production through firm commitments over the long-term. At this point, the company has made commitments to various pipeline projects to move up to 175,000 bbls/d to the West Coast and up to 150,000 bbls/d to the U.S. Gulf Coast. This transportation plan includes growing rail capacity to move up to 10% of production over the long term. In the second quarter, Cenovus used rail to transport about 7,900 bbls/d to the East Coast and to markets in the U.S. The company expects to move approximately 10,000 bbls/d on rail by the end of 2013 and up to 30,000 bbls/d by the end of 2014.
Business operations maintained during Alberta flooding
The June floods that caused major damage in southern Alberta resulted in restricted access to most of downtown Calgary for nearly a week, including Cenovus's head office and other buildings. The company's business continuity plan to handle this type of situation was successfully activated and all critical systems, communications and business functions continued remotely or from a Cenovus office building outside of downtown Calgary. Cenovus's operations in Alberta were minimally affected by the floods.
"Our thoughts remain with the many people whose lives have been impacted by the flooding," said Ferguson. "We commend the volunteers, including Cenovus staff, who are working to help those in need. Cenovus is donating $1 million to agencies assisting with the relief efforts and those community partners impacted by the floods."
|Q2||Q1||Full Year||Q4||Q3||Q2||Q1||Full Year|
|Oil sands total||94||100||90||101||96||80||82||67|
1 Totals may not add due to rounding.
2 Includes NGLs production.
Cenovus has a substantial portfolio of oil sands assets in northern Alberta with the potential to provide decades of growth. The two currently producing operations, Foster Creek and Christina Lake, use steam-assisted gravity drainage (SAGD), which involves drilling into the reservoir and pumping the oil to the surface. Cenovus has begun work on its third project, Narrows Lake, which is part of the Christina Lake Region. These projects are operated by Cenovus and are jointly owned with ConocoPhillips. Cenovus also has an enormous opportunity to deliver increased shareholder value through production growth from future developments. The company has identified several emerging projects and continues to assess its resources to prioritize development plans and support regulatory applications for new projects.
Foster Creek and Christina Lake
- Combined production at Foster Creek and Christina Lake climbed 17% to 93,797 bbls/d net in the second quarter of 2013 compared with the same period a year earlier.
- Foster Creek produced an average of 55,338 bbls/d net in the quarter, a 7% increase when compared with the same period a year earlier. Volumes were reduced in the second quarter of 2012 due to a full turnaround at the facility. The 2013 turnaround at Foster Creek is scheduled to begin in late September.
- Cenovus continues to reduce the backlog of workover activity required on wells and expects Foster Creek production to return to near full capacity in the fourth quarter.
- Christina Lake production averaged 38,459 bbls/d net, a 35% increase over the same period in 2012 due to the start-up of phase D in the second quarter of 2012. Cenovus completed its first major plant turnaround at the facility, which resulted in 11 days of full production outage and reduced production by about 7,600 bbls/d net in the quarter.
- Steam injection at Christina Lake phase E started in June, with first production achieved in mid-July. Cenovus expects the ramp-up of phase E to take six to nine months, similar to phase D, with the phase ultimately having the capacity to produce 40,000 bbls/d gross.
Wedge Well™ technology
- Cenovus's Wedge Well™ technology uses single horizontal wells, drilled between existing SAGD well pairs, to reach oil that would otherwise be unrecoverable. It has the potential to increase overall recovery from the reservoir between 10% and 15%, while reducing the steam to oil ratio (SOR).
- There are 56 wells at Foster Creek using Wedge Well™ technology and Cenovus anticipates bringing an additional 11 of these wells on production in the second half of 2013.
- Christina Lake is also benefiting from the use of Wedge WellTM technology. There are 10 of these wells now producing and Cenovus expects to drill another 15 wells before the end of the year.
- At Christina Lake, procurement, plant construction and major equipment fabrication continue for phase F, which is now about 30% complete. Engineering work continues for phase G.
- At Foster Creek, plant construction for the combined F, G and H expansion is approximately 60% complete. The central plant for phase F is about 78% complete and first production is expected in the third quarter of 2014. Pipe rack and equipment module assembly are essentially complete for phase G, and piling work was completed in May. Overall phase G is about 56% complete, with initial production expected in 2015. At phase H, site preparation, piling work and major equipment procurement continue to progress as planned.
- Combined capital investment at Foster Creek and Christina Lake was $351 million in the second quarter, up from $309 million in the same period of 2012 primarily due to planned spending on expansion phases.
- Operating costs at Foster Creek averaged $16.19/bbl in the second quarter, compared with $12.49/bbl a year earlier, as Cenovus incurred higher workover costs and higher prices for fuel and electricity. Non-fuel operating costs were $13.36/bbl in the quarter compared with $10.89/bbl in the same period of 2012, a 23% increase.
- While operating costs are expected to decrease over the remainder of the year compared with the second quarter, Cenovus has updated its guidance to reflect a higher annual average of between $14.90/bbl and $15.90/bbl for Foster Creek's operating costs.
- Operating costs at Christina Lake were $16.83/bbl in the second quarter, an increase from $12.52/bbl in the same period a year ago due to higher repairs and maintenance associated with the turnaround. Other factors included increased costs for waste fluid handling and trucking, and higher prices for fuel and electricity. Non-fuel operating costs at Christina Lake were $13.46/bbl in the quarter compared with $10.83/bbl in 2012, a 24% increase. While operating costs are expected to decrease over the remainder of the year compared with the second quarter, Cenovus has updated its guidance to reflect a slightly higher annual average of between $12.80/bbl and $13.60/bbl for Christina Lake's operating costs.
Steam to oil ratio (SOR)
- Cenovus uses natural gas to produce steam. The SOR measures the number of barrels of steam needed for every barrel of oil produced. A lower SOR means less steam is required, which reduces the amount of natural gas used. This lowers capital and operating costs, and results in fewer emissions and lower water usage per barrel of oil.
- Cenovus continues to achieve among the lowest SORs in the industry. The combined SOR for Cenovus's oil sands operations was 2.1 in the second quarter of 2013.
- The second quarter SOR at Christina Lake was 1.8, unchanged from the same period a year ago.
- Foster Creek's SOR was 2.4, compared with 2.1 in the second quarter of 2012. The increase is due to a high number of wells undergoing maintenance in the second quarter. Cenovus has updated its 2013 guidance to reflect a revised annual average SOR range for Foster Creek of 2.3 to 2.5.
Christina Dilbit Blend (CDB)
- CDB is a heavy oil blend stream launched in the fourth quarter of 2011. Cenovus sold approximately 92% of its Christina Lake production as CDB in the second quarter of 2013, up from 70% in the same period a year earlier.
- The CDB price differential to WCS improved approximately $0.50/bbl to $5.82/bbl when compared with the same period in 2012 as CDB continues to gain wider market acceptance.
- The Wood River Refinery ran approximately 109,000 bbls/d of CDB or equivalent high-TAN crudes during the second quarter of 2013. These crudes represented approximately 56% of the total heavy crude volumes processed at Wood River in the quarter.
- Cenovus's next major oil sands development, a three-phase project at Narrows Lake in northern Alberta, received full regulatory approval and partner approval for the first phase in 2012. The first phase of the project is anticipated to have a production capacity of 45,000 bbls/d gross, with first oil expected in 2017.
- Narrows Lake is expected to be the industry's first project to demonstrate solvent aided process (SAP), using butane, on a commercial scale.
- Site preparation, engineering and procurement are progressing as expected. Construction of the phase A plant is scheduled to start later in the third quarter of 2013.
- Cenovus invested $25 million to advance the Narrows Lake project in the second quarter of this year compared with $9 million in the same period in 2012. This included spending on site preparation, engineering and procurement.
- Cenovus's 100%-owned Telephone Lake property is located within the Borealis Region of northern Alberta. A revised application and environmental impact assessment (EIA) submitted in December 2011 is advancing through the regulatory process with approval anticipated in 2014.
- Cenovus is continuing its dewatering pilot project designed to remove a layer of non-potable water that is sitting on top of the oil sands deposit at Telephone Lake. While dewatering is not essential to the development of Telephone Lake, the company believes it could help improve the project's SOR by up to 30%, which should enhance project economics and reduce its impact on the environment.
- The pilot has been running as expected with positive results. Approximately 50% of the water has been displaced and replaced by air. Cenovus plans to complete the pilot in the fourth quarter of 2013.
- Capital spending in the second quarter was $17 million, up from $13 million a year earlier.
- At the company's 100%-owned Grand Rapids project, located within the Greater Pelican Region, work continues on a SAGD pilot project. The pilot project is progressing, with both well pairs operational. Cenovus is planning minor facility upgrades in the third quarter, which is expected to help increase production from the well pairs.
- A regulatory application and EIA for the 180,000 bbl/d commercial project has been submitted and Cenovus anticipates regulatory approval by the end of 2013.
- Capital investment at Grand Rapids was $8 million in the second quarter of 2013, up from $5 million a year earlier.
Cenovus produces heavy oil from the Wabiskaw formation at its 100%-owned Pelican Lake operation in the Greater Pelican Region, about 300 kilometres north of Edmonton. While this property produces conventional heavy oil, it's managed as part of Cenovus's oil sands segment. Since 2006, Cenovus has been injecting polymer to enhance production from the reservoir, which is also under waterflood. Based on reservoir performance of the polymer program, the company has a multi-year growth plan for Pelican Lake with production expected to reach 55,000 bbls/d.
- Pelican Lake produced 23,959 bbls/d in the second quarter of 2013, a 7% increase when compared with the same period in 2012 as infill wells drilled to expand the polymer flood continued to come on production.
- Cenovus invested $111 million at Pelican Lake in the second quarter for infill drilling related to the polymer flood program, facility expansion and other infrastructure, up from $104 million in the same period of 2012.
- The company has decided to delay some capital investment originally planned for 2013 to align spending with the moderate production ramp up currently associated with the polymer flood program.
- Operating costs at Pelican Lake averaged $22.21/bbl in the second quarter, a 25% increase from $17.71/bbl in the same quarter a year earlier mainly due to workover activities, higher electricity prices and usage related to the polymer flood expansion, and repairs and maintenance. While operating costs are expected to decrease over the remainder of the year compared with the second quarter, Cenovus has updated its guidance to reflect a slightly higher annual average of between $19.00/bbl and $20.00/bbl for Pelican Lake's operating costs.
Other conventional oil
In addition to Pelican Lake, Cenovus has conventional oil assets in Alberta, including tight oil opportunities, as well as the established Weyburn operation in Saskatchewan that uses carbon dioxide injection to enhance oil recovery.
- Total conventional oil production averaged 53,371 bbls/d in the second quarter, a slight increase when compared with the same quarter in 2012.
- Conventional oil production in Alberta averaged 32,151 bbls/d in the second quarter, up 7% from the same period in the previous year, primarily due to successful horizontal well performance related to the company's current drilling program to develop tight oil opportunities.
- Production at the Weyburn operation remained steady at 15,938 bbls/d net compared with 16,422 bbls/d net in the second quarter of 2012.
- Cenovus entered into an agreement to sell its Shaunavon tight oil asset in southern Saskatchewan for $240 million (plus closing adjustments) in early June, and closed the transaction in early July. An impairment of $57 million was recorded as depreciation, depletion and amortization (DD&A). The company's Bakken asset remains held for sale.
- Cenovus also incurred a $46 million exploration expense related to another tight oil play in Saskatchewan, as well as a $63 million pre-exploration expense related to a seperate conventional oil opportunity.
- Cenovus invested $130 million in its conventional oil assets, the majority of which was dedicated to development of emerging tight oil plays in Alberta.
- Operating costs for Cenovus's conventional oil operations increased 12% to $16.34/bbl in the second quarter of 2013 compared with the same period in 2012. This was mainly due to higher workforce and electricity costs.
- Operating cash flow from conventional oil assets in excess of capital investment increased 14% to $121 million in the second quarter when compared with the same period a year earlier.
|Q2||Q1||Full Year||Q4||Q3||Q2||Q1||Full Year|
Cenovus has a solid base of established, reliable natural gas properties in Alberta. These assets are an important component of the company's financial foundation, generating operating cash flow well in excess of their ongoing capital investment requirements. The natural gas business also acts as an economic hedge against price fluctuations, because natural gas fuels the company's oil sands and refining operations.
- Natural gas production in the second quarter of 2013 was approximately 536 million cubic feet per day (MMcf/d), down 10% from the same period last year, driven by expected natural declines and Cenovus's decision to direct capital investment toward its oil opportunities.
- Cenovus's average realized sales price for natural gas, including hedges, was $3.68 per thousand cubic feet (Mcf) in the period compared with $3.31 per Mcf in the second quarter of 2012.
- The company invested $5 million in its natural gas properties in the second quarter of 2013. Operating cash flow from natural gas in excess of capital investment was $113 million.
Cenovus's refining operations allow the company to capture value from crude oil production through to refined products such as diesel, gasoline and jet fuel. This integrated strategy provides a natural economic hedge when crude oil prices are discounted by providing lower feedstock costs to the Wood River Refinery in Illinois and Borger Refinery in Texas, which Cenovus jointly owns with the operator, Phillips 66.
- Operating cash flow from refining was $316 million in the quarter, 8% less than the same period a year earlier. This was primarily due to increased feedstock costs consistent with higher oil prices, as well as an unplanned hydrocracker outage at Wood River in June that affected product output.
- Cenovus's refineries processed an average of 439,000 bbls/d of crude oil in the second quarter, resulting in 457,000 bbls/d of refined product output. This was about 3% lower than in the same quarter a year ago primarily due to the unplanned outage at Wood River in June.
- The amount of Canadian heavy oil processed in the second quarter of 2013 was 230,000 bbls/d, similar to the same period a year earlier despite the unplanned outage at Wood River.
- Cenovus's refining operating cash flow is calculated on a first-in, first-out (FIFO) inventory accounting basis. Using the last-in, first-out (LIFO) accounting method employed by most U.S. refiners, Cenovus's second quarter 2013 refining operating cash flow would have been $33 million lower than reported under FIFO, compared with $95 million higher in the same quarter of 2012.
- The company invested $26 million in its refining operations during the second quarter, compared with $24 million in the same quarter of 2012.
The Cenovus Board of Directors declared a third quarter dividend of $0.242 per share, payable on September 30, 2013 to common shareholders of record as of September 13, 2013. Based on the July 23, 2013 closing share price on the Toronto Stock Exchange of $32.25, this represents an annualized yield of about 3%. Declaration of dividends is at the sole discretion of the Board. Cenovus's continued commitment to the dividend is an important aspect of the company's strategy to focus on increasing total shareholder return.
Cenovus's natural gas and crude oil hedging strategy helps it to achieve more predictability around cash flow and safeguard its capital program. The Board-approved risk management policy allows the company to financially hedge up to 75% of this year's and next year's expected natural gas production, net of internal fuel usage, and up to 50% and 25%, respectively, in the following two years. The policy also allows the company to enter fixed price hedges on as much as 50% of net liquids production this year and next, as well as 25% of net liquids production for each of the following two years. In addition to financial hedges, Cenovus benefits from a natural hedge with its gas production. About 135 MMcf/d of natural gas is expected to be consumed at the company's SAGD and refinery operations, which is more than offset by the gas Cenovus produces. The company's financial hedging positions are determined after considering this natural hedge.
Cenovus's financial hedge positions at June 30, 2013 include:
- approximately 10% or 18,500 bbls/d of expected oil production hedged for 2013 at an average Brent price of US$110.36/bbl and an additional 10% or 18,500 bbls/d at an average Brent price of C$111.72/bbl
- approximately 32% or 166 MMcf/d of expected natural gas production hedged for 2013 at an average NYMEX price of US$4.64/Mcf, plus internal usage of about 135 MMcf/d of natural gas and long-term sales of 29 MMcf/d of natural gas
- approximately 49,000 bbls/d of heavy crude exposure hedged for 2013 at an average WCS differential to WTI of US$20.74/bbl
- approximately 14,900 bbls/d of heavy crude exposure hedged for 2014 at an average WCS differential to WTI of US$20.39/bbl
- approximately 9,000 bbls/d of expected oil production hedged for 2014 at an average Brent price of US$100.35/bbl and an additional 6,000 bbls/d at an average Brent price of C$103.81/bbl
- Operating cash flow was $1.1 billion in the quarter, an increase of 4% when compared with the same period a year earlier. Operating cash flow from the company's upstream assets benefited from the narrowing WTI to WCS differential, as well as climbing oil production and increased natural gas prices, partially offset by higher operating costs, lower realized risk management gains and a decline in operating cash flow generated by the company's refining operations.
- Cash flow in the second quarter was $871 million, or $1.15 per share diluted, compared with $925 million, or $1.22 per share diluted, in the same period a year earlier as higher oil production and prices were more than offset by higher oil production costs, a decrease in operating cash flow from the company's refining operations, higher cash tax, lower realized risk management gains, and a $63 million conventional oil pre-exploration expense.
- Operating earnings in the quarter were $255 million, or $0.34 per share diluted, down 10% from the same quarter in 2012 mainly because of lower cash flow and increased DD&A, which reflected an impairment of $57 million on the company's Shaunavon asset disposition. Cenovus also incurred a $46 million exploration expense related to another tight oil play in Saskatchewan.
- Cenovus had a realized after-tax hedging gain of $16 million in the second quarter. The company received an average realized price, including hedging, of $70.33/bbl for its oil in the second quarter, compared with $65.56/bbl during the same period in 2012. The average realized price, including hedging, for natural gas in the second quarter was $3.68/Mcf, compared with $3.31/Mcf a year earlier.
- Cenovus recorded income tax expense of $101 million in the second quarter of 2013, giving the company an effective tax rate of 36%, compared with an effective rate of 37% in the year-earlier period.
- Cenovus's net earnings for the second quarter were $179 million compared with $397 million in the same period a year earlier, primarily as a result of lower unrealized risk management gains and higher unrealized foreign exchange losses in 2013, partially offset by a decline in deferred tax expense.
- Capital investment during the quarter was $706 million. That was a 7% increase from $660 million in the second quarter of 2012 as the company continues to expand its oil sands assets.
- General and administrative (G&A) expenses were $82 million in the second quarter, a 46% increase primarily due to an increase in staffing and office rent.
- Over the long term, Cenovus continues to target a debt to capitalization ratio of between 30% and 40% and a debt to adjusted EBITDA ratio of between 1.0 and 2.0 times. At June 30, 2013, the company's debt to capitalization ratio was 33% and debt to adjusted EBITDA, on a trailing 12-month basis, was 1.2 times.
(for the period ended June 30)
($ millions, except per share amounts)
Add back (deduct):
|Unrealized risk management (gains) losses, after-tax||(21)||(126)|
|Non-operating unrealized foreign exchange (gains) losses, after-tax||97||14|
|Divestiture (gains) losses, after-tax||-||(1)|
|Per share diluted||0.34||0.37|
|1 Operating earnings is a non-GAAP measures as defined in the Advisory.|
An external evaluation of Cenovus's oil sands assets by McDaniel & Associates Consultants Ltd., an independent qualified reserves evaluator, has identified the discovered portion of best estimate total bitumen initially-in-place (BIIP) on Cenovus lands as at December 31, 2012 has increased 66% to 93 billion barrels since the last evaluation at December 31, 2009.
Cenovus's active stratigraphic well program has been successful in converting much of the previously undiscovered BIIP into discovered BIIP. The company drilled more than 1,200 wells between the beginning of 2010 and the end of 2012. Total BIIP has been stable, increasing 4% from 137 billion barrels to 143 billion barrels over the three-year period, largely as the result of property acquisitions.
Best estimate total bitumen initially-in-place1 (billion barrels)
Company interest at December 31
|Total bitumen initially-in-place||143||137|
|Discovered bitumen initially-in-place||93||56|
|Commercial discovered bitumen initially-in-place2|
|Reserves (proved + probable)3||2.4||1.3|
|Sub-commercial discovered bitumen initially-in-place4|
|Economic contingent resources3,5||9.6||5.4|
|Undiscovered bitumen initially-in-place||50||82|
1 Bitumen initially-in-place estimates include unrecoverable volumes and
are not an estimate of the volume of the substances that will
ultimately be recovered. See the Advisory for a description of the
terms and associated contingencies. Totals may not add due to rounding.
2 Commercial discovered bitumen initially-in-place equals the cumulative production plus reserves.
3 Cumulative production, reserves and contingent resources are disclosed on a before royalties basis. Reserves and contingent resources as at December 31, 2009 were evaluated using SEC prices and costs. See the Advisory for details.
4 Sub-commercial discovered bitumen initially-in-place equals economic contingent resources plus the unrecoverable portion of discovered bitumen initially-in-place.
5 Any contingent resources as at December 31, 2012 that are sub-economic or that are classified as being subject to technology under development have been grouped into the unrecoverable portion of discovered bitumen initially-in-place. There is no certainty that it will be commercially viable to produce any portion of the resources.
6 There is no certainty that any portion of the resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the resources.
A rigorous process determines which portion of the BIIP can be developed and ultimately recovered. Large portions of the total BIIP are classified as unrecoverable because they are contained in accumulations that are too thin, have too low a bitumen concentration, or possess other geological characteristics unsuitable for recovery using current technologies. Deposits that can be developed with current production technologies, such as SAGD, fit into the exploitable bitumen in-place classification provided by the evaluator. Cenovus's total BIIP includes 32 billion barrels of BIIP in the Grosmont carbonate formation. The potential to exploit the Grosmont using technologies currently under development was not considered in the evaluation.
Bitumen recovery estimation (billion barrels)
Company interest at December 31
|Exploitable bitumen in-place1||24||14|
|Estimated recovery of exploitable bitumen in-place2||51%||48%|
|Exploitable bitumen in-place1||16||25|
|Estimated recovery of exploitable bitumen in-place2||53%||51%|
1 See the Advisory for a description of exploitable bitumen in-place.
2 Estimated recovery is provided by the independent qualified reserves evaluator.
3 There is no certainty that any portion of the resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the resources.
|Oil sands project schedule|
|Project phase||Regulatory status||
|Foster Creek1 A - E||120,000|
|Christina Lake1 A - D||98,000|
|Optimization (phases CDE)||Submitted Q4-2012||2015F||22,0003|
|Telephone Lake4||Submitted Q4-2011||TBD||90,000|
|Grand Rapids||Submitted Q4-2011||TBD||180,000|
1 Properties 50% owned by ConocoPhillips. Certain phases may be subject to
2 Includes 5,000 bbls/d gross submitted to the regulator in Q1 2013.
3 Increased from 12,000 bbls/d in Q2 2013 due to the addition of blowdown boilers.
4 Projected total capacity of more than 300,000 bbls/d.
Conference call today
9 a.m. Mountain Time (11 a.m. Eastern Time)
Cenovus will host a conference call today, July 24, 2013, starting at 9 a.m. MT (11a.m. ET). To participate, please dial 888-231-8191 (toll-free in North America) or 647-427-7450 approximately 10 minutes prior to the conference call. An archived recording of the call will be available from approximately 12 p.m. MT on July 24, 2013, until 10 p.m. MT on July 31, 2013, by dialing 855-859-2056 or 416-849-0833 and entering passcode 99935983. A live audio webcast of the conference call will also be available via cenovus.com or via the following URL: http://event.on24.com/r.htm?e=649075&s=1&k=0C47D6CE2ADBFDBF347615B36AF428DF The webcast will be archived for approximately 90 days.
Basis of Presentation Cenovus reports financial results in Canadian dollars and presents production volumes on a net to Cenovus before royalties basis, unless otherwise stated. Cenovus prepares its financial statements in accordance with International Financial Reporting Standards (IFRS).
Non-GAAP Measures This news release contains references to non-GAAP measures as follows:
- Operating cash flow is defined as revenues, less purchased product, transportation and blending, operating expenses, production and mineral taxes plus realized gains, less realized losses on risk management activities and is used to provide a consistent measure of the cash generating performance of the company's assets and improves the comparability of Cenovus's underlying financial performance between periods.
- Cash flow is defined as cash from operating activities excluding net change in other assets and liabilities and net change in non-cash working capital, both of which are defined on the Consolidated Statement of Cash Flows in Cenovus's interim and annual consolidated financial statements.
- Operating earnings is defined as net earnings excluding after-tax gain (loss) on discontinuance, after-tax gain on bargain purchase, after-tax effect of unrealized risk management gains (losses) on derivative instruments, after-tax unrealized foreign exchange gains (losses) on translation of U.S. dollar denominated notes issued from Canada and the Partnership Contribution Receivable, after-tax foreign exchange gains (losses) on settlement of intercompany transactions, after-tax gains (losses) on divestiture of assets, deferred income tax on foreign exchange recognized for tax purposes only related to U.S. dollar intercompany debt and the effect of changes in statutory income tax rates. Management views operating earnings as a better measure of performance than net earnings because the excluded items reduce the comparability of the company's underlying financial performance between periods. The majority of the U.S. dollar debt issued from Canada has maturity dates in excess of five years.
- Free cash flow is defined as cash flow in excess of capital investment, excluding net acquisitions and divestitures, and is used to determine the funds available for other investing and/or financing activities.
- Debt to capitalization and debt to adjusted EBITDA are two ratios that management uses to steward the company's overall debt position as measures of the company's overall financial strength. Debt is defined as short-term borrowings and long-term debt, including the current portion, excluding any amounts with respect to the partnership contribution payable and receivable. Capitalization is a non-GAAP measure defined as debt plus shareholders' equity. Adjusted EBITDA is defined as earnings before finance costs, interest income, income tax expense, depreciation, depletion and amortization, asset impairments, unrealized gain or loss on risk management, foreign exchange gains or losses, gains or losses on divestiture of assets and other income and loss, calculated on a trailing 12-month basis.
These measures have been described and presented in this news release in order to provide shareholders and potential investors with additional information regarding Cenovus's liquidity and its ability to generate funds to finance its operations. For further information, refer to Cenovus's most recent Management's Discussion & Analysis (MD&A) available at cenovus.com.
OIL & GAS INFORMATION
The estimates of total bitumen initially-in-place and all subcategories thereof and the associated recovery factors were prepared effective December 31, 2012 by McDaniel & Associates Consultants Ltd., an independent qualified reserves evaluator (IQRE), and are based on definitions contained in the Canadian Oil and Gas Evaluation Handbook (COGEH). The estimates of exploitable bitumen in-place (EBIP) were also prepared effective December 31, 2012 by the IQRE. The term "exploitable bitumen in-place" is not presently a COGEH defined term; however, the definition contained herein was provided by the IQRE and is derived from and consistent with the current draft proposed COGEH terminology. The term "best estimate", when used in reference to a BIIP estimate, is not defined in COGEH; however, it was determined by the IQRE to the same 50% confidence level as was applied to estimates of probable reserves and best estimate contingent resources.
The IQRE evaluation of Cenovus's reserves and bitumen contingent resources as at December 31, 2009 was compliant with the U.S. Securities and Exchange Commission (SEC) requirements, using 12 month average constant prices and costs. An IQRE evaluation using McDaniel January 1, 2010 forecast prices and costs did not produce a materially different result.
For further discussion regarding our contingent resources, see our 2012 Annual Information Form (AIF), available on SEDAR at sedar.com and at cenovus.com. Actual resources may be greater or less than the estimates provided. The following definitions accompany the disclosure contained herein:
Best estimate is considered to be the best estimate of the quantity of resources that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. Those resources that fall within the best estimate have a 50% probability that the actual quantities recovered will equal or exceed the estimate.
Total bitumen initially-in-place (BIIP) (equivalent to "total resources") is that quantity of bitumen that is estimated to exist originally in naturally occurring accumulations. It includes that quantity of bitumen that is estimated, as of a given date, to be contained in known accumulations, prior to production (discovered BIIP), plus those estimated quantities in accumulations yet to be discovered (undiscovered BIIP).
Discovered BIIP (equivalent to "discovered resources") is that quantity of bitumen that is estimated, as of a given date, to be contained in known accumulations prior to production. The recoverable portion of discovered BIIP includes production, reserves, and contingent resources; the remainder is categorized as unrecoverable. BIIP estimates include unrecoverable volumes and are not an estimate of the volume of the substances that will ultimately be recovered. There is no certainty that it will be commercially viable to produce any portion of the estimate.
Commercial discovered BIIP is that quantity of discovered BIIP that has met the essential social, environmental, and economic conditions, including political, legal, regulatory, and contractual conditions, to be considered capable of commercial production and includes production and reserves.
Production is the cumulative quantity of bitumen that has been recovered at a given date.
Reserves are estimated remaining quantities of bitumen anticipated to be recoverable from known accumulations, as of a given date, based on the analysis of drilling, geological, geophysical, and engineering data; the use of established technology; and specified economic conditions, which are generally accepted as being reasonable. Reserves are further classified according to the level of certainty associated with the estimates and may be sub-classified based on development and production status.
Proved Reserves are those quantities of bitumen, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations.
Probable Reserves are those additional reserves quantities of bitumen that are less certain to be recovered than proved reserves, but which, together with proved reserves, are as likely as not to be recovered.
Sub-commercial discovered BIIP is that quantity of discovered BIIP that has not met all of the essential social, environmental, and economic conditions, including political, legal, regulatory, and contractual conditions, to be capable of commercial production and includes contingent resources and unrecoverable discovered BIIP.
Contingent resources are those quantities of bitumen estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies may include such factors as economic, legal, environmental, political and regulatory matters or a lack of markets. It is also appropriate to classify as contingent resources the estimated discovered recoverable quantities associated with a project in the early evaluation stage. Contingent resources are further classified in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by their economic status. The McDaniel estimates of contingent resources have not been adjusted for risk based on the chance of development.
Economic contingent resources are those contingent resources that are currently economically recoverable based on specific forecasts of commodity prices and costs. Economic contingent resources are estimated using volumetric calculations of the in-place quantities, combined with performance from analog reservoirs. Existing SAGD projects that are producing from the McMurray-Wabiskaw formations are used as performance analogs at Foster Creek and Christina Lake. Other regional analogs are used for contingent resources estimation in the Cretaceous Grand Rapids formation at the Grand Rapids property in the Pelican Lake Region, in the McMurray formation at the Telephone Lake property in the Borealis Region and in the Clearwater formation in the Foster Creek Region.
Contingencies which must be overcome to enable the reclassification of contingent resources as reserves can be categorized as economic, non-technical and technical. The COGEH identifies non-technical contingencies as legal, environmental, political and regulatory matters or a lack of markets. Technical contingencies include available infrastructure and project justification. The outstanding contingencies applicable to our disclosed contingent resources do not include economic contingencies. Our bitumen contingent resources are located in four general regions: Foster Creek, Christina Lake, Borealis and Greater Pelican. Further information in respect of contingencies faced in these regions is included in our AIF.
Unrecoverable is that portion of discovered BIIP or undiscovered BIIP quantities which is estimated, as of a given date, not to be recoverable by future development projects. A portion of these quantities may become recoverable in the future as commercial circumstances change or technological developments occur; the remaining portion may never be recovered due to the physical/chemical constraints represented by subsurface interaction of fluids and reservoir rocks.
Undiscovered BIIP (equivalent to "undiscovered resources") is that quantity of bitumen that is estimated, on a given date, to be contained in accumulations yet to be discovered. The recoverable portion of undiscovered BIIP is referred to as prospective resources, the remainder is categorized as unrecoverable.
Prospective resources are those quantities of bitumen petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. Prospective resources have both an associated chance of discovery and a chance of development. Prospective resources are further subdivided in accordance with the level of certainty associated with recoverable estimates assuming their discovery and development and may be subclassified based on project maturity. The estimate of prospective resources has not been adjusted for risk based on the chance of discovery or the chance of development.
Exploitable bitumen in-place (EBIP) is the estimated volume of bitumen, before any production has been removed, which is contained in a subsurface stratigraphic interval that meets or exceeds certain reservoir characteristics considered necessary for the application of known recovery technologies. Examples of such reservoir characteristics include continuous net pay, porosity, and mass bitumen content.
This document contains certain forward-looking statements and other information (collectively "forward-looking information") about our current expectations, estimates and projections, made in light of our experience and perception of historical trends. Forward-looking information in this document is identified by words such as "anticipate", "believe", "expect", "plan", "forecast" or "F", "target", "project", "could", "focus", "vision", "goal", "proposed", "scheduled", "outlook", "potential", "may", "objective", "projected", "strategy" or similar expressions and includes suggestions of future outcomes, including statements about our growth strategy and related schedules, projected future value or net asset value, projections contained in our updated 2013 guidance, forecast operating and financial results, planned capital expenditures, expected future production, including the timing, stability or growth thereof, expected future refining capacity, broadening market access, improving cost structures, anticipated finding and development costs, expected reserves, contingent, prospective and bitumen initially-in-place resources estimates, bitumen recovery estimation, potential dividends and dividend growth strategy, anticipated timelines for future regulatory, partner or internal approvals, future impact of regulatory measures, forecasted commodity prices, future use and development of technology, including to reduce our environmental impact and projected increasing shareholder value. Readers are cautioned not to place undue reliance on forward-looking information as our actual results may differ materially from those expressed or implied.
Developing forward-looking information involves reliance on a number of assumptions and consideration of certain risks and uncertainties, some of which are specific to Cenovus and others that apply to the industry generally.
The factors or assumptions on which the forward-looking information is based include: assumptions inherent in our current guidance, available at cenovus.com; our projected capital investment levels, the flexibility of our capital spending plans and the associated source of funding; estimates of quantities of oil, bitumen, natural gas and liquids from properties and other sources not currently classified as proved; our ability to obtain necessary regulatory and partner approvals; the successful and timely implementation of capital projects or stages thereof; our ability to generate sufficient cash flow from operations to meet our current and future obligations; and other risks and uncertainties described from time to time in the filings we make with securities regulatory authorities.
The risk factors and uncertainties that could cause our actual results to differ materially, include: volatility of and assumptions regarding oil and gas prices; the effectiveness of our risk management program, including the impact of derivative financial instruments and the success of our hedging strategies; the accuracy of cost estimates; fluctuations in commodity prices, currency and interest rates; fluctuations in product supply and demand; market competition, including from alternative energy sources; risks inherent in our marketing operations, including credit risks; maintaining desirable ratios of debt to adjusted EBITDA as well as debt to capitalization; our ability to access various sources of debt and equity capital; accuracy of our reserves, resources and future production estimates; our ability to replace and expand oil and gas reserves; our ability to maintain our relationships with our partners and to successfully manage and operate our integrated heavy oil business; reliability of our assets; potential disruption or unexpected technical difficulties in developing new products and manufacturing processes; refining and marketing margins; potential failure of new products to achieve acceptance in the market; unexpected cost increases or technical difficulties in constructing or modifying manufacturing or refining facilities; unexpected difficulties in producing, transporting or refining of crude oil into petroleum and chemical products; risks associated with technology and its application to our business; the timing and the costs of well and pipeline construction; our ability to secure adequate product transportation; changes in the regulatory framework in any of the locations in which we operate, including changes to the regulatory approval process and land-use designations, royalty, tax, environmental, greenhouse gas, carbon and other laws or regulations, or changes to the interpretation of such laws and regulations, as adopted or proposed, the impact thereof and the costs associated with compliance; the expected impact and timing of various accounting pronouncements, rule changes and standards on our business, our financial results and our consolidated financial statements; changes in the general economic, market and business conditions; the political and economic conditions in the countries in which we operate; the occurrence of unexpected events such as war, terrorist threats and the instability resulting therefrom; and risks associated with existing and potential future lawsuits and regulatory actions against us.
Readers are cautioned that the foregoing lists are not exhaustive and are made as at the date hereof. For a full discussion of our material risk factors, see "Risk Factors" in our most recent AIF/Form 40-F, "Risk Management" in our current and annual MD&A and risk factors described in other documents we file from time to time with securities regulatory authorities, all of which are available on SEDAR at sedar.com, EDGAR at www.sec.gov and our website at cenovus.com.
TM denotes a trademark of Cenovus Energy Inc.
Cenovus Energy Inc.
Cenovus Energy Inc. is a Canadian integrated oil company. It is committed to applying fresh, progressive thinking to safely and responsibly unlock energy resources the world needs. Operations include oil sands projects in northern Alberta, which use specialized methods to drill and pump the oil to the surface, and established natural gas and oil production in Alberta and Saskatchewan. The company also has 50% ownership in two U.S. refineries. Cenovus shares trade under the symbol CVE, and are listed on the Toronto and New York stock exchanges. Its enterprise value is approximately $29 billion. For more information, visit cenovus.com.
SOURCE Cenovus Energy Inc.
Image with caption: "A steam assisted gravity drainage well pad at Cenovus's Christina Lake oil sands operation in northern Alberta (CNW Group/Cenovus Energy Inc.)". Image available at: http://photos.newswire.ca/images/download/20130724_C9234_PHOTO_EN_29206.jpg
Image with caption: "Cenovus's Christina Lake oil sands operation in northern Alberta (CNW Group/Cenovus Energy Inc.)". Image available at: http://photos.newswire.ca/images/download/20130724_C9234_PHOTO_EN_29207.jpg
Image with caption: "Construction continues at Cenovus's Christina Lake oil sands operation in northern Alberta (CNW Group/Cenovus Energy Inc.)". Image available at: http://photos.newswire.ca/images/download/20130724_C9234_PHOTO_EN_29205.jpg