Last updated on April 16, 2014 at 5:31 EDT

Cenovus total proved reserves up 12% to 2.2 billion BOE

February 14, 2013

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
            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
        --  Cash flow increased to about $3.6 billion in 2012, up 11% from
        --  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

“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
    ($ millions,
    except per share    2012    2011             2012      2011
    amounts)             Q4      Q4   % change Full Year Full Year % change

    Cash flow1           697     851     -18      3,643     3,276      11

      Per share
      diluted           0.92    1.12              4.80      4.32         

    earnings/loss1      -189     332     -157      866      1,239     -30

      Per share
      diluted          -0.25    0.44              1.14      1.64         

    Net earnings/loss   -118     266     -144      993      1,478     -33

      Per share
      diluted          -0.16    0.35              1.31      1.95         

    investment2          978     903       8      3,368     2,723      24


    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
    3Includes natural gas liquids (NGLs) production and production from
    Pelican Lake.
    4Reflects 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

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

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

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 Well(TM) technologies as well as the development of its new SkyStrat(TM) 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

“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 Projects

                                        Daily production1

    (Before royalties)
    (Mbbls/d)                      2012                 2011     2010

                       Full                 Full                 Full
                       Year Q4  Q3  Q2  Q1  Year Q4  Q3  Q2  Q1  Year

    Oil sands                                                       

      Foster Creek      58  59  63  52  57   55  55  56  50  58   51

      Christina Lake    32  42  32  29  25   12  20  10   8   9    8

    Oil sands total     90  101 96  80  82   67  75  66  58  67   59

    Conventional oil                                                

      Pelican Lake      23  24  24  22  21   20  21  20  19  21   23

      Weyburn           16  16  16  16  17   16  17  16  15  17   17

    conventional2       37  37  36  36  38   31  32  31  29  32   31

    Conventional total  76  77  76  75  75   68  70  67  64  71   70

    Total oil2         165  178 171 156 157 134  144 133 122 137 129

(1 )Totals may not add due to rounding.
(2 )Includes NGLs production.

Oil sands
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
            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
            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
            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
            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
            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

        --  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
        --  The Wood River
            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.

Emerging projects

Narrows Lake

        --  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.

Grand Rapids

        --  At the company's 100%-owned
            Grand Rapids
            property, located within the Greater Pelican Region, a
            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.

Telephone Lake

        --  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

Conventional oil

Pelican Lake
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
        --  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
            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
        --  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.

Natural Gas

     (Before                                        Daily production
     (MMcf/d)                    2012                            2011        2010

               Full                           Full                           Full
               Year   Q4    Q3    Q2    Q1    Year   Q4    Q3    Q2    Q1    Year

    Gas1       594    566   577   596   636   656    660   656   654   652   737

(       1 )Reflects the divestiture of a non-core property in the first quarter of

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
            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
            in late 2011, including lower feedstock costs and improved
        --  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
        --  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
            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
            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
            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
        --  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

    (Before royalties)    Bitumen  Heavy Oil Light & Medium Natural Gas &
                          (MMbbls) (MMbbls)    Oil & NGLs        CBM
                                                (MMbbls)        (Bcf)

    Start of 2012           1,455      175           115          1,203

    Extensions & improved    265        17            13            29

    Technical revisions       30         6            -2            51

    Economic factors           -         -            -            -58

    Acquisitions               -         -            1              1

    Divestitures               -         -            -            -59

    Production1              -33       -14           -12          -212

    End of 2012             1,717      184           115           955

    % Change                  18         5            -            -21

    Developed                185       122           934           949
    Undeveloped              1532      62             22            6

    Total proved            1,717      184           115           955

    Total probable           676       105            56           338

    Total proved plus       2,393      289           171          1,293

(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)                     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

    (Before royalties)                             

    Economic Contingent Resources1 Bitumen (billion bbls)

                                   2012 2011    % Change

    Low Estimate                   7.1  6.0         18

    Best Estimate                  9.6  8.2         17

    High Estimate                  12.8 10.8        19

(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.

Hedging strategy
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
        --  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.

Financial highlights

        --  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
        --  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
        --  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
        --  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)     2012  2011   2012      2011
    ($ millions, except per share amounts)  Q4    Q4  Full Year Full Year

    Net earnings
    Add back losses & deduct gains:        -118  266      993      1,478
      Per share diluted                    -0.16 0.35    1.31      1.95

    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

    Operating earnings/loss                -189  332      866      1,239

      Per share diluted                    -0.25 0.44    1.14      1.64

                                     Oil sands project schedule

       Project phase   Regulatory status First production    production
                                              target      capacity (bbls/d)

    Foster Creek1 A -
    E                                                            120,000

       F                     Approved          Q3-2014F          45,0002

       G                     Approved            2015F            40,000

       H                     Approved            2016F            40,000

       J                  Submit 2013F           2019F            50,000

    optimization                                                  15,000

       Total capacity                                            310,000

    Christina Lake1 A
    - D                                                           98,000

       E                     Approved          Q3-2013F           40,000

       F                     Approved            2016F            50,000

       G                     Approved            2017F            50,000

       H                  Submit 2013F           2019F            50,000

    optimization                                                  12,000

       Total capacity                                            300,000

    Narrows Lake1                                                      

        A                    Approved            2017F            45,000

        B-C                  Approved             TBD             85,000

        Total Capacity                                           130,000

    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
(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.

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 resourcesare 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 resourcesare 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
            projects that are producing from the McMurray-Wabiskaw
            formations are used as performance analogs at
            Foster Creek
            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
        --  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

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.

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SOURCE Cenovus Energy Inc.

Video with caption: “Brian Ferguson speaks to Cenovus’s 2012 earnings”. Video available at: http://stream1.newswire.ca/cgi-bin/playback.cgi?file=20130214_C5352_VIDEO_EN_23733.mp4&posterurl=http://photos.newswire.ca/images/20130214_C5352_PHOTO_EN_23733.jpg&clientName=Cenovus%20Energy%20Inc%2E&caption=Brian%20Ferguson%20speaks%20to%20Cenovus%27s%202012%20earnings&title=CENOVUS%20ENERGY%20INC%2E%20%2D%20Brian%20Ferguson%20speaks%20to%20Cenovus%27s%202012%20earnings&headline=Cenovus%20total%20proved%20reserves%20up%2012%25%20to%202%2E2%20billion%20BOE

Image with caption: “Coker and refinery expansion (CORE) project at the Wood River Refinery, jointly owned by Cenovus and Phillips 66 (CNW Group/Cenovus Energy Inc.)”. Image available at: http://photos.newswire.ca/images/download/20130214_C5352_PHOTO_EN_23727.jpg

Image with caption: “Well pad using steam-assisted gravity drainage (SAGD) at Cenovus’s Foster Creek operation in northern Alberta (CNW Group/Cenovus Energy Inc.)”. Image available at: http://photos.newswire.ca/images/download/20130214_C5352_PHOTO_EN_23728.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/20130214_C5352_PHOTO_EN_23726.jpg

Source: PR Newswire