Cenovus oil sands production increases 25% in 2014

Proved bitumen reserves up 7%

  • Combined oil sands production averaged more than 128,000 barrels per day (bbls/d) net in 2014, up 25% from 2013.
  • Non-fuel operating costs per barrel at the company's oil sands projects declined 14% compared with the previous year.
  • Total oil production averaged more than 203,000 bbls/d net, up 14% from 2013.
  • Capital investment was $3.1 billion, 6% lower than in 2013.
  • Cash flow was $3.5 billion, a 4% decrease compared with 2013. Rising oil sands production and higher average prices for heavy crude oil were more than offset by the impact of lower realized margins in Cenovus's refining business.
  • In 2014, the company received regulatory approval for its Grand Rapids and Telephone Lake oil sands projects and its Foster Creek phase J expansion.
  • Production replacement was 193% due to strong growth in proved reserves. Proved year-end bitumen reserves were nearly two billion barrels (bbls), up 7% from 2013.

"We had strong operating performance in our oil sands and conventional businesses in 2014, with significant growth in oil sands production and additions to our portfolio of regulatory-approved projects," said Brian Ferguson, Cenovus President & Chief Executive Officer. "With low oil prices expected to persist through 2015, we plan to continue building our production capacity, but at a slower pace, focusing on expansion projects at Foster Creek and Christina Lake that are already well advanced."




Production & financial summary

(for the period ended December 31)

Production (before royalties)

2014

Q4

2013

Q4

% change

2014

Full Year

2013

Full Year

% change

Oil sands (bbls/d)

142,213

113,890

25

128,195

102,500

25

Conventional oil1 (bbls/d)

73,964

74,853

-1

75,298

76,775

-2

Total oil (bbls/d)

216,177

188,743

15

203,493

179,275

14

Natural gas (MMcf/d)

479

514

-7

488

529

-8

Financial

($ millions, except per share amounts)







Cash flow2

401

835

-52

3,479

3,609

-4


Per share diluted

0.53

1.10


4.59

4.76


Operating earnings2

-590

212

-378

633

1,171

-46


 Per share diluted

-0.78

0.28


0.84

1.55


Net earnings

-472

-58

-714

744

662

12


Per share diluted

-0.62

-0.08


0.98

0.87


Capital investment

786

898

-12

3,051

3,262

-6








1 Includes natural gas liquids (NGLs).

2 Cash flow and operating earnings are non-GAAP measures as defined in the Advisory.
See also the earnings reconciliation summary in the operating earnings table.

CALGARY, Feb. 12, 2015 /CNW/ - Cenovus Energy Inc. (TSX: CVE) (NYSE: CVE) achieved solid production growth in 2014, driven by strong performance at its oil sands projects in northern Alberta. In addition, while the average benchmark price for Brent crude and West Texas Intermediate (WTI) decreased year over year, the company's upstream operations benefited from higher average prices for its heavy crude oil sold as Western Canadian Select (WCS). These factors, along with a weakening in the Canadian dollar versus the U.S. dollar, contributed to 19% higher upstream operating cash flow compared with 2013. This increase was more than offset by a sharp decline in operating cash flow from refining, largely due to lower average market crack spreads and higher heavy crude oil feedstock costs. Cenovus also increased its reserves base in 2014, achieving 193% production replacement.

"These are challenging times for the oil and gas industry," said Ferguson. "Cenovus is taking steps to ensure we remain strong during this market downturn. We have a solid foundation supported by great assets that provide us with the opportunity to create long-term value for investors."

In 2014, Cenovus achieved 25% production growth from its Christina Lake and Foster Creek oil sands operations, averaging more than 128,000 bbls/d net (256,000 bbls/d gross). Oil sands production volumes exceeded the company's full-year guidance by approximately 4,000 bbls/d net to Cenovus. Christina Lake production increased 40% to average about 69,000 bbls/d net after expansion phase E reached design capacity in early 2014. The facility also achieved a consistently high utilization rate for the year.

Foster Creek production averaged more than 59,000 bbls/d net in 2014, up 11% from the previous year. The production increase was the result of improved plant performance, continued optimization efforts and increased production from wells using Cenovus's Wedge WellTM technology. The company achieved first production from the phase F wells in September. Phase F, which added 30,000 bbls/d of gross production capacity, was producing approximately 4,000 bbls/d net (8,000 bbls/d gross) at the end of the year.

"We're pleased with the strong performance of our oil sands projects. Both Christina Lake and Foster Creek delivered reliable production with lower non-fuel operating costs per barrel and improved safety performance compared with 2013," said John Brannan, Executive Vice-President & Chief Operating Officer. "During this current period of lower oil prices, we're focusing on achieving additional cost savings to help keep our projects among the most cost efficient in the industry."

Cash flow was $3.5 billion in 2014, down 4% from the previous year, primarily due to an 82% decrease in operating cash flow from refining. In the fourth quarter of 2014, benchmark crude oil prices dropped sharply, and a narrowing of the Brent-WTI price differential contributed to lower average market crack spreads for the year. In addition, Cenovus's refining feedstock cost advantage - the price differential between WCS and WTI - narrowed in 2014 compared with the previous year, which increased heavy crude oil feedstock costs. As well, in the fourth quarter, refining operating cash flow was negatively impacted by an inventory writedown of $110 million and a $163 million adjustment related to accounting policy differences between Canada and the U.S. These adjustments were related to the decline in refined product and crude oil prices late in 2014.

Cenovus's operating and net earnings were negatively affected in 2014 by a $497 million non-cash goodwill impairment associated with Pelican Lake. The impairment was caused by a decline in forecast crude oil prices as well as a slowing of the development plan at Pelican Lake. There were no goodwill impairments in 2013. Cenovus also had non-cash asset impairments of $151 million related to tight oil exploration activities as well as to property, plant and equipment.

Cenovus had free cash flow of $428 million in 2014, 23% higher than in 2013, after capital investment of approximately $3.1 billion.

"We ended 2014 in a solid financial position with approximately $900 million in cash and cash equivalents on our balance sheet and debt ratios well within our target ranges," said Ferguson. "In the current challenging oil price environment, we're reducing capital spending in order to help preserve our financial resilience. As well, we have additional flexibility to further reduce capital spending if oil prices continue to fall or remain low for an extended period."

Cenovus is undertaking various measures to reduce its costs, including an expected 15% staff reduction, the bulk of which will come from its contract workforce. Employee salary increases have also been suspended for 2015 and the company is significantly reducing its discretionary spending, including spending on travel, conferences, offsite meetings and information technology upgrades.

Continued additions to reserves
Cenovus continued to add to its reserves in 2014. Proved bitumen reserves increased 7% in the year to almost two billion bbls, and proved plus probable bitumen reserves increased 30% to 3.3 billion bbls. Total proved reserves gained 4%, while total proved plus probable reserves increased 22%, according to the company's independent reserves and contingent resources evaluation. As a result of the large growth in proved plus probable bitumen reserves, economic bitumen best estimate contingent resources declined approximately 5% to 9.3 billion bbls from 2013.

Maximizing shareholder value
Cenovus has been evaluating opportunities to crystalize value for shareholders from its existing portfolio of assets. The options available to the company to maximize the value of its fee lands include a possible sale or initial public offering. Cenovus is market-ready to pursue various potential options with respect to its fee lands when the timing presents itself. In 2014, royalty interest production from these conventional oil and natural gas properties provided approximately 7,600 barrels of oil equivalent per day (BOE/d). This resulted in operating cash flow of about $150 million for Cenovus.

Oil Projects

Daily production1

(Before royalties)

(Mbbls/d)

2014

2013

2012


Full

Year

Q4

Q3

Q2

Q1

Full

Year

Q4

Q3

Q2

Q1

Full

Year

Oil sands













Christina Lake

69

74

68

68

66

49

61

53

38

44

32


Foster Creek

59

68

57

57

55

53

52

49

55

56

58

Oil sands total

128

142

125

125

120

103

114

102

94

100

90

Conventional oil













Pelican Lake

25

26

24

25

25

24

25

25

24

24

23


Weyburn

16

16

16

16

16

16

16

16

16

17

16


Other conventional2

34

32

34

36

36

36

34

34

37

39

37

Conventional total

75

74

74

77

76

77

75

75

77

80

76

Total oil

203

216

199

202

197

179

189

177

171

180

165

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 production growth. The two operations currently producing, Christina Lake and Foster Creek, use steam-assisted gravity drainage (SAGD), which involves drilling into the reservoir and injecting steam at low pressures to soften the thick oil so it can be pumped to the surface. Cenovus has a third major oil sands project under initial development at Narrows Lake, which is part of the Christina Lake region. These projects are operated by Cenovus and jointly owned with ConocoPhillips. Cenovus has a significant opportunity to deliver increased shareholder value over the long term through production growth from several identified emerging projects and additional future developments.

Christina Lake

Production

  • Production at Christina Lake averaged 69,023 bbls/d net in 2014, 40% higher than in 2013, primarily due to phase E reaching design capacity in the second quarter. Average production levels for the year ran slightly above Christina Lake's total gross design capacity and exceeded the company's expectations for 2014. In the fourth quarter, Christina Lake produced an average of 73,836 bbls/d net, an increase of 20% from the same period in 2013. Christina Lake continued to perform well in January with production averaging almost 77,000 bbls/d.
  • The steam to oil ratio (SOR) was 1.8 for 2014, similar to 2013.
  • Total operating costs at Christina Lake were better than the company's expectations at $11.20/bbl for the year, a 10% decline from $12.47/bbl in 2013 and below its 2014 guidance of $12.00/bbl. The decrease was primarily due to increased production and a decline in fluid, waste handling and trucking costs. Fuel costs increased $0.62/bbl due to a rise in natural gas prices, partially offset by a decrease in per-barrel fuel consumption.
  • Non-fuel operating costs for 2014 were $7.55/bbl, a 20% decline from $9.44/bbl in 2013.
  • The netback the company received for its Christina Lake oil rose 33% to $42.44/bbl in 2014 compared with 2013, due to an increase in the full year average realized crude oil sales price and lower per-barrel operating costs.

Expansions

  • The company continued construction at Christina Lake phases F and G in 2014. Phase F is well advanced, and Cenovus plans to continue building the project in 2015. First oil from phase F is expected in the second half of 2016. Due to the substantial decline in crude oil prices, construction work on phase G has been deferred to preserve cash.
  • Cenovus expects to continue to progress its plant optimization project at Christina Lake, with incremental production expected in the fourth quarter of 2015.
  • In 2014, total capital investment at Christina Lake was $794 million, 15% higher compared with the previous year. Most of the investment was focused on expansion phases F and G, phase E well pad and facility construction as well as sustaining well programs that included the use of Cenovus's Wedge WellTM technology. Capital was also directed to the plant optimization program.

Foster Creek

Production

  • Foster Creek production exceeded the company's guidance for the year, averaging 59,172 bbls/d net in 2014, 11% higher than in 2013. The increase was primarily due to improved performance at the operation's facilities, optimization efforts and increased production from wells using the company's Wedge WellTM technology. Fourth quarter production was 68,377 bbls/d net, up 30% compared with the same period in 2013. The strong operational performance continued in January with production averaging approximately 72,000 bbls/d.
  • Phase F is ramping up as expected and ended the year with production of approximately 4,000 bbls/d net (8,000 bbls/d gross). Phase F has a design capacity of 30,000 bbls/d of gross production. Production is expected to ramp up over a period of 18 months from first oil, which was achieved last September.
  • The SOR at Foster Creek was 2.6 in 2014, compared with 2.5 in 2013. The SOR is expected to range between 2.6 and 3.0 while expansion phases F and G are ramping up. After ramp up, the SOR is expected to drop below 2.5.
  • Total operating costs at Foster Creek were 5% higher than in 2013 but were lower than the company's forecast, largely due to better than expected production volumes and SOR coming in at the low end of guidance. Operating costs for 2014 averaged $16.55/bbl compared with $15.77/bbl in 2013 and Cenovus's 2014 guidance of $17.50/bbl. Fuel costs had a significant impact on per-unit operating costs at Foster Creek in 2014, increasing $1.58/bbl, or 55% compared with 2013. The increase was due to higher natural gas prices and increased consumption compared with the previous year.
  • Non-fuel operating costs were down 6% to $12.09/bbl compared with $12.89/bbl in 2013, reflecting the increased production volumes.
  • The netback the company received for its Foster Creek crude oil production was $44.95/bbl in 2014, a slight increase from the previous year. This was largely due to the higher average sales price the company received for its crude oil in 2014 compared with 2013.

Expansions

  • Capital investment in 2014 was $796 million, similar to 2013. Investment during the year was focused on the completion of phase F, the construction of phases G and H, the drilling of sustaining wells and operational improvement projects.
  • Cenovus plans to continue advancing phase G in 2015 and anticipates first oil in the first half of 2016. Due to the significant decrease in crude oil prices, construction work on phase H has been deferred to preserve cash.
  • In the fourth quarter of 2014, Cenovus received regulatory approval for phase J, which could add approximately 50,000 bbls/d of gross production capacity.

Narrows Lake

  • Engineering, procurement and construction work for phase A progressed in 2014.
  • Cenovus invested $175 million at Narrows Lake, compared with $152 million in 2013.
  • The company believes Narrows Lake has the potential to achieve total production capacity of 130,000 bbls/d. Narrows Lake is expected to be the industry's first project to use a solvent aided process (SAP) on a commercial scale, combining butane with steam to improve oil recovery.
  • In response to the substantial decline in crude oil prices, Cenovus has decided to defer further work at Narrows Lake to preserve cash. The company plans to take advantage of the slower pace of development to optimize its engineering and execution strategy with a focus on achieving the lowest capital efficiencies for the Narrows Lake project.

Emerging projects

Grand Rapids

  • Cenovus continues to operate a SAGD pilot project at Grand Rapids with two producing well pairs. The third pilot well pair is expected to be completed in early March, and steam circulation is expected to begin in the second quarter of 2015. It is anticipated that data from these well pairs will be used to help determine the company's development plan for Grand Rapids, subject to a recovery in crude oil prices.
  • The company has almost completed the dismantling and moving of an existing SAGD facility that Cenovus purchased in 2014 and plans to relocate to the Grand Rapids site once the development plan has been finalized. The project has received regulatory approval for total production capacity of 180,000 bbls/d.
  • Capital investment was $63 million at Grand Rapids in 2014, compared with $39 million in 2013.

Telephone Lake

  • Cenovus received approval during the fourth quarter from the Alberta Energy Regulator for its Telephone Lake oil sands project located in northern Alberta.
  • In 2014, the company invested $112 million at Telephone Lake, compared with $93 million in 2013. The 2014 investment program included the drilling of 45 stratigraphic test wells. Most of the planned development at Telephone Lake in 2015 has been deferred to preserve cash. The company continues to review development options to help ensure the lowest capital efficiencies possible for the project.

Conventional Oil


Cenovus has tight oil opportunities in Alberta as well as the established Weyburn operation in Saskatchewan that uses carbon dioxide injection to enhance oil recovery. Cenovus also produces conventional heavy oil from the Wabiskaw formation at its 100%-owned Pelican Lake operation in northern Alberta. Cenovus has been injecting polymer since 2006 to enhance production from the reservoir, which is also under waterflood.

  • Total conventional oil production declined 2% to 75,298 bbls/d in 2014 compared with the previous year. Increased production from the company's successful horizontal well program in southern Alberta and a slight rise in Pelican Lake production was more than offset by expected natural declines and the sale of the company's Lower Shaunavon asset in 2013 as well as a portion of its Bakken and Wainwright properties in 2014. Together, these assets produced approximately 2,200 bbls/d in 2014 compared with approximately 5,200 bbls/d in 2013. Total fourth quarter production declined 1% to 73,964 bbls/d compared with the same quarter in 2013. January production averaged more than 75,000 bbls/d.
  • Production at Pelican Lake in 2014 averaged 24,924 bbls/d, 3% higher compared with a year earlier due to increased response from the polymer flood program and additional infill wells coming online, partially offset by a planned turnaround. Fourth quarter production rose 6% to 25,906 bbls/d compared with the same period a year earlier.
  • Production from Weyburn averaged 16,196 bbls/d net compared with 16,361 bbls/d net in 2013. Fourth quarter production declined 2% to 16,050 bbls/d compared with the same period a year earlier.
  • As previously announced, Cenovus has suspended the majority of its conventional drilling program in southern Alberta and Saskatchewan for 2015. This suspension, along with the asset dispositions, is expected to reduce production to between 66,000 bbls/d and 70,000 bbls/d for 2015 compared with approximately 75,000 bbls/d in 2014.
  • Operating costs for Cenovus's conventional oil operations were $18.81/bbl, a 7% increase from $17.61/bbl in 2013. The increase was primarily due to higher costs for chemicals, lower production volumes, increased expenses for fluid, waste handling and trucking as well as repairs and maintenance. This was partially offset by lower electricity costs.
  • Cenovus invested $812 million in its conventional oil assets in 2014, compared with approximately $1.2 billion a year earlier. These assets generated $548 million of operating cash flow in excess of capital investment in 2014.

Natural Gas

Daily production

(Before royalties)

(MMcf/d)

2014

2013

2012


Full

Year

Q4

Q3

Q2

Q1

Full

Year

Q4

Q3

Q2

Q1

Full

Year

Natural gas

488

479

489

507

476

529

514

523

536

545

594

Cenovus has a solid base of established, reliable natural gas properties in Alberta. These properties are managed as financial assets, not production assets, generating operating cash flow well in excess of their ongoing capital investment requirements. The natural gas business also acts as an economic hedge against price fluctuations because natural gas fuels the company's oil sands and refining operations.

  • Natural gas production averaged 488 million cubic feet per day (MMcf/d) in 2014, down 8% compared with the previous year, driven by expected natural declines and the company's decision to focus capital investment on its crude oil assets. Production was 479 MMcf/d in the fourth quarter of 2014, a decline of 7% from the same period in 2013.
  • The company invested $34 million in its natural gas assets in 2014, up from $27 million in 2013. The assets generated $519 million in operating cash flow in excess of capital investment in 2014.
  • Cenovus's average realized sales price for natural gas, including hedges, was $4.41 per thousand cubic feet (Mcf) compared with $3.52 per Mcf in 2013.
  • Higher cash flow from natural gas more than offset the increase in fuel costs at Cenovus's operations in 2014 because the company produced more natural gas than it consumed at its oil sands and refining operations. Natural gas use at Cenovus's operations is forecast to be about 180 MMcf/d in 2015.

Market Access

Cenovus is concentrating on finding new customers in North America and around the world and is working to enhance its ability to move its oil to these customers. The company continues to support proposed pipelines to Canada's east and west coasts as well as to the U.S. to provide additional shipping capacity for its expected production growth. To complement its pipeline strategy, Cenovus takes a portfolio approach to marketing and transportation that also includes rail.

  • Cenovus now has 30,000 bbls/d of crude oil rail loading capacity. On average, the company transported approximately 10,000 bbls/d of crude oil by rail in 2014 to markets in Canada and the U.S., including 47 unit train shipments. Cenovus also began taking delivery of 825 coiled and insulated rail cars in the fourth quarter to further support its rail strategy.
  • As part of its oil sands partnership with ConocoPhillips, Cenovus is responsible for marketing the total gross production from its Christina Lake and Foster Creek projects. To ensure adequate capacity for expected future production growth from these projects, the company has been securing additional pipeline capacity. This includes a long-term transportation agreement signed with Inter Pipeline (IPL) to ship up to 500,000 bbls/d of oil blend via the recently completed Cold Lake pipeline expansion. Deliveries on the Cold Lake expansion began in early 2015.
  • Cenovus also has 50,000 bbls/d of contracted capacity on Enbridge's Flanagan South system, increasing to 75,000 bbls/d in 2018. Initial deliveries on Flanagan South, which provides additional pipeline access to the U.S. Gulf Coast, began in December.
  • In combination, this additional transportation capacity via rail and on the Cold Lake and Flanagan South pipeline systems is expected to increase per-barrel transportation costs at Foster Creek and Christina Lake to about $8.00/bbl in 2015 from approximately $3.00/bbl in 2014. Longer term, these transportation initiatives should allow Cenovus to capture higher pricing for a portion of its production. The increase in transportation costs on the Cold Lake pipeline is expected to be temporary. As the company's planned expansion phases come online at Foster Creek, incremental production growth is expected to reduce per-barrel costs.
  • Cenovus continues to use its firm service capacity of 11,500 bbls/d on the existing Trans Mountain pipeline, giving the company access to the West Coast.
  • The company has also committed to move 200,000 bbls/d on TransCanada's proposed Energy East pipeline, has additional shipping capacity of 175,000 bbls/d on planned pipelines to the West Coast and has 75,000 bbls/d of committed capacity on TransCanada's proposed Keystone XL system.

Refining

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 to discounted crude oil prices by providing lower feedstock costs to the Wood River Refinery in Illinois and the Borger Refinery in Texas, which Cenovus jointly owns with the operator, Phillips 66. 

Financial

  • Operating cash flow from refining was $201 million for the year, an 82% decline from $1.1 billion in 2013. The year-over-year decline was largely due to significant changes in benchmark crude oil prices in the fourth quarter of 2014. A narrowing of the Brent-WTI price differential contributed to lower average market crack spreads for the year. In addition, refining margins were negatively impacted by higher heavy crude oil feedstock costs.
  • Refining results were also affected by an inventory writedown of $110 million recorded in the fourth quarter of 2014, reflecting the significant decline in forecast refined product and crude oil prices.
  • Cenovus's refining operating cash flow is calculated on a first-in, first-out (FIFO) inventory accounting basis. Using the last-in, first-out (LIFO) accounting method employed by most U.S. refiners, Cenovus's operating cash flow from refining would have been approximately $101 million higher in 2014, excluding the impact of inventory writedowns. In the fourth quarter, the company's operating cash flow from refining would have been approximately $163 million higher using the LIFO accounting method.
  • Capital investment was $162 million compared with $106 million a year earlier.

Operations

  • Cenovus's refineries processed an average of 423,000 bbls/d gross in 2014, a 4% decrease from 2013, due to planned and unplanned outages in 2014.
  • Together, the two refineries processed an average of 199,000 bbls/d gross of heavy oil in 2014, compared with 222,000 bbls/d gross in 2013. The decline was primarily a result of the decision to process higher volumes of medium crude oil due to more favourable economics.
  • The refineries produced an average of 445,000 bbls/d gross of refined products in 2014, a 4% decrease from the previous year.

Reserves and Contingent Resources

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

  • At year-end 2014, Cenovus had total proved reserves of 2.4 billion BOE, an increase of 4% compared with 2013. 
  • Proved bitumen reserves for 2014 were up 7% compared with 2013 to approximately two billion bbls, while proved plus probable bitumen reserves increased 30% to approximately 3.3 billion bbls. This increase in proved reserves was primarily due to an area expansion at Foster Creek and improved performance at Christina Lake. These increases, plus additional probable reserves contained in the Foster Creek area expansion and the significant area expansion at Christina Lake, drove the growth in proved plus probable reserves.
  • Economic bitumen best estimate contingent resources fell to 9.3 billion bbls, declining approximately 5% from 2013 as a result of significant conversions to proved and probable reserves. For additional information on the company's contingent resources, see Oil and Gas Information in the Advisory.
  • Proved light and medium oil plus natural gas liquids (NGLs) reserves increased 4% to 120 million bbls, while proved heavy oil reserves declined approximately 13% due to the deferral of drilling at Pelican Lake and the sale of part of the Wainwright property. Natural gas proved reserves declined about 8% compared with 2013 as Cenovus continued to focus capital on developing its oil assets. As expected, this reallocation of capital has resulted in natural gas production outpacing reserves additions.
  • Cenovus's 2014 proved finding and development (F&D) costs, excluding changes in future development costs, were $13.39/BOE, down from $14.51/BOE in 2013, due to reduced capital spending while maintaining reserves additions. The three-year average F&D costs were $11.77/BOE, excluding changes in future development costs. The 2014 recycle ratio was 2.8 times.
  • For Cenovus's proved reserves, the IQREs have estimated the company's total future development costs to be $8.44/BOE, or $6.55/BOE on a de-escalated basis.
  • Cenovus achieved production replacement of 193% in 2014.
  • The overall proved reserves life index is approximately 23 years. The magnitude of the company's bitumen assets is significant with a bitumen proved reserves life index of 42 years, down 14% due to the company's increasing bitumen production. The conventional oil and NGLs proved reserves life is approximately 11 years.

 Proved reserves reconciliation

(Before royalties)

Bitumen

(MMbbls)

Heavy Oil

(MMbbls)

Light & Medium

Oil & NGLs

(MMbbls)

Natural Gas &

CBM

(Bcf)

Start of 2014

1,846

179

115

865

Extensions & improved recovery

108

14

17

23

Technical revisions

63

(13)

1

98

Economic factors

0

0

0

(12)

Acquisitions

0

0

0

2

Divestitures

0

(10)

(1)

(5)

Production1

(47)

(14)

(12)

(175)

End of 2014

1,970

156

120

796

% Change

7

(13)

4

(8)

Developed

Undeveloped

238

1,732

116

40

98

22

792

4

Total proved

1,970

156

120

796

Total probable

1,330

123

46

260

Total proved plus probable

3,300

279

166

1,056

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)

2014

2013

3 Year

Capital Investment ($ millions)




Finding and Development

2,782

3,026

8,821

Finding, Development and Acquisitions

2,800

3,058

8,985

Proved Reserves Additions2 (MMBOE)




Finding and Development

208

208

749

Finding, Development and Acquisitions

208

208

751

Proved Reserves Costs2 ($/BOE)




Finding and Development3

13.39

14.51

11.77

Finding, Development and Acquisitions4

13.46

14.67

11.97

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.

Financial

Dividend
The Cenovus Board of Directors declared a first quarter dividend of $0.2662 per share, payable on March 31, 2015 to common shareholders of record as of March 13, 2015. Based on the February 11, 2015 closing share price on the Toronto Stock Exchange of $24.68, this represents an annualized yield of about 4.3%. Declaration of dividends is at the sole discretion of the Board. Cenovus's continued commitment to a meaningful dividend is an important aspect of its strategy to focus on increasing total shareholder return.

To help further support balance sheet flexibility, the company has approved an update to its dividend reinvestment plan (DRIP), which permits shareholders to automatically reinvest cash dividends paid on their common shares in additional common shares. Cenovus intends to offer shareholders who wish to take advantage of the DRIP a 3% discount to the average market price for its shares. The company plans to issue common shares under the DRIP from treasury.

Cash flow, earnings and capital investment

  • Cenovus generated $3.5 billion in cash flow for the year, 4% lower than in 2013, largely due to the significant change in benchmark crude oil prices in the fourth quarter of 2014. Between September 30, 2014 and December 31, 2014, Brent crude, WTI and WCS prices fell between 40% and 50%. On an annual basis, average Brent crude prices declined approximately 9% in 2014, compared with the previous year, while average WTI prices fell approximately 5% and WCS prices increased 1%.
  • Operating cash flow was $4.2 billion in 2014, a decline of 7% compared with 2013. Approximately $3.9 billion of that operating cash flow was generated by Cenovus's oil and natural gas producing assets in 2014. Operating cash flow from the company's refining business was $201 million.
  • For the year, operating cash flow in excess of capital invested was $36 million from crude oil production at the company's oil sands projects, $548 million from conventional oil, $519 million from natural gas and $39 million from refining.
  • Operating earnings were $633 million in 2014, a 46% decrease compared with 2013, primarily due to a $497 million, or $0.66/share, goodwill impairment. The goodwill impairment, associated with the company's Pelican Lake asset, is due to a decline in forecast benchmark crude oil prices and a slowing of the long-term development plan for the project.
  • The company also recorded an impairment on property, plant and equipment which totalled $65 million, or $0.06/share, including $52 million on equipment Cenovus doesn't plan to use in the future and doesn't expect to be able to sell for its carrying value. In addition, Cenovus wrote down the value of crude oil and refined product inventories by $131 million, or $0.11/share, the majority of which was in its refining segment, and had $86 million, or $0.08/share, in exploration expense. The majority of the exploration expense was related to a determination that certain tight oil exploration assets weren't commercially viable.
  • Cenovus's net earnings for the year were $744 million, an increase of 12% from the previous year.
  • Capital investment was $3.1 billion, a 6% decline from 2013. Approximately two-thirds of the investment was at the company's oil sands operations as it progressed expansion phases at Christina Lake and Foster Creek as well as construction at Narrows Lake. Most of the remaining capital investment was directed to the company's conventional oil business, which focused on tight oil development, facilities work and the expansion of the polymer flood at Pelican Lake.

Risk management, G&A expenses and financial ratios

  • In the fourth quarter, Cenovus added Brent fixed price contracts for the first half of 2015 of 1,000 bbls/d at an average price of $100.25/bbl and 6,000 bbls/d at US$65.03/bbl. The company also added natural gas AECO fixed price contracts for 149 MMcf/d at an average price of $3.86/Mcf.
  • In 2014, total realized gains on risk management were $66 million and unrealized gains were $596 million, driven by the decline in average crude oil and natural gas benchmark prices relative to Cenovus's contract prices.
  • Cenovus received an average realized price, including hedging, of $71.85/bbl for its oil. The average realized price for natural gas, including hedging, was $4.41/Mcf.
  • General and administrative (G&A) expenses were $3.49/BOE for the year, compared with $3.58/BOE in 2013 due to increased production volumes.
  • Over the long term, Cenovus continues to target a debt to capitalization ratio of between 30% and 40% and a debt to adjusted earnings before interest, taxes, depreciation and amortization (EBITDA) ratio of between 1.0 and 2.0 times. At December 31, 2014, the company's debt to capitalization ratio was 35% and debt to adjusted EBITDA, on a trailing 12-month basis, was 1.4 times.

Operating earnings1

(for the period ended December 31)

($ millions, except per share amounts)

2014

Q4

2013

Q4

2014

Full Year

2013

Full Year

Earnings (loss) before income tax

Add back (deduct):

(520)

(22)

1,195

1,094


Unrealized risk management (gains) losses2

(416)

219

(596)

415


Non-operating unrealized foreign exchange (gains) losses3

186

(39)

458

52


Realized foreign exchange loss on Partnership contribution

-

146

-

146


(Gains) losses on divestiture of assets

1

-

(156)

1

Operating earnings (loss), before income tax

(749)

304

901

1,708


Income tax expense (recovery)

(159)

92

268

537

Operating earnings

(590)

212

633

1,171

1 Operating earnings is a non-GAAP measure as defined in the Advisory.

2 The unrealized risk management (gains) losses include the reversal of unrealized (gains) losses recognized
in prior periods.

3 Includes unrealized foreign exchange (gains) losses on translation of U.S. dollar denominated notes issued
from Canada and the Partnership Contribution Receivable and foreign exchange (gains) losses on settlement
of intercompany transactions.

Conference Call Today
9 a.m. Mountain Time (11 a.m. Eastern Time)
Cenovus will host a conference call today, February 12, 2015, starting at 9 a.m. MT (11 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. A live audio webcast of the conference call will also be available via cenovus.com. The webcast will be archived for approximately 90 days.

ADVISORY
FINANCIAL INFORMATION

Basis of Presentation Cenovus reports financial results in Canadian dollars and presents production volumes on a net to Cenovus before royalties basis, unless otherwise stated. Cenovus prepares its financial statements in accordance with International Financial Reporting Standards (IFRS).

Non-GAAP Measures This news release contains references to non-GAAP measures as follows:

  • Operating cash flow is defined as revenues, less purchased product, transportation and blending, operating expenses, production and mineral taxes plus realized gains, less realized losses on risk management activities and is used to provide a consistent measure of the cash generating performance of the company's assets and improves the comparability of Cenovus's underlying financial performance between periods. Items within the Corporate and Eliminations segment are excluded from the calculation of operating cash flow.
  • Cash flow is defined as cash from operating activities excluding net change in other assets and liabilities and net change in non-cash working capital, both of which are defined on the Consolidated Statement of Cash Flows in Cenovus's interim and annual Consolidated Financial Statements.
  • Free cash flow is defined as cash flow less capital investment.
  • Operating earnings is used to provide a consistent measure of the comparability of our underlying financial performance between periods by removing non-operating items. Operating earnings is defined as earnings before income tax excluding gain (loss) on discontinuance, gain on bargain purchase, unrealized risk management gains (losses) on derivative instruments, unrealized foreign exchange gains (losses) on translation of U.S. dollar denominated notes issued from Canada and the Partnership Contribution Receivable, foreign exchange gains (losses) on settlement of intercompany transactions, gains (losses) on divestiture of assets, less income taxes on operating earnings.
  • Debt to capitalization and debt to adjusted EBITDA are two ratios that management uses to steward the company's overall debt position as measures of the company's overall financial strength. Debt is defined as short-term borrowings and long-term debt, including the current portion, excluding any amounts with respect to the partnership contribution payable and receivable. Capitalization is a non-GAAP measure defined as debt plus shareholders' equity. Adjusted EBITDA is defined as earnings before finance costs, interest income, income tax expense, depreciation, depletion and amortization, asset impairments, unrealized gain or loss on risk management, foreign exchange gains or losses, gains or losses on divestiture of assets and other income and loss, calculated on a trailing 12-month basis.

These measures have been described and presented in this news release in order to provide shareholders and potential investors with additional information regarding Cenovus's liquidity and its ability to generate funds to finance its operations. For further information, refer to Cenovus's most recent Management's Discussion & Analysis (MD&A) available at cenovus.com.

OIL AND GAS INFORMATION
The estimates of reserves and resources data and related information were prepared effective December 31, 2014 by independent qualified reserves evaluators ("IQREs"), based on the Canadian Oil and Gas Evaluation Handbook and in compliance with the requirements of National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities. Estimates are presented using McDaniel & Associates Consultants Ltd. ("McDaniel") January 1, 2015 price forecast. Cenovus holds significant fee title rights which generate production for the company's 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 Information
Best estimate is considered to be the best estimate of the quantity of resources that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. Those resources that fall within the best estimate have a 50% probability that the actual quantities recovered will equal or exceed the estimate. Contingent resources are those quantities of bitumen estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies may include such factors as economic, legal, environmental, political and regulatory matters or a lack of markets. It is also appropriate to classify as contingent resources the estimated discovered recoverable quantities associated with a project in the early evaluation stage. Contingent resources are further classified in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by their economic status. The McDaniel estimates of contingent resources have not been adjusted for risk based on the chance of development. There is no certainty that it will be commercially viable to produce any portion of the contingent resources.

Economic contingent resources are those contingent resources that are currently economically recoverable based on specific forecasts of commodity prices and costs. Economic contingent resources are estimated using volumetric calculations of the in-place quantities, combined with performance from analog reservoirs. Existing SAGD projects that are producing from the McMurray-Wabiskaw formations are used as performance analogs at Foster Creek and Christina Lake. Other regional analogs are used for contingent resources estimation in the Cretaceous Grand Rapids formation at the Grand Rapids property in the Pelican Lake region, in the McMurray formation at the Telephone Lake property in the Borealis region and in the Clearwater formation in the Foster Creek region.

Contingencies which must be overcome to enable the reclassification of contingent resources as reserves can be categorized as economic, non-technical and technical. The Canadian Oil and Gas Evaluation Handbook identifies non-technical contingencies as legal, environmental, political and regulatory matters or a lack of markets. Technical contingencies include available infrastructure and project justification. The outstanding contingencies applicable to our disclosed economic contingent resources do not include economic contingencies.

Our bitumen contingent resources are located in four general regions: Foster Creek, Christina Lake, Borealis and Greater Pelican. Further information in respect of contingencies faced in these four regions is included in our Annual Information Form.

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

Netbacks reported in this news release are calculated as set out in the AIF. Heavy oil prices and transportation and blending costs exclude the costs of purchased condensate, which is blended with heavy oil. For 2014, the cost of condensate on a per barrel of unblended crude oil basis was as follows: Christina Lake - $45.45 and Foster Creek - $42.01.

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 $31.65/BOE for the year ended December 31, 2014, $32.97/BOE for the year ended December 31, 2013 and averaged $29.27/BOE for the three years ended December 31, 2014. 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 $19.38/BOE for the year ended December 31, 2014, $40.85/BOE for the year ended December 31, 2013 and averaged $22.98/BOE for the three years ended December 31, 2014. 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.

FORWARD-LOOKING INFORMATION
This document contains certain forward-looking statements and other information (collectively "forward-looking information") about Cenovus's current expectations, estimates and projections, made in light of the company's 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", "projected",  "future", "could", "should", "focus", "proposed", "schedule", "potential", "capacity", "may", "strategy" or similar expressions and includes suggestions of future outcomes, including statements about: growth strategy and related schedules; projections contained in the company's 2015 guidance; anticipated finding and development costs; expected reserves and resources additions; forecast operating and financial results; planned capital expenditures; project capacities; expected future production, including the timing, stability or growth thereof; future cost savings and project costs, including relative to the industry; potential options with respect to maximizing the value of the company's royalty fee lands; forecast natural gas use at operations; expected SOR; expected increase in production capacity through optimization activity; operating cash flow relative to ongoing capital investment requirements for properties; expected future refining capacity; broadening market access; improving cost structures; dividend plans and dividend strategy, including with respect to the dividend reinvestment plan; anticipated timelines for future regulatory, partner or internal approvals; future impact of regulatory measures; forecasted commodity prices; future use and development of technology; targeted future debt to capitalization and debt to adjusted EBITDA; and projected shareholder value and total shareholder return. Readers are cautioned not to place undue reliance on forward-looking information as the company's actual results may differ materially from those expressed or implied.

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

The factors or assumptions on which the forward-looking information is based include: assumptions disclosed in Cenovus's current guidance, available at cenovus.com; projected capital investment levels, the flexibility of 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; the company's ability to obtain necessary regulatory and partner approvals; the successful and timely implementation of capital projects or stages thereof; the company's ability to generate sufficient cash flow from operations to meet the company's current and future obligations; and other risks and uncertainties described from time to time in the filings Cenovus makes with securities regulatory authorities.

2015 guidance, available at cenovus.com, is based on an average diluted number of shares outstanding of approximately 760 million. It assumes: Brent US$53.50/bbl, WTI US$50.50/bbl; Western Canada Select US$36.25/bbl; NYMEX US$3.00/MMBtu; AECO $2.70/GJ; Chicago 3-2-1 Crack Spread US$11.75/bbl; Exchange Rate of $0.83 US$/C$.

Underlying assumptions in Cenovus's calculation of supply costs include: price forecast and associated royalties, capital costs, operating expenses, reservoir performance and discount rates. The company's supply costs are estimated using these assumptions to generate a long-term WTI price that provides a project-specific after-tax rate of return of at least 9% on future capital investment.

The risk factors and uncertainties that could cause Cenovus's actual results to differ materially include: volatility of and assumptions regarding oil and gas prices; the effectiveness of the company's risk management program, including the impact of derivative financial instruments, the success of the company's hedging strategies and the sufficiency of the company's liquidity position; 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 the company's marketing operations, including credit risks; maintaining desirable ratios of debt to adjusted EBITDA as well as debt to capitalization; the company's ability to access various sources of debt and equity capital, generally, and on terms acceptable to Cenovus; changes in credit ratings applicable to Cenovus or any of its securities; changes to the company's dividend plans or strategy, inclduing the dividend reinvestment plan; accuracy of reserves, resources and future production estimates; Cenovus's ability to replace and expand oil and gas reserves; Cenovus's ability to maintain its relationships with its partners and to successfully manage and operate its integrated heavy oil business; reliability of the company's 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 crude oil into petroleum and chemical products; risks associated with technology and its application to Cenovus's business; the timing and the costs of well and pipeline construction; the company's ability to secure adequate product transportation, including sufficient crude-by-rail or other alternate transportation; changes in the regulatory framework in any of the locations in which Cenovus operates, 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 Cenovus's business,  financial results and its Consolidated Financial Statements; changes in the general economic, market and business conditions; the political and economic conditions in the countries in which Cenovus operates; 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 Cenovus.

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 Cenovus's most recent Annual Information Form/Form 40-F, "Risk Management" in Cenovus's current and annual MD&A and risk factors described in other documents Cenovus files from time to time with securities regulatory authorities, all of which are available on SEDAR at sedar.com, EDGAR at sec.gov and the company's website at cenovus.com.

TM denotes a trademark of Cenovus Energy Inc.

Cenovus Energy Inc.
Cenovus Energy Inc. is a Canadian integrated oil company. It is committed to applying fresh, progressive thinking to safely and responsibly unlock energy resources the world needs. Operations include oil sands projects in northern Alberta, which use specialized methods to drill and pump the oil to the surface, and established natural gas and oil production in Alberta and Saskatchewan. The company also has 50% ownership in two U.S. refineries. Cenovus shares trade under the symbol CVE, and are listed on the Toronto and New York stock exchanges. Its enterprise value is approximately $24 billion. For more information, visit cenovus.com.

Find Cenovus on Facebook, Twitter, LinkedIn, YouTube and Instagram.

SOURCE Cenovus Energy Inc.

Image with caption: "Steam generators at Cenovus's Foster Creek project in northern Alberta. The project uses a process called steam-assisted gravity drainage (SAGD) to produce oil, which involves drilling into the reservoir and injecting steam at a low pressure to soften the oil so it can be pumped to the surface. (CNW Group/Cenovus Energy Inc.)". Image available at: http://photos.newswire.ca/images/download/20150212_C8832_PHOTO_EN_12019.jpg

Image with caption: "Cenovus's Christina Lake project in northern Alberta uses steam-assisted gravity drainage (SAGD) to produce oil. The process involves drilling into the reservoir and injecting steam at a low pressure to soften the oil so it can be pumped to the surface. (CNW Group/Cenovus Energy Inc.)". Image available at: http://photos.newswire.ca/images/download/20150212_C8832_PHOTO_EN_12020.jpg

For further information: CENOVUS CONTACTS: Investor Relations, Susan Grey, Director, Investor Relations, 403-766-4751; Media: Brett Harris, Media Lead, 403-766-3420; Graham Ingram, Senior Analyst, Investor Relations, 403-766-2849; Reg Curren, Senior Media Advisor, 403-766-2004; Anna Kozicky, Senior Analyst, Investor Relations, 403-766-4277; General media line: 403-766-7751; Steve Murray, Senior Analyst, Investor Relations, 403-766-3382

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