Proved bitumen reserves up 8%
- Combined oil sands production at Foster Creek and Christina Lake averaged almost 103,000 barrels per day (bbls/d) net in 2013, up 14% from 2012.
- Production at Christina Lake increased 55% to more than 49,000 bbls/d net in 2013. Christina Lake phase D reached full capacity in 2013, about six months after first production. Phase E is expected to achieve full capacity in the first quarter of 2014.
- Foster Creek production averaged more than 53,000 bbls/d net in 2013, down 8% from 2012.
- Proved bitumen reserves at the end of 2013 were more than 1.8 billion barrels (bbls), up 8% from 2012.
- Refining operations achieved a 97% utilization rate and increased processing of heavy crude oil by 12% to 222,000 bbls/d.
- Cash flow was $3.6 billion in 2013, comparable with the previous year.
- The Board of Directors approved a dividend increase of 10% for the first quarter of 2014, resulting in a quarterly dividend of $0.2662 per share.
“We had another year of solid reserves and production growth as well as strong performance from our refining business,” said Brian Ferguson, Cenovus President & Chief Executive Officer. “We continue to effectively execute our long-term business plan. The strength of our operations and balance sheet allows us to concentrate on growing total shareholder return, including our commitment to a dividend growth strategy.”
|Production & financial summary|
|(for the period ended December 31)
Production (before royalties)
|Oil sands total (bbls/d)||113,890||100,867||13||102,500||89,736||14|
|Conventional oil1 (bbls/d)||74,853||76,779||-3||76,775||75,667||1|
|Total oil (bbls/d)||188,743||177,646||6||179,275||165,403||8|
|Natural gas (MMcf/d)||514||566||-9||529||594||-11|
($ millions, except per share amounts)
|Per share diluted||1.10||0.92||4.76||4.80|
|Per share diluted||0.28||-0.25||1.55||1.14|
|Per share diluted||-0.08||-0.15||0.87||1.31|
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, Feb. 13, 2014 /CNW/ – Cenovus Energy Inc. (TSX: CVE) (NYSE: CVE) continued to deliver on its commitments in 2013, increasing oil sands production 14% and maintaining a strong balance sheet as it expanded its oil operations. In addition, the company’s refining operations again performed well, generating significant operating cash flow to support Cenovus’s long-term business plan. Cenovus also achieved solid growth in its oil reserves.
The increase in production from the company’s oil sands operations in 2013 was largely driven by its Christina Lake project. Christina Lake volumes increased 55% as phase D reached full production capacity and phase E, the company’s 10th oil sands phase, began production in July. The company expects to achieve full production capacity from this phase in the first quarter of 2014. The successful addition of these phases further demonstrates the importance of the company’s manufacturing approach to developing its oil sands assets. Cenovus expects Christina Lake to achieve production of between 124,000 bbls/d and 136,000 bbls/d gross this year. This represents production volumes of 95% of design capacity, which the company is targeting for the current phases.
“We have an excellent track record of delivering oil sands projects on schedule and at industry-leading capital efficiencies,” Ferguson said. “We plan to continue our disciplined approach to developing our oil sands assets.”
Higher production at Christina Lake more than offset an 8% year-over-year decline in volumes at Foster Creek. The decrease at Foster Creek was partially the result of catching up on well maintenance that was deferred in 2012. In addition, the evolution to common steam chambers in the initial project areas at Foster Creek prompted Cenovus to evaluate its long-term reservoir management plan and apply new techniques to optimize production performance. This includes determining the optimal reservoir pressure, drilling more wells using Wedge Well™ technology and moving more wells to the final stage of production, which is called the blowdown stage. Blowdown enables the company to move steam from older well pads that no longer need it for continued production to new areas of the reservoir. For the fourth quarter of 2013, Foster Creek output was in line with company expectations.
Total conventional oil production, including the heavy oil operation at Pelican Lake, averaged almost 77,000 bbls/d for the year, up 1%. Pelican Lake production increased 8%, from the previous year, due to infill drilling in 2012 and 2013. The company also achieved increased production volumes from its horizontal well program in southern Alberta. These increases were offset by the July sale of the Shaunavon tight oil assets in Saskatchewan, which resulted in a production decline of approximately 2,300 bbls/d on an annual basis compared with 2012.
Integrated operations provide financial stability
The company generated cash flow of $3.6 billion in 2013, in line with the previous year. Cenovus’s integrated strategy, which combines upstream oil production with downstream refining capacity, provides protection against volatile light-heavy oil differentials. Integration acts as a natural economic hedge against discounted heavy crude prices by providing lower feedstock costs to the company’s refineries.
The company’s two jointly owned refineries performed well in 2013 and generated operating cash flow in excess of capital invested of approximately $1 billion, net to Cenovus. Operating cash flow was negatively affected by declines in market crack spreads and higher costs for renewable identification numbers (RINs). Market crack spreads were more than 20% lower for the year compared with 2012. The cost of RINs increased to $153 million, net to Cenovus in 2013, an almost five-fold increase from the previous year. Refineries that do not blend renewable fuels such as ethanol into their gasoline and diesel are required to purchase RINs in the open market to comply with the Renewable Fuel Standards set by the U.S. Environmental Protection Agency (EPA). The EPA has proposed reducing biofuel blending quotas for 2014, which has led to a significant drop in the cost of RINs recently.
The impact of lower market crack spreads and higher RIN costs was substantially offset by strong operational performance from Cenovus’s refining assets in 2013. The company’s refineries processed 222,000 bbls/d of heavy oil, up 12% from 2012, the highest level since Cenovus became joint owner of the Wood River and Borger facilities in 2007. The ability to process higher volumes of less expensive heavy oil resulted in an improved feedstock cost advantage. Total refined product output increased 7% to average 463,000 bbls/d in 2013.
Continued additions to reserves and contingent resources
Cenovus continued to strengthen its reserves and resources base. The company’s proved bitumen reserves increased 8% to more than 1.8 billion bbls at the end of 2013, according to its independent reserves and contingent resources evaluation. Total proved reserves reached almost 2.3 billion barrels of oil equivalent (BOE) in 2013, up 5% from the previous year, resulting in a 214% production replacement ratio.
Proved plus probable bitumen reserves increased 6% to more than 2.5 billion bbls, while the company’s total proved plus probable reserves increased 4% to 3.2 billion BOE. Economic bitumen best estimate contingent resources increased 2% from 2012 to 9.8 billion bbls. Cenovus’s 2013 proved finding and development (F&D) costs, excluding changes in future development costs, were $14.51/BOE compared with $9.04/BOE in 2012. The three-year average was $9.05/BOE. The 2013 recycle ratio was 2.2 times.
Capital investment focused on existing projects
The company’s long-term business plan of creating shareholder value by increasing its planned capacity to approximately 525,000 bbls/d of net oil production within the next decade remains on track. In support of that, Cenovus invested approximately $3.3 billion to grow its business in 2013. Almost $1.5 billion was invested last year in Cenovus’s two operating oil sands projects, Christina Lake and Foster Creek. Cenovus began construction of the phase A plant at its Narrows Lake project late in 2013, investing $152 million for the year.
Total capital investment in 2013 declined by 3% from 2012 primarily due to lower spending on Cenovus’s conventional business after the sale of its Shaunavon tight oil assets and a slowing of investment at Pelican Lake.
Cenovus’s successful delivery of oil sands projects to date is largely attributable to its manufacturing approach to development. This includes constructing projects in templated and repeatable phases to help manage cost, quality and scheduling. As well, the company plans to continue to invest in its future by assessing its resource base and drilling more than 300 gross stratigraphic test wells in each of the next five years. This helps Cenovus to better define existing reservoirs and lays the groundwork for potential future reserves additions and project expansions.
Cenovus expects to invest between $2.8 billion and $3.1 billion in 2014, a 10% decrease from 2013. The company has built a large inventory of regulatory approved projects and is now allocating more of its capital to develop this established inventory. This includes projects now under construction at Foster Creek, Christina Lake and Narrows Lake, as well as Grand Rapids and Telephone Lake, which are anticipated to receive regulatory approval in 2014.
Foster Creek expansion update
The company has adjusted its timeline for achieving total expected production capacity at Foster Creek phases F, G and H. The total capacity numbers include the initial design capacity plus additional barrels anticipated to result from optimization. That optimization work focuses on the entire facility rather than individual phases. Optimization of the steam to oil ratio (SOR) can be achieved through innovations such as the use of Cenovus’s Wedge Well™ technology, optimizing reservoir pressures and effectively moving well pads to blowdown as they mature. Plant optimization can be accomplished through debottlenecking and facility upgrades such as improving the fluid handling capability at the plant.
As a result of the steam chamber changes mentioned earlier, the company intends to delay the optimization until it’s had more time to assess its new operating procedures. That means the optimization volumes are no longer expected to coincide with the start of production at each new phase.
Cenovus expects phases F, G and H to ramp up to a combined 90,000 bbls/d gross – the initial design capacity. Once those phases are complete, as planned in 2016, the company anticipates moving ahead with the optimization work. Optimization is anticipated to take about three years and bring the project up to its expected total full production capacity for phases A though H.
“Our confidence in Foster Creek and the reservoir’s ability to eventually produce more than 300,000 barrels per day gross remains unchanged,” Ferguson said. “This is one of the best SAGD projects in the industry. As we move forward, we’ll be focusing our capital at Foster Creek on investment that will bring the best value to shareholders.”
Attacking cost structures
Cenovus continues to seek efficiencies across its organization to ensure it remains a cost leader.
“We’re working hard to drive down costs,” said John Brannan, Executive Vice-President & Chief Operating Officer. “We’ve centralized some of our operational activities and we’re identifying opportunities in all areas of our operations to reduce capital and operating expenses.”
Cost saving initiatives include improving waste treatment processes, drilling and workover procedures and optimizing chemical usage. The company’s cost reduction strategy also includes reducing the number of planned new hires in 2014 compared with 2013 and reallocating staff to support oil projects already producing and those under construction.
Operating costs per barrel at Foster Creek were higher in 2013 compared with 2012, primarily due to increased well workover activities, higher fuel and workforce costs and lower production volumes. At Pelican Lake, operating costs per barrel in 2013 also rose from 2012 primarily due to increased polymer use. Operating costs per barrel at Christina Lake declined in 2013 from the previous year due to higher production volumes.
Expanding market access
Cenovus is concentrating on finding new customers in North America and around the world and working to ensure it has the ability to move its oil to these customers.
In 2013, the company committed to move 200,000 bbls/d on the proposed Energy East pipeline. It has additional shipping capacity of 175,000 bbls/d on proposed pipelines to the West Coast and 150,000 bbls/d on planned pipelines to the U.S. Gulf Coast, which is evenly split between Enbridge’s Flanagan South and TransCanada’s Keystone XL systems.
In addition to using pipelines, the company sold an average of 6,150 bbls/d of conventional oil that was transported by rail in 2013. By the end of 2013, Cenovus had rail capacity to transport 10,000 bbls/d of oil. Cenovus plans to begin using additional rail cars to transport some of its oil sands production by mid-2014 and expects to start taking delivery of 825 coiled and insulated leased rail cars in late 2014.
As part of its rail strategy, Cenovus entered into two multi-year terminal agreements in 2013. The company has contracted with Canexus for bitumen blend and unit train loading services at Bruderheim, Alberta as well as for rail loading services with US Development Group/Gibson Energy’s Hardisty, Alberta facility. Ultimately, the company expects to have the capacity to move up to 30,000 bbls/d of its blended oil volumes using rail by the end of 2014.
|Oil sands total||103||114||102||94||100||90||101||96||80||82||67|
1Totals 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 operations currently producing, 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 is currently building its third major oil sands project at Narrows Lake, which is part of the Christina Lake Region. These projects are operated by Cenovus and jointly owned with ConocoPhillips. Cenovus 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.
Foster Creek and Christina Lake
- Combined oil sands production at Foster Creek and Christina Lake increased 14% to 102,500 bbls/d net in 2013 from the previous year. Fourth quarter production also rose 13% in 2013 to almost 114,000 bbls/d net, compared with the same period a year earlier.
- Christina Lake production averaged 49,310 bbls/d net for the year, a 55% increase. Christina Lake produced an average of 61,471 bbls/d net in the fourth quarter, an increase of 47% from the same period in 2012.
- The significant increase at Christina Lake is the result of phase D reaching full capacity in the first quarter of 2013 and the addition of phase E, which achieved first oil production in mid-July. Phase E is expected to reach its design capacity during the first quarter of 2014. The five phases now in operation have a gross production capacity of 138,000 bbls/d and are expected to achieve average utilization of approximately 95%.
- The SOR at Christina Lake was 1.8 in 2013, an improvement from 1.9 in 2012.
- Foster Creek production averaged 53,190 bbls/d net in 2013, an 8% decrease compared with 2012. The decline was partially due to work to clear a backlog of well maintenance deferred in 2012. In addition, Cenovus continues to assess its operating procedures to optimize steam allocation and production as the reservoir supporting phases A to E evolves into common steam chambers.
- Foster Creek production in the fourth quarter was in line with the company’s expectations as the project ramped up following a planned major turnaround in the fall and well maintenance work was completed. December production averaged 57,383 bbls/d net. Total fourth quarter production was 52,419 bbls/d net, down 11% from the same period in 2012.
- Foster Creek’s 2013 SOR was 2.5, up from 2.2 in 2012, partially as a result of the changes discussed earlier regarding the evolution of the steam chambers. Cenovus expects an average SOR of 2.6 to 3.0 at Foster Creek in 2014 as reflected in the company’s updated guidance. The higher SOR is a result of a recent change in the start-up process for phase F, which is expected to begin production in the third quarter of this year. The company now plans to inject steam into the wells and circulate it for a longer period before initial production. Cenovus anticipates this will result in long-term production benefits that outweigh the added costs of a temporarily higher SOR.
- At Christina Lake, the phase F expansion is on schedule and on budget with about 44% of the project complete and engineering, procurement and plant construction work continuing. Engineering work also continues for phase G at Christina Lake. First production is expected from phase F in 2016 and phase G in 2017.
- At Foster Creek, phase F is on schedule and on budget with 90% of the project complete and first production expected in the third quarter of 2014, with full ramp up to be completed 12 to 18 months after first production begins. Phase G is 66% complete with initial production expected in 2015. Phase H is 35% complete and first production is expected in 2016.
- Combined capital investment at Foster Creek and Christina Lake was about $1.5 billion in 2013, up 12% from approximately $1.3 billion in 2012.
- Operating costs at Christina Lake were $12.47/bbl in 2013, a 4% decrease from $12.95/bbl the previous year. This was due to the increase in production from phases D and E. The decrease in per-barrel operating costs was partially offset by higher costs due to increased fuel consumption and prices, increased expenses associated with an expanded workforce for the new phases, repairs and maintenance, as well as fluid, waste handling and trucking costs. Non-fuel operating costs at Christina Lake were $9.44/bbl in 2013, a 10% decrease from $10.53/bbl in 2012.
- Operating costs at Foster Creek averaged $15.77/bbl in 2013, a 32% increase from $11.99/bbl in the same period last year. The increase was primarily due to lower production volumes, higher workover activities and increased cost from higher fuel prices and consumption. As well, there were higher workforce costs due to the hiring of additional field staff ahead of the start-up of phase F expected in the third quarter of 2014. Non-fuel operating costs at Foster Creek were $12.89/bbl for 2013 compared with $9.96/bbl in 2012, a 29% increase.
- Cenovus has updated its 2014 guidance for operating costs to a range of $16.40/bbl to $17.75/bbl at Foster Creek. The increase is a result of costs associated with bringing on phase F as well as additional preventative well maintenance, an anticipated increase in fuel prices, and higher expected SORs as the company implements its new reservoir management procedures.
- Overall progress for phase A at Narrows Lake, Cenovus’s next major oil sands development, was 16% complete at the end of the year. The first phase of the project is anticipated to have production capacity of 45,000 bbls/d gross, with first oil production expected in 2017. Site construction, engineering and procurement are progressing as expected.
- Narrows Lake is expected to be the industry’s first project to demonstrate solvent aided process (SAP), using butane, on a commercial scale.
- Cenovus invested $152 million to advance the Narrows Lake project in 2013.
- 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 the second quarter of 2014.
- A dewatering pilot project designed to remove an underground layer of non-potable water sitting on top of the oil sands deposit at Telephone Lake was successfully concluded during the fourth quarter. Approximately 70% of the top water was removed during the pilot and replaced with compressed air.
- 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.
- Cenovus invested $93 million in its Telephone Lake project in 2013, a decrease from $138 million in 2012. Capital investment decreased with the completion of drilling and facility construction for the dewatering pilot in the third quarter of 2012.
- At the company’s 100%-owned Grand Rapids project, located within the Greater Pelican Region, work continues on a SAGD pilot project with two well pairs in production.
- Cenovus completed a turnaround at Grand Rapids during the third quarter to resolve facility constraints that affected production on both well pairs in the first half of 2013.
- A regulatory application and EIA for the 180,000 bbl/d commercial project has been submitted and Cenovus anticipates receiving regulatory approval in the first quarter of 2014.
- Capital investment at Grand Rapids was $39 million in 2013, down from $65 million in the previous year, primarily due to drilling fewer stratigraphic test wells.
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. Cenovus has been injecting polymer since 2006 to enhance production from the reservoir, which is also under waterflood.
- Pelican Lake produced an average of 24,254 bbls/d for the year, an 8% increase from 2012 due to additional infill wells coming on production and increased response from the polymer flood. Fourth quarter production was 24,528 bbls/d, a 4% increase from the same period in 2012.
- Cenovus invested $465 million at Pelican Lake in 2013, primarily for the infill drilling and polymer flood programs. Capital investment at Pelican Lake was down 10% from 2012 as the company decided to slow the pace of development to better match production growth experienced at the project.
- Operating costs at Pelican Lake averaged $20.65/bbl for the year, a 21% increase from $17.08/bbl a year earlier, mainly due to increased polymer consumption related to the expansion of the polymer flood and higher workover and repairs and maintenance activities as well as increased electricity costs resulting from both higher prices and consumption.
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.
- Conventional oil production, excluding Pelican Lake, averaged 52,521 bbls/d in 2013, down 1% compared with 2012. The slight decrease was mainly due to the July sale of the company’s Shaunavon tight oil assets in Saskatchewan, partially offset by strong horizontal well performance from the company’s conventional drilling program. Shaunavon produced an annual average of 2,095 bbls/d in 2013 compared with 4,411 bbls/d in 2012. Other conventional oil production primarily included:
- average production in Alberta of 32,542 bbls/d, a 7% increase compared with 2012, primarily due to successful horizontal well drilling on fee lands
- average production at the Weyburn operation in Saskatchewan of 16,361 bbls/d, compared with 16,278 bbls/d in 2012.
- Cenovus invested $704 million in its conventional oil assets, excluding Pelican Lake, for the year, focusing on its emerging tight oil plays in Alberta.
- Operating cash flow from conventional oil assets, excluding Pelican Lake, in excess of capital investment was $299 million in 2013, an increase of 90% from 2012.
- Operating costs for Cenovus’s other conventional oil operations were $16.24/bbl in 2013, an increase of 7% from $15.12/bbl in 2012. This was mainly due to higher workforce, increased well workover on high-return wells to mitigate production declines as well as rising electricity costs due to higher market rates and increased consumption. Increased costs were partially offset by declines in repairs and maintenance mostly due to the Shaunavon assets sale.
Cenovus has a solid base of established, reliable natural gas properties in Alberta. These properties are important components of the company’s financial foundation and are managed as financial assets, not production assets, 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.
- The company invested $27 million in its natural gas properties during the year. Operating cash flow from natural gas in excess of capital investment was $410 million in 2013, an 11% decrease from 2012.
- Natural gas production in 2013 was approximately 529 million cubic feet per day (MMcf/d), down 11% from 2012. The decrease was driven by expected natural declines.
- Cenovus’s average realized sales price for natural gas, including hedges, was $3.52 per thousand cubic feet (Mcf) for 2013 compared with $3.56 per Mcf in 2012.
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 $1.1 billion for the year, 11% lower than 2012. The decline was due to lower market crack spreads and increased costs associated with RINs, substantially offset by higher refined product output and an improved feedstock cost advantage attributable to processing record heavy crude volumes.
- The company invested $106 million in its refining operations during the year compared with $118 million in 2012. Operating cash flow in excess of capital invested was approximately $1 billion, net to Cenovus, in 2013.
- Crack spreads were impacted by higher crude oil pipeline takeaway capacity in the southern tier of the U.S., which alleviated inland congestion and increased West Texas Intermediate (WTI) crude oil prices, bringing them closer to Brent crude prices. Higher refinery utilization, which increased supplies of transportation fuels across the U.S. Midwest, also impacted crack spreads.
- The cost of RINs increased almost five-fold from 2012 to $153 million, net to Cenovus, which negatively impacted 2013 gross refining margins. RIN costs have been trending lower since early in the fourth quarter of 2013 after the U.S. EPA proposed reducing the 2014 volume requirements for renewable blending.
- Cenovus’s refineries processed an average of 442,000 bbls/d of crude oil in 2013, resulting in 463,000 bbls/d of refined product output. This was up about 7% from the previous year when product output was reduced by planned turnarounds at both refineries.
- The company’s refineries processed an average of 222,000 bbls/d of heavy oil in 2013, the highest volume since the inception of the refining partnership in 2007, up 24,000 bbls/d compared with 2012.
- 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 2013 refining operating cash flow would have been $26 million lower than reported under FIFO compared with $111 million higher in 2012.
Reserves and Contingent Resources
All of Cenovus’s reserves and resources are evaluated each year by independent qualified reserves evaluators (IQREs).
- At year-end 2013, Cenovus had total proved reserves of almost 2.3 billion BOE, an increase of 5% compared with 2012.
- Proved bitumen reserves increased 8% in 2013 compared with 2012, to more than 1.8 billion bbls, while proved plus probable bitumen reserves grew 6% to approximately 2.5 billion bbls. This increase was primarily due to expansion of the development areas at Christina Lake and Foster Creek, plus an initial booking of probable reserves for the planned Grand Rapids project.
- Economic bitumen best estimate contingent resources increased to 9.8 billion bbls, up approximately 2% from 2012. Growth was more moderate than previous years as increases from stratigraphic well drilling and land acquisitions were offset by dispositions as well as slightly reduced recovery factors used by the company’s IQREs in portions of two non-producing properties. For additional information on the company’s contingent resources, see Oil and Gas Information in the Advisory.
- Proved light and medium oil reserves were unchanged, while proved heavy oil reserves decreased approximately 3% due to production outpacing additions and technical revisions to the resource base. Natural gas proved reserves declined about 9% compared with 2012 as Cenovus continued to focus capital on developing its oil assets. As expected, this has resulted in natural gas production outpacing reserves additions.
- Cenovus’s 2013 proved finding and development (F&D) costs, excluding changes in future development costs, were $14.51/BOE, up from $9.04/BOE in 2012 due to lower reserves additions. The three-year average F&D costs were $9.05/BOE, excluding changes in future development costs.
- For our proved reserves, the IQREs have estimated our total future development costs to be $7.80 per BOE, or $6.20 per BOE on a de-escalated basis.
- Cenovus achieved production replacement of more than 200% in 2013.
- Cenovus continues to use its illustrative net asset value (NAV) as an important measure of long-term success. At the end of 2013, Cenovus’s NAV was $35, a 12% decrease from year-end 2012. Despite solid growth in reserves and resources in 2013, the forecast of lower long-term commodity prices was the primary factor that resulted in this decline in NAV. Since the inception of the company in 2009, NAV has increased 25% primarily due to 72% total growth in reserves and resources.
- The overall proved reserves life index is approximately 24 years. The magnitude of the company’s bitumen assets is significant with a bitumen proved reserves life index of 49 years, down 6% due to the company’s increasing bitumen production. The conventional oil and NGLs proved reserves life is 11 years.
|Proved reserves reconciliation|
|Light & Medium
Oil & NGLs
|Natural Gas &
|Start of 2013||1,717||184||115||955|
|Extensions & improved recovery||134||21||11||24|
|End of 2013||1,846||179||115||865|
|Total proved plus probable||2,529||319||165||1,165|
1 Production used for the reserves reconciliation differs from reported production as it includes Cenovus gas volumes provided to the FCCL Partnership for steam generation, but does not include royalty interest production. See the Advisory – Oil and Gas Information for more information about royalty interest production.
|Proved reserves costs1|
|(Before royalties)||2013||2012||3 Year|
|Capital Investment ($ millions)|
|Finding and Development||3,026||3,013||8,214|
|Finding, Development and Acquisitions||3,058||3,127||8,429|
|Proved Reserves Additions2 (MMBOE)|
|Finding and Development||208||333||907|
|Finding, Development and Acquisitions||208||334||908|
|Proved Reserves Costs2 ($/BOE)|
|Finding and Development3||14.51||9.04||9.05|
|Finding, Development and Acquisitions4||14.67||9.36||9.28|
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.
The Cenovus Board of Directors approved a dividend increase of 10% for the first quarter of 2014, resulting in a dividend of $0.2662 per share, payable on March 31, 2014 to common shareholders of record as of March 14, 2014. Based on the February 12, 2014 closing share price on the Toronto Stock Exchange of $29.64, this represents an annualized yield of about 3.6%. Declaration of dividends is at the sole discretion of the Board. Cenovus’s continued commitment to a meaningful 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 expected 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 145 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 natural gas Cenovus produces. The company’s financial hedging positions are determined after considering this natural hedge.
Cenovus’s financial hedge positions at December 31, 2013 include:
- approximately 15% or 30,000 bbls/d of expected oil production hedged for 2014 at an average Brent price of US$102.04/bbl and an additional 10% or 20,000 bbls/d at an average Brent price of C$107.06/bbl
- a built-in hedge for natural gas production due to internal usage of about 145 MMcf/d of natural gas plus long-term fixed-price sales of 29 MMcf/d of natural gas
- approximately 15,900 bbls/d of heavy crude exposure hedged for 2014 at an average WCS differential to WTI of US$20.39/bbl.
- Operating cash flow was approximately $4.5 billion in 2013, comparable to 2012, due to higher crude oil volumes at Christina Lake and higher sales prices for crude. This was partially offset by lower realized risk management gains, increased operating costs and declines in natural gas production volumes.
- Cash flow in 2013 was $3.6 billion, or $4.76 per share diluted, unchanged from $3.6 billion, or $4.80 per share diluted, in 2012.
- Operating earnings were $1.2 billion, or $1.55 per share diluted, up 35% from 2012. The increase was due to the same factors affecting operating cash flow as well as a decline of $111 million in deferred income tax expense and no goodwill impairment in the year compared with an impairment of $393 million in 2012. Higher operating earnings were partially offset by increased depreciation, depletion and amortization expense.
- Cenovus’s net earnings for the year were $662 million compared with $995 million in 2012. The decrease was primarily the result of unrealized after-tax risk management losses of $310 million compared with gains of $43 million a year earlier, as well as realized after-tax foreign exchange losses of $146 million related to a decision by Cenovus’s partner ConocoPhillips to pay the remaining principal of a receivable connected to the oil sands joint operation and after-tax non-operating unrealized foreign exchange losses of $52 million compared with gains of $84 million the previous year.
- Cenovus had a realized after-tax hedging gain of $93 million in 2013. The company received an average realized price, including hedging, of $68.10/bbl for its oil in 2013 compared with $67.18/bbl in 2012. The average realized price for natural gas in the year, including hedging, was $3.52/Mcf compared with $3.56/Mcf in 2012.
- Cenovus recorded income tax expense of $432 million for 2013, giving the company an effective tax rate of 39.5% compared with an effective rate of 44% in 2012, primarily due to a non-deductible goodwill impairment charge of $393 million in 2012 and U.S. withholding tax on dividends of $68 million, offset by non-deductible foreign exchange losses in 2013.
- Capital investment for the year was $3.3 billion, a 3% decrease from $3.4 billion in 2012 as a result of lower spending at the company’s Pelican Lake operation as well as reduced investment in Saskatchewan after the sale of the company’s Shaunavon tight oil asset.
- General and administrative (G&A) expenses were $349 million in 2013, comparable with $350 million in the previous year. Excluding the impact of long-term incentives, costs increased due to higher rent and staffing expenses.
- Over the long term, Cenovus continues to target a debt to capitalization ratio of between 30% and 40% and a debt to adjusted earnings before interest, taxes, depreciation and amortization (EBITDA) ratio of between 1.0 and 2.0 times. At December 31, 2013, the company’s debt to capitalization ratio was 33% and debt to adjusted EBITDA, on a trailing 12-month basis, was 1.2 times.
|(for the period ended December 31)
($ millions, except per share amounts)
|Add back (deduct):|
|Unrealized risk management (gains) losses, after-tax||163||(87)||310||(43)|
|Non-operating unrealized foreign exchange (gains) losses,
|Realized foreign exchange loss on Partnership Contribution Receivable, after-tax||146||–||146||–|
|Divestiture (gains) losses, after-tax||–||–||1||–|
|Per share diluted||0.28||(0.25)||1.55||1.14|
1 Operating earnings is a non-GAAP measure as defined in the Advisory.
|Oil sands project schedule|
|Project phase||Regulatory status||First production
|Foster Creek1A – E||120,000|
|Christina Lake1A – E||138,000|
|Optimization (phases C,D,E)||Approved||2015F||22,000|
|Telephone Lake6||Submitted Q4-2011||TBD||90,000|
|Grand Rapids||Submitted Q4-2011||TBD||180,000|
1Properties 50% owned by ConocoPhillips. Certain phases may be subject to partner approval.
2 Represents first production target for phase F. Phase G first production expected in 2015 and phase H in 2016.
3 Each of phases F, G, H are expected to ramp up to 30,000 bbls/d in 12 to 18 months from first production. Optimization is expected to add an additional 35,000 bbls/d between 2016 and 2019.
4Includes 5,000 bbls/d gross submitted to the regulator in Q1 2013.
5 Represents first production target for phase F. Phase G first production expected in 2017.
6 Projected potential 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, February 13, 2014, starting at 9 a.m. MT (11 a.m. ET). To participate, please dial 1-888-231-8191 (toll-free in North America) or 1-647-427-7450 approximately 10 minutes prior to the conference call. An archived recording of the call will be available from approximately 12 p.m. MT on February 13, 2014, until 10 p.m. MT on February 20, 2014, by dialing 1-855-859-2056 or 1-416-849-0833 and entering conference passcode 19216840. A live audio webcast of the conference call will also be available via 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. Items within the Corporate and Eliminations segment are excluded from the calculation of operating cash flow.
- 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, the effect of changes in statutory income tax rates, and the after-tax realized foreign exchange loss on the early receipt of the Partnership Contribution Receivable. 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.
- 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 AND GAS INFORMATION
The estimates of reserves and resources data and related information were prepared effective December 31, 2013 by independent qualified reserves evaluators (“IQREs”), 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. Estimates are presented using McDaniel & Associates Consultants Ltd. (“McDaniel”) January 1, 2014 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.
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.
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. There is no certainty that it will be commercially viable to produce any portion of the contingent resources.
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 economic 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.
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 $32.97/BOE for the year ended December 31, 2013, $25.48/BOE for the year ended December 31, 2012 and averaged $22.57/BOE for the three years ended December 31, 2013. 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 $40.85/BOE for the year ended December 31, 2013, $20.04/BOE for the year ended December 31, 2012 and averaged $17.56/BOE for the three years ended December 31, 2013. 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”, “goal”, “proposed”, “scheduled”, “potential”, “may”, “projected”, “strategy” or similar expressions and includes suggestions of future outcomes, including statements about our growth strategy and related schedules, projections contained in our 2014 guidance, projected 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, estimated finding and development costs, expected reserves and contingent resources estimates, estimated proved reserves life index, broadening market access, improving cost structures, 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 disclosed 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.
2014 guidance, updated February 13, 2014, is available at cenovus.com, is based on an average diluted number of shares outstanding of approximately 757 million. It assumes: Brent US$105.00/bbl, WTI of US$102.00/bbl; Western Canada Select of US$76.00/bbl; NYMEX of US$4.00/MMBtu; AECO of C$3.30/GJ; Chicago 3-2-1 crack spread of US$13.50/bbl; exchange rate of $0.98 US$/C$. For the period 2015 to 2023, assumptions include: Brent US$105.00-US$110.00; WTI of US$100.00-US$106.00/bbl; Western Canada Select of C$81.00-C$91.00/bbl; NYMEX of US$4.25-US$4.75/MMBtu; AECO of C$3.70-C$4.31/GJ; Chicago 3-2-1 crack spread of US$12.00-US$13.00; exchange rate of $1.00 US$/C$; and average diluted number of shares outstanding of approximately 782 million.
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, including sufficient crude-by-rail or other alternate 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 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 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 $27 billion. For more information, visit cenovus.com.
SOURCE Cenovus Energy Inc.
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/20140213_C9739_PHOTO_EN_36584.jpg
Image with caption: “Cenovus’s Foster Creek oil sands operation in northern Alberta (CNW Group/Cenovus Energy Inc.)”. Image available at: http://photos.newswire.ca/images/download/20140213_C9739_PHOTO_EN_36585.jpg
Image with caption: “A well pad and drilling rig 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/20140213_C9739_PHOTO_EN_36586.jpg
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