Cenovus total proved reserves up 12% to 2.2 billion BOE

           Cenovus total proved reserves up 12% to 2.2 billion BOE

PR Newswire

CALGARY, Feb. 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 and Christina Lake averaged
    nearly 90,000 barrels per day (bbls/d) net in 2012, up 35% from 2011.
    Average production at Christina Lake nearly tripled in 2012 to almost
    32,000 bbls/d net.
  *Christina Lake phase D reached full capacity about six months after first
  *Cash flow increased to about $3.6 billion in 2012, up 11% from 2011.
  *The Board of Directors approved a dividend increase of 10% for the first
    quarter of 2013 resulting in a quarterly dividend of $0.242 per share.
  *Cenovus recorded a $393 million non-cash goodwill impairment in the fourth
    quarter which resulted in lower 2012 operating earnings and a fourth
    quarter earnings loss. This impairment related to the company's Suffield
    assets, principally natural gas.

"We had another strong year in 2012, achieving the milestones we set for
ourselves," said Brian Ferguson, President & Chief Executive Officer of
Cenovus. "We added significant new reserves and resources, increased our oil
production, enhanced our net asset value and generated record cash flow. We
remain committed to delivering a growing total shareholder return and have
again increased our dividend by 10%."

                        Financial & production summary
(for the period ended
December 31)
($ millions, except per   2012    2011              2012      2011
share amounts)             Q4      Q4    % change Full Year Full Year % change
Cash flow^1                697     851     -18      3,643     3,276      11
         Per share
          diluted         0.92    1.12             4.80      4.32       
earnings/loss^1           -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       
Capital investment^2       978     903      8       3,368     2,723      24
Production (before
Oil sands total (bbls/d) 100,867 74,576     35     89,736    66,533      35
Conventional oil^3
(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 gas^4 (MMcf/d)     566     660     -14       594       656       -9

^1Cash flow and operating earnings are non-GAAP measures as defined in the
Advisory. See also the Earnings Reconciliation Summary.
^2 Includes expenditures on property, plant and equipment and exploration and
evaluation assets, excluding acquisitions and divestitures.
^3 Includes natural gas liquids (NGLs) production and production from Pelican
^4 Reflects the divestiture of a non-core property in the first quarter of

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

"Our integrated approach continues to support our bottom line," Ferguson said.
"When our heavy oil producing assets are affected by low commodity prices, we
make up that value at our refineries. For 2013, we have supply agreements and
firm transportation and hedging contracts that, together with our refining
capacity, will enable us to offset almost all of our volume exposure to
discounted Canadian heavy crude prices."

Strong additions to reserves and contingent resources
Cenovus continues to strengthen its reserves and resources base. According to
the company's independent reserves and contingent resources evaluation, total
proved reserves were nearly 2.2 billion bbls of oil equivalent (BOE) at the
end of 2012, up 12% from the previous year.

Proved bitumen reserves increased 18% to more than 1.7 billion bbls, compared
with 2011, while proved plus probable bitumen reserves increased approximately
23% to nearly 2.4 billion bbls. Economic bitumen best estimate contingent
resources increased 17% from 2011 to 9.6 billion bbls. Proved light and medium
oil reserves remained unchanged, while proved heavy oil reserves increased
approximately 5% and proved natural gas reserves declined about 21% compared
with 2011. Cenovus's 2012 proved finding and development (F&D) costs,
excluding changes in future development costs, were a competitive $9.04/BOE.
The three-year average was $6.10/BOE. The 2012 recycle ratio was 3.2 times.

"Cenovus's stratigraphic well program continues to add significant new
resources to our already strong portfolio of oil sands assets," Ferguson said.
"This gives us even greater opportunity to develop new projects, move them
through the regulatory approvals process and create decades of solid growth

Integrated operations contribute to solid financial performance
Cenovus achieved cash flow of more than $3.6 billion, an 11% increase from the
previous year. Operating cash flow from refining benefited from the fact that
the Wood Rivery Refinery was able to process higher volumes of heavy oil as a
result of the completion of the coker and refinery expansion (CORE) project in
late 2011. While lower commodity prices had a negative impact on cash flow
from the company's oil producing assets, the ongoing price volatility provided
a double benefit to Cenovus's refining operations. Compared with 2011, the
price of Western Canadian Select (WCS), the benchmark Canadian heavy oil
blend, fell against the price of West Texas Intermediate (WTI), the North
American benchmark. The wider WTI-WCS differential resulted in lower feedstock
costs for the company's refineries. At the same time, there was a favourable
appreciation in the price of Brent crude, the global benchmark, against the
price of WTI, which allowed Cenovus's refineries to capture higher prices for
their finished products. Those lower feedstock costs and higher finished
product prices led to stronger refining margins, which also contributed to the
29% improvement in operating cash flow from refining when compared with 2011.

Goodwill impairment impacts earnings
A one-time non-cash goodwill write down of $393 million in the company's
conventional operations contributed to lower full year operating earnings in
2012 and to an operating loss of $189 million in the fourth quarter. For the
full year, the company had operating earnings of $866 million, down 30% from
2011. The full year decrease and quarterly loss were primarily due to the
goodwill impairment related to the company's Suffield conventional assets,
located on the Canadian Forces Base in southeast Alberta. Estimated future
cash flowsfor the assets have declined, largely as the result of a drop in
forecast natural gas prices over the long term. As a result, thecarrying
amount of goodwill related to the property hasexceeded its fair value and was
written off. The goodwill in question arose from the 2002 merger between
Alberta Energy Company and PanCanadian Energy Corporation.

Continued focus on operating costs
Managing operating costs is an important ongoing focus for Cenovus. Operating
costs per BOE at the company's oil sands and natural gas operations were
largely in line with Cenovus's 2012 forecasts, while operating costs at its
Pelican Lake heavy oil operations were slightly above guidance. Cenovus
anticipates more pressure on operating costs in 2013 as a result of expected
higher prices for natural gas and electricity needed to fuel the company's
operations. Operating costs at Pelican Lake are expected to rise again this
year with the expansion of the polymer flood as temporarily reduced reservoir
pressure required to safely complete infill drilling limits 2013 production
growth. Stronger production growth is expected in late 2013 and into 2014,
which should help reduce per barrel operating costs.

"Cenovus is working diligently to maintain our reputation as a low cost
producer," said John Brannan, Cenovus Executive Vice-President and Chief
Operating Officer. "We will continue to focus on reducing our costs per barrel
and increasing efficiency across all of our operations."

Growing net asset value
Cenovus measures its success in a number of ways with a key metric being
growth in net asset value (NAV). The company remains on track to reach its
goal of doubling its December 2009 baseline illustrative NAV of $28 by the end
of 2015. Despite weaker oil and gas prices, Cenovus's operational and
financial performance and consistent production growth allowed the company to
increase its NAV to approximately $40 in 2012, a 43% increase from the end of

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 2011.

"Widening oil price differentials are becoming an increasingly important
issue, not just for producers, but for all Canadians," Ferguson said. "With
the third largest oil reserves in the world, we have a tremendous opportunity
to capitalize on the growing global demand for energy. However, without
pipeline access to new markets we will continue to leave billions of dollars
in lost revenues on the table every year, to the detriment of the entire
Canadian economy."

Cenovus takes a portfolio approach to market access and continues to
proactively assess various options to transport its oil. The predictability of
the company's oil production growth gives it the confidence to support all
currently proposed pipeline projects that would open up new markets. Early in
2012, Cenovus started shipping 11,500 bbls/d of oil under a firm service
agreement on the Trans Mountain pipeline that runs from Edmonton to the West
Coast. The firm service agreement is beneficial as it gives Cenovus the
ability to get its oil to tidewater where it commands higher prices and it
allows the company to negotiate longer term arrangements for markets in
California and Asia. In addition to pipelines, Cenovus is now shipping about
6,000 bbls/d of conventional crude volumes to market by rail and is looking to
increase that to about 10,000 bbls/d in 2013.

                                 Oil Projects

                            Daily production^1
(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
 Other conventional^2  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 oil^2                 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 and Christina Lake increased 35% to
    almost 90,000 bbls/d net in 2012 compared with the previous year. Fourth
    quarter production also rose 35% in 2012 to nearly 101,000 bbls/d net,
    compared to the same period in 2011.
  *Christina Lake production almost tripled to an average of about 32,000
    bbls/d net in 2012, compared with the previous year. Christina Lake
    produced an average of approximately 42,000 bbls/d net in the fourth
    quarter, more than double the average production rate in the same period a
    year earlier.
  *The substantial increase in production at Christina Lake was due to the
    ramp-up of two new expansion phases. Phase C reached full capacity in the
    first quarter of 2012. Phase D began producing in July 2012, approximately
    three months ahead of schedule. It demonstrated full production capacity
    in January 2013, approximately six months after first production.
  *Foster Creek produced an average of nearly 58,000 bbls/d net in 2012,
    about 5% more than the 2011 average due to improved well performance and
    plant optimization. Fourth quarter production at Foster Creek averaged
    about 59,000 bbls/d net to Cenovus.
  *Both Christina Lake and Foster Creek achieved new single-day production
    highs of almost 47,000 and 65,500 bbls/d net respectively in 2012.
  *About 12% of current production at Foster Creek comes from 56 wells using
    Cenovus's Wedge Well^TM technology. These single horizontal wells, drilled
    between existing SAGD well pairs, reach oil that would otherwise be
    unrecoverable. The company's Wedge [ ]Well^TM technology has the potential
    to increase overall recovery from the reservoir by as much as 10%, while
    reducing the steam to oil ratio (SOR). Cenovus plans to drill and complete
    an additional eight wells at Foster Creek using Wedge Well^TM technology
    in 2013.
  *Christina Lake is also benefiting from the use of Wedge Well^TM 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%
    First production at phase F is expected in the third quarter of 2014.
    Spending on piling work, steel fabrication, module assembly and major
    equipment procurement is under way at phase G and design engineering
    continues at phase H.
  *Combined capital investment at Foster Creek and Christina Lake was more
    than $1.3 billion in 2012, a 46% increase compared with 2011. This
    includes spending on the expansion phases, stratigraphic test wells and
    maintenance capital.

Operating costs

  *Operating costs at Foster Creek averaged $11.99/bbl in 2012, about a 6%
    increase from $11.34/bbl the previous year. Non-fuel operating costs at
    Foster Creek were $9.96/bbl in 2012 compared with $9.14/bbl in 2011, a 9%
    increase. The increases were mostly due to added costs from hiring
    additional staff, as well as higher levels of waste and fluid handling,
    trucking and workover activity.
  *Operating costs at Christina Lake were $12.95/bbl in 2012, a 36% decrease
    from $20.20/bbl the previous year. Non-fuel operating costs at Christina
    Lake were $10.53/bbl in 2012 compared with $17.02/bbl in 2011, a 38%
    decrease. The decreases were primarily due to the significant increase in
    production at Christina Lake in 2012 and lower SORs.

Steam to oil ratios

  *SOR measures the number of barrels of steam needed for every barrel of oil
    produced, with Cenovus having one of the lowest ratios in the industry. A
    lower SOR means less natural gas is used to generate the steam, which
    results in reduced capital and operating costs, fewer emissions and lower
    water usage.
  *Cenovus continued to achieve low SORs in 2012 with ratios of approximately
    2.2 at Foster Creek, unchanged from 2011, and 1.9 at Christina Lake, down
    from 2.3 in 2011. The combined SOR for Cenovus's oil sands operations was
    about 2.1 in 2012.

Christina Dilbit Blend

  *Christina Dilbit Blend (CDB) is a heavy bitumen blend stream launched in
    the fourth quarter of 2011. Last year, 74% of production from Christina
    Lake was sold as CDB.
  *While CDB is priced at a discount to WCS, it is gaining acceptance with a
    wider base of refiners. Cenovus continued to add CDB into its contracts
    with downstream customers and saw the price differential narrow last year.
  *In the fourth quarter of 2012 the CDB discount to WCS was in the US$4.50
    to US$7.50/bbl range. Over the longer term, Cenovus expects a CDB to WCS
    discount in the US$3.00/bbl to US$5.00/bbl range.
  *The Wood River Refinery ran approximately 84,000 bbls/d gross of CDB or
    equivalent crudes during the fourth quarter of 2012. These crudes
    represented 55% of total heavy crude volumes in the fourth quarter, up
    from 40% in the third quarter of 2012.

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 SAGD pilot project is under way. The project is
    progressing smoothly with steaming of a second well pair, which is
    expected to begin producing this month. A joint regulatory application and
    Environmental Impact Assessment (EIA) for a 180,000 bbl/d commercial
    project has been submitted and is proceeding on schedule. Cenovus
    anticipates regulatory approval for Grand Rapids by the end of 2013.

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 flood.
  *Operating costs at Pelican Lake averaged $17.08/bbl in 2012, a 15%
    increase from $14.86/bbl in 2011. Per barrel operating costs have been
    impacted by lower than expected production growth due to reduced operating
    pressures related to temporary well shut-ins required to complete infill
    drilling between existing wells at Pelican Lake.
  *Operating costs at Pelican Lake were also higher due to additional
    workover activities, increased staffing levels and polymer consumption as
    a result of the expansion of the polymer flood.
  *Stronger production growth is expected in late 2013 and into 2014, which
    should help reduce per barrel operating costs.

Other conventional oil
In addition to Pelican Lake, Cenovus has extensive oil operations in Alberta
and Saskatchewan. These include conventional and tight oil assets in Alberta
and developing tight oil assets in southern Saskatchewan, as well as the
established Weyburn operation that uses carbon dioxide injection to enhance
oil recovery.

  *Alberta oil production averaged more than 30,000 bbls/d in 2012, up 10%
    from the previous year, primarily due to successful tight oil drilling
    programs and fewer weather and access issues than in 2011.
  *Production at the Weyburn operation was unchanged compared to the previous
    year at more than 16,000 bbls/d net.
  *Combined crude oil production from the Bakken and Lower Shaunavon
    operations averaged nearly 6,500 bbls/d, a 79% increase from the previous
    year due to increased drilling. Given the limited expansion opportunities
    that Cenovus has in these non-core properties in comparison to its other
    holdings, the company has determined it will commence a public process
    later this quarter to dispose of its interests in the Lower Shaunavon
    property and the operated part of its Bakken property.
  *Operating costs for Cenovus's conventional oil and liquids operations,
    excluding Pelican Lake, increased 9% to $15.12/bbl in 2012 compared with
    2011. This was mainly due to a combination of higher levels of waste and
    fluid handling, trucking, workover activities, repairs and maintenance in
    connection with single well batteries and higher workforce costs.

                                 Natural Gas

  (Before                            Daily production
royalties)              2012                           2011               2010
 (MMcf/d)   Full                           Full                           Full
            Year  Q4   Q3   Q2   Q1   Year  Q4   Q3   Q2   Q1   Year
Gas^1       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 2012.

Cenovus has a solid base of established, reliable natural gas properties in
Alberta. These assets are an important component of the company's financial
foundation, generating operating cash flow well in excess of their ongoing
capital investment requirements. The natural gas business also acts as an
economic hedge against price fluctuations, because natural gas fuels the
company's oil sands and refining operations.

  *Natural gas production in 2012 was approximately 594 million cubic feet
    per day (MMcf/d), down 9% from the previous year, as expected. The
    production drop was driven primarily by expected natural declines and the
    divestiture of a non-core property early in the first quarter of 2012.
    Excluding the impact of the divestiture, natural gas production would have
    been 6% lower than in 2011.
  *Cenovus's average realized sales price for natural gas, including hedges,
    was $3.56 per thousand cubic feet (Mcf) in 2012 compared with $4.52 per
    Mcf in 2011.
  *The company invested $51 million in its natural gas properties in 2012.
    Operating cash flow from natural gas in excess of capital investment was
    $462 million.
  *Cenovus anticipates managing an annual decline rate of 10% to 15% for its
    natural gas production, targeting a long-term production level of between
    400 MMcf/d and 500 MMcf/d to match Cenovus's future anticipated internal
    consumption at its oil sands and refining facilities.


Cenovus's refining operations allow the company to capture value from crude
oil production through to refined products such as diesel, gasoline and jet
fuel. This integrated strategy provides a natural economic hedge against
reduced crude oil prices by providing lower feedstock prices to Cenovus'sWood
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 tohigher benchmark crack
    spreads as well as the benefits from the completion of the CORE project at
    the Wood River Refinery in late 2011, including lower feedstock costs and
    improved refinery output.
  *Operating cash flow for 2012 would have been higher if not for planned
    fourth quarter major turnarounds at Wood River and Borger that continued
    longer than expected.
  *Cenovus's operating cash flow is calculated on a first-in, first-out
    (FIFO) inventory accounting basis.Using the last-in, first-out (LIFO)
    accountingmethod employed by most U.S. refiners, Cenovus's 2012 refining
    operating cash flow wouldhave been$111 million higher than reported
    under FIFO, compared with $95 million lower in 2011.
  *For the full year, the company's refining business generated $1.14 billion
    of operating cash flow in excess of the $118 million of capital invested
    in it.
  *Cenovus expects strong first quarter 2013 operating cash flow from its
    refineries in the range of $300 million to $400 million.
  *Both refineries combined processed an average of 412,000 bbls/d of crude
    oil in 2012, resulting in 433,000 bbls/d of refined product output, which
    was 3% higher than in 2011.
  *Total combined heavy crude oil processing capacity at the company's
    refineries increased to between 235,000 bbls/d and 255,000 bbls/d with the
    completion of the CORE project at the Wood River Refinery in late 2011.
    The CORE project has enhanced the company's ability to further integrate
    its growing bitumen production.
  *The amount of Canadian heavy oil processed in 2012 increased 57% to
    198,000 bbls/d.
  *Refinery crude utilization rates averaged 91% in 2012.

                      Reserves and Contingent Resources

All of Cenovus's reserves and resources are evaluated each year by independent
qualified reserves evaluators.

  *At year-end 2012, Cenovus had proved reserves of nearly 2.2 billion BOE,
    an increase of 12% compared with 2011.
  *Proved bitumen reserves increased 18% in 2012 compared with 2011, to more
    than 1.7 billion bbls, while proved plus probable bitumen reserves grew
    nearly 23% to approximately 2.4 billion bbls. This increase was primarily
    due to regulatory and partner approval of the company's Narrows Lake oil
    sands project and substantial reserves additions at Foster Creek and
    Christina Lake. The reserves additions at Christina Lake were due to
    increased well density and improved SOR performance. At Foster Creek the
    reserves additions were due to more efficient drainage of oil in the steam
  *Economic bitumen best estimate contingent resources increased to 9.6
    billion bbls, up approximately 17% from 2011. This increase is a result of
    Cenovus's extensive stratigraphic test well drilling program converting
    prospective resources to contingent resources. In addition, the
    independent evaluators recognized commercial SAGD feasibility in the
    Wabiskaw formation within the Greater Foster Creek Region and contingent
    resources on recently acquired oil sands assets in Alberta.
  *Proved light and medium oil reserves remained unchanged, while proved
    heavy oil reserves increased approximately 5% due to the ongoing expansion
    of the waterflood and polymer injection program at Pelican Lake. Natural
    gas reserves declined about 21% compared with 2011 as Cenovus continued to
    redirect capital to its oil assets. As expected, this has resulted in
    natural gas production outpacing reserves additions. Lower natural gas
    prices and the divestiture of a non-core property early in 2012 also
    contributed to lower natural gas reserves.
  *Cenovus's 2012 proved finding and development (F&D) costs, excluding
    changes in future development costs, were a competitive $9.04/BOE, up from
    $5.96/BOE in 2011 as capital spending increased and reserves additions
    decreased somewhat compared with 2011. The three-year average F&D costs
    were $6.10/BOE, excluding changes in future development costs.
  *Cenovus achieved production replacement of nearly 350% in 2012.
  *The overall proved reserves life index is approximately 23 years, a 5%
    increase compared with 2011. The magnitude of the company's bitumen assets
    is significant with a bitumen proved reserves life index of 52 years, down
    13% due to the company's rapidly increasing bitumen production. The
    conventional oil and NGLs proved reserves life is 12 years.

                        Proved reserves reconciliation
(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 recovery   265       17           13            29
Technical revisions               30        6           -2            51
Economic factors                  -         -           -             -58
Acquisitions                      -         -           1              1
Divestitures                      -         -           -             -59
Production^1                     -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 probable      2,393      289         171           1,293

^1Production used for the reserves reconciliation differs from reported
production as it includes Cenovus gas volumes provided to the FCCL Partnership
for steam generation, but does not include royalty interest production. See
the Advisory - Oil and Gas Information for more information about royalty
interest production.

                 Proved reserves costs^1
(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 Additions^2 (MMBOE)                 
Finding and Development                  333   366  1,075
Finding, Development and Acquisitions    334   366  1,076
Proved Reserves Costs^2 ($/BOE)                     
Finding and Development^3               9.04  5.96   6.10
Finding, Development and Acquisitions^4 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
^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 Resources^1 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 C$111.72/bbl
  *166 MMcf/d or approximately 32% of expected natural gas production hedged
    for 2013 at an average NYMEX price of US$4.64/Mcf, plus internal usage of
    approximately 135 MMcf/d of natural gas
  *no fixed price commodity hedges in place beyond 2013
  *approximately 49,200 bbls/d of heavy crude exposure hedged for 2013 at an
    average WCS differential to WTI of US$20.74/bbl
  *approximately 9,400 bbls/d of heavy crude exposure hedged for 2014 at an
    average WCS differential to WTI of US$20.13/bbl.

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
  *Operating earnings in 2012 were $866 million, or $1.14 per share diluted,
    compared with $1.2 billion, or $1.64 per share diluted, for the same
    period last year.
  *Earnings in 2012 reflected a non-cash goodwill impairment charge of
    approximately $0.52 per share related to the company's Suffield assets in
    southeast Alberta. This was primarily due to estimated declines in future
    natural gas prices.
  *Cenovus had a realized after-tax hedging gain of $250 million in 2012.
    Cenovus received an average realized price, including hedging, of
    $67.16/bbl for its oil in 2012, compared with $69.99/bbl during 2011. The
    average realized price, including hedging, for natural gas in 2012 was
    $3.56/Mcf, compared with $4.52/Mcf in 2011.
  *Cenovus recorded income tax expense of $783 million, giving the company an
    effective tax rate of 44%, a substantial increase from the 2011 effective
    rate of 33%. The increase is primarily due to the goodwill impairment,
    which is not deductible, and to a one-time tax charge related to a U.S.
    withholding tax of $68 million.
  *Cenovus's net earnings for the year were $993 million compared with
    approximately $1.5 billion in 2011. Net earnings were negatively impacted
    by lower commodity prices, the non-cash goodwill impairment, increased
    depreciation, depletion and amortization (DD&A) costs and lower unrealized
    after-tax risk management gains, partly offset by higher unrealized
    foreign exchange gains. The increased DD&A rates were due to higher future
    development costs associated with total proved reserves.
  *Capital investment during the year was nearly $3.4 billion, as planned.
    That was a 24% increase from $2.7 billion in 2011 as the company continued
    to advance development of its oil opportunities.
  *General and administrative (G&A) expenses were $352 million in 2012, which
    was less than the company's corporate guidance for the year. G&A expenses
    were 19% higher in 2012, compared with 2011, primarily due to increases in
    staffing, salaries and benefits, long-term incentive expense and office
    costs related to the continued growth of the company.
  *Over the long term, Cenovus continues to target a debt to capitalization
    ratio of between 30% and 40% and a debt to adjusted EBITDA ratio of
    between 1.0 and 2.0 times. At December 31, 2012, the company's debt to
    capitalization ratio was 32% and debt to adjusted EBITDA, on a trailing
    12-month basis, was 1.1 times.

                       Earnings reconciliation summary
(for the period ended December 31)              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
                                          First production Expected production
     Project phase      Regulatory status      target       capacity (bbls/d)
Foster Creek^1 A - E                                           120,000
 F                        Approved          Q3-2014F          45,000^2
 G                        Approved           2015F             40,000
 H                        Approved           2016F             40,000
 J                      Submit 2013F         2019F             50,000
 Future optimization                                         15,000
 Total capacity                                              310,000
Christina Lake^1 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
 Future optimization                                         12,000
 Total capacity                                              300,000
Narrows Lake^1                                                    
 A                       Approved           2017F             45,000
 B-C                     Approved            TBD              85,000
 Total Capacity                                             130,000
Grand Rapids            Submitted Q4-2011      2017F             180,000
Telephone Lake^3        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 (11:00a.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
  *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 resources  are those quantities of bitumen estimated, as of a
    given date, to be potentially recoverable from known accumulations using
    established technology or technology under development, but which are not
    currently considered to be commercially recoverable due to one or more
    contingencies. Contingencies may include such factors as economic, legal,
    environmental, political and regulatory matters or a lack of markets. It
    is also appropriate to classify as contingent resources the estimated
    discovered recoverable quantities associated with a project in the early
    evaluation stage. Contingent resources are further classified in
    accordance with the level of certainty associated with the estimates and
    may be sub-classified based on project maturity and/or characterized by
    their economic status. The McDaniel estimates of contingent resources have
    not been adjusted for risk based on the chance of development.
  *Economic contingent resources  are those contingent resources that are
    currently economically recoverable based on specific forecasts of
    commodity prices and costs.
  *Economic contingent resources are estimated using volumetric calculations
    of the in-place quantities, combined with performance from analog
    reservoirs. Existing SAGD projects that are producing from the
    McMurray-Wabiskaw formations are used as performance analogs at Foster
    Creek and Christina Lake. Other regional analogs are used for contingent
    resources estimation in the Cretaceous Grand Rapids formation at the Grand
    Rapids property in the Pelican Lake Region, in the McMurray formation at
    the Telephone Lake property in the Borealis Region and in the Clearwater
    formation in the Foster Creek Region.
  *Contingencies which must be overcome to enable the reclassification of
    contingent resources as reserves can be categorized as economic,
    non-technical and technical. The Canadian Oil and Gas Evaluation Handbook
    identifies non-technical contingencies as legal, environmental, political
    and regulatory matters or a lack of markets. Technical contingencies
    include available infrastructure and project justification. The
    outstanding contingencies applicable to our disclosed contingent resources
    do not include economic contingencies. Our bitumen contingent resources
    are located in four general regions: Foster Creek, Christina Lake,
    Borealis and Greater Pelican. Further information in respect of
    contingencies faced in these four regions is included in our Annual
    Information Form.
  *Best estimate is considered to be the best estimate of the quantity of
    resources that will actually be recovered. It is equally likely that the
    actual remaining quantities recovered will be greater or less than the
    best estimate. Those resources that fall within the best estimate have a
    50 percent probability that the actual quantities recovered will equal or
    exceed the estimate.

Barrels of Oil Equivalent Certain natural gas volumes have been converted to
barrels of oil equivalent (BOE) on the basis of six Mcf to one bbl. BOE may be
misleading, particularly if used in isolation. A conversion ratio of one bbl
to six Mcf is based on an energy equivalency conversion method primarily
applicable at the burner tip and does not represent value equivalency at the

Finding and Development Costs Finding and development costs disclosed in this
news release and used for calculating our recycle ratio do not include the
change in estimated future development costs. Cenovus uses finding and
development costs without changes in estimated future development costs as an
indicator of relative performance to be consistent with the methodology
accepted within the oil and gas industry.

Finding and development costs for proved reserves, excluding the effects of
acquisitions and dispositions but including the change in estimated future
development costs were $25.48/BOE for the year ended December 31, 2012,
$13.99/BOE for the year ended December 31, 2011 and averaged $16.35/BOE for
the three years ended December 31, 2012. Finding and development costs for
proved plus probable reserves, excluding the effects of acquisitions and
dispositions but including the change in estimated future development costs
were $20.04/BOE for the year ended December 31, 2012, $10.69/BOE for the year
ended December 31, 2011 and averaged $14.27/BOE for the three years ended
December 31, 2012. These finding and development costs were calculated by
dividing the sum of exploration costs, development costs and changes in future
development costs in the particular period by the reserves additions (the sum
of extensions and improved recovery, discoveries, technical revisions and
economic factors) in that period. The aggregate of the exploration and
development costs incurred in a particular period and the change during that
period in estimated future development costs generally will not reflect total
finding and development costs related to reserves additions for that period.

Net Asset Value With respect to the particular year being valued, the net
asset value (NAV) disclosed herein is based on the number of issued and
outstanding Cenovus shares as at December 31 as reported in our Annual
Information Form and Form 40-F, plus the total dilutive effect of Cenovus
shares related to stock option programs or other contracts as disclosed in the
"Per Share Amounts" note to our annual Consolidated Financial Statements. We
calculate NAV as an average of (i) our average trading price for the month of
December, (ii) an average of net asset values published by external analysts
in December following the announcement of our budget forecast, and (iii) an
average of two net asset values based primarily on discounted cash flows of
independently evaluated reserves, resources and refining data and using
internal corporate costs, with one based on constant prices and costs and one
based on forecast prices and costs.

This document contains certain forward-looking statements and other
information (collectively "forward-looking information") about our current
expectations, estimates and projections, made in light of our experience and
perception of historical trends. Forward-looking information in this document
is identified by words such as "anticipate", "believe", "expect", "plan",
"forecast" or "F", "target", "project", "could", "focus", "vision", "goal",
"proposed", "scheduled", "outlook", "potential", "may" or similar expressions
and includes suggestions of future outcomes, including statements about our
growth strategy and related schedules, projected future value or net asset
value, forecast operating and financial results, planned capital expenditures,
expected future production, including the timing, stability or growth thereof,
expected future refining capacity, anticipated finding and development costs,
expected reserves and contingent and prospective resources estimates,
potential dividends and dividend growth strategy, anticipated timelines for
future regulatory, partner or internal approvals, future impact of regulatory
measures, forecasted commodity prices, future use and development of
technology and projected increasing shareholder value. Readers are cautioned
not to place undue reliance on forward-looking information as our actual
results may differ materially from those expressed or implied.

Developing forward-looking information involves reliance on a number of
assumptions and consideration of certain risks and uncertainties, some of
which are specific to Cenovus and others that apply to the industry generally.

The factors or assumptions on which the forward-looking information is based
include: assumptions inherent in our current guidance, available at
www.cenovus.com; our projected capital investment levels, the flexibility of
our capital spending plans and the associated source of funding; estimates of
quantities of oil, bitumen, natural gas and liquids from properties and other
sources not currently classified as proved; our ability to obtain necessary
regulatory and partner approvals; the successful and timely implementation of
capital projects or stages thereof; our ability to generate sufficient cash
flow from operations to meet our current and future obligations; and other
risks and uncertainties described from time to time in the filings we make
with securities regulatory authorities.

The risk factors and uncertainties that could cause our actual results to
differ materially, include: volatility of and assumptions regarding oil and
gas prices; the effectiveness of our risk management program, including the
impact of derivative financial instruments and the success of our hedging
strategies; the accuracy of cost estimates; fluctuations in commodity prices,
currency and interest rates; fluctuations in product supply and demand; market
competition, including from alternative energy sources; risks inherent in our
marketing operations, including credit risks; maintaining desirable ratios of
debt to adjusted EBITDA as well as debt to capitalization; our ability to
access various sources of debt and equity capital; accuracy of our reserves,
resources and future production estimates; our ability to replace and expand
oil and gas reserves; our ability to maintain our relationship with our
partners and to successfully manage and operate our integrated heavy oil
business; reliability of our assets; potential disruption or unexpected
technical difficulties in developing new products and manufacturing processes;
refining and marketing margins; potential failure of new products to achieve
acceptance in the market; unexpected cost increases or technical difficulties
in constructing or modifying manufacturing or refining facilities; unexpected
difficulties in producing, transporting or refining of crude oil into
petroleum and chemical products; risks associated with technology and its
application to our business; the timing and the costs of well and pipeline
construction; our ability to secure adequate product transportation; changes
in the regulatory framework in any of the locations in which we operate,
including changes to the regulatory approval process and land-use
designations, royalty, tax, environmental, greenhouse gas, carbon and other
laws or regulations, or changes to the interpretation of such laws and
regulations, as adopted or proposed, the impact thereof and the costs
associated with compliance; the expected impact and timing of various
accounting pronouncements, rule changes and standards on our business, our
financial results and our consolidated financial statements; changes in the
general economic, market and business conditions; the political and economic
conditions in the countries in which we operate; the occurrence of unexpected
events such as war, terrorist threats and the instability resulting therefrom;
and risks associated with existing and potential future lawsuits and
regulatory actions against us.

Readers are cautioned that the foregoing lists are not exhaustive and are made
as at the date hereof. For a full discussion of our material risk factors, see
"Risk Factors" in our most recent Annual Information Form/Form 40-F, "Risk
Management" in our current MD&A and risk factors described in other documents
we file from time to time with securities regulatory authorities, all of which
are available on SEDAR at www.sedar.com, EDGAR at www.sec.gov and our website
at www.cenovus.com.

TM denotes a trademark of Cenovus Energy Inc.

Cenovus Energy Inc.

Cenovus Energy Inc. is a Canadian integrated oil company. It is committed to
applying fresh, progressive thinking to safely and responsibly unlock energy
resources the world needs. Operations include oil sands projects in northern
Alberta, which use specialized methods to drill and pump the oil to the
surface, and established natural gas and oil production in Alberta and
Saskatchewan. The company also has 50% ownership in two U.S. refineries.
Cenovus shares trade under the symbol CVE, and are listed on the Toronto and
New York stock exchanges. Its enterprise value is approximately $30 billion.
For more information, visit www.cenovus.com.

Find Cenovus on Facebook, Twitter, Linkedin and YouTube.

SOURCE Cenovus Energy Inc.

Video with caption: "Brian Ferguson speaks to Cenovus's 2012 earnings". Video
available at:

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:

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:

Image with caption: "Cenovus's Foster Creek oil sands operation in northern
Alberta (CNW Group/Cenovus Energy Inc.)". Image available at:



Paul Gagne
Specialist, Investor Relations

Bill Stait
Senior Analyst, Investor Relations

Graham Ingram
Senior Analyst, Investor Relations

Rhona DelFrari
Director, Media Relations

Brett Harris
Senior Advisor, Media Relations
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