EX-99.1

A news release disclosing the material change was issued by Cenovus Energy Inc. (“Cenovus”) on March 29, 2017 through the services of CNN.

On March 29, 2017, Cenovus entered into a purchase and sale agreement (the “Acquisition Agreement”) with ConocoPhillips Company and certain of its affiliates (collectively, “ConocoPhillips”) to acquire (the “Acquisition”): (i) ConocoPhillips’ 50% interest (the “FCCL Interest”) (being the remaining 50% interest that Cenovus does not already own) in FCCL Partnership (“FCCL”), the owner of the Foster Creek, Christina Lake and Narrows Lake oil sands projects in northeast Alberta (the “FCCL Assets”), and (ii) the majority of ConocoPhillips’ western Canadian conventional assets, including ConocoPhillips’ exploration and production assets and related infrastructure and agreements in the Elmworth-Wapiti, Kaybob-Edson and Clearwater operating areas (the “Elmworth-Wapiti Area”, “Kaybob-Edson Area” and the “Clearwater Area”, respectively) and other operating areas, and all of ConocoPhillips’ interest in petroleum and natural gas rights and oil sands leases within a certain area of mutual interest northwest of Foster Creek (the “Deep Basin Assets” and, together with the FCCL Assets, the “Assets”). The FCCL Interest and the Deep Basin Assets are to be acquired by Cenovus for total consideration of CA$17.7 billion, comprised of CA$14.1 billion cash (the “Cash Purchase Price”), and 208 million Common Shares (the “Consideration Shares” and, together with the Cash Purchase Price, the “Purchase Price”).

On March 29, 2017, Cenovus also entered into an agreement with a syndicate of underwriters (the “Underwriters”) co-led by RBC Capital Markets and J.P. Morgan pursuant to which the Underwriters agreed to purchase, on a bought deal basis, 187.5 million common shares of Cenovus (the “Common Shares”) at a price of CA$16.00 per Common Share, for aggregate gross proceeds of CA$3.0 billion (the “Offering”). In addition, Cenovus granted the Underwriters an over-allotment option, exercisable for a period of 30 days from closing of the Offering, to purchase up to an additional 28.125 million Common Shares at the Offering price. If the over-allotment option is exercised in full, the gross proceeds from the Offering will be CA$3.45 billion.

Pursuant to the Acquisition Agreement, Cenovus has agreed to acquire the Assets for the aggregate consideration of CA$17.7 billion, comprised of $14.1 billion in cash, and 208 million Common Shares. The Acquisition will have an effective date of January 1, 2017, and the date on which closing of the Acquisition occurs (the “Acquisition Closing Date”) is expected to be in the second quarter of 2017.

The Assets have forecast 2017 production of approximately 298,000 BOE/d. The Acquisition is immediately accretive to key metrics and, assuming the successful completion of a planned divestiture program, is expected to result in an 18% increase in 2018 adjusted funds flow per share compared with Cenovus’s original 2018 forecast.

A copy of the Acquisition Agreement, in redacted form, has been filed on SEDAR and may be viewed under Cenovus’s profile at www.sedar.com.

The acquisition of the FCCL Interest will consolidate the ownership interests in top-tier producing in-situ oil sands assets at Foster Creek and Christina Lake and provide Cenovus with full control over operations and current and potential future growth projects at Foster Creek, Christina Lake and Narrows Lake on a 100% working interest basis. This will increase Cenovus’s: (i) net oil sands landholdings by approximately 0.3 million acres, (ii) average daily bitumen production by approximately 178,000 bbls/d and (iii) proved bitumen reserves, as at December 31, 2016, by approximately 2,343 MMbbls, effectively doubling Cenovus’s oil sands exposure without any additional staff or integration requirements. In addition, Cenovus expects that consolidating its position in FCCL will allow it to effect cost improvements in its oil sands business through streamlined management processes and provide Cenovus with the full benefit from the near-to-medium term implementation of various technologies that Cenovus has developed.

The acquisition of the Deep Basin Assets will increase Cenovus’s leasehold rights in western Canada by approximately 3.0 million acres (net), including approximately 120 MBOE/d (net) of existing oil and natural gas production (26% liquids), and will add a large inventory of approximately 1,500 identified, short-cycle, high IRR drilling opportunities, as outlined in the chart below.¹ The Deep Basin Assets also include interests in approximately 27 natural gas processing facilities, with estimated net processing capacity of 1.4 Bcf/d and current throughput of approximately 560 MMcf/d (net), to provide cost-effective and timely support of current and future production volumes. In addition, the Deep Basin Assets will increase Cenovus’s proved light and medium oil and NGLs reserves as at December 31, 2016 by approximately 119 MMbbls and increase Cenovus’s proved natural gas reserves, as at December 31, 2016, by approximately 1,993 Bcf. Coupled with planned asset sales that Cenovus expects to undertake, the acquisition of the Deep Basin Assets is expected to enhance the quality of Cenovus’s short-cycle development inventory.

¹ “IRR” is defined as the interest rate at which the net present value of all future cash flows from a well equal zero. IRR does not have any standard meaning prescribed by the International Financial Reporting Standards (“IFRS”) or the Canadian Oil and Gas Evaluation Handbook and therefore may not be comparable with the calculation of similar measures for other entities. Cenovus believes that the presentation of IRR is relevant and useful to investors because it shows illustrative well-level economics in respect of wells that may be comparable to those Cenovus anticipates drilling in respect of Deep Basin Assets.


Operating area	Elmworth-Wapiti	Kaybob-Edson	Clearwater	Total

Production¹ (MBOE/d)	46	37	37	120

Proved plus probable reserves as at December 31, 2016² (MMBOE)	289	228	208	725

Land position (thousand net acres)	1,200	720	840	3,000³

Average working interest (%)	71	71	68

Future drilling opportunities	310	630	540	1,480

Target formations	Montney, Spirit River	Montney, Duvernay	Spirit River, Cardium, Glauconitic

¹ Forecast production for the full year 2017, before royalties. Assumes a January 1, 2017 effective date.

² Based upon the reports of McDaniel & Associates Consultants Ltd. (“McDaniel”), dated March 21, 2017, and GLJ Petroleum Consultants Ltd. (“GLJ”), dated March 6, 2017 (the “Assets Reserves Reports”), evaluating 100% of the Assets’ bitumen, heavy oil, light & medium oil, NGLs and natural gas proved and probable reserves at December 31, 2016.

Following the closing of the Acquisition, Cenovus expects that its capital expenditures in respect of the Deep Basin Assets for the next three years will focus on developing the Elmworth-Wapiti Area and Kaybob-Edson Area assets, with a particular focus on development in the prolific Spirit River and Montney formations. Cenovus expects to supplement its existing team with highly qualified technical staff from ConocoPhillips and to run a three rig program in 2017, ramping up thereafter as deemed appropriate, with the potential to grow production to approximately 170 MBOE/d (net) in 2019 compared to 120 MBOE/d (net) in 2017.

Cenovus expects the Acquisition to increase Adjusted Funds Flow (defined below) by 92% before the impact of expected dispositions, upstream operating costs per BOE to be reduced by 7% and general and administrative expenses per BOE to be reduced by 24% in 2017. Furthermore, Cenovus expects the acquired assets to generate Operating Margin (defined below) of CA$1.8 billion for 2017 (assuming flat US$50/bbl WTI prices throughout the period).

Following completion of the Acquisition, Cenovus expects to be the third-largest independent oil and gas producer in Canada by production, with a 2017 forecast pro forma production base of 588,000 BOE/d (75% liquids, before asset sales) and pro forma proved plus probable reserves as at December 31, 2016, of 7,763 MMBOE. Cenovus’s portfolio will span approximately 8.6 million net acres with anchor positions in two of Canada’s most prolific oil and gas plays: long-life, low-decline, best-in-class oil sands assets; and the Deep Basin, offering the flexibility to deploy capital into a large inventory of approximately 1,500 identified, short-cycle, high IRR drilling opportunities.

The following is a summary of the pro forma impact of the Acquisition on Cenovus’s 2017 forecast production, reserves and operating costs:


(dollar figures are in Canadian dollars)
Production (before royalties) (for the full year 2017)^{1, 2}	Cenovus	Pro forma	% Change
Oil sands (bbls/d)	178,000	356,000	100
Conventional oil³ and natural gas (BOE/d)	112,000	232,000	107
Total oil equivalent (BOE/d)	290,000	588,000	103
Reserves and financial information
Proved plus probable reserves (MMBOE)⁴	3,797	7,763	104
Adjusted funds flow per share (diluted)⁵	1.90	2.45	29
Operating costs ($/BOE)	10.15	9.45	-7
General & administrative costs ($/BOE)	2.45	1.85	-24

Cenovus expects that the Acquisition will provide it with a clear line of sight to five years of steady capital investment and production growth, including 125,000 bbls/d of near-term potential production capacity growth at Christina Lake, Foster Creek, and Narrows Lake and over a decade of attractive drilling opportunities already identified in the Deep Basin Assets.

Cenovus expects to continue to direct the majority of its capital to sustaining its currently producing oil sands projects. Following the completion of the Acquisition, Cenovus also plans to invest in development of the Deep Basin Assets, beginning with a three rig drilling program in 2017, and it is planning a three year infrastructure budget of between $250 and $300 million to maximize throughput and optimize development of the Deep Basin Assets. At the same time, Cenovus is targeting completion of non-core conventional asset divestitures which it expects will generate sale proceeds to repay and retire the Asset Sale Bridge Facility (defined below), but will also reduce near term production levels. This is expected to be more than offset with development of organic growth opportunities from Cenovus’s Christina Lake phase G oil sands project and the Deep Basin Assets following the completion of the Acquisition. With enhanced size and scale pro forma the Acquisition, Cenovus expects to have significant capital flexibility to support potential investment decisions.

The Purchase Price and the expenses related to the Acquisition will be financed at the closing of the Acquisition, directly or indirectly, with a combination of some or all of the following: (i) net proceeds of the Offering, (ii) amounts drawn under the Acquisition Credit Facilities (as defined below) and Cenovus’s existing CA$4.0 billion (or the equivalent amount in U.S. dollars) committed credit facility, which consists of a CA$1.0 billion tranche which matures on April 30, 2019, and a CA$3.0 billion tranche which matures on November 30, 2019 (the “Existing Credit Facility”), (iii) a portion of existing cash on hand and other sources available to Cenovus, and (iv) the issuance of the Consideration Shares. In addition, Cenovus anticipates a subsequent offering of senior debt, as well as select asset divestitures. The timing of the subsequent offering of senior debt and asset sales is subject to prevailing market conditions. Proceeds will be used to satisfy Cenovus’s bridge financing obligations, which extend for periods ranging from 12 to 24 months.

In conjunction with the Acquisition, Cenovus entered into an agreement with the Underwriters pursuant to which the Underwriters agreed to purchase, on a bought deal basis, 187.5 million Common Shares at a price of CA$16.00 per Common Share, for aggregate gross proceeds of CA$3.0 billion. In addition, the Underwriters were granted an over-allotment option for a period of 30 days from closing of the Offering, to purchase up to an additional 28.125 million Common Shares. If the over-allotment option is exercised in full, the aggregate gross proceeds from the Offering will be CA$3.45 billion. The Offering is expected to close on or about April 6, 2017. Cenovus intends to use the net proceeds from the Offering to finance a portion of the Cash Purchase Price payable by it to ConocoPhillips pursuant to the Acquisition. In the event that the Acquisition is not completed, Cenovus may use the net proceeds of the Offering to, among other things, reduce Cenovus’s outstanding indebtedness, finance future growth opportunities including acquisitions and investments, finance Cenovus’s capital expenditures, repurchase outstanding Common Shares or for other general corporate purposes.

In connection with the Offering, Cenovus has filed with the applicable securities regulatory authorities a prospectus supplement dated March 29, 2017 to its short form base shelf prospectus dated February 24, 2016. A copy of the prospectus supplement and the prospectus are able to be viewed under Cenovus’s profile at www.sedar.com.

For the purposes of financing a portion of the Cash Purchase Price, on March 29, 2017, Royal Bank of Canada and JPMorgan Chase Bank, N.A. committed to provide senior unsecured bridge term loan credit facilities to Cenovus in an aggregate principal amount of up to $10.5 billion on a fully underwritten basis (the “Acquisition Credit Facilities”). The Acquisition Credit Facilities will consist of: (i) an equity bridge term loan credit facility in an aggregate principal amount of $3.0 billion, (ii) a debt bridge term loan credit facility in an aggregate principal amount of $3.9 billion and (iii) an asset sale bridge term loan credit facility in an aggregate principal amount of $3.6 billion (the “Asset Sale Bridge Facility”). Cenovus will be the borrower under all of the Acquisition Credit Facilities.

In addition to the financing arrangements related to the Acquisition, Cenovus plans to extend the maturities on the tranches of the Existing Credit Facility to 2020 and 2021.

Cenovus retained two independent qualified reserves evaluators, McDaniel and GLJ, to evaluate and prepare the Assets Reserves Reports on 100% of the Assets’ bitumen, heavy oil, light & medium oil, NGLs and natural gas proved and probable reserves. McDaniel evaluated approximately 84% of the Assets’ proved reserves and GLJ evaluated approximately 16% of the Assets’ proved reserves.

The reserves data and other oil and gas information contained in this material change report is dated March 22, 2017, with an effective date of December 31, 2016. McDaniel’s preparation date of the information is March 21, 2017 and GLJ’s preparation date is March 6, 2017.

The information regarding the Assets set forth herein summarizes the bitumen, heavy oil, light & medium oils, NGLs and natural gas reserves associated with the Assets and the net present values of future net revenue for such reserves using forecast prices and costs as at December 31, 2016. The following reserves data has been prepared in accordance with the standards contained in the Canadian

Oil and Gas Evaluation Handbook and National Instrument 51-101 — Standards of Disclosure for Oil and Gas Activities (“NI 51-101”). See “Reserves and Resources Disclosure” below.

The reserves data presented summarizes the Assets’ bitumen, heavy oil, light & medium oil, NGLs, and natural gas reserves and the net present values (“NPV”) and future net revenue (“FNR”) for these reserves. The reserves data uses forecast prices and costs prior to provision for interest, general and administrative (“G&A”) expenses or the impact of any hedging activities. FNR has been presented on a before and after income tax basis.


	Bitumen (MMbbls)		Heavy Oil (MMbbls)		Light & Medium Oil (MMbbls)		NGLs (MMbbls)		Natural Gas (Bcf)		Total (MMBOE)

Before Royalties
Proved Reserves
Developed Producing		304		-		13		71		1,457		631
Developed Non-Producing		33		-		-		-		15		35
Undeveloped		2,006		-		3		32		521		2,128

Proved Reserves		2,343		-		16		103		1,993		2,794
Probable Reserves		897		-		11		67		1,180		1,172

Proved plus Probable Reserves		3,240		-		27		170		3,173		3,966

After Royalties Proved Reserves
Developed Producing		244		-		11		58		1,341		537
Developed Non-Producing		25		-		-		-		13		27
Undeveloped		1,510		-		2		28		480		1,620

Proved Reserves		1,779		-		13		86		1,834		2,184
Probable Reserves		670		-		10		55		1,060		912

Proved plus Probable Reserves		2,449		-		23		141		2,894		3,096


	Discounted at % / year ($ millions)										Unit Value Discounted at 10% ¹
	0%		5%		10%		15%		20%		$/BOE

Before Income Taxes
Proved Reserves
Developed Producing		10,159		9,581		8,346		7,338		6,551		15.56

Developed Non-Producing		926		704		550		440		360		19.98
Undeveloped		59,399		23,856		11,735		6,591		4,020		7.24

Proved Reserves		70,483		34,141		20,631		14,370		10,931		9.45

Probable Reserves		31,316		12,999		6,390		3,644		2,312		7.01


Proved plus Probable Reserves		101,799		47,140		27,021		18,013		13,242		8.73


	Discounted at % / year ($ millions)
	0%		5%		10%		15%		20%
After Income Taxes²
Proved Reserves
Developed Producing		8,717		8,397		7,357		6,500		5,830
Developed Non-Producing		687		538		431		353		294
Undeveloped		43,520		17,843		8,932		5,102		3,167
Proved Reserves		52,924		26,788		16,721		11,955		9,291
Probable Reserves		22,591		9,527		4,717		2,702		1,723
Proved plus Probable Reserves		75,515		36,305		21,437		14,657		11,014


Reserves Category	Product Types	FNR Before Income Taxes (discounted at 10%/year) ($ millions)	Unit Value Discounted at 10%/year¹ ($/BOE)
Proved	Bitumen	17,252	9.70
	Heavy Oil	1	23.90
	Light & Medium Oil	408	29.66
	Natural Gas & NGLs	2,970	7.58

	Total	20,631	9.45

Proved plus Probable	Bitumen	21,810	8.91
	Heavy Oil	1	23.81
	Light & Medium Oil	635	27.51
	Natural Gas & NGLs	4,575	7.33

	Total	27,021	8.73

After Royalties means volumes after deduction of royalties and includes royalty interest reserves, if any.

Before Royalties means volumes before deduction of royalties and excludes royalty interest reserves, if any.

Assets’ Interest means, in relation to production, reserves, resources and property, the interest (operating or non-operating) attributed to the Assets.

Gross means: (a) in relation to wells, the total number of wells in which an interest is included in the Assets; and (b) in relation to properties, the total acreage of properties in which an interest is included in the Assets.

Net means: (a) in relation to wells, the number of wells obtained by aggregating the working interest in each of the gross wells included in the Assets; and (b) in relation to the interest in a property included in the Assets, the total acreage in which it has an interest multiplied by its working interest.

Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, as of a given date, based on analysis of drilling, geological, geophysical and engineering data, the use of established technology and specified economic conditions, which are generally accepted as being reasonable.

Proved reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.

Probable reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.

Developed reserves are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (e.g., when compared to the cost of drilling a well) to put the reserves on production. The developed category may be subdivided as follows:

Developed producing reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty.

Developed non-producing reserves are those reserves that either have not been on production, or have previously been on production, but are shut-in, and the date of resumption of production is unknown.

Undeveloped reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (e.g., when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves classification (proved, probable) to which they are assigned.

The forecast of prices, inflation and exchange rate (the “McDaniel Forecast Prices”) provided in the table below was obtained from McDaniel and used to estimate FNR associated with the reserves disclosed herein. The McDaniel Forecast Prices are dated January 1, 2017. The inflation forecast was applied uniformly to prices beyond the forecast interval, and to all future costs. For historical prices that Cenovus realized during 2016, see “Production History” in Cenovus’s annual information form for the year ended December 31, 2016 dated February 15, 2017 (the “AIF”) filed on www.sedar.com.


	Oil					Natural Gas
Year	WTI Cushing Oklahoma (US$/ bbl)	Edmonton Par Price 40 API ($/bbl)	Cromer Medium 29.3 API ($/bbl)	Alberta Heavy 12 API ($/bbl)	WCS ($/bbl)	AECO Gas Price ($/MMBtu)	Inflation Rate (%/year)	Exchange Rate (US$/ CDN$)
2017	55.00	69.80	62.80	46.50	53.70	3.40	0.0	0.750
2018	58.70	72.70	67.60	50.50	58.20	3.15	2.0	0.775
2019	62.40	75.50	70.20	54.00	61.90	3.30	2.0	0.800
2020	69.00	81.10	75.40	58.00	66.50	3.60	2.0	0.825
2021	75.80	86.60	80.50	61.90	71.00	3.90	2.0	0.850
2022	77.30	88.30	82.10	63.10	72.40	3.95	2.0	0.850
2023	78.80	90.00	83.70	64.40	73.80	4.10	2.0	0.850
2024	80.40	91.80	85.40	65.60	75.30	4.25	2.0	0.850
2025	82.00	93.70	87.10	67.00	76.80	4.30	2.0	0.850
2026	83.70	95.60	88.90	68.40	78.40	4.40	2.0	0.850
2027	85.30	97.40	90.60	69.60	79.90	4.50	2.0	0.850
There-after	+2%/yr	+2%/yr	+2%/yr	+2%/yr	+2%/yr	+2%/yr	2.0	0.850

The following table outlines undiscounted future development costs deducted in the estimation of FNR calculated utilizing forecast prices and inflation for the years indicated:

Cenovus believes that existing cash balances, internally generated cash flows, Cenovus’s Existing Credit Facility, management of Cenovus’s asset portfolio and access to capital markets will be sufficient to fund Cenovus’s future development costs. However, there can be no guarantee that the necessary funds will be available or that Cenovus will allocate funding to develop all of Cenovus’s reserves. Failure to develop those reserves would have a negative impact on Cenovus’s FNR.

The interest or other costs of external funding are not included in the reserves and FNR estimates and would reduce FNR depending upon the funding sources utilized. Cenovus does not believe that interest or other funding costs would make development of any property uneconomic.

At the end of 2016, the FCCL Interest had proved undeveloped bitumen reserves of 2,006 million barrels Before Royalties, or approximately 86% of the proved bitumen reserves of the FCCL Interest. Of the FCCL Interest’s 897 million barrels of probable bitumen reserves, 856 million barrels, or approximately 95% are undeveloped. The evaluation of these reserves anticipates they will be recovered using SAGD.

Typical SAGD project development involves the initial installation of a steam generation facility and then progressively drilling sufficient SAGD well pairs to fully utilize the available steam.

Bitumen reserves can be classified as proved when there is sufficient stratigraphic drilling to have demonstrated to a high degree of certainty the presence of the bitumen in commercially recoverable volumes. McDaniel’s standard for sufficient drilling in the McMurray formation is a minimum of eight wells per section with 3D seismic, or 16 wells per section with no seismic. In other geological formations, such as the Grand Rapids, there may be some variation in the standard. Additionally, all requisite legal and regulatory approvals must have been obtained, operator and partner funding approvals must be in place, and a reasonable development timetable must be established. Proved developed bitumen reserves are differentiated from proved undeveloped bitumen reserves by the presence of drilled production/injection well pairs at the reserves estimation effective date. Because a steam plant has a long life relative to well pairs, in the early stages of a SAGD project, only a small portion of proved reserves will be developed as the number of well pairs drilled will be limited by the available steam capacity.

Recognition of probable reserves requires sufficient drilling of stratigraphic wells to establish reservoir suitability for SAGD. Reserves will be classified as probable if the well density falls between the stratigraphic well requirements for proved reserves and for probable reserves, and are located within an approved project area. If well density exceeds the requirement for proved reserves within an approved project area, but outside of an approved development area, those reserves can only be recognized as probable. McDaniel’s standard for probable reserves is a minimum of four stratigraphic wells per section. If reserves lie outside the approved development area, approval to include those reserves in the development area must be obtained before development drilling of SAGD well pairs can commence.

Development of the proved undeveloped reserves will take place in an orderly manner as additional well pairs are drilled to utilize the available steam when existing well pairs reach the end of their steam injection phase. The forecast production of the Assets’ proved bitumen reserves extends approximately 47 years, based on existing facilities. Production of the current proved developed portion is estimated to take approximately 13 years.

The Deep Basin Assets are oil and gas assets with reserves subject to development timing requirements as prescribed in N1 51-101 and the COGE Handbook. As such, all proved and proved plus probable undeveloped reserves tabulated above are scheduled to be developed within five years and 10 years, respectively.

The evaluation of reserves is a continuous process that can be significantly impacted by a variety of internal and external influences. Revisions are often required resulting from changes in pricing, economic conditions, regulatory changes, and historical performance. While these factors can be considered and potentially anticipated, certain judgments and assumptions are always required. As new information becomes available, these areas are reviewed and revised accordingly. For a discussion of the risk factors and uncertainties affecting reserves data, see “Risk Factors –Operational Risks – Uncertainty of Reserves and Future Net Revenue Estimates” in the AIF.

The following tables summarize the interests in producing and non-producing wells attributable to the Assets, as at December 31, 2016:


	Oil				Gas				Total
	Gross		Net		Gross		Net		Gross		Net
Producing Wells¹
Alberta
FCCL Interest		490		245		-		-		490		245
DBA		797		444		3,509		2,591		4,306		3,035
Total Alberta		1,287		689		3,509		2,591		4,796		3,280
British Columbia		3		2		735		329		738		331
Total		1,290		691		4,244		2,920		5,534		3,611


	Oil				Gas				Total
	Gross		Net		Gross		Net		Gross		Net
Non-Producing Wells¹
Alberta
FCCL Interest		98		49		-		-		98		49
DBA		-		-		16		8		16		8
Total Alberta		98		49		16		8		114		57
British Columbia		-		-		-		-		-		-
Total		98		49		16		8		114		57

The Assets contain no material properties with attributed reserves which are capable of producing, but which are not in production.

The following tables summarize the Assets’ gross participation and net interest in wells drilled in 2016¹:


	FCCL Interest				DBA				Total
	Gross		Net		Gross		Net		Gross		Net
Development Wells Drilled
Oil		52		26		1		1		53		27
Gas		-		-		10		7		10		7
Dry & Abandoned		-		-		-		-		-		-
Total Working Interest		52		26		11		8		63		34
Royalty		-		-		-		-		-		-
Total Canada		52		26		11		8		63		34

During the year ended December 31, 2016, 205 gross stratigraphic test wells (103 net wells) were drilled.

During the year ended December 31, 2016, no service wells were drilled within the FCCL Interest or Deep Basin Assets. SAGD well pairs are counted as a single producing well in the table above.

For all types of wells except stratigraphic test wells, the calculation of the number of wells is based on the number of surface locations. For stratigraphic test wells, the calculation is based on the number of bottomhole locations.

Development activities in respect of the Assets were focused on sustaining production at Christina Lake and Foster Creek.

The Assets include approximately 4.56 million gross acres (2.8 million net acres) of properties in Canada to which no reserves have been specifically attributed. These properties are planned for current and future development in both oil sands and conventional oil and gas operations. There are currently no work commitments on these properties.

The Assets include the rights to explore, develop, and exploit approximately 168,000 net acres that could potentially expire by December 31, 2017, which relate entirely to Crown and freehold land. Continuation applications have been submitted for the vast majority of these lands and Cenovus expects that very few of these lands will expire in 2017.

For areas where the Assets include interests in different formations under the same surface area through separate leases, gross and net acreage have been calculated on the basis of each individual lease.

Properties with no attributed reserves include Crown lands where bitumen contingent and prospective resources have been identified and Crown lands where exploration activities to date have not identified potential reserves in commercial quantities. See “Risk Factors – Financial Risks – Commodity Prices” and “Risk Factors – Financial Risks – Development and Operating Costs” and “Risk Factors – Operational Risks – Uncertainty of Reserves and Future Net Revenue Estimates” in Cenovus’s AIF for further discussion of economic and risk factors relevant to properties with no attributed reserves.

The estimated total future abandonment and reclamation costs for existing wells, facilities, and infrastructure is based on management’s estimate of costs to remediate, reclaim and abandon wells and facilities having regard to the working interest included in the Assets and the estimated timing of the costs to be incurred in future periods. Cenovus has developed a process to calculate these estimates, which considers applicable regulations, actual and anticipated costs, type and size of the well or facility and the geographic location.

Cenovus has estimated undiscounted future abandonment and reclamation costs for the existing Assets at approximately $1.7 billion (approximately $0.5 billion, discounted at 10%) at December 31, 2016, of which Cenovus expects between $42 million and $62 million will require payment in the next three financial years on a portion of the 4,118 net wells. Of the undiscounted future abandonment and reclamation costs to be incurred over the life of the proved reserves included in the Assets,

approximately $4.8 billion has been deducted in estimating the FNR, which represents the total existing estimated abandonment and reclamation costs associated with the Assets, plus all forecast estimates of abandonment and reclamation costs attributable to future development activity associated with the reserves.

The Deep Basin Assets include marketing, transportation and processing contracts which Cenovus will assume upon the closing of the Acquisition. Certain of these contracts may impact Cenovus’s exposure to commodity prices. Cenovus has not yet determined the nature or degree of such impact.

The following table summarizes the estimated 2017 average daily volume of the Assets’ working interest Before Royalties reflected in the reserves reports for the Assets using forecast prices and costs, all of which will be produced in Canada. These estimates assume certain activities take place, such as the development of undeveloped reserves, and that there are no divestitures.


2017 Estimated Production (Forecast prices and inflation)	Proved Reserves	Probable Reserves	Proved plus Probable Reserves
Bitumen (bbls/d)¹	176,482	8,030	184,512
Heavy Oil (bbls/d)	4	0	4
Light & Medium Oil (bbls/d)	5,381	107	5,488
NGLs (bbls/d)	28,892	904	29,796
Natural Gas (MMcf/d)	545	15	561
Assets’ Working Interest Before Royalties (BOE/d)	301,666	11,609	313,275


Average Working Interest Daily Production Volumes of Acquired Assets (barrels per day, unless otherwise stated)	2016
	Year		Q4		Q3		Q2		Q1
Crude Oil & NGLs (bbls/d)
FCCL Interest
Bitumen – Foster Creek		70,244		81,588		73,798		64,544		60,882
Bitumen – Christina Lake		79,449		82,808		79,793		78,060		77,093
		149,693		164,396		153,591		142,604		137,975
DBA
Light & Medium Oil		6,563		5,774		6,388		6,888		7,213
NGLs		25,855		24,310		25,553		25,693		27,885
		32,418		30,084		31,941		32,581		35,098
Total Crude Oil & NGLs		182,111		194,480		185,532		175,185		173,073
Natural Gas (MMcf/d)
DBA		526		497		514		529		566
Total Natural Gas & CBM		526		497		514		529		566
Total Production (BOE/d)		269,861		277,320		271,244		263,418		267,362


Average Royalty Interest Daily Production Volumes of Acquired Assets (barrels per day, unless otherwise stated)	2016
	Year		Q4		Q3		Q2		Q1
Crude Oil & NGLs (bbls/d)
FCCL Interest
Bitumen – Foster Creek		-		-		-		-		-
Bitumen – Christina Lake		-		-		-		-		-
		-		-		-		-		-
DBA
Light & Medium Oil		417		179		424		464		605
NGLs		414		379		424		429		422
		831		558		848		893		1,027
Total Crude Oil & NGLs		831		558		848		893		1,027
Natural Gas (MMcf/d)
DBA		7		6		7		8		9
Total Natural Gas		7		6		7		8		9
Total Production (BOE/d)		2,063		1,502		1,999		2,228		2,531

The following is a summary of selected historical operational and reserves information for Cenovus, for the FCCL Interest and the Deep Basin Assets and selected operational and reserves information for Cenovus on a pro forma basis after giving effect to the Acquisition, as if the Acquisition was completed on January 1, 2016 (in the case of the operational information) and on December 31, 2016 (in the case of the reserves information). The following is a summary only and must be read in conjunction with the Cenovus’s audited annual comparative consolidated financial statements and auditor’s report thereon for the year ended December 31, 2016 incorporated by reference in the prospectus, the information concerning Cenovus under the heading “Reserves Data and Other Oil and Gas Information” in the AIF and “Selected Oil and Gas Information in Respect of the Assets” in this material change report. All reserves were independently evaluated. The pro forma reserves information does not give effect to any adjustments for planned asset sales that may be completed subsequent to this material change report.

Average daily production Before Royalties for the year ended December 31, 2016


	Cenovus		FCCL Interest		DBA		Pro Forma
Crude Oil & NGLs (bbls/d)
Oil Sands
Foster Creek		70,244		70,244		-		140,488
Christina Lake		79,449		79,449		-		158,898
Total Oil Sands		149,693		149,693		-		299,386
Conventional
Heavy Oil		29,185		-		-		29,185
Light & Medium Oil		25,915		-		6,980		32,895
NGLs		1,065		-		26,269		27,334
Total Conventional		56,165		-		33,249		388,800
Total Crude Oil & NGLs		205,858		149,693		33,249		388,800
Natural Gas (MMcf/d)
Oil Sands		17		-		-		17
Conventional		377		-		534		911
Total Natural Gas		394		-		534		928
Total Production (BOE/d)		271,525		149,693		122,231		543,449


	Cenovus	FCCL Interest	DBA	Pro Forma
Bitumen (MMbbls)	2,343	2,343	-	4,686
Heavy Oil (MMbbls)	114	-	-	114
Light & Medium Oil (MMbbls)	100	-	16	116
NGLs (MMbbls)	2	-	103	105
Natural Gas & CBM (Bcf)	652	-	1,993	2,645
Total (MMBOE)	2,668	2,343	451	5,462


	Cenovus	FCCL Interest	DBA	Pro Forma
Bitumen (MMbbls)	3,319	3,240	-	6,559
Heavy Oil (MMbbls)	189	-	-	189
Light & Medium Oil (MMbbls)	142	-	27	169
NGLs (MMbbls)	2	-	170	172
Natural Gas & CBM (Bcf)	864	-	3,173	4,037
Total (MMBOE)	3,797	3,240	725	7,762

Concurrent with announcement of the Acquisition, Cenovus has begun marketing its legacy Alberta conventional assets at Pelican Lake and Suffield. Advisors have been retained and data rooms are open. Combined, these assets produced approximately 47,600 BOE/d in 2016, consisting of nearly 29,000 bbls/d of crude oil and 112 MMcf/d of natural gas. Cenovus plans to divest additional non-core conventional assets to streamline its portfolio. The proceeds from the successful sale of the Pelican Lake and Suffield assets, and other associated asset sales, are expected to be applied against Cenovus’s outstanding bridge loans.

ConocoPhillips has agreed to receive, as part of the Purchase Price, 208 million Common Shares of Cenovus. In relation to the Consideration Shares, at closing Cenovus and ConocoPhillips will enter into an investor agreement, and a registration rights agreement which, among other things, will restrict ConocoPhillips from selling or hedging its Cenovus shares for a period of six months from the closing date of the Acquisition. ConocoPhillips will also be restricted from nominating new members to Cenovus’s board of directors and must vote its Cenovus shares in accordance with management recommendations or abstain from voting.

At closing, Cenovus and ConocoPhillips have agreed to enter into a five-year contingent payment agreement related to the acquired portion of FCCL Assets that is triggered when the price of WCS rises above CA$52/bbl. The terms of the contingent payment agreement will allow Cenovus to retain 80% to 85% of WCS prices above CA$52/bbl, based on current gross FCCL production capacity. As production capacity increases with future expansions, the percentage of upside available to Cenovus will increase further.

For the five-year term of the agreement, Cenovus will make contingent payments to ConocoPhillips for each quarter in which the average daily price of WCS is above CA$52/bbl. The payments will be

calculated by multiplying CA$6 million by the amount the average daily WCS price exceeds CA$52/bbl. The calculation includes an adjustment mechanism related to certain significant production outages which may reduce the amount of a contingent payment. There are no maximum payment terms.

Executive Vice-President, Environment, Corporate Affairs, Legal & General Counsel

This material change report contains certain forward looking statements and forward looking information (collectively referred to as “forward looking information”) within the meaning of applicable securities legislation, including the United States Private Securities Litigation Reform Act of 1995, about Cenovus’s current expectations, estimates and projections about the future, based on certain assumptions made by Cenovus in light of Cenovus’s experience and perception of historical trends. Although Cenovus believes that the expectations represented by such forward looking information are reasonable, there can be no assurance that such expectations will prove to be correct.

This forward looking information is identified by words such as “anticipate”, “believe”, “expect”, “estimate”, “plan”, “forecast”, “future”, “target”, “position”, “project”, “committed”, “can be”, “pursue”, “capacity”, “could”, “should”, “focus”, “proposed”, “potential”, “priority”, “may”, “strategy”, “forward”, “will” or similar expressions and includes suggestions of future outcomes, including statements about: completion of the Acquisition, and the timing thereof; the anticipated benefits to Cenovus of the Acquisition, including the effect on Adjusted Funds Flow; Cenovus’s pro forma financial, operating and reserves information, anticipated drilling locations, drilling inventories and drilling opportunities, and production estimates after completion of the Acquisition; the midstream gathering, processing and transportation arrangements to be acquired and assumed by Cenovus in connection with the Acquisition; the availability and repayment of the existing Acquisition Credit Facilities; replacement of a portion of the Acquisition Credit Facilities through the issuance of the Common Shares pursuant to the Offering; replacement, refinancing or repayment of a portion of the Acquisition Credit Facilities through the issuance by Cenovus of debt securities; anticipated disposition of certain assets and the expected application of the proceeds of such dispositions to amounts owing under the Acquisition Credit Facilities; the anticipated effect of the Acquisition on Cenovus’s credit ratings; the

anticipated effect of the Acquisition on the consolidated capitalization of Cenovus following the completion of the Offering, the issuance of the Common Shares to ConocoPhillips, the anticipated borrowings under the Acquisition Credit Facilities; the completion of the Offering; the use of proceeds of the Offering; future contingent payments; Cenovus’s strategy and related milestones and schedules including expected timing for oil sands expansion phases and associated expected production capacities; Cenovus’s pro forma financial and operational projections for 2017, 2018 and future years and Cenovus’s plans and strategies to realize such projections; forecast exchange rates and trends; the expected development and growth of Cenovus’s business projections for the 2017, 2018 and future years and Cenovus’s plans and strategies to realize such projections; Cenovus’s forecast operating and financial results, including forecast sales prices, costs and cash flows; Cenovus’s expected ability to satisfy payment obligations as they become due; planned capital expenditures, including the amount, timing and financing thereof; Cenovus’s annual capital investment forecasts and plans with respect thereto; the techniques expected to be used to recover reserves and forecasts of the timing thereof; Cenovus’s expected future production, including the timing, stability or growth thereof; Cenovus’s expected reserves; Cenovus’s expected capacities, including for projects, transportation and refining; Cenovus’s expected ability to preserve Cenovus’s financial resilience and various plans and strategies with respect thereto; forecast cost savings and sustainability thereof; Cenovus’s priorities for 2017, 2018 and future years; Cenovus’s expectations for broadening market access; expected impacts of the contingent payment agreement; future use and development of technology; Cenovus’s ability to access and implement all technology necessary to efficiently and effectively operate Cenovus’s assets (including, but not limited to, the Assets) and achieve and sustain future cost reductions; and Cenovus’s projected shareholder return. Readers are cautioned not to place undue reliance on forward looking information as Cenovus’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 in general. The factors or assumptions on which the forward looking information is based include: timing and receipt of applicable regulatory approvals for the Acquisition and the Offering; all required financing being available to complete the Acquisition; Cenovus’s ability to successfully integrate the Deep Basin Assets; Cenovus’s ability to obtain and retain qualified staff and equipment in a timely and cost-efficient manner; Cenovus’s ability to access sufficient capital to pursue Cenovus’s development plans associated with full ownership of the FCCL Assets; the Offering being completed on the terms and timing expected; Cenovus’s ability to complete asset dispositions, including to repay and retire the Acquisition Credit Facilities; Cenovus’s ability to issue debt securities, including to repay and retire a portion of the Acquisition Credit Facilities; the impact that the Acquisition and the financing thereof may have on Cenovus’s current credit ratings; forecast crude oil and natural gas prices, forecast inflation and other assumptions inherent in Cenovus’s current guidance set out below; expected impacts of the contingent payment agreement; alignment of realized WCS prices and WCS prices as calculated under the contingent payment agreement; Cenovus’s projected capital investment levels, the flexibility of capital spending plans and the associated sources of funding; sustainability of achieved cost reductions, achievement of further cost reductions and sustainability thereof, including, but not limited to, in relation to the Assets; expected condensate prices; estimates of quantities of oil, bitumen, natural gas and NGLs from properties and other sources not currently classified as proved; future use and development of technology; Cenovus’s ability to access and implement all technology necessary to efficiently and effectively operate Cenovus’s assets (including, but not limited to, the Assets) and achieve and sustain cost reductions; Cenovus’s ability to implement capital projects or stages thereof in a successful and timely manner; Cenovus’s ability to generate sufficient cash flow to meet Cenovus’s current and future obligations; and other risks and uncertainties described from time to time in the filings Cenovus makes with securities regulatory authorities.

The forward looking information in this material change report also includes financial outlooks regarding Cenovus and other forward looking metrics (including production, financial and oil and gas related metrics) relating to Cenovus, the Acquisition and the Assets, including: the projected impact of lowering sustaining capital, including on the net present value of Cenovus’s assets; Cenovus’s projected capital expenditures; projected contingent payments; projections related to drilling locations and other opportunities, Cenovus’s expectations regarding the impact of the Acquisition on Adjusted Funds Flow, Adjusted Funds Flow per share, upstream operating costs per BOE, G&A expenses per BOE, and operating costs.

Unless otherwise specifically stated or the context dictates otherwise, the financial outlook and other forward looking metrics contained in this material change report, in addition to the generally applicable assumptions described above, are based on the following specific assumptions, as applicable: (i) WTI prices averaging US$50.00 in 2017, 2018, and 2019; (ii) Brent prices averaging US$52.25 in 2017, 2018, and 2019; (iii) NYMEX natural gas prices averaging US$3.00 in 2017, 2018, and 2019; (iv) AECO natural gas prices averaging $3.07 in 2017, 2018, and 2019; (v) the exchange rate for the conversion of one U.S. dollar into Canadian dollars averaging $1.33 in 2017, 2018, and 2019; (vi) the pricing differential between WCS and WTI averaging US$14.50 in 2017, 2018, and 2019; (vii) Chicago 3-2-1 Crack Spread averaging US$15.00/bbl in 2017, 2018, and 2019; (viii) the successful completion of Cenovus’s forecast capital expenditure and development plans as outlined in this material change report (including favourable drilling results and successful completion of major projects on time and on budget); (ix) the alignment of realized WCS prices and WCS prices as calculated under the contingent payment agreement; (x) overall production rates for 2017, 2018 and 2019 being in line with Cenovus’s expectations as outlined in this material change report; (xi) royalty rates in Alberta, Saskatchewan and British Columbia remaining unchanged from the currently announced rates for 2017, 2018 and 2019; and (xii) operating and G&A costs per BOE being in line with Cenovus’s expectations as outlined in this material change report.

Unless otherwise specifically stated or the context dictates otherwise, the financial outlook and forward looking metrics in this material change report, in addition to the generally applicable assumptions described above, do not include or account for the effects or impacts of planned asset sales.

The risk factors and uncertainties that could cause Cenovus’s actual results to differ materially, include: possible failure by Cenovus to realize the anticipated benefits of, and synergies from, the Acquisition; Cenovus’s inability to complete the Acquisition on the terms contemplated by the Acquisition Agreement or at all; possible failure to access or implement some or all of the technology necessary to efficiently and effectively operate Cenovus’s assets (including, but not limited to, the Assets) and achieve and sustain future cost reductions; volatility of and other assumptions regarding commodity prices; the effectiveness of Cenovus’s risk management program, including the impact of derivative financial instruments, the success of Cenovus’s hedging strategies and the sufficiency of Cenovus’s liquidity position; the accuracy of cost estimates; commodity prices, currency and interest rates; possible lack of alignment of realized WCS prices and WCS prices as calculated under the contingent payment agreement; product supply and demand; market competition, including from alternative energy sources; risks inherent in Cenovus’s marketing operations, including credit risks; exposure to counterparties and partners, including ability and willingness of such parties to satisfy contractual obligations in a timely manner; risks inherent in the operation of Cenovus’s crude-by-rail terminal, including health, safety and environmental risks; maintaining desirable ratios of Debt (and Net Debt) to Adjusted EBITDA as well as Debt (and Net Debt) to Capitalization; Cenovus’s ability to access various sources of debt and equity capital, generally, and on terms acceptable to us; Cenovus’s ability to

finance growth and sustaining capital expenditures; changes in credit ratings applicable to Cenovus or any of Cenovus’s securities; changes to Cenovus’s dividend plans or strategy, including the dividend reinvestment plan; accuracy of Cenovus’s reserves, resources, future production and future net revenue estimates; Cenovus’s ability to replace and expand oil and gas reserves; Cenovus’s ability to maintain Cenovus’s relationship with Cenovus’s partners and to successfully manage and operate Cenovus’s integrated business; reliability of Cenovus’s assets including in order to meet production targets; potential disruption or unexpected technical difficulties in developing new products and manufacturing processes; the occurrence of unexpected events such as fires, severe weather conditions, explosions, blow-outs, equipment failures, transportation incidents and other accidents or similar events; refining and marketing margins; inflationary pressures on operating costs, including labour, natural gas and other energy sources used in oil sands processes; potential failure of products to achieve or maintain acceptance in the market; risks associated with fossil fuel industry reputation; 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 Cenovus’s business; risks associated with climate change; the timing and the costs of well and pipeline construction; Cenovus’s ability to secure adequate and cost-effective product transportation including sufficient pipeline, crude-by-rail, marine or alternate transportation, including to address any gaps caused by constraints in the pipeline system; availability of, and Cenovus’s ability to attract and retain, critical talent; possible failure to obtain and retain qualified staff and equipment in a timely and cost-efficient manner; changes in labour relationships; 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, climate change 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, Cenovus’s financial results and Cenovus’s consolidated financial statements; changes in general economic, market and business conditions; political and economic conditions in the countries in which Cenovus operates or supplies; 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.

Statements relating to “reserves” are deemed to be forward looking information, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves and resources described exist in the quantities predicted or estimated, and can be profitably produced in the future.

Cenovus cautions that the foregoing list of important factors is not exhaustive. Events or circumstances could cause Cenovus’s actual results to differ materially from those estimated or projected and expressed in, or implied by, the forward looking information. You should carefully consider the matters discussed under “Risk Factors” in the prospectus and in the prospectus supplement. You should also refer to “Risk Factors” in the AIF, “Risk Management” in Cenovus’s management’s discussion and analysis of financial condition and results of operations for the year ended December 31, 2016, each as incorporated by reference in the prospectus, and to the risk factors described in other documents incorporated by reference in the prospectus.

You should not place undue reliance on the forward looking information contained in this material change report, as actual results achieved will vary from the forward looking information provided in this material change report and the variations may be material. Cenovus makes no representation that actual results achieved will be the same in whole or in part as those set out in the forward looking

information. Furthermore, the forward looking information contained in this material change report is made as of the date of this material change report. The purpose of the financial outlook in this material change report is to provide management’s expectations of the effects of the Offering and/or the Acquisition, as applicable. Except as required by applicable securities law, Cenovus undertakes no obligation to update publicly or otherwise revise any forward looking information or the foregoing list of factors affecting those statements, whether as a result of new information, future events or otherwise or the foregoing lists of factors affecting this information.

This cautionary statement qualifies all forward looking information contained in this material change report and the prospectus and incorporated by reference in the prospectus.

The prospective financial information included in this material change report has been prepared by, and is the responsibility of, Cenovus’s management.

The following measures do not have a standardized meaning as prescribed by IFRS and therefore are considered non-GAAP measures. You should not consider these measures in isolation or as a substitute for analysis of Cenovus’s results as reported under IFRS. These measures are defined differently by different companies in Cenovus’s industry. These measures may not be comparable to similar measures presented by other issuers.

Adjusted Funds Flow is a non-GAAP measure commonly used in the oil and gas industry to assist in measuring a company’s ability to finance its capital programs and meet its financial obligations. Adjusted Funds Flow is defined as Cash From Operating Activities excluding net change in other assets and liabilities and net change in non-cash working capital. Net change in other assets and liabilities is composed of site restoration costs and pension funding. Non-cash working capital is composed of current assets and current liabilities, excluding cash and cash equivalents and risk management.

Debt is a non-GAAP measure that Cenovus defines as short-term borrowings and the current and long-term portions of long-term debt. Debt is used as a component of Net Debt. Net Debt is a non-GAAP measure defined as Debt net of cash and cash equivalents. Adjusted EBITDA is a non-GAAP measure that Cenovus defines as earnings before finance costs, interest income, income tax expense, depreciation, depletion and amortization, goodwill impairments, asset impairments and reversals, unrealized gains (losses) on risk management, foreign exchange gains (losses), gains (losses) on divestiture of assets, revaluation gain and other income (loss), net, calculated on a trailing 12-month basis. Net debt to Adjusted EBITDA is used to steward Cenovus’s overall debt position and as a measure of Cenovus’s overall financial strength.

Capitalization is a non-GAAP measure that Cenovus defines as Debt plus shareholders’ equity. Net Debt to Capitalization is defined as net debt divided by net debt plus shareholders’ equity.

Operating Margin is an additional subtotal found in Note 1 of the audited annual comparative consolidated financial statements and auditor’s report thereon for the year ended December 31, 2016, and is used to provide a consistent measure of the cash generating performance of Cenovus’s assets for comparability of Cenovus’s underlying financial performance between periods. Operating Margin is defined as revenues less purchased product, transportation and blending, operating expenses and production and mineral taxes plus realized gains less realized losses on risk management activities.

The securities regulatory authorities in Canada have adopted NI 51-101, which imposes oil and gas disclosure standards for Canadian public issuers engaged in oil and gas activities. NI 51-101 requires oil and gas issuers, in their filings with Canadian securities regulatory authorities, to disclose proved and probable reserves, and to disclose reserves and production on a gross basis before deducting royalties. It also permits disclosure of resources and possible reserves. Probable reserves, possible reserves and resources are of a higher uncertainty and are less likely to be accurately estimated or recovered than proved reserves.

Cenovus is required to disclose reserves in accordance with Canadian securities law requirements and this material change report and the disclosure in certain of the documents incorporated by reference in the prospectus include reserves designated as probable reserves.

The U.S. Securities and Exchange Commission (the “SEC”) definitions of proved and probable reserves are different from the definitions contained in NI 51-101; therefore, proved and probable reserves disclosed herein and in the documents incorporated by reference in the prospectus in compliance with NI 51-101 may not be comparable to U.S. standards. The SEC requires U.S. oil and gas reporting companies, in their filings with the SEC, to disclose only proved reserves after the deduction of royalties and production due to others, but permits the optional disclosure of probable and possible reserves.

In addition, Cenovus is permitted to disclose estimates of resources other than reserves in accordance with Canadian securities laws, and certain documents incorporated by reference in the prospectus contain such estimates. The SEC does not permit the disclosure of resources other than reserves in reports filed with it by U.S. oil and gas reporting companies. Contingent and prospective resources are not, and should not be confused with, reserves. Investors are cautioned not to assume that any or all of Cenovus’s contingent and prospective resources will be converted into reserves. Additional information regarding these estimates can be found in Cenovus’s statement of contingent and prospective resources dated February 15, 2017, which is incorporated by reference in the prospectus.

Moreover, as required by NI 51-101, Cenovus has determined and disclosed the net present value of future net revenue from Cenovus’s reserves disclosure using forecast prices and costs. The SEC requires that reserves and related future net revenue be estimated based on historical 12 month average prices, but permits the optional disclosure of revenue estimates based on different price and cost criteria, including standardized future prices.

For additional information regarding the presentation of Cenovus’s reserves and other oil and gas information, see the section entitled “Reserves Data and Other Oil and Gas Information” in Cenovus’s AIF, which is incorporated by reference in the prospectus.

This material change report discloses potential future drilling locations in two categories: (a) proved locations and (b) probable locations. This material change report also discloses additional un-booked future drilling opportunities. Proved locations and probable locations are proposed drilling locations identified in the Assets Reserves Reports that have proved and/or probable reserves, as applicable, attributed to them in such report. Un-booked future drilling opportunities are internal Cenovus estimates based on prospective acreage and an assumption as to the number of wells that can be drilled per section based on industry practice and internal Cenovus technical analysis and review.

Un-booked future drilling opportunities have been identified by Cenovus management based on evaluation of applicable geologic, seismic, engineering, production and reserves information. Un-booked future drilling opportunities do not have proved or probable reserves attributed to them in the Assets Reserves Reports. Of the approximately 1,500 identified drilling opportunities within the Deep Basin Assets to be acquired, 212 are proved locations, 221 are probable locations and the remainder of which are un-booked future drilling opportunities.

Cenovus’s ability to drill and develop these locations and opportunities and the drilling locations on which Cenovus actually drills wells depends on a number of uncertainties and factors, including, but not limited to, the availability of capital, equipment and personnel, oil and natural gas prices, capital and operating costs, inclement weather, seasonal restrictions, drilling results, additional geological, geophysical and reservoir information that is obtained, production rate recovery, gathering system and transportation constraints, net price received for commodities produced, regulatory approvals and regulatory changes. As a result of these uncertainties, there can be no assurance that the potential future drilling locations and opportunities Cenovus has identified will ever be drilled or if Cenovus will be able to produce oil, NGL or natural gas from these or any other potential drilling locations or opportunities. As such, Cenovus’s actual drilling activities may differ materially from those presently identified, which could adversely affect Cenovus’s business. While certain of the identified un-booked drilling opportunities have been de-risked by drilling existing wells in relatively close proximity to such un-booked drilling opportunities, some of the other un-booked drilling opportunities are farther away from existing wells where Cenovus management has less information about the characteristics of the reservoir and therefore there is more uncertainty whether wells will be drilled and, if drilled, there is further uncertainty that such wells will result in additional proved or probable reserves or production.


Reserves Category	Revenue	Royalties	Operating Costs	Development Costs	Total Abandonment and Reclamation Costs¹	FNR Before Future Income Taxes	Future Income Taxes	FNR After Future Income Taxes
Proved	179,346	42,518	44,011	17,524	4,810	70,483	17,559	52,924
Proved plus Probable	255,979	60,766	60,890	26,486	6,038	101,799	26,284	75,515


Reserves Category ($ millions)	2017	2018	2019	2020	2021	Remainder	Total
Proved	362	718	856	789	434	14,365	17,524
Proved plus Probable	428	781	1,286	1,336	832	21,823	26,486


($ millions) 2016	2016
Acquisitions
Unproved		1
Proved		3
Total Acquisitions		4
Exploration Costs		111
Development Costs		652
Total Costs Incurred		767


Oil and NGLs		Natural Gas

bbls/d	barrels per day	Bcf	billion cubic feet
Mbbls/d	thousand barrels per day	Bcf/d	billion cubic feet per day
MMbbls	million barrels	MMcf/d	million cubic feet per day
NGLs	natural gas liquids	CBM	coal bed methane
BOE	barrel of oil equivalent
BOE/d	barrels of oil equivalent per day
MMBOE	million barrels of oil equivalent
MBOE/d	thousand barrels of oil equivalent per day
WTI	West Texas Intermediate
WCS	West Texas Select crude blend
SAGD	steam-assisted gravity drainage