EX-99.4

EX-99.4 5 d521082dex994.htm EX-99.4 EX-99.4

Exhibit 99.4

LOGO

Cenovus Energy Inc.

Supplementary Information – Oil and Gas Activities (unaudited)

For the Year Ended December 31, 2017

(Canadian Dollars)

DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES TOPIC 932

“EXTRACTIVE ACTIVITIES – OIL AND GAS” (unaudited)

The following select disclosures of Cenovus Energy Inc.’s (“Cenovus” or the “Company”) reserves and other oil and gas information have been prepared in accordance with United States (“U.S.”) Financial Accounting Standards Board (“FASB”) Topic 932, “Extractive Activities – Oil and Gas” and the U.S. disclosure requirements of the Securities and Exchange Commission (“SEC”).

All amounts pertaining to Cenovus’s audited Consolidated Financial Statements are prepared in accordance with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”). Unless otherwise noted, all dollars are in millions of Canadian dollars. All references to C$ or $ are to Canadian dollars and references to US$ are to U.S. dollars.

RESERVES DATA

The SEC Modernization of Oil and Gas Reporting final rules require that proved after royalty reserves be estimated using existing economic conditions (constant pricing). Cenovus’s results have been calculated using the average of the first-day-of-the-month prices for the prior twelve month period. This same twelve month average price is also used in calculating the aggregate amount of (and changes in) future cash inflows related to the standardized measure of discounted future net cash flows. Future fluctuations in prices, production rates, or changes in political or regulatory environments could cause Cenovus’s share of future production from Canadian reserves to be materially different from that presented.

The reserves disclosed are effective December 31, 2017, and were prepared by the independent, qualified reserves evaluators McDaniel & Associates Consultants Ltd. and GLJ Petroleum Consultants Ltd. There are significant differences between reserves evaluated under the SEC requirements and those presented in the Company’s Annual Information Form filed under National Instrument 51-101 “Standards of Disclosure for Oil and Gas Activities” (“NI 51-101”). NI 51-101 requires disclosure of before royalties reserves and the associated values using forecasted prices and costs.

The reserves presented in this supplemental information are estimates only. There are numerous uncertainties inherent in estimating quantities of reserves, including many factors beyond the Company’s control. In general, estimates of economically recoverable bitumen, crude oil, natural gas liquids and natural gas reserves and the future net cash flows derived therefrom are based upon a number of variable factors and assumptions, including but not limited to: product prices; future operating and capital costs; historical production from the properties and the assumed effects of regulation by governmental agencies, including with respect to royalty payments and taxes; initial production rates; production decline rates; and the availability, proximity and capacity of oil and gas gathering systems, pipelines and processing facilities, all of which may vary considerably from actual results.

All such estimates are to some degree uncertain and classifications of reserves are only attempts to define the degree of uncertainty involved. For those reasons, estimates of the economically recoverable bitumen, crude oil, natural gas liquids and natural gas reserves attributable to any particular group of properties, classification of such reserves based on risk of recovery and estimates of future net revenues expected therefrom, prepared by different engineers or by the same engineers at different times, may vary substantially. Cenovus’s actual production, sales, royalty payments, taxes and development and operating expenditures with respect to its reserves may vary from current estimates and such variances may be material.

Estimates with respect to reserves that may be developed and produced in the future are often based upon volumetric calculations and upon analogy to similar types of reserves, rather than upon actual production history. Subsequent evaluation of the same reserves based upon production history will result in variations, which may be material, in the estimated reserves.

Canadian provincial royalties are determined based on a graduated percentage scale which varies with prices and production rates. Canadian reserves, as presented on a net basis, assume royalty rates in existence at the time the estimates were made.

Subsequent to December 31, 2017 the Company has closed the sale of its Suffield property, resulting in the disposition of 64.0 million barrels of oil equivalent, comprised of approximately 80 percent natural gas and 20 percent crude oil.

The reserves data contained herein is dated February 13, 2018 with an effective date of December 31, 2017.


Cenovus Energy Inc.		Supplementary Information – Oil and Gas Activities (unaudited)

OIL AND GAS RESERVES INFORMATION

All of Cenovus’s reserves are located in Alberta and British Columbia, Canada.

Net Proved Reserves (Cenovus Share After Royalties)^(1)(2)(3)

Average Fiscal-Year Prices


	Bitumen (MMbbls)⁽³⁾		Natural Gas Liquids (MMbbls)⁽³⁾⁽⁴⁾		Crude Oil (MMbbls)⁽³⁾⁽⁴⁾		Natural Gas (Bcf)⁽³⁾		Total (MMBOE)⁽³⁾
2016
Beginning of year		1,953		1		189		539		2,233
Revisions and improved recovery		(128)		-		(45)		8		(172)
Extensions and discoveries		134		-		-		-		134
Purchase of reserves in place		-		-		-		-		-
Sale of reserves in place		-		-		-		-		-
Production		(54)		-		(18)		(141)		(95)
End of year		1,905		1		126		406		2,100
Developed		307		1		114		405		490
Undeveloped		1,598		-		12		1		1,610
Total		1,905		1		126		406		2,100

2017
Beginning of year		1,905		1		126		406		2,100
Revisions and improved recovery		73		-		5		102		95
Extensions and discoveries		129		1		-		33		135
Purchase of reserves in place		1,959		85		12		1,559		2,316
Sale of reserves in place		-		(1)		(104)		(73)		(117)
Production		(100)		(6)		(15)		(233)		(160)
End of year		3,966		80		24		1,794		4,369
Developed		664		51		23		1,390		970
Undeveloped		3,302		29		1		404		3,399
Total		3,966		80		24		1,794		4,369

(1)

Definitions:

(a)

“Net” reserves are the remaining reserves attributable to Cenovus, after deduction of estimated royalties and including royalty interests.

(b)

“Proved” oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations, i.e., prices and costs as of the date the estimate is made.

(c)

“Developed” oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods in which the cost of the required equipment is relatively minor compared to the cost of a new well.

(d)

“Undeveloped” reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(2)

Estimates of total net proved bitumen, crude oil, natural gas liquids, or natural gas reserves are not filed by Cenovus with any U.S. federal authority or agency other than the SEC.

(3)

“Million barrels” is abbreviated as MMbbls, “billion cubic feet” is abbreviated as Bcf, and “million barrel of oil equivalent” is abbreviated as MMBOE.

(4)

Natural gas liquids and crude oil have been presented separately to conform to the presentation adopted in 2017.

Changes to Reserves

The explanation of significant year-over-year changes in the Company’s net proved reserves for the year ended December 31, 2016 and December 31, 2017 is set forth below.

Year ended December 31, 2016

The changes to the Company’s net proved bitumen reserves in 2016 are explained as follows:

•

Revisions and improved recovery: The year-over-year decrease in average bitumen price rendered 235 million barrels of reserves at the Company’s Narrows Lake property uneconomic. The decrease was partially offset by increased reserves of 122 million barrels, which resulted from reduced royalty rates caused by lower WTI benchmark prices, at the Company’s Foster Creek and Christina Lake properties. The remaining difference is due to negative technical revisions.

•

Extensions and discoveries: In 2016, the Alberta Energy Regulator approved a development area expansion at the Company’s Christina Lake property, which increased the Company’s proved reserves by 134 million barrels.

The changes to the Company’s net proved crude oil reserves in 2016 are explained as follows:

•

Revisions and improved recovery: Crude oil reserves decreased in 2016 primarily due to lower year-over-year average prices, which rendered 46 million barrels of proved crude oil reserves at the Company’s Pelican Lake property uneconomic, offset by positive technical revisions.


Cenovus Energy Inc.		Supplementary Information – Oil and Gas Activities (unaudited)

Year ended December 31, 2017

The changes to the Company’s net proved bitumen reserves in 2017 are explained as follows:

•

Purchase of reserves in place: The Company concluded a material transaction to acquire its partner’s 50 percent interest in the Christina Lake, Foster Creek, and Narrows Lake properties (“FCCL”), increasing net proved reserves by 1,959 million barrels.

•

Revisions and improved recovery: The year-over-year increase in average bitumen price restored economic viability to the Narrows Lake project, increasing reserves by 243 million barrels. The increase was partially offset by decreased reserves of 144 million barrels, which resulted from increased royalty rates caused by higher WTI benchmark prices at the Company’s Foster Creek and Christina Lake properties. The remaining difference is attributable to technical revisions.

•

Extensions and discoveries: In 2017, the Alberta Energy Regulator approved development area expansions at the Foster Creek and Narrows Lake properties, increasing the Company’s net proved reserves by 129 million barrels.

The changes to the Company’s net proved reserves of crude oil, natural gas liquids, and natural gas in 2017 are as follows:

•

Purchase of reserves in place: The Company acquired significant assets in Alberta and British Columbia (the “Deep Basin Assets”). This added 12 million barrels of crude oil, 85 million barrels of natural gas liquids, and 1,559 billion cubic feet of natural gas reserves.

•

Sale of reserves in place: The Company sold its Palliser, Pelican Lake and Saskatchewan properties, reducing its net proved reserves of crude oil and natural gas by 104 million barrels and 73 billion cubic feet, respectively.

•

Revisions and improved recovery: Improved performance at Suffield and Athabasca Gas identified net proved natural gas reserves additions of 102 billion cubic feet. The Suffield property has subsequently been sold in early 2018.

STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS AND CHANGES THEREIN

In calculating the standardized measure of discounted future net cash flows, the average of the first-day-of-the-month prices for the prior twelve month period and cost assumptions were applied to Cenovus’s annual future production from net proved reserves to determine cash inflows. Future production and development costs do not include any cost inflation and assume the continuation of existing economic, operating and regulatory conditions. Future income taxes are calculated by applying statutory income tax rates to future pre-tax cash flows after provision for the tax cost of the oil and natural gas properties based upon existing laws and regulations. The discount was computed by application of a 10 percent discount factor to the future net cash flows. The calculation of the standardized measure of discounted future net cash flows is based upon the discounted future net cash flows prepared by independent qualified reserves evaluators in relation to the reserves they respectively evaluated, and adjusted to the extent provided by contractual arrangements such as price risk management activities, in existence at year end and to account for asset retirement obligations and future income taxes.

Cenovus cautions that the discounted future net cash flows relating to proved oil and gas reserves are an indication of neither the fair market value of Cenovus’s oil and gas properties, nor the future net cash flows expected to be generated from such properties. The discounted future net cash flows do not include the fair market value of exploratory properties and probable or possible oil and gas reserves, nor is consideration given to the effect of anticipated future changes in crude oil, natural gas liquids and natural gas prices, development, asset retirement and production costs and possible changes to tax and royalty regulations. The prescribed discount rate of 10 percent may not appropriately reflect future interest rates. The computation also excludes values attributable to Cenovus’s enhancing the netback price of the Company’s proprietary production.

Computation of the standardized measure of discounted future net cash flows relating to proved oil and gas reserves were based on the following average of the first-day-of-the-month benchmark prices for the twelve month period before the end of the year:

Crude Oil and Natural Gas Liquids

Natural Gas

WTI⁽¹⁾
Cushing
Oklahoma

(US$/bbl)

WCS⁽²⁾

(C$/bbl)

Edmonton
MSW⁽³⁾

(C$/bbl)

Edmonton

C5+

(C$/bbl)

Henry Hub
Louisiana

(US$/MMBtu)

AECO⁽⁴⁾

(C$/MMBtu)

2017

51.34

50.69

63.70

68.10

2.98

2.31

2016

42.75

37.98

52.06

55.32

2.49

2.17

(1)

WTI is an abbreviation for West Texas Intermediate.

(2)

WCS is an abbreviation for Western Canadian Select.

(3)

MSW is an abbreviation for Mixed Sweet Blend.

(4)

AECO is an abbreviation for Alberta Energy Company Operations.


Cenovus Energy Inc.		Supplementary Information – Oil and Gas Activities (unaudited)

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves


($ millions)	2017		2016
Future cash inflows		147,064	49,119
Less future:
Production costs		48,064	24,121
Development costs		22,850	11,293
Decommissioning liability payments		2,464	2,882
Income taxes		17,713	1,966
Future net cash flows		55,973	8,857
Less 10 percent annual discount for estimated timing of cash flows		36,263	5,225
Discounted future net cash flows		19,710	3,632

Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves


($ millions)	2017			2016
Balance, beginning of year		3,632		6,026
Changes resulting from:
Sales of oil and gas produced during the period		(2,885	)	(1,421)
Extensions, discoveries and improved recovery, net of related costs		826		285
Purchases of proved reserves in place		13,819		-
Sales of proved reserves in place		(571	)	-
Net change in prices and production costs		8,060		(3,895)
Revisions to quantity estimates		1,293		(750)
Accretion of discount		420		746
Previously estimated development costs incurred net of change in future development costs		(5	)	1,536
Asset Retirement Obligation		77		175
Other		277		58
Net change in income taxes		(5,233	)	872
Balance, end of year		19,710		3,632

OTHER FINANCIAL INFORMATION

Results of Operations


($ millions)	2017		2016
Oil and gas sales to external customers, net of royalties, transportation and blending and realized risk management		4,071	2,031
Intersegment sales		443	347
		4,514	2,378
Less:
Operating costs, production and mineral taxes, and accretion of decommissioning liabilities		1,755	1,085
Depreciation, depletion and amortization		1,753	1,222
Exploration expense		890	2
Operating income		116	69
Income taxes		31	19
Results of operations		85	50

Capitalized Costs ⁽¹⁾


($ millions)	2017		2016
Proved oil and gas properties		28,776	32,274
Unproved oil and gas properties ⁽²⁾		3,719	1,585
Total capital cost ⁽³⁾		32,495	33,859
Accumulated depreciation, depletion and amortization		2,435	20,396
Net capitalized costs		30,060	13,463

(1)

In connection with the acquisition of Cenovus’s partner’s 50 percent interest in FCCL, Cenovus was deemed to have disposed of its pre-existing interest (net capitalized cost of $9.7 billion) and re-acquired it at fair value ($12.3 billion) as required by IFRS 3, “Business Combinations” effectively resetting accumulated depreciation, depletion and amortization to zero.

(2)

Unproved oil and gas properties include exploration and evaluation assets for which no proved reserves have been recognized.

(3)

Includes assets held for sale.


Cenovus Energy Inc.		Supplementary Information – Oil and Gas Activities (unaudited)

Costs Incurred


($ millions)	2017		2016
Acquisitions
Unproved⁽¹⁾		3,372	11
Proved⁽²⁾⁽³⁾		15,016	-
Total acquisitions		18,388	11
Exploration costs		147	35
Development costs		1,257	738
Total costs incurred		19,792	784

(1)

An unproved property is a property to which no proved or probable reserves have been specifically attributed.

(2)

A proved property is a property to which proved and probable reserves have been specifically attributed.

(3)

Asset retirement costs are included in the year of acquisition.


Cenovus Energy Inc.		Supplementary Information – Oil and Gas Activities (unaudited)