Oil sands production increases 35% in 2012
- Proved bitumen reserves at the end of 2012 were more than 1.7 billion barrels (bbls), up 18% from 2011.
- Economic bitumen best estimate contingent resources at year end were 9.6 billion bbls, a 17% increase over 2011.
- Combined oil sands production at Foster Creek and Christina Lake averaged nearly 90,000 barrels per day (bbls/d) net in 2012, up 35% from 2011. Average production at Christina Lake nearly tripled in 2012 to almost 32,000 bbls/d net.
- Christina Lake phase D reached full capacity about six months after first production.
- Cash flow increased to about $3.6 billion in 2012, up 11% from 2011.
- The Board of Directors approved a dividend increase of 10% for the first quarter of 2013 resulting in a quarterly dividend of $0.242 per share.
- Cenovus recorded a $393 million non-cash goodwill impairment in the fourth quarter which resulted in lower 2012 operating earnings and a fourth quarter earnings loss. This impairment related to the company’s Suffield assets, principally natural gas.
“We had another strong year in 2012, achieving the milestones we set for ourselves,” said Brian Ferguson, President & Chief Executive Officer of Cenovus. “We added significant new reserves and resources, increased our oil production, enhanced our net asset value and generated record cash flow. We remain committed to delivering a growing total shareholder return and have again increased our dividend by 10%.”
|Financial & production summary|
|(for the period ended December 31)
($ millions, except per share amounts)
|Per share diluted||0.92||1.12||4.80||4.32|
|Per share diluted||-0.25||0.44||1.14||1.64|
|Per share diluted||-0.16||0.35||1.31||1.95|
|Production (before royalties)|
|Oil sands total (bbls/d)||100,867||74,576||35||89,736||66,533||35|
|Conventional oil3 (bbls/d)||76,779||69,697||10||75,667||67,706||12|
|Total oil (bbls/d)||177,646||144,273||23||165,403||134,239||23|
|Natural gas4 (MMcf/d)||566||660||-14||594||656||-9|
|1Cash flow and operating earnings are non-GAAP measures as defined in the Advisory. See also the Earnings Reconciliation Summary.
2 Includes expenditures on property, plant and equipment and exploration and evaluation assets, excluding acquisitions and divestitures.
3 Includes natural gas liquids (NGLs) production and production from Pelican Lake.
4 Reflects the divestiture of a non-core property in the first quarter of 2012.
CALGARY, Feb. 14, 2013 /PRNewswire/ – Cenovus Energy Inc. (TSX, NYSE: CVE) delivered another year of predictable, reliable performance in 2012. In addition to growing its reserves and resources base, the company recorded solid operational results driven by significant production growth and a strong contribution from its downstream refining business. Those results offset the impact of a reduction in average realized prices for crude oil and natural gas when compared with 2011. Average daily oil production grew 23% in 2012 while total cash flow rose 11% compared with the previous year. The company’s Christina Lake oil sands project led the growth in production, nearly tripling its average daily output from 2011. Christina Lake phase D achieved one of the fastest ramp-ups in the steam-assisted gravity drainage (SAGD) industry, demonstrating full production capacity about six months after first oil production. At Cenovus’s U.S. refineries, strong margins and increased heavy oil processing capacity led to a 29% increase in operating cash flow from refining.
“Our integrated approach continues to support our bottom line,” Ferguson said. “When our heavy oil producing assets are affected by low commodity prices, we make up that value at our refineries. For 2013, we have supply agreements and firm transportation and hedging contracts that, together with our refining capacity, will enable us to offset almost all of our volume exposure to discounted Canadian heavy crude prices.”
Strong additions to reserves and contingent resources
Cenovus continues to strengthen its reserves and resources base. According to the company’s independent reserves and contingent resources evaluation, total proved reserves were nearly 2.2 billion bbls of oil equivalent (BOE) at the end of 2012, up 12% from the previous year.
Proved bitumen reserves increased 18% to more than 1.7 billion bbls, compared with 2011, while proved plus probable bitumen reserves increased approximately 23% to nearly 2.4 billion bbls. Economic bitumen best estimate contingent resources increased 17% from 2011 to 9.6 billion bbls. Proved light and medium oil reserves remained unchanged, while proved heavy oil reserves increased approximately 5% and proved natural gas reserves declined about 21% compared with 2011. Cenovus’s 2012 proved finding and development (F&D) costs, excluding changes in future development costs, were a competitive $9.04/BOE. The three-year average was $6.10/BOE. The 2012 recycle ratio was 3.2 times.
“Cenovus’s stratigraphic well program continues to add significant new resources to our already strong portfolio of oil sands assets,” Ferguson said. “This gives us even greater opportunity to develop new projects, move them through the regulatory approvals process and create decades of solid growth ahead.”
Integrated operations contribute to solid financial performance
Cenovus achieved cash flow of more than $3.6 billion, an 11% increase from the previous year. Operating cash flow from refining benefited from the fact that the Wood Rivery Refinery was able to process higher volumes of heavy oil as a result of the completion of the coker and refinery expansion (CORE) project in late 2011. While lower commodity prices had a negative impact on cash flow from the company’s oil producing assets, the ongoing price volatility provided a double benefit to Cenovus’s refining operations. Compared with 2011, the price of Western Canadian Select (WCS), the benchmark Canadian heavy oil blend, fell against the price of West Texas Intermediate (WTI), the North American benchmark. The wider WTI-WCS differential resulted in lower feedstock costs for the company’s refineries. At the same time, there was a favourable appreciation in the price of Brent crude, the global benchmark, against the price of WTI, which allowed Cenovus’s refineries to capture higher prices for their finished products. Those lower feedstock costs and higher finished product prices led to stronger refining margins, which also contributed to the 29% improvement in operating cash flow from refining when compared with 2011.
Goodwill impairment impacts earnings
A one-time non-cash goodwill write down of $393 million in the company’s conventional operations contributed to lower full year operating earnings in 2012 and to an operating loss of $189 million in the fourth quarter. For the full year, the company had operating earnings of $866 million, down 30% from 2011. The full year decrease and quarterly loss were primarily due to the goodwill impairment related to the company’s Suffield conventional assets, located on the Canadian Forces Base in southeast Alberta. Estimated future cash flows for the assets have declined, largely as the result of a drop in forecast natural gas prices over the long term. As a result, the carrying amount of goodwill related to the property has exceeded its fair value and was written off. The goodwill in question arose from the 2002 merger between Alberta Energy Company and PanCanadian Energy Corporation.
Continued focus on operating costs
Managing operating costs is an important ongoing focus for Cenovus. Operating costs per BOE at the company’s oil sands and natural gas operations were largely in line with Cenovus’s 2012 forecasts, while operating costs at its Pelican Lake heavy oil operations were slightly above guidance. Cenovus anticipates more pressure on operating costs in 2013 as a result of expected higher prices for natural gas and electricity needed to fuel the company’s operations. Operating costs at Pelican Lake are expected to rise again this year with the expansion of the polymer flood as temporarily reduced reservoir pressure required to safely complete infill drilling limits 2013 production growth. Stronger production growth is expected in late 2013 and into 2014, which should help reduce per barrel operating costs.
“Cenovus is working diligently to maintain our reputation as a low cost producer,” said John Brannan, Cenovus Executive Vice-President and Chief Operating Officer. “We will continue to focus on reducing our costs per barrel and increasing efficiency across all of our operations.”
Growing net asset value
Cenovus measures its success in a number of ways with a key metric being growth in net asset value (NAV). The company remains on track to reach its goal of doubling its December 2009 baseline illustrative NAV of $28 by the end of 2015. Despite weaker oil and gas prices, Cenovus’s operational and financial performance and consistent production growth allowed the company to increase its NAV to approximately $40 in 2012, a 43% increase from the end of 2009.
Capital investment supports oil production growth
Cenovus is focused on creating value through its oil growth strategy, which remains on track with plans to achieve 500,000 bbls/d of net production by the end of 2021. As part of that strategy, the company invested almost $3.4 billion in its operations in 2012, a planned 24% increase from the previous year. About half of that capital spending supported development of the company’s oil sands assets. Nearly $1.4 billion went towards expansions at Foster Creek and Christina Lake and the development of Narrows Lake. Capital spending on emerging oil sands projects, including Grand Rapids and Telephone Lake, was approximately $316 million. Capital investment in 2012 included the drilling of 473 gross stratigraphic test wells. The results of these stratigraphic test wells will be used to support the expansion and development of the company’s oil sands projects.
Cenovus spent nearly $1.3 billion on its conventional oil assets in 2012. That includes more than $500 million at Pelican Lake to increase infill drilling for the polymer flood programs and facility expansion. The company invested nearly $850 million in its other conventional oil assets, including the continued development of its emerging tight oil plays.
Cenovus’s capital program includes investing in innovative technologies aimed at increasing production, while lowering operating costs per BOE and decreasing environmental impacts. In 2012, this led to continued investment in projects such as Cenovus’s enhanced start-up and patented Wedge WellTM technologies as well as the development of its new SkyStratTM drilling rig, a scaled-down version of a traditional stratigraphic drilling rig that can be transported to remote sites by helicopter.
Acquisitions and divestitures
While Cenovus does not have a need for major acquisitions or divestitures, the company is always looking for tuck-in opportunities that would enhance its current portfolio. Cenovus places value on maintaining a divestiture program as a form of capital discipline and will continue to assess the benefits of selling certain non-core assets. Purchases in 2012 were primarily tuck-in oil sands acquisitions adjacent to Cenovus’s Telephone Lake and Narrows Lake properties as well as tuck-in acquisitions of producing conventional crude oil properties in Alberta and Saskatchewan, adjacent to existing production. Divestitures in 2012 were mainly related to the sale of a non-core natural gas property in northern Alberta in the first quarter.
Following a portfolio review, Cenovus decided to put its Lower Shaunavon property and the operated part of its Bakken property in Saskatchewan up for sale. The company believes these are quality assets. However, Cenovus is unable to scale the projects up to a size that would be material to its portfolio due to competitive limitations on increasing its land base in the area. The sale process is expected to launch later this quarter.
Addressing market access challenges
Constraints on market access are having a negative impact on realized pricing for Canadian oil producers. Congestion on pipelines linking oil fields in Western Canada to U.S. markets contributed to a widening of the average discount (also known as the light/heavy differential) between WTI and WCS in 2012. The average WTI-WCS differential was US$30.37/bbl in December 2012 compared to US$11.72/bbl in December of 2011.
“Widening oil price differentials are becoming an increasingly important issue, not just for producers, but for all Canadians,” Ferguson said. “With the third largest oil reserves in the world, we have a tremendous opportunity to capitalize on the growing global demand for energy. However, without pipeline access to new markets we will continue to leave billions of dollars in lost revenues on the table every year, to the detriment of the entire Canadian economy.”
Cenovus takes a portfolio approach to market access and continues to proactively assess various options to transport its oil. The predictability of the company’s oil production growth gives it the confidence to support all currently proposed pipeline projects that would open up new markets. Early in 2012, Cenovus started shipping 11,500 bbls/d of oil under a firm service agreement on the Trans Mountain pipeline that runs from Edmonton to the West Coast. The firm service agreement is beneficial as it gives Cenovus the ability to get its oil to tidewater where it commands higher prices and it allows the company to negotiate longer term arrangements for markets in California and Asia. In addition to pipelines, Cenovus is now shipping about 6,000 bbls/d of conventional crude volumes to market by rail and is looking to increase that to about 10,000 bbls/d in 2013.
|Oil sands total||90||101||96||80||82||67||75||66||58||67||59|
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 future growth. The two currently producing operations, Foster Creek and Christina Lake, use SAGD to drill and pump the oil to the surface. 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 increased 35% to almost 90,000 bbls/d net in 2012 compared with the previous year. Fourth quarter production also rose 35% in 2012 to nearly 101,000 bbls/d net, compared to the same period in 2011.
- Christina Lake production almost tripled to an average of about 32,000 bbls/d net in 2012, compared with the previous year. Christina Lake produced an average of approximately 42,000 bbls/d net in the fourth quarter, more than double the average production rate in the same period a year earlier.
- The substantial increase in production at Christina Lake was due to the ramp-up of two new expansion phases. Phase C reached full capacity in the first quarter of 2012. Phase D began producing in July 2012, approximately three months ahead of schedule. It demonstrated full production capacity in January 2013, approximately six months after first production.
- Foster Creek produced an average of nearly 58,000 bbls/d net in 2012, about 5% more than the 2011 average due to improved well performance and plant optimization. Fourth quarter production at Foster Creek averaged about 59,000 bbls/d net to Cenovus.
- Both Christina Lake and Foster Creek achieved new single-day production highs of almost 47,000 and 65,500 bbls/d net respectively in 2012.
- About 12% of current production at Foster Creek comes from 56 wells using Cenovus’s Wedge WellTM technology. These single horizontal wells, drilled between existing SAGD well pairs, reach oil that would otherwise be unrecoverable. The company’s Wedge WellTM technology has the potential to increase overall recovery from the reservoir by as much as 10%, while reducing the steam to oil ratio (SOR). Cenovus plans to drill and complete an additional eight wells at Foster Creek using Wedge WellTM technology in 2013.
- Christina Lake is also benefiting from the use of Wedge WellTM technology with six of these wells now producing and another four drilled wells expected to begin producing in the first half of 2013.
- The overall Christina Lake phase E project is about 65% complete, while the central plant is nearly 87% complete. First production is anticipated in the third quarter of 2013. Piling and foundation work, engineering and major equipment fabrication continue for phase F and design engineering work is under way for phase G.
- At Foster Creek, overall progress of the combined F, G and H expansion is approximately 40% complete, while the phase F central plant is 67% complete.
First production at phase F is expected in the third quarter of 2014. Spending on piling work, steel fabrication, module assembly and major equipment procurement is under way at phase G and design engineering continues at phase H.
- Combined capital investment at Foster Creek and Christina Lake was more than $1.3 billion in 2012, a 46% increase compared with 2011. This includes spending on the expansion phases, stratigraphic test wells and maintenance capital.
- Operating costs at Foster Creek averaged $11.99/bbl in 2012, about a 6% increase from $11.34/bbl the previous year. Non-fuel operating costs at Foster Creek were $9.96/bbl in 2012 compared with $9.14/bbl in 2011, a 9% increase. The increases were mostly due to added costs from hiring additional staff, as well as higher levels of waste and fluid handling, trucking and workover activity.
- Operating costs at Christina Lake were $12.95/bbl in 2012, a 36% decrease from $20.20/bbl the previous year. Non-fuel operating costs at Christina Lake were $10.53/bbl in 2012 compared with $17.02/bbl in 2011, a 38% decrease. The decreases were primarily due to the significant increase in production at Christina Lake in 2012 and lower SORs.
Steam to oil ratios
- SOR measures the number of barrels of steam needed for every barrel of oil produced, with Cenovus having one of the lowest ratios in the industry. A lower SOR means less natural gas is used to generate the steam, which results in reduced capital and operating costs, fewer emissions and lower water usage.
- Cenovus continued to achieve low SORs in 2012 with ratios of approximately 2.2 at Foster Creek, unchanged from 2011, and 1.9 at Christina Lake, down from 2.3 in 2011. The combined SOR for Cenovus’s oil sands operations was about 2.1 in 2012.
Christina Dilbit Blend
- Christina Dilbit Blend (CDB) is a heavy bitumen blend stream launched in the fourth quarter of 2011. Last year, 74% of production from Christina Lake was sold as CDB.
- While CDB is priced at a discount to WCS, it is gaining acceptance with a wider base of refiners. Cenovus continued to add CDB into its contracts with downstream customers and saw the price differential narrow last year.
- In the fourth quarter of 2012 the CDB discount to WCS was in the US$4.50 to US$7.50/bbl range. Over the longer term, Cenovus expects a CDB to WCS discount in the US$3.00/bbl to US$5.00/bbl range.
- The Wood River Refinery ran approximately 84,000 bbls/d gross of CDB or equivalent crudes during the fourth quarter of 2012. These crudes represented 55% of total heavy crude volumes in the fourth quarter, up from 40% in the third quarter of 2012.
- Cenovus’s next major oil sands development, a three-phase project at Narrows Lake, received regulatory approval in 2012 as well as partner approval for the first phase. As a result of the approvals, Cenovus booked more than 200 million bbls of proved reserves last year. The project is 50%-owned with ConocoPhillips and Cenovus is the operator. Narrows Lake is expected to be the industry’s first project to demonstrate solvent aided process (SAP), with butane, on a commercial scale. Site preparation began in the third quarter of 2012 and phase A construction is scheduled to start in the third quarter of 2013. The first phase of the project is anticipated to have production capacity of 45,000 bbls/d, with first oil expected in 2017. Cenovus spent $44 million on Narrows Lake in 2012.
- At the company’s 100%-owned Grand Rapids property, located within the Greater Pelican Region, a SAGD pilot project is under way. The project is progressing smoothly with steaming of a second well pair, which is expected to begin producing this month. A joint regulatory application and Environmental Impact Assessment (EIA) for a 180,000 bbl/d commercial project has been submitted and is proceeding on schedule. Cenovus anticipates regulatory approval for Grand Rapids by the end of 2013.
- Cenovus’s 100%-owned Telephone Lake property is located within the Borealis Region of northern Alberta. A revised joint application and EIA submitted in December 2011 is advancing through the regulatory process and approval is anticipated early in 2014. Cenovus is continuing with 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. The dewatering operations have been running smoothly and early results are encouraging. While dewatering is not essential to the development of Telephone Lake, Cenovus believes it could improve the project’s SORs by up to 30%, enhancing its economics and reducing its impact on the environment.
Cenovus produces heavy oil from the Wabiskaw formation at its wholly-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 nearly 23,000 bbls/d in 2012, a 10% increase in production compared with 2011 due to the expansion of infill drilling and polymer injection.
- Cenovus plans to build on its success at Pelican Lake by drilling about 1,000 additional production and injection wells in the next five to seven years to expand the polymer flood.
- Operating costs at Pelican Lake averaged $17.08/bbl in 2012, a 15% increase from $14.86/bbl in 2011. Per barrel operating costs have been impacted by lower than expected production growth due to reduced operating pressures related to temporary well shut-ins required to complete infill drilling between existing wells at Pelican Lake.
- Operating costs at Pelican Lake were also higher due to additional workover activities, increased staffing levels and polymer consumption as a result of the expansion of the polymer flood.
- Stronger production growth is expected in late 2013 and into 2014, which should help reduce per barrel operating costs.
Other conventional oil
In addition to Pelican Lake, Cenovus has extensive oil operations in Alberta and Saskatchewan. These include conventional and tight oil assets in Alberta and developing tight oil assets in southern Saskatchewan, as well as the established Weyburn operation that uses carbon dioxide injection to enhance oil recovery.
- Alberta oil production averaged more than 30,000 bbls/d in 2012, up 10% from the previous year, primarily due to successful tight oil drilling programs and fewer weather and access issues than in 2011.
- Production at the Weyburn operation was unchanged compared to the previous year at more than 16,000 bbls/d net.
- Combined crude oil production from the Bakken and Lower Shaunavon operations averaged nearly 6,500 bbls/d, a 79% increase from the previous year due to increased drilling. Given the limited expansion opportunities that Cenovus has in these non-core properties in comparison to its other holdings, the company has determined it will commence a public process later this quarter to dispose of its interests in the Lower Shaunavon property and the operated part of its Bakken property.
- Operating costs for Cenovus’s conventional oil and liquids operations, excluding Pelican Lake, increased 9% to $15.12/bbl in 2012 compared with 2011. This was mainly due to a combination of higher levels of waste and fluid handling, trucking, workover activities, repairs and maintenance in connection with single well batteries and higher workforce costs.
1 Reflects the divestiture of a non-core property in the first quarter of 2012.
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 2012 was approximately 594 million cubic feet per day (MMcf/d), down 9% from the previous year, as expected. The production drop was driven primarily by expected natural declines and the divestiture of a non-core property early in the first quarter of 2012. Excluding the impact of the divestiture, natural gas production would have been 6% lower than in 2011.
- Cenovus’s average realized sales price for natural gas, including hedges, was $3.56 per thousand cubic feet (Mcf) in 2012 compared with $4.52 per Mcf in 2011.
- The company invested $51 million in its natural gas properties in 2012. Operating cash flow from natural gas in excess of capital investment was $462 million.
- Cenovus anticipates managing an annual decline rate of 10% to 15% for its natural gas production, targeting a long-term production level of between 400 MMcf/d and 500 MMcf/d to match Cenovus’s future anticipated internal consumption at its oil sands and refining facilities.
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 against reduced crude oil prices by providing lower feedstock prices to Cenovus’s Wood River Refinery in Illinois and Borger Refinery in Texas, which are jointly owned with the operator, Phillips 66.
- Operating cash flow from refining increased $282 million to nearly $1.3 billion, 29% more than in 2011. This was due to higher benchmark crack spreads as well as the benefits from the completion of the CORE project at the Wood River Refinery in late 2011, including lower feedstock costs and improved refinery output.
- Operating cash flow for 2012 would have been higher if not for planned fourth quarter major turnarounds at Wood River and Borger that continued longer than expected.
- Cenovus’s 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 2012 refining operating cash flow would have been $111 million higher than reported under FIFO, compared with $95 million lower in 2011.
- For the full year, the company’s refining business generated $1.14 billion of operating cash flow in excess of the $118 million of capital invested in it.
- Cenovus expects strong first quarter 2013 operating cash flow from its refineries in the range of $300 million to $400 million.
- Both refineries combined processed an average of 412,000 bbls/d of crude oil in 2012, resulting in 433,000 bbls/d of refined product output, which was 3% higher than in 2011.
- Total combined heavy crude oil processing capacity at the company’s refineries increased to between 235,000 bbls/d and 255,000 bbls/d with the completion of the CORE project at the Wood River Refinery in late 2011. The CORE project has enhanced the company’s ability to further integrate its growing bitumen production.
- The amount of Canadian heavy oil processed in 2012 increased 57% to 198,000 bbls/d.
- Refinery crude utilization rates averaged 91% in 2012.
Reserves and Contingent Resources
All of Cenovus’s reserves and resources are evaluated each year by independent qualified reserves evaluators.
- At year-end 2012, Cenovus had proved reserves of nearly 2.2 billion BOE, an increase of 12% compared with 2011.
- Proved bitumen reserves increased 18% in 2012 compared with 2011, to more than 1.7 billion bbls, while proved plus probable bitumen reserves grew nearly 23% to approximately 2.4 billion bbls. This increase was primarily due to regulatory and partner approval of the company’s Narrows Lake oil sands project and substantial reserves additions at Foster Creek and Christina Lake. The reserves additions at Christina Lake were due to increased well density and improved SOR performance. At Foster Creek the reserves additions were due to more efficient drainage of oil in the steam chambers.
- Economic bitumen best estimate contingent resources increased to 9.6 billion bbls, up approximately 17% from 2011. This increase is a result of Cenovus’s extensive stratigraphic test well drilling program converting prospective resources to contingent resources. In addition, the independent evaluators recognized commercial SAGD feasibility in the Wabiskaw formation within the Greater Foster Creek Region and contingent resources on recently acquired oil sands assets in Alberta.
- Proved light and medium oil reserves remained unchanged, while proved heavy oil reserves increased approximately 5% due to the ongoing expansion of the waterflood and polymer injection program at Pelican Lake. Natural gas reserves declined about 21% compared with 2011 as Cenovus continued to redirect capital to its oil assets. As expected, this has resulted in natural gas production outpacing reserves additions. Lower natural gas prices and the divestiture of a non-core property early in 2012 also contributed to lower natural gas reserves.
- Cenovus’s 2012 proved finding and development (F&D) costs, excluding changes in future development costs, were a competitive $9.04/BOE, up from $5.96/BOE in 2011 as capital spending increased and reserves additions decreased somewhat compared with 2011. The three-year average F&D costs were $6.10/BOE, excluding changes in future development costs.
- Cenovus achieved production replacement of nearly 350% in 2012.
- The overall proved reserves life index is approximately 23 years, a 5% increase compared with 2011. The magnitude of the company’s bitumen assets is significant with a bitumen proved reserves life index of 52 years, down 13% due to the company’s rapidly increasing bitumen production. The conventional oil and NGLs proved reserves life is 12 years.
|Proved reserves reconciliation|
|Light & Medium
Oil & NGLs
|Natural Gas &
|Start of 2012||1,455||175||115||1,203|
|Extensions & improved recovery||265||17||13||29|
|End of 2012||1,717||184||115||955|
|Total proved plus probable||2,393||289||171||1,293|
1Production used for the reserves reconciliation differs from reported production as it includes Cenovus gas volumes provided to the FCCL Partnership for steam generation, but does not include royalty interest production. See the Advisory – Oil and Gas Information for more information about royalty interest production.
|Proved reserves costs1|
|(Before royalties)||2012||2011||3 Year|
|Capital Investment ($ millions)|
|Finding and Development||3,013||2,175||6,562|
|Finding, Development and Acquisitions||3,127||2,244||6,793|
|Proved Reserves Additions2 (MMBOE)|
|Finding and Development||333||366||1,075|
|Finding, Development and Acquisitions||334||366||1,076|
|Proved Reserves Costs2 ($/BOE)|
|Finding and Development3||9.04||5.96||6.10|
|Finding, Development and Acquisitions4||9.36||6.14||6.31|
1 Finding and Development Cost calculations presented in the table do not include changes in future development costs. See the Advisory – Finding and Development Costs – for a full description of the methods used to calculate Finding and Development Costs which include the change in future development costs.
2 Reserves Additions for Finding and Development are calculated by summing technical revisions, extensions and improved recovery, discoveries and economic factors. Reserves Additions for Finding, Development and Acquisitions are calculated by summing Reserves Additions for Finding and Development and additions from acquisitions. See the Advisory – Oil and Gas Information.
3 Finding and Development Costs without changes in future development costs is equal to Finding and Development Capital Investment divided by Finding and Development Reserves Additions.
4 Finding, Development and Acquisitions without changes in future development costs is equal to Finding, Development and Acquisitions Capital Investment divided by Finding, Development and Acquisitions Reserves Additions.
|Bitumen contingent resources|
|Economic Contingent Resources1||Bitumen (billion bbls)|
1 For the definition of contingent resources, economic contingent resources and low, best and high estimate and a description of the contingencies associated with Cenovus’s economic contingent resources, please see the Advisory – Oil and Gas Information. There is no certainty that it will be commercially viable to produce any portion of the contingent resources.
The Cenovus Board of Directors has approved a 10% increase in the first quarter 2013 dividend to $0.242 per share, payable on March 28, 2013 to common shareholders of record as of March 15, 2013. Based on the February 13, 2013 closing share price on the Toronto Stock Exchange of $32.60, 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 strategy allows the company to financially hedge up to 75% of this year’s expected natural gas production, net of internal fuel use, and up to 50% and 25%, respectively, in the two following years. The company has Board approval for fixed price hedges on as much as 50% of net liquids production this year and 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 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 December 31, 2012 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
- 166 MMcf/d or approximately 32% of expected natural gas production hedged for 2013 at an average NYMEX price of US$4.64/Mcf, plus internal usage of approximately 135 MMcf/d of natural gas
- no fixed price commodity hedges in place beyond 2013
- approximately 49,200 bbls/d of heavy crude exposure hedged for 2013 at an average WCS differential to WTI of US$20.74/bbl
- approximately 9,400 bbls/d of heavy crude exposure hedged for 2014 at an average WCS differential to WTI of US$20.13/bbl.
- Cash flow in 2012 was more than $3.6 billion, or $4.80 per share diluted, compared with nearly $3.3 billion, or $4.32 per share diluted, a year earlier.
- Operating earnings in 2012 were $866 million, or $1.14 per share diluted, compared with $1.2 billion, or $1.64 per share diluted, for the same period last year.
- Earnings in 2012 reflected a non-cash goodwill impairment charge of approximately $0.52 per share related to the company’s Suffield assets in southeast Alberta. This was primarily due to estimated declines in future natural gas prices.
- Cenovus had a realized after-tax hedging gain of $250 million in 2012. Cenovus received an average realized price, including hedging, of $67.16/bbl for its oil in 2012, compared with $69.99/bbl during 2011. The average realized price, including hedging, for natural gas in 2012 was $3.56/Mcf, compared with $4.52/Mcf in 2011.
- Cenovus recorded income tax expense of $783 million, giving the company an effective tax rate of 44%, a substantial increase from the 2011 effective rate of 33%. The increase is primarily due to the goodwill impairment, which is not deductible, and to a one-time tax charge related to a U.S. withholding tax of $68 million.
- Cenovus’s net earnings for the year were $993 million compared with approximately $1.5 billion in 2011. Net earnings were negatively impacted by lower commodity prices, the non-cash goodwill impairment, increased depreciation, depletion and amortization (DD&A) costs and lower unrealized after-tax risk management gains, partly offset by higher unrealized foreign exchange gains. The increased DD&A rates were due to higher future development costs associated with total proved reserves.
- Capital investment during the year was nearly $3.4 billion, as planned. That was a 24% increase from $2.7 billion in 2011 as the company continued to advance development of its oil opportunities.
- General and administrative (G&A) expenses were $352 million in 2012, which was less than the company’s corporate guidance for the year. G&A expenses were 19% higher in 2012, compared with 2011, primarily due to increases in staffing, salaries and benefits, long-term incentive expense and office costs related to the continued growth of the company.
- Over the long term, Cenovus continues to target a debt to capitalization ratio of between 30% and 40% and a debt to adjusted EBITDA ratio of between 1.0 and 2.0 times. At December 31, 2012, the company’s debt to capitalization ratio was 32% and debt to adjusted EBITDA, on a trailing 12-month basis, was 1.1 times.
|Earnings reconciliation summary|
|(for the period ended December 31)
($ millions, except per share amounts)
Add back losses & deduct gains:
Per share diluted
|Unrealized mark-to-market hedging gain/loss, after-tax||87||-180||43||134|
|Non-operating foreign exchange gain/loss, after-tax||-16||25||84||14|
|Divestiture gain/loss, after-tax||–||89||–||91|
|Per share diluted||-0.25||0.44||1.14||1.64|
|Oil sands project schedule|
|Project phase||Regulatory status||First production
|Foster Creek1 A – E||120,000|
|Christina Lake1 A – D||98,000|
|Grand Rapids||Submitted Q4-2011||2017F||180,000|
|Telephone Lake3||Submitted Q4-2011||TBD||90,000|
1 Properties 50% owned by ConocoPhillips. Certain phases may be subject to partner approval.
2 Includes 5,000 bbls/d gross expected to be submitted to the regulator in 2013.
3 Projected total capacity of more than 300,000 bbls/d.
Conference call today
9:00 a.m. Mountain Time (11:00 a.m. Eastern Time)
Cenovus will host a conference call today, February 14, 2013, starting at 9:00 a.m. MT (11:00 a.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 12:00 p.m. MT on February 14, 2013, until midnight February 21, 2013, by dialing 855-859-2056 or 416-849-0833 and entering conference passcode 87391969. A live audio webcast of the conference call will also be available via www.cenovus.com. 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 adjusted earnings before interest income, finance costs, income taxes, depreciation, depletion and amortization, exploration expense, 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 www.cenovus.com.
OIL AND GAS INFORMATION
The estimates of reserves and resources data and related information were prepared effective December 31, 2012 by independent qualified reserves evaluators (“IQREs”) and are presented using McDaniel & Associates Consultants Ltd. (“McDaniel”) January 1, 2013 price forecast. We hold significant fee title rights which generate production for our account from third parties leasing those lands. The before royalties volumes presented in the reserves reconciliation (i) do not include reserves associated with this production and (ii) the production differs from other publicly reported production as it includes Cenovus gas volumes provided to the FCCL Partnership for steam generation, but does not include royalty interest production.
Resources Terminology The estimates of bitumen contingent resources were prepared by McDaniel, an IQRE, based on the Canadian Oil and Gas Evaluation Handbook and in compliance with the requirements of National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities.
- 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 Canadian Oil and Gas Evaluation Handbook 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 four regions is included in our Annual Information Form.
- 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 percent probability that the actual quantities recovered will equal or exceed the estimate.
Barrels of Oil Equivalent Certain natural gas volumes have been converted to barrels of oil equivalent (BOE) on the basis of six Mcf to one bbl. BOE may be misleading, particularly if used in isolation. A conversion ratio of one bbl to six Mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent value equivalency at the wellhead.
Finding and Development Costs Finding and development costs disclosed in this news release and used for calculating our recycle ratio do not include the change in estimated future development costs. Cenovus uses finding and development costs without changes in estimated future development costs as an indicator of relative performance to be consistent with the methodology accepted within the oil and gas industry.
Finding and development costs for proved reserves, excluding the effects of acquisitions and dispositions but including the change in estimated future development costs were $25.48/BOE for the year ended December 31, 2012, $13.99/BOE for the year ended December 31, 2011 and averaged $16.35/BOE for the three years ended December 31, 2012. Finding and development costs for proved plus probable reserves, excluding the effects of acquisitions and dispositions but including the change in estimated future development costs were $20.04/BOE for the year ended December 31, 2012, $10.69/BOE for the year ended December 31, 2011 and averaged $14.27/BOE for the three years ended December 31, 2012. These finding and development costs were calculated by dividing the sum of exploration costs, development costs and changes in future development costs in the particular period by the reserves additions (the sum of extensions and improved recovery, discoveries, technical revisions and economic factors) in that period. The aggregate of the exploration and development costs incurred in a particular period and the change during that period in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that period.
Net Asset Value With respect to the particular year being valued, the net asset value (NAV) disclosed herein is based on the number of issued and outstanding Cenovus shares as at December 31 as reported in our Annual Information Form and Form 40-F, plus the total dilutive effect of Cenovus shares related to stock option programs or other contracts as disclosed in the “Per Share Amounts” note to our annual Consolidated Financial Statements. We calculate NAV as an average of (i) our average trading price for the month of December, (ii) an average of net asset values published by external analysts in December following the announcement of our budget forecast, and (iii) an average of two net asset values based primarily on discounted cash flows of independently evaluated reserves, resources and refining data and using internal corporate costs, with one based on constant prices and costs and one based on forecast prices and costs.
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” 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, forecast operating and financial results, planned capital expenditures, expected future production, including the timing, stability or growth thereof, expected future refining capacity, anticipated finding and development costs, expected reserves and contingent and prospective resources estimates, 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 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 www.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 relationship 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 Annual Information Form/Form 40-F, “Risk Management” in our current 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 www.sedar.com, EDGAR at www.sec.gov and our website at www.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 $30 billion. For more information, visit www.cenovus.com.